\429\ Transmix is a by-product of the multi-product pipeline
distribution system. 40 CFR 80.84(a) defines transmix pipeline
interface that does not meet the specifications for a fuel that can
be used or sold, and that is composed solely of any combination of:
Previously certified gasoline (including previously certified
gasoline blendstocks that become gasoline solely upon the addition
of an oxygenate); distillate fuel; or gasoline blendstocks that are
suitable for use as a blendstock without further processing.
    \430\ Transmix processors produce ~0.1 percent of the gasoline
consumed in the U.S.
---------------------------------------------------------------------------

d. Accounting for Ethanol Blending in the Determination of Compliance
With Gasoline Sulfur Requirements
    In demonstrating compliance with the gasoline sulfur standards
finalized today, gasoline refiners and importers may adjust the sulfur
levels in the gasoline and blendstocks for oxygenate blending (BOBs)
that they produce/import to account for the downstream addition of
ethanol. We proposed that the sulfur content of denatured fuel ethanol
(DFE) used for downstream blending would be assumed to be 10 ppm in
making such demonstrations of compliance. Refiners commented that
refiners and importers should be allowed to either use the actual
sulfur value of the DFE or conduct laboratory hand blends of a
representative sample of DFE to determine the effect on the sulfur
content of the blended fuel from the addition of DFE. We agree that
refiners and importers should be allowed to use the actual sulfur
content of DFE when a sulfur test result is available and when the
refiner can demonstrate that the test result was derived from a
representative sample of the DFE that was blended with the gasoline or
BOB. The sulfur content of in-use DFE will typically be lower than the
10 ppm sulfur cap finalized today for DFE. We assumed that DFE would
have an average sulfur content of 5 ppm in conducting the refinery
analysis to support this rule. Therefore, today's final rule requires
that in determining their compliance with today's sulfur standards,
refiners and importers must either use the actual sulfur content of the
DFE established through testing of the DFE actually blended or assume a
5 ppm sulfur content for the DFE added downstream. To prevent potential
bias, a refiner or importer must choose to use only one method during
each annual compliance period.
2. Requirements for Gasoline Additives
    Today's action finalizes the requirement that manufacturers of
gasoline additives used downstream of the refinery at less than 1
volume percent must limit the sulfur contribution to the finished
gasoline from the use of their additive to no more than 3 ppm when the
additive is used at the maximum recommended treatment rate. The
additive manufacturer will be required to maintain records of its
additive production quality control activities which demonstrate that
the sulfur content of additive production batches is such that when the
additive is used at its maximum recommended treatment rate it will add
no more than 3 ppm to sulfur content of the finished gasoline. We
received comments in support of our proposed requirements (these
comments can be found in the docket to this rulemaking, and are
summarized in the Summary and Analysis of Comments document, which is
also located in the docket). An environmental organization commented
that the sulfur contribution from additives can have a material effect
on emissions performance given the level of vehicle emissions control
that is being finalized today. We also received comments from gasoline
additive manufactures were in favor of the proposed controls.
    The requirements finalized today are designed to prevent the
potential dumping of high sulfur materials into

gasoline under the guise of the addition of gasoline additives. We
continue to believe that all current gasoline additives contribute less
than 3 ppm to the sulfur content of the finished fuel when used at the
maximum recommended treatment rate (with 3 ppm being the extreme).
Normal additive production quality control practices already have had
to consider the sulfur contribution of the additive to finished
gasoline as a result of the Tier 2 gasoline sulfur requirements. The
maximum recommended treatment rate is already stated on product
transfer document or packaging for the additive. Additive manufacturers
are to retain production quality control records for 5 years and make
these available to EPA upon request. Therefore, the requirements
finalized today will not constrain the use of genuine gasoline
additives or result in significant additional costs to gasoline
additive manufacturers. Parties that introduce additives to gasoline at
over 1.0 volume percent are required to satisfy all of the obligations
of a refiner and fuel manufacturer including demonstration that the
finished blend meets the applicable sulfur specification.
    We also received comments from an environmental organization
requesting that EPA promulgate limits on the combined sulfur
contribution for all additives blended into a batch of gasoline in
addition to controlling the sulfur contribution from individual
additives. We believe that such additional controls are not necessary,
would add an unwarranted additional compliance burden, and could
interfere with the use of necessary downstream additives. Certain
additives that provide critical fuel performance characteristics (e.g.,
corrosion control, demulsifiers) contain sulfur-containing compounds as
an essential functional component. Such additives are used to remedy
specific instances of gasoline quality problems, and their treatment
rate is governed by the desire to limit the added cost from their use.

D. Averaging, Banking, and Trading Program

    In today's rule, we are finalizing an ABT program that will reduce
the compliance costs and promote the feasibility of the Tier 3 gasoline
sulfur program, because it will allow refiners and importers to choose
the most economical compliance strategy (i.e., investment in
technology, credits, or both) to meet the 10 ppm average sulfur
standard. In response to comments received on our proposal, we have
simplified and added flexibility to the ABT program. The ABT program
allows refiners and importers to continue to generate credits for
overcompliance with the current Tier 2 30 ppm average gasoline sulfur
standard through 2016, and the new 10 ppm average standard beginning in
2017. (Small refiners and small volume refineries have a January 1,
2020 compliance date, as described below.) These credits can be used
for compliance with either the Tier 2 standard through 2016 or the Tier
3 standard beginning in 2017. Credits can also be banked for future use
or transferred to other refineries for compliance with the average
sulfur standard. In addition, we are allowing refiners and importers to
also use any valid credits banked from 2012 and 2013 under the Tier 2
program toward compliance with either the Tier 2 or Tier 3 sulfur
programs. We believe these provisions will provide a seamless
transition from Tier 2 to the Tier 3 program.
1. How will the ABT program assist with compliance?
    The Tier 3 ABT program allows refiners and importers the
flexibility to: (1) Have varying gasoline sulfur levels for their
batches of fuel as long as they meet the 10 ppm average over the course
of the year; (2) use credits generated at one of its refineries to
offset higher sulfur gasoline produced at another of its refineries;
(3) bank generated credits for future use; and (4) participate in
trading (via buying and/or selling) of credits from another refiner to
help lower costs. The ABT program allows for the generation of credits
by refiners and importers for over-compliance with the 10 ppm sulfur
standard (on a refinery/facility basis), and for the transfer of these
credits to other refiners (for use a refinery) to reduce or eliminate
their need to make capital investments to meet the 10 ppm standard. The
ABT program will provide refiners and importers with multiple
approaches to compliance, and each can choose the approach that best
minimizes their costs.
2. ABT Modeling
    For the proposed rule, we modeled the effects of an ABT program on
refinery compliance. Our modeling determined the lowest cost approach
on a refinery-by-refinery basis under two scenarios: The first, in
which every refinery has the opportunity to make credit transfers with
every other refinery in the nation, and a more limited scenario in
which credit transfers would only occur within companies that own more
than one refinery.
    In developing today's final program, we also analyzed the Tier 2
credit market and found that, currently, Tier 2 sulfur credits are both
transferred within companies (intra-company) and traded between
companies (inter-company). As discussed in Chapter 4.3 of the RIA, in
2012 approximately 56% of the Tier 2 credit transactions were inter-
company trades. The remaining 44% were intra-company trades. This
analysis shows that there is a functioning, well-established gasoline
sulfur credit trading market. There does not appear to be any hindrance
to credit trading currently or in the future. We anticipate that a
significant number of refineries will take advantage of the opportunity
to generate or use credits, thus lowering their compliance burden for
the Tier 3 program. For a more complete discussion of our analysis of
credit trading and the associated cost impacts of the ABT program,
refer to Chapter 4.3 of the RIA.
3. Eligibility
    Consistent with our proposal, under today's final program, sulfur
credits may be generated by both U.S. refiners and importers of
gasoline into the U.S. only for gasoline that is subject to the sulfur
requirements as described in the regulations at Sec.  80.1603. This
excludes gasoline produced or imported for use in California
(``California gasoline'') and gasoline designated for export, but
includes gasoline produced by California refineries for use outside the
state. We sought comment in the proposed rule on whether or not to
include California. All comments received on this issue were against
the inclusion of such gasoline in the ABT program, largely because it
would cause additional burden but provide no appreciable credits to the
market to justify the additional compliance burden (such as batch
reporting). We agree with these comments, and are finalizing the
provision that California gasoline and gasoline for export will not be
included in the ABT program. In order to exclude exported gasoline and
California gasoline, refiners must keep records to demonstrate that the
excluded gasoline was designated for export or as California gasoline,
and was actually exported or used in California.
    While under existing fuel programs (e.g., MSAT2), we precluded
importers from generating ``early'' credits (credits generated before a
program start date), we are allowing importers to generate early
credits in the Tier 3 ABT program, consistent with our proposal.
Importers were previously precluded from generating early credits
because they generally did not need additional lead time to comply with
our fuel standards (as they most likely would not be

investing in new refining technologies) and we also thought it would be
difficult for them to establish representative baselines from which
early credits could be generated. However, early credit baselines are
not a part of the Tier 3 program, as discussed above. In addition,
commenters noted that while importers may not necessarily have to take
actions to desulfurize fuel like domestic refiners do, these parties
may have to pay premiums on obtaining lower sulfur fuel, thus their
efforts to provide lower sulfur fuel should also be able to generate
early credits. Thus, we are finalizing provisions allowing importers to
generate early credits for sending over-compliant gasoline to the
United States prior to January 1, 2017.
    We proposed to limit credit generation to refiners and importers.
Under the Tier 2 gasoline program, we allow refiners who produce
gasoline by combining blendstocks together or adding blendstocks to
previously certified gasoline (refiner-blenders) to participate in the
in the sulfur ABT program, but do not allow butane blenders who comply
with the reduced sampling, testing, and reporting requirements to
participate in the sulfur ABT program.\431\ We are extending these
provisions to butane and pentane blenders under the Tier 3
program.\432\ Under today's rule, any refiner who uses the reduced
sampling, testing, and reporting provisions for blending butane or
pentane into gasoline will not be allowed to generate credits. Refiner-
blenders who comply with the full suite of sampling, testing, and
reporting requirements will, however, be allowed to generate credits.
---------------------------------------------------------------------------

    \431\ The provisions for butane blenders are located in 40 CFR
80.82.
    \432\ See Section V.I. for a discussion of the requirements for
pentane blenders.
---------------------------------------------------------------------------

    We received several comments from ethanol producers and Growth
Energy (representing ethanol producers), who commented that DFE should
be subject to an annual average sulfur standard and that ethanol
producers should be able to participate in the ABT program that is
available to refiners and importers of gasoline. These commenters
stated that preventing them from participating in the ABT program would
provide refiners with pathways to allow delayed adoption of cleaner
fuel standards at their expense. Some ethanol producers commented that
they should be allowed to participate in the ABT program as a means of
offsetting the additional cost of the proposed per-batch sulfur testing
and reporting requirements. We also received comments from refiners
stating that credit generation should be permitted only for refiners
and importers.
    As in existing EPA fuel programs, we continue to believe that it is
not appropriate expand the ABT provisions to cover ethanol producers
and oxygenate blenders for several reasons. First, expanding the ABT
program beyond refiners and importers could greatly increase the number
of parties participating thereby potentially complicating EPA
compliance assurance activities while having little overall impact on
the sulfur credit pool. Second, the current ABT program under the Tier
2 gasoline sulfur program, which is limited to gasoline refiners and
importers, has functioned effectively with few compliance
irregularities. Third, experience with the unleaded gasoline program
suggests widespread abuse and fraud when credits have been allowed to
be generated or sold by parties other than refiners or importers
subject to the regulations. Fourth, it would require a considerably
more complicated compliance structure, including the application of all
refiner responsibilities to ethanol producers and blenders. Fifth,
there is no need for DFE producers to generate credits in order to
recoup the value for any lower sulfur content of their product. The
value of any lower sulfur content will be reflected in the market price
of DFE, similar to the octane value to refiners. Sixth, the sulfur ABT
provisions were included to ease the burden of compliance for refiners
who have to make capital changes to their facilities to meet today's
more stringent sulfur standards. In addition to reducing the cost of
today's gasoline sulfur program, the ABT provisions allow for an
earlier effective date of the sulfur standards than would otherwise be
possible. Such considerations are not applicable to ethanol producers
since capital expenditures for desulfurization equipment or other
equipment will not be needed at their facilities to comply with the
sulfur standards finalized today.\433\ Finally, overcompliance with the
per-gallon sulfur cap for DFE is not a valid basis for credit
generation. We expect that in all cases, the DFE sulfur level will be
below the cap. To allow credit generation for these parties, we would
need to set an additional annual average sulfur standard for DFE at
some level below 10 ppm and allow credits to be generated for
overcompliance with that standard. Accordingly, we do not believe it is
appropriate to allow ethanol producers or blenders to generate sulfur
credits under the Tier 3 gasoline sulfur program, and as such, we are
not finalizing such a provision. The Tier 3 rule prohibits any person
downstream of the refinery or importer that produced or imported
gasoline, CBOB, or RBOB who adds oxygenate to such product from
including the volume and sulfur content of the oxygenate in any
compliance calculations for credit generation.
---------------------------------------------------------------------------

    \433\ The requirements for ethanol producers finalized today are
discussed in Section V.G.4.
---------------------------------------------------------------------------

4. Credit Generation and Use
    Under the Tier 3 ABT program, the credit generation provisions are
nearly the same as those under the Tier 2 program. In essence, the Tier
2 program simply continues with a lower standard below which credits
are generated. Refiners and importers are allowed to average within and
across companies to meet the standard in the most cost-effective manner
possible, including generating and using credits. For Tier 3, refiners
and importers can generate credits for overcomplying with the 10 ppm
standard on a volume-weighted annual average basis beginning January 1,
2017. Credit generation periods remain 12 months long and continue to
be synchronized with annual compliance demonstration periods. The final
Tier 3 ABT program provisions for approved small refiners and small
volume refineries are discussed below in Section V.D.6.
    Consistent with our proposal, and to encourage early gasoline
desulfurization and give the refining industry flexibility to stagger
their investments over time, we are also finalizing provisions to allow
refiners and importers to generate credits prior to January 1, 2017
(i.e., early credits).
    We proposed an early credit program for overcompliance with the
current Tier 2 30 ppm gasoline sulfur standard from January 1, 2014
through December 31, 2016. These early credits were proposed to have a
credit life of three years, and could be used through December 31,
2019. We also proposed that refiners and importers who generated early
credits would then have to designate them at the end of the compliance
year as either Tier 2 credits or Tier 3 early credits, and the credits
would have to be used in accordance with the designation.
    We received several comments on our early credit provisions. Some
commenters stated that the requirement to designate credits as either
Tier 2 or Tier 3 would not provide refiners and importers the intended
amount of flexibility, as they may not necessarily be able to predict
if they will need to use those early credits for either Tier 2 or Tier
3 compliance. Further,

commenters were concerned that if more refiners than anticipated opt to
bank the credits for possible future use at their own refineries, it
could result in less credits being made available to the market. We
also received comments both in support of and against the proposed
three-year credit life. Some commenters stated that they believed that
all credits should have a five-year life to provide maximum flexibility
and more certainty on the availability of credits; while other
commenters supported the three-year credit life limit, because it would
coincide with the end of the small refiner/small refinery provisions
thus providing more certainty of the benefits of the Tier 3 program.
Finally, while not proposed, we received many comments requesting that
EPA clarify what would become of ``banked'' Tier 2 credits (Tier 2
credits generated in 2012 and/or 2013 that were not used before the end
of their five-year credit life and would have expired when the Tier 3
program began, under the terms of the proposed ABT program). Commenters
further stated that these credits should not expire, but rather should
be allowed to receive their full five-year credit life, as they
represent actual reductions in refinery sulfur levels.
    As discussed above, we are finalizing a more flexible approach to
the ABT program than what we proposed. We believe this will provide for
a more seamless transition from the Tier 2 to the Tier 3 credit
programs and more certainty on credit availability.
    Consistent with our proposal, refiners and importers may begin
generating early credits on January 1, 2014, and continue through
December 31, 2016. These credits will be generated on an annual average
basis, from a demonstration that the refiner or importer's annual
average gasoline sulfur level is below the current Tier 2 30 ppm annual
average sulfur standard. We believe this simple early credit approach
is possible because U.S. gasoline was averaging around 30 ppm as we
started developing the Tier 3 program, based on compliance data. Since
refiners and importers would need to continue to comply with the
existing Tier 2 sulfur standards during the early credit period, absent
Tier 3, they would need to maintain this level of performance on an
industry average basis. Accordingly, any additional gasoline sulfur
reductions beyond 30 ppm will be attributed to the proposed Tier 3
program.
    In response to comments received, we are not requiring that credits
be designated as either Tier 2 or Tier 3 and only used for the program
for which they were designated. Refiners and importers may use early
credits either for ongoing compliance with the Tier 2 program, or bank
them for future compliance with the Tier 3 program (within the limits
of the credit life restrictions). Essentially, the Tier 2 credit
generation provisions simply continue, and any banked credits generated
in 2014 through 2016 that were not used for compliance with the Tier 2
standards would be carried over for use in complying with Tier 3. We
believe that this will allow for more certainty of credit availability
before refiners must make their Tier 3 investment decisions, thus
reducing the cost of the program. It will also avoid any incentive for
refiners to use up banked Tier 2 credits prior to 2017 causing
increased in-use sulfur levels and emissions.
    Based on our analysis of the Tier 2 credit market for 2012, we
believe that there will be a balance of 2012 banked credits equivalent
to approximately two months of compliance, and we anticipate a similar
amount (perhaps more) for 2013. Although we did not propose to allow
for banked 2012 and 2013 Tier 2 credits to be used for compliance with
the Tier 3 program, we are finalizing this provision for a number of
reasons. First, the Tier 2 banked credits represent real reductions--
refiners and importers are currently generating these credits for
overcompliance with the Tier 2 gasoline sulfur standard. Second,
allowing these banked credits to receive their full five-year credit
life will provide more assurance of the credit availability for trading
for those who need them to comply with Tier 3 without a large capital
investment. As previously explained, this will allow for more certainty
of credits available far before making Tier 3 investment decisions,
thus reducing the cost of the program. A lack of certainty in the
credit trading market could lead to refiners banking more credits than
usual for their own use rather than allowing these credits to be
available in the market for trading. As shown in Chapter 4.3 of the
RIA, refiners tend to hold credits as an insurance policy until they
approach the end of their credit life. If credit-generating refiners
continue with this approach, credits generated in 2012 and 2013 will
likely be available for purchase in 2017 and 2018 for those refiners
that may want to rely on them for compliance (along with additional
early credits generated in 2014 through 2016). Finally, as we
anticipate that these credits will be equal to about four months of
compliance, the allowance of 2012 and 2013 banked Tier 2 credits makes
for a more flexible program by effectively allowing for a small amount
of additional lead time without adversely affecting the overall
benefits of the Tier 3 program. As discussed previously, this will
avoid any incentive for refiners to use up banked Tier 2 credits prior
to 2017 causing increased in-use sulfur levels and emissions. We
believe these provisions will allow the Tier 3 program to begin on
January 1, 2017, with more certainty regarding the availability of
credits for those refiners needing (or choosing) to defer investment to
better align with their existing turnaround/shutdown schedules.
    All credits generated before January 1, 2017 will be valid for five
years or until December 31, 2019, whichever is earlier--no early
credits may be used for compliance beginning January 1, 2020. Thus,
banked Tier 2 credits generated in 2012 and 2013 will receive their
full five-year life and will not expire at the start of the Tier 3
program. However, credits generated in 2015 and 2016 that are unused as
of December 31, 2019 will expire and become invalid. We believe that
structuring the early credit program this way will offer considerable
flexibility to refiners phasing in Tier 3 gasoline sulfur controls,
while still placing a date at which point the intended sulfur program
will be fully implemented and enforceable--January 1, 2020 (the same
date small refiners and small refineries must begin complying with the
10 ppm sulfur standard). This will also provide a date certain to give
auto manufacturers greater confidence for the design of their vehicles
that all vehicles in-use are running on 10 ppm average fuel. Otherwise,
it is possible that the greater ease of generating early credits
relative to 30 ppm sulfur (as opposed to 10 ppm in 2017 and beyond)
would allow higher sulfur levels to continue well beyond 2019.
    Consistent with our proposal, all credits generated beginning
January 1, 2017 will be for overcompliance with the Tier 3 10 ppm
annual average sulfur standard, and will have a five-year credit life.
We believe five years will give refiners and importers sufficient time
to use credits generated in previous years while still placing
limitations on credit life to help with enforcement. Five years is
consistent with the Tier 2 ABT program, as well as the current credit
life and recordkeeping provisions for other 40 CFR part 80 fuels
programs, and coincides with the applicable statute of limitations for
violations by parties who generate invalid credits. Credits must be
used within five years

from the year they were generated (regardless of when/if they are
traded), otherwise they will expire and become invalid. For example,
credits generated in 2017 can be applied towards 2018-2022 compliance,
as well as 2017 compliance. After March 31, 2023 (when reports for the
2022 annual compliance period will be due), credits generated in 2017
will expire and become invalid. Similarly, credits generated in 2018
can be applied towards 2019-2023 compliance, as well as 2018
compliance. After March 31, 2024, credits generated in 2018 expire, and
so on and so forth.
5. Credit Trading Provisions
    We are also finalizing provisions for credit trading in Tier 3 that
are identical to those under the current Tier 2 program. As in that
program, it is possible that sulfur credits could be generated by one
party, subsequently transferred or used in good faith by another, and
later found to have been calculated or created improperly or otherwise
determined to be invalid. As in the current Tier 2 program as well as
other 40 CFR part 80 fuel programs, if this occurs, we are requiring
that both the seller and purchaser will have to adjust their sulfur
calculations to reflect the proper credits and either party (or both)
could be determined to be in violation of the standards and other
requirements if the adjusted calculations demonstrate noncompliance
with the 10 ppm standard.
    Sulfur credits must be transferred directly from the refiner or
importer generating them to the party using them for compliance
purposes. This ensures that the parties purchasing them are better able
to assess the likelihood that the credits are valid. As proposed, we
are also finalizing an exception for the case where a credit generator
transfers credits to a refiner or importer who inadvertently cannot use
all the credits. In this case, the credits can be transferred a second
time to another refiner or importer. After the second trade, the
credits must be used or they will expire. Allowing a maximum of two
trades is consistent with other recent fuel programs and we believe it
is sufficiently flexible while still preserving adequate means for
enforcement. While some commenters stated that they believe the two-
trade maximum is not necessary given the fact that credits are only
being traded within a small part of industry, we believe that unlimited
trading could result in an unenforceable program and potentially lead
to problems with invalid credit trading. Given the widespread use of
credit trading between different companies under the Tier 2 program
despite this provision, there appears to already be sufficient
flexibility in the program. We received comments requesting that we
clarify that intra-company trading will continue to be unlimited as it
is in the existing Tier 2 ABT program. Intra-company trading will in
fact remain unlimited, and we have added language to the final Tier 3
regulations to clarify this.
    There are currently no prohibitions against brokers facilitating
the transfer of credits from one party to another. Any person can act
as a credit broker, regardless of whether such person is a refiner or
importer, as long as the title to the credits is transferred directly
from the generating refiner or importer to the using refiner or
importer. This prohibition on outside parties taking ownership of
credits was promulgated in response to problems encountered during
implementation of the unleaded gasoline program, and has since been
extended to subsequent fuels rulemakings. We continue to believe that
maintaining this prohibition will allow for maximum program
enforceability and consistency with all of our other ABT programs for
mobile sources and their fuels.
6. ABT Provisions for Small Refiners and Small Volume Refineries
    Consistent with our proposal, approved small refiners and small
volume refineries must comply with the 10 ppm annual average standard
by January 1, 2020, which allows for an additional three years for
compliance. This is the primary form of relief offered to small
refiners and small volume refineries under the Tier 3 gasoline sulfur
program (discussed further in Section V.E, below). Approved small
refiners and small volume refineries may continue to generate credits
for overcomplying with the 30 ppm Tier 2 standard before January 1,
2020. Prior to January 1, 2017, credits generated by small refiners and
small volume refineries can be traded/sold to non-small refiners for
use by December 31, 2019, and the credit revenues could be used to help
offset their Tier 3 investments.
    When the Tier 3 program begins on January 1, 2017, small refiners
and small volume refineries may continue to generate credits for
overcompliance with the 30 ppm sulfur standard (as they will still be
subject to the Tier 2 standards through December 1, 2019), or they may
generate credits for overcompliance with the Tier 3 10 ppm sulfur
standard. We are finalizing that small refiners and small volume
refineries must designate their credits as being generated for either
the Tier 2 or Tier 3 ABT program, as proposed. Credits designated and
generated as Tier 2 credits may only be traded with other small
refiners and small volume refineries (and these credits may only be
used for compliance through December 31, 2019). However, credits
designated and generated as Tier 3 credits may be traded with non-small
refiners as well. Additionally, from January 1, 2017 through December
31, 2019, if a small refiner's annual average sulfur level is below 10
ppm, they may elect to split the designation and generation of credits
between both the 10 ppm and 30 ppm standards (without double-counting).
For example, in 2017, a small refiner with an annual gasoline sulfur
average of 8 ppm could generate 20 ppm-volume Tier 2 credits (30 ppm-10
ppm) that could be used by other small refiners and small volume
refineries, or banked by the refinery for future Tier 2 compliance.
This small refiner would also generate 2 ppm-volume Tier 3 credits (10
ppm-8 ppm) that could be sold to refiners and importers subject to Tier
3, or banked by the refiner for future Tier 3 compliance.
7. Deficit Carryforward
    Under the final Tier 3 sulfur program, we are finalizing deficit
carryforward provisions similar to the existing Tier 2 program, whereby
an individual refinery that does not meet the 10 ppm standard in a
given year may carry a credit deficit forward for 1 year. Under this
deficit carryforward allowance, the refinery will have to make up the
credit deficit and come into compliance with the Tier 3 sulfur standard
the next calendar year. We received comments expressing concern that it
will be more challenging for refineries to make up their credit deficit
in one year with a 10 ppm sulfur standard, and requesting that the
deficit carryforward allowance be extended to two or three years. We
disagree with these comments primarily because of concerns with the
enforceability of allowing for a deficit beyond one year. In addition,
we believe that an extended deficit carryforward will further delay
Tier 3 sulfur reductions. While we acknowledge that there might be an
increased hurdle for some refiners to make up their own credit
shortfall, we believe the ABT program provides ample opportunity to
purchase credits from others. However, in recognition of unanticipated
circumstances, such as where credits are unavailable or are
prohibitively expensive such that the refiner could not make up the
deficit in one year, the Tier 3 hardship provisions provide EPA

with the authority to allow for extended deficit carryforward, if a
refiner's hardship petition demonstrates that it meets the criteria.
Thus, we are finalizing that a refiner could carry a deficit forward
for up to 3 years only in cases of hardship situations, as described
below in Section V.E.2.

E. Additional Program Flexibilities

1. Regulatory Flexibility Provisions
a. Small Business Regulatory Flexibility Provisions
    We are finalizing several regulatory flexibility provisions for
small entities in the fuels industry to reduce the burden that the Tier
3 program could have on them. As in previous fuel rulemakings, our
justification for including provisions specific to small businesses is
that these entities generally have a greater degree of difficulty in
complying with the standards compared to other entities.
    In developing the Tier 3 gasoline sulfur program, we evaluated the
environmental need as well as the technical and financial ability of
refiners and others in the fuel industry to meet the sulfur standards
as expeditiously as possible. We believe it is necessary and feasible
for the vast majority of the program to be implemented in the
established time frame to achieve the air quality benefits as soon as
possible. Based on information available from small refiners and others
(as discussed further in the Regulatory Flexibility Analysis
description in Section XII.C), we believe that the category of entities
classified as small generally face unique circumstances with regard to
compliance with environmental programs, compared to larger entities.
Thus, as discussed below, we are finalizing several regulatory
flexibility provisions for small refiners to reduce the burden that the
Tier 3 program could have on them.
    Small entities as a category generally lack the resources that are
available to larger companies to raise capital for investing in a new
regulatory program, such as shifting of internal funds, securing of
financing, or selling of assets. Small entities are also likely to have
more difficulty in competing for any needed engineering and
construction resources. This is because the magnitude of their projects
tends to be both smaller and less profitable for the contracted firms.
As such, we are including provisions in today's rule that would provide
assistance for small entities in meeting the 10 ppm sulfur standards.
This proposed approach would allow the overall program to begin as
early as possible; achieving the air quality benefits of the program as
soon as possible, while helping to ensure that small entities have
adequate time to raise capital for new fuel desulfurization equipment
or to make any other needed changes. We also believe that small
business regulatory flexibilities can provide these entities with
additional help and/or time to accumulate capital internally or to
secure capital financing from lenders, and could spread out the
availability of any needed engineering and construction resources in a
manner that they are available by the time they are needed.
i. Delayed Standards for Small Refiners
    We are finalizing a compliance date of January 1, 2020 for small
refiners, allowing small refiners to postpone compliance with the Tier
3 program for up to three years. Small refiners will have from January
1, 2017 through December 31, 2019 to continue production of gasoline
with an average sulfur level of 30 ppm (per the Tier 2 gasoline sulfur
program). This delayed compliance schedule for small refiners is not
intended as an opportunity for those refiners to increase their
production of gasoline with sulfur levels greater than 10 ppm, but
rather will help small refiners with compliance with the program. Since
the compliance costs for their competitors may rise during these three
years and since their gasoline will be sold into the same fungible
market, this delay will not only provide them more lead time, but also
financial support towards later compliance. Compliance with the 10 ppm
annual average sulfur standard will begin on January 1, 2020 for small
refiners. Further, as discussed in greater detail in Section V.D.5, a
small refiner would be allowed to continue using Tier 2 gasoline sulfur
credits through December 31, 2019 to meet their refinery average 30 ppm
sulfur standard.
ii. Refinery Gate and Downstream Caps
    During the Small Business Regulatory Enforcement Fairness Act
(SBREFA) Panel process, small refiners raised the concern that a
refinery gate cap of 20 ppm could cause problems during a refinery
turnaround or an upset because a cap of this level could result in a
refiner not being able to produce saleable gasoline. The Panel likewise
had concerns that a downstream cap of 25 ppm may cause problems for
small downstream entities such as transmix processors and gasoline
additive manufacturers. They stated it would not be feasible for
transmix processors to install desulfurization equipment to produce
gasoline that meets a 25 ppm sulfur cap. They also stated that such a
low sulfur cap could preclude certain necessary gasoline additives from
the market whose activity depends on sulfur containing components.
Thus, the Panel recommended that EPA assess and request comment on
retaining the current Tier 2 refinery gate and downstream caps of 80
and 95 ppm, respectively, to help provide maximum flexibility and avoid
system upsets for the entire refining and distribution system. Further,
the Small Business Administration (SBA) and Office of Management and
Budget (OMB) Panel members recommended that EPA propose retaining the
80 ppm and 95 ppm caps. The Panel also recommended that, if EPA were to
propose caps lower than 80 and 95 ppm, the Agency request comment on
additional refinery gate and downstream caps that are above 20/25 ppm
but below 80/95 ppm. As discussed above, we proposed options to
maintain the current 80/95 ppm caps or to lower them to 50/65 ppm and
sought comment on a refinery gate cap of 20 ppm with a downstream cap
of 25 ppm. We are retaining the current 80/95 ppm per-gallon sulfur
caps in today's final rule. For more information on today's final per-
gallon sulfur cap provisions and related comments, refer to Section V.C
of this preamble and Chapter 5 of the Summary and Analysis of Comments
document.
b. Small Volume Refinery Provisions
    Consistent with our proposal, we are finalizing a compliance date
of January 1, 2020 for small volume refineries. Approved small volume
refineries will receive a three-year delay (January 1, 2017 through
December 31, 2019) in meeting the 10 ppm average gasoline sulfur
standard, similar to the small refiner delay. During the development of
the Tier 3 rulemaking and throughout the SBREFA process, it became
evident that some refineries may experience higher compliance costs on
a per-gallon basis than other refineries, and in some cases
considerably higher. These are refineries owned by a refiner/company
that would not meet the SBA definition of a small business. In an
oversupplied gasoline market, these refineries may have difficulty
justifying capital investments to comply with new standards. In
recognition of this concern under the RFS program, Congress granted all
refineries with a crude oil throughput of less than or equal to 75,000
barrels per calendar day (bpcd) additional time to comply. Consistent
with this allowance, we are including delayed Tier 3 sulfur standards
for approved small volume refineries.

Overall, we believe that these small refineries are disproportionally
impacted when it comes to their cost of compliance and ability to
rationalize the investment costs in today's gasoline market. Giving
these refineries additional lead time will allow 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. Credit generation
opportunities for approved small volume refineries are identical to
those for small refiners, as described above in Section V.D.
    A refiner must apply and be approved for small volume refinery
status. We are finalizing a small volume refinery net crude throughput
of less than or equal to 75,000 bpcd, based on the highest crude
throughput for the 2012 calendar year. We received comment suggesting
that a higher crude throughput (e.g., 90,000 bpcd) would be more
appropriate, as the refining industry has changed since Congress set
the 75,000 bpcd throughput limit for small refineries in the RFS
program. In analyzing various crude throughput maximums between 75,000
and 90,000 bpcd, we do not believe it is appropriate or necessary to
increase the threshold beyond what was previously set by Congress. The
75,000 bpcd limit set by Congress was to recognize those refineries
that would have difficulty with compliance with a rulemaking (from both
a cost and feasibility standpoint), raising this limit would go beyond
Congress' intent.
2. Provisions for Refiners Facing Hardship Situations
    We are finalizing hardship provisions that are intended to
accommodate a refiner's inability to comply with the 10 ppm sulfur
standard at the start of the Tier 3 program, and to deal with
unforeseen circumstances that may occur at any point during the
program. These provisions, which are similar to those in existing fuels
programs, are available to all refiners, small and non-small, though
relief will be granted on a case-by-case basis following a showing of
certain requirements; primarily that compliance through the use of
credits is not feasible. Any hardship waiver granted will not be a
total waiver of compliance; rather, a hardship waiver will consist of
short-term relief that will allow a refiner facing a hardship situation
to, for example, receive additional time to comply. EPA will determine
appropriate hardship relief based on the nature and degree of the
hardship, as presented by the refiner in its hardship application, and
on our assessment of the credit market at that time. Further, as
discussed above in Section V.D.7, hardship waivers could grant relief
in the form of additional deficit carryforward for up to three years,
depending on the level of hardship and the status of the credit market.
A detailed description of the requirements for applying for a hardship
waiver is located in the regulations at 40 CFR 80.1625.
    We do not anticipate a great need for hardship relief, given the
flexibilities offered as part of the Tier 3 program and an expected
robust credit trading market. Nevertheless, we are finalizing hardship
provisions in this action as a failsafe for unforeseen circumstances,
or should credits become scarce or prohibitively expensive.
a. Temporary Waivers Based on Unforeseen Circumstances
    We are finalizing a provision to allow for temporary waivers based
on unforeseen circumstances. EPA would, at our discretion, permit a
refiner to seek a temporary waiver from the Tier 3 sulfur standards
under certain rare circumstances. This waiver provision is intended to
provide refiners relief in unanticipated circumstances--such as a
refinery fire or a natural disaster (i.e., force majeure)--that cannot
be reasonably foreseen now or in the near future. Under this provision,
a refiner can seek a hardship waiver for relief if it can demonstrate
that the magnitude of the impact is so severe as to require such an
extension. A refiner would need to show that: (1) The waiver is in the
public interest; (2) the nonconformity is unavoidable; (3) it will meet
the proposed Tier 3 standards as expeditiously as possible; (4) it will
make up the air quality detriment associated with the nonconforming
gasoline, where practicable; and (5) it will pay to the U.S. Treasury
an amount equal to the economic benefit of the nonconformity less the
amount expended to make up the air quality detriment. These conditions
are similar to those in existing fuels regulations, and are necessary
and appropriate to ensure that any waivers granted would be limited in
scope.
    Such a request will be based on the refiner's inability to produce
compliant gasoline at the affected facility due to extreme and unusual
circumstances outside the refiner's control that could not have been
avoided through the exercise of due diligence. The hardship request
will also need to show that other avenues for mitigating the problem,
such as the purchase of credits toward compliance under the ABT program
provisions, have been pursued and yet were insufficient or unavailable.
In light of other flexibilities, including the ABT program, we expect
that the need for such requests will be rare.
b. Temporary Waivers Based on Extreme Hardship Circumstances
    In addition to the provision for short-term relief in extreme
unforeseen circumstances, we are also finalizing a hardship provision
where a refiner may receive a hardship waiver based on severe economic
or physical lead time limitations of the refinery to comply with the
Tier 3 standards at the start of the program. A refiner seeking such
hardship relief under this provision must demonstrate that these
criteria were met. In addition to showing that unusual circumstances
exist that impose extreme hardship in meeting the Tier 3 standards, the
refiner will need to show that: (1) It has made best efforts to comply,
including through the purchase of credits; (2) the relief granted under
this provision is in the public interest; (3) the environmental impact
is acceptable; and (4) it has active plans to meet the requirements as
expeditiously as possible. We expect that hardship relief requests
under this provision will mostly be applicable at the beginning of the
Tier 3 program, when refiners are making their investments to comply.
If hardship relief under these circumstances is approved, we expect to
impose appropriate conditions to ensure that the refiner is making best
efforts to achieve compliance offsetting any loss of emission control
from the program.
    We believe that providing short-term relief to those refiners that
need additional time due to hardship circumstances will help to
facilitate the adoption of the overall Tier 3 program for the majority
of the industry. However, we do not intend for hardship waiver
provisions to encourage refiners to delay planning and investments they
would otherwise make. Again, because of the flexibilities of the
overall Tier 3 program, especially the ABT program, we expect the need
for additional relief to be rare.

F. Compliance Provisions

    This section describes the compliance provisions of today's
program. For the most part, the Tier 3 sulfur standards simply reflect
a lowering of the current Tier 2 sulfur standards. Thus, we are
retaining most of the same compliance provisions as the current Tier 2
program, with exceptions as noted. However, we also proposed and sought
comment on several fuel program

regulatory streamlining measures, including a broader program redesign
to streamline the reformulated gasoline and anti-dumping
regulations.\434\ As discussed below, some of these streamlining
measures will also impact the Tier 3 sulfur compliance provisions.
---------------------------------------------------------------------------

    \434\ For more information on Part 80 regulatory streamlining
options, refer to Section VI.
---------------------------------------------------------------------------

1. Registration, Reporting, and Recordkeeping Requirements
    Registration, recordkeeping, and reporting are necessary to track
compliance with the Tier 3 standards and the ABT program.
a. Registration Requirements
    Refiners, importers, and anyone acting as a refiner (e.g., a
terminal with blending or other refining operations) who expects to
produce or import gasoline must register each of its facilities with
EPA by June 1, 2016, or six months prior to producing gasoline meeting
the Tier 3 standards and/or participating in the credit program.
Manufacturers of denaturants that are designated as suitable for use in
the manufacture of DFE that meets federal requirements must also
register each of their facilities with EPA by June 1, 2016, or six
months prior to producing denaturant that is so designated.\435\
Manufacturers of pentane designated as suitable for use by blenders
into previously certified gasoline (PCG) subject to the Tier 2 program
must register each of their facilities with EPA prior to manufacturing
pentane for such downstream blending.\436\ Manufacturers of pentane for
use by blenders of pentane into PCG subject to the Tier 3 program must
register each of their facilities with EPA by June 1, 2016, or six
months prior to producing such pentane. After the Tier 3 program begins
on January 1, 2017, any non-registered parties must register at least
three months prior to producing gasoline, participating in the credit
market, producing denaturant designated as suitable for use in the
manufacture of DFE that meets federal requirements, or producing
pentane for downstream blending into PCG under the Tier 3 program.
Consistent with the existing registration requirements for butane
blenders, pentane blenders must comply with the fuel registration
requirements under the fuel and fuel additives registration program of
40 CFR part 79. Most refiners, importers, and ethanol producers and
some ethanol denaturant manufacturers are currently registered with EPA
under other 40 CFR part 80 fuels programs. All manufacturers of
gasoline additives for use in highway vehicles are already required to
be registered with EPA under 40 CFR part 79 fuel and fuel additives
program. Parties who are already registered do not have to register
again.
---------------------------------------------------------------------------

    \435\ As discussed in section V.I. of this preamble, the use of
denaturants that are so designated enables DFE manufacturers to use
streamlined provisions to demonstrate compliance with the Tier 3
sulfur requirements for DFE.
    \436\ The provisions for downstream blending of pentane into
gasoline described in section VI.A.3. will become effective 60 days
after the publication of this rule and may be used for gasoline
subject to the Tier 2 program requirements as well as gasoline
subject to the Tier 3 program requirements.
---------------------------------------------------------------------------

    The same basic forms currently being used for existing fuels
programs will be used for Tier 3 registration. These forms are well
known in the regulated community and are simple to fill out. Upon
receipt of a completed registration form, EPA will issue a unique 4-
digit company identification number and a unique 5-digit facility
identification number. As with existing fuels programs, these numbers
will be required for all reports sent to EPA and for PTDs.
    Registrations do not expire and do not have to be renewed; however,
registered parties are responsible for notifying us of any change to
their company or facility information.
    An entity's registration must include a corporate name and address
(including the name, telephone number, and email address of a corporate
contact person); and, for each facility operated by the entity:
     Type of facility (e.g., refinery, import facility,
pipeline, terminal, transmix facility, etc.)
     Facility name
     Physical location
     Name, telephone number, and email address of a corporate
contact person
b. Reporting Requirements
    Refiners and importers must submit annual reports demonstrating
their compliance with the Tier 3 standards, and on the generation, use,
and transfer of sulfur credits at each of its refineries or import
facilities. Similar to our other sulfur programs, refiners and
importers must submit data on individual batches of gasoline (including
batch volume and sulfur content). Based on our experience with existing
gasoline and sulfur-based programs, we believe that requiring annual
reports and individual sulfur batch data provides an effective means of
monitoring compliance with the standards and the credit program.
    Producers and importers of blender grade pentane for use by pentane
blenders must also submit annual reports that include data on
individual batches demonstrating compliance with the quality
requirements for blender grade pentane and batch volume.
    We proposed that producers and importers of DFE and other
oxygenates would be required to submit an annual report that includes
the total volume of DFE/oxygenate produced and an attestation that all
batches met the proposed fuel quality requirements. We continue to
believe that such annual reports are important enforcement and
compliance assurance mechanism and thus are finalizing the proposed
annual reporting requirements for oxygenate producers and importers.
    Tier 3 reports will be due annually on March 31, on forms as
required by EPA.
c. Recordkeeping Requirements
    Similar to current EPA fuels programs, refiners and importers must
retain all records that demonstrate compliance with the Tier 3 program,
including the ABT program.
    Manufacturers of DFE and other oxygenates must keep records for
five years on individual batches of DFE/oxygenate (including batch
volume,, denaturant concentration, and sulfur test results or other
records to demonstrate compliance with the Tier 3 sulfur requirements
as applicable).\437\
---------------------------------------------------------------------------

    \437\ As discussed in section V.G. of this preamble, DFE
manufacturers may demonstrate compliance with Tier 3 sulfur
requirements either by testing each batch or mathematically using
volumetric blend records and product transfer documents from the
denaturants used provided such denaturants are from a registered
denaturant producer.
---------------------------------------------------------------------------

    Manufacturers of ethanol denaturant that is designated as suitable
for use in the manufacture of DFE that meets federal requirements must
keep records on individual batches of such denaturant including batch
volume, and sulfur content.
    Manufacturers of pentane that is designated as suitable for use for
blending into PCG must keep records on individual batches of such
pentane including batch volume, sulfur content, benzene content, olefin
content, aromatic content, C6 and higher hydrocarbon content, and
purity as applicable.
    Manufacturers of gasoline additives for use in highway vehicles
must keep records on individual batches of such additives including
batch volume and additive production quality control activities which
demonstrate that the sulfur content of additive production batches
complies with the Tier 3 sulfur requirements. We expect that such
records would include the results of periodic sulfur testing but not
necessarily testing on each production batch.

    All parties in the gasoline, DFE, ethanol denaturant, pentane, and
gasoline additive production and distribution system subject to the
Tier 3 sulfur program are also required to keep records of all PTDs and
records of any quality assurance programs. Records must be retained for
five years. For credit transactions, records must be retained for five
years from the usage date. Records must be made available to EPA on
request; if electronic records are kept, hard copies must be made
available upon request.
    Information submitted to EPA may be claimed as confidential
business information (CBI). Parties making such a claim must follow all
reporting guidance and clearly mark the information being claimed as
proprietary. EPA will treat information covered by such a claim in
accordance with the regulations at 40 CFR part 2 and other Agency
procedures for handling proprietary information.
2. Sampling and Testing Requirements
    Under the Tier 2 program, a sulfur concentration must be determined
for every batch of gasoline. We are retaining this requirement under
the Tier 3 program. As with the existing Tier 2 program, this every-
batch testing requirement will be required to occur prior to the batch
leaving the refinery. We are also retaining the Tier 2 sampling,
testing, and sample retention requirements in today's final rule.
Additionally, as discussed below in Section VI, we have included
performance based measurement standards that will allow refiners to use
alternate test methods for measuring sulfur if they so choose.
    We proposed that manufacturers of DFE would be required to test
each individual batch of DFE for its sulfur content. In response to
comments, we are finalizing an alternative means for DFE manufacturers
to demonstrate compliance with the Tier 3 sulfur requirements in
addition to per batch testing.\438\ We anticipate that DFE
manufacturers will typically use this alternative means in the place of
per batch sulfur testing.
---------------------------------------------------------------------------

    \438\ The alternative means of demonstrating compliance with the
Tier 3 sulfur requirements for DFE manufacturers is discussed in
section V.G. of this preamble.
---------------------------------------------------------------------------

    As discussed above, manufacturers of additives for use in highway
gasoline vehicles must maintain records of additive production quality
control activities which demonstrate that the sulfur content of
additive production batches complies with the Tier 3 sulfur
requirements. We expect that periodic sulfur testing will be needed to
comply with this requirement but not necessarily testing on each
additive production batch. Manufacturers of pentane that is designated
as suitable for use by blenders into PCG must test every batch to
demonstrate compliance with the requirements sulfur content, benzene
content, olefin content, aromatic content, C6 and higher hydrocarbon
content, and purity as applicable. Blenders of pentane into gasoline
must conduct periodic sampling and testing of the pentane they receive
from each separate pentane supplier to demonstrate that the pentaene is
compliant with the applicable compositional requirements.
3. Small Refiner Compliance
    To qualify for small refiner status under the Tier 3 program, a
refiner must apply by June 1, 2016. As with our other existing EPA
fuels programs, we are continuing to use the Small Business
Administration definition of a small refiner: 1,500 employees (company-
wide). To qualify for small refiner status under Tier 3, a small
refiner must also meet the following additional criteria:
     The refiner must have produced gasoline from crude oil
during the 2012 calendar year.
     The refiner must have owned and operated the refinery
during the period from January 1, 2012 through December 31, 2012. New
owners that purchased a refinery after that date will have done so with
full knowledge of the proposed Tier 3 regulations, and should have
planned to comply along with their purchase decisions. As with existing
fuel programs, a refiner that restarts a refinery in the future may be
eligible for small refiner status. Thus, a refiner restarting a
refinery that was shut down or non-operational during calendar year
2012 can apply for small refiner status. In such cases, we will judge
eligibility under the employment and crude oil capacity criteria based
on the most recent 12 consecutive months prior to the application,
unless we conclude from data provided by the refiner that another
period of time is more appropriate. However, this is limited to a
company that owned the refinery at the time that it was shut down. New
purchasers will not be eligible for small refiner status for the same
reasons described above.
     The refiner must have had 1,500 employees or less based on
the average number of employees for all pay periods from January 1,
2012 through December 31, 2012 for all subsidiaries, parent companies
(i.e., any company or companies with controlling interest), and joint
ventures.
     The refiner must have had a crude oil capacity less than
or equal to 155,000 bpcd during the 2012 calendar year.
    A refiner applying for small refiner status must apply and provide
EPA with several types of information, as specified in the regulations,
by June 1, 2016. All refiners seeking small refiner status under this
program must apply for small refiner status, regardless of whether the
refiner has been approved for small refiner status under another fuel
program. As with applications for relief under other rules,
applications for small refiner status under this final rule that are
later found to contain false or inaccurate information will be void ab
initio.
    Requirements for small refiner status applications:
     The total crude oil capacity as reported to the Energy
Information Administration (EIA) of the U.S. Department of Energy (DOE)
for the most recent 12 months of operation. This includes the capacity
of all refineries controlled by a refiner and by all subsidiaries and
parent companies and joint ventures. We will presume that the
information submitted to EIA is correct. (In cases where a company
disagreed with this information, the company may petition EPA with
appropriate data to correct the record when the company submitted its
application for small refiner status. EPA will accept such alternate
data at its discretion.)
     The name and address of each company location where
employees worked during the 2012 calendar year; and the number of
employees at each location during this time period. This includes the
locations and number of employees working at all subsidiaries, parent
companies, and joint ventures.
     In the case of a refiner who reactivates a refinery that
was either shutdown or non-operational from January 1, 2012 through
December 31, 2012, the name and address of each company location where
employees worked since the refiner reactivated the refinery and the
average number of employees at each location for each calendar year
since the refiner reactivated the refinery.
     The type of business activities carried out at each
location.
     Contact information for a corporate contact person,
including: name, mailing address, phone and fax numbers, email address.
     A letter signed by the president, chief operating officer,
or chief executive officer of the company (or a designee) stating that
the information contained in the application is true to

the best of his/her knowledge and that the company owned the refinery
as of January 1, 2012.
    An approved small refiner that exceeds the employee count or crude
capacity criteria due to merger with, acquisition by, or the
acquisition of another entity will lose its small refiner status. In
situations where a small refiner loses its small refiner status due to
merger with a non-small refiner, acquisition of another refiner, or
acquisition by another refiner, we are finalizing provisions that are
similar to those in our existing fuels programs to allow up to an
additional 30 months of lead time to comply with the Tier 3 program
after the disqualifying event, but no later than December 31,
2019.\439\ This 30 months of additional lead time will only apply to
refineries that were previously subject to small refiner relief, as we
believe there will be no adverse environmental impact because of the
pre-existing relief provisions that applied to the small refiner. A
refiner will also lose its small refiner status if it ceases to process
crude oil.
---------------------------------------------------------------------------

    \439\ See, for example, 69 FR 39051 (June 29, 2004).
---------------------------------------------------------------------------

    Our intent has been, and continues to be, limiting the small
refiner relief provisions to a small subset of refiners that are
challenged, as discussed above. However, it is also our intent to avoid
stifling normal business growth. Therefore, an approved small refiner
who exceeds the employee count or crude oil capacity criteria through
normal business practices may retain its small refiner status. Further,
in the sole case of a merger between two approved small refiners, such
refiners will be permitted to retain their individual small refiner
status. Additional financial resources would not typically be provided
in the case of a merger between two small refiners. Small refiner
status for the two entities of the merger would not be affected; hence
the original compliance plans of the two refiners should not be
impacted. Moreover, no environmental detriment will result from the two
small refiners maintaining their small refiner status within the merged
entity as they would have likely maintained their small refiner status
had the merger not occurred.
4. Small Volume Refinery Compliance
    In the case of small volume refineries, the application process for
qualification is similar to that of a small refiner. A refiner that is
both a small refiner and owns a small volume refinery need not apply
for small volume refinery status; the small refiner application is all
that is needed. Small refineries must have a net crude throughput
threshold of no more than 75,000 bpcd based on the highest throughput
in calendar years 2011 or 2012 as the basis for receiving small volume
refinery status.
    Refiners must include the following in their applications for small
volume refinery status:
     Proof that the refiner produced gasoline from crude oil
during the 2012 calendar year.
     Proof that the refiner owned and operated the refinery
during the period from January 1, 2012 through December 31, 2012.
     The refinery's total crude throughput as reported to EIA
for each of calendar years 2011 and 2012. Again, we will presume that
the information submitted to EIA is correct. In cases where a refiner
disagrees with this information, the refiner may petition EPA with
appropriate data to correct the record when the refiner submits its
application for small volume refinery status. EPA will accept such
alternate data at its discretion.
     Contact information for a corporate contact person,
including: name, mailing address, phone and fax numbers, email address.
     A letter signed by the president, chief operating officer,
or chief executive officer of the company (or a designee) stating that
the information contained in the application is true to the best of
his/her knowledge and that the company owned the refinery as of January
1, 2012.
5. Attest Engagements, Violations, and Penalties
    In today's final rule we are retaining the existing Tier 2
requirements for attest engagements for generation of both early and
standard credits, use of credits, and compliance with the proposed
program, using the procedures currently used in existing EPA fuels
programs for attest engagements. The violation and penalty provisions
applicable to today's Tier 3 program will be very similar to the
provisions currently in effect in other gasoline programs as well.
6. Special Fuel Provisions and Exemptions
    The following paragraphs discuss several provisions and exemptions
from the Tier 3 gasoline sulfur standards in special circumstances.
a. Gasoline Used in Military Applications
    In both our diesel fuel program and the Tier 2 gasoline sulfur
program, we provided an exemption for fuel used in tactical military
vehicles and nonroad engines and equipment with a national security
exemption (NSE) from the vehicle and engine emissions standards. Due to
national security considerations, some of EPA's existing regulations
allow the military to request and receive NSEs for vehicles, engines,
and equipment from emissions regulations if the operational
requirements for such vehicles, engines, or equipment warrant such an
exemption. Fuel used in these applications is also exempt if it is used
in tactical military vehicles, engines, or equipment that are not
covered by an NSE but, for national security reasons (such as the need
to be ready for immediate deployment overseas), need to be fueled on
the same fuel as those with an NSE. We are including this exemption in
the Tier 3 gasoline program.
b. Gasoline Used in Research, Development, and Testing
    Similar to existing EPA fuels programs, we are finalizing
provisions to allow for requests for an exemption from the Tier 3
standards for gasoline used for research, development, and testing
purposes (``R & D exemption''). We recognize that there may be
legitimate research programs that require the use of gasoline with
sulfur levels greater than those allowed under the Tier 3 program.
Thus, we are including provisions for obtaining an exemption from the
prohibition against persons producing, distributing, transporting,
storing, selling, or dispensing gasoline that does not meet the Tier 3
gasoline sulfur standards, where such fuel is necessary to conduct a
research, development, or testing program.
    Parties seeking an R & D exemption must submit an application for
exemption to EPA that describes the purpose and scope of the program,
and the reasons why the noncompliant gasoline is necessary. Upon
presentation of the required information, an exemption may be granted
at the discretion of EPA, with the condition that EPA can withdraw the
exemption in the event the Agency determines the exemption is not
justified. In addition, an exemption based on false or inaccurate
information will be considered void ab initio. Gasoline subject to an
exemption will be exempt from certain provisions of this rule,
including the sulfur standards, provided certain requirements are met.
These requirements include the segregation of the exempt gasoline from
non-exempt gasoline, identification of the exempt gasoline on PTDs, and
pump labeling.

c. Gasoline for Export
    Gasoline produced for export, and that is actually exported for use
in a foreign country, will be considered exempt from the fuel content
standards and other requirements of the Tier 3 gasoline sulfur program.
In order to exclude exported gasoline, refiners must retain records to
demonstrate that the gasoline was exported. Such gasoline must be
designated by the refiner, and the PTD must state that the gasoline is
for ``export only''; otherwise, the gasoline will be considered as
intended for use in the U.S. and subject to the Tier 3 standards.
Gasoline intended for export must be segregated from all gasoline
intended for use in the U.S. Distributing or dispensing such fuel for
domestic use will be illegal.
d. Other Special Provisions and Exemptions
    Additionally, in existing EPA fuels programs we have included
exemptions for racing fuel and for fuel used in the U.S. territories of
Guam, American Samoa, and the Northern Mariana Islands; we are
finalizing such exemptions for the Tier 3 program as well.

G. Standards for Oxygenates (Including Denatured Fuel Ethanol) and
Certified Ethanol Denaturants

    The following discussion is focused on the standards finalized
today for denatured fuel ethanol (DFE) because DFE is the predominant
gasoline oxygenate currently in-use.\440\ These standards also apply to
other gasoline oxygenates.\441\
---------------------------------------------------------------------------

    \440\ An importer of biofuels commented that EPA should clarify
that the standards for DFE will apply to importers as well as
domestic producers. The regulations finalized today specifically
state that the standards for denatured fuel ethanol apply to
importers are will as domestic producers of DFE.
    \441\ Public comments supported our proposal to apply the same
standards to all gasoline oxygenates.
---------------------------------------------------------------------------

1. Sulfur Standard
    The Tier 2 gasoline requirements include the prohibition on
blending gasoline with DFE that has sulfur content higher than 30
ppm.\442\ This requirement reflects the 30 ppm refinery gasoline
average sulfur requirement under the Tier 2 program. Consistent with
the approach under the Tier 2 program and our proposed 10 ppm refinery
average sulfur standard for gasoline under the Tier 3 program, we
proposed that producers of DFE for use by oxygenate blenders would be
required to meet a 10 ppm sulfur cap beginning January 1, 2017. We
proposed requiring DFE producers to test each batch of DFE to
demonstrate compliance with the sulfur content standard, and to retain
and provide batch reports to EPA.
---------------------------------------------------------------------------

    \442\ 40 CFR 80.385(e).
---------------------------------------------------------------------------

    The Renewable Fuels Association (RFA) commented that if EPA were to
accept current industry practices used to assure that DFE is compliant
with the state of California's 10 ppm sulfur cap for DFE in place of
per-batch sulfur testing and reporting there would be no additional
burden to ethanol producers in meeting a 10 ppm sulfur cap.\443\ In
2002, RFA conducted an industry survey that demonstrated DFE
manufacturers were meeting California's 10 ppm maximum sulfur content
requirement. Since then, RFA has recommended to the ethanol industry
that all DFE meet this California requirement and indicated that
ethanol producers are adhering to this recommendation. Other commenters
also stated that DFE manufacturers have been producing DFE that
complies with California specifications because of logistical
difficulties in segregating ethanol destined for California from other
destinations.
---------------------------------------------------------------------------

    \443\ RFA requested regulatory relief from the proposed batch
testing and reporting requirements as discussed in preamble Section
V.G.4.
---------------------------------------------------------------------------

    An environmental organization commented that the proposed 10 ppm
sulfur cap for DFE was necessary to ensure that the Tier 3 program
benefits are actually realized. Refiners commented that requiring DFE
to meet a 10 ppm sulfur cap was essential to facilitating their
compliance with the Tier 3 gasoline sulfur requirements. In
demonstrating compliance with the 10 ppm average gasoline sulfur
standard finalized today, gasoline refiners and importers may adjust
the sulfur levels in the gasoline and BOBs that they produce/import to
account for the downstream addition of ethanol.\444\ Therefore, the
sulfur level of DFE has a direct effect on the extent of the
desulfurization measures that a refiner/importer will have to undertake
to comply with the gasoline sulfur standards finalized today. A refiner
commented that if the sulfur standard for DFE was left at its current
level of 30 ppm, greater capital investments would be needed to adjust
and lower the sulfur content of other gasoline blending streams to
prevent violation of the ultimate 10 ppm annual average standard.
---------------------------------------------------------------------------

    \444\ Accounting for the effect of oxygenate added downstream of
the refinery or import facility in demonstrating compliance with the
average gasoline sulfur standard is addressed in regulations
finalized today at Sec.  80.1603(d). See Section V.C. in today's
preamble regarding the sulfur level in DFE that must be used by
refiners and importers in making this compliance determination.
---------------------------------------------------------------------------

    Some ethanol producers and Growth Energy (representing ethanol
producers) commented that DFE should be subject to an annual average
sulfur standard and be able to participate in the averaging banking and
trading (ABT) program that is available to refiners and importers of
gasoline. Some ethanol producers commented that they should be allowed
to participate in the ABT program as a means of offsetting the
additional cost of the proposed per-batch sulfur testing and reporting
requirements.
    EPA believes that requiring DFE to comply with a 10 ppm sulfur cap
is the most appropriate means of ensuring that finished gasoline blends
attain the sulfur control goals of the Tier 3 program. Therefore,
today's rule finalizes a 10 ppm sulfur cap for DFE. Because essentially
all (if not all) DFE already meets California's 10 ppm sulfur standard,
EPA believes that the implementation of a federal 10 ppm sulfur cap for
DFE would not result in a significant increased burden for ethanol
producers.\445\ Neat ethanol produced with standard quality control
practices should have negligible sulfur content. Denaturants with
sufficiently low-sulfur content to facilitate compliance with the 10
ppm sulfur cap for DFE are widely available. Allowing DFE to exceed 10
ppm would result in the use of higher-sulfur denaturants, thereby
increasing gasoline refiner capital costs to install desulfurization
equipment. As discussed in Section V.D.3 of this preamble, there are
several reasons why we do not believe that it is appropriate to expand
the ABT provisions to include ethanol producers and importers.
Furthermore, as discussed in Section V.G.4, sulfur testing on each
batch of DFE will not be required provided that the DFE producer or
importer demonstrates compliance with the 10 ppm sulfur cap for DFE
with volumetric blending records, whereas an average standard would
require testing of every batch. We anticipate that DFE producers and
importers will typically choose to demonstrate compliance with the 10
ppm sulfur cap using volumetric blending records rather than per-batch
sulfur testing. Therefore, we do not anticipate that DFE producers and
importers will need to install additional sulfur testing equipment as a
result of today's rule. Hence, there is no need to extend the
flexibility of meeting an annual average sulfur standard and
participation in the ABT program to

ethanol producers and importers to help facilitate their compliance as
exists for gasoline refiners.\446\
---------------------------------------------------------------------------

    \445\ The potential for additional burden associated with
demonstrating compliance with a 10 ppm sulfur cap is discussed in
Section V.G.4.
    \446\ See Section V.D.3. of this preamble for additional
discussion of why we are not extending the sulfur averaging,
banking, and trading program to cover DFE manufacturers.
---------------------------------------------------------------------------

    Comments were supportive of the proposed January 1, 2017
implementation date for standards applicable to DFE. Today's action
requires that importers and manufacturers of DFE comply with the
standards finalized today beginning January 1, 2017.
2. Limitation on the Type of Ethanol Denaturant
    To limit the variability in DFE composition and the associated
potential impact on vehicle emissions, we proposed to allow the use of
only certified gasoline, gasoline blendstocks for oxygenate blending
(BOBs), and natural gasoline as denaturants. Commenters stated that it
would be unnecessary to place additional limits on the types of
denaturants that could be used beyond those in the ASTM specification
for DFE. Groups representing refiners stated that EPA had not presented
data to support that additional limitations on the types of denaturants
that can be used (or the allowed concentrations at which they may be
used) are needed beyond those adopted by ASTM and the State of
California to address concerns about the potential adverse impacts on
vehicle emissions performance. The ASTM specification for DFE requires
that the only denaturants that can be used are gasoline, gasoline
blendstocks, and natural gasoline. The State of California incorporated
the ASTM limits on allowable denaturants into its regulations for DFE
by reference.\447\ Thus, both ASTM and the State of California allow
the use of gasoline blendstocks other than BOBs as denaturants. One
refiner stated that DFE producers have used refinery gasoline
blendstocks such as ``light straight run'' and ``light naphtha'' as
denaturants and that removing this flexibility would increase DFE
production costs. They noted that access to this flexibility could
become more important under a 10 ppm sulfur cap for DFE. In addition to
needing to preserve the flexibility to use a range of gasoline
blendstocks, ethanol manufacturers stated that EPA should consider the
possibility of approving denaturants that are not currently allowed
under the ASTM specification for DFE. One refiner stated that ASTM is
the appropriate technical forum for the consideration of adding new
allowable denaturants.
---------------------------------------------------------------------------

    \447\ The California Code of Regulations references ASTM D 4806-
99 which limits the allowed denaturants to gasoline, gasoline
components, and natural gasoline.
---------------------------------------------------------------------------

    EPA continues to believe that it is appropriate to implement
additional controls to address the potential impact of fuel components
in denaturants other than sulfur on vehicle emissions. However, we
agree with the comments that it is not appropriate to implement
additional controls on the types of denaturants that may be used beyond
those currently adopted by ASTM and the State of California at this
time. Therefore, in response to comments, today's rule includes the
requirement that only gasoline, gasoline blendstocks, and natural
gasoline may be used to denature DFE.\448\ This requirement is
essentially the same as the current ASTM and State of California
specifications for the type of denaturants that may be used. We will
continue to monitor the potential need for additional controls on
ethanol denaturants, and may revisit this issue in the context of
setting in-use quality specifications for E85 in the future.\449\ We
will also continue to monitor the need for additional denaturants, and
when appropriate EPA may undertake a future rulemaking to consider
allowing their use.
---------------------------------------------------------------------------

    \448\ Finished gasoline used as denaturant must be compliant
with the applicable EPA requirements.
    \449\ See Section V.H. for a discussion of potential FFV in-use
fuel quality requirements.
---------------------------------------------------------------------------

    As discussed in Section V.G.4, in order for DFE producers and
importers to take advantage of streamlined provisions for demonstrating
compliance with the 10 ppm sulfur cap for DFE, they must only use
denaturants from registered producers that have been demonstrated as
meeting EPA compositional requirements. Denaturants from unregistered
denaturant producers may be used by DFE producers provided that they
test each batch of DFE to demonstrate compliance with the 10 ppm sulfur
cap for DFE.
3. Limitation on Ethanol Denaturant Concentration
    To further limit the potential impact on vehicle emissions of fuel
parameters in ethanol denaturants other than sulfur, we proposed to
limit denaturant concentration in DFE to a maximum of 2 volume percent,
which translates to 2.5 volume percent considering rounding. We also
requested comment on alternately adopting the additional fuel
specifications currently in force for DFE in the State of California.
While California allows a maximum denaturant content of 5 volume
percent consistent with the industry consensus ASTM International
(ASTM) specification for DFE, they also have maximum specifications for
benzene, olefins, and aromatics as well as sulfur.\450\
---------------------------------------------------------------------------

    \450\ California Code of Regulations 13 CCR section 2262.9. ASTM
International D4806-13a, ``Standard Specification for Denatured Fuel
Ethanol for Blending with Gasolines for Use as Automotive Spark-
Ignition Engine Fuel''.
---------------------------------------------------------------------------

    A number of refiners and ethanol manufacturers stated that it was
unnecessary to limit denaturant concentration beyond the 5 volume
percent specified by ASTM. Ethanol manufacturers stated that the RFS2
program requirement that DFE contain no more than 2 volume percent
denaturant for Renewable Identification Number (RIN) generation
purposes already provides a strong incentive to keep denaturant
concentration under 2 percent.\451\ However, they stated that the
flexibility to have a slightly higher denaturant content can be
important to ethanol producers. One ethanol producer stated that the
proposed maximum 2 volume percent cap on denaturant concentration would
provide insufficient tolerance given that the Alcohol and Tobacco Tax
and Trade Bureau requires a 1.96 percent minimum denaturant
concentration.\452\ They stated that EPA should provide a more
reasonable tolerance to avoid inadvertent compliance issues.
---------------------------------------------------------------------------

    \451\ This RFS2 program provision is covered under the
definition of renewable fuel/ethanol in 40 CFR 80.1401. The volume
of denaturant used in excess of 2 volume percent must be subtracted
from the total volume of DFE for RIN generation purposes.
    \452\ Alcohol and Tobacco Tax and Trade Bureau formulas require
a minimum of two parts of approved denaturant to 100 parts of
ethanol with a minimum of 195 proof ethanol.: 27 CFR Subpart X,
Distilled Spirits for Fuel Use; ASTM International D4806-13a,
``Standard Specification for Denatured Fuel Ethanol for Blending
with Gasolines for Use as Automotive Spark-Ignition Engine Fuel''.
---------------------------------------------------------------------------

    A number of refiners stated that the current 5 volume percent
maximum on denaturant concentration established by ASTM would limit
concerns regarding components other than sulfur so that they would be
unlikely to impact vehicle emissions performance. One refiner stated
that EPA should adopt the entire California specifications for DFE in
order to address concerns about potential emissions impacts of fuel
components in denaturants other than sulfur. They stated that this
would not impose an additional burden on DFE producers since logistical
difficulties in segregating ethanol destined for California from other
destinations has already caused producers to DFE to California
specifications.

    Since we are not finalizing benzene, olefin, or aromatics
specifications for ethanol denaturants like California, we continue to
believe that it is appropriate to implement a more stringent limit on
maximum denaturant concentration to address concerns about the
potential impact on vehicle emissions of fuel parameters in ethanol
denaturants other than sulfur. Setting a more stringent limit on
denaturant concentration will ensure that harmful components such as
benzene potentially present in ethanol denaturants are adequately
diluted in the finished fuel blend. We agree with comments that it is
appropriate to provide additional flexibility for the allowable
denaturant levels that may be used. Therefore, we are finalizing a 3.0
volume percent maximum on ethanol denaturant concentration. This
approach provides sufficient flexibility to DFE producers while
avoiding the need to impose additional testing burdens on denaturant
and DFE producers (e.g., for benzene and aromatics). We will consider
whether additional controls may be needed for mid-level ethanol blends
and E85 in a later action.
4. Demonstration of Compliance With the Sulfur Requirements and
Requirements for Certified Ethanol Denaturants
    To demonstrate compliance with the 10 ppm sulfur cap finalized
today, we proposed that producers and importers of DFE would be
required to test the sulfur content of each batch of DFE they produce.
We also proposed that DFE producers would be required to provide batch
records to EPA on an annual basis. We requested comment on whether to
require producers of denaturants for use in DFE to register with EPA
and to demonstrate compliance with a maximum sulfur specification based
on the anticipated dilution with ethanol.
    Refiners stated that producers of DFE should be subject to
requirements similar to those for gasoline refiners including batch
sampling. However, refiners stated there would be no added value in
requiring batch reports from DFE producers. Ethanol producers currently
use certificates of sulfur analysis from denaturant producers and
volumetric DFE blending records to assure themselves that when a sample
of DFE is tested by the State of California that it will be found to be
compliant with a 10 ppm sulfur cap.\453\ They stated that EPA should
accept such records to demonstrate compliance with the federal 10 ppm
sulfur cap for DFE in place of per-batch sulfur testing on DFE. Under
this approach, ethanol producers would maintain records regarding the
denaturant sulfur content and the calculations used to determine the
sulfur content of the finished DFE. Because the sulfur content of neat
(un-denatured) ethanol manufactured using industry standard quality
control practices should be negligible, the sulfur content of DFE is
effectively determined by the sulfur content of denaturant used.\454\
Ethanol producers stated that they would also perform standard quality
assurance activities including sampling incoming shipments of
denaturant for sulfur content on a periodic basis.
---------------------------------------------------------------------------

    \453\ The State of California does not rely on industry testing
and recordkeeping to help establish compliance with their sulfur
requirements for DFE, instead choosing to focus on direct testing
that they conduct. EPA relies on the review of industry records
including those associated with tesing conducted by industry as well
as direct testing conducted by EPA for compliance assurance.
    \454\ Ethanol manufacturers conduct periodic sulfate testing on
neat ethanol to ensure that sulfur contamination from the
manufacturing process is negligible.
---------------------------------------------------------------------------

    Ethanol producers stated that many DFE production facilities do not
have on site sulfur testing equipment and the installation of such
equipment would represent a substantial burden to DFE producers.
Ethanol producers stated that they had worked with denaturant producers
to ensure access to a low-sulfur stream of denaturants, and that it is
common business practice for denaturant producers to provide them with
information on the sulfur content of their product. Ethanol producers
stated that sulfur test results from the ASTM Inter-laboratory
Crosscheck Program (ILCP) for DFE illustrate that batch reporting for
DFE is unnecessary. They noted that the ILCP data shows DFE typically
has sulfur content of 1 to 5 ppm.
    Ethanol producers stated that requiring denaturant manufacturers to
register with EPA would limit the number of denaturant suppliers
willing to supply the ethanol industry. They stated that it is
inappropriate to require a natural gasoline producer to register in
order to supply product for DFE, because they are not required to
register in order to supply the same product to a gasoline blender.
    EPA agrees that is appropriate to finalize requirements for the
demonstration of compliance with the 10 ppm sulfur cap for DFE that are
based on current industry practices rather than requiring sulfur
testing on each batch of DFE.\455\ We agree that that potential
contribution to the sulfur content of DFE other than from the addition
of denaturants can be adequately addressed by the retention of
production quality control records by the ethanol manufacturer. We
agree that it is most appropriate to place the primary focus of
compliance assurance on the denaturant manufacturers given the
denaturant typically contributes the majority of the sulfur to the
finished DFE. Therefore, we are finalizing streamlined provisions that
DFE producers and importers may use in demonstrating compliance with
the 10 ppm sulfur cap for DFE as an alternative to testing each batch
of DFE for its sulfur content. These streamlined provisions are based
on the use of denaturant batch sulfur testing conducted by denaturant
producers who have registered with EPA and certified the denaturant
they produce as meeting EPA requirements.\456\ Uncertified denaturants
from unregistered denaturant producers may be used by DFE producers
provided that they test each batch of DFE to demonstrate compliance
with the 10 ppm sulfur cap for DFE.\457\
---------------------------------------------------------------------------

    \455\ Per-batch sulfur testing for other potential oxygenates
will be required to demonstrate compliance with the 10 ppm sulfur
cap. EPA may consider amending the requirements for other potential
oxygenates in a later rulemaking based on additional information
that we might receive.
    \456\ Certified denaturant producers and importers will be
required to register with EPA as a certified denaturant producer or
importer by November 1, 2016, or 60 days before introducing
certified denaturant into commerce, whichever is earlier.
    \457\ The limitation on the types of denaturants that may be
used and the maximum concentration at which a denaturant may be used
discussed in Section V.G.2 and 3 would apply regardless of whether a
denaturant from a registered or non-registered denaturant
manufacture are used.
---------------------------------------------------------------------------

    DFE manufacturers that use denaturants that have been certified and
designated on the denaturant product transfer document (PTD) as
suitable for use in the manufacture of DFE that meets federal
requirements will be able use PTDs for the denaturants used and
volumetric blending records which show that the denaturant was added at
3.0 volume percent or less in demonstrating compliance with the 10 ppm
sulfur cap for DFE in lieu of per-batch sulfur testing of DFE. The
sulfur content of ``neat'' (i.e. un-denatured) ethanol may be assumed
to be negligible for the purposes of demonstration of compliance using
volumetric blending records provided that the DFE manufacturer
maintains quality control records that demonstrate this assumption is
justified. Today's rule also requires that DFE manufacturers conduct
quality assurance to demonstrate affirmative defenses to

presumptive liability.\458\ Producers and importers of DFE must
initiate a PTD to accompany each batch of DFE which states that it
meets federal standards.
---------------------------------------------------------------------------

    \458\ Such quality assurance practices include periodic
calibration of the denaturant blending equipment to ensure that
denaturants are not added in excess of 3.0 volume percent.
---------------------------------------------------------------------------

    Denaturant manufacturers are accustomed to providing certificates
of sulfur analysis to DFE manufacturers. Therefore, we believe that the
requirements finalized today for denaturant manufacturers to conduct
per-batch sulfur testing, initiate a product transfer document stating
that denaturant is suitable for use in manufacturing DFE that meets
federal requirements, retain records, and register with EPA will not
represent a substantial new burden. DFE manufacturers who use the
mathematical method to demonstrate compliance with DFE sulfur
requirements must only use certified denaturants from registered
denaturant manufacturers. Registering with EPA will be a one-time act,
as will be the necessary modifications to denaturant product transfer
documents. Thus, the requirement to register with EPA should not be a
serious impediment for a manufacturer to enter the denaturant supply
market. We believe that it is necessary to require denaturant
manufacturers to register with EPA in order to facilitate compliance
oversight. EPA needs to be able to identify all manufacturers of
denaturants in order to periodically audit their records, and to
recognize potential denaturants in the system that are incorrectly
designated as a certified denaturant appropriate for use in
manufacturing DFE that meets federal sulfur requirements. Denaturant
manufacturers that supply their product to refiners for use in the
manufacture of gasoline are not required to register with EPA because,
unlike the DFE manufacturers, refiners are responsible for testing the
final gasoline they produce.
    As is current practice today, we anticipate that ethanol
manufacturers will negotiate the specific sulfur level they require
from denaturant manufacturers to facilitate compliance with the 10 ppm
sulfur cap for DFE taking into consideration what level of compliance
margin a given manufacturer feels is necessary. We believe that it is
appropriate to allow this practice to continue. We understand that
ethanol manufacturers currently require denaturant manufacturers to
provide a product with a sulfur content of 120 ppm or less in order to
ensure that DFE that contains 5 volume percent denaturant can comply
with California's 10 ppm sulfur cap for DFE. Thus, we expect that
denaturant manufacturers will not need to change the sulfur content of
the denaturant they manufacture in order to comply with the
requirements finalized today.
    Manufacturers of certified denaturants used by DFE producers that
employ the volumetric blending record method in demonstrating
compliance with the sulfur requirements for DFE must retain per batch
sulfur test data on the denaturants they produce to demonstrate that
the sulfur content of the denaturant will not cause the sulfur content
of DFE to exceed 10 ppm when added to neat ethanol at 3.0 volume
percent. The sulfur content of the certified denaturant must be stated
on the PTD and must be no greater that 330 ppm. Any sample of
denaturant which is designated as appropriate for use in manufacturing
DFE that meets federal requirements, that is found by EPA to have
sulfur content above 330 ppm will be deemed to be noncompliant, and the
denaturant manufacturer may be liable for the associated penalties. A
denaturant with a sulfur content of 330 ppm when used at 3.0 volume
percent would result in a sulfur content of the finished DFE of 10 ppm.
Certified denaturant manufacturers may represent the denaturant they
produce as having a sulfur content of less then 330 ppm on the PTD. In
such cases, the denaturant batch must not exceed the sulfur content
stated on the PTD.
    We continue to believe that annual reports from oxygenate producers
are important enforcement and compliance assurance tool. Therefore, we
are finalizing the requirement that producers and importers of DFE and
other oxygenates must register with EPA as and oxygenate producer or
importer and submit annual reports to EPA that include the total volume
of DFE/oxygenate produced and an attestation that all batches met the
proposed fuel quality requirements.\459\
---------------------------------------------------------------------------

    \459\ Oxygenate producers and importers will be required to
register with EPA as an oxygenate producer or importer by November
1, 2016, or 60 days before introducing certified denaturant into
commerce, whichever is earlier.
---------------------------------------------------------------------------

5. Additional Requirements for Denatured Fuel Ethanol, Ethanol
Denaturants, and Other Gasoline Oxygenates
    We are finalizing regulatory text to clarify that DFE and other
gasoline oxygenates must be composed solely of carbon, hydrogen,
oxygen, nitrogen, and sulfur. Manufacturers of denaturants that are
designated as suitable for use in the manufacture of DFE that meets
federal requirements will also be required to attest that the
denaturant is composed solely of carbon, hydrogen, oxygen, nitrogen,
and sulfur.
    Producers and importers of gasoline oxygenates, producers and
importers of denaturants designated as suitable for manufacturing DFE
meeting federal sulfur requirements, fuel distributors, and oxygenate
blenders will be required to maintain the applicable records for 5
years and provide them to EPA upon request.

H. Standards for Fuel Used in Flexible Fueled Vehicles

    Flexible fuel vehicles (FFVs) are vehicles that are capable of
operating on both gasoline and gasoline blends containing up to 83
volume percent ethanol. Ethanol fuel blends that contain from 51 and 83
volume percent ethanol (E51-83) have historically been referred to as
``E85'' in reference to the maximum allowed content of denatured
ethanol assuming a 2 percent denaturant concentration.\460\ Fuel blends
that contain from 16 to 50 percent ethanol (E16-50) are sometimes
referred to as mid-level ethanol blends. Both E51-83 and E16-50 are
currently used only in FFVs.
---------------------------------------------------------------------------

    \460\ Industry consensus standards for E51-83 are described in
ASTM International D5798-13, ``Standard Specification for Ethanol
Fuel Blends for Flexible-Fuel Automotive Spark-Ignition Engines''.
---------------------------------------------------------------------------

    Whether FFVs are operating on clear gasoline (E0), E85, or any
level of ethanol in between, to maintain emission performance the
vehicles still need fuel that meets certain quality specifications,
such as the 10 ppm average gasoline sulfur standard finalized today. We
anticipate that the use of higher level ethanol blends in FFVs will
continue to increase in the future as the RFS program continues to be
implemented. Significant public and private initiatives are also
currently underway to expand the use of ethanol blender pumps that
dispense a variety of ethanol blends for use in FFVs.\461\ Therefore it
is becoming increasingly important that all fuels used in FFVs, not
just gasoline, meet fuel quality standards. The lack of separate fuel
quality standards that apply to fuels used in FFVs could act to impede
the further expansion of ethanol blended fuels, which is important to
satisfying the requirements of the RFS program. For these reasons, we
believe it is

important that our gasoline quality standards for not just sulfur, but
also benzene, Reid Vapor Pressure (RVP), detergency, and compliance
with the interpretive rule defining the phrase ``substantially
similar'' in CAA section 211(f)(1) \462\ (i.e., contain only carbon,
hydrogen, oxygen, nitrogen, and sulfur) apply to any fuel used in an
FFV.
---------------------------------------------------------------------------

    \461\ The U.S. Department of Agriculture (USDA) has a program to
assist in the funding for the installation of as many as 10,000
ethanol blender pumps over the next 15 years in rural areas. Growth
Energy has a ``Blend Your Own Ethanol'' program to encourage the
installation of ethanol blender pumps.
    \462\ 73 FR 22277, 22281 (April 25, 2008).
---------------------------------------------------------------------------

    Our various standards for gasoline currently apply to any fuel sold
for use in motor vehicles, which is commonly or commercially known or
sold as gasoline. In the fuel and fuel additive registration program,
the gasoline family includes fuels composed of at least 50 percent
clear gasoline by volume.\463\ As a result, our gasoline standards
currently apply to E16-50 ethanol blends. However, additional
regulatory provisions could be useful to facilitate compliance
assurance if we are to continue to treat such mid-level ethanol blends
as gasoline.
---------------------------------------------------------------------------

    \463\ 40 CFR 79.56(e)(1)(i).
---------------------------------------------------------------------------

    The existing requirement that E51-83 must be substantially similar
(sub-sim) to the vehicle certification test fuel has provided a limited
measure of control over in-use E51-83 fuel quality. The finalization of
specifications for FFV exhaust emission test fuel in today's action
will provide improved clarity regarding what constitutes sub-sim for
in-use E51-83. However, these specifications are not sufficient to
provide clarity as to what is considered sub-sim for E51-83. For
example, E51-83 manufactured using only gasoline, gasoline blendstocks
for oxygenate blending (BOBs), a limited volume of butane that meets
the standards for downstream blending into gasoline, and denatured fuel
ethanol that meets the standards finalized today would clearly be sub-
sim. However, use of natural gasoline may or may not result in an E51-
83 blend that is sub-sim. In addition to the need for additional
clarity regarding what constitutes sub-sim for E51-83, standards for
sulfur, benzene, and RVP are needed to ensure fuel quality supports the
attainment of our environmental goals.
    At proposal, we sought comment on appropriate regulatory mechanisms
to implement in-use quality standards for E51-83 and E16-50. We
requested specific comment on possible approaches, including draft
regulations, which were described in detail in a memorandum to the
docket.\464\ The draft regulations contained fuel quality
specifications for E51-83 and two options that E51-83 manufacturers
could use to demonstrate compliance. We sought comment on whether the
Agency should continue to treat E16-50 as gasoline and on the need to
clarify existing regulations on the meaning of gasoline as any fuel
that contains 50 percent or more gasoline. Given that E16-50 can only
be used in FFVs, we also sought comment on whether to amend the
regulations to treat E16-50 as an alternative fuel. If EPA were to
treat E16-50 as an alternative fuel rather than gasoline, we sought
comment on whether we should take the same approach for E16-50 as
detailed in the draft regulations for E51-83 with respect to sulfur,
benzene, RVP standards, and substantially similar requirements under
CAA section 211(f).
---------------------------------------------------------------------------

    \464\ Possible Approach to Fuel Quality Standards for Fuel Used
in Flexible-Fuel Automotive Spark-Ignition Vehicles (FFVs),
Memorandum to the docket, Jeff Herzog, April 2013.
---------------------------------------------------------------------------

    We received comments in support of and against our proposal. The
vast majority of comments supported the need for EPA to promulgate in-
use quality standards for these higher level ethanol blends. We also
received a number of detailed productive comments on the draft
regulations. A number of stakeholders also expressed their willingness
to work with EPA to provide supplementary information on issues that
were not addressed at proposal and not contained in their comments. At
this time, we acknowledge that additional work is needed on some issues
and we note that such work could not be accommodated within the
timeline for this Tier 3 final rule. Therefore, we are deferring final
action on these provisions at this time. We will continue to work with
stakeholders in developing in-use fuel quality standards for higher
level ethanol blends following the publication of this final rule.
Subsequently, we may issue a supplementary proposal prior to issuing a
final rule if the additional information we receive from stakeholders
warrants such an action.

I. Sulfur Standards for Purity Butane and Purity Pentane Streams
Blended into Gasoline

    Under the Tier 2 gasoline program, ``purity'' butane blended into
gasoline downstream of the refinery is subject to a 30 ppm sulfur cap
and other specifications regarding its composition.\465\ This is
consistent with the 30 ppm refinery average sulfur standard under the
Tier 2 program. Today's action finalizes the proposed 10 ppm sulfur cap
for purity butane blended into gasoline effective January 1, 2017. This
is consistent with the Tier 3 10 ppm refinery average sulfur
specification finalized today.
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    \465\ 40 CFR 80.82.
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    As discussed in Section VI.A.4 in today's preamble, we are
finalizing provisions to allow ``purity'' pentane to be blended into
gasoline downstream of the refinery that are similar to the existing
provisions for butane blending. This allowance will become effective
June 27, 2014. Until December 31, 2016, a 30 ppm sulfur cap will apply
to purity pentane blended into gasoline consistent with the existing
sulfur cap for purity butane under the Tier 2 program.\466\ Beginning
January 1, 2017, a 10 ppm sulfur cap will apply to purity pentane
blended into gasoline consistent with the butane sulfur standard
finalized today.
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    \466\ Other requirements regarding the composition of purity
pentane will also apply that are similar to those for purity butane.
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    Butane blenders commented that a significant fraction of butane and
pentane might be expected to have sulfur content in excess of 10 ppm
after the Tier 3 gasoline sulfur requirements become effective. To
maintain a stable and adequate supply of butane and pentane for
downstream RVP trimming, butane blenders requested that EPA adopt a 10
ppm sulfur average cap with a 30 ppm sulfur cap.\467\
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    \467\ RVP trimming refers to the practice of adding a limited
amount of butane/pentane to previously certified gasoline at a
terminal so that the finished gasoline is closer to the maximum
applicable volatility standard (summer or winter) than can be
attained at the refinery level.
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    Butane and pentane have an inherently low sulfur content that can
be made to meet a 10 ppm sulfur cap with relatively mild
desulfurization techniques. We anticipate that butane and pentane
suppliers will desulfurize these blendstocks to well below 10 ppm
sulfur as part of their response to the Tier 3 gasoline sulfur
requirements. Therefore, we believe that allowing butane and pentane
used for RVP trimming to exceed a 10 ppm sulfur cap would needlessly
complicate compliance assurance and defer some of benefits of the Tier
3 sulfur requirements.

J. Standards for CNG and LPG

    The vehicle emissions standards finalized today are fuel neutral
(i.e., they are applicable regardless of the type of fuel that the
vehicle is designed to use). There currently are no sulfur standards
for the fuel used in compressed natural gas (CNG) and liquid propane
gas (LPG) vehicles. We requested comment on whether it is necessary for
EPA to establish sulfur standards for CNG and LPG to enable them
meeting more stringent vehicle

emissions standards, and whether a 15 ppm sulfur cap similar to that
established for highway diesel fuel would be appropriate. Comment was
also requested on whether and how to address the sulfur contribution
from odorants and other additives used in CNG and LPG.
    We received comments in support of and against EPA establishing
sulfur standards for CNG and LPG and whether such standards are
necessary to enable CNG and LPG vehicles to meet the vehicle emissions
standards finalized today.\468\ In addition, some commenters stated
that EPA should not establish new sulfur standards for in-use CNG and
LPG fuels until additional data is available on current sulfur levels,
and the feasibility/costs associated with potential additional sulfur
controls have been evaluated.
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    \468\ See Chapter 5.8. in the Summary and Analysis of Comments
Document that accompanies this rule.
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    EPA is deferring finalizing in-use sulfur requirements for CNG/LPG
in this final rule to provide additional time to work with stakeholders
to collect data on current CNG/LPG sulfur content, to determine whether
additional control of in-use CNG/LPG sulfur content is needed, and to
evaluate the feasibility and costs associated with potential additional
sulfur controls. Given that the information currently available
suggests already low sulfur levels in CNG/LPG, the vehicle emissions
standards finalized today will apply to CNG/LPG vehicles in addition to
vehicles fueled on gasoline, diesel fuel, or any other fuel.\469\
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    \469\ Several commenters provided information on CNG and LPG
sulfur levels as discussed in the Summary and Analysis of Comments
associated with this rule.
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K. Refinery Air Permitting Interactions

    EPA recognized when it proposed the Tier 3 fuel program that it is
important to the success of the Tier 3 fuel program that refineries be
able to obtain air permits, if needed, in time to complete the
modifications necessary to comply with the proposed gasoline sulfur
program. Accordingly, to help inform the public and obtain comment on
this topic, a section of the preamble to the proposed rule presented
background information on air permitting requirements and programs.
That information is not repeated in full here. Based on our preliminary
assessment of the proposed rule's implications for needed refinery
modifications, we estimated at the time of our proposal that only a
small percentage of refineries would likely need to make modifications
that would trigger a requirement to obtain air permits. Moreover, we
anticipated that these permit applications would be processed quickly
enough that air permitting would not be a significant obstacle to
timely compliance with the proposed gasoline sulfur program. We
continue to anticipate that there will be no such obstacle.
    Based on our final assessment, which takes into consideration
updated information on current refinery configurations and operations
and refineries' future plans as well as the requirements and
flexibilities in the final Tier 3 fuel program, we believe that under
the final Tier 3 gasoline sulfur standard from a low of four to a high
of nine refineries would need major source NSR permits, which includes
nonattainment New Source Review (NSR) and/or Prevention of Significant
Deterioration (PSD) permits. This estimate equates to approximately
four to eight percent of the 108 refineries projected to sell gasoline
that will be subject to the Tier 3 standards. The number of refineries
needing major source NSR permits could be even lower if refineries
apply emission controls to reduce emissions increases below the
significance levels applicable to affected pollutants or if they ``net
out'' of NSR for the affected pollutants. As stated above, EPA
continues to anticipate that permit applications associated with
refinery changes needed to comply with the Tier 3 fuel program will be
processed quickly enough that air permitting will not be a significant
obstacle to timely compliance with the gasoline sulfur program.
1. Proposal
    In the proposed rule, we stated our anticipation that the types of
changes (both physical and operational) that would occur at most
refineries would not result in sufficient emissions increases to
require major NSR permits as a prerequisite for completing the needed
changes for several reasons: because the emissions increase or the net
emissions increase is naturally less than the significant level,
because the refinery installs control technologies on project-affected
units to further limit the emissions increase, and/or because the
refinery ``nets out'' all or part of the emissions increase.
    However, we anticipated that a small number of refineries had the
potential to experience emissions increases to meet the proposed
gasoline sulfur standard that are large enough to trigger major NSR
(Nonattainment NSR and/or PSD). This small number of refineries would
have to obtain a major NSR preconstruction permit prior to making these
necessary process changes. For any required major NSR permits, the
associated control technology requirements (BACT and/or LAER) would
apply only to new or modified units associated with the project and not
to units at the refinery that are not affected by the project. We did
not anticipate that the time frames required for the small number of
affected refineries to obtain any needed NSR and/or PSD permits would
present an obstacle to timely compliance with the proposed Tier 3
gasoline sulfur requirements.
    In the proposal we also discussed a number of concepts that might
facilitate more expeditious permitting where it is required as a result
of refinery changes needed to meet the new requirements. That
discussion was based primarily on concepts that had arisen during the
earlier Tier 2 fuel program. That discussion is not repeated here. We
invited public comment on those concepts.
2. Updated Assessment of Tier 3 Refinery Changes and Permitting
Implications
    EPA has updated our refinery-by-refinery assessment of the physical
and operational changes that are likely to be needed to allow each
active refinery in the U.S. to produce gasoline that complies with the
final Tier 3 fuel specifications. We have also assessed the likely
effects of those changes on refinery emissions. This updated assessment
is described in more detail in the final RIA. Using this updated
assessment, we were able to update our understanding of the potential
scope of the major NSR permitting requirements refiners might face
under the final Tier 3 program. In general, our assessment indicates
that only a small number of refineries will likely need to make
modifications of a type and size that would trigger the need for a PSD
or nonattainment NSR permit.
    In our updated analysis, we adjusted the analysis to reflect the
existence of a nationwide average, banking, and trading (ABT) program
and refined our estimates regarding the physical and operational
changes that will be required at each refinery (as described in the
final RIA). The modifications at a given refinery could include revamps
to existing FCC pre- or post-treatment unit(s) or the installation of a
new grassroots post-treatment unit for sulfur reduction. Based on the
updated projections of refinery-specific changes, we re-estimated the
increased demand for energy (i.e., fuel to generate process heat,
steam, and electricity), hydrogen, and sulfur recovery associated with
meeting the final Tier 3 standards.

Having received no comments suggesting that they should be changed, we
re-applied the representative industry emission factors for NAAQS
pollutants, their precursors, and GHGs for each emitting process and
combined them with estimates of incremental activity to estimate the
emissions changes at each equipment unit (or group of similar units) at
each refinery.
    We determined upper and lower bounds for emissions increases
resulting from changes necessary to meet the final Tier 3 gasoline
sulfur specification. We did not have sufficient detailed information
to predict which refineries would find it most profitable to generate
additional electrical power and hydrogen on site rather than purchasing
these inputs from external suppliers. If a refinery generates these
additional inputs internally on site, the additional emissions would
count towards the significant emissions rates and could affect the need
for a major NSR permit. To account for these variables, we evaluated a
high and a low case for each identified scenario. Under the high case,
we assumed 100 percent internal generation of the additional electrical
power and hydrogen, and under the low case, 100 percent external
generation of the same. We expect refineries to actually be somewhere
between these two extreme cases in the future. For the identified high
and low cases, we compared the emissions increase for each pollutant at
each refinery to the significant emissions increase threshold for that
pollutant, taking into consideration the current attainment status for
each pollutant where the refinery is located.
    An important aspect of our analysis is that we assumed that
refineries would not install new emission controls on affected units
for the purpose of staying below the significant emissions increase
threshold and thereby not triggering major NSR. In particular, we did
not assume that selective catalytic reduction (SCR) to control
NOX emissions would be applied to new or modified fuel
combustion units. This is an important assumption that tends to result
in overestimates of the number of major NSR permits needed for NAAQS-
related pollutants. In reality, applying new emission controls would be
an option that refineries may employ to legally avoid major NSR
permitting. We also did not assume that refineries would ``net out'' of
NSR by taking credit for any emissions reductions occurring within a
contemporaneous timeframe, including any new emissions reduction
projects initiated specifically for the purpose of ``netting out.''
This analysis resulted in a prediction of whether a PSD and/or a
Nonattainment NSR permit would be needed for each refinery and the
pollutants that would have to be addressed in those permits, under each
of the two scenarios. Only the results for the high case are presented
here. More detailed results as well as the underlying methodology used
in the permitting analysis are described in the final RIA for this
rulemaking. In general terms, we found that for the low case only about
one-half the number of refineries were estimated to trigger major NSR
as were estimated for the high case.
    We found that under the high case, nine refineries appeared likely
to have significant emissions increases for one or more pollutants and
thus would trigger major NSR.\470\ This estimate equates to
approximately eight percent of the 108 refineries projected to sell
gasoline that will be subject to the Tier 3 standards. Of these nine
refineries, we predicted that three refineries would need major source
permits for NAAQS-related pollutants and their precursors (PSD and/or
Nonattainment NSR) and for GHGs (results for GHG are discussed below).
Thus, we believe that under the final Tier 3 program only about three
refineries may need major NSR air permits to address NAAQS pollutants.
This number could be lower if those refineries apply pollution
controls, such as SCR for NOX, to sufficiently reduce the
emissions increases to levels that are below the applicable pollutant
significance level, or if the refineries can achieve emissions
reductions elsewhere at the facility to ``net out'' of major NSR. For
refineries that are required to obtain a major NSR permit for NAAQS
pollutants, the permitting process is expected to normally take about 9
to 12 months once the permitting authority has received a complete
application.
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    \470\ Because state requirements regarding minor NSR permitting
vary and we do not expect minor NSR permitting programs to be a
significant challenge for refinery modification projects, we did not
attempt to estimate how many of the remaining refineries might need
to obtain minor NSR permits.
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    All three refineries just described as potentially needing NSR
permits for NAAQS pollutants are also projected to need PSD permits for
GHGs. In addition to these three refineries, we estimated that six
other refineries may require a PSD permit addressing only GHG emissions
from new or modified equipment that is part of the project. For these
nine refineries, BACT would have to be applied for GHG emissions, which
we expect in most cases would mean that new or modified fuel-burning