Based on our experience since 2014, we have concluded that the
current RFG opt-out regulatory procedures provide a better model for
considering state requests to relax the federal 7.8 psi RVP standard.
Our proposed regulations for relaxing the federal 7.8 psi RVP standard
in part 1090 mirrors the current part 80 RFG opt-out procedures, and
are as follows:
     The Governor of the state or his/her designee would
request in writing that EPA relax the federal 7.8 psi RVP standard.
     The state would continue to be required to revise its
approved SIP for the area (e.g., the ozone maintenance plan for the
area) to appropriately account for the change in emissions due to the
increase in the RVP limit and to address the CAA section 110(l) non-
interference requirements.
     The EPA Regional Office would have to approve that SIP
revision and CAA section 110(l) demonstration.
     Once, the Regional Office's action is complete, we would
establish an effective date for the relaxation, which would be no less
than 90 days after the effective date of the Regional Office's
approval. We would notify the Governor in writing, typically through a
letter, of the effective date and publish a notice in the Federal
Register. Gasoline meeting the 7.8 psi RVP standard would not be
required to be sold after that effective date.
     Subsequently, we would publish a separate final rule to
remove the area from the list of areas where the 7.8 psi RVP limit
continues to apply (i.e., from the list of areas in part 1090). We
believe that notice-and-comment rulemaking would no longer be necessary
for relaxation actions because it merely codifies a change that has
been made through a process that is included in our regulations and
would be merely administrative in nature.
    Use of this proposed process would eliminate the need for EPA to
complete a notice-and-comment rulemaking each time EPA acts on a
request to relax a low volatility gasoline standard to remove the
subject area from the list of areas subject to that standard. Under
this proposed process, similar to the current RFG opt-out procedures,
the effective date of the federal low RVP relaxation would be known
shortly after the EPA Regional Office's rulemaking on the state's SIP
revision becomes effective. We believe that using similar procedures
for acting on state requests to change either federal low RVP or RFG
programs would avoid unnecessary confusion and still continue to
provide the same level of environmental protection. Under both the
current regulations in part 80 and the proposed regulations in part
1090, the state's SIP revision must include revisions to the on-road
and nonroad mobile source NOX and VOC inventories to reflect
the removal of the federal low RVP fuel. The SIP must also demonstrate
that the area would continue to maintain the relevant ozone NAAQS and
that the change would not negatively impact the area's compliance with
other CAA requirements.\58\ Further, we would continue to act on such a
SIP revision and CAA section 110(l) non-interference demonstration
through notice-and-comment rulemaking. Finally, this proposed process,
which streamlines the RVP relaxation program, would result in the
conservation of limited government resources and bring certainty for
states, the public and gasoline suppliers as to when a state's request
to relax RVP would take effect.
---------------------------------------------------------------------------

    \58\ See CAA section 110(l).
---------------------------------------------------------------------------

h. Transitioning From Federal RFG or a Boutique Fuel Program to the
Federal RVP Standard in Certain States
    We are providing information to states that decide to either opt
out of federal RFG or remove a state SIP fuel rule that regulates
gasoline RVP (i.e., a boutique fuel) that the state in its SIP revision
(e.g., maintenance plan revision) may request that EPA apply the 9.0
psi RVP standard rather than the federal 7.8 psi RVP standard.\59\ The
SIP revision will have to document that increasing the summer RVP
standard to 9.0 psi will not interfere with attainment or maintenance
of the relevant ozone NAAQS or with requirements for reasonable further
progress, attainment, or maintenance of any other NAAQS.\60\ This
reflects our experience in working with states that have decided to
change their fuel programs in areas where the federal 9.0 psi RVP
standard could be applied.
---------------------------------------------------------------------------

    \59\ In rulemakings on June 11, 1990 (55 FR 23658) and December
12, 1991 (56 FR 64704), EPA promulgated regulations that established
a gasoline RVP standard of 7.8 psi from June 1st to September 15th
in nonattainment areas for the 1-hour ozone NAAQS in the following
states: Alabama; Arizona; Arkansas; California; Colorado; Florida;
Georgia; Kansas; Louisiana; Maryland; Mississippi; Missouri; Nevada;
New Mexico; North Carolina; Oklahoma; Oregon; South Carolina;
Tennessee; Texas; Utah and Virginia; and the District of Columbia.
The federal 9.0 psi RVP standard applies in the remaining states in
the continental U.S.
    \60\ See CAA section 110(l).
---------------------------------------------------------------------------

    In such cases, the ultimate goal of these states has been to allow
the sale of gasoline that meets the federal 9.0 psi RVP standard.
States have previously accomplished this goal by first submitting a SIP
revision (e.g., a maintenance plan revision) based on the application
of the federal 7.8 psi standard and then later submitting a second SIP
revision to initiate the process to relax the federal 7.8 psi RVP
standard to 9.0 psi. We are providing this information to ensure that
the relevant states are aware that they can accomplish the goal of
relaxing the federal RVP standard to 9.0 psi as long as the associated
SIP revision meet the CAA section 110(l) non-interference requirements
for the relevant ozone NAAQS and all other pollutants. Accomplishing
the goal of allowing the sale of gasoline that meets the federal 9.0
psi RVP standard with one SIP revision, EPA approval of one SIP
revision, and one EPA action to update the lists areas subject to the
specific gasoline standards will conserve state and federal resources.
    This proposal allowing the transition to the federal RVP standard
of 9.0 psi through one SIP revision continues to protect air quality
and public health because the state must demonstrate through its SIP
revision and CAA section 110(l) non-interference demonstration that air
quality goals are met as required by the CAA when gasoline that
complies with the federal RVP standard of 9.0 psi is sold in the area.
In addition, EPA must then approve that SIP revision and CAA section
110(l) demonstration through notice-and-comment rulemaking. This
approach also provides fuel suppliers with certainty and stability.
Under part 1090, fuel suppliers in such areas would not be required to
switch from supplying federal RFG or a state fuel to federal 7.8 psi
RVP gasoline for a short period of time only to ultimately switch to
supplying gasoline that meets the federal 9.0 psi RVP standard.
    We note, however, that if such a state wants EPA to apply the
federal 7.8 psi RVP limit, that state could document this intention in
its SIP revision, and the associated emissions modeling should be based
on application of the federal 7.8 psi RVP limit. In such a case, EPA
Headquarters would also complete a rulemaking to revise the list of
areas where the federal 7.8 psi RVP standard applies (i.e., add such an
area to the list in part 1090).
i. Announcing Updates to the Boutique Fuels List
    We are also using this action to announce that an updated boutique
fuel list is currently posted on our website. Section 1541(b) of EPAct
required EPA, in consultation with the Department of Energy (DOE), to
determine the total number of fuels approved into all SIPs

as of September 1, 2004, under section 211(c)(4)(C), and publish a list
of such fuels, including the state and Petroleum Administration for
Defense District (PADD) in which they are used for public review and
comment. EPA originally published the required list on 2006.\61\
---------------------------------------------------------------------------

    \61\ See 71 FR 78192 (December 28, 2006).
---------------------------------------------------------------------------

    Additionally, we are required to remove any fuels from the
published list if the fuel either ceases to be included in a SIP or is
identical to a federal fuel.\62\ Since the original list was published,
a number of fuels have been removed from approved SIPs and have thus
ceased to exist in SIPs.\63\ In Table V.5.h-1 we are providing an
updated list of boutique fuels that includes all of the boutique fuels
that are currently in approved SIPs. We also maintain a current list of
boutique fuels on our State Fuels website.\64\ We will continue to
update that website as changes to boutique fuels occur and periodically
announce updates in the Federal Register for fuels that are either
removed or added.
---------------------------------------------------------------------------

    \62\ See CAA section 211(c)(4)(C)(v)(III).
    \63\ Since December 2006, the following fuels have been removed
from approved SIPs: Pennsylvania--7.8 psi RVP; Maine--7.8 psi RVP;
Illinois--7.2 psi RVP; and Georgia--7.0 psi RVP with sulfur
provisions.
    \64\ See https://www.epa.gov/gasoline-standards/state-fuels.

              Table V.5.h-1--Total Number of Fuels Approved in SIPs Under CAA Section 211(c)(4)(C)
----------------------------------------------------------------------------------------------------------------
        Type of fuel control               PADD                              Region-state
----------------------------------------------------------------------------------------------------------------
RVP of 7.8 psi......................               2  5--Indiana.
                                                   3  6--Texas (May 1-October 1).*
RVP of 7.0 psi......................               2  7--Kansas.
                                                   2  5--Michigan.
                                                   2  7--Missouri.
                                                   3  4--Alabama.\65\
                                                   3  6--Texas.
Low Emission Diesel.................               3  6--Texas.
Cleaner Burning Gasoline (Summer)...               5  9--Arizona (May 1-September 30).*
Cleaner Burning Gasoline (Non-                     5  9--Arizona (October 1-April 30).
 Summer).
Winter Gasoline (aromatics & sulfur)               5  9--Nevada.\66\
----------------------------------------------------------------------------------------------------------------
* Dates refer to summer gasoline programs with different RVP control periods from the federal RVP control
  period, which runs from May 1st through September 15th for fuel manufacturers and June 1st through September
  15th for downstream parties.

5. Substantially Similar
---------------------------------------------------------------------------

    \65\ EPA has approved Alabama's request to move its SIP approved
7.0 psi RVP program to the contingency measure portion of the SIP
for the Birmingham area. Because the fuel rule was retained as a
contingency measure it remains on the boutique fuel list (see 77 FR
23619, April 20, 2012).
    \66\ Nevada's winter gasoline (aromatics and sulfur) fuel rule
was retained as a contingency measure and therefore remains on the
boutique fuel list (see 75 FR 59090, September 27, 2010).
---------------------------------------------------------------------------

    CAA section 211(f)(1)(B) prohibits the introduction into commerce
of ``any fuel or fuel additive for use by any person in motor vehicles
manufactured after model year 1974 which is not substantially similar
to any fuel or fuel additive utilized in the certification of any model
year 1975, or subsequent model year vehicle, or engine.'' While this
provision has always applied to fuel and fuel additive manufacturers by
virtue of it being a statutory requirement, we did not listed it in our
part 80 regulations among the requirements for fuel.\67\ We are
proposing to address the substantially similar requirements of the CAA
in part 1090 for gasoline and gasoline fuel additives as part of our
effort to consolidate fuels compliance requirements and make it easier
for regulated parties to understand their obligations.\68\ We are
proposing to include a requirement in the regulation that that all
gasoline, BOBs, and gasoline fuel additives must be substantially
similar under CAA section 211(f)(1)(B) or have a waiver under CAA
section 211(f)(4). We seek comment on this approach.
---------------------------------------------------------------------------

    \67\ The fuel and fuel additive registration requirements do,
however, require that manufacturers of fuels and fuel additives
demonstrate that fuels and fuel additives are either substantially
similar under CAA section 211(f)(1) or have a waiver under CAA
section 211(f)(4). See 40 CFR 79.11(i) and 79.21(h).
    \68\ See 81 FR 80877-8 (November 16, 2016).
---------------------------------------------------------------------------

    EPA has issued two coexisting definitions of substantially similar
for gasoline, one in 2008 \69\ and one in 2019,\70\ and several CAA
section 211(f)(4) waivers. The regulations proposed today refer to the
statutory provisions (CAA section 211(f)(1)(B) and (4)), and the
conditions associated with CAA section 211(f)(4) waivers and the
parameters associated with the 2019 definition of substantially
similar.
---------------------------------------------------------------------------

    \69\ See 73 FR 22277 (April 25, 2008).
    \70\ See 84 FR 26980 (June 10, 2019).
---------------------------------------------------------------------------

B. Diesel Fuel

1. Overview and Streamlining of Diesel Fuel Program
    Similar to our approach for the gasoline standards, we are
proposing to consolidate the diesel fuel standards into a single
subpart in part 1090 (subpart D). We are not proposing any changes to
the sulfur or cetane/aromatics standards for diesel fuel, the sulfur
standards for diesel fuel additives, or the ECA marine fuel standards.
We are removing expired provisions that were needed to support the
phase-in of the diesel fuel sulfur program. The phase-in period was
completed in 2014; however, these now expired phase-in provisions are
imbedded throughout the diesel program regulations, adding burden to
regulated parties in identifying their compliance duties and confusing
other stakeholders. As part of the transfer of current part 80
regulations to part 1090, we are also consolidating identical
provisions for highway and other diesel fuels into a single regulatory
requirement to improve clarity.
    We are proposing the following revisions to existing part 80
regulations in the following sections. First, we are proposing to
remove the requirement that motor vehicle diesel fuel be free of red
dye because we believe this requirement no longer provides an effective
means of evaluating compliance with the diesel sulfur standards.
Second, we are proposing to streamline the requirements that pertain to
importation of diesel fuel that does not meet EPA standards. Third, we
are proposing to remove the registration requirement for ECA marine
fuel distributors and associated requirements to include a registration
number on PTDs. Finally, we are proposing

streamlined means for downstream parties to redesignate heating oil,
kerosene, and jet fuel as ULSD that would require specific
documentation from the original fuel manufacturer.
    We expect that these proposed changes, when finalized, would
simplify the diesel fuel programs, resulting in reduced burden
associated with demonstrating compliance with the applicable sulfur
standards and maximize the fungibility of diesel fuel, allowing the
market to operate more efficiently. These changes are not expected to
change the stringency of the diesel fuel and IMO marine fuel standards.
2. Removing the Red Dye Requirement
    Part 80 currently requires that motor vehicle diesel fuel must be
free of visible evidence of dye solvent red 164 (which has a
characteristic red color in diesel fuel), except for motor vehicle
diesel fuel that is used in a manner that is tax exempt under section
4082 of the Internal Revenue Code.\71\ This EPA requirement is
consistent with a parallel requirement in the Internal Revenue Code
that is intended to support compliance with diesel fuel tax
requirements. Under the Internal Revenue Code, NRLM diesel fuel,
heating oil, and exempt highway diesel fuel \72\ must contain red dye
before leaving a fuel distribution terminal to indicate its tax-exempt
status.
---------------------------------------------------------------------------

    \71\ See 40 CFR 80.520(b).
    \72\ Such as diesel fuel used in school buses.
---------------------------------------------------------------------------

    When the sulfur standards for off-highway diesel fuel were less
stringent than those for motor vehicle diesel fuel, the presence of red
dye was a useful screening tool for EPA to identify potential
noncompliance with the sulfur standards for highway diesel fuel.
However, the presence of red dye has become a much less useful
indicator of sulfur noncompliance as other distillate fuels have become
subject to the same 15 ppm sulfur standard that applies to highway
diesel fuel. With the completion of the phase-in of our diesel fuel
sulfur program in 2014, all highway, nonroad, locomotive, and marine
diesel fuel must meet a 15 ppm sulfur standard except for a limited
volume of locomotive and marine (LM) diesel fuel produced by transmix
processors, which is subject to a 500 ppm sulfur standard. The
distribution of 500 ppm LM diesel fuel is subject to separate
compliance provisions to ensure that is not misdirected for use in
highway, nonroad, locomotive, or marine engines that require the use of
15 ppm diesel fuel (ULSD).
    The other potential source of red-dyed high-sulfur diesel fuel that
might inappropriately be diverted as highway diesel has been heating
oil. However, the vast majority of heating is currently subject to a 15
ppm standard.\73\ Therefore, we believe that the requirement that red
dye should not be present in motor vehicle diesel fuel no longer
provides meaningful added assurance of compliance with highway diesel
ULSD standards. Rather, the existence of this requirement complicates
the process of providing alternate sources of diesel fuel when supplies
of highway diesel fuel are constricted due to extreme and unusual
supply circumstances. State authorities are currently required to
request a waiver from EPA and the Internal Revenue Service (IRS) from
the respective agency's red dye requirements to enable the use of 15
ppm NRLM diesel fuel on highway during such circumstances. Eliminating
our red dye requirement would reduce state officials' waiver requests
to just an IRS waiver during such events without substantially
affecting the ability of EPA to enforce highway ULSD standards.
Therefore, we are proposing to remove the EPA requirement that motor
vehicle diesel fuel must be free from visual evidence of red dye.\74\
This proposed change would not alter the Internal Revenue Code
requirement that NRLM diesel fuel, heating oil, and exempt motor
vehicle diesel fuel must contain red dye before leaving a fuel
distribution terminal to indicate its tax-exempt status.
---------------------------------------------------------------------------

    \73\ The vast majority of heating oil is used in the Northeast
where states require that heating oil meet a 15 ppm sulfur standard.
See ``Guidance, Exemptions And Enforcement Discretion For New
England's ULSHO Transition,'' New England Fuel Institute (NEFI),
available at https://nefi.com/regulatory-compliance/new-englands-ulsho-transition.
    \74\ See 40 CFR 80.520(b)(1).
---------------------------------------------------------------------------

3. Importation of Off Spec Diesel Fuel
    We are proposing to replace the provisions for the importation of
diesel fuel treated as blendstock (DTAB) \75\ with a streamlined
procedure to handle imported off-spec diesel fuel. Under part 80, most
of the DTAB provisions are designed to account for the DTAB in
compliance calculations that have not been used since 2010. The part 80
provisions require importers to include DTAB in compliance calculations
that are no longer applicable, to keep DTAB segregated from other
diesel fuel, and limit the importer's ability to transfer title of
DTAB. Under part 1090, importers could import diesel fuel that does not
comply with EPA standards if certain provisions (which are a subset of
those currently required under part 80) are met. Under the proposed
provisions, the importer would be required to offload the imported
diesel fuel into one or more shore tanks containing diesel, sample and
test the blended fuel to confirm that it meets all applicable per-
gallon standards before introduction into commerce, and keep all
applicable records. We believe that this simplification provides the
needed flexibility for importers while providing improved clarity.
---------------------------------------------------------------------------

    \75\ See 40 CFR 80.512.
---------------------------------------------------------------------------

4. Annex VI Marine Fuel Standards
    In this action, we are mostly proposing to transpose without change
the regulations in subpart I of part 80 for distillate diesel fuel that
complies with the 0.10 percent (1,000 ppm) and 0.50 percent (5,000 ppm)
sulfur standards contained in Annex VI to the International Convention
for the Prevention of Pollution from Ships (MARPOL Annex VI). The U.S.
ratified MARPOL Annex VI and became a Party to this Protocol on October
8, 2009. MARPOL Annex VI requires marine vessels operating globally to
use fuel that meets the 0.50 percent sulfur standard starting January
1, 2020, rather than the current standard of 3.50 percent (35,000 ppm)
sulfur (``global marine fuel''). The MARPOL Annex VI standard is 0.10
percent sulfur for fuel used in vessels operating in designated
Emission Control Areas (ECAs).\76\
---------------------------------------------------------------------------

    \76\ Designated Emission Control Areas for the U.S. include the
North American ECA and the U.S. Caribbean Sea ECA. More specific
descriptions may be found in EPA fact sheets: ``Designation of North
American Emission Control Area to Reduce Emissions from Ships,''
EPA-420-F-10-015, March 2010; and ``Designation of Emission Control
Area to Reduce Emissions from Ships in the U.S. Caribbean,'' EPA-
420-F-11-024, July 2011.
---------------------------------------------------------------------------

    In a separate action, we modified our diesel fuel regulations in
part 80 to allow fuel manufacturers and distributors to sell distillate
diesel fuel meeting the 2020 global marine fuel standard instead of the
ULSD or ECA marine standards.\77\ We are incorporating those provisions
into part 1090 with minor changes to be consistent with the proposed
part 1090 structure.
---------------------------------------------------------------------------

    \77\ See 84 FR 69335 (December 18, 2019).
---------------------------------------------------------------------------

    Regarding ECA marine fuel, we are including the provisions from
part 80 in part 1090 without change save one major exception. Under
part 80, distributors of ECA marine fuel from the refiner to the point
of transfer to a vessel are currently required to register with EPA and
must include this registration number on PTDs.\78\ Distributors of
other

distillate and residual fuels had similar ``designate and track''
requirements during the phase-in of the ULSD standards for highway and
nonroad diesel fuel to allow the temporary use of limited volumes of
500 ppm highway and nonroad diesel fuel under the program's small
refiner and credit provisions.\79\ The majority of these requirements
gradually expired with the phase-out of the ULSD program's small
refiner and credit provisions that ended in 2014, which allowed the
production of limited volumes of 500 ppm highway diesel fuel. Beginning
in 2014, the only fuel distributors that must register with EPA are
those that handle ECA marine fuel and 500 ppm LM diesel fuel produced
by transmix processors.\80\
---------------------------------------------------------------------------

    \78\ See 40 CFR 80.597(d)(3).
    \79\ See 40 CFR 80.597 regarding the distributor registration
requirements and 40 CFR 80.590(a)(6)(i) for the associated PTD
requirements.
    \80\ The production of 500 ppm LM diesel fuel is discussed in
Section XIII.E.4.
---------------------------------------------------------------------------

    We believe that the benefit associated with having ECA marine fuel
distributors register with EPA may not outweigh the burdens associated
with this requirement. Like distributors of other regulated fuels,
distributors of ECA marine fuel would be required to identify
themselves on the PTD. This information could be used by EPA to help
determine what parties in the ECA marine fuel distribution chain may be
responsible for fuel represented as ECA marine fuel in the distribution
system that does not meet the requisite fuel quality standards. While
having a registration number on the ECA marine fuel PTD facilitates
this process, we do not believe that it is necessary. Therefore, we are
proposing to remove the requirement that distributors of ECA marine
fuel must register with EPA and include this registration number on ECA
marine fuel PTDs. We believe that this would meaningfully reduce the
burden to fuel distributors and would avoid potential delays in the
transportation of ECA marine fuel due to potential distributors not
being registered with EPA, while not diminishing the air quality
benefits of the ECA marine fuel program. Any person who produces diesel
fuel, including ECA marine fuel, by mixing blendstocks is a blender
manufacturer and must continue to register and comply with all
applicable requirements; this is consistent with the current regulatory
under part 80 and would be unchanged in part 1090. We request comment
on the benefits and costs of the current registration requirement for
ECA marine fuel distributors.
5. Heating Oil, Kerosene, and Jet Fuel
    Under part 80, we first established the diesel sulfur program that
required only on-highway or motor vehicle diesel to meet the 15 ppm
sulfur standard. We designed most of the provisions related to
designating, segregating, and labeling distillate fuels to avoid the
contamination of ULSD with higher sulfur distillate fuels, which at the
time were non-road diesel, heating oil, kerosene, and jet fuel. Now a
federal 15 ppm standard applies for motor vehicle, non-road,
locomotive, and marine diesel fuel, and, as discussed in Section V.B.2,
a state or local 15 ppm sulfur standard applies to most of the heating
oil used in the U.S. The provisions designed to avoid contamination of
ULSD with higher sulfur distillate fuels now exist where there is no
difference between most distillate fuels; however, the provisions have
remained in place despite this change in the distillate fuel market.
These obsolete provisions contribute to inefficiency in the
distribution system leading to higher costs, and barriers to the free
movement of fuel during times of unforeseen supply disruptions (e.g.,
refinery fires, hurricanes, etc.). Therefore, we are proposing to allow
heating oil, kerosene, and jet fuel certified to ULSD standards to be
redesignated downstream as ULSD for use in motor vehicles and NRLM
engines without recertification by the downstream party if certain
conditions are met.
    Under these proposed provisions, downstream parties could rely upon
documentation from pipelines or fuel manufacturers that the heating
oil, kerosene, or jet fuel was certified to meet the 15 ppm ULSD sulfur
standard and cetane/aromatics specifications to fungibly transport,
store, and dispense all 15 ppm sulfur distillate fuels downstream. We
are also proposing provisions in part 1090 that would also allow ULSD
to be used as heating oil, kerosene, jet fuel, or ECA marine fuel
without recertification as long as records are kept demonstrating that
the ULSD had been redesignated. We believe that these provisions would
maximize the fungibility of distillate fuels, resulting in
substantially reduced distributional costs and greater efficiency in
the fuels market.
    During the rule development process, several stakeholders asked
that we address issues regarding accounting for distillate fuels under
the RFS program. We believe that this is outside the scope of this
action. We recognize that this proposal could impact RFS compliance and
have finalized provisions to help clarify how obligated parties (i.e.,
refiners and importers of gasoline and diesel fuel) account for
distillate fuels under the RFS program in a separate action.\81\
---------------------------------------------------------------------------

    \81\ See 85 FR 7054-57 (February 6, 2020).
---------------------------------------------------------------------------

    We believe these proposed changes could help increase the
efficiency with which distillate fuels are distributed, resulting in
significant cost savings to stakeholders and consumers. We seek comment
on whether this is the case and on how to quantify the associated cost
savings.

VI. Exemptions, Hardships, and Special Provisions

A. Exemptions

    We are also transferring provisions that exempt fuels from
applicable standards that are currently contained in part 80 to part
1090. We are proposing minor revisions for purposes of modernizing
these exemptions as well as removing obsolete exemption provisions, and
any exemptions that were granted under part 80 will remain in effect
with their original conditions as applicable under part 1090. As a
result, instead of being scattered through various subparts as is the
current practice in part 80, these provisions would be consolidated
into a single subpart in part 1090 (subpart G) for all exemptions. This
includes those exemptions that require a petition such as the hardship
exemption and those that do not such as the for export exemption. This
structure is designed to increase their accessibility and usability.
Consistent with current provisions, exempted fuels, fuel additives, and
regulated blendstocks do not need to comply with the standards of part
1090, but remain subject to other requirements (e.g., registration,
reporting, and recordkeeping) that are now also proposed to be moved to
part 1090.
    We are not proposing any revisions to exemptions nor the related
requirements that apply to fuels used for national security and
military purposes, temporary research and development (R&D), racing,
and aviation. Similarly, we are not proposing to change the exemption
that applies to fuel in Guam, American Samoa, and the Commonwealth of
the Northern Mariana Islands. Summer gasoline in Alaska, Hawaii, Puerto
Rico, and the U.S. Virgin Islands would also continue to be exempt from
the federal volatility regulations.
    We are, however, proposing minor revisions to these exemptions for
consistency and as a result of consolidating the various part 80

exemptions. We are proposing that exemptions granted under part 80
would remain in effect under part 1090, and as previously explained
removing exemption provisions that are no longer active.
    We are proposing some changes to modernize the exemption
provisions. First, we are proposing to include language that would
impose conditions on parties operating under a research and development
(``R&D'') test program to prevent the inadvertent use of test fuels
exempted under a temporary R&D exemption by participants not included
in the test program. Recently, we have received requests for R&D
exemptions that focus on the effects of a certain fuel's use in more
real world operation conditions (as opposed to a contained laboratory
type situation). This often requires the test fuel be made available in
a way that could result in vehicles or engines not included as part of
the R&D program inappropriately using the test fuel. We believe it is
appropriate for applicants requesting such an R&D exemption to take
reasonable precautions to prevent consumers not participating in the
test program from fueling with the test fuel. We are requesting comment
on procedures that could be applied to fuels being tested under an R&D
exemption when the test includes consumer participation that could
result in the aforementioned misfueling.
    Second, we are proposing to allow certain exemptions for fuel
additives and regulated blendstocks. Under part 80, it was unclear
whether some exemptions applied to fuel additives and regulated
blendstocks under certain programs, such as the gasoline sulfur
program. Under 1090, fuel additives and regulated blendstocks would now
be exempt from applicable requirements if certain conditions are met.
For example, the military use exemption would now explicitly exempt
fuels, fuel additives and regulated blendstocks used in either military
vehicles or in support of military operations.
    Third, we are proposing that parties that transport and store
exempt aviation and racing fuel take reasonable precautions to avoid
the contamination of exempt fuels when using the same tanker trucks and
tanks to transport and store exempt and non-exempt fuels. Aviation and
racing gasoline can often contain lead additives that can harm emission
controls on vehicles and engines designed to operate on unleaded
gasoline. For example, when a tanker truck carrying exempt racing
gasoline is later used to transport non-exempt gasoline, residual
exempt racing gasoline could remain in the tanker truck and contaminate
the non-exempt gasoline. We believe it is prudent for parties to follow
established voluntary consensus-based standards for the cleaning out of
tanker trucks. As such, part 1090 lists two such examples for cleaning
tanker trucks to avoid contamination.\82\ We seek comment on this
proposed requirement and whether there are other voluntary consensus-
based standards we should reference.
---------------------------------------------------------------------------

    \82\ API Recommended Practice 1595 and Energy Institute & Joint
Inspection Group Standard 1530.
---------------------------------------------------------------------------

    California gasoline and diesel fuel are currently exempt from the
part 80 standards in separate provisions under the various subparts. We
are consolidating these existing exemptions for California fuels into a
single comprehensive section. This reorganization eliminates the
redundancy that resulted as new programs were implemented with
California exemptions and old programs sunset but remained in the
regulations with their original California fuels exemption.
Additionally, housing all the provisions for the California fuels
exemption in one section facilitates compliance with its requirements,
as regulated parties need not scour part 1090 for hidden exemption
provisions. We are also proposing provisions that clarify how
California gasoline and diesel fuels may be used in states other than
California in the consolidated California exemption section that
explains the provisions. Under the current part 80 regulations, fuel
manufacturers that make California gasoline and California diesel fuel
must recertify those fuels in order to sell them outside the state of
California. We are retaining this recertification requirement in part
1090. Fuel manufacturers of California gasoline may recertify their
fuels under the applicable standards of this part in order to sell such
gasoline outside California. When manufacturers of California gasoline
recertify their gasoline, they may participate in the Federal
Averaging, Banking, and Trading (``ABT'') programs for gasoline sulfur
and benzene. In addition to maintaining the option of recertifying, we
are proposing to allow California gasoline manufacturers or
distributors of California gasoline to simply redesignate the fuel as
CG or RFG, so long as the California gasoline meets all the
requirements for California reformulated gasoline under Title 13 of the
California Code of Regulations and the manufacturer or distributor
meets applicable designation and recordkeeping requirements.\83\ Under
this proposal, parties that redesignate California gasoline for use
outside of California would not be permitted to generate sulfur or
benzene credits from the redesignated fuel. Similarly, California
diesel fuel used outside of California would be deemed in compliance
with the standards of this part if it meets all the requirements Title
13 of the California Code of Regulations and the manufacturer or
distributor meets applicable designation and recordkeeping
requirements.\84\
---------------------------------------------------------------------------

    \83\ The explanation for the analysis we performed to determine
the equivalency of the California fuel standards can be found in the
technical memorandum, ``The California Fuel Equivalency
Memorandum,'' available in the docket for this action.
    \84\ The California reformulated gasoline and diesel fuel
standards are at least as stringent as the standards under this
part, therefore, these fuels should be allowed to be used throughout
the country. Cal. Code Regs. tit. 13, Sec. Sec.  2281-2282 (2019).
---------------------------------------------------------------------------

B. Exports

    We are transferring the current part 80 exemption from applicable
standards for fuels, fuel additives, and regulated blendstocks that are
designated for export to part 1090. Additionally, we are transferring
requirements for designation, product transfer documents, and gasoline
segregation for fuels designated for export that currently apply under
part 80 to part 1090. Diesel fuels not designated for export could be
exported without restriction as long as those fuels meet the applicable
fuel quality standards. However, the fuel remains subject to the
provisions of this part while in the U.S. For example, fuel designated
as ULSD must meet the applicable sulfur standards even if it will later
be exported. Such diesel fuel that meets ULSD standards would not need
to be segregated and may be redesignated for export by a distributor.
On the other hand, diesel fuel that does not meet the ULSD standards
would need to be designated for export and segregated from the point of
production until the diesel fuel was exported, as currently required
under part 80. We are also not proposing to require segregation of fuel
additives and regulated blendstocks designated for export. However,
some regulated parties have suggested applying the segregation
requirement to those products, and we are seeking comment on whether to
impose such a requirement as well as the impacts of imposing such a
requirement.
    Under part 80, gasoline manufacturers are required to segregate
gasoline designated for export. In this action, we are not proposing to
change this

segregation requirement for gasoline exports. The only modification
from part 80 is that these provisions, instead of being included in
each gasoline program subpart, will be consolidated into a single
subpart for exports under part 1090.

C. Hardships

    Under part 80, various subparts include separate provisions for
receiving an exemption from that subpart's fuel quality standards due
to unforeseeable hardship. We are proposing to consolidate these
exemptions into one general hardship provision for unforeseeable
circumstances (e.g., a natural disaster or refinery fire) that a
refinery cannot avoid with prudent planning (excluding financial and
supply chain hardship). The proposed reorganization is intended to make
the hardship provision easier to find and does not change either the
opportunity for a hardship or the regulated party's burden to
demonstrate that its circumstances satisfy the requirements for
applicable hardship exemptions. This change would not affect the RFS
program, however, given that we are retaining the program in part 80.
Accordingly, any exemptions available under that program would
similarly remain unaffected.

VII. Averaging, Banking, and Trading Provisions

A. Overview

    We are transferring the part 80 averaging, banking, and trading
(ABT) provisions for compliance with the sulfur and benzene average
standards for gasoline to part 1090.\85\ We are proposing modifications
that will facilitate consolidation of these various ABT regulatory
provisions in part 80 into a single set of ABT provisions in part 1090.
We are not transferring part 80 regulations that established separate
ABT provisions for small refiners and small volume refineries given
that they expired at the end of 2019. We have used ABT provisions to as
a means to both meet our environmental objectives and provide regulated
parties with the ability to comply with our fuel standards in the most
efficient and lowest cost manner. This section also includes changes to
how gasoline manufacturers could account for oxygenate added to
gasoline downstream of fuel manufacturing facilities in compliance
calculations. This section further describes a new proposed mechanism
that would allow downstream parties that recertify batches of gasoline
to use different types and amounts of oxygenate downstream of a
manufacturing facility.
---------------------------------------------------------------------------

    \85\ We do not have ABT provisions for diesel fuel, so this
section is only applicable to gasoline.
---------------------------------------------------------------------------

B. Compliance on Average

    We are proposing some minor changes to the format of the average
compliance calculations to align the sulfur and benzene compliance
calculations more closely to accommodate consolidating annual
compliance reporting into a single reporting format. Under part 80,
compliance with the benzene and sulfur average standards is
demonstrated in separate forms and use a slightly different
nomenclature. The proposed changes to the compliance calculations would
not affect how gasoline manufacturers currently comply with the average
standards or their stringency; however, the proposed equations appear
slightly different compared to the similar equations in part 80. We are
also proposing to add deficits incurred on an annual basis due to the
recertification of BOBs downstream to use different types and amounts
of oxygenates. This proposed change is discussed in detail in section
VII.G.
    As previously noted, all part 80 regulations that had separate ABT
provisions for small refiners and small volume refineries have expired
or will by the time this proposed rule is implemented. The last such
provisions are those related to the Tier 3 gasoline sulfur program,
which will expire on December 31, 2019, resulting in small refiners and
small volume refineries being required to be in compliance with the
same part 80 fuel quality standards as other refiners. Since the
proposed streamlined fuel quality regulations would take effect January
1, 2021, part 1090 does not include separate ABT provisions for small
refiners and small volume refineries. If in the future we propose new
fuel standards, we would likely consider flexibilities for small
refiners and small volume refineries as part of that future action.

C. Deficit Carryforward

    Under the Tier 3 sulfur and MSAT2 gasoline programs, we allow
gasoline manufacturers to carryforward deficits, whereby an individual
fuel manufacturing facility that does not meet either the sulfur or
benzene standard in each compliance period may carry a credit deficit
forward into the next compliance period. Under this deficit
carryforward allowance, the manufacturer for the facility must make up
the credit deficit and come into compliance with the applicable
standard(s) in the next compliance period. We are proposing to
consolidate the deficit carryforward provisions and we have proposed
language that differs from the part 80 deficit carryforward provisions
because the proposed language accommodates the consolidation of the
gasoline sulfur and benzene deficit carryforward provisions into a
single carryforward provision.

D. Credit Generation, Use, and Transfer

    We are also transferring the part 80 credit generation, use, and
transfer provisions for gasoline manufacturers to part 1090. We are
proposing minor changes to the language largely to ensure consistency
between the sulfur and benzene credit trading programs.
    We are not proposing any changes to the lifespan of generated
credits (i.e., credits generated under part 1090 would have the same
lifespan as afforded them under part 80). Additionally, credits
generated under part 80 would still be usable to comply with average
standards under part 1090. To facilitate the use of part 80 credits
under part 1090, we are including language to make it clear that
credits generated under part 80 would still be valid for compliance
under part 1090 for the specified life of the credits under part 80.
For example, for credits generated for the 2020 compliance period,
gasoline manufacturers could use those credits through the 2025
compliance period.

E. Invalid Credits

    We are transferring the part 80 provisions for treatment of invalid
credits to part 1090 without any modifications. Since the establishment
of the sulfur and benzene ABT programs, we migrated tracking of credit
transactions into EMTS. During the rule development process, we
received feedback from stakeholders suggesting that the process for
remediating invalid credits was onerous due to the administrative
process associated with modifying credits in EMTS. Stakeholders also
suggested that we rearrange the compliance deadlines to have annual
compliance reports due after annual audits have occurred. Some
stakeholders suggested that since the annual audit process identifies
several issues after annual compliance reports have been submitted
(i.e., after credits have been traded and retired for compliance), this
switch would then allow for fewer resubmissions of reports and fewer
remedial actions for invalid credits. Responsible parties would not
need to amend reports since they would have been able to correct the
original compliance reports based on an audit. We are not proposing to
change the compliance deadlines. We believe

changing the compliance deadlines would disrupt a relatively well
functioning compliance program and we believe other actions proposed as
part of the streamlined fuel quality regulations would reduce the
frequency of resubmissions and remedial actions. For example, we
believe by allowing less precision in the rounding of gallons,
responsible parties would have fewer remedial actions if audits
identify that a party was off by a single gallon on their annual
reports. We also believe that by streamlining the regulatory and
reporting requirements, compliance demonstrations would be less prone
to the types of errors that often require resubmissions. We also note
that companies always have the option of performing their own audits
internally. However, we seek comment on whether we should rearrange the
compliance deadlines as a means to reduce resubmissions and remedial
actions.

F. Downstream Oxygenate Accounting

    We are proposing a single method for gasoline manufacturers to
account for oxygenate added downstream of a fuel manufacturing
facility. Oxygenate accounting provides the flexibility for fuel
manufacturers to ensure that average standards are met. Under part 80,
we have provided several mechanisms, depending on the gasoline program,
for refiners and importers to account for oxygenate added downstream.
Under the current part 80 RFG provisions for oxygenate blending and
accounting, refiners and importers create a hand blend and test the
hand blend for reported parameters and include these values in their
compliance calculations to demonstrate compliance with sulfur and
benzene average standards and the RFG performance standards. The
refiner or importer then specifies the type(s) and amount(s) of
oxygenates on PTDs to be added by the oxygenate blender, who must then
follow the blending instructions by the refiner or importer. Further,
refiners and importers must contract with an independent surveyor to
verify that an oxygenate is added downstream at levels reported to EPA
in batch reports.
    Due to the fungible nature of most CG and CBOB, it is difficult for
many CG/CBOB refiners or importers to account for oxygenate that is
added downstream. Under part 80, CG/CBOB refiners and importers can
only account for oxygenate if the refiner or importer can establish
that the oxygenate was in fact added to the CG or CBOB. The CG/CBOB
refiner or importer can establish that the oxygenate was blended by
either: (1) Blending the oxygenate themselves; or (2) having a contract
with an oxygenate blender specifying procedures the oxygenate blender
will follow to add the amount of oxygenate claimed by the CG/CBOB
refiner or importer and the refiner or importer has an oversight
program to ensure that the oxygenate blending takes place. Under Tier
3, CG/CBOB refiners and importers may assume 10 percent ethanol
containing 5 ppm sulfur in compliance calculations to account for
oxygenate added downstream. Further, part 80 does not contain any
allowance provisions to assume dilution of benzene from oxygenate added
downstream. Based on information gleaned during the rule development
process, it appears the average sulfur levels for DFE are lower (2-3
ppm) than the assumed value of 5 ppm allowed under Tier 3. This
regulatory disparate treatment of CG/CBOB compared to RFG/RBOB has
created a scenario where it is more difficult for CG/CBOB refiners and
importers to account for the benefits of the addition of downstream
oxygenates.
    In part 1090, we are proposing to require gasoline manufacturers to
use ``hand blends'' when accounting for oxygenate added downstream. We
are also proposing to require that oxygenate blenders follow
instructions for the type(s) and amount(s) of oxygenated from the BOB
manufacturer. The proposed requirements for gasoline manufacturers and
oxygenate blenders largely mirror the requirements for oxygenate
blending and accounting found in the RFG program.
    The main differences between the proposed hand blend approach and
the current RFG program is that the accompanying in-use survey would be
national in scope (instead of just a survey of RFG areas), and the BOB
manufacturer would need to participate in the proposed national
sampling oversight program. The accompanying in-use survey requirements
are discussed in more detail in Section X. Additionally, since we are
broadening the scope of the oxygenate accounting process from RBOB to
all BOB, we are also proposing that gasoline manufacturers prepare
samples using the hand blend procedures in ASTM D7717 and that
commercially available oxygenate (e.g., denatured fuel ethanol) be used
to make hand blends. The oxygenate used should reflect the anticipated
sulfur and benzene levels of the oxygenate that will ultimately be
blended with the BOB. All other proposed requirements would be the same
as currently specified for the RFG program.
    During the rule development process, we received feedback from some
stakeholders requesting that we allow multiple different options for
gasoline manufacturers to account for oxygenate added downstream. These
stakeholders argued that the use of assumptions in compliance
calculations, as currently allowed under Tier 3 for sulfur, could be
easier for some manufacturers to adopt. As discussed earlier, we
currently allow for many different methods for accounting for oxygenate
added downstream. While this has allowed some gasoline manufacturers
(primarily manufacturers of RFG) to benefit from this ability, it has
practically precluded other gasoline manufacturers (primarily
manufacturers of CG) from enjoying the same flexibility, creating an
unlevel playing field. We believe that providing a single method of
accounting for oxygenate added downstream ensures a level playing field
for all gasoline manufacturers and allows us to better assure that
appropriate levels of oxygenate are accounted for through in-use
verification in the downstream survey. Additionally, setting
assumptions for manufacturers to use in compliance calculations would
require information on what those assumptions should be for all
regulated parameters (i.e., benzene, sulfur, and RVP). The validity of
such assumptions could change over time as new oxygenates or, in the
case of DFE, new sources of denaturant are established over time.
Changing such assumptions would require EPA to amend its regulations,
potentially resulting in an inadvertent change in in-use fuel quality.
On the other hand, by utilizing the proposed hand blend approach, we
would allow gasoline manufacturers to adjust hand blends to adapt to
market changes almost immediately (e.g., if there was an increased
demand for E0 or E15). This would ensure that what is reported is
ultimately reflective of what is happening in the market, thereby
maintaining the stringency of the fuel quality standards over time.
However, we seek comment on allowing parties to use assumptions and if
so, appropriate assumed values for oxygenates added downstream. In
particular, we seek specific data supporting the use of assumed values.
    Also, during the rule development process, some stakeholders
highlighted that allowing CG manufacturers that are not currently
accounting for oxygenate added downstream may result in a change in in-
use fuel quality. These stakeholders pointed out that if CG
manufacturers are not currently taking advantage of oxygenate
accounting due to the difficultly of ensuring that

oxygenate is added downstream, these manufacturers would be slightly
over-complying with the required sulfur and benzene average standards.
We expect any such effects to be minimal, and we discuss these
potential effects in more detail in Section XIV.\86\
---------------------------------------------------------------------------

    \86\ We discuss these effects in more detail in the technical
memorandum, ``Estimated Effects of Proposed Downstream Oxygenate
Accounting Provisions,'' available in the docket for this action.
---------------------------------------------------------------------------

G. Downstream Oxygenate Recertification

    Under the part 80 RFG program, oxygenate blenders must add the
type(s) and amount(s) of oxygenate(s) to RBOB as specified by refiners
under 40 CFR 80.69. Refiners must specify blending instructions for all
RBOB, most of which is to be made into E10. An oxygenate blender that
recertifies a batch of RBOB under part 80 is a gasoline refiner and
must comply with all the applicable requirements for a gasoline
refiner. These requirements include registration under part 79 as a
fuel manufacturer, registering under part 80 as a refiner, complying
with sulfur and benzene average standards, and batch sampling and
testing. As a result of these requirements and the relatively low
volume of E0 needed, oxygenate blenders do not typically opt to assume
the role of a gasoline refiner, reducing the availability of E0 in RFG
areas. Similarly, the RFG regulations under part 80 practically
preclude the use of isobutanol in RBOBs since the regulations require
that oxygenate blenders add the type and amount of oxygenate specified
by the RFG refiner or importer (which is predominately E10). Under part
80, parties may recertify the batch of RFG; however, the high cost
associated with recertifying batches of RBOB downstream essentially
precludes oxygenate blenders from blending isobutanol in RFG areas
since the batch sizes are relatively small (typically the volume of a
single tanker truck).
    These restrictions, currently limited to RFG areas, could be
compounded by the proposed downstream oxygenate provisions discussed in
Section VII.F. Consequently, we are proposing a provision in part 1090
that would allow parties downstream of gasoline manufacturing
facilities to more easily recertify BOBs for different types and
amounts of oxygenates. Specifically, we are proposing a downstream
certification mechanism to allow for oxygenate blenders to recertify
batches of BOB for different types and amounts of oxygenates as the
market demands to make sure that consumers can still have E0, E15, or
isobutanol-blended gasoline available as needed. In other words, under
part 1090, oxygenate blenders must follow the blending instructions on
PTDs by gasoline manufacturers unless they recertify the batch for a
different type and/or amount of oxygenate.
    We are proposing to require that parties that wish to recertify
BOBs must determine the number of sulfur and benzene credits lost by
any lack of downstream oxygenate dilution in cases where the party
added less oxygenate than was specified by the gasoline manufacturer.
For example, if a party takes a premium BOB intended for blending with
ethanol at 10 volume percent and wishes to use it as E0 for
recreational vehicles, this party would need to make up for the lost
dilution of the sulfur and benzene in the national fuel pool. We have
included additional compliance calculations that such parties would
need to use to determine the number of sulfur and benzene credits
needed. In this calculation, we are proposing default assumed values
for the amount of sulfur and benzene from the BOB. We are proposing
default values of 11 ppm sulfur and 0.68 volume percent benzene. These
proposed values are reflective of the national sulfur and benzene
average values adjusted for the absence of denatured fuel ethanol added
at 10 volume percent ethanol.\87\ The goal of these proposed values is
to avoid requiring additional sampling and testing from the
recertifying party. We believe that due to the small batch volume for
recertified product, typically the size of a tanker truck, the amount
of credits needed for any given batch of recertified gasoline would be
low and small changes from actual benzene and sulfur content would be
in the noise of the proposed compliance calculation and washed out in
the marketplace. However, we seek comment on whether different default
values would be appropriate.
---------------------------------------------------------------------------

    \87\ We took the national average values for sulfur (10 ppm) and
benzene (0.62 volume percent) and multiplied them by 110 percent.
---------------------------------------------------------------------------

    In cases where a party adds the same volume of oxygenate or more,
these credit makeup regulations would not apply, as more than enough
sulfur and benzene dilution would have occurred. For example, adding 15
volume percent ethanol into a BOB intended for the addition of 10
volume percent ethanol or adding 12 volume percent isobutanol to a
batch of BOB intended for the addition of 10 volume percent ethanol.
All other applicable requirements under the CAA and parts 79, 80 and
1090 would apply to the recertified fuel. For example, the recertified
gasoline would need to meet RVP requirements in the summer, meet per-
gallon sulfur requirements, and be substantially similar under CAA
section 211(f). Part 80 currently does not allow oxygenate blenders to
generate credits in cases where additional oxygenate is added to RBOB
or CBOB and part 1090 would not change this. The challenges associated
with implementing and enforcing such a credit provision with so many
entities on such small volumes has historically created considerable
difficulties, and there does not appear to be any compelling reason
here to change from the current regulations.
    In order to ensure that parties that recertify BOBs downstream
adhere to the proposed provisions for downstream oxygenate
recertification, we are proposing that these parties would need to
register with EPA, transact any needed sulfur and benzene credits,
submit annual compliance reports, and keep records documenting the
blending activities and reports submitted to EPA. In lieu of requiring
the burden of sampling and testing each batch, we are also proposing
that these parties simply undergo an annual attest engagement audit and
submit an attest report similar to the report required for gasoline
manufacturers. The proposed requirements would only apply to parties
that incur a deficit by recertifying BOBs with less oxygenate than
specified on the PTD. If a party is already registered with EPA and
complies with sulfur and benzene averaging requirements, the party
would include the total number of credits needed as a result of
downstream oxygenate recertification in their annual compliance
calculations as a deficit.
    During the rule development process, we solicited feedback on
whether parties that recertify BOBs downstream should undergo an annual
audit to help ensure that the party complied with the proposed
requirements correctly. We received feedback from stakeholders stating
that while many of the parties that would elect to use this flexibility
are already registered with EPA under part 80, these parties often do
not have an annual attest engagement as they do not manufacture
gasoline. Therefore, these stakeholders argued that having an attest
engagement, which costs tens of thousands of dollars per year, for a
small volume of fuel (one tanker truck of approximately 8,000 gallons)
is unreasonably burdensome and would significantly increase the costs
of recertified fuels. We agree with this feedback; however, we believe
that parties that recertify a significant

amount of gasoline for different types and amounts of oxygenates should
undergo an annual audit as these parties could have a greater effect on
the larger sulfur and benzene pools. Therefore, we are proposing that
parties that recertify less than 200,000 total gallons of gasoline for
different types and amounts of oxygenate during a compliance period
would be exempt from the annual attest audit and report.\88\ We believe
this proposed flexibility would allow small blenders to avoid a
substantial amount of compliance costs associated with recertification
of batches of gasoline for different types and amounts of oxygenates
while ensuring integrity in the sulfur and benzene credit markets. We
seek comment on whether this allowance is appropriate.
---------------------------------------------------------------------------

    \88\ We estimated this value based on the 1st percentile of
credit transaction sizes for benzene credits in 2018. Our analysis
for calculating the 200,000 gallon number is included in the
technical memorandum, ``Estimated Effects of Proposed Downstream
Oxygenate Accounting Provisions,'' available in the docket for this
action.
---------------------------------------------------------------------------

    Also, during the rule development process we received feedback
asking for alternatives to the proposed downstream oxygenate
recertification approach. Stakeholders suggested potentially developing
a factor that would go into a gasoline manufacturer's compliance
calculations that estimated the nationwide level of oxygenate blended
into gasoline. While we believe this measure could effectively capture
the amount of oxygenate added downstream, it creates level-playing
field concerns by effectively increasing the standard for gasoline
manufacturers that certify 100 percent of their batches with oxygenates
and decreasing the standards for parties that certify less than 100
percent. Additionally, we believe that setting the factor creates
challenges. For example, if we set a level consistent with today's
oxygenate blending levels and the market changes the amount of
oxygenate added to the fuel pool in the future, we would have to
undertake a future rulemaking to accommodate the new amount of
oxygenate blended into gasoline. If we put in place an administrative
process to adjust the factor on a periodic basis (e.g., annually), we
believe it would be challenging to continually monitor and track the
appropriate number without imposing significant additional reporting
and tracking burdens on the part of industry. Failure to provide a new
reporting and tracking mechanism would result in delays in establishing
the factor on a periodic basis providing uncertainty for gasoline
manufacturers in determining sulfur and benzene average standards. We
believe the proposed approach provides the desired marketplace
flexibility, puts in place appropriate and manageable measures to
ensure environmental performance, and allows for flexibility both now
and into the future without the need for additional regulatory action.
However, we seek comment on other approaches to allow parties to
recertify batches of BOB for different types and amounts of oxygenates
downstream.
    Finally, during the rule development process, we received feedback
asking for an allowance to carry forward a deficit related to
downstream oxygenate recertification. Stakeholders suggested that it
would take time for the sulfur and benzene credit markets and regulated
parties to adjust to this proposed flexibility. They suggested that
allowing a limited time deficit carry-forward would allow for this
proposed flexibility to be implemented more smoothly. We believe that
the amount of credits needed to satisfy deficits incurred related to
downstream oxygenate recertification is relatively small and that
allowing parties to carry-forward deficits related to this proposed
provision would result in some parties failing to satisfy those
deficits. Therefore, we are not proposing to allow deficit carry-
forwards for deficits created by downstream oxygenate recertification.
However, we seek comment on whether providing such a deficit carry-
forward is needed to help implement the proposed downstream oxygenate
recertification provisions. Comments on this subject should include a
reasonable period of time for consideration.

VIII. Registration, Reporting, Product Transfer Document, and
Recordkeeping Requirements

A. Overview

    We are mostly transferring the existing part 80 registration,
reporting, PTD, and recordkeeping provisions that are distributed among
various subparts in part 80 to part 1090. We also intend to reconcile,
simplify, and logically organize those provisions. The resulting
registration, reporting, product transfer document (PTD), and
recordkeeping requirements proposed for part 1090 are like those
already in place under part 80. Where possible we have sought to reduce
the impacts upon regulated parties and reduce the burden associated
with maintaining and submitting information. In certain cases, we have
proposed regulations to simplify or better align reporting requirements
with current industry practice, which is particularly true of the batch
reporting requirements described in greater detail below.
    Information submitted under part 1090 may be claimed as
confidential business information (CBI) by the submitter, including
certain information submitted via registration and reporting systems.
EPA will protect such information from public release in accordance
with the provisions of 40 CFR part 2 and in a manner consistent with
EPA rules and guidelines related to CBI. Our public release of EPA
enforcement-related determinations and EPA actions, together with basic
information regarding the party or parties involved and the
parameter(s) or credits affected, does not involve the release of
information that is entitled to treatment as CBI. Such information may
include the company name and company identification number, the
facility name and facility identification number, the total quantity of
fuel and parameter, and the time period when the violation occurred.
Enforcement-related determinations and actions within the scope of this
release of information include notices of violation, administrative
complaints, civil complaints, criminal information, and criminal
indictments. Although we are not proposing a comprehensive CBI
determination at this time, we may undertake that activity in a future
rulemaking.

B. Registration

1. Purpose of Registration
    Registration is necessary to: (1) Identify which parties engage in
regulated activities under our regulations; (2) allow regulated parties
access to systems to submit information required under our fuel quality
regulations; and (3) provide regulated parties with company and
compliance-level identification numbers for producing PTDs and other
records. This action would make modest changes to the existing
registration system including modernizing certain terminology and
making updates that make registration easier to understand and
implement.
2. Who Must Register
    The proposed registration requirements are designed to update
terminology to better reflect current roles and activities in the fuel
production and distribution system. We are proposing registration
requirements for certain third parties, such as independent auditors.
These are explained in greater detail below. The following parties
would have to register

with EPA prior to engaging in any activity under part 1090:

 Gasoline manufacturers
 Diesel fuel and ECA marine manufacturers
 Oxygenate blenders
 Oxygenate producers
 Certified butane blenders
 Certified pentane producers
 Certified pentane blenders
 Transmix processors
 Certified ethanol denaturant producers
 Distributors, carriers and resellers who are part of a 500 ppm
LM diesel chain and who are part of a compliance plan proposed under 40
CFR 1090.515(c)
 Independent surveyors
 Auditors
 Third parties who require access to EPA's registration and
reporting systems, including those who submit reports on behalf of any
party regulated under part 1090

    Nearly all parties who would be subject to registration under part
1090 are already registered under part 80. We are not requiring parties
who are already registered under part 80 to go through the effort to
re-register their company or their facilities under part 1090. We are
proposing to include specific provisions in part 1090 that would ensure
such parties do not need to re-register. For example, although we do
not currently register parties under part 80 as ``gasoline
manufacturers,'' parties who are currently registered as ``refiners''
would be understood to fall under this new term and would not have to
re-register. We do not believe that this action will result in a
significant number of new registrants, and existing registrants would
only need to make the type of routine registration updates they already
are required to make (e.g., to add or delete activities they engage in
or to change an address).
    We are also proposing to remove an existing registration
requirement under part 80. Although independent laboratories are
required to register under part 80, we are proposing to remove this
registration requirement and are not transferring this requirement from
part 80 to part 1090. As a result, independent laboratories would no
longer be required to register unless they submit information directly
on behalf of another party, such as a gasoline manufacturer. In such
cases, they would need to update their registration to reflect that
they are submitting reports on behalf of a regulated party and would
have to associate with the company or companies for which they will
submit reports. Association is a step within the existing registration
system and is designed to ensure that the company for which the reports
are submitted by the ``agent'' agrees to that arrangement. Association
is designed to be a simple step that would still prevent an
unauthorized party from submitting reports on another's behalf without
their consent or knowledge.\89\
---------------------------------------------------------------------------

    \89\ During the rule development process, we received feedback
suggesting that we should maintain the registration requirement and
the itinerant RFG independent laboratory testing program; this issue
is discussed in more detail in Section X.B.
---------------------------------------------------------------------------

    We are also proposing new registration requirements for independent
surveyors and independent auditors under part 1090. These parties are
not subject to registration requirements under part 80 but either
submit survey plans and periodic reports to EPA under various
provisions or perform attest engagements for regulated parties under
part 80. We thus believe that requiring them to register would allow
them to submit reports directly to EPA and thereby further streamline
the process of getting the information to EPA.
    Independent surveyors perform the compliance surveys and the
proposed voluntary sampling oversight program (discussed in more detail
in Section X). At present, there is only one known independent
surveyor, performing four types of surveys under part 80. As previously
noted, independent surveyors already submit survey reports to EPA, in a
variety of ways. As discussed in Section VIII.C.8, we are proposing to
have them register so that they may submit reports via EPA's reporting
systems. Although this would create a small, new class of registrants
(currently only one new submitter), we believe the burden of
registering is outweighed by the simplicity and reliability of having
surveyors utilizing the electronic reporting system to submit their
information. This proposed change would allow us to more quickly
publicly post in-use survey results.
    As also previously noted, independent auditors already perform
attest engagements on behalf of parties who are required to demonstrate
compliance via reporting. Under part 80, the regulated party (e.g., a
gasoline manufacturer) is required to hire an auditor to perform the
attest engagement, and the auditor gives the attest engagement to the
party who then must submit it to EPA. In order to streamline the
reporting process, we are proposing to require auditors to submit the
attest engagement directly to EPA in a manner that ensures that the
party for whom it was prepared is aware of the submission to EPA. To
implement this change, auditors would register and associate with the
party to submit reports directly to EPA. Association will ensure that
the regulated party knows and agrees that the auditor is submitting
their report.
3. What Is Included in Registration
    Similar to existing provisions in part 80, registration under part
1090 would entail submitting general information about the company and
its compliance-level activities (e.g., facilities), including the
address, activities engaged in, name of a responsible corporate officer
(RCO), contact information, and location of records. Parties who submit
reports to EPA must complete the steps required to set up an account
with EPA's Central Data Exchange (CDX) and/or with OTAQ Registration
(OTAQReg). Most regulated parties affected by this action have already
registered and have already set up the necessary accounts.
4. Deadlines for Registration
    We are proposing that registration must occur prior to a party
engaging in any activity that requires registration, but we are not
specifying a firm deadline for registration as we have in the past.
Under part 80, new registrants had to register 60 days prior to
engaging in activity. This timeframe remains a useful guideline,
however, as we must be allowed an appropriate amount of time to process
and activate registration-related requests. We are retaining the
requirements from part 80 that updates to existing registration must
occur within 30 days of the event requiring the change. We do not
expect many new registrants and existing registrants would continue to
be registered under part 1090. However, we do anticipate registering up
to 100 attest auditors, one surveyor, and 50 third parties. We have
docketed a detailed ICR supporting statement that describes the
recordkeeping and reporting (including registration) burden in terms of
number of parties, hours, and dollars.
    Company and compliance-level (e.g., facility) identification
numbers already in use will remain valid under part 1090.
5. Proposed Approach to Changes in Ownership
    In part 1090 we have sought to address some on-going issues and
concerns regarding registration updates. For example, we have received
feedback over the years from registrants that changes in ownership
should be addressed more clearly in the registration section.
Consequently, we

are proposing provisions to clarify how a company may initiate a change
in ownership for registration purposes. The proposed provisions on
updating registrations for ownership change largely codify existing
guidance provided to companies under part 80.
    Proposed provisions in part 1090 clarify that companies would have
to notify EPA of a change in ownership and, in cases requiring
registration of a new company, complete registration prior to engaging
in any activity requiring registration under part 1090. In the case of
a change in ownership requiring an update to an existing registration,
the company would need to complete the registration update within 30
days of the change. For any party that is a fuel or fuel additive
manufacturer, the new owner would need to be in full compliance with
any applicable part 79 registration requirements. Since part 1090
registration is needed in order to report and engage in credit
transactions and comply with the fuel quality regulations, parties have
great incentive to submit ownership change information to EPA as soon
as it is available. We have received feedback from stakeholders who
have told us that having a requirement that they submit ownership
change information by a specific, advance deadline (e.g., 60 days
before the change in ownership occurs) is not workable due to how
ownership changes are effectuated in the business world. Although we
are not proposing a specific, advance deadline, we note that it
typically takes some time for EPA to process a new registration and
urge companies to attempt to submit materials as soon as possible and
to consider that 60 days prior is a good guideline. Based on our
experience with ownership changes under part 80, companies want EPA to
activate registration changes for ownership changes in a timely manner
to ensure that registrations are up-to-date and that the company can
engage in credit generation, trading, and use as soon as practical.
Often, these companies request a specific date for the ownership change
to be reflected with respect to their registration. Because many
ownership changes in the fuel quality programs are quite complicated
and involve many facilities, in order for EPA to reasonably act on this
type of registration update, we need adequate time to process
registration changes.
    We believe common ownership changes may include: Companies and/or
facilities that are bought in their entirety by another party;
companies and/or facilities whose majority owner changes; or a merger
resulting in creation of a new company and/or facility. We are not
proposing a specific list of documentation that parties may have to
submit to support a change in ownership affecting their registration.
What documentation, if any, is needed is highly situational. However,
we do have experience with typical documentation submitted by parties
that may be appropriate, and that may include: sale documentation or
contract (portions may be claimed as CBI and redacted); Articles of
Incorporation, Certificate of Incorporation, or Corporate Charter
issued by a state; and/or other legal documents showing ownership
(e.g., deeds). Parties anticipating the need to update registration due
to a change in ownership should contact EPA as soon as possible in
order to discuss their unique situation.
6. Proposed Approach to Cancellation of Registration
    We are proposing provisions regarding voluntary and involuntary
cancellation of registration. Similar provisions exist for the RFS
program in 40 CFR part 80, subpart M, and we believe they work well for
both compliance and compliance assistance purposes; therefore, we are
proposing to adopt them for part 1090.
    Voluntary cancellation would be initiated by the registered party
(e.g., if the party's business changes and it no longer engages in an
activity that requires registration).
    Involuntary cancellation would be initiated by EPA, typically in
cases where the party has failed to submit required reports or attest
engagements, or for a prolonged period of inactivity. Specifically,
involuntary cancellation may occur where:
     The party has not accessed its account or engaged in any
registration or reporting activity within 24 months.
     The party has failed to comply with any registration
requirements, such as updating needed information.
     The party has failed to submit any required notification
or report within 30 days of the required submission date.
     The attest engagement has not been received within 30 days
of the required submission date.
     The party fails to pay a penalty or to perform any
requirements under the terms of a court order, administrative order,
consent decree, or administrative settlement between the party and EPA.
     The party submits false or incomplete information.
     The party denies EPA access or prevents EPA from
completing authorized activities under sections 114 or 208 of the CAA
despite presenting a warrant or court order. This includes a failure to
provide reasonable assistance.
     The party fails to keep or provide the records required by
part 1090.
     The party otherwise circumvents the intent of the CAA or
part 1090.
    We would provide notification of our intention to cancel the
party's registration and the registrant would have an opportunity to
address any deficiencies identified in the notice (e.g., to submit
required reports) or to explain why no deficiency exists. If we do not
receive missing reports within 14 days of notification, then the
registration may be canceled without further notice. We believe it is
important to have a procedure to keep registrations up-to-date and to
ensure that parties perform activities required to maintain active
registration.
    We are proposing that in instances of willfulness or those in which
public health, interest, or safety requires otherwise, EPA may
deactivate the registration of the party without any notice to the
party. In such cases, we will provide written notification to the RCO
identifying the reason(s) EPA deactivated the registration of the
party. We expect such situations to be extreme and rare and intend to
follow the notice and response provisions described above in nearly all
cases.

C. Reporting

1. Purpose of Reporting
    We require reports from regulated parties for the following
reasons: (1) To monitor compliance with standards necessary to protect
human health and the environment; (2) to allow regulated parties to
comply with average standards via the use of credits and credit trading
systems; (3) to have accurate information to inform EPA decisions; and
(4) to promote public transparency. Regulated parties submit various
reports to EPA under both parts 79 and 80. Part 1090 updates and, in
many cases simplifies, what must already be reported to EPA under part
80. As described further in this section, we are proposing to reduce
the number of parameters to be tested and reported and, in some cases,
to reduce the required frequency of reporting.
2. Who Must Report
    The following parties would have to report under part 1090:

 Gasoline manufacturers
 Diesel manufacturers and ECA marine manufacturers
 Transmix Processors
 Oxygenate producers
 Certified butane blenders
 Certified pentane producers

 Certified pentane blenders
 Independent surveyors
 Auditors

    As discussed earlier in this section, certain parties are required
to register to receive company and compliance-level identification
numbers for use on PTDs and for recordkeeping, although they would not
have reporting requirements under part 1090. For example, parties
involved in the manufacture and distribution of 500 ppm LM diesel fuel
would register and receive company and compliance-level identification
numbers to use on PTDs and records but would not submit reports under
this part 1090.
3. What Is New With This Proposal
    We are proposing to eliminate reporting of the following gasoline
parameters that are currently collected under part 80 and no longer
necessary under part 1090 to certify batches and demonstrate compliance
with the RFG standards (discussed in more detail in Section V.A.2):
 Aromatics and the associated test method
 Olefins and the associated test method
 Methanol and the associated test method
 MTBE and the associated test method
 Ethanol and the associated test method
 ETBE and the associated test method
 TAME and the associated test method
 T-Butanol and the associated test method
 T50 and the associated test method
 T90 and the associated test method
 E200 and the associated test method
 E300 and the associated test method
 Toxics
 VOCs
 Exhaust Toxics Emission
 Other identifying information (i.e., Batch Grade, lab waiver,
Independent lab analysis requirement)

    We are proposing to retain only four main parameters for gasoline
reporting: Sulfur, benzene, RVP, and oxygenate type/content.\90\ We
believe the parameters we are proposing to eliminate from reporting,
although once useful, are no longer needed in reports, as discussed in
Section V.A.2. Removing these parameters would reduce compliance costs
related to reporting, sampling, and testing, without sacrificing our
goal of protecting human health and the environment. We are also
proposing to simplify the annual, batch, and credit transactions
reporting, which result in many fewer forms and data elements for
respondents.
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    \90\ For batches that are certified using the hand blend
approach (discussed in more detail in Section VII.F), oxygenates
typically would not be tested; however, gasoline manufacturers would
report the type and amount of each oxygenate blended to make the
hand blend. Manufacturers that certify batches of gasoline using a
different approach would still need to test and report oxygenate
content unless they know that the gasoline contains no oxygenate
(i.e., the gasoline is E0). Furthermore, in all cases, we would only
require that gasoline manufacturers report the oxygenates added or
tested for instead of reporting information for all potential
oxygenates. We believe this would greatly simplify oxygenate
reporting requirements compared to part 80.
---------------------------------------------------------------------------

    There are currently numerous reporting forms in use under part 80;
we seek to simplify and reduce the number of forms under part 1090.
Proposed reporting formats are available in the docket for this action
and have also been included in the information collection request (ICR)
described in Section XV.C.
4. Proposed Reporting Requirements for Gasoline Manufacturers
    As previously discussed, we are transferring the current part 80
requirements for annual, batch, and credit transaction reporting for
gasoline manufacturers to part 1090. We are proposing to: (1) Reduce
the number of parameters and test methods to be reported under part
1090 as compared to part 80; and (2) simplify the method of reporting.
The proposed reporting requirements for these parties includes the
following:
     Annual compliance demonstration for sulfur, to include
information about the total volume of gasoline produced or imported,
the compliance sulfur value, summary information about sulfur credits
owned, generated, retired, etc., and information about credit deficits.
This information is like the information already required and submitted
under part 80.
     Annual compliance demonstration for benzene, to include
information about the total volume of gasoline produced or imported,
the compliance benzene value, summary information benzene credits
owned, generated, retired, etc., and information about credit deficits.
This information is like the information already required and submitted
under part 80.
     Batch reporting, including information about individual
batches of gasoline, to include information about the date of
production or import, the volume, the designation of the gasoline or
BOB, the tested sulfur and benzene content of the batch, and the tested
RVP for summer gasoline or BOB. The proposed regulations address
reporting for a variety of gasoline products and reporting scenarios
and explains reporting for specific scenarios, such as the reporting
for blendstocks added by gasoline manufacturers to PCG by either the
compliance by addition or compliance by subtraction method and
reporting for blending of certified butane or pentane. We have prepared
a technical memorandum and a detailed color-coded batch reporting
summary table reflecting the information to be submitted for a variety
of products. This information is available in the docket for this
action and has been provided as an addendum to the ICR described in
Section XV.C.
     Credit transaction reporting, including information about
the generation, purchase, sale, retirement, etc. of sulfur and benzene
credits. This information is like the information already required and
submitted under part 80.
     Attest engagements. Under part 1090, there is a change to
the method of submission of annual attest engagements. As discussed
above, we are proposing to add independent auditors to the list of
parties that can submit attest engagements, provided that they first
register with EPA and are associated with a company. To ensure the
party for whom the attest engagement is prepared is aware, we are
proposing that the independent auditor and the company for whom they
are preparing the report must associate within the registration system.
The existing attest engagement requirements are sprinkled around part
80; this action would condense the existing requirements into a single
subpart (subpart R). We are also proposing to align the submission of
the attest engagements for the RFS program so that they would be
submitted directly by the independent auditor and to include
association, as well. We are aware that some regulated parties have
expressed concern that they would not know if their attest engagement
has been submitted by the auditor and would not be afforded time to
review and respond to the auditor's findings. To address this concern,
we are requesting comment from regulated parties on what information
and required steps are needed prior to submission by the attest
auditor. The attest engagement submission would require a description
of the findings and the steps the regulated party will take to address
remedial actions, but does not necessarily require the remedial action
steps to all occur before submission. Attest engagements are discussed
in detail in Section XII.B.

5. Proposed Reporting Requirements for Gasoline Manufacturers That
Recertify BOB for Different Type(s) and Amount(s) of Oxygenate
    In order to implement the proposed optional provisions discussed in
Section VII.G with respect to treatment of BOBs, we are proposing
reporting requirements for gasoline manufacturers that recertify BOB
for different types and amounts of oxygenate. When a person recertifies
a BOB with less oxygenate than specified by the fuel manufacturer, they
would be required to submit information about recertification activity
on a batch level report and include any deficits incurred in their
annual sulfur and benzene compliance report.\91\ Credit transactions
associated with re-certification of the BOB would also be reported.
Similar to what is currently allowed under part 80 for certified butane
and pentane blending, we are proposing to allow parties that recertify
BOBs to include all volumes and deficits in a single reported batch of
up to 30 days. This will help minimize the potential reporting burden
associated with this requirement.
---------------------------------------------------------------------------

    \91\ Parties that add more of the same type of oxygenate would
not be expected to submit reports for those volumes. For example,
under part 1090, if a party only blended 15 volume percent ethanol
into a BOB that was specified for blending up to 10 volume percent
ethanol, the blender would not submit reports.
---------------------------------------------------------------------------

6. Proposed Reporting for Oxygenate Producers and Importers
    We are proposing that oxygenate producers and importers must
continue under part 1090 to submit batch reports providing information
about the oxygenate they produce or import as already required under
part 80. Reporting for oxygenate producers would be on a compliance-
level (e.g., facility) basis. The information to be submitted includes
information about the oxygenate produced or imported, including the
sulfur content of the batch and the test method used. For denatured
ethanol, the report would specify whether the denaturant is certified
ethanol denaturant or non-certified. The information contained in these
reports does not differ from current part 80 reporting requirements,
but the proposed regulation is designed to standardize the type and
format of the information submitted.
7. Proposed Reporting for Certified Pentane Producers and Importers
    We are proposing that certified pentane producers and importers
submit batch reports that provide information about the certified
pentane produced or imported, including the pentane, sulfur, and
benzene content of each batch and the test methods used. The
information contained in these reports does not differ from current
part 80 reporting requirements, but the proposed regulation is designed
to standardize the type and format of the information submitted.
8. Proposed Reporting by Diesel Manufacturers
    We are proposing limited batch reporting for manufacturers of
diesel fuel. Specifically, we are proposing that manufacturers of
diesel fuel (excluding 500 LM from transmix) that test any batch found
to exceed the applicable 15 ppm sulfur standard would report
information about that batch. Batches that do not exceed the applicable
15 ppm sulfur standard would not be reported to EPA. The specific
information proposed to be reported includes the company and facility
identifier, the batch identifier, and the tested sulfur content in ppm,
and test method used. Since diesel manufacturers are required to test
their product for sulfur content and must retain information related to
sampling and test results already, we believe the burden of reporting a
relatively small number of batches found to exceed the applicable 15
ppm is small. We acknowledge that diesel sulfur batch reporting under
40 CFR part 80, subpart I, generally ended on September 1, 2014;
however, the requirement to test and retain records related to sulfur
content continues. We are proposing limited batch reporting because we
believe it will assist us in our compliance oversight efforts and in
ensuring that the human health and environmental benefits of the
program are realized.
    We also collect some information about diesel sulfur via the annual
fuel manufacturer reports, required under part 79. The existing reports
are limited in their contemporary value for several reasons. First,
they require only information about highway diesel fuel and do not
include NRLM diesel fuel. Second, they require information on a
manufacturer level, rather than on a facility/refinery level and,
therefore, are of limited use for compliance purposes. Third, the high/
low/average sulfur values are collected as a volume percentage rather
than in ppm, a throwback to the 1970s when diesel sulfur levels were
not regulated and sulfur content was much higher. Our purpose in
collecting this information at that time was to understand, on a high
level, the general characteristics of fuel that may affect human health
and the environment and to determine whether future regulation might be
needed. The part 79 reports have historically collected the information
to the extent known by the manufacturer. Although manufacturers of
diesel fuel have been submitting the information, it is submitted in an
inconsistent format. For example, we typically receive values expressed
in ppm already, as the use of volume percent is no longer the preferred
method.
    We are proposing to transition diesel sulfur reporting from part 79
and move it entirely into part 1090 reporting forms. This transition
includes reporting total volume and max/average sulfur results (using
ppm as the unit of measure) by company ID and five-digit reporting ID
(i.e., facility ID).
9. Reports by Independent Surveyors
    As previously discussed, we are proposing to remove the requirement
for registration and submission of reports by independent laboratories
and also proposing a requirement for registration and reporting by
independent surveyors. The proposed registration requirement for
independent surveyors are discussed in greater detail in Section
X.A.2.d. For reporting purposes, an independent surveyor must submit
plans, notifications, and quarterly survey reports to EPA
electronically. The quarterly reports include information about retail
outlets visited by the independent surveyor and the characteristics of
the fuels samples and tested (e.g., oxygenate type and amount, sulfur
content, benzene content, etc.). Independent surveyors would also have
an annual reporting requirement that addresses summary statistics and
describes compliance rates and non-compliance issues. For the proposed
national survey program, this type of information is already collected
as part of the part 80 survey programs. Information collected under the
proposed national sampling oversight program is like information
already collected under the RFG independent laboratory testing program
under part 80.
10. Deadlines for Reporting
    We are proposing that the annual reports by independent surveyors
must be submitted by March 31. We are retaining the existing deadlines
for reports under part 80 for reports submitted under part 1090.
Specifically:
     Annual compliance reports for sulfur and benzene would
continue to be submitted by March 31 for the preceding compliance
period (e.g., reports covering the calendar year 2021 must be submitted
to EPA by March 31, 2022).

     Batch reports would be submitted by March 31 for the
preceding compliance period. This was previously the fourth quarter
batch reporting due date. We are proposing to reduce the frequency of
batch reporting that currently applies under part 80, going from
quarterly to annually.
     Attest engagements would continue to be submitted by the
independent auditor by June 1 for the preceding compliance period.
     Reports by independent surveyors would continue to be
submitted quarterly on June 1 (covering January 1-March 31), September
1 (covering April 1-June 30), December 1 (covering July 1-September
30), and March 31 (covering October 1-December 31). Annual reports by
independent surveyors must be submitted by March 31.
11. Proposed Reporting Forms
    Proposed reporting formats are discussed in more detail in the
technical memorandum covering batch reporting, available in the docket
for this action, and in the ICR. The ICR includes actual proposed
reporting instructions. Interested parties are urged to review these
materials and provide feedback.
    The information collected in the proposed reports should be
familiar to existing registered and reporting parties. We have designed
part 1090 and the proposed reports to address areas where reporting
requirements were previously unclear or cumbersome and to reduce the
existing reporting burden.

D. Product Transfer Documents (PTDs)

    The general purpose and requirements for PTDs do not differ from
the existing requirements in part 80. PTDs are documents generated in
the normal course of business that provided a clear description of the
product being transferred. Under part 1090, PTDs would still be
required each time a person transfers title or custody to a product
regulated under part 1090. The typical format of PTDs is not changed by
this action--basic information including identification of the
transferor/transferee, location of the transfer, volume and type of
product, etc. remain familiar. As with existing part 80, commonly
understood codes may be used by ``upstream parties'' and where a
transfer is made to those other than truck carriers, retailers, or
wholesale purchaser-consumers (WPCs). Transfers to truck carriers,
retailers, or WPCs would require the specified, printed statement and
product information rather than a code. As with existing part 80, PTDs
would have to be kept by each transferor and transferee.
    Part 1090 mostly consolidates the various PTD language requirements
throughout part 80 into a single, consistent section to help bring
uniformity to the PTD language across fuels, fuel additives, and
regulated parties. This action would remove PTD language that is no
longer needed and provide standard, updated language to address a
variety of common products and situations. We are, however, proposing
some minor modifications from the existing part 80 requirements.
    We are proposing language to identify fuel covered by all known,
specific exemptions (e.g., R&D exemption, racing fuel exemption, etc.)
in a more consistent manner. Part 80 only requires that exempt fuels be
identified on PTDs as exempt and is inconsistent with its language
requirements across the various part 80 fuel quality programs. We
intend to make our PTD requirements more consistent so we are proposing
a more prescriptive format for exempt fuels.
    Under some programs in part 80, we have allowed parties to petition
for alternative PTD language for some PTD requirements, but not for
other PTD requirements. During the rule development process, several
stakeholders highlighted that instances exist where our PTD
requirements may conflict with other federal, state, or local PTD or
identification requirements. In such cases, fuels, fuel additives, or
regulated blendstocks could be identified with contradictory language
that makes it difficult for parties in the fuel distribution system to
comply with all applicable federal, state, and local requirements. To
address these potential issues, we are also proposing to allow parties
to seek approval for alternative PTD language for all proposed PTD
language requirements. Based on experience implementing part 80, we do
not anticipate that many parties will request alternative PTD language.

E. Recordkeeping

    We are maintaining the record retention requirements in part 80.
All parties that keep records under part 80 would continue to keep the
same or similar records under part 1090. Records that must be
maintained are those already familiar to regulated parties, including:
Information that supports the registration and reports submitted to
EPA, information related to waivers (such as R&D programs), copies of
PTDs, sampling and test results and related laboratory documents,
information about credit transactions for sulfur and benzene, and
information related to compliance calculations. We anticipate that the
number of records retained will decrease under part 1090, in large part
because the number of sampled, tested, and reported parameters for
gasoline and certain regulated blendstocks would decrease.

F. Rounding

    The standards and compliance requirements under part 1090 require
extensive use of numbers to quantify fuel parameters and fuel volumes,
along with numerous occasions to calculate new quantities to properly
document compliance. A rigorous compliance demonstration depends on
properly managing precision and significant figures in recorded values
and calculations. Part 80 addresses rounding and precision by simply
instructing regulated parties to round test results to the nearest unit
of significant digits specified in the applicable fuel standard as
described in ASTM E29. We are proposing a much broader and consistent
approach in part 1090. We codified a standard approach to rounding in
40 CFR 1065.20 that is consistent with ASTM E29. We are proposing to
apply this rounding protocol to all recorded values under part 1090.
    The action includes additional specifications for calculating and
recording numerical values. First, we are proposing to specify that
rounding intermediate values in a calculation is not appropriate. This
principle is intended to preserve the accuracy and precision until the
calculations reach a final result, at which point the final result can
be rounded to the appropriate number of decimal places or significant
figures. We recognize that intermediate values must sometimes be
transcribed (such as from an analyzer to a spreadsheet), which cannot
be done with infinite precision. We are therefore proposing that
intermediate values should be recorded and used with full precision,
except that rounding is permissible if the value retains at least six
significant digits. This is not a proposal to require six significant
digits for all recorded values. Rather, if an intermediate quantity
with more than six significant digits needs to be transcribed, parties
may use the specified rounding protocol to eliminate the additional
digits. Also note that we generally allow for using measurement devices
that incorporate proper internal rounding protocols to report test
results.
    Second, multiplying a value by a percentage must keep the precision
of the original value. This is equivalent to considering the specified
percentage to be infinitely precise. For example, calculating 1 percent
or 1.0 percent of 1,234 would result in a value of 12.34.

This is relevant for calculating an averaging standard for benzene.
Fuel volume is multiplied by exactly 0.62 percent, rather than using a
value of 0.624 (which rounds down to 0.62) before multiplying by fuel
volume.

G. Certification and Designation of Batches

    The certification and designation of batches of fuels, fuel
additives, and regulated blendstocks are crucial elements to ensuring
that fuels, fuel additives, and regulated blendstocks meet our fuel
quality standards and aid in the distribution of such products.
Certification is the process where a manufacturer or producer
demonstrates that their product meets EPA's standards. Designation is
the identification of a batch (typically on PTDs) as meeting specific
requirements for a category of fuel (e.g., summer RFG), fuel additive
(e.g., diesel fuel additives), or regulated blendstocks (e.g.,
certified butane or certified pentane). Parties throughout the fuel
distribution system rely on designations to appropriately transport,
store, dispense, and sell fuels. Part 80 generally has provisions for
certification and designation of products separately for each program.
Part 1090 consolidates these various certification and designation
procedures into a single set of provisions.
    Regarding certification, most of the certification procedures for
fuels, fuel additives, and regulated blendstocks for part 80 are
outlined in guidance. We are proposing in part 1090 to incorporate such
guidance into the regulations and establishes a clear process to
certify batches. The proposed regulations include the following four
steps:
     Registration prior to the production of fuel, fuel
additive, or regulated blendstock (if required).
     Sampling and testing the fuel, fuel additive, or regulated
blendstock to demonstrate that the product meets applicable quality
standards.
     Assignment of a batch identification number (if required).
     Designation of the batch as appropriate.
    We believe these four steps are consistent with how parties
currently certify products under part 80. These requirements satisfy
CAA section 211(k)(4) describing certification procedures for RFG.
    Regarding designation, for gasoline and gasoline-related additives
and regulated blendstocks, we are proposing to substantially modify the
designation requirements for these products. Most of these proposed
changes reflect the removal of the Complex Model for use in the
certification of batches of RFG and the harmonization of the RFG and CG
programs. Many of the prior designations to segregate RFG and CG are no
longer necessary, so we are proposing to remove those designations.
Additionally, we are proposing more flexible redesignation provisions
for distributors of gasoline. These proposed provisions largely reflect
the proposed streamlining of the RFG program and the more fungible
nature that would result.
    Distributors of gasoline would be allowed to redesignate winter
RFG/RBOB to winter CG/CBOB (and vice versa) and summer gasoline from a
more stringent RVP standard to a less stringent RVP standard without
recertification (e.g., from summer RFG meeting the 7.4 psi RVP standard
to 9.0 psi RVP summer CG). Any person that mixes summer gasoline with
summer or winter gasoline that has a different RVP designation must
either designate the resulting mixture as meeting the least stringent
RVP designation of any batch in the blend or determine the RVP of the
mixture and designate the new batch accurately to reflect the RVP of
the gasoline as described under this section. When transitioning from
winter to summer gasoline, parties are not required to test the RVP but
must exercise good engineering judgement to assure that the gasoline
meets the applicable RVP standard.
    We are also making it clear that parties can redesignate California
gasoline that meets CARB standards without recertification, as
explained in more detail in Section VI.A. We believe these
flexibilities will help maximize the fungibility of gasoline.
    For diesel fuel, diesel additives, and diesel regulated
blendstocks, we are largely proposing to maintain the part 80
designation requirements. We are, however, proposing two notable
changes. First, we are proposing a more flexible designation scheme for
distillate fuels certified to meet ULSD standards. The intent of the
proposed regulations is to ensure that fuels that meet the ULSD
standards could be designated as necessary to be used as home heating
oil, motor vehicle, nonroad, locomotive, or marine diesel fuel (defined
as MVNLRM diesel fuel in part 80), or IMO marine fuel. This change
would allow parties to make sure that fuels are designated
appropriately throughout the distribution system.\92\ Second, similarly
to gasoline, we are proposing to allow parties to redesignate
California diesel fuel that meets the ULSD standards without
recertification. We believe the proposed designation changes for diesel
fuel would help maximize the fungibility of distillate fuels that meet
the ULSD standards.
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    \92\ This action does not address how these fuels are accounted
for inclusion in obligated parties' RVO calculations under the RFS
program. We recently finalized changes to part 80 to account for the
redesignation of distillate fuels meeting the ULSD standards (see 85
FR 7054-7057, February 6, 2020).
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    We seek comment on the proposed certification and designation
provisions.

IX. Sampling, Testing, and Retention Requirements

    Our fuel quality programs consists of performance standards and
compliance provisions that require measurement of various fuel
parameters. These measurements in turn rely on specified procedures
contained in part 80. We are transferring these same test procedures
from part 80 into part 1090. We are also reorganizing the testing
provisions in part 1090 and proposing several clarifications to reflect
current best practices. We are further consolidating test procedures
for gasoline and diesel fuel in some cases. This section highlights the
proposed changes relative to what currently applies under part 80.\93\
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    \93\ The updated procedures are described in greater detail in
the technical memorandum, ``Technical Issues Related to Streamlining
Measurement Procedures for 40 CFR part 1090,'' available in the
docket for this action.
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A. Overview and Scope of Testing

    Part 80 requires gasoline manufacturers to measure 11 complex model
parameters. This action would significantly reduce the number of
parameters that gasoline manufacturers must measure for determining
compliance with the fuel standards. Part 1090 would require fuel
manufacturers to measure the sulfur and benzene content of every batch
of gasoline and to measure the RVP of every batch of summer gasoline.
Fuel manufacturers will also be required to sample and test for
oxygenates in specific situations when EPA believes it could be
difficult for the fuel manufacturer to assure compliance with oxygenate
standards without sampling and testing the gasoline. For gasoline
produced at a blending manufacturing facility or a transmix processing
facility, we are retaining the part 80 requirement to test gasoline for
distillation parameters. The distillation testing provides a
distillation curve that shows how much of the gasoline has flashed off
as the temperature of the sample is increased. This curve can provide
some confirmation that the blended product has a distillation profile
that is generally

consistent with gasoline meeting the substantially similar requirements
of the CAA. The results of the distillation testing would not be
required to be reported, but instead would be retained at the facility
to provide additional data that can be reviewed in the event of
complaints about potential compliance or performance issues. We
understand that distillation parameters are effectively a condition of
merchantability of gasoline in the U.S., so such testing is already
being performed by fuel manufacturers.
    Part 80 requires RFG refiners to obtain test results for all
parameters required to determine compliance. Part 80 also requires CG
refiners to measure sulfur content in gasoline and diesel fuel prior to
introduction into commerce. Requiring measurement before shipping from
the refinery provides assurance of compliance prior to the fuel being
mixed and commingled in the fungible distribution system and
potentially even consumed. Unlike many regulatory situations where it
is possible to go back after the fact and correct the noncompliance,
this is difficult if not impossible in most situations for fuel once it
has left the fuel manufacturing facility. Consistent with part 80, we
are proposing to require all gasoline manufacturers to obtain test
results for sulfur and RVP (during the summer months) before shipping
gasoline from the fuel manufacturing facility. Part 80 requires RFG
refiners to obtain test results for benzene before shipping gasoline,
but does not require CG refiners to obtain these results before
shipping from the refinery. We are not proposing to require gasoline
manufacturers to test for benzene before shipping gasoline from the
fuel manufacturing facility, but we are seeking comment on whether this
would be appropriate. Some fuel manufacturers have suggested that being
able to test after shipping product from the fuel manufacturing
facility would make the testing substantially less burdensome. Taking
time to perform testing and verify results can cause delays in managing
the flow of producing and shipping product. We are not revising fuel
requirements that impose the obligation to test fuels before shipping
from the fuel manufacturing facility. With the simplified test
requirements of the streamlined program, we believe there is no
justification to avoid the compliance-assurance advantage of individual
batch measurements whenever that is possible. However, we seek comment
on this and what provisions could be put in place in its absence to
provide assurance that the fuel met the standards in the absence of
testing. For example, we could require fuel manufacturers to keep
records documenting their engineering assessment that supports a
conclusion that the fuel meets applicable standards despite the absence
of test results. Such an assessment would need to account for varying
refinery processes, maintenance or other system changes, personnel
changes, source and quality of any blending components, and any other
relevant variables.
    We are maintaining exceptions to testing under current waivers that
do not require measurement of fuel properties prior to shipment.
Currently 40 CFR 80.65, 80.581, and 80.1630 describe separate programs
for in-line blending configurations to qualify for a waiver from the
test-before-ship requirements as part of an approved process with
annual quality audits. We are transferring these existing provisions
that allow for the in-line blending waiver only for shipment
configurations because they do not allow for conventional batch
testing. For example, sending finished fuel directly into a pipeline or
a marine vessel generally does not allow for conventional batch
measurement, so we expect refiners to continue to rely on the in-line
blending waiver for these shipping arrangements. Refiners are similarly
prevented from timely batch measurements if they create fuel batches
that are greater than they can contain in a single storage tank. We are
therefore transferring these existing part 80 waiver provisions for in-
line blending also to operations that involve these over-sized batches
to part 1090. The transferred provisions, when effective, would mean
that the restricted application of the in-line blending waiver does not
prevent refiners from using automated in-line sampling procedures as
described in ASTM D4177 for measuring fuel parameters for a given
batch.

B. Handling and Testing Samples

1. Collecting and Preparing Samples for Testing
    Accurate test results are dependent on the sample being
representative of the fuel batch. We are transferring the sampling
procedures and demonstrating homogeneity of fuel samples that are
currently specified in 40 CFR 80.8. This provision generally specifies
procedures for manual sampling as described in ASTM D4057 or automated
in-line sampling as described in ASTM D4177. The additional procedures
for sampling related to gasoline RVP as described in ASTM D5842 are
also being transferred to part 1090.
    Some of the current regulations in part 80 related to sample
collection, however, do not adequately address sampling procedures
because they do not provide the necessary specifications for testing.
We have addressed some of those omissions through guidance documents
published over the years.\94\ We are also proposing to add numerous
minor clarifications and adjustments to the regulatory text to reflect
current best sampling practices.
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    \94\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10,
1997,'' EPA-420-R-03-009, July 2003.
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2. Sample Preparation for BOB Testing
    Section VII describes the proposed new approach for oxygenate
accounting for gasoline that would allow parties that either produce or
import BOB and instruct downstream blenders to add oxygenates to meet
sampling requirements by blending oxygenates into a BOB sample to
represent the final blended fuel--a ``hand blend.'' \95\ This would
involve preparing each fuel sample by adding oxygenates to the BOB
sample in a way that corresponds to instructions to downstream blenders
for the sampled batch of fuel.
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    \95\ The regulations at 40 CFR 80.69 and 80.101 practically
limits this practice to RBOB. As discussed in Section VII, we are
proposing to make it more practical for all fuel manufacturers of
BOB to account for the addition of oxygenate added downstream. Part
80 does not currently specify preparation procedures for hand
blends.
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    Preparing the hand blend sample involves decisions about which
samples to use for blending. For example, three tested BOB samples may
be available to prepare the hand blend. Also, a single hand blend might
represent different types and amounts of oxygenate, as reflected in the
blending instructions for downstream parties. We are proposing to
address these examples of discretion in the specified procedures by
requiring that the hand blend represent a worst-case test condition. In
the case of sulfur measurements from multiple samples to represent a
batch of BOB, this requires further testing with the sample that has
the highest sulfur measurement.
    Winter gasoline would need to be blended with the lowest specified
percentage of any oxygenate type given in the instructions for
downstream blending. For example, if blending instructions specify an 8
percent isobutanol blend in addition to E10 and E15, the hand blend
would need to be an 8 percent isobutanol blend. This reflects the fact
that dilution is the primary effect of blending on fuel parameters
other than RVP. A different

approach is necessary to properly select the type and amount of
oxygenate for hand blending in summer gasoline. Under this proposal,
summer gasoline would need to be blended with the lowest specified
percentage of ethanol given in the instructions for downstream blending
(i.e., blend for E10 if the instructions identify E10 and E15 for
downstream blending, even if the blending instructions include an
option to blend with a lower percentage of a different oxygenate).
3. Sample Retention
    Part 80 currently describes sample-retention requirements in
multiple provisions. Stakeholders have pointed out that there is
ambiguity about whether the regulation requires sample retention for 30
or 90 days. We are proposing to require all fuel manufacturers to keep
fuel samples used to demonstrate compliance with all applicable
standards for 30 days, except for blending manufacturers.
    A longer retention time applies for blending manufacturers since
these manufacturers typically have less control over the quality of the
blendstocks they use to produce gasoline, which can cause decreased
fuel quality without robust controls. Crude refineries typically
distribute fuels through a distribution network with multiple levels of
control to ensure fuel quality (e.g., through pipelines that have
strict product specifications prior to injection) while blending
manufacturers can make fuels on a more ad hoc basis (e.g., in a tanker
truck). We therefore believe it is appropriate to require a longer
retention period to help trace potential issues with fuel quality. We
are proposing a minimum retention period of 120 days for fuel samples
that blending manufacturers use for testing to demonstrate compliance
with gasoline or diesel fuel standards.
    For testing BOB and hand blended samples of oxygenated gasoline as
described in Section IX.C, the sample-retention requirements apply for
both the BOB sample and the hand-blended sample used to demonstrate
compliance. Gasoline manufacturers producing BOB have expressed a
concern that space limitations would make it difficult to store both
the BOB sample and the hand-blended sample used to demonstrate
compliance. We are therefore proposing that gasoline manufacturers do
not need to keep each hand-blended sample; they would instead need to
keep a DFE sample to allow them to create new hand-blended samples
corresponding to each BOB sample. With this approach, a single DFE
sample might be available for blending with multiple BOB samples.

C. Measurement Procedures

    Demonstrating compliance with fuel quality standards requires a
wide range of measurement procedures. Our fuel quality regulations rely
heavily on standardized test methods published by voluntary consensus
standards bodies such as ASTM International. As described below, the
proposed regulations in part 1090 reference certain measurement
procedures, in most cases with provisions allowing for using
alternative procedures, including updated versions of referenced
procedures in some instances.
1. Procedures for Gasoline Surveys
    Testing for gasoline surveys is intended to provide a consistent
indication of in-use fuel parameters over time. Testing will generally
be performed by a selected set of test labs to represent the range of
fuels in distribution over time.
    We are proposing to require that survey measurements rely on the
referee procedures identified under PBMS, where applicable. The
following procedures apply for additional parameters:

 ASTM D5769 for aromatic content
 ASTM D6550 for olefin content
 ASTM D86 for T50 and T90 distillation points

    We request comment on the specified procedures for measuring the
various fuel parameters for surveys.
2. Procedures To Determine Cetane Index for Diesel Fuel
    Part 80 and the Clean Air Act establishes a cetane index standard
at or above 40 for diesel fuel used with motor vehicles and nonroad
equipment. (See 40 CFR 80.520(a)(2)). Part 80 also references ASTM D976
as the procedure for determining cetane index in diesel fuel. During
the development of this action, industry stakeholders advocated for