distinction. EPA believes that the Act as a whole is best interpreted
as requiring all types of qualifying renewable fuels under EISA to be
made from renewable biomass. In this manner the land and feedstock
restrictions that Congress deemed important in the context of biofuel
production apply to all types of renewable fuels.
    EPA also does not agree with the commenter who suggested that the
listing in the definition of renewable biomass of ``biomass obtained
from the immediate vicinity of buildings and other areas regularly
occupied by people, or of public infrastructure, at risk from
wildfire'' should be interpreted to include MSW. It is clear that the
term ``at risk of wildfire'' modifies the entire sentence, and the
purpose of the listing is to make the biomass that is removed in
wildfire minimization efforts, such as brush and dead woody material,
available for renewable fuel production. Such material does not
typically include MSW. Had Congress intended to include MSW in the
definition of renewable biomass, EPA believes it would have clearly
done so, in a manner similar to the approach taken in EPAct.
    EPA also does not believe that it would be reasonable to interpret
the reference to ``separated yard or food waste'' to include unsorted
MSW. Although MSW contains yard and food waste, such an approach would
not give meaning to the word ``separated.''
    We do believe, however, that yard and food wastes that are part of
MSW, and are separated from it, should qualify as renewable biomass.
MSW is the logical source from which yard waste and food waste can be
separated. As to the degree of separation required, some commenters
suggested a simple ``post recycling'' test be appropriate. They would
leave to municipalities and waste handlers a determination of how much
waste should be recycled before the residue was used as a feedstock for
renewable fuel production. EPA believes that such an approach would not
guarantee sufficient ``separation'' from MSW of materials that are not
yard waste or food waste to give meaning to the statutory text.
Instead, EPA believes it would be reasonable in the MSW context to
interpret the word ``separated'' in the term ``separated yard or food
waste'' to refer to the degree of separation to the extent that is
reasonably practicable. A large amount of material can be, and is,
removed from MSW and sold to companies that will recycle the material.
EPA believes that the residues remaining after reasonably practicable
efforts to remove recyclable materials other than food and yard waste
(including paper, cardboard, plastic, textiles, metal and glass) from
MSW should qualify as separated yard and food waste. This MSW-derived
residue would likely include some amount of residual non-recyclable
plastic and rubber of fossil fuel origin, much of it being wrapping and
packaging material for food. Since this material cannot be practicably
separated from the remaining food and yard waste, EPA believes it is
incidental material that is impractical to remove and therefore
appropriate to include in the category of separated food and yard
waste. In sum, EPA believes that the biogenic portion of the residue
remaining after paper, cardboard, plastic, textiles metal and glass
have been removed for recycling should qualify as renewable biomass.
This interpretation is consistent with the text of the statute, and
will promote the productive use of materials that would otherwise be
landfilled. It will also further the goals of EISA in promoting energy
independence and the reduction of GHG emissions from transportation
fuels.
    EPA notes there are a variety of recycling methods that can be
used, including curbside recycling programs, as well as separation and
sorting at a material recovery facility (MRF). For the latter, the
sorting could be done by hand or by automated equipment, or by a
combination of the two. Sorting by hand is very labor intensive and
much slower than using an automated system. In most cases the ``by-
hand'' system produces a slightly cleaner stream, but the high cost of
labor usually makes the automated system more cost-effective.
Separation via MRFs is generally very efficient and can provide
comparable if not better removal of recyclables to that achieved by
curbside recycling.
    Based on this analysis, today's rule provides that those MSW-
derived residues that remain after reasonably practicable separation of
recyclable materials other than food and yard waste is renewable
biomass. What remains to be addressed is what regulatory mechanisms
should be used to ensure the appropriate generation of RINs when
separated yard and food waste is used as a feedstock. We are finalizing
two methods.
    The first method would apply primarily to a small subset of
producers who are able to obtain yard and/or food wastes that have been
kept separate since waste generation from the MSW waste stream.
Examples of such wastes are lawn and leaf waste that have never entered
the general MSW waste stream. Typically, such wastes contain incidental
amounts of materials such as the plastic twine used to bind twigs
together, food wrappers, and other extraneous materials. As with our
general approach to the presence of incidental, de minimus contaminants
in feedstocks that are unintentionally present and impractical to
remove, the presence of such material in separated yard or food waste
will not disqualify such wastes as renewable biomass, and the
contaminants may be disregarded by producers and importers generating

RINs. (See definition of renewable biomass and 80.1426(f)(1).) Waste
streams kept separate since generation from MSW that consist of yard
waste are expected to be composed almost entirely of woody material or
leaves, and therefore will be deemed to be composed of cellulosic
materials. Waste streams consisting of food wastes, however, may
contain both cellulosic and non-cellulosic materials. For example, a
food processing plant may generate both wastes that are primarily
starches and sugars (such as carrot and potato peelings, as well as
fruits and vegetables that are discarded) as well as corn cobs and
other materials that are cellulosic. We will deem waste streams
consisting of food waste to be composed entirely of non-cellulosic
materials, and qualifying as advanced biofuels, unless the producer
demonstrates that some portion of the food waste is cellulosic. The
cellulosic portion would then qualify as cellulosic biofuel. The method
for quantifying the cellulosic and non-cellulosic portions of the food
waste stream is to be described in a written plan which must be
submitted to EPA under the registration procedures in 80.1450(b)(vii)
for approval and which indicates the location of the facility from
which wastes are obtained, how identification and quantification of
waste material is to be accomplished, and evidence that the wastes
qualify as fully separated yard or food wastes. The producer must also
maintain records regarding the source of the feedstock and the amounts
obtained.
    The second method would involve use as feedstock by a renewable
fuel producer of the portion of MSW remaining after reasonably
practical separation activities to remove recyclable materials,
resulting in a separated MSW-derived residue that qualifies as
separated yard and food waste. Today's rule requires that parties that
intend to use MSW-derived residue as a feedstock for RIN-generating
renewable fuel production ensure that reasonably practical efforts are
made to separate recyclable paper, cardboard, textiles, plastics, metal
and glass from the MSW, according to a plan that is submitted by the
renewable fuel producer and approved by EPA under the registration
procedures in 80.1450(b)(viii). In determining whether the plan
submittals provide for reasonably practicable separation of recyclables
EPA will consider: (1) The extent and nature of recycling that may have
occurred prior to receipt of the MSW material by the renewable fuel
producer, (2) available recycling technology and practices, and (3) the
technology or practices selected by the fuel producer, including an
explanation for such selection and reasons why other technologies or
practices were not selected. EPA asks that any CBI accompanying a plan
or a party's justification for a plan be segregated from the non-CBI
portions of the submissions, so as to facilitate disclosure of the non-
CBI portion of plan submittals, and approved plans, to interested
members of the public.
    Producers using this second option, will need to determine what
RINs to assign to a fuel that is derived from a variety of materials,
including yard waste (largely cellulosic) and food waste (largely
starches and sugar), as well as incidental materials remaining after
reasonably practical separation efforts such as plastic and rubber of
fossil origin. EPA has not yet evaluated the lifecycle greenhouse gas
performance of fuel made from such mixed sources of waste, so is unable
at this time to assign a D code for such fuel. However, if a producer
uses ASTM test method D-6866 on the fuel made from MSW-derived
feedstock, it can determine what portion of the rule is of fossil and
non-fossil origin. The non-fossil portion of the fuel will likely be
largely derived from cellulosic materials (yard waste, textiles, paper,
and construction materials), and to a much smaller extent starch-based
materials (food wastes). Unfortunately, EPA is not aware of a test
method that is able to distinguish between cellulosic- and starch-
derived renewable fuel. Under these circumstances, EPA believes that it
is appropriate for producers to base RIN assignment on the predominant
component and, therefore, to assume that the biogenic portion of their
fuel is entirely of cellulosic origin. The non-biogenic portion of the
fuel, however, would not qualify for RINs at this time. Thus, in sum,
we are providing via the ASTM testing method an opportunity for
producers using an MSW-derived feedstock to generate RINs only for the
biogenic portion of their renewable fuel. There is no D code for the
remaining fossil-derived fraction of the fuel in today's rule nor for
the entire volume of renewable fuel produced when using MSW-derived
residue as a feedstock. The petition process for assigning such codes
in today's rule can be used for such purpose.
    Procedures for the use of ASTM Method D-6866 are detailed in 40 CFR
80.1426(f)(9) of today's rule. We solicited comment on this method, and
while the context of the discussion of method D-6866 was with respect
to using it for gasoline (see 74 FR 24951), the comments we received
provided us information on the method itself. Also, commenters were
supportive of its use. Fuel producers must either run the ASTM D-6866
method for each batch of fuel produced, or run it on composite samples
of the food and yard waste-derived fuel derived from post-recycling MSW
residues. Producers will be required at a minimum to take samples of
every batch of fuel produced over the course of one month and combine
them into a single composite sample. The D-6866 test would then be
applied to the composite sample, and the resulting non-fossil derived
fraction will be deemed cellulosic biofuel, and applied to all batches
of fuel produced in the next month to determine the appropriate number
of RINs that must be generated. The producer would be required to
recalculate this fraction at least monthly. For the first month, the
producer can estimate the non-fossil fraction, and then make a
correction as needed in the second month. (The procedure using the ASTM
D-6866 method applies not only to the waste-derived fuel discussed here
but also to all partially renewable transportation fuels, and is
discussed in further detail in Section II.D.4. See also the regulations
at Sec.  80.1426(f)(4)).
    The procedures for assigning D codes to the fuel produced from such
wastes are discussed in further detail in Section II.D.5.
    One commenter suggested that biogas from landfills should be
treated in the same manner as renewable fuel produced from MSW. EPA
agrees with the commenter to a certain extent. The definition of
``advanced biofuels'' in EISA identifies ``Biogas (including landfill
gas and sewage waste treatment gas) produced through the conversion of
organic matter from renewable biomass'' as ``eligible for
consideration'' as an advanced biofuel. However, as with MSW, the
statute requires that advanced biofuel be a ``renewable fuel'' and that
such fuel be made from ``renewable biomass.'' The closest reference
within the definition of renewable biomass to landfill material is
``separated yard or food waste.'' However, in applying the
interpretation of ``separated'' yard and food waste described above for
MSW to landfill material, we come to a different result. Landfill
material has by design been put out of practical human reach. It has
been disposed of in locations, and in a manner, that is designed to be
permanent. For example, modern landfills are placed over impermeable
liners and sealed with a permanent cap. In addition, the food and yard
waste present in a landfill has over time become intermingled with
other

materials to an extraordinary extent. This occurs in the process of
waste collection, shipment, and disposal, and subsequently through
waste decay, leaching and movement within the landfill. Additionally,
we note that the process of biogas formation in a landfill provides
some element of separation, in that it is formed only from the biogenic
components of landfill material, including but not strictly limited to
food and yard waste. Thus, plastics, metal and glass are effectively
``separated'' out through the process of biogas formation. As a result
of the intermixing of wastes, the fact that biogas is formed only from
the biogenic portion of landfill material, and the fact that landfill
material is as a practical matter inaccessible for further separation,
EPA believes that no further practical separation is possible for
landfill material and biogas should be considered as produced from
separated yard and food waste for purposes of EISA. Therefore, all
biogas from landfills is eligible for RIN generation.
    We have considered whether to require biogas producers to use ASTM
Method D-6866 to identify the biogenic versus non-biogenic fractions of
the fuel. However, as noted above, biogas is not formed from non-
biogenic compounds in landfills. (Kaplan, et al., 2009) \9\ Thus, no
purpose would be solved in using the ASTM method in the biogas context.
---------------------------------------------------------------------------

    \9\ Kaplan, et al. (2009). ``Is it Better to Burn or Bury Waste
for Clean Electricity Generation?'' Environmental Science &
Technology 2009 43(6), 1711-1717 (Found in Table S1 of supplemental
material to the article, at http://pubs.acs.org/doi/suppl/10.1021/
es802395e/suppl_file/es802395e_si_001.pdf).
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C. Expanded Registration Process for Producers and Importers

    In order to implement and enforce the new restrictions on
qualifying renewable fuel under RFS2, we are revising the registration
process for renewable fuel producers and importers. Under the RFS1
program, all producers and importers of renewable fuel who produce or
import more than 10,000 gallons of fuel annually must register with
EPA's fuels program prior to generating RINs. Renewable fuel producer
and importer registration under the RFS1 program consists of filling
out two forms: 3520-20A (Fuels Programs Company/Entity Registration),
which requires basic contact information for the company and basic
business activity information and 3520-20B (Gasoline Programs Facility
Registration) or 3520-20B1 (Diesel Programs Facility Registration),
which require basic contact information for each facility owned by the
producer or importer. More detailed information on the renewable fuel
production facility, such as production capacity and process,
feedstocks, and products was not required for most producers or
importers to generate RINs under RFS1 (producers of cellulosic biomass
ethanol and waste-derived ethanol are the exception to this).
    Additionally, EPA recommends companies register their renewable
fuels or fuel additives under title 40 CFR part 79 as a motor vehicle
fuel. In fact, renewable fuels intended for use in motor vehicles will
be required to be registered under title 40 CFR part 79 prior to any
introduction into commerce. Manufacturers and subsequent parties of
fuels and fuel additives not registered under part 79 will be liable
for separate penalties under 40 CFR parts 79 and 80 in the event their
unregistered product is introduced into commerce for use in a motor
vehicle. Further if a registered fuel or fuel additive is used in
manner that is not consistent with their product's registration under
part 79 the manufacturer and subsequent parties will be liable for
penalties under parts 79 and 80. If EPA determines based on the
company's registration that they are not producing renewable fuel, the
company will not be able to generate RINs and the RINs generated for
fuel produced from nonrenewable sources will be invalidated.
    Due to the revised definitions of renewable fuel under EISA, we
proposed to expand the registration process for renewable fuel
producers and importers in order to implement the new program
effectively. We received a number of comments that opposed the expanded
registration as commenters deemed it overly burdensome, costly and
unnecessary. However, EPA is finalizing the proposed expanded
registration requirements for the following reasons. The information to
be collected through the expanded registration process is essential to
generating and assigning a certain category of RIN to a volume of fuel.
Additionally, the information collected is essential to determining
whether the feedstock used to produce the fuel meets the definition of
renewable biomass, whether the lifecycle greenhouse gas emissions of
the fuel meets a certain GHG reduction threshold and, in some cases,
whether the renewable fuel production facility is considered to be
grandfathered into the program. Therefore, we are requiring producers,
including foreign producers, and importers that generate RINs to
provide us with information on their feedstocks, facilities, and
products, in order to implement and enforce the program and have
confidence that producers and importers are properly categorizing their
fuel and generating RINs. The registration procedures will be
integrated with the new EPA Moderated Transaction System, discussed in
detail in Section III.A of this preamble.
1. Domestic Renewable Fuel Producers
    Information on products, feedstocks, and facilities contained in a
producer's registration will be used to verify the validity of RINs
generated and their proper categorization as either cellulosic biofuel,
biomass-based diesel, advanced biofuel, or other renewable fuel. In
addition, producers of renewable fuel from facilities that qualify for
the exemption from the 20% GHG reduction threshold (as discussed in
Section II.B.3) must provide information that demonstrates when the
facility commenced construction, and that establishes the baseline
volume of the fuel. For those facilities that would qualify as
grandfathered but are not in operation we are allowing until May 1,
2013 to submit and receive approval for a complete facility
registration. This provision does not require actual fuel production,
but simply the filing of registration materials that assert a claim for
exempt status. It will benefit both fuel producers, who will likely be
able to more readily collect the required information if it is done
promptly, and EPA enforcement personnel seeking to verify the
information. However, given the potentially significant implications of
this requirement for facilities that may qualify for the exemption but
miss the registration deadline, the rule also provides that EPA may
waive the requirement if it determines that the submission is
verifiable to the same extent as a timely-submitted registration.
    With respect to products, we are requiring that producers provide
information on the types of renewable fuel and co-products that a
facility is capable of producing. With respect to feedstocks, we are
requiring producers to provide to EPA a list of all the different
feedstocks that a renewable fuel producer's facility is likely to use
to convert into renewable fuel. With respect to the producer's
facilities, two types of information must be reported to the Agency.
First, producers must describe each facility's fuel production
processes (e.g., wet mill, dry mill, thermochemical, etc.), and
thermal/process energy source(s). Second, in order to determine what
production volumes would be grandfathered and

thus deemed to be in compliance with the 20% GHG threshold, we are
requiring evidence and certification of the facility's qualification
under the definition of ``commence construction'' as well as
information necessary to establish its renewable fuel baseline volume
per the requirement outlined in Section II.B.3 of this preamble.
    EPA proposed to require that renewable fuel producers have a third-
party engineering review of their facilities prior to generating RINs
under RFS2, and every 3 years thereafter. EPA received comments that
the on-site engineering review was overly burdensome, unnecessary and
costly. A number of commenters noted that the time allotted for
conducting the reviews, between the rule's publication and prior to RIN
generation, is not adequate for producers to hire an engineer and
conduct the review for all of their facilities. Several commenters
requested that on-site licensed engineers be allowed to conduct any
necessary facility reviews.
    EPA is finalizing the proposed requirement for an on-site
engineering review of facilities producing renewable fuel due to the
variability of production facilities, the increase in the number of
categories of renewable fuels, and the importance of ensuring that RINs
are generated in the correct category. Without these engineering
reviews, we do not believe it would be possible to implement the RFS2
program in a manner that ensured the requirements of EISA were being
fulfilled. Additionally, the engineering review provides a check
against fraudulent RIN generation. In order to establish the proper
basis for RIN generation, we are requiring that every renewable fuel
producer have the on-site engineering review of their facility
performed in conjunction with his or her initial registration for the
new RFS program. The engineering reviews must be conducted by
independent third parties who can maintain impartiality and objectivity
in evaluating the facilities and their processes. Additionally, the on-
site engineering review must be conducted every three years thereafter
to verify that the fuel pathways established in the initial
registration are still applicable. These requirements apply unless the
renewable fuel producer updates its facility registration information
to qualify for a new RIN category (i.e., D code), in which case the
review needs to be performed within 60 days of the registration update.
Finally, producers are required to submit a copy of their independent
engineering review to EPA, for verification and enforcement purposes.
2. Foreign Renewable Fuel Producers
    Under RFS1, foreign renewable fuel producers of cellulosic biomass
ethanol and waste-derived ethanol may apply to EPA to generate RINs for
their own fuel. For RFS2, we proposed that foreign producers of
renewable fuel meet the same requirements as domestic producers,
including registering information about their feedstocks, facilities,
and products, as well as submitting an on-site independent engineering
review of their facilities at the time of registration for the program
and every three years thereafter. These requirements apply to all
foreign renewable fuel producers who plan to export their products to
the U.S. as part of the RFS2 program, whether the foreign producer
generates RINs for their fuel or an importer does.
    Foreign producers, like domestic producers, must also undergo an
independent engineering review of their facilities, conducted by an
independent third party who is a licensed professional engineer (P.E.),
or foreign equivalent who works in the chemical engineering field. The
independent third party must provide to EPA documentation of his or her
qualifications as part of the engineering review, including proof of
appropriate P.E. license or foreign equivalent. The third-party
engineering review must be conducted by both foreign producers who plan
to generate RINs and those that don't generate RINs but anticipate
their fuel will be exported to the United States by an importer who
will generate the RINs.
3. Renewable Fuel Importers
    We are requiring importers who generate RINs for imported fuel that
they receive without RINs may only do so under certain circumstances.
If an importer receives fuel without RINs, the importer may only
generate RINs for that fuel if they can verify the fuel pathway and
that feedstocks use meet the definition of renewable biomass. An
importer must rely on his supplier, a foreign renewable fuel producer,
to provide documentation to support any claims for their decision to
generate RINs. An importer may have an agreement with a foreign
renewable fuel producer for the importer to generate RINs if the
foreign producer has not done so already. However, the foreign
renewable fuel producer must be registered with EPA and must have had a
third-party engineering review conducted, as noted above, in order for
EPA to be able to verify that the renewable biomass and GHG reduction
requirements of EISA are being fulfilled. Section II.D.2.b describes
the RIN generating restrictions and requirements for importers under
RFS2.
4. Process and Timing
    We are making forms for expanded registration for renewable fuel
producers and importers, as well as forms for registration of other
regulated parties, available electronically with the publication of
this final rule. Paper registration forms will only be accepted in
exceptional cases. Registration forms must be submitted and accepted by
the EPA by July 1, 2010, or 60 days prior to a producer producing or
importer importing any renewable fuel, whichever dates come later. If a
producer changes its fuel pathway (feedstock, production process, or
fuel type) to not listed in his registration information on file with
EPA but the change will not incur a change of RIN category for the fuel
(i.e., a change in the appropriate D code), the producer must update
his registration information within seven (7) days of the change.
However, if the fuel producer changes its fuel pathway in a manner that
would result in a change in its RIN category (and thus a new D code),
such an update would need to be submitted at least 60 days prior to the
change, followed by submittal of a complete on-site independent
engineering review of the producer's facility also within 60 days of
the change. If EPA finds that these deadlines and requirements have not
been met, or that a facility's registered profile, dictated by the
various parameters for product, process and feedstock, does not reflect
actual products produced, processes employed, or feedstocks used, then
EPA reserves the right to void, ab initio, any affected RINs generated
and may impose significant penalties. For example a newly registered
(i.e. not grandfathered) ethanol production facility claims in their
registration that they qualify to generate RINs based upon the use of
two advanced engineering practices (1) corn oil fractionation and (2)
production of wet DGS co-product that is, at a minimum, 35% of its
total DGS produced annually. However, during an audit of the producer's
records, it is found that of all their DGS produced, less than 15% was
wet. In this example, the producer has committed a violation that
results in the disqualification of their eligibility to generate RINs;
that is, they no longer have an eligible pathway that demonstrates
qualification with the 20% GHG threshold requirement for corn ethanol
producers. As such any and all RINs produced may be deemed invalid and
the producer may be subject to Clean Air Act penalties.

    The required independent engineering review as discussed above for
domestic and foreign renewable fuel producers is an integral part of
the registration process. The agency recognizes, through comments
received, that there are significant concerns involving timing
necessary and ability to produce a completed engineering review to
satisfy registration requirements. Since the publication of the RFS2
NPRM, we have delivered consistently a message stating that advanced
planning and preparation was necessary from all parties, EPA and the
regulated community inclusive, for successful implementation of this
program. In an effort to reduce demand on engineering resources, we are
allowing grandfathered facilities an additional six months to submit
their engineering review. This will direct the focus of engineering
review resources on producers of advanced, cellulosic and biomass based
diesel. EPA fully expects these producers of advanced renewable fuels
to meet the engineering review requirement; however, if they are having
difficulties producing engineer's reports prior to April 1, we ask that
they contact us.

D. Generation of RINs

    Under RFS2, each RIN will continue to be generated by the producer
or importer of the renewable fuel, as in the RFS1 program. In order to
determine the number of RINs that must be generated and assigned to a
batch of renewable fuel, the actual volume of the batch of renewable
fuel must be multiplied by the appropriate Equivalence Value. The
producer or importer must also determine the appropriate D code to
assign to the RIN to identify which of the four standards the RIN can
be used to meet. This section describes these two aspects of the
generation of RINs. Other aspects of the generation of RINs, such as
the definition of a batch, as well as the assignment of RINs to
batches, will remain unchanged from the RFS1 requirements. We received
several comments regarding the method for calculating temperature
standardization of biodiesel and address this issue in Section III.G.
1. Equivalence Values
    For RFS1, we interpreted CAA section 211(o) as allowing us to
develop Equivalence Values representing the number of gallons that can
be claimed for compliance purposes for every physical gallon of
renewable fuel. We described how the use of Equivalence Values adjusted
for renewable content and based on energy content in comparison to the
energy content of ethanol was consistent with the sections of EPAct
that provided extra credit for cellulosic and waste-derived renewable
fuels, and the direction that EPA establish ``appropriate'' credit for
biodiesel and renewable fuel volumes in excess of the mandated volumes.
We also noted that the use of Equivalence Values based on energy
content was an appropriate measure of the extent to which a renewable
fuel would replace or reduce the quantity of petroleum or other fossil
fuel present in a fuel mixture. EPA stated that these provisions
indicated that Congress did not intend to restrict EPA discretion in
implementing the program to utilizing a straight volume measurement of
gallons. See 72 FR 23918-23920, and 71 FR 55570-55571. The result was
an Equivalence Value for ethanol of 1.0, for butanol of 1.3, for
biodiesel (mono alkyl ester) of 1.5, and for non-ester renewable diesel
of 1.7.
    In the NPRM we noted that EISA made a number of changes to CAA
section 211(o) that impacted our consideration of Equivalence Values in
the context of the RFS2 program. For instance, EISA eliminated the 2.5-
to-1 credit for cellulosic biomass ethanol and waste-derived ethanol
and replaced this provision with large mandated volumes of cellulosic
biofuel and advanced biofuels. EISA also expanded the program to
include four separate categories of renewable fuel (cellulosic biofuel,
biomass-based diesel, advanced biofuel, and total renewable fuel) and
included GHG thresholds in the definitions of each category. Each of
these categories of renewable fuel has its own volume requirement, and
thus there will exist a guaranteed market for each. As a result of
these new requirements, we indicated that there may no longer be a need
for additional incentives for certain fuels in the form of Equivalence
Values greater than 1.0.
    In the NPRM we co-proposed and took comment on two options for
Equivalence Values:
    1. Equivalence Values would be based on the energy content and
renewable content of each renewable fuel in comparison to denatured
ethanol, consistent with the approach under RFS1, with the addition
that biomass-based diesel standard would be based on energy content in
comparison to biodiesel.
    2. All liquid renewable fuels would be counted strictly on the
basis of their measured volumes, and the Equivalence Values for all
renewable fuels would be 1.0 (essentially, Equivalence Values would no
longer apply).
    In response to the NPRM, some stakeholders pointed to the
aforementioned changes brought about by EISA as support for a straight
volume approach to Equivalence Values, and argued that it had always
been the intent of Congress that the statutory volume mandates be
treated as straight volumes. Stakeholders taking this position were
generally producers of corn ethanol. However, a broad group of other
stakeholders including refiners, biodiesel producers, a broad group of
advanced biofuel producers, fuel distributor and States indicated that
the first option for an energy-based approach to Equivalence Values was
both supported by the statute and necessary to provide for equitable
treatment of advanced biofuels. They noted that EISA did not change
certain of the statutory provisions EPA looked to for support under
RFS1 in establishing Equivalence Values based on relative volumetric
energy content in comparison to ethanol. For instance, CAA 211(o)
continues to direct EPA to determine an ``appropriate'' credit for
biodiesel, and also directs EPA to determine the ``appropriate'' amount
of credit for renewable fuel use in excess of the required volumes. Had
Congress intended to change these provisions they could have easily
done so. Moreover, some stakeholders argued that the existence of four
standards is not a sufficient reason to eliminate the use of energy-
based Equivalence Values for RFS2. The four categories are defined in
such a way that a variety of different types of renewable fuel could
qualify for each category, such that no single specific type of
renewable fuel will have a guaranteed market. For example, the
cellulosic biofuel requirement could be met with both cellulosic
ethanol or cellulosic diesel. As a result, the existence of four
standards under RFS2 does not obviate the value of standardizing for
energy content, which provides a level playing field under RFS1 for
various types of renewable fuels based on energy content.
    Some stakeholders who supported an energy-based approach to
Equivalence Values also argued that a straight volume approach would be
likely to create a disincentive for the development of new renewable
fuels that have a higher energy content than ethanol. For a given mass
of feedstock, the volume of renewable fuel that can be produced is
roughly inversely proportional to its energy content. For instance, one
ton of biomass could be gasified and converted to syngas, which could
then be catalytically reformed into either 80 gallons of ethanol (and
another 14 gal of other alcohols) or 50

gallons of diesel fuel (and naphtha).\10\ If RINs were assigned on a
straight volume basis, the producer could maximize the number of RINs
he is able to generate and sell by producing ethanol instead of diesel.
Thus, even if the market would otherwise lean towards demanding greater
volumes of diesel, the greater RIN value for producing ethanol may
favor their production instead. However, if the energy-based
Equivalence Values were maintained, the producer could assign 1.7 RINs
to each gallon of diesel made from biomass in comparison to 1.0 RIN to
each gallon of ethanol from biomass, and the total number of RINs
generated would be essentially the same for the diesel as it would be
for the ethanol. The use of energy-based Equivalence Values could thus
provide a level playing field in terms of the RFS program's incentives
to produce different types of renewable fuel from the available
feedstocks. The market would then be free to choose the most
appropriate renewable fuels without any bias imposed by the RFS
regulations, and the costs imposed on different types of renewable fuel
through the assignment of RINs would be more evenly aligned with the
ability of those fuels to power vehicles and engines, and displace
fossil fuel-based gasoline or diesel. Since the technologies for
producing more energy-dense fuels such as cellulosic diesel are still
in the early stages of development, they may benefit from not having to
overcome the disincentive in the form of the same Equivalence Value
based on straight volume.
---------------------------------------------------------------------------

    \10\ Another example would be a fermentation process in which
one ton of cellulose could be used to produce either 70 gallons of
ethanol or 55 gallons of butanol.
---------------------------------------------------------------------------

    Based on our interpretation of EISA as allowing the use of energy-
based Equivalence Values, and because we believe it provides a level
playing field for the development of different fuels that can displace
the use of fossil fuels, and that this approach therefore furthers the
energy independence goals of EISA, we are finalizing the energy-based
approach to Equivalence Values in today's action. We also note that a
large number of companies have already made investments based on the
decisions made for RFS1, and using energy-based Equivalence Values will
maintain consistency with RFS1 and ease the transition into RFS2.
Insofar as renewable fuels with volumetric energy contents higher than
ethanol are used, the actual volumes of renewable fuel that are
necessary to meet the EISA volume mandates will be smaller than those
shown in Table I.A.1-1. The impact on the physical volume will depend
on actual volumes of various advanced biofuels produced in the future.
The main scenario modeled for this final rule includes a forecast for
considerable volumes of relatively high energy diesel fuel made from
renewable biomass, and still results in a physical volume mandate of
30.5 billion gallons. The energy-based approach results in the advanced
biofuel standard being automatically met during the first few years of
the program. For instance, the biomass-based diesel mandated volume for
2010 is 0.65 billion gallons, which will be treated as 0.975 billion
gallons (1.5 x 0.65) in the context of meeting the advanced biofuel
standard. Since the mandated volume for advanced biofuel in 2010 is
0.95 billion gallons, this requirement is automatically met by
compliance with the biomass-based diesel standard.
    Although we are finalizing an energy-based approach to Equivalence
Values, we believe that Congress intended the biomass-based diesel
volume mandate to be treated as diesel volumes rather than as ethanol-
equivalent volumes. Since all RINs are generated based on energy
equivalency to ethanol, to accomplish this, we have modified the
formula for calculating the standard for biomass-based diesel to
compensate such that one physical gallon of biomass-based diesel will
count as one gallon for purposes of meeting the biomass-based diesel
standard, but will be counted based on their Equivalence Value for
purposes of meeting the advanced biofuel and total renewable fuel
standards. Since it is likely that the statutory volume mandates were
based on projections for biodiesel, we have chosen to use the
Equivalence Value for biodiesel, 1.5, in this calculation. See Section
II.E.1.a for further discussion. Other diesel fuel made from renewable
biomass can also qualify as biomass-based diesel (e.g., renewable
diesel, cellulosic diesel). But since the variation in energy content
between them is relatively small, variation in the total physical
volume of biomass-based diesel will likewise be small.
    In the NPRM we also proposed that the energy content of denatured
ethanol be changed from the 77,550 Btu/gal value used in the RFS1
program to 77,930 Btu/gal (lower heating value). The revised value was
intended to provide a more accurate estimate of the energy content of
pure ethanol, 76,400 Btu/gal, rather than the rounded value of 76,000
Btu/gal that was used under RFS1. Except for the Renewable Fuels
Association who supported this change, most stakeholders did not
comment on this proposal. However, based on new provisions in the Food,
Conservation, and Energy Act of 2008, we have since determined that the
denaturant content of ethanol should be assumed to be 2% rather than
the 5% used in the RFS1 program. This additional change results in a
denatured ethanol energy content of 77,000 Btu/gal and a renewable
content of denatured ethanol of 97.2%.\11\ The value of 77,000 Btu/gal
will be used to convert biogas and renewable electricity into volumes
of renewable fuel under RFS2. This change also affects the formula for
calculating Equivalence Values assigned to renewable fuels. The new
formula is shown below:

    \11\ Value is lower than 98% because it is based on energy
content of denaturant versus ethanol, not relative volume.
---------------------------------------------------------------------------

EV = (R/0.972) * (EC/77,000)

Where:

EV = Equivalence Value for the renewable fuel, rounded to the
nearest tenth.
R = Renewable content of the renewable fuel. This is a measure of
the portion of a renewable fuel that came from a renewable source,
expressed as a percent, on an energy basis.
EC = Energy content of the renewable fuel, in Btu per gallon (lower
heating value).

Under this new formula, Equivalence Values assigned to specific types
of renewable fuel under RFS1 will continue unchanged under RFS2.
However, non-ester renewable diesel will be required to have a lower
energy content of at least 123,500 Btu/gal in order to qualify for an
Equivalence Value of 1.7. A non-ester renewable diesel with a lower
energy content would be required to apply for a different Equivalent
Value according to the provisions in Sec.  80.1415.
2. Fuel Pathways and Assignment of D Codes
    As described in Section II.A, RINs under RFS2 would in general
continue to have the same number of digits and code definitions as
under RFS1. The one change will be that, while the D code will continue
to identify the standard to which the RIN can be applied, it will be
modified to have four values corresponding to the four different
renewable fuel categories defined in EISA. These four D code values and
the corresponding categories are shown in Table II.A-1.
    In order to generate RINs for renewable fuel that meets the various
eligibility requirements (see Section II.B), a producer or importer
must know which D code to assign to those RINs. Following the approach
we described in the NPRM, a producer or importer will determine the
appropriate D code using a lookup table in the regulations. The

lookup table lists various combinations of fuel type, production
process, and feedstock, and the producer or importer chooses the
appropriate combination representing the fuel he is producing and for
which he is generating RINs. Parties generating RINs are required to
use the D code specified in the lookup table and are not permitted to
use a D code representing a broader renewable fuel category. For
example, a party whose fuel qualified as biomass-based diesel could not
choose to categorize that fuel as advanced biofuel or general renewable
fuel for purposes of RIN generation.\12\
---------------------------------------------------------------------------

    \12\ However, a biomass-based diesel RIN can be used to satisfy
Renewable Volume Obligations (RVO) for biomass-based diesel,
advanced biofuel, and total renewable fuel. See Section II.G.3 for
further discussion of the use of RINs for compliance purposes.
---------------------------------------------------------------------------

    This section describes our approach to the assignment of D codes to
RINs for domestic producers, foreign producers, and importers of
renewable fuel. Subsequent sections address the generation of RINs in
special circumstances, such as when a production facility has multiple
applicable combinations of feedstock, fuel type, and production process
within a calendar year, production facilities that co-process renewable
biomass and fossil fuels, and production facilities for which the
lookup table does not provide an applicable D code.
a. Producers
    For both domestic and foreign producers of renewable fuel, the
lookup table identifies individual fuel ``pathways'' comprised of
unique combinations of the type of renewable fuel being produced, the
feedstock used to produce the renewable fuel, and a description of the
production process. Each pathway is assigned to one of the D codes on
the basis of the revised renewable fuel definitions provided in EISA
and our assessment of the GHG lifecycle performance for that pathway. A
description of the lifecycle assessment of each fuel pathway and the
process we used for determining the associated D code can be found in
Section V.
    Note that the generation of RINs also requires as a prerequisite
that the feedstocks used to make the renewable fuel meet the definition
of ``renewable biomass'' as described in Section II.B.4, including
applicable land use restrictions. If a producer is not able to
demonstrate that his feedstocks meet the definition of renewable
biomass, RINs cannot be generated. However, as noted in Section
II.B.4.b.1, feedstocks typically include incidental contaminants. These
contaminants may have been intentionally added to promote cultivation
(e.g., pesticides, herbicides, fertilizer) or transport (e.g., nylon
baling rope). In addition, there may be some incidental contamination
of a particular load of feedstocks with co-product during feedstock
production, or with other agricultural materials during shipping. For
example, there may be incidental corn kernels remaining on some corn
cobs used to produce cellulosic biofuel, or some sorghum kernels left
in a shipping container that are introduced into a load of corn kernels
being shipped to a biofuel production facility. The final regulations
clarify that in assigning D codes for renewable fuel, producers and
importers should disregard the presence of incidental contaminants in
their feedstocks if the incidental contaminants are related to
customary feedstock production and transport, and are impractical to
remove and occur in de minimus levels.
    Through our assessment of the lifecycle GHG impacts of different
pathways and the application of the EISA definitions for each of the
four categories of renewable fuel, including the GHG thresholds, we
have determined that all four categories will have pathways that could
be used to meet the Act's volume requirements. For example, ethanol
made from corn stover or switchgrass in an enzymatic hydrolysis process
will count as cellulosic biofuel. Biodiesel made from waste grease or
soybean oil can count as biomass-based diesel. Ethanol made from
sugarcane sugar will count as advanced biofuel. Finally, a variety of
pathways will count as renewable fuel under the RFS2 program. The
complete list of pathways that are valid under our final RFS2 program
is discussed in Section V.C and are provided in the regulations at
Sec.  80.1426(f).
    Producers must choose the appropriate D code from the lookup table
in the regulations based on the fuel pathway that describes their
facility. The fuel pathway must be specified by the producer in the
registration process as described in Section II.C. If there are changes
to a producer's facility or feedstock such that their fuel would
require a D code that was different from any D code(s) which their
existing registration information already allowed, the producer is
required to revise its registration information with EPA 30 days prior
to changing the applicable D code it uses to generate RINs. Situations
in which multiple fuel pathways could apply to a single facility are
addressed in Section II.D.3 below.
    For producers for whom none of the defined fuel pathways in the
lookup table apply, a producer can still generate RINs if he meets the
criteria for grandfathered or deemed compliant status as described in
Section II.B.3 and his fuel meets the definition of renewable fuel as
described in Section II.B.1. In this case he would use a D code of 6
for those RINs generated under the grandfathering or deemed compliant
provisions.
    A diesel fuel product produced from cellulosic feedstocks that
meets the 60% GHG threshold can qualify as either cellulosic biofuel or
biomass-based diesel. In the NPRM, we proposed that the producer of
such ``cellulosic diesel'' be required to choose whether to categorize
his product as either cellulosic biofuel or biomass-based diesel.
However, we requested comment on an alternative approach in which an
additional D code would be defined to represent cellulosic diesel
allowing the cellulosic diesel RIN to be sold into either market. As
described more fully in Section II.A above, we are finalizing this
alternative approach in today's final rule. Producers or importers of a
fuel that qualifies as both biomass-based diesel and cellulosic biofuel
must use a D code of 7 in the RINs they generate, and will thus have
the flexibility of marketing such RINs to parties seeking either
cellulosic biofuel or biomass-based diesel RINs, depending on market
demand. Obligated parties can apply RINs with a D code of 7 to either
their cellulosic biofuel or biomass-based diesel RVOs, but not both.
    In addition to the above comments, we received comments requesting
that the use of biogas as process heat in the production of ethanol,
should not be limited to use at the site of renewable fuel production.
Specifically, commenters point out that the introduction of gas
produced from landfills or animal wastes to fungible pipelines is the
only practical manner for most renewable fuel facilities to acquire and
use landfill gas, since very few are located adjacent to landfills, or
have dedicated pipelines from landfill gas operations to their
facilities.\13\ The commenters suggested that ethanol plants causing
landfill gas to be introduced into a fungible gas pipeline be allowed
to claim those volumes. The alternative would be to allow landfill

gas that is only used onsite to be counted in establishing the pathway.
---------------------------------------------------------------------------

    \13\ This suggestion was also made by several companies with
respect to the RFS1 definition of cellulosic biomass ethanol, which
allowed corn-based ethanol to be deemed cellulosic if 90% of the
fossil fuel used at the ethanol facility to make ethanol was
displaced by fuel derived from animal or other waste materials,
including landfill gas.
---------------------------------------------------------------------------

    We believe that the suggested approach has merit. We agree that it
does not make any difference in terms of the beneficial environmental
attributes associated with the use of landfill gas whether the
displacement of fossil fuel occurs in a fungible natural gas pipeline,
or in a specific facility that draws gas volume from that pipeline. In
fact, a similar approach is widely used with respect to electricity
generated by renewable biomass that is placed into a commercial
electricity grid. A party buying the renewable power is credited with
doing so in state renewable portfolio programs even though the power
from these sources is placed in the fungible grid and the electrons
produced by a renewable source may never actually be used by the party
purchasing it. In essence these programs assume that the renewable
power purchased and introduced into the grid is in fact used by the
purchaser, even though all parties acknowledge that use of the actual
renewable-derived electrons can never be verified once placed in the
fungible grid. We believe that this approach will ultimately further
the GHG reduction and energy security goals of RFS2.
    Producers may therefore take into account such displacement
provided that they demonstrate that a verifiable contractual pathway
exists and that such pathway ensures that (1) a specific volume of
landfill gas was placed into a commercial pipeline that ultimately
serves the transportation fueling facility and (2) that the drawn into
this facility from that pipeline matches the volume of landfill gas
placed into the pipeline system. Thus facilities using such a fuel
pathway may then use an appropriate D code for generation of RINs.
    This approach also applies to biogas and electricity made from
renewable fuels and which are used for transportation. Producers of
such fuel will be able to generate RINs, provided that a contractual
pathway exists that provides evidence that specific quantities of the
renewable fuel (either biogas or electricity) was purchased and
contracted to be delivered to a specific transportation fueling
facility.\14\ We specify that the pipeline (or transmission line)
system must ultimately serve the subject facility. For electricity that
is produced by the co-firing of fossil fuels with renewable biomass
derived fuels, we are requiring that the resulting electricity is pro-
rated to represent only that amount of electricity generated by the
qualifying biogas, for the purpose of computing RINs.
---------------------------------------------------------------------------

    \14\ Note that biogas used for transportation fuel includes
propane made from renewable biomass.
---------------------------------------------------------------------------

    We are also providing for those situations in which biogas or
renewable electricity is provided directly to the transportation
facility, rather than using a commercial distribution system such as
pipelines or transmission lines. For both cases--dedicated use and
commercial distribution--producers must provide contractual evidence of
the production and sale of such fuel, and there are also reporting and
recordkeeping requirements to be followed as well.
    Presently, there is no D code for electricity that is produced from
renewable biomass. The petition process for assigning such codes in
today's rule can be used for such purpose.
b. Importers
    For imported renewable fuel under RFS2, we are anticipating the
importer to be the primary party responsible for generating RINs.
However, the foreign producer of renewable fuel can instead elect to
generate RINs themselves under certain conditions as described more
fully in Section II.D.2.c below. This approach is consistent with the
approach under RFS1.
    Under RFS1, importers who import more than 10,000 gallons in a
calendar year were required to generate RINs for all imported renewable
fuel based on its type, except for cases in which the foreign producer
generated RINs for cellulosic biomass ethanol or waste-derived ethanol.
Due to the new definitions of renewable fuel and renewable biomass in
EISA, importers can no longer generate RINs under RFS2 on the basis of
fuel type alone. Instead, they must be able to demonstrate that the
renewable biomass definition has been met for the renewable fuel they
intend to import and for which they will generate RINs. They must also
have sufficient information about the feedstock and process used to
make the renewable fuel to allow them to identify the appropriate D
code from the lookup table for the RINs they generate. Therefore, in
order to generate RINs, the importer will be required to obtain this
information from a foreign producer. RINs can only be generated if a
demonstration is made that the feedstocks used to produce the renewable
fuel meet the definition of renewable biomass.
    In summary, under today's final rule, importers can import any
renewable fuel, but can only generate RINs to represent the imported
renewable fuel under the two conditions described below. If these
conditions do not apply, the importer can import biofuel but cannot
generate RINs to represent that biofuel.
    1. The imported renewable fuel is not accompanied by RINs generated
by the registered foreign producer
    2. The importer obtains from the foreign producer:
--Documentation demonstrating that the renewable biomass definition has
been met for the volume of renewable fuel being imported.
--Documentation about the feedstock and production process used to
produce the renewable fuel to allow the importer to determine the
appropriate D-code designation in the RINs generated.

We are also finalizing additional requirements for foreign producers
who either generate RINs or provide documentation to an importer
sufficient to allow the importer to generate RINs. As described more
fully in the next section, these additional requirements include
restrictions on mixing of biofuels in the distribution system as it
travels from the foreign producer to the importer.
    Finally, EPA is assessing whether additional requirements on
foreign-generated fuel may be necessary for situations in which
importers are generating RINs for the fuel. Additional requirements may
be necessary to ensure that the importers have sufficient information
to properly generate the RINs and that EPA has sufficient information
to determine whether those RINs have been legitimately generated. EPA
will pursue an amendment to the final RFS2 regulations if we find that
additional requirements are appropriate and necessary.
c. Additional Provisions for Foreign Producers
    In general, we are requiring foreign producers of renewable fuel to
meet the same requirements as domestic producers with respect to
registration, recordkeeping and reporting, attest engagements, and the
transfer of RINs they generate with the batches of renewable fuel that
those RINs represent. However, we are also placing additional
requirements on foreign producers to ensure that RINs entering the U.S.
are valid and that the regulations can be enforced at foreign
facilities. These additional requirements are designed to accommodate
the more limited access that EPA enforcement personnel have to foreign
entities that are regulated parties under RFS2, and also the fact that
foreign-produced biofuel intended for export to the U.S. is often mixed
with biofuel that will not be exported to the U.S.

    Under RFS1, foreign producers had the option of generating RINs for
the renewable fuel that they export to the U.S. if they wanted to
designate their fuel as cellulosic biomass ethanol or waste-derived
ethanol, and thereby take advantage of the additional 1.5 credit value
afforded by the 2.5 Equivalence Value for such products. In order to
ensure that EPA had the ability to enforce the regulations relating to
the generation of RINs from such foreign ethanol producers, the RFS1
regulations specified additional requirements for them, including
posting a bond, admitting EPA enforcement personnel, and submitting to
third-party engineering reviews of their production process. For RFS2,
we are maintaining these additional requirements for foreign producers
because EPA enforcement personnel have the same limitations under RFS2
with regard to access to foreign entities that are regulated parties as
they did under RFS1.
    EISA also creates other unique challenges in the implementation and
enforcement of the renewable fuel standards for foreign-produced
renewable fuel imported into the U.S. Unlike our other fuels programs,
EPA cannot determine whether a particular shipment of renewable fuel is
eligible to generate RINs under the new program by testing the fuel
itself. Instead, information regarding the feedstock that was used to
produce renewable fuel and the process by which it was produced is
vital to determining the proper renewable fuel category and RIN type
for the imported fuel under the RFS2 program. Thus, whether foreign
producers or importers generate RINs, this information must be
collected and maintained by the RIN generator.
    If a foreign producer generates RINs for renewable fuel that it
produces and exports to the U.S., we are requiring that ethanol must be
dewatered and denatured by the foreign producer prior to leaving the
production facility and prior to the generation of RINs. This is
consistent with our definition of renewable fuel in which ethanol that
is valid under RFS2 must be denatured. Moreover, the foreign producer
is required to strictly segregate a batch of renewable fuel and its
associated RINs from all other volumes of renewable fuel as it travels
from the foreign producer to the importer. The strict segregation
ensures that RINs entering the U.S. appropriately represent the
renewable fuel imported into the U.S. both in terms of renewable fuel
type and volume.
    Several commenters requested that in general the importer be the
RIN generator for imported renewable fuel. Since most imported ethanol
is currently made in Brazil and is not denatured by the foreign
producer, any RINs generated must be generated by the importer.
However, to accomplish this, the importer must obtain the appropriate
information from a foreign producer regarding compliance with the
renewable biomass definition and a description of the associated
pathway for the renewable fuel. Under these circumstances, the foreign
producer must ensure that the information is transferred along with the
renewable fuel through the distribution system until it reaches the
importer. The foreign producer's volume of renewable fuel need not be
strictly segregated from other volumes in this case, so long as a
volume of chemically indistinguishable renewable fuel is tracked
through the distribution system from the foreign producer to the
importer, and the information needed by the importer to generate RINs
follows this same path through the distribution system. Strict
segregation of the volume is not necessary in this case, and the
importer will determine appropriate number of RINs for the specific
volume and type of renewable fuel that he imports.
    Finally, if a foreign producer chooses not to participate in the
RFS2 program and thus neither generates RINs nor provides information
to the importer so that the importer can generate RINs, the foreign
producer can still export biofuel to the U.S. However, under these
circumstances the biofuel would not be renewable fuel under RFS2, no
RINs could be generated by any party, and thus the foreign producer
would not be subject to any of the registration, recordkeeping,
reporting, or attest engagement requirements.
3. Facilities With Multiple Applicable Pathways
    If a given facility's operations can be fully represented by a
single pathway, then a single D code taken from the lookup table will
be applicable to all RINs generated for fuel produced at that facility.
However, we recognize that this will not always be the case. Some
facilities use multiple feedstocks at the same time, or switch between
different feedstocks over the course of a year. A facility may be
modified to produce the same fuel but with a different process, or may
be modified to produce a different type of fuel. Any of these
situations could result in multiple pathways being applicable to a
facility, and thus there may be more than one applicable D code for
various RINs generated at the facility.
    If more than one pathway applies to a facility within a compliance
period, no special steps will need to be taken if the D code is the
same for all the applicable pathways. In this case, all RINs generated
at the facility will have the same D code regardless. Such a producer
with multiple applicable pathways must still describe its feedstock(s),
fuel type(s), and production process(es) in its initial registration
and annual report to the Agency so that we can verify that the D code
used was appropriate.
    However, if more than one pathway applies to a facility within a
compliance period and these pathways have been assigned different D
codes, then the producer must determine which D codes to use when
generating RINs. There are a number of different ways that this could
occur. For instance, a producer could change feedstocks, production
processes, or the type of fuel he produces in the middle of a
compliance period. Or, he could use more than one feedstock or produce
more than one fuel type simultaneously. The approach we are finalizing
for designating D codes for RINs in these cases follows the approach
described in the NPRM and is summarized in Table II.D.3-1.

   Table II.D.3-1--Approach To Assigning Multiple D Codes for Multiple
                           Applicable Pathways
------------------------------------------------------------------------
            Case/Description                    Proposed approach
------------------------------------------------------------------------
1. The pathway applicable to a facility  The applicable D code used in
 changes on a specific date, such that    generating RINs must change on
 one single pathway applies before the    the date that the fuel
 date and another single pathway          produced changes pathways.
 applies on and after the date.
2. One facility produces two or more     The volumes of the different
 different types of renewable fuel at     types of renewable fuel should
 the same time.                           be measured separately, with
                                          different D codes applied to
                                          the separate volumes.

3. One facility uses two or more         For any given batch of
 different feedstocks at the same time    renewable fuel, the producer
 to produce a single type of renewable    should assign the applicable D
 fuel.                                    codes using a ratio (explained
                                          below) defined by the amount
                                          of each type of feedstock
                                          used.
------------------------------------------------------------------------

    Commenters were generally supportive of this approach to multiple
applicable pathways, and as a result we are finalizing it with few
modifications from the proposal. Further discussion of the comments we
received can be found in Section 3.5.4 of the S&A document.
    Following our proposal, cases listed in Table II.D.3-1 will be
treated as hierarchical, with Case 2 only being used to address a
facility's circumstances if Case 1 is not applicable, and Case 3 only
being used to address a facility's circumstances if Case 2 is not
applicable. This approach covers all likely cases in which multiple
applicable pathways may apply to a renewable fuel producer. Some
examples of how Case 2 or 3 would apply are provided in the NPRM.
    A facility where two or more different types of feedstock are used
to produce a single fuel (such as Case 3 in Table II.D.3-1) will be
required to generate two or more separate batch-RINs \15\ for a single
volume of renewable fuel, and these separate batch-RINs will have
different D codes. The D codes will be chosen on the basis of the
different pathways as defined in the lookup table in Sec.  80.1426(f).
The number of gallon-RINs that will be included in each of the batch-
RINs will depend on the relative amount of the different types of
feedstocks used by the facility. In the NPRM, we proposed to use the
relative energy content of the feedstocks to determine how many gallon-
RINs should be assigned to each D code. Commenters generally did not
address this aspect of our proposal, and we are finalizing it in
today's action. Thus, the useable energy content of each feedstock must
be used to divide the total number of gallon-RINs generated for a batch
of renewable fuel into two or more groups, each corresponding to a
different D code. Several separate batch-RINs can then be generated and
assigned to the single volume of renewable fuel. The applicable
calculations are given in the regulations at Sec.  80.1426(f)(3).
---------------------------------------------------------------------------

    \15\ Batch-RINs and gallon-RINs are defined in the regulations
at 40 CFR 80.1401.
---------------------------------------------------------------------------

    We proposed several elements of the calculation of the useable
energy content of the feedstocks, including the following:
    1. Only that fraction of a feedstock which is expected to be
converted into renewable fuel by the facility can be counted in the
calculation, taking into account facility conversion efficiency.
    2. The producer of the renewable fuel is required to designate this
fraction once each year for the feedstocks processed by his facility
during that year, and to include this information as part of his
reporting requirements.
    3. Each producer is required to designate the energy content (in
Btu/lb) once each year of the portion of each of his feedstocks which
is converted into fuel. The producer may determine these values for his
own feedstocks, or may use default values provided in the regulations
at Sec.  80.1426(f)(7).
    4. Each producer is required to determine the total mass of each
type of feedstock used by the facility on at least a daily basis.
    Based on the paucity of comments we received on this issue, we are
finalizing the provisions regarding the calculation of useable energy
content of the feedstocks as it was proposed in the NPRM. As described
in Section II.J, producers of renewable fuel will be required to submit
information in their reports on the feedstocks they used, their
production processes, and the type of fuel(s) they produced during the
compliance period. This will apply to both domestic producers and
foreign producers who export any renewable fuel to the U.S. We will use
this information to verify that the D codes used in generating RINs
were appropriate.
4. Facilities That Co-Process Renewable Biomass and Fossil Fuels
    We expect situations to arise in which a producer uses a renewable
feedstock simultaneously with a fossil fuel feedstock, producing a
single fuel that is only partially renewable. For instance, biomass
might be co-fired with coal in a coal-to-liquids (CTL) process that
uses Fischer-Tropsch chemistry to make diesel fuel, biomass and waste
plastics might be fed simultaneously into a catalytic or gasification
process to make diesel fuel, or vegetable oils could be fed to a
hydrotreater along with petroleum to produce a diesel fuel. In these
cases, the diesel fuel will be only partially renewable. RINs can be
generated in such cases, but must be done in such a way that the number
of gallon-RINs corresponds only to the renewable portion of the fuel.
    Under RFS1, we created a provision to address the co-processing of
``renewable crudes'' along with petroleum feedstocks to produce a
gasoline or diesel fuel that is partially renewable. See 40 CFR
80.1126(d)(6). However, this provision would not apply in cases where
either the renewable feedstock or the fossil fuel feedstock is a gas
(e.g., biogas, natural gas) or a solid (e.g., biomass, coal).
Therefore, we are eliminating the RFS1 provision applicable only to
liquid feedstocks and replacing it with a more comprehensive approach
that will apply to liquid, solid, or gaseous feedstocks and any type of
conversion process. In this final approach, producers are required to
use the relative energy content of their renewable and non-renewable
feedstocks to determine the renewable fraction of the fuel that they
produce. This fraction in turn is used to determine the number of
gallon-RINs that should be generated for each batch. Commenters said
little about our proposed methodology to use the relative energy
content of the feedstocks, and we are therefore finalizing it largely
as proposed.
    We also requested comment on allowing renewable fuel producers to
use an accepted test method to directly measure the fraction of the
fuel that is derived from biomass rather than a fossil fuel feedstock.
For instance, ASTM D-6866 is a radiocarbon dating test method that can
be used to determine the renewable content of transportation fuel. The
use of such a test method can be used in lieu of the calculation of the
renewable portion of the fuel based on the relative energy content of
the renewable biomass and fossil feedstocks. Commenters generally
supported the option of using a radiocarbon dating approach. As a
result, we believe it would be appropriate and are finalizing a
provision to allow parties that co-process renewable biomass and fossil
fuels to choose between using the relative energy in the feedstocks or
ASTM D-6866 to determine the number of gallon-RINs that should be
generated. Regardless of the approach chosen, the

producer will still need to separately verify that the renewable
feedstocks meet the definition of renewable biomass.
    If a producer chose to use the energy content of the feedstocks,
the calculation would be similar to the treatment of renewable fuels
with multiple D codes as described in Section II.D.3 above. As shown in
the regulations at Sec.  80.1426(f)(3), the producer would determine
the renewable fuel volume that would be assigned RINs based on the
amount of energy in the renewable feedstock relative to the amount of
energy in the fossil feedstock. Only one batch-RIN would be generated
for a single volume of fuel produced from both a renewable feedstock
and a fossil feedstock, and this one batch-RIN must be based on the
contribution that the renewable feedstock makes to the total volume of
fuel. The calculation of the relative energy contents includes factors
that take into account the conversion efficiency of the plant, and as a
result potentially different reaction rates and byproduct formation for
the various feedstocks will be accounted for. The relative energy
content of the feedstocks is used to adjust the basic calculation of
the number of gallon-RINs downward from that calculated on the basis of
batch fuel volume and the applicable Equivalence Value. The D code that
must be assigned to the RINs is drawn from the lookup table in the
regulations as if the feedstock was entirely renewable biomass. Thus,
for instance, a coal-to-liquids plant that co-processes some cellulosic
biomass to make diesel fuel would be treated as a plant that produces
only cellulosic diesel for purposes of identifying the appropriate D
code for the fraction of biofuel that qualifies as renewable fuel under
EISA.
    If a producer chose to use D-6866, he would be required to either
apply this test to every batch, or alternatively to take samples of
every batch of fuel he produced over the course of one month and
combine them into a single composite sample. The D-6866 test would then
be applied to the composite sample, and the resulting renewable
fraction would be applied to all batches of fuel produced in the next
month to determine the appropriate number of RINs that must be
generated. For the first month, the producer can estimate the non-
fossil fraction, and then make a correction as needed in the second
month. The producer would be required to recalculate the renewable
fraction every subsequent month. See the regulations at Sec.
80.1426(f)(9).
5. Facilities That Process Municipal Solid Waste
    As described in Section II.B.4.d, only the separated yard and food
waste of municipal solid waste (MSW) are considered to be renewable
biomass and may be used to produce renewable fuels under the RFS2
program. While renewable fuel producers may produce fuel from all
organic components of MSW, they may generate RINs for only that portion
of MSW that qualifies as renewable biomass. We are providing two
methods for determining the appropriate number of RINs to generate for
each batch of fuel, depending on whether the feedstock is pure food and
yard waste, or separated municipal solid waste, as described in Section
II.B.4.d. While not all biogenic material in the separated MSW is
cellulosic, the vast majority of it is likely to be in most situations.
Specifically, separated municipal solid waste may contain some non-
biogenic materials such as plastics that were unable to be recycled due
to market conditions. We are requiring producers of renewable fuel made
from separated municipal solid waste to use the radiocarbon dating
method D-6866 to calculate the biogenic fraction, presumed to be
composed of cellulosic materials. Therefore, unless a renewable fuel
producer is using MSW streams that are clearly not cellulosic, we
anticipate that a D code of either 3 or 7 will be appropriate for such
RINs. See the regulations at Sec.  80.1426(f).
6. RINless Biofuel
    Under the RFS1 program, all renewable fuel made from renewable
feedstocks and used as motor vehicle fuel in the U.S. was assigned
RINs. Therefore, aside from the very small amounts of biofuel used in
nonroad applications or as heating oil, all renewable fuel produced or
imported counted towards the mandated volume goals of the RFS program.
Although conventional diesel fuel was not subject to the standards
under RFS1, all other motor vehicle fuel fell into two groups: fuel
subject to the standards, and fuel for which RINs were generated and
was used to meet those standards.
    Under RFS2, our approach to compliance with the renewable biomass
provision will allow the possibility for some biofuel to be produced
without RINs. As described in Section II.B.4 above, we are modifying
our approach to compliance with the renewable biomass provision so that
renewable fuel producers using feedstocks from domestic planted crops
and crop residue will be presumed to meet the renewable biomass
provision. Under this ``aggregate compliance'' approach, these
producers will be generating RINs for all their renewable fuel.
However, producers who use foreign-grown crops or crop residue or other
feedstocks such as planted trees or forestry residues will not be able
to take advantage of this aggregate compliance approach. Instead, they
will be required to demonstrate that their feedstocks meet the
renewable biomass definition, including the associated land use
restrictions, before they will be permitted to generate RINs. Absent
such a demonstration, these producers can still produce biofuel but
will not generate RINs. In addition, fuel producers whose fuel does not
qualify as renewable fuel under this program because it does not meet
the 20% GHG threshold (and is not grandfathered) can still produce
biofuel but will not be allowed to generate RINs. Transportation fuel
consumed in the U.S. will therefore be comprised of three groups: fuel
subject to the standards (gasoline and diesel), fuel for which RINs are
generated and will be used to meet those standards, and RINless
biofuel. RINless biofuel will not be covered under any aspect of the
RFS2 program, despite the fact that in many cases it will meet the EISA
definition of transportation fuel upon blending with gasoline or
diesel.
    In their comments in response to the NPRM, several refiners
suggested that RINless biofuel should be treated as an obligated volume
similar to gasoline and diesel, and thus be subject to the standards.
Doing so would ensure that all transportation fuels are covered under
the RFS2 program, consistent with RFS1. Such an approach would also
provide renewable fuel producers with an incentive to demonstrate that
their feedstocks meet the renewable biomass definition and thus
generate RINs for all the biofuel that they produce. There could be
less potential for market manipulation on the part of biofuel producers
who might be considering producing RINless biofuel as a means for
increasing demand for renewable fuel and RINs.
    Nevertheless, we do not believe that it would be appropriate at
this time to finalize a requirement that RINless biofuel be considered
an obligated fuel subject to the standards. We did not propose such an
approach in the NPRM, and as a result many renewable fuel producers who
could be affected did not have an opportunity to consider and comment
on it. Moreover, the volume of RINless biofuel is likely to be small
compared to the volume of renewable fuel with RINs since RINs have
value and producers currently have an

incentive to generate them. However, if in the future RIN values should
fall--for instance, if crude oil prices rise high enough and the market
drives up demand for biofuels--the incentive to demonstrate compliance
with the renewable biomass definition may decrease and there may be an
increase in the volume of RINless biofuel. Under such circumstances it
may be appropriate to reconsider whether RINless biofuel should be
designated as an obligated volume subject to the standards.

E. Applicable Standards

    The renewable fuel standards are expressed as a volume percentage,
and are used by each refiner, blender or importer to determine their
renewable fuel volume obligations. The applicable percentages are set
so that if each regulated party meets the percentages, then the amount
of renewable fuel, cellulosic biofuel, biomass-based diesel, and
advanced biofuel used will meet the volumes specified in Table I.A.1-
1.\16\
---------------------------------------------------------------------------

    \16\ Actual volumes can vary from the amounts required in the
statute. For instance, lower volumes may result if the statutorily
required volumes are adjusted downward according to the waiver
provisions in CAA 211(o)(7)(D). Also, higher or lower volumes may
result depending on the actual consumption of gasoline and diesel in
comparison to the projected volumes used to set the standards.
---------------------------------------------------------------------------

    The formulas finalized today for use in deriving annual renewable
fuel standards are based in part on an estimate of combined gasoline
and diesel volumes, for both highway and nonroad uses, for the year in
which the standards will apply. The standards will apply to refiners,
blenders, and importers of these fuels. As described more fully in
Section II.F.3, other producers of transportation fuel, such as
producers of natural gas, propane, and electricity from fossil fuels,
are not subject to the standards. Since the standards apply to
refiners, blenders and importers of gasoline and diesel, these are also
the transportation fuels that are used to determine the annual volume
obligations of an individual refiner, blender, or importer.
    The projected volumes of gasoline and diesel used to calculate the
standards will continue to be provided by EIA's Short-Term Energy
Outlook (STEO). The standards applicable to a given calendar year will
be published by November 30 of the previous year. Gasoline and diesel
volumes will continue to be adjusted to account for the required
renewable fuel volumes. In addition, gasoline and diesel volumes
produced by small refineries and small refiners will be exempt through
2010, and that year's standard is adjusted accordingly, as discussed
below.
    As discussed in the proposal, four separate standards are required
under the RFS2 program, corresponding to the four separate volume
requirements shown in Table I.A.1-1. The specific formulas we use to
calculate the renewable fuel standards are described below in Section
II.E.1.
    In order for an obligated party to demonstrate compliance, the
percentage standards are converted into the volume of renewable fuel
each obligated party is required to satisfy. This volume of renewable
fuel is the volume for which the obligated party is responsible under
the RFS program, and continues to be referred to as its Renewable
Volume Obligation (RVO). Since there are four separate standards under
the RFS2 program, there are likewise four separate RVOs applicable to
each obligated party. Each standard applies to the sum of all gasoline
and diesel produced or imported. Determination of RVOs is discussed in
Section II.G.2.
1. Calculation of Standards
a. How Are the Standards Calculated?
    The four separate renewable fuel standards are based primarily on
(1) the 49-state \17\ gasoline and diesel consumption volumes projected
by EIA, and (2) the total volume of renewable fuels required by EISA
for the coming year. Table I.A.2-1 shows the required overall volumes
of four types of renewable fuel specified in EISA. Each renewable fuel
standard is expressed as a volume percentage of combined gasoline and
diesel sold or introduced into commerce in the U.S., and is used by
each obligated party to determine its renewable volume obligation.
---------------------------------------------------------------------------

    \17\ Hawaii opted-in to the original RFS program; that opt-in is
carried forward to this program.
---------------------------------------------------------------------------

    Today we are finalizing an approach to setting standards that is
based in part on the sum of all gasoline and diesel produced or
imported in the 48 contiguous states and Hawaii. An approach we are not
adopting but which we discussed in the proposal would have split the
standards between those that would be specific to gasoline and those
that would be specific to diesel. Though this approach to setting
standards would more readily align the RFS obligations with the
relative amounts of gasoline and diesel produced or imported by each
obligated party, we are not adopting this approach because it relies on
projections of the relative amounts of gasoline-displacing and diesel-
displacing renewable fuels. These projections would need to be updated
every year, and as stated in the proposal, we believe that such an
approach would unnecessarily complicate the program.
    While the required amount of total renewable fuel for a given year
is provided by EISA, the Act requires EPA to base the standards on an
EIA estimate of the amount of gasoline and diesel that will be sold or
introduced into commerce for that year. As discussed in the proposal,
EIA's STEO will continue to be the source for projected gasoline, and
now diesel, consumption estimates. In order to achieve the volumes of
renewable fuels specified in EISA, the gasoline and diesel volumes used
to determine the standard must be the non-renewable portion of the
gasoline and diesel pools. Because the STEO volumes include renewable
fuel use, we must subtract the total renewable fuel volume from the
total gasoline and diesel volume to get total non-renewable gasoline
and diesel volumes. The Act also requires EPA to use EIA estimates of
renewable fuel volumes; the best estimation of the coming year's
renewable fuel consumption is found in Table 8 (U.S. Renewable Energy
Supply and Consumption) of the STEO. Additional information on
projected renewable fuel use will be included as it becomes available.
    As discussed in Section II.D.1, we are finalizing the energy
content approach to Equivalence Values for the cellulosic biofuel,
advanced biofuel, and total renewable fuel standards. However, the
biomass-based diesel standard is based on the volume of biodiesel. In
order to align both of these approaches simultaneously, biodiesel will
continue to generate 1.5 RINs per gallon as in RFS1, and the biomass-
based diesel volume mandate from EISA is then adjusted upward by the
same 1.5 factor. The net result is a biomass-based diesel gallon being
worth 1.0 gallons toward the biomass-based diesel standard, but 1.5
gallons toward the other standards.
    CAA section 211(o) exempts small refineries \18\ from the RFS
requirements until the 2011 compliance period. In RFS1, we extended
this exemption to the few remaining small refiners not already
exempted.\19\ Small refineries and small refiners will continue to be
exempt from the program until 2011 under the new RFS2 regulations. Thus
we have excluded their gasoline and diesel volumes from the overall
non-renewable gasoline and diesel volumes used to determine the
applicable percentages until 2011. As discussed in

the proposal, total small refinery and small refiner gasoline
production volume is expected to be fairly constant compared to total
U.S. transportation fuel production. Thus we estimated small refinery
and small refiner gasoline and diesel volumes using a constant
percentage of national consumption, as we did in RFS1. Using
information from gasoline batch reports submitted to EPA for 2006, EIA
data, and input from the California Air Resources Board regarding
California small refiners, we estimate that small refinery volumes
constitute 11.9% of the gasoline pool, and 15.2% of the diesel pool.
---------------------------------------------------------------------------

    \18\ Under section 211(o) of the Clean Air Act, small refineries
are those with 75,000 bbl/day or less average aggregate daily crude
oil throughput.
    \19\ See Section III.E.
---------------------------------------------------------------------------

    CAA section 211(o) requires that the small refinery adjustment also
account for renewable fuels used during the prior year by small
refineries that are exempt and do not participate in the RFS2 program.
Accounting for this volume of renewable fuel would reduce the total
volume of renewable fuel use required of others, and thus directionally
would reduce the percentage standards. However, as we discussed in
RFS1, the amount of renewable fuel that would qualify, i.e., that was
used by exempt small refineries and small refiners but not used as part
of the RFS program, is expected to be very small. In fact, these
volumes would not significantly change the resulting percentage
standards. Whatever renewable fuels small refineries and small refiners
blend will be reflected as RINs available in the market; thus there is
no need for a separate accounting of their renewable fuel use in the
equations used to determine the standards. We proposed and are
finalizing this value as zero.
    The levels of the percentage standards would be reduced if Alaska
or a U.S. territory chooses to participate in the RFS2 program, as
gasoline and diesel produced in or imported into that state or
territory would then be subject to the standard. Section 211(o) of the
Clean Air Act requires that the renewable fuel be consumed in the
contiguous 48 states, and any other state or territory that opts-in to
the program (Hawaii has subsequently opted in). However, because
renewable fuel produced in Alaska or a U.S. territory is unlikely to be
transported to the contiguous 48 states or to Hawaii, including their
renewable fuel volumes in the calculation of the standard would not
serve the purpose intended by section 211(o) of the Clean Air Act of
ensuring that the statutorily required renewable fuel volumes are
consumed in the 48 contiguous states and any state or territory that
opts-in. Therefore, renewable fuels used in Alaska or U.S. territories
are not included in the renewable fuel volumes that are subtracted from
the total gasoline and diesel volume estimates.
    In summary, the total projected non-renewable gasoline and diesel
volumes from which the annual standards are calculated are based on EIA
projections of gasoline and diesel consumption in the contiguous 48
states and Hawaii, adjusted by constant percentages of 11.9% and 15.2%
in 2010 to account for small refinery/refiner gasoline and diesel
volumes, respectively, and with built-in correction factors to be used
when and if Alaska or a territory opt-in to the program.
    The following formulas are used to calculate the percentage
standards:
[GRAPHIC] [TIFF OMITTED] TR26MR10.415

[GRAPHIC] [TIFF OMITTED] TR26MR10.416

[GRAPHIC] [TIFF OMITTED] TR26MR10.417

[GRAPHIC] [TIFF OMITTED] TR26MR10.418

Where

StdCB,i = The cellulosic biofuel standard for year i, in
percent
StdBBD,i = The biomass-based diesel standard (ethanol-
equivalent basis) for year i, in percent
StdAB,i = The advanced biofuel standard for year i, in
percent
StdRF,i = The renewable fuel standard for year i, in
percent
RFVCB,i = Annual volume of cellulosic biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVBBD,i = Annual volume of biomass-based diesel required
by section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVAB,i = Annual volume of advanced biofuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
RFVRF,i = Annual volume of renewable fuel required by
section 211(o)(2)(B) of the Clean Air Act for year i, in gallons
Gi = Amount of gasoline projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons*
Di = Amount of diesel projected to be used in the 48
contiguous states and Hawaii, in year i, in gallons
RGi = Amount of renewable fuel blended into gasoline that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons
RDi = Amount of renewable fuel blended into diesel that
is projected to be consumed in the 48 contiguous states and Hawaii,
in year i, in gallons
GSi = Amount of gasoline projected to be used in Alaska
or a U.S. territory in year i if the state or territory opts-in, in
gallons*
RGSi = Amount of renewable fuel blended into gasoline
that is projected to be consumed in Alaska or a U.S. territory in
year i if the state or territory opts-in, in gallons
DSi = Amount of diesel projected to be used in Alaska or
a U.S. territory in year i if the state or territory opts-in, in
gallons *
RDSi = Amount of renewable fuel blended into diesel that
is projected to be consumed in Alaska or a U.S. territory in

year i if the state or territory opts-in, in gallons
GEi = The amount of gasoline projected to be produced by
exempt small refineries and small refiners in year i, in gallons, in
any year they are exempt per Sec. Sec.  80.1441 and 80.1442,
respectively. Equivalent to 0.119*(Gi-RGi).
DEi = The amount of diesel projected to be produced by
exempt small refineries and small refiners in year i, in gallons, in
any year they are exempt per Sec. Sec.  80.1441 and 80.1442,
respectively. Equivalent to 0.152*(Di-RDi).

    * Note that these terms for projected volumes of gasoline and
diesel use include gasoline and diesel that has been blended with
renewable fuel.
b. Standards for 2010
    We are finalizing the standards for 2010 in today's action. As
explained in Section I.A.2, while the rulemaking is not effective until
July 1, 2010, the 2010 standards we are setting are annual standards
with compliance demonstrations are due by February 28, 2011.
    Under CAA section 211(o)(7)(D)(i), EPA is required to make a
determination each year regarding whether the required volumes of
cellulosic biofuel for the following year can be produced. For any
calendar year for which the projected volume of cellulosic biofuel
production is less than the minimum required volume, the projected
volume becomes the basis for the cellulosic biofuel standard. In such a
case, the statute also indicates that EPA may also lower the required
volumes for advanced biofuel and total renewable fuel.
    As discussed in Section IV.B., we are utilizing the EIA projection
of 5.04 million gallons (6.5 million ethanol equivalent gallons) of
cellulosic biofuel as the basis for setting the percentage standard for
cellulosic biofuel for 2010. This is lower than the 100 million gallon
standard set by EISA that we proposed upholding, but reflects the
current state of the industry, as discussed in section V.B. We expect
continued growth in the industry in 2011 and beyond. Since the advanced
biofuel standard is met by just the biomass-based diesel volume
required in 2010, and additional volumes of other advanced biofuels
(e.g., sugarcane ethanol) are available as well, no change to the
advanced biofuel standard is necessary for 2010. Moreover, given the
nested nature of the volume mandates, since no change in the advanced
biofuel standard is necessary, the total renewable fuel standard need
not be changed either.

                  Table II.E.1.b-1--Standards for 2010
------------------------------------------------------------------------
                                                               Percent
------------------------------------------------------------------------
Cellulosic biofuel........................................         0.004
Biomass-based diesel......................................         1.10
Advanced biofuel..........................................         0.61
Renewable fuel............................................         8.25
------------------------------------------------------------------------

2. Treatment of Biomass-Based Diesel in 2009 and 2010
    As described in Section I.A.2, the four separate 2010 standards
issued in today's rule will apply to all gasoline and diesel produced
in 2010. However, EISA included volume mandates for biomass-based
diesel, advanced biofuel, and total renewable fuel that applied in
2009. Since the RFS2 program was not effective in 2009 and thus the
volume mandates for biomass-based diesel and advanced biofuel were not
implemented in 2009, our NPRM proposed a mechanism to ensure that the
2009 biomass-based diesel volume mandate would eventually be met. In
today's final rule we are finalizing the proposed approach.
a. Shift in 2009 Biomass-Based Diesel Compliance Demonstration to 2010
    Under the RFS1 regulations that applied in 2009, we set the
applicable standard for total renewable fuel in November 2008 \20\
using the required volume of 11.1 billion gallons specified in the
Clean Air Act (as amended by EISA), gasoline volume projections from
EIA, and the formula provided in the regulations at Sec.  80.1105(d).
The existing RFS1 regulations did not provide a mechanism for requiring
the use of 0.5 billion gallons of biomass-based diesel or the 0.6
billion gallons of advanced biofuel mandated by EISA for 2009.
---------------------------------------------------------------------------

    \20\ See 73 FR 70643 (November 21, 2008).
---------------------------------------------------------------------------

    In the NPRM we proposed that the compliance demonstration for the
2009 biomass-based diesel requirement of 0.5 bill gal be extended to
2010. This approach would combine the 0.5 bill gal requirement for 2009
and the 0.65 bill gal requirement for 2010 into a single requirement of
1.15 bill gal for which compliance demonstrations would be made by
February 28, 2011. As described in the NPRM, we believe that the
deficit carryover provision provides a conceptual mechanism for this
approach, since it would have allowed obligated parties to defer
compliance with any or all of the 2009 standards until 2010. We are
finalizing this approach in today's action. We believe it will ensure
that these two year's worth of biomass-based diesel will be used, while
providing reasonable lead time for obligated parties. It avoids a
transition that fails to have any requirements related to the 2009
biomass-based diesel volume, and instead requires the use of the 2009
volume but achieves this by extending the compliance period by one
year. We believe this is a reasonable exercise of our authority under
section 211(o)(2) to issue regulations that ensure that the volumes for
2009 are ultimately used, even though we were unable to issue final
regulations prior to the 2009 compliance year. We announced our
intentions to implement the 2009 and 2010 biomass-based diesel
requirements in this manner in the November 2008 Federal Register
notice cited previously. We reiterated these intentions in our NPRM.
Thus, obligated parties will have had sufficient lead time to acquire a
sufficient number of biomass-based diesel RINs by the end of 2010 to
comply with the standard based on 1.15 bill gal.
    Data available at the time of this writing suggests that
approximately 450 million gallons of biodiesel was produced in 2009,
thus requiring 700 million gallons to be produced in 2010 to satisfy
the combined 2009 and 2010 volume mandates. Information from commenters
and other contacts in the biodiesel industry indicate that feedstocks
and production facilities will be available in 2010 to produce this
volume.
    Refiners generally commented that the proposed approach to 2009 and
2010 biomass-based diesel volumes was not appropriate and should not be
implemented. They also recommended that the RFS2 program should be made
effective on January 1, 2011 with no carryover of any previous-year
obligations for biomass-based diesel or any other volume mandate. In
contrast, the National Biodiesel Board and several individual biodiesel
producers supported the proposed approach, but believed it was
insufficient to compel obligated parties to purchase biodiesel in 2009,
something they considered critical to the survival of the biodiesel
industry. Many of these commenters requested that we conduct an interim
rulemaking that would apply to 2009 to implement the EISA mandated
volume of 0.5 billion gallons of biomass-based diesel. If the RFS2
program could not be implemented until 2011, they likewise requested
that interim measures be taken for 2010 to ensure that the full 1.15
bill gal requirement would be implemented. However, putting in place
this new volume requirement without also putting in place EISA's new
definition for biomass-based diesel, renewable fuel, and renewable
biomass

would have raised significant legal and policy issues that would
necessarily have required a new proposal with its own public notice and
comment process. Because of the significant time required for notice
and comment rulemaking, the need to provide industry with adequate lead
time for new requirements, and the fact that we were already well into
calendar year 2009 at the time the request for an interim rule was
received, it was unlikely that any interim rule could have impacted
biodiesel demand in 2009. Moreover, Agency resources applied to the
interim rulemaking would have been unavailable for development of the
final RFS2 rulemaking. Developing an interim rule could have undermined
EPA's ability to complete the full RFS2 program regulations in time for
2010 implementation. As a result, we did not pursue an interim
rulemaking.
    With regard to advanced biofuel, it is not necessary to implement a
separate requirement for the 0.6 billion gallon mandate for 2009. Due
to the nested nature of the volume requirements and the fact that
Equivalence Values will be based on the energy content relative to
ethanol, the 0.5 billion gallon requirement for biomass-based diesel
will count as 0.75 billion gallons of advanced biofuel, exceeding the
requirement of 0.6 billion gallons. Thus compliance with the biomass-
based diesel requirement in 2009 automatically results in compliance
with the advanced biofuel standard.
    All 2009 biodiesel and renewable diesel RINs, identifiable through
an RR code of 15 or 17 respectively under the RFS1 regulations, will be
valid for showing compliance with the adjusted 2010 biomass-based
diesel standard of 1.15 billion gallons. This use of previous year RINs
for current year compliance is consistent with our approach to any
other standard for any other year and consistent with the flexibility
available to any obligated party that carries a deficit from one year
to the next. Moreover, it allows an obligated party to acquire
sufficient biodiesel and renewable diesel RINs during 2009 to comply
with the 0.5 billion gallons requirement, even though their compliance
demonstration would not occur until the 2010 compliance period.
    We did not reduce the 2009 volume requirement for total renewable
fuel by 0.5 billion gallons to account for the fact that we intended to
move the compliance demonstration for this volume has been moved to the
2010 compliance period. Instead, we are allowing 2009 biodiesel and
renewable diesel RINs to be used for compliance purposes for both the
2009 total renewable fuel standard as well as the 2010 adjusted
biomass-based diesel standard (but not for the 2010 advanced biofuel or
total renewable fuel standards). To accomplish this, we proposed in the
NPRM that an obligated party would add up the 2009 biodiesel and
renewable diesel RINs that he used for 2009 compliance with the RFS1
standard for total renewable fuel, and reduce his 2010 biomass-based
diesel obligation by this amount. Thus, 2009 biodiesel and renewable
diesel RINs are essentially used twice. Any remaining 2010 biomass-
based diesel obligation would need to be covered either with 2009
biodiesel and renewable diesel RINs that were not used for compliance
in 2009 or with 2010 biomass-based diesel RINs. We are finalizing this
approach in today's notice.
b. Treatment of Deficit Carryovers, RIN Rollover, and RIN Valid Life
for Adjusted 2010 Biomass-Based Diesel Requirement
    Our transition approach for biomass-based diesel is conceptually
similar, but not identical, to the statutory deficit carryover
provision. In a typical deficit carryover situation, an obligated party
can carry forward any amount of a current-year deficit to the following
year. In the absence of any modifications to the deficit carryover
provisions for our biomass-based diesel transition provisions, then, an
obligated party that did not fully comply with the 2010 biomass-based
diesel requirement of 1.15 billion gallons could carry a deficit of any
amount into 2011. As described in the NPRM, we believe that the deficit
carryover provisions should be modified in the context of the
transition biomass-based diesel approach to more closely represent what
would have occurred if we had been able to implement the 0.5 bill gal
requirement in 2009. Specifically, we are prohibiting obligated parties
from carrying over a biomass-based diesel deficit into 2011 larger than
that based on the 0.65 bill gal volume requirement for 2010. This is
the amount that would have been permitted had we been able to implement
the biomass-based diesel requirements in 2009. In practice, this means
that deficit carryovers from 2010 into 2011 for biomass-based diesel
cannot not exceed 57% (0.65/1.15) of an obligated party's 2010 RVO.
This approach also helps to ensure a minimum volume mandate for
companies producing biomass-based diesel each year.
    Similarly, in the absence of any modifications to the provisions
regarding valid life of RINs, 2008 biodiesel and renewable diesel RINs
could not be used for compliance in 2010 with the adjusted biomass-
based diesel standard, despite the fact that the 2010 standard includes
the 2009 requirement for which 2008 RINs should be valid. The National
Biodiesel Board opposed this approach on the basis that the use of 2008
RINs for 2010 compliance demonstrations violated the 2-year valid life
limit for RINs. However, since the 2010 compliance demonstration will
include the obligation that would have applied in 2009, and 2008 RINs
would be valid for 2009 compliance, we are allowing excess 2008
biodiesel and renewable diesel RINs that were not used for compliance
purposes in 2008 to be used for compliance purposes in 2009 or 2010.
    As described in Section III.D, we are requiring the 20% RIN
rollover cap to apply in all years, and separately for all four
standards. However, consistent with our approach to deficit carryovers,
we believe that an additional constraint is warranted in the
application of the rollover cap to the biomass-based diesel obligation
in the 2010 compliance year to more closely represent what would have
occurred if we had been able to implement the 0.5 bill gal requirement
in 2009. Specifically, we are limiting the use of excess 2008 RINs to
20% of the statutory 2009 requirement of 0.5 bill gal. This is
equivalent to 0.1 bill gal (20% of 0.5 bill gal), or 8.7% of the
combined 2009/2010 obligation of 1.15 bill gal (0.1/1.15). Thus,
obligated parties will be allowed to use excess 2008 and 2009 biodiesel
and renewable diesel RINs for compliance with the 2010 combined
standard of 1.15 bill gal, so long as the sum of all previous-year RINs
(2008 plus 2009 RINs) does not exceed 20% of their 2010 obligation, and
the 2008 RINs do not exceed 8.7% of their 2010 obligation.
    Under RFS1, RINs are generated when renewable fuel is produced, but
if the fuel is ultimately used for purposes other than as motor vehicle
fuel the RINs must generally be retired. Under EISA, however, RINs
generated for renewable fuel that is ultimately used for nonroad
purposes, heating oil, or jet fuel are valid for compliance purposes.
To more closely align our transition approach for biomass-based diesel
to what could have occurred if we had issued the RFS2 standards prior
to 2009, we are allowing 2009 RINs that are retired because they are
ultimately used for nonroad, heating oil or jet fuel purposes to be
valid for compliance with the 2010 standards. Such RINs can

be reinstated by the retiring party in 2010.
3. Future Standards
    The statutorily-prescribed phase-in period ends in 2012 for
biomass-based diesel and in 2022 for cellulosic biofuel, advanced
biofuel, and total renewable fuel. Beyond these years, EISA requires
EPA to determine the applicable volumes based on a review of the
implementation of the program up to that time, and an analysis of a
wide variety of factors such as the impact of the production of
renewable fuels on the environment, energy security, infrastructure,
costs, and other factors. For these future standards, EPA must
promulgate rules establishing the applicable volumes no later than 14
months before the first year for which such applicable volumes would
apply. For biomass-based diesel, this would mean that final rules would
need to be issued by October 31, 2011 for application starting on
January 1, 2013. In today's rulemaking, we are not suggesting any
specific volume requirements for biomass-based diesel for 2013 and
beyond that would be appropriate under the statutory criteria that we
must consider. Likewise, we are not suggesting any specific volume
requirements for the other three renewable fuel categories for 2023 and
beyond. However, the statute requires that the biomass-based diesel
volume in 2013 and beyond must be no less than 1.0 billion gallons, and
that advanced biofuels in 2023 and beyond must represent at a minimum
the same percentage of total renewable fuel as it does in 2022. These
provisions will be implemented as part of an annual standard-setting
process.

F. Fuels That Are Subject to the Standards

    Under RFS1, producers and importers of gasoline are obligated
parties subject to the standards--any party that produces or imports
only diesel fuel is not subject to the standards. EISA changes this
provision by expanding the RFS program in general to include all
transportation fuel. As discussed above, however, section 211(o)(3)
continues to require EPA to determine which refiners, blenders, and
importers are treated as subject to the standard. As described further
in Section II.G below, under this rule, the sum of all highway and
nonroad gasoline and diesel fuel produced or imported within a calendar
year will be the basis on which the RVOs are calculated. This section
provides our final definition of gasoline and diesel for the purposes
of the RFS2 program.
1. Gasoline
    As with the RFS1 rule, the volume of gasoline used in calculating
the RVO under RFS2 will continue to include all finished gasoline
(reformulated gasoline (RFG) and conventional gasoline (CG)) produced
or imported for use in the contiguous United States or Hawaii, as well
as all unfinished gasoline that becomes finished gasoline upon the
addition of oxygenate blended downstream from the refinery or importer.
This includes both unfinished reformulated gasoline, called
``reformulated gasoline blendstock for oxygenate blending,'' or
``RBOB,'' and unfinished conventional gasoline designed for downstream
oxygenate blending (e.g., sub-octane conventional gasoline), called
``CBOB.'' The volume of any other unfinished gasoline or blendstock,
(such as butane or naphtha produced in a refinery) or exported
gasoline, will not be included in the obligated volume, except where
the blendstock is combined with other blendstock or gasoline to produce
finished gasoline, RBOB, or CBOB. Where a blendstock is blended with
other blendstock to produce finished gasoline, RBOB, or CBOB, the total
volume of the gasoline blend will be included in the volume used to
determine the blender's renewable fuels obligation. Where a blendstock
is added to finished gasoline, only the volume of the blendstock will
be included, since the finished gasoline would have been included in
the compliance determinations of the refiner or importer of the
gasoline. For purposes of this preamble, the various gasoline products
described above that we are including in a party's obligated volume are
collectively called ``gasoline.''
    Also consistent with the RFS1 program, we are continuing the
exclusion of any volume of renewable fuel contained in gasoline from
the volume of gasoline used to determine the renewable fuels
obligations. This exclusion applies to any renewable fuels that are
blended into gasoline at a refinery, contained in imported gasoline, or
added at a downstream location. Thus, for example, any ethanol added to
RBOB or CBOB at a refinery's rack or terminal downstream from the
refinery or importer will be excluded from the volume of gasoline used
by the refiner or importer to determine the obligation. This is
consistent with how the standard itself is calculated--EPA determines
the applicable percentage by comparing the overall projected volume of
gasoline used to the overall renewable fuel volume that is specified in
the statute, and EPA excludes ethanol and other renewable fuels that
are blended into the gasoline in determining the overall projected
volume of gasoline. When an obligated party determines their RVO by
applying the applicable percentage to the amount of gasoline they
produce or import, it is consistent to also exclude ethanol and other
renewable fuel blends from the calculation of the volume of gasoline
produced.
    As with the RFS1 rule, Gasoline Treated as Blendstock (GTAB) will
continue to be treated as a blendstock under the RFS2 program, and thus
will not count towards a party's renewable fuel obligation. Where the
GTAB is blended with other blendstock (other than renewable fuel) to
produce gasoline, the total volume of the gasoline blend, including the
GTAB, will be included in the volume of gasoline used to determine the
renewable fuel obligation. Where GTAB is blended with renewable fuel to
produce gasoline, only the GTAB volume will be included in the volume
of gasoline used to determine the renewable fuel obligation. Where the
GTAB is blended with finished gasoline, only the GTAB volume will be
included in the volume of gasoline used to determine the renewable fuel
obligation.
2. Diesel
    EISA expanded the RFS program to include transportation fuels other
than gasoline, thus both highway and nonroad diesel must be used in
calculating a party's RVO. Any party that produces or imports
petroleum-based diesel fuel that is designated as motor vehicle,
nonroad, locomotive, and marine diesel fuel (MVNRLM) (or any
subcategory of MVNRLM) will be required to include the volume of that
diesel fuel in the determination of its RVO under the RFS2 rule. Diesel
fuel includes any distillate fuel that meets the definition of MVNRLM
diesel fuel as it has already been defined in the regulations at Sec.
80.2(qqq), including any subcategories such as MV (motor vehicle diesel
fuel produced for use in highway diesel engines and vehicles), NRLM
(diesel fuel produced for use in nonroad, locomotive, and marine diesel
engines and equipment/vessels), NR (diesel fuel produced for use in
nonroad engines and equipment), and LM (diesel fuel produced for use in
locomotives and marine diesel engines and vessels).\21\ Transportation
fuels meeting

the definition of MVNRLM will be used to calculate the RVOs, and
refiners, blenders, or importers of MVNRLM will be treated as obligated
parties. As such, diesel fuel that is designated as heating oil, jet
fuel, or any designation other than MVNRLM or a subcategory of MVNRLM,
will not be subject to the applicable percentage standard and will not
be used to calculate the RVOs.\22\ We requested comment on the idea
that any diesel fuel not meeting these requirements, such as distillate
or residual fuel intended solely for use in ocean-going vessels, would
not be used to calculate the RVOs.
---------------------------------------------------------------------------

    \21\ EPA's diesel fuel regulations use the term ``nonroad'' to
designate one large category of land based off-highway engines and
vehicles, recognizing that locomotive and marine engines and vessels
are also nonroad engines and vehicles under EPAct's definition of
nonroad. Except where noted, the discussion of nonroad in reference
to transportation fuel includes the entire category covered by
EPAct's definition of nonroad.
    \22\ See 40 CFR 80.598(a) for the kinds of fuel types used by
refiners or importers in designating their diesel fuel.
---------------------------------------------------------------------------

    One commenter expressed support for including heating oil and jet
fuel into the RIN program, but not to subject these fuels to the RVO
mandate. The commenter stated that fluctuating weather conditions make
it hard to predict with any reliability the volumes of heating oil that
will be used in a given year. Another commenter stated that it supports
the extension of the RFS program to transportation fuels, including
diesel and nonroad fuels.
    With respect to fuels for use in ocean-going vessels, EISA
specifies that ``transportation fuels'' do not include such fuels. We
are interpreting that ``fuels for use in ocean-going vessels'' means
residual or distillate fuels other than MVNRLM intended to be used to
power large ocean-going vessels (e.g., those vessels that are powered
by Category 3 (C3), and some Category 2 (C2), marine engines and that
operate internationally). Thus, fuel for use in ocean-going vessels, or
that an obligated party can verify as having been used in an ocean-
going vessel, will be excluded from the renewable fuel standards. Also,
in the context of the recently finalized fuel standards for C3 marine
vessels, this would mean that fuel meeting the 1,000 ppm fuel sulfur
standard would not be considered obligated volume, while all MVNRLM
diesel fuel would.
3. Other Transportation Fuels
    Transportation fuels other than gasoline or MVNRLM diesel fuel
(natural gas, propane, and electricity) will not be used to calculate
the RVOs of any obligated party. We believe this is a reasonable way to
implement the obligations of 211(o)(3) because the volumes are small
and the producers cannot readily differentiate the small portion used
in the transportation sector from the large portion used in other
sectors (in fact, the producer may have no knowledge of its ultimate
use). We will reconsider this approach if and when these volumes grow.
At the same time, it is clear that these fuels can be used as
transportation fuel, and under certain circumstances, producers of such
``other transportation fuels'' may generate RINs as a producer or
importer of a renewable fuel. See Section II.D.2.a for further
discussion of other RIN-generating fuels.

G. Renewable Volume Obligations (RVOs)

    Under RFS1, each obligated party was required to determine its RVO
based on the applicable percentage standard and its annual gasoline
volume. The RVO represented the volume of renewable fuel that the
obligated party was required to ensure was used in the U.S. in a given
calendar year. Obligated parties were required to meet their RVO
through the accumulation of RINs which represent the amount of
renewable fuel used as motor vehicle fuel that was sold or introduced
into commerce within the U.S. Each gallon-RIN counted as one gallon of
renewable fuel for compliance purposes.
    We are maintaining this approach to compliance under the RFS2
program. However, one primary difference between RFS1 and the new RFS2
program in terms of demonstrating compliance is that each obligated
party now has four RVOs instead of one (through 2012) or two (starting
in 2013) under the RFS1 program. Also, as discussed above, RVOs are now
calculated based on production or importation of both gasoline and
diesel fuels, rather than gasoline alone.
    By acquiring RINs and applying them to their RVOs, obligated
parties are deemed to have satisfied their obligation to cause the
renewable fuel represented by the RINs to be consumed as transportation
fuel in highway or nonroad vehicles or engines. Obligated parties are
not required to physically blend the renewable fuel into gasoline or
diesel fuel themselves. The accumulation of RINs will continue to be
the means through which each obligated party shows compliance with its
RVOs and thus with the renewable fuel standards.
    If an obligated party acquires more RINs than it needs to meet its
RVOs, then in general it can retain the excess RINs for use in
complying with its RVOs in the following year (subject to the 20%
rollover cap discussed in Section III.D) or transfer the excess RINs to
another party. If, alternatively, an obligated party has not acquired
sufficient RINs to meet its RVOs, then under certain conditions it can
carry a deficit into the next year.
    This section describes our approach to the calculation of RVOs
under RFS2 and the RINs that are valid for demonstrating compliance
with those RVOs. This includes a description of the special treatment
that must be applied to RFS1 RINs used for compliance purposes under
RFS2, since RINs generated under RFS1 regulations are not exactly the
same as those generated in under RFS2.
1. Designation of Obligated Parties
    In the NPRM, we proposed to continue to designate obligated parties
under the RFS2 program as they were designated under RFS1, with the
addition of diesel fuel producers and importers. Regarding gasoline
producers and importers, we proposed that obligated parties who are
subject to the standard would be those that produce or import finished
gasoline (RFG and conventional) or unfinished gasoline that becomes
finished gasoline upon the addition of an oxygenate blended downstream
from the refinery or importer. Unfinished gasoline would include
reformulated gasoline blendstock for oxygenate blending (RBOB), and
conventional gasoline blendstock designed for downstream oxygenate
blending (CBOB) which is generally sub-octane conventional gasoline.
The volume of any other unfinished gasoline or blendstock, such as
butane, would not be included in the volume used to determine the RVO,
except where the blendstock was combined with other blendstock or
finished gasoline to produce finished gasoline, RBOB, or CBOB. Thus,
parties downstream of a refinery or importer would only be obligated
parties to the degree that they use non-renewable blendstocks to make
finished gasoline, RBOB, CBOB, or diesel fuel.
    We also took comment on two alternative approaches to the
designation of obligated parties:

--Elimination of RBOB and CBOB from the list of fuels that are subject
to the standard, such that a party's RVO would be based only on the
non-renewable volume of finished gasoline or diesel that he produces or
imports, thereby moving a portion of the obligation to downstream
blenders of renewable fuels into RBOB and CBOB.
--Moving the obligations for all gasoline and diesel downstream of
refineries and importers to parties who supply finished transportation
fuels to retail outlets or to wholesale purchaser-consumer facilities.

These alternative approaches have the potential to more evenly align a
party's access to RINs with that party's obligations under the RFS2
program. As described more fully in the NPRM, we considered these
alternatives because of market conditions that had changed since the
RFS1 program began. For instance, obligated parties who have excess
RINs have been observed to retain rather than sell them to ensure they
have a sufficient number for the next year's compliance. This was most
likely to occur with major integrated refiners who operate gasoline
marketing operations and thus have direct access to RINs for ethanol
blended into their gasoline. Refiners whose operations are focused
primarily on producing refined products with less marketing do not have
such direct access to RINs and could potentially find it difficult to
acquire a sufficient number for compliance despite the fact that the
total nationwide volume of renewable fuel meets or exceeds the
standard. The result might be a higher price for RINs (and fuel) in the
marketplace than would be expected under a more liquid RIN market. For
similar reasons, we also took comment on possible changes to the
requirement that RINs be transferred with volume through the
distribution system as discussed more fully in Section II.H.4.
    In response to the NPRM, stakeholders differed significantly on
whether EPA should implement one of these alternative approaches. For
instance, while some refiners expressed support for moving the
obligations to downstream parties such as blenders, terminals, and/or
wholesale purchaser-consumers, other refiners preferred to maintain the
current approach. Blenders and other downstream parties generally
expressed opposition to a change in the designation of obligated