determining whether the 90% displacement criterion has been met. We are
interpreting it in this way because we believe the accounting of fuel
use associated with transportation and other life cycle activities
would be extremely difficult and in many cases impossible.\19\
---------------------------------------------------------------------------

    \19\ In Section IX of today's preamble we discuss our analysis
of the lifecycle fuel impacts of the RFS rule, with respect to
greenhouse gas (GHG) emissions. While we do account for fuel used in
hauling materials to ethanol plants in our analysis, we are using
average nationwide values, rather than data collected for individual
plants.
---------------------------------------------------------------------------

    Based on the operation of ethanol plants, we are viewing this
definition to apply to waste materials used to produce thermal energy
rather than electrical energy. Electrical usage at ethanol plants is
used for lights and equipment not directly related to the production of
ethanol. Also, the calculation of fossil fuel used to generate such
electrical usage would be difficult because it is not always possible
to track the source of electricity that is purchased off-site.
Therefore, the final regulations consider displacement of 90 percent of
fossil fuels at the ethanol plant to mean those fuels consumed on-site
and that are used to generate thermal energy used to produce ethanol.
    One commenter suggested that electricity from cogeneration (i.e.,
combined heat and power) units be considered in determining the
percentage of fossil fuel use that is displaced. The commenter claims
that allowing consideration of electricity use would provide an
incentive for cogeneration to be used at ethanol plants. Our findings
regarding the use of electricity at ethanol plants remain the same--
that is, it is not used as part of

the heat source in ethanol production for economic reasons. We note
also that the commenter did not present any evidence to the contrary.
As such, we continue to maintain that electricity is not ``normally
used in the production of ethanol'' and we are therefore only
considering the displacement of fossil fuels associated with thermal
energy at the plant.
    Owners who claim their product qualifies as cellulosic biomass
ethanol based on the 90 percent fossil fuel displacement through the
use of waste materials (i.e., animal wastes, and other waste materials)
are required under today's rule to keep records of fuel (waste-derived
and fossil fuel) used for thermal energy for verification of their
claims. They will also be required to track the fossil fuel equivalent
of any off-site generated waste heat that is captured and which
displaces fossil fuel used in the ethanol production process. Since
such waste heat would typically be purchased through agreement with the
off-site owner, we do not feel it burdensome for owners to track such
information. Owners will therefore calculate the amount of energy in
Btu's associated with waste-derived fuels (including the fossil fuel
equivalent waste heat), and divided by the total energy in Btus used to
produce ethanol in a given year. Ethanol produced from such facilities
will get the benefit of the 2.5 ratio. (Section III.D.3.e discusses the
requirements for owners of facilities that claim to have produced
cellulosic ethanol under the 90 percent displacement provision, but
which fail to meet those requirements.)
c. Ethanol That Is Made From the Non-Cellulosic Portions of Animal,
Other Waste, and Municipal Waste
    ``Waste derived ethanol'' is defined in the Act as ethanol derived
from ``animal wastes, including poultry fats and poultry wastes, and
other waste materials; * * * or municipal solid waste.'' Both animal
wastes and municipal solid waste are also listed as allowable
feedstocks for the production of ``cellulosic biomass ethanol.'' When
such feedstocks do not contain cellulose, however, the resulting
ethanol is waste derived. Both waste-derived and cellulosic ethanol
both are considered equivalent to 2.5 gallons of renewable fuel when
determining compliance with the renewable volume obligation.
d. Foreign Producers of Cellulosic and Waste-Derived Ethanol
    Some commenters stated that foreign ethanol producers should not be
able to have their cellulosic or waste-derived ethanol treated in the
same manner as domestic cellulosic or waste-derived ethanol under the
RFS program because of the difficulty in verifying their compliance
with the provisions discussed above. Today's rule allows such producers
to participate, provided they meet the requirements discussed in
Section IV.D.2. of the preamble. The requirements for foreign producers
of cellulosic or waste-derived ethanol are different than for domestic
producers and allow for verification of compliance.
2. What Is Biodiesel?
    The Act states that ``The term `renewable fuel' includes * * *
biodiesel (as defined in section 312(f)) of the Energy Policy Act of
1992.'' This definition, as modified by Section 1515 of the Energy Act
states:

    The term ``biodiesel'' means a diesel fuel substitute produced
from nonpetroleum renewable resources that meets the registration
requirements for fuels and fuel additives established by the
Environmental Protection Agency under section 7545 of this title,
and includes biodiesel derived from animal wastes, including poultry
fats and poultry wastes, and other waste materials, or municipal
solid waste and sludges and oils derived from wastewater and the
treatment of wastewater.

    This definition of biodiesel would include both mono-alkyl esters
which meet the current ASTM specification D-6751-07 \20\ (the most
common meaning of the term ``biodiesel'') that have been registered
with EPA, and any non-esters that are intended for use in engines that
are designed to run on conventional, petroleum-derived diesel fuel,
have been registered with the EPA, and are made from any of the
feedstocks listed above.
---------------------------------------------------------------------------

    \20\ In the event that the ASTM specification D-6751 is
succeeded with an updated specification in the future, EPA may
revise the regulations accordingly at such time. Regulations cannot
be promulgated that only reference ``the most recent version'' of an
ASTM standard, since doing so would place the American Society for
Testing and Materials in the position of a regulatory body.
---------------------------------------------------------------------------

    To implement the above definition of biodiesel in the context of
the RFS rulemaking while still recognizing the unique history and role
of mono-alkyl esters meeting ASTM D-6751, we have divided the Act's
definition of biodiesel into two separate parts: Biodiesel (mono-alkyl
esters) and non-ester renewable diesel. The combination of ``biodiesel
(mono-alkyl esters)'' and ``non-ester renewable diesel'' in the
regulations fulfills the Act's definition of biodiesel. Commenters
supported EPA's approach in defining biodiesel in this manner.
a. Biodiesel (Mono-Alkyl Esters)
    Under today's rule, the term ``biodiesel (mono-alkyl esters)''
means a motor vehicle fuel which: (1) Meets the registration
requirements for fuels and fuel additives established by the
Environmental Protection Agency under section 7545 of this title (Clean
Air Act Section 211); (2) is a mono-alkyl ester; (3) meets ASTM
specification D-6751-07; (4) is intended for use in engines that are
designed to run on conventional, petroleum-derived diesel fuel, and (5)
is derived from nonpetroleum renewable resources.
b. Non-Ester Renewable Diesel
    The term ``non-ester renewable diesel'' means a motor vehicle fuel
which: (1) Meets the registration requirements for fuels and fuel
additives established by the Environmental Protection Agency under
section 7545 of this title (Clean Air Act Section 211); (2) is not a
mono-alkyl ester; (3) is intended for use in engines that are designed
to run on conventional, petroleum-derived diesel fuel, and (4) is
derived from nonpetroleum renewable resources. Current examples of a
non-ester renewable diesel include: ``Renewable diesel'' produced by
the Neste or UOP process, or diesel fuel produced by processing fats
and oils through a refinery hydrotreating process.
3. Does Renewable Fuel Include Motor Fuel That Is Made From
Coprocessing a Renewable Feedstock With Fossil Fuels?
    Renewable fuels can be produced by processing biologically derived
wastes such as animal fats, as well as other nonpetroleum based
feedstocks in a traditional refinery--that is, a refinery that normally
uses crude oil or other fossil fuel-based blendstocks as feeds to
processing units. Such wastes are pre-processed so that they are in
liquid form to enable their further processing in units at a
traditional refinery. In the proposed rule, we defined such feedstocks
as ``biocrudes'' and included a discussion on how the fuels resulting
from these feedstocks should be counted. Our basic approach remains the
same. We have changed the term ``biocrudes'' to ``renewable crudes'',
since we believe it is more accurate. We are providing additional
discussion in this preamble on how renewable fuels are made from
renewable crudes.
    The fuels resulting from the co-processing of the pre-processed
liquid form of these renewable crudes (i.e., those feedstocks listed in
the definition of ``renewable fuel'' and, for biodiesel, in the
statutory definition of ``biodiesel'') in a traditional refinery are

themselves indistinguishable from the gasoline and diesel products
produced from crude oil. As such, the treatment of any resulting
renewable fuel presents a particular complication in terms of RFS
program compliance--namely, if such fuels are indistinguishable from
gasoline and diesel produced from crude oil feedstocks, how are the
volumes to be measured? Also, some renewable feedstocks are used to
produce renewable diesel (discussed in Section III.B.2 above). In other
circumstances renewable feedstocks are processed in dedicated
facilities or units--that is, in either (1) facilities other than
refineries that process fossil fuels, (2) equipment located within a
traditional refinery but which is dedicated to renewable feedstocks, or
(3) equipment located within a traditional refinery that processes
renewable and conventional feedstocks but solely for the production of
motor vehicle fuels.
    The processing approach for the renewable feedstock dictates
whether the resulting fuel is distinguishable from crude oil-based
fuels by virtue of its being made and stored separately from fossil
fuels as discussed in further detail below. Therefore, our method for
counting renewable fuels made from renewable feedstocks differ based on
how the renewable feedstock is processed
a. Definition of ``Renewable Crudes'' and ``Renewable Crude-Based
Fuels''
    Under some circumstances renewable feedstocks can be preprocessed
into a liquid that is similar to petroleum-based feedstocks used in
traditional refineries. We are classifying such liquids as ``renewable
crudes,'' and any motor vehicle fuel that is made from such liquids is
defined broadly as ``renewable crude-based fuel''.
    There are three approaches that can be taken to making renewable
fuels from renewable crudes. The first would include gasoline or diesel
products resulting from the processing of renewable crudes in
production units within refineries that simultaneously process crude
oil and other petroleum based feedstocks. In these cases, the final
product consists of a mixture of renewable fuel and fossil-based fuel,
and may include both motor vehicle fuel and non-motor vehicle fuel. The
second approach would include diesel and other products resulting from
processing renewable crudes at a stand-alone facility that does not
process any fossil fuels, or at a facility dedicated to renewable
crudes within a traditional refinery.\21\ In this case, a batch of
renewable crude used as feedstock to a production unit would replace
crude oil or other petroleum based feedstocks which ordinarily would be
the feedstock in that process unit. The third approach would be non-
ester renewable diesel fuel produced by processing fats and oils
through a refinery hydrotreating process. All three approaches can
produce renewable fuel that is valid for compliance purposes under the
RFS program, but the measurement of volumes produced and/or their
associated Equivalence Values may differ.
---------------------------------------------------------------------------

    \21\ Renewable crude-based fuels will need to be registered
under the provisions contained in 40 CFR 79 Part 4 before they can
be sold commercially.
---------------------------------------------------------------------------

b. How Are Renewable Crude-Based Fuel Volumes Measured?
    As discussed above, some renewable feedstocks are processed in
facilities other than refineries, or in equipment located within a
traditional refinery but which is dedicated to renewable feedstocks.
The resulting product is ``renewable diesel'' (and such units may in
the future also produce ``renewable gasoline'' though none is currently
made in such dedicated facilities). In other situations, renewable
crudes are coprocessed along with crude oils in traditional refineries,
resulting in gasoline or diesel products that may be combinations of
renewable and non-renewable fuels.
    In the case of renewable crude coprocessed with fossil fuels in
refineries, we are assuming that all of the renewable crude used as a
feedstock in a refinery unit will end up as a renewable crude-based
fuel that is valid for RFS compliance purposes. We are taking this
approach because renewable crudes that are processed through distillate
hydrotreaters are first pre-processed so that they are in liquid form,
and such liquid produces diesel fuel in volumes approximately equal to
the amount that is input to the hydrotreater. We are assuming that
renewable crudes could also be processed in other process units at
refineries to make gasoline. The renewable crude processed at a
refinery is functionally equivalent to crude oil, and the end products
(gasoline and/or diesel) are indistinguishable from products made from
crude oil. Thus, rather than requiring the refiner to document what
portion of the renewable crude-based fuel is renewable fuel, we are
requiring that the volume of the renewable crude itself count as the
volume of renewable fuel produced for the purposes of determining the
volume block codes that are in the RIN (discussed in further detail in
Section III.D).\22\ The general counting procedure for renewable crude-
based fuels that are not derived through coprocessing with fossil fuels
is that the volumes of renewable fuel produced are measured directly,
and an appropriate Equivalence Value is assigned according to the
methodology discussed in Section III.B.4.
---------------------------------------------------------------------------

    \22\ We are considering the volumes of renewable crude itself,
not the feedstocks that are made into renewable crude.
---------------------------------------------------------------------------

4. What Are ``Equivalence Values'' for Renewable Fuel?
    One question that EPA needed to address in developing the
regulations was how to count volumes of renewable fuel in determining
compliance with the renewable volume obligation. The Act stipulates
that every gallon of waste-derived ethanol and cellulosic biomass
ethanol should count as if it were 2.5 gallons for RFS compliance
purposes. The Act does not stipulate similar values for other renewable
fuels, but as described below we believe it is appropriate to do so.
    We are requiring that the ``Equivalence Values'' for renewable
fuels other than those for which specific values are set forth in the
Act be based on their energy content in comparison to the energy
content of ethanol, adjusted as necessary for their renewable content.
The result is an Equivalence Value for corn ethanol of 1.0, for
biobutanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, and for
non-ester renewable diesel of 1.7. However, the methodology can be used
to determine the appropriate equivalence value for any other potential
renewable fuel as well.
    This section describes why the use of the Equivalence Value
approach in today's rule is appropriate under the Act, and our
conclusions regarding the possible future use of lifecycle analyses as
the basis of Equivalence Values.
 a. Authority Under the Act To Establish Equivalence Values
    We are requiring that Equivalence Values be assigned to every
renewable fuel to provide an indication of the number of gallons that
can be claimed for compliance purposes for every physical gallon of
renewable fuel. An Equivalence Value of 1.0 means that every physical
gallon of renewable fuel counts as one gallon for RFS compliance
purposes. An Equivalence Value greater than 1.0 means that every
physical gallon of renewable fuel counts as more than one gallon for
RFS compliance

purposes, while a value less than 1.0 counts as less than one gallon.
    We have interpreted the Act as allowing us to develop Equivalence
Values according to the methodology discussed below. We believe that
the use of Equivalence Values based on energy content in comparison to
the energy content of ethanol is consistent with the intent of Congress
to treat different renewable fuels differently in different
circumstances, and to provide incentives for use of renewable fuels in
certain circumstances, as evidenced by those specific circumstances
addressed by Congress. The Act has several provisions that provide for
mechanisms other than straight volume measurement to determine the
value of a renewable fuel in terms of RFS compliance. For example, 1
gallon of cellulosic biomass or waste derived ethanol is to be treated
as 2.5 gallons of renewable fuel. EPA is also required to establish an
``appropriate amount of credits'' for biodiesel, and to provide for
``an appropriate amount of credit'' for using more renewable fuels than
are required to meet your obligation. EPA is also to determine the
``renewable fuel portion'' of a blending component derived from a
renewable fuel. These statutory provisions provide evidence that
Congress did not limit this program solely to a straight volume
measurement of gallons in the context of the RFS program.
    In response to the NPRM, some commenters supported our view that
the Act provides sufficient context and direction to permit the use of
Equivalence Values, while other commenters opposed this view. Some
parties commented that the methodology proposed in the NPRM did not go
far enough. These parties argued that instead of energy content, EPA
should be using lifecycle impacts to set the Equivalence Values.
Lifecycle analyses are discussed in more detail in Section III.B.4.c.
    Parties that opposed our proposed approach to Equivalence Values
argued that since the Act did not explicitly give EPA the authority to
set Equivalence Values for renewable fuels other than cellulosic
biomass ethanol and waste-derived ethanol, EPA had no authority to do
so. In their view, the explicit inclusion of a 2.5 credit value for
cellulosic and waste-derived ethanol and the omission of any credit
values for other renewables fuels should be taken as evidence that
Congress intended all other renewable fuels to have Equivalence Values
of 1.0.
    We disagree that our discretion is so strictly limited. The Act
specifically gave EPA the authority to determine an ``appropriate''
credit for biodiesel, and also establishes a 2.5 value for cellulosic
biomass ethanol and waste-derived ethanol. As ethanol and biodiesel
were likely the two primary renewable fuels envisioned in the near-term
under the Act, it would seem normal for Congress to have focused on
these. However, Congress also clearly allowed for other renewable fuels
to participate in the RFS program, and it is appropriate for EPA to
consider how they should be treated under the Act. Furthermore, in
addition to the Act's direction that EPA determine an appropriate level
of credit for biodiesel, the Act also directs EPA to determine the
``appropriate'' amount of credit for renewable fuel use in excess of
the required volumes, and to determine the ``renewable fuel portion''
of a blending component derived from a renewable fuel. These statutory
provisions lend further support to our belief that Congress did not
limit the RFS program solely to a straight volume measurement of
gallons. Having concluded that it is appropriate to determine an
appropriate level of credit for biodiesel based on energy content as
compared to ethanol, EPA is using a consistent approach for other types
of renewable fuels for which a specific statutory credit value is not
prescribed.
    Another reason given by parties opposing our approach to
Equivalence Values was that Equivalence Values higher than 1.0 would
result in actual volumes of renewable fuel being less than the volumes
required by the Act. Although it is true that the Act specifies the
annual volumes of renewable fuel that the program must require and
directs EPA to promulgate regulations ensuring that gasoline sold each
year ``contains the applicable volume of renewable fuel,'' the Act also
contains language that makes the achievement of those volumes
imprecise. For instance, the deficit carryover provision allows any
obligated party to fail to meet its RVO in one year if it meets the
deficit and its RVO in the next year. If many obligated parties took
advantage of this provision, it could result in the nationwide total
volume obligation for a particular calendar year not being met. In
addition, the calculation of the renewable fuel standard is based on
projected nationwide gasoline volumes provided by EIA (see Section
III.A). If the projected gasoline volume falls short of the actual
gasoline volume in a given year, the standard will fail to create the
demand for the full renewable fuel volume required by the Act for that
year. The Act contains no provision for correcting for underestimated
gasoline volumes, and as a result the volumes required by the Act may
not be consumed in use.
    Some commenters disagreed with our belief that there will only be
very limited additional situations where an Equivalence Value other
than 1.0 is used. They expressed concern that the provision for
Equivalence Values will interfere with meeting the total national
volume goals for usage of renewable fuel.
    While in the long term we agree that renewable fuels with an
Equivalence Value greater than 1.0 may grow to become a larger portion
of the renewable fuel pool, we do not believe that this is likely to be
the case before 2013, the time period when the statute specifies the
overall national volumes. EPA will be issuing a new rule prior to 2013,
and can reconsider its approach to Equivalence Values for renewable
fuel at that time if it is appropriate to do so. For instance, EIA
projects that biodiesel volumes will reach 300 million gallons by 2012.
With the Equivalence Value of 1.5 that we are finalizing today, this
means that the 7.5 billion gallons required by the Act for 2012 could
be met with 7.35 billion gallons of renewable fuel. However, this
result is well within the variability in actual volumes resulting from
the other statutory provisions described above, and would still result
in 7.5 billon gallons of ethanol-equivalent (in terms of energy
content) renewable fuel being consumed. Congress explicitly recognized
the expected use of credits for biodiesel, as it did for cellulosic
ethanol. By requiring or authorizing EPA to assign credit values for
such products, Congress recognized that the national volumes specified
in the Act would not necessarily be met on a gallon per gallon basis.
For the very limited number of other renewable fuels not covered by
these express statutory provisions, assigning an equivalence value is
consistent with this overall approach. Moreover, EIA is projecting that
the total volume of renewable fuel will exceed the Act's requirements
by a substantial margin due primarily to the favorable economics of
ethanol in comparison to gasoline. Under such projections, the
existence of renewable fuels with Equivalence Values higher than 1.0
will have no impact on the demand for renewable fuel.
    Finally, the Act also contains language indicating that EPA has
flexibility in determining how various renewable fuels should count
towards meeting the required annual volumes. For instance, valid
renewable fuels are defined as those that ``replace or reduce the
quantity of fossil fuel present in a fuel mixture used to operate a
motor

vehicle.'' Fossil fuels such as gasoline or diesel are only replaced or
reduced to the degree that the energy they contain is replaced or
reduced. We do not believe it would be appropriate to treat a renewable
fuel with very low volumetric energy content as being equivalent to a
renewable fuel with very high volumetric energy content, since the
impact on motor vehicle fossil fuel use is very different for these two
renewable fuels. The use of Equivalence Values based on volumetric
energy content helps to achieve this goal.
    A case in point would be butanol. It is produced from the same
feedstocks as ethanol (i.e., starch crops such as corn) in a similar
process. However, it results in an alcohol with a higher volumetric
energy content than ethanol. If we were to give butanol an Equivalence
Value of 1.0, it would provide an economic disincentive for corn to be
used to produce butanol instead of ethanol.
    As a result, we continue to believe that the assignment of
Equivalence Values other than 1.0 to some renewable fuels is a
reasonable way for the RFS program to establish ``appropriate'' credit
values while also ensuring that the Act's volume obligations, read
together with the Act's directions regarding credit values towards
fulfillment of that obligation, are satisfied. This approach is
consistent with the way Congress treated the various specific
circumstances noted above, and thus is basically a continuation of that
process.
b. Energy Content and Renewable Content as the Basis for Equivalence
Values
    To appropriately account for the different energy contents of
different renewable fuels as well as the fact that some renewable fuels
actually contain some non-renewable content, we are requiring that
Equivalence Values be calculated using both the renewable content of a
renewable fuel and its energy content. This section describes the
calculation methodology for Equivalence Values.
    In order to take the energy content of a renewable fuel into
account when calculating the Equivalence Values, we must identify an
appropriate point of reference. Ethanol is a reasonable point of
reference as it is currently the most prominent renewable fuel in the
transportation sector, and it is likely that the authors of the Act saw
ethanol as the primary means through which the required volumes would
be met in at least the first years of the RFS program. By comparing
every renewable fuel to ethanol on an equivalent energy content basis,
each renewable fuel is assigned an Equivalence Value that precisely
accounts for the amount of petroleum in motor vehicle fuel that is
reduced or replaced by that renewable fuel in comparison to ethanol. To
the degree that corn-based ethanol continues to dominate the pool of
renewable fuel, this approach allows actual volumes of renewable fuel
to be consistent with the volumes required by the Act.
    Equivalence Values also account for the renewable content of
renewable fuels, since the presence of any non-renewable content
impairs the ability of the renewable fuel to replace or reduce the
quantity of fossil fuel present in a fuel mixture used to operate a
motor vehicle. The Act specifically states that only the renewable fuel
portion of a blending component should be considered part of the
applicable volume under the RFS program. As described in more detail
below, we have interpreted this to mean that every renewable fuel
should be evaluated at the molecular level to distinguish between those
molar fractions that were derived from a renewable feedstock, versus
those molar fractions that were derived from a fossil fuel feedstock.
Along with energy content in comparison to ethanol, the relative energy
fraction of renewable versus non-renewable content is thus used
directly as the basis for the Equivalence Value.
    We are requiring that the calculation of Equivalence Values
simultaneously take into account both the renewable content of a
renewable fuel and its energy content in comparison to denatured
ethanol. To accomplish this, we are requiring the following formula:

EV = (RRF / REth) x (ECRF /
ECEth)

Where:

EV = Equivalence Value for the renewable fuel.
RRF = Renewable content of the renewable fuel, in percent
of molecular energy.
REth = Renewable content of denatured ethanol, in percent
of molecular energy.
ECRF = Energy content of the renewable fuel, in Btu per
gallon (LHV).
ECEth = Energy content of denatured ethanol, in Btu per
gallon (LHV).

    Instead of the higher heating value, the lower heating value (LHV)
is used to represent energy content because it more accurately reflects
the energy available in the fuel to produce work.
    R is a measure of that portion of the renewable fuel molecules
which can be considered to have come from a renewable source. Since R
(that is, RRF and REth) is being combined with
relative energy content in the formula above, the value of R cannot be
based on the weight fraction of the atoms in the molecule which came
from a renewable feedstock (the ``renewable atoms''), but rather must
be based on the energy inherent in that portion of the molecules
comprised of renewable atoms. To identify the renewable atoms within
the molecules that comprise the renewable fuel, we must examine the
chemical process through which the renewable fuel was produced. A
detailed explanation of calculations for R and several examples are
given in a technical memorandum in the docket.\23\
---------------------------------------------------------------------------

    \23\ ``Calculation of equivalence values for renewable fuels
under the RFS program'', memo from David Korotney to EPA Air Docket
OAR-2005-0161.
---------------------------------------------------------------------------

    In the case of ethanol, denaturants are added to preclude the
ethanol's use as food. Denaturants are generally a fossil-fuel based,
gasoline-like hydrocarbon in concentrations of 2-5 volume percent, with
5 percent being the most common historical level. One commenter argued
that the Equivalence Value of ethanol must be specified as 0.95 for
this very reason. However, as described in the NPRM, we believe that
the Equivalence Value for ethanol should be specified as 1.0 despite
the presence of a denaturant. First, as stated above, ethanol is
expected to dominate the renewable fuel pool for at least the next
several years, and it is likely that the authors of the Act recognized
this fact. Thus it seems likely that it was the intent of the authors
of the Act that each physical gallon of denatured ethanol be counted as
one gallon for RFS compliance purposes. Second, the accounting of
ethanol has historically ignored the presence of the denaturant. For
instance, under Internal Revenue Service (IRS) regulations the
denaturant can be counted as ethanol by parties filing claims to the
IRS for the federal excise tax credit. Also, EIA reporting requirements
for ethanol producers allow them to include the denaturant in their
reported volumes. The commenter arguing for the use of an Equivalence
Value of 0.95 for ethanol provided no additional information to counter
these arguments.
    Since we are requiring that denatured ethanol be assigned an
Equivalence Value of 1.0, this must be reflected in the values of
REth and ECEth. We have calculated these values
to be 93.1 percent and 77,550 Btu/gal, respectively. Details of these
calculations can be found in the aforementioned technical memorandum to
the docket. The final equation to be used for calculation of
Equivalence Values is therefore:

EV = (R / 0.931) * (EC / 77,550)

Where:

EV = Equivalence Value for the renewable fuel.

R = Renewable content of the renewable fuel, expressed as a percent,
on an energy basis, of the renewable fuel that comes from a
renewable feedstock.
EC = Energy content of the renewable fuel, in Btu per gallon (lower
heating value).

    For the specific case of biogas which cannot be measured in
volumetric units, we are specifying that 77,550 Btu of biogas will be
considered to be the equivalent of one gallon of renewable fuel.
    The calculation of the Equivalence Value for a particular renewable
fuel can lead to values that deviate only slightly from 1.0, and/or can
have varying degrees of precision depending on the uncertainty in the
value of R or ECRF. In the NPRM we proposed several
simplifications to streamline the application of Equivalence Values in
the context of the RFS program. These included the use of pre-specified
bins, rounding, and the use of an Equivalence Value of 1.0 when the
calculated value was close to 1.0. We received some comments suggesting
that these three simplifications unnecessarily complicated the
determination of Equivalence Values. Based on comments received, we
have determined for the final rule to simplify the application of
Equivalence Values by only requiring the calculated values be rounded
to the first decimal place. Also, based on consideration of comments
received on how such products should be counted, for renewable diesel
produced by processing fats and oils through a refinery hydrotreating
process, we have determined that the default Equivalence Value should
be 1.7 consistent with renewable diesel produced through other
processes. This approach recognizes that hydrotreating produces a
product consistent with our definition of non-ester renewable diesel.
Furthermore, based on comments received, the volume of the final
product is expected to be comparable to the volume of the input
renewable crude. Therefore, the volume of renewable crude will be used
as a surrogate for the volume of the final product. With the exception
of renewable diesel produced through hydroteating fats or oils which is
identical to renewable diesel, none of the specific Equivalence Values
proposed in the NPRM have changed as a result of this simplification.
The final values are shown in the table below.

      Table III.B.4-1.--Equivalence Values for Some Renewable Fuels
------------------------------------------------------------------------
                                                             Equivalence
                                                              value (EV)
------------------------------------------------------------------------
Cellulosic biomass ethanol or waste-derived ethanol \24\...         2.5
Ethanol from corn, starches, or sugar......................         1.0
Biodiesel (mono alkyl ester)...............................         1.5
Non-ester renewable diesel and hydrotreated renewable               1.7
 crudes....................................................
Butanol....................................................         1.3
Renewable crude-based fuels................................         1.0
------------------------------------------------------------------------

    Consistent with the NPRM, the Equivalence Value for renewable
crude-based fuels is 1.0. Although some renewable crude-based fuels
might warrant a higher value based on their energy content, it is also
likely that some of the renewable crude does not end up as a motor
vehicle fuel. Rather than requiring the refiner to document what
portion of the biocrude-based renewable fuel is other than diesel or
gasoline (e.g., jet fuel), we are combining the Equivalence Value of
1.0 with a requirement that the volume of the renewable crude itself
count as the volume of renewable fuel produced for the purposes of
determining the volume block codes that are in the RIN (discussed in
further detail in Section III.D). While this approach may result in
some products such as jet fuel being counted as renewable fuel, we
believe the majority of the products produced will be motor vehicle
fuel because we assume refiners who elect to use biocrudes would do so
to help meet the requirements of this rule. Furthermore, both diesel
and gasoline presently make up about 85 percent of the product slate of
refineries on average. This amount that has been steadily increasing
for over time, and we expect that the percentage will continue to
increase as demand for gasoline and diesel increases. Thus the
designation of an Equivalence Value of 1.0 balances out the potentially
higher energy content of renewable crude-based fuels with the potential
for lower yields of renewable fuel produced as motor vehicle fuel. We
received no comment on this issue and are finalizing it as proposed.
---------------------------------------------------------------------------

    \24\ The 2.5 value is specified by the Energy Act, and is not
based on the EV formula discussed earlier.
---------------------------------------------------------------------------

    Since there are a wide variety of possible renewable fuels that
could qualify under the RFS program, there may be cases in which a
party produces a renewable fuel not shown in Table III.B.4-1. A party
may also produce a renewable fuel listed in the above table, but which
has a different renewable content or energy content than the values
assumed for our calculations. For such cases we have created a
regulatory mechanism through which the producer may submit a petition
to the Agency describing the renewable fuel, its feedstock and
production process, and the calculation of its Equivalence Value. The
Agency will review the petition and approve an appropriate Equivalence
Value based on the information provided. We will publish newly assigned
Equivalence Values in the Federal Register at the same time as the
annual standard is published each November.
    In the NPRM, we also described an additional approach to setting
the Equivalence Value for biodiesel (mono alkyl esters). Since ethanol
derived from waste products such as animal wastes and municipal solid
waste will be assigned an Equivalence Value of 2.5 based on a
requirement in the Act, we pointed out that it might be appropriate to
create a parallel provision for biodiesel made from wastes. Under this
approach, biodiesel made from waste products would have been assigned
an Equivalence Value of 2.5 through 2012. Supporters of 2.5 Equivalence
Value argued that it would place the treatment of waste-derived
biodiesel on the same level as waste-derived ethanol, and that it would
be good Agency policy to encourage and reward parties that turn
materials that would otherwise be wasted into usable motor vehicle
fuel. While some of these arguments may have merit, we nevertheless
believe that it is most appropriate to maintain the general methodology
applicable to renewable fuels at this time and reserve the 2.5:1
valuation for just the fuel specified by Congress. Therefore, we have
not finalized a 2.5 Equivalence Value for waste-derived biodiesel.
    For the specific case of ETBE, we have chosen for this final rule
to eliminate a uniquely determined Equivalence Value. As described in
Section III.D.2.b, ETBE is generally made from ethanol to which RINs
will have already been assigned. An ETBE producer, therefore, would
need only assign the RINs received with the ethanol to the ETBE made
from that ethanol. In this case, there will be no need to generate new
RINs, and therefore no need for a separate Equivalence Value.
    Except for cellulosic biomass ethanol and waste-derived ethanol,
the Equivalence Values shown in Table III.B.4-1, or any others approved
through the petition process, will be applicable for all years.
However, beginning in 2013, the 2.5 to 1 ratio no longer applies for
cellulosic biomass

ethanol. The Act is unclear about whether the 2.5 to 1 ratio for waste-
derived ethanol will apply after 2012, though it might be appropriate
to treat cellulosic biomass ethanol and waste-derived ethanol in a
consistent manner. Nevertheless, in the subsequent rulemaking mentioned
above, we will address this issue explicitly. In today's final rule we
are only specifying the ratio for cellulosic biomass and waste-derived
ethanol prior to 2013.
c. Lifecycle Analyses as the Basis for Equivalence Values
    In the NPRM we also described an alternative approach in which
Equivalence Values for renewable fuels would be based on lifecycle
analyses. We described both the merits and challenges associated with
such an approach and requested comment. Based on the comments received
we continue to believe that lifecycle analyses could provide a means of
reflecting the relative benefits of one renewable fuel in comparison to
another. However, we are not, in this action, establishing Equivalence
Values on a lifecycle basis. Rather, we intend to continue evaluating
and updating the tools and assumptions associated with lifecycle
analyses in a collaborative effort with stakeholders. This rulemaking
makes no determination and should not be interpreted to make any
determination regarding whether EPA has the legal authority under
section 1501 of the Energy Act, as incorporated in section 211(o) of
the Clean Air Act, to use lifecycle analysis in establishing
Equivalence Values in general or Equivalence Values specifically
related to greenhouse gas or carbon dioxide emissions. This section
describes some of the comments we received on the use of lifecycle
analyses and our responses.
    Lifecycle analyses involve an examination of fossil fuel used, and
emissions generated, at all stages of a renewable fuel's life. A
typical lifecycle analysis examines production of the feedstock, its
transport to a conversion facility, the conversion of the feedstock
into renewable motor vehicle fuel, and the transport of the renewable
fuel to the consumer. At each stage, every activity that consumes
fossil fuels or results in emissions is quantified, and these energy
consumption and emission estimates are then summed over all stages. By
accounting for every activity associated with renewable fuels over
their entire life, we can assess renewable fuels in terms of not just
their impact within the transportation sector, but across all sectors
and thus for the nation as a whole. In this way, lifecycle analyses
provide a more complete picture of the potential impacts of different
fuels or different fuel sources. While the use of energy content to
establish Equivalence Values is an improvement over a simple gallon-
for-gallon approach, a lifecycle basis would provide a further level of
sophistication in assessing the net energy input and output of fuels
and the emissions associated with the use of different fuels.
    Supporters of the use of lifecycle analyses for setting the
Equivalence Values of different renewable fuels pointed to several
advantages of this approach. First, doing so could create an incentive
for obligated parties to choose renewable fuels having a greater
ability to reduce fossil fuel use or resulting emissions, since such
renewable fuels would have higher Equivalence Values and thus greater
value in terms of compliance with the RFS requirements. The
preferential demand for renewable fuels having higher Equivalence
Values could in turn spur additional growth in production of these
renewable fuels. Second, using lifecycle analyses as the basis for
Equivalence Values could orient the RFS program more explicitly towards
reducing petroleum use, fossil fuel use or emissions.
    However, the use of lifecycle analyses to establish the Equivalence
Values for different renewable fuels also raises a number of issues,
generally acknowledged by supporters of the use of lifecycle analyses.
For instance, lifecycle analyses can be conducted using several
different metrics, including total fossil fuel consumed, petroleum
energy consumed, regulated pollutant emissions (e.g., VOC,
NOX, PM), carbon dioxide emissions, or greenhouse gas
emissions. Each metric would result in a different set of Equivalence
Values. At the present time there is no consensus on which metric would
be most appropriate for this purpose or the purposes of the Act.
    There is also no consensus on the approach to lifecycle analyses
themselves. Although we have chosen to base our lifecycle analyses on
Argonne National Laboratory's GREET model for the reasons described in
Section IX, there are a variety of other lifecycle models and analyses
available. The choice of model inputs and assumptions all have a
bearing on the results of lifecycle analyses, and many of these
assumptions remain the subject of debate among researchers. Lifecycle
analyses must also contend with the fact that the inputs and
assumptions generally represent industry-wide averages even though
energy consumed and emissions generated vary widely from one facility
or process to another.
    There currently exists no organized, comprehensive dialogue among
stakeholders about the appropriate tools and assumptions behind any
lifecycle analyses. We will be initiating more comprehensive
discussions about lifecycle analyses with stakeholders in the near
future.
    Another issue related to using lifecycle analyses as the basis for
Equivalence Values pertains to the ultimate impact that the RFS program
would have on petroleum use, fossil fuel use, regulated pollutant
emissions, and/or emissions of GHGs. With a fixed volume of renewable
fuel required under the RFS program, any renewable fuel with an
Equivalence Value greater than 1.0 would necessarily mean that fewer
actual gallons would be needed to meet the RFS standard. Thus, the
advantage per gallon may be offset with fewer overall gallons,
resulting in no overall additional benefit under the chosen metric for
using fuels with higher Equivalence Values unless the RFS standard was
simultaneously adjusted by Congress.
    Based on comments received in response to our NPRM, we continue to
believe that the current state of scientific inquiry surrounding
lifecycle analyses is not sufficiently robust to warrant its use to set
Equivalence Values in this final rule. Since renewable fuel use is
expected to far exceed the standards being finalized today, a higher
equivalence value for those renewables with greater lifecycle benefits
will likely do little to stimulate their use. However, if in the future
the RFS standard more closely matches renewable demand, this could be
important. We are committed to continuing our investigations into
lifecycle analyses.

C. What Gasoline Is Used To Calculate the Renewable Fuel Obligation and
Who Is Required To Meet the Obligation?

1. What Gasoline Is Used To Calculate the Volume of Renewable Fuel
Required To Meet a Party's Obligation?
    The Act requires EPA to promulgate regulations designed to ensure
that ``gasoline sold or introduced into commerce in the United States
(except in noncontiguous states or territories)'' contains on an annual
average basis, the applicable aggregate volumes of renewable fuels as
prescribed in the Act.\25\ To implement this provision, today's final
rule provides that the volume of gasoline used to determined the
renewable fuel obligation must include all finished gasoline (RFG and

conventional) produced or imported for use in the contiguous United
States during the annual averaging period and all unfinished gasoline
that becomes finished gasoline upon the addition of oxygenate blended
downstream from the refinery or importer. This would include 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, is not
included in the volume used to determine the renewable fuel obligation,
except where the blendstock is combined with other blendstock or
finished 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 is
included in the volume used to determine the renewable fuels obligation
for the blender. Where a blendstock is added to finished gasoline, only
the volume of the blendstock is included, since the finished gasoline
would have been included in the compliance determinations of the
refiner or importer of the gasoline.
---------------------------------------------------------------------------

    \25\ CAA Section 211(o)(2)(A)(i), as added by Section 1501(a) of
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Gasoline produced or imported for use in a noncontiguous state or
U.S. territory \26\ is not included in the volume used to determine the
renewable fuel obligation (unless the noncontiguous state or territory
has opted-in to the RFS program), nor is gasoline, RBOB or CBOB
exported for use outside the United States.
---------------------------------------------------------------------------

    \26\ The noncontiguous states are Alaska and Hawaii. The
territories are the Commonwealth of Puerto Rico, the U.S. Virgin
Islands, Guam, American Samoa, and the Commonwealth of the Northern
Marianas.
---------------------------------------------------------------------------

    For purposes of this preamble, the various gasoline products (as
described above) that are included in the volume of gasoline used to
determine the renewable fuel obligation are collectively called
``gasoline.''
    The final rule excludes the volume of renewable fuels contained in
gasoline from the volume of gasoline used to determine the renewable
fuels obligation. In implementing the Act's renewable fuels
requirement, our primary goal was to design a program that is simple,
flexible and enforceable. If the program were to include renewable
fuels in the volume of gasoline used to determine the renewable fuel
obligation, then every blender that blends ethanol downstream from the
refinery or importer would be subject to the renewable fuel obligation
for the volume of ethanol that they blend. There are currently
approximately 1,200 such ethanol blenders. Of these blenders, only
those who blend ethanol into RBOB are regulated parties under current
fuels regulations. Designating all of these ethanol blenders as
obligated parties under the RFS program would greatly expand the number
of regulated parties and increase the complexity of the RFS program
beyond that which is necessary to carry out the renewable fuels mandate
under the Act.
    The Act provides that the renewable fuel obligation shall be
``applicable to refiners, blenders, and importers, as appropriate.''
\27\ For the reasons discussed above, we believe it is appropriate to
exclude downstream renewable fuel blenders from the group of parties
subject to the renewable fuel obligation and to exclude renewable fuels
from the volume of gasoline used to determine the renewable fuel
obligation. 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 downstream from the refinery or importer would be excluded
from the volume of gasoline used to determine the obligation. Any non-
renewable fuel added downstream, however, would be included in the
volume of gasoline used to determine the obligation. This approach has
no impact on the total volume of renewable fuels required (which is
specified in the Act and must be met regardless of the approach taken
here), but merely on the number of obligated parties. As discussed
earlier, this volume of renewable fuel is likewise excluded from the
calculation performed each year by EPA to determine the applicable
percentage.
---------------------------------------------------------------------------

    \27\ CAA Section 211(o)(3)(B), as added by Section 1501(a) of
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    The NPRM was unclear with regard to whether obligated parties are
to determine their renewable fuel obligation based on the gasoline
production of all of their facilities in the aggregate, or each
facility individually. As discussed above, EPA has discretion under the
Energy Act to determine the renewable fuels obligation applicable to
parties, ``as appropriate.'' We believe that allowing obligated parties
to determine their obligation based on either their facilities in the
aggregate or individually is appropriate, since allowing this
flexibility will not affect compliance with the RFS. Although some
commenters expressed concern that obligated parties with multiple
facilities could gain an economic advantage over obligated parties with
only a single facility if aggregate compliance is allowed, we do not
believe that this will be the case given the unrestricted trading
allowed under our program. We also believe that clarification in the
regulations regarding the basis on which the obligation may be
determined is a necessary and logical outgrowth of the proposal. As a
result, the regulations have been modified in the final rule to clarify
that the renewable fuels obligation may be determined based on the
gasoline production of all of an obligated party's facilities in the
aggregate, or each facility individually.
    We received comment that EPA should clarify when obligated parties
must include imported gasoline that is used as ``gasoline treated as
blendstock'', or GTAB, in the volume of gasoline used to determine the
party's renewable fuel obligation. As stated in the preamble to the
proposed rule, GTAB is to be treated as a blendstock with regard to the
RFS rule. Where the GTAB is blended with other blendstock (other than
only renewable fuel) to produce gasoline, the total volume of the
gasoline blend, including the GTAB, is 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 is
included in the volume of gasoline used to determine the renewable fuel
obligation (since the finished gasoline will already be included in the
RFS calculations of the refiner of that gasoline). For purposes of
compliance demonstrations, the RFS rule treats GTAB in a manner that is
consistent with the reformulated gasoline (RFG) and conventional
gasoline (CG) regulations. Under the RFG/CG regulations, importers who
designate imported gasoline as GTAB must be registered with EPA as both
an importer and a refiner. The importer submits separate compliance
reports to EPA, one in its capacity as an importer, and one in its
capacity as a refiner. The GTAB is blended by the importer and included
in the importer's compliance calculations in its capacity as a refiner
of the GTAB, and is excluded from the importer's compliance
calculations in its capacity as an importer. The RFS rule treats GTAB
in a similar manner; i.e., the importer includes the GTAB in the volume
of gasoline used to determine the renewable fuel obligation of the
importer in its capacity as a refiner of the GTAB, and excludes the
GTAB in the volume of gasoline used to

determine the renewable fuel obligation of the importer in its capacity
as an importer. The regulations have been clarified with regard to how
GTAB is used to determine the GTAB importer's renewable fuels
obligation.
    We received comment that EPA should clarify that the terms RBOB and
CBOB include ``blendstocks for oxygenate blending'' that are designed
to comply with state fuels requirements, such as CARBOB (California),
AZRBOB (Arizona), and LVBOB (Las Vegas). As discussed in Section
III.C.1, all gasoline, and all unfinished gasoline that becomes
finished gasoline upon the addition of oxygenate, that is produced or
imported for use in the contiguous United States is included in the
volume of gasoline used to determine an obligated party's renewable
fuels obligation. As such, any finished gasoline, or unfinished
gasoline that becomes finished gasoline upon the addition of oxygenate,
that is produced or imported to comply with state fuels programs must
also be included in the volume of gasoline used to determine an
obligated party's renewable fuels obligation. The regulations have been
clarified in this regard.
2. Who Is Required To Meet the Renewable Fuels Obligation?
    Under the final rule, any person who meets the definition of
refiner under the fuels regulations, which includes any blender who
produces gasoline by combining blendstocks or blending blendstocks into
finished gasoline, is subject to the renewable fuels obligation. Any
person who brings gasoline into the 48 contiguous states from a foreign
country or from an area that has not opted-in to the RFS program, or
brings gasoline from a foreign country or an area that has not opted-in
to the RFS program into an area that has opted-in to the RFS program,
is considered an importer under the RFS program and is subject to the
renewable fuels obligation. As noted above, a blender who only blends
renewable fuels downstream from the refinery or importer is not subject
to the renewable fuel obligation. Any person that is required to meet
the renewable fuels obligation is called an ``obligated party.'' We
generally refer to all of the obligated parties as refiners and
importers, since the covered blenders are all refiners under the
regulations.
    A refiner or importer located in a noncontiguous state or U.S.
territory is not subject to the renewable fuel obligation and thus is
not an obligated party (unless the noncontiguous state or territory
opts-in to the RFS program). A party located within the contiguous 48
states is an obligated party if it ``imports'' into the 48 states any
gasoline produced or imported by a refiner or importer located in a
noncontiguous state or territory.
    We received comment that EPA should clarify how the RFS rule
applies to transmix processors and blenders. Transmix processors and
blenders are treated like any other blenders under the RFS rule.
Transmix processors are parties that separate the gasoline portion of
the transmix from the transmix and either sell the gasoline portion as
finished gasoline or blend it with other components to produce
gasoline. Transmix processors exclude the gasoline portion of the
transmix from the volume that is used to determine the party's
renewable fuel obligation, since the gasoline portion of the transmix
would have been included in the volume used to determine the renewable
fuels obligation of the refiner or importer of the gasoline. In
calculating the volume used to determine its renewable fuel obligation,
the transmix processor would include any blendstocks (other than
renewable fuels) that are added to the gasoline separated from the
transmix. Where the transmix processor combines the gasoline portion of
the transmix with purchased finished gasoline, both the gasoline
portion of the transmix and the finished gasoline would be excluded,
since the finished gasoline would have been included in the volume used
to determine the renewable fuels obligation of the refiner or importer
of the finished gasoline. Transmix blenders are parties that blend
small amounts of unprocessed transmix into gasoline. Transmix blenders
are not obligated parties if they only blend transmix into finished
gasoline. If the transmix blender adds blendstocks to the transmix, the
transmix blender would be an obligated party with regard to the volume
of blendstocks added. The regulations have been clarified with regard
to how the RFS rule applies to transmix processors and blenders.
3. What Exemptions Are Available Under the RFS Program?
a. Small Refinery and Small Refiner Exemption
    The Act provides an exemption from the RFS standard for small
refineries during the first five years of the program. The Act defines
small refinery as ``a refinery for which the average aggregate daily
crude oil throughput for a calendar year (as determined by dividing the
aggregate throughput for the calendar year by the number of days in the
calendar year) does not exceed 75,000 barrels.'' \28\ Thus, any
gasoline produced at a refinery that qualifies as a small refinery
under this definition is not counted in determining the renewable fuel
obligation of a refiner until January 1, 2011. Where a refiner complies
with the renewable fuel obligation on an aggregate basis for multiple
refineries, the refiner may exclude from its compliance calculations
gasoline produced at any refinery that qualifies as a small refinery
under the RFS program. This exemption applies to any refinery that
meets the definition of small refinery stated above regardless of the
size of the refining company that owns the refinery. Based on
information currently available to us we expect 42 small refineries to
qualify for this exemption. Beginning in 2011, small refineries will be
required to meet the same renewable fuel obligation as all other
refineries, unless their exemption is extended pursuant to Sec.
80.1141(e).
---------------------------------------------------------------------------

    \28\ CAA Section 211(o)(a)(9), as added by Section 1501(a) of
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    In addition to small refineries as defined in the Act, we proposed
to extend this relief to refiners who, during 2004: (1) Produced
gasoline at a refinery by processing crude oil through refinery
processing units; (2) employed an average of no more than 1,500 people,
including all employees of the small refiner, any parent company and
its subsidiary companies; and (3) had a total average crude oil
processing capability for all of the small refiner's refineries of
155,000 barrels per calendar day (bpcd). These size criteria were
established in prior rulemakings and were the result of our analyses of
small refiner impacts. Based on information currently available to us,
we believe that there are only three gasoline refineries owned by small
refiners that meet these criteria and that currently exceed the 75,000
bpcd crude oil processing capability defined by the Act.
    We received comments supporting the proposed extension of the small
refinery exemption to small refiners, and we also received comments
opposing the proposed provision. Commenters that supported the
provision generally stated that they believe that a small refiner
exemption is necessary as those entities (i.e., companies) that would
qualify as small refiners are generally at an economic disadvantage due
to their company size--whereas the Act only recognizes facilities,
based on the size of each location. These commenters also stated that
they have concerns with the cost and the availability of credits under
this program, and believe that provisions for small refiners are

necessary to help mitigate any significant adverse economic impact on
these entities. Commenters that opposed the provision stated that they
believe that EPA exceeded its discretionary authority, that there
appears to be no basis on which the Agency can legitimately expand this
statutory exemption to add small refiners, and that Congress ``clearly
did not intend that the exemption be broadened to also include small
refiners.'' One commenter also stated that it does not believe that
small refiner provisions are necessary because this rule does not
require costly capital investments like previous fuel regulations.
    As stated in the proposal, we believe that we have discretion in
determining an appropriate lead-time for the start-up of this program,
as well as discretion to determine the regulated refiners, blenders and
importers, ``as appropriate.'' We continue to believe that some
refiners, due to their size, generally face greater challenges compared
to larger refiners. The Small Business Regulatory Enforcement Fairness
Act (SBREFA) also recognizes this and requires agencies, during
promulgation of new standards, to assess the potential impacts on small
businesses (as defined by the Small Business Administration (SBA) at 13
CFR 121.201). For those instances where the Agency cannot certify that
a rule will not have a significant economic impact on a substantial
number of small entities, we are required to convene a SBREFA Panel. A
SBREFA Panel process--which generally takes at least six months to
complete--entails performing outreach with entities that meet the
definition of a small business to develop ways to mitigate potential
adverse economic impacts on small entities, in consultation with SBA
and the Office of Management and Budget (OMB).
    ``Small refiners'' have historically been recognized in EPA fuel
regulations as those refiners who employ no more than 1,500 employees
and have an average crude oil capacity of 155,000 bpcd. These refiners
generally have greater difficulty in raising and securing capital for
investing in capital improvements and in competing for engineering
resources and projects. This rulemaking does not require that refiners
make capital improvements, however there are still significant costs
associated with meeting the standard. While we were not required to
assess the impacts on small businesses under the Energy Policy Act, we
are required to do so under SBREFA. Based on our own analysis and
outreach with small refiners, our assessment is that this rule will not
impose a significant adverse economic impact on small refiners if they
are given the small refinery exemption. Further, as noted above, we
believe that no more than three additional refiners that do not meet
the Energy Policy Act's definition of a small refinery will qualify as
small refiners for this rule. Therefore, we are finalizing the proposed
provision that the small refinery exemption will be provided to
qualified small refiners. This exemption does not mean that less
renewable fuel will be used than is required in the Energy Policy Act;
rather, it just means that small refiners will not be obligated to
ensure that those volumes are attained during the period of their
exemption.
    We also proposed to allow foreign refiners to apply for a small
refinery or small refiner exemption under the RFS program. We requested
comment on the provision and related aspects, and we received some
comments in which commenters stated that they believe that there is no
reason to extend the small refinery exemption to these refiners. One
commenter even stated that it believes that such an allowance would be
unlawful. We proposed this provision for consistency with prior
gasoline-related fuel programs (anti-dumping, MSAT, and gasoline
sulfur) which allowed foreign refiners to receive such exemptions, and
we are finalizing the provision in this action. Under this provision,
foreign small refiners and foreign small refineries can apply for an
exemption from the RFS standards such that importers would not count
the small refiner or small refinery gasoline volumes towards the
importer's renewable volume obligation. The Energy Policy Act does not
prohibit EPA from granting this avenue of relief to foreign entities,
and EPA believes it is consistent with the spirit of international
trade agreements to provide it.
    In the proposal we stated that applications for a small refinery
exemption must be received by EPA by September 1, 2007 for the
exemption to be effective in 2007 and subsequent calendar years. We
proposed that the application should include documentation that the
small refinery's average aggregate daily crude oil throughput for
calendar year 2004 did not exceed 75,000 barrels; and that eligibility
would be based on 2004 data (rather than 2005). Further, we proposed
that the small refinery exemption would be effective 60 days after
receipt of the application by EPA unless EPA notifies the applicant
that the application was not approved or that additional documentation
is required. We received comments on this provision in which commenters
stated that requiring small refinery applications was inconsistent with
the language set out in the Act. The commenters stated that small
refineries should not be obligated parties in 2007 even if they do not
submit a small refinery application by September 1, 2007. We agree with
these statements, and believe that the Energy Policy Act did in fact
intend to provide this exemption without the need for small refineries
to submit applications. However, in order to ensure that this provision
is not being misused, we believe that it is necessary for refiners to
verify that their refineries meet the definition set out in the Act.
Therefore, we are finalizing that the small refinery exemption will
become active immediately upon the effective date of the rule. Refiners
will only be required to send a letter to EPA verifying their status as
a small refinery. We did not receive any comments on our proposal to
base eligibility on 2004 data, nor did we receive comments on whether a
multiple-year average should be used. We believe that eligibility
should be based on 2004 data rather than on 2005 data, since it was the
first full year prior to passage of the Energy Act. In addition, some
refineries' production may have been affected by Hurricanes Katrina and
Rita in 2005. We are thus finalizing our proposed approach to base
eligibility on 2004 data.
    As discussed above, we proposed that refiners that do not qualify
for a small refinery exemption under the 75,000 bpcd criteria, but
nevertheless meet the criteria of a small refiner may apply for small
refiner status under the RFS rule. We proposed that the applications
must be received by EPA by September 1, 2007 for the exemption to be
effective in 2007 and subsequent calendar years (similar to the small
refinery exemption). We also proposed that small refiner status would
be determined based on documentation submitted in the application which
demonstrates that the refiner met the criteria for small refiner status
during the calendar year 2004 and that EPA would notify a refiner of
approval or disapproval of small refiner status by letter.
    The final rule provides that qualified small refiners receiving the
small refinery exemption will also receive the exemption immediately
upon the effective date of the rule. These refiners must also submit a
verification letter showing that they meet the small refiner criteria.
This letter will be similar to the small refiner applications required
under other EPA fuel programs (and must contain all the required
elements

specified in the regulations at Sec.  80.1142), except the letter will
not be due prior to the program. Small refiner status verification
letters for this rule that are later found to contain false or
inaccurate information will be void as of the effective date of these
regulations. Unlike the case for small refineries, small refiners who
subsequently do not meet all of the criteria for small refiner status
(i.e., cease producing gasoline by processing crude oil, employ more
than 1,500 people or exceed the 155,000 bpcd crude oil capacity limit)
as a result of a merger with or acquisition of or by another entity are
disqualified as small refiners, except in the case of a merger between
two previously approved small refiners. As in other EPA programs, where
such disqualification occurs, the refiner must notify EPA in writing no
later than 20 days following the disqualifying event.
    The Act provides that the Secretary of Energy must conduct a study
for EPA to determine whether compliance with the renewable fuels
requirement would impose a disproportionate economic hardship on small
refineries. If the study finds that compliance with the renewable fuels
requirements would impose a disproportionate economic hardship on a
particular small refinery, EPA is required to extend the small
refinery's exemption for a period of not less than two additional years
(i.e., to 2013). The Act also provides that a refiner with a small
refinery may at any time petition EPA for an extension of the exemption
for the reason of disproportionate economic hardship. In accordance
with these provisions of the Act, we are finalizing the provision that
refiners with small refineries may petition EPA for an extension of the
small refinery exemption. As provided in the Act, EPA will act on the
petition not later than 90 days after the date of receipt of the
petition. Today's regulations do not provide a comparable opportunity
for an extension of the small refinery exemption for small refiners.
Therefore, all parties temporarily exempted from the RFS program on the
basis of qualifying as a small refiner, rather than a small refinery,
must comply with the program beginning January 1, 2011 (unless they
waive their exemption prior to this date).
    During the initial exemption period for small refineries and small
refiners and any extended exemption periods for small refineries, the
gasoline produced by exempted small refineries and refineries owned by
approved small refiners will not be subject to the renewable fuel
standard.
    We proposed that the automatic exemption to 2011 and any small
refinery extended exemptions may be waived upon notification to EPA;
and we are finalizing this provision. Gasoline produced at a refinery
which waives its exemption will be included in the RFS program and will
be included in the gasoline used to determine the refiner's renewable
fuel obligation. If a refiner waives the exemption for its small
refinery or its exemption as a small refiner, the refiner will be able
to separate and transfer RINs like any other obligated party. If a
refiner does not waive the exemption, the refiner could still separate
and transfer RINs, but only for the renewable fuel that the refiner
itself blends into gasoline (i.e. the refinery operates as an oxygenate
blender facility). Thus, exempt small refineries and small refiners who
blend ethanol can separate RINs from batches without opting in to the
program in the same manner that an oxygenate blender is allowed to do.
b. General Hardship Exemption
    In recent rulemakings, we have included a general hardship
exemption for parties that are able to demonstrate severe economic
hardship in complying with the standard. We proposed not to include
provisions for a general hardship exemption in the RFS program. Unlike
most other fuels programs, the RFS program includes inherent
flexibility since compliance with the renewable fuels standard is based
on a nationwide trading program, without any per gallon requirements,
and without any requirement that the refiner or importer produce the
renewable fuel. By purchasing RINs, obligated parties will be able to
fulfill their renewable fuel obligation without having to make capital
investments that may otherwise be necessary in order to blend renewable
fuels into gasoline. We believe that sufficient RINs will be available
and at reasonable prices, given that EIA projects that far greater
renewable fuels will be used than required. Given the flexibility
provided in the RIN trading program, including the provisions for
deficit carry-over, and the fact that the standard is proportional to
the volume of gasoline actually produced or imported, we continue to
believe a general hardship exemption is not warranted. As a result, the
final rule does not contain provisions for a general hardship
exemption.
c. Temporary Hardship Exemption Based on Unforeseen Circumstances
    In recent rulemakings, we have included a temporary hardship
exemption based on unforeseen circumstances. We proposed not to include
such an exemption in the RFS program. The need for such an exemption
would primarily be based on the inability to comply with the renewable
fuels standard due to a natural disaster, such as a hurricane. However,
in the event of a natural disaster, we believe it is likely that the
volume of gasoline produced by an obligated party would also drop,
which would result in a reduction in the renewable fuel requirement.
We, therefore, reasoned in the NPRM that unforeseen circumstances, such
as a hurricane or other natural disaster, would not result in a party's
inability to obtain sufficient RINs to comply with the applicable
renewable fuels standard.
    We received several comments regarding the inclusion of a temporary
hardship exemption based on unforeseen circumstances. One commenter
believes it would be of value to have a mechanism for selectively
waiving or modifying the RFS downward on a temporary basis in the event
of unforeseen circumstances such as significant drought affecting
potential crop production. The commenter believes that crop shortages
could have an impact on a national level, or a major disaster may
impact logistics of renewable fuel distribution regionally,
necessitating a more rapid response from EPA than is provided in the
Energy Act. Another commenter believes that a temporary hardship
exemption based on unforeseen circumstances should be included in the
rule since it is impossible to predict how the RFS program will impact
small refiners. Another commenter believes that, given the variety of
potentially challenging unforeseen events during the last several
years, it is not inconceivable that man-made or natural circumstances
could adversely impact the RFS program. A natural disaster in the
agricultural section, for example, may make it difficult to meet the
renewable fuels mandate which, in turn, could drive the price of RINs
high enough to disrupt the gasoline market. The commenter believes that
a mechanism built into the program from the outset would provide a more
flexible and less disruptive way to address unforeseen circumstances
than the more time-consuming waiver process provided in the Energy Act.
    Under other EPA fuels programs, compliance is based on a
demonstration that the fuel meets certain component or emissions
standards. Unforeseen circumstances, such as a natural disaster, may
affect an individual refiner's or importer's ability to produce or
import fuel that complies with the

standards. As a result, we have included in other fuels programs
provisions for a temporary hardship exemption from the standards in the
event of an unforeseen natural disaster that affects a party's ability
to produce gasoline that complies with the standards. Unlike most other
fuels programs, compliance under the RFS program is based on a
demonstration that a party has fulfilled its individual renewable fuels
obligation on an annual basis, as compared to meeting specific gasoline
content requirements. The renewable fuels obligation can be met through
the use of purchased RINs, and there is a deficit carry forward
provision allowing compliance to be shown over more than one year. In
the event of a natural disaster, the volume of gasoline produced by an
obligated party is also likely to drop, which would result in a
reduction in the party's renewable fuel obligation. As a result, we
believe that an individual party would be able to meet its renewable
fuel obligation even in the event of a natural disaster that affects
the party's refinery or blending facility. Therefore, unlike other
fuels programs, we do not believe there is a need to include a
temporary hardship exemption in the RFS rule to address an individual
party's inability to comply with its renewable fuels obligation due to
unforeseen circumstances.
    Most of the concerns raised by the commenters relate to problems
that would have a more regional or national effect, as compared to
affecting one or a few individuals. In the event that unforeseen
circumstances do occur which result in a shortage of renewable fuel and
available RINs, we believe that Congress provided an adequate mechanism
for addressing such situations in the Energy Act.\29\ The Energy Act
provides that on petition by one or more States, EPA, in consultation
with the Departments of Agriculture and Energy, may waive the required
aggregate renewable fuels volume obligation in whole or in part upon a
sufficient showing of economic or environmental harm, or inadequate
supply. As a result, we believe that a renewable fuel supply problem
that affects all parties can be addressed using this statutory
provision. We have carefully considered the comments; however, we do
not believe that the comments provide a compelling rationale for
providing a temporary hardship exemption from the RFS obligation based
on unusual circumstances that goes beyond the provisions that Congress
included in the Energy Act. As a result, the final rule does not
contain provisions for a temporary hardship exemption based on
unforeseen circumstances.
---------------------------------------------------------------------------

    \29\ CAA section 211(o)(7), as added by Section 1501(a) of the
Energy Policy Act of 2005.
---------------------------------------------------------------------------

4. What Are the Opt-in and State Waiver Provisions Under the RFS
Program?
a. Opt-in Provisions for Noncontiguous States and Territories
    The Act provides that, upon the petition of a noncontiguous state
or U.S. territory, EPA may apply the renewable fuels requirements to
gasoline produced in or imported into that noncontiguous state or U.S.
territory at the same time as, or any time after the promulgation of
regulations establishing the RFS program.\30\ In granting such a
petition, EPA may issue or revise the RFS regulations, establish
applicable volume percentages, provide for generation of credits, and
take other actions as necessary to allow for the application of the RFS
program in a noncontiguous state or territory. We believe that approval
of the petition does not require a showing other than a request by the
Governor of the State or the equivalent official of a Territory to be
included in the program.
---------------------------------------------------------------------------

    \30\ CAA Section 211(o)(2)(A)(ii), as added by Section 1501(a)
of the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Today's final rule will implement this provision of the Act by
providing a process whereby the governor of a noncontiguous state or
territory may petition EPA to have the state or territory included in
the RFS program. The petition must be received by EPA on or before
November 1 for the noncontiguous state or territory to be included in
the RFS program in the next calendar year. A noncontiguous state or
territory for which a petition is received after November 1 would not
be included in the RFS program in the next calendar year, but would be
included in the RFS program in the subsequent year. For example, if EPA
receives a petition on September 1, 2007, the noncontiguous state or
territory would be included in the RFS program beginning on January 1,
2008. If EPA receives a petition on December 1, 2007, the noncontiguous
state or territory would be included in the RFS program beginning
January 1, 2009. We believe that requiring petitions to be received by
November 1 is necessary to allow EPA time to make any adjustments in
the applicable standard. The method for calculating the renewable fuels
standard to reflect the addition of a state or territory that has opted
into the RFS program is discussed in Section III.A. Because today's
regulations make EPA approval of an opt-in petition automatic if it is
signed by the appropriate authority and properly delivered to EPA, EPA
does not envision providing an opportunity to comment on an opt-in
request, although we will provide notice in the publication of the
standard for the following year.
    We received several comments regarding when a noncontiguous state
or territory should be able to opt-in to the RFS program. One commenter
supported the approach in this final rule that EPA use the EIA Short-
term Energy Outlook published each October to assist in determining the
percentage standard and therefore a state can only opt-in beginning
with the first full compliance period of 2008. Another commenter
believed we should include a provision to allow noncontiguous states or
territories to opt-in to the first compliance period which starts
September 1, 2007. While we see the merits of allowing a noncontiguous
state or territory to opt-in to the first compliance period, we intend
to maintain the current approach and allow noncontiguous states and
territories to opt-in beginning with the 2008 compliance year. The
statute clearly states that the program may apply to noncontiguous
states and territories (that have petitioned EPA) at any time after
these regulations have been promulgated. Given the short period of time
between publication of the final rule and the effective date of the
program, the need for a state and regulated parties to discuss opting-
in with knowledge of the final version of the rule, and the requirement
for EPA to notify obligated parties with sufficient lead time to any
change in the standard, EPA believes 2008 is the earliest practical
date for an opt-in to be effective. In addition, EPA notes that none of
the noncontiguous states or territories indicated a strong interest in
opting-in for the remainder of the 2007 compliance period.
    Where a noncontiguous state or territory opts-in to the RFS
program, producers and importers of gasoline for that state or
territory will be obligated parties subject to the renewable fuel
requirements. All refiners and importers who produce or import gasoline
for use in a state or territory that has opted-in to the RFS program
will be required to comply with the renewable fuel standard and will be
able to separate RINs from batches of renewable fuels in the same
manner as other obligated parties.
    Once a petition to opt-in to the RFS program is approved by EPA,
the state or territory would remain in the RFS program and be treated
as any of the 48 contiguous states. We received a comment asserting
that once a state or

territory opts-in, they should be required to remain in the program for
at least 5 years. As stated earlier, EPA will recognize a state or
territory that opts-in to the program as identical to any of the 48
states. The current regulations do not allow a state to opt-out and the
only form of relief from the program is a waiver, in whole or in part,
of the national renewable fuel volume requirement. Noncontiguous states
and territories should be aware of the obligations of the program and
should only choose to opt-in if they expect to meet those obligations
for the indefinite future. If in the future a state believes EPA should
change its regulations and allow an opt-out the state could petition
EPA to change the regulations. As in other situations where a party
petitions EPA to revise its regulations, EPA would be in a position at
that point to consider the concerns raised by the state as well as
other interested stakeholder and to determine whether it would be
appropriate to revise the regulations.
b. State Waiver Provisions
    The Energy Act provides that EPA, in consultation with the U.S.
Department of Agriculture (USDA) and the Department of Energy (DOE),
may waive the renewable fuels requirements in whole or in part upon a
petition by one or more states by reducing the national quantity of
renewable fuel required under the Act.\31\ The Act also outlines the
basic requirements for such a waiver, such as a demonstration that
implementation of the renewable fuels requirements would severely harm
the economy or environment of a state, a region, or the United States
or that there is an inadequate domestic supply of renewable fuel.
---------------------------------------------------------------------------

    \31\ CAA Section 211(o)(7), as added by Section 1501(a) of the
Energy Policy Act of 2005.
---------------------------------------------------------------------------

    If EPA, after public notice and opportunity for comment, approves a
state's petition for a waiver of the RFS program, the Act stipulates
that the national quantity of renewable fuel required (Table I.B-1) may
be reduced in whole or in part. This reduction could reduce the
percentage standard applicable to all obligated parties. However, there
is no provision in the Act that would permit EPA to reduce or eliminate
any obligations under the RFS program specifically for parties located
within the state that petitioned for the waiver. Thus all refiners,
importers, and blenders located in the state would still be obligated
parties if they produce gasoline. In addition, an approval of a state's
petition for a waiver may not have any impact on renewable fuel use in
that state since it would not be a prohibition on the sale or
consumption of renewable fuels in that state. In fact, the Act
prohibits the regulations from restricting the geographic areas in
which renewable fuels may be used.\32\ Renewable fuel use in the state
in question would thus continue to be driven by natural market forces
and, perhaps if the economics of ethanol blending were less favorable
than today, the nationally-applicable renewable fuel standard.
---------------------------------------------------------------------------

    \32\ CAA Section 211(o)(2)(iii), as added by Section 1501(a) of
the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Given that state petitions for a waiver of the RFS program appear
unlikely to affect renewable fuel use in that state, we have not
finalized regulations providing more specificity regarding the criteria
for a waiver or the ramifications of Agency approval of such a waiver
in terms of the level or applicability of the standard. However, states
can still submit petitions to the Agency for a waiver of the RFS
requirements under the provision in the Energy Act and such petitions
will be addressed by EPA on a case-by-case basis.
    We received several comments objecting to the decision to not
propose regulations detailing the waiver process and our rationale for
not doing so. One commenter stated that nothing in the statute prevents
relief from being directed toward a state which has requested the
waiver by reducing the renewable fuel obligation of refiners, blenders,
and importers who market gasoline in the affected state. Contrary to
the commenter's assertion, the statute states that, ``[t]he
Administrator * * * may waive the requirements * * * by reducing the
national quantity of renewable fuel required''.\33\ Congress's clear
intent was to limit EPA's authority to provide relief under the state
waiver provision of section 211(o)(7). Relief under that provision is
limited to reducing the total national volume required under the RFS
program. Thus, the renewable volume obligation for regulated parties
would be reduced, but the reduced obligation would still apply to all
obligated refiners, blenders and importers, including those in the
state that requested the waiver. This may provide some relief to the
part of the country submitting the petition, but EPA is not authorized
to grant other more targeted relief such as reducing the percentage for
some refiners and not others or refusing to count towards compliance
renewable fuel that is produced or used in certain parts of the
country. It should be noted here that this approach holds true for
states or territories which have opted-in to the program as well. Once
a state or territory has opted-in to the program, they will be treated
as identical to any other state and specific relief will not be
provided to regulated parties serving these areas after the approval of
a waiver. Noncontiguous states and territories should consider this in
discussions with regulated parties before opting-in to the program.
---------------------------------------------------------------------------

    \33\ CAA Section 211(o)(7), as added by Section 1501(a) of the
Energy Policy Act of 2005.
---------------------------------------------------------------------------

    Another commenter stated that EPA should publish regulations
outlining specific criteria that will be considered in reviewing a
petition, so that the public would have a more meaningful opportunity
to participate in the process. While EPA realizes that the criteria
provided by the statute are quite general, the rationales of severe
environmental or economic harm or inadequate domestic supply are
sufficient for a basic framework upon which a petition can be built and
evaluated. Each situation in which a waiver may be requested will be
unique, and promulgating a list of more specific criteria in the
abstract may be counter-productive. Communication between the
petitioning state(s), EPA, DOE, USDA, and public and industry
stakeholders should begin early in the process, well before a waiver
request is submitted. This communication will supply these federal
agencies with a knowledgeable background of the situation prompting the
potential waiver request. The waiver request may even prove unnecessary
after an initial investigation and analysis of the situation. If not,
and if the state continues to believe that a valid basis for submission
of a petition exists, federal agencies can instruct the state(s) as to
what more detailed information is needed for waiver approval. Petitions
will be published in the Federal Register, as required by statute, to
provide public notice and opportunity for comment.
    A third commenter raised the point that there is no provision in
the Act that would permit EPA to waive any obligations for specific
entities in a state that has petitioned for a waiver, and in the case
of an emergency, such as a natural disaster, specific relief may be
warranted. The commenter is correct in the observation that EPA cannot
waive obligations for specific entities or locations. However, the Act
does authorize EPA to waive the obligations of the program as it
applies to all obligated parties, in whole or in part, depending on the
severity of the situation.

D. How Do Obligated Parties Comply With the Standard?

    Under the Act, EPA is to establish a renewable fuel standard
annually, expressed as a percentage of gasoline sold or introduced into
commerce, that will ensure that overall a specified total national
volume of renewable fuels will be used in gasoline in the U.S. The Act
does not require each obligated party to necessarily do the blending
themselves in order to comply with this obligation. Rather, under the
credit trading program required by the Act, each obligated party is
allowed to satisfy its obligations either through its own actions or
through the transfer of credits from others who have more than
satisfied their individual requirements.
    This section describes our final compliance program. It is based on
the use of unique renewable identification numbers (RINs) assigned to
batches of renewable fuel by renewable fuel producers and importers.
These RINs can then be sold or traded, and ultimately used by any
obligated party to demonstrate compliance with the applicable standard.
Excess RINs serve the function of the credits envisioned by the Act and
also provide additional benefits, as described below. We believe that
our approach is consistent with the language and intent of the Act and
preserves the natural market forces and blending practices that will
keep renewable fuel costs to a minimum.
1. Why Use Renewable Identification Numbers?
    Once renewable fuels are produced or imported, there is very high
confidence that all but de minimus quantities will in fact be blended
into gasoline or otherwise used as motor vehicle fuels, except for
exports. Renewable fuels are not used for food, chemicals, or as
feedstocks to other production processes. In fact the denaturant that
must be added to ethanol is designed specifically to ensure that the
ethanol is primarily used as motor vehicle fuel. In discussions with
stakeholders prior to release of the NPRM, it became clear that other
renewable fuels, including biodiesel and renewable fuels used in their
neat (unblended) form, likewise are not used in appreciable quantities
for anything other than motor vehicle fuel. Therefore if a refiner
ensures that a certain volume of renewable fuel has been produced, in
effect they have also ensured that this volume will be blended into
gasoline or otherwise used as a motor vehicle fuel. Focusing on
production of renewable fuel as a surrogate for use of such fuel has
many benefits as far as streamlining the program and minimizing the
influence that the program has on the operation of the market.
    In order to implement a program that is based on production of a
certain volume of renewable fuels, we are finalizing a system of volume
accounting and tracking of renewable fuels. We are requiring that this
system be based on the assignment of unique numbers to each batch of
renewable fuel. These numbers are called Renewable Identification
Numbers or RINs, and are assigned to each batch by the renewable fuel
producer or importer.
    The use of RINs allows the Agency to measure and track renewable
fuel volumes starting at the point of their production rather than at
the point when they are blended into conventional fuels. Although an
alternative approach would be to measure renewable fuel volumes as they
are blended into conventional gasoline or diesel, measuring renewable
fuel volumes at the point of production provides more accurate
measurements that can be easily verified. For instance, ethanol
producers are already required to report their production volumes to
EIA through Monthly Oxygenate Reports. These data provide an
independent source for verifying volumes. The total number of batches
and parties involved are also minimized in this approach. The total
number of batches is smallest at the point of production, since batches
are commonly split into smaller ones as they proceed through the
distribution system to the place where they are blended into
conventional fuel. The number of renewable fuel producers is also far
smaller than the number of blenders. Currently there just over 100
ethanol plants and 85 biodiesel plants in the U.S., compared with
approximately 1200 blenders \34\ based on IRS data.
---------------------------------------------------------------------------

    \34\ Those blenders who add ethanol to RBOB are already
regulated under our reformulated gasoline regulations.
---------------------------------------------------------------------------

    The assignment of RINs to batches of renewable fuel at the point of
their production also allows those batches to be identified according
to various categories important for compliance purposes. For instance,
the RIN will contain a component that specifies whether a batch of
ethanol was made from cellulosic feedstocks. This RIN component will be
of particular importance for 2013 and beyond when the Act specifies a
national volume requirement for cellulosic biomass ethanol. The RIN
will also identify the Equivalence Value of the renewable fuel which
will often only be known at the point of its production. Finally, the
RIN will identify the year in which the batch was produced, a critical
element in determining the applicable time period within which RINs are
valid for compliance purposes.
    Although production volumes of renewable fuels intended for
blending into gasoline are a reasonably accurate surrogate for volumes
ultimately blended into gasoline, changes can occur at various times
throughout the year in the volumes of renewable fuel that are in
storage. These stock changes involve the temporary storage of renewable
fuel during times of excess and can affect the length of time between
production and ultimate use. While there may be seasonal fluctuations
in stocks due to seasonal demand, these stock changes always have a net
change of zero over the long term since there is no economic benefit to
stockpiling renewable fuels. As a result there is no need to account
for stock changes in our program.
    Exports of renewable fuel represent the only significant
distribution pathway that could impair the use of production as a
surrogate for renewable fuel blending into gasoline or other use as a
motor vehicle fuel. However, our approach accounts for exports through
an explicit requirement placed upon exporters (discussed in Section
III.D.4 below). As a result, we are confident that our approach
satisfies the statutory obligation that our regulations impose
obligations on refiners and importers that will ensure that gasoline
sold or introduced into commerce in the U.S. each year will contain the
volumes of renewable fuel specified in the Act. By tracking the amount
of renewable fuel produced or imported and subtracting the amount
exported, we will have an accurate accounting of the renewable fuel
actually consumed as motor vehicle fuel in the U.S. Exports of
renewable fuel are discussed in more detail in Section III.D.4.
a. RINs Serve the Purpose of a Credit Trading Program
    According to the Act, we must promulgate regulations that include
provisions for a credit trading program. The credit trading program
allows a refiner that overcomplied with its annual RVO to generate
credits representing the excess renewable fuel. The Act stipulates that
those credits can then be used within the ensuing 12 month period, or
transferred to another refiner that had not blended sufficient
renewable fuel into its gasoline to satisfy its RVO. In this way the
credit trading program permits current blending practices to continue
wherein

some refiners purchase a significant amount of renewable fuel for
blending into their gasoline while others do little or none, thus
providing a means for all refiners to economically comply with the
standard.
    Our RIN-based program fulfills all the functions of a credit
trading program and thus meets the Act's requirements. If at the end of
a compliance period a party had more RINs than it needed to show
compliance with its renewable volume obligation, these excess RINs
would serve the function of credits and could be used or traded in the
next compliance period. RINs can be transferred to another party in an
identical fashion to a credit. However, our program provides additional
flexibility in that it permits all RINs to be transferred between
parties before they are deemed to be in excess of a party's annual RVO
at the end of the year. This is because a RIN serves two functions: It
is direct evidence of compliance and, after a compliance year is over,
excess RINs serve the function of credits for overcompliance. Thus the
RIN approach has the advantage of allowing real-time trading without
having to wait until the end of the year to determine excess.
    As in other motor vehicle fuels credit programs, we are also
requiring that any renewable producer that generates RINs must use an
independent auditor to conduct annual reviews of the party's renewable
production, RIN generation, and RIN transactions. These reviews are
called ``attest engagements,'' because the auditor is asked to attest
to the validity of the regulated party's credit transactions. For
example, the reformulated gasoline program requires attest engagements
for refiners and importers, and downstream oxygenate blenders to verify
the underlying documentation forming the basis of the required reports
(40 CFR part 80, subpart F). In the case of RIN generation, the auditor
is required to verify that the number of RINs generated matched the
volume of renewable fuels produced, that any extra value RINs are
appropriately generated, and that RIN numbers are properly transferred
with the renewable fuel as required by the regulations.
b. Alternative Approach to Tracking Batches
    If we had not implemented a RIN-based system for uniquely
identifying, measuring, and tracking batches of renewable fuel, the RFS
program would necessarily require that we measure renewable fuel
volumes at the point in the distribution system where they are actually
blended into conventional gasoline or diesel or used in their neat form
as motor vehicle fuel. The NPRM described a number of significant
problems that this approach would create, including the potential for
double-counting, increasing the number of parties subject to
enforcement provisions, and the loss of a distinction between
cellulosic ethanol and other forms of ethanol. We concluded that a
blender-based approach to tracking volumes of renewable fuel was
inferior to our proposed program focusing on the point of production
and importation. We did not receive any comments supporting a blender-
based approach and, consistent with the rationale provided in the
proposed rule, have decided not to implement it.
2. Generating RINs and Assigning Them to Batches
a. Form of Renewable Identification Numbers
    Each RIN is generated by the producer or importer of the renewable
fuel and uniquely identifies not only a specific batch, but also every
gallon in that batch. The RIN consists of a 38-character code having
the following form:

RIN: KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE

Where:
K = Code distinguishing assigned RINs from separated RINs.
YYYY = Calendar year of production or import.
CCCC = Company ID.
FFFFF = Facility ID.
BBBBB = Batch number.
RR = Code identifying the Equivalence Value.
D = Code identifying cellulosic biomass ethanol.
SSSSSSSS = Start of RIN block.
EEEEEEEE = End of RIN block.

    In response to the NPRM, one commenter requested that the full RIN
generation date, not just the year, be included in the RIN. We believe
that this is unnecessary and would unduly lengthen the RIN. Compliance
with the standard is determined on a calendar year basis, and the year
of RIN generation is necessary in order to ensure that RINs are used
for compliance purposes only in the calendar year generated or the
following year. See Section III.D.3.b. The full RIN generation date,
while a potentially useful piece of information in the context of
potential enforcement activities, is not necessary as a component of
the RIN since recordkeeping requirements contain this same information
and can be consulted in the enforcement context.
    The company and facility IDs are assigned by the EPA as part of the
registration process as described in Section IV.B. Company IDs will be
used primarily to determine compliance, while the inclusion of facility
IDs allows the assignment of batch numbers unique to each facility. The
use of both company and facility IDs is also consistent with our
approach in other fuel programs. The batch number is chosen by the
producer and includes five digits to allow for facilities that produce
up to a hundred thousand batches per year. In the NPRM we proposed that
batch numbers be sequential values starting with 00001 at the beginning
of each year. Following release of the NPRM, some stakeholders
expressed the desire to be able to align RIN batch numbers with numbers
used in other aspects of their business. As a result, we have
determined that the requirement that the batch numbers be sequential is
not necessary so long as each batch number is unique within a given
calendar year. Batches are described more fully in Section III.E.1.a.
    The RR, D, and K codes together describe the nature of the
renewable fuel and the RINs that are generated to represent it. The RR
code simply represents the Equivalence Value for the renewable fuel,
multiplied by 10 to eliminate the decimal place inherent in Equivalence
Values. Equivalence Values form the basis for the total number of RINs
that can be generated for a given volume of renewable fuel, and are
described in Section III.B.4.
    The D code identifies cellulosic biomass ethanol batches as such.
Since the Act requires that a minimum of 250 million gallons of
cellulosic biomass ethanol be consumed starting in 2013, obligated
parties will need to be able to distinguish RINs representing
cellulosic biomass ethanol from RINs representing other types of
renewable fuel. This requirement is discussed in more detail in Section
III.A.
    In the NPRM, the K code served to distinguish between standard-
value RINs and extra-value RINs, and it was placed in the middle of the
RIN. As described more fully in Section III.E.1.a, our final rule
eliminates the need for a distinction between standard-value RINs and
extra-value RINs, but requires a distinction between RINs that must be
transferred with a volume of renewable fuel (assigned RINs) and RINs
that can be transferred without renewable fuel (separated RINs). Thus
for the final rule we have changed the purpose of the K code. As
described in Section III.E.2, we are requiring that RINs separated from
volumes of renewable fuel be identified as such, by changing the K code
from a value of 1 to a value of 2. Placing the K code at the beginning
of the RIN

makes this process more straightforward for obligated parties and
oxygenate blenders who will be responsible for changing the K code
after separating a RIN from renewable fuel.
    The RIN also contains two codes SSSSSSSS and EEEEEEEE that together
identify the ``RIN block'' which demarcates the number of gallons of
renewable fuel that the batch represents in the context of compliance.
Depending on the Equivalence Value, this may not necessarily be the
same as the actual number of gallons in the batch. The methodology for
designating the SSSSSSSS and EEEEEEEE values is described in Section
III.D.2.b below.
    In the NPRM we assigned six digits to the RIN block codes to allow
batches up to a million gallons in size. Based on comments received, we
have decided to expand the number of digits to eight to accommodate
batches up to 100 million gallons in size. Although it is highly
unlikely that a single tank would hold this volume, we are adding a
definition of ``batch'' to our final regulations that would allow this
high volume to be counted as a single batch for the purposes of
generating RINs.
    In the NPRM we pointed out that ``RIN'' can refer to either the
number representing an entire batch or the number representing one
gallon of renewable fuel in the context of compliance. In order to make
the distinction clear, we are defining the latter as a gallon-RIN, and
a batch-RIN will represent multiple gallon-RINs. In the case of a
gallon-RIN, the values of SSSSSSSS and EEEEEEEE will be identical. A
batch-RIN, on the other hand, will generally have different values for
SSSSSSSS and EEEEEEEE, representing the starting and ending values of a
batch of renewable fuel. Examples of RINs are presented in the next
section.
b. Generating RINs
    As described in Section III.E.1.a, we have eliminated the
distinction between standard-value RINs and extra-value RINs for this
final rule. Instead, all gallon-RINs must be assigned to batches of
renewable fuel by the producer or importer. Consistent with the NPRM,
each gallon-RIN will continue to represent one gallon of renewable fuel
in the context of compliance.
    Also consistent with the NPRM, we are requiring that RIN generation
begin at the same time that the renewable fuel standard becomes
applicable to obligated parties. Thus RINs must be generated for all
renewable fuel produced or imported on or after September 1, 2007.
Since many producers and importers will have renewable fuel in
inventory at the start of the program that was produced prior to
September 1, 2007, we are also allowing them to generate RINs for such
renewable fuel. This provision ensures that every gallon that a
producer or importer sells starting on September 1, 2007 can have an
assigned RIN, and obligated parties that take ownership of renewable
fuel directly from a producer or importer will have greater assurance
of having access to RINs at the start of the program. Other volumes of
ethanol in inventory in the distribution system on September 1, 2007
will continue to be sold and distributed without RINs.
    In order to determine the number of gallon-RINs that must be
generated and assigned to a batch by a producer or importer, the actual
volume of the batch must be multiplied by the Equivalence Value to
determine an applicable ``RIN volume'':

VRIN = EV x Vs

Where:

VRIN = RIN volume, in gallons, representing the number of
gallon-RINs that must be generated (rounded to the nearest whole
gallon).
EV = Equivalence value for the renewable fuel.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons.

    When RINs are first assigned to a batch of renewable fuel by its
producer or importer, the RIN block start for that batch will in
general be 1 (i.e., SSSSSSSS will have a value of 00000001). The RIN
block end value EEEEEEEE will be equal to the RIN volume calculated
above. The batch-RIN then represents all the gallon-RINs assigned to
the batch. Table III.D.2.b-1 provides some examples of the number of
gallon-RINs that would be assigned to a batch under different
circumstances.

              Table III.D.2.B-1.--Examples of Batch-RINs 35
------------------------------------------------------------------------

-------------------------------------------------------------------------
Batch volume: 2000 gallons corn ethanol.
Equivalence value: 1.0.
Gallon-RINs: 2000.
Batch-RIN: 1-2007-1234-12345-00001-10-2-00000001-00002000.
------------------------------------------------------------------------
Batch volume: 2000 gallons biodiesel.
Equivalence value: 1.5.
Gallon-RINs: 3000.
Batch-RIN: 1-2007-1234-12345-00002-15-2-00000001-00003000.
------------------------------------------------------------------------
Batch volume: 2000 gallons cellulosic ethanol.
Equivalence value: 2.5.
Gallon-RINs: 5000.
Batch-RIN: 1-2007-1234-12345-00003-25-1-00000001-00005000.
------------------------------------------------------------------------

    The RIN block will often represent the actual number of gallons in
the batch, for cases where the Equivalence Value is 1.0. In other
cases, the RIN block start and RIN block end values in the batch-RIN
will not exactly correspond to the volume of the batch. For instance,
in cases where the Equivalence Value is larger than 1.0, the number of
gallon-RINs generated will be larger than the number of gallons in the
batch. In such cases the batch will have a greater value in terms of
compliance than a batch with the same volume but an Equivalence Value
equal to 1.0. Likewise, a batch with an Equivalence Value less than 1.0
will have a smaller value in terms of compliance than a batch with the
same volume but an Equivalence Value equal to 1.0. In the context of
our modified approach to RIN distribution as described in Section
III.E.1, however, the transfer of RINs with batches will be
straightforward regardless of the number of gallon-RINs assigned to a
particular volume of renewable fuel, as every gallon-RIN will always
have the capability of covering one gallon of an obligated party's RVO.
---------------------------------------------------------------------------

    \35\ RIN codes have been separated by hyphens in this table for
demonstrative purposes only. In actual use, no hyphens would be
present in the RIN.
---------------------------------------------------------------------------

    In response to the NPRM, some obligated parties requested that
fractional RINs be used for cases in which the Equivalence Value is
less than 1.0. Under this approach, every gallon in a batch would still
have an assigned gallon-RIN, but those gallon-RINs would represent only
a fraction of a gallon for compliance purposes. The commenters also
argued that our proposed system in which RINs are assigned to only a
portion of a batch would be unworkable given the need to ensure that
RINs remain assigned to batches as they travel through the distribution
system.
    We continue to believe that the most straightforward system
calculates the number of gallon-RINs representing a batch as the
product of the Equivalence Value and the actual volume of the batch.
Then every gallon-RIN will have the capability of covering one gallon
of an obligated party's RVO, and thus every gallon-RIN has the same
value. This is true both for renewable fuels with Equivalence Values
less than 1.0, and renewable fuels with Equivalence Values greater than
1.0. Also, as described in Section III.E.1, we have modified our
approach to the distribution of RINs assigned to volumes of renewable
fuel. As a result, the batch-splitting and batch-merging protocols have
become largely irrelevant, and thus the transfer of renewable fuels
having an

Equivalence Value less than 1.0 has become greatly simplified. We are
therefore finalizing our proposed approach in which renewable fuels
having an Equivalence Value less than 1.0 result in fewer assigned
gallon-RINs than gallons in a batch.
    Following release of the NPRM, we also identified some cases in
which the generation of RINs for a partially renewable fuel or blending
component would result in double-counting of RINs generated. For
instance, ethyl tertiary butyl ether (ETBE) is made from combining
ethanol with isobutylene. The ethanol is generally from corn, and the
isobutylene is generally from petroleum. The ETBE producer may purchase
ethanol from another source, and that ethanol may already have RINs
assigned to it. In such cases it would not be appropriate for the ETBE
producer to generate additional RINs for the ETBE made from that
ethanol. Even if the ETBE producer purchased ethanol without assigned
RINs, our program design ensures that either RINs were generated for
the ethanol and separated prior to purchase by the ETBE producer, or
RINs were legitimately not assigned to the ethanol. The NPRM did not
address the potential for generating RINs twice for the same renewable
fuel in these cases. Therefore, we are finalizing a provision
prohibiting a party from generating RINs for a partially renewable fuel
or blending component that it produces if the renewable feedstock used
to make the renewable fuel or blending component was acquired from
another party. Any RINs acquired with the renewable feedstock (e.g.
ethanol) must be assigned to the product made from that feedstock (e.g.
ETBE). This approach is consistent with comments submitted by Lyondell
Chemical Company.
c. Cases in Which RINS Are Not Generated
    Although in general every batch of renewable fuel produced or
imported must have an assigned batch-RIN, there are several cases in
which a RIN may not be assigned to a batch by a producer or importer.
For instance, if the renewable fuel was consumed within the confines of
the production facility where it was made, it would not be acquired by
either an obligated party or a gasoline blender. In such cases, the RIN
could not be separated from the batch and transferred separately since
producers do not have this right. A RIN is assigned to renewable fuel
when ownership of the renewable fuel is transferred to another party.
Since no such transfer would occur in this case, no RIN should be
generated.
    A second case in which some renewable fuel would not have an
assigned RIN would occur for small volume producers. We are allowing
renewable fuel producers who produce less than 10,000 gallons in a year
to avoid the requirement to generate RINs and assign them to batches.
Such producers would not contribute meaningfully to the nationwide pool
of renewable fuel, and we do not believe that the very small business
operations involved should be subject to the burden of recordkeeping
and reporting. Although two commenters disagreed that these small
volume producers should be exempt from the requirement to generate
RINs, they did not provide compelling evidence that the exemption would
create a problem in the distribution system or provide an unfair
advantage to small producers. As a result we are finalizing this
provision as proposed. Note that if a small producer chooses to
register as a renewable fuel producer under the RFS program, they will
be subject to all the regulatory provisions that apply to all
producers, including the requirement to assign RINs to batches.
    In the NPRM we proposed that a renewable fuel producer which also
operated as an exporter would not be required to generate and assign a
RIN to any renewable fuel that it produced and exported. However, one
commenter pointed out that this approach could lead to confusion
regarding which gallons should have an assigned RIN and which should
not, given the complex nature of tracking volumes of renewable fuel. As
a result we have determined that this provision should be eliminated.
Our final regulations require that producers assign RINs to all
renewable fuel, regardless of whether it is exported. Exports of
renewable fuel are discussed further in Section III.D.4.
3. Calculating and Reporting Compliance
    Under our program, RINs form the basis of the volume accounting and
tracking system that allows each obligated party to demonstrate that
they have met their renewable fuel obligation each year. This section
describes how the compliance process using RINs works. Our approach to
the distribution and trading of RINs is covered separately in Section
III.E below.
a. Using RINs To Meet the Standard
    Under our program, each obligated party must determine its
Renewable Volume Obligation (RVO) based on the applicable percentage
standard and its annual gasoline volume as described in Section
III.A.4. The RVO represents the volume of renewable fuel that the
obligated party must ensure is used in the U.S. in a given calendar
year. Since the nationwide renewable fuel volumes shown in Table I.B-1
are required by the Act to be consumed in whole calendar years, each
obligated party must likewise calculate its RVO on an annual basis.
    Since our program uses RINs as a measure of the amount of renewable
fuel used as motor vehicle fuel that is sold or introduced into
commerce within the U.S., obligated parties must meet their RVO through
the accumulation of RINs. In so doing, they will effectively be causing
the renewable fuel represented by the RINs to be consumed as motor
vehicle fuel. Obligated parties are not required to physically blend
the renewable fuel into gasoline or diesel fuel themselves. The
accumulation of RINs is the means through which each obligated party
shows compliance with its RVO and thus with the renewable fuel
standard.
    For each calendar year, each obligated party is required to submit
a report to the Agency documenting the RINs it acquired and showing
that the sum of all gallon-RINs acquired is equal to or greater than
its RVO. This reporting is discussed in more detail in Section IV. In
the context of demonstrating compliance, all gallon-RINs have the same
compliance value. The Agency can then verify that the RINs used for
compliance purposes are valid by simply comparing RINs reported by
producers to RINs claimed by obligated parties. We can also verify
simply that any given gallon-RIN was not double-counted, i.e., used by
more than one obligated party for compliance purposes. In order to be
able to identify the cause of any double-counting, however, additional
information is needed on RIN transactions as discussed in Section IV.
    If an obligated party has acquired more RINs than it needs to meet
its RVO, then in general it can retain the excess RINs for use in
complying with its RVO in the following year or transfer the excess
RINs to another party. The conditions under which this is allowed are
determined by the valid life of a RIN, described in more detail in
Section III.D.3.b below. If, alternatively, an obligated party has not
acquired sufficient RINs to meet its RVO, then under certain conditions
it can carry a deficit into the next year. Deficit carryovers are
discussed in more detail in Section III.D.3.d.
    The regulations prohibit any party from creating or transferring
invalid RINs. Invalid RINs cannot be used in demonstrating compliance
regardless of

the good faith belief of a party that the RINs are valid. These
enforcement provisions are necessary to ensure the RFS program goals
are not compromised by illegal conduct in the creation and transfer of
RINs.
    As in other motor vehicle fuel credit programs, the regulations
address the consequences if an obligated party is found to have used
invalid RINs to demonstrate compliance with its RVO. In this situation,
the refiner or importer that used the invalid RINs will be required to
deduct any invalid RINs from its compliance calculations. The refiner
or importer will be liable for violating the standard if the remaining
number of valid RINs is insufficient to meet its RVO, and the obligated
party may be subject to additional monetary penalties if it used
invalid RINs in its compliance demonstration. See Section V of this
preamble for further discussion regarding liability for use of invalid
RINs.
    Just as for RIN generators, we are also requiring that obligated
parties conduct attest engagements for the volume of gasoline they
produce and the number of RINs procured to ensure compliance with their
RVO. In most cases, this should amount to little more than is already
required under existing EPA gasoline regulations. In the case of
renewable fuel exporters, the attest engagement will verify the volume
of renewable fuel exported and therefore the magnitude of their RVO.
Attest engagement reports must be submitted to the party that
commissioned the engagement and to EPA. See Section IV of this preamble
for further discussion of the attest engagement requirements.
b. Valid Life of RINs
    The Act requires that renewable fuel credits be valid for showing