would need a mechanism for distinguishing between these two categories
of RINs in order to appropriately apply them to the standards. One
straightforward way of accomplishing this would be to use values for
the D code under RFS2 that do not overlap the values for the D code
under RFS1. Table III.A-2 describes the D code definitions under such
an alternative approach.

                                  Table III.A-2--Alternative D Code Definitions
----------------------------------------------------------------------------------------------------------------
                D value                         Meaning under RFS1                  Meaning under RFS2
----------------------------------------------------------------------------------------------------------------
1......................................  Cellulosic biomass ethanol.....  Not applicable.
2......................................  Any renewable fuel that is not   Not applicable.
                                          cellulosic biomass ethanol.
3......................................  Not applicable.................  Cellulosic biofuel.
4......................................  Not applicable.................  Biomass-based diesel.
5......................................  Not applicable.................  Advanced biofuel.
6......................................  Not applicable.................  Renewable fuel.
----------------------------------------------------------------------------------------------------------------

    In this alternative approach, D code values of 1 and 2 would only
be relevant for RINs generated under RFS1, and D code values of 3, 4,
5, and 6 would only be relevant for RINs generated under RFS2. As a
result, 2010 RINs generated under RFS1 would be subject to our proposed
RFS1/RFS2 transition provisions wherein they would be assigned to one
of the four annual standards that would apply in 2010 using their RR
and/or D codes. See Section III.G.3 for further description of how we
propose using RFS1 RINs to meet standards under RFS2.
    Under RFS2, each batch-RIN generated would continue to uniquely
identify not only a specific batch of renewable fuel, but also every
gallon-RIN assigned to that batch. Thus the RIN would continue to be
defined as follows:

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 the renewable fuel category
SSSSSSSS = Start of RIN block
EEEEEEEE = End of RIN block

B. New Eligibility Requirements for Renewable Fuels

    Aside from the higher volume requirements, most of the substantive
changes that EISA makes to the RFS program affect the eligibility of
renewable fuels in meeting one of the four volume requirements.
Eligibility would be determined based on the types of feedstocks that
can be used, the land that can be used to grow feedstocks for renewable
fuel production, the processes that can be used to convert those
feedstocks into fuel, and the lifecycle greenhouse gas (GHG) emissions
that can be emitted in comparison to the gasoline or diesel that the
renewable fuel displaces. This section describes these eligibility
criteria and how we propose to include them in the RFS2 program.
1. Changes in Renewable Fuel Definitions
    Under the existing Renewable Fuel Standard (RFS1), renewable fuel
is defined generally as ``any motor vehicle fuel that is used to
replace or reduce the quantity of fossil fuel present in a fuel mixture
used to fuel a motor vehicle''. The RFS1 definition includes motor
vehicle fuels produced from biomass material such as grain, starch,
fats, greases, oils, and biogas. The definition specifically includes
cellulosic biomass ethanol, waste derived ethanol, and biodiesel, all
of which are defined separately. (See 72 FR 23915.)
    The definitions of renewable fuels under today's proposed rule
(RFS2) are based on the new statutory definition in EISA. Like the
existing rules, the definitions in RFS2 include a general definition of
renewable fuel, but unlike RFS1, we are including a separate definition
of ``Renewable Biomass'' which identifies the feedstocks from which
renewable fuels may be made.
    Another difference in the definitions of renewable fuel is that
RFS2 contains three subcategories of renewable fuels: (1) Advanced
Biofuel, (2) Cellulosic Biofuel and (3) Biomass-Based Diesel. Each must
meet threshold levels of reduction of greenhouse gas emissions as
discussed in Section III.B.2. The specific definitions and how they
differ from RFS1 follow below.
a. Renewable Fuel and Renewable Biomass
    ``Renewable Fuel'' is defined as fuel produced from renewable
biomass and that is used to replace or reduce the quantity of fossil
fuel present in a transportation fuel. The definition of ``Renewable
Fuel'' now refers to ``transportation fuel'' rather than referring to
motor vehicle fuel. ``Transportation fuel'' is also defined, and means
fuel used in motor vehicles, motor vehicle engines, nonroad vehicles or
nonroad engines (except for ocean going vessels).
    We propose to allow fuel producers and importers to include
electricity, natural gas, and propane (i.e., compressed natural gas
(CNG) and liquefied petroleum gas (LPG)) as a RIN-generating renewable
fuel in today's program only if they can identify the specific
quantities of their product which are actually used as a transportation
fuel, and if the fuel is produced from renewable biomass. This may be
possible for some portion of electricity, natural gas, and propane
since many of the affected vehicles and equipment are in centrally-
fueled fleets supplied under contract by a particular producer or
importer of natural gas or propane. A producer or importer of
electricity, natural gas, or propane who could document the use of his
product in a vehicle or engine would be allowed to generate RINs to
represent that product, if it met the definition of renewable fuel.
Given that the primary use of electricity, natural gas, and propane is
not for fueling vehicles and engines, and the producer generally does
not know how it will be used, we cannot require that producers or
importers of these fuels generate RINs for all the volumes they produce
as we do with other renewable fuels.
    Our proposal to allow electricity, natural gas, and propane to
generate RINs under certain conditions is consistent with our treatment
of neat renewable fuels under RFS1 and EISA's requirement that all
transportation fuels be included in RFS2. With specific regard to
renewable electricity, Section 206 of EISA requires the EPA to conduct
a study of the feasibility of issuing credits under the RFS2 program
for renewable electricity used by electric vehicles. Once completed,
this study will provide additional information regarding the means by
which renewable electricity is able to generate RINs under the RFS2
program.
    As an alternative to allowing producers and importers of
electricity, natural gas, and propane to generate RINs if they can
demonstrate that their product is a renewable fuel and it is used as
transportation fuel, we could allow or require parties who supply these
fuels to centrally fueled fleets to generate the RINs even if they are
not the producer of the fuel. This approach

would treat the supplier of the fuel to the fleet as the producer or
importer who then generates RINs, as they are the party who in effect
changes the fuel from a fuel that can be used in a variety of ways and
ensures that it is in fact used as transportation fuel. This
alternative approach might enable a larger volume of electricity,
natural gas, and propane that is made from renewable biomass and which
is actually used in vehicles or engines to be included in our proposed
fuels program as RIN-generating, since in many cases a supplier could
document the use of these fuels in vehicles or engines, while a
producer could not. In addition, in this case the supplier is the party
who causes the fuel to transition from general fuel supply to fuel
designated for use in motor vehicles or nonroad applications--in that
sense, the supplier is more like a producer or importer than the
upstream producer or importer. However, if we were to allow the
supplier of renewable electricity, natural gas, or propane to generate
RINs in such cases, it may also be appropriate to require suppliers of
fossil-based electricity, natural gas, or propane to determine a
Renewable Volume Obligation (RVO) that includes these fuels used as
transportation fuel. See Section III.F.3 for further discussion. We
request comment on this alternative approach for generating RINs for
renewable electricity, natural gas and propane.
    The term ``Renewable Biomass'' as defined in EISA, means:
    1. Planted crops and crop residue,
    2. Planted trees and tree residues,
    3. Animal waste material and byproducts,
    4. Slash and pre-commercial thinnings (from non-federal
forestlands),
    5. Biomass cleared from the vicinity of buildings and other areas
to reduce the risk of wildfire,
    6. Algae, and
    7. Separated yard waste or food waste.
    Section III.B.4 of this preamble outlines our proposed
interpretations for most of the key terms contained in the EISA
definition of ``renewable biomass'' and possible approaches for
implementing the land restrictions on renewable biomass that are
included in EISA. It is worth noting here, however, that the statutory
definition of ``renewable biomass'' does not include a reference to
municipal solid waste (MSW) as did the definition of ``cellulosic
biomass ethanol'' in the Energy Policy Act of 2005 (EPAct), but instead
includes ``separated yard waste and food waste. EPA's proposed
definition of renewable biomass in today's regulation includes the
language present in EISA, and we propose to clarify in the regulations
that ``yard waste'' is leaves, sticks, pine needles, grass and hedge
clippings, and similar waste from residential, commercial, or
industrial areas. Nevertheless, EPA invites comment on whether the
definition of ``renewable biomass'' should be interpreted as including
or excluding MSW from the definition of renewable biomass.
    While the lack of a reference to MSW and the new listing of
separated yard waste and food waste could be readily interpreted to
exclude MSW as a qualifying feedstock under RFS2, EPA believes there
are indications of ambiguity on this issue and solicits comment on
whether EPA can and should interpret EISA as including MSW that
contains yard and/or food waste within the definition of renewable
biomass. On the one hand, the reference in the statutory definition to
``separated yard waste and food waste,'' and the lack of reference to
other components of MSW (such as waste paper and wood waste) suggests
that only yard and food wastes physically separated from other waste
materials satisfy the definition of renewable biomass as opposed to the
yard and food waste present in MSW. This view would exclude unprocessed
MSW from any role in the development of renewable fuel under EISA, and
would also likely severely limit the amount of yard and food waste
available as feedstock for EISA-qualifying fuel, since large quantities
of these materials are disposed of as unprocessed MSW.
    On the other hand, there are some indications that Congress may not
have specifically intended to exclude MSW from playing a role in the
development of renewable fuels under EISA. For example, ethanol
``derived from waste material'' and biogas ``including landfill gas''
are specifically identified as ``eligible for consideration'' in the
definition of advanced biofuel. While landfill gas is generated
primarily by the yard waste and food waste in a landfill, these wastes
typically are not separated from each other in a landfill. In addition,
Congress did not define the term ``separated'' and did not otherwise
specify the degree of ``separation'' required of yard and food waste in
the definition of renewable biomass. Thus, it might be reasonable to
consider these items sufficiently ``separated'' from other materials,
including non-waste materials, when food and yard waste is present in
MSW. In addition, the processing of MSW to fuel will effectively
separate out the materials in MSW that cannot be made into fuel, such
as glass and metal, and non-biomass portions of MSW (for example,
pastics) could be excluded from getting credit under the RFS program as
described in Section III.D.4. EPA invites comment on whether there is
enough separation of food and yard waste in MSW used in renewable fuel
production for MSW containing yard and food waste to meet the
definition of renewable biomass.
    Approximately 35% by weight of MSW is paper wastes, and another 6%
by weight from wood wastes. Combined with food and yard wastes, more
than 60% by weight of MSW is biomass that could be used to make ethanol
and other renewable fuels.\5\ The volume of ethanol associated with MSW
as a feedstock is described in more detail in Section 1.1 of the Draft
Regulatory Impact Analysis (DRIA).
---------------------------------------------------------------------------

    \5\ Construction and demolition (C&D) wastes are not typically
considered as elements of MSW. Because they are significant
feedstocks for the production of ethanol, we include such wastes in
our economic analysis (Section V). Therefore, for all practical
purposes, the discussion here as it pertains to whether MSW should
be included in the definition of ``renewable biomass'' also applies
to C&D wastes.
---------------------------------------------------------------------------

    Our discussions with stakeholders indicate that a potential concern
with interpreting the definition of renewable biomass to include MSW
containing yard and/or food waste is that this approach may cause some
decrease in the amount of paper that is separated from the MSW waste
stream and recycled into paper products. We believe, however, that
current waste handling practices and current and anticipated market
conditions would continue to provide a strong incentive for paper
separation and recycling. A narrow reading of the statute to exclude
MSW-derived renewable fuel would directionally reduce the options
available for meeting the goal of EISA to reduce our dependence on
foreign sources of energy.
    By including MSW containing yard and/or food waste in the
definition of renewable biomass, we could also allow renewable fuel to
be produced in part from certain plastics in the MSW waste stream. We
believe this could be appropriate given that plastics that would
otherwise be destined for landfills can be used for fuel and energy
production. We recognize that the definition of renewable biomass
generally includes only materials of a non fossil-fuel origin, and ask
that commenters consider this issue in their comments on whether: (1)
MSW containing yard and food waste should qualify as renewable biomass,
(2) if non-fossil portions of MSW should be included in the definition
of renewable biomass, and (3) if non-fossil portions of

MSW should not be included, whether the approach discussed in Section
III.D.4 can provide an appropriate means for excluding the non-fossil
portions.
    Although we are proposing to exclude MSW from the definition of
``renewable biomass'' for the proposed rule, our analysis of renewable
fuel volume (discussed in Section V) assumes that MSW is included for
purposes of quantifying the potential future volume of renewable fuel.
EPA intends to resolve this matter in the final rule, and we solicit
comment on the approach that we should take.
b. Advanced Biofuel
    ``Advanced Biofuel'' is a renewable fuel other than ethanol derived
from corn starch and which must also achieve a lifecycle GHG emission
displacement of 50%, compared to the gasoline or diesel fuel it
displaces. As such, advanced biofuel would be assigned a D code of 3 as
shown in Table III.A-1.
    ``Advanced biofuel'' also may be biomass-based diesel, biogas
(including landfill gas and sewage waste treatment gas), butanol or
other alcohols produced through conversion of organic matter from
renewable biomass, and other fuels derived from cellulosic biomass, as
long as it meets the proposed 40-44% GHG emission reduction threshold.
``Advanced Biofuel'' is a renewable fuel other than ethanol derived
from corn starch and for which lifecycle GHG emissions are at least 40-
44% less than the gasoline or diesel fuel it displaces. Advanced
biofuel would be assigned a D code of 3 as shown in Table III.A-1.
    While ``Advanced Biofuel'' specifically excludes ethanol derived
from corn starch, it includes other types of ethanol derived from
renewable biomass, including ethanol made from cellulose,
hemicellulose, lignin, sugar or any starch other than corn starch, as
long as it meets the proposed 40-44% GHG emission reduction threshold.
Thus, even if corn starch-derived ethanol were made so that it met the
proposed 40-44% GHG reduction threshold, it would still be excluded
from being defined as an advanced biofuel. Such ethanol, while not an
advanced biofuel, would still qualify as a renewable fuel for purposes
of meeting the standards.
    ``Advanced biofuel'' also may be biomass-based diesel, biogas
(including landfill gas and sewage waste treatment gas), butanol or
other alcohols produced through conversion of organic matter from
renewable biomass, and other fuels derived from cellulosic biomass, as
long as it is derived from renewable biomass and meets the proposed 40-
44% GHG emission reduction threshold.
c. Cellulosic Biofuel
    Cellulosic biofuel is renewable fuel, not necessarily ethanol,
derived from any cellulose, hemicellulose, or lignin each of which must
originate from renewable biomass. It must also achieve a lifecycle GHG
emission reduction of at least 60%, compared to the gasoline or diesel
fuel it displaces. Cellulosic biofuel is assigned a D code of 1 as
shown in Table III.A-1. Cellulosic biofuel in general also qualifies as
both ``advanced biofuel'' and ``renewable fuel''.
    The proposed definition of cellulosic biofuel for RFS2 is broader
in some respects than the RFS1 definition of ``cellulosic biomass
ethanol''. That definition included only ethanol, whereas the RFS2
definition of cellulosic biofuels includes any biomass-to-liquid fuel
in addition to ethanol. The definition of ``cellulosic biofuel'' in
RFS2 differs from RFS1 in another significant way. The RFS1 definition
provided that ethanol made at any facility--regardless of whether
cellulosic feedstock is used or not--may be defined as cellulosic if at
such facility ``animal wastes or other waste materials are digested or
otherwise used to displace 90% or more of the fossil fuel normally used
in the production of ethanol.'' This provision was not included in
EISA, and therefore does not appear in the definitions pertaining to
cellulosic biofuel in today's proposed rule.
d. Biomass-Based Diesel
    Under today's proposed rule ``Biomass-based diesel'' includes both
biodiesel (mono-alkyl esters) and non-ester renewable diesel (including
cellulosic diesel). The definition is the same very broad definition of
``biodiesel'' that was in EPAct and in RFS1, with three exceptions.
First, EISA requires that such fuel be made from renewable biomass.
Second, its lifecycle GHG emissions must be at least 50% less than the
gasoline or diesel fuel it displaces. Third, the statutory definition
of ``Biomass-based diesel'' excludes renewable fuel derived from co-
processing biomass with a petroleum feedstock. In drafting the proposed
definition, we considered two options for how co-processing could be
treated. The first option would consider co-processing to occur only if
both petroleum and biomass feedstock are processed in the same unit
simultaneously. The second option would consider co-processing to occur
if renewable biomass and petroleum feedstock are processed in the same
unit at any time; i.e., either simultaneously or sequentially. Under
the second option, if petroleum feedstock was processed in the unit,
then no fuel produced from such unit, even from a biomass feedstock,
would be deemed to be biomass-based diesel.
    We are proposing the first option to be used in the definition in
today's rule. Under this approach, a batch of fuel qualifying for the D
code of 2 that is produced in a processing unit in which only renewable
biomass is the feedstock for such batch, would meet the definition of
``Biomass-Based Diesel. Thus, serial batch processing in which 100%
vegetable oil is processed one day/week/month and 100% petroleum the
next day/week/month could occur without the activity being considered
``co-processing.'' The resulting products could be blended together,
but only the volume produced from vegetable oil would count as biomass-
based diesel. We believe this is the most straightforward approach and
an appropriate one, given that it would allow RINs to be generated for
volumes of fuel meeting the 50% GHG reduction threshold that is derived
from renewable biomass, while not providing any credit for fuel derived
from petroleum sources. In addition, this approach avoids the need for
potentially complex provisions addressing how fuel should be treated
when existing or even mothballed petroleum hydrotreating equipment is
retrofitted and placed into new service for renewable fuel production
or vice versa.
    Under today's proposal, any fuel that does not satisfy the
definition of biomass-based diesel only because it is co-processed with
petroleum would still meet the definition of ``Advanced Biofuel''
provided it meets the 50% GHG threshold and other criteria for the D
code of 3. Similarly it would meet the definition of renewable fuel if
it meets a GHG emission reduction threshold of 20%. In neither case,
however, would it meet the definition of biomass-based diesel.
    This restriction is only really an issue for renewable diesel and
biodiesel produced via the fatty acid methyl ester (FAME) process. For
other forms of biodiesel, it is never made through any sort of co-
processing with petroleum.\6\

Producers of renewable diesel must therefore specify whether or not
they use ``co-processing'' to produce the fuel in order to determine
the correct D code for the RIN.
---------------------------------------------------------------------------

    \6\ The production of biodiesel (mono alkyl esters) does require
the addition of methanol which is usually derived from natural gas,
but which contributes a very small amount to the resulting product.
We do not believe that this was intended by the statute's reference
to ``co-processing'' which we believe was intended to address only
renewable fats or oils co-processed with petroleum in a hydrotreater
to produce renewable diesel.
---------------------------------------------------------------------------

e. Additional Renewable Fuel
    The statutory definition of ``additional renewable fuel'' specifies
fuel produced from renewable biomass that is used to replace or reduce
fossil fuels used in home heating oil or jet fuel. EISA indicates that
EPA may allow for the generation of credits for such additional
renewable fuel that will be valid for compliance purposes. Under the
RFS program, RINs operate in the role of credits, and RINs are
generated when renewable fuel is produced rather than when it is
blended. In most cases, however, renewable fuel producers do not know
at the time of fuel production (and RIN generation) how their fuel will
ultimately be used.
    Under RFS1, only RINs assigned to renewable fuel that was blended
into motor vehicle fuel are valid for compliance purposes. As a result,
we created special provisions requiring that RINs be retired if they
were assigned to renewable fuel that was ultimately blended into
nonroad fuel. The new EISA provisions regarding additional renewable
fuel make the RFS1 requirement for retiring RINs unnecessary if
renewable fuel is blended into heating oil or jet fuel. As a result, we
propose modifying the regulatory requirements to allow RINs assigned to
renewable fuel blended into heating oil or jet fuel to continue to be
valid for compliance purposes.
2. Lifecycle GHG Thresholds
    As part of the new definitions that EISA creates for cellulosic
biofuel, biomass-based diesel, advanced biofuel, and renewable fuel,
EISA also sets minimum performance measures or ``thresholds'' for
lifecycle GHG emissions. These thresholds represent the percent
reduction in lifecycle GHGs that is estimated to occur when a renewable
fuel displaces gasoline or diesel fuel. Table III.B.2-1 lists the
thresholds required by EISA.

           Table III.B.2-1--Required Lifecycle GHG Thresholds
       [Percent reduction from a 2005 gasoline or diesel baseline]
------------------------------------------------------------------------

------------------------------------------------------------------------
Renewable fuel.................................................       20
Advanced biofuel...............................................       50
Biomass-based diesel...........................................       50
Cellulosic biofuel.............................................       60
------------------------------------------------------------------------

    There are also special provisions for each of these thresholds:
    Renewable fuel: The 20% threshold only applies to renewable fuel
from new facilities that commenced construction after December 19,
2007, with an additional exemption from the 20% threshold for ethanol
plants that commenced construction in 2008 or 2009 and are fired with
natural gas, biomass, or any combination thereof. Facilities not
subject to the 20% threshold would be ``grandfathered.'' See Section
III.B.3 below for a complete discussion of grandfathering. Also, EPA
can adjust the 20% threshold to as low as 10%, but the adjustment must
be the minimum possible, and the resulting threshold must be
established at the maximum achievable level based on natural gas fired
corn-based ethanol plants.
    Advanced biofuel and biomass-based diesel: The 50% threshold can be
adjusted to as low as 40%, but the adjustment must be the minimum
possible and result in the maximum achievable threshold taking cost
into consideration. Also, such adjustments could be made only if it was
determined that the 50% threshold was not commercially feasible for
fuels made using a variety of feedstocks, technologies, and processes.
As described more fully in Section VI.D, we are proposing that the GHG
threshold for advanced biofuels be adjusted to 44% or potentially as
low as 40% depending on the results from the analyses that will be
conducted for the final rule.
    Cellulosic biofuel: Similarly to advanced biofuel and biomass-based
diesel, the 60% threshold applicable to cellulosic biofuel can be
adjusted to as low as 50%, but the adjustment must be the minimum
possible and result in the maximum achievable threshold taking cost
into consideration. Also, such adjustments could be made only if it was
determined that the 60% threshold was not commercially feasible for
fuels made using a variety of feedstocks, technologies, and processes.
    Our analyses of lifecycle GHG emissions, discussed in detail in
Section VI, included all GHGs related to the full fuel cycle, including
all stages of fuel and feedstock production and distribution, from
feedstock generation and extraction through distribution, delivery, and
use of the finished fuel. They included direct emissions and any
significant indirect emissions such as significant emissions from land
use changes. These lifecycle analyses were used to determine whether
the thresholds shown in Table III.B.2-1 should be adjusted downwards
and which specific combinations of feedstock, fuel type, and production
process met those thresholds under the assumption of a 100-year
timeframe and 2% discount rate for GHG emission impacts.
    We are not proposing to adjust any of these thresholds. However, we
may adjust the GHG threshold for biomass-based diesel and/or advanced
biofuel downward for the final rule based on additional lifecycle GHG
analyses and further assessments of the market potential for volumes
that can meet the requirements for these categories of renewable fuel.
As explained in more detail in Section VI.D, ethanol produced from
sugarcane sugar has been estimated to have a lifecycle GHG performance
of 44% (under the assumption of a 100 year timeframe and 2% discount
rate), short of the 50% threshold specified in EISA. Ethanol from
sugarcane is one of the few currently commercial pathways that have the
potential to meet the requirements for advanced biofuel in the near
term (in addition to cellulosic biofuel and biomass-based diesel which
are a subset of advanced biofuel, and any other new fuels that may
arise), and the only such pathway that was subjected to lifecycle
analysis to date. If ethanol from sugarcane does not qualify as
advanced biofuel, it is likely that it would not be commercially
feasible for the advanced biofuel volume requirements to be met in the
near term. We request comment on whether it would be necessary to
adjust the GHG threshold for advanced biofuel. For similar reasons, as
discussed in more detail in Section VI.D, we are also seeking comment
on the need to adjust the GHG threshold for biomass-based diesel.
3. Renewable Fuel Exempt From 20 Percent GHG Threshold
    EISA amends section 211(o) of the Clean Air Act to provide that
renewable fuel produced from new facilities which commenced
construction after December 19, 2007 must achieve at least a 20%
reduction in lifecycle greenhouse gas emissions compared to baseline
lifecycle greenhouse gas emissions.\7\ Facilities that commenced
construction before December 19, 2007 are ``grandfathered'' and thereby
exempt from the 20% GHG reduction requirement.
---------------------------------------------------------------------------

    \7\ Section 211(o)(2)(A)(i) of the Clean Air Act as amended by
EISA. Note that this is not a prohibition--facilities that make
ethanol can continue to do so. It is a minimum requirement for
facilities to generate RINs under today's proposed rule; failure to
meet such requirements means that the ethanol produced from such
facilities cannot generate RINs.

---------------------------------------------------------------------------

    For facilities that produce ethanol and for which construction
commenced after December 19, 2007, section 210 of EISA states that
``for calendar years 2008 and 2009, any ethanol plant that is fired
with natural gas, biomass, or any combination thereof is deemed to be
in compliance with the 20% threshold.'' We refer to these facilities as
``deemed compliant.'' This provision does not specify whether such
facilities are deemed to be in compliance only for the period of 2008
and 2009, or indefinitely. Nor does EISA specify a date by which such
qualifying facilities must have started operation. Although the Act is
unclear as to whether their special treatment is only for 2008/2009, or
for a longer time period, we believe that it would be a harsh result
for investors in these new facilities, and generally inconsistent with
the energy independence goals of EISA, for these new facilities to only
be guaranteed two years of participation in the RFS2 program. We
propose that the statute be interpreted to mean that fuel from such
qualifying facilities, regardless of date of startup of operations,
would be exempt from the 20% GHG threshold requirement for the same
time period as facilities that commence construction prior to December
19, 2007, provided that such plants commence construction prior to
December 31, 2009, complete such construction in a reasonable amount of
time, and continue to burn only natural gas, biomass, or a combination
thereof. Therefore, we believe that they should be treated like
grandfathered facilities. We seek comment, however, on the alternative
in which after 2009, such plants must meet the 20% threshold in order
to generate RINs for renewable fuel produced.
    Based on our survey of ethanol plants in operation, as well as
those not yet in operation but which commenced construction prior to
December 19, 2007, it is likely that production capacity of ethanol
from all such facilities will reach 15 billion gallons. (See Section
<IP_ADDRESS> of the DRIA.) This volume of ethanol will be excluded from
having to meet the 20% GHG threshold by the grandfathering and deemed
compliant provisions of EISA.\8\ For ease of reference, we will refer
to both these provisions as the ``exemption provisions'' of EISA.
---------------------------------------------------------------------------

    \8\ The grandfathering and deemed compliant provisions in EISA
sections 202 and 210 do not apply to the advanced biofuels, biomass-
based diesel or cellulosic biofuel standards for which the Act
requires a 50 or 60% GHG reduction threshold to be met regardless of
when the facilities producing such fuels are constructed.
---------------------------------------------------------------------------

    EISA does not define the term ``new facility'' and, as mentioned
above, does not clarify whether ``deemed compliant'' facilities have
that status for only 2008 and 2009, or for a longer time period. EPA
seeks, in interpreting these terms, to avoid long-term backsliding with
respect to environmental performance and to also provide a level
playing field for future investments. Thus, we want to avoid incentives
that would allow overall GHG performance to worsen via expansion at
older plants with poorer GHG performance or by modifications such as
switches to more polluting process heat sources, such as coal. At the
same time, we also want to offer protection for historical business
investments that were made prior to enactment of EISA, and we want
future significant investments to meet the GHG reduction standards of
the Act. Finally we want to avoid excessive case-by-case decision
making where possible, and seek instead a rule that offers ease of
implementation while providing certainty to EPA and the regulated
industry.
    We are proposing one basic approach to the exemption provisions and
seeking comment on five additional options. In fashioning the basic
proposal and alternative options for exempted facilities, we considered
aspects of exemption approaches elsewhere in the CAA and EPA
regulations to evaluate whether they would foster the above-described
objectives. We are only looking to these other provisions for guidance
and are not bound to follow any already-established approach for a
different statutory provision (especially as those other provisions may
contain definitions that Congress did not incorporate here).
a. Definition of Commence Construction
    In defining ``commence'' and ``construction'', we wanted a clear
designation that would be broad enough to avoid facility-specific
issues, but narrow enough to prevent new facilities (i.e., post-
December 19, 2007) from being grandfathered. We believe that the
definitions of ``commence'' and ``Begin actual construction'' in the
Prevention of Significant Deterioration (PSD) regulations, which draws
upon definitions in the Clean Air Act, served this purpose. (40 CFR
52.21(b)(9) and (11)). Specifically, under the PSD regulations,
``commence'' means that the owner or operator has all necessary
preconstruction approvals or permits and either has begun a continuous
program of actual on-site construction to be completed in a reasonable
time, or entered into binding agreements which cannot be cancelled or
modified without substantial loss.'' Such activities include, but are
not limited to, ``installation of building supports and foundations,
laying underground pipe work and construction of permanent storage
structures.'' We have added language to the definition that is
currently not in the PSD definition with respect to multi-phased
projects. We are proposing that for multi-phased projects, commencement
of construction of one phase does not constitute commencement of
construction of any later phase, unless each phase is ``mutually
dependent'' on the other on a physical and chemical basis, rather than
economic.
    The PSD regulations provide additional conditions beyond what
constitutes commencement. Specifically, the regulations require that
the owner or operator ``did not discontinue construction for a period
of 18 months or more and completed construction within a reasonable
time.'' (40 CFR 52.21(i)(4)(ii)(c). While ``reasonable time'' may vary
depending on the type of project, we believe that with respect to
renewable fuel facilities, a reasonable time to complete construction
is no greater than 3 years from initial commencement of construction.
We seek comment on the use of these definitions.
b. Definition and Boundaries of a Facility
    We propose that the grandfathering and deemed compliant exemptions
apply to ``facilities.'' Our proposed definition of this term is
similar in some respects to the definition of ``building, structure,
facility, or installation'' contained in the PSD regulations in 40 CFR
52.21. We have modified the definition, however, to focus on the
typical renewable fuel plant. We therefore propose to describe the
exempt ``facilities'' as including all of the activities and equipment
associated with the manufacture of renewable fuel which are located on
one property and under the control of the same person or persons.
c. Options Proposed in Today's Rulemaking
    We are proposing one basic approach to the grandfathering
provisions and seeking comment on five additional options. The basic
approach would provide an indefinite extension of grandfathering and
deemed compliant status but with a limitation of the exemption from the
20% GHG threshold to a baseline volume of renewable fuel. The five
additional options for which we seek comment are: (1) Expiration of
exemption for grandfathered and ``deemed compliant'' status when
facilities undergo sufficient changes to

be considered ``reconstructed''; (2) Expiration of exemption 15 years
after EISA enactment, industry-wide; (3) Expiration of exemption 15
years after EISA enactment with limitation of exemption to baseline
volume; (4) ``Significant'' production components are treated as
facilities and grandfathered or deemed compliant status ends when they
are replaced; and (5) Indefinite exemption and no limitations placed on
baseline volumes.
i. Basic Approach: Grandfathering Limited to Baseline Volumes
    We are proposing and seeking comments on an option which generally
limits the volume of any renewable fuel for which a grandfathered and
deemed compliant facility can generate RINs without complying with the
20% GHG reduction threshold to the capacity volume specified in a state
or Federal air permit or the greater of nameplate capacity or actual
production. This approach is similar to how we have treated small
refiner flexibilities under our other fuel rules. As a sub-option to
this approach, we also seek comment on a provision whereby facilities
would lose their status if they switch to a process fuel or feedstock
which results in an increase of GHG emissions.
(1) Increases in Volume of Renewable Fuel Produced at Grandfathered
Facilities due to Expansion
    For facilities that commenced construction prior to December 19,
2007, we are proposing to define the baseline volume of renewable fuel
exempt from the 20% GHG threshold requirement to be the maximum
volumetric capacity of the facility as allowed in any applicable state
air permit or Federal Title V operating permit. If the capacity of a
facility is not stipulated in such air permits, then the grandfathered
volume is the greater of the nameplate capacity of the facility or
historical annual peak production prior to enactment of EISA. Volumes
greater than this amount which may typically be due to expansions of
the facility which occur after December 19, 2007, would be subject to
the 20% GHG reduction requirement in order for the facility to generate
RINs for the incremental expanded volume. The increased volume would be
considered as if produced from a ``new facility'' which commenced
construction after December 19, 2007. Changes that might occur to the
mix of renewable fuels produced within the facility would remain
grandfathered as long as the overall volume fell within the baseline
volume.
    The baseline volume would be defined as above for deemed compliant
facilities with the exception that if the maximum capacity is not
stipulated in air permits, then the exempt volume would be the maximum
annual peak production during the plant's first three years of
operation. In addition, any production volume increase that is
attributable to construction which commenced prior to December 31, 2009
would be exempt from the 20% GHG threshold, provided that the facility
continued to use natural gas, biomass or a combination thereof for
process energy. Because deemed compliant facilities owe their status to
the fact that they use natural gas, biomass or a combination thereof
for process heat, we propose that their status would be lost, and they
would be subject to the 20% GHG threshold requirement, at any time that
they change to a process energy source other than natural gas and/or
biomass. Finally, because EISA limits deemed compliant facilities to
ethanol facilities, we propose that if there are any changes in the mix
of renewable fuels produced by the facility that only the ethanol
volume remain grandfathered. We solicit comment, however, on whether
the statute could be read to allow deemed compliant facilities to be
treated the same as grandfathered facilities by allowing a mix of
renewable fuels.
    Volume limitations contained in air permits may be defined in terms
of peak hourly production rates or a maximum annual capacity. If they
are defined only as maximum hourly production rates, they would need to
be converted to an annual rate. We believe that assuming 24-hour per
day production over 365 days per year (8,760 production hours) may
overstate nameplate capacity. In other regulations that pertain to
refinery operations, we have assumed a conversion rate of 90% of the
total hours in a year (7884 production hours). We seek comment on what
would be an appropriate conversion rate for renewable fuel facilities.
    The facility registration process (see Section III.C) would be used
to define the baseline volume for individual facilities. Owners and
operators would submit information substantiating the nameplate
capacity of the plant, as well as historical annual peak capacity if
such is greater than nameplate capacity. Subsequent expansions at a
grandfathered that result in an increase in volume would subject the
increase in volume to the 20% GHG emission reduction threshold (but not
the original baseline volume). Thus, any new expansions would need to
be designed to achieve the 20% GHG reduction threshold if the facility
wants to generate RINs for that volume. Such determinations would be
made on the basis of EPA-defined corn ethanol fuel pathway categories
that are deemed to represent such 20% reduction. As an alternative
approach to the greater of nameplate capacity or historical annual peak
capacity, we seek comment on an approach in which the baseline volume
is the actual volume of renewable fuel produced during the 2006
calendar year, where adequate data is available. Since there has been a
particularly high demand for ethanol in recent years, the use of 2006
data may be a fair representation of the real production capacity for
most plants. For plants that have not operated for an adequate shake
down period, the information in the state or Federal air permit could
be used and if this is not available, the nameplate capacity could be
used. As mentioned above, deemed compliant facilities would be exempt
from the 20% GHG threshold for baseline volumes and any additional
volumes regarding which construction commenced prior to December 31,
2009.
    We recognize, however, that some debottlenecking type changes may
cause increases in volume that are within a plant's inherent capacity.
To account for this in past regulations (e.g., 40 CFR 80.552 and 554)
we allowed for an increase of 5% above the baseline volume. Based on
conversations with builders of ethanol plants, however, such plants
have often been debottlenecked to exceed nameplate capacity by 20% and
sometimes much higher. We seek comment on whether we should allow a 10%
tolerance on the baseline volume for which RINs can be generated
without complying with the 20% GHG reduction threshold. Once that 10%
increase in volume is exceeded, the total increase above baseline
volume would then be subject to the 20% GHG reduction requirement in
order to generate RINs. We also seek comment on tolerance values in the
5 to 20% range.
    Our guiding philosophy of protecting historical business
investments that were made to comply with the provisions of RFS1 is
realized by allowing production increases within a plant's inherent
capacity. At the same time, the alternative of requiring compliance
with the 20% GHG reduction requirement for increases in volume above
10% over the baseline volume, would place new volumes from
grandfathered facilities on a level playing field with product from new
grass roots facilities. We believe that a level playing field for new
investments

is fair and consistent with the provisions of EISA.
(2) Replacements of Equipment
    If production equipment such as boilers, conveyors, hoppers,
storage tanks and other equipment are replaced, it would not be
considered construction of a ``new facility'' under this option of
today's proposal--the baseline volume of fuel would continue to be
exempt from the 20% GHG threshold. We discuss in a sub-option in
III.B.3.c.i(4) below in which if the replacement unit uses a higher
polluting fuel in terms of GHG emissions such replacement would render
the facility a new facility, and it would no longer be exempt from the
20% GHG threshold. We also solicit comment on an approach that would
require that if coal-fired units are replaced, that the replacement
units must be fired with natural gas or biofuel for the product to be
eligible for RINs that do not satisfy the 20% GHG threshold.
(3) Registration, Recordkeeping and Reporting
    Facility owner/operators would be required to provide evidence and
certification of commencement of construction. Owner/operators must
provide annual records of process fuels used on a BTU basis, feedstocks
used and product volumes. For facilities that are located outside the
United States (including outside the Commonwealth of Puerto Rico, the
U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the
Northern Mariana Islands) owners would be required to provide
certification as well. Since the definition of commencement of
construction includes having all necessary air permits, we would
require that facilities outside the United States to certify that such
facilities have obtained all necessary permits for construction and
operation required by the appropriate national and local environmental
agencies.
(4) Sub-Option of Treatment of Future Modifications
    We seek comment on a sub-option to the basic approach whereby
facilities would lose their grandfathered status if they switch to a
process fuel or feedstock which results in an increase of GHG
emissions. Some facilities may keep production volumes the same, but
change some or all of their feedstocks and energy sources, thus causing
a facility's product to fall further below the GHG performance for the
fuel pathway it produced at the time of enactment. We are therefore
seeking comment on an approach to limit the initial grandfathering only
for the fuel pathways that applied during 2007, when establishing the
volume baseline. Table III.B.3.c.i-1 below presents a ranking of fuels
and feedstock by fuel pathway in order of life cycle GHG emissions (as
discussed further in Section VI.E). (Table III.B.3.c.i-1 is based on
the table of fuel pathways contained in proposed regulations 40 CFR
80.1426.) Since the majority of facilities under consideration in this
portion of the rulemaking consists of ethanol plants, the table below
is limited to those types. Any changes to a facility that shift it to a
feedstock or use of a process energy source that results in higher GHG
emissions on the basis of the ranking categories in Table III.B.3.c.i-1
below would terminate the facility's grandfathered status.
    For example, an ethanol dry mill plant using natural gas for
process heat, as well as combined heat and power (CHP), is ranked as
``2'' in the table below. If the plant (or any portion of the plant)
switches to coal, it is ranked as ``4''. The higher number indicates an
increase in GHG emissions. Therefore in this example, the plant is
considered to have undertaken a modification that increases GHG
emissions, would render the facility as ``new'' and its grandfathered
status would end. Similarly, replacements of equipment that worsen GHG
emissions would also terminate grandfathered status. (For replacements
of equipment that do not change the fuel, nor result in an increase in
volume of renewable fuel, the grandfathered status of the plant would
remain, as discussed in Section III.B.3.c.i(2) above.)

    Table III.B.3.c.i-1--Groups of Renewable Fuel Facilities by Fuel
                      Feedstock and Process Energy
------------------------------------------------------------------------
                                      Production process
            Feedstock                    requirements          Ranking
------------------------------------------------------------------------
Starch from corn, wheat, barley,   --Process heat derived              1
 oats, rice, or sorghum.            from biomass.
Starch from corn, wheat, barley,   --Dry mill plant........            2
 oats, rice, or sorghum.
                                   --All process heat
                                    derived from natural
                                    gas.
                                   --Combined heat and
                                    power (CHP).
                                   --Fractionation of
                                    feedstocks.
                                   --Dried distillers
                                    grains.
Starch from corn, wheat, barley,   --Dry mill plant........            3
 oats, rice, or sorghum.
                                   --All process heat
                                    derived from natural
                                    gas.
                                   --Wet distillers grains.
Starch from corn, wheat, barley,   --Dry mill plant........            4
 oats, rice, or sorghum.
                                   --All or part of process
                                    heat derived from coal.
                                   --Combined heat and
                                    power (CHP).
                                   --Fractionation of
                                    feedstocks.
                                   --Membrane separation of
                                    ethanol.
                                   --Raw starch hydrolysis.
                                   --Dried distillers
                                    grains.
Starch from corn, wheat, barley,   --Dry mill plant........            5
 oats, rice, or sorghum.
                                   --All or part of process
                                    heat derived from coal.
                                   --Combined heat and
                                    power (CHP).
                                   --Fractionation of
                                    feedstocks.
                                   --Membrane separation of
                                    ethanol.
                                   --Wet distillers grains.
Sugarcane sugar..................  --Process heat derived              1
                                    from sugarcane bagasse.
Sugarcane sugar..................  --Process heat derived              2
                                    from natural gas.
Sugarcane sugar..................  --Process heat derived              3
                                    from coal.
------------------------------------------------------------------------

    We considered whether improvements at a facility (i.e., a fuel
switch from coal to natural gas) that still result in GHG performance
less than 20% should be credited to allow the facility to increase its
baseline volume. We decided not to propose such an approach because it
would take away an incentive for new plants that achieve greater than
20% GHG reduction to be constructed. As such, this would go against our
guiding principle of providing equal opportunities for future
investments in new plants.
    We recognize that there may be combinations of changes made at a
plant, some of which may worsen GHG emissions and others which may
cause an improvement and that not all such combinations can be taken
into account in a single table of fuel pathways. We seek comment on
ways to address such combinations.
ii. Alternative Options for Which We Seek Comment
(1) Facilities That Meet the Definition of ``Reconstruction'' Are
Considered New
    An alternative approach on which we are seeking comment would
consider whether a facility is effectively a ``new'' facility with
respect to the costs incurred in maintaining the plant over time.
Starting in 2010, we would require facility owners to report annually
(specifically by January 31) to EPA the expenses for replacements,
additions, and repairs undertaken at facilities since start up of the
facility through the year prior to reporting. The Agency would then
determine whether the degree of such activities warrants considering
the facility as effectively ``new''. That substantial rebuilding or
modernization may render an existing facility a new facility for
regulatory purposes finds analogies in other Clean Air Act regulatory
programs. For example, under the New Source Performance Standards
(NSPS) equipment that has been ``reconstructed'' as defined in 40 CFR
60.15 is considered new. Specifically, ``reconstruction'' is defined in
40 CFR 60.15 as ``the replacement of components of an existing facility
to such an extent that the fixed capital cost of the new components
exceeds 50% of the fixed capital cost that would be required to
construct a comparable entirely new facility. In addition to the NSPS
program, regulations such as the recently promulgated standards for
locomotive and marine engines (73 FR 25160; May 6, 2008) use a more
encompassing concept of reconstruction and consider a vessel to be new
if it is modified such that the value of the modifications exceeds 50%
of the value of the modified vessel. We are seeking comment on an
approach wherein upon the Agency's determination that costs of
replacements, repairs and upgrades conducted since the start-up of the
facility meet the test of ``reconstruction'' (i.e., the costs equal or
exceed 50% of what it would cost to rebuild), that the facility would
be considered effectively new, and would be subject to the 20% GHG
reduction requirements.
    The application of the definition of reconstruction in the NSPS
program occurs on an equipment-wide rather than on a plant-wide basis.
Under this option, we would apply the concept of a ``new'' facility on
a plant-wide basis similar to the approach we have taken in the
recently promulgated locomotive and marine standards. We believe that a
plant-wide approach is appropriate under RFS2 because it is not the
emissions from individual pieces of equipment that are being regulated.
Rather, the 20% GHG reduction standard applies to the renewable fuel
produced by the facility, and it is logical to consider all of the
equipment and structures at the facility involved in producing the
product in evaluating when a grandfathered facility has been
reconstructed. For these reasons, we believe that it would be
reasonable to apply the definition of ``new'' on a plant-wide basis.
Also, since upgrades, replacements and repairs will occur on an ongoing
basis we would consider rebuilding or reconstruction to occur over time
as the accumulation of all individual upgrades, replacements and
repairs.
    The NSPS definition also requires that it be ``technologically and
economically feasible for the reconstructed facility to meet applicable
standards that apply to new facilities.'' We do not think that EISA
requires this additional consideration, and also do not believe that
there is any compelling public policy justification for allowing a
reconstructed facility to continue to make renewable fuel that does not
meet the 20% GHG reduction standard based upon a claim that it is
technologically or economically infeasible. EPA's experience in the New
Source Review (NSR) program has demonstrated that it is extremely
difficult to clearly define what the terms ``technologically and
economically feasible'' mean. Aside from such definitional
difficulties, however, and as discussed in Section III.B.3.c.ii(2)
below, we believe that it is technologically feasible to meet the 20%
GHG reduction and with proper planning would be economically so, as
well. Therefore, this alternative option would not require such a
showing.
    Our assessment of whether a facility has been reconstructed would
be based on application of an appropriate cost model such as U.S.
Department of Agriculture's cost estimation model for construction of
new ethanol plants described by Kwiatkowski, J. et al. (2006) \9\.
Costs associated with the costs of repair and replacement of all parts
(including the labor associated with replacement and repair), would be
included in such calculation, regardless of the parts' intended useful
life. We seek comment on whether to also include costs associated with
employee labor related to routine maintenance, and also whether the
costs of repairs and replacements at the facility should be limited
only to the property directly related to the production of
biofuels.\10\
---------------------------------------------------------------------------

    \9\ Kwiatkowski, J.R., McAloon, A., Taylor, F. Johnson, D. 2006.
``Modeling the process and costs of fuel ethanol production by the
corn dry-grind process.'' Industrial Crops and Products 23 (2006)
288-296.
    \10\ We note that under NSPS the costs considered in determining
whether the definition of reconstruction has been met are restricted
to the capital costs of equipment and materials. The RFS2 program is
authorized from EISA which does not rely on the definitions of
``modification'' and ``routine maintenance and repair'' that are in
NSPS and other new source programs (e.g., New Source Review,
National Emission Standards for Hazardous Pollutants). Since our
application of the term ``reconstruction'' assumes that over time,
renewable fuel facilities may become substantially rebuilt it is
therefore appropriate to consider not only equipment replacements
but some of the labor costs associated with such replacements.
---------------------------------------------------------------------------

    Under this alternative option, the volume of renewable fuel that
qualifies for an exemption from the 20% GHG threshold would remain
fixed at the baseline volume as in the basic option described in
III.B.3(c)(i). However, we also seek comment on whether the volume of
renewable fuel at a grandfathered facility should be allowed to
increase above baseline volumes under this option. Specifically,
increases in volume could be exempt until such time as the entire plant
is deemed to have been reconstructed. In making such assessment and
applying the 50% test, the basis for the cost of a ``comparable
entirely new facility'' would be a facility with the original baseline
volume. For example, if an existing plant has a 100 million gallon per
year capacity and expands its volume to 120 million gallons per year,
reconstruction would occur if the costs incurred over time equal or
exceed 50% of the cost of a comparable 100 million gallon per year
facility.
    Under this alternative option, owner/operators or other responsible
parties would be required to provide records of costs incurred for
additions, replacements, and repairs that have

occurred since start-up. Such records would be provided on an annual
basis to EPA by May 31, and would include cumulative cost information
up to the prior year.
    We recognize that implementation of a facility-wide definition of
``reconstruction'' would be complex. Records of costs since start-up
may not be available for older facilities. Also, this alternative
option requires EPA enforcement staff to have sufficient financial
knowledge and experience to be able to evaluate the veracity of claims
regarding various types of expenditures. Calculating the costs of
repairs and replacements also poses challenges. Specifically, as
discussed above, we seek comment on whether the costs of routine
maintenance and repair should be included in such assessments. Were
such costs to be included, the determination of whether a replacement
or a repair is routine may not always be straightforward. In addition
to the recordkeeping and implementation issues, however, there is an
important policy consideration that is also significant. As in the case
of the NSR program, where many industry representatives have argued
that the program has a chilling effect on projects that could provide
environmental benefits, the reconstruction approach in this alternative
option could also provide a disincentive to implementation of safety
and environmental projects. Thus, this option could have the unintended
consequence of causing facilities to refrain from investing in projects
that will increase safety and efficiency and reduce emissions in order
to avoid triggering the 50% cost threshold. We seek comment on this
issue.
(2) Expiration Date of 15 Years for Exempted Facilities
    The above discussion highlights potential complexities in
implementing the option of considering reconstruction of exempted
facilities on a case-by-case basis. These include potential disputes
over how to calculate costs, as well as verifying records of
expenditures. In addition, that option has as a potential unintended
consequence, a disincentive for investment in projects that could
improve safety, efficiency and environmental performance. As an
alternative to the case-by case approach described above, this option
offers a practical way of implementing the reconstruction concept by
establishing an expiration date for all grandfathered and deemed
compliant facilities after a period of 15 years from enactment of EISA
(i.e., after December 31, 2022), regardless of when such facilities
commenced construction or began operation. Under such option, the
grandfathered and deemed compliant facilities would be subject to the
20% GHG threshold starting on January 1, 2023. Renewable fuel produced
from these facilities after this date would be required to comply with
the 20% threshold requirement in order to generate RINs.
    Based on our discussions with companies that construct ethanol
plants, we believe that facility owners will make decisions about
equipment replacements and technology upgrades that will continue to
improve the overall operating costs and energy efficiency of the plant
which ultimately lead to improvements in GHG emission performance as
well. In particular, energy-intensive processes in the plant are likely
to be replaced or upgraded to increase fuel and operating efficiency,
thus reducing operating costs of the plant, and increasing output.
Nilles (2006) reports that the first line of next-generation dry-grind
ethanol plants was built with mild steel components and that in 10 or
15 years, those components will need to be replaced entirely--most
likely with stainless steel. Of particular importance is that durable
materials as well as weaker materials all require maintenance and
replacement. As such, the components and equipment in ethanol
facilities are designed to be easily replaced and to allow simple
maintenance.\11\
---------------------------------------------------------------------------

    \11\ Nilles, D. 2006. ``Time Testing''; Ethanol Producer
Magazine, May, Vol. 12, No. 5.
---------------------------------------------------------------------------

    Using cost data contained in the U.S. Department of Agriculture's
cost estimation model for construction of new ethanol plants described
by Kwiatkowski, J. et al (2006), we calculated the cost of a
replacement of specific components in a hypothetical 100 million gallon
ethanol facility.12 13 We assumed that all steel tanks are
replaced with stainless steel tanks, and that specific combustion
equipment is replaced. Combining replacement costs with maintenance,
repairs, upgrades and supply costs (at 2% of the capital cost of the
facility per year), we calculated that over 15 years, the accumulated
costs range from 50% to 75% of the capital cost of an equivalent
facility.\14\
---------------------------------------------------------------------------

    \12\ Op Cit., Kwiatkowski, et al. (2006).
    \13\ Note to Docket (EPA-HQ-OAR-2005-0161), ``Analysis of Costs
of Replacements and Repairs at a Hypothetical 100 MM GPY Ethanol
Facility''; from Barry Garelick, Environmental Protection
Specialist, Assessment and Standards Division, Office of
Transportation and Air Quality; October 16, 2008.
    \14\ The USDA model gives the installed capitol cost of a 40
million GPY facility at approximately $60 million (2006 dollars).
The model also gives replacement costs of individual components
(steel tanks and the ring dryer) at about $13 million. Ongoing
maintenance costs are estimated at about $6 million per year.
---------------------------------------------------------------------------

    As discussed in Section <IP_ADDRESS> of the DRIA, per our conversations
with builders of ethanol plants, the changes and upgrades would be made
to improve competitiveness which will also improve operating and fuel
efficiency, thus tending to improve overall GHG performance of the
plant. The high price of natural gas has many ethanol plants
considering alternative fuel sources. Greater biofuel availability and
potential low life cycle green house gas emissions incentives may
further encourage ethanol producers to switch from fossil fuels for
process heat to biomass based fuels. In addition, ethanol producers may
consider energy saving changes to the ethanol production process.
Several process changes, including raw starch hydrolysis, corn
fractionation, corn oil extraction, and membrane separation, are likely
to be adopted to varying degrees. Since such changes would be
consistent with ultimately achieving the 20% GHG reduction required of
new facilities, we believe it is reasonable to expect that the newly
rebuilt facilities could meet the 20% GHG reduction threshold, based on
the results of a life cycle analysis.\15\
---------------------------------------------------------------------------

    \15\ Unless and until EPA conducts facility specific life cycle
analyses, however, compliance with the 20% GHG reduction threshold
would be made on the basis of fuel pathways as described in Section
III.D.2.
---------------------------------------------------------------------------

    We solicit further information and data, particularly evidence of
the types of replacements and ongoing maintenance that has occurred at
existing plants and what is projected to occur in the future. We will
evaluate such information along with other comments received during the
public comment period. We also solicit comment on whether a period
other than 15 years may be more appropriate.
    Under this approach, facilities that are exempted could expand
their volume of renewable fuel production, or could switch fuels or
feedstocks within the 15 year exemption period without fear of losing
their temporary exemption. While some of these activities have the
potential to worsen GHG emissions further below the 20% threshold
requirement, we believe that the imposition of an expiration date will
result in modifications to facilities that tend to increase the
efficiency and GHG performance of the plant rather than worsen them.
The need for compliance with the 20% threshold requirement by a date
certain would provide an incentive for owners and operators of

such plants to ensure the changes they make over time would bring them
into compliance with the 20% requirement at the end of the 15 year
period.
    While the facilities built in 2008 and 2009 would be in operation
for less than 15 years, the majority of ethanol plants will have been
in operation for 15 years or longer. As discussed in Section V.B.1,
approximately 15 billion gallons of corn ethanol production capacity is
currently online, idled or under construction. While some of these
plants/projects are currently on hold due to the economy, we anticipate
that this corn ethanol capacity will come online in the future under
the proposed RFS2 program. And the majority of these plants commenced
construction prior to 2008. We solicit comment, however, on whether
there should be a plant-specific expiration date of 15 years after
commencement of operations for deemed compliant facilities that
commenced construction in 2008 or 2009. Under this sub-option, the
expiration date for such plants would be 15 years from the time the
facility began operation, per registration made by the owner of the
facility.
    The option of limiting the exemption period to 15 years or other
specific time period offers certainty to industry for a 15 year period,
and also certainty that at the end of that time period they will be
subject to the 20% GHG reduction threshold. This time period could be
used by facility owners to ensure the facility will ultimately meet the
requirement. Finally, the option ensures that investments made in
equipment to comply with RFS1 requirements are protected with respect
to being fully depreciated for tax purposes.\16\ Furthermore, this
approach is easy to implement, and avoids case-by-case determinations
that can extremely be time-consuming, contentious, and costly for both
industry and EPA. In addition, because the exemption expiration date
would apply to all facilities, this option would provide no incentive
to delay modifications that increase energy efficiency, safety, or
improve environmental performance unlike the option described above
involving case-by-case consideration of reconstruction.
---------------------------------------------------------------------------

    \16\ Specifically, Table B-2 of IRS Publication 946, ``How To
Depreciate Property'' provides class lives and recovery periods for
use in computing depreciation for asset classes categorized by SIC
codes. Ethanol facilities (which are in SIC 28, Manufacture of
Chemical and Allied Products) is given a class life of 10 years. For
facilities that qualify for Modified Accelerated Cost Recovery
System (MACRS), the period is 7 years.
---------------------------------------------------------------------------

(3) Expiration Date of 15 Years for Grandfathered Facilities and
Limitation on Volume
    We also seek comment on a hybrid approach in which an expiration
date of 15 years is established for grandfathered and deemed compliant
facilities, but prior to then, the facilities' exemption from the 20%
GHG threshold would be limited to their baseline volumes, as in the
option described in Section III.B.3.c.
(4) ``Significant Production Units'' Are Defined as Facilities
    We seek comment on an approach in which ``facility'' would be
defined on the basis of ``significant production units''. For example,
the regulations regarding air toxic emissions for the miscellaneous
organic chemical manufacturing industry (which includes ethanol
manufacturing plants) under NESHAPS (40 CFR 2440(c)) apply to
miscellaneous chemical process units and heat exchangers within a
single facility. This option, therefore, would follow a similar
approach, and treat as new facilities subject to the 20% GHG reduction
requirement any new significant production units.
    Defining ``facility'' as a significant production unit would raise
the question of when an increase in volume due to the addition of
specific pieces of equipment should be considered augmenting current
production lines as opposed to being a new production line. We solicit
comment on this approach as well as how the term ``significant
production unit'' would need to be defined in the regulations to avoid
ambiguity. Any incidental increases in volume due to the addition of
pieces of equipment that would not constitute a new ``significant
production unit'' line would continue to be grandfathered, as would
increases in volume associated with changes made to debottleneck the
facility.
(5) Indefinite Grandfathering and No Limitations Placed on Volume
    Under our basic option, described in Section III.B.3.c.i, we would
interpret the statutory language to mean that expansions of
grandfathered facilities after enactment of EISA and which expand
volume beyond a plant's inherent capacity are not among those that
qualify for an exemption from the 20% GHG reduction requirement.
Otherwise, a facility that qualifies for grandfathering could be
expanded by any amount, and the additional volume would also receive
protection. We do not believe that this was the intent of the language
in EISA. Nevertheless, we recognize that there are alternative
interpretations of the statute and therefore seek comment on an
alternative that places no limitations on the volume of renewable fuel
from grandfathered or deemed compliant facilities. Under such option,
``new facility'' would be defined solely as a new ``greenfield'' plant.
 4. Renewable Biomass With Land Restrictions
    As explained in Section III.B.1.a, EISA lists seven types of
feedstock that qualify as ``renewable biomass'':
    1. Planted crops and crop residue.
    2. Planted trees and tree residue.
    3. Animal waste material and animal byproducts.
    4. Slash and pre-commercial thinnings.
    5. Biomass obtained from the vicinity of buildings at risk from
wildfire.
    6. Algae.
    7. Separated yard or food waste.

    EISA limits not only the types of feedstocks that can be used to
make renewable fuel, but also the land that several of these renewable
fuel feedstocks may come from. Specifically, EISA's definition of
renewable biomass incorporates land restrictions for planted crops and
crop residue, planted trees and tree residue, slash and pre-commercial
thinnings, and biomass from wildfire areas. EISA does not prohibit the
production of renewable fuel feedstock that does not meet the
definition of renewable biomass, nor does it prohibit the production of
renewable fuel from feedstock that does not meet the definition of
renewable biomass. It does, however, prohibit the generation of RINs
for renewable fuel made from feedstock that does not meet the
definition of renewable biomass, which includes not meeting the
associated land restrictions. The following sections discuss the
challenges of implementing the land restrictions contained in the
definition of renewable biomass and propose approaches for establishing
a workable implementation scheme.
a. Definitions of Terms
    EISA's descriptions of four feedstock types noted above--planted
crops and crop residue, planted trees and tree residue, slash and pre-
commercial thinnings, and biomass from wildfire areas--contain terms
that can be interpreted in multiple ways. The following sections
discuss our proposed interpretations for many of the terms contained in
EISA's definition of renewable biomass. In developing this proposal, we
consulted many sources, including the USDA, as well as stakeholder
groups, in order to

determine the range of possible interpretations for these different
terms. We have made every attempt to define these terms as consistently
with USDA and industry standards as possible, while keeping them
workable for purposes of program implementation. We seek comment on our
proposed definitions of important terms in the following sections.
i. Planted Crops and Crop Residue
    The first type of renewable biomass described in EISA is planted
crops and crop residue harvested from agricultural land cleared or
cultivated at any time prior to December 19, 2007, that is either
actively managed or fallow, and nonforested. We propose to interpret
the term ``planted crops'' to include all annual or perennial
agricultural crops that may be used as feedstock for renewable fuel,
such as grains, oilseeds, and sugarcane, as well as energy crops, such
as switchgrass, prairie grass, and other species, providing that they
were intentionally applied to the ground by humans either by direct
application as seed or nursery stock, or through intentional natural
seeding by mature plants left undisturbed for that purpose. Many energy
crops that could be used for cellulosic biofuel production, especially
perennial cover plants, are currently grown in the U.S. without
significant agronomic inputs such as fertilizer, pesticides, or other
chemical treatment. These crops may be introduced or indigenous to the
area in which they grow, and may have been originally planted decades
ago. We propose to include this type of vegetation as a planted crop
with the recognition that it may include some plants that were
intentionally naturally generated, i.e., resulted from natural seeding
from existing plants, and not planted through direct human
intervention. We believe that given the increasing importance under
RFS2 of biofuels produced from cellulosic feedstocks, such as
switchgrass and other grasses, such a definition is appropriate. We
note that because EISA contains specific provisions for planted trees
and tree residue from tree plantations, we propose that the definition
of planted crops in EISA exclude planted trees, even if they may be
considered planted crops under some circumstances.
    We further propose that ``crop residue'' be limited to the residue
left over from the harvesting of planted crops, such as corn stover and
sugarcane bagasse. However, we seek comment on an alternative
interpretation that would include as crop residue biomass from
agricultural land removed for purposes of invasive species control or
fire management. In that context ``crop residue'' would include any
biomass removed from agricultural land that facilitates crop
management, whether or not the crop itself is part of the residue.
    Our proposed regulations would restrict planted crops and crop
residue to that harvested from existing agricultural land. With respect
to what land would qualify as agricultural land, we first turned to the
mutually exclusive categories of land defined by USDA's Natural
Resources Conservation Service (NRCS) in its annual Natural Resources
Inventory (NRI), a statistical survey designed to estimate natural
resource conditions and trends on non-federal U.S. lands.\17\ The
categories used in the NRI are cropland, pastureland, rangeland, forest
land, Conservation Reserve Program (CRP) land, federal land, developed
land, and ``other rural land.'' We have chosen to include in our
proposed definition of agricultural land three of these land
categories--cropland, pastureland, and CRP land. Using the NRI
descriptions of these land types as models, we developed definitions
for these land types for this proposal.
---------------------------------------------------------------------------

    \17\ Natural Resource Conservation Service, USDA, ``Natural
Resources Inventory 2003 Annual NRI,'' February 2007. Available at
http://www.nrcs.usda.gov/technical/NRI/2003/Landuse-mrb.pdf.
---------------------------------------------------------------------------

    We propose to define cropland as land used for the production of
crops for harvest, including cultivated cropland for row crops or
close-grown crops and non-cultivated cropland for horticultural crops.
Corn, wheat, barley, and soybeans are renewable fuel feedstocks that
would be grown on cropland. We propose to define pastureland as land
managed primarily for the production of indigenous or introduced forage
plants for livestock grazing or hay production, and to prevent
succession to other plant types. Under this proposed definition, land
would qualify as pastureland if it is maintained for grazing or hay
production and not allowed to develop greater ecological diversity.
Switchgrass is one example of a renewable fuel feedstock that could be
grown on pastureland.
    We also propose that CRP land be counted as ``agricultural land''
under RFS2. The CRP is administered by USDA's Farm Service Agency and
is designed to promote restoration of environmentally sensitive lands
by offering annual rental payments in return for removing land from
cultivation over a period of several years. To qualify for the CRP,
land had to have been used for agricultural production for at least
three years prior to entering the program. For this reason, we believe
it is appropriate to propose that CRP land be included under the rubric
of agricultural land.
    In addition, we seek comment on whether rangeland should be
included as agricultural land under RFS2. Rangeland is land on which
the indigenous or introduced vegetation is predominantly grasses,
grass-like plants, forbs or shrubs and which--unlike cropland or
pastureland--is predominantly managed as a natural ecosystem. Given the
relative lower degree of management of such lands, it is questionable
whether any rangeland should qualify as ``actively managed'' under EISA
(a general discussion on our proposed interpretation of the term
``actively managed'' is presented later in this section). On the other
hand, we understand that there is frequently some degree of management
on such lands, such as controlling invasive species, managing grazing
rates, fencing, etc.
    Therefore, we believe that there may be merit in allowing planted
crops and crop residue from rangeland to qualify as renewable biomass
under this program. This would allow, for example, existing switchgrass
or native grasses on rangeland to be used for renewable fuel production
that qualifies for RIN generation under this program. However, we are
not proposing to include rangeland as agricultural land due to our own
implementation concerns as well as issues raised by stakeholders over
the potential for providing any incentive for increased crop production
in rangeland areas. We seek comment on the issue and on the points
raised in the following discussion.
    Allowing rangeland to qualify as agricultural land under RFS2 would
make millions of acres of additional non-cropland, non-forested land
qualify for renewable fuel feedstock production in the U.S. This
additional land could be important to support future expansion of
dedicated energy crops, such as switchgrass and tall prairie grass,
which currently grow or could grow on such lands. The availability of
rangeland could alleviate some of the competition on cropland and
pastureland for space to grow crops for biofuel feedstocks, thereby
allowing continued growth of food crops on land best suited for that
specific purpose. It would also provide rangeland owners with the
potential for increased revenues from their lands by producing
feedstocks for renewable fuel, and decrease the pressure for such lands
to be converted to cropland for food crop production.

    However, we recognize that rangeland is a term that can be used to
describe a wide variety of ecosystems, including certain grasslands,
savannas, wetlands, deserts, and even tundra. These types of ecosystems
represent land that at best could serve only marginally well for
producing renewable fuel feedstocks, and at worst could suffer
significantly if intensive agricultural practices were imposed upon
them for purposes of producing crops. We also recognize that if we were
to include rangeland as agricultural land under RFS2, there is a risk
that some rangeland, including native grasslands and shrublands, could
be converted to produce monoculture crops. We raise these concerns for
two reasons. First, certain rangeland cannot be used sustainably for
agricultural crop production, and any such short-term use could
seriously diminish the long-term potential of these lands to be used
for less-intensive forage production or even to return to their
previous ecological state. Second, conversion of relatively undisturbed
rangeland to the production of annual crops could in some cases result
in large releases of GHGs that have been stored in the soil. EPA
believes that Congress enacted the renewable biomass definition in part
to minimize GHG releases from land conversion, a goal that could be
undermined by conversion of rangeland to intensive crop production
under RFS2. On the other hand, it may be argued that while GHGs would
be emitted initially, planting dedicated energy crops rather than food
crops on such land could yield more positive than negative results over
time. Such could be the case if the alternative were to grow energy
crops on cropland, consequently displacing food crops to other lands,
either in the U.S. or abroad. This displacement could lead to overall
higher direct and indirect GHG emissions. EPA solicits comment on the
potential GHG effects if rangeland were included as eligible
agricultural land under RFS2. We are especially interested in data that
could help us to quantify such impacts.
    While enforcement of the overall renewable biomass provisions under
the final RFS2 program is expected to be challenging, it is possible
that including rangeland as qualifying agricultural land under the RFS2
program would increase enforcement complexity. As discussed later in
this section, in order to qualify as renewable biomass under RFS2,
agricultural products must come from agricultural land that was cleared
or cultivated at any time prior to enactment of EISA, and either
actively managed or fallow, and nonforested. We believe that evidence
of past intensive use and management of rangeland may be considerably
more rare, and considerably less definitive, than for other types of
agricultural land. In addition, given the continuous, open nature of
some rangeland, there would likely be difficulty in identifying the
precise boundaries of a parcel of qualifying rangeland. EPA seeks
comment on these issues.
    We thus seek comment on whether or not we should include rangeland
in the definition of ``existing agricultural land'' in the final RFS2
program, as well as comment on whether or not the benefits of including
rangeland exceed the disadvantages. We also seek comment on how best to
define rangeland, and whether we can define rangeland in a meaningful
way such that sensitive ecosystems that may generally be described as
rangeland can be protected from cultivation for renewable fuel
feedstock production.
    Furthermore, EPA solicits comment on an alternative option that
would include rangeland as agricultural land, but that would interpret
the EISA ``actively managed'' criterion in the renewable biomass
definition (again, discussed later in this section) to limit the types
of planted crops or crop residues from specific parcels of land that
can qualify as renewable biomass by reference to the type of management
(cropland, pastureland, or rangeland) being practiced on the date EISA
was enacted. For example, if at some point in the future corn or other
row crops are grown on land that was pastureland or rangeland when EISA
was enacted, such row crops would not qualify as renewable biomass
under RFS2. This approach could thus reduce the incentives for
pastureland and rangeland owners to convert their land to cropland. We
believe that this approach could have less environmental harm than
allowing unrestricted use of qualifying rangeland for the production of
crops for renewable fuel production.
    While our proposed implementation approach and alternatives are
presented later in this section, it is important to note here that the
principal drawback to this alternative option involves its
implementation and enforcement. This approach would require that land
types (again, cropland, pastureland, or rangeland) be identified as of
the date of EISA enactment in order to determine which feedstocks grown
on such land would qualify as renewable biomass. In practical terms,
such an approach may mean, for example, that a renewable fuel producer
would need to be able to identify not only whether a given shipment of
corn was grown on agricultural land cleared or cultivated prior to
enactment of EISA, but also that the land was not previously
pastureland or rangeland that had been converted to cropland after
enactment of EISA. If it was, it would not qualify as renewable
biomass. We are concerned that adding this additional feedstock
verification criterion to those already contained in this proposal
could render the program unworkable and unenforceable. However, we
invite comment on this option, and specifically request comment on how
this option could be implemented in a workable and enforceable manner.
    In keeping with the statutory definition for renewable biomass, we
propose to include in our definition of existing agricultural land the
requirement that the land was cleared or cultivated prior to December
19, 2007, and that, since December 19, 2007, it has been continuously
actively managed (as agricultural land) or fallow, and nonforested. We
believe the language ``cleared or cultivated at any time'' prior to
December 19, 2007, describes most cultivable land in the U.S., since so
much of the country's native forests and grasslands were cleared in the
17th, 18th, and 19th centuries, if not before, for agriculture. We
further believe that land that was cropland, pastureland, or CRP land
on December 19, 2007, would automatically satisfy this particular
criterion, and that therefore it is not of significant concern from an
implementation or enforcement perspective.
    In the event that we were to include rangeland as agricultural land
under the final RFS2 program, satisfying the ``cleared or cultivated''
criterion could pose significant challenges. Some rangeland has never
been cleared or cultivated, or may have been cleared or cultivated
prior to December 19, 2007, but no evidence exists to confirm this.
Therefore, we could not assume that it would necessarily meet the
``cleared or cultivated'' criterion. For instance, grasslands in the
Midwest and West that during the Dust Bowl of the 1930s had been used
for cultivation could meet this criterion, but other western grasslands
and prairies used for cattle grazing may not. We seek comment on how
best to verify that rangeland to be used for renewable fuel feedstock
production was cleared or cultivated at some point prior to December
2007. We also seek comment on whether the challenge associated with
applying this criterion to rangeland is sufficient (alone or combined
with the concerns raised earlier about the inclusion of rangeland in
the definition of agricultural land) to exclude rangeland

from the final definition of agricultural land.
    We believe that the more restrictive, and therefore more important,
criteria is whether agricultural land is actively managed or fallow,
and nonforested, per the statutory language. We propose to interpret
the phrase ``that is actively managed or fallow, and nonforested'' as
meaning that land must have been actively managed or fallow, and
nonforested, on December 19, 2007, and continuously thereafter in order
to qualify for renewable biomass production. We believe this
interpretation of the legislative language is reasonable and
appropriate for the following reason. The EISA language uses the
present tense (``is actively managed * * *'') rather than the past
tense to describe qualifying agricultural land. We interpret this
language to mean that at the time the planted crops or crop residue are
harvested (i.e., now or at some time in the future), the land from
which they come must be actively managed or fallow, and nonforested.
However, assuming that the land was cleared or cultivated at some point
in time, then any land converted to agricultural land after December
19, 2007, and used to produce crops or crop residue would inherently
meet the definition of ``is actively managed or fallow, and
nonforested,'' and the EISA land restriction for planted crops and crop
residue would have little meaning (except in cases where it could be
established that the land in question had never been cleared or
cultivated). We believe that in order for this provision to have
meaning, we must require that agricultural land remain ``continuously''
either actively managed or fallow, and nonforested, since December 19,
2007. In this way, the upper bound on acreage that qualifies for
planted crop and crop residue production under RFS2 would be limited to
existing agricultural land--cropland, pastureland, or CRP land--as of
December 19, 2007, and the phrase ``is actively managed or fallow, and
nonforested'' would be interpreted in a meaningful way.
    We propose that ``actively managed'' would mean managed for a
predetermined outcome as evidenced by any of the following: sales
records for planted crops, crop residue, or livestock; purchasing
records for land treatments such as fertilizer, weed control, or
reseeding; a written management plan for agricultural purposes;
documentation of participation in an agricultural program sponsored by
a Federal, state or local government agency; or documentation of land
management in accordance with an agricultural certification program.
Examples of government programs or product certification programs that
would indicate active agricultural land management include USDA's
certified organic program or the Federal Crop Insurance program.
    We realize that it may be difficult to conclude that certain land
has been actively managed continuously since December 2007 based solely
on the existence of receipts for fertilizer or seed. However, we have
included sales and purchasing records in the list of written
documentation that could be used to indicate active management due to
the fact that there may be qualifying land that is not registered with
any formal agricultural program, for which the owner does not receive
government benefits, and for which no written management plan exists
(or existed as of December 2007). We believe this may be the case
especially for pastureland from which no crops are harvested or sold.
Other evidence that could be used regarding the consistent management
of pastureland since December 2007 are records associated with the sale
of livestock that grazed on the land. We seek comment on our proposal
to include relevant records of sales and purchasing as adequate
documentation to prove that land was actively managed since December
2007 and whether there may be other records, such as tax or insurance
records, which could satisfy this requirement more effectively.
    The term ``fallow'' is generally used to describe cultivated land
taken out of production for a finite period of time. We believe it may
be argued that fallow land is actively managed land because there is a
clear purpose or goal for taking the land out of production for a
period of time (e.g., to conserve soil moisture). Nonetheless, because
the EISA language clearly identifies a difference between actively
managed agricultural land and fallow agricultural land, we propose to
define fallow to mean agricultural land that is intentionally left idle
to regenerate for future agricultural purposes, with no seeding or
planting, harvesting, mowing, or treatment during the fallow period.
While fallow agricultural land is characterized by a lack of activity
on the land, we believe that the decision to let land lie fallow is
made deliberately and intentionally by a land owner or farmer such that
there should be documentation of such intent. We seek comment on this
assumption and on whether there are other means of verifying whether
land was fallow, particularly as of December 2007. We also seek comment
on whether we should specify in the regulations a time period after
which land that is not actively managed for agricultural purposes
should be considered to have been abandoned for agriculture (and not
eligible for renewable biomass production under RFS2), as opposed to
being left fallow. If specifying such a time limit is appropriate, we
seek comment on what the time period should be, and if there should be
a distinction between allowable fallow periods for different types of
agricultural land.
    Finally, in order to define the term ``nonforested,'' we first
propose to define the term ``forestland'' as generally undeveloped land
covering a minimum area of 1 acre upon which the predominant vegetative
cover is trees, including land that formerly had such tree cover and
that will be regenerated. We are also proposing that forestland would
not include tree plantations. Under this proposal, ``nonforested'' land
would be land that is not forestland. We believe this definition is
sufficient to make distinctions between forestland and land that is
considered nonforested in the field. However, we seek comment on
whether we should incorporate into our definition of forestland more
quantitative descriptors, such as a minimum percentage of canopy cover
or minimum or maximum tree height, to help clarify what would be
considered forestland. For example, the NRI definition of forestland
includes a minimum of twenty-five percent canopy cover. We also seek
comment on whether the one-acre minimum size designation is
appropriate.
ii. Planted Trees and Tree Residue
    The definition of renewable biomass in EISA includes planted trees
and tree residue from actively managed tree plantations on non-federal
land cleared at any time prior to December 19, 2007, including land
belonging to an Indian tribe or an Indian individual, that is held in
trust by the United States or subject to a restriction against
alienation imposed by the United States. We propose to define the term
``planted trees'' to include not only trees that were established by
human intervention such as planting saplings and artificial seeding,
but also trees established from natural seeding by mature trees left
undisturbed for such a purpose. We understand that, depending on the
particular conditions at a plantation, certain trees in a stand may be
harvested, while others are maintained, for the express purpose of
naturally regenerating new trees. We believe that trees established in
such a fashion, and which meet the conditions for planted trees in
every other way, should not be

excluded from qualifying as renewable biomass under RFS2.
    Rather than using the term ``tree residue,'' we propose to use the
term ``slash'' in our regulations as a more descriptive, but otherwise
synonymous, term. According to the Dictionary of Forestry (1998, p.
168), slash is ``the residue, e.g., treetops and branches, left on the
ground after logging or accumulating as a result of a storm, fire,
girdling, or delimbing.'' We believe that this substitution will
simplify our regulations, since paragraph (iv) of the EISA definition
of renewable biomass also uses the term ``slash.'' Furthermore, the
term ``slash'' is a common term that has a specific meaning to
industry. As noted earlier, we have attempted to define terms in RFS2
using existing and commonly understood definitions to the extent
possible. The term ``slash'' is more descriptive than ``tree residue,''
and yet in practice means the same thing, so we are proposing to use it
rather than ``tree residue.'' We also propose to clarify that slash can
include tree bark and can be the result of any natural disaster,
including flooding.
    In concert with our proposed definition for ``planted trees,'' we
propose to define a ``tree plantation'' as a stand of no fewer than 100
planted trees of similar age and comprising one or two tree species, or
an area managed for growth of such trees covering a minimum of 1 acre.
Given that only trees from a tree plantation may be used as renewable
biomass under RFS2, we believe that the definition should be clear and
easily applied in the field. We recognize that this proposed definition
is more specific than the Dictionary of Forestry's definition of ``tree
plantation,'' which is ``a stand composed primarily of trees
established by planting or artificial seeding.'' We seek comment on all
aspects of our proposed definition of tree plantation.
    We also propose to apply the same management restrictions on tree
plantations as on agricultural land and to interpret the EISA language
as requiring that to qualify for renewable biomass production under
RFS2, a tree plantation must have been cleared at any time prior to
December 19, 2007, and continuously actively managed since December 19,
2007. Similar to our proposal for actively managed agricultural land,
we propose to define the term ``actively managed'' in the context of
tree plantations as managed for a predetermined outcome as evidenced by
any of the following: Sales records for planted trees or slash;
purchasing records for seeds, seedlings, or other nursery stock; a
written management plan for silvicultural purposes; documentation of
participation in a silvicultural program sponsored by a Federal, state
or local government agency; or documentation of land management in
accordance with an agricultural or silvicultural product certification
program. Silvicultural programs such as those of the Forest Stewardship
Council, the Sustainable Forestry Initiative, the American Tree Farm
System, or USDA are examples of the types of programs that could
indicate actively managed tree plantations.
iii. Slash and Pre-Commercial Thinnings
    The EISA definition of renewable biomass includes slash and pre-
commercial thinnings from non-federal forestlands, including
forestlands belonging to an Indian tribe or an Indian individual, that
are held in trust by the United States or subject to a restriction
against alienation imposed by the United States. It excludes slash and
pre-commercial thinnings from forests or forestlands that are
ecological communities with a global or State ranking of critically
imperiled, imperiled, or rare pursuant to a State Natural Heritage
Program, old growth forest, or late successional forest.
    As described in Sec. III.B.4.a.i of this preamble, our proposed
definition of ``forestland'' is generally undeveloped land covering a
minimum area of 1 acre upon which the primary vegetative species are
trees, including land that formerly had such tree cover and that will
be regenerated. Also as noted in Sec. III.B.4.a.ii of this preamble, we
propose to adopt the definition of slash listed in the Dictionary of
Forestry. As for ``pre-commercial thinnings,'' the Dictionary of
Forestry defines the act of such thinning as ``the removal of trees not
for immediate financial return but to reduce stocking to concentrate
growth on the more desirable trees.'' \18\ Because what may now be
considered pre-commercial may eventually be saleable as renewable fuel
feedstock, we propose not to include any reference to ``financial
return'' in our definition, but rather to define pre-commercial
thinnings as those trees removed from a stand of trees in order to
reduce stocking to concentrate growth on more desirable trees. We
propose to include diseased trees in the definition of pre-commercial
thinnings due to the fact that they can threaten the integrity of an
otherwise healthy stand of trees, and their removal can be viewed as
reducing stocking to promote the growth of more desirable trees. We
seek comment on whether our definition of pre-commercial thinnings
should include a maximum diameter and, if so, what the appropriate
maximum diameter should be.
---------------------------------------------------------------------------

    \18\ Helms, John, ed. ``The Dictionary of Forestry.'' Bethesda,
MD: Society of American Foresters, 2003.
---------------------------------------------------------------------------

    We understand that the State Natural Heritage Programs referred to
in EISA are those comprising a network associated with NatureServe, a
non-profit conservation and research organization. The network includes
local programs in each of the 50 United States, other U.S. territories
and regions including the Navajo Nation and Tennessee Valley Authority,
eleven Canadian provinces and territories, and eleven Latin American
countries. Individual Natural Heritage Programs collect, analyze, and
distribute scientific information about the biological diversity found
within their jurisdictions. As part of their activities, these programs
survey and apply NatureServe's rankings, such as critically imperiled
(S1), imperiled (S2), and rare (S3) to species and ecological
communities within their respective borders. NatureServe meanwhile uses
data gathered by these Natural Heritage Programs to apply its global
rankings, such as critically imperiled (G1), imperiled (G2), or
vulnerable (the equivalent of the term ``rare,'' or G3), to species and
ecological communities found in multiple States or territories. We
propose to prohibit slash and pre-commercial thinnings from all forest
ecological communities with global or State rankings of critically
imperiled, imperiled, or vulnerable (``rare'' in the case of State
rankings) from being used for renewable fuel for which RINs may be
generated under RFS2. We seek comment on our interpretation that the
statutory language implies including global rankings determined by
NatureServe, including the ranking of vulnerable (G3), in the land
restrictions under RFS2 since State Natural Heritage Programs, which
were explicitly referenced in EISA, do not establish global rankings.
    The various state-level Natural Heritage Programs in the U.S. and
abroad differ in organizational affiliation, with some operated as
agencies of state or provincial government and others residing within
universities or non-profit organizations. According to the NatureServe
Web site, ``consistent standards for collecting and managing data allow
information from different programs to be shared and combined
regionally, nationally, and internationally. The nearly 800 staff from
across the network are experts in their fields, and include some of the
most knowledgeable field biologists and

conservation planners in their regions.'' Different Natural Heritage
Programs have different processes for initiating and performing surveys
of ecological communities. In many cases, the programs respond to
requests for environmental reviews or surveys from parties interested
in specific locations, oftentimes for a fee. They do not make available
for public consumption detailed information on the location of a ranked
ecological community in some cases to protect the communities
themselves and in other cases to protect private property interests.
Additionally, the datasets maintained by different Natural Heritage
Programs may not completely represent all of the vulnerable ecological
communities in their respective States or territories simply due to the
fact that surveys have not been performed for all areas.
    NatureServe, however, interacts with each of the State Natural
Heritage Programs to update their central database to include each
State program's ecological community rankings. We propose to use data
compiled by NatureServe and published in a special report to identify
``ecologically sensitive forestland.'' The report would list all forest
ecological communities in the U.S. with a global ranking of G1, G2, or
G3, or with a State ranking of S1, S2, or S3, and would include
descriptions of the key geographic and biologic attributes of the
referenced ecological community. The document would be incorporated by
reference into the definition of renewable biomass in the final RFS2
regulations, and the effect would be to identify specific ecological
communities from which slash and pre-commercial thinnings could not be
used as feedstock for the production of renewable fuel that would
qualify for RINs under RFS2. In the future, it may be necessary to
update this list as appropriate through notice and comment rulemaking.
    We will place a draft version of this document in the docket for
the proposed rule as soon as it is available. EPA solicits comment both
on this general incorporation-by-reference approach and on each
individual listing in the document. We also seek comment on whether EPA
should include in the document forest ecological communities outside of
the 50 United States (such as in Canada or Latin American countries)
that have natural heritage rankings of G1, G2, or G3 or S1, S2, or S3.
In addition, we request comment on other ways that EPA may be able to
provide the protections that Congress intended for important ecological
communities with state-level rankings pursuant to a State Natural
Heritage Program.
    To complete the definition of ``ecologically sensitive
forestland,'' we propose to include old growth and late successional
forestland which is characterized by trees at least 200 years old.\19\
We seek comment on this definition, including the proposed 200-year
tree age, on whether we should specify a process for determining when a
forest is ``characterized by'' trees of this or another age, and on
other ways to identify old growth or late successional forestland.
---------------------------------------------------------------------------

    \19\ Old-growth forest is defined in the Dictionary of Forestry
as ``the (usually) late successional stage of forest development.
Note: Old-growth forests are defined in many ways; generally,
structural characteristics used to describe old-growth forests
include (a) live trees: Number and minimum size of both seral and
climax dominants, (b) canopy conditions: Commonly including
multilayering, (c) snags: Minimum number of specific size, and (d)
down logs and coarse woody debris: Minimum tonnage and numbers of
pieces of specific size. Note: Old-growth forests generally contain
trees that are large for their species and site and sometimes
decadent (overmature) with broken tops, often a variety of trees
sizes, large snags and logs, and a developed and often patchy
understory * * *.''
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iv. Biomass Obtained From Certain Areas at Risk From Wildfire
    The EISA definition of renewable biomass includes biomass obtained
from the immediate vicinity of buildings and other areas regularly
occupied by people, or of public infrastructure, at risk from wildfire.
We propose to clarify in the regulations that ``biomass'' is organic
matter that is available on a renewable or recurring basis, and that it
must be obtained from within 200 feet of buildings, campgrounds, and
other areas regularly occupied by people, or of public infrastructure,
such as utility corridors, bridges, and roadways, in areas at risk of
wildfire. We propose to define ``areas at risk of wildfire'' as areas
located within--or within one mile of--forestland, tree plantations, or
any other generally undeveloped tract of land that is at least one acre
in size with substantial vegetative cover.
    It is our understanding that 100 to 200 feet is the minimum
distance recommended for clearing trees and brush away from homes and
other property in certain wildfire-prone areas, depending on slope and
vegetation.\20\ We propose that under RFS2, the term ``immediate
vicinity'' would mean within 200 feet of a given structure or area, but
we seek comment on the appropriateness of limiting the distance to
within 100 feet.
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    \20\ See Cohen, Jack. ``Reducing the Wildland Fire Threat to
Homes: Where and How Much?'' USDA Forest Service Gen.Tech.Rep. PSW-
GTR-173. 1999. See also U.S. Federal Emergency Management Agency
(FEMA) Web site http://www.fema.gov/hazard/wildfire/index.shtm.
---------------------------------------------------------------------------

    A great deal of work has been done to identify communities and
areas on the landscape in the vicinity of public lands that are at risk
of wildfire by States in cooperation and consultation with the U.S.
Forest Service, Bureau of Land Management, and other federal, State,
and local agencies and tribes. In order to take advantage of this work,
we seek comment on two possible implementation alternatives. The first
alternative would incorporate into our definition of ``areas at risk of
wildfire'' any communities identified as ``communities at risk''
through a process defined within the ``Field Guidance--Identifying and
Prioritizing Communities at Risk'' (National Association of State
Foresters, June 2003) and covered by a community wildfire protection
plan (CWPP) developed in accordance with ``Preparing a Community
Wildfire Protection Plan--A Handbook for Wildland-Urban Interface
Communities'' (Society of American Foresters, March 2004) and certified
by a State Forester or equivalent. We believe that it may make sense to
include communities with CWPPs in the definition of ``areas at risk of
wildfire'' since they represent specific areas around the U.S. that are
identified and agreed upon through a public process that includes local
and state representatives, federal agencies, and stakeholders.
Additionally, CWPP guidelines indicate that normally three entities
must mutually agree to the contents of the CWPPs: The applicable local
government, the local fire department or departments, and the state
entity responsible for forest management (State Forester or
equivalent). As of June 2008, there were roughly 52,000 total
``communities at risk'' and 5,000 ``communities at risk'' covered by a
CWPP.
    We seek comment on incorporating by reference into the final RFS2
regulations a list of ``communities at risk'' with an approved CWPP.
Similar to the document proposed for Natural Heritage Rankings, this
document would be incorporated by reference into the definition of
``areas at risk of wildfire'' in the final RFS2 regulations. Because
this list does not currently exist, EPA would be required to seek data
from each State in order to assemble the document. The effect of this
incorporation by reference would be to identify specific areas in the
U.S. at risk of wildfire and from which biomass obtained from the
immediate vicinity of buildings and other areas regularly occupied by
people, or of public infrastructure, could be easily identified

and documented as renewable biomass. In the future, it may be necessary
to update this list as appropriate through notice and comment
rulemaking.
    The second implementation approach on which we seek comment would
incorporate into our definition of ``areas at risk of wildfire'' any
areas identified as wildland urban interface (WUI) land, or land in
which houses meet wildland vegetation or are mixed with vegetation. The
concept of the WUI was established as part of the Healthy Forests
Restoration Act (Pub. L. 108-148) which provided a means for
prioritizing, planning, and executing hazardous fuels reduction
projects on federal lands. SILVIS Lab, in the Department of Forest
Ecology and Management and the University of Wisconsin, Madison, has,
with funding provided by the U.S. Forest Service, mapped WUI lands
based on data from the 2000 U.S. Census and U.S. Geological Survey
National Land Cover Data.\21\ We seek comment on whether and how best
to make use of this WUI map and data to help implement the land
restrictions for biomass obtained from areas at risk of wildfire under
RFS2.
---------------------------------------------------------------------------

    \21\ See http://silvis.forest.wisc.edu/projects/US_WUI_2000.asp.
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b. Issues Related to Implementation and Enforceability
    Incorporating the new definition of renewable biomass into the RFS2
program raises issues that we did not have to consider when designing
the RFS1 program. Under RFS1, the source of a renewable fuel feedstock
was not a central concern, and it was a relatively straightforward
matter to require all fuel made from specified renewable feedstocks to
be assigned RINs. However, with the terms ``renewable fuel'' and
``renewable biomass'' being defined differently under EISA, we must
consider potential issues related to implementation and enforcement to
ensure that renewable fuel for which RINs are generated is produced
from qualifying renewable biomass.
    Our proposed approach to the treatment of renewable biomass under
RFS2 is intended to define the conditions under which RINs can be
generated as well as the conditions under which renewable fuel can be
produced or imported without RINs. Both of these areas are described in
more detail below.
i. Ensuring That RINs Are Generated Only for Fuels Made From Renewable
Biomass
    The effect of adding EISA's definition of renewable biomass to the
RFS program is to ensure that renewable fuels are only allowed to
participate in the program if the feedstocks from which they were made
come from certain types of land. In the context of our regulatory
program, this means that RINs could only be generated if it can be
established that the feedstock from which the fuel was made came from
these types of lands. Otherwise, no RINs could be generated to
represent the renewable fuel produced or imported.
    We have considered the possibility that land restrictions contained
within the definition of renewable biomass may not, in practice, result
in a significant change in agricultural practices. For example, a
farmer wishing to expand his production by cutting forested land could
grow feedstock for renewable fuel on his existing agricultural land and
move production for food, animal feed, and fiber production to newly
cultivated land. While the EISA language is fairly clear about what
lands may be used for harvesting renewable fuel feedstocks, it does not
specifically address the potential for switching non-feedstock crops to
new lands. Our proposed options recognize the potential for this
behavior but do not attempt to prohibit it as we believe doing so would
be beyond our mandate under EISA. EPA believes that Congress would have
specifically directed EPA to regulate this practice if they intended
EPA to do so.
    Another major issue we have considered is the treatment of
domestically produced renewable fuel feedstocks versus imported
feedstocks and imported renewable fuel, since the new EISA language
does not distinguish between domestic renewable fuel feedstocks and
renewable fuel and feedstocks that come from abroad. Under RFS1, RINs
must be generated for imported renewable fuel by the renewable fuel
importer. Foreign renewable fuel producers may not participate as
producers in the program (i.e., may not generate RINs for their fuel)
unless they produce cellulosic biomass or waste-derived ethanol and
register with EPA. Because RFS1 does not define renewable fuel by its
source, assigning RINs to imported renewable fuel under RFS1 is a
straightforward responsibility of the importer.
    However, under RFS2, ensuring that the feedstock used to produce
imported renewable fuel meets the definition of renewable biomass
presents additional challenges to designing a program that can apply to
both domestic and imported renewable fuel. The options contained in
today's proposal attempt to address this additional constraint, as
discussed in Section III.B.4.d of this preamble.
ii. Ensuring That RINs Are Generated for All Qualifying Renewable Fuel
    Under RFS1, virtually all renewable fuel is required to be assigned
a RIN by the producer or importer. This requirement was developed and
finalized in the RFS1 rulemaking in order to address stakeholder
concerns, particularly from obligated parties, that the number of
available RINs should reflect the total volume of renewable fuel used
in the transportation sector in the U.S. and facilitate program
compliance. The only circumstances under which a batch of fuel is not
assigned a RIN in RFS1 is if the feedstock used to produce the fuel is
not among those listed in the regulatory definition of renewable fuel
at Sec.  80.1101(d), the producer or importer of the fuel produces or
imports less than 10,000 gallons per year, or the fuel is produced and
used for off-road or other non-motor vehicle purposes. As a result, we
believe that almost all renewable fuel produced or imported into the
U.S. is assigned RINs under the RFS1 program, and thus the number of
RINs available to obligated parties represents as accurately as
possible the volume of renewable fuel being used in the U.S.
transportation sector.
    EISA has dramatically increased the mandated volumes of renewable
fuel that obligated parties must ensure are produced and used in the
U.S. At the same time, EISA makes it more difficult for renewable fuel
producers to demonstrate that they have fuel that qualifies for RIN
generation by restricting qualifying renewable fuel to that made from
``renewable biomass,'' defined to include restrictions on the types of
land from which feedstocks may be harvested, as discussed in this
section. The inclusion of such land restrictions under RFS2 may mean
that, in some situations, a renewable fuel producer would prefer to
forgo the benefits of RIN generation to avoid the cost and difficulty
of ensuring that its feedstocks qualify for RIN generation. If a
sufficient number of renewable fuel producers acted in this way, it
could lead to a situation in which not all qualifying fuel is assigned
RINs, thus resulting in a short RIN market that could force obligated
parties into non-compliance. Another possible outcome would be that the
demand for and price of RINs would increase significantly, making
compliance by obligated parties more costly and difficult than
necessary and raising prices for consumers.
    In order to avoid situations in which obligated parties cannot
comply with

their annual RVOs and the volume mandates in EISA are not met, or
instances where the requirements are met but at an inflated price, we
believe that our proposal should ensure that RINs are generated for all
fuel made from feedstock that meets the definition of renewable biomass
and which meets the GHG emissions reduction thresholds set out in EISA.
This would require eliminating any incentive for renewable fuel
producers to avoid ascertaining where their feedstocks come from. As
described in Section III.B.4.d below, we propose to require a
demonstration of the type of land used to produce any feedstock used in
the production of renewable fuel, regardless of whether RINs are
generated or not, and to require that RINs be generated for all
qualifying fuel.
    However, we also seek comment on an alternative approach wherein a
renewable fuel producer would not be required to make any demonstration
with regard to the origin of feedstocks used in fuel production if the
fuel producer were not generating RINs. In this situation, we would
rely on the price of RINs in the market to encourage renewable fuel
producers to generate RINs where possible. This approach would have the
advantage of lessening the regulatory burden for renewable fuel
producers using feedstock that is not renewable biomass, and would
generally simplify the regulations relating to implementation of the
renewable biomass definition. The disadvantage to this approach, as
discussed above, would be the increased potential for a RIN shortage
caused by renewable fuel producers choosing not to generate RINs for
qualifying renewable fuel and a concurrent increase in the price of
RINs that do exist. Under such circumstances, it is likely that some
obligated parties could not acquire sufficient RINs for compliance
purposes, while others could comply but at an inflated cost.
    A further step that we could take to streamline not just the
implementation of the renewable biomass definition, but also the
tracking and trading of RINs, would be to remove the restriction
established under the RFS1 rule requiring that RINs be assigned to
batches of renewable fuel and transferred with those batches. Instead,
renewable fuel producers could sell RINs (with a K code of 2 rather
than 1) separately from volumes of renewable fuel. While this
alternative approach could potentially place obligated parties at
greater risk of market manipulation by renewable fuel producers, it
could also provide a greater incentive for producers to demonstrate
that the renewable biomass definition has been met for their
feedstocks. That is, by having the flexibility to sell RINs independent
from volume, producers could potentially command higher prices for
those RINs. This would make RINS more valuable to them, and provide an
incentive to generate as many RINs as possible. As a result, producers
would be motivated to demonstrate that their feedstocks meet the
renewable biomass definition. However, this approach could also
increase compliance costs for obligated parties. For further discussion
of this approach, see Section III.H.4.
c. Review of Existing Programs
i. USDA Programs
    To inform our approach for designing an implementation scheme for
the renewable biomass land restrictions under RFS2, we reviewed a
number of programs and models that track, certify, or verify
agricultural and silvicultural products or land use in the U.S. and
abroad. First we looked at several existing programs administered by
USDA that involve data collection from agricultural land owners,