investigation of the RIN transfer. A penalty might include both the
economic benefit of using invalid RINs and/or a gravity component.
    Although an obligated party would be liable under our proposed
program for a violation if it used invalid RINs for compliance
purposes, we would normally look first to the generator or seller of
the invalid RINs both for payment of penalty and to procure sufficient
valid RINs to offset the invalid RINs. However, if, for example, that
party was out of business, then attention would turn to the obligated
party who would have to obtain sufficient valid RINs to offset the
invalid RINs.
    We request comment on the need for additional prohibition and
liability provisions specific to the proposed RFS 2 program.

IV. What Other Program Changes Have We Considered?

    In addition to the regulatory changes we are proposing today in
response to EISA that are designed to implement the provisions of RFS2,
there are a number of other changes to the RFS program that we are
considering. These changes would be designed to increase flexibility,
simplify compliance, or address RIN transfer issues that have arisen
since the start of the RFS1 program. We have also investigated impacts
on small businesses and are proposing approaches designed to address
the impacts of the program on them.

A. Attest Engagements

    The purpose of an attest engagement is to receive third party
verification of information reported to EPA. An attest engagement,
which is similar to a financial audit, is conducted by a Certified
Public Accountant (CPA) or Certified Independent Auditor (CIA)
following agreed-upon procedures. Under the RFS1 program, an attest
engagement must be conducted annually. We propose to apply the same
provision to this proposed RFS2 rule. However, we seek comment on
whether there should be any flexibility provisions for those who own a
small number of RINs and what level of flexibility might be appropriate
(e.g., allowing those who own a small number of RINs to submit an
attest engagement every two years, rather than every year).

B. Small Refinery and Small Refiner Flexibilities

1. Small Refinery Temporary Exemption
    CAA section 211(o)(8), enacted as part of EPAct, provides a
temporary exemption to small refineries (those refineries with a crude
throughput of no more than 75,000 barrels of crude per day, as defined
in section 211(o)(1)(K)) through December 31, 2010.\44\ Accordingly,
the RFS1 program regulations exempt gasoline produced by small
refineries from the renewable fuels standard (unless the exemption was
waived), see 40 CFR 80.1141. EISA did not alter the small refinery
exemption in any way. Therefore, we intend to retain this small
refinery temporary exemption in the RFS2 program without change.
Further, as discussed below in Section IV.B.2.c, we are proposing to
continue one of the hardship provisions for small refineries provided
at 40 CFR 80.1141(e).
---------------------------------------------------------------------------

    \44\ Small refineries are also allowed to waive this exemption.
---------------------------------------------------------------------------

2. Small Refiner Flexibilities
    As mentioned above, EPAct granted a temporary exemption from the
RFS program to small refineries through December 31, 2010. In the RFS1
final rule, we exercised our discretion under section 211(o)(3)(B) and
extended this temporary exemption to the few remaining small refiners
that met the Small Business Administration's (SBA) definition of a
small business (1,500 employees or less company-wide) but did not meet
the Congressional small refinery definition as noted above.
    As explained in the discussion of our compliance with the
Regulatory Flexibility Act below in Section XII.C and in the Initial
Regulatory Flexibility Analysis in Chapter 7 of the draft RIA, we
considered the impacts of today's proposed regulations on small
businesses. Most of our analysis of small business impacts was
performed as a part of the work of the Small Business Advocacy Review
Panel (SBAR Panel, or ``the Panel'') convened by EPA, pursuant to the
Regulatory Flexibility Act as amended by the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA). The Final Report of the
Panel is available in the docket for this proposed rule. For the SBREFA
process, we conducted outreach, fact-finding, and analysis of the
potential impacts of our regulations on small businesses.
    During the SBREFA process, small refiners informed us that they
would need to rely heavily on RINs and/or make capital improvements to
comply with the RFS2 requirements. These refiners raised concerns about
the RIN program itself, uncertainty (with the required renewable fuel
volumes, RIN availability, and cost), and the desire for a RIN system
review access to RINs, and the difficulty in raising capital and
competing for engineering resources to make capital improvements.
    During the Panel process, EPA raised a concern regarding provisions
for small refiners in the RFS2 rule; and this rule presents a very
different issue than the small refinery versus small refiner concept
from RFS1. This issue deals with whether or not EPA has the authority
to provide a subset of small refineries (those that are operated by
small refiners) with an extension of time that would be different from,
and more than, the temporary exemption specified by Congress in section
211(o)(9) for small refineries (temporary exemption through December
31, 2010, with the potential for extensions of the exemption beyond
this date if certain criteria are met.). In other words, the temporary
exemption specified by Congress provided relief for those small
refiners that are covered by the small refinery provision; EPA believes
that providing these refiners with an additional exemption different
from that provided by section 211(o)(9) may be inconsistent with the
intent of Congress. Congress spoke directly to the relief that EPA may
provide for small refineries, including those small refineries operated
by small refiners, and limited it to a blanket exemption through
December 31, 2010, with additional extensions if the criteria specified
by Congress were met.
    The Panel recommended that EPA consider the issues raised by the
SERs and discussions had by the Panel itself, and that EPA should
consider comments on flexibility alternatives that would help to
mitigate negative impacts on small businesses to the extent allowable
by the Clean Air Act. A summary of further recommendations of the Panel
are discussed in Section XII.C of this preamble, and a full discussion
of the regulatory alternatives discussed and recommended by the Panel
can be found in the SBREFA Final Panel Report.

a. Extension of Existing RFS1 Temporary Exemption
    As previously stated, the RFS1 program regulations provide small
refiners who operate small refineries, as well as those small refiners
who do not operate small refineries, with a temporary exemption from
the standards through December 31, 2010. Small refiner SERs suggested
that an additional temporary exemption for the RFS2 program would be
beneficial to them in meeting the RFS2 standards; and the Panel
recommended that EPA propose a delay in the effective date of the
standards until 2014 for small entities, to the maximum extent allowed
by the statute.
    We have evaluated an additional temporary exemption for small
refiners for the required RFS2 standards, and we have also evaluated
such an exemption with respect to our concerns about our authority to
provide an extension of the temporary exemption for small refineries
that is different from that provided in CAA section 211(o)(9). As a
result, we believe that the limitations of the statute do not
necessarily allow us the discretion to provide an exemption for small
refiners only (i.e., small refiners but not small refineries) beyond
that provided in section 211(o)(9). However, it is important to
recognize that the 211(o)(9) small refinery provision does allow for
extensions beyond December 31, 2010, with two separate provisions
addressing extensions beyond 2010. These provisions are discussed below
in Section IV.B.2.c.
    Therefore, we are proposing to continue the temporary exemption
finalized in RFS1--through December 31, 2010--for small refineries and
all qualified small refiners. We also request comment on the
interpretation of our authority under the CAA and the appropriateness
of providing an extension to small refiners only beyond that authorized
by section 211(o)(9).
b. Program Review
    During the SBREFA process, the small refiner SERs also requested
that EPA perform an annual program review, to begin one year before
small refiners are required to comply with the program. We have slight
concerns that such a review could lead to some redundancy since EPA is
required to publish a notice of the applicable RFS standards in the
Federal Register annually, and this annual process will inevitably
include an evaluation of the projected availability of renewable fuels.
Nevertheless, some Panel members commented that they believe a program
review could be beneficial to small entities in providing them some
insight to the RFS program's progress and alleviate some uncertainty
regarding the RIN system. As we will be publishing a Federal Register
notice annually, the Panel recommended that we include an update of RIN
system progress (e.g., RIN trading, publicly-available information RIN
availability, etc.) in this annual notice.
    We propose to include elements of RIN system progress--such as RIN
trading and availability--in the annual Federal Register RFS2 standards
notice. We also invite comment on additional elements to include in
this review.
c. Extensions of the Temporary Exemption Based on Disproportionate
Economic Hardship
    As noted above, there are two provisions in section 211(o)(9) that
allow for an extension of the temporary exemption beyond December 31,
2010. One involves a study by the Department of Energy (DOE) concerning
whether compliance with the renewable fuel requirements would impose
disproportionate economic hardship on small refineries, and would grant
an extension of at least two years for a small refinery that DOE
determines would be subject to such disproportionate hardship. Another
provision authorizes EPA to grant an extension for a small refinery
based upon disproportionate economic hardship, on a case-by-case basis.
    We believe that these avenues of relief can and should be fully
explored by small refiners who are covered by the small refinery
provision. In addition, we believe that it is appropriate to consider
allowing petitions to EPA for an extension of the temporary exemption
based on disproportionate economic hardship for those small refiners
who are not covered by the small refinery provision (again, per our
discretion under section 211(o)(3)(B)); this would ensure that all
small refiners have the same relief available to them as small
refineries do. Thus, we are proposing a hardship provision for small
refineries in the RFS2 program, that any small refinery may apply for a
case-by-case hardship at any time on the basis of disproportionate
economic hardship per CAA section 211(o)(9)(B). While EISA stated (per
section 211(o)(9)(A)(ii)(I)) that the small refinery temporary
exemption shall be extended for at least two years for any small
refinery that the DOE small refinery study determines would face
disproportionate economic hardship in meeting the requirements of the
RFS2 program, we are not proposing this hardship provision given the
outcome of the DOE small refinery study (as discussed below).
    In the small refinery study, ``EPACT 2005 Section 1501 Small
Refineries Exemption Study'', DOE's finding was that there is no reason
to believe that any small refinery would be disproportionately harmed
by inclusion in the proposed RFS2 program. This finding was based on
the fact that there appeared to be no shortage of RINs available under
RFS1, and EISA has provided flexibility through waiver authority (per
section 211(o)(7)). Further, in the case of the cellulosic biofuel
standard, cellulosic biofuel allowances can be provided from EPA at
prices established in EISA (see proposed regulation section 80.1455).
DOE thus determined that no small refinery would be subject to
disproportionate economic hardship under the proposed RFS2 program, and
that the small refinery exemption should not be extended beyond
December 31, 2010. DOE noted in the study that, if circumstances were
to change and/or the RIN market were to become non-competitive or
illiquid, individual small refineries have the ability to petition EPA
for an extension of their small refinery exemption (as proposed at
draft regulation section 80.1441). We note that the findings of DOE's
small refinery study, and a consideration of EPA's ongoing review of
the functioning of the RIN market, could factor into the basis for
approval of such a hardship request.
    We are also proposing a case-by-case hardship provision for those
small refiners that do not operate small refineries, at draft
regulation section 80.1442(h), using our discretion under CAA section
211(o)(3)(B). This proposed provision would allow those small refiners
that do not operate small refineries to apply for the same kind of
extension as a small refinery. In evaluating applications for this
proposed hardship provision, it was recommended by the SBAR Panel that
EPA take into consideration information gathered from annual reports
and RIN system progress updates.
d. Phase-in
    The small refiner SERs suggested that a phase-in of the obligations
applicable to small refiners would be beneficial for compliance, such
that small refiners would comply by gradually meeting the standards on
an incremental basis over a period of time, after which point they
would comply fully with the RFS2 standards, however we have concerns
about our authority under the statute to allow for such a phase-in of
the standards. CAA section 211(o)(3)(B) states that the renewable fuel
obligation

shall ``consist of a single applicable percentage that applies to all
categories of persons specified'' as obligated parties. This kind of
phase-in approach would result in different applicable percentages
being applied to different obligated parties. Further, as discussed
above, such a phase-in approach would provide more relief to small
refineries operated by small refiners than that provided under the
small refinery provision. We do not believe that we can use our
discretion under the statute to allow for such a provision; however we
invite comment on the concept of a phase-in provision for all small
refiners.
e. RIN-Related Flexibilities
    The small refiner SERs requested that the proposed rule contain
provisions for small refiners related to the RIN system, such as
flexibilities in the RIN rollover cap percentage and allowing all small
refiners to use RINs interchangeably. Currently in the RFS program, up
to 20% of a previous year's RINs may be ``rolled over'' and used for
compliance in the following year. A provision to allow for
flexibilities in the rollover cap could include a higher RIN rollover
cap for small refiners for some period of time or for at least some of
the four standards. While the rollover cap is the means through which
we are implementing the limited credit lifetime provisions in section
211(o) of the CAA, and therefore cannot simply be eliminated, the
magnitude of the cap can be modified to some extent. Thus, there could
be an opportunity to provide appropriate flexibility in this area.
However, given the results of the DOE small refinery study, we do not
believe it would be appropriate to propose a change to the RIN rollover
cap for small refiners today. However, we request comment on the
concept of increasing the RIN rollover cap percentage for small
refiners. We also request comment on an appropriate level of that
percentage. For example, would a rollover cap of 50% for small refiners
be appropriate? Or, would an intermediate value between 20% and 50%,
such as 35%, be more appropriate?
    The Panel recommended that we take comment on allowing RINs to be
used interchangeably for small refiners, but not propose this concept
because under this approach small refiners would arguably be subject to
a different applicable percentage than other obligated parties.
However, this concept fails to require the four different standards
mandated by Congress (e.g., conventional biofuel could not be used
instead of cellulosic biofuel or biomass-based diesel), and is not
consistent with section 211(o) of the Clean Air Act. Thus, we are not
proposing this provision in this action, however we invite comment on
such an approach for small refiners.

C. Other Flexibilities

1. Upward Delegation of RIN-Separating Responsibilities
    Since the start of the RFS1 program on September 1, 2007, there
have been a number of instances in which a party who receives RINs with
a volume of renewable fuel is required to either separate or retire
those RINs, but views the recordkeeping and reporting requirements
under the RFS program as an unnecessary burden. Such circumstances
typically might involve a renewable fuel blender, a party that uses
renewable fuel in its neat form, or a party that uses renewable fuel in
a non-highway application and is therefore required to retire the RINs
(under RFS1) associated with the volume. In some of these cases, the
affected party may purchase and/or use only small volumes of renewable
fuel and, absent the RFS program, would be subject to few if any other
EPA regulations governing fuels.
    This situation will become more prevalent with the RFS2 program, as
EISA added diesel fuel to the RFS program. With the RFS1 rule, small
blenders (generally farmers and other parties that use nonroad diesel
fuel) blending small amounts of biodiesel were not covered under the
rule as EPAct mandated renewable fuel blending for highway use only.
EISA mandates certain amounts of renewable fuels to be blended into
transportation fuels--which includes nonroad diesel fuel. Thus, parties
that were not regulated under the RFS1 rule who only blend a small
amount of renewable fuel (and, as mentioned above, are generally not
subject to many of the EPA fuels regulations) would now be regulated by
the program.
    Consequently, we believe it may be appropriate, and thus we are
proposing today, to permit blenders who only blend a small amount of
renewable fuel to allow the party directly upstream to separate RINs on
their behalf. Such a provision would be consistent with the fact that
the RFS1 program already allows marketers of renewable fuels to assign
more RINs to some of their sold product and no RINs to the rest of
their sold product. We believe that this provision would eliminate
undue burden on small parties who would otherwise not be regulated by
this program. We are proposing that this provision apply to small
blenders who blend and trade less than 125,000 total gallons of
renewable fuel per year. We also request comment on whether or not this
threshold is appropriate.
    We envision that such a provision would be available to any blender
who must separate RINs from a volume of renewable fuel under Sec.
80.1429(b)(2). We also request comment on appropriate documentation to
authorize this upward delegation. This could be something such as a
document given to the supplier identifying the RIN separation that the
supplier would perform. The document could include sufficient
information to precisely identify the conditions of the authorization,
such as the volume of renewable fuel in question and the number of RINs
assigned to that volume. By necessity the document would need to be
signed by both parties, and copies retained as records by both parties,
since the supplier would then be responsible for these actions. The
supplier would then be allowed to retain ownership of RINs assigned to
a volume of renewable fuel when that volume is transferred, under the
condition that the RINs be separated or retired concurrently with the
transfer of the volume. We are proposing an annual authorization that
would apply to all volumes of renewable fuel transferred between two
parties for a given year (i.e., the two parties would enter into a
contract stating that the supplier has RIN-separation responsibilities
for all transferred volumes).
    We are proposing this provision solely for the case of blenders who
blend and trade less than 125,000 total gallons of renewable fuel per
year. A company that blends 100,000 gallons and trades 100,000 gallons
would not be able to use this provision. However, we request comment on
whether authorization to delegate RIN-separation responsibilities
should also be allowed for other parties as well.
2. Small Producer Exemption
    Under the RFS1 program, parties who produce or import less than
10,000 gallons of renewable fuel in a year are not required to generate
RINs for that volume, and are not required to register with the EPA if
they do not take ownership of RINs generated by other parties. We
propose to maintain this exemption under the RFS2 rule. However, we
request comment on whether the 10,000 gallon threshold should be higher
given that the total volume of renewable fuel mandated by EISA is
considerably higher than that required by the RFS1 program, or
conversely whether it should be lower given that the biomass-based
diesel standard is considerably lower than the

mandated volume for total renewable fuel.

D. 20% Rollover Cap

    EISA does not change the language in CAA section 211(o)(5) stating
that renewable fuel credits must be valid for showing compliance for 12
months as of the date of generation. As discussed in the RFS1 final
rulemaking, we interpreted the statute such that credits would
represent renewable fuel volumes in excess of what an obligated party
needs to meet their annual compliance obligation. Given that the
renewable fuel standard is an annual standard, obligated parties
determine compliance shortly after the end of the year, and credits
would be identified at that time. In the context of our RIN-based
program, we have accomplished the statute's objective by allowing RINs
to be used to show compliance for the year in which the renewable fuel
was produced and its associated RIN first generated, or for the
following year. RINs not used for compliance purposes in the year in
which they were generated will by definition be in excess of the RINs
needed by obligated parties in that year, making excess RINs equivalent
to the credits referred to in section 211(o)(5). Excess RINs are valid
for compliance purposes in the year following the one in which they
initially came into existence. RINs not used within their valid life
will thereafter cease to be valid for compliance purposes.
    In the RFS1 final rulemaking, we also discussed the potential
``rollover'' of excess RINs over multiple years. This can occur in
situations wherein the total number of RINs generated each year for a
number of years in a row exceeds the number of RINs required under the
RFS program for those years. The excess RINs generated in one year
could be used to show compliance in the next year, leading to the
generation of new excess RINs in the next year, causing the total
number of excess RINs in the market to accumulate over multiple years
despite the limit on RIN life. The rollover issue could in some
circumstances undermine the ability of a limit on credit life to
guarantee an ongoing market for renewable fuels.
    To implement the Act's restriction on the life of credits and
address the rollover issue, the RFS1 final rulemaking implemented a 20%
cap on the amount of an obligated party's RVO that can be met using
previous-year RINs. Thus each obligated party is required to use
current-year RINs to meet at least 80% of its RVO, with a maximum of
20% being derived from previous-year RINs. Any previous-year RINs that
an obligated party may have that are in excess of the 20% cap can be
traded to other obligated parties that need them. If the previous-year
RINs in excess of the 20% cap are not used by any obligated party for
compliance, they will thereafter cease to be valid for compliance
purposes.
    EISA does not modify the statutory provisions regarding credit
life, and the volume changes by EISA also do not change at least the
possibility of large rollovers of RINs for individual obligated
parties. Therefore, we propose to maintain the regulatory requirement
for a 20% rollover cap under the new RFS2 program. However, under RFS2
obligated parties will have four RVOs instead of one. As a result, we
are proposing that the 20% rollover cap would apply separately to all
four RVOs. We do not believe it would be appropriate to apply the
rollover cap to only the RVO representing total renewable fuel, leaving
the other three RVOs with no rollover cap. Doing so would allow all
previous-year RINs used for compliance to be those with a D code of 4,
and this in turn would allow an obligated party to meet one of the
nested standards, such as that for biomass-based diesel, using more
than 20% previous-year RINs. This could result in significant rollover
of RINs with a D code of 2, representing biomass-based diesel, and the
valid life of these RINs would have no meaning in this case.
    Some obligated parties have suggested that the rollover cap should
be raised to a value higher than 20%, citing the need for greater
flexibility in the face of significantly higher volume requirements.
However, we believe that a higher value could create disruptions in the
RIN market as parties with excess RINs would have a greater incentive
to hold onto them rather than sell them. This would especially be a
concern in years where the volume of renewable fuel available in the
market is very close to the RFS requirements. Nevertheless, we request
comment on whether the 20% rollover cap should be raised to a higher
value.
    As described in Section III.G.4, some parties have also suggested
that the rollover cap should be lowered to a value lower than 20%, such
as 10%. In the event of concerns about the availability of RINs, a
lower rollover cap would provide a greater incentive for parties with
excess RINs to sell them rather than hold onto them. However, a lower
rollover cap would also reduce flexibility for many obligated parties.
While we are not proposing it in today's notice, we request comment on
it.

E. Concept for EPA Moderated Transaction System

1. The Need for an EPA Moderated Transaction System
    In implementing RFS1, we found that the 38-digit standardized RINs
have proven confusing to many parties in the distribution chain.
Parties have made various errors in generating and using RINs. For
example, we have seen errors wherein parties have transposed digits
within the RIN. We have seen parties creating alphanumeric RINs,
despite the fact that RINs are supposed to consist of all numbers. We
have also seen incorrect numbering of volume start and end codes.
    Once an error is made within a RIN, the error propagates throughout
the distribution system. Correcting an error can require significant
time and resources and involve many steps. Not only must reports to EPA
be corrected, underlying records and reports reflecting RIN
transactions must also be located and corrected to reflect discovery of
an error. Because reporting related to RIN transactions under RFS1 is
only on a quarterly basis, a RIN error may exist for several months
before being discovered.
    Incorrect RINs are invalid RINs. If parties in the distribution
system cannot track down and correct the error made by one of them in a
timely manner, then all downstream parties that trade the invalid RIN
will be in violation. Because RINs are the basic unit of compliance for
the RFS1 program, it is important that parties have confidence when
generating and using them.
    All parties in the RFS1 and the proposed RFS2 regulated community
use RINs. These parties include producers of renewable fuels, obligated
parties, exporters, and other owners of RINS, typically marketers of
renewable fuels and blenders. (Anyone can own RINs, but those who do
would be subject to registration, recordkeeping, reporting, and attest
engagement requirements described in this preamble.). Currently under
RFS1, all RINs are used to comply with a single standard, and in 2013
an additional cellulosic standard would have been added. Under this
proposed rule, there are four standards, and RINs must be generated to
identify four types of renewable fuels: cellulosic biofuel, biomass-
based diesel, other advanced biofuels, and other renewable fuels (e.g.,
corn ethanol). (For a more detailed discussion of RINs, see Section
III.A of this preamble.) In the proposed EPA Moderated Transaction
System (EMTS), the four types of RINs will be managed through four
types of account.

    Based upon problems we observed with the use of RINs under RFS1,
and considering that we will now have a more complex system including
four standards instead of just one, we believe that the best way to
screen RINs and conduct RIN-based transactions is through EMTS.
    This section describes the proposed EMTS and options for
implementing it. By implementing EMTS, we believe that we would be able
to greatly reduce RIN-related errors and efficiently and accurately
manage the universe of RINs. There are two aspects to our proposal for
EMTS. The first aspect focuses upon creating four, generic types of RIN
account. The second aspect focuses upon actually developing a ``real
time'' environment for handling RIN trades.
2. How EMTS Would Work
    EMTS would be a closed, EPA-managed system that provides a
mechanism for screening RINs as well as a structured environment for
conducting RIN transactions. ``Screening'' RINs will mean that parties
would have much greater confidence that the RINs they handle are
genuine. Although screening cannot remove all human error, we believe
it can remove most of it.
    We propose that screening and assignment of RINs be made at the
logical point, i.e., the point when RINs are generated through
production or importation of renewable fuel. A renewable producer would
electronically submit, in ``real time,'' a batch report for the volume
of renewable fuel produced or imported, as well as a list of the RINs
generated and assigned. EMTS would automatically screen each batch and
either reject the RINs or permit them to pass into the transaction
system, into the RIN generator's account, as one of the four types of
RINs. Note that under RFS1, RIN generation (batch) and RIN transaction
reports are submitted quarterly. Batch reports are submitted by
producers and importers quarterly and reflect how they generated and
assigned RINS to batches. RIN transaction reports are submitted by all
parties who engage in RIN transactions, including buying or selling
RINs. Under this proposed approach for RFS2, these batch reports and
RIN transaction reports would be submitted monthly for calendar year
2010. However, once EMTS is implemented in calendar year 2011, these
separate periodic reports may no longer be necessary. Instead the
information would be submitted as RINs are generated and assigned
within EMTS.
    Under RFS1, the producer or importer list RINs they generate and
assign via the batch report. EPA, in turn, uses the batch report data
to verify RINs generated and transacted. The report is submitted
quarterly. Under RFS1, the purpose of the RIN transaction report is to
document RIN transactions and to document that RINs have been sold or
transferred from party to party in the distribution system. This report
is also submitted quarterly. The RIN transaction report includes the
following information in this report: its name, its EPA company
registration number, and in some cases (where compliance is on a
facility basis), its EPA facility identification number. For the
quarterly reporting period, the reporting party indicates the
transaction type (RIN purchase, RIN sale, expired RIN, or retired RIN),
and the date of the transaction. For a RIN purchase or sale, the
transaction report includes the trading partner's name and the trading
partner's EPA company registration number. There is also information
that may have to be submitted in the event a reporting party must
report a RIN that has been retired (e.g., when a RIN has become invalid
due to the spillage of the associated volume of renewable fuel). As
discussed above, the shortcoming of these reports is that they are only
submitted quarterly. RIN errors that affect compliance may not be
discovered for many months because of the relative infrequency of
reporting transactions to EPA. EMTS will assume the functionality of
batch reporting and transaction reporting used by regulated parties,
allowing EPA to better screen RINs and reduce or eliminate generation
and transaction errors.
    Under the RFS2 program, we are proposing that batch reports
submitted by producers and importers and RIN transaction reports be
submitted monthly rather than quarterly in the first year of the
program (i.e., calendar year 2010). During 2010, we will be finishing
development and testing of the EMTS. In order to minimize the hardship
that undiscovered, invalid RINs may cause, we propose and seek comment
on increasing the frequency of reporting and our own review of reports
in order to assist the regulated community with compliance. As we
develop EMTS through calendar year 2010, we intend to invite and
encourage interested reporting parties to ``opt in'' to EMTS. This will
serve a two-fold purpose: regulated parties may opt to gain familiarity
EMTS before it becomes fully operational and we may have actual
customers with which to test EMTS prior to it becoming fully
operational. We believe that permitting interested parties to ``opt
in'' will result in a better EMTS for all.
    In the second year of the program (i.e., calendar year 2011 and
forward), we anticipate fully implementing the proposed EMTS and
receiving the data contained in batch and RIN transaction reports in
relatively ``real time'' (i.e., as transactions occur). We propose that
``real time'' be construed as within three (3) business days of a
reportable event (e.g., generation and assignment of RINs, transfer of
RINs).
    Parties who use EMTS would have to register with EPA in accordance
with the proposed RFS2 registration program described in Section III.C
of this preamble. They would also have to create an account (i.e.,
register) via EPA's Central Data Exchange (CDX), as we envision
managing EMTS via CDX. CDX is a secure and central portal through which
parties may submit compliance reports. We propose that parties must
establish an account with EMTS by October 1, 2010 or 60 days prior to
engaging in any transaction involving RINs, whichever is later. As
discussed above, the actual items of information covered by reporting
under RFS2 are nearly identical to those reported under RFS1.
    Once registration occurs with EMTS, individual RIN accounts would
be established and the system would manage the accounts for each
individual party. The RIN accounts would correspond to the four broad
types of renewable fuel. RIN accounts would be established for
cellulosic biofuel, biomass-based diesel, other advanced biofuels, and
other renewable fuels (including corn ethanol). One big advantage of
RIN accounts is that the system would make available generic accounts
for transactions involving RINs of similar type. The unique
identification of the RIN would exist within EMTS, but parties engaging
in RIN transactions would no longer have to worry about incorrectly
recording or using 38-digit RIN numbers. As with RFS1, there is no
``good faith'' provision to RIN ownership. An underlying principle of
RIN ownership is still one of ``buyer beware'' and RINs may be
prohibited from use at any time if they are found to be invalid.
Because of the ``buyer beware'' aspect, we intend to offer the option
for a buyer to accept or reject RINs from specific RIN generators or
from classes of RIN generators. Also, we propose to collect information
about the price associated with RINs traded. This information is not
collected under RFS1, but we believe this information has great
programmatic value to EPA because it may help us to anticipate and

appropriately react to market disruptions and other compliance
challenges, assess and develop responses to potential waivers, and
assist in setting future renewable standards. We believe that highly
summarized price information (e.g., the average price of RINs traded
nationwide) may be valuable to regulated parties, as well, and may help
them to anticipate and avoid market disruptions.
    The following is an example of how a RIN transaction might occur in
the proposed EMTS model:
    1. Seller logs into EMTS and posts his sale of 10,000 RINs to
Buyer. For this example, assume the RINs were generated in 2008 and
were assigned to 10,000 gallons of ``other renewable fuel'' (corn
ethanol). Seller's RIN account for ``other renewable fuel'' is
automatically reduced by 10,000 with the posting of his sale to Buyer.
Buyer receives automatic notification of the pending transaction.
    2. Buyer logs into EMTS. She sees the sale transaction pending.
Assuming it is correct, she accepts it. Upon her acceptance, her RIN
account for ``other renewable fuel'' (corn ethanol) is automatically
increased by 10,000 2008 assigned RINs.
    3. After Seller has posted his sale and Buyer has accepted it, EMTS
automatically notifies both Buyer and Seller that the transaction has
been fully completed.
    Under EMTS as we are proposing it, the seller would always have to
initiate any transaction. The seller's account is reduced when he posts
his sale. The buyer must acknowledge the sale in order to have the RINs
transferred to her account. Transactions would always be limited to
available RINs. Notification would automatically be sent to both the
buyer and the seller upon completion of the transaction. EPA proposes
to consider any sale or transfer as complete upon acknowledgement by
the buyer.
    We propose that RINs and the parameters of RIN generation (e.g.,
year) be considered public information. We also propose that summary
RIN price information, such as average price of all RINs in a broad
geographic area (such as a state, region, or nationwide) be considered
public information. This summary price information would be aggregated
from transactions conducted within EMTS, but would not be identified
with individual companies or particular transactions that have
occurred. Because we believe information about RIN pricing in general
will be useful to regulated parties, we are proposing to make this
information available to them. We propose that the actual transactions
between parties and that individual company account information may be
claimed as confidential business information (CBI) by the parties to
that transaction. EPA would treat any information submitted that is
covered by a CBI claim in accordance with the procedures at 40 CFR Part
2 and applicable Agency policies and guidelines for the handling of
claimed CBI.
3. Implementation of EMTS
    We anticipate that implementing EMTS will take until January 1,
2011, although we are proposing that the RFS2 program be effective on
January 1, 2010. We anticipate that development of EMTS will require
significant time and effort and that a delayed effective date may
permit better pre-testing with interested regulated parties. We propose
to permit regulated parties who are willing to participate in EMTS
early to voluntarily opt-in to the system before January 1, 2011. The
actual date for these parties' opt-in will depend upon the actual
timeline for development of EMTS. We encourage comments from interested
parties as to how we might best make use of the development period and
the proposed opportunity for willing and interested parties to ``opt
in'' early.
    Under our proposed scenario, for the 2010 compliance year,
recordkeeping and reporting would be analogous to RFS1, although
registration would be enhanced in accordance with the discussion in
Section III.C of this preamble and recordkeeping and reporting would
reflect the four types of RIN described above. In order to avoid
propagation of RIN-related errors and to prevent errors from going too
long without being detected, we believe it is necessary to increase the
frequency of batch reporting and RIN transaction reporting to monthly
rather than quarterly during 2010.
    EPA will implement the EMTS during the first year of the RFS2
program. RINs generated under the RFS1 regulations will continue to be
traded and reported using the current processes. RINs would still have
unique identifying information, but EMTS will allow transactions to
take place on a generic basis having the system track the specific
unique identifiers. We believe that EMTS will virtually eliminate
errors related to tracking and using individual RINs. Parties will be
required to submit RIN transactions by specifying RIN year, RIN
assignment, RIN fuel type, and any other reporting requirement
specified by the administrator.
    Implementation of EMTS should save considerable time and resources
for both industry and EPA. This is most evident considering that the
proposed system virtually eliminates multiple sources of administrative
errors, resulting in a reduction in costs and effort expended to
correct and regenerate product transfer documents, documentation and
recordkeeping, and resubmitting reports to EPA. We anticipate that a
fully functioning EMTS will result in fewer reports and easier
reporting for industry, and fewer reports requiring processing by EPA.
Industry will need to spend less time and effort verifying the validity
of the RINs they procure and allowing them to procure them on the open
market with confidence. EPA will need to spend less time tracking down
the responsible parties for invalid RINs. This is possible because EMTS
will remove management of the 38-digit RIN from the hands of the
reporting community. At the same time, EPA and the reporting community
will be working with a standardized system, reducing stresses and
development costs on IT systems.
    In summary, the advantage to implementing EMTS is that parties may
engage in RIN transactions with a high degree of confidence. Errors
would be virtually eliminated. Everyone engaging in RIN transactions
would have a simplified environment in which to work which should
minimize the level of resources needed for implementation. However, the
one unavoidable disadvantage that we foresee is that parties would have
to switch to a new and different reporting system in the second year of
the RFS2 program. Some errors may still occur in by parties who
continue to generate and use the 38-digit RINs during 2010. As
discussed above, we propose to increase the frequency of batch and RIN
transaction reporting to monthly for 2010, in order that we may help
parties discover errors and correct them before they become violations.
We also propose to permit parties to voluntarily ``opt in'' to using
EMTS while it is still in development in order to ease the transition.
We invite comment from all interested parties as to how we may best
assist regulated parties in transitioning from the ``old'' RFS1 method
of handing RINs to the ``new,'' proposed RFS2 EMTS method on January 1,
2011.
    We also invite comment on whether, in the event the RFS2 start date
is delayed, EPA should nevertheless allow a one-year period during
which use of EMTS is optional, or if EPA should begin the program at
the inception of the delayed RFS2 program if EMTS is fully operational
at that time.

F. Retail Dispenser Labelling for Gasoline With Greater Than 10 Percent
Ethanol

    Fuel retailers expressed concern that the magnitude of the price
discount for E85 relative to E10 that would be necessary to facilitate
sufficient use of E85 would encourage widespread misfueling of non-flex
fuel vehicles. Today's proposal contains labeling requirements for
pumps that dispense blends that contain greater than 10% ethanol which
state that the use in non-flex fuel vehicles is prohibited and may
cause damage to the vehicle.\45\ We anticipate that the industry would
also conduct public information activities to alert customers who may
not have yet become accustomed to seeing E85 at retail to avoid using
E85 in their non-flex-fuel vehicles. Uniquely colored/labeled nozzle
handles may also be useful in helping to prevent accidental cases of
misfueling. We believe that in most cases the warnings that the use of
E85 in non-flex fuel vehicles is illegal, can damage the vehicle, and
can void vehicle manufacturer warranties may be a sufficient
disincentive to prevent intentional misfueling. In cases where
intentional misfueling may occasionally take place, the party is likely
to experience drivability problems and thus would not repeat the act.
---------------------------------------------------------------------------

    \45\ See section 80.1469 in the proposed regulatory text.
---------------------------------------------------------------------------

    Today's proposal does not contain requirements that E85 refueling
hardware be configured to prevent the introduction of E85 into non-
flex-fuel vehicles. It is unclear how such an approach could be
implemented to allow the approximately 6 million flex-fuel vehicles on
the road today to continue to be fueled with E85 without modification
to their filler neck hardware.\46\ In any event, we do not believe that
unique E85 nozzles are necessary.
---------------------------------------------------------------------------

    \46\ An E85 nozzle design and corresponding flex-fuel vehicle
filler design that would prevent the introduction of E85 into non-
flex-fuel vehicles while allowing flex fuel vehicles to be fueled
with E10 as well as E85 would also prevent the introduction of E85
into current flex-fuel vehicles since there is currently no
difference in nozzle/filler neck hardware between flex-fuel and non-
flex-fuel vehicles.
---------------------------------------------------------------------------

    We request comment on whether the proposed labeling requirements
and voluntary measures such as those described above would provide
sufficient warning to fuel retail customers not to refuel non-flex-fuel
vehicles with E85. To the extent that other measures to prevent
misfueling are thought to be necessary, comment is requested on the
specific nature of such measures and the associated potential costs and
benefits. One additional potential measure to prevent misfueling would
be for cards to be issued to flex fuel vehicle owners and for all E85
dispensers to be equipped with card readers that would allow E85 to be
dispensed only to card holders.

V. Assessment of Renewable Fuel Production Capacity and Use

    To assess the impacts of this rule, there must be a clear
understanding of the kind of renewable fuels that could be used, the
types and locations of their feedstocks, the fuel volumes that could be
produced by a given feedstock, and any challenges associated with their
use. This section provides this assessment of the potential feedstocks
and renewable fuels that may be used to meet the Energy Independence
and Security Act (EISA) and the rationale behind our projections of
various fuel types to represent the control case for analysis purposes.
Definitional issues regarding the four types of renewable fuel required
under EISA are discussed in Section III.B of this preamble.

A. Summary of Projected Volumes

    EISA mandates the use of increasing volumes of renewable fuel. To
assess the impacts of this increase in renewable fuel volume from
business-as-usual (what is likely to have occurred without EISA), we
have established a reference and control case from which subsequent
analyses are based. The reference case is essentially a projection of
renewable fuel volumes without the enactment of EISA. The control case
is a projection of the volumes and types of renewable fuel that might
be used to comply with the EISA volume mandates. Both the reference and
control cases are discussed in further detail below.
1. Reference Case
    Our reference case renewable fuel volumes are based on the Energy
Information Administration's (EIA) Annual Energy Outlook (AEO) 2007
reference case projections. The AEO 2007 presents long-term projections
of energy supply, demand, and prices through 2030 based on results from
EIA's National Energy Modeling System (NEMS). EIA's analysis focuses
primarily on a reference case (which we use as our reference case),
lower and higher economic growth cases, and lower and higher energy
price cases. AEO 2007 projections generally are based on Federal,
State, and local laws and regulations in effect on or before October
31, 2006.\47\ The potential impacts of pending or proposed legislation,
regulations, and standards are not reflected in the projections. While
AEO 2007 is not as up-to-date as AEO 2008 (or the recently released AEO
2009), we chose to use AEO 2007 because AEO 2008 already includes the
impact of increased renewable fuel volumes under EISA as well as fuel
economy improvements under CAFE, whereas AEO 2007 did not. Table V.A.1-
1 summarizes the fuel types and volumes for the years 2009-2022 as
taken from AEO 2007. For our air quality analysis we also considered a
reference case assuming the mandated renewable fuel volumes under the
Renewable Fuel Standard Program from the Energy Policy Act of 2005
(EPAct). Refer to Section VII for further details.
---------------------------------------------------------------------------

    \47\ EIA. Annual Energy Outlook 2007 with Projections to 2030.
http://www.eia.doe.gov/oiaf/archive/aeo07/index.html. Accessed
February 2008.

                     Table V.A.1-1--AEO 2007 Reference Case Projected Renewable Fuel Volumes
                                                [billion gallons]
----------------------------------------------------------------------------------------------------------------
                                                 Advanced biofuel                  Non-advanced
                                 ------------------------------------------------     biofuel
                                    Cellulosic     Biomass-based  Other advanced ----------------      Total
              Year                    biofuel        diesel\a\        biofuel                        renewable
                                 ------------------------------------------------                      fuel
                                    Cellulosic         FAME          Imported      Corn  ethanol
                                      ethanol      biodiesel\b\       ethanol
----------------------------------------------------------------------------------------------------------------
2009............................            0.07            0.32            0.50            9.44           10.33
2010............................            0.12            0.32            0.29           10.49           11.22
2011............................            0.19            0.33            0.16           10.69           11.37
2012............................            0.25            0.33            0.18           10.81           11.57

2013............................            0.25            0.33            0.19           10.93           11.70
2014............................            0.25            0.23            0.20           11.01           11.69
2015............................            0.25            0.25            0.39           11.10           11.99
2016............................            0.25            0.35            0.51           11.16           12.27
2017............................            0.25            0.36            0.53           11.30           12.44
2018............................            0.25            0.36            0.54           11.49           12.64
2019............................            0.25            0.37            0.58           11.69           12.89
2020............................            0.25            0.37            0.60           11.83           13.05
2021............................            0.25            0.38            0.63           12.07           13.33
2022............................            0.25            0.38            0.64           12.29           13.56
----------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. AEO
  2007 only projects FAME biodiesel volumes.
\b\ Fatty acid methyl ester (FAME) biodiesel.

2. Control Case for Analyses
    Our assessment of the renewable fuel volumes required to meet EISA
necessitates establishing a primary set of fuel types and volumes on
which to base our assessment of the impacts of the new standards. EISA
contains four broad categories: cellulosic biofuel, biomass-based
diesel, total advanced biofuel, and total renewable fuel. As these
categories could be met with a wide variety of fuel choices, in order
to assess the impacts of the rule, we projected a set of reasonable
renewable fuel volumes based on our interpretation at the time we began
our analysis of likely fuels that could come to market.
    Although actual volumes and feedstocks may be different, we believe
the projections made for our control case are within the range of
reasonable predictions and allow for an assessment of the potential
impacts of the RFS2 standards. Table V.A.2-1 summarizes the fuel types
used for the control case and their corresponding volumes for the years
2009-2022.

                                              Table V.A. 2-1--Control Case Projected Renewable Fuel Volumes
                                                                    [billion gallons]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Advanced biofuel                             Non-
                                                              -----------------------------------------------------------------   Advanced
                                                                Cellulosic  Biomass-based diesel \a\   Other advanced biofuel     Biofuel
                                                                 biofuel   -----------------------------------------------------------------    Total
                             Year                             -------------                Non-co-        Co-                                 renewable
                                                                              FAME \b\    processed    processed     Imported       Corn         fuel
                                                                Cellulosic   biodiesel    renewable    renewable     ethanol      ethanol
                                                                 ethanol                    diesel       diesel
--------------------------------------------------------------------------------------------------------------------------------------------------------
2009.........................................................         0.00         0.50         0.00         0.00         0.50         9.85        10.85
2010.........................................................         0.10         0.64         0.01         0.01         0.29        11.55        12.60
2011.........................................................         0.25         0.77         0.03         0.03         0.16        12.29        13.53
2012.........................................................         0.50         0.96         0.04         0.04         0.18        12.94        14.66
2013.........................................................         1.00         0.94         0.06         0.06         0.19        13.75        16.00
2014.........................................................         1.75         0.93         0.07         0.07         0.36        14.40        17.58
2015.........................................................         3.00         0.91         0.09         0.09         0.83        15.00        19.92
2016.........................................................         4.25         0.90         0.10         0.10         1.31        15.00        21.66
2017.........................................................         5.50         0.88         0.12         0.12         1.78        15.00        23.40
2018.........................................................         7.00         0.87         0.13         0.13         2.25        15.00        25.38
2019.........................................................         8.50         0.85         0.15         0.15         2.72        15.00        27.37
2020.........................................................        10.50         0.84         0.16         0.16         2.70        15.00        29.36
2021.........................................................        13.50         0.83         0.17         0.17         2.67        15.00        32.34
2022.........................................................        16.00         0.81         0.19         0.19         3.14        15.00        35.33
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Biomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.
\b\ Fatty acid methyl ester (FAME) biodiesel.

    We needed to make this projection soon after EISA was signed to
allow sufficient time to conduct our long lead-time analyses. As a
result, we used the same ethanol-equivalence basis for these
projections as was used in the RFS1 rulemaking. However, as described
in Section III.D.1, we are also co-proposing that volumes of renewable
fuel be counted on a straight gallon-for-gallon basis under RFS2, such
that all Equivalence Values would be 1.0. The net effect of these two
approaches to Equivalence Values on projected volumes is very small;
instead of 36 billion gallons of renewable fuel in 2022, our control
case includes 35.3 billion gallons. We do not believe that

this difference will substantively affect the analyses that are based
on our projected control case volumes.
    The following subsections detail our rationale for projecting the
amount and type of fuels needed to meet EISA as shown in Table V.A.2-1.
For cellulosic biofuel we have assumed that the entire volume will be
domestically produced cellulosic ethanol. Biomass-based diesel is
assumed to be comprised of a majority of fatty-acid methyl ester (FAME)
biodiesel and a smaller portion of non-co-processed renewable diesel.
The portion of the advanced biofuel category not met from cellulosic
biofuel and biomass-based diesel is assumed to come mainly from
imported (sugarcane) ethanol with a smaller amount from co-processed
renewable diesel. The total renewable fuel volume not required to be
comprised of advanced biofuels is assumed to be met with corn ethanol.
    In addition, the following subsections also describe other fuels
that have the potential to contribute to meeting EISA, but because of
their uncertainty of use, or because their use likely might be
negligible we have chosen to not assume any use for our analysis.
Examples of these types of renewable fuels or blendstocks include bio-
butanol, biogas, cellulosic diesel, cellulosic gasoline, biofuel from
algae, jatropha, or palm, imported cellulosic ethanol, other biomass-
to-liquids (BTL), and other alcohols or ethers. We intend to revisit
these assumptions for the final rule and invite comment on whether
these renewable fuels or other potential fuels which have not been
included in our analyses should be included.
a. Cellulosic Biofuel
    As defined in EISA, cellulosic biofuel means renewable fuel
produced from any cellulose, hemicellulose, or lignin that is derived
from renewable biomass and that has lifecycle greenhouse gas emissions,
as determined by the Administrator, that are at least 60% less than the
baseline lifecycle greenhouse gas emissions.
    When many people think of cellulosic biofuel, they immediately
think of cellulosic ethanol. However, cellulosic biofuel could be
comprised of other alcohols, synthetic gasoline, synthetic diesel fuel,
and synthetic jet fuel, propane, and biogas. Whether cellulosic biofuel
is ethanol will depend on a number of factors, including production
costs, the form of tax subsidies, credit programs, and issues
associated with blending the biofuel into the fuel pool. It will also
depend on the relative demand for gasoline and diesel fuel. For
instance, European refineries are undersupplying the European market
with diesel fuel and oversupplying it with gasoline, and based on the
recent high diesel fuel price margins over gasoline, it seems that the
U.S. is falling in line with Europe. Therefore, if the U.S. trend is
toward being relatively oversupplied with gasoline, there could be a
price advantage towards producing renewable fuels that displace diesel
fuel rather than a gasoline fuel replacement like ethanol.
    Current efforts in converting cellulosic feedstocks into fuels
focus on biochemical and thermochemical conversion processes.
Biochemical processes use live bacteria or isolated enzymes, or acids,
to break cellulose down into fermentable sugars. The advantage of using
live bacteria or enzymes is that simple carbon steel could be used
which helps to control the capital costs. However, bacteria and enzymes
that break down cellulose are generally specific to certain types of
cellulose, thus, the cellulosic biofuel facility may have difficulty
processing different types of feedstocks.\48\ If live bacteria are
used, the bacteria could be susceptible to contamination that could
force a plant shutdown. An example of a company using enzymes to
process cellulose into ethanol is Iogen, which has a demonstration
plant in Canada.
---------------------------------------------------------------------------

    \48\ This is currently an area of intense research.
---------------------------------------------------------------------------

    On the other hand, biochemical processes which rely on strong acids
will likely be less susceptible to contamination issues, and could more
easily process mixed feedstocks. Thus, strong acid biochemical
cellulosic ethanol plants could process MSW or a variety of feedstocks
which may be available in areas where no single feedstock dominates.
The strong acids, however, would likely require more expensive
metallurgy. A company which is planning to use strong acids to
hydrolyze the cellulose is Blue Fire Ethanol. Blue Fire is planning on
building a MSW plant in Southern California. Once cellulose is reduced
to simple sugars, either strong acid or enzymatic cellulosic ethanol
plants operate in a manner similar to a corn ethanol plant. This
consists of fermenting sugars into ethanol and then separating the
ethanol from the water that facilitated the fermentation step.
    The thermochemical conversion process is very different from the
biochemical process right from the beginning. For the thermochemical
process, feedstocks are partially burned with oxygen at a very high
temperature and converted into a synthesis gas comprised of carbon
monoxide and hydrogen. The principal advantage of the thermochemical
process is that virtually any hydrocarbon material could be processed
as feedstock, as they would all be converted to the synthesis gas, even
if they produce different relative concentrations of carbon monoxide
and hydrogen. The synthesis gas is typically converted to ethanol or
diesel by one of several different processes.
    Examples of companies currently pursuing the thermochemical route
to selectively produce ethanol include Range Ethanol and Coskata. Range
Ethanol is using a specially formulated catalyst that will primarily
produce ethanol, but it will produce other higher molecular weight
alcohols as well which would be recycled and mostly converted to
ethanol. Coskata, which is being supported by General Motors, is
planning on using bacteria to convert the synthesis gas to ethanol.
    Another thermochemical plant could employ a very similar
gasification reactor, but instead of producing ethanol from syngas, a
Fischer Tropsch (F-T) reactor would be used to produce a primarily
diesel product, i.e., cellulosic diesel. The F-T reactor would use a
specially designed iron or cobalt catalyst to convert the syngas to
straight chain hydrocarbon compounds of varying lengths and molecular
weights. The heavier of these hydrocarbon compounds are then
hydrocracked to produce a very high percentage of valuable diesel fuel
and naphtha (gasoline type compounds). The F-T diesel fuel produced
from the F-T process is very high in quality due to its high cetane and
essentially zero sulfur level. While the naphtha produced from the F-T
process also contains essentially zero sulfur, it is very low in octane
and thus is a poor gasoline blendstock (although it could still be
desirable as a gasoline blendstock because of all the high octane
ethanol being blended into gasoline). Cellulosic naphtha is also
valuable as a cracking feedstock for producing various petrochemical
compounds. Since the F-T diesel is of better quality than the naphtha,
the heavier hydrocarbon compounds are selectively hydrocracked to
produce more diesel over naphtha.
    No commercial cellulosic diesel plants currently exist in the U.S.,
nor elsewhere in the world. Currently, there is a cellulosic diesel
pilot plant operated by Choren in Germany and a commercial sized plant
in the planning stages by Choren also in Germany. Choren is planning to
employ woody materials and agricultural residue as feedstocks. Choren
specially developed a three-stage gasification process for dealing with
the complexities of

biomass and has partnered with Shell which has commercialized a F-T
reaction process. The Choren commercial cellulosic diesel plant in
Germany is expected to begin operating in 2010. Although coal-to-
liquids (CTL) plants rely on coal as their feedstock, they are very
similar to cellulosic diesel plants in design and help to demonstrate
the feasibility of the cellulosic diesel process. There are CTL pilot
plants which are operating today, as well as a number of commercial CTL
plants operating today or in the planning stages. Some of these plants
have experimented with or are being planned for co-feeding biomass
along with the coal. A current list of proposed cellulosic diesel and
CTL plants is provided in Chapter 1 of the DRIA.
    In terms of production costs, at least for the current state of
technology, neither the biochemical nor thermochemical platforms
(comparing enzymatic biochemical processing to ethanol and
thermochemical processing to cellulosic diesel) appear to have clear
advantages in capital costs or operating costs.\49\ Other processing
techniques, for example, the syngas-to-ethanol process used by Coskata,
claim to be capable of producing at even lower production costs, but
without any commercial facilities operating today, it is hard to
predict how these other processing techniques differ from our estimates
of what the production costs for cellulosic biofuel facilities will be
in the future and which technology pathways will be most economic. As
such, both enzymatic biochemical and thermochemical technologies could
be key processing pathways for the production of cellulosic biofuel.
---------------------------------------------------------------------------

    \49\ Wright, M. and Brown, R, ``Comparative Economics of
Biorefineries Based on the Biochemical and Thermochemical
Platforms,'' Biofuels, Bioprod. Bioref. 1:49-56, 2007.
---------------------------------------------------------------------------

    The economic competitiveness of cellulosic biofuels will also
depend on the extent of financial support from the government. Under
the Farm Bill of 2008, both cellulosic ethanol and cellulosic diesel
receive the same tax subsidies ($1.01 per gallon each). The tax
subsidy, however, gives ethanol producers a considerable advantage over
those producing cellulosic diesel due to the feedstock quantity needed
per gallon produced (i.e., typically the higher the energy content of
the product, the more feedstock that is required). On an energy basis,
cellulosic ethanol would receive approximately $13/mmBtu while
cellulosic diesel would receive approximately $8/mmBtu. In a similar
manner, if we were to finalize an approach to the Equivalence Values
for generating RINs in which volume rather than energy content is the
basis, there would be an advantage for the production of cellulosic
ethanol over cellulosic diesel.
    One large advantage that cellulosic diesel has over ethanol is the
ability for the fuel to be blended easily into the current distribution
infrastructure at sizeable volumes. There are currently factors tending
to limit the amount of ethanol that can be blended into the fuel pool
(see Section V.D. for more discussion). Thus, the production of
cellulosic diesel instead of cellulosic ethanol could help increase
consumption of renewable fuels.
    Thus, there is uncertainty as to which mix of cellulosic biofuels
will be produced to fulfill the 16 Bgal mandate by 2022. The latest
release of AEO 2009, for example, estimates a mixture of cellulosic
diesel and ethanol produced for cellulosic biofuel. For assessing the
impacts of the RFS2 standards, we made the simplifying assumption that
cellulosic biofuel would only consist of ethanol, though market
realities may also result in cellulosic diesel and other products. We
are requesting comment on the types of cellulosic biofuel that should
be accounted for in our analyses and whether certain fuels are more
likely to come to fruition than others.
    Cellulosic biofuel could also be produced internationally. One
example of internationally produced cellulosic biofuel is ethanol
produced from bagasse or straw from sugarcane processing in Brazil.
Currently, Brazil burns bagasse to produce steam and generate
bioelectricity. However, improving efficiencies over the coming decade
may allow an increasing portion of bagasse to be allocated to other
uses, including cellulosic biofuel, as the demand for bagasse for steam
and bioelectricity could remain relatively constant.
    One recent study assessed the biomass feedstock potential for
selected countries outside the United States and projected supply
available for export or for biofuel production.50 51 For the
study's baseline projection in 2017, it was estimated that
approximately 21 billion ethanol-equivalent gallons could be produced
from cellulosic feedstocks at $36/dry tonne or less. The majority
(~80%) projected is from bagasse, with the rest from forest products.
Brazil was projected to have the most potential for cellulosic
feedstock production from both bagasse and forest products. Other
countries include India, China, and those belonging to the Caribbean
Basin Initiative (CBI), though much smaller feedstock supplies are
projected as compared to Brazil. Although international production of
cellulosic biofuel is possible, it is uncertain whether this supply
would be available primarily to the U.S. or whether other nations would
consume the fuel domestically. Therefore, for our analyses we have
chosen to assume that all the cellulosic biofuel used to comply with
RFS2 would be produced domestically.
---------------------------------------------------------------------------

    \50\ Countries evaluated include Argentina, Brazil, Canada,
China, Colombia, India, Mexico, and CBI.
    \51\ Kline, K. et al., ``Biofuel Feedstock Assessment for
Selected Countries,'' Oak Ridge National Laboratory, February 2008.
---------------------------------------------------------------------------

b. Biomass-Based Diesel
    Biomass-based diesel as defined in EISA means renewable fuel that
is biodiesel as defined in section 312(f) of the Energy Policy Act of
1992 with lifecycle greenhouse gas emissions, as determined by the
Administrator, that are at least 50% less than the baseline lifecycle
greenhouse gas emissions. Biomass-based diesel can include fatty acid
methyl ester (FAME) biodiesel, renewable diesel (RD) that has not been
co-processed with a petroleum feedstock, as well as cellulosic diesel.
Although cellulosic diesel produced through the Fischer-Tropsch (F-T)
process could potentially contribute to the biomass-based diesel
category, we have assumed for our analyses that the fuel and its
corresponding feedstocks (cellulosic biomass) are already accounted for
in the cellulosic biofuel category discussed previously in Section
V.A.2.a.
    FAME and RD processes can make acceptable quality fuel from
vegetable oils, fats, and greases, and thus will generally compete for
the same feedstock pool. For our analyses, we have assumed that the
volume contribution from FAME biodiesel and RD will be a function of
the available feedstock types. In our analysis we assumed that virgin
plant oils would be preferentially processed by biodiesel plants, while
the majority of fats and greases would be routed to RD
production.52 53 This is because the RD process involves
hydrotreating (or thermal depolymerization), which is more severe and
uses multiple chemical mechanisms to reform the fat molecules into
diesel range material. The FAME

process, by contrast, relies on more specific chemical mechanisms and
requires pre-treatment if the feedstocks contain more than trace
amounts of free fatty acids or other contaminates which are typical of
recycled fats and greases. In terms of volume availability of
feedstocks, supplies of fats and greases are more limited than virgin
vegetable oils. As a result, our control case assumes the majority of
biomass-based diesel volume is met using biodiesel facilities
processing vegetable oils, with RD making up a smaller portion and
using solely fats and greases.
---------------------------------------------------------------------------

    \52\ Recent changes to federal tax subsidies and market shifts
may warrant changes to this assumption. We will reevaluate the
relative production volumes of biodiesel and renewable diesel for
the FRM.
    \53\ This analysis was conducted prior to the completion of our
lifecycle analysis discussed in Section VI, and assumes the fuels
will meet the required GHG threshold.
---------------------------------------------------------------------------

    The RD production volume must be further classified as co-processed
or non-co-processed, depending on whether the renewable material was
mixed with petroleum during the hydrotreating operations (more details
on this definition are in Section III.B.1). EISA specifically forbids
co-processed RD from being counted as biomass-based diesel, but it can
still count toward the total advanced biofuel requirement. What
fraction of RD will ultimately be co-processed is uncertain at this
time, since little or no commercial production of RD is currently
underway, and little public information is available about the
comparative economics and feasibility of the two methods. We assumed in
our control case that half the material will be non-co-processed and
thus qualify as biomass-based diesel. We invite comment on whether RD
production will favor co-processing or non-co-processing with a
petroleum feedstock in the future.
    Perhaps the feedstock with the greatest potential for providing
large volumes of oil for the production of biomass-based diesel is
microalgae. Algae grown on land in photo-bioreactors or in open ponds
could potentially yield 15 to 50 times more oil per acre than
traditional oil crops such as soy, rapeseed, or oil palm. Additionally
it can be cultivated on marginal land with low nutrient inputs, and
thus does not suffer from the sheer resource constraints that make
other biofuel feedstocks problematic at large scale. However, several
technical hurdles do still exist. Specifically, more efficient
harvesting, dewatering and lipid extraction methods are needed to lower
costs to a level competitive with other biodiesel feedstocks (20-30% of
current costs). Until these hurdles are overcome, it is unlikely that
algae-based biodiesel can be commercially competitive with other
biodiesel fuels. Thus, for our control case we have chosen not to
include oil from algae as a feedstock. Although the majority of algae
to biofuel companies are focusing on producing algae oil for
traditional biodiesel production, several companies are alternatively
using algae for producing ethanol or crude oil for gasoline or diesel
which could also help contribute to the advanced biofuel mandate.\54\
For more detail on algae as a feedstock refer to Section 1.1 of the
DRIA.
---------------------------------------------------------------------------

    \54\ Algenol and Sapphire Energy, see http://www.algenolbiofuels.com/ and http://www.sapphireenergy.com/.
---------------------------------------------------------------------------

    Jatropha curcas, a shrub native to Central America, is yet another
possible biofuel feedstock. The perennial yields oil-rich seeds yearly,
with oil yields per acre up to 4 times that of soy and twice that of
rapeseed under optimal conditions. It can grow on low-nutrient lands,
and is tolerant of drought. However, jatropha yields under these
marginal conditions are hard to predict because of insufficient
commercial experience; it is possible that jatropha will have low
yields in the sub-optimal conditions where its cultivation would be
most advantageous. Furthermore, jatropha seed harvesting is very labor
intensive, and little is known about the crop's sustainability impacts,
its long-term yield, or the feasibility of cultivation as a
monoculture. It is unlikely that jatropha can be cultivated in the
United States economically or sustainably, and the possibility of
importing jatropha oil or biodiesel from producing countries is very
uncertain because overseas cultivation efforts are still underdeveloped
and initial volumes will likely be used domestically. As a result, we
have not projected the use of jatropha as a feedstock under our control
case. For more detail on the potential use of jatropha refer to Section
1.1 of the DRIA.
c. Other Advanced Biofuel
    As defined in EISA, advanced biofuel means renewable fuel, other
than ethanol derived from corn starch, that has lifecycle greenhouse
gas emissions, as determined by the Administrator, that are at least
50% less than baseline lifecycle greenhouse gas emissions. 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. As defined in EISA, advanced biofuel includes the
cellulosic biofuel, biomass-based diesel, and co-processed renewable
diesel categories that were mentioned in Sections V.A.2.a and V.A.2.b
above. However, EISA requires greater volumes of advanced biofuel than
just the volumes required of these fuels; see Table V.A.2-1. It is
entirely possible that greater volumes of cellulosic biofuel, biomass-
based diesel, and co-processed renewable diesel than required by EISA
could be produced in the future. Our control case, however, does not
assume that cellulosic biofuel and biomass-based diesel volumes will
exceed those required under EISA.\55\ As a result, to meet the total
advanced biofuel volume required under EISA, advanced biofuel types are
needed other than cellulosic biofuel, biomass-based diesel, and co-
processed renewable diesel through 2022.
---------------------------------------------------------------------------

    \55\ While cellulosic biofuel will not be limited by feedstock
availability, it likely will be limited by the very aggressive ramp
up in production volume for an industry which is still being
demonstrated on the pilot scale and therefore is not yet
commercially viable. On the other hand, biomass-based diesel derived
from agricultural oils and animal fats are faced with relatively
high feedstock costs which limit feedstock supply.
---------------------------------------------------------------------------

    We have assumed for our control case that the most likely source of
advanced fuel other than cellulosic biofuel, biomass-based diesel, and
co-processed renewable diesel would be from imported sugarcane
ethanol.\56\ Our assessment of international fuel ethanol production
and demand indicate that anywhere from 3.8-4.2 Bgal of sugarcane
ethanol from Brazil could be available for export by 2020/2022. If this
volume were to be made available to the U.S., then there would be
sufficient volume to meet the advanced biofuel standard. To calculate
the amount of imported ethanol needed to meet the EISA standards, we
took the difference between the total advanced biofuel category and
cellulosic biofuel, biomass-based diesel, and co-processed renewable
diesel categories. The amount of imported ethanol required by 2022 is
approximately 3.2 Bgal. We solicit comment on our estimate of 3.2 Bgal
and whether or not it is reasonable to assume that Brazil (or any other
country) could satisfy this demand.
---------------------------------------------------------------------------

    \56\ This analysis was conducted prior to the completion of our
lifecycle analysis discussed in Section VI, and assumes the fuel
will meet the required GHG threshold.
---------------------------------------------------------------------------

    Recent news indicates that there are also plans for sugarcane
ethanol to be produced in the U.S in places where the sugar subsidy
does not apply. For instance, sugarcane has been grown in California's
Imperial Valley specifically for the purpose of making ethanol and
using the cane's biomass to generate electricity to power the ethanol
distillery as well as export excess electricity to the electric
grid.\57\ There are at least two projects being developed at this time
that could result in several

hundred million gallons of ethanol produced. The sugarcane is being
grown on marginal and existing cropland that is unsuitable for food
crops and will replace forage crops like alfalfa, Bermuda grass, Klein
grass, etc. Harvesting is expected to be fully mechanized. Thus, there
is potential for these projects and perhaps others to help contribute
to the EISA biofuels mandate. This could lower the volume needed to be
imported from Brazil.
---------------------------------------------------------------------------

    \57\ Personal communication with Nathalie Hoffman, Managing
Member of California Renewable Energies, LLC, August 27, 2008.
---------------------------------------------------------------------------

    Butanol is another potential motor vehicle fuel which could be
produced from biomass and used in lieu of ethanol to comply with the
RFS2 standard. Production of butanol is being pursued by a number of
companies including a partnership between BP and Dupont. Other
companies which have expressed the intent to produce biobutanol are
Baer Biofuels and Gevo. The near term technology being pursued for
producing butanol involves fermentation of starch compounds, although
it can also be produced from cellulose. Butanol has several inherent
advantages compared to ethanol. First, it has higher energy density
than ethanol which would improve fuel economy (mpg). Second, butanol is
much less water soluble which may allow the butanol to be blended in at
the refinery and the resulting butanol-gasoline blend then more easily
shipped through pipelines. This would reduce distribution costs
associated with ethanol's need to be shipped separately from its
gasoline blendstock and also save on the blending costs incurred at the
terminal. Third, butanol can be blended in higher concentrations than
10% which would likely allow butanol to be blended with gasoline at
high enough concentrations to avoid the need for most or all of high
concentration ethanol-gasoline blends, such as E85, that require the
use of fuel flexible vehicles. For example, because of butanol's lower
oxygen content, it can be blended at 16% (by volume) to match the
oxygen concentration of ethanol blended at 10% (by volume).\58\ Because
of butanol's higher energy density, when blending butanol at 16% by
volume, it is the renewable fuels equivalent to blending ethanol at
about 20 percent. Thus, butanol would enable achieving most of the RFS2
standard by blending a lower concentration of renewable fuel than
having to resort to a sizable volume of E85 as in the case of ethanol.
As pointed out in Section V.D., the need to blend ethanol as E85
provides some difficult challenges. The use of butanol may be one means
of avoiding these blending difficulties.
---------------------------------------------------------------------------

    \58\ To obtain EPA approval for butanol blends as high as 16% by
volume would require that the butanol be blended with an approved
corrosion inhibitor.
---------------------------------------------------------------------------

    At the same time, butanol has a couple of less desirable aspects
relative to ethanol. First, butanol is lower in octane compared to
ethanol--ethanol has a very high blending octane of around 115, while
butanol's octane ranges from 87 octane numbers for normal butanol and
94 octane numbers for isobutanol. Potential butanol producers are
likely to pursue producing isobutanol over normal butanol because of
isobutanol's higher octane content. Higher octane is a valuable
attribute of any gasoline blendstock because it helps to reduce
refining costs. A second negative property of butanol is that it has a
much higher viscosity compared to either gasoline or ethanol. High
viscosity makes a fuel harder to pump, and more difficult to atomize in
the combustion chamber in an internal combustion engine. The third
downside to butanol is that it is more expensive to produce than
ethanol, although the higher production cost is partially offset by its
higher energy density.
    Another potential source of renewable transportation fuel is
biomethane refined from biogas. Biogas is a term meaning a combustible
mixture of methane and other light gases derived from biogenic sources.
It can be combusted directly in some applications, but for use in
highway vehicles it is typically purified to closely resemble fossil
natural gas for which the vehicles are typically designed. The
definition of biogas as given in EISA is sufficiently broad to cover
combustible gases produced by biological decomposition of organic
matter, as in a landfill or wastewater treatment facility, as well as
those produced via thermochemical decomposition of biomass.
    Currently, the largest source of biogas is landfill gas collection,
where the majority of fuel is combusted to generate electricity, with a
small portion being upgraded to methane suitable for use in heavy duty
vehicle fleets. Current literature suggests approximately 16 billion
gasoline gallons equivalent of biogas (referring to energy content)
could potentially be produced in the long term, with about two thirds
coming from biomass gasification and about one third coming from waste
streams such as landfills and human and animal sewage
digestion.59 60
---------------------------------------------------------------------------

    \59\ National Renewable Energy Laboratory estimate based on
biomass portion available at $45-$55/dry ton. Using POLYSYS Policy
Analysis System, Agricultural Policy Analysis Center, University of
Tennessee. http://www.agpolicy.org/polysys.html. Accessed May 2008.
    \60\ Milbrandt, A., ``Geographic Perspective on the Current
Biomass Resource Availability in the United States.'' 70 pp., NREL
Report No. TP-560-39181, 2005.
---------------------------------------------------------------------------

    Because the majority of the biogas volume estimates assume biomass
as a feedstock, we have chosen not to include this fuel in our analyses
since we are projecting most available biomass will be used for
cellulosic liquid biofuel production in the long term. The remaining
biogas potentially available from waste-related sources would come from
a large number of small streams requiring purification and connection
to storage and/or distribution facilities, which would involve
significant economic hurdles. An additional and important source of
uncertainty is whether there would be a sufficient number of vehicles
configured to consume these volumes of biogas. Thus, we expect future
biogas fuel streams to continue to find non-transportation uses such as
electrical power generation or facility heating.
d. Other Renewable Fuel
    The remaining portion of total renewable fuel not met with advanced
biofuel is assumed to come from corn-based ethanol. EISA effectively
sets a limit for participation in the RFS program of 15 Bgal of corn
ethanol by 2022. It should be noted, however, that there is no specific
``corn-ethanol'' mandated volume, and that any advanced biofuel
produced above and beyond what is required for the advanced biofuel
requirements could reduce the amount of corn ethanol needed to meet the
total renewable fuel standard. This occurs in our projections during
the earlier years (2009-2014) in which we project that some fuels could
compete favorably with corn ethanol (e.g. biodiesel and imported
ethanol). Beginning around 2015, fuels qualifying as advanced biofuels
likely will be devoted to meeting the increasingly stringent volume
mandates for advanced biofuel. It is also worth noting that more than
15 Bgal of corn ethanol could be produced and RINs generated for that
volume under our proposed RFS2 regulations. However, obligated parties
would not be required to purchase more than 15 Bgal worth of corn
ethanol RINs.
    We are assuming for our analysis that sufficient corn ethanol will
be produced to meet the 15 Bgal limit. However, this assumes that in
the future corn ethanol production is not limited due to environmental
constraints, such as water quantity issues (see Section 6.10 of the
DRIA). This also assumes that in

the future either corn ethanol plants are constructed or modified to
meet the 20% GHG threshold, or that sufficient corn ethanol production
exists that is grandfathered and not required to meet the 20%
threshold. Our current projection is that up to 15 Bgal could be
grandfathered, but actual volumes will be determined at the time of
facility registration. Refer to Section <IP_ADDRESS> of the DRIA for more
information. Since our current lifecycle analysis estimates that much
of the current corn ethanol would not meet the 20% GHG reduction
threshold required of non-grandfathered facilities without facility
upgrades, then if actual grandfathered corn volumes are less than 15
Bgal it may be necessary to meet the volume mandate with other
renewable fuels or through the use of advanced technologies that could
improve the corn ethanol lifecycle GHG estimates.

B. Renewable Fuel Production

1. Corn/Starch Ethanol
    The majority of domestic biofuel production currently comes from
plants processing corn and other similarly-processed grains in the
Midwest. However, there are a handful of plants located outside the
Corn Belt and a few plants processing simple sugars from food or
beverage waste. In this section, we will summarize the present state of
the corn/starch ethanol industry and discuss how we expect things to
change in the future under the proposed RFS2 program.
a. Historic/Current Production
    The United States is currently the largest ethanol producer in the
world. In 2008, the U.S. produced almost nine billion gallons of fuel
ethanol for domestic consumption, the majority of which came from
locally-grown corn.\61\ Although the U.S. ethanol industry has been in
existence since the 1970s, it has rapidly expanded over the past few
years due to the phase-out of methyl tertiary butyl ether (MTBE),\62\
elevated crude oil prices, state mandates and tax incentives, the
introduction of the Federal Volume Ethanol Excise Tax Credit
(VEETC),\63\ and the implementation of the existing RFS1 program.\64\
As shown in Figure V.B.1-1, U.S. ethanol production has grown
exponentially over the past decade.
---------------------------------------------------------------------------

    \61\ Based on total transportation ethanol reported in EIA's
March 2009 Monthly Energy Review (Table 10.2) less imports (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
    \62\ For more information on how the phase-out of MTBE helped
spur ethanol production/consumption, refer to Section V.D.1.
    \63\ On October 22, 2004, President Bush signed into law H.R.
4520, the American Jobs Creation Act of 2004 (JOBS Bill), which
created the Volumetric Ethanol Excise Tax Credit (VEETC). The $0.51/
gal VEETC for ethanol blender replaced the former fuel excise tax
exemption, blender's credit, and pure ethanol fuel credit. However,
the recently-enacted 2008 Farm Bill modifies the alcohol credit so
that corn ethanol gets a reduced credit of $0.45/gal and cellulosic
biofuel a credit of $1.01/gal effective January 1, 2009.
    \64\ On May 1, 2007, EPA published a final rule (72 FR 23900)
implementing the Renewable Fuel Standard (RFS) required by EPAct.
The RFS requires that 4.0 billion gallons of renewable fuel be
blended into gasoline/diesel by 2006, growing to 7.5 billion gallons
by 2012.
    \65\ Based on total transportation ethanol reported in EIA's
March 2009 Monthly Energy Review (Table 10.2) less imports (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm).
[GRAPHIC] [TIFF OMITTED] TP26MY09.004

    As of April 1, 2009, there were 169 corn/starch ethanol plants
operating in the U.S. with a combined estimated production capacity of
10.5 billion gallons per year.\66\ This does not include a number of
ethanol plants that are currently idled.\67\ The majority of today's
ethanol (over 91% by volume) is produced exclusively from corn. Another
8% comes from a blend of corn and/or similarly processed grains (milo,
wheat, or barley) and less than half a percent is produced from cheese
whey, waste beverages, and sugars/starches combined. A summary of U.S.
ethanol production by feedstock is presented in Table V.B.1-1.
---------------------------------------------------------------------------

    \66\ Our April 2009 corn/starch ethanol industry
characterization was based on a variety of sources including:
Renewable Fuels Association (RFA) Ethanol Biorefinery Locations
(updated March 31, 2009); Ethanol Producer Magazine (EPM) Producing
plant list (last modified on April 7, 2009), and ethanol producer
Web sites. The baseline does not include ethanol plants whose
primary business is industrial or food-grade ethanol production nor
does it include plants that might be located in the Virgin Islands
or U.S. territories. Where applicable, current/historic production
levels have been used in lieu of nameplate capacities to estimate
production capacity. The April 2009 information presented in this
section reflects our most recent knowledge of the corn/starch
ethanol industry. However, for various NPRM impact analyses, an
earlier May 2008 industry assessment was used. For more on this
assessment, refer to Section <IP_ADDRESS> of the DRIA.
    \67\ In addition to idled plants, the assessment does not
include idled production capacity at facilities that are currently
operating at 50% or less than their nameplate capacity.

                   Table V.B.1-1--Current Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
                                                                Capacity    Percent of   Number of    Percent of
           Plant feedstock (Primary listed first)                 MGY        capacity      plants       plants
----------------------------------------------------------------------------------------------------------------
Corn \a\....................................................        9,605         91.2          144         85.2
Corn, Milo \b\..............................................          717          6.8           14          8.3
Corn, Wheat.................................................          130          1.2            1          0.6
Milo........................................................            3          0.0            1          0.6
Wheat, Milo.................................................           50          0.5            1          0.6
Cheese Whey.................................................            5          0.0            1          0.6
Waste Beverages \c\.........................................           19          0.2            5          3.0
Waste Sugars & Starches \d\.................................            7          0.1            2          1.2
                                                             ---------------------------------------------------
    Total...................................................       10,535          100          169          100
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, two facilities also operating pilot-level cellulosic ethanol
  plants at these locations, and four facilities planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.

    As shown in Table V.B.1-1, of the 169 operating plants, 161 process
corn and/or other similarly processed grains. Of these facilities, 150
utilize dry-milling technologies and the remaining 11 plants rely on
wet-milling processes. Dry mill ethanol plants grind the entire kernel
and generally produce only one primary co-product: Distillers grains
with solubles (DGS). The co-product is sold wet (WDGS) or dried (DDGS)
to the agricultural market as animal feed. However, there are a growing
number of dry mill ethanol plants pursuing front-end fractionation or
back-end extraction to produce fuel-grade corn oil for the biodiesel
industry. There are also additional plants pursuing cold starch
fermentation and other energy-saving processing technologies. For more
on the dry-milling and wet-milling processes as well as emerging
advanced technologies, refer to Section 1.4 of the DRIA.
    In contrast to dry mill plants, wet mill facilities separate the
kernel prior to processing into its component parts (germ, fiber,
protein, and starch) and in turn produce other co-products (usually
gluten feed, gluten meal, and food-grade corn oil) in addition to DGS.
Wet mill plants are generally more costly to build but are larger in
size on average.\68\ As such, 11.5% of the current grain ethanol
production comes from the 11 previously-mentioned wet mill facilities.
The remaining eight plants which process cheese whey, waste beverages
or sugars/starches, operate differently than their grain-based
counterparts. These small production facilities do not require milling
and operate a simpler enzymatic fermentation process.
---------------------------------------------------------------------------

    \68\ According to our April 2009 corn ethanol plant assessment,
the average wet mill plant capacity was 111 million gallons per
year--almost twice that of the average dry mill plant capacity (62
million gallons per year). For more on average plant sizes, refer to
Section <IP_ADDRESS> of the DRIA.
---------------------------------------------------------------------------

    Ethanol production is a relatively resource-intensive process that
requires the use of water, electricity, and steam.\69\ Steam needed to
heat the process is generally produced on-site or by other dedicated
boilers.\70\ The ethanol industry relies primarily on natural gas. Of
today's 169 ethanol production facilities, 142 burn natural gas \71\
(exclusively), three burn a combination of natural gas and biomass, one
recently started burning a combination of natural gas, landfill biogas
and wood, and two burn a combination of natural gas and syrup from the
process. In addition, 20 plants burn coal as their primary fuel and one
burns a combination of coal and biomass. Our research suggests that 25
plants currently utilize cogeneration or combined heat and power (CHP)
technology, although others may exist. CHP is a mechanism for improving
overall plant efficiency. Whether owned by the ethanol facility, their
local utility, or a third party, CHP facilities produce their own
electricity and use the waste heat from power production for process
steam, reducing the energy intensity of ethanol production.\72\ A
summary of the energy sources and CHP technology utilized by today's
ethanol plants is found in Table V.B.1-2.
---------------------------------------------------------------------------

    \69\ For more information on plant energy requirements, refer to
Section <IP_ADDRESS> of the DRIA.
    \70\ We are also aware of a couple plants that pull steam
directly from a nearby utility.
    \71\ Facilities were assumed to burn natural gas if the plant
boiler fuel was unspecified or unavailable on the public domain.
    \72\ For more on CHP technology, refer to Section <IP_ADDRESS> of the
DRIA.

                 Table V.B.1-2--Current Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                   Capacity    Percent of   Number of    Percent of
   Plant energy source (primary listed first)        MGY        capacity      plants       plants     CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\.......................................        1,868         17.7           20         11.8            9
Coal, Biomass..................................           50          0.5            1          0.6            0
Natural Gas \b\................................        8,294         78.7          142         84.0           15
Natural Gas, Biomass \c\.......................          113          1.1            3          1.8            1
Natural Gas, Landfill Biogas, Wood.............          110          1.0            1          0.6            0
Natural Gas, Syrup.............................          101          1.0            2          1.2            0
                                                ----------------------------------------------------------------
    Total......................................       10,535        100.0          169        100.0           25
----------------------------------------------------------------------------------------------------------------
\a\ Includes four plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition
  to coal and one facility that intends to transition to biomas in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
  biogas, and two facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.

    Since the majority of ethanol is made from corn, it is no surprise
that most of the plants are located in the Midwest near the Corn Belt.
Of today's 169 ethanol production facilities, 151 are located in the 15
states comprising PADD 2. For a map of the Petroleum Administration for
Defense Districts or PADDs, refer to Figure V.B.1-2.
[GRAPHIC] [TIFF OMITTED] TP26MY09.005

    As a region, PADD 2 accounts for 94% (or almost 10 billion gallons)
of today's estimated ethanol production capacity, as shown in Table
V.B.1-3. For more information on today's ethanol plants and a detailed
map of their locations, refer to Section 1.5 of the DRIA.

                     Table V.B.1-3--Current Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
                                                                Capacity    Percent of   Number of    Percent of
                            PADD                                  MGY        capacity      plants       plants
----------------------------------------------------------------------------------------------------------------
PADD 1......................................................          150          1.4            3          1.8
PADD 2......................................................        9,900         94.0          151         89.3
PADD 3......................................................          194          1.8            3          1.8
PADD 4......................................................          160          1.5            7          4.1
PADD 5......................................................          131          1.2            5          3.0
                                                             ---------------------------------------------------
    Total...................................................       10,535        100.0          169        100.0
----------------------------------------------------------------------------------------------------------------

    The U.S. ethanol industry is currently comprised of a mixture of
company-owned plants and locally-owned farmer cooperatives (co-ops).
The majority of today's ethanol production facilities are company-
owned, and on average these plants are larger in size than farmer-owned
co-ops. Accordingly, company-owned plants account for more than 79% of
today's ethanol production capacity.\73\ Furthermore, 30% of the total
domestic product comes from 38 plants owned by just three different
companies--POET Biorefining, Archer Daniels Midland (ADM), and Valero
Renewables.\74\
---------------------------------------------------------------------------

    \73\ Farmer-owned plant status derived from Renewable Fuels
Association (RFA), Ethanol Biorefinery Locations (updated March 31,
2009). For more on average plant sizes, refer to Section 1.5.1 of
the DRIA.
    \74\ Valero recently entered into the renewable fuels business
by acquiring five idled corn ethanol plants and one construction
site formerly owned by VeraSun Energy Corporation. Valero has since
purchased two more idled VeraSun plants, but they have not been
brought back online yet.

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

b. Forecasted Production Under RFS2
    As highlighted above, 10.5 billion gallons of corn/starch ethanol
plant capacity was online as of April 1, 2009. So even if no additional
capacity was added, U.S. ethanol production would grow from 2008 to
2009, provided facilities continue to operate at or above today's
production levels. And despite today's temporary unfavorable market
conditions (i.e., low ethanol market values), we expect the ethanol
industry will continue to expand in the future under RFS2. Although
there is not a set corn ethanol standard, EISA allows for 15 billion
gallons of the 36-billion gallon renewable fuel standard to be met by
conventional biofuels. And we expect that corn and other sugar or
starch-based ethanol will fulfill this requirement. Furthermore, we
project that all new corn/starch ethanol plant capacity brought online
under RFS2 would either meet the conventional biofuel GHG threshold
requirement \75\ or meet the grandfathering requirement (for more
information, refer to Section <IP_ADDRESS> of the DRIA).
---------------------------------------------------------------------------

    \75\ The lifecycle assessment values which assume a 2% discount
rate over a 100-year timeframe.
---------------------------------------------------------------------------

    In addition to the 169 corn/starch ethanol plants that are
currently online today, 36 plants are presently idled. Some of these
constructed facilities (namely smaller ethanol plants) have been idled
for quite some time, whereas other plants have just recently been put
into ``hot idle'' mode. A number of ethanol producers (e.g., VeraSun)
are idling operations, putting projects on hold, selling off plants,
and even filing for Chapter 11 bankruptcy. In addition, we are aware of
two facilities that are currently operating at 50% or less than their
nameplate capacity. As crude oil and gasoline prices rise again in the
future, corn ethanol production will become more viable again and we
expect that these plants will resume operations. At the time of our
April 2009 ethanol industry assessment, there were also 19 new ethanol
plants under construction in the U.S, and two plant expansion projects
underway. While many of these projects are also on hold due to the
current economic conditions, we expect these facilities will eventually
come online under the RFS2 program. A summary of the projected industry
growth is found in Table V.B.1-4.\76\
---------------------------------------------------------------------------

    \76\ Idled plants and construction projects based on Renewable
Fuels Association (RFA) Ethanol Biorefinery Locations (updated March
31, 2009); Ethanol Producer Magazine (EPM) Not Producing and Under
Construction plant lists (last modified on April 7, 2009), ethanol
producer Web sites, and follow-up correspondence with ethanol
producers. It is worth noting that for our industry assessment,
``under construction'' implies that more than just a ground breaking
ceremony has taken place.

                             Table V.B.1-4--Potential Industry Expansion Under RFS2
----------------------------------------------------------------------------------------------------------------
                                                           Growth in ethanol production
                                 -------------------------------------------------------------------------------
                                      Plants                            New
                                     currently     Idled plants/   construction      Expansion         Total
                                      online       capacity \a\      projects        projects
----------------------------------------------------------------------------------------------------------------
Plant Capacity (MGY)............          10,535           2,471           1,955              80          15,042
Total No. of Plants.............             169              36              19               2             226
----------------------------------------------------------------------------------------------------------------
\a\ Includes the idled plant capacity of the two facilities that are currently operating at 50% or less than
  nameplate capacity.

    While theoretically it only takes 12 to 18 months to build an
ethanol plant,\77\ the rate at which new plant capacity comes online
will be dictated by market conditions, which will in part be influenced
by the RFS2 requirements. As mentioned above, today's proposed program
will create a growing demand for corn ethanol reaching 15 billion
gallons by 2015. However, it is possible that market conditions could
drive demand even higher. Whether the nation will overcomply with the
corn ethanol standard is uncertain and will be determined by feedstock
availability/pricing, crude oil pricing, and the relative ethanol/
gasoline price relationship. To measure the impacts of the proposed
RFS2 program, we assumed that corn ethanol production would not exceed
15 billion gallons. We also assumed that all growth would come from new
plants or plant expansion projects (in addition to idled plants being
brought back online).\78\ However, it is possible that some of the
growth could come from minor process improvements (e.g.,
debottlenecking) at existing facilities.
---------------------------------------------------------------------------

    \77\ For more information on plant build rates, refer to Section
1.2.5 of the RIA.
    \78\ For our NPRM impact analyses, we relied on an earlier May
2008 industry assessment. For more information, refer to Section
<IP_ADDRESS> of the DRIA.
---------------------------------------------------------------------------

    Once all the aforementioned projects are complete, we project that
there would be 226 corn/starch ethanol plants operating in the U.S.
with a combined production capacity of around 15 billion gallons per
year. Much like today's ethanol industry, the overwhelming majority of
new production capacity (93% by volume) is expected to come from corn-
fed plants. Another 7% is forecasted to come from plants processing a
blend of corn and other grains, and a very small increase is projected
to come from idled cheese whey and waste beverage plants coming back
online. A summary of the forecasted ethanol production by feedstock
under the RFS2 program is found in Table V.B.1-5.

               Table V.B.1-5--Projected RFS2 Corn/Starch Ethanol Production Capacity by Feedstock
----------------------------------------------------------------------------------------------------------------
                                                                Additional production      Total RFS2 estimate
                                                             ---------------------------------------------------
           Plant feedstock (primary listed first)               Capacity    Number of     Capacity    Number of
                                                                  MGY         plants        MGY         plants
----------------------------------------------------------------------------------------------------------------
Corn \a\....................................................        4,197           49       13,802          193
Corn, Milo \b\..............................................          185            3          902           17
Corn, Wheat.................................................            8            1          138            2
Corn, Wheat, Milo...........................................          110            2          110            2
Milo........................................................            0            0            3            1
Wheat, Milo.................................................            0            0           50            1

Cheese Whey.................................................            3            1            8            2
Waste Beverages \c\.........................................            4            1           23            6
Waste Sugars & Starches \d\.................................            0            0            7            2
                                                             ---------------------------------------------------
    Total...................................................        4,507           57       15,042          226
----------------------------------------------------------------------------------------------------------------
\a\ Includes one facility processing seed corn, another facility processing small amounts of whey, two
  facilities also operating pilot-level cellulosic ethanol plants at these locations, and four facilities
  planning on incorporating cellulosic feedstocks in the future.
\b\ Includes one facility processing a small amount of molasses in addition to corn and milo.
\c\ Includes two facilities processing brewery waste.
\d\ Includes one facility processing potato waste that intends to add corn in the future.

    Based on current industry plans, the majority of additional corn/
grain ethanol production capacity (almost 84% by volume) is predicted
to come from new or expanded plants burning natural gas.\79\
Additionally, we are forecasting one new plant and a reopening of
another plant relying on manure biogas. We are also predicting
expansions at three coal-fired ethanol plants.\80\ Of the 55 new
ethanol plants, our research indicates that five would utilize
cogeneration, bringing the total number of CHP facilities to 30. A
summary of the projected near-term ethanol plant energy sources is
found in Table V.B.1-6.
---------------------------------------------------------------------------

    \79\ Facilities were assumed to burn natural gas if the plant
boiler fuel was unspecified or unavailable on the public domain.
    \80\ Two of the three coal-fired plant expansions appear as new
plants in Table V.B.1-6. This is because two of the expansion
projects consist of adding dry milling plant capacity to an existing
wet mill plant. However, our interpretation is that these facilities
will rely on the same (potentially expanded) coal-fired boilers for
process steam. Since all the aforementioned coal-fired ethanol
production facilities appear to have commenced construction prior to
December 19, 2007, we project that the ethanol produced at these
facilities will be grandfathered under the proposed RFS2 rule. For
more on our grandfathered volume estimate, refer to Section <IP_ADDRESS>
of the DRIA.

           Table V.B.1-6--Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source
----------------------------------------------------------------------------------------------------------------
                                                   Additional production            Total RFS2 estimate
                                                ----------------------------------------------------------------
   Plant energy source (primary listed first)      Capacity    Number of     Capacity    Number of
                                                     MGY         plants        MGY         plants     CHP tech.
----------------------------------------------------------------------------------------------------------------
Coal \a\.......................................          610            2        2,478           22           11
Coal, Biomass..................................            0            0           50            1            0
Manure Biogas..................................          134            2          134            2            0
Natural Gas \b\................................        3,763           53       12,056          195           18
Natural Gas, Biomass \c\.......................            0            0          113            3            1
Natural Gas, Landfill Biogas, Wood.............            0            0          110            1            0
Natural Gas, Syrup.............................            0            0          101            2            0
                                                ----------------------------------------------------------------
    Total......................................        4,507           57       15,042          226           30
----------------------------------------------------------------------------------------------------------------
\a\ Includes six plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition to
  coal and one facility that intends to transition to biomass in the future.
\b\ Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage
  biogas, and six facilities that might switch to coal in the future.
\c\ Includes one facility processing bran in addition to natural gas.

    The information in Table V.B.1.6 is based on short-term industry
production plans at the time of our April 1, 2009 plant assessment.
However, we are anticipating growth in advanced ethanol production
technologies under the proposed RFS2 program. We project that fuel
prices will drive a large number of corn ethanol plants to transition
from conventional boiler fuels to advanced biomass-based feedstocks. We
also believe that fossil fuel/electricity prices will drive a number of
ethanol producers to pursue CHP technology. For more on our projected
2022 utilization of these technologies under the RFS2 program, refer to
Section <IP_ADDRESS> of the DRIA.
    Under the proposed RFS2 program, the majority of new ethanol
production is expected to originate from PADD 2, close to where most of
the corn is grown. However, there are a number of ``destination''
ethanol plants being built outside the Midwest in response to
production subsidies, E10/E85 retail pump incentives, and state
mandates. A summary of the forecasted ethanol production by PADD under
the RFS2 program can be found in Table V.B.1-7.

                  Table V.B.1-7--Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD
----------------------------------------------------------------------------------------------------------------
                                                                Additional production      Total RFS2 Estimate
                                                             ---------------------------------------------------
                            PADD                                Capacity    Number of     Capacity    Number of
                                                                  MGY         plants        MGY         plants
----------------------------------------------------------------------------------------------------------------
PADD 1......................................................          178            3          328            6
PADD 2......................................................        3,566           43       13,466          194
PADD 3......................................................          350            4          544            7
PADD 4......................................................           50            1          210            8
PADD 5......................................................          363            6          494           11
                                                             ---------------------------------------------------
    Total...................................................        4,507           57       15,042          226
----------------------------------------------------------------------------------------------------------------

2. Cellulosic Biofuel
    Ethanol currently dominates U.S. biofuel production, and more
specifically, ethanol produced from corn and other grains. However,
cellulosic feedstocks have the potential to greatly expand domestic
ethanol production, both volumetrically and geographically. It is also
possible to produce synthetic diesel fuel from cellulosic feedstocks
(also known as ``cellulosic diesel'') through a Fischer-Tropsch
gasification process or a thermal depolymerization process. We are also
aware of one company using live bacteria to break down biomass and
produce cellulosic diesel and other petroleum replacements. Before
wide-scale commercialization of cellulosic biofuel can occur in today's
marketplace, technical and logistical barriers must be overcome. In
addition to today's RFS2 program which sets aggressive goals for all
ethanol production, the Department of Energy (DOE) and other federal
and state agencies are helping to spur industry growth.
a. Current Production/Plans
    The cellulosic biofuel industry is essentially in its infancy. With
the exception of a 20 million-gallon-per year cellulosic diesel plant
recently opened by Cello Energy in Bay Minette, AL, the majority of
facilities in operation today are small pilot- or demonstration-level
plants. Most of these facilities operate intermittently and produce
insignificant volumes of biofuel. Some researchers are focusing on
processing corn residues, e.g., corn stover, cobs, and/or fiber. Some
are focusing on other agricultural residues such as sugarcane bagasse,
rice and wheat straw. Others are looking at waste products such as
forestry residues, citrus residues, pulp or paper mill waste, municipal
solid waste (MSW), and construction and demolition (C&D) debris.
Dedicated energy crops including switchgrass and poplar trees are also
being investigated.
    Based on an April 2009 assessment of information available on the
public domain, there are currently 25 pilot- and demonstration-level
(or smaller) cellulosic ethanol plants operating in the United States.
However, only 9 of these plants report measurable volumes of ethanol
production. In addition, we are aware of one pilot-level cellulosic
diesel plant in addition to the commercial-level Cello Energy
plant.\81\ A summary of these 11 facilities totaling just over 23
million gallons of annual production capacity is provided in Table
V.B.2-1. The date listed in the table indicates when the facility first
began operations. For more on the existing cellulosic ethanol and
diesel plants, refer to Sections <IP_ADDRESS> and <IP_ADDRESS> of the DRIA.
---------------------------------------------------------------------------

    \81\ Our April 2009 cellulosic ethanol industry characterization
was based on researching DOE- and USDA-supported projects, plants
referenced in HART's Ethanol & Biodiesel News (through the April 14,
2009 issue), plants included on the Cellulosic Ethanol Site (http://www.thecesite.com/), and plants referenced on other biofuel industry
Web sites.

                                Table V.B.2-1--Existing Cellulosic Biofuel Plants
----------------------------------------------------------------------------------------------------------------