[Federal Register Volume 75, Number 244 (Tuesday, December 21, 2010)]
[Rules and Regulations]
[Pages 79964-79978]
[FR Doc No: 2010-31910]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 80

[EPA EPA-HQ-OAR-2005-0161; FRL-9241-4]
RIN 2060-AQ31

Regulation of Fuels and Fuel Additives: Modifications to
Renewable Fuel Standard Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final r ule.

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SUMMARY: EPA is finalizing amendments to certain of the Renewable Fuel
Standard program regulations that were published on March 26, 2010, and
that took effect on July 1, 2010 (``the RFS2 regulations''). Following
publication of the RFS2 regulations, promulgated in response to the
requirements of the Energy Independence and Security Act of 2007, EPA
discovered some technical errors and areas within the final RFS2
regulations that could benefit from clarification or modification. In a
direct final rule and parallel notice of proposed rulemaking published
on May 10, 2010, EPA included language to amend the regulations to make
the appropriate corrections, clarifications, and modifications.
However, EPA received adverse comment on a few provisions in the direct
final rule and, on June 30, 2010, withdrew those provisions prior to
their effective date of July 1, 2010. In today's action, EPA is
addressing the comments received on the portions of the direct final
rule that were withdrawn and is taking final action regarding the
withdrawn provisions based on consideration of the comments received.

DATES: This final rule is effective on January 1, 2011.

ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2005-0161. All documents in the docket are listed on the
http:://www.regulations.gov Web site. Although listed in the index,
some information is not publicly available, e.g., CBI or other
information whose disclosure is restricted by statute. Certain other
material, such as copyrighted material, is not placed on the Internet
and will be publicly available only in hard copy form. Publicly
available docket materials are generally available either
electronically through http://www.regulations.gov or in hard copy at
the Air and Radiation Docket, ID No. EPA-HQ-OAR-2005-0161, EPA West,
Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public
Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through
Friday, excluding legal holidays. The telephone number for the Public
Reading Room is<PHONE_NUMBER>, and the telephone number for the Air
and Radiation Docket is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Megan Brachtl, Compliance and
Innovative Strategies Division, Office of Transportation and Air
Quality (6405J), Environmental Protection Agency, 1200 Pennsylvania
Avenue, NW., 20460; telephone number:<PHONE_NUMBER>; fax number: (202)
343-2802; e-mail address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. General Information

A. Does this action apply to me?

    Entities potentially affected by this final rule include those
involved with the production, importation, distribution, and sale of
transportation fuels, including gasoline and diesel fuel and renewable
fuels such as ethanol and biodiesel. Regulated categories and entities
affected by this action include:

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                                                                                Examples of potentially
                Category                    NAICS codes\a\      SIC codes\b\            regulated parties
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Industry................................             324110               2911  Petroleum refiners, importers.
Industry................................             325193               2869  Ethyl alcohol manufacturers.
Industry................................             325199               2869  Other basic organic chemical
                                                                                manufacturers.
Industry................................             424690               5169  Chemical and allied products
                                                                                merchant wholesalers.
Industry................................             424710               5171  Petroleum bulk stations and
                                                                                terminals.
Industry................................             424720               5172  Petroleum and petroleum products
                                                                                merchant wholesalers.
Industry................................             454319               5989  Other fuel dealers.
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\a\ North American Industry Classification System (NAICS).
\b\ Standard Industrial Classification (SIC) system code.

    This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that EPA is now aware
could potentially be regulated by this action. Other types of entities
not listed in the table could also be regulated. To determine whether
your activities would be regulated by this action, you should carefully
examine the applicability criteria of Part 80, subpart M of title 40 of
the Code of Federal Regulations. If you have any questions regarding
the applicability of this action to a particular entity, consult the
person in the FOR FURTHER INFORMATION CONTACT section above.

II. Renewable Fuel Standard (RFS2) Program Amendments

    EPA issued final regulations implementing changes to the Renewable
Fuel Standard program required by EISA on March 26, 2010, at 75 FR
14670 (``the RFS2 regulations''). Following publication of the RFS2
regulations, EPA discovered some technical errors and areas that could
benefit from clarification or modification and, in parallel proposed
and direct final rules published on May 10, 2010 (75 FR 26049, 75 FR
26026), included amendments to the regulations to correct these
deficiencies. EPA received adverse comment on a few of the amendments
and therefore, on June 30, 2010, withdrew the portions of the direct
final rule that were the subject of adverse comment (75 FR 37733). The
withdrawn provisions consist of the following:

--Certain of the amendments to Sec.  80.1401, specifically those which
moved the definitions of ``actual peak capacity,'' ``baseline volume,''
and ``permitted capacity'' from Sec.  80.1403(a), revised the
definition of ``actual peak capacity'' to clarify how it is calculated,
and revised the definition of ``permitted capacity'' to clarify the
dates by which permits used to establish a facility's permitted
capacity must have been issued or revised;

--Sec.  80.1425, which clarified that RINs generated after July 1,
2010, may only be generated and transferred using the EPA Moderated
Transaction System (EMTS) and will not be identified by a 38-digit
code, and that the value of EEEEEEEE in a batch-RIN will be determined
by the number of gallon-RINs generated for the batch;
--Sec.  80.1426(d)(1), Sec.  80.1426(f)(3)(iv), and Sec.
80.1426(f)(3)(v), which clarified that a unique batch code in the RIN,
or its equivalent in EMTS, is used to identify a batch of renewable
fuel from a given renewable fuel producer or importer;
--Table 2 to Sec.  80.1426, which clarified the extent to which
renewable fuel producers must use advanced technologies in order for
their fuel to qualify for certain pathways identified in Table 1 to
Sec.  80.1426;
--Sec.  80.1426(f)(12), which clarified the requirements for gas used
for process heat at a renewable fuel facility to be considered biogas
for purposes of Table 1 to Sec.  80.1426;
--Sec.  80.1452(b), which clarified that RINs must be generated in EMTS
within five business days of being assigned to a batch of renewable
fuel and clarified the information required to be submitted via EMTS
for each batch of renewable fuel produced or imported; and,
--Sec.  80.1452(c), which clarified that transactions involving RINs
generated on or after July 1, 2010, must be conducted via EMTS within
five business days of a reportable event, and clarified the meaning of
the term ``reportable event'' and the information required to be
submitted via EMTS for each transaction involving RINs generated on or
after July 1, 2010.

EPA published a parallel proposed rule (75 FR 26049) on the same day as
the direct final rule (75 FR 26026). The proposed rule invited comment
on the provisions of the direct final rule and indicated that a second
comment period would not be offered on the proposal in the event that
portions of the direct final rule were withdrawn in response to adverse
comment. In this action, we are responding to the comments received on
the portions of the direct final rule that were subsequently withdrawn,
and we are taking final action regarding the withdrawn provisions based
on consideration of these comments. We are also finalizing a minor
amendment to Sec.  80.1451(b)(1)(ii)(M) which was described in the
preamble to the direct final rule and was included in the accompanying
regulations, but the amendatory language prefacing the regulation
inadvertently omitted reference to it. As a result, the Office of the
Federal Register did not codify the amended regulation even though it
was included in the direct final rule. The modification simply removes
the words ``of renewable fuel'' to make the regulatory language
consistent with other entries in the subparagraph. We received no
adverse comment on this proposed amendment, and we consider it a non-
substantive technical correction.

A. Permitted Capacity for Renewable Fuel Production Facilities

    In the final RFS2 regulations, we specified in Sec.  80.1403(a)(1)
that the ``baseline volume'' of fuel that is exempt from the 20 percent
greenhouse gas (GHG) reduction requirement at grandfathered facilities
described in Sec. Sec.  80.1403(c) and (d) would be determined by their
``permitted capacity'' or, if that could not be determined, by their
``actual peak capacity.'' In the registration provisions at Sec.
80.1450(b)(1)(v)(B), we identified the permits that are relevant in
establishing ``permitted capacity.'' Specifically, for facilities that
commenced construction on or before December 19, 2007, the final RFS2
regulations stated that ``permitted capacity'' is based on permits
issued or revised no later than December 19, 2007. For ethanol
facilities that commenced construction after December 19, 2007, and on
or before December 31, 2009, and that are fired with natural gas,
biomass, or a combination thereof, the RFS2 regulations stated that
``permitted capacity'' is based on permits issued or revised no later
than December 31, 2009.
    In the final RFS2 regulations, we did not include in the definition
of ``permitted capacity'' references identical to those placed in the
registration section to the latest issuance dates of permits that could
be used to establish ``permitted capacity.'' Therefore, in the direct
final rule published at 75 FR 26026 (May 10, 2010), EPA modified the
definition of ``permitted capacity'' to specify the same dates for
relevant permits as were provided in the registration provisions in the
final RFS2 regulations. We believed that such a revision would improve
the clarity of the regulations, while not changing the substance of the
requirements.
    However, we received adverse comments during and after the comment
period expressing concern over the modified definition of ``permitted
capacity,'' which commenters stated posed ``new constraints'' on the
qualification of eligible fuel volumes that could be exempt at
grandfathered facilities. One commenter described an ethanol facility
fired by natural gas, and therefore potentially eligible for an
exemption from the 20 percent GHG reduction requirement pursuant to
Sec.  80.1403(d), for which permits were issued and construction
completed prior to December 31, 2009, and for which an application for
a permit revision seeking an increase in permitted capacity was
submitted to the permitting authority in 2008. The commenter claimed
that the revised permit reflected the facility's original plant design,
however the permitting authority did not issue a revised permit for the
facility until March 2010. According to the revised definition of
``permitted capacity'' in the regulations as amended by the direct
final rule and according to the original registration requirements of
the final RFS2 regulations, permits issued or revised after December
31, 2009, could not be used to establish ``permitted capacity,'' and
therefore the additional capacity in the revised permit could not be
included in the facility's baseline volume. The commenter explained
that many ethanol producers originally applied for permits for their
facilities based on conservative initial production volumes supported
by their plant designers' emission guarantees, and that after an
initial period of operation, performance testing, and fine tuning of
operations, they have found that they could produce greater volumes.
They explained that many developers of ethanol facilities, including
their own, sought to obtain construction permits without going through
EPA's New Source Review (NSR) program, and were able to do so by
obtaining construction permits that specified less than 100 tons per
year of emissions even though their facilities were capable of emitting
more and producing a correspondingly greater volume of renewable fuel.
In May 2007, when EPA changed to 250 tons per year the emissions
threshold that would trigger NSR for ethanol production facilities,
these plants then found it in their interest to seek increases in their
permitted capacity beyond that specified in their earlier-issued
permits, since they could do so without triggering NSR. The commenter
argued that ethanol facilities should be allowed to use the capacity in
such later-issued permits, including their own March 2010 revised
permit, to establish their ``permitted capacity'' under RFS2.
    We also received additional comments after the close of the

comment period from a collective group of ethanol facilities in
Illinois referencing the initial commenter's comments that the cut-off
dates in the revised definition of ``permitted capacity'' created
restrictions for their facilities that would prohibit them from having
the ``inherent capacity'' of their facilities qualify for the
grandfathering exemption under RFS2. In addition, the commenters
referenced what they felt was an inequitable allowance for facilities
located in states that did not place production limits in their air
permits, who therefore were allowed to use ``actual peak capacity''
(which is based on actual production records \1\) to establish their
baseline volume exempt from the 20 percent GHG reduction requirement
under RFS2. The commenters further cited potential cost effects if
their full ``inherent capacity'' was not allowed to be included in the
exempt baseline volume, such as the additional costs associated with
either plant modifications (presumably needed to qualify their non-
exempt fuel as meeting the 20 percent GHG reduction requirement) or
exporting the non-exempt volume of fuel for consumption outside of the
United States.
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    \1\ Pursuant to Sec.  80.1403(a)(3)(i) in the RFS2 regulations
issued March 26, 2010, ``actual peak capacity'' is based on the last
five calendar years prior to 2008 for facilities qualifying under
Sec.  80.1403(c) unless no such capacity exists, in which case it is
based on any calendar year after startup during the first three
years of operation. For facilities qualifying pursuant to Sec.
80.1403(d), ``actual peak capacity'' is based on any calendar year
after start-up during the first three years of operation, as
specified in Sec.  80.1403(a)(3)(ii).
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    The commenters proposed revised language for the definition of
``permitted capacity'' that would allow an extended time frame for
facilities to seek permit modifications to reflect their ``inherent
capacity.'' They proposed that EPA modify the final RFS2 regulations to
allow facilities to use as their baseline volume the capacity limits in
permits issued by regulatory authorities which were applied for within
three years after start-up of a new or expanded facility (but not less
than one year after the effective date of the final rule) and issued
within not more than two years thereafter. The commenters also stated
that many facilities had no notice of EPA's time limitation on those
permits in either the proposed or final RFS2 rule (74 FR 24904,
published May 26, 2009, and 75 FR 14670, published March 26, 2010) and
therefore had inadequate notice to make appropriate plans to apply for
and obtain new permits within the RFS2 deadlines. They further
expressed concern that the permit cut-off date that restricts
grandfathered production capacity precedes the date of the proposed
rule. They also cited a statement made in the proposed RFS2 rule that
EPA's guiding principal is to ``allow production increases within a
plant's inherent capacity'' (74 FR 24904, 24926, May 26, 2009). One
commenter also referred to EPA's RFS2 Summary and Analysis of Comments,
p. 3-139 (Pub. No. EPA-420-R-10-003, February 2010), in which, they
state, EPA assumed that permitted capacity would likely reflect maximum
inherent capacity. The commenter said that such an assumption would be
valid for some situations, but not valid for others, especially with
the limitations EPA intended to place on the date of permits that could
be used to establish ``permitted capacity.''
    The Energy Independence and Security Act of 2007 (EISA or ``the
Act'') provides that the 20 percent GHG reduction requirement applies
to ``new facilities'' that commence construction after the date of
enactment. It also provides that ``for calendar years 2008 and 2009,
any ethanol plant that is fired with natural gas, biomass, or any
combination thereof is deemed to be in compliance with [the] 20 percent
reduction requirement * * *'' In the proposed RFS2 rule we noted that
the term ``new facility'' is not defined in EISA and, therefore, that
EPA would need to interpret the term in the context of the RFS2
regulations. We also noted ambiguity in the statutory section related
to ethanol facilities that commenced construction in 2008 and 2009 and
that are fired with natural gas or biomass, in that the Act was not
clear as to whether these facilities should be ``deemed compliant''
with the 20 percent GHG reduction requirement for only the two years
specified, or indefinitely. For both types of facilities, we believe
the approach we are finalizing in this rule provides an appropriate
method of implementing statutory requirements that is consistent with
the text and objectives of the statute, while also leading to a
workable program.
    First, with respect to ``deemed compliant'' ethanol facilities
fired with natural gas or biomass for which construction commenced
after enactment of EISA but on or before December 31, 2009, we believe,
as discussed in the proposed RFS2 rule, that Congress could have
intended that these facilities are only ``deemed compliant'' for those
two years or for a longer or indefinite time period (assuming they
continued to be fired with natural gas or biomass). The ambiguity can
be seen through a comparison of the first sentence of EISA Section
210(a) and the second sentence. The first sentence provides that ``for
calendar year 2008, transportation fuel sold or introduced into
commerce in the United States'' that is produced by facilities that
commenced construction after the date of enactment of EISA must meet
the 20 percent GHG reduction requirement. This sentence is very
specific, applying directly to ``transportation fuel'' that is ``sold
or introduced into commerce'' in 2008. The second sentence in this
section does not specifically refer to fuel, but instead refers to
``any ethanol plant that is fired with natural gas, biomass, or any
combination thereof'' and provides that such facilities are ``deemed
compliant'' with the 20 percent GHG reduction requirements of the Act.
The sentence is introduced by the words ``[f]or 2008 and 2009.'' Since
fuel from facilities that commenced construction prior to the date of
enactment is already exempt from the 20 percent GHG reduction
requirement by virtue of CAA Section 211(o)(2)(A)(i), the ``deemed
compliant'' provision in the second sentence of EISA 210(a) clearly
applies to ethanol facilities that commenced construction after that
date.
    We believe the scope of the exemption is ambiguous, however,
because Congress did not specifically refer to fuel sold in specified
years in the second sentence, as they did in the first sentence, but
instead referred to ``ethanol plants.'' Because of this construct, it
is unclear exactly what fuel should be covered by the exemption. EPA
identified two general approaches to interpreting this provision in its
proposed rule: Either interpreting it to provide a limited two year
exemption, or interpreting it to provide an exemption for fuel produced
by qualifying facilities that would be of equal duration to the
exemption provided in CAA Section 211(o)(2)(i) for fuel from facilities
that commenced construction prior to EISA enactment. We reasoned that
it would be a harsh result for investors in these new facilities, and
generally inconsistent with the energy independence goals of EISA, to
interpret the Act such that these facilities would only be guaranteed
two years of participation in the RFS2 program. Therefore in our final
RFS2 regulations we provided an indefinite exemption from the 20
percent GHG reduction requirement for their baseline volumes
(determined through either ``permitted capacity'' or, if ``permitted
capacity'' cannot be determined, ``actual peak capacity'') provided
that they continue to be fired by natural gas, biomass, or a
combination thereof.
    Contrary to the commenters' assertions, nothing in EISA suggests
that

these ``deemed compliant'' facilities should be allowed to continually
expand their production beyond levels achieved in 2008 and 2009 simply
because they could do so without additional physical construction.
Rather, the approach EPA has adopted of seeking to limit the exempt
volume at these grandfathered facilities to that which was lawfully
allowed in applicable permits issued no later than December 31, 2009,
is fully consistent with the statutory references to 2008 and 2009.
    We believe it is consistent with the statutory text to limit the
grandfathered production from ``deemed compliant'' facilities to the
maximum volume allowed under applicable permits in the 2008 to 2009
timeframe. We also believe that this approach is supported by the same
policy considerations, discussed below, that have led us to a similar
approach for facilities that commenced construction prior to EISA
enactment. We have only deviated from this concept with respect to
those ``deemed compliant'' facilities for which capacity cannot be
determined by reference to applicable permits. Those facilities, some
of which may not have been operational in the 2008 to 2009 timeframe,
by necessity are allowed to establish their baseline volume by
reference to actual production levels (``actual peak capacity'') within
a specified time period after they commence operations. For both
``deemed compliant'' facilities and facilities that commenced
construction prior to EISA enactment, we believe that allowing
facilities to establish their baseline volume by actual production for
any calendar year within the first three years of operation is
appropriate because it allows a reasonable amount of time to correct
possible production launch problems. This is an exception to the
general rule, and is allowed only if permit limits are not available to
establish baseline volume.
    While there may be instances, as suggested by commenters, in which
facilities that use ``actual peak capacity'' to establish their
baseline volume could come closer to obtaining an exemption for what
the owner may consider their ``inherent capacity'' than those
establishing their baseline volume through permit limits, EPA notes
that this need not always be the case. For example, some plants, whose
baseline volume is established through ``actual peak capacity'' because
they do not have a capacity stated on a permit, may not, due to certain
start-up problems or market conditions, actually produce up to their
projected or potential capacity during the first three years of
operation. Nonetheless, they are required under the final RFS2
regulations to use the maximum annual production during these first
three years of operation to establish their baseline volume.\2\ On the
other hand, some plants that applied for permits reflecting a certain
``permitted capacity'' that may have been based on their facility's
projected maximum capacity, but who in practice may not be able to
achieve this capacity or do not do so for some period of time due to
market conditions, are allowed under the final RFS2 regulations to use
this higher ``permitted capacity'' to establish their baseline volume.
In these scenarios, baseline volume established through ``permitted
capacity'' may be greater than the baseline volume that could be
achieved by a comparable facility by reference to actual production
during the first three years of operation. Thus, while it is true that
``permitted capacity'' does not always reflect potential capacity,
``actual peak capacity'' also does not necessarily reflect a facility's
potential capacity, as demonstrated in our examples above. Therefore,
we disagree with the commenters' statement that facilities using
``actual peak capacity'' to establish their baseline volume have an
unfair advantage over facilities that must use their ``permitted
capacity'' to establish their baseline volume.
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    \2\ We note that while some air permits may not contain
restrictions on plant capacity, most contain restrictions on
emission rates, fuel consumption, throughputs, and sizes of vessels.
Thus, there are some limitations on capacity that are related to
restrictions on these parameters in the air permit.
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    With respect to facilities that commenced construction before the
date of enactment of EISA, commenters also state that EPA should
interpret the EISA grandfathering provisions to allow volumes from such
facilities to be exempt up to the maximum of their ``inherent
capacity.'' The statute does not use the term ``inherent capacity,''
and instead applies the 20 percent GHG reduction requirement to ``new
facilities that commence construction'' after the date of enactment. In
the RFS2 rulemaking, EPA addressed the issue of how to implement this
grandfathering provision by defining both the facilities and their
production volumes that would be grandfathered, and considering all
other production volumes to be subject to the 20 percent GHG reduction
threshold. EPA identified the grandfathered volumes in two steps.
First, EPA identified the facilities that could be considered available
for grandfathering by using definitions of ``facility'' and ``commence
construction'' that were similar but not identical to those used in
EPA's stationary source Prevention of Significant Deterioration (PSD)
permitting program. After identifying these facilities, EPA followed a
second step to identify what volumes at those facilities would be
grandfathered. In this final rulemaking, EPA is addressing the same
issue of what volume should be grandfathered as we did for the final
RFS2 rulemaking.
    EPA rejected the approach of determining that any and all volumes
produced at qualifying facilities should be considered grandfathered.
EPA also rejected the approach specified in the NPRM of requiring
facilities to report on expenses for replacements, additions, and
repairs so that EPA could determine on a case-by-case basis if such
activities warranted considering the facility as effectively ``new''
for purposes of the grandfathering provisions. Instead, EPA chose an
approach that extends an indefinite exemption to baseline volumes at
qualifying facilities, and defines the grandfathered volume by
reference to ``permitted capacity'' contained in air permits that
govern the operation of a facility at the time of the statutory
deadline. If such capacity is not stipulated in the permit, then the
baseline is established by ``actual peak capacity'' achieved within
either the last five calendar years prior to 2008 or, if the plant is
not yet in operation, the first three years after start-up. The
``permitted capacity'' or the actual operations history of the plant
would define a baseline volume, and increases above 105 percent of this
volume would be considered production by a new facility. These criteria
are objective and their use avoids the case-by-case decision-making
that would be required if less objective criteria were applied.
    In this rulemaking, EPA proposed to clarify but not change this
approach, and commenters have suggested that EPA now change the
approach substantially. EPA rejects this request for a change in
approach for many of the same reasons given in the preamble to the
final RFS2 regulations.
    First, EPA notes that the statute does not define the terms ``new
facility'' or ``commence construction,'' providing EPA discretion to
interpret these terms in a reasonable fashion that promotes the goals
of the statute. EPA notes that there were no objections to how EPA
defined the universe of facilities that can produce grandfathered
renewable fuel in the proposed RFS2 regulations. Rather, commenters
raised issues regarding what volumes and years of production from these
facilities (and from any modifications or expansions to the facilities)
should be considered grandfathered. The only issue raised in

the current set of comments, however, is the extent to which volumes
above those allowed at the time of the statutory deadlines should be
grandfathered.
    As in the RFS2 rulemaking, EPA is faced with two basic approaches.
The first approach is raised by commenters who suggest applying the
concept of ``maximum capacity'' or ``inherent capacity'' on a case-by-
case basis. Some commenters have suggested this could be limited in
time to a set number of years in the future. Under this approach, EPA
would evaluate each permit revision that occurs and would need to
determine if the changes undertaken were within the ``inherent
capacity'' of a qualifying facility. If they were not, the volumes
would be considered produced by a new facility for which construction
commenced after the statutory deadline.
    EPA does not agree that this is either a required or an appropriate
approach. EISA does not define the phrase ``new facilities that
commence construction,'' nor does it refer to or require that EPA
follow the approach suggested by the commenters. As was the case in the
proposed and final RFS2 rules, EPA is concerned about the lack of
objectivity and concreteness in applying a concept such as ``inherent
capacity.'' There is no clear or concrete meaning to this term. In
practice, renewable fuel facilities can and do evolve over time. A
facility and its operations are typically in a constant state of flux
to address changing circumstances and to optimize production under
those circumstances. These changing circumstances can involve a full
range of activities that may include changes in equipment or
operations, with any of these changes ranging from minor to major. Once
one aspect of facility design or operation that constrains capacity is
optimized, another aspect becomes the constraining factor. This
process, which can include what is often referred to as
debottlenecking, is iterative and can continue indefinitely. Thus the
terms ``inherent capacity,'' ``nameplate capacity,'' and ``design
capacity'' have meaning only in a general or broad sense. EPA does not
believe it could develop criteria that would fairly and objectively
define these terms. Without such criteria, the case-by-case analysis to
implement such an approach would be difficult to accomplish in a fair
and consistent manner, thus making such an approach undesirable.
Instead, EPA's approach is definitive, allowing in all cases 105
percent of ``permitted capacity'' or, if permit limits are not
available, 105 percent of ``actual peak capacity'' to establish
baseline volumes. The 105 percent factor allows a consistent and
definitive allowance beyond ``permitted capacity'' or ``actual peak
capacity'' measures. As stated in the preamble to the final RFS2 rule,
it provides an allowance for debottlenecking and minor changes that may
be brought about by normal maintenance that is consistent with the
proper operation of a facility, while being sufficiently small so as to
not encourage plant expansions that are unrelated to debottlenecking
and normal maintenance procedures (75 FR 14670, 14689, March 26, 2010).
EPA believes that such an allowance is consistent with the concept of
applying the 20 percent GHG reduction requirement to ``new facilities
that commence construction'' after EISA, while not also introducing a
difficult case-by-case implementation approach to the rules as
suggested by the commenters.
    Under the approach taken in the final RFS2 rule and clarified in
the direct final rule, future changes in production above 105 percent
of the baseline volume would be treated as production by a new facility
that commenced construction after the statutory deadline. Typically the
increase in production, whether caused by a permit change or otherwise,
would be the result of changes made in order to increase production,
whether physical changes in equipment or changes in operation. These
changes would make the plant different in a way that would allow it to
produce more renewable fuel. Implementation of these changes would be
considered construction, whether it is from a process of physical
construction, physical replacement, change in operation, redesign, or
reconfiguration. EPA broadly interprets the terms ``new'' and
``construction'' in the final RFS2 rule to encompass the kinds of
changes typically taken to increase production.
    EPA recognizes that the approach we have taken in the final RFS2
rule encompasses a broad variety of physical, operational, and other
efficiency changes. EPA favors its approach because it gives reasonable
meaning to the terms in EISA in a way that provides clear and objective
criteria, and it avoids the problems and complexities noted above with
the case-by-case approach that tries to implement an ``inherent
capacity'' criterion. It is also a reasonable way to further the goals
of the grandfathering provision and for evaluating future increases in
production.
    By arguing that the ``inherent capacity'' of a plant built before
enactment must be grandfathered regardless of permit limitations on the
date of enactment, commenters seem to be equating the term
``construction'' in the statute with ``physical construction.'' Their
rationale is that if the increased volumes are not derived from new
physical construction of a facility after the date of enactment, then
any and all fuel from that grandfathered facility must be covered by
the exemption. However, the term ``construction'' is not defined in
EISA and need not be viewed in this manner. For example, Congress
defined the term ``construction'' in CAA section 169(2) for the PSD
program to include ``modifications'' as defined in CAA section
111(a)(4). That term is defined in the statute to include ``any change
in, or change in the method of operation of, a stationary source which
increases the amount of any air pollutant emitted by such source or
which results in the emission of any air pollutant not previously
emitted.'' The definition of ``commence construction'' adopted in the
final RFS2 regulations specifically incorporates by reference the
definition of ``begin actual construction'' from the PSD regulations,
where the term ``construction'' is defined as ``any physical change or
change in the method of operation * * * that would result in a change
in emissions.'' (See 40 CFR 80. 1403(a)(4), 52.21(b)(1) and
53.21(b)(8).) EPA's treatment of post-enactment ``construction'' under
the final RFS2 regulations to include operational modifications leading
to the production of additional renewable fuel is therefore comparable
to the approach adopted by Congress in the PSD program with respect to
modifications that may lead to increased emissions.
    The approach EPA adopted in the final RFS2 rule, and which we
reaffirm today, reasonably promotes the goals of this statutory
provision. EPA's analysis as part of the RFS2 rulemaking showed that
the aggregate volumes of grandfathered ethanol for the entire industry
would be approximately 15 billion gallons (74 FR 24904, 24925, May 26,
2009). Given the volume mandates and GHG reduction thresholds for the
other three categories of renewable fuel (advanced biofuel, biomass-
based diesel, and cellulosic biofuel), 15 billion gallons is (by
coincidence) approximately the maximum amount of grandfathered ethanol
that could be used in the RFS2 program for compliance purposes.\3\ In
addition, EISA provides a considerable benefit to facilities claiming
exemption from the 20 percent GHG reduction threshold. Such an
exemption is not

provided to similar facilities for which construction commences after
the statutory deadlines. The exemption reasonably preserves the
investment decisions of owners made prior to the time of enactment of
EISA. Those investment decisions were clearly based on the practices of
the facilities constructed on or before the statutory deadlines,
including any permit-related constraints in existence at the time. Any
future increases in production based on future permit changes could
generally be an enhancement to the value of the facility and would be
based on future decisions, not investment decisions made prior to
enactment of EISA.
---------------------------------------------------------------------------

    \3\ Table 1.1.1 from ``Renewable Fuel Standard Program (RFS2)
Regulatory Impact Analysis'' (EPA-420-R-10-006); February 2010.
---------------------------------------------------------------------------

    We acknowledge the statement we made in the proposal for the RFS2
regulations, referenced by one of the commenters, that ``our guiding
philosophy of protecting historical business investments that were made
to comply with the provisions of RFS1 are realized by allowing
production increases within a facility's inherent capacity,'' (74 FR
24904, 24926, May 26, 2009). We need to point out, however, that the
statement was made in the context of soliciting comment on allowing a
10 percent tolerance level above ``permitted capacity'' and, as noted
above, we proposed that ``permitted capacity'' would be ascertained at
the time of facility registration. The 10 percent allowance was,
therefore, proposed for comment as a straightforward and readily-
implementable mechanism to reflect in grandfathered volumes as much of
a plant's ``inherent capacity'' as practical while avoiding case-by-
case assessments into the future indefinitely. In the same paragraph in
the proposal, we further state that ``at the same time, the alternative
of requiring compliance with the 20% GHG reduction requirement for
increases in volume above 10% over the baseline volume, [sic] would
place new volumes from grandfathered facilities on a level playing
field with product from new grass roots facilities. We believe that a
level playing field for new investments is fair and consistent with the
provisions of EISA,'' (74 FR 24904, 24926, May 26, 2009).
    Based on comments received on the RFS2 proposed rule, we decided to
reject the 10 percent tolerance and ``to interpret the exemption of the
baseline volume of renewable fuel from the 20 percent GHG reduction
requirement as extending indefinitely.'' We noted that any tolerance
provided could, therefore, ``be present in the marketplace for a
considerable time period.'' Furthermore, we also stated that
``increases in volume of 10 percent or greater could be the result of
modifications other than debottlenecking,'' and instead adopted a 5
percent tolerance level (75 FR 14670, 14689, March 26, 2010). We
believe that these statements from the preamble to the RFS2 final rule
are consistent with the arguments we have set forth above.
    We disagree with the commenters' statement that facilities had
inadequate notice of the time limitations for permits that could be
used to establish baseline volume that is exempt from the 20 percent
GHG reduction requirement. The preamble to the proposed rule stated
that ``the facility registration process * * * would be used to define
the baseline volume for individual facilities. Owners and operators
would submit information substantiating the nameplate capacity of the
plant, as well as historical annual peak capacity if such is greater
than nameplate capacity,'' (74 FR 24904, 24926, May 26, 2009). In the
proposal, nameplate capacity was defined in terms of permitted
capacity. Furthermore, in discussing the facility registration process,
the preamble stated that ``in order to determine what production
volumes would be grandfathered and thus deemed to be in compliance with
the 20% GHG threshold, we would require * * * information necessary to
establish [a facility's] renewable fuel baseline volume * * * '' (74 FR
24904, 24942, May 26, 2009). These discussions made it clear that the
baseline volume would be determined in the registration process, and
they did not indicate that making such determinations would be an
ongoing process into the future. Under the RFS2 proposal, registration
was to occur by January 1, 2010, or 60 days prior to commencement of
production, whichever was later. The January 1, 2010, proposal date for
the submission of permits to establish baseline volume with
registration materials is fully consistent with the provision in the
final rule that permits used to establish ``permitted capacity'' for
``deemed compliant'' facilities must have been issued no later than
December 31, 2009, and for other grandfathered facilities by December
19, 2007. While the proposal would have allowed grandfathered
facilities that commenced production after January 1, 2010, additional
time to submit their registration materials, the preamble discussion
did not suggest that this would afford them the opportunity to use
permits issued after the relevant time periods referenced in EISA for
purposes of establishing baseline volume. In addition, in describing
EPA's basic proposal, EPA explained that, for facilities that commenced
construction prior to EISA enactment, volumes greater than baseline
volume ``which may typically be due to expansions of the facility which
occur after December 19, 2007, would be subject to the 20% GHG
reduction requirement in order for the facility to generate RINs for
the incremental expanded volume. The increased volume would be
considered as if produced from a `new facility' which commenced
construction after December 19, 2007.'' EPA believes that these
preamble statements provided adequate notice to the regulated community
that EPA was considering limitations on the dates of permits that could
be used to establish baseline volume, and also believes that commenters
were reasonably apprised based on the discussion of dates in the
preamble and the dates referenced in the statute that the permit cut-
off dates ultimately selected for this purpose were under
consideration.
    As stated previously, the definition of ``permitted capacity'' in
the direct final rule was revised to include the same permit cut-off
dates referenced in the existing unamended registration section in the
final RFS2 regulations. The direct final rule would not have
established these cut-off dates as new requirements, but would merely
have provided clarity to the existing regulations by placing references
to permit dates in the definition of ``permitted capacity'' that are
comparable to those that already existed in Sec.  80.1450(b)(1)(v)(B).
Commenters clearly had notice of these permit cut-off dates in
commenting on the direct final rule, and brought their concerns to
EPA's attention in the context of this rulemaking. EPA has considered
these comments and has decided not to revise the regulations in the
manner they have proposed, but instead, for all of the reasons
discussed above, to finalize in this rule the same definition of
``permitted capacity'' that was included in the direct final rule and
parallel proposal.
    EPA is also finalizing the amendments included in the direct final
rule and parallel proposal that we did not receive adverse comment on,
but that were tied to the revised definition of ``permitted capacity''
and therefore were also withdrawn in the June 30, 2010, notice (75 FR
37733). These related amendments move the definitions of ``actual peak
capacity,'' ``baseline volume,'' and ``permitted capacity'' from their
original locations at Sec.  80.1403(a) to Sec.  80.1401 in order to
consolidate them with other definitions used in 40 CFR part 80, subpart
M. They revise the definition of ``actual peak capacity'' to clarify
that actual peak capacity for facilities that commenced

construction prior to December 19, 2007, but that did not have at least
one calendar year of actual production prior to 2008, should be based
on any calendar year after startup during the first three years of
operation. They also clarify that for facilities that commenced
construction after December 19, 2007, but before January 1, 2010, that
are fired with natural gas, biomass, or a combination thereof, ``actual
peak capacity'' is based on any calendar year after startup during the
first three years of operation. These amendments, which are closely
tied to changes to the definition of ``permitted capacity'' that we are
finalizing today, are also being finalized as they were proposed at 75
FR 26049 (May 10, 2010).

B. Treatment of Renewable Identification Numbers

    In order to facilitate the transition from RFS1 to RFS2, many of
the final RFS2 regulations clarified the differences between how
Renewable Identification Numbers (RINs) are treated under each program.
However, in the final RFS2 rule, the section on product transfer
documents (PTD) requirements was not clear about the information that
must be on PTDs for RINs under the RFS2 program, and we issued several
amendments to Sec.  80.1453 in the direct final rule to clarify the PTD
requirements under RFS2. We did not receive any adverse comment on
these amendments.
    In conjunction with the amendments to Sec.  80.1453, we proposed
amendments to Sec.  80.1425, which provides a description of the 38-
digit RIN. The amendments were meant to clarify that RINs generated
under RFS2 are not identified by a 38-digit code, but rather that most
of the information contained within the RFS1 38-digit code is entered
and made available in the EPA Moderated Transaction System (EMTS) as
separate data elements. We also proposed amendments to Sec.
80.1426(d)(1), (f)(3)(iv), and (f)(3)(v) to clarify that either the
batch (BBBBB) component of the RIN or its EMTS-equivalent can be used
to identify a particular batch of renewable fuel.
    We received adverse comment from several parties on the proposed
amendments to Sec.  80.1425, who took issue with the elimination in
EMTS of the SSSSSSSS and EEEEEEE components (start and end numbers) of
the RFS1 38-digit RIN. The commenters expressed concern that the 38-
digit code was being abandoned and claimed this proposed change would
impact a regulated party's right and ability to maintain an independent
accounting of their RINs at a unit (gallon-RIN) level. They also
claimed that without this information, attempts to manage RIN
transactions would be problematic for the regulated community.
Furthermore, the commenters stated that they saw no steps taken in the
rulemaking process that would have notified industry of EPA's intent to
move away from the 38-digit RIN.
    In the preamble to the RFS2 NPRM, we outlined the concept for EMTS
and described the circumstances experienced under the RFS1 program that
led us to conclude that such a system would be necessary and preferable
to the RFS1 approach to RIN generation and transaction. We stated that
``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. * * * We
have also seen incorrect numbering of volume start and end codes,'' (74
FR 24974). In the preamble to the NPRM, we also acknowledged that
``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,'' (74 FR 24974). Finally, we
noted that ``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,'' (74 FR 24974).
    We proposed and finalized EMTS in the RFS2 rulemaking process as
the solution to address most, if not all, of these issues, and to
handle the increasingly complex RIN generation and transaction
requirements under RFS2 due to the increased volume mandates and four
categories of renewable fuel. While the commenters are correct that
EMTS does not employ the 38-digit RIN as it was originally conceived
for the RFS1 program, the system is designed to allow users to transact
RINs in a generic way while still maintaining the ability to know any
individual RIN's source at a company and facility level. We described
this change in the preambles to both the proposed and final RFS2
regulations. (See 74 FR 24975 and 75 FR 14733.) Specifically, in the
preamble to the final RFS2 regulations, we stated, ``one major
advantage of EMTS * * * is that the system will simplify trading by
allowing RINs to be traded generically. Only some specifying
information will be needed to trade RINs, such as RIN quantity, fuel
type, RIN assignment, RIN year, RIN price or price per gallon. * * *
The actual items of transactional information covered under RFS2 are
very similar to those reported under RFS1,'' (75 FR 14733).
    Indeed, all major components of the RIN as conceived under the RFS1
program are used in EMTS with the exception of the ``S'' and ``E''
starting and ending RIN values. The S and E components of the 38-digit
RIN served two purposes under RFS1. One was to determine the number of
gallon-RINs contained in a batch-RIN segment, calculated by subtracting
the ending RIN value from the starting RIN value. The second use was to
ensure that the number of gallon-RINs represented by a batch-RIN did
not grow or decrease as it was passed from buyer to seller, in many
cases multiple times. As noted above, under RFS1, an overlap or
duplication of S and E codes between transactions was an indication
that something had gone wrong during the exchange of RIN information.
    Under RFS2, EMTS performs transactions of individual RINs (the RFS1
equivalent of gallon-RINs) with a simple reference to RIN quantity, and
the system does not use S and E components. Being a closed system,
there is no opportunity for a RIN owner to purposefully or accidentally
increase or decrease the number of RINs originally associated with a
batch of renewable fuel. The original RIN quantity may be subdivided
into smaller parts as the RINs and renewable fuel are transferred from
one party to another, but EMTS accounts for the original total number
of RINs at all times. This feature allows EMTS to manage RIN quantities
without the need for S and E components.
    We believe that the comment we received suggesting that a regulated
party's right and ability to maintain an independent accounting of
their RINs at a unit level would be negatively affected by eliminating
the use of the 38-digit RIN is unfounded. In the preambles to both the
proposed and final RFS2 rules, we discussed the fact that, like under
the RFS1 program, there is no ``good faith'' provision with respect to
RIN ownership. To help companies manage their RINs in such a ``buyer
beware'' environment, we proposed and finalized that a RIN purchaser
can accept or reject RINs from specific RIN generators or from classes
of RIN generators (74 FR 24975, 75 FR 14733). In practice, this
allowance has translated into a function within EMTS that allows a RIN
account holder to block RINs generated by specific companies and/or
facilities.

EMTS now also allows a RIN transferee to review details of RINs offered
by a transferor, such as the RIN generators' company and facility ID
numbers, prior to accepting or rejecting the transaction. In this way,
a RIN account holder can protect himself or herself from being
transferred RINs generated by a company with whom the RIN account
holder chooses not to do business, even if indirectly. There is also a
function within EMTS that allows a RIN account holder to transact
unique, as opposed to generic, RINs. Unique RINs carry specific
information related to the RIN generator, date of production, and batch
number. As discussed above, EMTS is a closed system, and the total
number of RINs associated with a particular batch of renewable fuel
cannot increase or decrease even as the RINs are subdivided and
transferred to multiple RIN owners. This fundamental characteristic of
EMTS, together with the added features of being able to block certain
RINs and trade unique ones, enhances the ability of any RIN account
holder to protect their interests.
    As for the commenters' concerns that they were not notified of
EPA's intent to move away from the 38-digit RIN during the RFS2
rulemaking process, EPA disagrees. As discussed above, EPA introduced
the concept and basic functionality of EMTS in the preamble to the RFS2
NPRM (74 FR 24904) and development of the new system commenced shortly
thereafter. The process of development and testing was conducted openly
and with significant stakeholder input and participation, including
direct involvement by at least one of the commenters. A number of
workshops, webinars and discussions were held throughout the period
between publication of the NPRM and issuance of the final RFS2
regulations. In addition, presentation materials, users' guides, data
schema, data templates, and tutorials were offered for interested
parties to understand and provide input on system design and
development. Based on this input, EPA was able to successfully deploy
EMTS on July 1, 2010, concurrent with the RFS2 regulations taking
effect.
    We believe that the transition from the 38-digit RIN under RFS1 to
the generic RIN under RFS2 allows for greater system flexibility and
integrity, while maintaining the detailed RIN information necessary for
regulated parties to perform independent checks on RINs they generate,
receive, and transfer. In addition, we believe that the information
presented throughout the rulemaking process for RFS2 adequately and
transparently prepared regulated parties for the transition to EMTS.
For these reasons, we are finalizing the amendment to the introductory
text to Sec.  80.1425 as it was set forth in the May 10, 2010, direct
final rule and parallel proposal (75 FR 26026, 75 FR 26049).
Specifically, we are amending the text to clarify that RINs generated
after July 1, 2010, may only be generated and transferred using EMTS
and will not be identified by a 38-digit code. We are also amending
Sec.  80.1425(i) to simply clarify that the value of EEEEEEEE is a
number representing the last gallon-RIN associated with a volume of
renewable fuel.
    In addition to the proposed amendments to Sec.  80.1425, we also
proposed amendments to Sec.  80.1426(d)(1), (f)(3)(iv), and (f)(3)(v)
to clarify that either the batch (BBBBB) component in the RIN or its
EMTS-equivalent would be used to identify a particular batch of
renewable fuel. A commenter stated that the phrase ``or its equivalent
in EMTS'' when referring to batch-identifying information in EMTS is
not clearly defined, and they expressed concern that this language
would limit regulated companies from properly certifying their data and
would inhibit the ability of accountants to attest to their clients'
data. The commenter also requested that the language be clarified so
that regulated parties can certify their data and accountants can
reasonably rely on it.
    Under RFS1, the BBBBB code was a unique user-specified value that
could only contain numbers and had to contain five digits. The
requirement to assign a ``unique'' batch number allowed the regulated
community and EPA to determine which RINs were associated with each
volume of renewable fuel, and it prevented double-counting by requiring
renewable fuel producers or importers to generate one, and only one,
RIN for each volume of renewable fuel. Because it could represent up to
one calendar month's worth of renewable fuel production (or
importation) and up to 99,999,999 gallons, RIN generators frequently
generated 12 batches in a calendar year, one for each month. In EMTS,
the batch number is a unique user-specified value that can contain up
to 20 alphanumeric or other characters. It is a field required for RIN
generation and a RIN owner may view the batch number associated with
any RIN in their possession. We believe that the larger field format
and ability to use letters as well as other characters to identify a
batch in EMTS enhances a regulated party's ability to certify their RIN
data--either as RIN generators or as RIN owners--and, in turn, allows a
party's CPA to attest to the validity of such data. At the same time,
we agree with the comment that the proposed language was vague and does
not adequately describe what the EMTS-equivalent of the BBBBB code is.
We are therefore not finalizing the amendments to these sections and
will revert to the language in the final RFS2 regulations that simply
refer to a ``unique batch identifier,'' which may be either the five-
digit BBBBB component or the EMTS batch number of up to 20 characters.

C. Advanced Technologies for Renewable Fuel Pathways

    The final RFS2 rule includes two corn ethanol pathways in Table 1
to Sec.  80.1426 that require the use of one or two advanced
technologies at the production facility as a prerequisite to the
generation of RINs. The five advanced technologies available for this
purpose are listed in Table 2 to Sec.  80.1426. In developing this list
of advanced technologies, EPA relied upon modeling that included the
use of one or more advanced technologies at a base corn-ethanol
plant.\4\. In all cases, the modeling assumed use of a given advanced
technology across 100 percent of the ethanol production. The pathways
in Table 1 and the list of advanced technologies in Table 2 represent
the application of advanced technologies to 100 percent of production,
consistent with the modeling they were based on.
---------------------------------------------------------------------------

    \4\ A base plant is one representing average energy usage and no
advanced technologies. See the Regulatory Impact Analysis for the
RFS2 final rule, EPA-420-R-10-006, February 2010, Section <IP_ADDRESS>.
---------------------------------------------------------------------------

    However, neither the list in Table 2 nor the pathway descriptions
in Table 1 were explicit on this percent of usage. As a result, some
producers of corn ethanol assumed that any degree of implementation of
advanced technologies, even to the point of de minimis GHG benefit,
would be acceptable and consistent with the letter of the regulations.
In the direct final rule and parallel proposal published on May 10,
2010 (75 FR 26026, 75 FR 26049), we announced a revision to Table 2 to
Sec.  80.1426 to clarify the degree to which advanced technologies must
be implemented in order to represent a valid advanced technology for
the generation of RINs. The announced revision specified that the
advanced technologies must be applied to all production at the corn
ethanol facility. In response to the direct final rule, we received
adverse comments from several stakeholders objecting to the changes to
Table 2 to Sec.  80.1426. As a result, we withdrew the changes to Table
2 to Sec.  80.1426 in a Federal Register notice

published on June 30, 2010 (75 FR 37733).
    There were several alternative approaches to advanced technologies
that were suggested by commenters, including the creation of additional
pathways to add to Table 1 to Sec.  80.1426. EPA notes at the outset
that the scope of this rulemaking effort as it relates to Tables 1 and
2 to Sec.  80.1426 is to clarify the regulatory language that
identifies the pathways and specifications for advanced technologies
that were modeled as part of the RFS2 rulemaking effort and that were
determined to lead to an appropriate level of GHG reduction. EPA
continues to evaluate additional pathways on its own initiative, and
may approve the use of additional pathways, as it recently did for
canola oil biodiesel.\5\ EPA has also established a petition process in
Sec.  80.1416 to allow parties seeking the addition of new pathways to
Table 1 to Sec.  80.1426 to bring those pathways to EPA's attention for
evaluation. EPA urges parties seeking EPA consideration of new pathways
to utilize that process. While EPA will fully evaluate any petitions
for new pathways when and if they are submitted to EPA pursuant to
Sec.  80.1416, EPA also provides in this preamble some preliminary
thoughts regarding some of the commenters' suggestions for new
pathways, even though they are beyond the scope of this rulemaking
effort.
---------------------------------------------------------------------------

    \5\ 75 FR 59622, September 28, 2010.
---------------------------------------------------------------------------

    One commenter suggested that EPA incorporate into Table 2 an
energy-based metric for identifying the extent to which each advanced
technology must be used at corn ethanol facilities in order to be
deemed to achieve a 20 percent GHG reduction. The commenter suggested
that this approach could be accomplished by basing the metric on the
pathway in Table 1 to Sec.  80.1426 that specifies no greater that 50
percent drying of distillers grains and solubles (DGS) and no advanced
technologies. The premise of the comment is that any combination of
advanced technologies that reduces energy usage by a specified amount
will achieve the 20 percent GHG threshold. EPA rejects this approach as
an oversimplification that is not currently consistent with the
modeling used by EPA in developing the list of pathways and advanced
technologies in Tables 1 and 2 to Sec.  80.1426. First, EPA's modeling
assumed an industry average for the various advanced technologies, and
not any specific brand or type of technology. As such, the results
cannot be translated into the specific equipment used and operated at a
single plant. The precision of the modeling does not support an
extrapolation down to specific technology at a specific plant, which
would be required under the commenter's approach.
    Second, EPA modeled various scenarios, including a base plant with
100 percent drying of DGS, a base plant with 100 percent wet DGS, and
various combinations of advanced technologies. In some cases use of
just one specific technology such as CHP or corn oil fractionation was
modeled. In other cases a base plant was modeled while progressively
adding different advanced technologies. EPA's modeling by necessity did
not cover the universe of all possible combinations of advanced
technologies, and as such does not allow for a precise quantification
of each advanced technology either by itself or in combination with a
second advanced technology. The modeling does provide clear indication
that (1) There can be interactive effects between pairs of advanced
technologies, (2) advanced technologies can have complex impacts, and
the reductions in GHG emissions are not all based on just a simple
linear reduction in energy use, and (3) different combinations of
advanced technologies are likely to lead to a range of results across
the various combinations. EPA's conclusion in the final RFS2 rulemaking
was that the GHG benefits of the use of advanced technologies as
specified in Tables 1 and 2 to Sec.  80.1426 would in all cases allow
at least a limited degree of GHG reduction beyond the 20 percent
threshold, with the exact degree of reduction dependent on the specific
combination of advanced technologies and drying of DGS. As a result,
the modeling performed by EPA to date does not support specifying a
simple formula that could allow usage of advanced technologies as a
function of measured reductions in energy usage. Thus EPA believes
there is not a technical basis at this time for the approach suggested
by the commenter.
    We also received a suggestion that the table of advanced
technologies be modified to include the option of ``energy efficient
plant design'' that could be achieved through documented low energy
use. In this approach, EPA would establish a level of energy input per
gallon of product that would reflect achievement of the 20 percent GHG
reduction threshold, and industry would be free to use any method to
achieve that required energy utilization standard. Records of fuel and
electricity use in the facility would be submitted to demonstrate
attainment of the standard. This suggestion is clearly beyond the scope
of this rulemaking effort, which is limited to clarifying the
regulatory language related to the modeling and analyses that EPA
conducted as part of the RFS2 rulemaking. Although the commenter
suggested that the energy utilization standard could be set using
existing modeling tied to an existing pathway in Table 1 to Sec.
80.1426, EPA believes that this would not be technically justified for
the same reasons, described above, that it would not be appropriate to
use this metric to establish specifications regarding use of advanced
technologies. Thus, the suggested approach would likely require new
analyses to identify an appropriate energy utilization standard that
would take into account all possible direct and indirect effects
associated with multiple possible permutations of facility technology
and practice. It could also require additional recordkeeping and
reporting requirements as well as new formulas or tabulated values in
the regulations for converting energy use into GHG reductions. All such
changes would entail dramatically different approaches to the
identification of pathways that achieve the necessary amount of GHG
reduction to qualify under the Act than were finalized in the RFS2
rulemaking. Therefore, we did not propose and are not adopting the
commenter's suggested approach in today's rulemaking. Parties
advocating this approach are encouraged to utilize the petition process
in Sec.  80.1416 to request that EPA further evaluate this concept and,
in the context of their petition, to address the concerns that EPA
noted above.
    A number of commenters suggested that application of advanced
technologies to 100 percent of the production at a corn ethanol plant
was not feasible. One commenter pointed out that common and legitimate
downtime for an advanced technology, even if it is of a very short
duration, could preclude a corn ethanol producer from generating any
RINs if Table 2 to Sec.  80.1426 requires application of an advanced
technology to all production at a facility. Another commenter suggested
that advanced technologies be required to be applied to 90 percent of
the production at a corn ethanol facility, instead of 100 percent. In
response, we do recognize that there may be occasions in which an
advanced technology must be halted or bypassed for a short time for
maintenance, repair, or other reasons. To determine whether the
regulations could be modified to address this concern, we reviewed the
original lifecycle GHG modeling for corn ethanol plants that was done
for the RFS2 final rule. The modeling

indicates that use of the advanced technologies as specified should in
all cases provide a minimum margin of compliance beyond the 20 percent
GHG reduction threshold, and in some cases a larger margin. Thus a
small reduction in the application of advanced technologies should
still ensure that the 20 percent GHG threshold is met. EPA recognizes
that this is a question of degree and is basing this on expert judgment
and not specific new modeling. As such, no more than a small reduction
in percent usage is warranted absent further modeling. As a result, we
have modified the regulatory requirements so that advanced technologies
must be applied to at least 90 percent of the production at a corn
ethanol facility. Moreover, we are requiring that compliance with this
90 percent criterion be made over the course of a calendar year,
consistent with the approach to the maximum allowable fraction of DGS
that can be dried under certain corn ethanol pathways in Table 1 to
Sec.  80.1426. This approach relies on judgment based on the lifecycle
modeling that was previously performed, as described above, to provide
some flexibility for downtime of an advanced technology while still
requiring the requisite level of GHG reduction.
    Since compliance with the advanced technologies in Table 2 to Sec.
80.1426 is determined on an annual basis, any RINs that are generated
based upon the use of one or more of these technologies could be
considered invalid if the technologies are not employed in accordance
with the specifications in Table 2, including any requirement based
upon use of these technologies for 90 percent of production on a
calendar year basis. We note, however, that in determining an
appropriate remedy for a violation arising from a renewable fuel
producer's failure to properly employ advanced technologies in
accordance with the specifications in Table 2 to Sec.  80.1426, EPA may
consider a number of factors, including the volume of fuel for which
RINs were generated that was produced without the advanced
technologies, the reasons that the advanced technologies were not
employed, and efforts taken by the renewable fuel producer to remedy
the harm caused by the violation.
    Another suggested change would have allowed GHG reductions for
ethanol volume that is grandfathered under Sec.  80.1403 to be used as
a credit for ethanol volume that has not been grandfathered. Such an
approach could mean that all the GHG reductions associated with
applying a given advanced technology to an entire corn ethanol plant
could be deemed to apply to only the volume that is in excess of the
plant's grandfathered baseline volume. We do not believe that this
would be appropriate. Not only did we not propose such an approach to
compliance with the 20 percent GHG reduction threshold, but it would
amount to transferring GHG reductions from grandfathered volume to non-
grandfathered volume. In so doing, a corn ethanol producer could claim
that its non-grandfathered ethanol met the 20 percent GHG reduction
threshold even if the plant as a whole did not and there was no
discernable difference in plant operations between the grandfathered
and non-grandfathered volume. The regulations do not allow GHG
reduction credits to be assumed for grandfathered volume and then used
to offset the GHG emissions from the non-grandfathered portion of the
facility's production. Non-grandfathered production must be assessed
separately.
    Some commenters raised a concern that the proposed language
requiring application of advanced technologies to ``all'' production at
a facility necessarily required that the advanced technologies be
applied to volumes that are grandfathered and are not subject to the 20
percent GHG reduction threshold for renewable fuel. This was not our
intention. Advanced technologies are not required for volumes that are
grandfathered according to Sec.  80.1403. Thus, we have modified the
regulations to clarify that Tables 1 and 2 to Sec.  80.1426 do not
apply to volumes of fuel for which RINs are generated pursuant to Sec.
80.1426(f)(6).
    With regard to corn oil extraction, we believe that the description
in Table 2 to Sec.  80.1426 requires additional modification to more
accurately reflect the lifecycle modeling that was conducted. For
instance, some commenters pointed out that the terms ``thin stillage''
and ``distillers grains and solubles'' do not accurately describe the
byproduct categories to which corn oil extraction can be applied. More
appropriate might be thin stillage and wet cake, or alternatively just
the whole stillage which precedes the derivatives thin stillage and wet
cake. Our lifecycle modeling assumed that corn oil extraction was
applied to all the byproducts that are included in whole stillage.
However, after further consideration, we believe that a more
straightforward approach to specifying the required application of corn
oil extraction in the regulations would be to identify the amount of
oil that must be extracted rather than the amount of whole stillage to
which the technology must be applied. This approach is consistent with
a suggestion from one commenter and will result in the same GHG
reductions as our proposed approach. This approach will also allow
corn-ethanol producers utilizing the corn oil extraction advanced
technology to apply it to particular byproducts as they see fit,
providing only that the requisite quantity of oil is extracted.
    The lifecycle modeling that led us to include corn oil
fractionation in Table 2 to Sec.  80.1426 assumed an oil extraction
rate of 1.48 pounds of oil per bushel of corn. As described above, we
have determined that a 10 percent reduction in the application of this
advanced technology can be accommodated while still ensuring that the
20 percent GHG threshold has been met. An oil extraction rate of 1.33
pounds per bushel represents 90 percent of the value we assumed in
developing Table 2 to Sec.  80.1426. Thus, in today's rule we are
modifying the description of corn oil extraction to require a minimum
of 1.33 pounds of oil to be extracted from whole stillage or its
derivatives per bushel of corn that is processed into ethanol. This oil
extraction rate is substantially less than the total amount of oils
contained in byproducts from corn ethanol processing. As a result, we
believe this approach will address concerns from some commenters that
the proposed language would have required all oil to be removed from
distillers grains, potentially creating an unmarketable product.
Although one commenter suggested a corn oil extraction rate of 1.0
pound per bushel, we do not believe that this level of implementation
of this advanced technology would ensure that the 20 percent GHG
reduction threshold has been met.
    With regard to combined heat and power (CHP), one commenter
expressed concern that the application of CHP to all of the production
at a corn ethanol facility could require the installation of new
boilers sized to produce electricity. The commenter argued that such
actions were unnecessary and would make CHP commercially unviable.
However, the identification of advanced technologies in Table 2 to
Sec.  80.1426 and the calculation of their required usage rate is
designed to ensure that the 20 percent GHG reduction threshold can be
met. The costs of implementation of CHP were not considered in
determining the technical issue of the GHG reduction threshold
determination. However, we have reviewed the modeling conducted as part
of the RFS2 rulemaking and have determined that application of CHP to
90 percent of production at a corn ethanol facility will achieve a 20
percent GHG reduction, and we have

modified Table 2 to Sec.  80.1426 accordingly.
    In conjunction with the modifications to Table 2 to Sec.  80.1426
as described above, we are finalizing additional recordkeeping and
attest engagement requirements to help ensure that RINs are properly
generated for corn ethanol produced at facilities that employ advanced
technologies listed in Table 2 to Sec.  80.1426. Specifically, we are
finalizing a requirement at Sec.  80.1454(b)(3)(xi) that, for RINs
generated for ethanol produced from corn starch at a facility using
advanced technologies in accordance with the requirements in Tables 1
and 2 to Sec.  80.1426, producers must maintain documentation to
demonstrate that advanced technologies used to qualify such ethanol for
RIN generation were employed at least 90 percent of the time on a
calendar year basis. In addition, we are finalizing an amendment to the
attest engagement procedures for renewable fuel producers at Sec.
80.1464(b)(1)(iii) that, for RINs generated for ethanol produced from
corn starch at a facility that used advanced technologies in accordance
with the requirements in Tables 1 and 2 to Sec.  80.1426, will require
verification that the advanced technologies used to qualify such
ethanol for RIN generation were employed at least 90 percent of the
time on a calendar year basis. We believe that these requirements are
natural outgrowths of the final changes being made to Table 2 to Sec.
80.1426 in response to comments received on our proposed amendments to
this section, and that these additional recordkeeping and attestation
requirements are necessary to ensure compliance with and enforceability
of this aspect of the RFS program.

D. Use of Biogas from a Dedicated Pipeline at Renewable Fuel Production
Facilities

    EPA proposed to amend 40 CFR 80.1426(f)(12) to clarify the
requirements that must be met in order for gas used for process heat at
a renewable fuel production facility to be considered biogas for
purposes of the ``production process requirements'' column of Table 1
to Sec.  80.1426. In order to differentiate the requirements associated
with biogas transported via a dedicated pipeline versus those
associated with biogas transported via a common carrier pipeline, we
proposed to subdivide the requirements under Sec.  80.1426(f)(12). Thus
revisions to Sec.  80.1426(f)(12)(i) were proposed to describe the
requirements for biogas transported via a dedicated pipeline, and
revisions to Sec.  80.1426(f)(12)(ii) were proposed to describe the
requirements for biogas transported via a common carrier pipeline. In
drafting the proposed revised regulations applicable to biogas in a
dedicated pipeline in Sec.  80.1426(f)(12)(i), we mistakenly included
language in paragraph Sec.  80.1426(f)(12)(i)(D) that referred to
biogas placed in a common carrier pipeline, and proposed requiring that
such pipeline ultimately serve the renewable fuel producer's facility.
A commenter rightfully expressed confusion over the proposed amendment
at Sec.  80.1426(f)(12)(i), since Sec.  80.1426(f)(12)(ii) is the
appropriate section for references to biogas in a common carrier
pipeline. We received no other comments on our proposed changes to
Sec.  80.1426(f)(12).
    EPA agrees that the amendment at Sec.  80.1426(f)(12)(i)(D) was
proposed in error and therefore is finalizing all proposed amendments
to Sec.  80.1426(f)(12), with the exception of Sec.
80.1426(f)(12)(i)(D). We considered retaining the provision by deleting
the words ``common carrier'' that modify the reference to ``pipeline.''
However, Sec.  80.1426(f)(12)(i) already specifies that the biogas
discussed in this section is ``directly transported to the facility.''
Therefore, a modified Sec.  80.1426(f)(12)(i)(D) is not necessary, and
we have simply deleted the provision. We also noted a typographical
error and some potentially confusing text in Sec.
80.1426(f)(12)(ii)(C) and have taken this opportunity to make the
appropriate corrections.

E. Time Limits for Reporting Transactions in EMTS

    The final RFS2 regulations require any RIN generator to submit, via
their account in the EPA Moderated Transaction System (EMTS),
information about any batch of renewable fuel and the RINs generated
for it within five days of the production or importation of the batch
(see Sec.  80.1452(b) at 75 FR 14887). Likewise, the final RFS2
regulations also require any party that engages in RIN transactions to
submit, via their EMTS account, information about the transaction
within five business days (see Sec.  80.1452(c) at 75 FR 14887). These
transactional time limits were finalized in order to strike a balance
between the need for EMTS to be a ``real time'' system and the need for
some amount of flexibility to accommodate existing business practices
related to conducting renewable fuel and RIN transactions.
    After the RFS2 regulations were finalized, EPA received numerous
inquiries from regulated parties about whether the five day limit
applied to both the transactional buyer and seller together, or whether
each seller and each buyer had five days to perform their respective
actions in EMTS. We therefore proposed to amend Sec.  80.1452(b) and
(c) to clarify our original intent with respect to when RIN information
needed to be submitted to EMTS. Specifically, we proposed to revise
Sec.  80.1452(b) to clarify that RIN information must be entered into
EMTS within five business days of RINs being assigned to a batch of
renewable fuel and to clarify the information required to be submitted
via EMTS for each such batch. We also proposed to revise Sec.
80.1452(c) to clarify that transactions involving RINs generated on or
after July 1, 2010, must be conducted via EMTS within five business
days of a reportable event, to clarify the meaning of the term
``reportable event,'' and to clarify the information required to be
submitted via EMTS for each transaction involving RINs generated on or
after July 1, 2010.
    We received one adverse comment on the proposed amendatory language
to Sec.  80.1452(b) and (c) that expressed concern over a buyer's
inability to check the accuracy and validity of RINs that may be
received via a renewable fuel product transfer document (PTD) and an
inability to prevent RINs with errors from being traded further. As
discussed above, in addition to the adverse comment, we received
feedback from regulated parties prior to the publication of the direct
final and parallel proposed rules on May 10, 2010 (75 FR 26026, 75 FR
26049), that the five business day requirement for both parties may be
acceptable on the seller's side of the transaction, but that it can
prove difficult for a buyer to confirm or send transactional
information within five days of the PTD date. This difficulty may be
due to the fact that the PTD may be generated and sent when the fuel is
shipped, and the shipping may take longer than a week, or because all
RINs may be aggregated on one PTD that is sent weekly or monthly along
with renewable fuel.
    Based on the comment received as part of this rulemaking and the
additional feedback received prior to this rulemaking, we are
finalizing an amendment to Sec.  80.1452(c) that will increase the
number of days a buyer has to submit transactional information to EMTS.
Specifically, a buyer will have ten business days from the date on the
PTD to submit information about a transaction, including accepting a
transaction initiated by a seller, in EMTS. The seller will still be
required to submit information within five

business days of the date on the PTD. Thus the buyer will have a
minimum of five days, and a maximum of up to ten days if the seller
acts on the same date as the date on the PTD, to enter the required
information into EMTS.
    Although the comment makes reference both to 80.1452(b) and (c), we
believe that the amendatory language to Sec.  80.1452(c) alleviates the
problem cited by the commenter and therefore we are finalizing the
amendment to 80.1452(b), to allow up to five business days after RIN
assignment for a RIN generator to submit RIN information for a batch of
renewable fuel to EMTS, as proposed at 75 FR 26049 (May 10, 2010). We
also noted inconsistency and some potentially confusing text at Sec.
80.1452(b)(1), (b)(2), (b)(4), and (b)(5) and have taken this
opportunity to make the appropriate corrections.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866, (58 FR 51735, October 4, 1993) the
Agency must determine whether the regulatory action is ``significant''
and therefore subject to OMB review and the requirements of the
Executive Order. The Order defines ``significant regulatory action'' as
one that is likely to result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
    (2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
    (4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
    It has been determined that this action is not a ``significant
regulatory action'' under the terms of Executive Order 12866 and is
therefore not subject to OMB review.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
The corrections, clarifications, and modifications to the final RFS2
regulations contained in this rule are within the scope of the
information collection requirements submitted to the Office of
Management and Budget (OMB) for the final RFS2 regulations. OMB has
previously approved the information collection requirements contained
in the existing regulations at 40 CFR part 80, subpart M under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and
has assigned OMB control number 2060-0640. The OMB control numbers for
EPA's regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this final rule on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. This final
rule will note impose any requirements on small entities that were not
already considered under the final RFS2 regulations, as it makes
relatively minor corrections and modifications to those regulations.

D. Unfunded Mandates Reform Act

    This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
We have determined that this action will not result in expenditures of
$100 million or more for the above parties and thus, this rule is not
subject to the requirements of sections 202 or 205 of UMRA.
    This rule is also not subject to the requirements of section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. It only applies to
gasoline, diesel, and renewable fuel producers, importers, distributors
and marketers and makes relatively minor corrections and modifications
to the RFS2 regulations.

E. Executive Order 13132 (Federalism)

    This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This action only applies to
gasoline, diesel, and renewable fuel producers, importers, distributors
and marketers and makes relatively minor corrections and modifications
to the RFS2 regulations. Thus, Executive Order 13132 does not apply to
this action.

F. Executive Order 13175 (Consultation and Coordination With Indian
Tribal Governments)

    This final rule does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It applies to
gasoline, diesel, and renewable fuel producers, importers, distributors
and marketers. This action makes relatively minor corrections and
modifications to the RFS regulations, and does not impose any
enforceable duties on communities of Indian tribal governments. Thus,
Executive Order 13175 does not apply to this action.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying
only to those regulatory actions that concern health or safety risks,
such that the analysis required under section 5-501 of the EO has the
potential to influence the regulation. This action is not subject to EO
13045 because it does not establish an environmental standard intended
to mitigate health or safety risks.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This rule is not subject to Executive Order 13211 (66 FR 18355, May
22, 2001), because it is not a significant regulatory action under
Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs EPA to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
    This action does not involve technical standards. Therefore, EPA
did not consider the use of any voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations.

    Executive Order (EO) 12898 (59 FR 7629, February 16, 1994)
establishes federal executive policy on environmental justice. Its main
provision directs federal agencies, to the greatest extent practicable
and permitted by law, to make environmental justice part of their
mission by identifying and addressing, as appropriate,
disproportionately high and adverse human health or environmental
effects of their programs, policies, and activities on minority
populations and low-income populations in the United States.
    EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. These technical amendments do not relax the control
measures on sources regulated by the RFS regulations and therefore will
not cause emissions increases from these sources.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2).

L. Clean Air Act Section 307(d)

    This rule is subject to Section 307(d) of the CAA. Section
307(d)(7)(B) provides that ``[o]nly an objection to a rule or procedure
which was raised with reasonable specificity during the period for
public comment (including any public hearing) may be raised during
judicial review.'' This section also provides a mechanism for the EPA
to convene a proceeding for reconsideration, ``[i]f the person raising
an objection can demonstrate to the EPA that it was impracticable to
raise such objection within [the period for public comment] or if the
grounds for such objection arose after the period for public comment
(but within the time specified for judicial review) and if such
objection is of central relevance to the outcome of the rule.'' Any
person seeking to make such a demonstration to the EPA should submit a
Petition for Reconsideration to the Office of the Administrator, U.S.
EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., NW.,
Washington, DC 20460, with a copy to both the person(s) listed in the
preceding FOR FURTHER INFORMATION CONTACT section, and the Director of
the Air and Radiation Law Office, Office of General Counsel (Mail Code
2344A), U.S. EPA, 1200 Pennsylvania Ave., NW., Washington, DC 20460.

List of Subjects in 40 CFR Part 80

    Environmental protection, Fuel additives, Gasoline, Imports, Motor
vehicle pollution, Reporting and recordkeeping requirements.

    Dated: December 14, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons set forth in the preamble, 40 CFR part 80 is amended as
follows:

PART 80--REGULATION OF FUELS AND FUEL ADDITIVES

0
1. The authority citation for part 80 continues to read as follows:

    Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a).

0
2. Section 80.1401 is amended by adding definitions of ``Actual peak
capacity'', ``Baseline volume'', and ``Permitted capacity'', in
alphabetical order to read as follows:

Sec.  80.1401  Definitions.

* * * * *
    Actual peak capacity means 105% of the maximum annual volume of
renewable fuels produced from a specific renewable fuel production
facility on a calendar year basis.
    (1) For facilities that commenced construction prior to December
19, 2007, the actual peak capacity is based on the last five calendar
years prior to 2008, unless no such production exists, in which case
actual peak capacity is based on any calendar year after startup during
the first three years of operation.
    (2) For facilities that commenced construction after December 19,
2007 and before January 1, 2010 that are fired with natural gas,
biomass, or a combination thereof, the actual peak capacity is based on
any calendar year after startup during the first three years of
operation.
    (3) For all other facilities not included above, the actual peak
capacity is based on the last five calendar years prior to the year in
which the owner or operator registers the facility under the provisions
of Sec.  80.1450, unless no such production exists, in which case
actual peak capacity is based on any calendar year after startup during
the first three years of operation.
* * * * *
    Baseline volume means the permitted capacity or, if permitted
capacity cannot be determined, the actual peak capacity of a specific
renewable fuel production facility on a calendar year basis.
* * * * *
    Permitted capacity means 105% of the maximum permissible volume
output of renewable fuel that is allowed under operating conditions
specified in the most restrictive of all applicable preconstruction,
construction and operating permits issued by regulatory authorities
(including local, regional, state or a foreign equivalent of a state,
and federal permits, or permits issued by foreign governmental
agencies) that govern the construction and/or operation of the
renewable fuel facility, based on an annual volume output on a calendar
year basis. If the permit specifies maximum rated volume output on an
hourly basis, then annual volume output is determined by multiplying
the hourly output by 8,322 hours per year.
    (1) For facilities that commenced construction prior to December
19, 2007, the permitted capacity is based on

permits issued or revised no later than December 19, 2007.
    (2) For facilities that commenced construction after December 19,
2007 and before January 1, 2010 that are fired with natural gas,
biomass, or a combination thereof, the permitted capacity is based on
permits issued or revised no later than December 31, 2009.
    (3) For facilities other than those described in paragraphs (1) and
(2) of this definition, permitted capacity is based on the most recent
applicable permits.
* * * * *

0
3. Section 80.1403 is amended by revising paragraph (a) to read as
follows:

Sec.  80.1403  Which fuels are not subject to the 20% GHG thresholds?

    (a) For purposes of this section, the following definitions apply:
    (1) Commence construction, as applied to facilities that produce
renewable fuel, means that:
    (i) The owner or operator has all necessary preconstruction
approvals or permits (as defined at 40 CFR 52.21(b)(10)), and has
satisfied either of the following:
    (A) Begun, or caused to begin, a continuous program of actual
construction on-site (as defined in 40 CFR 52.21(b)(11)).
    (B) Entered into binding agreements or contractual obligations,
which cannot be cancelled or modified without substantial loss to the
owner or operator, to undertake a program of actual construction of the
facility.
    (ii) For multi-phased projects, the commencement of construction of
one phase does not constitute commencement of construction of any later
phase, unless each phase is mutually dependent for physical and
chemical reasons only.
    (2) [Reserved]
* * * * *

0
4. Section 80.1425 is amended by revising the introductory text and
paragraph (i) to read as follows:

Sec.  80.1425  Renewable Identification Numbers (RINs).

    RINs generated on or after July 1, 2010 shall not be generated as a
38-digit code, but shall be identified by the information specified in
paragraphs (a) through (i) of this section and introduced into EMTS as
data elements during the generation of RINs pursuant to Sec.
80.1452(b). For RINs generated prior to July 1, 2010, each RIN is a 38-
digit code of the following form:
KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE
* * * * *
    (i) EEEEEEEE is a number representing the last gallon-RIN
associated with a volume of renewable fuel.

0
5. Section 80.1426 is amended as follows:
0
a. By revising introductory text to paragraph (f)(1).
0
b. By revising Table 2 to Sec.  80.1426.
0
c. By revising paragraph (f)(12).

Sec.  80.1426  How are RINs generated and assigned to batches of
renewable fuel by renewable fuel producers or importers?

* * * * *
    (f) * * *
    (1) Applicable pathways. D codes shall be used in RINs generated by
producers or importers of renewable fuel according to the pathways
listed in Table 1 to this section, subparagraph 6 of this section, or
as approved by the Administrator. In choosing an appropriate D code,
producers and importers may disregard any incidental, de minimis
feedstock contaminants that are impractical to remove and are related
to customary feedstock production and transport. Tables 1 and 2 to this
section do not apply to, and impose no requirements with respect to,
volumes of fuel for which RINs are generated pursuant to subparagraph 6
of this section.
* * * * *

            Table 2 to Sec.   80.1426--Advanced Technologies
------------------------------------------------------------------------

-------------------------------------------------------------------------
Corn oil fractionation that is applied to at least 90% of the corn used
 to produce ethanol on a calendar year basis.
------------------------------------------------------------------------
Corn oil extraction that is applied to the whole stillage and/or
 derivatives of whole stillage and results in recovery of corn oil at an
 annual average rate equal to or greater than 1.33 pounds oil per bushel
 of corn processed into ethanol.
------------------------------------------------------------------------
Membrane separation in which at least 90% of ethanol dehydration is
 carried out using a hydrophilic membrane on a calendar year basis.
------------------------------------------------------------------------
Raw starch hydrolysis that is used for at least 90% of starch hydrolysis
 used to produce ethanol instead of hydrolysis using a traditional high
 heat cooking process, calculated on a calendar year basis.
------------------------------------------------------------------------
Combined heat and power such that, on a calendar year basis, at least
 90% of the thermal energy associated with ethanol production (including
 thermal energy produced at the facility and that which is derived from
 an off-site waste heat supplier), exclusive of any thermal energy used
 for the drying of distillers grains and solubles, is used to produce
 electricity prior to being used to meet the process heat requirements
 of the facility.
------------------------------------------------------------------------

* * * * *
    (12) For purposes of Table 1 to this section, process heat produced
from combustion of gas at a renewable fuel facility is considered
derived from biomass if the gas is biogas.
    (i) For biogas directly transported to the facility without being
placed in a commercial distribution system, all of the following
conditions must be met:
    (A) The producer has entered into a written contract for the
procurement of a specific volume of biogas with a specific heat
content.
    (B) The volume of biogas was sold to the renewable fuel production
facility, and to no other facility.
    (C) The volume and heat content of biogas injected into the
pipeline and the volume of gas used as process heat are measured by
continuous metering.
    (ii) For biogas that has been gathered, processed and injected into
a common carrier pipeline, all of the following conditions must be met:
    (A) The producer has entered into a written contract for the
procurement of a specific volume of biogas with a specific heat
content.
    (B) The volume of biogas was sold to the renewable fuel production
facility, and to no other facility.
    (C) The volume of biogas that is withdrawn from the pipeline is
withdrawn in a manner and at a time consistent with the transport of
fuel between the injection and withdrawal points.
    (D) The volume and heat content of biogas injected into the
pipeline and the volume of gas used as process heat are measured by
continuous metering.
    (E) The common carrier pipeline into which the biogas is placed
ultimately

serves the producer's renewable fuel facility.
    (iii) The process heat produced from combustion of gas at a
renewable fuel facility described in paragraph (f)(12)(i) of this
section shall not be considered derived from biomass if any other party
relied upon the contracted volume of biogas for the creation of RINs.
* * * * *
    6. Section 80.1451 is amended by revising paragraph (b)(1)(ii)(M)
to read as follows:

Sec.  80.1451  What are the reporting requirements under the RFS
program?

* * * * *
    (b) * * *
    (1) * * *
    (ii) * * *
    (M) The type of co-products produced with each batch.
* * * * *

0
7. Section 80.1452 is amended as follows:
0
a. By revising paragraphs (b) introductory text, (b)(1), (b)(2),
(b)(4), (b)(5), (b)(6), (b)(9), (b)(13), and (b)(15).
0
b. By revising paragraphs (c) introductory text, (c)(4), (c)(5), and
(c)(7).

Sec.  80.1452  What are the requirements related to the EPA Moderated
Transaction System (EMTS)?

* * * * *
    (b) Starting July 1, 2010, each time a domestic or foreign producer
or importer of renewable fuel assigns RINs to a batch of renewable fuel
pursuant to Sec.  80.1426(e), all the following information must be
submitted to EPA via the submitting party's EMTS account within five
(5) business days of the date of RIN assignment.
    (1) The name of the renewable fuel producer or importer.
    (2) The EPA company registration number of the renewable fuel or
foreign ethanol producer, as applicable.
* * * * *
    (4) The EPA facility registration number of the renewable fuel or
foreign ethanol producer, as applicable.
    (5) The importer's EPA facility registration number if applicable.
    (6) The D code of RINs generated for the batch.
* * * * *
    (9) The fuel type of the batch.
* * * * *
    (13) The type and quantity of feedstock(s) used for the batch.
* * * * *
    (15) The type and quantity of co-products produced with the batch
of renewable fuel.
* * * * *
    (c) Starting July 1, 2010, each time any party sells, separates, or
retires RINs generated on or after July 1, 2010, all the following
information must be submitted to EPA via the submitting party's EMTS
account within five (5) business days of the reportable event. Starting
July 1, 2010, each time any party purchases RINs generated on or after
July 1, 2010, all the following information must be submitted to EPA
via the submitting party's EMTS account within ten (10) business days
of the reportable event. The reportable event for a RIN purchase or
sale occurs on the date of transfer per Sec.  80.1453(a)(4). The
reportable event for a RIN separation or retirement occurs on the date
of separation or retirement as described in Sec.  80.1429.
* * * * *
    (4) The RIN status (Assigned or Separated).
    (5) The D code of the RINs.
* * * * *
    (7) The date of transfer per Sec.  80.1453(a)(4), if applicable.
* * * * *

0
8. Section 80.1454 is amended by revising paragraph (b)(3)(xi) and
adding a new paragraph (b)(3)(xii).

Sec.  80.1454  What are the recordkeeping requirements under the RFS
program?

* * * * *
    (b) * * *
    (3) * * *
    (xi) For RINs generated for ethanol produced from corn starch at a
facility using a pathway in Table 1 to Sec.  80.1426 that requires the
use of one or more of the advanced technologies listed in Table 2 to
Sec.  80.1426, documentation to demonstrate that employment of the
required advanced technology or technologies was conducted in
accordance with the specifications in Tables 1 and 2 to Sec.  80.1426,
including any requirement for application to 90% of the production on a
calendar year basis.
    (xii) All commercial documents and additional information related
to details of RIN generation.
* * * * *

0
9. Section 80.1464 is amended by revising paragraph (b)(1)(iii) to read
as follows:

Sec.  80.1464  What are the attest engagement requirements under the
RFS program?

* * * * *
    (b) * * *
    (1) * * *
    (iii) Verify that the proper number of RINs were generated and
assigned pursuant to the requirements of Sec.  80.1426 for each batch
of renewable fuel produced or imported. For RINs generated for ethanol
produced from corn starch at a facility using a pathway in Table 1 to
Sec.  80.1426 that requires the use of one or more of the advanced
technologies listed in Table 2 to Sec.  80.1426, verify that the
required advanced technology or technologies were employed in
accordance with the specifications in Tables 1 and 2 to Sec.  80.1426,
including any requirement for application to 90% of the production on a
calendar year basis.
* * * * *
[FR Doc. 2010-31910 Filed 12-20-10; 8:45 am]
BILLING CODE 6560-50-P