Total Fuel Production                     -33,000     < or = -33,000
     Emissions \57\...............
------------------------------------------------------------------------

    Table 13 below breaks down by stage the lifecycle GHG emissions for
the renewable gasoline and renewable gasoline blendstock pathways using
corn stover and the 2005 petroleum baseline. The table demonstrates the
contribution of each stage in the fuel pathway and its relative
significance in terms of GHG emissions. These results are also
presented in graphical form in a supplemental memorandum to the
docket.\58\ As noted above, these analyses assume natural gas as the
process energy when needed; using biogas or biomass as process energy
would result in an even better lifecycle GHG impact.
---------------------------------------------------------------------------

    \57\ Numbers do not add up due to rounding.
    \58\ Memorandum to the Air and Radiation Docket EPA-HQ-OAR-2011-
0542 ``Supplemental Information for Renewable Gasoline and Renewable
Gasoline Blendstock Pathways Under the Renewable Fuel Standard
(RFS2) Program''.

 Table 13--Lifecycle GHG Emissions for Renewable Gasoline and Renewable Gasoline Blendstock Pathways Using Corn
                                                  Stover, 2022
                                               [kg CO2-eq./mmBtu]
----------------------------------------------------------------------------------------------------------------
                                                                                Direct
                                                                               biochemical
                                          Catalytic         Biochemical      fermentation to
                                         pyrolysis to     fermentation to       renewable        2005 gasoline
              Fuel type                   renewable          renewable         gasoline and         baseline
                                           gasoline         gasoline via        renewable
                                          blendstock      carboxylic acid        gasoline
                                                                                blendstock
----------------------------------------------------------------------------------------------------------------
Net Domestic Agriculture (w/o land                    9                  8               ~ 11  .................
 use change)........................
Net International Agriculture (w/o
 land use change):
    Domestic Land Use Change........                 -9                 -8              ~ -11  .................
International Land Use Change:
    Fuel Production.................                 28                 30         < or = -33                 19
    Fuel and Feedstock Transport....                  2                  2                ~ 2                  *
    Tailpipe Emissions..............                  2                  2                ~ 1                 79
                                     ---------------------------------------------------------------------------
        Total Emissions.............                 32                 34         < or = -29                 98
                                     ===========================================================================
        % Change from Baseline......               -67%               -65%              -129%  .................
----------------------------------------------------------------------------------------------------------------
* Emissions included in fuel production stage.

d. Extension of Modeling Results to Other Production Processes
Producing Renewable Gasoline or Renewable Gasoline Blendstock
    In the RFS2 rulemaking, we modeled the GHG emissions results from
the biochemical fermentation process to ethanol, thermochemical
gasification processes to mixed alcohols (primarily ethanol) and mixed
hydrocarbons (primarily diesel fuel). We extended these modeled process
results to apply when the biofuel was produced from ``any'' process. We
determined that since we modeled multiple cellulosic biofuel processes
and all were shown to exceed the 60% lifecycle GHG threshold
requirements for cellulosic biofuel using the specified feedstocks its
was reasonable to extend to other processes that might develop as these
would likely represent improvements over existing processes as the
industry works to improve the economics of cellulosic biofuel
production by, for example, reducing energy consumption and improving
process yields. Similarly, this rule assesses multiple processes for
the production of renewable gasoline and renewable gasoline blendstocks
and all were shown to exceed the 60% lifecycle GHG threshold
requirements for cellulosic biofuel using specified feedstocks.
    As was the case in our earlier rulemaking, a couple reasons in
particular support extending our modeling results to other production
process producing renewable gasoline or renewable gasoline blendstock
from cellulosic feedstock. Under this rule we analyzed the core
technologies most likely available through 2022 for production of
renewable gasoline and renewable gasoline blendstock routes from
cellulosic feedstock as shown in literature. \59\ \60\ The
two primary routes for renewable gasoline and renewable gasoline
blendstock production from cellulosic feedstock can be classified as
either thermochemical or biological. Each of these two major categories
has two subcategories. The processes under the thermochemical category
include:
---------------------------------------------------------------------------

    \59\ Regalbuto, John. ``An NSF perspective on next generation
hydrocarbon biorefineries,'' Computers and Chemical Engineering 34
(2010) 1393-1396. February 2010.
    \60\ Serrano-Ruiz, J., Dumesic, James. ``Catalytic routes for
the conversion of biomass into liquid hydrocarbon transportation
fuels,'' Energy Environmental Science (2011) 4, 83-99.
---------------------------------------------------------------------------

     Pyrolysis--in which cellulosic biomass is decomposed with
temperature to bio-oils and requires further catalytic processing to
produce a finished fuel.
     Gasification--in which cellulosic biomass is decomposed to
syngas with further catalytic processing of methanol to gasoline or
through Fischer-Tropsch (F-T) synthesis to gasoline.
    The processes under the biochemical category include:
     Direct fermentation--requires the release of sugars from
biomass and the use of ``synthetic biology'' in which microorganisms
are altered to ferment sugars straight into hydrocarbons instead of
alcohols.
     Fermentation w/catalytic upgrading--requires the release
of sugars from biomass and aqueous- or liquid-phase processing of
sugars or intermediate fermentation products into hydrocarbons using
solid catalysts,
    As part of the modeling effort here, as well as for the RFS2 final
rule, we have considered the lifecycle GHG impacts of the four possible
production technologies mentioned above. The pyrolysis, direct
fermentation, and fermentation with catalytic upgrading are considered
in this rule and the gasification route was already included in the
RFS2 final rule. In all cases, the processes that we have considered
meet the 60% lifecycle GHG reduction required for cellulosic biofuels.
Furthermore, we believe that the results from our modeling would cover
all the likely variations within these potential routes for producing
renewable gasoline and renewable gasoline blendstock which also use
natural gas, biogas or biomass for process energy and that all such
production variations would also meet the 60% lifecycle threshold.
    The main reason for this is that we believe that our energy input
assumptions are reasonable at this time but probably in some cases
conservative for commercial scale cellulosic facilities. The cellulosic
industry is in its early stages of development and many of the
estimates of process technology GHG impacts is based on pre-commercial
scale assessments and demonstration programs. Commercial scale
cellulosic facilities will continue to make efficiency improvements
over time to maximize their fuel products/co-products and minimize
wastes. For cellulosic facilities, such improvements include increasing
conversion yields and fully utilizing the biomass input for valuable
products.
    An example of increasing the amount of biomass utilized is the
combustion of undigested or unconverted biomass for heat and power. The
three routes that we analyzed for the production of renewable gasoline
and renewable gasoline blendstock in today's rule assume an electricity
production credit from the economically-driven use of

lignin or waste byproducts; we also ran a sensitivity case where no
electricity credit was given. We found that all of the routes analyzed
would still pass the GHG threshold without an electricity credit,
providing confidence that over the range of technology options, these
process technologies will surely allow the cellulosic biofuel produced
to exceed the threshold for cellulosic biouel GHG performance. Without
excess electricity production the catalytic pyrolysis pathway results
in a 65% lifecycle GHG reduction, the biochemical fermentation via
carboxylic acid pathway results in a 62% lifecycle GHG reduction, and
the direct biochemical fermentation pathway results in a 93% reduction
in lifecycle GHG emissions compared to the petroleum fuel baseline.
    Additionally, while the final results reported in this rule include
an electricity credit, this electricity credit is based on current
technology for generating electricity; it is possible that over the
next decade as cellulosic biofuel production matures, the efficiency
with which electricity is generated at these facilities will also
improve. Such efficiency improvements will tend to improve the GHG
performance for cellulosic biofuel technologies in general including
those used to produce renewable gasoline.
    Furthermore, industry has identified other areas for energy
improvements which our current pathway analyses do not include.
Therefore, the results we have come up with for the individual pathway
types represent conservative estimates and any variations in the
pathways considered are likely to result in greater GHG reductions that
what is considered here. For example, the variation of the catalytic
pyrolysis route considered here resulted in a 67% reduction in
lifecycle GHG emissions compared to the petroleum baseline. However, as
was mentioned this was based on data from our NREL modeling and
industry CBI data indicated more efficient energy performance which, if
realized, would improve GHG performance. Another area for improvement
in this pathway could be the use of anaerobic digestion to treat
organics in waste water. If the anaerobic digestion is on-site, then
enough biogas could potentially be produced to replace all of the
fossil natural gas used as fuel and about half the natural gas fed for
hydrogen production.\61\ Thus, fossil natural gas consumption could be
further minimized under certain scenarios. We believe that as
commercial scale cellulosic facilities develop, more of these
improvements will be made to maximize the use of all the biomass and
waste byproducts available to bring the facility closer to energy self-
sufficiency. These improvements could help to increase the economic
profitability for cellulosic facilities where fossil energy inputs
become costly to purchase. Therefore we can extend the modeling results
for our pyrolysis route to all variations of this production technology
which use natural gas, biogas or biomass for production energy for
producing renewable gasoline or renewable gasoline blendstock.
---------------------------------------------------------------------------

    \61\ Kinchin, Christopher. Catalytic Fast Pyrolysis with
Upgrading to Gasoline and Diesel Blendstocks. National Renewable
Energy Laboratory (NREL). 2011.
---------------------------------------------------------------------------

    The F-T gasification technology route considered as part of the
RFS2 final rule resulted in an approximately 91% reduction in lifecycle
GHG emissions compared to the petroleum baseline. This could be
considered a conservative estimate as the process did not assume any
excess electricity production, which as mentioned above could lead to
additional GHG reductions. The F-T process involves gasifying biomass
into syngas (mix of H2 and CO) and then converting the
syngas through a catalytic process into a hydrocarbon mix that is
further refined into finished product. The F-T process considered was
based on producing both gasoline and diesel fuel so that it was not
optimized for renewable gasoline production. A process for producing
primarily renewable gasoline rather than diesel from a gasification
route should not result in a significantly worse GHG impacts compared
to the mixed fuel process analyzed. Furthermore, as the lifecycle GHG
reduction from the F-T process considered was around 91%, there is
considerable room for variations in this route to still meet the 60%
lifecycle GHG reduction threshold for cellulosic fuels. Therefore, in
addition to the F-T process orginially analyzed for producing naphtha,
we can extend the results based on the above analyses to include all
variations of the gasification route which use natural gas, biogas or
biomass for production energy for producing renewable gasoline or
renewable gasoline blendstock. These variations include for example
different catalysts and different refining processes to produce
different mixes of final fuel product. While the current Table 1 entry
in the regulations does not specify process energy sources, we are
adding these specific eligible energy sources since we have not
analyzed other energy sources (e.g. coal) as also allowing the pathway
to meet the GHG performance threshold.
    There is an even wider gap between the results modeled for the
direct fermentation route and the cellulosic lifecycle GHG threshold.
The variation we considered for the direct fermentation process
resulted in an approximately 129% reduction in lifecycle GHG emissions
compared to the petroleum baseline. This process did consider
production of electricity as part of the process but as mentioned even
if this was not the case the pathway would still easily fall below the
60% lifecycle threshold for cellulosic biofuels. If actual emissions
from other necessary changes to the direct biochemical fermentation to
hydrocarbons process represent some small increment in GHG emissions,
the pathway would still likely meet the threshold. Therefore, we can
extend the results to all variations of the direct biochemical route
for renewable gasoline or renewable gasoline blendstock production
which use natural gas, biogas or biomass for production energy.
    The biochemical with catalytic upgrading route that we evaluated
resulted in a 65% reduction in GHG emissions compared to the petroleum
baseline. However, this can be considered a conservative estimate. For
instance, the biochemical fermentation to gasoline via carboxylic acid
route considered did not include the potential for generating steam
from the combustion of undigested biomass and then using this steam for
process energy. If this had been included, natural gas consumption
could potentially be decreased which would lower the potential GHG
emissions estimated from the process. Therefore, the scenario analyzed
could be considered conservative in estimating actual natural gas
usage. As was the case with the pyrolysis route considered, we believe
that as commercial scale cellulosic facilities develop, improvements
will be made to maximize the use of all the biomass and waste
byproducts available to bring the facility closer to energy self-
sufficiency. These improvements help to increase the economic
profitability for cellulosic facilities where fossil energy inputs
become costly to purchase. The processes we analyzed for this
rulemaking utilized a mix of natural gas and biomass for process
energy, with biogas replacing natural gas providing improved GHG
performance. We have not analyzed other fuel types (e.g., coal) and are
therefore not approving processes that utilized other fuel sources at
this point. Therefore, we are extending our results

to include all variations of the biochemical with catalytic upgrading
process utilizing natural gas, biogas or biomass for process energy.
    While actual cellulosic facilities may show some modifications to
the process scenarios we have already analyzed, our results give a good
indication of the range of emissions we could expect from processes
producing renewable gasoline and renewable gasoline blendstock from
cellulosic feedstock, all of which meet the 60% cellulosic biofuel
threshold (assuming they are utilizing natural gas, biogas or biomass
for process energy). Technology changes in the future are likely to
increase efficiency to maximize profits, while also lowering lifecycle
GHG emissions. Therefore, we have concluded that since all of the
renewable gasoline or renewable gasoline blendstock fuel processing
methods we have analyzed exceed the 60% threshold using specific
cellulosic feedstock types, we can conclude that processes producing
renewable gasoline or renewable gasoline blendstock that fit within the
categories of process analyzed here and are produced from the same
feedstock types and using natural gas, biogas or biomass for process
energy use will also meet the 60% GHG reduction threshold. In addition,
while other technologies may develop, we expect that they will only
become commercially competitive if they have better yield (more gallons
per ton of feedstock) or lower production cost due to lower energy
consumption. Both of these factors would suggest better GHG
performance. This would certainly be the case if such processes also
relied upon using biogas and/or biomass as the primary energy source.
Therefore based on our review of the existing primary cellulosic
biofuel production processes, likely GHG emission improvements for
existing or new technologies, and consideration of the positive GHG
emissions benefits associated with using biogas and/or biomass for
process energy, we are approving for cellulosic RIN generation any
process for renewable gasoline and renewable gasoline blendstock
production using specified cellulosic biomass feedstocks as long as the
process utilizes biogas and/or biomass for all process energy.
5. Summary
    Three renewable gasoline and renewable gasoline blendstock pathways
were compared to baseline petroleum gasoline, using the same value for
baseline gasoline as in the RFS2 final rule analysis. The results of
the analysis indicate that the renewable gasoline and renewable
gasoline blendstock pathways result in a GHG emissions reduction of 65-
129% or better compared to the gasoline fuel it would replace using
corn stover as a feedstock. Since the renewable gasoline and renewable
gasoline blendstock pathways which use corn stover as a feedstock all
exceed the 60% lifecycle GHG threshold requirements for cellulosic
biofuel, and since these pathways capture the likely current
technologies and since future technology improvements are likely to
increase efficiency and lower GHG emissions, we have determined that
all processes producing renewable gasoline or renewable gasoline
blendstock from corn stover can qualify if they fall in the following
process characterizations:
     Catalytic pyrolysis and upgrading utilizing natural gas,
biogas, and/or biomass as the only process energy sources.
     Gasification and upgrading utilizing natural gas, biogas,
and/or biomass as the only process energy sources.
     Direct fermentation utilizing natural gas, biogas, and/or
biomass as the only process energy sources.
     Fermentation and upgrading utilizing natural gas, biogas,
and/or biomass as the only process energy sources.
     Any process utilizing biogas and/or biomass as the only
process energy sources.
    As was the case for extending corn stover results to other
feedstocks in the RFS2 final rule, these results are also reasonably
extended to feedstocks with similar or lower GHG emissions profiles,
including the following feedstocks:
     Cellulosic biomass from crop residue, slash, pre-
commercial thinnings and tree residue, annual cover crops;
     Cellulosic components of separated yard waste;
     Cellulosic components of separated food waste; and
     Cellulosic components of separated MSW.
    For more information on the reasoning for extension to these other
feedstocks refer to the feedstock production and distribution section
or the RFS2 rulemaking (75 FR 14793-14795).
    Based on these results, today's rule includes pathways for the
generation of cellulosic biofuel RINs for renewable gasoline or
renewable gasoline blendstock produced by catalytic pyrolysis and
upgrading, gasification and upgrading, direct fermentation,
fermentation and upgrading, all utilizing natural gas, biogas, and/or
biomass as the only process energy sources or any process utilizing
biogas and/or biomass as the only energy sources, and using corn stover
as a feedstock or the feedstocks noted above. In order to qualify for
RIN generation, the fuel must meet the other definitional criteria for
renewable fuel (e.g., produced from renewable biomass, and used to
reduce or replace petroleum-based transportation fuel, heating oil or
jet fuel) specified in the Clean Air Act and the RFS regulations.
    A manufacturer of a renewable motor vehicle gasoline (including
parties using a renewable blendstock obtained from another party), must
satisfy EPA motor vehicle registration requirements in 40 CFR Part 79
for the fuel to be used as a transportation fuel. Per 40 CFR
79.56(e)(3)(i), a renewable motor vehicle gasoline would be in the Non-
Baseline Gasoline category or the Atypical Gasoline category (depending
on its properties) since it is not derived only from conventional
petroleum, heavy oil deposits, coal, tar sands and/or oil sands (40 CFR
79.56(e)(3)(i)(5)).In either case, the Tier 1 requirements at 40 CFR
79.52 (emissions characterization) and the Tier 2 requirements at 40
CFR 79.53 (animal exposure) are conditions for registration unless the
manufacturer qualifies for a small business provision at 40 CFR
79.58(d). For a non-baseline gasoline, a manufacturer under $50 million
in annual revenue is exempt from Tier 1 and Tier 2. For an atypical
gasoline there is no exemption from Tier 1, but a manufacturer under
$10 million in annual revenue is exempt from Tier 2.
    Registration for a motor vehicle gasoline at 40 CFR 79 is via EPA
Form 3520-12, Fuel Manufacturer Notification for Motor Vehicle Fuel,
available at: http://www.epa.gov/otaq/regs/fuels/ffarsfrms.htm.

D. Esterification Production Process Inclusion for Specified Feedstocks
Producing Biodiesel

    Table 14, shown below, includes pathways for biodiesel using
specified feedstocks and the production process transesterification.
Transesterification is the most commonly used method to produce
biodiesel (i.e., methyl esters) by

reacting triglycerides with methanol typically under the presence of a
base catalyst, see the simplified form in Equation 1.\62\
---------------------------------------------------------------------------

    \62\ Commonly used base catalysts include sodium hydroxide
(NaOH), potassium hydroxide (KOH) and sodium methoxide
(NaOCH3).

                     Table 14--Excerpts of Existing Fuel Pathways From Sec.   40 CFR 80.1426
----------------------------------------------------------------------------------------------------------------
                                                        Production process
            Fuel type                  Feedstock           requirements                    D-Code
----------------------------------------------------------------------------------------------------------------
Biodiesel, and renewable diesel.  Soy bean oil; Oil    One of the           4 (Biomass-Based Diesel).
                                   from annual          following: Trans-
                                   covercrops; Algal    Esterification
                                   oil; Biogenic        Hydrotreating
                                   waste oils/fats/     Excluding
                                   greases; Non-food    processes that co-
                                   grade corn oil.      process renewable
                                                        biomass and
                                                        petroleum.
Biodiesel, and renewable diesel.  Soy bean oil; Oil    One of the           5 (Advanced Biofuel).
                                   from annual          following: Trans-
                                   covercrops; Algal    Esterification
                                   oil; Biogenic        Hydrotreating
                                   waste oils/fats/     Includes only
                                   greases; Non-food    processes that co-
                                   grade corn oil.      process renewable
                                                        biomass and
                                                        petroleum.
----------------------------------------------------------------------------------------------------------------

                                                                            [GRAPHIC] [TIFF OMITTED] TR05JA12.008

    While triglycerides are usually the main component of oils, fats,
and grease feedstocks, there are other components such as free fatty
acids (FFAs) that are typically removed prior to transesterification.
Removal or conversion of FFAs is important if the traditional base-
catalyzed transesterification production process is used since FFAs
will react with base catalysts to produce soaps that inhibit the
transesterification reaction. Table 15 below gives the usual ranges for
FFAs found in biodiesel feedstocks.

          Table 15--Ranges of FFA in Biodiesel Feedstocks 63 64
------------------------------------------------------------------------
                                                              Percentage
                    Biodiesel feedstock                          FFA
------------------------------------------------------------------------
Refined vegetable oils.....................................        <0.05
Crude vegetable oils.......................................      0.3-0.7
Restaurant waste grease....................................          2-7
Yellow grease..............................................          <15
Animal fat.................................................         5-30
Brown grease...............................................          >15
Trap grease................................................       40-100
------------------------------------------------------------------------

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

    \63\ Van Gerpen, J., Shanks, B., Pruszko, R., Clements, D.,
Knothe, G., ``Biodiesel Production Technology,'' NREL/SR-510-36244,
July 2004.
    \64\ Van Gerpen, J., ``Used and Waste Oil and Grease for
Biodiesel,'' NC State University A&T State University Cooperative
Extension, http://www.extension.org/pages/Used_and_Waste_Oil_and_Grease_for_Biodiesel.
---------------------------------------------------------------------------

    One of the most widely used methods for treating biodiesel
feedstocks with higher FFA content is acid catalysis. Acid catalysis
typically uses a strong acid such as sulfuric acid to catalyze the
esterification of the FFAs and the transesterification of the
triglycerides. The simplified form of the esterification process is
given below in Equation 2. Acid esterification can be applied to
feedstocks with FFA contents above 5%. Because the transesterification
of triglycerides is slow under acid catalysis, a technique commonly
used to overcome the reaction rate issue is to first convert the FFAs
through an acid esterification (also known as an acid ``pretreatment''
step), and then follow-up with the traditional base-catalyzed
transesterification of triglycerides. See Figure 2 for a general flow
diagram of the acid esterification and subsequent transesterification
biodiesel process.
[GRAPHIC] [TIFF OMITTED] TR05JA12.009

[GRAPHIC] [TIFF OMITTED] TR05JA12.010

    Under the RFS2 final rule, biodiesel from biogenic waste oils/fats/
greases qualifies for D-Codes 4 and 5 using a ``transesterification''
process. This conclusion was based on the analysis of yellow grease as
a feedstock in a process where there was an acid ``pretreatment'' or
``esterification'' process to treat the FFAs contained in the
feedstock. In fact, one of the material inputs assumed in the modeling
for the final RFS2 rule yellow grease pathway is sulfuric acid, which
is the catalyst commonly used for acid esterification. However, we had
not stipulated ``esterification'' as a qualified production process in
Table 1 to Sec.  40 CFR 80.1426. We believe this ambiguity could
unnecessarily cause confusion as to whether esterification can also be
used for the production of biodiesel under the currently approved
pathways.
    Since the biodiesel modeling completed for the final RFS2 rule
actually includes esterification upstream of the transesterification
process, we find it appropriate to clarify Table 1 to Sec.  40 CFR
80.1426 to include ``esterification'' as a qualified process in which
to produce biodiesel. As the modeling for yellow grease met an 86% GHG
reduction emissions level, and yellow grease is typically <15% FFA
content, it is reasonable to conclude that esterification and
subsequent transesterification with a yellow grease feedstock
containing FFAs at the very least up to 15% can meet the GHG reduction
threshold for biomass-based diesel and advanced biofuel of 50%.
    As noted in Table 15, however, there are feedstocks that may
contain even higher levels of FFAs. As described below, EPA has
evaluated the use of these higher FFA feedstocks to make biodiesel and
has determined that use of such feedstocks also results in a biodiesel
with lifecycle GHG emissions at least 50% less than that of
conventional fuel.
    The National Biodiesel Board (NBB) has conducted a comprehensive
survey of the actual energy used by commercial biodiesel production
plants in the U.S.\65\ The survey depicts the amount of energy and
incidental process materials such as acids used to produce a gallon of
biodiesel. The survey data returned represents 37% of the surveyed 230
NBB biodiesel members in 2008 and includes producers using a variety of
virgin oils and recycled or reclaimed fats and oils. While there is no
specific data on the FFA content of the feedstocks used, the feedstocks
did include reclaimed greases which represent the feedstocks which
typically have the highest FFA content. As the data is partially
aggregated, we used the maximum surveyed electricity and natural gas
used at the facilities and a high estimate of ``materials used'' based
on a sum of industry averages for all process materials for calculating
potential GHG emissions. Even though some of the facilities might be
processing feedstocks with relatively low FFA content, we believe that
using these maximum observed inputs for energy used plus a high
estimate for process materials used will estimate the highest GHG
emissions profile for biodiesel production GHG emissions. When combined
with the feedstock GHG emissions impact (see discussion below), the
results still predict a GHG emissions reduction comfortably exceeding
50% as compared to the petroleum fuel it displaces. Therefore, there is
little risk in predicting that any facility that utilizes
esterification and feedstock over the range of likely FFA content can
meet the 50% biomass-based diesel and advanced biofuel threshold.
---------------------------------------------------------------------------

    \65\ National Biodiesel Board, Comprehensive Survey on Energy
Use for Biodiesel Production (2008) http://www.biodiesel.org/news/RFS/rfs2docs/NBB%20Energy%20Use%20Survey%20FINAL.pdf.
---------------------------------------------------------------------------

    According to the survey, the maximum electricity use for a producer
reached as high as 3,071 Btu per gallon biodiesel. This is about 5
times higher than the industry average. The maximum natural gas usage
for a producer reached as high as 12,324 Btu per gallon biodiesel,
which is about 3.5 times higher than the industry average. For
``materials used'' only an industry average for each material was
provided in the survey. Therefore, as a conservative estimate, we
totaled all the average material inputs to equal 0.51 kg/gal
biodiesel.\66\ We believe that this is conservative because not all
facilities are likely to use each and every one of the process
materials listed in the survey (e.g., we totaled all the acids

used even though a facility is not likely to use each different acid).
Thus, our estimate of materials used will estimate a level of maximum
usage of materials at a given facility. In addition, we did not include
a glycerin co-product credit when calculating emissions since the
esterification reaction does not produce glycerin (see Equation 2).
Using the same methodology as was used for the yellow grease modeling
under RFS2, but using the high energy and materials use assumptions per
the above discussion and omitting the glycerin co-product credit, we
estimate the emissions from biodiesel processing at 23,708
gCO2eq per mmBtu of biodiesel. The estimated GHG emissions
reduction for the entire process is -71%. Since the GHG threshold is at
-50% for biomass-based diesel and advanced biofuel, we believe that
there is a large enough margin in the results to reasonably conclude
that biodiesel using esterification of specified feedstocks with any
level of FFA content meets the biomass-based diesel and advanced
biofuel 50% lifecycle GHG reduction threshold. Therefore, we are
including the process ``esterification'' as an approved biodiesel
production process in Table 1 to Sec.  40 CFR 80.1426. In addition,
consistent with the modeling conducted for RFS2, we interpret the RFS
regulations as they existed prior to today's rule as including a direct
esterification process as part of the biodiesel pathways for which only
``trans-esterification'' was specifically referenced in Table 1 to
Sec.  40 CFR 80.1426.
---------------------------------------------------------------------------

    \66\ The material inputs include methanol, sodium methylate,
sodium hydroxide, potassium hydroxide, hydrochloric acid, sulfuric
acid, phosphoric acid, and citric acid. The majority of material
input is from methanol.
---------------------------------------------------------------------------

V. Additional Changes to Listing of Available Pathways in Table 1 of
80.1426

    We are also finalizing two changes to Table 1 to 80.1426 that were
proposed on July 1, 2011 (76 FR 38844). The first change adds ID
letters to pathways to facilitate references to specific pathways. The
second change adds ``rapeseed'' to the existing pathway for renewable
fuel made from canola oil.
    On September 28, 2010, EPA published a ``Supplemental Determination
for Renewable Fuels Produced Under the Final RFS2 Program from Canola
Oil'' (FR Vol. 75, No. 187, pg 59622-59634). In the July 1, 2011 NPRM
(76 FR 38844) we proposed to clarify two aspects of the supplemental
determination. First we proposed to amend the regulatory language in
Table 1 to Sec.  80.1426 to clarify that the currently-approved pathway
for canola also applies more generally to rapeseed. While ``canola''
was specifically described as the feedstock evaluated in the
supplemental determination, we had not intended the supplemental
determination to cover just those varieties or sources of rapeseed that
are identified as canola, but to all rapeseed. As described in the July
1, 2011 NPRM, we currently interpret the reference to ``canola'' in
Table 1 to Sec.  80.1426 to include any rapeseed. To eliminate
ambiguity caused by the current language, however, we proposed to
replace the term ``canola'' in that table with the term ``canola/
rapeseed''. Canola is a type of rapeseed. While the term ``canola'' is
often used in the American continent and in Australia, the term
``rapeseed'' is often used in Europe and other countries to describe
the same crop. We received no adverse comments on our proposal, and
thus are finalizing it as proposed. This change will enhance the
clarity of the regulations regarding the feedstocks that qualify under
the approved canola biodiesel pathway.
    Second, we wish to clarify that although the GHG emissions of
producing fuels from canola feedstock grown in the U.S. and Canada was
specifically modeled as the most likely source of canola (or rapeseed)
oil used for biodiesel produced for sale and use in the U.S., we also
intended that the approved pathway cover canola/rapeseed oil from other
countries, and we interpret our regulations in that manner. We expect
the vast majority of biodiesel used in the U.S. and produced from
canola/rapeseed oil will come from U.S. and Canadian crops. Incidental
amounts from crops produced in other nations will not impact our
average GHG emissions for two reasons. First, our analyses considered
world-wide impacts and thus considered canola/rapeseed crop production
in other countries. Second, other countries most likely to be exporting
canola/rapeseed or biodiesel product from canola/rapeseed are likely to
be major producers which typically use similar cultivars and farming
techniques. Therefore, GHG emissions from producing biodiesel with
canola/rapeseed grown in other countries should be very similar to the
GHG emissions we modeled for Canadian and U.S. canola, though they
could be slightly (and insignificantly) higher or lower. At any rate,
even if there were unexpected larger differences, EPA believes the
small amounts of feedstock or fuel potentially coming from other
countries will not impact our threshold analysis. Therefore, EPA
interprets the approved canola pathway as covering canola/rapeseed
regardless of country origin.

VI. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under Executive Orders 12866 and 13563
(76 FR 3821, January 21, 2011).

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 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 numbers 2060- 0637 and 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 action on small
entities, I certify that this rule will not have a significant economic
impact on a substantial number of small entities. This rule will not
impose any new requirements on small entities. The

relatively minor corrections and modifications this rule makes to the
final RFS2 regulations do not impact small entities.

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 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 (Feb. 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 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
amendments would not relax the control measures on sources regulated by
the RFS regulations and therefore would 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. A major rule cannot take effect until 60 days after it
is published in the Federal Register. 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.
This action is not a ``major rule'' as defined by 5 U.S.C. 804(2).

VII. Statutory Provisions and Legal Authority

    Statutory authority for the rule finalized today can be found in
section 211 of the Clean Air Act, 42 U.S.C. 7545. Additional support
for the procedural and compliance related aspects of today's rule,
including the recordkeeping requirements, come from Sections 114, 208,
and 301(a) of the Clean Air Act, 42 U.S.C. 7414, 7542, and 7601(a).

List of Subjects in 40 CFR Part 80

    Environmental protection, Administrative practice and procedure,
Agriculture, Air pollution control, Confidential business information,
Diesel Fuel, Energy, Forest and forest products, Fuel additives,
Gasoline, Imports, Labeling, Motor vehicle pollution, Penalties,
Petroleum, Reporting and recordkeeping requirements.

    Dated: November 30, 2011.
Lisa P. Jackson,
Administrator.
    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, 7521(1), 7545 and 7601(a).

0
2. Section 80.1401 is amended by addition of the following definitions
of ``Renewable Gasoline'' and ``Renewable Gasoline Blendstock'' in
alphabetical order to read as follows:

Sec.  80.1401  Definitions.

* * * * *
    Renewable gasoline means renewable fuel made from renewable biomass
that is composed of only hydrocarbons and which meets the definition of
gasoline in Sec.  80.2(c).
    Renewable gasoline blendstock means a blendstock made from
renewable biomass that is composed of only hydrocarbons and which meets
the definition of gasoline blendstock in Sec.  80.2(s).
* * * * *

0
3. Section 80.1426 is amended by revising Table 1 in paragraph (f)(1)
to read as follows:

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

* * * * *
    (f) * * *
    (1) * * *

         Table 1 to Sec.   80.1426--Applicable D Codes for Each Fuel Pathway for Use in Generating RINs
----------------------------------------------------------------------------------------------------------------
                                                                              Production process
               Fuel type                           Feedstock                     requirements            D-Code
----------------------------------------------------------------------------------------------------------------
A Ethanol.............................  Corn starch...................  All of the following: Dry mill         6
                                                                         process, using natural gas,
                                                                         biomass, or biogas for
                                                                         process energy and at least
                                                                         two advanced technologies
                                                                         from Table 2 to this section.
B Ethanol.............................  Corn starch...................  All of the following: Dry mill         6
                                                                         process, using natural gas,
                                                                         biomass, or biogas for
                                                                         process energy and at least
                                                                         one of the advanced
                                                                         technologies from Table 2 to
                                                                         this section plus drying no
                                                                         more than 65% of the
                                                                         distillers grains with
                                                                         solubles it markets annually.
C Ethanol.............................  Corn starch...................  All of the following: Dry mill         6
                                                                         process, using natural gas,
                                                                         biomass, or biogas for
                                                                         process energy and drying no
                                                                         more than 50% of the
                                                                         distillers grains with
                                                                         solubles it markets annually.
D Ethanol.............................  Corn starch...................  Wet mill process using biomass         6
                                                                         or biogas for process energy.
E Ethanol.............................  Starches from crop residue and  Fermentation using natural             6
                                         annual covercrops.              gas, biomass, or biogas for
                                                                         process energy.
F Biodiesel, renewable diesel, jet      Soy bean oil; Oil from annual   One of the following: Trans-           4
 fuel and heating oil.                   covercrops; Algal oil;          Esterification,
                                         Biogenic waste oils/fats/       Esterification Hydrotreating
                                         greases; Non-food grade corn    Excluding processes that co-
                                         oil; Camelina oil.              process renewable biomass and
                                                                         petroleum.
G Biodiesel, heating oil..............  Canola/Rapeseed oil...........  Trans-Esterification using             4
                                                                         natural gas or biomass for
                                                                         process energy.
H Biodiesel, renewable diesel, jet      Soy bean oil; Oil from annual   One of the following: Trans-           5
 fuel and heating oil.                   covercrops; Algal oil;          Esterification,
                                         Biogenic waste oils/fats/       Esterification Hydrotreating
                                         greases; Non-food grade corn    Includes only processes that
                                         oil Camelina oil.               co-process renewable biomass
                                                                         and petroleum.
I Naphtha, LPG........................  Camelina oil..................  Hydrotreating.................         5
J Ethanol.............................  Sugarcane.....................  Fermentation..................         5
K Ethanol.............................  Cellulosic Biomass from crop    Any...........................         3
                                         residue, slash, pre-
                                         commercial thinnings and tree
                                         residue, annual covercrops,
                                         switchgrass, miscanthus,
                                         napiergrass, giant reed, and
                                         energy cane; cellulosic
                                         components of separated yard
                                         waste; cellulosic components
                                         of separated food waste; and
                                         cellulosic components of
                                         separated MSW.
L Cellulosic Diesel, jet fuel and       Cellulosic Biomass from crop    Any...........................         7
 heating oil.                            residue, slash, pre-
                                         commercial thinnings and tree
                                         residue, annual covercrops,
                                         switchgrass, miscanthus,
                                         napiergrass, giant reed and
                                         energy cane; cellulosic
                                         components of separated yard
                                         waste; cellulosic components
                                         of separated food waste; and
                                         cellulosic components of
                                         separated MSW.

M Renewable Gasoline and Renewable      Cellulosic Biomass from crop    Catalytic Pyrolysis,                   3
 Gasoline Blendstock.                    residue, slash, pre-            Gasification and Upgrading,
                                         commercial thinnings, tree      Direct Fermentation,
                                         residue, annual cover crops;    Fermentation and Upgrading,
                                         cellulosic components of        all utilizing natural gas,
                                         separated yard waste;           biogas, and/or biomass as the
                                         cellulosic components of        only process energy sources.
                                         separated food waste; and       Any process utilizing biogas
                                         cellulosic components of        and/or biomass as the only
                                         separated MSW.                  process energy sources.
N Butanol.............................  Corn starch...................  Fermentation; dry mill using           6
                                                                         natural gas, biomass, or
                                                                         biogas for process energy.
O Ethanol, renewable diesel, jet fuel,  The non-cellulosic portions of  Any...........................         5
 heating oil, and naphtha.               separated food waste.
P Biogas..............................  Landfills, sewage waste         Any...........................         5
                                         treatment plants, manure
                                         digesters.
----------------------------------------------------------------------------------------------------------------

* * * * *
[FR Doc. 2011-31580 Filed 1-4-12; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register Volume 81, Number 195 (Friday, October 7, 2016)]
[Notices]
[Pages 69808-69809]
[FR Doc No: 2016-24271]

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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Notice of Availability of Environmental Assessment

FFP Missouri 16, LLC.............  Project No. 13753-002
FFP Missouri 15, LLC.............  Project No. 13762-002
Solia 8 Hydroelectric, LLC.......  Project No. 13771-002
FFP Missouri 13, LLC.............  Project No. 13763-002
Solia 5 Hydroelectric, LLC.......  Project No. 13766-002
Solia 4 Hydroelectric, LLC.......  Project No. 13767-002

    In accordance with the National Environmental Policy Act of 1969
and the Federal Energy Regulatory Commission's (Commission or FERC)
regulations, 18 Code of Federal Regulations Part 380, Office of Energy
Projects staff has reviewed applications for original licenses for the
Opekiska Lock and Dam Hydroelectric Project (FERC No. 13753-002),
Morgantown Lock and Dam Hydroelectric Project (FERC No. 13762-002),
Point Marion Lock and Dam Hydroelectric Project (FERC No. 13771-002),
Grays Landing Lock and Dam Hydroelectric Project (FERC No. 13763-002),
Maxwell Locks and Dam Hydroelectric Project (FERC No. 13766-002), and
Monongahela Locks and Dam 4 (also known as Charleroi Locks and Dam)
Hydroelectric Project (FERC No. 13767-002) on the Monongahela River.
These projects are referred to collectively as the Monongahela River
Projects.
    The projects would all be located at existing locks and dams owned
by the U.S. Army Corps of Engineers on the Monongahela River. The
Opekiska Lock and Dam Hydroelectric Project would be located upstream
of Fairmont, West Virginia, in Monongalia County at river mile (RM)
115.4. The Morgantown Lock and Dam Hydroelectric Project would be
located downstream of Morgantown, West Virginia, in Monongalia County
at RM 102. The Point Marion Lock and Dam Hydroelectric Project would be
located near Point Marion, Pennsylvania, in Fayette County at RM 90.8.
The Grays Landing Lock and Dam Hydroelectric Project would be located
southwest of Masontown, Pennsylvania,

in Greene and Fayette Counties at RM 82. The Maxwell Locks and Dam
Hydroelectric Project would be located downstream of Brownsville,
Pennsylvania, in Washington County at RM 61.2. The Monongahela Locks
and Dam 4 Hydroelectric Project would be located near Charleroi,
Pennsylvania, in Washington County at RM 41.5. The projects would
collectively occupy 19.9 acres of federal land.
    Staff has prepared a multi-project environmental assessment (EA)
that analyzes the potential environmental effects of the six projects
and concludes that constructing and operating the projects, with
appropriate environmental protection measures, would not constitute a
major federal action that would significantly affect the quality of the
human environment.
    A copy of the EA is available for review at the Commission in the
Public Reference Room or may be viewed on the Commission's Web site at
www.ferc.gov using the ``eLibrary'' link. Enter the docket number for
one of the proposed projects (e.g., P-13753), excluding the last three
digits, in the docket number field to access the document. For
assistance, contact FERC Online Support at<EMAIL_ADDRESS>or toll-free at 1-866-208-3676, or for TTY,<PHONE_NUMBER>.
    You may also register online at http://www.ferc.gov/docs-filing/esubscription.asp to be notified via email of new filings and issuances
related to these or other pending projects. For assistance, contact
FERC Online Support.
    Any comments should be filed within 30 days from the date of this
notice. The Commission strongly encourages electronic filing. Please
file comments using the Commission's eFiling system at http://www.ferc.gov/docs-filing/efiling.asp. For assistance, please contact
FERC Online Support at<EMAIL_ADDRESS>or toll-free at 1-
866-208-3676, or for TTY,<PHONE_NUMBER>. In lieu of electronic filing,
please send a paper copy to: Secretary, Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426. The first page
of any filing should include: ``Opekiska Lock and Dam Hydroelectric
Project No. 13753-002, Morgantown Lock and Dam Hydroelectric Project
No. 13762-002, Point Marion Lock and Dam Hydroelectric Project No.
13771-002, Grays Landing Lock and Dam Hydroelectric Project No. 13763-
002, Maxwell Locks and Dam Hydroelectric Project No. 13766-002, and/or
Monongahela Locks and Dam 4 Hydroelectric Project No. 13767-002,'' as
appropriate.
    For further information, contact Nicholas Ettema at<PHONE_NUMBER>
or by email at<EMAIL_ADDRESS>
    Dated: September 30, 2016.
Kimberly D. Bose,
Secretary.
[FR Doc. 2016-24271 Filed 10-6-16; 8:45 am]
 BILLING CODE 6717-01-P


[Federal Register Volume 80, Number 243 (Friday, December 18, 2015)]
[Rules and Regulations]
[Pages 78979-78981]
[FR Doc No: 2015-31885]

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DEPARTMENT OF HOMELAND SECURITY

Coast Guard

33 CFR Part 165

[Docket Number USCG-2015-1030]
RIN 1625-AA87

Security Zone; Kailua Bay, Oahu, HI

AGENCY: Coast Guard, DHS.

ACTION: Temporary final rule.

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

SUMMARY: The Coast Guard is establishing a temporary security zone in
support of a visit by very important persons (VIPs). The security zone
begins on the navigable waters in Kailua Bay on the west side of a line
connecting Kapoho Point and continuing at a bearing of 227[deg] (true)
as well as the nearby channel from its entrance near Kapoho Point to a
point along the channel 150 yards to the south of the N. Kalaheo Avenue
Road Bridge. This security zone is necessary to ensure the safety of
the VIPs.

DATES: This rule is effective from 6:00 a.m. (HST) on December 18,
2015, through 10:00 p.m. (HST) on January 3, 2016.

ADDRESSES: Documents mentioned in this preamble are part of docket
USCG-2015-1030. To view documents mentioned in this preamble as being
available in the docket, go to http://www.regulations.gov, type USCG-
2015-1030 in the ``SEARCH'' box and click ``SEARCH.'' Click on Open
Docket Folder on the line associated with this rule.

FOR FURTHER INFORMATION CONTACT: If you have questions on this rule,
call or email Lieutenant Commander Nicolas Jarboe, Waterways Management
Division, U.S. Coast Guard Sector Honolulu; telephone<PHONE_NUMBER>,
email<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. Table of Abbreviations

CFR Code of Federal Regulations
DHS Department of Homeland Security
E.O. Executive order
FR Federal Register
NPRM Notice of proposed rulemaking
TFR Temporary final rule
Pub. L. Public Law
Sec.  Section
U.S.C. United States Code
VIP Very Important Person

II. Background Information and Regulatory History

    The Coast Guard is issuing this temporary final rule without prior
notice and opportunity to comment pursuant to authority under section
4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553 (b)). This
provision authorizes an agency to issue a rule without prior notice and
opportunity to comment when the agency, for good cause, finds those
procedures are ``impractical, unnecessary, or contrary to the public
interest.'' Under 5 U.S.C. 553(d)(3), the Coast Guard finds that good
cause exists for making this rule effective less than 30 days after
publication in the Federal Register. The details of the VIPs' travel to
Hawaii were not made available to the Coast Guard in sufficient time to
issue a notice of proposed rulemaking. Due to the need for immediate
action, the restriction of vessel traffic is necessary to protect the
VIPs; therefore, a 30-day notice period is impracticable. Delaying the
effective date would be contrary to the security zone's intended
objectives of protecting the VIPs, mitigating potential terroristic
acts, enhancing public and maritime safety and security. Publishing a
Notice of Proposed Rulemaking (NPRM) and delaying the effective date
would be contrary to the public interest since the occasion would occur
before a notice-and-comment rulemaking could be completed, thereby
jeopardizing the safety of the VIPs. The COTP finds that this temporary
security zone must be effective by December 18, 2015 to ensure the
safety of the VIPs during their visit to the Kailua Bay area on the
eastern coast of Oahu, Hawaii. The Coast Guard received the official
request on November 1, 2015.

III. Legal Authority and Need for Rule

    The Coast Guard is issuing this rule under the authority in 33
U.S.C. 1231. From December 18, 2015 through January 3, 2016, VIPs of
the United States of America plans to visit the Kailua Bay area on
Oahu, Hawaii. The security zone begins on the navigable waters in
Kailua Bay on the west side of a line connecting Kapoho Point and
continuing at a bearing of 227[deg] (true) as well as the nearby
channel from its entrance near Kapoho Point to a point along the
channel 150 yards to the south of the N. Kalaheo Avenue Road Bridge.
The Captain of the Port of Honolulu (COTP) has determined that there is
reasonable potential for terroristic acts associated with the VIPs
visit to the Kailua Bay area, and that a security zone is necessary to
ensure their safety.

IV. Discussion of Comments, Changes, and the Rule

    This temporary final rule establishes a security zone from 6:00
a.m. (HST) on December 18, 2015, through 10:00 p.m. (HST) on January
03, 2016. The security zone area is located within the COTP Zone (See
33 CFR 3.70-10) and covers all U.S. navigable waters in the Kailua Bay
on the west side of a line connecting Kapoho Point and continuing at a
bearing of 227[deg] (true) to 21[deg]25'11'' N., 157[deg]44'39'' W.; as
well as the nearby channel from its entrance near Kapoho Point to a
point along the channel 150 yards to the south of the N. Kalaheo Avenue
Road Bridge. This zone extends from the surface of the water to the
ocean floor. This zone will include the navigable waters of the channel
beginning at a point 21[deg]25'04'' N., 157[deg]44'54'' W., then
extending to 21[deg]25'27'' N., 157[deg]44'21'' W. (Kapoho Point)
including all the waters to the west of a straight line to
21[deg]25'11'' N., 157[deg]44'39'' W., and the extending back to the
original point 21[deg]25'04'' N., 157[deg]44'54'' W.
    One (1) yellow buoy and two (2) shore-side markers will be placed
in proximity of the security zone along the security zone boundary and
one (1) orange boom will be placed at the channel boundary south of the
N. Kalaheo Avenue Road Bridge as visual aids for mariners and public to
approximate the zone. An illustration of the security zone will be made
available on www.regulations.gov in docket for this rulemaking, USCG-
2015-1030. No vessel or person will be permitted to enter the security
zone without obtaining permission from the COTP or a designated
representative.

V. Regulatory Analyses

    We developed this rule after considering numerous statutes and
executive orders (E.O.s) related to rulemaking. Below we summarize our
analyses based on these statutes and executive orders.

A. Regulatory Planning and Review

    E.O.s 12866 and 13563 direct agencies to assess the costs and
benefits of available regulatory alternatives and, if regulation is
necessary, to select regulatory approaches that maximize net benefits.
E.O. 13563 emphasizes the importance of quantifying both costs and
benefits, of reducing costs, of harmonizing rules, and of promoting
flexibility. The Coast Guard expects the economical impact of this rule
to be so minimal that a full Regulatory Evaluation under the regulatory
policies and procedures of DHS is unnecessary. This expectation is
based on the limited duration of the zone, the limited geographic area
affected by it, and the lack of commercial vessel traffic affected by
the zone. This rule has not been designated a ``significant regulatory
action,'' under E.O. 12866. Accordingly, it has not been reviewed by
the Office of Management and Budget.

B. Impact on Small Entities

    The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as
amended, requires Federal agencies to consider the potential impact of
regulations on small entities during rulemaking. The term ``small
entities'' comprises small businesses, not-for-profit organizations
that are independently owned and operated and are not dominant in their
fields, and governmental jurisdictions with populations of less than
50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule
will not have a significant economic impact on a substantial number of
small entities.
    While some owners or operators of vessels intending to transit the
security zone may be small entities, for the reasons stated in section
V.A above, this rule will not have a significant economic impact on any
vessel owner or operator.
    Under section 213(a) of the Small Business Regulatory Enforcement
Fairness Act of 1996 (Pub. L. 104-121), we want to assist small
entities in understanding this rule. If the rule would affect your
small business, organization, or governmental jurisdiction and you have
questions concerning its provisions or options for compliance, please
contact the person listed in the FOR FURTHER INFORMATION CONTACT
section.
    Small businesses may send comments on the actions of Federal
employees who enforce, or otherwise determine compliance with, Federal
regulations to the Small Business and Agriculture Regulatory
Enforcement Ombudsman and the Regional Small Business Regulatory
Fairness Boards. The Ombudsman evaluates these actions annually and
rates each agency's responsiveness to small business. If you wish to
comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR
(1-888-734-3247). The

Coast Guard will not retaliate against small entities that question or
complain about this rule or any policy or action of the Coast Guard.

C. Collection of Information

    This rule will not call for a new collection of information under
the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

D. Federalism and Indian Tribal Governments

    A rule has implications for federalism under E.O. 13132,
Federalism, if it has a substantial direct effect 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. We have analyzed this rule under that Order and have
determined that it is consistent with the fundamental federalism
principles and preemption requirements described in E.O. 13132.
    Also, this rule does not have tribal implications under E.O. 13175,
Consultation and Coordination with Indian Tribal Governments, because
it does not have a substantial direct effect on one or more Indian
tribes, on the relationship between the Federal Government and Indian
tribes, or on the distribution of power and responsibilities between
the Federal Government and Indian tribes. If you believe this rule has
implications for federalism or Indian tribes, please contact the person
listed in the FOR FURTHER INFORMATION CONTACT section above.

E. Unfunded Mandates Reform Act

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538)
requires Federal agencies to assess the effects of their discretionary
regulatory actions. In particular, the Act addresses actions that may
result in the expenditure by a State, local, or tribal government, in
the aggregate, or by the private sector of $100,000,000 (adjusted for
inflation) or more in any one year. Though this rule will not result in
such an expenditure, we do discuss the effects of this rule elsewhere
in this preamble.

F. Environment

    We have analyzed this rule under Department of Homeland Security
Management Directive 023-01 and Commandant Instruction M16475.lD, which
guide the Coast Guard in complying with the National Environmental
Policy Act of 1969 (42 U.S.C. 4321-4370f), and have determined that
this action is one of a category of actions that do not individually or
cumulatively have a significant effect on the human environment. It is
categorically excluded from further review under paragraph 34(g) of
Figure 2-1 of the Commandant Instruction. An environmental analysis
checklist supporting this determination and a Categorical Exclusion
Determination are available in the docket where indicated under
ADDRESSES.

G. Protest Activities

    The Coast Guard respects the First Amendment rights of protesters.
Protesters are asked to contact the person listed in the FOR FURTHER
INFORMATION CONTACT section to coordinate protest activities so that
your message can be received without jeopardizing the safety or
security of people, places or vessels.

List of Subjects in 33 CFR Part 165

    Harbors, Marine safety, Navigation (water), Reporting and
recordkeeping requirements, Security measures, Waterways.

    For the reasons discussed in the preamble, the Coast Guard amends
33 CFR part 165 as follows:

PART 165--REGULATED NAVIGATION AREAS AND LIMITED ACCESS AREAS

0
1. The authority citation for part 165 continues to read as follows:

    Authority:  33 U.S.C. 1231; 50 U.S.C. 191; 33 CFR 1.05-1, 6.04-
1, 6.04-6, and 160.5; Department of Homeland Security Delegation No.
0170.1.

0
2. Add Sec.  165.T14-1030 to read as follows:

Sec.  165.T14-1030  Security Zone; Kailua Bay, Oahu, HI.

    (a) Location. The security zone area is located within the Captain
of the Port (COTP) Zone (See 33 CFR 3.70-10) and covers all U.S.
navigable waters in the Kailua Bay on the west side of a line
connecting Kapoho Point and continuing at a bearing of 227[deg] (true)
to 21[deg]25'11'' N., 157[deg]44'39'' W.; as well as the nearby channel
from its entrance near Kapoho Point to a point along the channel 150
yards to the south of the N. Kalaheo Avenue Road Bridge. This zone
extends from the surface of the water to the ocean floor. This zone
will include the navigable waters of the channel beginning at a point
21[deg]24'56'' N., 157[deg]44'58'' W., then extending to 21[deg]25'27''
N., 157[deg]44'21'' W. (Kapoho Point) including all the waters to the
west of a straight line to 21[deg]25'11'' N., 157[deg]44'39'' W., and
extending back to the original point 21[deg]24'56'' N., 157[deg]44'58''
W.
    (b) Effective period. 6:00 a.m. (HST) on December 18 2015, through
10:00 p.m. (HST) on January 3, 2016.
    (c) Regulations. The general regulations governing security zones
contained in Sec.  165.33 of subpart D of this part apply to the
security zone created by this temporary regulations.
    (1) All persons are required to comply with the general regulations
governing security zones found in this part.
    (2) Entry into or remaining in this zone is prohibited unless
authorized by the COTP.
    (3) Persons desiring to transit the security zones identified in
paragraph (a) of this section may contact the COTP at the Command
Center telephone number<PHONE_NUMBER> and<PHONE_NUMBER>, fax (808)
842-2642 or on VHF channel 16 (156.8 Mhz) to seek permission to transit
the zones. If permission is granted, all persons and vessels must
comply with the instructions of the COTP or his designated
representative and proceed at the minimum speed necessary to maintain a
safe course while in the zone.
    (4) The U.S. Coast Guard may be assisted in the patrol and
enforcement of the security zone by Federal, State, and local agencies.
    (d) Notice of enforcement. The COTP will cause notice of the
enforcement of the security zone described in this section to be made
by verbal broadcasts and written notice to mariners and the general
public.
    (e) Definitions. As used in this section, designated representative
means any Coast Guard commissioned, warrant, or petty officer who has
been authorized by the COTP to assist in enforcing the security zones
described in paragraph (a) of this section.

    Dated: November 30, 2015.
S.N. Gilreath,
Captain, U.S. Coast Guard, Captain of the Port, Honolulu.
[FR Doc. 2015-31885 Filed 12-15-15; 4:15 pm]
 BILLING CODE 9110-04-P