Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program
[Federal Register: May 1, 2007 (Volume 72, Number 83)]
[Rules and Regulations]
[Page 23949-23998]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr01my07-9]
[[pp. 23949-23998]]
Regulation of Fuels and Fuel Additives:
Renewable Fuel Standard Program
[[Continued from page 23948]]
[[Page 23949]]
attest engagements, and the independent third party verification
discussed above. The attest engagements for a foreign ethanol producer
must be conducted by a U.S. auditor (if not a U.S. based auditor, the
auditor must be approved in advance by EPA). Similar to other fuels
programs, the foreign ethanol producer will be required to comply with
additional requirements designed to ensure that enforcement of the
regulations at the foreign ethanol facility will not be compromised.
The independent third party P.E. conducting the facility verification
must be approved by EPA before the foreign entity will be allowed to
treat its cellulosic biomass or waste-derived ethanol in the same
manner as domestic producers. The foreign ethanol producer must arrange
for the P.E. to inspect the facility and submit a report to us which
describes the physical plant and its operation and includes
documentation of the P.E.'s qualifications. The foreign ethanol
producer must agree to provide access to EPA personnel for the purposes
of conducting inspections and audits, post a bond, and arrange for an
independent inspector to monitor ship loading and offloading records to
ensure that volumes of ethanol do not change from port of shipping to
port of entry. The independent inspector must be approved by EPA prior
to the shipment of any ethanol designated by the foreign ethanol
producer as ethanol which is to be treated as cellulosic biomass or
waste-derived ethanol. Cellulosic biomass or waste-derived ethanol
produced by a foreign ethanol producer must be identified as such on
product transfer documents that accompany the ethanol to the importer.
(These additional provisions for foreign ethanol producers are
contained in Sec. 80.1166.)
The provisions for foreign ethanol producers are optional and are
available only to foreign producers of cellulosic biomass or waste-
derived ethanol. Ethanol or other renewable fuels produced and exported
to the United States by other foreign producers are regulated through
the importer. An importer that receives ethanol identified as
cellulosic biomass or waste-derived ethanol produced by a foreign
producer with an approved application would not assign RINs to the
ethanol, as RINs for such ethanol will be assigned by the foreign
ethanol producer. The importer, like any other marketer, would transfer
the RINs assigned by the foreign producer with a volume of ethanol and
report the transactions to us.
E. Attest Engagements
1. What Are the Attest Engagement Requirements Under the RFS Program?
Attest engagements are similar to financial audits and consist of
an independent, professional review of compliance records and reports.
Similar to other fuels programs, the RFS program requires reporting
parties to arrange for annual attest engagements to be conducted by an
auditor that is ``independent'' under the criteria specified in the
regulations. We believe that the attest engagements provide an
appropriate and useful tool for verifying the accuracy of the
information reported to us. Attest engagements are performed in
accordance with standard procedures and standards established by the
American Institute of Certified Public Accountants and the Institute of
Internal Auditors. The attest engagement consists of an outside
certified public accountant (CPA) or certified independent auditor
(CIA) following agreed upon procedures to determine whether underlying
records, reported items, and transactions agree, and issuing a report
as to their findings. Attest engagements are performed on an annual basis.
2. Who Is Subject to the Attest Engagement Requirements for the RFS Program?
Obligated parties, producers, exporters and importers of renewable
fuel, and any party who own RINs are all subject to the attest
engagement requirements.
3. How Are the Attest Engagement Requirements in This Final Rule
Different From Those Proposed?
We had proposed that obligated parties, exporters, and renewable
fuels producers be subject to attest engagement requirements. We
received several comments on this proposal. Some commenters suggested
that the attest engagements should be required for renewable fuels
producers and importers, but not for obligated parties. These
commenters believe that attest engagements are needed for renewable
fuel producers and importers in order to verify reported production and
RIN volumes, whereas we can monitor compliance by obligated parties by
cross-checking their reports regarding RIN transactions and use with
the reports from other parties. These commenters also believe that the
information required by obligated parties under the RFS program is not
such that an attest engagement is needed because the rule does not
require verification of raw data as with other fuels programs. We have
considered these comments but continue to believe that the attest
engagements are an appropriate means of verifying the accuracy of the
information reported to us by obligated parties. In addition to
documentation of RIN transactions and use, the reports include
information on production and import volumes and calculation of the
party's RFS obligation. We believe that attest engagements are
necessary in order to verify that the underlying data regarding
production and import volumes and RFS obligation, as well as the
underlying data regarding RIN transactions and use, support the
information included in the reports. As a result, the final rule
includes an attest engagement requirement for obligated parties.
We also received several comments that the attest engagement
auditor should be required to examine only representative samples of
the party's RIN transaction documents rather than the documents for
each RIN transaction, as required in the proposed regulations. We agree
that examination of representative samples of RIN transaction documents
would provide sufficient oversight and that the requirement included in
the proposed regulations may be unnecessarily burdensome. As a result,
the attest engagement provisions have been modified to require the
auditor to examine only representative samples of RIN transaction
documents. However, in the case of attest engagements applied to RIN
generation by producers or importers of renewable fuel, or the use of
RINs for compliance purposes by obligated parties or exporters, the
auditor must examine documentation for all RINs generated or used. We
believe this requirement is necessary to ensure that obligated parties
and exporters are meeting their RFS obligation and that ethanol
producers and importers are assigning RINs to each batch of renewable
fuel produced or imported as required under the regulations.
The proposed attest engagement regulations at Sec. 80.1164(b) did
not include importers of renewable fuels. One commenter pointed out
these procedures should apply to both renewable fuels producers and
importers. Renewable fuel importers have the same reporting
requirements as renewable fuel producers, and, therefore, there is the
same need for verification of the information given on the reports
through attest engagements. It was an inadvertent oversight that
renewable fuel importers were not included in the parties required to
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comply with the attest engagement procedures in proposed Sec.
80.1164(b), and that applying the requirements in Sec. 80.1164(b) to
renewable fuel importers is a logical outgrowth of the proposed
regulations. As a result, the regulations have been modified to include
renewable fuel importers in the parties required to comply with the
attest procedures in Sec. 80.1164(b).
In addition to obligated parties, exporters and renewable fuel
producers and importers, we believe that an attest engagement
requirement is necessary for any party who takes ownership of a RIN. As
discussed above, attest engagements provide an appropriate and useful
tool for verifying the accuracy of the information reported to us. Like
obligated parties and renewable fuel producers and importers, the final
rule requires RIN owners to submit information regarding RIN
transaction activity to us. We believe that attest engagement audits
are necessary to verify the accuracy of the information included in
these reports. Therefore, this final rule includes an attest engagement
requirement for RIN owners who are not obligated parties or renewable
fuel producers or importers. We believe that inclusion of the
requirement in the final rule is a logical outgrowth of the proposed
attest engagement requirements for other parties who are required to
submit similar information regarding RIN transaction activity to us.
V. What Acts Are Prohibited and Who Is Liable for Violations?
The prohibition and liability provisions applicable to the RFS
program are similar to those of other gasoline programs. The final rule
identifies certain prohibited acts, such as a failure to acquire
sufficient RINs to meet a party's renewable fuel obligation (RVO),
producing or importing a renewable fuel without properly assigning a
RIN, creating, transferring or using invalid RINs, improperly
transferring renewable fuel volumes without RINs, improperly separating
RINs from renewable fuel, retaining more RINs during a quarter than the
party's inventory of renewable fuel, or transferring RINs that are not
identified by proper RIN numbers. Any person subject to a prohibition
will be held liable for violating that prohibition. Thus, for example,
an obligated party will be liable if the party fails to acquire
sufficient RINs to meet its RVO. A party who produces or imports
renewable fuels will be liable for a failure to properly assign RINs to
batches of renewable fuel produced or imported. A renewable fuels
marketer will be liable for improperly transferring renewable fuel
volumes without RINs or retaining more RINs during a quarter than the
party's inventory of renewable fuels. Any party may be liable for
creating, transferring, or using an invalid RIN, or transferring a RIN
that is not properly identified.
In addition, any person who is subject to an affirmative
requirement under the RFS program will be liable for a failure to
comply with the requirement. For example, an obligated party will be
liable for a failure to comply with the annual compliance reporting
requirements. A renewable fuel producer or importer will be liable for
a failure to comply with the applicable renewable fuel batch reporting
requirements. Any party subject to recordkeeping or product transfer
document requirements would be liable for a failure to comply with
these requirements. Like other EPA fuels programs, the final rule
provides that a party who causes another party to violate a prohibition
or fail to comply with a requirement may be found liable for the violation.
The Energy Act amended the penalty and injunction provisions in
section 211(d) of the Clean Air Act to apply to violations of the
renewable fuels requirements in section 211(o).\42\ Accordingly, under
the final rule, any person who violates any prohibition or requirement
of the RFS program may be subject to civil penalties for every day of
each such violation and the amount of economic benefit or savings
resulting from the violation. Under the final rule, a failure to
acquire sufficient RINs to meet a party's renewable fuels obligation
will constitute a separate day of violation for each day the violation
occurred during the annual averaging period.
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\42\ Section 1501(b) of the Energy Policy Act of 2005.
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Because there are no standards under the RFS rule that may be
measured downstream, we believe that a presumptive liability scheme,
i.e., a scheme in which parties upstream from the facility where the
violation is found are presumed liable for the violation, would not be
applicable under the RFS program. As a result, the RFS rule does not
contain such a scheme.
The regulations prohibit any party from creating, transferring or
using invalid RINs. These invalid RIN provisions apply regardless of
the good faith belief of a party that the RINs are valid. These
enforcement provisions are necessary to ensure the RFS program goals
are not compromised by illegal conduct in the creation and transfer of RINs.
Any obligated party that reports the use of invalid RINs to meet
its renewable fuels obligation may be liable for a regulatory violation
for use of invalid RINs. If the obligated party fails to meet its
renewable fuels obligation without the invalid RINs, the party may also
be liable for not meeting its renewable fuels obligation. In addition,
the transfer of invalid RINs is prohibited, so that any party or
parties that transfer invalid RINs may be liable for a regulatory
violation for transferring the invalid RINs. In a case where invalid
RINs are transferred and used, EPA normally will hold each party that
committed a violation responsible, including both the user and the
transferor of the invalid RINs. For this reason, obligated parties and
RIN brokers should use good business judgment when deciding whether to
purchase RINs from any particular seller and should consider including
prudent business safeguards in RIN transactions, such as requiring RIN
sellers to sign contracts with indemnity provisions to protect the
purchaser in the event penalties are assessed because we find the RINs
are invalid. Similarly, parties that sell RINs should take steps to
ensure any RINs that are sold were properly created to avoid penalties
that result from the transfer of invalid RINs.
As in other motor vehicle fuel credit programs, the regulations
address the consequences if an obligated party is found to have used
invalid RINs to demonstrate compliance with its RVO. In this situation,
the obligated party that used the invalid RINs will be required to
deduct any invalid RINs from its compliance calculations. As discussed
above, the obligated party will be liable for not meeting its renewable
fuels obligation if the remaining number of valid RINs is insufficient
to meet its RVO, and the obligated party may be subject to monetary
penalties if it used invalid RINs in its compliance demonstration. In
determining an appropriate penalty, EPA will consider a number of
factors, including whether the obligated party did in fact procure
sufficient valid RINs to cover the deficit created by the invalid RINs.
A penalty may include both the economic benefit of using invalid RINs
and a gravity component.
Although an obligated party may be liable for a violation if it
uses invalid RINs for compliance purposes, we normally will look first
to the generator or seller of the invalid RINs both for payment of
penalty and to procure sufficient valid RINs to offset the invalid
RINs. However, if EPA is unable to
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obtain relief from that party, attention will turn to the obligated
party who may then be required to obtain sufficient valid RINs to
offset the invalid RINs.
We received several comments on the prohibition regarding use of
invalid RINs. Some commenters believe that an obligated party that uses
RINs which are later found to be invalid should be given an opportunity
to ``cure'' the shortfall caused by the invalid RINs without penalty.
As indicated above, a penalty for a good faith purchaser is not
automatic. Where an invalid RIN was created by another party, such as
the producer or marketer of the renewable fuel, the party responsible
for the existence of the invalid RIN would be liable and would be
required to purchase a RIN to make up for the invalid RIN and pay an
appropriate penalty. If the responsible party cannot be identified or
is out of business, or if EPA is otherwise unable to obtain relief from
the party, then the obligated party that used the RIN would be required
to purchase a RIN to make up for the invalid RIN. However, any penalty
for a good faith purchaser would likely be small, particularly where
EPA is able to obtain relief from the party that was responsible for
the invalid RIN. Where a RIN was originally believed to be valid but is
later found to be invalid, whether a current year RIN may be used to
make up for the prior-year invalid RIN would be determined in the
context of the enforcement action.
Another commenter suggested that an obligated party should not be
liable for a violation unless the party knowingly used the invalid RINs
to demonstrate compliance. Where the suspect RINs are later proved to
be valid, the party should be able to use the RINs in the subsequent
year regardless of the year of generation or any rollover cap. For the
reasons stated above, we believe that it is appropriate to hold an
obligated party responsible for using invalid RINs even where the party
in good faith believed the RINs to be valid. Normally, suspect RINs
will be not be replaced until the RINs are proved to be invalid. In the
unlikely circumstance that a RIN is first determined to be invalid and
then later found to be valid, the ability to use the RIN in a subsequent
year would be determined in the context of the enforcement action.
Finally, parties that are predominately renewable fuel producers or
importers, but which must be designated as obligated parties due to the
production or importation of a small amount of gasoline, should not be
able to separate RINs from all renewable fuels that they own. To
address such circumstances, we are prohibiting obligated parties from
separating RINs that they generate from volumes of renewable fuel in
excess of their RVO. However, obligated parties must separate any RINs
generated by other parties from renewable fuel if they own the
renewable fuel.
VI. Current and Projected Renewable Fuel Production and Use
While the definition of renewable fuel does not limit compliance
with the standard to any one particular type of renewable fuel, ethanol
is currently the most prevalent renewable fuel blended into gasoline
today. Biodiesel represents another renewable fuel which, while not as
widespread as ethanol use (in terms of volume), has been increasing in
production capacity and use over the last several years. This section
provides a brief overview of the ethanol and biodiesel industries today
and how they are projected to grow into the future.
A. Overview of U.S. Ethanol Industry and Future Production/Consumption
1. Current Ethanol Production
As of October 2006, there were 110 ethanol production facilities
operating in the United States with a combined production capacity of
approximately 5.2 billion gallons per year.\43\ All of the ethanol
currently produced comes from grain or starch-based feedstocks that can
easily be broken down into ethanol via traditional fermentation
processes. The majority of ethanol (almost 92 percent by volume) is
produced exclusively from corn. Another 7 percent comes from a blend of
corn and/or similarly processed grains (milo, wheat, or barley) and
less than 1 percent is produced from waste beverages, cheese whey, and
sugars/starches combined. A summary of ethanol production by feedstock
is presented in Table VI.A.1-1.
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\43\ The October 2006 ethanol production capacity baseline was
generated based on the June 2006 NPRM plant list and updated on
October 18, 2006 based on a variety of data sources including:
Renewable Fuels Association (RFA), Ethanol Biorefinery Locations
(updated October 16, 2006); Ethanol Producer Magazine (EPM), plant
list (downloaded October 18, 2006) and monthly publications (June
2006 through October 2006); ICF International, Ethanol Industry
Profile (September 30, 2006); BioFuels Journal, News & Information
for the Ethanol and BioFuels Industries (breaking news posted June
16, 2006 through October 18, 2006); and ethanol producer Web sites.
The baseline includes small-scale ethanol production facilities as
well as former food-grade ethanol plants that have since
transitioned into the fuel-grade ethanol market. Where applicable,
current ethanol plant production levels have been used to represent
plant capacity, as nameplate capacities are often underestimated.
This analysis does not consider ethanol plants that may be located
in the Virgin Islands or U.S. territories.
Table VI.A.1-1.--2006 U.S. Ethanol Production by Feedstock
------------------------------------------------------------------------
Percent
Plant feedstock Capacity of Number of Percent
MMgy capacity plants of plants
------------------------------------------------------------------------
Cheese Whey................. 8 0.1 2 1.8
Corn a...................... 4,780 91.6 90 81.8
Corn, Barley................ 40 0.8 1 0.9
Corn, Milo b................ 244 4.7 8 7.3
Corn, Wheat................. 90 1.7 2 1.8
Milo, Wheat................. 40 0.8 1 0.9
Sugars, Starches............ 2 0.0 1 0.9
Waste Beverages c........... 16 0.3 5 4.5
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Total................... 5,218 100.0 110 100.0
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a Includes two facilities processing seed corn and another facility
processing corn which intends to transition to corn stalks,
switchgrass, and biomass in the future.
b Includes one facility procesisng small amounts of molasses in addition
to corn and milo.
c Includes two facilities processing brewery waste.
[[Page 23952]]
There are a total of 102 plants processing corn and/or other
similarly processed grains. Of these facilities, 92 utilize dry-milling
technologies and the remaining 10 plants rely on wet-milling processes.
Dry mill ethanol plants grind the entire kernel and produce only one
primary co-product: Distillers' grains with solubles (DGS). The co-
product is sold wet (WDGS) or dried (DDGS) to the agricultural market
as animal feed. In contrast to dry mill plants, wet mill facilities
separate the kernel prior to processing and in turn produce other co-
products (usually gluten feed, gluten meal, and oil) in addition to
DGS. Wet mill plants are generally more costly to build but are larger
in size on average. As such, nearly 22 percent of the current overall
ethanol production comes from the 10 previously-mentioned wet mill
facilities.
The remaining 8 plants which process waste beverages, cheese whey,
or sugars/starches, operate differently than their grain-based
counterparts. These facilities do not require milling and instead
operate a simpler enzymatic fermentation process.
In addition to grain and starch-to-ethanol production, another
method exists for producing ethanol from a more diverse feedstock base.
This process involves converting cellulosic materials such as bagasse,
wood, straw, switchgrass, and other biomass into ethanol. Cellulose
consists of tightly-linked polymers of starch, and production of
ethanol from it requires additional steps to convert these polymers
into fermentable sugars. Scientists are actively pursuing acid and
enzyme hydrolysis as well as gasification to achieve this goal, but the
technologies are still not fully developed for large-scale commercial
production. As of October 2006, the only known cellulose-to-ethanol
plant in North America was Iogen in Canada, which produces
approximately one million gallons of ethanol per year from wood chips.
Several companies have announced plans to build cellulose-to-ethanol
plants in the U.S., but most are still in the research and development
or pre-construction planning phases. The majority of the plans involve
converting bagasse, rice hulls, wood, switchgrass, corn stalks, and
other agricultural waste or biomass into ethanol. For a more detailed
discussion on future cellulosic ethanol plants and production
technologies, refer to RIA Sections 1.2.3.6 and 7.1.2, respectively.
Ethanol production is a relatively resource-intensive process that
requires the use of water, electricity, and steam. Steam needed to heat
the process is generally produced onsite or by other dedicated boilers.
Of today's 110 ethanol production facilities, 101 burn natural gas, 7
burn coal, 1 burns coal and biomass, and 1 burns syrup from the process
to produce steam.\44\ Our research suggests that 11 plants currently
utilize cogeneration or combined heat and power (CHP) technology,
although others may exist. CHP is a mechanism for improving overall
plant efficiency. Whether owned by the ethanol facility, their local
utility, or a third party; CHP facilities produce their own electricity
and use the waste heat from power production for process steam,
reducing the energy intensity of ethanol production. A summary of the
energy sources and CHP technology utilized by today's ethanol plants is
found in Table VI.A.1-2.
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\44\ Facilities were assumed to burn natural gas if the plant
fuel type was not mentioned or unavailable.
Table VI.A.1-2.--2006 U.S. Ethanol Production by Energy Source
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Percent
Plant energy source Capacity of Number of Percent CHP tech.
MMgy capacity plants of plants
----------------------------------------------------------------------------------------------------------------
Coal..................................................... 1,042 20.0 7 6.3 2
Coal, Biomass............................................ 50 1.0 1 0.9 0
Natural Gas \a\.......................................... 4,077 78.1 101 91.8 9
Syrup.................................................... 48 0.9 1 0.9 0
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Total................................................ 5,218 100.0 110 100.0 11
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\a\ Includes three facilities burning natural gas which intend to transition to coal or biomass in the future.
The majority of domestic ethanol is currently produced in the
Midwest within PADD 2--where most of the corn is grown. Of the 110 U.S.
ethanol production facilities, 100 are located in PADD 2. As a region,
PADD 2 accounts for 96 percent (or over five billion gallons) of the
annual domestic ethanol production, as shown in Table VI.A.1-3.
Table VI.A.1-3.--2006 U.S. Ethanol Production by PADD
------------------------------------------------------------------------
Percent
PADD Capacity of Number of Percent
MMgy capacity plants of plants
------------------------------------------------------------------------
PADD 1...................... 0.4 0.0 1 0.9
PADD 2...................... 5,012 96.0 100 90.9
PADD 3...................... 30 0.6 1 0.9
PADD 4...................... 105 2.0 4 3.6
PADD 5...................... 71 1.4 4 3.6
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Total................... 5,218 100.0 110 100.0
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Leading the Midwest in ethanol production are Iowa, Illinois,
Nebraska, Minnesota, and South Dakota with a combined capacity of
nearly four billion gallons per year. Together, these five states' 70
ethanol plants account for 76 percent of the total domestic product.
However, although the majority of ethanol production comes from PADD 2,
there are a growing number of plants located outside the traditional
corn belt. In addition to the 15 states comprising PADD 2, ethanol
plants are currently located in California, Colorado, Georgia, New
Mexico, and Wyoming. Some of these facilities ship in feedstocks
(namely corn) from the Midwest, others rely on locally grown/produced
feedstocks, while others rely on a combination of both.
The U.S. ethanol industry is currently comprised of a mixture of
corporations and farmer-owned cooperatives (co-ops). More than half (or
60) of today's plants are owned by corporations and, on average, these
plants are larger in size than farmer-owned co-ops. Accordingly,
company-owned plants account for almost 64 percent of the total U.S.
ethanol production capacity. Further, more than 50 percent of the total
domestic product comes from plants owned by just 6 different
companies--Archer Daniels Midland, Broin, VeraSun, Hawkeye Renewables,
Global/MGP Ingredients, and Aventine Renewable Energy.\45\
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\45\ Includes Broin's minority ownership in 18 U.S. ethanol plants.
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2. Expected Growth in Ethanol Production
Over the past 25 years, domestic fuel ethanol production has
steadily increased due to environmental regulation, federal and state
tax incentives, and market demand. More recently, ethanol production
has soared due to the phase out of MTBE, an increasing number of state
ethanol mandates, and elevated crude oil prices. As shown in Figure
VI.A.2-1, over the past three years, domestic ethanol production has
nearly doubled from 2.1 billion gallons in 2002 to 4.0 billion gallons
in 2005. For 2006, the Renewable Fuels Association is anticipating
about 4.7 billion gallons of domestic ethanol production.\46\
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\46\ Based on RFA comments received in response to the proposed
rulemaking, 71 FR 55552 (September 22, 2006).
[GRAPHIC]
[TIFF OMITTED] TR01MY07.047
EPA forecasts that domestic ethanol production will continue to
grow into the future. In addition to the past impacts of federal and
state tax incentives, as well as the more recent impacts of state
ethanol mandates and the removal of MTBE from all U.S. gasoline, crude
oil prices are expected to continue to drive up demand for
[[Page 23954]]
ethanol. As a result, the nation is on track to exceed the renewable
fuel volume requirements contained in the Act. Today's ethanol
production capacity (5.2 billion gallons) is already exceeding the 2007
renewable fuel requirement (4.7 billion gallons). In addition, there is
another 3.4 billion gallons of ethanol production capacity currently
under construction.\47\ A summary of the new construction and plant
expansion projects currently underway (as of October 2006) is found in
Table VI.A.2-1.
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\47\ Under construction plant locatons, capacities, feedstocks,
and energy sources as well as planned/proposed plant locations and
capacities were derived from a variety of data soruces including
Renewable Fuels Association (RFA), Ethanol Biorefinery Locations
(updated October 16, 2006); Ethanol Producer Magazine (EPM), under
construction plant list (downloaded October 18, 2006) and monthly
publications (June 2006 through October 2006); ICF International,
Ethanol Industry Profile (September 30, 2006); BioFuels Journal,
News & Information for the Ethanol and BioFuels Industries (breaking
news posted June 16, 2006 through October 18, 2006); and ethanol
producer Web sites. This analysis does not consider ethanol plants
under construction or planned for the Virgin Islands or U.S.
territories.
Table VI.A.2-1.--Under Construction U.S. Ethanol Production Capacity
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Oct. 2006 baseline Under const. Base + under const.
PADD ------------------------------------------------------------------------------
MMgy Plants MMgy a Plants MMgy a Plants
----------------------------------------------------------------------------------------------------------------
PADD 1........................... 0.4 1 115 1 115 2
PADD 2........................... 5,012 100 2,764 39 7,776 139
PADD 3........................... 30 1 230 3 260 4
PADD 4........................... 105 4 50 1 155 5
PADD 5........................... 71 4 198 3 269 7
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Total........................ 5,218 110 3,357 47 8,575 157
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a Includes plant expansions.
A select group of builders, technology providers, and construction
contractors are completing the majority of the construction projects
described in Table VI.A.2-1. As such, the completion dates of these
projects are staggered over approximately 18 months, resulting in the
gradual phase-in of ethanol production shown in Figure VI.A.2-2.\48\
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\48\ Construction timelines based on information obtained from
press releases and ethanol producer Web sites.
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[[Page 23955]]
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[TIFF OMITTED] TR01MY07.048
As shown in Table VI.A.2-1 and Figure VI.A.2-2, once all the
construction projects currently underway are complete (estimated by
March 2008), the resulting U.S. ethanol production capacity would be
about 8.6 billion gallons. Without even considering forecasted
biodiesel production (described below in Section VI.B.1), this would be
more than enough renewable fuel to satisfy the 2012 RFS requirements
(7.5 billion gallons). However, ethanol production is expected to
continue to grow. There are more and more ethanol projects being
announced each day. These potential projects are at various stages of
planning from conducting feasibility studies to gaining local approval
to applying for permits to financing/fundraising to obtaining
contractor agreements. Together these potential projects could result
in an additional 21 billion gallons of ethanol production capacity as
shown in Table VI.A.2-2.
Table VI.A.2-2.--Other Potential U.S. Ethanol Production Capacity
----------------------------------------------------------------------------------------------------------------
Base + under const. Planned Proposed
PADD -----------------------------------------------------------------
MMgy \a\ Plants MMgy \a\ Plants MMgy \a\ Plants
----------------------------------------------------------------------------------------------------------------
PADD 1........................................ 115 2 548.0 8 934 21
PADD 2........................................ 7,776 139 4,633 44 11,722 136
PADD 3........................................ 260 4 250 4 876 14
PADD 4........................................ 155 5 100 1 783 14
PADD 5........................................ 269 7 232 8 775 23
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Subtotal.............................. 8,575 157 5,763 65 15,090 208
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Total \b\............................. ......... ......... 14,339 222 29,428 430
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\a\ Includes plant expansions.
\b\ Total including existing plus under construction plants.
Although there is clearly a great potential for ethanol production
growth, it is highly unlikely that all the announced projects would
actually reach completion in a reasonable amount of time, or at all,
considering the large number of projects moving forward. Since there is
no precise way to know exactly which plants will come
[[Page 23956]]
to fruition in the future, we have chosen to focus our subsequent
discussion on forecasted ethanol production on plants which are likely
to be online by 2012.\49\ This includes existing plants as well as
projects which are under construction (refer to Table VI.A.2-1) or in
the final planning stages (denoted as ``planned'' in Table VI.A.2-2).
The distinction between ``planned'' versus ``proposed'' is that as of
October 2006 planned projects had completed permitting, fundraising/
financing, and had builders assigned with definitive construction
timelines whereas proposed projects did not.
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\49\ A more detailed summary of the plants we considered is
found in a March 5, 2007 note to the docket titled: RFS Industry
Characterization--Ethanol Production.
Table VI.A.2-3.--Forecasted 2012 Ethanol Production by PADD
------------------------------------------------------------------------
Percent
PADD Capacity of Number of Percent
MMgy capacity plants of plants
------------------------------------------------------------------------
PADD 1...................... 663 4.6 10 4.5
PADD 2...................... 12,409 86.5 183 82.4
PADD 3...................... 510 3.6 8 3.6
PADD 4...................... 255 1.8 6 2.7
PADD 5...................... 501 3.5 15 6.8
-------------------------------------------
Total................... 14,339 100.0 222 100.0
------------------------------------------------------------------------
As shown above in Table VI.A.2-3, once all the under construction
and planned projects are complete the resulting ethanol production
capacity would be 14.3 billion gallons. The majority of which would
still originate from PADD 2. This volume, expected to be online by
2012, exceeds the EIA AEO 2006 demand estimate (9.6 billion gallons by
2012, discussed more in RIA Section 2.1). The forecasted growth would
nearly triple today's production capacity and greatly exceed the 2012
RFS requirement (7.5 billion gallons). While our forecast represents
ethanol production capacity (actual production could be lower), we
believe it is still a good indicator of what domestic ethanol
production could look like in the future. In addition, we predict that
domestic ethanol production will continue to be supplemented by imports
in the future. According to a current report by F.O. Licht, U.S. net
import demand is estimated to be around 300 million gallons per year by
2012, being supplied primarily through the Caribbean Basin Initiative
(CBI), with some direct imports from Brazil during times of shortfall
or high price. For more information on ethanol imports, refer to RIA
Section 1.5.
Of the 112 forecasted new ethanol plants (47 under construction and
65 planned), 106 would rely on grain-based feedstocks. More
specifically, 89 would rely exclusively on corn, 13 would process a
blend of corn and/or similarly processed grains (milo or wheat), 3
would process molasses, and 1 would process a combination of molasses
and sweet sorghum (milo). Of the remaining six plants (all in the
planned stage), four would process cellulosic biomass feedstocks and
two would start off processing corn and later transition to cellulosic
materials. Of the four dedicated cellulosic plants, one would process
bagasse, one would process a combination of bagasse and wood, and two
would process biomass. Of the two transitional corn/cellulosic plants,
one would ultimately process a combination of bagasse, rice hulls, and
wood and the other would ultimately process wood and other agricultural
residues. In addition to the forecasted new plants, an existing corn
ethanol plant plans to expand production and transition to corn stalks,
switchgrass, and biomass in the future. A summary of the resulting
overall feedstock usage (including current, under construction, and
planned projects) is found in Table VI.A.2-4.
Table VI.A.2-4.--Forecasted 2012 U.S. Ethanol Production by Feedstock
------------------------------------------------------------------------
Percent
Plant feedstock Capacity of Number of Percent
MMgy capacity plants of plants
------------------------------------------------------------------------
Bagasse..................... 7 0.1 1 0.5
Bagasse, Wood............... 2 0.0 1 0.5
Bagasse, Wood, Rice Hulls 108 0.8 1 0.5
\a\........................
Biomass..................... 55 0.4 2 0.9
Cheese Whey................. 8 0.1 2 0.9
Corn \b\.................... 12,495 87.1 178 80.2
Corn, Barley................ 40 0.3 1 0.5
Corn, Milo \c\.............. 1,132 7.9 20 9.0
Corn, Wheat................. 235 1.6 3 1.4
Corn Stalks, Switchgrass, 40 0.3 1 0.5
Biomass \a\................
Milo, Wheat................. 40 0.3 1 0.5
Molasses \d\................ 52 0.4 4 1.8
Sugars, Starches............ 2 0.0 1 0.5
Waste Beverages \e\......... 16 0.1 5 2.3
Wood Agricultural Residues 108 0.8 1 0.5
\a\........................
-------------------------------------------
Total................... 14,339 100.0 222 100.0
------------------------------------------------------------------------
\a\ Facilities plan to start off processing corn.
[[Page 23957]]
\b\ Includes two facilities processing seed corn.
\c\ Includes one facility processing small amounts of molasses in
addition to corn and milo.
\d\ Includes one facility planning to process sweet sorghum (milo) in
addition to molasses.
\e\ Includes two facilities processing brewery waste.
Of the 112 forecasted new plants, 100 would burn some amount of
natural gas--at least initially. More specifically, 91 plants would
rely exclusively on natural gas; 2 would rely on a combination of
natural gas, bran and biomass; 1 would burn a combination of natural
gas, distillers' grains and syrup; and 6 would start off burning
natural gas and later transition to coal. As for the remaining 12
plants, 3 would burn manure-derived methane (biogas); 7 would rely
exclusively on coal; 1 would burn a combination of coal and biomass;
and 1 would burn a combination of coal, tires and biomass. In addition
to the new ethanol plants, three existing plants currently burning
natural gas are predicted to transition to alternate boiler fuels in
the future. More specifically, two plants plan to transition to biomass
and one plans to start burning coal. Our research suggests that 7 of
the new plants would utilize combined heat and power (CHP) technology,
although others may exist. Three of the new CHP plants would burn
natural gas, three would burn coal, and one would burn a combination of
coal, tires, and biomass. Among the existing CHP plants, two are
predicted to transition from natural gas to coal or biomass at this
time. Overall, the net number of CHP ethanol plants would increase from
11 to 18. A summary of the resulting overall plant energy source
utilization is found below in Table VI.A.2-5.
Table VI.A.2-5.--Forecasted 2012 U.S. Ethanol Production by Energy Source
----------------------------------------------------------------------------------------------------------------
Percent
Plant energy source Capacity of Number of Percent CHP tech.
MMgy capacity plants of plants
----------------------------------------------------------------------------------------------------------------
Biomass \a\.............................................. 112 0.8 2 0.9 1
Coal \b\................................................. 2,095 14.6 21 9.5 6
Coal, Biomass............................................ 75 0.5 2 0.9 0
Coal, Biomass, Tires..................................... 275 1.9 1 0.5 1
Manure Biogas \c\........................................ 144 1.0 3 1.4 0
Natural Gas.............................................. 11,275 78.6 189 85.1 10
Natural Gas, Bran, Biomass............................... 264 1.8 2 0.9 0
Natural Gas, Distiller's Grain, Syrup.................... 50 0.3 1 0.5 0
Syrup.................................................... 49 0.3 1 0.5 0
------------------------------------------------------
Total................................................ 14,339 100.0 222 100.0 18
----------------------------------------------------------------------------------------------------------------
\a\ Represents two existing natural gas-fired plants that plan to transition to biomass.
\b\ Includes two plants planning on burning lignite coal or coal lines. Includes one existing plant currently
burning natural gas that plans to transition to coal. Includes six new plants that will start off burning
natural gas and later transition to coal.
\c\ Includes one facility planning on burning cotton gin in addition to manure biogas.
The Energy Policy Act of 2005 requires that 250 million gallons of
the renewable fuel consumed in 2013 and beyond meet the definition of
cellulosic biomass ethanol. The Act defines cellulosic biomass ethanol
as ethanol derived from any lignocellulosic or hemicellulosic matter
that is available on a renewable or recurring basis including dedicated
energy crops and trees, wood and wood residues, plants, grasses,
agricultural residues, fibers, animal wastes and other waste materials,
and municipal solid waste. The term also includes any ethanol produced
in facilities where animal or other waste materials are digested or
otherwise used to displace 90 percent of more of the fossil fuel
normally used in the production of ethanol.
As shown in Table VI.A.2-4, there are seven ethanol plants planning
to utilize cellulosic feedstocks in the future. These facilities have a
combined ethanol production capacity of 320 million gallons per year.
It is unclear whether these plants would be online and capable of
producing 250 million gallons of ethanol by 2013 to meet the Act's
cellulosic biomass ethanol requirement. However, as shown in Table
VI.A.2-5, there are 12 facilities that burn or plan to burn waste
materials to power their ethanol plants. Depending on how much fossil
fuel is displaced, these facilities (with a combined ethanol production
capacity of 969 million gallons per year) could also meet the
definition of cellulosic biomass ethanol under the Act. Considering
both feedstock and waste energy plants, the total cellulosic ethanol
potential could be as high as 1.3 billion gallons. Even if only one
fifth of this ethanol were to end up qualifying as cellulosic biomass
ethanol or come to fruition by 2013, it would be more than enough to
satisfy the 250 million gallon requirement specified in the Act.\50\
---------------------------------------------------------------------------
\50\ We anticipate a ramp-up in cellulosic ethanol production in
the years to come so that capacity exists to satisfy the Act's 2013
requirement (250 million gallons of cellulosic biomass ethanol).
Therefore, for subsequent analysis purposes, we have assumed that
250 million gallons of ethanol would come from cellulosic biomass
sources by 2012.
---------------------------------------------------------------------------
3. Current Ethanol and MTBE Consumption
To understand the impact of the increased ethanol production/use on
gasoline properties and in turn overall air quality, we first need to
gain a better understanding of where ethanol is used today and how the
picture is going to change in the future. As such, in addition to the
production analysis presented above, we have completed a parallel
consumption analysis comparing current ethanol consumption to future
predictions.
In the 2004 base case, 3.5 billion gallons of ethanol \51\ and 1.9
billion gallons of MTBE \52\ were blended into gasoline to supply the
transportation sector with a total of 136 billion gallons of
gasoline.\53\ A breakdown of the 2004
[[Page 23958]]
gasoline and oxygenate consumption by PADD is found below in Table VI-
A.3-1.
---------------------------------------------------------------------------
\51\ EIA Monthly Energy Review, June 2006 (Table 10.1: Renewable
Energy Consumption by Source, Appendix A: Thermal Conversion
Factors).
\52\ File containing historical RFG MTBE usage obtained from EIA
representative on March 9, 2006.
\53\ EIA 2004 Petroleum Marketing Annually (Table 48: Prime
Supplier Sales Volumes of Motor Gasoline by Grade, Formulation, PAD
District, and State).
Table VI.A.3-1.--2004 U.S. Gasoline & Oxygenate Consumption by PADD
----------------------------------------------------------------------------------------------------------------
Ethanol MTBE \a\
Gasoline ---------------------------------------------------
PADD MMgal Percent of Percent of
MMgal gasoline MMgal gasoline
----------------------------------------------------------------------------------------------------------------
PADD 1......................................... 49,193 660 1.3 1,360 2.8
PADD 2......................................... 38,789 1,616 4.2 1 0.0
PADD 3......................................... 20,615 79 0.4 498 2.4
PADD 4......................................... 4,542 83 1.8 0 0.0
PADD 5 \b\..................................... 7,918 209 2.6 19 0.2
California..................................... 14,836 853 5.8 0 0.0
----------------------------------------------------------------
Total...................................... 135,893 3,500 2.6 1,878 1.4
----------------------------------------------------------------------------------------------------------------
\a\ MTBE blended into RFG.
\b\ PADD 5 excluding California.
As shown above, nearly half (or about 45 percent) of the ethanol
was consumed in PADD 2 gasoline, where the majority of ethanol was
produced. The next highest region of use was the State of California
which accounted for about 25 percent of domestic ethanol consumption.
This is reasonable because California alone accounts for over 10
percent of the nation's total gasoline consumption and all the fuel
(both Federal RFG and California Phase 3 RFG) has been assumed to
contain ethanol (following their recent MTBE ban) at 5.7 volume
percent.\54\ The bulk of the remaining ethanol was used in reformulated
gasoline (RFG) and winter oxy-fuel areas requiring oxygenated gasoline.
Overall, 62 percent of ethanol was used in RFG, 33 percent was used in
CG, and 5 percent was used in winter oxy-fuel.\55\
---------------------------------------------------------------------------
\54\ Current California gasoline regualtions make it very
difficult to meet the NOX emissions performance standard
with ethanol content higher than about 6 vol%. For our analysis, all
California RFG was assumed to contain 5.7 volume percent ethanol based on
a conversation with Dean Simeroth at California Air Resources Board (CARB).
\55\ For the purpose of this analysis, except where noted, the
term ``RFG'' pertains to Federal RFG plus California Phase 3 RFG
(CaRFG3) and Arizona Clean Burning Gasoline (CBG).
---------------------------------------------------------------------------
As shown above in Table VI.A.3-1, 99 percent of MTBE use occurred
in PADDs 1 and 3. This reflects the high concentration of RFG areas in
the northeast (PADD 1) and the local production of MTBE in the gulf
coast (PADD 3). PADD 1 receives a large portion of its gasoline from
PADD 3 refineries who either produce the fossil-fuel based oxygenate or
are closely affiliated with MTBE-producing petrochemical facilities in
the area. Overall, 100 percent of MTBE in 2004 was assumed to be used
in reformulated gasoline.\56\
---------------------------------------------------------------------------
\56\ 2004 MTBE consumption was obtained from EIA. The data
received was limited to states with RFG programs, thus MTBE use was
assumed to be limited to RFG areas for the purpose of this analysis.
---------------------------------------------------------------------------
In 2004, total ethanol use exceeded MTBE use. Ethanol's lead
oxygenate role is relatively new, however the trend has been a
progression over the past few years. From 2001 to 2004, ethanol
consumption more than doubled (from 1.7 to 3.5 billion gallons), while
MTBE use (in RFG) was virtually cut in half (from 3.7 to 1.9 billion
gallons). A plot of oxygenate use over the past decade is provided
below in Figure VI.A.3-1.
The nation's transition to ethanol is linked to states' responses
to recent environmental concerns surrounding MTBE groundwater
contamination. Resulting concerns over drinking water quality have
prompted several states to significantly restrict or completely ban
MTBE use in gasoline. At the time of this analysis, 19 states had
adopted MTBE bans. A list of the states with MTBE bans is provided in
RIA Table 2.1-4.
[[Page 23959]]
[GRAPHIC]
[TIFF OMITTED] TR01MY07.049
4. Expected Growth in Ethanol Consumption
As mentioned above, ethanol demand is expected to increase well
beyond the levels contained in the renewable fuels standard (RFS) under
the Act. With the removal of the RFG oxygenate mandate,\57\ all U.S.
refiners are taking steps to eliminate the use of MTBE as quickly as
possible. In order to complete this transition quickly (by 2007 at the
latest) while maintaining gasoline volume, octane, and mobile source
air toxics emission performance standards, refiners have elected to
blend ethanol into virtually all of their RFG.\58\ This has caused a
dramatic increase in demand for ethanol which, in 2006, was met by
temporarily shifting large volumes of ethanol out of conventional
gasoline and into RFG areas. By 2012, however, ethanol production will
have grown to accommodate the removal of MTBE without the need for such
a shift from conventional gasoline. More important than the removal of
MTBE over the long term, however, is the impact that the rise in crude
oil price is having on demand for renewable fuels, both ethanol and
biodiesel. This has dramatically improved the economics for renewable
fuel use, leading to a surge in demand that is expected to continue. In
the Annual Energy Outlook (AEO) 2006, EIA forecasted that by 2012,
total ethanol use (corn, cellulosic, and imports) would be about 9.6
billion gallons and biodiesel use would be about 0.3 billion gallons at
a crude oil price forecast of $48 per barrel.\59\ This ethanol
projection was not based on what amount the market would demand (which
could be higher), but rather on the amount that could be produced by
2012. Others are making similar predictions, and as discussed above in
VI.A.2, production capacity would be sufficient.
---------------------------------------------------------------------------
\57\ Energy Act Section 1504, promulgated on May 8, 2006 at 71 FR 26691.
\58\ Based on discussions with the refining industry.
\59\ In AEO 2007, EIA is forecasted an even higher ethanol
consumption of 11.2 billion gallons by 2012. The draft report was
issued on December 5, 2006 and we could not incorporate it into the
refinery modeling used to conduct our analyses.
---------------------------------------------------------------------------
In assessing the impacts of expanded renewable fuel use, we have
chosen to evaluate two different future ethanol consumption levels, one
reflecting the statutory required minimum, and one reflecting the
higher levels projected by EIA. For the statutory consumption scenario
we assumed 6.7 billion gallons of ethanol use (0.25 billion gallons of
which was assumed to be cellulosic) and 0.3 billion gallons of
biodiesel. This figure is lower than the 7.2 billion gallons of ethanol
we modeled in the proposal because it considers the renewable fuel
equivalence values we are finalizing for corn ethanol (1), biodiesel
(1.5) and cellulosic ethanol (2.5). For the higher projected renewable
fuel consumption scenario, we assumed 9.6 billion gallons of ethanol
(0.25 billion gallons of which was assumed to be cellulosic) and 0.3
billion gallons of biodiesel. Although the actual renewable fuel
volumes consumed in 2012 may differ from both the required and
projected volumes, we believe that
[[Page 23960]]
these two scenarios provide a reasonable range for analysis purposes.
For more information on how the renewable fuel usage scenarios we
considered, refer to RIA Section 2.1.
To estimate where ethanol would be consumed in 2012, we used a
linear programming (LP) refinery cost model (discussed in more detail
in Section VII). For both future ethanol consumption scenarios
discussed above, the modeling provided us with a summary of ethanol
usage by PADD, fuel type, and season. There was some post-processing
involved to ensure that all state ethanol mandates and winter oxy-fuel
requirements were satisfied. The adjusted results for the 6.7 Bgal RFS
case and the 9.6 Bgal EIA case are presented below in Tables VI.A.4-1
and VI.A.4-2, respectively.
Table VI.A.4-1.--Forecasted 2012 U.S. Ethanol Consumption (MMgal) 6.7 Bgal RFS Case
----------------------------------------------------------------------------------------------------------------
Summer ethanol use Winter ethanol use
PADD ------------------------------------------------------------------ Total
CG \a\ RFG \b\ Total CG \a\ RFG \b\ Total ethanol
----------------------------------------------------------------------------------------------------------------
PADD 1............................. 399 679 1,078 350 706 1,057 2,134
PADD 2............................. 1,667 59 1,726 1,082 288 1,370 3,096
PADD 3............................. 161 47 208 146 0 146 354
PADDs 4/5 c........................ 135 0 135 138 0 138 274
California......................... 0 414 414 0 398 398 813
----------------------------------------------------------------------------
Total.......................... 2,362 1,200 3,562 1,717 1,392 3,109 6,671
----------------------------------------------------------------------------------------------------------------
\a\ Includes Arizona CBG and winter oxy-fuel.
\b\ Federal RFG and California Phase 3 RFG.
\c\ PADDS 4 and 5 excluding California.
Table VI.A.4-1.--Forecasted 2012 U.S. Ethanol Consumption by Season (MMgal) 9.6 Bgal EIA Case
----------------------------------------------------------------------------------------------------------------
Summer ethanol use Winter ethanol use
PADD ------------------------------------------------------------------ Total
CG \a\ RFG \b\ Total CG \a\ RFG \b\ Total ethanol
----------------------------------------------------------------------------------------------------------------
PADD1.............................. 610 630 1,240 267 973 1,240 2,481
PADD2.............................. 1,735 185 1,919 1,631 366 1,998 3,917
PADD3.............................. 901 47 949 856 0 856 1,805
PADD 4/5 \c\....................... 339 0 339 154 0 154 492
California......................... 0 435 435 0 470 470 905
----------------------------------------------------------------------------
Total.......................... 3,584 1,298 4,882 2,908 1,809 4,718 9,600
----------------------------------------------------------------------------------------------------------------
\a\ Includes Arizona CBG and winter oxy-fuel.
\b\ Federal RFG and California Phase 3 RFG.
\c\ PADDs 4 and 5 excluding California.
As shown above, the LP modeling predicts that the majority of
ethanol will be consumed in PADD 2, where most of the ethanol is
produced. The results show varying levels of ethanol usage in RFG in
response to the removal of the oxygenate requirement. For the higher
ethanol consumption scenario, the modeling suggests that the majority
of additional ethanol would be absorbed in PADD 3 conventional
gasoline. With respect to seasonality, in both cases, the modeling
predicts that a greater fraction of ethanol use would occur in the
summertime due to the 1psi RVP waiver. For a more detailed discussion
on future ethanol consumption, refer to Chapter 2 of the RIA.
B. Overview of Biodiesel Industry and Future Production/Consumption
1. Characterization of U.S. Biodiesel Production/Consumption
Historically, the cost to make biodiesel was an inhibiting factor
to production in the U.S. The cost to produce biodiesel was high
compared to the price of petroleum derived diesel fuel, even with the
subsidies and credits provided by federal and state programs. Much of
the demand occurred as a result of mandates from states and local
municipalities, that required the use of biodiesel. However, over the
past couple of years biodiesel production has been increasing rapidly.
The combination of higher crude oil prices and greater federal tax
subsidies has created a favorable economic situation. The Biodiesel
Blenders Tax Credit programs and the Commodity Credit Commission Bio-
energy Program, both subsidize producers and offset production costs.
The Energy Policy Act extended the Biodiesel Blenders Tax Credit
program to 2008. This credit provides about one dollar per gallon in
the form of a federal excise tax credit to biodiesel blenders from
virgin vegetable oil feedstocks and 50 cents per gallon to biodiesel
produced from recycled grease and animal fats. The program was started
in 2004 under the American Jobs Act, spurring the expansion of
biodiesel production and demand. Historical estimates and future
forecasts of biodiesel production in the U.S. are presented in Table
VI.B.1-1 below.
Table VI.B.1-1.--Estimated Biodiesel Production
------------------------------------------------------------------------
Million
Year gallons
per year
------------------------------------------------------------------------
2001......................................................... 5
2002......................................................... 15
2003......................................................... 20
2004......................................................... 25
2005......................................................... 91
2006......................................................... 150
2007......................................................... 414
2012......................................................... 303
------------------------------------------------------------------------
Source: Historical data from 2001-2004 obtained from estimates from John
Baize `` The Outlook and Impact of Biodiesel on the Oilseeds Sector''
USDA Outlook Conference 06. Year 2005 data from USDA Bioenergy Program
http://www.fsa.usda.gov/daco/bioenergy/2005/FY2005ProductPayments,
Year 2006 data from verbal quote based on projection by NBB in June of
2006. Production data for years 2007 and higher are from EIA's AEO 2006.
With the increase in biodiesel production, there has also been a
[[Page 23961]]
corresponding rapid expansion in biodiesel production capacity.
Presently, there are 85 biodiesel plants in operation with an annual
production capacity of 580 million gallons per year.\60\ The majority
of the current production capacity was built in 2005 and 2006, and was
first available to produce fuel in the later part of 2005 and in 2006.
Though the capacity has grown, historically the biodiesel production
capacity has far exceeded actual production with only 10-30 percent of
this being utilized to make biodiesel. The excess capacity, though, may
be from biodiesel plants that do not operate full time and from
production capacity that is primarily devoted to making esters for the
ole-chemical markets, see Table VI.B.1-2.
---------------------------------------------------------------------------
\60\ NBB Survey September 13, 2006 ``U.S. Biodiesel Production
Capacity''.
\61\ From Presentation ``Biodiesel Production Capacity,'' by
Leland Tong, National Biodiesel Conference and Expo, February 7, 2006.
Table VI.B.1-2.--U.S. Production Capacity History a
------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006
------------------------------------------------------------------------
Plants........................ 9 11 16 22 45 85
Capacity (million gal/yr)..... 50 54 85 157 290 580
------------------------------------------------------------------------
\a\ Capacity Data based on surveys conducted around the month of
September for most years, though the 2006 information is based on a
survey conducted in January 2006.\61\
2. Expected Growth in U.S. Biodiesel Production/Consumption
In addition to the 85 biodiesel plants already in production, as of
early 2006, there were 65 plants in the construction phase and 13
existing plants that are expanding their capacity, which when completed
would increase total biodiesel production capacity to over one billion
gallons per year. Most of these plants should be completed by late
2007. As shown in Table VI.B.2-1 if all of this capacity came to
fruition, U.S. biodiesel capacity would exceed 1.4 billion gallons.
Table VI.B.2-1.--Projected Biodiesel Production Capacity
------------------------------------------------------------------------
Existing Construction
plants phase
------------------------------------------------------------------------
Number of plants........................ 85 78
Total Plant Capacity, (MM Gallon/year).. 580 1,400
------------------------------------------------------------------------
For cost and emission analysis purposes, three biodiesel usage
cases were considered: A 2004 base case, a 2012 reference case, and a
2012 control case. The 2004 base case was formed based on historical
biodiesel usage (25 million gallons as summarized in Table VI.B.1.1).
The reference case was computed by taking the 2004 base case and
growing it out to 2012 by applying the 2004-2012 EIA diesel fuel growth
rate.\62\ The resulting 2012 reference case consisted of 30 million
gallons of biodiesel. Finally, for the 2012 control case, forecasted
biodiesel use was assumed to be 300 million gallons based on EIA's AEO
2006 report (rounded value from Table VI.B.1.1). Unlike forecasted
ethanol use, biodiesel use was assumed to be constant at 300 million
gallons under both the statutory and higher projected renewable fuel
consumption scenarios described in VI.A.4. EIA's projection is based on
the assumption that the blender's tax credit is not renewed beyond
2008. If the tax credit is renewed, the projection for biodiesel demand
would increase.
---------------------------------------------------------------------------
\62\ EIA Annual Energy Outlook 2006, Table 1.
---------------------------------------------------------------------------
C. Feasibility of the RFS Program Volume Obligations
This section examines whether there are any feasibility issues
associated with the meeting the minimum renewable fuel requirements of
the Energy Act. Issues are examined with respect to renewable
production capacity, cellulosic ethanol production capacity, and
distribution system capability. Land resource requirements are
discussed in Chapter 7 of the RIA.
1. Production Capacity of Ethanol and Biodiesel
As shown in Sections VI.A. and VI.B., increases in renewable fuel
production capacity are already proceeding at a pace significantly
faster than required to meet the 2012 mandate in the Act of 7.5 billion
gallons as well as the mandate (starting in 2013) of a minimum of 250
million gallons of cellulosic ethanol. The combination of ethanol and
biodiesel plants in existence and planned or under construction is
expected to provide a total renewable fuel production capacity of over
9.6 billion gallons by the end of 2012. Production capacity is expected
to continue to increase in response to strong demand. We estimate that
this will require a maximum of 2,100 construction workers and 90
engineers on a monthly basis through 2012.
2. Technology Available To Produce Cellulosic Ethanol
There are a wide variety of government and renewable fuels industry
research and development programs dedicated to improving our ability to
produce renewable fuels from cellulosic feedstocks. In this discussion,
we deal with at least three completely different approaches to
producing ethanol from cellulosic biomass. The first is based on what
NREL refers to as the ``sugar platform,'' \63\ which refers to
pretreating the biomass, then hydrolyzing the cellulosic and hemicellulosic
components into sugars, and then fermenting the sugars into ethanol.
---------------------------------------------------------------------------
\63\ Enzyme Sugar Platform (ESP), Project Next Steps National
Renewable Energy, Dan Schell, FY03 Review Meeting; Laboratory
Operated for the U.S. Department of Energy by Midwest Research
Institute ? B NREL, Golden, Colorado, May 1-2, 2003; U.S.
Department of Energy by Midwest Research Institute ? Battelle
? Bechtel.
---------------------------------------------------------------------------
Corn grain is a nearly ideal feedstock for producing ethanol by
fermentation, especially when compared with cellulosic biomass
feedstocks. Corn grain is easily ground into small particles, following
which the exposed starch which has [alpha]-linked saccharide polymers
is easily hydrolyzed into
[[Page 23962]]
simple, single component sugar which can then be easily fermented into
ethanol. By comparison, the biomass lignin structure must be either
mechanically or chemically broken down to permit hydrolyzing chemicals
and enzymes access to the saccharide polymers. The central problem is
that the cellulose/hemicellulose saccharide polymers are [beta]-linked
which makes hydrolysis much more difficult. Simple microbial
fermentation used in corn sugar fermentation is also not possible,
since the cellulose and hemicellulose (6 & 5 carbon molecules,
respectively) have not been able to be fermented by the same microbe.
We discuss various pretreatment, hydrolysis and fermentation
technologies, below. The second and third approaches have nothing to do
with pretreatment, acids, enzymes, or fermentation. The second is
sometimes referred to as the ``syngas'' or ``gas-to-liquid'' approach;
we will call it the ``Syngas Platform.'' Briefly, the cellulosic
biomass feedstock is steam-reformed to produce syngas which is then
converted to ethanol over a Fischer-Tropsch catalyst. The third
approach uses plasma technology.
a. Sugar Platform
Plant cell walls are made up of cellulose and hemicellulose
polymers embedded in a lignin matrix. This complex structure prevents
both the first step, hydrolyzation of the cellulose and hemicellulose
polymers, and the second step, fermentation of the hydrolyzed sugars
into ethanol.
i. Pretreatment
Those who wish to use cellulosic biomass feedstocks to produce
ethanol face several, difficult problems. The lignin sheath, present in
all cellulosic materials, prevents, or at the very least, severely
restricts hydrolysis. To produce ethanol from cellulosic biomass
feedstocks by fermentation, some type of thermo-mechanical, mechanical,
chemical or a combination of these pretreatments is always necessary
before the cellulosic and hemicellulosic polymers can be hydrolyzed. In
effect, the lignin structure must be ``opened'' to allow efficient and
effective strong acid hydrolysis, weak acid hydrolysis, or weak acid
enzymatic hydrolysis of the cellulose/hemicellulose to their glucose
and xylose sugar components. Over time, many pretreatment methods or
combinations of methods have been tried, some with more success than
others. Usually, intense physical pretreatments such as steam explosion
are required; grasses and forest thinnings usually need to be chipped,
prior to chemical or enzymatic hydrolysis. The most common chemical
pretreatments for cellulosic feedstocks are strong acid, dilute acid,
caustic, organic solvents, ammonia, sulfur dioxide, carbon dioxide or
other chemicals which make the biomass more accessible to the enzymes.
Following pretreatment, acidic (dilute and concentrated) and enzymatic
hydrolysis are the two process types commonly used to hydrolyze
cellulosic feedstocks before fermentation into ethanol.\64\
---------------------------------------------------------------------------
\64\ Appendix B, Overview of Cellulose-Ethanol Production
Technology; OREGON CELLULOSE-ETHANOL STUDY, An evaluation of the
potential for ethanol production in Oregon using cellulose-based
feedstocks; Prepared by: Angela Graf, Bryan & Bryan Inc., 5015 Red
Gulch, Cotopaxi, Colorado 81223; Tom Koehler, Celilo Group, 2208
S.W. First Ave, #320, Portland, Oregon 97204; For submission
to: The Oregon Office of Energy.
---------------------------------------------------------------------------
ii. Dilute Acid Hydrolysis
Dilute acid hydrolysis is the oldest technology for converting
cellulose biomass to ethanol. The dilute acid process uses a 1-percent
sulfuric acid in a continuous flow reactor at about 420 [deg]F;
reaction times are measured in seconds and minutes, which facilitates
continuous processing. The process involves two reactions with a sugar
conversion efficiency of about 50 percent. The process conditions at
which the cellulosic molecules are converted into sugar are also those
at which the sugar is almost immediately converted into other
chemicals, principally furfural. The rapid conversion to furfural
reduces the sugar yield, which along with other by-products inhibits
the fermentation process. One way to decrease sugar degradation is to
use a two-stage process which takes advantage of the fact that
hemicellulose (5-carbon) sugars degrade more rapidly than cellulose (6-
carbon) sugars. The first stage is conducted under mild process
conditions to recover the 5-carbon sugars, while the second stage is
conducted under harsher conditions to recover the 6-carbon sugars. Both
hydrolyzed solutions are then fermented to ethanol. Lime is used to
neutralize the residual acid before the fermentation stage. Regardless,
some sugar degrades to furfural, which naturally limits the net yield
of ethanol. The residual cellulose and lignin are used as boiler fuel
for electricity or steam production.\65\
---------------------------------------------------------------------------
\65\ Ibid.
---------------------------------------------------------------------------
iii. Concentrated acid hydrolysis
Concentrated acid hydrolysis uses a 70-percent sulfuric acid
solution, followed by water hydrolysis to convert the cellulose into
sugar. The process rapidly, and nearly completely, converts cellulose
to glucose (6-carbon) and hemicellulose to xylose (5-carbon) sugar,
with little degradation to furfural; the reaction times are typically
slower than those of the dilute acid process. The critical factors
needed to make this process economically viable are to optimize sugar
recovery and cost effectively recover the acid for recycling. The
concentrated acid process is somewhat more complicated and requires
more time, but it has the primary advantage of yielding up to about 90%
of both hemicellulosic and cellulosic sugars.\66\ In addition, a
significant advantage of the concentrated acid process is that it is
carried out at relatively low temperatures, about 212 [deg]F, and low
pressure, such that fiberglass reactors and piping can be used.
---------------------------------------------------------------------------
\66\ Ibid.
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iv. Enzymatic hydrolysis
Enzymatic hydrolysis is not necessarily a recent discovery. We
found reports of research conducted by a variety of companies and
government agencies going back to at least 1991. 67 68 69
The enzymatic hydrolysis of cellulose was reportedly discovered when a
fungus, trichoderma reesei, was identified which produced cellulase
enzymes that broke down cotton clothing and tents in the South Pacific
during World War II. Since then, generations of cellulases have been
developed through genetic modifications of the fungus strain. As in
acid hydrolysis, the hydrolyzing enzymes must have access to the
cellulose and hemicellulose in order to work efficiently. Although
enzymatic hydrolysis requires some kind of pretreatment, purely
physical pretreatments are typically not adequate. Furthermore, the
chemical method uses dilute sulfuric acid, which is poisonous to the
fermentation
[[Page 23963]]
microorganisms and must be detoxified. While original enzymatic
hydrolysis processes used separate hydrolysis and fermentation steps,
recent process improvements integrate saccharification and fermentation
by combining the cellulase enzymes and fermenting microbes in one
vessel. This results in a one-step process of sugar production and
fermentation, referred to as the simultaneous saccharification and
fermentation (SSF) process. One disadvantage is that the cellulase
enzyme and fermentation organism must operate under the same process
conditions, which could decrease the sugar and, ultimately, the ethanol
yields. An alternative to the SSF technology is the sequential
hydrolysis and fermentation (SHF) process. The separation of hydrolysis
and fermentation enables enzymes to operate at higher temperatures in
the hydrolysis step to increase sugar production and more moderate
temperatures in the fermentation step to optimize the conversion of
sugar into ethanol.
---------------------------------------------------------------------------
\67\ Technical and Economic Analysis Of An Enzymatic Hydrolysis
Based Ethanol Plant, Fuels and Chemicals Research and Engineering
Division, Solar Energy Research Institute, Golden CO, 80401, June
1991 ? DRAFT ? SERI Protected Proprietary Information
? Do Not Copy.
\68\ Biomass to Ethanol Process Evaluation, A report prepared
for National Renewable Energy Laboratory, December 1994; Chem
Systems Inc. 303 South Broadway, Tarrytown, New York, 10591.
\69\ Lignocellulosic Biomass to Ethanol Process Design and
Economics Utilizing Co-Current Dilute Acid Prehydrolysis and
Enzymatic Hydrolysis Current and Futuristic Scenarios, July 1999
? NREL/TP-580-26157; Robert Wooley, Mark Ruth, John Sheehan,
and Kelly Ibsen, Biotechnology Center for Fuels and Chemicals; Henry
Majdeski and Adrian Galvez, Delta-T Corporation; National Renewable
Energy Laboratory, 1617 Cole Boulevard, Golden, Colorado 80401-3393;
NREL is a U.S. Department of Energy Laboratory Operated by Midwest
Research Institute ? Battelle ? Bechtel; Contract No.
DE-AC36-98-GO10337.
---------------------------------------------------------------------------
Cost-effective cellulase enzymes must also be developed for this
technology to be completely successful.\70\ Several companies are using
variations of these technologies to develop processes for converting
cellulosic biomass into ethanol by way of fermentation. A few groups,
using recently developed genome modifying technology, have been able to
produce a variety of new or modified enzymes and microbes that show
promise for use in weak- or dilute-acid enzymatic-prehydrolysis.
Another problem with cellulosic feedstocks is, as previously described,
that the hydrolysis reactions produce both glucose, the six-carbon
sugar, and xylose, the five-carbon sugar (pentose sugar,
C5H10O5; sometimes called ``wood
sugar''). Early conversion technology required different microbes to
ferment each sugar. Recent research has developed better fermenting
organisms. Now, glucose and xylose can be co-fermented--hence, the
present-day terminology: Weak-acid enzymatic hydrolysis and co-fermentation.
---------------------------------------------------------------------------
\70\ Ibid.
---------------------------------------------------------------------------
b. Syngas Platform
The second platform for producing cellulosic ethanol is to convert
the biomass into a syngas which is then converted into ethanol. A
``generic'' syngas process is essentially a ``steam reformer,'' which
``gasifies'' biomass and other carbon based substances including
wastes, in a reduced-oxygen environment and reacts them with steam to
produce a synthesis gas or ``syngas'' consisting primarily of carbon
monoxide and hydrogen. The syngas is then passed over in a Fischer-
Tropsch catalyst to produce ethanol.
The biomass feedstock is dried to about 15% moisture content and
ground small enough to be efficiently burned and reacted in the
reformer. The reformer, an important upstream element of the process,
is essentially a common solid-fuel gasifier, which with some
modification and steam injection becomes what is sometimes referred to
as the ``primary reformer.''
When any fuel is completely burned, all of its potential energy is
released as heat which can be recovered for immediate use. In a common
gasification process, the partially burned fuel (wood or coal) releases
a small amount of heat, but leaves some uncombusted, gaseous products.
Ordinarily, the hot product gases are fed directly to a nearby boiler
or gas turbine, to do work; it has been reported that for a well-
designed system, the overall efficiency may approach that of a solid
fuel boiler. However, when steam is injected into the gasifier, it
reacts with the burning solid fuel to produce more gaseous product. The
primary reaction is between carbon and water which produces hydrogen
and carbon monoxide and an inorganic ash. The ash and heavy
hydrocarbon-tars are removed from the raw syngas before it is
compressed and passed over Fisher-Tropsch catalyst to produce ethanol.
Fisher-Tropsch technology has been used for many years in the chemical
and refining industries, most notably to produce gasoline and diesel
fuel from syngas produced by coal gasification. Whether the Fischer-
Tropsch reaction produces diesel or ethanol is primarily the result of
changes to process pressure, temperature and in some cases the use of
custom catalysts. In most cases, the Fischer-Tropsch process did not
produce pure ethanol in the first pass through the system. Rather, a
stream of mixed chemicals was produced, including gasoline, diesel, and
oxygenated hydrocarbons (alcohol).\71\
---------------------------------------------------------------------------
\71\ Gridley Ethanol Demonstration Project Utilizing Biomass
Gasification Technology: Pilot Plant Gasifier and Syngas Conversion
Testing, August 2002-June 2004; February 2005 ? NREL/SR-510-
37581; TSS Consultants, For the City of Gridley, California, 1617
Cole Boulevard, Golden, Colorado 80401-3393, 303-275-3000 ?
http://www.nrel.gov; Operated for the U.S. Department of Energy
Office of Energy Efficiency and Renewable Energy by Midwest Research
Institute ? Battelle Contract No. DE-AC36-99-GO10337.
---------------------------------------------------------------------------
c. Plasma Technology
The development of another technology, called plasma, is also
underway for creating a syngas from which ethanol is produced. A plasma
``reactor,'' generates an ionized gas (plasma) which serves as an
electrical conductor to transfer intense radiant energy to a biomass or
waste material. This intense energy is said to actually breakdown the
various materials in the biomass or waste into their atomic components.
Anything present in the feed-mass that doesn't gasify, is essentially
``vitrified.'' This vitrified stream is reportedly inert and can be
used as aggregate in paving materials. Following gasification, the
syngas is cooled, impurities are removed, and the gas is sent to
ethanol production as with the syngas platform described above.\72\
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\72\ Ethanol From Tires Via Plasma Converter Plus Fischer
Tropsch, March 15, 2006;
http://thefraserdomain.typepad.com/energy/2006/03/ethanol_from_ti.html.
---------------------------------------------------------------------------
d. Feedstock Optimization
Cellulosic biomass can come from a variety of sources. Because the
conversion of cellulosic biomass to ethanol has not yet been
commercially demonstrated, we cannot say at this time which feedstocks
are superior to others. A few of the many resources are: Post-sorted
municipal waste, rice and wheat straw,\73\ soft-woods, hardwood, switch
grass, and bagasse. Regardless, each feedstock requires a specific
combination of pretreatment methods and enzyme ``cocktails'' to
optimize the operation and maximize the ethanol yield. One of the many
challenges for the cellulose-ethanol industry is to find the best
feedstocks and then develop the most cost-effective ways for converting
them into ethanol.
---------------------------------------------------------------------------
\73\ Wheat Straw for Ethanol Production in Washington: A
Resource, Technical, and Economic Assessment, September 2001,
WSUCEEP2001084; Prepared by: James D. Kerstetter, Ph.D., John Kim
Lyons, Washington State University Cooperative Extension Energy
Program, 925 Plum Street, SE., P.O. Box 43165, Olympia, WA 98504-
3165; Prepared for: Washington State Office of Trade and Economic
Development.
---------------------------------------------------------------------------
3. Renewable Fuel Distribution System Capability
Ethanol and biodiesel blended fuels are currently not shipped by
petroleum product pipeline due to operational issues and additional
cost factors. Hence, a separate distribution system is needed for
ethanol and biodiesel up to the point where they are blended into
petroleum-based fuel as it is loaded into tank trucks for delivery to
retail and fleet operators. In cases where ethanol and biodiesel are
produced within 200 miles of a terminal, trucking is often the preferred
means of distribution. For longer shipping distances, the preferred
[[Page 23964]]
method of bringing renewable fuels to terminals is by rail and barge.
Modifications to the rail, barge, tank truck, and terminal
distribution systems will be needed to support the transport of the
anticipated increased volumes of renewable fuels. These modifications
include the addition of terminal blending systems for ethanol and
biodiesel, additional storage tanks at terminals, additional rail
delivery systems at terminals for ethanol and biodiesel, and additional
rail cars, barges, and tank trucks to distribute ethanol and biodiesel
to terminals. Terminal storage tanks for 100 percent biodiesel will
also need to be heated during cold months to prevent gelling. The most
comprehensive study of the infrastructure requirements for an expanded
fuel ethanol industry was conducted for the Department of Energy (DOE)
in 2002.\74\ The conclusions reached in that study indicate that the
changes needed to handle the anticipated increased volume of ethanol by
2012 will not represent a major obstacle to industry. While some
changes have taken place since this report was issued, including an
increased reliance on rail over marine transport, we continue to
believe that the rail and marine transportation industries can manage
the increased growth in demand in an orderly fashion. This belief is
supported by the demonstrated ability for the industry to handle the
rapid increases and redistribution of ethanol use across the country
over the last several years as MTBE was removed. The necessary facility
changes at terminals and at retail stations to dispense ethanol
containing fuels have been occurring at a record pace. Given that
future growth is expected to progress at a steadier pace and with
greater advance warning in response to economic drivers, we anticipate
that the distribution system will be able to respond appropriately. A
discussion of the costs associated making the changes discussed above
is contained in Section VII.B of today's preamble.
---------------------------------------------------------------------------
\74\ ``Infrastructure Requirements for an Expanded Fuel Ethanol
Industry,'' Downstream Alternatives Inc., January 15, 2002.
---------------------------------------------------------------------------
VII. Impacts on Cost of Renewable Fuels and Gasoline
This section examines the impact on fuel costs resulting from the
growth in renewable fuel use between a base year of 2004 and 2012. We
note that based on analyses conducted by the Energy Information
Administration (EIA), renewable fuels will be used in gasoline and
diesel fuel in excess of the RFS requirements. As such, the changes in
the use of renewable fuels and their related cost impacts are not
directly attributable to the RFS rule. Rather, our analysis assesses
the broader fuels impacts of the growth in renewable fuel use in the
context of corresponding changes to the makeup of gasoline. These fuel
impacts include the elimination of the reformulated gasoline (RFG)
oxygen standard which has resulted in the refiners ceasing to use the
gasoline blendstock methyl tertiary butyl ether (MTBE) and replacing it
with ethanol. Thus, in this analysis, we are assessing the impact on
the cost of gasoline and diesel fuel of increased use of renewable
fuels, the cost savings resulting from the phase out of MTBE and the
increased cost due to the other changes in fuel quality that result.
As discussed in Section II, we chose to analyze a range of
renewable fuel use. In the case of ethanol's use in gasoline, the lower
end of this range is based on the minimum renewable fuel volume
requirements in the Act, (the RFS case) and the higher end is based on
AEO 2006 (the EIA case). At both ends of this range, we assume that
biodiesel consumption will be the level estimated in AEO 2006. We
analyzed the projected fuel consumption scenario and associated program
costs in 2012, the year that the RFS is fully phased-in. The volumes of
renewable fuels consumed in 2012 at the two ends of the range are
summarized in Table II.A.1-1.
We have estimated an average corn ethanol production cost of $1.26
per gallon in 2012 (2004 dollars) for the RFS case and $1.32 per gallon
for the EIA case. For cellulosic ethanol, we estimate it will cost
approximately $1.65 in 2012 (2004 dollars) to produce a gallon of
ethanol using corn stover as a cellulosic feedstock. In this analysis,
however, we assume that the cellulosic requirement will be met by corn-
based ethanol produced by energy sourced from biomass (animal and other
waste materials as discussed in Section III.B of today's preamble) and
costing the same as corn based ethanol produced by conventional means.
We estimated production costs for soy-derived biodiesel of $2.06
per gallon in 2004 and $1.89 per gallon in 2012. For yellow grease
derived biodiesel, we estimate an average production cost of $1.19 per
gallon in 2004 and $1.11 in 2012.
For the proposed rule, we estimated the cost of increased use of
renewable fuel and other major cost impacts by developing our own cost
spreadsheet model. That analysis considered the production cost,
distribution cost as well as the cost for balancing the octane and RVP
caused by these fuel changes. That analysis, however, could not
properly balance octane and other gasoline qualities. For this final
rule, we have therefore used the services of Jacobs Consultancy to run
their refinery LP model to estimate the cost impacts of the RFS rule.
The results from the refinery LP model indicate that the impacts on
overall gasoline costs from the increased use of ethanol and the
corresponding changes to the other aspects of gasoline would be 0.49
cents per gallon for the RFS case. The EIA case would result in
increased total cost of 1.03 cents per gallon. The actual cost at the
fuel pump, however, will be decreased due to the effect of State and
Federal tax subsidies for ethanol. Taking this into consideration
results in ``at the pump'' decreased costs (cost savings) of -0.47
cents per gallon for the RFS case and ``at the pump'' decreased cost of
-0.83 cents per gallon for the EIA case. Section 7 of the RIA contains
more detail on the cost analysis used to develop these costs.
A. Renewable Fuel Production and Blending Costs
1. Ethanol Production Costs
a. Corn Ethanol
A significant amount of work has been done in the last decade on
surveying and modeling the costs involved in producing ethanol from
corn to serve business and investment purposes as well as to try to
educate energy policy decisions. Corn ethanol costs for our work were
estimated using a model developed by USDA in the 1990s that has been
continuously updated by USDA. The most current version was documented
in a peer-reviewed journal paper on cost modeling of the dry-grind corn
ethanol process, and it produces results that compare well with cost
information found in surveys of existing plants.75 76 We
made some minor modifications to the USDA model to allow scaling of the
plant size, to allow consideration of plant energy sources other than
natural gas, and to adjust for energy prices in 2012, the year of our
analysis.
---------------------------------------------------------------------------
\75\ Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B.,
Industrial Crops and Products 23 (2006) 288-296.
\76\ Shapouri, H., Gallagher, P., USDA's 2002 Ethanol Cost-of-
Production Survey (published July 2005).
---------------------------------------------------------------------------
The cost of ethanol production is most sensitive to the prices of
corn and the primary co-product, DDGS. Utilities, capital, and labor
expenses also have an impact, although to a lesser extent. Corn
feedstock minus DDGS sale credits
[[Page 23965]]
represents about 48% of the final per-gallon cost, while utilities,
capital and labor comprise about 19%, 9%, and 6%, respectively. For
this work, we used corn prices of $2.50/bu and $2.71/bu for the RFS and
EIA cases, respectively, with corresponding DDGS prices at $83.35/ton
and $85.16/ton (2004 dollars). These estimates are from modeling work
done for this rulemaking using the Forestry and Agricultural Sector
Optimization Model, which is described in more detail in Chapter 8 of
the RIA. Energy prices were derived from historical data and projected
to 2012 using EIA's AEO 2006. More details on how the ethanol
production cost estimates were made can be found in Chapter 7 of the RIA.
The estimated average corn ethanol production cost of $1.26 per
gallon in 2012 (2004 dollars) in the RFS case and $1.32 per gallon in
the EIA case represents the full cost to the plant operator, including
purchase of feedstocks, energy required for operations, capital
depreciation, labor, overhead, and denaturant, minus revenue from sale
of co-products. It assumes that 86% of new plants will use natural gas
as a thermal energy source, at a price of $6.16/MMBtu (2004
dollars).\77\ It does not account for any subsidies on production or
sale of ethanol. Note that the cost figure generated here is
independent of the market price of ethanol, which has been related
closely to the wholesale price of gasoline for the past decade.78 79
---------------------------------------------------------------------------
\77\ For more details on fuel sources and costs of production,
see RIA Chapter 1.2.2 and 7.1.1.2.
\78\ Whims, J., Sparks Companies, Inc. and Kansas State
University, ``Corn Based Ethanol Costs and Margins, Attachment 1''
(Published May 2002).
\79\ Piel, W.J., Tier & Associates, Inc., March 9, 2006 report
on costs of ethanol production and alternatives.
---------------------------------------------------------------------------
Under the Energy Act, starch-based ethanol can be counted as
cellulosic if at least 90% of the process energy is derived from
renewable feedstocks, which include plant cellulose, municipal solid
waste, and manure biogas.\80\ It is expected that the vast majority of
the 250 million gallons per year of cellulosic ethanol production
required by 2013 will be made using this provision. While we have been
unable to develop a detailed production cost estimate for corn ethanol
meeting cellulosic criteria, we assume that the costs will not be
significantly different from conventionally produced corn ethanol. We
believe this is reasonable because the costs of hauling, storing, and
processing this low or zero cost waste material in order to combust it
will be significant, thus making overall production costs at these
plants similar to gas-fired ethanol plants. As of the time of this
writing, we know of only a few operating plants of this type, and
expect the quantity of ethanol produced this way to remain a relatively
small fraction of the total ethanol demand. Thus, the sensitivity of
the overall analysis to this assumption is also very small.\81\ Based
on these factors, we have assigned starch ethanol made using this
cellulosic criteria the same cost as ethanol produced from corn using
conventional means.
---------------------------------------------------------------------------
\80\ Energy Policy Act of 2005, Section 1501 amending Clean Air
Act Section 211(o)(1)(A).
\81\ See Table VI.A.1-2 for more details on number of operating
ethanol plants and their fuel sources.
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b. Cellulosic Ethanol
In 1999, the National Renewable Energy Laboratory (NREL) published
a report outlining its work with the USDA to design a computer model of
a plant to produce ethanol from hard-wood chips.\82\ Although the model
was originally prepared for hardwood chips, it was meant to serve as a
modifiable-platform for ongoing research using cellulosic biomass as
feedstock to produce ethanol. Their long-term plan was that various
indices, costs, technologies, and other factors would be regularly updated.
---------------------------------------------------------------------------
\82\ Lignocellulosic Biomass to Ethanol Process Design and
Economics Utilizing Co-Current Dilute Acid Prehydrolysis and
Enzymatic Hydrolysis Current and Futuristic Scenarios, Robert
Wooley, Mark Ruth, John Sheehan, and Kelly Ibsen, Biotechnology
Center for Fuels and Chemicals, Henry Majdeski and Adrian Galvez,
Delta-T Corporation; National Renewable Energy Laboratory, Golden,
CO, July 1999, NREL/TP-580-26157.
---------------------------------------------------------------------------
NREL and USDA used a modified version of the model to compare the
cost of using corn-grain with the cost of using corn stover to produce
ethanol. We used the corn stover model from the second NREL/USDA study
for the analysis for this rule. Because there were no operating plants
that could potentially provide real world process design, construction,
and operating data for processing cellulosic ethanol, NREL had
considered modeling the plant based on assumptions associated with a
first-of-a-kind or pioneer plant. The literature indicates that such
models often underestimate actual costs since the high performance
assumed for pioneer process plants is generally unrealistic.
Instead, the NREL researchers assumed that the corn stover plant
was an Nth generation plant, e.g., not a pioneer plant or first-or-its
kind, built after the industry had been sufficiently established to
provide verified costs. The corn stover plant was normalized to the
corn kernel plant, e.g., placed on a similar basis.\83\ It is also
reasonable to expect that the cost of cellulosic ethanol would be
higher than corn ethanol because of the complexity of the cellulose
conversion process. Recently, process improvements and advancements in
corn production have considerably reduced the cost of producing corn
ethanol. We also believe it is realistic to assume that cellulose-
derived ethanol process improvements will be made and that one can
likewise reasonably expect that, as the industry matures, the cost of
producing ethanol from cellulose will also decrease.
---------------------------------------------------------------------------
\83\ Determining the Cost of Producing Ethanol from Corn Starch
and Lignocellulosic Feedstocks; A Joint Study Sponsored by: USDA and
USDOE, October 2000 ? NREL/TP-580-28893 ? Andrew
McAloon, Frank Taylor, Winnie Yee, USDA, Eastern Regional Research
Center Agricultural Research Service; Kelly Ibsen, Robert Wooley,
National Renewable Energy Laboratory, Biotechnology Center for Fuels
and Chemicals, 1617 Cole Boulevard, Golden, CO, 80401-3393; NREL is
a USDOE Operated by Midwest Research Institute ? Battelle
? Bechtel; Contract No. DE-AC36-99-GO10337.
---------------------------------------------------------------------------
We calculated fixed and variable operating costs using percentages
of direct labor and total installed capital costs. Following this
methodology, we estimate that producing a gallon of ethanol using corn
stover as a cellulosic feedstock would cost $1.65 in 2012 (2004 dollars).
2. Biodiesel Production Costs
We based our estimate for the cost to produce biodiesel on the use
of USDA's, NREL's and EIA's biodiesel computer models, along with
estimates from engineering vendors that design biodiesel plants.
Biodiesel fuel can be made from a wide variety of virgin vegetable oils
such as canola, corn oil, cottonseed, etc. though, the operating costs
(minus the costs of the feedstock oils) for these virgin vegetable oils
are similar to the costs based on using soy oil as a feedstock,
according to an analysis by NREL Biodiesel costs are therefore
determined based on the use of soy oil, since this is the most commonly
used virgin vegetable feedstock oil, and the use of recycled cooking
oil (yellow grease) as a feedstock. Production costs are based on the
process of continuous transesterification, which converts these
feedstock oils to esters, along with the ester finishing processes and
glycerol recovery. The models and vendors data are used to estimate the
capital, fixed and operating costs associated with the production of
biodiesel fuel, considering utility, labor, land and any other process
and operating requirements, along with the prices for
[[Page 23966]]
feedstock oils, methanol, chemicals and the byproduct glycerol.
The USDA, NREL and EIA models are based on a medium sized biodiesel
plant that was designed to process raw degummed virgin soy oil as the
feedstock. Additionally, the EIA model also contains a representation
to estimate the biodiesel production cost for a plant that uses yellow
grease as a feedstock. In the USDA model, the equipment needs and
operating requirements for their biodiesel plant was estimated through
the use of process simulation software. This software determines the
biodiesel process requirements based on the use of established
engineering relationships, process operating conditions and reagent
needs. To substantiate the validity and accuracy of their model, USDA
solicited feedback from major biodiesel producers. Based on responses,
they then made adjustments to their model and updated their input
prices to year 2005. The NREL model is also based on process simulation
software, though the results are adjusted to reflect NREL's modeling
methods, using prices based on year 2002. The output for all of these
models was provided in spreadsheet format. We also use engineering
vendor estimates as another source to generate soy oil and yellow
grease biodiesel production costs. These firms are primarily engaged in
the business of designing biodiesel plants.
The production costs are based on an average biodiesel plant
located in the Midwest using feedstock oils and methanol, which are
catalyzed into esters and glycerol by use of sodium hydroxide. Because
local feedstock costs, distribution costs, and biodiesel plant type
introduce some variability into cost estimates, we believe that using
an average plant to estimate production costs provides a reasonable
approach. Therefore, we simplified our analysis and used costs based on
an average plant and average feedstock prices since the total biodiesel
volumes forecasted are not large and represent a small fraction of the
total projected renewable volumes.
The models and vendor estimates are further modified to use input
prices for feedstocks, byproducts and energy that reflect the effects
of the fuels provisions in the Energy Act. In order to capture a range
of production costs, we generated cost projections from all of the
models and vendors. We present the details on these estimates in
Chapter 7 of the RIA.
For soy oil biodiesel production, we estimate a production cost
ranging from $1.89 to $2.15 per gallon in 2012 (in 2004 dollars) using
these different models and sources of information. For yellow grease
derived biodiesel, we used the EIA and vendor estimates to generate
total production costs which range from $1.11 to $1.56 for year 2012.
With the current Biodiesel Blender Tax Credit Program, producers
using virgin vegetable oil stocks receive a one dollar per gallon tax
subsidy while yellow grease producers receive 50 cents per gallon,
reducing the net production cost to a range of 89 to 115 cents per
gallon for soy oil and 61 to 106 cents per gallon for yellow greased
derived biodiesel fuel in 2012. This compares favorably to the
projected wholesale diesel fuel prices of 138 cents per gallon in 2012,
signifying that the economics for biodiesel are positive under the
effects of the blender credit program, though the tax credit program
will expire in 2008 if it is not extended. Congress may later elect to
extend the blender credit program following the precedence used for
extending the ethanol blending subsidies. Additionally, the Small
Biodiesel Blenders Tax credit program and state tax and credit programs
offer some additional subsidies and credits, though the benefits are
modest in comparison to the Blender's Tax credit.
3. Diesel Fuel Costs
Biodiesel fuel is blended into highway and nonroad diesel fuel,
which increases the volume and therefore the supply of diesel fuel and
thereby reduces the demand for refinery-produced diesel fuel. In this
section, we estimate the overall cost impact, considering how much
refinery based diesel fuel is displaced by the forecasted production
volume of biodiesel fuel. The cost impacts are evaluated considering
the production cost of biodiesel with and without the subsidy from the
Biodiesel Blenders Tax credit program. Additionally, the diesel cost
impacts are quantified with refinery diesel prices as forecasted by
Jacob's which is based on EIA's AEO 2006.
We estimate the net effect that biodiesel production has on overall
cost for diesel fuel in year 2012 using total production costs for
biodiesel and diesel fuel. The costs are evaluated based on how much
refinery based diesel fuel is displaced by the biodiesel volumes as
forecasted by EIA, accounting for energy density differences between
the fuels. The cost impact is estimated from a 2004 year basis, by
multiplying the production costs of each fuel by the respective changes
in volumes for biodiesel and estimated displaced diesel fuel. We
further assume that all of the forecasted biodiesel volume is used as
transport fuel, neglecting minor uses in the heating oil market.
For RFS cases, the net effect of biodiesel production on diesel
fuel costs, including the biodiesel blenders' subsidy, is a reduction
in the cost of transport diesel fuel costs by $114 million per year,
which equates to a reduction in fuel cost of about 0.20 cents per
gallon.\84\ Without the subsidy, the transport diesel fuel costs are
increased by $91 million per year, or an increase of 0.16 cents per
gallon for transport diesel fuel.
---------------------------------------------------------------------------
\84\ Based on EIA's AEO 2006, 58.9 billion gallons of highway
and off-road diesel fuel is projected to be consumed in 2012.
---------------------------------------------------------------------------
B. Distribution Costs
1. Ethanol Distribution Costs
There are two components to the costs associated with distributing
the volumes of ethanol necessary to meet the requirements of the
Renewable Fuels Standard (RFS): (1) The capital cost of making the
necessary upgrades to the fuel distribution infrastructure system, and
(2) the ongoing additional freight costs associated with shipping
ethanol to terminals. The most comprehensive study of the
infrastructure requirements for an expanded fuel ethanol industry was
conducted for the Department of Energy (DOE) in 2002.\85\ That study
provided the foundation for our estimates of the capital costs
associated with upgrading the distribution infrastructure system as
well as the freight costs to handle the increased volume of ethanol
needed to meet the requirements of the RFS in 2012. Distribution costs
are evaluated here for both the RFS case and for the EIA case. The 2012
reference case against which we are estimating the cost of distributing
the additional volume of ethanol needed to meet the requirements of the
RFS is 3.9 billion gallons.
---------------------------------------------------------------------------
\85\ Infrastructure Requirements for an Expanded Fuel Ethanol
Industry, Downstream Alternatives Inc., January 15, 2002.
---------------------------------------------------------------------------
a. Capital Costs To Upgrade Distribution System for Increased Ethanol Volume
The 2002 DOE study examined two cases regarding the use of
renewable fuels for estimating the capital costs for distributing
additional ethanol. The first assumed that 5.1 billion gal/yr of
ethanol would be used in 2010, and the second assumed that 10 billion
gal/yr of ethanol would be used in the 2015 timetable. We interpolated
between these two cases to provide the foundation for our estimate of
the capital costs to support the use of 6.7 billion gal/yr of ethanol
in 2012 for the
[[Page 23967]]
RFS case.\86\ The 10 billion gal/yr case examined in the DOE study was
used as the foundation in estimating the capital costs under the EIA
projected case examined in today's rule of 9.6 billion gal/yr of
ethanol.\87\ Our estimated capital costs in this final rule differ from
those in the proposed rule for several reasons. We adjusted our capital
costs from those in the proposal to reflect an increase in the cost of
tank cars and barges used to ship ethanol since the DOE study was
conducted. In addition, we are assuming an increased reliance on rail
transport over that projected in the DOE study.\88\
---------------------------------------------------------------------------
\86\ See chapter 7.3 of the Regulatory Impact Analysis
associated with today's rule for additional discussion of how the
results of the DAI study were adjusted to reflect current conditions
in estimating the ethanol distribution infrastructure capital costs
under today's rule.
\87\ For both the 6.7 bill gal/yr and 9.6 bill gal/yr cases, the
baseline from which the DOE study cases were projected was adjusted
to reflect a 3.9 bill gal/yr 2012 baseline.
\88\ This increased reliance on rail transport was the subject
of a sensitivity analysis conducted for the proposed rule.
---------------------------------------------------------------------------
Table VII.B.1.a-1contains our estimates of the infrastructure
changes and associated capital costs for the two ethanol use scenarios
examined in today's rule. Amortized over 15 years with a 7 percent cost
of capital, the total capital costs equate to approximately 1.4 cents
per gallon of ethanol under the RFS case and 1.2 cents per gallon under
the EIA case.\89\
---------------------------------------------------------------------------
\89\ These capital costs will be incurred incrementally during
the period of 2007-2012 as ethanol volumes increase. For the purpose
of this analysis, we assumed that all capital costs were incurred in 2007.
Table VII.B.1.A-1.--Estimated Ethanol Distribution Infrastructure
Capital Costs ($M) *
------------------------------------------------------------------------
RFS case EIA case
6.7 Bgal/yr 9.6 Bgal/yr
------------------------------------------------------------------------
Fixed Facilities:
Retail...................................... 20 44
Terminals................................... 115 241
Mobile Facilities:
Transport Trucks............................ 24 50
Barges...................................... 21 43
Rail Cars................................... 172 297
-------------------------
Total Capital Costs....................... 352 675
------------------------------------------------------------------------
* Relative to a 3.9 billion gal/yr reference case.
b. Ethanol Freight Costs
The Energy Information Administration (EIA) translated the ethanol
freight cost estimates in the DOE study to a census division basis.\90\
For this final rule, we translated the EIA projections into State-by-
State and national average freight costs to align with our State-by-
State ethanol use estimates. Not including capital recovery, we
estimate that the freight cost to transport ethanol to terminals would
range from 4 cents per gallon in the Midwest to 25 cents per gallon to
the West Coast. On a national basis, this averages to 11.3 cents per
gallon of ethanol under the RFS case and 11.9 cents per gallon under
the EIA case.\91\ We adjusted the estimated ethanol freight costs from
those in the proposal by increasing the cost of shipping ethanol to
satellite versus hub terminals, by increasing the cost of gathering
ethanol for large volume shipments to hub terminals, and by increasing
the percentage of ethanol delivered to large volume terminals versus
the volume delivered to lesser volume terminals.\92\
---------------------------------------------------------------------------
\90\ Petroleum Market Model of the National Energy Modeling
System, Part 2, March 2006, DOE/EIA-059 (2006),
http://tonto.eia.doe.gov/FTPROOT/modeldoc/m059(2006)-2.pdf.
\91\ See Chapter 7.3 of the RIA.
\92\ Hub terminals refer to those terminals where ethanol is
delivered in large volume shipments such as by unit train
(consisting of 70 tank cars or more) or marine barges/tanker.
Satellite terminals are those terminals that are either supplied
from a hub terminal or receive ethanol shipments in smaller
quantities directly from the producer. See Chapter 7 of the RIA
regarding how these estimates were adjusted from those in the proposal
and the check of our estimates against current ethanol freight rates.
---------------------------------------------------------------------------
Including the cost of capital recovery for the necessary
distribution facility changes, we estimate the national average cost of
distributing ethanol to be 12.7 cents per gallon under the RFS case and
13.1 cents per gallon under the EIA case.\93\ Thus, we estimate the
total cost for producing and distributing ethanol to be between $1.39
and $1.45 per gallon of ethanol, on a nationwide average basis. This
estimate includes both the capital costs to upgrade the distribution
system and freight costs.
---------------------------------------------------------------------------
\93\ All capital costs were assumed to be incurred in 2007 and
were amortized over 15 years at a 7 percent cost of capital.
---------------------------------------------------------------------------
2. Biodiesel Distribution Costs
The volume of biodiesel used by 2012 under the RFS is estimated at
300 million gallons per year. The 2012 baseline case against which we
are estimating the cost of distributing the additional volume of
biodiesel is 30 million gallons.\94\
---------------------------------------------------------------------------
\94\ 2004 baseline of 25 million gallons grown with diesel
demand to 2012.
---------------------------------------------------------------------------
The capital costs associated with distribution of biodiesel are
higher per gallon than those associated with the distribution of
ethanol due to the need for storage tanks, blending systems, barges,
tanker trucks and rail cars to be insulated and in many cases heated
during the winter months.\95\ In the proposal, we estimated that these
capital costs would be approximately $50,000,000. We adjusted our
estimate of these capital costs for this final rule based on additional
information regarding the cost to install necessary storage and
blending equipment at terminals and the need for additional rail tank
cars for biodiesel.\96\ As discussed in the RIA, we now estimate that
handling the increased biodiesel volume will require a total capital
cost investment of $145,500,000 which equates to about 6 cents per
gallon of new biodiesel volume.\97\
---------------------------------------------------------------------------
\95\ See Chapter 1.3 of the Regulatory Impact Analysis
associated with today's rule for a discussion of the special
handling requirements for biodiesel under cold conditions.
\96\ Biodiesel rail tank cars typically have a capacity of
25,500 gallons as opposed to 30,000 gallons for an ethanol tank car.
Thus, additional tank cars are needed to transport a given volume of
biodiesel relative to the same volume of ethanol.
\97\ Capital costs will be incurred incrementally over the
period of 2007-2012 as biodiesel volumes increase. For the purpose
of this analysis, all capital costs were assumed to be incurred in
2007 and were amortized over 15 years at a 7 percent cost of capital.
---------------------------------------------------------------------------
In the proposal, we estimated that the freight costs for ethanol
may adequately reflect those for biodiesel as well. In response to
comments, we sought additional information regarding the freight costs
for biodiesel. This information indicates that freight costs for
biodiesel are typically 30 percent higher than those for ethanol which
translates into an estimate of 15.5 cents per gallon for biodiesel
freight costs on a national average basis.\98\
---------------------------------------------------------------------------
\98\ The estimated ethanol freight costs were increased by 30
percent to arrive at the estimate of biodiesel freight costs.
---------------------------------------------------------------------------
Including the cost of capital recovery for the necessary
distribution facility changes, we estimate the cost of distributing
biodiesel to be 21.5 cents per gallon. Depending on whether the
feedstock is waste grease or virgin oil, we estimate the total cost for
producing and distributing biodiesel to be between $1.33 and $2.11 per
gallon of biodiesel, on a nationwide average basis.\99\ This estimate
includes both the capital costs to upgrade the distribution system and
freight costs, and the wide range reflects differences in different
types of production feedstocks.
---------------------------------------------------------------------------
\99\ See Section VII.A.2. of this preamble regarding biodiesel
production costs. We estimated 2012 production costs of $1.89 per
gal for soy-derived biodiesel and $1.11 per gal for yellow grease
derived biodiesel.
---------------------------------------------------------------------------
C. Estimated Costs to Gasoline
To estimate the cost of increased use of renewable fuels, the cost
savings from the phase out of MTBE and the production cost of alkylate,
we relied on
[[Page 23968]]
refinery modeling conducted by Jacob's Consultancy that established
baselines based on 2004 volumes, which were then used to project a
reference case and 2 control cases for 2012. The contractor developed a
five region, U.S. demand model in which specific regional clean product
demands are sold at hypothetical regional terminals.
1. Description of Cases Modeled
a. Base Case (2004)
The baseline case was established by modeling fuel volumes for
2004, with data on fuel properties provided to the contractor by EPA.
Fuel property data for this base case was built off of 2004 refinery
batch reports provided to EPA; however, the base case assumed sulfur
standards based on gasoline data in 2004, not with fully phased in Tier
2 gasoline standards at the 30 ppm level. In addition we assumed the
phase-in of 15 ppm sulfur standards for highway, nonroad, locomotive
and marine diesel fuel. The supply/demand balance for the U.S. was
based on gasoline volumes from EIA and the California Air Resources
Board (CARB). Our decision to use 2004 rather than 2005 as the baseline
year was because of the refinery upset conditions associated with the
Gulf Coast hurricanes in 2005.
b. Reference Case (2012)
The reference case was based on modeling the base case, using 2012
fuel prices, and scaling the 2004 fuel volumes to 2012 based on growth
in fuel demand. In addition, we scaled MTBE and ethanol upward, in
proportion to gasoline growth, and assumed the RFS program would not be
in effect. For example, if the PADD 1 gasoline pool MTBE oxygen was 0.5
wt% in 2004, the reference case assumed it should remain at 0.5 wt%.
Finally, we assumed the MSAT 1 standards would remain in place as would
the RFG oxygen mandate. We assumed the crude slate quality in 2012 is
the same as the baseline case.
c. Control Cases (2012)
Two control cases were run for 2012. The assumptions for each of
the control cases are summarized below
Control Case 1 (RFS case): 6.7 billion gallons/yr (BGY) of ethanol
in gasoline; it reflects the renewable fuel mandate. We have also
assumed that 0.3 billion gallons of biodiesel will be consumed as
reflected in Table II.A.1-1. In addition, it is assumed that no MTBE is
in gasoline, MSAT1 is in place, the psi waiver for conventional
gasoline containing 10 volume percent ethanol is in effect, the RFS is
in effect, and there is no RFG oxygenate mandate.
Control Case 2 (EIA case): Same as Control Case 1, except the
ethanol volume in gasoline is 9.6 BGY.
2. Overview of Cost Analysis Provided by the Contractor Refinery Model
The estimated cost of increased use of renewable fuels, the cost
savings from the phase out of MTBE and the cost of converting some of
the former MTBE feedstocks to produce alkylate, isooctane, and
isooctene is provided by the output of the refinery model. As described
in VII.C.1, the cost analysis was conducted by comparing the 2012
reference case with the two control cases which are assumed to take
place in 2012.
The major factors which impact the costs in the refinery model are
(1) blending in more ethanol, (2) adjusting the gasoline blending to
lower RVP, (3) removing the MTBE, (4) converting MTBE feedstocks to
other high quality replacement, and (5) adjusting for the change in
gasoline energy density. The first is the addition of ethanol to the
gasoline pool. The refinery model estimates the cost impact of
increasing the volume of ethanol in the reference case from 3.94
billion gallons to 6.67 and 9.60 billion gallons in the RFS and EIA
modeled cases, respectively. The estimated production prices for
ethanol for the RFS and EIA cases are provided above in Section VII.A.
We also show the results with the federal and state subsidies applied
to the production price of ethanol.
The addition of ethanol to wintertime gasoline, and to summertime
RFG, will cause an increase of approximately 1 psi in RVP which needs
to be offset to maintain constant RVP levels. One method that refiners
could choose to offset the increase in RVP is to reduce the butane
levels in their gasoline. To some extent, the modeling results showed
some occurrences of that, but it also did not report an overall
increase in butane sales as a result of the increased use of ethanol.
To convert the captive MTBE over to alkylate, after the rejection
of methanol, refiners will need to combine refinery-produced isobutane
with the isobutylene that was used as a feedstock for MTBE. The use of
the isobutane will reduce the RVP of the gasoline pool from which it
comes, helping to offset the RVP impacts of ethanol. Also, the
increased production of alkylate provides a low RVP gasoline blendstock
which offsets a portion of the cracked stocks produced by the fluidized
catalytic cracker unit. Other means that the refinery model used to
offset the high blending RVP of ethanol included purchasing gasoline
components with lower RVP, producing more poly gasoline which has low
RVP and selling more high-RVP naphtha to petrochemical sales.
3. Overall Impact on Fuel Cost
Based on the refinery modeling conducted for today's rule, we have
calculated the costs of these fuels changes that will occur for the RFS
and EIA cases. The costs are expressed two different ways. First, we
express the cost of the program without the ethanol consumption
subsidies in which the costs are based on the total accumulated cost of
each of the fuels changes. Second, we express the cost with the ethanol
consumption subsidies included since the subsidized portion of the
renewable fuels costs will not be represented to the consumer in its
fuels costs paid at the pump, but instead by being paid through the
state and federal tax revenues. In all cases, the capital costs are
amortized at 7 percent return on investment (ROI), and based on 2006
dollars.
a. Cost Without Ethanol Subsidies
Table VII.C.3.a-1 summarizes the costs without ethanol subsidies
for each of the two control cases, including the cost for each aspect
of the fuel changes, and the aggregated total and the per-gallon costs
for all the fuel changes.\100\ This estimate of costs reflects the
changes in gasoline that are occurring with the expanded use of
ethanol, including the corresponding removal of MTBE. These costs
include the labor, utility and other operating costs, fixed costs and
the capital costs for all the fuel changes expected. The per-gallon
costs are derived by dividing the total costs over all U.S. gasoline
projected to be consumed in 2012. We excluded federal and state ethanol
consumption subsidies which avoids the transfer payments caused by
these subsidies that would hide a portion of the program's costs.
---------------------------------------------------------------------------
\100\ EPA typically assesses social benefits and costs of a
rulemaking. However, this analysis is more limited in its scope by
examining the average cost of production of ethanol and gasoline
without accounting for the effects of farm subsidies that tend to
distort the market price of agricultural commodities.
[[Page 23969]]
Table VII.C.3.A-1.--Estimated Cost Without Ethanol Consumption Subsidies
[Million dollars and cents per gallon; 7% ROI and 2006 dollars]
----------------------------------------------------------------------------------------------------------------
RFS case 6.8 EIA case 9.6 EIA case 9.6
billion gals billion gals billion gals
incremental to incremental to incremental to
reference case reference case RFS case
----------------------------------------------------------------------------------------------------------------
Capital Costs ($MM)............................................. -5,878 -7,311 -1,433
Amortized Capital Costs ($MM/yr)................................ -647 -804 -158
Fixed Operating Cost ($MM/yr)................................... -178 -222 -43
Variable Operating Cost ($MM/yr)................................ -201 -491 -290
Fuel Economy Cost ($MM/yr)...................................... 1,848 3,255 1407
Total Cost ($MM/yr)......................................... 823 1739 915
Capital Costs (c/gal of gasoline)............................... -0.40 -0.49 -0.10
Fixed Operating Cost (c/gal of gasoline)........................ -0.11 -0.14 -0.03
Variable Operating Cost (c/gal of gasoline)..................... -0.12 -0.30 -0.18
Fuel Economy Cost (c/gal of gasoline)........................... 1.13 1.98 0.86
Total Cost Excluding Subsidies (c/gal of gasoline).......... 0.50 1.06 0.56
----------------------------------------------------------------------------------------------------------------
Our analysis shows that when considering all the costs associated
with these fuel changes resulting from the expanded use of subsidized
ethanol that these various possible gasoline use scenarios will
increase fuel costs by $820 million or $1,740 million in the year 2012
for the RFS and EIA cases, respectively. Expressed as per-gallon costs,
these fuel changes would increase fuel costs by 0.50 to 1.1 cents per
gallon of gasoline.
b. Gasoline Costs Including Ethanol Consumption Tax Subsidies
Table VII.C.3.b-1 expresses the total and per-gallon gasoline costs
for the two control scenarios with the federal and state ethanol
subsidies included. The federal tax subsidy is 51 cents per gallon for
each gallon of new ethanol blended into gasoline. The state tax
subsidies apply in 5 states and range from 1.6 to 29 cents per gallon.
The cost reduction to the fuel industry and consumers is estimated by
multiplying the subsidy times the volume of new ethanol estimated to be
used in the state. The per-gallon costs are derived by dividing the
total costs over all U.S. gasoline projected to be consumed in 2012.
Table VII.C.3.B-1.--Estimated Cost Including Ethanol Consumption Subsidies
[Million dollars and cents per gallon; 7% ROI and 2006 dollars]
----------------------------------------------------------------------------------------------------------------
RFS case 6.8 EIA case 9.6 EIA case 9.6
billion gals billion gals billion gals
incremental to incremental to incremental to
reference case reference case RFS case
----------------------------------------------------------------------------------------------------------------
Total Cost ($MM/yr)............................................. 823 1739 915
Federal Subsidy ($MM/yr)........................................ -1376 -2865 -1489
State Subsidies ($MM/yr)........................................ -5 -31 -26
Revised Total Cost ($MM/yr)................................. -558 -1158 -600
Per-Gallon Cost Excluding Subsidies (c/gal of gasoline)......... 0.50 1.06 0.56
Federal Subsidy (c/gal of gasoline)............................. -0.84 -1.74 -0.90
State Subsidies (c/gal of gasoline)............................. -0.003 -0.02 -0.02
Total Cost Including Subsidies (c/gal of gasoline).......... -0.34 -0.71 -0.37
----------------------------------------------------------------------------------------------------------------
The cost including subsidies better represents gasoline's
production cost as reflected to the fuel industry as a whole and to
consumers ``at the pump'' because the federal and state subsidies tend
to hide a portion of the actual costs. Our analysis estimates that the
fuel industry and consumers will see a 0.34 and 0.71 cent per gallon
decrease in the apparent cost of producing gasoline for the RFS and EIA
cases, respectively.
VIII. What Are the Impacts of Increased Ethanol Use on Emissions and
Air Quality?
In this section, we evaluate the impact of increased production and
use of renewable fuels on emissions and air quality in the U.S.,
particularly ethanol and biodiesel. In performing these analyses, we
compare the emissions which would have occurred in the future if fuel
quality had remained unchanged from pre-Act levels to those which will
be either required under the Energy Policy Act of 2005 (Energy Act or
the Act) or exist due to market forces.
This approach differs from that traditionally taken in EPA
regulatory impact analyses. Traditionally, we would have compared
future emissions with and without the requirement of the Energy Act.
However, as described in Section II, we expect that total renewable
fuel use in the U.S. in 2012 to exceed the Act's requirements even in
the absence of the RFS program. Thus, a traditional regulatory impact
analysis would have shown no impact on emissions or air quality. This
is because, strictly speaking, if the same volume and types of
renewable fuels are produced and used with and without the RFS program,
the RFS program has no impact on fuel quality and thus, no impact on
emissions or air quality. However, levels of renewable fuel use are
increasing dramatically relative to both today and the recent past,
with corresponding impacts on emissions and air quality. We believe
that it is appropriate to evaluate these changes here, regardless of
whether they are occurring due to economic forces or Energy Act
requirements.
In the process of estimating the impact of increased renewable fuel
use, we also include the impact of reduced use of MTBE in gasoline. It
is the
[[Page 23970]]
increased production and use of ethanol which is facilitating the
continued production of RFG which meets both commercial and EPA
regulatory specifications without the use of MTBE. Because of this
connection, we found it impractical to isolate the impact of increased
ethanol use from the removal of MTBE.
A. Effect of Renewable Fuel Use on Emissions
1. Emissions From Gasoline Fueled Motor Vehicles and Equipment
Several models of the impact of gasoline quality on motor vehicle
emissions have been developed since the early 1990's. We evaluated
these models and selected those which were based on the most
comprehensive set of emissions data and developed using the most
advanced statistical tools for this analysis. Still, as will be
described below, significant uncertainty exists as to the effect of
these gasoline components on emissions from both motor vehicle and
nonroad equipment, particularly from the latest vehicle and engine
models equipped with the most advanced emission controls. Pending
adequate funding, we plan to conduct significant vehicle and equipment
testing over the next several years to improve our estimates of the
impact of these additives and other gasoline properties on emissions.
We hope that the results from these test programs will be available for
reference in the future evaluations of the emission and air quality
impacts of U.S. fuel programs required by the Act.\101\
---------------------------------------------------------------------------
\101\ Subject to funding.
---------------------------------------------------------------------------
The remainder of this sub-section is divided into three parts. The
first evaluates the impact of increased ethanol use and decreased MTBE
use on gasoline quality. The second evaluates the impact of increased
ethanol use and decreased MTBE use on motor vehicle emissions. The
third evaluates the impact of increased ethanol use and decreased MTBE
use on nonroad equipment emissions.
a. Gasoline Fuel Quality
For the final rulemaking, we estimate the impact of increased
ethanol use and decreased MTBE use on gasoline quality using refinery
modeling conducted specifically for the RFS rulemaking.\102\ In
general, adding ethanol to gasoline reduces the aromatic content of
conventional gasoline and the mid- and high-distillation temperatures
(e.g., T50 and T90). RVP increases except in areas where ethanol blends
are not provided a 1.0 RVP waiver of the applicable RVP standards in
the summer. With the exception of RVP, adding MTBE directionally
produces the same impacts. Thus, the effect of removing MTBE results in
essentially the opposite impacts. Neither oxygenate is expected to
affect sulfur levels, as refiners control sulfur independently in order
to meet the Tier 2 sulfur standards.
---------------------------------------------------------------------------
\102\ Refinery modeling performed in support of the original RFG
rulemaking is also used to help separate the effects of the two oxygenates.
---------------------------------------------------------------------------
The impacts of oxygenate use are smaller with respect to RFG. This
is due to RFG's VOC and toxics emission performance specifications,
which limit the range of feasible fuel quality values. Thus, oxygenate
type or level does not consistently affect the RVP level and aromatic
and benzene contents of RFG.
Table VIII.A.1.a-1 shows the fuel quality of a typical summertime,
non-oxygenated conventional gasoline and how these qualities change
with the addition of 10 volume percent ethanol. Similarly, the table
shows the fuel quality of a typical MTBE RFG blend and how fuel quality
might change with either ethanol use or simply MTBE removal. All of
these fuels are based, in whole or in part, on projections made by
Jacobs in their recent refinery modeling performed for EPA and
therefore, represent improvements over the projections made for the
NPRM. Please see Chapter 2 of the RIA for a detailed description of the
methodologies used to determine the specific changes in projected fuel
quality. As discussed there, we use the Jacobs model projections of RFG
fuel quality directly in our emission modeling. For conventional
gasoline, we use the Jacobs modeling described in Section VII to
determine the change in fuel quality due to ethanol use and apply this
change to base fuel quality estimates contained in EPA's NMIM emission
inventory model. Sulfur is not shown in Table VIII.A.1.a-1, as it is
held constant at 30 ppm, which is the average Tier 2 sulfur standard
applicable to all gasoline sold in the U.S. in the timeframe of our
emission analyses.
Table VIII.A.1.A-1.--Typical Summertime Fuel Quality
----------------------------------------------------------------------------------------------------------------
Conventional gasoline Reformulated gasoline \a\
----------------------------------------------------------------
Fuel parameter Non-
Typical 9 Ethanol MTBE blend Ethanol oxygenated
RVP blend blend blend
----------------------------------------------------------------------------------------------------------------
RVP (psi)...................................... 8.7 9.7 7.0 7.0 7.0
T50............................................ 218 205 179 184 175
T90............................................ 332 329 303 335 309
E200........................................... 41 50 60 58 52
E300........................................... 82 82 89 82 88
Aromatics (vol%)............................... 32 27 20 20 20
Olefins (vol%)................................. 7.7 7.7 4 14 15
Oxygen (wt%)................................... 0 3.5 2.1 3.5 0
Benzene (vol%)................................. 1.0 1.0 0.74 0.70 0.72
----------------------------------------------------------------------------------------------------------------
\a\ MTBE blend--Reference Case PADD 1 South, Ethanol blend--RFS Case PADD 1 North, Non-oxy blend. -RFS Case PADD
1 South.
b. Emissions From Motor Vehicles
We use the EPA Predictive Models to estimate the impact of gasoline
fuel quality on exhaust VOC and NOX emissions from motor
vehicles. These models were developed in 2000, in support of EPA's
response to California's request for a waiver of the RFG oxygen
mandate. These models represent a significant update of the EPA Complex
Model. However, they are still based on emission data from Tier 0
vehicles (roughly equivalent to 1990 model year vehicles). We based our
estimates of the impact of fuel quality on CO emissions on the EPA
MOBILE6.2 model. We base our estimates of the impact of fuel quality
[[Page 23971]]
on exhaust toxic emissions (benzene, formaldehyde, acetaldehyde, and
1,3-butadiene) primarily on the MOBILE6.2 model, updated to reflect the
effect of fuel quality on exhaust VOC emissions per the EPA Predictive
Models. Very limited data are available on the effect of gasoline
quality on PM emissions. Therefore, the effect of increased ethanol use
on PM emissions can only be qualitatively discussed.
In responding to California's request for a waiver of the RFG
oxygen mandate in 2000, we found that both very limited and conflicting
data were available on the effect of fuel quality on exhaust emissions
from Tier 1 and later vehicles.\103\ Thus, we assumed at the time that
changes to gasoline quality would not affect VOC, CO and NOX
exhaust emissions from these vehicles.\104\ Very little additional data
have been collected since that time on which to modify this assumption.
Consequently, for our primary analysis for today's final rule we have
maintained the assumption that changes to gasoline do not affect
exhaust emissions from Tier 1 and later technology vehicles.
---------------------------------------------------------------------------
\103\ The one exception was the impact of sulfur on emissions
from these later vehicles, which is not an issue here due to the
fact that renewable fuel use is not expected to change sulfur levels
significantly.
\104\ An exception is that MOBILE6.2 applies the effect of
oxygenate on CO emissions to Tier 1 and later vehicles which are
expected to be high emitters based on their age and mileage.
---------------------------------------------------------------------------
For the NPRM, we evaluated one recent study by the Coordinating
Research Council (CRC) which assessed the impact of ethanol and two
other fuel properties on emissions from twelve 2000-2004 model year
vehicles (CRC study E-67). Based on comments received on the NPRM, we
evaluated four additional studies of the fuel-emission effects of
recent model year vehicles. The results of these test programs indicate
that emissions from these late model year vehicles are likely sensitive
to changes in fuel properties. However, both the size and direction of
the effects are not consistent between the various studies. More
testing is still needed before confident predictions of the effect of
fuel quality on emissions from these vehicles can be made.
In the NPRM, we developed two sets of assumptions regarding the
effect of fuel quality on emissions from Tier 1 and later vehicles to
reflect this uncertainty. A primary analysis assumed that exhaust
emissions from Tier 1 and later vehicles are not sensitive to fuel
quality. This is consistent with our analysis of California's request
for a waiver of the RFG oxygen mandate. A sensitivity analysis assumed
that the NMHC and NOX emissions from Tier 1 and later
vehicles were as sensitive to fuel quality as Tier 0 vehicles. Only one
effect of fuel quality on CO emissions was assumed, that contained in
EPA's MOBILE6.2 emission inventory model.
The five available studies of Tier 1 and later vehicles support
continuing this approach for exhaust NMHC and NOX emissions.
The assumptions supporting both our primary and sensitivity analyses
reasonably bracket the results of the five studies. However, we have
decided to perform a sensitivity analysis for CO emissions, as well. In
this case, we apply the fuel-emission effects from MOBILE6.2 for Tier 0
vehicles to Tier 1 and later vehicles. This is analogous to the
approach taken for exhaust NMHC and NOX emissions.
We base our estimates of fuel quality on non-exhaust VOC and
benzene emissions on the EPA MOBILE6.2 model. The one exception to this
is the effect of ethanol on permeation emissions through plastic fuel
tanks and elastomers used in fuel line connections. Recent testing has
shown that ethanol increases permeation emissions, both by permeating
itself and increasing the permeation of other gasoline components. This
effect was included in EPA's analysis of California's most recent
request for a waiver of the RFG oxygen requirement, but is not in
MOBILE6.2.\105\ Therefore, we have added the effect of ethanol on
permeation emissions to MOBILE6.2's estimate of non-exhaust VOC
emissions in assessing the impact of gasoline quality on these emissions.
---------------------------------------------------------------------------
\105\ For more information on California's request for a waiver
of the RFG oxygen mandate and the Decision Document for EPA's
response, see http://www.epa.gov/otaq/rfg_regs.htm#waiver.
---------------------------------------------------------------------------
No models are available which address the impact of gasoline
quality on PM emissions. Very limited data indicate that ethanol
blending might reduce exhaust PM emissions under very cold weather
conditions (e.g., -20 [deg]F to 0 [deg]F). Very limited testing at
warmer temperatures (e.g., 20 [deg]F to 75 [deg]F) shows no definite
trend in PM emissions with oxygen content. Thus, for now, no
quantitative estimates can be made regarding the effect of ethanol use
on direct PM emissions.
Table VIII.A.1.b-1 presents the average per vehicle (2012 fleet)
emission impacts of three types of RFG: Non-oxygenated, a typical MTBE
RFG as has been marketed in the Gulf Coast, and a typical ethanol RFG
which has been marketed in the Midwest.
Table VIII.A.1.B-1.--Effect of RFG on Per Mile Emissions From Tier 0 Vehicles Relative to a Typical 9psi RVP
Conventional Gasoline a
----------------------------------------------------------------------------------------------------------------
11 Volume 10 Volume
Pollutant Source Non-Oxy RFG percent percent
(percent) MTBE ethanol
----------------------------------------------------------------------------------------------------------------
Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC....................................... EPA Predictive Models........ -13.4 -15.3 -9.7
NOX....................................... -2.4 -1.7 7.3
CO........................................ MOBILE6.2.................... -22 -31 -36
Exhaust Benzene........................... EPA Predictive and Complex -21.2 -29.7 -38.9
Models.
Formaldehyde.............................. -5.9 19.4 2.3
Acetaldehyde.............................. -0.2 -9.5 173.7
1,3-Butadiene............................. 20.9 -29.2 6.1
----------------------------------------------------------------------------------------------------------------
Non-Exhaust Emissions
----------------------------------------------------------------------------------------------------------------
VOC....................................... MOBILE6.2 & CRC E-65......... -30 -30 -18
Benzene................................... MOBILE6.2 & Complex Models... -40 -43 -32
----------------------------------------------------------------------------------------------------------------
\a\ Average per vehicle effects for the 2012 fleet during summer conditions.
[[Page 23972]]
As can be seen, all three types of RFG produce significantly lower
emissions of VOC, CO and benzene than conventional gasoline. The impact
of ethanol RFG on non-exhaust VOC emissions is lower than the other two
types of RFG due to the impact of ethanol on permeation emissions. The
impact of RFG on emissions of NOX and the other air toxics
depends on the type of RFG blend. The most notable effect on toxic
emissions in percentage terms is the 173 percent increase in
acetaldehyde with the use of ethanol. However, as will be seen below,
base acetaldehyde emissions are low relative to the other toxics. While
not shown, the total mass emissions of the four toxic pollutants always
decreases, as benzene is by far the largest constituent.
It should be noted that these comparisons assume that all gasoline
blends meet EPA's Tier 2 gasoline sulfur standard of 30 ppm. Prior to
the Tier 2 program, RFG contained less sulfur than conventional
gasoline and reduced NOX emissions to a greater degree
compared to conventional gasoline.
Historically, no non-oxygenated RFG was sold, due to the
requirement that RFG contain at least 2.0 weight percent oxygen.
However, with the Energy Act's removal of this requirement, all three
types of RFG blends can be sold today. Increased use of ethanol in RFG
would therefore either replace MTBE RFG or non-oxygenated RFG. The
former has already occurred in many areas, as MTBE was essentially
removed from the U.S. gasoline market by the end of 2006. The impact of
using ethanol in RFG in lieu of MTBE or no oxygenate can be seen from
comparing the relative impacts of the various RFG blends shown in Table
VIII.A.1.b-1.
Blending RFG with ethanol instead of MTBE or no oxygenate will
increase VOC and NOX emissions and decrease CO emissions.
Exhaust benzene and formaldehyde emissions will decrease, but non-
exhaust benzene, acetaldehyde, and 1,3-butadiene emissions will
increase. All of these impacts are on a per vehicle basis and apply to
Tier 0 vehicles only. The overall impact of increased ethanol use on
total emissions of these various pollutants is described below.
Table VIII.A.1.b-2 presents the effect of blending either MTBE or
ethanol into conventional gasoline while matching octane.
Table VIII.A.1.B-2.--Effect of MTBE and Ethanol in Conventional Gasoline
on Tier 0 Vehicle Emissions Relative to a Typical Non-Oxygenated
Conventional Gasoline a
------------------------------------------------------------------------
11 Volume 10 Volume
Pollutant Source percent percent
MTBE ethanol \b\
------------------------------------------------------------------------
Exhaust VOC.................. EPA Predictive -9.2 -7.4
Models.
NOX.......................... -2.6 7.7
CO \c\....................... MOBILE6.2...... -6/-11 -11/-19
Exhaust Benzene.............. EPA Predictive -22.8 -24.9
and Complex
Models.
Formaldehyde................. +21.3 +6.7
Acetaldehyde................. +0.8 +156.8
1,3-Butadiene................ -3.7 -13.2
Non-Exhaust VOC.............. MOBILE6.2...... Zero +30
Non-Exhaust Benzene.......... MOBILE6.2 & -9.5 +15.8
Complex Models.
------------------------------------------------------------------------
a Average per vehicle effects for the 2012 fleet during summer conditions.
b Assumes a 1.0 psi RVP waiver for ethanol blends.
c The first figure shown applies to normal emitters; the second applies
to high emitters.
Use of either oxygenate reduces exhaust VOC and CO emissions, but
increases NOX emissions. The ethanol blend increases non-
exhaust VOC emissions due to the commonly granted 1.0 psi waiver of the
RVP standard, as well as increased permeation emissions. Both
oxygenated blends reduce exhaust benzene and 1,3-butadiene emissions.
As above, ethanol increases non-exhaust benzene and acetaldehyde
emissions. While small amounts of MTBE may have still been used in CG
in 2004, for our reference case we have assumed that all MTBE use was
in RFG. Therefore, we are not predicting any emissions impact related
to removing MTBE from conventional gasoline. Increased use of
conventional ethanol blends will be in lieu of non-oxygenated
conventional gasoline. Thus, the more relevant column in Table
VII.A.1.b-2 for our modeling is the last column, which shows the
emission impact of a 10 volume percent ethanol blend relative to non-
oxygenated gasoline.
The exhaust emission effects shown above for VOC and NOX
emissions only apply to Tier 0 vehicles in our primary analysis. For
example, MOBILE6.2 estimates that 34 of exhaust VOC emissions and 16 of
NOX emissions from gasoline vehicles in 2012 come from Tier
0 vehicles. In the sensitivity analysis, these effects are extended to
all gasoline vehicles. The effect of RVP and permeation on non-exhaust
VOC emissions is temperature dependent. The figures shown above are based
on the distribution of temperatures occurring across the U.S. in July.
We received several comments related to the effect of ethanol on
emissions from onroad vehicles. None of the comments led us to change
the basic approach taken to estimating the impact of changing fuel
quality described above. Several comments suggested that we expand our
discussion of the uncertainty in these fuel effects (as well as the
effects of fuel quality on emissions from nonroad equipment and diesels
described below). While such an expanded discussion might be generally
desirable, the lack of relevant emission data from late model vehicles
and equipment prevents this. We believe that we have adequately
described the uncertainty in the emission estimates presented below and
our plans to obtain more data in order to improve these estimates in
the near future.
c. Nonroad Equipment
To estimate the effect of gasoline quality on emissions from
nonroad equipment, we used EPA's NONROAD emission model. We used the
2005 version of this model, NONROAD2005, which includes the effect of
ethanol on permeation emissions from most nonroad equipment.
Only sulfur and oxygen content affect exhaust VOC, CO and
NOX emissions in NONROAD. Since sulfur level is assumed to
remain constant, the only difference in exhaust emissions between
conventional and reformulated gasoline is due to oxygen content. Table
VIII.A.1.c-1 shows the effect of adding
[[Page 23973]]
11 volume percent MTBE or 10 volume percent ethanol to non-oxygenated
gasoline on these emissions.
Table VIII.A.1.C-1.--Effect MTBE and Ethanol on Nonroad Exhaust Emissions Relative to a Typical Non-Oxygenated
Gasoline
----------------------------------------------------------------------------------------------------------------
4-Stroke engines 2-Stroke engines
---------------------------------------------------
Base fuel 11 Volume 10 Volume 11 Volume 10 Volume
percent percent percent percent
MTBE ethanol MTBE ethanol
----------------------------------------------------------------------------------------------------------------
Exhaust VOC................................................. -9 -16 -1 -2
Non-Exhaust VOC............................................. 0 26 0 26
CO.......................................................... -13 -22 -13 -23
NOX......................................................... +23 +40 +37 +65
----------------------------------------------------------------------------------------------------------------
As can be seen, higher oxygen content reduces exhaust VOC and CO
emissions significantly, but also increases NOX emissions.
However, NOX emissions from these engines tend to be fairly
low to start with, given the fact that these engines run much richer
than stoichiometric. Thus, a large percentage increase of a relative
low base value can be a relatively small increase in absolute terms.
Evaporative emissions from nonroad equipment are impacted by only
RVP, and permeation by ethanol content. Both the RVP increase due to
blending of ethanol and its permeation effect cause non-exhaust VOC
emissions to increase with the use of ethanol in nonroad equipment. The
26 percent effect represents the average impact across the U.S. in July
for both 2-stroke and 4-stroke equipment. We updated the NONROAD2005
hose permeation emission factors for small spark-ignition engines and
recreational marine watercraft to reflect the use of ethanol.
For nonroad toxics emissions, we base our estimates of the impact
of fuel quality on the fraction of exhaust VOC emissions represented by
each toxic on MOBILE6.2 (i.e., the same effects predicted for onroad
vehicles). The National Mobile Inventory Model (NMIM) contains
estimates of the fraction of VOC emissions represented by the various
air toxics based on oxygenate type (none, MTBE or ethanol). However,
estimates for nonroad gasoline engines running on different fuel types
are limited, making it difficult to accurately model the impacts of
changes in fuel quality. In the recent final rule addressing mobile air
toxic emissions, EPA replaced the toxic-related fuel effects contained
in NMIM with those from MOBILE6.2 for onroad vehicles.\106\ We follow
the same methodology here. Future testing could significantly alter
these emission impact estimates.
---------------------------------------------------------------------------
\106\ 71, Federal Register, 15804, March 29, 2006.
---------------------------------------------------------------------------
2. Diesel Fuel Quality: Biodiesel
EPA assessed the impact of biodiesel fuel on emissions in 2002 and
published a draft report summarizing the results.\107\ This report
included a technical analysis of biodiesel effects on regulated and
unregulated pollutants from diesel powered vehicles and concluded that
biodiesel fuels improved PM, HC and CO emissions of diesel engines
while slightly increasing their NOX emissions.
---------------------------------------------------------------------------
\107\ ``A Comprehensive Analysis of Biodiesel Impacts on Exhaust
Emissions,'' Draft Technical Report, U.S. EPA, EPA420-P-02-001,
October 2002. http://www.epa.gov/otaq/models/biodsl.htm.
---------------------------------------------------------------------------
While the conclusions reached in the 2002 EPA report relative to
biodiesel effects on VOC, CO and PM emissions have been generally
accepted, the magnitude of the B20 effect on NOX remains
controversial due to conflicting results from different studies.
Significant new testing is being planned with broad stakeholder
participation and support in order to better estimate the impact of
biodiesel on NOX and other exhaust emissions from the in-use
fleet of diesel engines. We hope to incorporate the data from such
additional testing into the analyses for other studies required by the
Energy Act in 2008 and 2009, and into a subsequent rule to set the RFS
program standard for 2013 and later.
3. Renewable Fuel Production and Distribution
Areas experiencing increased renewable production will experience
the corresponding emission increases associated with their production.
The primary impact of renewable fuel production and distribution
regards ethanol, since it is expected to be the predominant renewable
fuel used in the foreseeable future. We approximate the impact of
increased ethanol and biodiesel production, including corn and soy
farming, on emissions based on DOE's GREET model, version 1.7. In
addition, we develop a second estimate of emissions from ethanol
production facilities using estimates of emissions from current ethanol
plants obtained from the States. We also include emissions effects
resulting from the transport of increased volumes of renewable fuels
and decreased volumes of gasoline and diesel fuel. These emissions are
summarized in Table VIII.A.3-1.
Table VIII.A.3-1.--Well-to-Pump Emissions for Producing and Distributing Renewable Fuels
[Grams per gallon ethanol or biodiesel]
\a\
----------------------------------------------------------------------------------------------------------------
GREET1.7 GREET1.7 + state data
----------------------------------------------------
Pollutant Current Future Current Future Biodiesel--GREET1.7
ethanol ethanol ethanol ethanol
plants plants plants plants
----------------------------------------------------------------------------------------------------------------
VOC.................................... 1.8 1.8 3.6 3.2 37.6
CO..................................... 4.0 4.1 4.4 4.3 12.7
NOX.................................... 11.4 11.4 10.8 13.0 25.1
PM10................................... 4.9 4.9 6.1 2.8 4.8
[[Page 23974]]
SOX.................................... 6.4 6.4 7.2 9.7 21.8
----------------------------------------------------------------------------------------------------------------
\a\ Includes credit for reduced distribution of gasoline and diesel fuel.
At the same time, areas with refineries might experience reduced
emissions, not necessarily relative to current emission levels, but
relative to those which would have occurred in the future had renewable
fuel use not risen. However, to the degree that increased renewable
fuel use reduces imports of gasoline and diesel fuel, as opposed to the
domestic production of these fuels, these reduced refinery emissions
will occur overseas and not in the U.S.
Similarly, areas with MTBE production facilities might experience
reduced emissions from these plants as they cease producing MTBE.
However, many of these plants may be converted to produce other
gasoline blendstocks, such as iso-octane or alkylate. In this case,
their emissions are not likely to change substantially.
B. Impact on Emission Inventories
We use the NMIM to estimate emissions under the various ethanol
scenarios on a county by county basis. NMIM basically runs MOBILE6.2
and NONROAD2005 with county-specific inputs pertaining to fuel quality,
ambient conditions, levels of onroad vehicle VMT and nonroad equipment
usage, etc. We ran NMIM for two months, July and January. We estimate
annual emission inventories by summing the two monthly inventories and
multiplying by six.
As described above, we removed the effect of gasoline fuel quality
on exhaust VOC and NOX emissions from the onroad motor
vehicle inventories which are embedded in MOBILE6.2. We then applied
the exhaust emission effects from the EPA Predictive Models. In our
primary analysis, we only applied these EPA Predictive Model effects to
exhaust VOC and NOX emissions from Tier 0 vehicles. In a
sensitivity case, we applied them to exhaust VOC and NOX
emissions from all vehicles. Regarding the effect of fuel quality on
emissions of four air toxics from nonroad equipment (in terms of their
fraction of VOC emissions), in all cases we replaced the fuel effects
contained in NMIM with those for motor vehicles contained in MOBILE6.2.
The projected emission inventories for the primary analysis are
presented first, followed by those for the sensitivity analysis.
1. Primary Analysis
The national emission inventories for VOC, CO and NOX in
2012 with current fuels (i.e., ``reference fuel'') are summarized in
Table VIII.B.1-1. Also shown are the changes in emissions projected for
the two levels of ethanol use (i.e., ``control cases'') described in
Section VI.
Table VIII.B.1-1.--2012 Emissions Nationwide From Gasoline Vehicles and
Equipment Under Several Ethanol Use Scenarios--Primary Analysis
[Tons per year]
\108\
------------------------------------------------------------------------
Inventory Change in inventory in
------------- control cases
Pollutant Reference -------------------------
case RFS case EIA case
------------------------------------------------------------------------
VOC.............................. 5,882,000 18,000 43,000
NOX.............................. 2,487,000 23,000 40,000
CO............................... 55,022,000 -483,000 -1,366,000
Benzene.......................... 178,000 -3,200 -7,200
Formaldehyde..................... 40,400 -600 -200
Acetaldehyde..................... 19,900 3,400 7,100
1,3-Butadiene.................... 18,900 -200 -300
------------------------------------------------------------------------
Both VOC and NOX emissions are projected to increase
with increased use of ethanol. However, the increases are small,
generally less than 2 percent. CO emissions are projected to decrease
by about 0.9 to 2.5 percent. Benzene emissions are projected to
decrease by 1.8 to 4.0 percent. Formaldehyde emissions are projected to
decrease slightly, on the order of 0.5 to 1.5 percent. 1,3-butadiene
emissions are projected to decrease by about 1.1 to 1.6 percent. The
largest change is in acetaldehyde emissions, an increase of 17.1 to
35.7 percent, as acetaldehyde is a partial combustion product of ethanol.
---------------------------------------------------------------------------
\108\ These emission estimates do not include the impact of the
recent mobile source air toxic standards (72 FR 8428, February 26, 2007).
---------------------------------------------------------------------------
CO also participates in forming ozone, much like VOCs. Generally,
CO is 15-50 times less reactive than typical VOC. Still, the reduction
in CO emissions is roughly 27-32 times the increase in VOC emissions in
the two scenarios. Thus, the projected reduction in CO emissions is
important from an ozone perspective. However, as described above, the
methodology for projecting the effect of ethanol use on CO emissions is
inconsistent with that for exhaust VOC and NOX emissions.
Thus, comparisons between changes in VOC and CO emissions are
particularly uncertain.
There will also be some increases in emissions due to ethanol and
biodiesel production. Table VIII.B.1-2 shows estimates of annual
emissions expected to occur nationwide due to increased production of
ethanol. These estimates include a reduction in emissions related to
the distribution of the displaced gasoline. The table reflects the use of
[[Page 23975]]
emissions factors from DOE's GREET model, version 1.7, as well as
estimates of ethanol plant emissions obtained from the States. It
should be noted that emissions in the base case assume an 80/20 mix of
dry mill and wet mill facilities. New plants (and thus, the emission
increases) assume 100% dry mill facilities.
Table VIII.B.1-2.--Annual Emissions Nationwide From Ethanol Production and Transportation: 2012
[Tons per year]
----------------------------------------------------------------------------------------------------------------
GREET1.7 GREET1.7 + State data
-----------------------------------------------------------------------------
Base case RFS case EIA case Base case RFS case EIA case
----------------------------------------------------------------------------------------------------------------
Emissions Increase in emissions Emissions Increase in emissions
----------------------------------------------------------------------------------------------------------------
VOC............................... 8,000 5,000 11,000 14,000 10,000 20,000
NOX............................... 17,000 13,000 26,000 18,000 14,000 27,000
CO................................ 49,000 35,000 72,000 56,000 40,000 81,000
PM10.............................. 21,000 15,000 30,000 12,000 9,000 18,000
SOX............................... 27,000 20,000 41,000 42,000 30,000 61,000
----------------------------------------------------------------------------------------------------------------
As can be seen, the potential increases in emissions from ethanol
production and transportation are of the same order of magnitude as
those from ethanol use, with the exception of CO emissions. The vast
majority of these emissions are related to farming and ethanol
production. Both farms and ethanol plants are generally located in
ozone attainment areas.
Where counties are constructing new ethanol plants, expanding
existing plants, or planning construction for future plants, the
average increase in VOC and NOX emissions from plants alone
are about 26 tons/month VOC and 35 tons/month NOX using
state data (about 17 tons/month VOC and 25 tons/month NOX
using GREET 1.7 emission factors). Average VOC and NOX
emissions increase to about 61 tons/month and 83 tons/month,
respectively, in the 10% of counties expecting largest increases in
ethanol production. For both VOC and NOX, emissions
estimates are about 35% less when using the GREET 1.7 emission factors.
Table VIII.B.1-3 shows estimates of annual emissions expected to
occur nationwide due to increased production of biodiesel. These
estimates include a reduction in emissions related to the distribution
of the displaced diesel fuel. Again, these emissions are generally
expected to be in ozone attainment areas.
Table VIII.B.1-3.--Annual Emissions Nationwide From Biodiesel Production
and Transportation
[Tons per year]
------------------------------------------------------------------------
2012
Reference Emissions
inventory: inventory:
Pollutant 30 mill gal 300 mill
biodiesel gal
per year biodiesel
per year
------------------------------------------------------------------------
VOC........................................... 1,400 14,000
NOX........................................... 1,500 15,000
CO............................................ 800 8,000
PM10.......................................... 50 500
SOX........................................... 250 2,500
------------------------------------------------------------------------
2. Sensitivity Analysis
The national emission inventories for VOC and NOX in
2012 with current fuels are summarized in Table VIII.B.2-1. Here, the
emission effects contained in the EPA Predictive Models are assumed to
apply to all vehicles, not just Tier 0 vehicles. Also shown are the
changes in emissions projected for the two cases for future ethanol volume.
Table VIII.B.2-1.--2012 Emissions Nationwide From Gasoline Vehicles and
Equipment Under Two Future Ethanol Use Scenarios--Sensitivity Analysis
[Tons per year]
------------------------------------------------------------------------
Inventory Change in inventory in
------------- control cases
Pollutant Reference -------------------------
case RFS case EIA case
------------------------------------------------------------------------
VOC.............................. 5,834,000 -20,000 -4,000
NOX.............................. 2,519,000 68,000 106,000
CO............................... 54,315,000 -692,000 -1,975,000
Benzene.......................... 175,700 -5,000 -9,400
Formaldehyde..................... 39,600 -1,100 -700
Acetaldehyde..................... 19,500 3,000 6,600
1,3-Butadiene.................... 18,600 -400 -600
------------------------------------------------------------------------
The overall VOC and NOX emission impacts of the various
ethanol use scenarios change to some degree when all motor vehicles are
assumed to be sensitive to fuel ethanol content. The increase in VOC
emissions turns into a net decrease due to a greater reduction in
exhaust VOC emissions from onroad vehicles. However, the increase in
NOX emissions gets larger, as more vehicles are assumed to
be affected by ethanol. Emissions of the four air toxics generally
decrease slightly, due to the greater reduction in exhaust VOC emissions.
[[Page 23976]]
3. Local and Regional VOC and NOX Emission Impacts in July
We also estimate the percentage change in VOC, NOX, and
CO emissions from gasoline fueled motor vehicles and equipment in those
areas which actually experienced a significant change in ethanol use.
Specifically, we focused on areas where the market share of ethanol
blends was projected to change by 50 percent or more. We also focused
on summertime emissions, as these are most relevant to ozone formation.
Finally, we developed separately estimates for: (1) RFG areas,
including the state of California and the portions of Arizona where
their CBG fuel programs apply, (2) low RVP areas (i.e., RVP standards
less than 9.0 RVP, and (3) areas with a 9.0 RVP standard. This set of
groupings helps to highlight the emissions impact of increased ethanol
use in those areas where emission control is most important.
Table VIII.B.3-1 presents our primary estimates of the percentage
change in VOC, NOX, and CO emission inventories for these
three types of areas. Note that the analyses here are very similar to
those described in Section 5.1 of the RIA, with the exception that
Table VIII.B.3-1 below reflects 50 states (instead of 37 eastern
states) and excludes diesel emissions.
Table VIII.B.3-1.--July 2015 Change in Emissions from Gasoline Vehicles
and Equipment in Counties Where Ethanol Use Changed Significantly--
Primary Analysis
------------------------------------------------------------------------
Ethanol use RFS case EIA case
------------------------------------------------------------------------
RFG Areas
------------------------------------------------------------------------
Ethanol Use..................... Down.............. Up.
VOC............................. 0.8%.............. 2.3%.
NOX............................. -3.4%............. 1.6%.
CO.............................. 6.1%.............. -2.6%.
------------------------------------------------------------------------
Low RVP Areas
------------------------------------------------------------------------
Ethanol Use..................... Up................ Up.
VOC............................. 4.2%.............. 4.6%.
NOX............................. 6.2%.............. 5.7%.
CO.............................. -12.5%............ -13.7%.
------------------------------------------------------------------------
Other Areas (9.0 RVP)
------------------------------------------------------------------------
Ethanol Use..................... Up................ Up.
VOC............................. 3.6%.............. 4.6%.
NOX............................. 7.3%.............. 7.0%.
CO.............................. -6.4%............. -6.0%.
------------------------------------------------------------------------
As expected, increased ethanol use tends to increase NOX
emissions. The increase in low RVP and other areas is greater than in
RFG areas, since the RFG in the RFG areas included in this analysis all
contained MTBE. Also, increased ethanol use tends to increase VOC
emissions, indicating that the increase in non-exhaust VOC emissions
exceeds the reduction in exhaust VOC emissions. This effect is muted
with RFG due to the absence of an RVP waiver for ethanol blends. We
would expect very similar results for 2012. The reader is referred to
Chapter 2 of the RIA for discussion of how ethanol levels will change
at the state-level.
Table VIII.B.3-2 presents the percentage change in VOC,
NOX, and CO emission inventories under our sensitivity case
(i.e., when we apply the emission effects of the EPA Predictive Models
to all motor vehicles).
Table VIII.B.3-2.--July 2015 Change in Emissions From Gasoline Vehicles
and Equipment in Counties Where Ethanol Use Changed Significantly--
Sensitivity Analysis
------------------------------------------------------------------------
Ethanol use RFS case EIA case
------------------------------------------------------------------------
RFG Areas
------------------------------------------------------------------------
Ethanol Use..................... Down.............. Up.
VOC............................. -1.0%............. 1.0%.
NOX............................. -0.9%............. 5.6%.
CO.............................. 7.3%.............. -3.0%.
------------------------------------------------------------------------
Low RVP Areas
------------------------------------------------------------------------
Ethanol Use..................... Up................ Up.
VOC............................. 3.4%.............. 3.7%.
NOX............................. 10.4%............. 10.8%.
CO.............................. -15.0%............ -16.4%.
------------------------------------------------------------------------
Other Areas (9.0 RVP)
------------------------------------------------------------------------
Ethanol Use..................... Up................ Up.
VOC............................. 3.0%.............. 3.9%.
NOX............................. 10.8%............. 11.0%.
[[Page 23977]]
CO.............................. -9.0%............. -8.9%.
------------------------------------------------------------------------
Directionally, the changes in VOC and NOX emissions in
the various areas are consistent with those from our primary analysis.
The main difference is that the increases in VOC emissions are smaller,
due to more vehicles experiencing a reduction in exhaust VOC emissions,
and the increases in NOX emissions are larger.
C. Impact on Air Quality
We estimate the impact of increased ethanol use on the ambient
concentrations of two pollutants: Ozone and PM. Quantitative estimates
are made for ozone, while only qualitative estimates can be made
currently for ambient PM. These impacts are described below.
1. Impact of Increased Ethanol Use on Ozone
We use a metamodeling tool developed at EPA, the ozone response
surface metamodel (Ozone RSM), to estimate the effects of the projected
changes in emissions from gasoline vehicles and equipment for the RFS
and EIA cases. We included the estimated changes in emissions from
renewable fuel production and distribution. Because of limitations in
the Ozone RSM, we could not easily assign these emissions to the
specific counties where the plants are or are expected to be located.
Instead, we assigned all of the emissions related to renewable fuel
production and distribution to the set of states expected to contain
most of the production facilities.
The Ozone RSM was created using multiple runs of the Comprehensive
Air Quality Model with Extensions (CAMX). Base and proposed
control CAMX metamodeling was completed for the year 2015
over a modeling domain that includes all or part of 37 Eastern U.S.
states, plus the District of Columbia. For more information on the
Ozone RSM, please see Chapter 5 of the RIA for this final rule.
The Ozone RSM limits the number of geographically distinct changes
in VOC and NOX emissions which can be simulated. As a
result, we could not apply distinct changes in emissions for each
county. Therefore, two separate runs were made with different VOC and
NOX emissions reductions. We then selected the ozone impacts
from the various runs which best matched the VOC and NOX
emission reductions for that county. This models the impact of local
emissions reasonably well, but loses some accuracy with respect to
ozone transport. No ozone impact was assumed for areas which did not
experience a significant change in ethanol use. The predicted ozone
impacts of increased ethanol use for those areas where ethanol use is
projected to change by more than a 50% market share are summarized in
Table VIII.C.1-1. As shown in the Table 5.1-2 of the RIA, national
average impacts (based on the 37-state area modeled) which include
those areas where no change in ethanol use is occurring are
considerably smaller.
Table VIII.C.1-1.--Impact on 8-Hour Design Value Equivalent Ozone Levels (ppb) a
----------------------------------------------------------------------------------------------------------------
Primary analysis Sensitivity analysis
---------------------------------------------------
RFS case EIA case RFS case EIA case
----------------------------------------------------------------------------------------------------------------
Minimum Change.............................................. -0.015 0.000 -0.115 0.028
Maximum Change.............................................. 0.329 0.337 0.624 0.549
Average Change \b\.......................................... 0.153 0.181 0.300 0.325
Population-Weighted Change \b\.............................. 0.154 0.183 0.272 0.315
----------------------------------------------------------------------------------------------------------------
\a\ In comparison to the 80 ppb 8-hour ozone standards.
\b\ Only for those areas experiencing a change in ethanol blend market share of at least 50 percent.
As can be seen, ozone levels generally increase to a small degree
with increased ethanol use. This is likely due to the projected
increases in both VOC and NOX emissions. Some areas do see a
small decrease in ozone levels. In our primary analysis, where exhaust
emissions from Tier 1 and later onroad vehicles are assumed to be
unaffected by ethanol use, the population-weighted increase in ambient
ozone levels in those areas where ethanol use changed significantly is
0.154-0.183 ppb. Since the 8-hour ambient ozone standard is 85 ppb,
this increase represents about 0.2 percent of the standard, a very
small percentage.
In our sensitivity analysis, where exhaust emissions from Tier 1
and later onroad vehicles are assumed to respond to ethanol like Tier 0
vehicles, the population-weighted increase in ambient ozone levels is
slightly less than twice as high, or 0.272-0.315 ppb. This increase
represents about 0.35 percent of the standard.
There are a number of important caveats concerning these estimates.
First, the emission effects of adding ethanol to gasoline are based on
extremely limited data for recent vehicles and equipment. Second, the
Ozone RSM does not account for changes in CO emissions. As shown above,
ethanol use should reduce CO emissions significantly, directionally
reducing ambient ozone levels in those areas where ozone formation is
VOC-limited. (Ozone levels in areas which are NOX-limited
are less likely to be affected by a change in CO emissions.) The Ozone
RSM also does not account for changes in VOC reactivity. With
additional ethanol use, the ethanol content of VOC should increase.
Ethanol is less reactive than the average VOC. Therefore, this change
should also reduce ambient ozone levels in a way not addressed by the
Ozone RSM, again in those areas where ozone formation is predominantly
VOC-limited. Because of these limitations, anyone interested in the
impact of increased ethanol use on ozone in any particular area should
utilize more comprehensive dispersion modeling which accounts for these
and other important factors.
We received several requests in comments on the proposal to
quantify the impact of the reduced CO emissions
[[Page 23978]]
and VOC reactivity on ozone. As discussed in the S&A document, this is
not possible without running more sophisticated ambient dispersion
models. The impact of CO emissions and VOC reactivity on ozone vary
significantly depending on ambient conditions and the relative amount
of VOC and NOX in the atmosphere. Therefore, general rules
of thumb cannot be applied.
Moving to health effects, exposure to ozone has been linked to lung
function decrements, respiratory symptoms, aggravation of asthma,
increased hospital and emergency room visits, increased asthma
medication usage, inflammation of the lungs, and a variety of other
respiratory effects and cardiovascular effects including premature
mortality. Ozone can also adversely affect the agricultural and
forestry sectors by decreasing yields of crops and forests. Although
the health and welfare impacts of changes in ambient ozone levels are
typically quantified in regulatory impact analyses, we do not evaluate
them for this analysis. On average, the changes in ambient ozone levels
shown above are small and would be even smaller if changes in CO
emissions and VOC reactivity were taken into account. The increase in
ozone would likely lead to negligible monetized impacts. We therefore
do not estimate and monetize ozone health impacts for the changes in
renewable use due to the small magnitude of this change, and the
uncertainty present in the air quality modeling conducted here, as well
as the uncertainty in the underlying emission effects themselves
discussed earlier.
2. Particulate Matter
Ambient PM can come from two distinct sources. First, PM can be
directly emitted into the atmosphere. Second, PM can be formed in the
atmosphere from gaseous pollutants. Gasoline-fueled vehicles and
equipment contribute to ambient PM concentrations in both ways.
As described above, we are not currently able to predict the impact
of fuel quality on direct PM emissions from gasoline-fueled vehicles or
equipment. Therefore, we are unable at this time to project the effect
that increased ethanol use will have on levels of directly emitted PM
in the atmosphere.
PM can also be formed in the atmosphere (termed secondary PM here)
from several gaseous pollutants emitted by gasoline-fueled vehicles and
equipment. Sulfur dioxide emissions contribute to ambient sulfate PM.
NOX emissions contribute to ambient nitrate PM. VOC
emissions contribute to ambient organic PM. Increased ethanol use is
not expected to change gasoline sulfur levels, so emissions of sulfur
dioxide and any resultant ambient concentrations of sulfate PM are not
expected to change. Increased ethanol use is expected to increase
NOX emissions, so the possibility exists that ambient
nitrate PM levels could increase. Increased ethanol is generally
expected to increase total VOC emissions, which could also impact the
formation of secondary organic PM. However, while non-exhaust VOC
emissions are expected to increase, exhaust VOC emissions are expected
to decrease. Generally, the higher the molecular weight of the specific
VOC emitted, the greater the likelihood it will form PM in the
atmosphere. Non-exhaust VOC is predominantly low in molecular weight,
as much of it is due to fuel evaporating. Thus, emissions of VOCs
likely to form PM in the atmosphere are likely decreasing with ethanol use.
The formation of secondary organic PM is very complex, due in part
to the wide variety of VOCs emitted into the atmosphere. The degree to
which a specific gaseous VOC reacts to form PM in the atmosphere
depends on the types of reactions that specific VOC undergoes and the
products of those reactions. Both of these factors depend on other
pollutants present, such as the hydroxyl radical, ozone, NOX
and other reactive compounds. The relative mass of secondary PM formed
per mass of gaseous VOC emitted can also depend on the total
concentration of gaseous VOC and organic PM in the atmosphere. Most of
the secondary organic PM exists in a continually changing equilibrium
between the gaseous and PM phases. Both the rates of these reactions
and the gaseous-PM equilibria depend on temperature, so seasonal
differences can be expected.
Recent smog chamber studies have indicated that gaseous aromatic
VOCs can form secondary PM under certain conditions. These compounds
comprise a greater fraction of exhaust VOC emissions than non-exhaust
VOC emissions, as non-exhaust VOC emissions are dominated by VOCs with
relatively high vapor pressures. Aromatic VOCs tend to have lower vapor
pressures. As increased ethanol use is expected to reduce exhaust VOC
emissions, emissions of aromatic VOCs should also decrease. In
addition, refiners are expected to reduce the aromatic content of
gasoline by 5 volume percentage points as ethanol is blended into
gasoline. Emissions of aromatic VOCs should decrease with lower
concentrations of aromatics in gasoline. Thus, emissions of gaseous
aromatic VOCs could decrease for both reasons.
Overall, we expect that the decrease in secondary organic PM is
likely to exceed the increase in secondary nitrate PM. In 1999,
NOX emissions from gasoline-fueled vehicles and equipment
comprised about 20% of national NOX emissions from all
sources. In contrast, gasoline-fueled vehicles and equipment comprised
over 60% of all national gaseous aromatic VOC emissions. The percentage
increase in national NOX emissions due to increased ethanol
use should be smaller than the percentage decrease in national
emissions of gaseous aromatics. Finally, in most urban areas, ambient
levels of secondary organic PM exceed those of secondary nitrate PM.
Thus, directionally, we expect a net reduction in ambient PM levels due
to increased ethanol use. However, we are unable to quantify this
reduction at this time.
EPA currently utilizes the CMAQ model to predict ambient levels of
PM as a function of gaseous and PM emissions. This model includes
mechanisms to predict the formation of nitrate PM from NOX
emissions. However, it does not currently include any mechanisms
addressing the formation of secondary organic PM. EPA is currently
developing a model of secondary organic PM from gaseous toluene
emissions. We plan to incorporate this mechanism into the CMAQ model in
2007. The impact of other aromatic compounds will be added as further
research clarifies their role in secondary organic PM formation.
Therefore, we expect to be able to quantitatively estimate the impact
of decreased toluene emissions and increased NOX emissions
due to increased ethanol use as part of future analyses of U.S. fuel
requirements required by the Act.
IX. Impacts on Fossil Fuel Consumption and Related Implications
Renewable fuels have been of significant interest for many years
due to their potential to displace fossil fuels, which have often been
targeted as primary contributors to emissions of greenhouse gases such
as carbon dioxide, and national energy concerns primarily due to an
increasing dependence on foreign sources of petroleum. In the Notice of
Proposed Rulemaking, we provided a preliminary assessment of the
greenhouse gas emission and energy impacts of renewable fuel and an
initial assessment of the economic value of renewable fuel displacing
petroleum-based fuels. We
[[Page 23979]]
also indicated that we would be updating an analysis of energy security
impacts that had been prepared by analysts at the Oak Ridge National
Laboratory (ORNL) of the Department of Energy. We present some
discussion of that analysis here.
We also performed a full lifecycle or well-to-wheel analysis for
this final rule to estimate the GHG and fossil energy reductions from
replacing petroleum based fuels with renewable fuels. Argonne National
Laboratory's (ANL) GREET \109\ model was utilized for this lifecycle
analysis. Table IX-1 summarizes this model's estimated impact that
increases in the use of renewable fuels are projected to have on GHG
emissions and fossil fuel consumption for the two renewable fuel volume
scenarios considered in this final rulemaking relative to the reference
case. As described later in this section, the results in Table IX-1 are
based on a number of input assumptions including coal being used as
process fuel in 14% of ethanol facilities.
---------------------------------------------------------------------------
\109\ Greenhouse gases, Regulated Emissions, and Energy use in
Transportation.
---------------------------------------------------------------------------
As noted in Section III, although we have chosen to base our
lifecycle analyses on Argonne National Laboratory's GREET model there
are a variety of other lifecycle models and analyses available. The
choice of model inputs and assumptions all have a bearing on the
results of lifecycle analyses, and many of these assumptions remain the
subject of debate among researchers. Lifecycle analyses must also
contend with the fact that the inputs and assumptions generally
represent industry-wide averages even though energy consumed and
emissions generated can vary widely from one facility or process to
another.
There currently exists no organized, comprehensive dialogue among
stakeholders about the appropriate tools and assumptions behind any
lifecycle analyses. We will be initiating more comprehensive
discussions about lifecycle analyses with stakeholders in the near future.
Table IX-1.--GREET Model Lifecycle Reductions From Increased Renewable Fuel Use Relative to the 2012 Reference
Case
----------------------------------------------------------------------------------------------------------------
RFS case EIA case
-----------------------------------------------------
% of trans. % of trans.
Reduction sector Reduction sector
----------------------------------------------------------------------------------------------------------------
Fossil Energy (QBtu)...................................... 0.15 0.48 0.27 0.85
Petroleum Energy (Bgal)................................... 2.0 0.82 3.9 1.60
GHG Emissions (MMT CO2-eq.)............................... 8.0 0.36 13.1 0.59
CO2 Emissions (MMT CO2)................................... 11.0 0.52 19.5 0.93
----------------------------------------------------------------------------------------------------------------
We used the petroleum energy reductions shown in Table IX-1 to
determine implications on imports of petroleum products. Our analysis
found that calculated petroleum energy reductions come almost entirely
from imports of finished products in this 2012 case and amount to the
equivalent of 123,000 barrels of transportation fuel under the RFS case
and 240,000 barrels of transportation fuel for the EIA case.
Another effect of increased use of renewable fuels in the U.S. is
that it diversifies the energy sources in making transportation fuel.
Diverse sources of fuel energy reduce both financial and strategic
risks associated with a potential disruption in supply or a spike in
cost of a particular energy source. This reduction in risks is a
measure of improved energy security. The ORNL report used an ``oil
premium'' approach to identify those energy-security related impacts
which are not reflected in the market price of oil, and which are
expected to change in response to an incremental change in the level of
U.S. oil imports.
The following sections provide a more complete description of our
analyses of the GHG emissions, fossil fuel, oil imports, and energy
security impacts of this final rule.
A. Impacts on Lifecycle GHG Emissions and Fossil Energy Use
Although the use of renewable fuels in the transportation sector
directly displaces some petroleum consumed as motor vehicle fuel, this
displacement of petroleum is in fact only one aspect of the overall
impact of renewable fuels on fossil fuel use. Fossil fuels are also
used in producing and transporting renewable feedstocks such as plants
or animal byproducts, in converting the renewable feedstocks into
renewable fuel, and in transporting and blending the renewable fuels
for consumption as motor vehicle fuel. To estimate the true impacts of
increases in renewable fuels on fossil fuel use, modelers attempt to
take many or all these steps into account.
Similarly, energy is used and GHGs emitted in the pumping of oil,
transporting the oil to the refinery, refining the crude oil into
finished transportation fuel, transporting the refined gasoline or
diesel fuel to the consumer and then burning the fuel in the vehicle.
Such analyses are termed lifecycle or well-to-wheels analyses. We
performed a full lifecycle analysis as part of this final rulemaking to
determine the GHG and fossil energy reductions from the increased use
of renewable fuels.
This lifecycle assessment approach and rationale were highlighted
in the proposal. Comments received focused mainly on improving the
process, for example the choice of lifecycle model used and initiating
a stakeholder dialogue to build consensus around the assumptions and
approach. In general comments were supportive of using a full lifecycle
assessment approach, but differed on the appropriate model and
associated assumptions EPA should use in its analysis.
1. Time Frame and Volumes Considered
The results presented in this analysis represent a snapshot in
time. They represent annual GHG and fossil fuel savings in the year
considered, in this case 2012. Consistent with the emissions modeling
described in Section VII, our analysis of the GHG and fossil fuel
consumption impacts of renewable fuel use was conducted using three
volume scenarios. The first scenario was the same reference case used
elsewhere in this final rulemaking. The reference case scenario
provided the point of comparison for the other two scenarios. The other
two renewable fuel scenarios for 2012 represented the
[[Page 23980]]
RFS program requirements and the volume projected by EIA.
In both the RFS and EIA scenarios, we assumed that the biodiesel
production volume would be 0.303 billion gallons based on EIA AEO2006
projections. Furthermore, for both scenarios we assume that 250 million
gallons of ethanol that qualify for cellulosic biomass ethanol credit
will be produced in 2012 from corn using biomass as the process energy
source. The remaining renewable fuel volumes in each scenario would be
ethanol made from corn and imports. The import volume is based on EIA's
projections for the percent of total ethanol volume supplied by imports
in 2012. The total volumes for all three scenarios are shown in Table
II.A.1-1.
For the purposes of calculating this difference or the amount of
conventional fuel no longer consumed--that is, displaced--as a result
of the use of the replacement renewable fuel, we assumed the ethanol
volumes shown in Table II.A.1-1 are 5% denatured. The ethanol volumes
were adjusted down to represent pure (100%) ethanol, biodiesel volumes
were not adjusted. The adjusted volumes were then converted to total
Btu using the appropriate volumetric energy content values (76,000 Btu/
gal for ethanol, 115,000 Btu/gal for gasoline, 118,000 Btu/gal for
biodiesel, and 130,000 Btu/gal for diesel fuel). We make the assumption
that vehicle energy efficiency will not be affected by the presence of
renewable fuels (i.e., efficiency of combusting one Btu of ethanol is
equal to the efficiency of combusting one Btu of gasoline).
This lifecycle analysis is conducted without any regard to the
geographic attributes of where emissions or energy use occurs; the
model represents global reductions in GHG emissions and energy use, not
just those occurring in the U.S. For example, under a full lifecycle
assessment approach, the savings associated with reducing overseas
crude oil extraction and refining are included, as are the
international emissions associated with producing imported ethanol.
There were two exceptions to this, both dealing with secondary impacts
that may result internationally due to the expanded use of renewable
fuels within the United States.
The first exception is the emissions associated with international
land use change. Due to decreasing corn exports some changes to
international land use may occur, for example, as more crops are
planted in other regions to compensate for the decrease in crop exports
from the U.S. While the emissions associated with domestic land use
change are well understood and are included in our lifecycle analysis,
we did not include the potential impact on international land use and
any emissions that might directly result. Our currently modeling
capability does not allow us to assess what international land use
changes would occur or how these changes would affect greenhouse gas
emissions. For example, we would need to know how international
cropping patterns would change as well as farming inputs and practices
that might affect emissions assessment.
The second case where we have not quantified the international
impacts results from any reduction in world oil prices would tend to
result from decreased demand in the U.S. as renewable fuels replace
oil. It is commonly presumed in economic analyses that all else being
equal quantity demanded of a valuable good (i.e., oil) will increase as
price decreases. A world wide reduction of oil price would tend to
reduce the cost of producing transportation fuel which in turn would
tend to reduce the price consumers internationally would have to pay
for this fuel.
To the extent fuel prices are decreased, demand and consumption
would tend to increase; this impact of reduced cost of driving is
sometimes referred to as a ``rebound effect.'' Such a greater
consumption internationally would presumably result in an increase in
greenhouse gas emissions as consumers in the rest of the world drive
more. These increased emissions would in part offset the emission
impacts otherwise described in this preamble. While such international
impacts of U.S. actions are important to understand, we have not have
fully considered and quantified the international rebound effects of
this renewable fuel standard. Nevertheless, such impacts remain an
important consideration for future analysis.
2. GREET Model
As in the analyses for the proposal, for this final rulemaking we
used the GREET fuel-cycle model. GREET has been under development for
several years and has undergone extensive peer review through multiple
updates. Of the available sources of information on lifecycle analyses
of energy consumed and emissions generated, we believe that GREET
offers the most comprehensive treatment of the transportation sector.
For this final rule, we used an updated version of the GREET model
\110\, with a few modifications to its input assumptions. These changes
since the NPRM are described below.
---------------------------------------------------------------------------
\110\ GREET version 1.7, released November 10, 2006.
---------------------------------------------------------------------------
The two main comments we received on our lifecycle modeling were
that we should initiate a public dialogue on lifecycle analyses, models
and assumptions, and that our sole reliance on the GREET model should
be avoided, given other models are available. We have begun a public
dialogue in that we identify the assumptions in the GREET model that
were examined and modified for this final rulemaking. Furthermore, we
will be initiating more comprehensive discussions about lifecycle
analysis with stakeholders which could lead to an increased use of
lifecycle analysis in future actions.
In terms of our sole reliance on the GREET model, several other
models have been developed for conducting renewable fuels lifecycle
analysis. For example, researchers at the Energy and Resources Group
(ERG) of the University of California Berkeley have developed the ERG
Biofuel Analysis Meta-Model (EBAMM) and Mark Delucchi at the Institute
of Transportation Studies of the University of California Davis has
developed the Lifecycle Emissions Model (LEM). Other non-fuel specific
lifecycle modeling tools could also be used to perform renewable fuel
lifecycle analysis.
Several studies have been released recently making use of these
other models and showing different results than we find in the analysis
done for this rule. For example, whereas GREET estimates a net GHG
reduction of about 22% for corn ethanol compared to gasoline, the
previously cited works by Farrell et al. utilizing the EBAMM show
around a 13% reduction. The main difference in results is not due to
the model used but assumptions on scope and input data.
For example, most studies focus on average or current ethanol
production which uses a current mix of wet and dry mill ethanol
production and use of coal and natural gas as process energy. In
contrast, for this rulemaking we consider future increases in renewable
fuel production so we focus on new production capacity which will rely
more heavily on more efficient dry mill production than the current mix
of wet and dry mill capacities. Other studies also typically base
ethanol and farm energy use on historic data while we are assuming
future capacity increases will use a state of the art dry milling plant
and most current farming energy use
[[Page 23981]]
data. Varying assumptions concerning how land use change impact
CO2 emissions and agriculture related GHG emissions could
also have an impact on overall results. Other studies also differ in
the environmental flows considered. For example, GREET uses the
internationally accepted set of greenhouse gases while Delucchi uses
additional types of greenhouse gases.
We have not had an opportunity to develop comparable analyses of
the GHG and energy impacts of this rule using these other models.
However, as discussed in chapters 6.1.1 and 6.2.3 of the RIA, we
believe the scope of the GREET model and the assumptions we have used
in running the model tend toward the middle of the range. Therefore we
believe these results provide a reasonable assessment of the energy and
GHG impacts of the expanded use of renewable fuels.
a. Renewable Fuel Pathways Considered
The feedstocks and processes used to model renewable fuel
production were those which our analysis in Chapter 1 of the RIA shows
will primarily be used through 2012. However, other pathways for
producing renewable fuels may become popular such as producing
cellulosic biomass ethanol from municipal solid waste as well as
different process for the feedstocks considered, like gasification of
switchgrass and production of ``renewable'' diesel fuel through
hydrotreating vegetable oils.
Furthermore, the lifecycle analysis used for this rulemaking is
based on averages of the different renewable fuels modeled. For
example, the GHG emission and fossil energy savings associated with
increased use of corn ethanol are calculated based on a mix of corn wet
and dry milling, assuming a certain projected mix of each process.
While this method may not exactly represent the reductions associated
with a given gallon of renewable fuel, it is accurate for the purpose
of this analysis which is to determine the impact of the total
increased volume of renewable fuels used.
We recognize that different feedstocks and processes will each have
unique characteristics when it comes to lifecycle GHG emissions and
energy use. However, we understand that other feedstocks and processes
as well as differences in other parts of the renewable fuel lifecycle
will impact the savings associated with their use and this is the focus
of ongoing work at the agency.
b. Modifications to GREET
Since the analysis done for the NPRM, we have updated the GREET
model with the following changes:
--Included CO2 emissions from corn farming lime use.
--Updated the corn farming fertilizer use inputs.
--Added cellulosic biomass ethanol production from corn stover and
forest waste.
--Modeled biomass as a process fuel source in corn ethanol dry milling.
In addition to the changes listed above we also examined and
updated other GREET input assumptions for corn ethanol and biodiesel
production.
We also examined several other GREET input values, but determined
that the default GREET values should not be changed for a variety of
reasons. These included, corn and ethanol transport distances and modes
and byproduct allocation methods. Our investigation of these other
GREET input values are discussed more fully in Chapter 6 of the RIA.
The current GREET default factors for these other inputs were included
in the analysis for this final rule.
We did not investigate the input values associated with the
production of petroleum-based gasoline or diesel fuel in the GREET
model for this final rule. However, the refinery modeling discussed in
Section VII provides some additional information on the process energy
requirements associated with the production of gasoline and diesel
under a renewable fuels mandate. We will use information from this
refinery modeling in future analysis to determine if any GREET input
values should be changed.
A summary of the GREET input values we investigated and modified
for the final rule analysis is given below.
Corn Farming Energy Use: Corn farming energy use was updated based
on the most recent USDA Agricultural Resource Management Survey (ARMS) data.
CO2 from Land Use Change: The GREET model has a default factor for
CO2 from land use change that was included in the NPRM
analysis. This factor was updated based on the results of the
agricultural sector modeling outlined in Section X. The CO2
emissions from land use change used in the final rulemaking represents
approximately 1% of total corn ethanol lifecycle GHG emissions.
However, this value could be more significant if increased amounts of
renewable fuels are used in the transportation sector. The issue of
CO2 emissions from land use change associated with
converting forest or Conservation Reserve Program (CRP) land into crop
production for use in producing renewable fuels is an important factor
to consider when determining the overall sustainability of renewable
fuel use. While the analysis described above is indicating that the
volumes of renewable fuel analyzed in this rulemaking will not cause a
significant change in land use, this is an area we will continue to
research for any future analysis.
Corn Ethanol Wet-Mill Versus Dry Mill Plants: For this analysis, we
expect most new ethanol plants will be dry mill operations. That has
been the trend in the last few years as the demand for ethanol has
grown, and our analysis of ethanol plants under construction and
planned for the near future has verified this. Our analysis of
production plans, as outlined in Section VI, indicates that essentially
all new ethanol production will be from dry mill plants (99%).
Corn Ethanol Dry Mill Plant Energy Use and Fuel Mix: Our review of
plants under construction and those planned for the near future as
outlined in Section VI, indicates that coal will be used as process
fuel for approximately 14% of the new under construction and planned
ethanol production volume capacity. The energy use at a dry mill plant
using natural gas was based on the model developed by USDA and modified
by EPA for use in the cost analysis of this rulemaking described in
Section VII. For this analysis, we assumed that a coal plant would
require 15% \111\ more electricity demand due to coal handling and have
a 13% increase in thermal demand for steam dryers as compared to the
natural gas fueled plant. We also considered a case where a corn
ethanol plant utilized biomass as a fuel source. For this case we
assumed the same amount of fuel and purchased electricity energy per
gallon as a coal powered plant. This assumption is based on the biomass
plant having more fuel handling than a natural gas plant and producing
steam for DDGS drying.
---------------------------------------------------------------------------
\111\ Baseline Energy Consumption Estimates for Natural Gas and
Coal-based Ethanol Plants--The Potential Impact of Combined Heat and
Power (CHP), Prepared for: U.S. Environmental Protection Agency
Combined Heat & Power Partnership, Prepared by: Energy and
Environmental Analysis, Inc., July 2006.
---------------------------------------------------------------------------
Corn Ethanol Dry Mill Plant Production Yield: Modern ethanol plants
are now able to produce more than 2.7 gallons of ethanol per bushel of
corn compared with less than 2.4 gallons of ethanol per bushel of corn
in 1980. The development of new enzymes continues to increase the
potential ethanol yield. We used a value of
[[Page 23982]]
2.71 \112\ gal/bu in our analysis, which may underestimate actual
future yields. For additional information on our yield analysis, see
the cost modeling of corn ethanol discussed in Section VII.
---------------------------------------------------------------------------
\112\ All yield values presented represent pure ethanol
production (i.e. no denaturant).
---------------------------------------------------------------------------
Corn Ethanol Co-Products: We based the amount of DDGS produced by
an ethanol dry mill plant on the USDA model used in the cost analysis
work of this rulemaking, described in Section VII. Based on the
agricultural sector modeling outlined in Section X, we assumed that one
ton of DDGS displaces 0.5 tons of corn and 0.5 tons of soybean meal. We
also assume for corn ethanol wet milling that one ton of corn gluten
meal substitutes for one ton of soybean meal, one ton of corn gluten
feed substitutes for 0.5 tons of corn, and one ton of corn oil
substitutes for one ton of soybean oil.
Biodiesel Production: Two scenarios for biodiesel production were
considered, one utilizing soybean oil as a feedstock and one using
yellow grease. For the soybean oil scenario, the energy use and inputs
for the biodiesel production process were based on a model developed by
NREL and used by EPA in the cost modeling of soybean oil biodiesel, as
discussed in Section VII. The GREET model does not have a specific case
of biodiesel production from yellow grease. Therefore, as a surrogate
we used the soybean oil based model with several adjustments. For the
yellow grease case, we did not include soybean agriculture emissions or
energy use. Soybean crushing was still included as a surrogate for
yellow grease processing (purification, water removal, etc.). Also, due
to additional processing requirements, the energy use associated with
producing biodiesel from yellow grease is higher than for soybean oil
biodiesel production. As per the cost modeling of yellow grease
biodiesel discussed in Section VII, the energy use for yellow grease
biodiesel production was assumed to be 1.72 times the energy used for
soybean oil biodiesel.
Biodiesel Transportation: Biodiesel transportation was based on the
distribution infrastructure modeling for this rulemaking which
indicates pipelines are not currently used to transport biodiesel and
are not projected to play a role in biodiesel transport in the future
time frame considered. Therefore, GREET default factors for biodiesel
transportation from plant to terminal were modified to remove pipeline
transport.
c. Sensitivity Analysis
As mentioned above, the results of lifecycle analysis are highly
dependent on the input data assumptions used. Section IX.A.1.b outlined
changes made to the GREET model inputs to better represent the scope
and purpose of our analysis for this rulemaking. However, we also
performed several sensitivity analyses on some key assumptions to see
how varying them would impact overall results.
We performed a sensitivity analysis on expanding the lifecycle fuel
production system boundaries to include farm equipment production
(e.g., emissions and energy use associated with producing steel,
rubber, etc. used to make farming equipment). It was found that
including farm equipment production energy use and emissions increases
ethanol lifecycle energy use and GHG emissions by approximately 1
percent. Therefore, the lifecycle results are not changed significantly
due to this expansion of system boundaries.
We also performed a sensitivity analysis on the allocation method
used in ethanol production. A number of by-products are made during the
production of ethanol. In lifecycle analyses, the energy consumed and
emissions generated by an ethanol plant must be allocated not only to
ethanol, but also to each of the by-products. There are a number of
methods that can be used to estimate by-product allocations. The
displacement method for by-product allocation, described in Section
6.1.2.10 of the RIA, is the default for the GREET model and is the
method used by EPA. However, we evaluated another method, the process
energy approach, to determine the impact this assumption has on the
overall results of the analysis.
Use of the process energy based allocation method reduces ethanol
lifecycle energy use and GHG emissions by approximately 30 percent
compared to the displacement allocation approach. This indicates that
ethanol lifecycle analysis results are extremely sensitive to the
choice of allocation method used. (See the RIA, Chapter 6 for more
information on these two by-product allocation methods) The
displacement allocation method is the method supported by international
lifecycle assessment standards \113\ and therefore EPA feels that it is
the most accurate and preferred method to use. This does however
highlight the sensitivity of lifecycle analysis results to choice of
input parameters and assumptions.
---------------------------------------------------------------------------
\113\ ISO 14044:2006(E), ``Environmental Management--Life Cycle
Assessment--Requirements and Guidelines'', International Organization for
Standardization (ISO), First edition, 2006-07-01, Switzerland.
---------------------------------------------------------------------------
3. Displacement Indexes (DI)
The displacement index (DI) represents the percent reduction in GHG
emissions or fossil fuel energy brought about by the use of a renewable
fuel in comparison to the conventional gasoline or diesel that the
renewable fuel replaces. The formula for calculating the displacement
index depends on which fuel is being displaced (i.e. gasoline or
diesel), and which endpoint is of interest (e.g. petroleum energy,
GHG). For instance, when investigating the CO2 impacts of
ethanol used in gasoline, the displacement index is calculated as follows:
[GRAPHIC]
[TIFF OMITTED] TR01MY07.058
The units of g/Btu ensure that the comparison between the renewable
fuel and the conventional fuel is made on a common basis, and that
differences in the volumetric energy content of the fuels is taken into
account. The denominator includes the CO2 emitted through
combustion of the gasoline itself in addition to all the CO2
emitted during its manufacturer and distribution. The numerator, in
contrast, includes only the CO2 emitted during the
manufacturer and distribution of ethanol, not the CO2
emitted during combustion of the ethanol.
The combustion of biomass-based fuels, such as ethanol from corn
and woody crops, generates CO2. However, in the long run the
CO2 emitted from biomass-based fuels combustion does not
increase atmospheric CO2 concentrations, assuming the
biogenic carbon emitted is offset by the uptake of CO2
resulting from the growth of new biomass. Thus ethanol's carbon can be
thought of as cycling from the environment into the plant material
[[Page 23983]]
used to make ethanol and, upon combustion of the ethanol, back into the
environment from which it came. As a result, CO2 emissions
from biomass-based fuels combustion are not included in their lifecycle
emissions results and are not used in the CO2 displacement
index calculations shown above. Net carbon fluxes from changes in
biogenic carbon reservoirs in wooded or crop lands are accounted for
separately in the GREET model.
Using GREET, we calculated the lifecycle values for energy consumed
and GHGs produced for corn-ethanol, cellulosic ethanol, and soybean-
based biodiesel. These values were in turn used to calculate the
displacement indexes. The results are shown in Table IX.A.3-1. Details
of these calculations can be found in Chapter 6 of the RIA.
Table IX.A.3-1.--Displacement Indexes Derived From GREET
[In percent]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Corn ethanol Cellulosic
Corn ethanol (biomass fuel) ethanol Imported ethanol Biodiesel
--------------------------------------------------------------------------------------------------------------------------------------------------------
DIFossil Fuel................................................. 39.4 76.3 92.7 69.0 61.5
DIPetroleum................................................... 91.8 92.0 91.7 92.0 91.2
DIGHG......................................................... 21.8 54.1 90.9 56.0 67.7
DICO2......................................................... 40.3 72.3 100.1 71.0 69.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
The displacement indexes in this table represent the impact of
replacing a Btu of gasoline or diesel with a Btu of renewable fuel.
Thus, for instance, for every Btu of gasoline which is replaced by corn
ethanol, the total lifecycle GHG emissions that would have been
produced from that Btu of gasoline would be reduced by 21.8 percent.
For every Btu of diesel which is replaced by biodiesel, the total
lifecycle petroleum energy that would have been consumed as a result of
burning that Btu of diesel fuel would be reduced by 91.2 percent.
Consistent with the cost modeling done for this rule, for the 2012
cases we assume the ``cellulosic'' ethanol volume is actually produced
from corn utilizing a biomass fuel source at the ethanol production
plant. The displacement index for that fuel as shown in Table IX.A.3-1
is used in the calculation of reductions. We have included the column
for cellulosic ethanol for comparison, indicating that a move toward
cellulosic ethanol will not displace petroleum much differently than
other renewable fuels but will have a positive impact on GHG emissions
reductions.
For imported ethanol, it is more difficult to estimate the
lifecycle energy and GHG displacement indexes since we know much less
about how the crops used to make the ethanol are grown and what energy
is used in the ethanol production facility. While not exclusively, we
anticipate much imported ethanol to be primarily sugarcane based ethanol.
The GHG emissions when producing sugarcane ethanol differs from
corn ethanol in that the GHG emissions from growing sugarcane is likely
different than for growing a equivalent amount of corn to make a gallon
of ethanol. Also, the process of turning sugar into ethanol is easier
than when starting with starch and therefore less energy intensive
(which typically translates into lower GHG). Importantly, we understand
that at least some of the ethanol produced in Brazil uses the bagasse
from the sugarcane itself as a process fuel source. We know from our
analysis that using a biomass source for process energy greatly
improves the GHG benefit of the renewable fuel. These factors would
result in sugarcane ethanol having a greater GHG benefit per gallon
than corn ethanol, certainly where natural gas or coal is the typical
process fuel source used.
Conversely, sugarcane ethanol production does not result in a co-
product such as distillers grain as in the case of corn ethanol. In our
analyses, accounting for co-products significantly improved the GHG
displacement index for corn ethanol. Furthermore, there would be
additional transportation emissions associated with transporting the
imported ethanol to the U.S. as compared to domestically produced
ethanol. Developing a technically rigorous lifecycle estimate for
energy needs and GHG impacts for imported ethanol is not a simple task
and was not available in the timeframe of this rulemaking.
Considering all of the differences between imported and domestic
ethanol, for this rulemaking, we assumed imported ethanol would be
predominately from sugarcane and have estimated DI's approximately mid-
way between the DI's for corn ethanol and DI's for cellulosic ethanol.
We are continuing to develop a better understanding of the lifecycle
energy and GHG impacts of producing ethanol from sugarcane and other
likely feedstock sources of imported ethanol for any future analysis.
4. Impacts of Increased Renewable Fuel Use
We used the methodology described above to evaluate impacts of
increased use of renewable fuels on consumption of petroleum and fossil
fuels and also on emissions of CO2 and GHGs. This section
describes our results.
a. Greenhouse Gases and Carbon Dioxide
We estimated the reduction associated with the increased use of
renewable fuels on lifecycle emissions of CO2 and total GHG.
Since total GHG emission reductions are lower than CO2
reductions, this indicates that lifecycle emissions of CH4
and N2O are higher for renewable fuels than for the
conventional fuels replaced. These values are then compared to the U.S.
transportation sector emissions to get a percent reduction. The
estimates for the 2012 cases are presented in Table IX.A.4.a-1.
[[Page 23984]]
Table IX.A.4.A-1.--Estimated CO2 and GHG Emission Impacts of Increased
Use of Renewable Fuels in the Transportation Sector in 2012, Relative to
the 2012 Reference Case
------------------------------------------------------------------------
RFS case EIA case
------------------------------------------------------------------------
CO2 Reduction (million metric tons CO2)... 11.0 19.5
Percent reduction in Transportation Sector 0.52 0.93
CO Emissions.............................
GHG Reduction (million metric tons CO2- 8.0 13.1
eq.).....................................
Percent reduction in Transportation Sector 0.36 0.59
GHG Emissions............................
------------------------------------------------------------------------
b. Fossil Fuel and Petroleum
We estimated the reduction associated with the increased use of
renewable fuels on lifecycle fossil fuels and petroleum. These values
are then compared to the U.S. transportation sector emissions to get a
percent reduction. The estimates for the 2012 cases are presented in
Table IX.A.4.b-1.
Table IX.A.4.B-1.--Estimated Fossil Fuel and Petroleum Impacts of
Increased Use of Renewable Fuels in the Transportation Sector in 2012,
Relative to the 2012 Reference Case
------------------------------------------------------------------------
RFS case EIA case
------------------------------------------------------------------------
Fossil Fuel Reduction (quadrillion Btu)... 0.15 0.27
Percent reduction in Transportation Sector 0.48 0.85
Fossil Fuel Use..........................
Petroleum Energy Reduction (billion gal.). 2.0 3.9
Percent reduction in Transportation Sector 0.82 1.60
Petroleum Use............................
------------------------------------------------------------------------
B. Implications of Reduced Imports of Petroleum Products
In the proposal, we estimated the impact of expanded renewable fuel
use on the importation of oil and finished transportation fuel. No
comments were received suggesting alternative methodologies should be
used. Therefore, we have incorporated that calculation in this final
rule without change.
In 2005, the United States imported almost 60 percent of the oil it
consumed. This compares to just over 35 percent of oil from imports in
1975.\114\ Transportation accounts for 70 percent of the U.S. oil
consumption. It is clear that oil imports have a significant impact on
the U.S. economy. Expanded production of renewable fuel is expected to
contribute to energy diversification and the development of domestic
sources of energy. We consider whether the RFS will reduce U.S.
dependence on imported oil by calculating avoided expenditures on
petroleum imports. Note that we do not calculate whether this reduction
is on the net, socially beneficial, which would depend on the scarcity
value of domestically produced ethanol versus that of imported
petroleum products. However, the next section does discuss some of the
energy security implications unique to petroleum imports.
---------------------------------------------------------------------------
\114\ Davis, Stacy C.; Diegel, Susan W., Transportation Energy
Data Book: 25th Edition, Oak Ridge National Laboratory, U.S.
Department of Energy, ORNL-6974, 2006.
---------------------------------------------------------------------------
To assess the impact of the RFS program on petroleum imports, we
estimate the fraction of domestic consumption derived from foreign
sources using results from the AEO 2006. We compared the levels and mix
of imports in the AEO reference case with those in the low
macroeconomic growth case and high oil price case. In Section 6.4.1 of
the RIA we describe in greater detail how fuel producers may change
their levels and mix of imports in response to a decrease in fuel
demand. For the purposes of this rulemaking, we show values for the low
macroeconomic growth comparison, where import reductions come almost
entirely from imports of finished products as shown below in Table
IX.B-1. The reductions in imports are compared to the AEO projected
levels of net petroleum imports. The range of reductions in net
petroleum imports are estimated to be between 0.9 to 1.7 percent, as
shown in Table IX.B-1.
Table IX.B-1.--Net Reductions in Imports in 2012
------------------------------------------------------------------------
RFS case EIA case
------------------------------------------------------------------------
Reduction in finished products* (barrels per day). 123,000 240,000
Percent reduction**............................... 0.89% 1.73%
------------------------------------------------------------------------
* Net reductions relative to 2012 reference case.
** Compared to AEO 2006 projections for 2012 reference case.
We also calculate the change in expenditures in both petroleum and
ethanol imports and compare these with the U.S. trade position measured
as U.S. net exports of all goods and services economy-wide. The
decreased expenditures were calculated by multiplying the changes in
gasoline, diesel, and ethanol imports by the respective AEO 2006
wholesale gasoline, distillate, and ethanol price forecasts for the
specific analysis years. In Table IX.B-2, the net expenditures in
reduced petroleum imports, increased ethanol imports, and decreased
corn exports are compared to the total value of U.S. net exports of
goods and services for the whole economy for 2012. Relative to the 2012
projection, the avoided expenditures due to the RFS would represent 0.4
to 0.7% of economy-wide net exports.
[[Page 23985]]
Table IX.B-2.--Avoided Import Expenditures ($2004 Billion)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Expenditures
on Expenditures Decreased Net Percent of
Cases AEO total net exports petroleum on ethanol corn expenditures total net
imports imports exports on imports exports
--------------------------------------------------------------------------------------------------------------------------------------------------------
RFS Case........................................ -$383 (year 2012)................. -$2.6 +$0.7 +$0.6 -$1.4 0.4%
EIA Case........................................ .................................. -$5.1 +$1.0 +$1.3 -$2.8 0.7%
--------------------------------------------------------------------------------------------------------------------------------------------------------
C. Energy Security Implications of Increases in Renewable Fuels
One of the effects of increased use of renewable fuels in the U.S.
from the RFS is that it diversifies the energy sources in making
transportation fuel. A potential disruption in supply reflected in the
price volatility of a particular energy source carries with it both
financial as well as strategic risks. These risks can be reduced to the
extent that diverse sources of fuel energy reduce the dependence on any
one source. This reduction in risks is a measure of improved energy
security.
At the time of the proposal, EPA stated that an analysis would be
completed and estimates provided in support of this rule. In order to
understand the energy security implications of the RFS, EPA has worked
with Oak Ridge National Laboratory (ORNL), which has developed
approaches for evaluating the social costs and energy security
implications of oil use. In a new study produced for the RFS, entitled
``The Energy Security Benefits of Reduced Oil Use, 2006-2015,'' ORNL
has updated and applied the method used in the 1997 report ``Oil
Imports: An Assessment of Benefits and Costs'', by Leiby, Jones, Curlee
and Lee.115 116 While the 1997 report including a
description of methodology and results at that time has been used or
cited on a number of occasions, this updated analysis and results have
not been available for full public consideration. Since energy security
will be a key consideration in future actions aimed at reducing our
dependence on oil, it is important to assure estimates of energy
security impacts have been thoroughly examined in a full and open
public forum. Since the updated analysis was only recently available,
such a thorough analysis has not been possible. Therefore, EPA has
decided to consider this update as a draft report, include it as part
of the record of this rulemaking and invite further public analysis and
consideration of both this particular draft report but also other
perspectives on how to best quantify energy security benefits. To
facilitate that additional consideration, we highlight below some of
the key aspects of this particular draft analysis.
---------------------------------------------------------------------------
\115\ Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and
Russell Lee, Oil Imports: An Assessment of Benefits and Costs, ORNL-
6851, Oak Ridge National Laboratory, November, 1997.
\116\ The 1997 ORNL paper was cited and its results used in DOT/
NHTSA's rules establishing CAFE standards for 2008 through 2011
model year light trucks. See DOT/NHTSA, Final Regulatory Impacts
Analysis: Corporate Average Fuel Economy and CAFE Reform MY 2008-
2011, March 2006.
---------------------------------------------------------------------------
The approach developed by ORNL estimates the incremental benefits
to society, in dollars per barrel, of reducing U.S. oil imports, called
``oil premium.'' Since the 1997 publication of this report, changes in
oil market conditions, both current and projected, suggest that the
magnitude of the oil premium has changed. Significant driving factors
that have been revised include: Oil prices, current and anticipated
levels of OPEC production, U.S. import levels, the estimated
responsiveness of regional oil supplies and demands to price, and the
likelihood of oil supply disruptions. For this analysis, oil prices
from the EIA's AEO 2006 were used. Using the ``oil premium'' approach,
estimates of benefits of improved energy security from reduced U.S. oil
imports from increased use of renewable fuels are calculated.
In conducting this analysis, ORNL considered the full economic cost
of importing petroleum into the U.S. The full economic cost of
importing petroleum into the U.S. is defined for this analysis to
include two components in addition to the purchase price of petroleum
itself. These are: (1) The higher costs for oil imports resulting from
the effect of U.S. import demand on the world oil price and OPEC market
power (i.e., the so called ``demand'' or ``monoposony'' costs); and (2)
the risk of reductions in U.S. economic output and disruption of the
U.S. economy caused by sudden disruptions in the supply of imported oil
to the U.S. (i.e., macroeconomic disruption/adjustment costs).
1. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, and
Economic Output
The first component of the full economic costs of importing
petroleum into the U.S. follows from the effect of U.S. import demand
on the world oil price over the long-run. Because the U.S. is a
sufficiently large purchaser of foreign oil supplies, its purchases can
affect the world oil price. This monopsony power means that increases
in U.S. petroleum demand can cause the world price of crude oil to
rise, and conversely, that reduced U.S. petroleum demand can reduce the
world price of crude oil. Thus, one consequence of decreasing U.S. oil
purchases due to increased use of renewable fuel is the potential
decrease in the crude oil price paid for all crude oil purchased.
2. Short-Run Disruption Premium From Expected Costs of Sudden Supply
Disruptions
The second component of the external economic costs resulting from
U.S. oil imports arises from the vulnerability of the U.S. economy to
oil shocks. The cost of shocks depends on their likelihood, size, and
length, the capabilities of the market and U.S. Strategic Petroleum
Reserve (SPR), the largest stockpile of government-owned emergency
crude oil in the world, to respond, and the sensitivity of the U.S.
economy to sudden price increases. While the total vulnerability of the
U.S. economy to oil price shocks depends on the levels of both U.S.
petroleum consumption and imports, variation in import levels or demand
flexibility can affect the magnitude of potential increases in oil
price due to supply disruptions. Disruptions are uncertain events, so
the costs of alternative possible disruptions are weighted by
disruption probabilities. The probabilities used by the ORNL study are
based on a 2005 Energy Modeling Forum\117\ synthesis of expert judgment
and are used to determine an expected value of disruption costs, and
the change in those expected costs given reduced U.S. oil imports.
3. Costs of Existing U.S. Energy Security Policies
The last often-identified component of the full economic costs of
U.S. oil
[[Page 23986]]
imports is the costs to the U.S. taxpayers of existing U.S. energy
security policies. The two primary examples are maintaining a military
presence to help secure stable oil supply from potentially vulnerable
regions of the world and maintaining the SPR to provide buffer supplies
and help protect the U.S. economy from the consequences of global oil
supply disruptions.
U.S. military costs are excluded from the analysis performed by
ORNL because their attribution to particular missions or activities is
difficult. Most military forces serve a broad range of security and
foreign policy objectives. Attempts to attribute some share of U.S.
military costs to oil imports are further challenged by the need to
estimate how those costs might vary with incremental variations in U.S.
oil imports. Similarly, while the costs for building and maintaining
the SPR are more clearly related to U.S. oil use and imports,
historically these costs have not varied in response to changes in U.S.
oil import levels. Thus, while SPR is factored into the ORNL analysis,
the cost of maintaining the SPR is excluded.
As stated earlier, we have placed the draft report in the docket of
this rulemaking for the purposes of inviting further consideration.
However, the draft results of that report have not been used in
quantifying the impacts of this rule.
X. Agricultural Sector Economic Impacts
As described in the Notice of Proposed Rulemaking (NPRM), we used
the Forest and Agricultural Sector Optimization Model (FASOM) developed
by Professor Bruce McCarl of Texas A&M University and others, to
estimate the agricultural sector impacts of increasing renewable fuel
volumes required by the RFS and for those volumes anticipated by EIA
for 2012. Although current renewable fuel volume predictions are higher
than the scenarios described in this rulemaking, we based our analysis
on assumptions developed during the NPRM process. Our agricultural
sector analysis considered the impacts of the domestic production of
renewable fuels. Therefore, when we refer to either the RFS Case or the
EIA Case, we include only renewable fuels produced from feedstocks
grown in the U.S.\118\
At the time the NPRM was published, we had not yet finished our
analysis of the agricultural impacts associated with the RFS. In the
NPRM, we stated our intent to have the analysis completed in time for
the Final Rulemaking (FRM). In the proposal we described our plan to
evaluate the effect of increasing renewable fuels volumes on U.S.
commodity prices, renewable fuel byproduct prices, livestock feed
sources, land use, exports, and farm income. The results of this
analysis are summarized in this section. Additional details are
included in the Regulatory Impact Analysis (RIA).
---------------------------------------------------------------------------
\117\ Stanford Energy Modeling Forum, Phillip C. Beccue and
Hillard G. Huntington, ``An Assessment of Oil Market Disruption
Risks,'' Final Report, EMF SR 8, October, 2005.
\118\ The RIA contains additional information on the renewable
fuels volumes analyzed for this rulemaking.
---------------------------------------------------------------------------
FASOM is a long-term economic model of the U.S. agriculture sector
that attempts to maximize total revenues for producers while meeting
the demands of consumers. Using a number of inputs, FASOM estimates
which crops, livestock, and processed agricultural products will be
produced in the U.S. The cost of these and other inputs are used to
determine the price and level of production of commodities (e.g., field
crops, livestock, and biofuel products). FASOM does not capture short-
term fluctuations (i.e., month-to-month, annual) in prices and
production, however, as it is designed to identify long-term trends
(i.e., five to ten years).
FASOM predicts that as renewable fuel volumes increase, corn prices
will rise by about 18 cents (RFS Case) and 39 cents (EIA Case) above
the Reference Case price of $2.32 per bushel. For consistency, all of
the dollar estimates are presented in 2004 dollars. Soybean prices will
rise by about 18 cents (RFS Case) and 21 cents (EIA Case) above the
Reference Case price of $5.26 per bushel by 2012. Since biodiesel
volumes will not increase significantly in either the RFS or EIA
scenarios, FASOM does not predict significant changes in the soybean
related markets with respect to usage changes, or most other variables
of interest for this rulemaking. The one exception is U.S. soybean
exports, which are affected modestly.
Changes in corn use can be seen by the changing percentage of corn
used for ethanol. In 2005, approximately 12 percent of the corn supply
was used for ethanol production, however we estimate the amount of corn
used for ethanol in 2012 will increase to 20 percent (RFS Case) and 26
percent (EIA Case).
The rising price of corn and soybeans has a direct impact on how
corn is used. Higher domestic corn prices lead to lower U.S. exports as
the world markets shift to other sources of these products or expand
the use of substitute grains. FASOM estimates that U.S. corn exports
will drop from about 2 billion bushels in our Reference Case, to 1.6
billion bushels (RFS Case) and 1.3 billion bushels (EIA Case) by 2012.
U.S. exports of corn are estimated to drop by about 19 percent by 2012
for the RFS Case and by roughly 38 percent in the EIA Case. In value
terms, U.S. exports of corn fall by $573 million in the RFS Case and by
$1.29 billion in the EIA Case in 2012.
The impact on domestic livestock feed due to higher corn prices and
higher U.S. demand for corn in ethanol is also partially offset by
decreasing the use of corn for U.S. livestock feed. Substitutes are
available for corn as a feedstock, and this market is price sensitive.
One alternate feedstock is distillers dried grains with solubles
(DDGS), a byproduct associated with the dry milling of ethanol
production. Since FASOM predicts relatively flat prices for DDGS across
all ethanol volume scenarios, the result is a significant increase in
the use of DDGS as a feed source. We estimate DDGS in feed for the RFS
case will almost double by 2012, increasing from 8.5 million tons to
15.2 million tons. Under the EIA Case, we expect DDGS to increase to
22.2 million tons by 2012.
The increase in soybean prices is estimated to cause a decline in
U.S. soybean exports. In terms of export earnings, U.S. exports of
soybeans fall by $220 million in the RFS Case and by $194 million in
the EIA Case in 2012.
The increase in renewable fuel production provides a significant
increase in net farm income to the U.S. agricultural sector. FASOM
predicts that in 2012, net U.S. farm income will increase by $2.6
billion dollars in the RFS renewable fuel volumes case (RFS Case) and
$5.4 billion in the EIA renewable fuel volumes case (EIA Case). The RFS
and EIA farm revenue increases represent roughly a 5 and 10 percent
increase, respectively, in U.S. net farm income from the sale of farm
commodities over the Reference Case of roughly $53 billion.
Higher corn prices will have a direct impact on the value of U.S.
agricultural land. As demand for corn and farm products increases, the
price of U.S. farm land will also increase. Our analysis shows that in
2012, higher renewable fuel volumes increase land prices by about 8
percent (RFS Case) and 17 percent (EIA Case). Much of the high quality,
suitable land in the U.S. is already being used to produce corn. FASOM
estimates an increase of 1.6 million acres (RFS Case) and 2.6 million
acres (EIA Case) above the 78.5 million corn acres harvested in the
Reference Case in 2012. Due to this higher value of land, we are
predicting that farms will withdraw a portion of the land currently in
the Conservation Reserve Program (CRP), about 2.3 million acres (RFS
Case) and 2.5 million acres (EIA
[[Page 23987]]
Case) out of the approximately 40 million acres in CRP.\119\
---------------------------------------------------------------------------
\119\ Since much of the CRP land is ill suited for corn or
soybean production, it is unlikely this land will go directly into
corn or soybean production but instead will more likely be used to
replace other agricultural land uses displaced by expanded corn and
soybean production.
---------------------------------------------------------------------------
FASOM estimates U.S. annual wholesale food costs will increase by
approximately $2.2 billion with the RFS renewable volumes and $3.7
billion with the EIA renewable volumes by 2012. These costs translate
to approximately $7 per person per year (RFS case) and $12 per person
per year (EIA case).
In the proposal, we noted that expansion in the use of renewable
fuels also raises the issue of whether water quality and rural
ecosystems in general could be affected due to increased production of
agricultural feedstocks used to produce greater volumes of renewable
fuels. We received one comment from Marathon asserting that our
environmental assessment was incomplete and did not address water
quality issues. In the time frame to complete this rulemaking, we were
not able to conduct a comprehensive assessment of the environmental
impacts in the agricultural sector of the wider use of renewable fuels.
However, we have considered two indicators--fertilizer use on
agricultural crops and Conservation Resource Program (CRP) lands--that
may relate to environmental quality and water quality from the
production of renewable fuels. The CRP is a voluntary program
administered by the U.S. Department of Agriculture that helps defray
the costs to farmers of taking agricultural lands out of production and
placing them in CRP to provide environmental protection.
As discussed in Section X, FASOM predicts the total amount of
nitrogen applied on all farms will increase by 1.2 percent in the RFS
Case and by 2 percent in the EIA Case, relative to the Reference Case
in 2012. The total amount of phosphorous applied on all farms increases
by 0.7 percent in the RFS Case and 1.2 percent in the EIA Case,
relative to the Reference Case in 2012. Currently, there are
approximately 40 million acres in the CRP. FASOM predicts 2.3 million
acres (RFS Case) and 2.5 million acres (EIA Case) of land would be
withdrawn from the CRP due to higher land values.
XI. Public Participation
Many interested parties participated in the rulemaking process that
culminates with this final rule. This process provided opportunity for
submitting written public comments following the proposal that we
published on September 22, 2006 (71 FR 55552). We considered these
comments in developing the final rule. In addition, we held a public
hearing on the proposed rulemaking on October 13, 2006, and we have
considered comments presented at the hearing.
Throughout the rulemaking process, EPA met with stakeholders
including representatives from the refining industry, renewable fuels
production, and marketers and distributors, and others. The program we
are finalizing today was developed as a collaborative effort with these
stakeholders.
We have prepared a detailed Summary and Analysis of Comments
document, which describes comments we received on the proposal and our
response to each of these comments. The Summary and Analysis of
Comments is available in the docket for this rule at the Internet
address listed under ADDRESSES, as well as on the Office of
Transportation and Air Quality Web site (http://www.epa.gov/otaq/renewablefuels/
index.htm). In addition, comments and responses for key
issues are included throughout this preamble.
XII. Administrative Requirements
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order (EO) 12866, (58 FR 51735, October 4, 1993)
this action is a ``significant regulatory action'' because of the
policy implications of the final rule. Even though EPA has estimated
that renewable fuel use through 2012 will be sufficient through the
operation of market forces to meet the levels required in the standard,
the final rule reflects the first renewable fuel mandate at the federal
level. Accordingly, EPA submitted this action to the Office of
Management and Budget (OMB) for review under EO 12866 and any changes
made in response to OMB recommendations have been documented in the
docket for this action.
B. Paperwork Reduction Act
The information collection requirements in this final rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) prepared by EPA has been assigned
EPA ICR number 2242.02. The information collection requirements are not
enforceable until OMB approves them.
The information is planned to be collected to ensure that the
required amount of renewable fuel is used each year. The credit trading
program required by the Energy Policy Act will be satisfied through a
program utilizing Renewable Identification Numbers (RINs), which are
assigned when renewable fuel is produced in or imported to geographic
areas covered by the rule. Production and importation of renewable fuel
will serve as a surrogate measure of renewable fuel consumption. Our
final RIN-based program will fulfill all the functions of a credit
trading program, and thus will meet the Energy Policy Act's
requirements. For each calendar year, each obligated party will be
required to submit a report to the Agency documenting the RINs it
acquired, and showing that the sum of all RINs acquired is equal to or
greater than its renewable volume obligation. The Agency could then
verify that the RINs used for compliance purposes were valid by simply
comparing RINs reported by producers to RINs claimed by obligated parties.
For fuel standards, Section 208(a) of the Clean Air Act requires
that manufacturers provide information the Administrator may reasonably
require to determine compliance with the regulations; submission of the
information is therefore mandatory. We will consider confidential all
information meeting the requirements of Section 208(c) of the Clean Air
Act.
The annual public reporting and recordkeeping burden for this
collection of information is estimated to be 3.3 hours per response. A
document entitled ``Information Collection Request (ICR); OMB-83
Supporting Statement, Environmental Protection Agency, Office of Air
and Radiation,'' has been placed in the public docket. The supporting
statement provides a detailed explanation of the Agency's estimates by
collection activity and explains how comments may be submitted by
interested parties. The estimates contained in the docket are briefly
summarized here:
Estimated total number of potential respondents: 6,425.
Estimated total number of responses: 13,380.
Estimated total annual burden hours: 43,030.
Estimated total respondent cost (estimated at $71 per hour):
$3,055,130.
Estimated total non-postage purchased services (estimated at $142
per hour): $5,219,920.
EPA received various comments on the rulemaking provisions covered
by the proposed ICR. All comments that were submitted to EPA are
considered in the Summary and Analysis of Comments, which can be found
in the
[[Page 23988]]
docket. In response to comments, we have increased the frequency of
reporting for transaction and summary reports from annually to
quarterly. We have also removed a burden for small refiners that was
associated with applying for small-refiner flexibilities. The burdens
and costs shown above account for these changes.
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in this
final rule.
C. Regulatory Flexibility Act
1. Overview
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 (see table below); (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. The
following table provides an overview of the primary SBA small business
categories potentially affected by this regulation:
---------------------------------------------------------------------------
\120\ In the NPRM, we also referred to a 125,000 barrels of
crude per day (bpcd) crude capacity limit. This criterion was
inadvertently used and is not applicable for this program (as it
only applies in cases of government procurement). We note that the
number of small entities remains the same whether this criterion is
used or not.
------------------------------------------------------------------------
Defined as small NAICS codes
Industry entity by SBA if \a\
------------------------------------------------------------------------
Gasoline refiners.................. < =1,500 324110
employees.\120\.
------------------------------------------------------------------------
\a\ North American Industrial Classification System.
EPA has determined that it is not necessary to prepare a regulatory
flexibility analysis in connection with this final rule.
2. Background
Since the vast majority of crude oil produced in or imported into
the U.S. is consumed as gasoline or diesel fuel, concerns about our
dependence on foreign sources of crude oil has renewed interest in
renewable transportation fuels. The passage of the Energy Policy Act of
2005 demonstrated a strong commitment on the part of U.S. policymakers
to consider additional means of supporting renewable fuels as a
supplement to petroleum-based fuels in the transportation sector.
Section 1501 of the Energy Policy Act, which was added to the CAA as
Section 211(o), requires EPA to establish the RFS program to ensure
that the pool of gasoline sold in the contiguous 48 states contains
specific volumes of renewable fuel for each calendar year starting with
2006. The Agency is required to set a standard for each year
representing the amount of renewable fuel that obligated parties (e.g.,
refiners, blenders, and importers) must use as a percentage of gasoline
sold or introduced into commerce, and the Agency is required to
promulgate a credit trading program for the RFS program.
3. Small Refineries Versus Small Refiners
Title XV (Ethanol and Motor Fuels) of the Energy Policy Act
provides, at Section 1501(a)(2) [42 U.S.C. 7545(o)(9)(A)-(D)], special
provisions for ``small refineries'', such as a temporary exemption from
the standards until calendar year 2011. The Act defines the term
``small refinery'' as ``* * * a refinery for which the average
aggregate daily crude oil throughput for a calendar year * * * does not
exceed 75,000 barrels.'' As shown in the table above, this term is
different than SBA's small business category for gasoline refiners,
which is what the Regulatory Flexibility Act is concerned with. EPA is
required under the RFA to consider impacts on small entities meeting
SBA's small business definition; these entities are referred to as
``small refiners'' for our regulatory flexibility analysis under SBREFA.
A small refinery, per the Energy Policy Act, is a refinery where
the annual crude throughput is less than or equal to 75,000 barrels
(i.e., a small-capacity refinery), and could be owned by a larger
refiner that exceeds SBA's small entity size standards. The small
business employee criteria were established for SBA's small business
definition to set apart those companies which are most likely to be at
an inherent economic disadvantage relative to larger businesses.
4. Summary of Potentially Affected Small Entities
The refiners that are potentially affected by this rule are those
that produce gasoline. For our recent final rule ``Control of Hazardous
Air Pollutants From Mobile Sources'' (72 FR 8428, February 26, 2007),
we performed an industry characterization of potentially affected
gasoline refiners. We used that industry characterization to determine
which refiners would also meet the SBA definition of a small entity.
From that industry characterization, and further analysis following the
Notice of Proposed Rulemaking (71 FR 55552, September 22, 2006), we
have determined that there are 15 gasoline refiners who own 16
refineries (14 refiners own one refinery each, the remaining refiner
owns two refineries) that meet the definition of a small refiner. Of
the 16 refineries, 13 also meet the Energy Policy Act's definition of a
small refinery.
5. Impact of the Regulations on Small Entities
As previously stated, many aspects of the RFS program, such as the
required amount of annual renewable fuel volumes, are specified in the
Energy Policy Act. As discussed above in Section II.A.1, the annual
projections of ethanol production to satisfy market demand exceed the
required annual renewable fuel volumes. When the small refinery
exemption ends, it is anticipated that there will be over one
[[Page 23989]]
billion gallons in excess RINs available. We believe that this large
volume of excess RINs will also lower the costs of this program. Thus,
with the short-term relief provided under the Energy Policy Act for
small refineries, and the anticipated low cost of RINs when the
exemption expires, we believe that this program will not impose a
significant economic burden on small refineries, small refiners, or any
other obligated party. Therefore, we have determined that this rule
will not have a significant economic impact on a substantial number of
small entities.
When the Agency certifies that a rule will not have a significant
economic impact on a substantial number of small entities, EPA's policy
is to make an assessment of the rule's impact on any small entities and
to engage the potentially regulated entities in a dialog regarding the
rule, and minimize the impact to the extent feasible. The following
sections discuss our outreach with the potentially affected small
entities and regulatory flexibilities to decrease the burden on these
entities in compliance with the requirements of the RFS program.
6. Small Refiner Outreach
We do not believe that the RFS program would have a significant
economic impact on a substantial number of small entities, however we
have still tried to reduce the impact of this rule on small entities.
Prior to issuing the proposed rule, we held meetings with small
refiners to discuss the requirements of the RFS program and the special
provisions offered by the Energy Policy Act for small refineries.
The Energy Policy Act set out the following provisions for small
refineries:
? A temporary exemption from the Renewable Fuels Standard
requirement until 2011;
? An extension of the temporary exemption period for at
least two years for any small refinery where it is determined that the
refinery would be subject to a disproportionate economic hardship if
required to comply;
? Any small refinery may petition, at any time, for an
exemption based on disproportionate economic hardship; and,
? A small refinery may waive its temporary exemption to
participate in the credit generation program, or it may also ``opt-
in'', by waiving its temporary exemption, to be subject to the RFS
requirement.
During these meetings with the small refiners we also discussed the
impacts of these provisions being offered to small refineries only.
Three refiners met the definition of a small refiner, but their
refineries did not meet the Act's definition of a small refinery; which
naturally concerned the small refiners. Another concern that the small
refiners had was that if this rule were to have a significant economic
impact on a substantial number of small entities a lengthy SBREFA
process would ensue (which would delay the promulgation of the RFS
rulemaking) and thus provide less lead time for these small entities
prior to the RFS program start date.
Following our discussions with the small refiners, they provided
three suggested regulatory flexibility options that they believed could
further assist affected small entities in complying with the RFS
program standard: (1) That all small refiners be afforded the Act's
small refinery temporary exemption, (2) that small refiners be allowed
to generate credits if they elect to comply with the RFS program
standard prior to the 2011 small refinery compliance date, and (3)
relieve small refiners who generate blending credits of the RFS program
compliance requirements.
We agreed with the small refiners' suggestion that small refiners
be afforded the same temporary exemption that the Act specifies for
small refineries. This relief would apply to refiners who meet the
1,500 employee count criteria, as well as the crude capacity criteria
that we have used in previous fuels programs when providing relief for
small refiners. Regarding the small refiners' second and third
suggestions regarding credits, we note that the RIN-based program will
automatically provide them with credit for any renewables that they
blend into their motor fuels. Until 2011, small refiners will
essentially be treated as oxygenate blenders and may separate RINs from
batches and trade or sell these RINs, unless they choose to opt-in to
the program.
7. Reporting, Recordkeeping, and Compliance Requirements
Registration, recordkeeping and reporting are necessary to track
compliance with the renewable fuels standard and transactions involving
RINs, and these compliance requirements will be similar to those
required under our previous and current 40 CFR part 80 fuel compliance
programs. We will use the same basic forms for RFS program registration
that we use under the reformulated gasoline (RFG) and anti-dumping
program, as these forms are well known in the regulated community and
are simple to fill out. We will use a simplified method of reporting
via the Agency's Central Data Exchange (CDX), which will reduce the
reporting burden on regulated parties. Records related to RIN
transactions may be kept in any format and the period of record
retention by reporting parties is five years, similar to other fuel
programs. Records to be retained include copies of all compliance
reports submitted to EPA and copies of product transfer documents
(PTDs). Sections IV and V, above, contain more detailed discussions on
the registration, recordkeeping, reporting, and compliance requirements
of this final rule.
8. Related Federal Rules
We are aware of a few other current or proposed Federal rules that
are related to this rule. The primary related federal rules are the
Mobile Source Air Toxics (MSAT2) rule (72 FR 8428, February 26, 2007),
the Tier 2 Vehicle/Gasoline Sulfur rulemaking (65 FR 6698, February 10,
2000), and the fuel sulfur rules for highway diesel (66 FR 5002,
January 18, 2001) and nonroad diesel (69 FR 38958, June 29, 2004).
9. Conclusions
As stated above, based on the statutory relief provided by the
Energy Policy Act for small refineries, we are certifying that this
rule will not have a significant economic impact on a substantial
number of small entities. Additionally, we believe that extending the
small refinery exemption to small refiners would further reduce the
economic impacts on small entities. We believe that small refiners
generally lack the resources available to larger companies, and
therefore find it appropriate to extend this exemption to all small
refiners. Thus, we are extending the small refinery temporary exemption
to all qualified small refiners. Small refiners will also be permitted
to separate RINs from batches and trade or sell these RINs prior to
2011 if the small refiner operates as an ethanol blender.
Past fuels rulemakings have included a provision that, for the
purposes of the regulatory flexibility provisions for small entities, a
refiner must also have an average crude capacity of no more than
155,000 barrels of crude per day (bpcd). To be consistent with these
previous rules, we are finalizing in this rule that refiners that meet
this criterion (in addition to having no more than 1,500 total
corporate employees) will be considered small refiners for the purposes
of the regulatory flexibility provisions for this rulemaking.
Since the RFS program would have no significant economic impact on
a substantial number of small entities
[[Page 23990]]
with only the relief required in the Energy Policy Act for small
refineries, it also follows that the rule will have no significant
economic impact on a substantial number of small entities with the
additional relief this final rule provides for small refiners.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted.
Before EPA establishes any regulatory requirements that may
significantly or uniquely affect small governments, including tribal
governments, it must have developed under Section 203 of the UMRA a
small government agency plan. The plan must provide for notifying
potentially affected small governments, enabling officials of affected
small governments to have meaningful and timely input in the
development of EPA regulatory programs with significant Federal
intergovernmental mandates, and informing, educating, and advising
small governments on compliance with the regulatory requirements.
EPA has determined that 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. EPA has estimated that renewable fuel use
through 2012 will be sufficient to meet the required levels. Therefore,
individual refiners, blenders, and importers are already on track to
meet rule obligations through normal market-driven incentives. Thus,
today's rule is not subject to the requirements of Sections 202 and 205
of the UMRA.
EPA has determined that this rule contains no regulatory
requirements that might significantly or uniquely affect small
governments. Compliance with the mandates of the RFS rule, including
the reporting and recordkeeping requirements, are the responsibility of
exporters, producers, and importers of renewable fuel and gasoline, and
not small governments.
E. Executive Order 13132: Federalism
Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that 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.''
This final rule 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. Thus, Executive Order 13132 does
not apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicited comment on the proposed rule
from State and local officials. A number of states commented on the
proposed rule. These comments are available in the rulemaking docket,
and are summarized and addressed in the Summary and Analysis document.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (59 FR 22951, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This final rule does not have
tribal implications, as specified in Executive Order 13175. This rule
will be implemented at the Federal level and will apply to refiners,
blenders, and importers. Tribal governments will be affected only to
the extent they purchase and use regulated fuels. Thus, Executive Order
13175 does not apply to this rule.
G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks
Executive Order 13045: ``Protection of Children from Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.
EPA interprets EO 13045 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 final rule is not subject to EO 13045 because it
does not establish an environmental standard intended to mitigate
health or safety risks and because it implements specific standards
established by Congress in statutes.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This rule is not a ``significant energy action'' as defined in
Executive Order 13211, ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 28355
(May 22, 2001)) because it is not likely to have a significant adverse
effect on the supply, distribution, or use of energy.
EPA expects the provisions to have very little effect on the
national fuel supply since normal market forces alone are promoting
greater renewable fuel use than required by the RFS mandate. We discuss
our analysis of the energy and supply effects of the increased use of
renewable fuels in Sections VI and X of this preamble.
I. National Technology Transfer Advancement Act
As noted in the proposed rule, Section 12(d) of the National
Technology Transfer and Advancement Act of 1995 (``NTTAA''), Public Law
No. 104-113, 12(d) (15 U.S.C. 272 note)
[[Page 23991]]
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. The NTTAA directs EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
This rulemaking involves technical standards. EPA has decided to
use ASTM D6751-06a ``Standard Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels''. This standard was developed
by ASTM International (originally known as the American Society for
Testing and Materials), Subcommittee D02.E0, and was approved in August
2006. The standard may be obtained through the ASTM Web site
(http://www.astm.org) or by calling ASTM at (610) 832-9585.
ASTM D6751-06a meets the objectives of this final rule because it
establishes one of the criteria by which biodiesel is defined.
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 lacks the discretionary authority to address environmental
justice in this final rulemaking since the Agency is implementing
specific standards established by Congress in statutes. Although EPA
lacks authority to modify today's regulatory decision on the basis of
environmental justice considerations, EPA nevertheless determined that
this final rule does not have a disproportionately high and adverse
human health or environmental impact on minority or low-income populations.
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). The effective date of the rule is September 1, 2007.
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.
XIII. Statutory Authority
Statutory authority for the rules 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 CAA, 42 U.S.C. 7414, 7542, and 7601(a).
List of Subjects in 40 CFR Part 80
Environmental protection, Air pollution control, Fuel additives,
Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle
pollution, Penalties, Reporting and recordkeeping requirements.
Dated: April 10, 2007.
Stephen L. Johnson,
Administrator.
?
40 CFR part 80 is amended as follows:
PART 80--REGULATION OF FUEL AND FUEL ADDITIVES
? 1. The authority citation for part 80 continues to read as follows:
Authority: 42 U.S.C. 7414, 7542, 7545, and 7601(a).
? 2. Section 80.1100 is revised to read as follows:
Sec. 80.1100 How is the statutory default requirement for 2006 implemented?
(a) Definitions. For calendar year 2006, the definitions of section
80.2 and the following additional definitions apply to this section.
(1) Renewable fuel. (i) Renewable fuel means motor vehicle fuel
that is used to replace or reduce the quantity of fossil fuel present
in a fuel mixture used to operate a motor vehicle, and which:
(A) Is produced from grain, starch, oil seeds, vegetable, animal,
or fish materials including fats, greases, and oils, sugarcane, sugar
beets, sugar components, tobacco, potatoes, or other biomass; or
(B) Is natural gas produced from a biogas source, including a
landfill, sewage waste treatment plant, feedlot, or other place where
decaying organic material is found.
(ii) The term ``renewable fuel'' includes cellulosic biomass
ethanol, waste derived ethanol, biodiesel, and any blending components
derived from renewable fuel.
(2) Cellulosic biomass ethanol means ethanol derived from any
lignocellulosic or hemicellulosic matter that is available on a
renewable or recurring basis, including dedicated energy crops and
trees, wood and wood residues, plants, grasses, agricultural residues,
fibers, animal wastes and other waste materials, and municipal solid
waste. The term also includes any ethanol produced in facilities where
animal wastes or other waste materials are digested or otherwise used
to displace 90 percent or more of the fossil fuel normally used in the
production of ethanol.
(3) Waste derived ethanol means ethanol derived from animal wastes,
including poultry fats and poultry wastes, and other waste materials,
or municipal solid waste.
(4) Small refinery means a refinery for which the average aggregate
daily crude
[[Page 23992]]
oil throughput for a calendar year (as determined by dividing the
aggregate throughput for the calendar year by the number of days in the
calendar year) does not exceed 75,000 barrels.
(5) Biodiesel means a diesel fuel substitute produced from
nonpetroleum renewable resources that meets the registration
requirements for fuels and fuel additives established by the
Environmental Protection Agency under section 211 of the Clean Air Act.
It includes biodiesel derived from animal wastes (including poultry
fats and poultry wastes) and other waste materials, or biodiesel
derived from municipal solid waste and sludges and oils derived from
wastewater and the treatment of wastewater.
(b) Renewable Fuel Standard for 2006. The percentage of renewable
fuel in the total volume of gasoline sold or dispensed to consumers in
2006 in the United States shall be a minimum of 2.78 percent on an
annual average volume basis.
(c) Responsible parties. Parties collectively responsible for
attainment of the standard in paragraph (b) of this section are
refiners (including blenders) and importers of gasoline. However, a
party that is a refiner only because he owns or operates a small
refinery is exempt from this responsibility.
(d) EPA determination of attainment. EPA will determine after the
close of 2006 whether or not the requirement in paragraph (b) of this
section has been met. EPA will base this determination on information
routinely published by the Energy Information Administration on the
annual domestic volume of gasoline sold or dispensed to U.S. consumers
and of ethanol produced for use in such gasoline, supplemented by
readily available information concerning the use in motor fuel of other
renewable fuels such as cellulosic biomass ethanol, waste derived
ethanol, biodiesel, and other non-ethanol renewable fuels.
(1) The renewable fuel volume will equal the sum of all renewable
fuel volumes used in motor fuel, provided that:
(i) One gallon of cellulosic biomass ethanol or waste derived
ethanol shall be considered to be the equivalent of 2.5 gallons of
renewable fuel; and
(ii) Only the renewable fuel portion of blending components derived
from renewable fuel shall be counted towards the renewable fuel volume.
(2) If the nationwide average volume percent of renewable fuel in
gasoline in 2006 is equal to or greater than the standard in paragraph
(b) of this section, the standard has been met.
(e) Consequence of nonattainment in 2006. In the event that EPA
determines that the requirement in paragraph (b) of this section has
not been attained in 2006, a deficit carryover volume shall be added to
the renewable fuel volume obligation for 2007 for use in calculating
the standard applicable to gasoline in 2007.
(1) The deficit carryover volume shall be calculated as follows:
DC = Vgas * (Rs-Ra)
Where:
DC = Deficit carryover, in gallons, of renewable fuel.
Vgas = Volume of gasoline sold or dispensed to U.S. consumers in
2006, in gallons.
Rs = 0.0278.
Ra = Ratio of renewable fuel volume divided by total gasoline volume
determined in accordance with paragraph (d)(2) of this section.
(2) There shall be no other consequence of failure to attain the
standard in paragraph (b) of this section in 2006 for any of the
parties in paragraph (c) of this section.
? 3. Section 80.1101 is added to read as follows:
Sec. 80.1101 Definitions.
The definitions of Sec. 80.2 and the following additional
definitions apply for the purposes of this subpart. For calendar year
2007 and beyond, the definitions in this section Sec. 80.1101 supplant
those in Sec. 80.1100.
(a) Cellulosic biomass ethanol means either of the following:
(1) Ethanol derived from any lignocellulosic or hemicellulosic
matter that is available on a renewable or recurring basis and includes
any of the following:
(i) Dedicated energy crops and trees.
(ii) Wood and wood residues.
(iii) Plants.
(iv) Grasses.
(v) Agricultural residues.
(vi) Animal wastes and other waste materials, the latter of which
may include waste materials that are residues (e.g., residual tops,
branches, and limbs from a tree farm).
(vii) Municipal solid waste.
(2) Ethanol made at facilities at which animal wastes or other
waste materials are digested or otherwise used onsite to displace 90
percent or more of the fossil fuel that is combusted to produce thermal
energy integral to the process of making ethanol, by:
(i) The direct combustion of the waste materials or a byproduct
resulting from digestion of such waste materials (e.g., methane from
animal wastes) to make thermal energy; and/or
(ii) The use of waste heat captured from an off-site combustion
process as a source of thermal energy.
(b) Waste derived ethanol means ethanol derived from either of the
following:
(1) Animal wastes, including poultry fats and poultry wastes, and
other waste materials.
(2) Municipal solid waste.
(c) Biogas means methane or other hydrocarbon gas produced from
decaying organic material, including landfills, sewage waste treatment
plants, and animal feedlots.
(d) Renewable fuel. (1) Renewable fuel is any motor vehicle fuel
that is used to replace or reduce the quantity of fossil fuel present
in a fuel mixture used to fuel a motor vehicle, and is produced from
any of the following:
(i) Grain.
(ii) Starch.
(iii) Oilseeds.
(iv) Vegetable, animal, or fish materials including fats, greases,
and oils.
(v) Sugarcane.
(vi) Sugar beets.
(vii) Sugar components.
(viii) Tobacco.
(ix) Potatoes.
(x) Other biomass.
(xi) Natural gas produced from a biogas source, including a
landfill, sewage waste treatment plant, feedlot, or other place where
there is decaying organic material.
(2) The term ``Renewable fuel'' includes cellulosic biomass
ethanol, waste derived ethanol, biodiesel (mono-alky ester), non-ester
renewable diesel, and blending components derived from renewable fuel.
(3) Ethanol covered by this definition shall be denatured as
required and defined in 27 CFR parts 20 and 21.
(4) Small volume additives (excluding denaturants) less than 1.0
percent of the total volume of a renewable fuel shall be counted as
part of the total renewable fuel volume.
(5) A fuel produced by a renewable fuel producer that is used in
boilers or heaters is not a motor vehicle fuel and therefore is not a
renewable fuel.
(e) Blending component has the same meaning as ``Gasoline blending
stock, blendstock, or component'' as defined at Sec. 80.2(s), for
which the portion that can be counted as renewable fuel is calculated
as set forth in Sec. 80.1115(a).
(f) Motor vehicle has the meaning given in Section 216(2) of the
Clean Air Act (42 U.S.C. 7550).
(g) Small refinery means a refinery for which the average aggregate
daily crude oil throughput for the calendar year 2004 (as determined by
dividing the
[[Page 23993]]
aggregate throughput for the calendar year by the number of days in the
calendar year) does not exceed 75,000 barrels.
(h) Biodiesel (mono-alkyl ester) means a motor vehicle fuel or fuel
additive which is all the following:
(1) Registered as a motor vehicle fuel or fuel additive under 40
CFR part 79.
(2) A mono-alkyl ester.
(3) Meets ASTM D-6751-07, entitled ``Standard Specification for
Biodiesel Fuel Blendstock (B100) for Middle Distillate Fuels.'' ASTM D-
6751-07 is incorporated by reference. This incorporation by reference
was approved by the Director of the Federal Register in accordance with
5 U.S.C. 552(a) and 1 CFR part 51. A copy may be obtained from the
American Society for Testing and Materials, 100 Barr Harbor Drive, West
Conshohocken, Pennsylvania. A copy may be inspected at the EPA Docket
Center, Docket No. EPA-HQ-OAR-2005-0161, EPA/DC, EPA West, Room 3334,
1301 Constitution Ave., NW., Washington, DC, or at the National
Archives and Records Administration (NARA). For information on the
availability of this material at NARA, call 202-741-6030, or go to:
http://www.archives.gov/federal-register/cfr/ibr-locations.html.
(4) Intended for use in engines that are designed to run on
conventional diesel fuel.
(5) Derived from nonpetroleum renewable resources (as defined in
paragraph (m) of this section).
(i) Non-ester renewable diesel means a motor vehicle fuel or fuel
additive which is all the following:
(1) Registered as a motor vehicle fuel or fuel additive under 40
CFR part 79.
(2) Not a mono-alkyl ester.
(3) Intended for use in engines that are designed to run on
conventional diesel fuel.
(4) Derived from nonpetroleum renewable resources (as defined in
paragraph (m) of this section).
(j) Renewable crude means biologically derived liquid feedstocks
including but not limited to poultry fats, poultry wastes, vegetable
oil, and greases that are used as feedstocks to make gasoline or diesel
fuels at production units as specified in paragraph (k) of this section.
(k) Renewable crude-based fuels are renewable fuels that are
gasoline or diesel products resulting from the processing of renewable
crudes in production units within refineries or at dedicated facilities
within refineries, that process petroleum based feedstocks and which
make gasoline and diesel fuel.
(l) Importers. For the purposes of this subpart only, an importer
of gasoline or renewable fuel is:
(1) Any person who brings gasoline or renewable fuel into the 48
contiguous states of the United States from a foreign country or from
an area that has not opted in to the program requirements of this
subpart pursuant to Sec. 80.1143; and
(2) Any person who brings gasoline or renewable fuel into an area
that has opted in to the program requirements of this subpart pursuant
to Sec. 80.1143.
(m) Nonpetroleum renewable resources include, but are not limited
to the following:
(1) Plant oils.
(2) Animal fats and animal wastes, including poultry fats and
poultry wastes, and other waste materials.
(3) Municipal solid waste and sludges and oils derived from
wastewater and the treatment of wastewater.
(n) Export of renewable fuel means:
(1) Transfer of a batch of renewable fuel to a location outside the
United States; and
(2) Transfer of a batch of renewable fuel from a location in the
contiguous 48 states to Alaska, Hawaii, or a United States territory,
unless that state or territory has received an approval from the
Administrator to opt-in to the renewable fuel program pursuant to Sec.
80.1143.
(o) Renewable Identification Number (RIN), is a unique number
generated to represent a volume of renewable fuel pursuant to
Sec. Sec. 80.1125 and 80.1126.
(1) Gallon-RIN is a RIN that represents an individual gallon of
renewable fuel; and
(2) Batch-RIN is a RIN that represents multiple gallon-RINs.
(p) Neat renewable fuel is a renewable fuel to which only de
minimus amounts of conventional gasoline or diesel have been added.
Sec. Sec. 80.1102 through 80.1103 [Reserved]
? 4. Sections 80.1102 and 80.1103 are reserved.
? 5. Sections 80.1104 through 80.1107 are added to read as follows:
Subpart K--Renewable Fuel Standard
* * * * *
Sec.
80.1104 What are the implementation dates for the Renewable Fuel
Standard Program?
80.1105 What is the Renewable Fuel Standard?
80.1106 To whom does the Renewable Volume Obligation apply?
80.1107 How is the Renewable Volume Obligation calculated?
* * * * *
Sec. 80.1104 What are the implementation dates for the Renewable Fuel
Standard Program?
The RFS standards and other requirements of Sec. 80.1101 and all
sections following are effective beginning on September 1, 2007.
Sec. 80.1105 What is the Renewable Fuel Standard?
(a) The annual value of the renewable fuel standard for 2007 shall
be 4.02 percent.
(b) Beginning with the 2008 compliance period, EPA will calculate
the value of the annual standard and publish this value in the Federal
Register by November 30 of the year preceding the compliance period.
(c) EPA will base the calculation of the standard on information
provided by the Energy Information Administration regarding projected
gasoline volumes and projected volumes of renewable fuel expected to be
used in gasoline blending for the upcoming year.
(d) EPA will calculate the annual renewable fuel standard using the
following equation:
[GRAPHIC]
[TIFF OMITTED] TR01MY07.059
Where:
RFStdi = Renewable Fuel Standard, in year i, in percent.
RFVi = Nationwide annual volume of renewable fuels
required by section 211(o)(2)(B) of the Act (42 U.S.C. 7545), for
year i, in gallons.
Gi = Amount of gasoline projected to be used in the 48
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that
is projected to be used in the 48 contiguous states, in year i, in gallons.
GSi = Amount of gasoline projected to be used in
noncontiguous states or territories (if the state or territory opts-
in), in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that
is projected to be used in noncontiguous states or territories (if the
[[Page 23994]]
state or territory opts-in), in year i, in gallons.
GEi = Amount of gasoline projected to be produced by
exempt small refineries and small refiners, in year i, in gallons
(through 2010 only, except to the extent that a small refinery
exemption is extended pursuant to Sec. 80.1141(e)).
Celli = Beginning in 2013, the amount of renewable fuel
that is required to come from cellulosic sources, in year i, in gallons.
(e) Beginning with the 2013 compliance period, EPA will calculate
the value of the annual cellulosic standard and publish this value in
the Federal Register by November 30 of the year preceding the
compliance period.
(f) EPA will calculate the annual cellulosic standard using the
following equation:
[GRAPHIC]
[TIFF OMITTED] TR01MY07.060
Where:
RFCelli = Renewable Fuel Cellulosic Standard in year i,
in percent.
Gi = Amount of gasoline projected to be used in the 48
contiguous states, in year i, in gallons.
Ri = Amount of renewable fuel blended into gasoline that
is projected to be used in the 48 contiguous states, in year i, in gallons.
GSi = Amount of gasoline projected to be used in
noncontiguous states or territories (if the state or territory opts-
in), in year i, in gallons.
RSi = Amount of renewable fuel blended into gasoline that
is projected to be used in noncontiguous states or territories (if
the state or territory opts-in), in year i, in gallons.
Celli = Amount of renewable fuel that is required to come
from cellulosic sources, in year i, in gallons.
Sec. 80.1106 To whom does the Renewable Volume Obligation apply?
(a) (1) An obligated party is a refiner that produces gasoline
within the 48 contiguous states, or an importer that imports gasoline
into the 48 contiguous states. A party that simply adds renewable fuel
to gasoline, as defined in Sec. 80.1107(c), is not an obligated party.
(2) If the Administrator approves a petition of Alaska, Hawaii, or
a United States territory to opt-in to the renewable fuel program under
the provisions in Sec. 80.1143, then ``obligated party'' shall also
include any refiner that produces gasoline within that state or
territory, or any importer that imports gasoline into that state or
territory.
(3) For the purposes of this section, ``gasoline'' refers to any
and all of the products specified at Sec. 80.1107(c).
(b) For each compliance period starting with 2007, any obligated
party is required to demonstrate, pursuant to Sec. 80.1127, that it
has satisfied the Renewable Volume Obligation for that compliance
period, as specified in Sec. 80.1107(a).
(c) An obligated party may comply with the requirements of
paragraph (b) of this section for all of its refineries in the
aggregate, or for each refinery individually.
(d) An obligated party must comply with the requirements of
paragraph (b) of this section for all of its imported gasoline in the
aggregate.
(e) An obligated party that is both a refiner and importer must
comply with the requirements of paragraph (b) of this section for its
imported gasoline separately from gasoline produced by its refinery or
refineries.
(f) Where a refinery or importer is jointly owned by two or more
parties, the requirements of paragraph (b) of this section may be met
by one of the joint owners for all of the gasoline produced at the
refinery, or all of the imported gasoline, in the aggregate, or each
party may meet the requirements of paragraph (b) of this section for
the portion of the gasoline that it owns, as long as all of the
gasoline produced at the refinery, or all of the imported gasoline, is
accounted for in determining the renewable fuels obligation under Sec.
80.1107.
(g) The requirements in paragraph (b) of this section apply to the
following compliance periods:
(1) For 2007, the compliance period is September 1 through December 31.
(2) Beginning in 2008, and every year thereafter, the compliance
period is January 1 through December 31.
Sec. 80.1107 How is the Renewable Volume Obligation calculated?
(a) The Renewable Volume Obligation for an obligated party is
determined according to the following formula:
RVOi = (RFStdi * GVi) + Di-1
Where:
RVOi = The Renewable Volume Obligation for an obligated
party for calendar year i, in gallons of renewable fuel.
RFStdi = The renewable fuel standard for calendar year i,
determined by EPA pursuant to Sec. 80.1105, in percent.
GVi = The non-renewable gasoline volume, determined in
accordance with paragraphs (b), (c), and (d) of this section, which
is produced or imported by the obligated party in calendar year i,
in gallons.
Di-1 = Renewable fuel deficit carryover from the previous
year, per Sec. 80.1127(b), in gallons.
(b) The non-renewable gasoline volume for a refiner, blender, or
importer for a given year, GVi, specified in paragraph (a)
of this section is calculated as follows:
[GRAPHIC]
[TIFF OMITTED] TR01MY07.061
Where:
x = Individual batch of gasoline produced or imported in calendar year i.
n = Total number of batches of gasoline produced or imported in
calendar year i.
Gx = Volume of batch x of gasoline produced or imported,
in gallons.
y = Individual batch of renewable fuel blended into gasoline in
calendar year i.
m = Total number of batches of renewable fuel blended into gasoline
in calendar year i.
RBy = Volume of batch y of renewable fuel blended into
gasoline, in gallons.
(c) All of the following products that are produced or imported
during a compliance period, collectively called ``gasoline'' for the
purposes of this section (unless otherwise specified), are to be
included in the volume used to calculate a party's renewable volume
obligation under paragraph (a) of this section, except as provided in
paragraph (d) of this section:
(1) Reformulated gasoline, whether or not renewable fuel is later
added to it.
(2) Conventional gasoline, whether or not renewable fuel is later
added to it.
(3) Reformulated gasoline blendstock that becomes finished
reformulated gasoline upon the addition of oxygenate (``RBOB'').
(4) Conventional gasoline blendstock that becomes finished
conventional gasoline upon the addition of oxygenate (``CBOB'').
(5) Blendstock (including butane and gasoline treated as blendstock
(``GTAB'')) that has been combined with other blendstock and/or
finished gasoline to produce gasoline.
(6) Any gasoline, or any unfinished gasoline that becomes finished
gasoline upon the addition of oxygenate, that is produced or imported
to comply with a state or local fuels program.
(d) The following products are not included in the volume of
gasoline produced or imported used to calculate a party's renewable
volume obligation under paragraph (a) of this section:
(1) Any renewable fuel as defined in Sec. 80.1101(d).
(2) Blendstock that has not been combined with other blendstock or
finished gasoline to produce gasoline.
(3) Gasoline produced or imported for use in Alaska, Hawaii, the
Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American
Samoa, and the Commonwealth of the Northern Marianas, unless the area
has opted into the RFS program under Sec. 80.1143.
(4) Gasoline produced by a small refinery that has an exemption
under Sec. 80.1141 or an approved small refiner
[[Page 23995]]
that has an exemption under Sec. 80.1142 until January 1, 2011 (or
later, for small refineries, if their exemption is extended pursuant to
Sec. 80.1141(e)).
(5) Gasoline exported for use outside the 48 United States, and
gasoline exported for use outside Alaska, Hawaii, the Commonwealth of
Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the
Commonwealth of the Northern Marianas, if the area has opted into the
RFS program under Sec. 80.1143.
(6) For blenders, the volume of finished gasoline, RBOB, or CBOB to
which a blender adds blendstocks.
(7) The gasoline portion of transmix produced by a transmix
processor, or the transmix blended into gasoline by a transmix blender,
under 40 CFR 80.84.
Sec. Sec. 80.1108 through 80.1114 [Reserved]
? 6. Sections 80.1108 through 80.1114 are reserved.
? 7. Section 80.1115 is added to read as follows:
Sec. 80.1115 How are equivalence values assigned to renewable fuel?
(a)(1) Each gallon of a renewable fuel shall be assigned an
equivalence value by the producer or importer pursuant to paragraph (b)
or (c) of this section.
(2) The equivalence value is a number that is used to determine how
many gallon-RINs can be generated for a batch of renewable fuel
according to Sec. 80.1126.
(b) Equivalence values shall be assigned for certain renewable
fuels as follows:
(1) Cellulosic biomass ethanol and waste derived ethanol produced
on or before December 31, 2012 which is denatured shall have an
equivalence value of 2.5.
(2) Ethanol other than cellulosic biomass ethanol or waste-derived
ethanol which is denatured shall have an equivalence value of 1.0.
(3) Biodiesel (mono-alkyl ester) shall have an equivalence value of 1.5.
(4) Butanol shall have an equivalence value of 1.3.
(5) Non-ester renewable diesel, including that produced from
coprocessing a renewable crude with fossil fuels in a hydrotreater,
shall have an equivalence value of 1.7.
(6) All other renewable crude-based renewable fuels shall have an
equivalence value of 1.0.
(c)(1) For renewable fuels not listed in paragraph (b) of this
section, a producer or importer shall submit an application to the
Agency for an equivalence value following the provisions of paragraph
(d) of this section.
(2) A producer or importer may also submit an application for an
alternative equivalence value pursuant to paragraph (d) of this section
if the renewable fuel is listed in paragraph (b) of this section, but
the producer or importer has reason to believe that a different
equivalence value than that listed in paragraph (b) of this section is
warranted.
(d) Determination of equivalence values. (1) Except as provided in
paragraph (d)(4) of this section, the equivalence value for renewable
fuels described in paragraph (c) of this section shall be calculated
using the following formula:
EV = (R / 0.931) * (EC / 77,550)
Where:
EV = Equivalence Value for the renewable fuel, rounded to the
nearest tenth.
R = Renewable content of the renewable fuel. This is a measure of
the portion of a renewable fuel that came from a renewable source,
expressed as a percent, on an energy basis.
EC = Energy content of the renewable fuel, in Btu per gallon (lower
heating value).
(2) The application for an equivalence value shall include a
technical justification that includes a description of the renewable
fuel, feedstock(s) used to make it, and the production process.
(3) The Agency will review the technical justification and assign
an appropriate Equivalence Value to the renewable fuel based on the
procedure in this paragraph (d).
(4) For biogas, the Equivalence Value is 1.0, and 77,550 Btu of
biogas is equivalent to 1 gallon of renewable fuel.
Sec. Sec. 80.1116 through 80.1124 [Reserved]
? 8. Sections 80.1116 through 80.1124 are reserved.
? 9. Sections 80.1125 through 80.1132 are added to read as follows:
Subpart K--Renewable Fuel Standard
* * * * *
Sec.
80.1125 Renewable Identification Numbers (RINs).
80.1126 How are RINs generated and assigned to batches of renewable
fuel by renewable fuel producers or importers?
80.1127 How are RINs used to demonstrate compliance?
80.1128 General requirements for RIN distribution.
80.1129 Requirements for separating RINs from volumes of renewable
fuel.
80.1130 Requirements for exporters of renewable fuels.
80.1131 Treatment of invalid RINs.
80.1132 Reported spillage of renewable fuel.
* * * * *
Sec. 80.1125 Renewable Identification Numbers (RINs).
Each RIN is a 38 character numeric code of the following form:
KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE
(a) K is a number identifying the type of RIN as follows:
(1) K has the value of 1 when the RIN is assigned to a volume of
renewable fuel pursuant to Sec. Sec. 80.1126(e) and 80.1128(a).
(2) K has the value of 2 when the RIN has been separated from a
volume of renewable fuel pursuant to Sec. 80.1126(e)(4) or Sec. 80.1129.
(b) YYYY is the calendar year in which the batch of renewable fuel
was produced or imported. YYYY also represents the year in which the
RIN was originally generated.
(c) CCCC is the registration number assigned according to Sec.
80.1150 to the producer or importer of the batch of renewable fuel.
(d) FFFFF is the registration number assigned according to Sec.
80.1150 to the facility at which the batch of renewable fuel was
produced or imported.
(e) BBBBB is a serial number assigned to the batch which is chosen
by the producer or importer of the batch such that no two batches have
the same value in a given calendar year.
(f) RR is a number representing the equivalence value of the
renewable fuel as specified in Sec. 80.1115 and multiplied by 10 to
produce the value for RR.
(g) D is a number identifying the type of renewable fuel, as follows:
(1) D has the value of 1 if the renewable fuel can be categorized
as cellulosic biomass ethanol as defined in Sec. 80.1101(a).
(2) D has the value of 2 if the renewable fuel cannot be
categorized as cellulosic biomass ethanol as defined in Sec. 80.1101(a).
(h) SSSSSSSS is a number representing the first gallon-RIN
associated with a batch of renewable fuel.
(i) EEEEEEEE is a number representing the last gallon-RIN
associated with a batch of renewable fuel. EEEEEEEE will be identical
to SSSSSSSS if the batch-RIN represents a single gallon-RIN. Assign the
value of EEEEEEEE as described in Sec. 80.1126.
Sec. 80.1126 How are RINs generated and assigned to batches of
renewable fuel by renewable fuel producers or importers?
(a) Regional applicability. (1) Except as provided in paragraph (b)
of this section, a RIN must be assigned by a renewable fuel producer or
importer to every batch of renewable fuel produced by a facility
located in the contiguous 48 states of the United States, or imported
into the contiguous 48 states.
(2) If the Administrator approves a petition of Alaska, Hawaii, or
a United
[[Page 23996]]
States territory to opt-in to the renewable fuel program under the
provisions in Sec. 80.1143, then the requirements of paragraph (a)(1)
of this section shall also apply to renewable fuel produced or imported
into that state or territory beginning in the next calendar year.
(b) Volume threshold. Renewable fuel producers located within the
United States that produce less than 10,000 gallons of renewable fuel
each year, and importers that import less than 10,000 gallons of
renewable fuel each year, are not required to generate and assign RINs
to batches of renewable fuel. Such producers and importers are also
exempt from the registration, reporting, and recordkeeping requirements
of Sec. Sec. 80.1150-80.1152. However, for such producers and
importers that voluntarily generate and assign RINs, all the
requirements of this subpart apply.
(c) Definition of batch. For the purposes of this section and Sec.
80.1125, a ``batch of renewable fuel'' is a volume of renewable fuel
that has been assigned a unique RIN code BBBBB within a calendar year
by the producer or importer of the renewable fuel in accordance with
the provisions of this section and Sec. 80.1125.
(1) The number of gallon-RINs generated for a batch of renewable
fuel may not exceed 99,999,999.
(2) A batch of renewable fuel cannot represent renewable fuel
produced or imported in excess of one calendar month.
(d) Generation of RINs. (1) Except as provided in paragraph (b) of
this section, the producer or importer of a batch of renewable fuel
must generate RINs for that batch, including any renewable fuel
contained in imported gasoline.
(2) A producer or importer of renewable fuel may generate RINs for
volumes of renewable fuel that it owns on September 1, 2007.
(3) A party generating a RIN shall specify the appropriate
numerical values for each component of the RIN in accordance with the
provisions of Sec. 80.1125 and this paragraph (d).
(4) Except as provided in paragraph (d)(6) of this section, the
number of gallon-RINs that shall be generated for a given batch of
renewable fuel shall be equal to a volume calculated according to the
following formula:
VRIN = EV * Vs
Where:
VRIN = RIN volume, in gallons, for use determining the
number of gallon-RINs that shall be generated.
EV = Equivalence value for the renewable fuel per Sec. 80.1115.
Vs = Standardized volume of the batch of renewable fuel
at 60 [deg]F, in gallons, calculated in accordance with paragraph
(d)(7) of this section.
(5) Multiple gallon-RINs generated to represent a given volume of
renewable fuel can be represented by a single batch-RIN through the
appropriate designation of the RIN volume codes SSSSSSSS and EEEEEEEE.
(i) The value of SSSSSSSS in the batch-RIN shall be 00000001 to
represent the first gallon-RIN associated with the volume of renewable fuel.
(ii) The value of EEEEEEEE in the batch-RIN shall represent the
last gallon-RIN associated with the volume of renewable fuel, based on
the RIN volume determined pursuant to paragraph (d)(4) of this section.
(6) (i) For renewable crude-based renewable fuels produced in a
facility or unit that coprocesses renewable crudes and fossil fuels,
the number of gallon-RINs that shall be generated for a given batch of
renewable fuel shall be equal to the gallons of renewable crude used
rather than the gallons of renewable fuel produced.
(ii) Parties that produce renewable crude-based renewable fuels in
a facility or unit that coprocesses renewable crudes and fossil fuels
may submit a petition to the Agency requesting the use of volumes of
renewable fuel produced as the basis for the number of gallon-RINs,
pursuant to paragraph (d)(4) of this section.
(7) Standardization of volumes. In determining the standardized
volume of a batch of renewable fuel for purposes of generating RINs
under this paragraph (d), the batch volumes shall be adjusted to a
standard temperature of 60 [deg]F.
(i) For ethanol, the following formula shall be used:
Vs,e = Va,e * (-0.0006301 * T + 1.0378)
Where:
Vs,e = Standardized volume of ethanol at 60 [deg]F, in gallons.
Va,e = Actual volume of ethanol, in gallons.
T = Actual temperature of the batch, in [deg]F.
(ii) For biodiesel (mono alkyl esters), the following formula shall
be used:
Vs,b = Va,b * (-0.0008008 * T + 1.0480)
Where:
Vs,b = Standardized volume of biodiesel at 60 [deg]F, in gallons.
Va,b = Actual volume of biodiesel, in gallons.
T = Actual temperature of the batch, in [deg]F.
(iii) For other renewable fuels, an appropriate formula commonly
accepted by the industry shall be used to standardize the actual volume
to 60 [deg]F. Formulas used must be reported to the Agency, and may be
reviewed for appropriateness.
(8) (i) A party is prohibited from generating RINs for a volume of
renewable fuel that it produces if:
(A) The renewable fuel has been produced from a chemical conversion
process that uses another renewable fuel as a feedstock; and
(B) The renewable fuel used as a feedstock was produced by another
party.
(ii) Any RINs that the party acquired with renewable fuel used as a
feedstock shall be assigned to the new renewable fuel that was made
with that feedstock.
(e) Assignment of RINs to batches. (1) Except as provided in
paragraph (e)(4) of this section, the producer or importer of renewable
fuel must assign all RINs generated to volumes of renewable fuel.
(2) A RIN is assigned to a volume of renewable fuel when ownership
of the RIN is transferred along with the transfer of ownership of the
volume of renewable fuel, pursuant to Sec. 80.1128(a).
(3) All assigned RINs shall have a K code value of 1.
(4) RINs not assigned to batches. (i) If a party produces or
imports a batch of cellulosic biomass ethanol or waste-derived ethanol
having an equivalence value of 2.5, that party must assign at least one
gallon-RIN to each gallon of cellulosic biomass ethanol or waste-derived
ethanol, representing the first 1.0 portion of the Equivalence Value.
(ii) Any remaining gallon-RINs generated for the cellulosic biomass
ethanol or waste-derived ethanol which represent the remaining 1.5
portion of the Equivalence Value may remain unassigned.
(iii) The producer or importer of cellulosic biomass ethanol or
waste-derived ethanol shall designate the K code as 2 for all
unassigned RINs.
Sec. 80.1127 How are RINs used to demonstrate compliance?
(a) Renewable volume obligations. (1) Except as specified in
paragraph (b) of this section, each party that is obligated to meet the
Renewable Volume Obligation under Sec. 80.1107, or each party that is
an exporter of renewable fuels that is obligated to meet a Renewable
Volume Obligation under Sec. 80.1130, must demonstrate pursuant to
Sec. 80.1152(a)(1) that it has taken ownership of sufficient RINs to
satisfy the following equation:
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i
+
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
= RVOi
Where:
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i
= Sum of all owned gallon-RINs that were generated in year i and
are being applied towards the RVOi, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
= Sum of all owned gallon-RINs that were generated in year i-1 and
are being applied towards the RVOi, in gallons.
[[Page 23997]]
RVOi = The Renewable Volume Obligation for the obligated
party or renewable fuel exporter for calendar year i, in gallons,
pursuant to Sec. 80.1107 or Sec. 80.1130.
(2) For compliance for calendar years 2008 and later, the value of
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
may not exceed a value determined by the following inequality:
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
<= 0.20 x RVOi
(3) RINs may only be used to demonstrate compliance with the RVO
for the calendar year in which they were generated or the following
calendar year. RINs used to demonstrate compliance in one year cannot
be used to demonstrate compliance in any other year.
(4) A party may only use a RIN for purposes of meeting the
requirements of paragraphs (a)(1) and (a)(2) of this section if that
RIN is an unassigned RIN with a K code of 2 obtained in accordance with
Sec. Sec. 80.1126(e)(4), 80.1128, and 80.1129.
(5) The number of gallon-RINs associated with a given batch-RIN
that can be used for compliance with the RVO shall be calculated from
the following formula:
RINNUM = EEEEEEEE-SSSSSSSS + 1
Where:
RINNUM = Number of gallon-RINs associated with a batch-RIN, where
each gallon-RIN represents one gallon of renewable fuel for
compliance purposes.
EEEEEEEE = Batch-RIN component identifying the last gallon-RIN
associated with the batch-RIN.
SSSSSSSS = Batch-RIN component identifying the first gallon-RIN
associated with the batch-RIN.
(b) Deficit carryovers. (1) An obligated party or an exporter of
renewable fuel that fails to meet the requirements of paragraphs (a)(1)
or (a)(2) of this section for calendar year i is permitted to carry a
deficit into year i+1 under the following conditions:
(i) The party did not carry a deficit into calendar year i from
calendar year i-1.
(ii) The party subsequently meets the requirements of paragraph
(a)(1) of this section for calendar year i+1 and carries no deficit
into year i+2.
(2) A deficit is calculated according to the following formula:
Di RVOi-1
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i+1
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
Where:
Di = The deficit, in gallons, generated in calendar year
i that must be carried over to year i+1 if allowed to do so pursuant
to paragraph (b)(1)(i) of this section.
RVOi = The Renewable Volume Obligation for the obligated
party or renewable fuel exporter for calendar year i, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
= Sum of all acquired gallon-RINs that were generated in year i and
are being applied towards the RVOi, in gallons.
(<3-ln [><5-ln )>{<3-ln ]>RINNUM)i-1
= Sum of all acquired gallon-RINs that were generated in year i-1
and are being applied towards the RVOi, in gallons.
Sec. 80.1128 General requirements for RIN distribution.
(a) RINs assigned to volumes of renewable fuel. (1) Assigned RIN,
for the purposes of this subpart, means a RIN assigned to a volume of
renewable fuel pursuant to Sec. 80.1126(e) with a K code of 1.
(2) Except as provided in Sec. 80.1126(e)(4) and Sec. 80.1129, no
party can separate a RIN that has been assigned to a batch pursuant to
Sec. 80.1126(e).
(3) An assigned RIN cannot be transferred to another party without
simultaneously transferring a volume of renewable fuel to that same party.
(4) No more than 2.5 assigned gallon-RINs with a K code of 1 can be
transferred to another party with every gallon of renewable fuel
transferred to that same party.
(5) (i) On each of the dates listed in paragraph (a)(5)(v) of this
section in any calendar year, the following equation must be satisfied
for assigned RINs and volumes of renewable fuel owned by a party:
<3-ln [><5-ln )>{<3-ln ]>(RIN)D <=
<3-ln [><5-ln )>{<3-ln ]>(Vsi
xEVi)D
Where:
D = Applicable date.
<3-ln [><5-ln )>{<3-ln ]>(RIN)D
= Sum of all assigned gallon-RINs with a K code of 1 that are owned
on date D.
(Vsi)D = Volume i of renewable fuel owned on
date D, standardized to 60 [deg]F, in gallons.
EVi = Equivalence value representing volume i.
<3-ln [><5-ln )>{<3-ln ]>(Vsix
EVi)D = Sum of all volumes of renewable fuel
owned on date D, multiplied by their respective equivalence values.
(ii) The equivalence value EVi for use in the equation
in paragraph (a)(5)(i) of this section for any volume of ethanol shall
be 2.5.
(iii) If the equivalence value for a volume of renewable fuel i can
be determined pursuant to Sec. 80.1115 based on its composition, then
the appropriate equivalence value shall be used for EVi.
(iv) If the equivalence value for a volume of renewable fuel cannot
be determined based on its composition, the value of EVi
shall be 1.0.
(v) The applicable dates are March 31, June 30, September 30, and
December 31. For 2007 only, the applicable dates are September 30, and
December 31.
(6) Producers and importers of renewable fuel. (i) Except as
provided in paragraph (a)(6)(ii) of this section, a producer or
importer of renewable fuel must transfer ownership of a number of
gallon-RINs with a K code of 1 whenever it transfers ownership of a
volume of renewable fuel such that the ratio of gallon-RINs to gallons
is equal to the equivalence value for the renewable fuel.
<3-ln [><5-ln )>{<3-ln ]>(RIN) / Vs = EV
Where:
<3-ln [><5-ln )>{<3-ln ]>(RIN) = Sum of
all gallon-RINs with a K code of 1 which are transferred along with
volume Vs.
Vs = A volume of renewable fuel transferred, standardized
to 60 [deg]F, in gallons.
EV = Equivalence value assigned to the renewable fuel being transferred.
(ii) A producer or importer of renewable fuel can transfer
ownership of a volume of renewable fuel without simultaneously
transferring ownership of gallon-RINs having a K code of 1 if it can
demonstrate one of the following:
(A) It is a small volume producer exempt from the requirement to
generate RINs pursuant to Sec. 80.1126(b); or
(B) The producer or importer received an equivalent volume of
renewable fuel from another party without accompanying RINs.
(C) The producer or importer has generated RINs for cellulosic
biomass ethanol or waste-derived ethanol having an equivalence value of
2.5, and has chosen to specify as unassigned a number of gallon-RINs
pursuant to Sec. 80.1126(e)(4).
(7) Any transfer of ownership of assigned RINs must be documented
on product transfer documents generated pursuant to Sec. 80.1153.
(i) The RIN must be recorded on the product transfer document used
to transfer ownership of the RIN and the volume to another party; or
(ii) The RIN must be recorded on a separate product transfer
document transferred to the same party on the same day as the product
transfer document used to transfer ownership of the volume of renewable
fuel.
(b) RINs not assigned to volumes of renewable fuel. (1) Unassigned
RIN, for the purposes of this subpart, means a RIN with a K code of 2
that has been separated from a volume of renewable fuel pursuant to
Sec. 80.1126(e)(4) or Sec. 80.1129.
(2) Any party that has registered pursuant to Sec. 80.1150 can
hold title to an unassigned RIN.
(3) Unassigned RINs can be transferred from one party to another
any number of times.
(4) An unassigned batch-RIN can be divided by its holder into
multiple batch-RINs, each representing a smaller number of gallon-RINs,
if all of the following conditions are met:
[[Page 23998]]
(i) All RIN components other than SSSSSSSS and EEEEEEEE are
identical for the original parent and newly formed daughter RINs.
(ii) The sum of the gallon-RINs associated with the multiple
daughter batch-RINs is equal to the gallon-RINs associated with the
parent batch-RIN.
Sec. 80.1129 Requirements for separating RINs from volumes of
renewable fuel.
(a)(1) Separation of a RIN from a volume of renewable fuel means
termination of the assignment of the RIN to a volume of renewable fuel.
(2) RINs that have been separated from volumes of renewable fuel
become unassigned RINs subject to the provisions of Sec. 80.1128(b).
(b) A RIN that is assigned to a volume of renewable fuel is
separated from that volume only under one of the following conditions:
(1) Except as provided in paragraph (b)(6) of this section, a party
that is an obligated party according to Sec. 80.1106 must separate any
RINs that have been assigned to a volume of renewable fuel if they own
that volume.
(2) Except as provided in paragraph (b)(5) of this section, any
party that owns a volume of renewable fuel must separate any RINs that
have been assigned to that volume once the volume is blended with
gasoline or diesel to produce a motor vehicle fuel.
(3) Any party that exports a volume of renewable fuel must separate
any RINs that have been assigned to the exported volume.
(4) Any renewable fuel producer or importer that produces or
imports a volume of renewable fuel shall have the right to separate any
RINs that have been assigned to that volume if the producer or importer
designates the renewable fuel as motor vehicle fuel and the renewable
fuel is used as motor vehicle fuel.
(5) RINs assigned to a volume of biodiesel (mono-alkyl ester) can
only be separated from that volume pursuant to paragraph (b)(2) of this
section if such biodiesel is blended into diesel fuel at a
concentration of 80 volume percent biodiesel (mono-alkyl ester) or less.
(i) This paragraph (b)(5) shall not apply to obligated parties or
exporters of renewable fuel.
(ii) This paragraph (b)(5) shall not apply to renewable fuel
producers meeting the requirements of paragraph (b)(4) of this section.
(6) For RINs that an obligated party generates, the obligated party
can only separate such RINs from volumes of renewable fuel if the
number of gallon-RINs separated is less than or equal to its annual RVO.
(7) A producer or importer of cellulosic biomass ethanol or waste-
derived ethanol can separate a portion of the RINs that it generates
pursuant to Sec. 80.1126(e)(4).
(c) The party responsible for separating a RIN from a volume of
renewable fuel shall change the K code in the RIN from a value of 1 to
a value of 2 prior to transferring the RIN to any other party.
(d) (1) Upon and after separation from a renewable fuel volume, a
RIN shall not appear on documentation that is either:
(i) Used to identify title to the volume of renewable fuel; or
(ii) Transferred with the volume of renewable fuel.
(2) Upon and after separation of a RIN from its associated volume,
product transfer documents used to transfer ownership of the volume
must continue to meet the requirements of Sec. 80.1153(a)(5)(iii).
(e) Any obligated party that uses a renewable fuel in a boiler or
heater must retire any RINs associated with that volume of renewable
fuel and report the retired RINs in the applicable reports under Sec.
80.1152.
Sec. 80.1130 Requirements for exporters of renewable fuels.
(a) Any party that owns any amount of renewable fuel (in its neat
form or blended with gasoline or diesel) that is exported from the
region described in Sec. 80.1126(a) shall acquire sufficient RINs to
offset a Renewable Volume Obligation representing the exported
renewable fuel.
(b) Renewable Volume Obligations. An exporter of renewable fuel
shall determine its Renewable Volume Obligation from the volumes of the
renewable fuel exported.
(1) A renewable fuel exporter's total Renewable Volume Obligation
shall be calculated according to the following formula:
RVOi = [Sgr](VOLk * EVk)i +
Di-1
Where:
RVOi = The Renewable Volume Obligation for the exporter
for calendar year i, in gallons of renewable fuel.
k = A discrete volume of renewable fuel.
VOLk = The standardized volume of discrete volume k of
exported renewable fuel, in gallons, calculated in accordance with
Sec. 80.1126(d)(7).
EVk = The equivalence value associated with discrete volume k.
[Sgr]
= Sum involving all volumes of renewable fuel exported.
Di-1 = Renewable fuel deficit carryover from the
previous year, in gallons.
(2)(i) If the equivalence value for a volume of renewable fuel can
be determined pursuant to Sec. 80.1115 based on its composition, then
the appropriate equivalence value shall be used in the calculation of
the exporter's Renewable Volume Obligation.
(ii) If the equivalence value for a volume of renewable fuel cannot
be determined, the value of EVk shall be 1.0.
(c) Each exporter of renewable fuel must demonstrate compliance
with its RVO using RINs it has acquired pursuant to Sec. 80.1127.
Sec. 80.1131 Treatment of invalid RINs.
(a) Invalid RINs. An invalid RIN is a RIN that is any of the following:
(1) Is a duplicate of a valid RIN.
(2) Was based on volumes that have not been standardized to 60 [deg]F.
(3) Has expired.
(4) Was based on an incorrect equivalence value.
(5) Is deemed invalid under Sec. 80.1167(g).
(6) Does not represent renewable fuel as it is defined in Sec. 80.1101.
(7) Was otherwise improperly generated.
(b) In the case of RINs that are invalid, the following provisions apply:
(1) Invalid RINs cannot be used to achieve compliance with the
Renewable Volume Obligation of an obligated party or exporter,
regardless of the party's good faith belief that the RINs were valid at
the time they were acquired.
(2) Upon determination by any party that RINs owned are invalid,
the party must adjust their records, reports, and compliance
calculations as necessary to reflect the deletion of the invalid RINs.
(3) Any valid RINs remaining after deleting invalid RINs must first
be applied to correct the transfer of invalid RINs to another party
before applying the valid RINs to meet the party's Renewable Volume
Obligation at the end of the compliance year.
(4) In the event that the same RIN is transferred to two or more
parties, all such RINs will be deemed to be invalid, unless EPA in its
sole discretion determines that some portion of these RINs is valid.
Sec. 80.1132 Reported spillage of renewable fuel.
(a) A reported spillage under paragraph (d) of this section means a
spillage of renewable fuel associated with a requirement by a federal,
state or local authority to report the spillage.
(b) Except as provided in paragraph (c) of this section, in the
event of a reported spillage of any volume of renewable fuel, the owner
of the renewable fuel must retire a number of gallon-RINs corresponding
to the volume of spilled renewable fuel multiplied by its equivalence
value.
[[Continued on page 23999]]
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