Agriculture-Based Biofuels:
Overview and Emerging Issues
Randy Schnepf
Specialist in Agricultural Policy
January 20, 2012
Congressional Research Service
7-5700
www.crs.gov
R41282
CRS Report for Congress
Pr
epared for Members and Committees of Congress

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Agriculture-Based Biofuels: Overview and Emerging Issues

Summary
Since the late 1970s, U.S. policymakers at both the federal and state levels have enacted a variety
of incentives, regulations, and programs to encourage the production and use of agriculture-based
biofuels. Initially, federal biofuels policies were developed to help kick-start the biofuels industry
during its early development, when neither production capacity nor a market for the finished
product was widely available. Federal policy has played a key role in helping to close the price
gap between biofuels and cheaper petroleum fuels. Now, as the industry has evolved, other policy
goals (e.g., national energy security, climate change concerns, support for rural economies) are
cited by proponents as justification for continuing policy support.
The U.S. biofuels sector has responded to these government incentives by expanding output every
year since 1980 (with the exception of 1996), with important implications for the domestic and
international food and fuel sectors. The production of ethanol (the primary biofuel produced in
the United States) has risen from about 175 million gallons in 1980 to nearly 14 billion gallons in
2011. U.S. biodiesel production, albeit much smaller, has also shown strong growth, rising from
0.5 million gallons in 1999 to a projected 800 million gallons in 2011.
Despite this rapid growth, total agriculture-based biofuels production accounted for only about
8% of U.S. transportation fuel consumption (gasoline and diesel combined) on a volume basis
and 6% on a gasoline-equivalent basis in 2011. Federal biofuels policies have had costs, including
unintended market and environmental consequences and large federal outlays (estimated at over
$6 billion in 2011). Despite the direct and indirect costs of federal biofuels policy and the
relatively small role of biofuels as an energy source, the U.S. biofuels sector continues to push for
federal involvement. But critics of federal policy intervention in the biofuels sector have also
emerged.
Current issues and policy developments related to the U.S. biofuels sector that are of interest to
Congress include the following:
• Many federal biofuels policies (e.g., tax credits and import tariffs) require routine
congressional monitoring and occasional reconsideration in the form of
reauthorization or new appropriations funding.
• The 10% ethanol-to-gasoline blend ratio—known as the “blend wall”—poses a
barrier to expansion of ethanol use. The Environmental Protection Agency (EPA),
has issued waivers to allow ethanol blending of up to 15% (per gallon of
gasoline) for use in model year 2001 and newer light-duty motor vehicles.
However, the limitation to newer vehicles, coupled with infrastructure issues, is
likely to limit rapid expansion of blending rates.
• The slow development of cellulosic biofuels has raised concerns about the
industry’s ability to meet large federal usage mandates, which in turn has raised
the potential for future EPA waivers of mandated biofuel volumes and has
contributed to a cycle of slow investment in and development of the sector.
Several trade issues (including European Union anti-dumping and countervailing duty
proceedings against imports of U.S. ethanol precipitated by surging U.S. ethanol exports)
emerged in 2011 that, if realized, could slow further development of the U.S. biofuels sector.
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Contents
Introduction...................................................................................................................................... 1
Federal Biofuels Policies Have Encouraged Rapid Growth ..................................................... 1
... And Conflicting Viewpoints .................................................................................................. 2
Biofuels Defined.............................................................................................................................. 3
Ethanol from Corn Starch Dominates U.S. Biofuels Production .............................................. 4
Biofuels Value Determinants ..................................................................................................... 5
Evolution of the U.S. Ethanol Sector............................................................................................... 6
Federal Policy Kick-Starts Ethanol Production......................................................................... 6
Government Role Has Grown Since 2000 .......................................................................... 7
The Ethanol Industry’s Perfect Storm in 2005 .................................................................... 8
EISA Greatly Expands Mandate, Shifts Focus to Cellulosic Biofuels.............................. 10
2008 Farm Bill Reinforces Focus on Cellulosic Biofuels................................................. 12
Questions Emerge Concerning Rapid Biofuels Expansion ..................................................... 13
Ethanol Production Capacity Centered on Corn Belt .............................................................. 14
Evolution of the U.S. Biodiesel Sector .......................................................................................... 15
U.S. Biodiesel Industry Starts Late, Grows Slowly................................................................. 16
Biodiesel Production Capacity Spreads Nationwide ............................................................... 18
U.S. Retail Delivery Infrastructure and Vehicle Fleet ................................................................... 19
Flex-Fuel vs. Standard Ethanol-Gasoline Blend Vehicles ....................................................... 20
Ruling on the Ethanol-to-Gasoline Blending Limit: 10% vs. 15% ......................................... 21
FFV Fleet and E85 Pump Availability as Limiting Factors..................................................... 22
Federal Programs That Support Biofuels....................................................................................... 23
Tax Credits............................................................................................................................... 23
Import Tariff on Foreign-Produced Ethanol ............................................................................ 24
The Renewable Fuel Standard (RFS) ...................................................................................... 24
Other Indirect Federal Policies................................................................................................ 25
Current Biofuels Policy Issues....................................................................................................... 26
Pending Congressional Actions............................................................................................... 26
2008 Farm Bill Expiration................................................................................................. 26
Cellulosic Biofuels Tax Credit .......................................................................................... 27
Cellulosic Biofuels Feedstock Program: BCAP................................................................ 27
Pending EPA Actions............................................................................................................... 27
Waiver of Mandated Use Requirements............................................................................ 27
Estimation of GHG Emission Reductions......................................................................... 28
Endangerment Findings for Greenhouse Gases (GHGs)................................................... 29
Other Pending or Emerging Biofuels Issues............................................................................ 29
CARB’s LCFS Restriction on Midwestern Ethanol.......................................................... 29
Trade Issues....................................................................................................................... 30

Figures
Figure 1. Biofuels Were a Small Share of U.S. Motor Transportation Fuel Use in 2011 ................ 2
Figure 2. Annual U.S. Ethanol Production, Historical and Projected, 1980 to 2015....................... 6
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Figure 3. Annual U.S. Corn Use by Major Activity, 1980 to 2011.................................................. 9
Figure 4. Renewable Fuels Standard (RFS2) vs. U.S. Ethanol Production Since 1995 ................ 11
Figure 5. Monthly Farm Prices for Corn, Soybeans, and Crude Oil, 2000 to 2011....................... 12
Figure 6. U.S. Ethanol Production Capacity Is Centered on the Corn Belt ................................... 14
Figure 7. Annual U.S. Biodiesel Production, 1999 to 2015........................................................... 17
Figure 8. E85 Refueling Locations by State .................................................................................. 22
Figure 9. U.S. Ethanol Exports Surge in 2011............................................................................... 32

Tables
Table 1. U.S. Corn-Use Share of Annual Production by Major Activity, 1980 to 2011 ................ 10
Table 2. U.S. Ethanol Output and Production Capacity by State................................................... 15
Table 3. U.S. Biodiesel Production Capacity Partial Estimate as of January 12, 2012 ................. 19
Table 4. Federal Tax Credits Available for Qualifying Biofuels.................................................... 24

Contacts
Author Contact Information........................................................................................................... 33

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Introduction
Increasing dependence on foreign sources of crude oil, concerns over global climate change, and
the desire to promote domestic rural economies have raised interest in renewable biofuels as an
alternative to petroleum in the U.S. transportation sector. However, energy from renewable
sources has historically been more expensive to produce and use than fossil-fuel-based energy.1
U.S. policymakers have attempted to overcome this economic impediment by enacting an
increasing number of policies since the late 1970s, at both the state and federal levels, to directly
support U.S. biofuels production and use. Policy measures have included blending and production
tax credits to lower the cost of biofuels to end users, an import tariff to protect domestic ethanol
from cheaper foreign-produced ethanol, research grants to stimulate the development of new
technologies, loans and loan guarantees to facilitate the development of biofuels production and
distribution infrastructure, and, perhaps most importantly, minimum usage requirements to
guarantee a market for biofuels irrespective of their cost.2
This report reviews the evolution of the U.S. biofuels sector and the role that federal policy has
played in shaping its development.3 In addition, it highlights emerging issues that are critical to
the biofuels sector and of relevance to Congress.
Federal Biofuels Policies Have Encouraged Rapid Growth ...
Federal biofuels programs have proven critical to the economic success of the U.S. biofuels
industry, primarily ethanol and biodiesel, whose output has grown rapidly in recent years. Yet,
despite the rapid growth, U.S. biofuels consumption remains a small share (5.9% on an energy-
equivalent basis in 2011) of national transportation fuel use (Figure 1).
Furthermore, the sector remains heavily dependent on federal policies that, concomitant with the
growth in U.S. biofuels production, have required rapidly increasing federal budget outlays. In
2011, the estimated annual cost of direct federal support for biofuels production and use was
estimated at over $6 billion. In addition, the rapid expansion of U.S. corn ethanol production to
meet the dramatic rise in corn use for ethanol (the U.S. Department of Agriculture estimates that
40% of both 2010 and 2011 U.S. corn production was used for ethanol production) has provoked
questions about its long-run sustainability and the possibility of unintended consequences in other
markets as well as for the environment.4
It is widely believed that the ultimate success of the U.S. biofuels sector will depend on its ability
to shift away from traditional row crops such as corn or soybeans for processing feedstock, and
toward other, cheaper forms of biomass that do not compete with traditional food crops. Recent
federal biofuels policies have attempted to assist this shift by focusing on the development of a

1 Excluding the costs of externalities (e.g., air pollution, environmental degradation, illness and disease, or indirect land
use changes and market-price effects) linked to emissions associated with burning either fossil fuels or biofuels.
2 For more details and a complete listing of federal biofuels programs and incentives, see CRS Report R40110, Biofuels
Incentives: A Summary of Federal Programs.
3 For background information on agriculture-based U.S. biofuels, see the list of related CRS Reports available at the
CRS website “Issues in Focus: Agriculture: Agriculture-Based Biofuels.”
4 See CRS Report R40155, Renewable Fuel Standard (RFS): Overview and Issues.
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cellulosic biofuels industry.5 However, the speed of cellulosic biofuels development remains a
major uncertainty, since new technologies must first emerge and be implemented on a
commercial scale.6 The uncertainty surrounding the development of such new technologies and
their commercial adaptation has been a major impediment to the flow of much needed private-
sector investment funds into the cellulosic biofuels sector.
Figure 1. Biofuels Were a Small Share of U.S. Motor Transportation Fuel Use in 2011
150
Ethanol
(7% share)
100
allons
Biodiesel
(2% share)
illion G
B 50
0
Gasoline
Diesel

Sources: Ethanol use: Renewable Fuels Association; Biodiesel and total motor vehicle fuel use: Energy
Information Agency (EIA), Department of Energy (DOE).
Note: All data are in gasoline-equivalent gallons (GEG).
... And Conflicting Viewpoints
The trade-offs between benefits to farm and rural economies, as opposed to large federal budget
costs and the potential for unintended consequences, have led to emergence of both proponents
and critics of the government subsidies and mandates that underwrite biofuels production.
Proponents of government support for agriculture-based biofuels production have cited national
energy security, reductions in greenhouse gas emissions, and raising domestic demand for U.S.-
produced farm products as viable justifications. In many cases, biofuels are more environmentally
friendly (in terms of emissions of toxins, volatile organic compounds, and greenhouse gases) than

5 Cellulosic biofuels are derived from the sugar contained in plant cellulose. For more information, see CRS Report
RL34738, Cellulosic Biofuels: Analysis of Policy Issues for Congress.
6 See CRS Report R41460, Cellulosic Ethanol: Feedstocks, Conversion Technologies, Economics, and Policy Options,
and CRS Report R41106, Meeting the Renewable Fuel Standard (RFS) Mandate for Cellulosic Biofuels: Questions and
Answers.
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petroleum products. In addition, proponents argue that rural, agriculture-based energy production
can enhance rural incomes and expand employment opportunities, while encouraging greater
value-added for U.S. agricultural commodities.7
In contrast, critics argue that, in the absence of subsidies, current biofuels production strategies
can only be economically competitive with existing fossil fuels at much higher petroleum prices,
or if significant improvements in existing technologies are made or new technologies are
developed.8 Until such technological breakthroughs are achieved, critics contend that the
subsidies distort energy market incentives and divert research funds from the development of
other renewable energy sources, such as solar or geothermal, that offer potentially cleaner, more
bountiful alternatives. Still others question the rationale behind policies that promote biofuels for
energy security. These critics question whether the United States could ever produce sufficient
feedstock of starches, sugars, or vegetable oils to permit biofuels production to meaningfully
offset petroleum imports.9 Finally, some argue that the focus on development of alternative
energy sources undermines efforts for greater conservation to reduce energy waste.
Biofuels Defined
Any fuel produced from biological materials—whether burned for heat or processed into
alcohol—qualifies as a “biofuel.” However, the term is most often used to refer to liquid
transportation fuels produced from some type of biomass. Biomass is organic matter that can be
converted into energy. Common examples of biomass include food crops, crops for energy (e.g.,
switchgrass or prairie perennials), crop residues, wood waste and byproducts, and animal manure.
The term biomass has been a part of legislation enacted by Congress for various programs over
the past 30 years; however, its explicit definition has evolved with shifting policy objectives.10
Over the last few years, the concept of biomass has grown to include such diverse sources as
algae, construction debris, municipal solid waste, yard waste, and food waste. The exact
definition of biomass is critical, since it determines which feedstocks qualify for the different
biofuels programs. For example, a current point of contention regarding the definition is the
inclusion of biomass from federal lands. Some argue that removal of biomass from these lands
may lead to ecological harm. Another example involves algae-based biofuels, which presently do
not qualify for inclusion under cellulosic biofuels usage mandates, but do qualify for the
“advanced other” biofuels mandate.11 This differentiation may slow or inhibit investments in
algae-based biofuels.

7 Examples of ethanol policy proponents include the Renewable Fuels Association (RFA), the National Corn Growers
Association (NCGA), and Growth Energy. Biodiesel proponents include the American Soybean Association and the
National Biodiesel Board.
8 Advocates of this position include free-market proponents such as the Cato Institute, federal budget watchdog groups
such as Citizens Against Government Waste, Taxpayers for Common Sense, and farm subsidy watchdog groups such
as the Environmental Working Group.
9 For example, see James and Stephen Eaves, “Is Ethanol the ‘Energy Security’ Solution?” editorial,
Washingtonpost.com, October 3, 2007; or R. Wisner and P. Baumel, “Ethanol, Exports, and Livestock: Will There be
Enough Corn to Supply Future Needs?,” Feedstuffs, no. 30, vol. 76, July 26, 2004.
10 See CRS Report R40529, Biomass: Comparison of Definitions in Legislation Through the 111th Congress.
11 See CRS Report R42122, Algae’s Potential as a Transportation Biofuel.
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Types of biofuels include ethanol, biodiesel, methanol, and butanol; however, the two principal
biofuels are ethanol and biodiesel. Ethanol, or ethyl alcohol, is an alcohol made by fermenting
and distilling simple sugars.12 As a result, ethanol can be produced from any biological feedstock
that contains appreciable amounts of sugar or materials that can be converted into sugar such as
starch or cellulose. Sugar beets and sugar cane are examples of feedstock that contain sugar. Corn
contains starch that can relatively easily be converted into sugar. Trees, grasses, and most
agricultural and municipal wastes are made up of a significant percentage of cellulose, which can
also be converted to sugar, although with more difficulty than is required to convert starch.
Ethanol from Corn Starch Dominates U.S. Biofuels Production
Since its development in the late 1970s, U.S. biofuels output has relied almost exclusively on
ethanol produced from corn starch. Small amounts of ethanol have been produced using sorghum,
wheat, barley, and brewery waste. This contrasts with Brazil, the world’s second-largest ethanol
producer behind the United States, where sugar cane is the principal feedstock. In 2010, the
United States and Brazil accounted for 88% of the world’s ethanol production.13 Approximately
13.2 billion gallons of ethanol were produced in the United States in 2010, over 95% from corn
starch. Other domestic feedstocks used for ethanol production include grain sorghum and sweet
sorghum.
Because of concerns over the significant expansion in corn production for use as an ethanol
feedstock, interest has grown in spurring the development of motor fuels produced from
cellulosic biomass materials. Since these biomass sources do not compete with traditional food
and feed crops for prime cropland, it is thought that their use would result in substantially fewer
unintended market effects. However, the technology needed for the conversion of cellulose into
its constituent sugars before conversion to biofuels, while successful in laboratory settings,
remains expensive and has yet to be replicated on a commercial scale. Many uncertainties remain
concerning both the viability and the speed of commercial development of cellulosic biofuels.14
After ethanol, biodiesel is the next most significant biofuel in the United States. Biodiesel is an
alternative diesel fuel that can be produced from any type of organic-based oil, including
vegetable oils, animal fats, and waste restaurant grease and oils. In the United States and Brazil,
biodiesel was traditionally made from soybean oil. In the European Union, rapeseed oil is the
primary feedstock. However, persistently high vegetable oil prices have pushed biodiesel
producers to refocus on much cheaper animal fats (especially poultry fat) and tropical palm oil.
Other biofuels with the potential to play a role in the U.S. market include diesel fuel substitutes
and other alcohols (e.g., methanol and butanol) produced from biomass. In addition to expanding
domestic production of biofuels, there is some interest in expanding imports of sugar-based
ethanol—usually produced from sugar cane in Brazil. U.S. sugar-ethanol imports peaked at
660 million gallons in 2006 (including 434 million from Brazil). Recent market factors—U.S.
ethanol production approaching the “blend wall”, high international sugar prices, lower-than-

12 See CRS Report RL33290, Fuel Ethanol: Background and Public Policy Issues.
13 According to data from the Renewable Fuel Association, U.S. ethanol production in 2010 was 13.231 billion gallons,
Brazil’s was 6.922 billion gallons, and the world total was 22.947 billion gallons.
14 See CRS Report RL34738, Cellulosic Biofuels: Analysis of Policy Issues for Congress.
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expected sugarcane output in Brazil, and a weak U.S. dollar—have resulted in the United States
becoming a net exporter of ethanol during 2010 and 2011.15
Biofuels Value Determinants
The value of a biofuel is determined by its end use. Biodiesel’s primary use is as a substitute for
petroleum-based diesel fuel. Ethanol is primarily used as a substitute for gasoline; however, it has
some additional properties (i.e., oxygenate and octane enhancer) that provide value as a gasoline
additive. Both ethanol and biodiesel may derive value as an additive to meet federal usage
mandates depending on market conditions. A federal usage mandate (referred to as a Renewable
Fuel Standard or RFS) was first introduced in 2006 by the Energy Policy Act of 2005 (P.L. 109-
58), which required that a gradually increasing minimum volume of biofuel must be blended into
the national transportation fuel supply each year.16
With respect to ethanol, there is no difference to the end user between corn-starch ethanol and
cellulosic ethanol, although their production processes differ substantially in terms of feedstock,
technology, and cost. As a result, they both share the same value determinants. In the presence of
government policy, demand for ethanol derives from four potential uses:17
• as an additive to gasoline to enhance its octane level;
• as an oxygenate to help improve engine combustion and cleaner burning of fuel;
• as an additive to gasoline to meet federally mandated minimum usage
requirements under the RFS; or
• as a substitute for gasoline, either blended with gasoline as a fuel extender at low
blend levels (e.g., 10% ethanol to 90% gasoline, known as E10), or in pure
(E100) or near pure (E85) form in flexible fuel vehicles.
Ethanol’s use as an additive for octane or oxygenate purposes occurs primarily at low blend levels
of 2% or 3%, and is small relative to the growth in total usage of recent years. When ethanol is
being added to enhance engine performance rather than as a fuel extender, it is a complement to
gasoline and may potentially capture a price premium over standard gasoline.
Federal policy that mandates the use of a minimum volume of biofuel creates a further source of
demand that behaves very much as though ethanol were a fuel additive like an oxygenate or
octane enhancer. Demand for biofuels to fulfill a mandate is not based on price, but rather on
government fiat. As long as the consumption of biofuels is less than the mandated volume, its use
is obligatory. However, when the supply of biofuels exceeds the mandated usage volume, its use
is no longer obligatory and it must compete directly in the marketplace with its petroleum-based
counterpart. As a result, once they have met their RFS blending mandates, gasoline blenders,
seeking to maximize their profits, are very sensitive to ethanol and gasoline price relationships.
Since 2006, when the RFS was first introduced, both ethanol production capacity and supply
(production and imports combined) have easily exceeded the federally mandated usage levels

15 Based on official statistics from the International Trade Commission, Dept. of Commerce.
16 This is described in greater detail later in this report, in the section titled “Evolution of the U.S. Ethanol Sector.”
17 See CRS Report RL33290, Fuel Ethanol: Background and Public Policy Issues.
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(Figure 2). As a result, ethanol’s principal value has been as a transportation fuel (rather than as
an additive), where it competes directly with gasoline. Furthermore, since ethanol contains only
about 68% of the energy content of gasoline, value-conscious consumers can be expected to
willingly pay only about 68% of the price of gasoline for ethanol.
Figure 2. Annual U.S. Ethanol Production, Historical and Projected, 1980 to 2015
15 Billion Gallons
Production Capacity
12
RFS2
RFS2 established
9
Hurricane Katrina;
RFS1 established
6
MTBE Phase Out
RFS1
Bioenergy Program
3
begins payments
Historical
Projected
0
1980
1985
1990
1995
2000
2005
2010
2015
Source: 1980-2010, Renewable Fuels Association. Projections for 2011-2015 are from CRS.
Note: RFS2 shown in the chart includes projections for both corn-starch and cel ulosic ethanol production.
Evolution of the U.S. Ethanol Sector
Federal Policy Kick-Starts Ethanol Production
Several events contributed to the historical startup and growth of U.S. ethanol production in the
late 1970s. First, the global energy crises of the early and late 1970s provided the rationale for a
federal policy initiative aimed at promoting energy independence from foreign crude oil sources.
In response, the U.S. Congress established a partial exemption for ethanol from the motor fuels
excise tax (legislated as part of the Energy Tax Act of 1978). All ethanol blended in the United
States—whether imported or produced domestically—was eligible for a $0.40 per gallon tax
credit. In 1980, an import duty for fuel ethanol was established by the Omnibus Reconciliation
Act of 1980 (P.L. 96-499) to offset the domestic tax credit being applied to foreign-sourced
ethanol.
As U.S. ethanol production began to emerge in the 1980s, ethanol became recognized as a
gasoline oxygenate. The Deficit Reduction Act of 1984 raised the ethanol tax credit to $0.60 per
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gallon.18 Based on its oxygenate characteristic, provisions of the Clean Air Act Amendments of
1990 (CAAA90) favored ethanol blending with reformulated gasoline (RFG).19 One of the
requirements of RFG specified by CAAA90 was a 2% oxygen requirement, which was met by
blending “oxygenates,” including methyl tertiary butyl ether (MTBE) and ethanol into the
gasoline.20 Ethanol was the preferred oxygenate in the Midwest where it was produced, while
MTBE was used in almost all RFG outside of the Midwest.
In addition to CAAA90 oxygenate requirements, a small ethanol producer tax credit was
established in 1990 (Omnibus Budget Reconciliation Act of 1990; P.L. 101-508) as a $0.10 per
gallon supplement to the existing ethanol tax credit, but limited to the first 15 million gallons of
ethanol produced by ethanol producers with production capacity below 30 million gallons per
year.21 Aided by these events, the U.S. ethanol industry slowly grew during its first two decades—
rising from an estimated 175 million gallons in 1980 to 1.8 billion gallons in 2001. By 2001,
ethanol production was using about 7% of the U.S. corn crop.
Government Role Has Grown Since 2000
The first decade of the 2000s experienced a substantial increase in federal involvement in the
U.S. biofuels sector. In FY2001, the Bioenergy Program22 began making payments from the U.S.
Department of Agriculture’s (USDA’s) Commodity Credit Corporation (CCC)23 to eligible biofuel
producers—ethanol and biodiesel—based on any year-to-year increases in the quantity of biofuels
produced. The Bioenergy Program was instituted by USDA because the program’s principal goal
was to encourage greater purchases of eligible farm commodities used in the production of
biofuels (e.g., corn for ethanol or soybean oil for biodiesel).
The executive order creating the Bioenergy Program was followed by a series of legislation
containing various provisions that further aided the U.S. biofuels industry. The first of these, the
Biomass Research and Development Act of 2000 (Biomass Act; Title III, P.L. 106-224),
contained several provisions to expand research and development in the area of biomass-based
renewable fuel production.
The 2002 farm bill (P.L. 107-171) included several biofuels programs spread across three separate
titles—Title II: Conservation, Title VI: Rural Development, and Title IX: Energy (the first-ever
energy title in a farm bill). Each title contained programs that encouraged the research,

18 “Ethanol Policy: Past, Present, and Future,” by James A. Duffield, Irene M. Xiarchos, and Steve A. Halbrook, South
Dakota Law Review, Fall 2008.
19 USDA, Office of Energy Policy and New Uses, The Energy Balance of Corn Ethanol: An Update, AER-813, by
Hosein Shapouri, James A. Duffield, and Michael Wang, July 2002.
20 “Status and Impact of State MTBE Ban,” Energy Information Administration (EIA), U.S. Dept. of Energy (DOE),
revised March 27, 3003; available at http://www.eia.doe.gov/oiaf/servicerpt/mtbeban/.
21 The 30 million gallon threshold was extended to 60 million gallons by the Energy Policy Act of 2005 (P.L. 109-58).
22 The Bioenergy Program was initiated on August 12, 1999, by President Clinton’s Executive Order 13134. On
October 31, 2000, then-Secretary of Agriculture Glickman announced that, pursuant to the executive order, $300
million of Commodity Credit Corporation (CCC) funds ($150 million in both FY2001 and FY2002) would be made
available to encourage expanded production of biofuels.
23 The CCC is a U.S. government-owned and -operated corporation, created in 1933, with broad powers to support farm
income and prices and to assist in the export of U.S. agricultural products. Toward this end, the CCC finances USDA’s
domestic price and income support programs and its export programs using its permanent authority to borrow up to $30
billion at any one time from the U.S. Treasury.
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production, and use of renewable fuels such as ethanol, biodiesel, anaerobic digesters, and wind
energy systems. In addition, Section 9010 of Title IX codified and extended the Bioenergy
Program and its funding by providing that $150 million would be available annually through the
CCC for FY2003-FY2006.24
The Healthy Forests Restoration Act of 2003 (P.L. 108-148) amended the Biomass Act of 2000 by
expanding the use of grants, contracts, and assistance for biomass to include a broader range of
forest management activities. It also expanded funding availability of programs established by the
Biomass Act and the 2002 farm bill, and it established a program to accelerate adoption of
biomass-related technologies through community-based marketing and demonstration activities,
and to establish small-scale businesses to use biomass materials.
The American Jobs Creation Act of 2004 (P.L. 108-357) contained a provision (Section 301) that
replaced the existing tax exemptions for alcohol fuels (i.e., ethanol) with an excise tax credit of
$0.51 per gallon. This act also extended the small ethanol producer tax credit.
In addition to a growing list of federal and state policies, the U.S. biofuels industry received an
additional boost in the early 2000s with the emergence of water contamination problems
associated with MTBE in several locations scattered throughout the country. MTBE was thought
to be a possible carcinogen and, as a result, posed serious health and liability issues. In 1999,
California (which, at the time, consumed nearly 32% of MTBE in the United States) petitioned
the U.S. Environmental Protection Agency (EPA) for a waiver of the CAAA90 oxygenate
requirement.25 However, California’s waiver request was denied by the EPA in mid-2001 since
the EPA determined that there was sufficient ethanol production available to replace MTBE.
By 2003, legislation that would phase out or restrict the use of MTBE in gasoline had been passed
in 16 states, including California and New York (with a combined 40% national MTBE market
share).26 Between October 1, 2003, and January 1, 2004, over 43% of MTBE consumption in the
United States was banned. According to the EIA, the state MTBE ban would require an additional
demand for ethanol of 2.73 billion gallons in 2004.
With the legislative boosts and the MTBE phase-out, investments in the biofuels sector began to
show results. The number of plants producing ethanol grew from 50 on January 1, 1999, to 81 by
January 1, 2005. Concomitantly, U.S. ethanol production began to accelerate, rising to 3.9 billion
gallons by 2005 and using over 14% of the nation’s corn crop (Figure 2, Figure 3, and Table 1).
The Ethanol Industry’s Perfect Storm in 2005
On the heels of the large MTBE phase-out that occurred in 2004 and the surge in ethanol demand,
two major events coincided in 2005 to produce extremely favorable economic conditions in the
U.S. ethanol sector that persisted through most of 2006. These events included the following.
• The Energy Policy Act of 2005 (EPACT; P.L. 109-58) was signed into law on
August 8, 2005. EPACT contained several provisions related to agriculture-based

24 The Bioenergy Program was phased out at the end of FY2006.
25 “Status and Impact of State MTBE Ban,” Energy Information Administration (EIA), U.S. Dept. of Energy (DOE),
revised March 27, 3003; available at http://www.eia.doe.gov/oiaf/servicerpt/mtbeban/.
26 Ibid.
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renewable energy production, including biofuels research and funding,
expansions of existing biofuels tax credits and creation of new credits, and the
creation of the first-ever national minimum-usage mandate, the Renewable Fuels
Standard (RFS1; Section 1501), which required that 4 billion gallons (bgals) of
ethanol be used domestically in 2006, increasing to 7.5 bgals by 2012.
• In August and September, Hurricanes Katrina and Rita struck the Gulf Coast
region, causing severe damage to Gulf Coast petroleum importing and refining
infrastructure, putting them off-line for several months, and driving petroleum
product prices sharply higher. Meanwhile, corn prices remained relatively low at
about $2 per bushel, creating a period of extreme profitability for the sector.
The combination of high ethanol prices and low corn prices that persisted in 2006 created a
period of “unique” profitability for the U.S. ethanol industry. At that time, a 40 million gallon
nameplate ethanol plant costing approximately $60 million could recover its entire capital
investment in less than a year of normal operations.27 In addition, the establishment of the first
RFS—by guaranteeing a market for new ethanol production—removed much of the investment
risk from the sector.
Figure 3. Annual U.S. Corn Use by Major Activity, 1980 to 2011
7
Billion bushels
Feed
6
5
Ethanol
4
3
Exports
2
1
Food
0
1980
1985
1990
1995
2000
2005
2010

Source: USDA, Production, Supply, and Distribution (PSD) database, January 12, 2012.
Notes: Feed includes a residual category to balance USDA supply and demand estimates.

27 Based on CRS simulations of an ethanol dry mill spreadsheet model developed by D. Tiffany and V. Eidman in
Factors Associated with Success of Fuel Ethanol Producers, Staff Paper P03-7, Dept of Applied Economics, University
of Minnesota, August 2003. Note, nameplate capacity represents the capacity that the design engineers will warrant. In
most cases, an efficiently run plant will operate in excess of its nameplate capacity.
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Table 1. U.S. Corn-Use Share of Annual Production by Major Activity, 1980 to 2011
Crop
Year
Ethanol Food Exports Feed
1980 1%
9% 36% 58%
1985 3% 10% 14% 63%
1990 4% 13% 22% 59%
1995 5% 14% 26% 55%
2000 6% 13% 20% 60%
2005 14% 12% 19% 55%
2010 38% 11% 14% 37%
2011 40% 11% 13% 36%
Source: Calculations are by CRS from USDA, PSD database, January 12, 2012.
Note: Values may sum to greater than 100% because some usage may derive from carryover stocks.
As a result of this “perfect storm” of policy and market events, investment money flowed into the
construction of new ethanol plants, and U.S. ethanol production capacity (either in existence or
under construction) more than doubled in just two years, rising from an estimated 4.4 bgals
produced in 81 plants in January 2005 to 11.1 bgals produced in 110 plants by January 2007. The
ethanol expansion was almost entirely in dry-mill corn processing plants. As a result, corn’s role
as the primary feedstock used in ethanol production in the United States continued to grow. In
2006, corn use for ethanol nearly matched U.S. corn exports at about 2.1 billion bushels. In 2007,
U.S. corn exports hit a record 2.4 billion bushels; however, corn-for-ethanol use jumped to over
3 billion bushels. For the first time in U.S. history, the bushels of corn used for ethanol production
would be greater than the bushels of corn exported (Figure 3).
EISA Greatly Expands Mandate, Shifts Focus to Cellulosic Biofuels
In light of the rapid expansion of the U.S. biofuels industry, the RFS1 mandate was quickly
outgrown in 2006 (Figure 2). On December 19, 2007, Congress dramatically raised the “bar” by
passing the Energy Independence and Security Act of 2007 (EISA, P.L. 110-140).28 EISA
superseded and greatly expanded EPACT’s biofuels mandate relative to historical production
(Figure 4).
The expanded RFS (referred to as RFS2) required the use of 9 bgals of biofuels in 2008 and
expanded the mandate to 36 bgals annually in 2022. The new mandate had some provisos,
foremost of which was that only 15 bgals of RFS-qualifying biofuels could be ethanol from corn
starch. In addition, all increases in the RFS mandate from 2016 onwards must be met by
advanced biofuels (i.e., non-corn-starch biofuels) and no less than 16 bgals must be derived from
cellulosic feedstock in 2022. In addition, the new mandate established by EISA carved out
specific volume requirements for biomass-based diesel fuels.

28 See CRS Report R40155, Renewable Fuel Standard (RFS): Overview and Issues.
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Figure 4. Renewable Fuels Standard (RFS2) vs. U.S. Ethanol Production Since 1995
Billion gallons
40
Actual Production
Mandated Use
30
Biomass-based diesel
Unspecified Advanced Biofuels
Cellulosic Biofuel
20
Corn-starch Ethanol
Actual Ethanol Production
Actual Production
10
0
1995
2000
2005
2010
2015
2020

Sources: Actual ethanol production data for 1995-2010 is from Renewable Fuels Association; data for RFS2
mandates is from EISA (P.L. 110-140). Data includes revisions to RFS2 cel ulosic mandates for 2011 and 2012.
Meanwhile, prices for many agricultural commodities—including nearly all major U.S. program
crops—started a steady upward trend in late 2006. Then, in early 2007, the upward trend for
commodity prices turned into a steep rise. By mid-2008 market prices for several agricultural
commodities had reached record or near-record levels (Figure 5).29 In particular, both corn and
crude oil hit record high prices in both spot and futures markets, thus symbolizing the growing
linkage between U.S. field crops and energy markets.30 The upward rise in the price of corn in
2007 and early 2008 sucked the profits out of the U.S. biofuels sector and put the brakes on new
investment. It also fueled a “food-versus-fuel” debate about the potential for continued expansion
in corn use for ethanol to have unintended consequences in other agricultural and environmental
markets. While most economists and market analysts agreed that the dramatic price rise of 2008
was due to factors other than biofuels policy, they also are nearly universally agreed that the
strong, steady growth in ethanol demand for corn has had an important price effect, not just on
the price of corn, but in other agricultural markets including food, feed, fuel, and land.
By mid-2008, the commodity price rise had completely reversed itself and turned into a near free-
fall, coinciding with the financial crisis that broke in late 2008. The extreme price volatility
created many difficulties throughout the marketing chain for agricultural buyers and sellers. The
experience of $7.00-per-bushel corn, albeit temporary, shattered the idea that biofuels were a
panacea for solving the nation’s energy security problem and left concerns about the potential for
unintended consequences from future biofuels expansion.

29 For more information about markets during this period, see CRS Report RL34474, High Agricultural Commodity
Prices: What Are the Issues? See also, “What Is Driving Food Prices,” by Philip C. Abbott, Christopher Hurt, and
Wallace E. Tyner, Farm Foundation, July 2008; hereinafter referred to as Abbott et al., 2008.
30 On June 23, 2008, the nearby futures contract for No. 2, yellow corn hit a record $7.65 per bushel on the Chicago
Board of Trade. On July 7, 2008, the nearby futures contract for Crude Oil hit $147.27 per barrel at the New York
Mercantile Exchange, while the nearby Brent Crude Oil contract hit $147.50 at the ICE Futures Europe exchange.
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Figure 5. Monthly Farm Prices for Corn, Soybeans, and Crude Oil, 2000 to 2011
(Index: 2006 = 100)
300
Corn
250
200
Soybeans
150
100
50
Crude Oil
0
2000
2002
2004
2006
2008
2010
2012
Sources: Corn and soybean prices are monthly average farm prices, National Agricultural Statistics Service
(NASS), USDA; crude oil is the spot price, f.o.b., for West Texas Intermediate, Cushing, OK, EIA, DOE.
Notes: To facilitate comparison of relative price movements, the monthly prices have been converted to an
index where the 12-month average for calendar 2006 has been set to 100.
2008 Farm Bill Reinforces Focus on Cellulosic Biofuels
The 2008 farm bill (Food, Conservation, and Energy Act of 2008; P.L. 110-246) extended and
expanded many existing biofuels programs.31 In particular, Title XV (“Trade and Tax Provisions”)
extended the biofuels tax incentives and the tariff on ethanol imports, although the tax credit for
corn-starch ethanol was reduced to $0.45 per gallon. But in the wake of the commodity market
price run-up of early 2008, the new farm bill also re-emphasized EISA’s policy shift towards
research and development of advanced and cellulosic bioenergy in an effort to avoid many of the
unintended consequences of relying too heavily on major field crops as the principal biomass
feedstock. In addition, it established a new tax credit of $1.01 per gallon for cellulosic biofuel.
Like the 2002 farm bill, it contained a distinct energy title (Title IX) that covers a wide range of
energy and agricultural topics with extensive attention to biofuels, including corn starch-based
ethanol, cellulosic ethanol, and biodiesel. Energy grants and loans are provided through initiatives
such as the Bioenergy Program for Advanced Biofuels to promote the development of cellulosic
biorefinery capacity. The Repowering Assistance Program supports increasing efficiencies in
existing refineries. Programs such as the Rural Energy for America Program (REAP) assist rural
communities and businesses in becoming more energy-efficient and self-sufficient, with an
emphasis on small operations. Cellulosic feedstocks—for example, switchgrass and woody
biomass—are given high priority both in research and funding. The Biomass Crop Assistance

31 See CRS Report R41985, Renewable Energy Programs and the Farm Bill: Status and Issues.
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Program (BCAP), the Biorefinery Assistance Program, and the Forest Biomass for Energy
Program provide support to develop alternative feedstock resources and the infrastructure to
support the production, harvest, storage, and processing of cellulosic biomass feedstocks.
Title VII, the research title of the 2008 farm bill, contains numerous renewable-energy-related
provisions that promote research, development, and demonstration of biomass-based renewable
energy and biofuels. One of the major policy issues debated prior to the passage of the 2008 farm
bill was the impact of the rapid, ethanol-driven expansion of U.S. corn production. This issue was
made salient by the dramatic surge in commodity prices experienced in 2007 and early 2008. In
partial consideration, the enacted bill requires reports on the economic impacts of ethanol
production, reflecting concerns that the increasing share of corn production being used for ethanol
contributed to high commodity prices and food price inflation.
Questions Emerge Concerning Rapid Biofuels Expansion
By 2009, more than half of all U.S. gasoline contained some ethanol (mostly blended at the 10%
level or lower). U.S. ethanol consumption in 2011 is estimated at 13.8 billion gallons (bgals),
which was blended into roughly 138 bgals of gasoline—this represents about 10% of annual
gasoline demand on a volume basis, and 7% on an energy basis. With national gasoline
consumption stagnant (following the financial crisis of 2008 and ensuing economic recession),
ethanol production may have reached the 10% ethanol-to-gasoline blend wall (described later in
this report).32
Meanwhile, robust economic growth in major global markets in 2010 and early 2011 (including
China, India, Brazil, and other parts of Asia and the Middle East) reinvigorated international
consumer demand and, when coupled a weak U.S. dollar and events that occurred in international
feed grain markets—drought in Russia, Kazakhstan, and the Ukraine in 2010, plus strong Chinese
demand for corn and feedstuffs—contributed to record U.S. agricultural export values in 2010
and 2011.33 U.S. ethanol production in 2010 consumed 40% of the U.S. corn crop, surpassed
corn-for-feed use for the first time in history (Figure 3), and contributed to near historic low
ending stock projections (relative to expected demand) for U.S. corn and soybean for 2010 and
2011.34 These market conditions helped to spur another surge in agricultural commodity prices
starting in mid-2010 (Figure 5), thus spreading the effects of rapidly expanding ethanol
production and corn demand across several other sectors of the U.S. economy as well.
In the long term, the expanded RFS2 is likely to play a dominant role in the development of the
U.S. biofuels sector, but with considerable uncertainty regarding spillover effects in other markets
and on other important policy goals.35 Emerging resource constraints have provoked questions
about corn-based ethanol’s long-run sustainability and the possibility of unintended consequences
in other markets as well as on the environment.

32 See CRS Report R40445, Intermediate-Level Blends of Ethanol in Gasoline, and the Ethanol “Blend Wall.”
33 USDA, ERS, Outlook for U.S. Agricultural Trade, AES-72, November 30, 2011.
34 For more information on this and other market factors, see CRS Report R41956, U.S. Livestock and Poultry Feed
Use and Availability: Background and Emerging Issues .
35 See CRS Report R40155, Renewable Fuel Standard (RFS): Overview and Issues.
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By late 2011, policy makers and the U.S. biofuels industry were confronted by questions
regarding the ability to meet the expanding mandate for biofuels from non-corn sources such as
cellulosic biomass materials, whose production capacity has been slow to develop,36 or biomass-
based diesel, which remains expensive to produce owing to the relatively high prices of its
feedstocks. In addition, despite plentiful production, domestic consumption of corn ethanol
appeared to be increasingly stymied by the “blend wall” (described later in this report). Finally,
considerable uncertainty remains regarding the development of the infrastructure capacity (e.g.,
trucks, pipelines, pumps, etc.) needed to deliver the expanding biofuels mandate to consumers.
Ethanol Production Capacity Centered on Corn Belt
As of January 10, 2012, U.S. ethanol production was underway or planned in 209 plants located
in 28 states based primarily around the central and western Corn Belt, where corn supplies are
most plentiful (Figure 6 and Table 2). Existing U.S. ethanol plant capacity was estimated at
14.797 billion gallons per year (BGPY), with another 0.025 BGPY of capacity under construction
(either as new plants or expansion of existing plants). Thus, total annual U.S. ethanol production
capacity in existence or under construction was about 14.8 BGPY, well in excess of the 13.2 bgals
RFS2 mandate for corn-starch ethanol in 2012 (Figure 2).
Figure 6. U.S. Ethanol Production Capacity Is Centered on the Corn Belt

Source: USDA; U.S. corn production for 2010 compared with ethanol plant locations as of March 3, 2011;
available at http://www.nass.usda.gov/Charts_and_Maps/Ethanol_Plants/U._S._Ethanol_Plants/index.asp.
Iowa is by far the leading ethanol-producing state, with a 27% share of total U.S. output. The top
six Corn Belt states of Iowa, Nebraska, Illinois, Minnesota, Indiana, and South Dakota account
for nearly 73% of national production (Table 2). On a national level, actual operating capacity of

36 See CRS Report R41106, Meeting the Renewable Fuel Standard (RFS) Mandate for Cellulosic Biofuels: Questions
and Answers.
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14.2 BGPY represents about 96% of nameplate capacity. However, several states including
Nebraska, Minnesota, Indiana, Kansas, Ohio, and the “other” category of states are operating
substantially below their nameplate capacity, suggesting that industry profitability varies by
geographic circumstance, primarily due to variations in feedstock cost and availability, with
current circumstances favoring producers located near ample corn supplies.
Table 2. U.S. Ethanol Output and Production Capacity by State
Operating Production

Current
Under
Nameplate
Contr. or
# of
% of
Cum %
Capacity
Expansion
Rank State
Plants
MGPY
output
output

(MGPY)
(MGPY)
1 Iowa
39
3,864
27.2%
27.2%
3,864
—
2 Nebraska
26
1,701
12.0%
39.2%
1,803
—
3 Illinois
13
1,352
9.5%
48.7%
1,395

—
4 Minnesota
22
1,207
8.5%
57.2%
1,225
—
5 Indiana
14
1,141
8.0%
65.2%
1,162
—
6 S. Dakota
15
1,032
7.3%
72.5%
1,032
—
7
Wisconsin 9 504
3.5%
76.0%
504

—
8
Ohio
7 478
3.4%
79.4%
538

—
9 N. Dakota
6
460
3.2%
82.6%
470
—
10 Kansas
13
437
3.1%
85.7%
496
25
11
Texas
4 355
2.5%
88.2%
355

—
12 Michigan
5
268
1.9%
90.1%
268

—
13
Missouri 5 251
1.8%
91.9%
251

—
14
Tennessee 2 225
1.6%
93.5%
225

—
15
Colorado 4 125
0.9%
94.3%
125

—
Others
25
804
5.7%
100%
1,084

—
U.S. Total
209
14,203
100%

14,797
25
Source: Renewable Fuels Association as of January 10, 2012; state-level aggregations are by CRS.
Note: Output and production capacity data are in million gallons per year (MPGY).
Evolution of the U.S. Biodiesel Sector
Biodiesel can be produced from any animal fat or vegetable oil (such as soybean oil or recycled
cooking oil). Historically, most U.S. biodiesel was made from soybean oil. However, with the rise
in soybean prices since 2007 (Figure 5), biodiesel producers have aggressively shifted to cheaper
vegetable oils and animal fats (especially poultry fat) such that by 2011 less than half of U.S.
biodiesel production was estimated to be based on soybean oil.
According to the National Biodiesel Board (NBB), biodiesel is nontoxic, biodegradable, and
essentially free of sulfur and aromatics. In addition, it works in any diesel engine with few or no
modifications and offers similar fuel economy, horsepower, and torque, but with superior
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lubricity and important emission improvements over petroleum diesel.37 Biodiesel is used almost
uniquely as a substitute for petroleum diesel. Biodiesel delivers slightly less energy than
petroleum diesel (about 92%). As a result, fuel blenders and consumers are very sensitive to price
differences between biodiesel and petroleum-based diesel. The price relationship between
vegetable oils and petroleum diesel is the key determinant of profitability in the biodiesel
industry. About 7.5 pounds of vegetable oil are used in each gallon of biodiesel. Because soybean
oil has traditionally been the primary feedstock for biodiesel, U.S. soybean producers and the
American Soybean Association (ASA) are strong advocates for greater government support for
biodiesel production.
U.S. Biodiesel Industry Starts Late, Grows Slowly
The U.S. biodiesel industry did not emerge until the late 1990s. Despite strong growth in the
2000s, U.S. biodiesel consumption remains small relative to national diesel consumption levels.
In 2011 (Figure 1), U.S. biodiesel consumption represented about 2% (in diesel-equivalent units)
of national diesel transportation fuel use of about 40.7 billion gallons.38 Because biodiesel and
diesel fuel are so similar, biodiesel can also be used for the same non-transportation activities. In
2011, 54.7 billion gallons of diesel fuel were used for heating and power generation by
residential, commercial, and industry, and by railroad and vessel traffic, bringing total U.S. diesel
fuel use to nearly 102 billion gallons (including 6.5 billion gallons of residual fuel oil).
U.S. biodiesel production grew slowly from under 1 million gallons in 1999 to an estimated 678
million gallons in 2008 (Figure 7), before falling back substantially in 2009 and 2010. Bioenergy
Program payments provided an initial impetus for plant investments from 2001 through 2006.
The American Jobs Creation Act of 2004 (P.L. 108-357) created the first ever federal biodiesel tax
incentive—a federal excise tax and income tax credit of $1.00 for every gallon of agri-biodiesel
(i.e., virgin vegetable oil and animal fat) that was used in blending with petroleum diesel; and a
$0.50 credit for every gallon of non-agri-biodiesel (i.e., recycled oils such as yellow grease). The
distinction between biodiesel from virgin and recycled oils was eventually removed (P.L. 110-
343; October 3, 2008), and all biodiesel qualified for the credit of $1.00 per gallon until its
expiration on December 31, 2011.
In 2005 the U.S. biodiesel industry received a major economic boost from the same series of
market and policy developments described earlier in the ethanol section of this report.39 The
Energy Policy Act of 2005 extended the biodiesel tax credit and established a Small Agri-
Biodiesel Producer Credit of $0.10 per gallon on the first 15 million gallons of biodiesel produced
from plants with production capacity below 60 million gallons per year.
Biomass-based diesel was not part of the initial biofuels RFS1 mandate under the Energy Policy
Act of 2005, but was included as a distinct category in the RFS2 created under EISA of 2007. The
RFS2 biomass-based diesel mandate for 2009 was 500 million gallons. However, since EPA did
not have rules in place to operate that portion of the RFS in 2009, the mandate took effect for the
first time in 2010 under a special one-time arrangement whereby the biomass-based diesel RFS

37 For more information, visit the NBB at http://www.biodiesel.org.
38 EIA, DOE; biodiesel production estimates from “Annual Energy Outlook 2011,” Transportation Sector Energy Use
by Mode and Type, Reference Case.
39 See section “The Ethanol Industry’s Perfect Storm in 2005.”
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for 2009 was combined with the 2010 mandate (of 650 million gallons) into a single RFS of
1,150 million gallons for 2010. In 2011, the mandate returns to its original trajectory of 800
million gallons, rising to 1 billion gallons in 2012. While most or all of this mandate is expected
to be met using biodiesel, other fuels, including renewable diesel,40 algae-based diesel, or
cellulosic diesel, would also qualify.
Figure 7. Annual U.S. Biodiesel Production, 1999 to 2015
1.2 Billion Gallons
RFS2 for biomass-based diesel
becomes ef ective in 2010;
RFS2
however, biodiesel tax credit
expires for much of year
0.9
0.6
Hurricane Katrina
0.3 Bioenergy Program
begins payments
Projected
Historical
0.0
1999
2001
2003
2005
2007
2009
2011
2013
2015
Source: Data for 1999-2010, Energy Information Agency (EIA), Dept. of Energy (DOE). Projections for 2011-
2015 are from CRS.
Notes: Although the RFS2 mandate for biodiesel was to begin in 2009, implementation rules were not available
until February 2010. As a result, the RFS2 mandate for 2009 of 500 million gallons was combined with the 2010
mandate of 650 million gallons for a one-time mandate of 1.15 billion gallons in 2010.
Starting in mid-2007, the U.S. biodiesel industry suffered from unfavorable market conditions as
prices for vegetable oil rose relative to diesel fuel. Most biodiesel plants continued to operate into
2008 in hopes of either higher diesel prices or lower vegetable oil prices, and the industry
produced record output of an estimated 678 million gallons.41 However, the financial crisis of late
2008 and the ensuing economic recession weakened demand for transportation fuel, and
petroleum prices (including diesel fuel) fell sharply in the second half of 2008. In March 2009,
the European Union (EU) imposed anti-dumping and countervailing duty tariffs on imports of
U.S. biodiesel (described later) that effectively shut down U.S. biodiesel exports to the EU.42

40 While similar to “biodiesel,” “renewable diesel” is produced through different processes and results in a fuel with
somewhat different chemical characteristics. There is a separate tax credit of $1.00 per gallon for renewable diesel.
41 DOE, EIA, Monthly Biodiesel Production Report, March 2009.
42 “EU Imposes Five-Year AD, CVD Duties on U.S. Biodiesel,” Inside U.S. Trade, July 7, 2009.
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As a result, the biodiesel industry experienced several bankruptcies and some loss of capacity
during 2009. U.S. biodiesel production in 2009 fell to 506 million gallons,43 down over 25% from
2008. The unfavorable economic conditions for biodiesel production extended into 2010 and
were made worse by the expiration of the biodiesel tax credit at the end of 2009. The tax credit
was eventually renewed on December 17, 2010 (P.L. 111-312), and made available retroactively
to all 2010 biodiesel production; however, the extended delay and poor market conditions
contributed to substantially reduced U.S. biodiesel production of 311 million gallons in 2010.
During 2010, the U.S. biodiesel industry saw 52 out of 170 operating plants stop operations while
many others scaled back on production.44 The renewal of the tax credit and the expanded RFS2
biodiesel usage mandate of 800 million gallons in 2011 revived the industry and spurred a
projected record production of 800 million gallons in 2011.
Two factors are expected to support biodiesel production at or above 1 billion gallons starting in
2012 and going forward: first, the RFS2 biodiesel mandate grows to 1 billion gallons in 2012 and
1.28 billion in 2013; second, the RFS2 for advanced biofuels (for which biodiesel is a qualifying
fuel) grows even faster, with 2 billion gallons in 2012 rising to 21 billion gallons by 2022.
Although cellulosic biofuel was originally envisioned to fill most of the advanced biofuel
mandate, slow progress in commercial production to date suggests that biodiesel may be used to
meet at least a portion of the advanced biofuel mandate in the future.
Biodiesel Production Capacity Spreads Nationwide
As mentioned earlier, the primary feedstock for biodiesel includes both vegetable oils and animal
fats, both of which are produced over a greater geographic area than corn. As a result, biodiesel
plants are more widely dispersed across the United States than are ethanol plants (Table 3).
According to the National Biodiesel Board (NBB), as of January 17, 2012, there were 148
companies in the United States with the potential to produce biodiesel commercially that were
either in operation or idled, with total annual production capacity (within the oleochemical
industry) of 1.426 billion gallons per year. Because many of these plants also can produce other
products such as cosmetics, estimated total capacity (and capacity for expansion) is far greater
than actual biodiesel production.
The unfavorable economic conditions of 2009 and 2010, coupled with the delay in extending the
biodiesel tax credit in 2010, contributed to a substantial shake-up in the biodiesel industry. Many
plants situated in the heart of corn and soybean country dropped out of business, while new plants
sprang up in locations near alternate vegetable or animal oil sources. As a result, the U.S.
biodiesel industry is more diversified and less centralized than the ethanol industry. Unlike
ethanol, where the top six producing states account for 73% of national capacity, the top six
biodiesel-producing states achieve only a 51% share, thus demonstrating the more widespread
nature of U.S. biodiesel production capacity.


43Energy Information Administration (EIA), DOE.
44 “Tax Credits, Mandates Bring Back Biodiesel Plants,” Energy & Environmental New, September 19, 2011.
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Table 3. U.S. Biodiesel Production Capacity Partial Estimate as of January 12, 2012
Production
Rank
State
# of Plants
Capacity (MGY)
% of output
Cum % output
1 Missouri
8
195.5
13.7%
13.7%
2 Washington
5
130.0
9.1%
22.8%
3 Texas
13
122.8
8.6%
31.4%
4 Iowa

11
112.0
7.9%
39.3%
5 Indiana
4
85.8
6.0%
45.3%
6 N.
Dakota
1
85.0
6.0%
51.3%
7 Ohio
3
65.0
4.6%
55.8%
8 South
Carolina
3
65.0
4.6%
60.4%
9 Pennsylvania
7
61.6
4.3%
64.7%
10 Kentucky
4
60.8
4.3%
69.0%
11 California
11
57.8
4.0%
73.0%
12 Arkansas
2
50.0
3.5%
76.5%
13 Alabama
3
45.0
3.2%
79.7%
14 Georgia
7
37.1
2.6%
82.3%
15 Oklahoma
2
35.0
2.5%
84.7%
Others
64
217.9
15.3%
100%
U.S. Total
148
1,426.1
100%

Source: National Biodiesel Board (NBB), http://www.biodiesel.org/buyingbiodiesel/plants/showall.aspx. State-
level aggregations are by CRS.
Notes: This list is limited to members of the NBB. As a result, the total biodiesel production capacity of
1.4 bgals is a lower bound on actual national production capacity.
U.S. Retail Delivery Infrastructure and Vehicle Fleet
A key determinant of the demand for biofuels as a transportation fuel is the U.S. vehicle fleet and
the infrastructure that delivers fuel to consumers at the retail level. According to the Department
of Energy (DOE), over three-fourths of U.S. transportation fuel is consumed as gasoline or
gasoline blends (Figure 1). The U.S. Department of Transportation (DOT) estimated that there
were 254.2 million registered passenger vehicles (including trucks and buses) in the United States
in 2009.
Because of its physical properties, pure ethanol cannot be used in the same infrastructure (e.g.,
pipelines, storage tanks, service pumps) used to deliver retail gasoline. In the past, conventional
thinking was that standard motor vehicles were not intended for ethanol blend ratios above 10%,
as ethanol tends to make the engine run at a higher temperature than standard reformulated
gasoline. In addition, the presence of ethanol can be corrosive on rubber and plastic parts in the
car engine.
As a result, prior to October 2010, the amount of ethanol that could be blended in gasoline for use
in standard vehicle motors without modification was limited to 10% by volume, by guidance
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developed by the EPA under the Clean Air Act, as well as by vehicle and engine warranties, and
certification procedures for fuel-dispensing equipment. In addition, most vehicle warranties did
not cover any motor damage resulting from use of ethanol blends above 10%. In the past, only
flex-fuel vehicles (FFVs) have been capable of using higher ethanol blends.
Regional infrastructure issues suggest that the actual limiting value is something less than the
13.8 bgals implied by the 10% blending limitation. This “blending-limited” volume is often
referred to as the “blend wall.”45
However, recent EPA rulings have expanded the eligible vehicle pool for ethanol blends greater
than 10%. In October 2010, EPA ruled that 15% ethanol blends could be used in 2007 model year
or newer passenger vehicles (including cars, SUVs, and light pickup trucks). Then, on January
21, 2011, EPA further expanded the eligible passenger vehicle pool to include model years 2001
through 2006. Despite this expansion, the fact that a portion of currently active passenger vehicles
are not eligible for E15 both limits ethanol retail delivery opportunities and raises the cost of
delivery. In contrast, biodiesel is very similar in nature to petroleum diesel and does not have the
same infrastructure limitations.
Flex-Fuel vs. Standard Ethanol-Gasoline Blend Vehicles
Ethanol has traditionally been blended into gasoline at the 10% level (E10) or lower, where it can
be used in vehicles with standard motors. It has also been sold in purer forms such as E85 (85%
ethanol and 15% gasoline) targeted for flex-fuel vehicles (FFVs) with motors specially designed
for higher ethanol content. However, E85 presently represents less than 1% of U.S. ethanol
consumption.46 Its wider distribution and use is limited by the number of filling station pumps
capable of dispensing E85, the number of FFVs in the United States, and the willingness of
consumers to use the fuel.
In 2011, ethanol blending as a share of the national gasoline supply reached 10% on a volume
basis.47 In many urban retail fuel stations, pure gasoline is no longer available. Instead, gasoline
fuel pumps are labeled as containing “up to a 10% blend of ethanol.” In these situations, ethanol
is treated as indistinguishable from gasoline by consumers.
In 2012, as much as 14.2 bgals of ethanol are mandated under the RFS for use in the nation’s
gasoline supply (including 13.2 bgals of corn-starch ethanol, 8.5 million gallons of cellulosic
ethanol, and potentially another 1.0 bgals of “other” advanced biofuel). The combined level of
mandated biofuels represents a 10.4% volumetric share of the projected 138.4 bgals of U.S.
gasoline consumption for 2012.

45 See CRS Report R40445, Intermediate-Level Blends of Ethanol in Gasoline, and the Ethanol “Blend Wall.”
46 The most recent EIA, DOE, data on E85 consumption is from 2008, when 62.5 million gallons of E85 were
consumed out of about 137.6 billion gallons of blended gasoline.
47 Calculated by CRS as 13.8 bgals of ethanol out of approximately 137.7 bgals of gasoline and ethanol consumed.
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Ruling on the Ethanol-to-Gasoline Blending Limit: 10% vs. 15%48
For ethanol consumption to exceed the so-called blend wall and meet the RFS mandates,
increased consumption at higher blending ratios is needed. For example, raising the blending
limit from 10% to a higher ratio such as 15% or 20% would immediately expand the “blend wall”
to somewhere in the range of 20 billion to 27 billion gallons. The U.S. ethanol industry is a strong
proponent of raising the blending ratio. On March 6, 2009, Growth Energy (on behalf of 52 U.S.
ethanol producers) applied to the EPA for a waiver from the then-current Clean Air Act E10 limit
and an increase in the maximum allowable concentration to 15% (E15).
As mentioned earlier, on October 13, 2010, EPA issued a partial waiver for gasoline that contains
up to a 15% ethanol blend (E15) for use in model year 2007 or newer light-duty motor vehicles
(i.e., passenger cars, light-duty trucks, and sport utility vehicles).49 However, EPA also announced
that no waiver would be granted for E15 use in model year 2000 and older light-duty motor
vehicles, as well as in any motorcycles, heavy duty vehicles, or non-road engines. This later
restriction opens up the possibility of “mis-fueling”—that is, using higher ethanol blends in
vehicles not appropriate for the EPA 15% blend waiver.
On January 21, 2011, following the results of additional DOE testing, EPA expanded the waiver
on E15 to allow its use in model year 2001-2006 vehicles. According to the Renewable Fuel
Association (RFA), the approval of E15 use in model year 2001 and newer passenger vehicles
expands eligibility to 62% of vehicles on U.S. roads.50 In addition to the EPA waiver
announcement, fuel producers will need to register the new fuel blends and submit health effects
testing to EPA. Further, numerous other changes have to occur before gas stations will begin
selling E15, including many approvals by states and significant infrastructure changes (pumps,
storage tanks, etc.). As a result, the vehicle limitation to newer models, coupled with potential
infrastructure issues, is likely to limit rapid expansion of blending rates. Moreover, a group of
engineering and equipment manufacturers has challenged the partial waiver in court, arguing that
EPA failed to estimate the likelihood of mis-fueling (using E15 in equipment denied a waiver)
and the economic and environmental consequences of that mis-fueling.51
Two additional options to resolving this bottleneck exist but appear to be long-run alternatives.
First, increased use of ethanol in flex-fuel vehicles (FFVs) at ethanol-to-gasoline blend ratios as
high as 85% (referred to as E85) is a possibility. However, increased E85 use involves substantial
infrastructure development, particularly in the number of designated storage tanks and E-85 retail
pumps, as well as a rapid expansion of the FFV fleet to absorb larger volumes of ethanol.
A second alternative is to expand use of processing technologies at the biofuel plant to produce
biofuels in a “drop-in” form (e.g., butanol) that can be used by existing petroleum-based
distribution and storage infrastructure and the current fleet of U.S. vehicles. However, more
infrastructure-friendly biofuels generally require more processing than ethanol and are therefore
more expensive to produce.

48 For more information, see EPA Fuel Additive Notices, at http://www.epa.gov/otaq/additive.htm.
49 EPA, Fuels and Fuel Additives, “EPA Announces E15 Partial Waiver Decision and Fuel Pump Labeling Proposal,”
EPA420-F-10-054, October 13, 2010; at http://www.epa.gov/otaq/regs/fuels/additive/e15/420f10054.htm.
50 “E15 Decision Opens Blend to 2 Out of 3 Vehicles; More Work Yet to be Done,” RFA news release, Jan. 21, 2011.
51 Outdoor Power Equipment Institute (OPEI), “Fact Sheet: E-15 Partial Waiver Legal Challenge,” December 17, 2010.
The case is Alliance of Automobile Manufacturers et.al v. Environmental Protection Agency.
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FFV Fleet and E85 Pump Availability as Limiting Factors
At blend ratios above 10%, ethanol must compete directly with gasoline as a transportation fuel.
For ethanol to operate primarily as a gasoline substitute, at least two things must happen. First,
ethanol must be priced competitively with gasoline on an energy-content or miles-per-gallon
basis. Second, both the U.S. fleet of FFVs and the number and availability of high-blend-ratio
retail pumps must expand.
FFVs can be designed to operate with a varying share of ethanol; however, the most common is
the flex-fuel E85 vehicle.52 For consumers with FFVs that have access to E85 pumps, the price
relationship between ethanol and gasoline is important. Varying blend ratios of ethanol with
gasoline make the miles-per-gallon calculation more difficult, but the principal holds that,
whenever the consumer has a choice between different fuels, he or she is likely to prefer the fuel
choice that returns the most miles-per-gallon at the lowest cost.
The market for E85 is limited by both the number of E85 vehicles and the number of E85 fueling
stations. According to the Renewable Fuels Association (RFA), there were more than 8 million
FFVs on the roads in 2011, representing about 3% of U.S. passenger vehicles. However, not all
FFV owners have access to (or choose to use) E85 retail pumps. As of early 2012, about 2,860
retail stations in the United States offered E85 (1.8% out of 160,000 stations).53 Most E85 fueling
stations are concentrated in the upper midwestern states near the current ethanol production
heartland (Figure 8).
Figure 8. E85 Refueling Locations by State

Source: U.S. DOE, Alternative Fuels and Advanced Vehicles Data Center, November 2010, available at
http://www.afdc.energy.gov/afdc/ethanol/ethanol_locations.html.

52 In Brazil, the nation’s entire fleet of passenger vehicles is made up of FFVs. All gasoline sold in Brazil contains at
least 20% ethanol, while 100% ethanol is also available at every retail service station. Thus, Brazilian consumers make
fuel choices based on the price relationship between blended gasoline (E20 to E25) and E100 pure ethanol.
53 For more information, see the Renewable Fuels Association’s E-85 online information site at
http://www.ethanolrfa.org/pages/e-85.
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Federal Programs That Support Biofuels
As described in the earlier sections on the growth of the ethanol and biodiesel industries, federal
policy has played a key role in helping to close the price gap between biofuels and cheaper
petroleum fuels. Initially, federal biofuels policies were developed to help kick-start the biofuels
industry during its early development, when neither production capacity nor a market for the
finished product were widely available. Now, as the industry has evolved, other policy goals (e.g.,
national energy security, climate change concerns, support for rural economies) are cited as
justifications for continuing policy support.
Oversight and implementation of these policies is spread across several government agencies, but
the primary responsibility lies with EPA, USDA, and DOE. As the number, complexity, and
budgetary implications of federal biofuels policies have grown, so too has the number of
proponents and critics. Many biofuels-related policy debates occur along geographic lines. For
example, Midwest corn- and ethanol-producing states are major proponents of federal policy
support, whereas many residents of the East and West Coast urban states perceive expensive
biofuel usage mandates as being forced upon them while their access to cheaper Brazilian sugar-
cane ethanol was, for many years, limited by an import tariff. Another source of biofuels policy
conflict has emerged between the major users of corn. Livestock producers have seen their feed
costs escalate with the growth in biofuels corn demand and are highly critical of further federal
biofuels support.
Most of the biofuels policies developed and funded by Congress are subject to oversight and
periodic reauthorization.54 For most of the past three decades, three types of federal programs
have provided the core support for the U.S. biofuels industry: blending and production tax credits
to lower the cost of biofuels to end users, an import tariff to protect domestic ethanol from
cheaper foreign-produced ethanol, and volume-specific usage mandates to guarantee a market for
biofuels irrespective of their cost. In addition, the biofuels industry has been supported by several
indirect policies in the form of research grants to stimulate the development of new technologies,
and grants, loans, and loan guarantees to facilitate the development of biofuels feedstocks as well
as market and distribution infrastructure.
Tax Credits
Various tax credits and other incentives have been available for the production, blending, and/or
sale of biofuels and biofuel blends (Table 4). Tax credits vary by the type of fuel and the size of
the producer. Because of their budgetary cost, the tax credits are rarely extended for more than a
year or two at a time. As a result, they routinely require congressional action to be extended. On
December 31, 2011, most biofuels blending and production tax credits expired, with the
exception of the cellulosic biofuels production tax credit, which is set to expire at the end of
2012.

54 For a more complete list of federal biofuels incentives, see CRS Report R40110, Biofuels Incentives: A Summary of
Federal Programs.
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Table 4. Federal Tax Credits Available for Qualifying Biofuels
Tax Credit:
Expiration
Biofuel
$/gallon Details Date
Volumetric Ethanol Excise Tax
$0.45
Available in unlimited amount to all
Expired
Credit (VEETC)
qualifying biofuels.
Small Ethanol Producer Credit
$0.10
Available on the first 15 million gallons
Expired
(mgal) of any producer with
production capacity below 60 mgal.
Biodiesel Tax Credit
$1.00
Available in unlimited amount to all
Expired
qualifying biodiesel.
Small Agri-Biodiesel Producer Credit
$0.10
Available on the first 15 mgal of any
Expired
producer with production capacity
below 60 mgal.
Cellulosic Biofuels Production Tax
$1.01
Available in unlimited amount to all
Dec. 31, 2012
Credit
qualifying biofuels.
Source: CRS Report R40110, Biofuels Incentives: A Summary of Federal Programs, by Brent D. Yacobucci.
Import Tariff on Foreign-Produced Ethanol
Prior to 2012, most imported ethanol was subject to a most-favored-nation duty set of $0.54 per
gallon of ethanol (for fuel use) and a 2.5% ad valorem tariff. The stated goal of the import tariff
was to offset the ethanol blending tax credit which was also available for foreign-produced
ethanol. However, the fixed $0.54-per-gallon most favored-nation duty (identified by 9901.00.50
and 9901.00.52 of the Harmonized Tariff System (HTS)) expired on December 31, 2011. The
2.5% ad valorem tariff (2207.10.60 of the HTS) does not expire but is permanent until or unless
the HTS code itself is changed. In most years the tariff was a significant barrier to direct Brazilian
imports. However, some Brazilian ethanol could be brought into the United States duty-free if it
was dehydrated (reprocessed) in Caribbean Basin Initiative (CBI) countries.55 Up to 7% of the
U.S. ethanol market could be supplied duty-free in this fashion; historically, however, ethanol
dehydrated in CBI countries has only represented about 2% of the total U.S. market.
The Renewable Fuel Standard (RFS)56
The RFS requires the blending of renewable fuels (including ethanol and biodiesel) in U.S.
transportation fuel. The RFS includes specific quotas for advanced biofuels (i.e., non-corn-starch
ethanol), cellulosic biofuels, and biomass-based diesel fuel, as well as a total biofuels mandate.
The RFS also includes a cap on the eligible volume of corn-starch ethanol.
Under the overall biofuels RFS, fuel suppliers were required to supply 9 billion gallons (bgals) of
renewable fuel in 2008. This requirement increases annually to 36 bgals in 2022, of which only
15 bgals can be ethanol from corn starch. The remaining 21 bgals are to be so-called “advanced
biofuels”—fuels produced from non-corn-starch feedstocks—of which 16 bgals are to be from

55 See CRS Report RS21930, Ethanol Imports and the Caribbean Basin Initiative (CBI).
56 RFS (referred to as RFS1) was begun by the Energy Policy Act of 2005, (§ 1501; P.L. 109-58). The RFS was greatly
expanded (referred to as RFS2) by the Energy Independence and Security Act of 2007 (EISA, § 202, P.L. 110-140).
For more information on the RFS, see CRS Report R40155, Renewable Fuel Standard (RFS): Overview and Issues.
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cellulosic biofuels, 1 bgals from biomass-based diesel, and 4 bgals from other biofuels (most
likely imported sugar-cane ethanol from Brazil).
The RFS is administered by EPA and involves tradable certificates—Renewable Identification
Numbers (RINs)—assigned to each batch of biofuel.57 A RIN is a unique 38-character number
that is issued to each gallon of biofuel (in accordance with EPA guidelines) by the biofuels
producer or importer at the point of biofuels production or the port of importation. When biofuels
change ownership (e.g., are sold by a producer to a blender), the RINs are also transferred. When
biofuels are blended for retail sale or at the port of embarkation for export, the RIN is separated
from the fuel and may be used for RFS compliance or trade. At the end of the year, each blender
must have enough RINs to show that it has met its share of each of the four mandated RFS
standards. When the RFS is binding (i.e., the actual volume of biofuels used just equals the RFS
mandated volume) the RIN value will reflect the full price gap between a biofuel producer’s
supply price and a biofuel blender’s demand price.58
In addition to compliance demonstration, RINs can be used for credit trading. If a blender has
already met its mandated share and has blended surplus biofuels of a particular RFS category, it
can sell the extra RINs to another blender (who has failed to meet its blending mandate for that
same biofuel) or it can hold onto the RINs for future use (20% of the current year’s RFS
obligation may be carried forward either to satisfy the succeeding year’s blending requirement or
for future sale).
In addition to volume mandates, EISA specified that the lifecycle greenhouse gas (GHG)
emissions of a qualifying renewable fuel must be less than the lifecycle GHG emissions of the
2005 baseline average gasoline or diesel that it replaces.59 Lifecycle GHG emission reduction
thresholds were established for each of the four biofuels categories—20% for corn-starch ethanol
from new refineries, 50% for advanced biofuels, 60% for cellulosic biofuels, and 50% for
biomass-based diesel.
Other Indirect Federal Policies
Several additional biofuels programs have been created to provide various grants, loans, and loan
guarantees in support of research and development of related technology, as well as support for
biofuels infrastructure development. Many of these programs reside in the energy title (Title IX)
of the 2008 farm bill (P.L. 110-246).60 Federal programs also require federal agencies to give
preference to bio-based products in purchasing fuels and other supplies. Cellulosic plant
investment is further facilitated by a special depreciation allowance created under the Tax Relief
and Health Care Act of 2006 (P.L. 109-432). Also, several states have their own incentives,

57 “Renewable Identification Numbers Are the Tracking Instrument and Bellwether of U.S. Biofuel Mandates,” by
Wyatt Thompson, Seth Meyer, and Pat Westhoff, EuroChoices, vol. 8, no. 3, 2009.
58 “Mandates, Tax Credits, and Tariffs: Does the U.S. Biofuels Industry Need Them All?” by Bruce A. Babcock, CARD
Policy Briefs 10-PB-1, Center for Agricultural and Rural Development, Iowa State University, March 2010.
59 For more information, see CRS Report R40460, Calculation of Lifecycle Greenhouse Gas Emissions for the
Renewable Fuel Standard (RFS).
60 CRS Report R41985, Renewable Energy Programs and the Farm Bill: Status and Issues.
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regulations, and programs in support of renewable fuel research, production, and use that
supplement or exceed federal incentives.61
In addition to direct and indirect biofuels policies, the U.S. biofuels industry benefits from U.S.
farm programs in the form of price and income support programs (i.e., marketing loan benefits
and the counter-cyclical payment program) and risk-reducing farm programs (e.g., Acreage Crop
Revenue Election (ACRE), Supplemental Revenue Assistance Payments (SURE), federal crop
insurance, and disaster assistance), which encourage greater production and lower prices than
would occur in the absence of federal programs in a free-market equilibrium.62 As a result,
agricultural feedstocks are both lower-priced and more abundant than without federal farm
programs. This helps lower production costs for the U.S. biofuels sector, and makes U.S. biofuels
more competitive with foreign-produced biofuels.
Current Biofuels Policy Issues
Most of the federal biofuels tax credit provisions, as well as the import tariff on foreign-produced
ethanol, have short legislative lives and require frequent extension.63 The primary energy-related
issue for the next farm bill is the expiration at the end of FY2012 and lack of baseline funding
going forward for all major energy-related provisions of Title IX. In addition, the appearance of
substantial redundancy across renewable energy programs at USDA and DOE, the slow
development of the U.S. cellulosic biofuels sector, and concerns about the emerging spillover
effects of increasing corn use for ethanol production are issues that are likely to emerge during
the next farm bill debate.
Pending Congressional Actions
2008 Farm Bill Expiration
Most of the biofuels policy provisions contained in the 2008 farm bill (P.L. 110-246) were
extended through FY2012, at which time they will be reviewed as part of the next farm bill
debate.64 The 2008 farm bill authorized $1.1 billion in mandatory funding for energy programs,
including $320 million for the Biorefinery Assistance Program, $300 million for the Bioenergy
Program for Advanced Biofuels, and $255 million for the Rural Energy for America Program
(REAP). The Biomass Crop Assistance Program (BCAP) was authorized to receive such sums as
necessary (i.e., funding is open-ended and depends on program participation), although Congress
eventually put limits on mandatory funding of $552 million in FY2010, $112 million in FY2011,
and $17 million in FY2012. None of the major farm-bill energy programs have baseline funding

61 For more information, see the “Federal & State Incentives & Laws,” Alternative Fuels and Advanced Vehicles Data
Center, Energy Efficiency and Renewable Energy (EERE), DOE, at http://www.afdc.energy.gov/afdc/laws/.
62 For more information on U.S. farm programs, see CRS Report RL34594, Farm Commodity Programs
in the 2008 Farm Bill; CRS Report R40422, A 2008 Farm Bill Program Option: Average Crop Revenue Election
(ACRE); CRS Report R40452, A Whole-Farm Crop Disaster Program: Supplemental Revenue Assistance Payments
(SURE); and CRS Report R40532, Federal Crop Insurance: Background and Issues.
63 See CRS Report R40110, Biofuels Incentives: A Summary of Federal Programs.
64 See CRS Report R41985, Renewable Energy Programs and the Farm Bill: Status and Issues.
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after FY2012. As a result, the tight federal budget suggests that new revenues or offsetting cuts
will likely be required to extend them beyond FY2012.
Cellulosic Biofuels Tax Credit
While most biofuels tax credits and and the import duty on foreign fuel ethanol expired on
December 31, 2011, the cellulosic biofuel tax credit does not expire until December 31, 2012.
The cellulosic biofuels industry is expected to lobby actively for extension of the cellulosic
biofuel tax credit. However, a tight federal budget combined with lack of progress in developing
commercial production of cellulosic biofuels are likely to work against an extension.
Cellulosic Biofuels Feedstock Program: BCAP
Investors have been reluctant to invest in what so far is a commercially unproven technology—
the conversion of cellulosic biomass to biofuels. Development of the cellulosic biofuels industry
hinges on effective use of new feedstocks. To this effect, the Biomass Crop Assistance Program
(BCAP) was created under the 2008 farm bill to facilitate the development of those new
feedstocks and kick-start the cellulosic biofuels industry.65 BCAP (via USDA’s CCC) provides
financial assistance to producers or entities that deliver eligible biomass material to designated
biomass conversion facilities for use as heat, power, bio-based products, or biofuels. Initial
assistance will be for the collection, harvest, storage, and transportation (CHST) costs associated
with the delivery of eligible materials.
Because BCAP is intended to underwrite an as yet nonexistent industry—the cellulosic biofuels
industry—considerable uncertainty exists over how it should evolve so as to be most useful to
jump-starting the commercialization of cellulosic biofuels production. USDA published the final
rule for implementing BCAP on October 27, 2010.66 However, BCAP is in the early stages of
implementation, and concerns regarding eligibility, sustainability, and funding continue to be
discussed. These issues could shape future congressional action on the program in the context of
budgetary measures and possible reauthorization in the next farm bill. Congress will likely be
monitoring closely both the implementation of BCAP and its effect on the development of the
cellulosic biofuels sector.
Pending EPA Actions
Waiver of Mandated Use Requirements
The RFS mandates the use of over 15 bgals of biofuels in 2012. The mandate grows to 20.5 bgals
of biofuels use by 2015. By 2022, 36 bgals of biofuels must be consumed under the RFS. Each
year EPA must review the likelihood of outyear biofuel production meeting or failing to meet
required RFS usage levels, and adjust the mandates accordingly. EPA’s biofuels standards for
each upcoming year are announced on a preliminary basis in the spring of the preceding year,

65 See CRS Report R41296, Biomass Crop Assistance Program (BCAP): Status and Issues.
66 USDA, CCC, “Biomass Crop Assistance Program,” 75 Federal Register 66201, October 27, 2010.
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when EPA issues a notice of proposed rulemaking, and on a final basis by November 30 of the
preceding year, when EPA issues a final rule.67
The EPA has already waived the original RFS2 mandate for cellulosic biofuel for each of the first
three years—2010, 2011, and 2012. The likelihood of future EPA waivers could deter capital
investments in the sector and make future waivers become a self-fulfilling prophecy.
The likelihood of meeting RFS mandates for traditional biofuels hinges both on the “blend wall”
and on the slow emergence of a national infrastructure needed to facilitate the distribution and use
of the growing mandated biofuel volumes. Even with the expansion of the blending ratio to 15%
for model year 2001 and newer passenger vehicles, the higher blend wall of approximately 20 to
21 bgals will become a real barrier to expanded biofuels use by 2015.
Estimation of GHG Emission Reductions
Under EISA, EPA is responsible for evaluating whether a renewable fuel meets the specific GHG
reduction threshold assigned to its RFS category. Determining compliance with the thresholds
requires a comprehensive evaluation of renewable fuels on the basis of their lifecycle emissions.68
The concept of “lifecycle emissions” encompasses an evaluation of GHG emissions along the
entire pathway of a biofuel from the production, harvesting, and marketing of its feedstocks to the
processing and distribution of the biofuel, including any significant indirect emissions such as
significant emissions from land uses changes that might result from changes in crop patterns due
to the various biofuels incentives (as explicitly required in Section 201, P.L. 110-140).
More specifically, the concern is that expanded field crop production in the United States for
ethanol production has led to commodity price increases that, in turn, have induced increased land
cultivation in other countries, and as a result, have increased net global GHG emissions. The
measurement of indirect land use changes (ILUC) is necessarily inexact because so many
potential activities and countervailing forces are involved. As a result, inclusion of ILUC as part
of the EPA’s lifecycle GHG reduction analysis has been controversial.
Initially, EPA’s lifecycle GHG reduction models proved very sensitive to assumptions regarding
the extent of indirect land use changes, and suggested that some standard biofuels may not be
eligible for inclusion under the RFS. EPA models were updated prior to the final RFS rule
(February 2009) using newer data and produced more inclusive results. For example, corn-starch
ethanol was determined to achieve a 21% reduction in GHG emissions compared to the gasoline
2005 baseline, thus just surpassing the 20% reduction threshold.69 EPA models for estimating land
use changes and other life-cycle factors involved in GHG emissions are continually re-evaluated
as new or better data, methods, or analytical techniques become available. The nature of the
future changes to EPA models, and their potential to include or exclude certain biofuels, remains a
critical aspect of the RFS mandates and the U.S. biofuels industry’s ability to meet the mandates.

67 See CRS Report RS22870, Waiver Authority Under the Renewable Fuel Standard (RFS).
68 For more information, see CRS Report R40460, Calculation of Lifecycle Greenhouse Gas Emissions for the
Renewable Fuel Standard (RFS).
69 “V. Lifecycle Analysis of Greenhouse Gas Emissions;” Regulation of Fuels and Fuel Additives: Changes to
Renewable Fuel Standard Program; Final Rule, 40 CFR Part 80, Federal Register, March 26, 2010, p. 14786.
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Endangerment Findings for Greenhouse Gases (GHGs)
On April 2, 2007, in Massachusetts v. EPA (549 U.S. 497 (2007)), the U.S. Supreme Court
determined that GHGs are air pollutants covered under Section 202(a) of the Clean Air Act. The
Court held that EPA must determine whether or not emissions of GHGs from new motor vehicles
cause or contribute to air pollution that may reasonably be anticipated to endanger public health
or welfare, or whether the science is too uncertain to make a reasoned decision.70 This court
ruling allows EPA to regulate GHGs without further congressional action, and could bring into
play the issue of indirect land use changes, given their alleged GHG emissions effects, which may
put all ethanol production in question. On June 11, 2010, a Senate resolution (S.J.Res. 26) that
would have blocked EPA from using the Clean Air Act to regulate GHGs was defeated (53-47).71
Prior to the vote, on June 8, 2010, the White House had issued a statement saying that if S.J.Res.
26 reached the President’s desk (i.e., passed both chambers of Congress), President Obama would
veto it.
Other Pending or Emerging Biofuels Issues
CARB’s LCFS Restriction on Midwestern Ethanol
In January 2007, then-Governor Schwarzenegger established a Low Carbon Fuels Standard
(LCFS) by executive order for California.72 The executive order directed the state’s Secretary for
Environmental Protection to coordinate the actions of the California Energy Commission, the
California Air Resources Board (CARB), the University of California, and other agencies to
develop protocols for measuring the “life-cycle carbon intensity” of transportation fuels.
Under the LCFS, CARB proposed reducing emissions of GHGs by lowering the carbon content
of transportation fuels used in California. The LCFS established performance standards that fuel
producers and importers must meet each year starting in 2011. As part of its LCFS modeling
effort, CARB includes an estimate of the ILUC impact of grain-based ethanol. Largely because of
the ILUC value assigned to corn-starch ethanol, most midwestern ethanol production does not
qualify for use as a transportation fuel under California’s LCFS.73 This result has important
implications for how or whether the federal RFS mandates can be met for the nation as a whole,
since California is both the largest state (39 million people), the largest consumer of gasoline, and
a major ethanol consumer of approximately 1.5 billion gallons annually.74
A 2010 analysis from Purdue University concluded that CARB overestimated the ILUC impact of
grain-based ethanol by a factor of two in developing its LCFS.75 In October 2011, researchers at

70 For more information see “Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section
202(a) of the Clean Air Act,” EPA, at http://www.epa.gov/climatechange/endangerment.html.
71 DTN Ag Policy Blog, “Senators Face Emissions Test,” Chris Clayton, June 9, 2010.
72 For more information, see “Low Carbon Fuel Standard,” California Energy Commission, at
http://www.energy.ca.gov/low_carbon_fuel_standard/index.html.
73 For more information see, “Proposed Regulation to Implement the Low Carbon Fuel Standard,” Initial Statement of
Reasons, Vol. 1, CARB, March 5, 2009, at http://www.arb.ca.gov/fuels/lcfs/lcfs.htm.
74 Todd Neeley, “US Scientists Demand Revision of Biofuels Carbon Accounting,” DTN Ethanol blog, May 25, 2010.
75 “New Study Undercuts California Low Carbon Fuel Standard, Shows Evolving Land Use Change Debate,”
Renewable Fuels Association (RFA), news entry, April 28, 2010, at http://www.ethanolrfa.org. The final version of the
Purdue study was released as, “Land Use Changes and Consequent CO2 Emissions due to US Corn Ethanol
(continued...)
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the Department of Energy’s Oak Ridge National laboratory (ORNL) concluded that ILUC
resulting from expanded corn ethanol production over the past decade has likely been “minimal to
zero.”76 The ORNL research was presented to CARB in early October. On November 18, CARB
adopted a resolution to integrate the latest ILUC research based on the Purdue study into the
LCFS regulation. As a result it is anticipated that the ILUC penalty for corn ethanol will be cut by
at least half by spring of 2011.77 In light of the CARB revisions to its ILUC models and their
consequent impact on GHG, the Renewable Fuels Association (RFA) wrote an open letter to the
EPA on November 23, 2010, requesting that the EPA also incorporate the new research into
modeling of lifecycle GHG emissions under the RFS2.78
On December 24, 2009, several ethanol groups (including RFA and Growth Energy) filed a
lawsuit asserting that the California LCFS violated the U.S. Constitution by seeking to regulate
farming and ethanol production practices in the United States under the “commerce clause,”
which leaves regulation of interstate commerce to the federal government.79 On December 29,
2011, a U.S. district judge ruled that California’s LCFS law did violate the U.S. Constitution’s
commerce clause. The U.S. District Court of the Eastern District of California then issued an
injunction halting enforcement of California’s LCFS. The judge ruled that CARB had failed to
establish that there are no alternative methods to advance its goals of reducing GHG emissions to
combat global warming. As a result, corn-based ethanol from the Midwest, which had been
classified as a high-carbon fuel under the LCFS, will now be eligible for use in California. The
ruling allows CARB to appeal the court’s decision immediately to the U.S. Court of Appeals for
the Ninth Circuit.
Trade Issues
Three trade issues (including Chinese anti-dumping charges against an ethanol by-product, an
anti-dumping investigation against European Union imports of U.S. ethanol, and an unexpected
surge in U.S. ethanol exports) have emerged in 2011 that, if realized, could slow further
development of the U.S. biofuels sector.
China Anti-Dumping Investigation of U.S. DDGs
On December 28, 2010, China initiated an antidumping investigation into imports from the
United States of distiller’s dried grains (DDGs)—a by-product of the conversion of corn into

(...continued)
Production: A Comprehensive Analysis,” Wallace E. Tyner, Farzad Taheripour, Qianlai Zhuang, Dileep Birur, and Uris
Baldos, Dept of Agr. Econ., Purdue University, July 2010; at http://www.transportation.anl.gov/pdfs/MC/625.PDF.
76 “Dept. of Energy Researchers: ILUC Impact ‘Minimal to Zero’”, RFA, 2010 Press Releases, October 20, 2010, at
http://www.ethanolrfa.org; and “Empirical Analysis of the Sources of Corn Used for Ethanol Production in the United
States: 2001-2009,” presentation to National Corn Growers Assoc. by Debo Oladosu and Keith Kline, ORNL,
November 4, 2010; at http://www.ornl.gov/sci/besd/cbes/Symposia/
Empirical_Analysis_Source_Corn_Ethanol_Nov2010.pdf.
77 “CARB Responds to Industry Urging, Will Cut LCFS Penalty for Ethanol in Half”, RFA, 2010 Press Releases,
November 19, 2010, at http://www.ethanolrfa.org.
78 “RFA to EPA: Reevaluate Modeling of Lifecycle GHG Emissions Under RFS2”, RFA, 2010 Press Releases,
November 29, 2010, at http://www.ethanolrfa.org.
79 Todd Neely, “Court Strikes Down California LCFS: Ruling Opens Door to Large Ethanol Market,” DTN: The
Progressive Farmer, December 29, 2011.
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ethanol that is a relatively high-protein (30%) animal feed. In China DDGs are used primarily for
feeding swine and poultry.80 U.S. DDG exports grew rapidly during 2010, reportedly rising from
about 530,000 tons in 2009 to 2.9 million tons (valued at over $450 million)—a surge of nearly
550%. Four Chinese firms that account for approximately 50% of Chinese ethanol production
appear to be the petitioners. The Chinese firms allege that the U.S. is dumping DDG into their
livestock markets whereas high internal corn prices make Chinese DDGs uncompetitive.
Several news sources report that the anti-dumping probe is a retaliatory response to a U.S.
complaint filed at the WTO against Chinese wind power subsidies. Whatever the reason, U.S.
DDG exporters could face duties as high as 50% while the investigation is ongoing and starting as
early as June 2011.81 Duties could be raised as high as 100% toward the end of the investigation.
China is the third-leading importer of U.S. DDG exports. Loss of the Chinese DDG market could
result in lower U.S. DDG prices and cut into the profit margin of U.S. ethanol producers. The
U.S. Grains Council is organizing the industry response to China’s DDG anti-dumping
investigation.82 As of January 17, 2012, China’s anti-dumping case remains active, and Chinese
purchases of U.S. DDGs slowed considerably year-to-year in June; however, no additional tariffs
have been imposed.
EU Launches Trade Dispute Over Surging U.S. Ethanol Exports
U.S. ethanol exports surged to record levels during 2011 (Figure 9), driven in part by blending
wall limits, but also motivated in part by a sharp fall-off in Brazil’s ethanol exports due to high
international sugar prices. Based on the export pace through the first 11 months of 2011, the
United States will export over 1.1 billion gallons of ethanol, or about 8% of 2011 production. The
top three destinations for U.S. ethanol exports in 2011 are Brazil (32%), Canada (26%), and the
European Union (EU) (25%). Large U.S. ethanol exports are problematic in that they run counter
to the often-cited policy goal of national energy security.
EU policy has promoted renewable energy use, along with GHG reductions and energy
conservation, for much of the past decade.83 As a result, EU policy support has engendered a
substantial domestic renewable energy industry. As part of a “Renewable Energy Directive”
adopted by the European Parliament on December 17, 2008, the EU established a 20-20-20 plan
that calls for a 20% reduction in GHG emissions compared to 1990 levels, a 20% increase in
renewable energy use, and a 20% reduction in overall energy consumption. As part of the 20-20-
20 plan, the EU also adopted a mandate for renewable content in transportation fuels of 5.75% in
2010, rising to 10% by 2020.
The anti-dumping (AD) and countervailing duty (CVD) investigations were requested by ePURE,
an association of European ethanol producers, which claimed that the importation of subsidized
U.S. ethanol was hurting EU biofuel producers. The association argued that the surge in U.S.
ethanol exports was the result of federal and state tax credits and other subsidy support provided

80 “China Says It Will Investigate Dumping of U.S. Ethanol By-Products,” China Update, Inside U.S. Trade, January 7,
2011.
81 “China Anti-Dumping Probe Concerns Ethanol Producers,” Cheryl Anderson, DTN News Service, January 11, 2011.
82 “US DDGS Industry Responds to China’s DDGS Anti-Dumping Investigation,” U.S. Grain Council, January 14,
2011, at http://www.grains.org/news-events/2846-us-ddgs-industry-responds-to-chinas-ddgs-anti-dumping-
investigation.
83 See the European Commission’s official “Renewable Energy” website at http://ec.europa.eu/energy/renewables/.
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to U.S. ethanol producers. On November 25, 2011, the EU initiated an anti-dumping investigation
into whether U.S. exporters sold ethanol at unfair prices and were backed by subsidies in
violation of international trade rules to the detriment of EU producers.84
Figure 9. U.S. Ethanol Exports Surge in 2011
1,200
1,000
800
Million Gallons
600
400
200
0
1990
1995
2000
2005
2010

Source: U.S. Department of Commerce, U.S. Census Bureau, Foreign Trade Statistics.
Note: 2011 data are projected by CRS based on January through November export data.
At issue is a European allegation that international ethanol traders were exporting E90 (90%
ethanol blends) to Europe to take advantage of the EU’s lower tariff on such blends as well as the
tax incentive for ethanol blending in the United States—the $0.45 per gallon incentive known as
VEETC (which expired on December 31, 2011). In response to the EU anti-dumping
investigation, the RFA pointed out that the ethanol tax credits (most of which expired on
December 31, 2011) were not made available to U.S. ethanol producers, but “to gasoline
blenders, marketers, and other end users.”85 If the EU finds the complaint viable, it could impose
tariffs on U.S. ethanol, as it did in 2009 when similar complaints against U.S. biodiesel exports
led to the imposition by the EU of 40% duties for a five-year period.86



84 World Trade Online, “EU Launches AD, CVD Investigations into U.S. Ethanol Exports,” December 8, 2011.
85 “RFA Responds to EU Ethanol Investigation,” RFA News Release, November 28, 2011; http://www.ethanolrfa.org.
86 Agri-Pulse, “RFA Tells EU: ‘It’s Not Us!” November 30, 2011.
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Author Contact Information

Randy Schnepf

Specialist in Agricultural Policy
rschnepf@crs.loc.gov, 7-4277


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