Order Code RL32712
CRS Report for Congress
Received through the CRS Web
Agriculture-Based Renewable Energy Production
Updated May 18, 2006
Randy Schnepf
Specialist in Agricultural Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress

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Agriculture-Based Renewable Energy Production
Summary
Since the late 1970s, U.S. policy makers 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 renewable energy. Motivations cited for
these legislative initiatives include energy security concerns, reduction in greenhouse
gas emissions, and raising domestic demand for U.S.-produced farm products.
Agricultural households and rural communities have responded to these
government incentives and have expanded their production of renewable energy,
primarily in the form of biofuels and wind power, every year since 1996. The
production of ethanol (the primary biofuel produced by the agricultural sector) has
risen from about 175 million gallons in 1980 to 3.9 billion gallons per year in 2005.
Biodiesel production is at a much smaller level, but has also shown growth rising
from 0.5 million gallons in 1999 to an estimated 75 million gallons in 2005. Wind
energy systems production capacity has also grown rapidly, rising from 1.7 million
megawatts in 1997 to an estimated 9.1 million megawatts by January 2006.
Despite this rapid growth, agriculture- and rural-based energy production
accounted for only about 0.6% of total U.S. energy consumption in 2004 (571 trillion
Btu (British Thermal Units) out of 98,200 trillion Btu). Ethanol accounted for about
74% of agriculture-based energy production, wind energy systems for 25%, and
biodiesel energy output for 1%.
Key points that emerge from this report are:
! agriculture has been rapidly developing its renewable energy
production capacity (primarily as biofuels and wind); however, this
growth has depended heavily on federal and state programs and
incentives;
! rising fossil fuel prices improve renewable energy’s market
competitiveness; however, significant improvement of existing
technology or the development of new technology still is needed for
current biofuel production strategies to be economically competitive
with existing fossil fuels in the absence of government support; and
! a review of available data suggests that farm-based energy
production is unlikely to be able to substantially reduce the nation’s
dependence on petroleum imports unless there is a significant
decline in consumption. Also, other uses (food, animal feed,
industrial processing, etc.) of biomass feedstocks are likely to be
adversely impacted by rapid growth in use for bioenergy.
This report provides background information on farm-based energy production
and how this fits into the national energy-use picture. It briefly reviews the primary
agriculture-based renewable energy types and issues of concern associated with their
production, particularly their economic and energy efficiencies and long-run supply.
Finally, this report examines the major legislation related to farm-based energy
production and use. This report will be updated as events warrant.

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Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Agriculture’s Share of Energy Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Agriculture-Based Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Corn-Based Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Ethanol from Cellulosic Biomass Crops . . . . . . . . . . . . . . . . . . . . . . . 12
Methane from an Anaerobic Digester . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Biodiesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Box: Primer on Measuring Electric Energy . . . . . . . . . . . . . . . . . . . . . . . . . 28
Public Laws That Support Agriculture-Based Energy Production and Its Use . . 29
Clean Air Act Amendments of 1990 (CAAA; P.L. 101-549) . . . . . . . . . . . 29
Energy Policy Act of 1992 (EPACT; P.L. 102-486) . . . . . . . . . . . . . . . . . . 29
Biomass Research and Development Act of 2000 (Biomass Act; Title III, P.L.
106-224) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Energy Provisions in the 2002 Farm Bill (P.L. 107-171) . . . . . . . . . . . . . . 31
The Healthy Forest Restoration Act of 2003 (P.L. 108-148) . . . . . . . . . . . . 34
The American Jobs Creation Act of 2004 (P.L. 108-357) . . . . . . . . . . . . . . 34
Energy Policy Act of 2005 (EPACT; P.L. 109-58) . . . . . . . . . . . . . . . . . . . 35
Agriculture-Related Energy Bills in 109th Congress . . . . . . . . . . . . . . . . . . 38
State Laws and Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
For More Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Renewable Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
List of Figures
Figure 1. U.S. Ethanol Production, Actual 1980-2005 and
Projected 2006-2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Figure 2. Corn versus Gasoline Prices, 1991-2006 . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 3. U.S. Biodiesel Production, 1998-2005 . . . . . . . . . . . . . . . . . . . . . . . . 17
Figure 4. Soybean Oil vs Diesel Fuel Prices, 1994 to 2006 . . . . . . . . . . . . . . . . 19
Figure 5. U.S. Installed Wind Energy Capacity, 1981-2006P . . . . . . . . . . . . . . 23
Figure 6. Natural Gas Price, Wellhead, 1998 to 2005 . . . . . . . . . . . . . . . . . . . . 26
Figure 7. U.S. Areas with Highest Wind Potential . . . . . . . . . . . . . . . . . . . . . . . 27

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List of Tables
Table 1. U.S. Energy Production and Consumption, 2004 . . . . . . . . . . . . . . . . . . 2
Table 2. Ethanol Production Capacity by State, April 2006 . . . . . . . . . . . . . . . . . 6
Table 3. Energy and Price Comparisons for Alternate Fuels, February 2006 . . . . 9
Table 4. U.S. Diesel Fuel Use, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Table 5. U.S. Potential Biodiesel Feedstocks, 2002-2003 . . . . . . . . . . . . . . . . . 21
Table 7. Installed Wind Energy Capacity by State, Jan. 24, 2006 . . . . . . . . . . . 24

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Agriculture-Based
Renewable Energy Production
Introduction
Agriculture’s role as a consumer of energy is well known.1 However, under the
encouragement of expanding government support the U.S. agricultural sector also is
developing a capacity to produce energy, primarily as renewable biofuels and wind
power. Farm-based energy production — biofuels and wind-generated electricity —
has grown rapidly in recent years, but still remains small relative to total national
energy needs. In 2004, ethanol, biodiesel, and wind provided 0.6% of U.S. energy
consumption (Table 1). Ethanol accounted for about 74% of agriculture-based
energy production in 2004; wind energy systems for 25%; and biodiesel for 1%.
In general, fossil-fuel-based energy is less expensive to produce and use than
energy from renewable sources.2 However, since the late 1970s, U.S. policy makers
at both the federal and state levels have enacted a variety of incentives, regulations,
and programs to encourage the production and use of cleaner, renewable agriculture-
based energy.3 These programs have proven critical to the economic success of rural
renewable energy production. The benefits to rural economies and to the environment
contrast with the generally higher costs, and have led to numerous proponents as well
as critics of the government subsidies that underwrite agriculture-based renewable
energy production.
Proponents of government support for agriculture-based renewable energy have
cited national energy security, reduction in greenhouse gas emissions, and raising
domestic demand for U.S.-produced farm products as viable justification.4 In
addition, proponents argue that rural, agriculture-based energy production can
1 For more information on energy use by the agricultural sector, see CRS Report RL32677,
Energy Use in Agriculture: Background and Issues, by Randy Schnepf.
2 Excluding the costs of externalities associated with burning fossil fuels such as air
pollution, environmental degradation, and illness and disease linked to emissions.
3 See section on “Public Laws That Support Agriculture-Based Energy Production and Use,”
below, for a listing of major laws supporting farm-based renewable energy production.
4 For examples of proponent policy positions, see the National Corn Growers Association
(NCGA) at [http://www.ncga.com/ethanol/main/index.htm], and the American Soybean
Association (ASA) at [http://www.soygrowers.com/policy/].

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CRS-2
enhance rural incomes and employment opportunities, while encouraging greater
value-added for U.S. agricultural commodities.5
Table 1. U.S. Energy Production and Consumption, 2004
Production
Consumption
Quadrillion
Quadrillion
% of
Energy source
Btu
% of total
Btu
total
Total
70.4
100.0%
99.7
100.0%
Fossil Fuels
56.0
80.1%
85.6
85.9%
Petroleum and products
11.5
16.4%
40.1
40.2%
Coal
22.7
32.2%
22.4
22.4%
Natural Gas
21.8
31.0%
23.0
23.1%
Nuclear
8.2
11.7%
8.2
8.3%
Renewables
6.1
8.7%
6.1
6.1%
Hydroelectric power
2.7
3.9%
2.7
2.7%
Biomass
2.8
4.0%
2.8
2.9%
Wood, waste, other
2.4
3.4%
2.4
2.4%
Ethanol
0.4
0.6%
0.4
0.4%
Biodiesel
0.0
0.0%
0.0
0.0%
Geothermal
0.3
0.5%
0.3
0.3%
Solar
0.1
0.1%
0.1
0.1%
Wind
0.1
0.2%
0.1
0.1%
Source: Ethanol data: Renewable Fuels Association, [http://www.ethanolrfa.org]; biodiesel data:
National Biodiesel Board, [http://www.biodiesel.org]; all other data: DOE, Energy Information
Agency (EIA), Historical Data, Annual Energy Overview, Tables 1.2 and 1.3, [http://www.eia.doe.
gov/emeu/aer/overview.html].
In contrast, petroleum industry critics of biofuel subsidies argue that
technological advances such as seismography, drilling, and extraction continue to
expand the fossil-fuel resource base, which remains far cheaper and more accessible
than biofuel supplies. Other critics argue that current biofuel production strategies
can only be economically competitive with existing fossil fuels in the absence of
subsidies if significant improvements in existing technologies are made or new
technologies are developed.6 Until such technological breakthroughs are achieved,
5 Several studies have analyzed the positive gains to commodity prices, farm incomes, and
rural employment attributable to increased government support for biofuel production. For
examples, see the “For More Information” section at the end of this report.
6 Advocates of this position include free-market proponents such as the Cato Institute, and
(continued...)

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CRS-3
critics contend that the subsidies distort energy market incentives and divert research
funds from the development of other potential 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 feedstocks of either starches, sugars, or vegetable oils to permit biofuel
production to meaningfully offset petroleum imports.7 Finally, there are those who
argue that the focus on development of alternative energy sources undermines efforts
to conserve and reduce the nation’s energy dependence.
This report will discuss and compare agriculture-based energy production of
ethanol, biodiesel, and wind energy based on three criteria:
! Economic Efficiency compares the price of agriculture-based
renewable energy with the price of competing energy sources,
primarily fossil fuels.
! Energy Efficiency compares energy output from agriculture-based
renewable energy relative to the fossil energy used to produce it.
! Long-Run Supply Issues consider supply and demand factors that
are likely to influence the growth of agriculture-based energy
production.
Several additional criteria may be used for comparing different fuels, including
performance, emissions, safety, and infrastructure needs. For more information on
these additional criteria and others, see CRS Report RL30758, Alternative
Transportation Fuels and Vehicles: Energy, Environment, and Development Issues,
by Brent D. Yacobucci.
Agriculture’s Share of Energy Production
In 2004, the major agriculture-produced energy source — ethanol — accounted
for about 1.6% of U.S. gasoline motor-vehicle consumption8 and about 0.3% of total
6 (...continued)
federal budget watchdog groups such as Citizens Against Government Waste and Taxpayers
for Common Sense.
7 For example, see Robert Wisner and Phillip Baumel, “Ethanol, Exports, and Livestock:
Will There be Enough Corn to Supply Future Needs?,” Feedstuffs, no. 30, vol. 76, July 26,
2004.
8 Based on projected motor vehicle fuel use, DOE, Energy Information Agency (EIA),
“Table 10. Estimated Consumption of Vehicle Fuels in the United States, 1995-2004,” at
(continued...)

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CRS-4
U.S. energy consumption (see Table 1). In addition to ethanol production, several
other renewable energy sources — biodiesel, wind, anaerobic digesters, and non-
traditional biomass — also appear to offer particular advantages to the agricultural
sector. Presently, the volume of agriculture-based energy produced from these
emerging renewable sources is small relative to ethanol production. However, an
expanding list of federal and state incentives, regulations, and programs that were
enacted over the past decade have helped to encourage more diversity in renewable
energy production and use.
Agriculture-Based Biofuels
Biofuels are liquid fuels produced from biomass. Types of biofuels include
ethanol, biodiesel, methanol, and reformulated gasoline components.9 The Biomass
Research and Development Act of 2000 (P.L. 106-224; Title III) defines biomass as
“any organic matter that is available on a renewable or recurring basis, including
agricultural crops and trees, wood and wood wastes and residues, plants (including
aquatic plants), grasses, residues, fibers, and animal wastes, municipal wastes, and
other waste materials.”
Biofuels are primarily used as transportation fuels for cars, trucks, buses,
airplanes, and trains. As a result, their principal competitors are gasoline and diesel
fuel. Unlike fossil fuels, which have a fixed resource base that declines with use,
biofuels are produced from renewable feedstocks. Furthermore, under most
circumstances biofuels are more environmentally friendly (in terms of emissions of
toxins, volatile organic compounds, and greenhouse gases) than petroleum products.
Supporters of biofuels emphasize that biofuel plants generate value-added economic
activity that increases demand for local feedstocks, which raises commodity prices,
farm incomes, and rural employment.
Ethanol
Ethanol, or ethyl alcohol, is an alcohol made by fermenting and distilling simple
sugars.10 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 feedstocks
that contain sugar. Corn contains starch that can relatively easily be converted into
sugar. In the United States corn is the principal ingredient used in the production of
ethanol; in Brazil (traditionally the world’s largest ethanol producer), sugar cane is
the primary feedstock. A significant percentage of trees and grasses are made up of
cellulose which can also be converted to sugar, although with more difficulty than
required to convert starch. In recent years, researchers have begun experimenting
8 (...continued)
[http://www.eia.doe.gov/cneaf/alternate/page/datatables/aft1-13_03.html]; and estimated
ethanol use, Renewable Fuels Association, “Industry Statistics,” at [http://www.ethanolrfa.
org/industry/statistics/].
9 For more information on alternative fuels, see CRS Report RL30758, Alternative
Transportation Fuels and Vehicles: Energy, Environment, and Development Issues, by
Brent D. Yacobucci. See also DOE, National Renewable Energy Laboratory (NREL),
Biomass Energy Basics, available at [http://www.nrel.gov/learning/re_biomass.html].
10 For more information, see CRS Report RL33290, Fuel Ethanol: Background and Public
Policy Issues, by Brent D. Yacobucci.

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CRS-5
with the possibility of growing hybrid grass and tree crops explicitly for ethanol
production. In addition, sorghum and potatoes, as well as crop residue and animal
waste, are potential feedstocks.
Ethanol production has shown rapid growth in the United States in recent years
(Figure 1). Several events contributed to the historical growth of ethanol production:
the energy crises of the early and late 1970s; a partial exemption from the motor fuels
excise tax (legislated as part of the Energy Tax Act of 1978); ethanol’s emergence
as a gasoline oxygenate; and provisions of the Clean Air Act Amendments of 1990
that favored ethanol blending with gasoline.11 Ethanol production is projected to
continue growing rapidly through at least 2012 on the strength of both the extension
of existing and the addition of new government incentives (described below).
Figure 1. U.S. Ethanol Production,
Actual 1980-2005 and Projected 2006-2012
8000
Renewable
Fuels
6000
Standard
4000
2000
Actual
0
1980 1985 1990 1995 2000 2005 2010
Source: 1980-2005, American Coalition for Ethanol; [www.ethanol.org];
projections for 2006-2012 are based on Renewable Fuels Mandate of 7.5
billion gallons met entirely by domestic ethanol production.
U.S. ethanol production presently is underway or planned in 20 states based
primarily around the central and western Corn Belt, where corn supplies are most
plentiful (see Table 2).12 Corn accounts for about 95% of the feedstocks used in
ethanol production in the United States. As of April 27, 2006, existing U.S. ethanol
plant capacity was a reported 4,486 million gallons per year (MGPY), with an
additional capacity of 2,230 MGPY under construction. Thus, total annual U.S.
11 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.
12 See Renewable Fuels Association, Industry Statistics, at [http://www.ethanolrfa.org/
industry/statistics/].

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CRS-6
ethanol production capacity in existence or under construction as of April 27, 2006,
was 6.7 billion gallons.
Corn-Based Ethanol. USDA estimated that 1.6 billion bushels of corn (or
14.4% of total U.S. corn production) from the 2005 corn crop were used to produce
ethanol during the 2005/06 (September-August) corn marketing year.13 Despite its
rapid growth, ethanol production represents a minor part of U.S. gasoline
consumption. In calendar 2005, U.S. ethanol production of 3.9 billion gallons
accounted for about a 2% projected share of national gasoline use (2.6 billion
gasoline-equivalent gallons (GEG) out of a projected 139.9 billion gallons).14
Table 2. Ethanol Production Capacity by State, April 2006
State
Currently operating
Under construction
Total
Million
Million
Million
gal/yr %
gal./yr.
gal/yr
%
Iowa
1,218
27%
480
1,698
25%
Nebraska
553
12%
504
1,057
16%
Illinois
724
16%
107
831
12%
South Dakota
585
13%
238
823
12%
Minnesota
536
12%
58
594
9%
Indiana
102
2%
290
392
6%
Wisconsin
188
4%
40
228
3%
Michigan
50
1%
157
207
3%
Kansas
167
4%
40
207
3%
Missouri
110
2%
45
155
2%
Others
253
6%
271
523
8%
U.S. Total
4,486
100%
2,230
6,715
100%
Source: Renewable Fuels Association, Industry Statistics: U.S. Fuel Ethanol Production Capacity,
at [http://www.ethanolrfa.org/industry/statistics/], April 27, 2006.
Economic Efficiency. Ethanol’s primary fuel competitor is gasoline.
Wholesale ethanol prices, before incentives from the federal and state governments,
are generally significantly higher than those of their fossil fuel counterparts. For
example, during January-February 2006, the average retail price of E85 (a blend of
85% ethanol with 15% gasoline) was $2.75 per GEG, compared with $2.23 for
13 Corn use for ethanol: USDA, World Agricultural Outlook Board, World Agricultural
Supply and Demand Estimates, May 12, 2006.
14 Based on a conversion rate of 1.73 GEG per bushel of corn (2.7 gallons of ethanol per
bushel of corn and 0.67 GEG per gallon of ethanol). DOE, IEA, “Table 10. Estimated
Consumption of Vehicle Fuels in the United States, 1995-2004,” at [http://www.eia.doe.gov/
cneaf/alternate/page/datatables/aft1-13_03.html]. CRS projections based on DOE/EIA data
and extrapolated growth rates.

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CRS-7
regular grade gasoline (see Table 3).15 The price difference of 52¢ on an 85% blend
implies that pure (100%) ethanol costs 61¢ per GEG more than gasoline. The federal
production tax credit of 51¢ per gallon of pure ethanol (see below) offsets much of
the price difference, thereby helping ethanol to compete in the marketplace.
Apart from government incentives, the economics underlying corn-based
ethanol’s market competitiveness hinge on the following factors:
! the price of feedstocks, primarily corn;
! the price of the processing fuel, primarily natural gas or electricity,
used at the ethanol plant;
! the cost of transporting feedstocks to the ethanol plant and
transporting the finished ethanol to the user; and
! the price of feedstock co-products (for dry-milled corn: distillers
dried grains; for wet-milled corn: corn gluten feed, corn gluten meal,
and corn oil).
Higher prices for corn, processing fuel, and transportation hurt ethanol’s market
competitiveness, while higher prices for corn by-products and gasoline improve
ethanol’s competitiveness in the marketplace.
Feedstock costs are the largest single cost factor in the production of ethanol.
Each bushel of corn yields approximately 2.7 gallons of ethanol. As a result, the
relative relationship of corn to gasoline prices provides a strong indicator of the
ethanol industry’s well-being (see Figure 2). A comparison of corn versus gasoline
prices suggests that the general trend since the late 1990s has clearly been in
ethanol’s favor as national average monthly gasoline prices have surged above the
$2.00 per gallon level while corn prices have fluctuated around the $2.00 per bushel
level since the late 1990s.
15 DOE, Energy Efficiency and Renewable Energy (EERE), Alternative Fuel Price Report,
Feb. 2006, at [http://www.eere.energy.gov/afdc/resources/pricereport/price_report.html].

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CRS-8
Figure 2. Corn vs. Gasoline Prices, 1991-2006
5
3
Gasoline
4
2
3
1
2
Corn
1
0
1991
1994
1997
2000
2003
2006
Source: Prices are monthly averages: Corn,No.2, yellow, Chicago; USDA,
AMS; gasoline prices are national average retail, DOE, EIA;.
Feedstock costs are the largest single cost factor in the production of ethanol.
Each bushel of corn yields approximately 2.7 gallons of ethanol. As a result, the
relative relationship of corn to gasoline prices provides a strong indicator of the
ethanol industry’s well-being (see Figure 2). A comparison of corn versus gasoline
prices suggests that the general trend since the late 1990s has clearly been in
ethanol’s favor as national average monthly gasoline prices have surged above the
$2.00 per gallon level while corn prices have fluctuated around the $2.00 per bushel
level since the late 1990s.
Government Support. Federal subsidies help ethanol to overcome its higher
cost relative to gasoline. The Energy Tax Act of 1978 first established a partial
exemption for ethanol fuel from federal fuel excise taxes.16 In addition to the partial
excise tax exemption, certain income tax credits are available for motor fuels
containing biomass alcohol. However, the different tax credits are coordinated such
that the same biofuel cannot be claimed for both income and excise tax purposes.
The primary federal incentives include:17
! a production tax credit of 51¢ per gallon of pure (100%) ethanol —
the tax incentive was extended through 2010 and converted to a tax
credit from a partial tax exemption of the federal excise tax under
the American Jobs Creation Act of 2004 (P.L. 108-357);
! a small producer income tax credit (26 U.S.C. 40) of 10¢ per gallon
for the first 15 million gallons of production for ethanol producers
16 For a legislative history of federal ethanol incentives, see GAO, Tax Incentives for
Petroleum and Ethanol Fuels, RCED-00-301R, Sept. 25, 2000.
17 For more information, see section on “Public Laws That Support Agriculture-Based
Energy Production and Use,” below.

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CRS-9
whose total output does not exceed 60 million gallons of ethanol per
year (extended from 30 to 60 million under Sec. 1347 of P.L. 109-
58); and
! incentive payments (contingent on annual appropriations) on year-
to-year production increases of renewable energy under USDA’s
Bioenergy Program (7 U.S.C. 8108).
Indirectly, other federal programs support ethanol production by requiring
federal agencies to give preference to biobased products in purchasing fuels and other
supplies and by providing incentives for research on renewable fuels. Also, several
states have their own incentives, regulations, and programs in support of renewable
fuel research, production, and consumption that supplement or exceed federal
incentives.
Energy Efficiency. The net energy balance (NEB) of a fuel can be expressed
as a ratio of the energy produced from a production process relative to the energy
used in the production process. An output/input ratio of 1.0 implies that energy
output equals energy input. The critical factors underlying ethanol’s energy
efficiency or NEB include:
! corn yields per acre;
! the energy efficiency of corn production, including the energy
embodied in inputs such as fuels, fertilizers, pesticides, seed corn,
and cultivation practices;
! the energy efficiency of the corn-to-ethanol production process —
about 79% of the corn used for ethanol is processed by “dry” milling
(a grinding process) where the average conversion rate was
estimated at 2.64 gallons of ethanol per bushel of corn; and about
21% is processed by “wet” milling plants (a chemical extraction
process) which yields 2.68 gallons per bushel;18 and
! the energy value of corn by-products.
Table 3. Energy and Price Comparisons for Alternate Fuels,
February 2006
National
National
Btu’s per
Avg. Price:
Avg. Price:
Fuel type
Unit
unita
$ per unit
GEGb
$ per GEG
Gasoline:
gallon
125,071
$2.23
1.00
$2.23
conventional
Ethanol (E85)c
gallon
90,383
$1.98
0.72
$2.75
Diesel fuel
gallon
138,690
$2.56
1.11
$2.31
Biodiesel (B20)
gallon
138,690
$2.64
1.11
$2.38
18 Dry milling and wet milling production shares are from the Renewable Fuels Association,
Ethanol Industry Outlook 2006. Ethanol yield rates are from Shapouri et al., AER 813
(2002), p. 9. According to USDA, dry milling is more energy efficient than wet milling,
particularly when corn co-products are considered. These ethanol yield rates have been
improving gradually overtime with technological improvements in the efficiency of ethanol
processing from corn.

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CRS-10
Propane
gallon
91,333
$1.98
0.74
$2.68
Compressed
Natural Gasd
gallon
35,500
$0.56
0.28
$1.99
Natural Gase
1,000 ft.3
1,030,000
$9.34
8.24
$1.13
Biogas
1,000 ft.3
10 x (% of
methane)f
na
na
na
Electricityg
kilowatt-
3,413
5¢ - 9¢
na
na
hour
Source: Prices are for Jan.-Feb. 2006; DOE, EIA, Clean Cities Alternative Fuel Price Report, Feb.
2006; [http://www.eere.energy.gov/afdc/resources/pricereport/price_report.html].
na = not applicable.
a. Conversion rates for petroleum-based fuels and electricity are from DOE, Monthly Energy Review,
August 2004. A Btu (British thermal unit) is a measure of the heat content of a fuel and
indicates the amount of energy contained in the fuel. Because energy sources vary by form (gas,
liquid, or solid) and energy content, the use of Btu’s provides a common benchmark for various
types of energy.
b. GEG = gasoline equivalent gallon. The GEG allows for comparison across different forms — gas,
liquid, kilowatt, etc. It is derived from the Btu content by first converting each fuel’s units to
gallons, then dividing each fuel’s Btu unit rate by gasoline’s Btu unit rate of 125,071, and finally
multiplying each fuel’s volume by the resulting ratio.
c. 100% ethanol has an energy content of 84,262 Btu per gallon.
d. Compressed natural gas (CNG) is generally stored under pressure at between 2,000 to 3,500
pounds per square inch (psi). The energy content varies with the pressure. For simplification,
data in this table assumes that CNG is stored at 3,000 psi with an energy content of 35,500 Btu
per gallon.
e. Natural Gas prices, $ per 1,000 cu. ft., are industrial prices for the month of Feb. 2006, from DOE,
EIA, available at [http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm].
f. When burned, biogas yields about 10 Btu per percentage of methane composition. For example,
65% methane yields 650 Btu per cubic foot or 650,000 per 1,000 cu. ft.
g. Prices are for total industry electricity (all sectors) rates per kilowatt-hour for 2004; from DOE,
EIA, available at [http://www.eia.doe.gov/cneaf/electricity/epa/epat7p4.html].
Over the past decade technical improvements in the production of agricultural
inputs (particularly nitrogen fertilizer) and ethanol, coupled with higher corn yields
per acre and stable or lower input needs, appear to have raised ethanol’s NEB. In
2004, USDA economists reported that, assuming “best production practices and state
of the art processing technology,” the NEB of corn-ethanol (based on 2001 data) was
a positive 1.67 — that is, 67% more energy was returned from a gallon of ethanol
than was used in its production.19 This compares with an NEB of 0.81 for gasoline
— that is, 19% less energy is returned from a gallon of gasoline than is used in its life
19 H. Shapouri, J. Duffield, and M. Wang, New Estimates of the Energy Balance of Corn
Ethanol, presented at 2004 Corn Utilization & Technology Conference of the Corn Refiners
Association, June 7-9, 2004, Indianapolis, IN (hereafter cited as Shapouri (2004)).

---

CRS-11
cycle from source to user.20 Other researchers have found much lower NEB values
under less optimistic assumptions, leading to some dispute over corn-to-ethanol’s
representative NEB.21 However, a recent study compared several major corn-to-
ethanol NEB analyses and found that, when by-products are properly accounted for,
the corn-to-ethanol process has a positive NEB (i.e., greater than 1.0) and that the
NEB is improving with technology.22
Long-Run Supply Issues. Despite improving energy efficiency, the ability
for domestic ethanol production to measurably substitute for petroleum imports is
questionable, particularly when ethanol production depends almost entirely on corn
as the primary feedstock. The import share of U.S. petroleum consumption was
estimated at 54% in 2004, and is expected to grow to 70% by 2025.23 Presently,
ethanol production accounts for about 1.6% of U.S. gasoline consumption while
using about 12% of the U.S. corn production. If the entire 2005 U.S. corn production
of 11.1 billion bushels were dedicated to ethanol production, the resultant 30 billion
gallons of ethanol (20.2 billion GEG) would represent about 14.5% of projected
national gasoline use of 139.1 billion gallons.24 In 2005, slightly more than 75
million acres of corn were harvested. Nearly 140 million acres would be needed to
produce enough corn and subsequent ethanol to substitute for 50% of petroleum
imports (or 27% of total U.S. petroleum consumption).25 Since 1970, corn harvested
acres have never reached 76 million acres. Thus, barring a drastic realignment of
U.S. field crop production patterns, corn-based ethanol’s potential as a petroleum
import substitute appears to be limited by a crop area constraint.
Domestic and international demand places additional limitations on corn use for
ethanol production in the United States. Corn traditionally represents about 57% of
feed concentrates and processed feedstuffs fed to animals in the United States.26
Also, the United States is the world’s leading corn exporter, with nearly a 66% share
of world trade during the past decade. In 2003/04, the United States exported nearly
19% of its corn production.
Growth in corn-for-ethanol use would reduce both exports and domestic feed
use of corn unless accompanied by offsetting growth in domestic production. There
is an inherent tradeoff in using a widely consumed agricultural product for a non-
agricultural use. As corn-based ethanol production increases, so does total corn
demand and corn prices. Higher corn prices, in turn, mean higher feed costs for
20 Minnesota Department of Agriculture, Energy Balance/Life Cycle Inventory for Ethanol,
Biodiesel and Petroleum Fuels, at [http://www.mda.state.mn.us/ethanol/balance.html].
21 Professor David Pimentel, Cornell University, College of Agriculture and Life Sciences,
has researched and published extensive criticisms of corn-based ethanol production.
22 Alexander E. Farrel et al, “Ethanol Can Contribute to Energy and Environmental Goals,”
Science, vol. 311 (Jan. 27, 2006), pp. 506-508.
23 DOE, EIA, Annual Energy Outlook 2004 with Projections to 2025.
24 Based on USDA’s Nov. 12, 2004, WASDE, and using comparable conversion rates.
25 Assuming corn yields of 150 bushel per acre, and an ethanol yield of 2.7 gal/bu.
26 USDA, ERS, Feed Situation and Outlook Yearbook, FDS-2003, Apr. 2003.

---

CRS-12
cattle, hog, and poultry producers. The corn co-products from ethanol processing
would likely substitute for some of the lost feed value of corn used in ethanol
processing.27 However, about 66% of the original weight of corn is consumed in
producing ethanol and is no longer available for feed.28 Higher corn prices would
also likely result in lost export sales. International feed markets are very price
sensitive as several different grains and feedstuffs are relatively close substitutes. A
sharp rise in U.S. corn prices would likely result in a more than proportionate decline
in corn exports.
Furthermore, as ethanol production increases, the energy needed to process the
corn into ethanol (derived primarily from natural gas) would increase. For example,
an estimated 209 billion cu. ft. of natural gas was used to process the 1.6 billion
bushels of corn into ethanol from the 2005 crop.29 The energy needed to process the
entire 2005 corn crop of 11.1 billion bushels into ethanol would be approximately
1.5 trillion cubic feet of natural gas. Total U.S. natural gas consumption was an
estimated 22.2 trillion cu. ft. in 2005.30 The United States has been a net importer of
natural gas since the early 1980s. Because natural gas is used extensively in
electricity production in the United States, significant increases in its use as a
processing fuel in the production of ethanol would likely result in substantial
increases in both prices and imports of natural gas.
These supply issues suggest that corn’s long-run potential as an ethanol
feedstock is somewhat limited. According to the DOE, the cost of producing and
transporting ethanol will continue to limit its use as a renewable fuel; ethanol relies
heavily on federal and state support to remain economically viable; and the supply
of ethanol is extremely sensitive to corn prices, as seen in 1996 when record farm
prices received for corn led to a sharp reduction in U.S. ethanol production. Finally,
DOE suggests that the ability to produce ethanol from low-cost biomass will
ultimately be the key to making it competitive as a gasoline additive.31
In contrast to expanded biofuel production, research suggests that far greater
fuel economies could be obtained by a small adjustment in existing vehicle mileage
requirements. For example, an increase in fuel economy of one mile per gallon
27 For a discussion of potential feed market effects due to growing ethanol production, see
Bob Kohlmeyer, “The Other Side of Ethanol’s Bonanza,” Ag Perspectives (World
Perspectives, Inc.), Dec. 14, 2004; and 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.
28 Shapouri (2004), p. 4.
29 CRS calculations based on Shapouri (2004) energy usage rates: 49,733 Btu/gal of ethanol;
1.6 billion bushels of corn processed into 4.3 billion gallons at 2.7 gal/bu.
30 DOE, EIA, Annual Energy Outlook 2006 with Projections to 2030, Table 1-Total Energy
Supply and Disposition Summary; at [http://www.eia.doe.gov/oiaf/aeo/index.html].
31 DOE, EIA, “Outlook for Biomass Ethanol Production and Demand,” by Joseph DiPardo,
July 30, 2002, available at [http://www.eia.doe.gov/oiaf/analysispaper/biomass.html];
hereafter referred to as DiPardo (2002).

---

CRS-13
across all passenger vehicles in the United States has been estimated to cut petroleum
consumption by more than all alternative fuels and replacement fuels combined.32
Ethanol from Cellulosic Biomass Crops.33 Besides corn, several other
agricultural products are viable feedstocks and appear to offer long-term supply
potential — particularly cellulose-based feedstocks. An emerging cellulosic
feedstock with apparently large potential as an ethanol feedstock is switchgrass, a
native grass that thrives on marginal lands as well as on prime cropland, and needs
little water and no fertilizer. The opening of Conservation Reserve Program (CRP)
land to switchgrass production under Section 2101 of the 2002 farm bill (P.L. 107-
171) has helped to spur interest in its use as a cellulosic feedstock for ethanol
production. Other potential cellulose-to-ethanol feedstocks include fast-growing
woody crops such as hybrid poplar and willow trees, as well as waste biomass
materials — logging residues, wood processing mill residues, urban wood wastes,
and selected agricultural residues such as sugar cane bagasse and rice straw.
The main impediment to the development of a cellulose-based ethanol industry
is the state of cellulosic conversion technology (i.e., the process of converting
cellulose-based feedstocks into fermentable sugars). Currently, cellulosic conversion
technology is rudimentary and expensive. As a result, no commercial cellulose-to-
ethanol facilities are in operation in the United States, although plans to build several
facilities are underway. On April 21, 2004, Iogen — a Canadian firm — became the
first firm to successfully engage in the commercial production of cellulosic ethanol
(from wheat straw) at a large-scale demonstration plant in Ottawa.34 In addition, pilot
facilities are operational in both the United States and Canada.

Economic Efficiency. The conversion of cellulosic feedstocks to ethanol
parallels the corn conversion process, except that the cellulose must first be
converted to fermentable sugars. As a result, the key factors underlying cellulosic-
based ethanol’s price competitiveness are essentially the same as for corn-based
ethanol, with the addition of the cost of cellulosic conversion.
Cellulosic feedstocks are significantly less expensive than corn; however, at
present they are more costly to convert to ethanol because of the extensive processing
required. Currently, cellulosic conversion is done using either dilute or concentrated
acid hydrolysis — both processes are prohibitively expensive. However, the DOE
suggests that enzymatic hydrolysis, which processes cellulose into sugar using
cellulase enzymes, offers both processing advantages as well as the greatest potential
for cost reductions. Current cost estimates of cellulase enzymes range from 30¢ to
32 CRS Report RL30758, Alternative Transportation Fuels and Vehicles: Energy,
Environment, and Development Issues, by Brent D. Yacobucci.
33 For more information on biomass from non-traditional crops as a renewable energy, see
the DOE, EERE, Biomass Program, “Biomass Feedstocks,” at [http://www1.eere.energy.
gov/biomass/biomass_feedstocks.html]. See also, Ethanol From Cellulose: A General
Review, P.C.Badger, Purdue University, Center for New Crops and Plant Products at
[http://www.hort.purdue.edu/newcrop/ncnu02/v5-017.html].
34 For more information visit Iogen Corporation’s website at [http://www.iogen.ca/].

---

CRS-14
50¢ per gallon of ethanol.35 The DOE is also studying thermal hydrolysis as a
potentially more cost-effective method for processing cellulose into sugar.
Based on the state of existing technologies and their potential for improvement,
the DOE estimates that improvements to enzymatic hydrolysis could eventually bring
the cost to less than 5¢ per gallon, but this may still be a decade or more away. Were
this to happen, then the significantly lower cost of cellulosic feedstocks would make
cellulosic-based ethanol dramatically less expensive than corn-based ethanol and
gasoline at current prices.
Iogen’s breakthrough involved the successful use of recombinant DNA-
produced enzymes to break apart cellulose to produce sugar for fermentation into
ethanol. Both the DOE and USDA are funding research to improve cellulosic
conversion as well as to breed higher yielding cellulosic crops. In 1978, the DOE
established the Bioenergy Feedstock Development Program (BFDP) at the Oak Ridge
National Laboratory. The BFDP is engaged in the development of new crops and
cropping systems that can be used as dedicated bioenergy feedstocks. Some of the
crops showing good cellulosic production per acre with strong potential for further
gains include fast-growing trees (e.g., hybrid poplars and willows), shrubs, and
grasses (e.g., switchgrass).
Government Support. Although no commercial cellulosic ethanol production
has occurred yet in the United States, two provisions of the 2002 farm bill (P.L. 107-
171) and several provision of the Energy Policy Act of 2005 (EPACT; P.L. 109-58)
have encouraged research in this area. The first provision (Section 2101) allows for
the use of Conservation Reserve Program lands for wind energy generation and
biomass harvesting for energy production and has helped to spur interest in hardy
biofuel feedstocks that are able to thrive on marginal lands. Another provision
(Section 9008) provides competitive funding for research and development projects
on biofuels and bio-based chemicals in an attempt to motivate further production and
use of non-traditional biomass feedstocks.36 EPACT’s biomass provisions are
discussed later in the report (see “Public Laws That Support Agriculture-Based
Energy Production and Use,” below).
Energy Efficiency. The use of cellulosic biomass in the production of
ethanol yields a higher net energy balance compared to corn — a 34% net gain for
corn vs. a 100% gain for cellulosic biomass — based on a 1999 comparative study.37
While corn’s net energy balance (under optimistic assumptions concerning corn
production and ethanol processing technology) was estimated at 67% by USDA in
2004, it is likely that cellulosic biomass’s net energy balance would also have
35 DOE, EERE, Biomass Program, “Cellulase Enzyme Research,” available at
[http://www1.eere.energy.gov/biomass/cellulase_enzyme.html].
36 For more information, see Biomass Research and Development Initiative, USDA/DOE,
at [http://www.biomass.govtools.us/].
37 Argonne National Laboratory, Center for Transportation Research, Effects of Fuel Ethanol
Use on Fuel-Cycle Energy and Greenhouse Gas, ANL/ESD-38, by M. Wang, C. Saricks,
and D. Santini, Jan. 1999, as referenced in DOE, DiPardo (2002).

---

CRS-15
experienced parallel gains for the same reasons — improved crop yields and
production practices, and improved processing technology.
Long-Run Supply Issues. Cellulosic feedstocks have an advantage over
corn in that they grow well on marginal lands, whereas corn requires fertile cropland
(as well as timely water and the addition of soil amendments). This greatly expands
the potential area for growing cellulosic feedstocks relative to corn. For example, in
2001 nearly 76 million acres were planted to corn, out of 244 million acres planted
to the eight major field crops (corn, soybeans, wheat, cotton, barley, sorghum, oats,
and rice). In contrast, that same year the United States had 433 million acres of total
cropland (including forage crops and temporarily idled cropland) and 578 million
acres of permanent pastureland, most of which is potentially viable for switchgrass
production.38
A 2003 BFDP study suggests that if 42 million acres of cropped, idle, pasture,
and CRP acres were converted to switchgrass production, 188 million dry tons of
switchgrass could be produced annually (at an implied yield of 4.5 metric tons per
acre), resulting in the production of 16.7 billion gallons of ethanol or 10.9 billion
GEG.39 This would represent about 8% of U.S. gasoline use in 2004. Existing
research plots have produced switchgrass yields of 15 dry tons per acre per year,
suggesting tremendous long-run production potential. However, before any supply
potential can be realized, research must first overcome the cellulosic conversion cost
issue through technological developments.
Methane from an Anaerobic Digester
An anaerobic digester is a device that promotes the decomposition of manure
or “digestion” of the organics in manure by anaerobic bacteria (in the absence of
oxygen) to simple organics while producing biogas as a waste product.40 The
principal components of biogas from this process are methane (60% to 70%), carbon
dioxide (30% to 40%), and trace amounts of other gases. Methane is the major
component of the natural gas used in many homes for cooking and heating, and is a
significant fuel in electricity production. Biogas can also be used as a fuel in a hot
water heater if hydrogen sulfide is first removed from the biogas supply. As a result,
the generation and use of biogas can significantly reduce the cost of electricity and
other farm fuels such as natural gas, propane, and fuel oil.
38 United Nations, Food and Agricultural Organization (FAO), FAOSTATS.
39 USDA, Office of Energy Policy and New Uses (OEPNU), The Economic Impacts of
Bioenergy Crop Production on U.S. Agriculture, AER 816, by Daniel De La Torre Ugarte
et al., Feb. 2003; available at [http://www.usda.gov/oce/reports/energy/index.htm].
40 For more information on anaerobic digesters, see Appropriate Technology Transfer for
Rural Areas (ATTRA), Anaerobic Digestion of Animal Wastes: Factors to Consider, by
John Balsam, Oct. 2002, at [http://www.attra.ncat.org/energy.html#Renewable]; or Iowa
State University, Agricultural Marketing Resource Center, Anaerobic Digesters, at
[http://www.agmrc.org/agmrc/commodity/biomass/].

---

CRS-16
By late 2002, there were 41 digester systems in operation at commercial U.S.
livestock farms, with an additional 30 expected to be in operation by 2003.41 In 35
of the 41 operational systems, the captured biogas is used to generate electrical power
and heat. These produce the equivalent of approximately 4 megawatts per year. The
remaining systems flare the captured gas for odor control, and they reduce methane
emissions by about 7,400 tons on a carbon-equivalent basis.
Anaerobic digestion system proposals have frequently received funding under
the Renewable Energy Program (REP) of the 2002 farm bill (P.L. 107-171, Title IX,
Section 9006). In 2004, 37 anaerobic digester proposals from 26 different states were
awarded funding under the REP.42 Also, the AgStar program — a voluntary
cooperative effort by USDA, EPA, and DOE — encourages methane recovery at
confined livestock operations that manage manure as liquid slurries.
Economic Efficiency. The primary benefits of anaerobic digestion are
animal waste management, odor control, nutrient recycling, greenhouse gas
reduction, and water quality protection. Except in very large systems, biogas
production is a highly useful but secondary benefit. As a result, anaerobic digestion
systems do not effectively compete with other renewable energy production systems
on the basis of energy production alone. Instead, they compete with and are cost-
competitive when compared to conventional waste management practices according
to EPA.43 Depending on the infrastructure design — generally some combination of
storage pond, covered or aerated treatment lagoon, heated digester, and open storage
tank — anaerobic digestion systems can range in investment cost from $200 to $500
per Animal Unit (i.e., per 1,000 pounds of live weight). In addition to the initial
infrastructure investment, recurring costs include manure and effluent handling, and
general maintenance. According to EPA, these systems can have financially
attractive payback periods of three to seven years when energy gas uses are
employed. On average, manure from a lactating 1,400-pound dairy cow can generate
enough biogas to produce 550 Kilowatts per year.44 A 200-head dairy herd could
generate 500 to 600 Kilowatts per day. At 6¢ per kilowatt hour, this would represent
potential energy cost savings of $6,000 to $10,000 per year.
The principal by-product of anaerobic digestion is the effluent (i.e., the digested
manure). Because anaerobic digestion substantially reduces ammonia losses, the
effluent is more nitrogen-rich than untreated manure, making it more valuable for
subsequent field application. Also, digested manure is high in fiber, making it
41 U.S. Environmental Protection Agency (EPA), The AgStar Program, Guide to Operational
Systems, U.S. Operating Digesters by State, available at [http://www.epa.gov/agstar/
operation/bystate.html].
42 USDA, News Release No. 0386.04, Sept. 15, 2004; Veneman Announces $22.8 Million
to Support Renewable Energy Initiatives in 26 States, available at [http://www.usda.gov/
Newsroom/0386.04.html]. For funding and program information on the Renewable Energy
and Energy Efficiency Program, see [http://www.rurdev.usda.gov/rd/energy/].
43 EPA, OAR, Managing Manure with Biogas Recovery Systems, EPA-430-F-02-004, winter
2002.
44 ATTRA, Anaerobic Digestion of Animal Wastes: Factors to Consider, Oct. 2002.

---

CRS-17
valuable as a high-quality potting soil ingredient or mulch. Other cost savings
include lower total lagoon volume requirements for animal waste management
systems (which reduces excavation costs and the land area requirement), and lower
cover costs because of smaller lagoon surface areas.
Energy Efficiency. Because biogas is essentially a by-product of an animal
waste management activity, and because the biogas produced by the system can be
used to operate the system, the energy output from an anaerobic digestion system can
be viewed as achieving even or positive energy balance. The principal energy input
would be the fuel used to operate the manure handling equipment.
Long-Run Supply Issues. Anaerobic digesters are most feasible alongside
large confined animal feeding operations (CAFOs). According to USDA, biogas
production for generating cost effective electricity requires manure from more than
150 large animals. As animal feeding operations steadily increase in size, the
opportunity for anaerobic digestion systems will likewise increase.
Biodiesel
Biodiesel is an alternative diesel fuel that is produced from any animal fat or
vegetable oil (such as soybean oil or recycled cooking oil). About 90% of U.S.
biodiesel is made from soybean oil. As a result, U.S. soybean producers and the
American Soybean Association (ASA) are strong advocates for greater government
support for biodiesel production.
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 lubricity and important emission
improvements over petroleum diesel.45 Biodiesel is increasingly being adopted by
major fleets nationwide. The U.S. Postal Service, the U.S. military, and many state
governments are directing their bus and truck fleets to incorporate biodiesel fuels as
part of their fuel base.
45 For more information, visit the National Biodiesel Board at [http://www.biodiesel.org].

---

CRS-18
Figure 3. U.S. Biodiesel Production, 1998-2005
80
60
40
20
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1998
1
2000
20
2002
2004
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U.S. biodiesel production has shown strong growth in recent years, increasing
from under 1 million gallons in 1999 to an estimated 75 million gallons in 2005
(Figure 3). However, U.S. biodiesel production remains small relative to national
diesel consumption levels. In 2004, biodiesel production of 33 million gallons
represented 0.08% of the 43,852 million gallons of diesel fuel used nationally for
vehicle transportation.46 In addition to vehicle use, 17,892 million gallons of diesel
fuel were used for heating and power generation by residential, commercial, and
industry, and by railroad and vessel traffic in 2004, bringing total U.S. diesel fuel use
to nearly 62,384 million gallons (Table 4).
According to the NBB, as of May 1, 2006, there were 65 companies producing
and marketing biodiesel commercially in the United States, and another 50 new firms
that are reportedly under construction or are scheduled to be completed within the
next 18 months.47 The NBB reported that early 2006 U.S. biodiesel production
capacity (within the oleochemical industry) was an estimated 395 million gallons per
year, but would add another 713.7 million gallons within the next 18 months.
Because many of these plants also can produce other products such as cosmetics,
46 Biodiesel consumption estimates are from DOE, IEA, “Alternatives to Traditional
Transportation Fuels 2003, Estimated Data.”
47 A description of biodiesel production capacity with maps of existing and proposed plants
is available at [http://www.biodiesel.org/resources/fuelfactsheets/default.shtm].

---

CRS-19
estimated total capacity (and capacity for expansion) is far greater than actual
biodiesel production.
Table 4. U.S. Diesel Fuel Use, 2004
Hypothetical scenario:
Total
1% of total useb
Soybean oil
equivalents:
Million
Million
million
U.S. Diesel Use in 2004
gallonsa
%
gallons
poundsa
Total Vehicle Use
43,852
70%
439
3,377
On-Road
37,125
60%
371
2,859
Off-Road
2,861
5%
29
220
Military
359
1%
4
28
Farm
3,508
6%
35
270
Total Non-vehicle Use
18,532
30%
185
1,427
All uses
62,384
100%
624
4,804
Source: DOE, EIA, U.S. Annual Adjusted Sales of Distillate Fuel Oil by End Use.
a. Pounds are converted from gallons of oil using a 7.7 pounds-to-gallon conversion rate.
b. Hypothetical scenario included for comparison purposes only.
Economic Efficiency. Biodiesel is generally more expensive than its fossil
fuel counterpart. For example, during January-February 2006, the retail price of B20
(a blend of 20% biodiesel with 80% conventional diesel) averaged $2.64 per gallon
compared with $2.56 for conventional diesel fuel (Table 3). The approximate price
difference of 8¢ on a 20% blend implies that pure (100%) biodiesel costs as much as
40¢ more per gallon to produce.
The prices of biodiesel feedstocks, as well as petroleum-based diesel fuel, vary
over time based on domestic and international supply and demand conditions
(Figure 4). As diesel fuel prices rise relative to biodiesel, and/or as biodiesel
production costs fall through lower commodity prices or technological improvements
in the production process, biodiesel becomes more economical. In addition, federal
and state assistance helps to make biodiesel more competitive with diesel fuel.

---

CRS-20
Figure 4. Soybean Oil vs. Diesel Fuel Prices, 1994-2006
35
3.5
3
30
Diesel Fuel
2.5
25
2
1.5
20
1
15
0.5
Soybean Oil
10
0
1994 1996 1998 2000 2002 2004 2006
Source: diesel fuel: DOE, EIA; soybean oil: USDA, FAS “Oilseed
Circular.”
Government Support. The primary federal incentives for biodiesel production
are somewhat similar to ethanol and include the following.48

! A production excise tax credit signed into law on October 22, 2004,
as part of the American Jobs Creation Act of 2004 (Sec. 1344; P.L.
109-58). Under the biodiesel production tax credit, the subsidy
amounts to $1.00 for every gallon of agri-biodiesel (i.e., virgin
vegetable oil and animal fat) that is used in blending with petroleum
diesel. A 50¢ credit is available for every gallon of non-agri-
biodiesel (i.e., recycled oils such as yellow grease).
! A small producer income tax credit (Sec. 1345; P.L. 109-58) of 10¢
per gallon for the first 15 million gallons of production for biodiesel
producers whose total output does not exceed 60 million gallons of
biodiesel per year.
! Incentive payments (contingent on annual appropriations) on year-
to-year production increases of renewable energy under USDA’s
Bioenergy Program (7 U.S.C. 8108).
Indirectly, other federal programs support biodiesel production by requiring
federal agencies to give preference to biobased products in purchasing fuels and other
supplies and by providing incentives for research on renewable fuels. Also, several
48 See also section on “Public Laws That Support Agriculture-Based Energy Production and
Use,” below.

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CRS-21
states have their own incentives, regulations, and programs in support of renewable
fuel research, production, and consumption that supplement or exceed federal
incentives.
At February 2006 prices, the federal tax credit would make biodiesel very
competitive with petroleum-based diesel fuel, as the 20¢ tax credit on a gallon of B20
would more than offset the 8¢ price difference with conventional diesel. However,
unlike the ethanol tax credit, which was extended through 2010, the biodiesel tax
credit expires at the end of calendar year 2008. In addition to the production tax
credit, USDA’s Bioenergy Program (7 U.S.C. 8108) provides incentive payments
(contingent on annual appropriations) on year-to-year production increases of
renewable energy.
Energy Efficiency. Biodiesel appears to have a significantly better net
energy balance than ethanol, according to a joint USDA-DOE 1998 study that found
biodiesel to have an NEB of 3.2 — that is, 220% more energy was returned from a
gallon of pure biodiesel than was used in its production.49 In contrast, the study
authors point out that petroleum diesel has an NEB of 0.83 — that is, 17% less
energy was returned from a gallon of petroleum diesel than was used in its life cycle
from source to user.
Long-Run Supply Issues. Both the ASA and the NBB are optimistic that
the federal biodiesel tax incentive will provide the same boost to biodiesel production
that ethanol has obtained from its federal tax incentive.50 However, many commodity
market analysts are skeptical of such claims. They contend that the biodiesel industry
still faces several hurdles: the retail distribution network for biodiesel has yet to be
established; the federal tax credit, which expires on December 31, 2008, does not
provide sufficient time for the industry to develop; and potential oil feedstocks are
relatively less abundant than ethanol feedstocks, making the long-run outlook more
uncertain.
In addition, biodiesel production confronts the same limited ability to substitute
for petroleum imports and the same type of consumption tradeoffs as ethanol
production. As an example consider a hypothetical scenario (as shown in Table 4)
whereby 1% of current vehicle diesel fuel use were to originate from biodiesel
sources. This hypothetical mandate would require about 439 million gallons of
biodiesel (compared to current production of about 75 million gallons) or
approximately 3.4 billion pounds of vegetable oil. During 2003, a total of 31.7
billion pounds of vegetable oils and animal fats were produced in the United States
(Table 5); however, most of this production was committed to other food and
industrial uses. Uncommitted biodiesel feedstocks (as measured by the available
stock levels on September 30, 2003) were 2.1 billion pounds. Thus, after exhausting
all available feedstocks, an additional 1.3 billion pounds of oil would be needed to
49 DOE, National Renewable Energy Laboratory (NREL), An Overview of Biodiesel and
Petroleum Diesel Life Cycles, NREL/TP-580-24772, by John Sheehan et al., May 1998,
available at [http://www.afdc.doe.gov/pdfs/3812.pdf].
50 For more information, see NBB, “Ground-Breaking Biodiesel Tax Incentive Passes,” at
[http://www.biodiesel.org/resources/pressreleases/gen/20041011_ FSC_Passes_Senate.pdf].

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CRS-22
meet the hypothetical 1% biodiesel blending requirement. This is equivalent to the
1.3 billion pounds of soybean oil exported by the United States in 2004/05.
Table 5. U.S. Potential Biodiesel Feedstocks, 2002-2003
Oil Production,
Ending Stocks:
Wholesale
2002-2003
Sept. 30, 2003
pricea
Million
Million
Million
Million
Oil type
$/lb
pounds
gallonsb
pounds
gallonsb
Crops
23,050
2,994
1,834
238
Soybean
20.6
18,435
2,394
1,486
193
Corn
22.3
2,453
319
114
15
Cottonseed
25.7
725
94
40
5
Sunflowerseed
26.4
320
42
25
3
Canola
23.6c
541
70
55
7
Peanut
44.5
286
37
50
6
Flaxseed/linseed
na
201
26
45
6
Safflower
na
89
12
19
2
Rapeseed
23.6c
0
0
0
0
Animal fat & other
8,698
1,130
299
39
Lard
18.1
262
34
9
1
Edible tallow
16.9
1,974
256
26
3
Inedible tallow
na
3,690
479
221
29
Yellow grease
11.6
2,772
360
43
6
Total supply
31,748
4,123
2,134
277
Source: USDA, ERS, Oil Crops Yearbook, OCS-2003, October 2003. Rapeseed was calculated by
multiplying oil production by a 40% conversion rate. The inedible tallow and yellow grease supplies
come from Dept of Commerce, Bureau of Census, Fats and Oils, Production, Consumption and
Stocks, Annual Summary 2002.
na = not available.
a. Average of monthly price quotes for 2000/01 to 2003/04 marketing years (Oct. to Sept.). USDA,
ERS, Oil Crops Outlook, various issues. Yellow grease price is a 1993-95 average from USDA,
ERS, AER 770, Sept. 1998, p. 9.
b. Pounds are converted to gallons of oil using a 7.7 pounds-to-gallon conversion rate.
c. Rapeseed oil, f.o.b., Rotterdam; USDA, FAS, Oilseeds: World Market and Trade, various issues.
If soybean oil exports were to remain unchanged, the deficit biodiesel feedstocks
could be obtained either by reducing U.S. whole soybean exports by about 127
million bushels (then crushing them for their oil) or by expanding soybean
production by approximately 3.0 million acres (assuming a yield of about 42 bushels
per acre). A further possibility is that U.S. producers could shift towards the
production of higher-oil content oilseeds such as canola or sunflower.
The bottom line is that a small increase in demand of fats and oils for biodiesel
production could quickly exhaust available feedstock supplies and push vegetable oil

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CRS-23
prices significantly higher due to the low elasticity of demand for vegetable oils in
food consumption.51 At the same time, it would begin to disturb feed markets.
As with ethanol production, increased soybean oil production (dedicated to
biodiesel production) would generate substantial increases in animal feeds in the
form of high-protein meals. When a bushel of soybeans is processed (or crushed),
nearly 80% of the resultant output is in the form of soybean meal, while only about
18%-19% is output as soybean oil. Thus, for every 1 pound of soybean oil produced
by crushing whole soybeans, over 4 pounds of soybean meal are also produced.
Crushing an additional 127 million bushels of soybeans for soybean oil would
produce over 3 million short tons (s.t.) of soybean meal. In 2004/05, the United
States produced 40.7 million s.t. of soybean meal. An additional 3 million s.t. of
soybean meal (an increase of 7.3%) entering U.S. feed markets would compete
directly with the feed by-products of ethanol production (distillers dried grains, corn
gluten feed, and corn gluten meal) with economic ramifications that have not yet
been fully explored.52 Also similar to ethanol production, natural gas demand would
likely rise with the increase in biodiesel processing.53
Wind Energy Systems
In 2004, electricity from wind energy systems accounted for about 0.1% of U.S.
total energy consumption (Table 1). However, wind-generated electricity was a
much larger share of electricity used by the U.S. agriculture sector (28%), and of total
direct energy used by U.S. agriculture (9%).54 According to the American Wind
Energy Association (AWEA), total installed wind energy production capacity has
expanded rapidly in the United States since the late 1990s, rising from 1,848
megawatts (MW) in 1998 to a reported 9,141 MW by January 24, 2006 (Figure 5).55
By May 2006, the AWEA reported that the U.S. wind industry was on pace to install
an additional 3,000 MW in 2006. About 86% of production capacity is in 10
predominantly midwestern and western states (see Table 6). (See “Box: Primer on
51 ERS reported the U.S. own-price elasticity for “oils & fats” at -0.027 — i.e., a 10%
increase in price would result in a 0.27% decline in consumption. In other words, demand
declines only negligibly relative to a price rise. Such inelastic demand is associated with
sharp price spikes in periods of supply shortfall. USDA, ERS, International Evidence on
Food Consumption Patterns, Tech. Bulletin No. 1904, Sept. 2003, p. 67.
52 For a parallel discussion of feed market consequences from domestic ethanol industry
expansion, see Wisner and Baumel in Feedstuffs, no. 30, vol. 76, July 26, 2004.
53 Assuming natural gas is the processing fuel, natural gas demand would increase due to
two factors: (1) to produce the steam and process heat in oilseed crushing and (2) to produce
methanol used in the conversion step. NREL, An Overview of Biodiesel and Petroleum
Diesel Life Cycles, NREL/TP-580-24772, by John Sheehan et al., May 1998, p. 19.
54 Data for agricultural use of wind-generated electricity is for 2003. For more information
on energy consumption by U.S. agriculture, see CRS Report RL32677, Energy Use in
Agriculture: Background and Issues, by Randy Schnepf.
55 American Wind Energy Association (AWEA), at [http://www.awea.org].

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CRS-24
Measuring Electric Energy” later in this report for a description of megawatts and
other energy terminology.)
What Is Behind the Rapid Growth of Installed Capacity? Over the
past 20 years, the cost of wind power has fallen approximately 90%, while rising
natural gas prices have pushed up costs for gas-fired power plants, helping to
improve wind energy’s market competitiveness.56 In addition, wind-generated
electricity production and use is supported by several federal and state financial and
tax incentives, loan and grant programs, and renewable portfolio standards. As of
September 2005, renewable portfolio standards (RPSs) have been adopted by 21
states and the District of Columbia. An RPS requires that utilities must derive a
certain percentage of their overall electric generation from renewable energy sources
such as wind power.57 Environmental and energy security concerns also have
encouraged interest in clean, renewable energy sources such as wind power. Finally,
rural incomes receive a boost from companies installing wind turbines in rural areas.
Landowners have typically received annual lease fees that range from $2,000 to
$5,000 per turbine per year for up to 20 years depending on factors such as the
project size, the capacity of the turbines, and the amount of electricity produced.

Figure 5. U.S. Installed Wind Energy Capacity, 1981-2006P
12000
10000
8000
6000
4000
2000
0
1981
1986
1991
1996
2001 2006P
Source: DOE and AWEA; 2006 is projected by AWEA.
56 AWEA, The Economics of Wind Energy, Mar. 2002.
57 AWEA, “State-Level Renewable Energy Portfolio Standards,” Sept. 2, 2005; available at
[http://www.awea.org/pubs/factsheets.html].

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CRS-25
Economic Efficiency. The per-unit cost of utility-scale wind energy is the
sum of the various costs — capital, operations, and maintenance — divided by the
annual energy generation. Utility-scale wind power projects — those projects that
generate at least 1 MW of electric power annually for sale to a local utility — account
for over 90% of wind power generation in the United States.58 For utility-scale
sources of wind power, a number of turbines are usually built close together to form
a wind farm.
Table 6. Installed Wind Energy Capacity by State,
January 24, 2006
State
Megawatts
Share
Cumulative %
California
2,150
23.5%
23.5%
Texas
1,995
21.8%
45.3%
Iowa
836
9.1%
54.4%
Minnesota
744
8.1%
62.6%
Oklahoma
475
5.2%
67.8%
New Mexico
407
4.4%
72.2%
Washington
390
4.3%
76.5%
Oregon
338
3.7%
80.2%
Wyoming
288
3.1%
83.3%
Kansas
264
2.9%
86.2%
Others
1,264
13.8%
100.0%
U.S. Total
9,151
100.0%
100.0%
Source: AWEA, [http://www.awea.org/projects/].
In contrast with biofuel energy, wind power has no fuel costs. Instead,
electricity production depends on the kinetic energy of wind (replenished through
atmospheric processes). As a result, its operating costs are lower than costs for
power generated from biofuels. However, the initial capital investment in equipment
needed to set up a utility-scale wind energy system is substantially greater than for
competing fossil or biofuels. Major infrastructure costs include the tower (30 meters
or higher) and the turbine blades (generally constructed of fiberglass; up to 20 meters
in length; and weighing several thousand pounds). Capital costs generally run about
$1 million per MW of capacity, so a wind energy system of 10 1.5-MW turbines
would cost about $15 million. Farmers generally find leasing their land for wind
power projects easier than owning projects. Leasing is easier because energy
companies can better address the costs, technical issues, tax advantages, and risks of
wind projects. In 2004, less than 1% of wind power capacity installed nationwide
was owned by farmers.59
58 GAO, Wind Power, GAO-04-756, Sept. 2004, p. 66.
59 Ibid., p. 6.

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CRS-26
While the financing costs of a wind energy project dominate its competitiveness
in the energy marketplace, there are several other factors that also contribute to the
economics of utility-scale wind energy production. These include:60
! the wind speed and frequency at the turbine location — the energy
that can be tapped from the wind is proportional to the cube of the
wind speed, so a slight increase in wind speed results in a large
increase in electricity generation;
! improvements in turbine design and configuration — the taller the
turbine and the larger the area swept by the blades, the more
productive the turbine;
! economies of scale — larger systems operate more economically
than smaller systems by spreading operations/maintenance costs
over more kilowatt-hours;
! transmission and market access conditions (see below); and
! environmental and other policy constraints — for example, stricter
environmental regulations placed on fossil fuel emissions enhance
wind energy’s economic competitiveness; or, alternately, greater
protection of birds or bats,61 especially threatened or endangered
species, could reduce wind energy’s economic competitiveness.
Government Support. In addition to market factors, the rate of wind energy
system development for electricity generation has been highly dependent on federal
government support, particularly a production tax credit that provides a 1.8¢ credit
for each kilowatt-hour of electricity produced by qualifying turbines built by the end
of 2007 for a 10-year period.62 In some cases the tax credit may be combined with
a five-year accelerated depreciation schedule for wind turbines, as well as with
grants, loans, and loan guarantees offered under several different programs.63 A
modern wind turbine can produce electricity for about 2.5¢ to 4¢ per kilowatt hour
(including the government subsidy). This implies that the federal production tax
credit amounts to 31% to 41% of the cost of production of wind energy. In contrast
to wind-generated electricity costs, modern natural-gas-fired power plants produce
a kilowatt-hour of electricity for about 5.5¢ (including both fuel and capital costs)
when natural gas prices are at $6 per million Btu’s (or equivalently per 1,000 cu.ft.).64
60 AWEA, The Economics of Wind Energy, at [http://www.awea.org].
61 Justin Blum, “Researchers Alarmed by Bat Deaths From Wind Turbines,” Washington
Post, by Jan. 1, 2005.
62 The federal production tax credit was initially established as a 1.5¢ tax credit in 1992
dollars in the Energy Policy Act of 1992 (P.L. 102-146). The tax credit was extended in the
American Jobs Creation Act of 2004 (P.L. 108-357; Sec. 710) with an adjustment for annual
inflation that raised it to its current value of 1.8¢ per kWh.
63 A five-year depreciation schedule is allowed for renewable energy systems under the
Economic Recovery Tax Act of 1981, as amended (P.L. 97-34; Stat. 230, codified as 26
U.S.C. § 168(e)(3)(B)(vi)).
64 Rebecca Smith, “Not Just Tilting Anymore,” Wall Street Journal, Oct. 14, 2004.

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CRS-27
Wellhead natural gas prices have shown considerable volatility since the late
1990s (Figure 6); but spiked sharply upward in September 2005 following Hurricane
Katrina’s damage to the Gulf Coast petroleum and natural gas importing and refining
infrastructure. Prices have fallen back substantially from their October 2005 peak of
$10.97 per 1,000 cu.ft., however, market conditions suggest that the steady price rise
that has occurred since 2002 is unlikely to weaken anytime soon.65 As of May 10,
2006, the Henry Hub wellhead price of natural gas was quoted at $6.50 per 1,000
cu.ft. If natural gas prices continue to be substantially higher than average levels in
the 1990s, wind power is likely to be competitive in parts of the country where good
wind resources and transmission access can be coupled with the federal production
tax credit.
Figure 6. Natural Gas Price, Wellhead, 1994-2006
12
10
8
6
4
2
0
1994 1996 1998 2000 2002 2004 2006
Source: DOE, EIA; monthly average wellhead (wholesale) price .
Long-Run Supply Issues. Despite the advantages listed above, U.S. wind
potential remains largely untapped, particularly in many of the states with the greatest
wind potential, such as North and South Dakota (see Figure 7). Factors inhibiting
growth in these states include lack of either (1) major population centers with large
electric power demand needed to justify large investments in wind power, or (2)
adequate transmission capacity to carry electricity produced from wind in sparsely
populated rural areas to distant cities.
65 For a discussion of natural gas market price factors, see CRS Report RL32677, Energy
Use in Agriculture: Background and Issues, by Randy Schnepf.

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CRS-28
Areas considered most favorable for wind power have average annual wind
speeds of about 16 miles per hour or more. The DOE map of U.S. wind potential
confirms that the most favorable areas tend to be located in sparsely populated
regions, which may disfavor wind-generated electricity production for several
reasons. First, transmission lines may be either inaccessible or of insufficient
capacity to move surplus wind-generated electricity to distant demand sources.
Second, transmission pricing mechanisms may disfavor moving electricity across
long distances due to distance-based charges or according to the number of utility
territories crossed. Third, high infrastructure costs for the initial hook-up to the
power grid may discourage entry, although larger wind farms can benefit from
economies of scale on the initial hook-up. Fourth, new entrants may see their access
to the transmission power grid limited in favor of traditional customers during
periods of heavy congestion. Finally, wind plant operators are often penalized for
deviations in electricity delivery to a transmission line that result from the variability
in available wind speed.
Figure 7. U.S. Areas with Highest Wind Potential
Environmental Concerns. Three potential environmental issues — impacts
on the visual landscape, bird and bat deaths, and noise issues — vary in importance
based on local conditions. In some rural localities, the merits of wind energy appear
to have split the environmental movement. For example, in the Kansas Flint Hills,
local chapters of the Audubon Society and Nature Conservancy oppose installation
of wind turbines, saying that they would befoul the landscape and harm wildlife;
while Kansas Sierra Club leaders argue that exploiting wind power would help to
reduce America’s dependence on fossil fuels.

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CRS-29
Box: Primer on Measuring Electric Energy
News stories covering electric generation topics often try to illustrate the worth of
a megawatt in terms of how many homes a particular amount of generation could serve.
However, substantial variation may appear in implied household usage rates. So what
really is a megawatt (MW) and how many homes can one MW of generation really serve?
Basics. A watt (W) is the basic unit used to measure electric power. Watts measure
instantaneous power. In contrast, a watt-hour (Wh) measures the total amount of energy
consumed in an hour. For example, a 100 W light bulb is rated to consume 100 W of
power when turned on. If a 100 W bulb were on for 4 hours it would consume 400 Wh
of energy. A kilowatt (kW) equals 1,000 W and a megawatt (MW) equals 1,000 kW or
1 million W. Electricity production and consumption are measured in kilowatt-hours
(kWh), while generating capacity is measured in kilowatts or megawatts. If a power plant
that has 1 MW of capacity operated nonstop (i.e, 100%) during all 8,760 hours in the
year, it would produce 8,760,000 kWh.
More realistically, a 100 MW rated wind farm is capable of producing 100 MW
during peak winds, but will produce much less than its rated amount when winds are
light. As a result of these varying wind speeds, over the course of a year a wind farm may
only average 30 MW of power production. On average, wind power turbines typically
operate the equivalent of less than 40% of the peak (full load) hours in the year due to the
intermittency of the wind. Wind turbines are “on-line” — actually generating electricity
— only when wind speeds are sufficiently strong (i.e., at least 9 to 10 miles per hour).
Average MW per Household. In its 2004 analysis of the U.S. wind industry, the
Government Accountability Office (GAO) assumed that an average U.S. household
consumed about 10,000 kWh per year (GAO, Renewable Energy: Wind Power’s
Contribution to Electric Power Generation and Impact on Farms and Rural
Communities, GAO-04-756, Sept. 2004). However, the amount of electricity consumed
by a typical residential household varies dramatically by region of the country.
According to 2001 Energy Information Administration (EIA) data, New England
residential homes consumed the least amount of electricity, averaging 653 kWh of load
in a month, while the East South Central region, which includes states such as Georgia
and Alabama and Tennessee, consumed nearly double that amount at 1,193 kWh per
household. The large regional disparity in electric consumption is driven by many factors
including the heavier use of air conditioning in the South. As a result, a 1 MW generator
in the Northeast would be capable of serving about twice as many households as the same
generator located in the South because households in the Northeast consume half the
amount of electricity as those in the South.
So how many homes can a wind turbine rated at 1 MW really serve? In the United
States, a wind turbine with a peak generating capacity of 1 MW, rated at 30% annual
capacity, placed on a tower situated on a farm, ranch, or other rural land, can generate
about 2.6 million kilowatt-hours [=(1MW)*(30%)*(8.76 kWh)] in a year which is enough
electricity to serve the needs of 184 (East South Central) to 354 (New England) average
U.S. households depending on which region of the country you live in (Table 6).
Source: Bob Bellemare, UtiliPoint International Inc., Issue Alert, June 24, 2003;
available at [http://www.utilipoint.com/issuealert/article.asp?id=1728].

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CRS-30
Public Laws That Support Agriculture-Based
Energy Production and Use
This section provides a brief overview of the major pieces of legislation that
support agriculture-based renewable energy production. Federal support is provided
in the form of excise and income tax credits; loans, grants, and loan guarantees;
research, development, and demonstration assistance; educational program
assistance; procurement preferences; and user mandates.66
Clean Air Act Amendments of 1990 (CAAA; P.L. 101-549)
The Reformulated Gasoline and Oxygenated Fuels programs of the CAAA have
provided substantial stimuli to the use of ethanol.67 In addition, the CAAA requires
the Environmental Protection Agency (EPA) to identify and regulate air emissions
from all significant sources, including on- and off-road vehicles, urban buses, marine
engines, stationary equipment, recreational vehicles, and small engines used for lawn
and garden equipment. All of these sources are candidates for biofuel use.
Energy Policy Act of 1992 (EPACT; P.L. 102-486)
Energy security provisions of EPACT favor expanded production of renewable
fuels. Provisions related to agriculture-based energy production included:
! EPACT’s alternative-fuel motor fleet program implemented by DOE
requires federal, state, and alternative fuel providers to increase
purchases of alternative-fueled vehicles. Under this program, DOE
has designated neat (100%) biodiesel as an environmentally positive
or “clean” alternative fuel.68
! A 1.5¢ per kilowatt/hour production tax credit (PTC) for wind
energy was established. The PTC is applied to electricity produced
during a wind plant’s first ten years of operation.
Biomass Research and Development Act of 2000
(Biomass Act; Title III, P.L. 106-224)
The Biomass Act (Title III of the Agricultural Risk Protection Act of 2000 [P.L.
106-224]) contains several provisions to further research and development in the area
of biomass-based renewable fuel production.
66 For information on federal tax credits for renewable energy, see CRS Issue Brief IB10054,
Energy Tax Policy, by Salvatore Lazzari. For more information on federal production tax
credits for biofuels, see CRS Report RL30758, Alternative Transportation Fuels and
Vehicles: Energy, Environment, and Development Issues, by Brent D. Yacobucci.
67 CRS Report RL33290, Fuel Ethanol: Background and Public Policy Issues, by Brent D.
Yacobucci.
68 NBB, “Biodiesel Emissions,” at [http://www.biodiesel.org/pdf_files/fuelfactsheets/
emissions.pdf].

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CRS-31
! (Sec. 304) The Secretaries of Agriculture and Energy shall
cooperate with respect to, and coordinate, policies and procedures
that promote research and development leading to the production of
biobased fuels and products.
! (Sec. 305) A Biomass Research and Development Board is
established to coordinate programs within and among departments
and agencies of the Federal Government for the purpose of
promoting the use of biofuels and products.
! (Sec. 306) A Biomass Research and Development Technical
Advisory Committee is established to advise, facilitate, evaluate, and
perform strategic planning on activities related to research,
development, and use of biobased fuels and products.
! (Sec. 307) A Biomass Research and Development Initiative is
established under which competitively awarded grants, contracts,
and financial assistance are provided to eligible entities undertaking
research on, and development and demonstration of, biobased fuels
and products.69
! (Sec. 309) The Secretaries of Agriculture and Energy are obliged to
submit an annual joint report to Congress accounting for the nature
and use of any funding made available under this initiative.70
! (Sec. 310) To undertake these activities, Commodity Credit
Corporation (CCC) funds of $49 million per year were authorized
for FY2002-FY2005.
Biomass-related program funding levels were expanded through FY2007 by
Section 9008 of the 2002 farm bill (P.L. 107-171) which also made available (until
expended) new funding of $5 million in FY2002 and $14 million in each of FY2003-
FY2007. Subsequently, Title II of the Healthy Forest Restoration Act of 2003 (P.L.
108-148) raised the annual authorization from $49 million to $54 million. Finally
Sections 942-948 of the Energy Policy Act of 2005 (P.L. 109-58) raised the annual
authorization from $54 million to $200 million starting in FY2006, and extended it
through FY2015. In addition to new funding, many of the original biomass-related
provisions were expanded and new provisions were added by these same laws as
described below.
Energy Provisions in the 2002 Farm Bill (P.L. 107-171)71
In the 2002 farm bill, three separate titles — Title IX: Energy, Title II:
Conservation, and Title VI: Rural Development — each contain programs that
69 The official website for the Biomass Research and Development Initiative may be found
at [http://www.bioproducts-bioenergy.gov/default.asp].
70 This report is available at [http://www.bioproducts-bioenergy.gov/publications.asp].
71 USDA, 2002 Farm Bill, “Title IX — Energy,” online information available at
[http://www.usda.gov/farmbill/energy_fb.html]. For more information, see CRS Report
RL31271, Energy Provisions of the Farm Bill: Comparison of the New Law with Previous
Law and House and Senate Bills, by Brent D. Yacobucci.

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CRS-32
encourage the research, production, and use of renewable fuels such as ethanol,
biodiesel, and wind energy systems.
Federal Procurement of Biobased Products (Title IX, Section 9002).
Federal agencies are required to purchase biobased products under certain conditions.
A voluntary biobased labeling program is included. Legislation provides funding of
$1 million annually through the USDA’s Commodity Credit Corporation (CCC) for
FY2002-FY2007 for testing biobased products. USDA published final rules in the
Federal Register (vol. 70, no. 1, pp. 41-50, January 3, 2005). The regulations define
what a biobased product is under the statue, identify biobased product categories, and
specify the criteria for qualifying those products for preferred procurement.
Biorefinery Development Grants (Title IX, Section 9003). Federal
grants are provided to ethanol and biodiesel producers who construct or expand their
production capacity. Funding for this program was authorized in the 2002 farm bill,
but no funding was appropriated. Through FY2006, no funding had yet been
proposed; therefore, no implementation regulations have been developed.
Biodiesel Fuel Education Program (Title IX, Section 9004).
Administered by USDA’s Cooperative State Research, Education, and Extension
Service, competitively awarded grants are made to nonprofit organizations that
educate governmental and private entities operating vehicle fleets, and educate the
public about the benefits of biodiesel fuel use. Final implementation rules were
published in the Federal Register (vol. 68, no. 189, September 30, 2003).
Legislation provides funding of $1 million annually through the CCC for FY2003-
FY2007 to fund the program. As of January 2006, only two awardees — the
National Biodiesel Board and the University of Idaho — had been selected.72
Energy Audit and Renewable Energy Development Program (Title
IX, Section 9005). This program is intended to assist producers in identifying their
on-farm potential for energy efficiency and renewable energy use. Funding for this
program was authorized in the 2002 farm bill, but through FY2006 no funding has
been appropriated. As a result, no implementation regulations have been developed.
Renewable Energy Systems and Energy Efficiency Improvements
(Renewable Energy Program) (Title IX; Section 9006). Administered by
USDA’s Rural Development Agency, this program authorizes loans, loan guarantees,
and grants to farmers, ranchers, and rural small businesses to purchase renewable
energy systems and make energy efficiency improvements.73 Grant funds may be
used to pay up to 25% of the project costs. Combined grants and loans or loan
guarantees may fund up to 50% of the project cost. Eligible projects include those
that derive energy from wind, solar, biomass, or geothermal sources. Projects using
energy from those sources to produce hydrogen from biomass or water are also
eligible. Legislation provides that $23 million will be available annually through the
72 These awardees were selected in August 2003; more information is available at
[http://www.biodiesel.org/usda/].
73 For more information on this program, see [http://www.rurdev.usda.gov/rbs/farmbill/
index.html].

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CCC for FY2003-FY2007 for this program. Unspent money lapses at the end of each
year. Final implementation rules, including program guidelines for receiving and
reviewing future loan and loan guarantee applications, were published in the Federal
Register (vol. 708, no. 136, July 18, 2005).
Prior to each fiscal year, USDA publishes a Notice of Funds Availability
(NOFA) in the Federal Register inviting applications for the Renewable Energy
Program, most recently on March 28, 2005, when the availability of $22.8 million
(half as competitive grants, and half for guaranteed loans) was announced. Not all
applications are accepted. On September 14, 2005, USDA announced that $21
million in grants for FY2006 were offered to 150 applicants for renewable energy and
energy efficient projects in 32 states.74
USDA estimates that loans and loan guarantees would be more effective than
grants in assisting renewable energy projects, because program funds would be
needed only for the credit subsidy costs (i.e., government payments made minus loan
repayments to the government). USDA estimated that offering $11.4 million as loan
guarantees funding would equate to as much as $200 million in annual program
support.75
Hydrogen and Fuel Cell Technologies (Title IX, Section 9007).
Legislation requires that USDA and DOE cooperate on research into farm and rural
applications for hydrogen fuel and fuel cell technologies under a memorandum of
understanding. No new budget authority is provided.
Biomass Research and Development (Title IX; Section 9008).76 This
provision extends an existing program — created under the Biomass Research and
Development Act (BRDA) of 2000 — that provides competitive funding for research
and development projects on biofuels and bio-based chemicals and products,
administered jointly by the Secretaries of Agriculture and Energy. Under the BRDA,
$49 million per year was authorized for FY2002-FY2005. Section 9008 extended
the $49 million in budget authority through FY2007, and added new funding levels
of $5 million in FY2002 and $14 million for FY2003-FY2007 — unspent funds may
be carried forward, making the additional funding total $75 million for FY2002-
FY2007. (The $49 million in annual funding for FY2002-FY2007 was raised to $54
million for that same period by P.L. 108-148, then raised to $200 million per year for
FY2006-FY2015 by Sec. 941 of P.L. 109-58; see below). On October 6, 2005,
USDA announced that 11 biomass research, development and demonstration projects
were selected to receive $12.6 million for the Biomass Research and Development
Initiative.77 The total value of the projects is nearly $19 million, including cost
sharing of the private-sector partners.
74 USDA News Release 0372.05, Sept. 14, 2005.
75 USDA News Release 0261.05, July 15, 2005. For more information on the broader
potential of loan guarantees see, GAO, Wind Power, GAO-04-756, Sept. 2004, pp. 54-55.
76 For more information, see the joint USDA-DOE website at [http://www.bioproducts-
bioenergy.gov/].
77 USDA, News Release No. 0426.05, Oct. 6, 2005.

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Cooperative Research and Development — Carbon Sequestration
(Title IX; Section 9009). This provision amends the Agricultural Risk Protection
Act of 2000 (P.L. 106-224, Sec. 221) to extend through FY2011 the one-time
authorization of $15 million of the Carbon Cycle Research Program, which provides
grants to land-grant universities for carbon cycle research with on-farm applications.
Bioenergy Program (Title IX; Section 9010). This is an existing program
(7 C.F.R. 1424) in which the Secretary makes payments from the CCC to eligible
bioenergy producers — ethanol and biodiesel — based on any year-to-year increase
in the quantity of bioenergy that they produce (fiscal year basis). The goal is to
encourage greater purchases of eligible commodities used in the production of
bioenergy (e.g., corn for ethanol or soybean oil for biodiesel). The Bioenergy
Program was initiated on August 12, 1999, by Executive Order 13134. On October
31, 2000, then-Secretary of Agriculture Glickman announced that, pursuant to the
executive order, $300 million of discretionary CCC funds ($150 million in both
FY2001 and FY2002) would be made available to encourage expanded production
of biofuels. The 2002 farm bill extended the program and its funding by providing
that $150 million would be available annually through the CCC for FY2003-FY2006.
The final rule for the Bioenergy Program was published in the Federal Register
(vol. 68, no. 88, May 7, 2003).
The FY2003 appropriations act limited spending for the Bioenergy Program
funding for FY2003 to 77% ($115.5 million) of the $150 million; however, the full
$150 million was eventually spent.78 In FY2004, no limitations were imposed.
However, a $50 million reduction from the $150 million was contained in the
FY2005 appropriations act, followed by a $90 million reduction in the FY2006
appropriations act.
Renewable Energy on Conservation Reserve Program (CRP) Lands
(Title II; Section 2101). This provision amends Section 3832 of the Farm Security
Act of 1985 (1985 farm bill) to allow the use of CRP lands for biomass (16 USC
3832(a)(7)(A)) and wind energy generation (16 USC 3832(a)(7)(B)) harvesting for
energy production.
Rural Development Loan and Grant Eligibility Expanded to More
Renewables (Title VI). Section 6013 — Loans and Loan Guarantees for
Renewable Energy Systems — amends Section 310B of the Consolidated Farm and
Rural Development Act (CFRDA) (7 U.S.C. 1932(a)(3)) to allow loans for wind
energy systems and anaerobic digesters. Section 6017(g)(A) — Business and
Industry Direct and Guaranteed Loans — amends Section 310B of CFRDA (7 U.S.C.
1932) to expand eligibility to include farmer and rancher equity ownership in wind
power projects. Limits range from $25 million to $40 million per project. Section
6401(a)(2) — Value-Added Agricultural Product Market Development Grants —
amends Section 231 of CFRDA (7 U.S.C. 1621 note; P.L.106-224) to expand
eligibility to include farm- or ranch-based renewable energy systems. Competitive
grants are available to assist producers with feasibility studies, business plans,
78 USDA, FSA, Bioenergy Program Archives, 2003 Program Activity, available at
[http://www.fsa.usda.gov/DACO/bioenergy/bio_dacoArchive.htm].

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CRS-35
marketing strategies, and start-up capital. The maximum grant amount is $500,000
per project.
Additional support for renewable energy projects is available in the form of
various loans and grants from USDA’s Rural Development Agency under other
programs such as the Small Business Innovation Research (SBIR) grants and
Value-Added Producer Grants (VAPG).79 In keeping with a trend started in 2003,
USDA is giving priority consideration to grant applications that dedicate at least 51%
of the project costs to biomass energy.
The Healthy Forest Restoration Act of 2003 (P.L. 108-148)
Title II of 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. In addition, Sec. 201(b) increased the annual amount of
discretionary funding available under the Biomass Act for FY2002-FY2007 from $49
million to $54 million (7 USC 8101 note). Section 202 granted authority to the
Secretary of Agriculture to establish 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. It also
authorized $5 million annually to be appropriated for each of FY2004-FY2008 for
such activities. Finally, Sec. 203 established a biomass utilization grant program to
provide funds to offset the costs incurred in purchasing biomass materials for
qualifying facilities. Funding of $5 million annually was authorized to be
appropriated for each of FY2004-FY2008 for this biomass utilization grant program.
The American Jobs Creation Act of 2004 (P.L. 108-357)
The American Jobs Creation Act — signed into law on October 22, 2004 —
contains two provisions (Sections 301 and 701) that provide tax exemptions for three
agri-based renewable fuels: ethanol, biodiesel, and wind energy.
Federal Fuel Tax Exemption for Ethanol (Section 301). This provision
provides for an extension and replaces the previous federal ethanol tax incentive (26
U.S.C. 40). The tax credit is revised to allow for blenders of gasohol to receive a
federal tax exemption of $0.51 per gallon for every gallon of pure ethanol. Under
this volumetric orientation, the blending level is no longer relevant to the calculation
of the tax credit. Instead, the total volume of ethanol used is the basis for calculating
the tax.80 The tax credit for alcohol fuels was extended through December 31, 2010.
Federal Fuel Tax Exemption for Biodiesel (Section 301). This
provision provides for 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 is used in blending with petroleum diesel; and a 50¢
79 For more information see [http://www.rurdev.usda.gov/rd/energy/].
80 For more information, see the American Coalition for Ethanol, Volumetric Ethanol Excise
Tax Credit (VEETC) at [http://www.ethanol.org/veetc.html]

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CRS-36
credit for every gallon of non-agri-biodiesel (i.e., recycled oils such as yellow
grease). The tax credits for biodiesel fuels were extended through December 31,
2006 (extended through 2008 by P.L. 109-58; see below).
Federal Production Tax Exemption for Wind Energy Systems
(Section 710). This provision renews a federal production tax credit (PTC) that
expired on December 31, 2003. The renewed tax credit provides a 1.5¢ credit
(adjusted annually for inflation) for a 10-year period for each kilowatt-hour of
electricity produced by qualifying turbines that are built by the end of 2005 (extended
through 2007 by P.L. 109-58; see below). The inflation-adjusted PTC stood at 1.8¢
per kWh as of December 2003.
Energy Policy Act of 2005 (EPACT; P.L. 109-58)
The Energy Policy Act of 2005 — signed into law on August 8, 2005 —
contains several provision related to agriculture-based renewable energy production
including the following.81
National Renewable Fuels Standard (RFS) (Sec. 1501). Requires that
4.0 billion gallons of renewable fuel be used domestically in 2006, increasing to 7.5
billion gallons by 2012.
Minimum Quantity of Ethanol from Cellulosic Biomass (Sec. 1501).
For calendar 2013 and each year thereafter, the RFS volume shall contain a minimum
of 250 million gallons derived from cellulosic biomass.
Special Consideration for Cellulosic Biomass or Waste Derived
Ethanol (Sec. 1501). For purposes of the RFS, each gallon of cellulosic biomass
ethanol or waste derived ethanol shall be counted as the equivalent of 2.5 gallons of
renewable fuel.
Small Ethanol Producer Credit Adjusted (Sec. 1347). The definition
of a small ethanol producer was extended from 30 million gallons per year to 60
million gallons per year. Qualifying producers are eligible for an additional tax credit
of 10¢ per gallon on the first 15 million gallons of production.
Biodiesel Tax Credit Extension Through 2008 (Sec. 1344). Extends
the $1.00 per gallon biodiesel tax credit through 2008.
Small Biodiesel Producer Credit Established (Sec. 1345). Agri-
biodiesel producers with a productive capacity not in excess of 60 million gallons are
eligible for an additional tax credit of 10¢ per gallon on the first 15 million gallons
of production.
81 For more information, see CRS Report RL32204, Omnibus Energy Legislation:
Comparison of Non-Tax Provisions in the H.R. 6 Conference Report and S. 2095, by Mark
Holt and Carol Glover, coordinators; and CRS Report RL32078, Omnibus Energy
Legislation: Comparison of Major Provisions in House- and Senate-Passed Versions of
H.R. 6, Plus S. 14, by Mark Holt, coordinator.

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CRS-37
Funding Support for Research, Development, and Demonstration
of Alternate Biofuel Processes. Several alternate forms of assistance including
(Sec. 1512) grants for conversion assistance of cellulosic biomass, waste-derived
ethanol, and approved renewable fuels; (Sec. 1514) establish a demonstration
program for advanced biofuel technologies; (Sec. 1515) extend biodiesel feedstock
sources to include animal and municipal waste; and (Sec. 1516) provide loan
guarantees for demonstration projects for ethanol derived from surgarcane, bagasse,
and other sugarcane byproducts.
Wind PTC Extension Through 2007 (Sec. 1301). Provides a two-year
extension through December 31, 2007, for the production tax credit for wind;
maintains the PTC inflation adjustment factor of current law; and (Sec. 1302) extends
the PTC to agricultural cooperatives.
Agricultural Biomass Research and Development Programs (Sec.
942-948). This section of EPACT provides several amendments to the BRDA as
follows. Section 941 updates BRDA to intensify focus on achieving the scientific
breakthroughs (particularly with respect to cellulosic biomass) required for expanded
deployment of biobased fuels, products, and power, including:
! increased emphasis on feedstock production and delivery, including
technologies for harvest, handling and transport of crop residues;
! research and demonstration (R&D) of opportunities for synergy with
existing biofuels production, such as use of dried distillers grains
(DDGs) as a bridge feedstock;
! support for development of new and innovative biobased products
made from corn, soybeans, wheat, sunflower, and other raw
agricultural commodities;
! ensuring a balanced and focused R&D approach by distributing
funding by technical area (20% to feedstock production; 45% to
overcoming biomass recalcitrance; 30% to product diversification;
and 5% to strategic guidance), and within each technical area by
value category (15% to applied fundamentals; 35% to innovation;
and 50% to demonstration); and
! increasing annual program authorization from the current $54
million to $200 million for 10 years — FY2006-FY2015.
Section 942 expands the production incentives for cellulosic biofuels by
directing the Secretary of Energy to establish a program of production incentives to
deliver the first billion gallons of annual cellulosic biofuels production by 2015.
Funds are allocated for proposed projects through set payments on a per gallon basis
for the first 100 million gallons of annual production, followed by a reverse auction
competitive solicitation process to secure low-cost cellulosic biofuels production
contracts. Production incentives are awarded to the lowest bidders, with not more
than 25% of the funds committed for each auction awarded to a single bid. Awards
may not exceed $100 million in any year, nor $1 billion over the lifetime of the
program. The first auction shall take place within one year of the first year of annual
production of 100 million gallons of cellulosic biofuels, with subsequent auctions
each year thereafter until annual cellulosic biofuels production reaches 1 billion

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CRS-38
gallons. Funding of $250 million, until expended, is authorized to carry out this
section subject to appropriations.
Section 943 corrects the Biobased Procurement Program authorized under
Section 9002 of the 2002 farm bill by applying the provision to federal government
contractors. The program currently requires federal agencies to give preference to
biobased products for procurement exceeding $10,000 when suitable biobased
products are available at reasonable cost. This provision would expand the
requirement to federal contractors. It also directs the Architect of the Capitol, the
Sergeant at Arms of the Senate, and the Chief Administrative Officer of the House
of Representatives to comply with the Biobased Procurement Program for
procurement of the United States Capitol Complex. Furthermore, it directs the
Architect of the Capitol to establish within the Capitol Complex a program of public
education regarding its use of biobased products.
Sections 944-946 establish USDA grants programs to assist small biobased
businesses with marketing and certification of biobased products (Sec. 944; funding
of $1 million is authorized for FY2006, and such sums as necessary thereafter); to
assist regional bioeconomy development associations and Land Grant institutions in
supporting and promoting the growth of regional bioeconomies (Sec. 945; funding
of $1 million is authorized for FY2006, and such sums as necessary thereafter); and
for demonstrations by farmer-owned enterprises of innovations in pre-processing of
feedstocks and multiple crop harvesting techniques, such as one-pass harvesting, to
add value and lower the investment cost of feedstock processing at the biorefinery
(Sec. 946; annual funding of $5 million is authorized for FY2006-FY2010).
Section 947 establishes a USDA program of education and outreach consisting
of (1) training and technical assistance for feedstock producers to promote producer
ownership and investment in processing facilities; and (2) public education and
outreach to familiarize consumers with biobased fuels and products. Annual funding
of $1 million is authorized for FY2006-FY2010.
Finally, Section 948 requires a report on the economic potential of biobased
products through the year 2025 as well as the economic potential by product area
(within one year of enactment or by Aug. 8, 2006) , and analysis of economic
indicators of the biobased economy (within two years of enactment or by Aug. 8,
2007) .
Agriculture-Related Energy Bills in 109th Congress
Several additional bills have been introduced in the 109th Congress that seek to
enhance or extend current provisions in existing law that support agriculture-based
energy production and use. Many of these bills emphasize expanded production and
use of biofuels and other renewable energy sources. Examples of these include H.R.
140; H.R. 622; H.R. 737; H.R. 983; H.R. 4409; H.R. 4897; H.R. 5010; H.R. 5296;
S. 326; S. 427; S. 1210; S. 1229; S. 1609; S. 2025; S. 2398; S. 2401; and S. 2571.
In addition, several bills have been introduced that seek to provide incentives
for the production and use of alternative fuel vehicles. See CRS Issue Brief IB10128,
Alternative Fuels and Advanced Technology Vehicles: Issues in Congress, by Brent

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CRS-39
D. Yacobucci for a listing of proposed legislation on alternative fuel vehicles. See
CRS Report RS22351, Tax Incentives for Alternative Fuel and Advanced Technology
Vehicles, by Brent D. Yacobucci for a description of existing alternative-fuel vehicle
tax incentives.
State Laws and Programs
Several state laws and programs influence the economics of renewable energy
production and use by providing incentives for research, production, and
consumption of renewable fuels such as biofuels and wind energy systems.82 In
addition, demand for agriculture-based renewable energy is being driven, in part, by
state Renewable Portfolio Standards (RPS) that require utilities to obtain set
percentages of their electricity from renewable sources by certain target dates.
The amounts and deadlines vary, but as of January 2006, 34 states had laws
instituting RPSs requiring, at a minimum, that state vehicle fleets procure certain
volumes or percentages of renewable fuels. In several states, the RPS applied state-
wide on all motor vehicles; for example see Minnesota Statutes Section 239.77 which
requires that all diesel fuel sold or offered for sale in the state for use in internal
combustion engines must contain at least 2% biodiesel fuel by volume. This mandate
was to take effect by June 30, 2005, provided certain market conditions were met.83
82 For more information on state and federal programs, see State and Federal Incentives and
Laws, at the DOE’s Alternative Fuels Data Center, [http://www.eere.energy.gov/afdc/
laws/incen_laws.html].
83 For more information on Minnesota vehicle fuel acquisition requirements, visit
[http://www.eere.energy.gov/afdc/progs/view_ind_mtx.cgi?reg/REQ/MN/0].

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CRS-40
For More Information
Renewable Energy
DOE, Energy Information Agency (EIA), [http://www.eia.doe.gov/].
DOE, National Renewable Energy Laboratory (NREL), Renewable Energy,
[http://www.nrel.gov/].
USDA, Oak Ridge National Laboratory, Energy Efficiency and Renewable Energy
Program, Renewable Energy, [http://www.ornl.gov/sci/eere/renewables/index.htm].
USDA, Office of the Chief Economist, Office of Energy Policy and New Uses
(OEPNU), [http://www.usda.gov/oce/energy/index.htm].
The Sustainable Energy Coalition, [http://www.sustainableenergy.org/].
Eidman, Vernon R. “Agriculture as a Producer of Energy,” presentation at USDA
conference Agriculture as a Producer and Consumer of Energy, June 24, 2004.
Biofuels
CRS Report RL33290, Fuel Ethanol: Background and Public Policy Issues, by Brent
D. Yacobucci.
American Coalition for Ethanol, [http://www.ethanol.org/].
Renewable Fuels Association (RFA), [http://www.ethanolrfa.org/].
The Distillery and Fuel Ethanol Worldwide Network, [http://www.distill.com/].
The National Biodiesel Board (NBB), [http://www.biodiesel.org/].
DOE, Energy Efficiency and Renewable Energy (EERE), Alternative Fuels Data
Center, [http://www.eere.energy.gov/afdc/].
Environmental Protection Agency (EPA), Fuels and Fuel Additives, Alternative
Fuels, [http://www.epa.gov/otaq/consumer/fuels/altfuels/altfuels.htm].
Economic Benefits of Biofuel Production
Food and Agricultural Policy Research Institute (FAPRI), Impacts of Increased
Ethanol & Biodiesel Demand, FAPRI-UMC Report #13-01, October 2001, available
at [http://www.fapri.missouri.edu/].
P. Gallagher, D. Otto, H. Shapouri, J. Price, G. Schamel, M. Dikeman, and H.
Brubacker, The Effects of Expanding Ethanol Markets on Ethanol Production, Feed
Markets, and the Iowa Economy, Staff Paper #342, Dept. of Economics, Iowa St.
Univ., June 30, 2001.

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Shapouri, Hosein, James Duffield, Andrew McAloon, Michael Wang. “The 2001 Net
Energy Balance of Corn-ethanol.” Paper presented at the Corn Utilization and
Technology Conference, June 7-9, 2004, Indianapolis, IN.
Shapouri, Hosein; James A. Duffield, and Michael Wang. The Energy Balance of
Corn Ethanol: An Update. USDA, Office of the Chief Economist, Office of Energy
Policy and New Uses. Agricultural Economic Report (AER) No. 813, July 2002;
available at [http://www.usda.gov/oce/reports/energy/index.htm].
Urbanchuk, J. M. The Contribution of the Ethanol Industry to the American
Economy in 2004, March 12, 2004, available at [http://www.ncga.com/ethanol/pdfs/
EthanolEconomicContributionREV.pdf]
Urbanchuk, J. M. and J. Kapell, Ethanol and the Local Community, June 20, 2002,
available at [http://www.ncga.com/ethanol/pdfs/EthanolLocalCommunity.pdf].
Urbanchuk, J. M. An Economic Analysis of Legislation for a Renewable Fuels
Requirement for Highway Motor Fuels, November 7, 2001.
Anaerobic Digestion Systems
The Agricultural Marketing Research Center, Bio-Mass/Forages, at
[http://www.agmrc.org/agmrc/commodity/biomass/].
Wind Energy Systems
American Wind Energy Association (AWEA), [http://www.awea.org/].
DOE, Wind Energy Program, [http://www.eere.energy.gov/RE/wind.html].
The Utility Wind Interest Group, [http://www.uwig.org].

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