Order Code RL32712
CRS Report for Congress
Received through the CRS Web
Agriculture-Based Renewable Energy Production
January 4, 2005
Randy Schnepf
Specialist in Agricultural Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress
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 3.3 billion gallons per year in 2004.
Biodiesel production has risen from 0.5 million gallons in 1999 to over 30 million
gallons in 2004. Wind energy systems production capacity has shown nearly all of
its growth in the past six years, rising from 1.7 million megawatts in 1997 to an
estimated 6.7 million megawatts in 2003.
Agriculture- and rural-based energy production reached 374 trillion Btu (British
Thermal Units) in 2003. Of this amount, ethanol accounted for about 70%; wind
energy systems for 29%; and biodiesel energy output for 1%. This contribution
provided 0.4% of total U.S. energy consumption in 2003 (98.2 quadrillion Btu).
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 stocks 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.
Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Agriculture’s Share of Energy Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Agriculture-Based Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Corn-Based Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Ethanol from Cellulosic Biomass Crops . . . . . . . . . . . . . . . . . . . . . . . 11
Methane from an Anaerobic Digester . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Biodiesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Public Laws That Support Energy Production and Use by Agriculture . . . . . . . . 26
Clean Air Act Amendments of 1990 (CAAA; P.L. 101-549) . . . . . . . . . . . 26
Energy Policy Act of 1992 (EPACT; P.L. 102-486) . . . . . . . . . . . . . . . . . . 26
The American Jobs Creation Act of 2004 (AJCA; P.L. 108-357) . . . . . . . . 26
Energy Provisions in the 2002 Farm Bill (P.L. 107-171) . . . . . . . . . . . . . . 27
Agriculture-Related Provisions in 108th Congress
Omnibus Energy Legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
State Laws and Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
For More Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Renewable Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
List of Figures
Figure 1. U.S. Ethanol Production, Annual 1980-2004 . . . . . . . . . . . . . . . . . . . . 5
Figure 2. Corn versus Gasoline Prices, 1991-2004 . . . . . . . . . . . . . . . . . . . . . . . . 7
Figure 3. U.S. Biodiesel Production, 1998-2004 . . . . . . . . . . . . . . . . . . . . . . . . 15
Figure 4. Soybean Oil vs Diesel Fuel, 1994 to 2004 . . . . . . . . . . . . . . . . . . . . . . 17
Figure 5. U.S. Installed Wind Energy Capacity, 1981-2003 . . . . . . . . . . . . . . . . 20
Figure 6. Natural Gas Price, 1998 to 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Figure 7. U.S. Areas with Highest Wind Potential . . . . . . . . . . . . . . . . . . . . . . . 24
List of Tables
Table 1. U.S. Energy Production and Consumption, 2003 . . . . . . . . . . . . . . . . . . 3
Table 2. Ethanol Production Capacity by State, November 2004 . . . . . . . . . . . . . 6
Table 3. Energy and Price Comparisons: Various Fuels . . . . . . . . . . . . . . . . . . . . 8
Table 4. U.S. Diesel Fuel Use, 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Table 5. U.S. Potential Biodiesel Feedstocks, 2002/03 . . . . . . . . . . . . . . . . . . . 19
Table 6. Installed Wind Energy Capacity by State, August 2004 . . . . . . . . . . . . 21
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 has grown rapidly in recent years, but still
remains small relative to total national energy needs. In 2003, it provided 0.4% of
total U.S. energy consumption (see Table 1). Ethanol accounted for about 70% of
agriculture-based energy production in 2003; wind energy systems for 29%; and
biodiesel energy output 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. 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.3 In
addition, proponents argue that rural, agriculture-based energy production can
enhance rural incomes and employment opportunities, while encouraging greater
value-added for U.S. agricultural commodities.4
1 For more information on energy use by the agricultural sector, see CRS Report RL32677,
Energy Use in Agriculture: Background and Issues.
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 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/].
4 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.
CRS-2
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.5 Until such technological breakthroughs are achieved,
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.6 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 the 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 the Department of Energy (DOE), Energy
Efficiency and Renewable Energy (EERE), Alternative Fuels Data Center, at
[http://www.eere.energy.gov/afdc/altfuel/fuel_properties.html]; or see CRS Report
RL30758, Alternative Transportation Fuels and Vehicles: Energy, Environment, and
Development Issues.
5 Advocates of this position include free-market proponents such as the Cato Institute, and
federal budget watchdog groups such as Citizens Against Government Waste and Taxpayers
for Common Sense.
6 For example, see the Natural Resources Defense Council’s fact sheet on biomass energy
at [http://www.nrdc.org/air/energy/fbiom.asp]. See also 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.
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Agriculture’s Share of Energy Production
In 2003, the major agriculture-produced energy source — ethanol — accounted
for about 0.8% of U.S. petroleum consumption and about 0.3% of total 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.7
Table 1. U.S. Energy Production and Consumption, 2003
Production
Consumption
Quadrillion
% of
Quadrillion
% of
Energy source
Btu
total
Btu
total
Total
70.5
100.0%
98.2
100.0%
Fossil Fuels
56.4
80.1%
84.4
85.9%
Nuclear
8.0
11.3%
8.0
8.1%
Renewables
6.2
8.7%
6.2
6.3%
Fossil Fuel Categories
Petroleum and products
12.1
17.2%
39.0
39.8%
Coal
22.3
31.7%
22.7
23.1%
Natural Gas
22.0
31.2%
22.6
23.0%
Renewable Categories
Hydroelectric power
2.8
3.9%
2.8
2.8%
Wood, waste, oth. alcohol
2.6
3.7%
2.6
2.7%
Geothermal
0.3
0.4%
0.3
0.3%
Solar
0.1
0.1%
0.1
0.1%
Ethanol
0.3
0.4%
0.3
0.3%
Biodiesel
0.0
0.0%
0.0
0.0%
Wind
0.1
0.2%
0.1
0.1%
Source: Ethanol data: American Coalition on Ethanol, [http://www.ethanol.org]; biodiesel data:
National Biodiesel Board, [http://www.biodiesel.org]; all other data: DOE, Energy Information
Agency (EIA), Table 1.2, “Energy Production by Source, 1949-2003,” and Table 1.3, “Total U.S.
Energy Consumption by Source.”
7 See section on “Public Laws That Support Energy Production and Use by Agriculture,”
below, for a listing of major laws supporting farm-based renewable energy production.
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Agriculture-Based Biofuels
Biofuels are liquid fuels produced from biomass. Types of biofuels include
ethanol, biodiesel, methanol, and reformulated gasoline components.8 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.
Ethanol9
Ethanol, or ethyl alcohol, is an alcohol made by fermenting and distilling simple
sugars. 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 (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 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
(see Figure 1). Several events have contributed to greater 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
8 For more information on these and other alternative fuels, see CRS Report RL30758,
Alternative Transportation Fuels and Vehicles: Energy, Environment, and Development
Issues. See also DOE, National Renewable Energy Laboratory (NREL), Introduction to
Biofuels, available at [http://www.nrel.gov/clean_energy/biofuels.html].
9 For more information, see CRS Report RL30369, Fuel Ethanol: Background and Public
Policy Issues.
CRS-5
as a gasoline oxygenate, and provisions of the Clean Air Act Amendments of 1990
that favored ethanol blending with gasoline.10
Figure 1. U.S. Ethanol Production, Annual 1980-2004
In November 2004, existing U.S. ethanol plant capacity was a reported 3,419
million gallons per year, with an additional capacity of 706 million gallons per year
under construction. U.S. ethanol production presently is underway or planned in 25
states centered around the central and western Corn Belt, where corn supplies are
most plentiful (see Table 2).11 Corn accounts for over 90% of the feedstocks used
in ethanol production in the United States.
Corn-Based Ethanol. USDA projects that 1.425 billion bushels of corn (or
12.2% of total U.S. corn production) will be used from the 2004 corn crop to produce
up to 3.8 billion gallons of ethanol during 2004/05 (September-August).12 In
gasoline-equivalent gallons (GEG), this represents more than 2.5 billion gallons.13
Despite its rapid growth, ethanol production represents a minor part of U.S. gasoline
consumption, with a projected 1.6% share in 2004 (2.1 billion GEG out of 136.4
billion gallons of total gasoline use).14
10 For more information, see 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 (hereafter referred to as Shapouri (2002).
11 See American Coalition for Ethanol, Ethanol Production, at [http://www.ethanol.org/
production.html].
12 Data sources — corn use for ethanol: USDA, World Agricultural Outlook Board, World
Agricultural Supply and Demand Estimates, Dec. 10, 2004; ethanol production: American
Coalition for Ethanol, Ethanol Production, at [http://www.ethanol.org/production.html].
13 Based on a conversion rate of 1.73 GEG per bushel of corn (2.66 gallons of ethanol per
bushel of corn and 0.65 GEG per gallon of ethanol).
14 U.S. gasoline use: DOE, IEA, Alternatives to Traditional Transportation Fuels 2003, at
(continued...)
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Table 2. Ethanol Production Capacity by State, November 2004
Under
State
Operating
Construction
Total
Million gallons per year
Iowa
872
350
1,222
Illinois
695
33
728
Minnesota
398
149
546
Nebraska
492
0
492
South Dakota
384
20
404
Kansas
134
20
154
Wisconsin
87
40
127
Missouri
65
40
105
Indiana
95
0
95
Others
197
54
251
U.S. Total
3,419
706
4,124
Source: Renewable Fuels Association, U.S. Fuel Ethanol Production Capacity, at [http://www.
ethanolrfa.org/eth_prod_fac.html], November 2004.
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 the week of June 14, 2004, the average retail price of E85 (a blend
of 85% ethanol with 15% gasoline) ranged between $2.28 and $2.70 per GEG,
compared with a range of $1.92 to $2.24 for regular grade gasoline (see Table 3).15
The approximate price difference of 36¢ to 46¢ implies that pure ethanol costs as
much as 42¢ to 54¢ per GEG more than gasoline. The federal production tax credit
of 51¢ per gallon of pure ethanol (see below) offsets most 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).
14 (...continued)
[http://www.eia.doe.gov/cneaf/alternate/page/datatables/atf1-13_03.html].
15 DOE, Energy Efficiency and Renewable Energy (EERE), Alternative Fuel Price Report,
June 29, 2004, at [http://www.eere.energy.gov/afdc/resources/pricereport/price_report.html].
CRS-7
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. As a result, the relative relationship of corn
to gasoline prices provides a strong indicator of the ethanol industry’s well-being.
A comparison of corn versus gasoline prices (see Figure 2) suggests that the general
trend since the late 1990s has clearly been in ethanol’s favor as national average
monthly gasoline prices have surged towards the $2.00 per gallon level while corn
prices have returned to the $2.00 per bushel level of the early 2000s.
Figure 2. Corn versus Gasoline Prices, 1991-2004
Government Support. Federal subsidies help ethanol to overcome its higher
cost relative to gasoline. The primary federal incentives include:16
! 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 USC 40) of 10¢ per gallon
for the first 15 million gallons of production for ethanol producers
whose total output does not exceed 30 million gallons of ethanol per
year; 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
16 For more information, see section on “Public Laws That Support Energy Production and
Use by Agriculture,” later in this report.
CRS-8
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.
Table 3. Energy and Price Comparisons: Various Fuels
Average
Average
Btu’s per
Price:
Price:
Fuel type
Unit
unita
$ per unit
GEGb
$ per GEGc
Gasoline:
conventional
gallon
125,071
$1.92 - $2.24
1.00
$1.92 - $2.24
Ethanol (E85)
gallon
83,361
$1.82 - $2.16
0.80
$2.28 - $2.70
Diesel fuel
gallon
138,690
$1.64 - $2.00
1.11
$1.48 - $1.80
Biodiesel (B20)
gallon
138,690
$1.73 - $2.11
1.11
$1.56 - $1.90
Propane
gallon
91,333
$1.40 - $2.25
0.74
$1.88 - $3.02
Natural Gasd
1,000 ft.3
1,030
$6.08 - $8.08
na
$1.02 - $1.54
10 x
Biogas
1,000 ft.3
(% methane)e
na
na
na
kilowatt-
Electricityf
hour
3,413
5¢ - 16¢
na
na
Source: Conversion rates for petroleum-based fuels and electricity are from DOE, Monthly Energy
Review, August 2004.
na = not applicable.
a 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 allows the adding of various types of energy using a common benchmark.
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 125,000, and finally multiplying
each fuel’s volume by the resulting ratio.
c DOE, EIA, The Alternative Fuel Price Report, June 29, 2004. Prices are for mid-June 2004. The
retail price per gallon has been converted to price per GEG units.
d Natural Gas prices, $ per 1,000 cu. ft., are industrial prices for the month of July 4, 2004, from DOE,
EIA, available at [http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm].
e When burned, biogas yields about 10 Btu per percentage of methane composition. For example, 65%
methane yields 650 Btu per 1,000 cubic foot.
f Prices are for commercial electricity rates per kilowatt-hour.
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;
! the energy efficiency of corn production, including the energy
embodied in inputs such as fertilizers, pesticides, seed corn, and
cultivation practices;
! the energy efficiency of the corn-to-ethanol production process —
about 55% of the corn used for ethanol is processed by “dry” milling
CRS-9
(a grinding process); 45% is processed by “wet” milling plants (a
chemical extraction process); and
! the energy value of corn by-products.17
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.18 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
cycle from source to user.19 Other researchers have found much lower NEB values
under less optimistic assumptions.20
Long-Run Supply Issues. Despite improving energy efficiency, the ability
for domestic ethanol production to measureably substitute for petroleum imports is
questionable, particularly when ethanol production depends almost entirely on corn
as the primary feedstock. The U.S. petroleum import share is estimated at 54% of
consumption in 2004 and is expected to grow to a 70% share by 2025.21 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 2004 U.S. corn production
were dedicated to ethanol production, the resultant 20.3 billion GEG would represent
about 15% of projected national gasoline use of 136.4 billion gallons.22 In 2004,
slightly more than 73 million acres of corn are expected to be harvested. At least 140
million acres would be needed to produce enough corn and subsequent ethanol to
substitute for 50% of gasoline imports (or 27% of U.S. consumption).23 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
17 According to USDA, dry milling is more energy efficient than wet milling, particularly
when corn co-products are considered; Shapouri (2002), p. 5.
18 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 referred to as Shapouri (2004).
19 Minnesota Dept. of Agr., Energy Balance/Life Cycle Inventory for Ethanol, Biodiesel and
Petroleum Fuels, at [http://www.mda.state.mn.us/ethanol/balance.html].
20 Professor David Pimentel, Cornell University, College of Agriculture and Life Sciences,
has researched and published extensive criticisms of corn-based ethanol production. For
example, see [http://www.news.cornell.edu/Chronicle/01/8.23.01/Pimentel-ethaol.html].
21 DOE, EIA, Annual Energy Outlook 2004 with Projections to 2025.
22 Based on USDA’s Nov. 12, 2004, WASDE, and using comparable conversion rates.
23 Assuming yields of 150 bushel per acre.
CRS-10
feed concentrates and processed feedstuffs fed to animals in the United States.24
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.
Plus, 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 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.25 However, about 66% of the original weight of corn is
consumed in producing ethanol and is no longer available for feed.26 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 (derived primarily
from natural gas) needed to process the corn into ethanol would increase. For
example, the energy needed to process the entire 2004 corn crop into ethanol would
be approximately 1.6 trillion cubic feet of natural gas (or 1.4 trillion cu. ft. more than
is currently used).27 Total U.S. natural gas consumption was about 22.6 trillion cu.ft.
in 2003. 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.28
24 USDA, ERS, Feed Situation and Outlook Yearbook, FDS-2003, April 2003.
25 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.
26 Shapouri (2004), p. 4.
27 CRS calculations based on DOE energy usage rates.
28 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-11
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
across all passenger vehicles in the United States could cut petroleum consumption
by more than all alternative fuels and replacement fuels combined.29
Ethanol from Cellulosic Biomass Crops.30 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.31 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
29 CRS Report RL30758, Alternative Transportation Fuels and Vehicles: Energy,
Environment, and Development Issues, p. 24.
30 For more information on biomass from non-traditional crops as a renewable energy, see
the American Bioenergy Association at [http://www.biomass.org/].
31 Christopher J. Chipello,”Iogen’s Milestone: It’s Selling Ethanol Made of Farm Waste,”
Wall Street Journal, April 21, 2004.
CRS-12
50¢ per gallon of ethanol.32 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) 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.33
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.34
While corn’s net energy balance (under optimistic assumptions concerning corn
production and ethanol processing technology) has been estimated at 67% by USDA
in 2004, it is likely that cellulosic biomass’s net energy balance would also have
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
32 DOE, EERE, Biomass Program, “Cellulase Enzyme Research,” available at [http://www.
eere.energy.gov/biomass/cellulase_enzyme.html].
33 For more information, see [http://www.bioproducts-bioenergy.gov].
34 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, January 1999, as referenced in DOE, DiPardo (2002).
CRS-13
(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.35
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.36 This would represent about 8% of U.S. gasoline use in 2003. 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 Digester37
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. 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.
By late 2002, there were an estimated 40 digester systems in operation at
commercial U.S. livestock farms, with an additional 30 expected to be in operation
by 2003.38 Anaerobic digestion system proposals have frequently received funding
under the Renewable Energy Program (REP) of the 2002 farm bill (P.L. 107-171,
35 United Nations, Food and Agricultural Organization (FAO), FAOSTATS.
36 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/oepnu/].
37 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]; or Iowa State University,
Agricultural Marketing Resource Center, Anaerobic Digesters/Methane, at [http://www.
agmrc.org/ biomass/anaerobicmain.html].
38 U.S. Environmental Protection Agency (EPA), Office of Air and Radiation (OAR),
Managing Manure with Biogas Recovery Systems, EPA-430-F-02-004,Winter 2002.
CRS-14
Title IX, Section 9008). In 2004, 37 anaerobic digester proposals from 26 different
states were awarded funding under the REP.39 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.40
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.41 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.42 A 200-head dairy herd could
generate 500 to 600 Kilowatts per day. At 6¢ per kWh, this would represent potential
energy cost savings of $6,600 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
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.
39 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].
40 DOE, EERE, Methane (Biogas) from Anaerobic Digesters, at [http://www.eere.energy.
gov/consumerinfo/factsheets/ab5.html].
41 EPA, OAR, Managing Manure with Biogas Recovery Systems, EPA-430-F-02-004,Winter
2002.
42 ATTRA, Anaerobic Digestion of Animal Wastes: Factors to Consider, Oct. 2002.
CRS-15
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.
Figure 3. U.S. Biodiesel Production, 1998-2004
U.S. biodiesel production has shown strong growth in recent years, increasing
from under 1 million gallons in 1999 to over 30 million gallons in 2004 (see Figure
3). However, U.S. biodiesel production remains small relative to national diesel
consumption levels. In 2003, biodiesel production of 25 million gallons represented
0.06% of the 40 billion gallons of diesel fuel used nationally for vehicle
transportation.43 In addition to vehicle use, 17.8 billion gallons of diesel fuel were
used for heating and power generation by residential, commercial, and industry, and
43 Biodiesel consumption estimates are from DOE, IEA, “Alternatives to Traditional
Transportation Fuels 2003, Estimated Data.”
CRS-16
by railroad and vessel traffic in 2002, bringing total U.S. diesel fuel use to nearly 58
billion gallons (see Table 4).
As of October 2004, there were more than 20 companies producing and
marketing biodiesel commercially in the United States, and another 20 new firms that
have reported their plans to construct dedicated biodiesel plants in the near future.44
The NBB reported that mid-2004 U.S. biodiesel production capacity was an
estimated 150 million gallons per year, but would likely double in size over the next
12-18 months based on the number of ongoing biodiesel projects.45 But many of
these plants also can produce other products, for example, cosmetics, so total
capacity (and capacity for expansion) is far greater than actual biodiesel production.
Economic Efficiency. Biodiesel is generally more expensive than its fossil
fuel counterpart. For example, during the week of June 14, 2004, the average retail
price of B20 (a blend of 20% biodiesel with 80% conventional diesel) ranged from
$1.73 to $2.11 per gallon compared with a range of $1.64 to $2.00 for conventional
diesel fuel (see Table 3).46 The approximate price difference of 10¢ implies that pure
biodiesel costs as much as 50¢ more per gallon to produce.
Table 4. U.S. Diesel Fuel Use, 2002
Hypothetical Scenario:
Total
1% of Total Useb
Soybean Oil
Million
Million
Equivalents:
U.S. Diesel Use in 2002
gallonsa
gallons
Million poundsa
Total Vehicle Use
40,043
400
3,083
On-Road
34,309
343
2,642
Off-Road
2,224
22
171
Military
331
3
25
Farm
3,179
32
245
Total Non-vehicle Use
17,842
178
1,374
All Uses
57,885
579
4,457
Source: U.S. diesel use is from DOE, EIA, U.S. Annual Distillate Sales by End Use.
aPounds are converted from gallons of oil using a 7.7 pounds-to-gallon conversion rate.
bHypothetical scenario included for comparison purposes only.
The prices of biodiesel feedstocks, as well as petroleum-based diesel fuel, vary
over time based on domestic and international supply and demand conditions (see
Figure 4). As diesel fuel prices rise relative to biodiesel, and/or as biodiesel
44 National Biodiesel Board (NBB), “U.S. Biodiesel Production Capacity,” October 2004,
available at [http://www.biodiesel.org/pdf_files/Production%20Capacity_2004.pdf].
45 Ibid.
46 DOE, EERE, Alternative Fuel Price Report, June 29, 2004, available at [http://www.
eere.energy.gov/afdc/resources/pricereport/ price_report.html].
CRS-17
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.
Government Support. The primary federal incentive for biodiesel production
is a production excise tax credit signed into law on October 22, 2004, as part of the
American Jobs Creation Act of 2004 (P.L. 108-357). 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). At current 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 10¢ 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 2006.
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.
Figure 4. Soybean Oil vs Diesel Fuel, 1994 to 2004
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.47 In contrast, the study
authors point out that petroleum diesel has an NEB of 0.83 — that is, 17% less
47 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].
CRS-18
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.48 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, 2006, 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. If, under a hypothetical scenario (as shown in Table 4), 1% of current
vehicle diesel fuel use were to originate from biodiesel sources, this would require
about 400 million gallons of biodiesel (compared to current production of about 30
million gallons) or approximately 3 billion pounds of soybean oil. During 2003, a
total of 31.7 billion pounds of vegetable oils and animal fats were produced in the
United States; 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 (see Table 5).
If biodiesel were to be 1% of diesel use, an additional 900 million pounds of
soybean oil would be needed after exhausting all available feedstocks. This is nearly
equivalent to the 937 million pounds of soybean oils exported by the United States
in 2003/04. If soybean oil exports were to remain unchanged, the deficit feedstocks
could be obtained either by reducing U.S. whole soybean exports by about 80 million
bushels or by expanding soybean production by approximately 1.6 million acres
(assuming a yield of about 50 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
prices significantly higher due to the low elasticity of demand for vegetable oils in
food consumption.49 At the same time, it would begin to disturb feed markets.
48 For more information, see NBB, “Ground-Breaking Biodiesel Tax Incentive Passes,” at
[http://www.biodiesel.org/resources/pressreleases/gen/20041011_ FSC_Passes_Senate.pdf];
see also section on “Public Laws That Support Energy Production and Use by Agriculture”
later in this report.
49 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.
CRS-19
Table 5. U.S. Potential Biodiesel Feedstocks, 2002/03
Oil Production,
Ending Stocks:
Wholesale
2002/03
Sept. 30, 2003
pricea
Million
Million
Million
Million
Oil type
$/lb
pounds
gallonsa
pounds
gallonsa
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.
aAverage 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.
bPounds are converted to gallons of oil using a 7.7 pounds-to-gallon conversion rate.
cThe price average is for rapeseed oil, f.o.b., Rotterdam; USDA, FAS, Oilseeds: World Market and
Trade, various issues.
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 80 million bushels of soybeans for soybean oil would
produce over 1.9 million short tons (s.t.) of soybean meal. In 2003/04, the United
States produced 36.6 million s.t. of soybean meal. An additional 1.9 million s.t. of
soybean meal entering U.S. feed markets would compete directly with the feed by-
products of ethanol production (distillers dried grains, corn gluten feed, and corn
CRS-20
gluten meal) with economic ramifications that have not yet been fully explored.50
Also similar to ethanol production, natural gas demand would likely rise with the
increase in biodiesel processing.51
Wind Energy Systems
In 2003, electricity from wind energy systems accounted for about 0.1% of U.S.
total energy consumption (see Table 1). However, wind-generated electricity
compared more favorably as a share of electricity used by the U.S. agriculture sector
(28%), or of total direct energy used by U.S. agriculture (9%) that same year.52 Total
installed wind energy production capacity has expanded rapidly in the United States
in the past six years, rising from 1,848 megawatts (MW)53 in 1998 to nearly 6,400
MW by 2003 (see Figure 5).54 About 90% of capacity is in 10 predominantly
midwestern and western states (see Table 6).
Figure 5. U.S. Installed Wind Energy Capacity, 1981-2003
50 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.
51 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.
52 For more information on energy consumption by U.S. agriculture, see CRS Report
RL32677, Energy Use in Agriculture: Background and Issues.
53 A watt is the basic unit used to measure electric power. A kilowatt (kW) equals 1,000
watts and a megawatt (MW) equals 1,000 kW or 1 million watts. 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 operates nonstop
during all 8,760 hours in the year, it will produce 8,760,000 kWh.
54 American Wind Energy Association (AWEA), at [http://www.awea.org].
CRS-21
In the United States, a wind turbine with a generating capacity of 1 MW, placed
on a tower situated on a farm, ranch, or other rural land, can generate enough
electricity in a year — between 2.4 to 3 million kilowatt-hours (kWh) — to serve the
needs of 240 to 300 average U.S. households.55 However, 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).
Table 6. Installed Wind Energy Capacity by State, August 2004
State
Megawatts
Share
California
2,042.6
32.0%
Texas
1,293.0
20.3%
Minnesota
562.7
8.8%
Iowa
471.2
7.4%
Wyoming
284.6
4.5%
Oregon
259.4
4.1%
Washington
243.8
3.8%
Colorado
223.2
3.5%
New Mexico
206.6
3.2%
Oklahoma
176.3
2.8%
Others
610.5
9.6%
U.S. Total
6,373.9
100.0%
Source: AWEA.
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
October 2004, renewable portfolio standards have been implemented by 17 states and
require 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
55 An average U.S. household consumes roughly 10,000 kWh per year. Government
Accountability Office (GAO), Renewable Energy: Wind Power’s Contribution to Electric
Power Generation and Impact on Farms and Rural Communities, GAO-04-756, Sept. 2004;
hereafter referred to as GAO, Wind Power, GAO-04-756, Sept. 2004.
56 AWEA, The Economics of Wind Energy, March 2002.
57 Rebecca Smith,“Not Just Tilting Anymore,” Wall Street Journal, Oct. 14, 2004.
CRS-22
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 depending on factors
such as the project size, the capacity of the turbines, and the amount of electricity
produced.
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.
In contrast with fossil fuel 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 fossil fuels. However, the initial capital investment in
equipment needed to set up a utility-scale wind energy system is substantially greater
than for competing fossil fuels. 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 megawatt of capacity, so a wind energy system of 10 1.5-
megawatt 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. Less than 1% of wind power capacity installed nationwide is
owned by farmers.59
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 paragraph below);
and
58 GAO, Wind Power, GAO-04-756, Sept. 2004, p. 66.
59 Ibid., p. 6.
60 AWEA, The Economics of Wind Energy; at [http://www.awea.org].
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! 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 2005 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.64
Figure 6. Natural Gas Price, 1998 to 2004
61 Justin Blum, “Researchers Alarmed by Bat Deaths From Wind Turbines,” Washington
Post, by January 1, 2005.
62 The federal production tax credit was renewed Oct. 22, 2004 (P.L. 108-357; Sec. 710).
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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Natural gas prices have shown considerable volatility since the late 1990s (see
Figure 6); however, market conditions suggest that the sharp price rise that has
occurred since 2002 is unlikely to weaken anytime soon.65 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.
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 Dakota 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.
Figure 7. U.S. Areas with Highest Wind Potential
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
65 For a discussion of natural gas market price factors, see CRS Report RL32677, Energy
Use in Agriculture: Background and Issues.
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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.
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.
CRS-26
Public Laws That Support Energy Production
and Use by Agriculture
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.66 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. 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.67 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. Currently over 400 fleets use the fuel.68
The American Jobs Creation Act of 2004
(AJCA; P.L. 108-357)69
The AJCA contains two provisions (Section 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 the
revision, 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.
Federal Fuel Tax Exemption for Biodiesel (Section 301). This
provision provides for the first ever federal biodiesel tax incentive — a federal excise
66 CRS Report RL30369, Fuel Ethanol: Background and Public Policy Issues, p. 6.
67 NBB, “Biodiesel Emissions,” at [http://www.biodiesel.org/pdf_files/emissions.pdf].
68 NBB, “Biodiesel 2004 Backgrounder,” at
[http://www.biodiesel.org/pdf_files/backgrounder.PDF].
69 P.L. 108-357 was signed into law by the President on Oct. 22, 2004. For a discussion of
the tax provisions in the bill, as well as information on federal tax credits for other forms
of renewable energy, see CRS Report IB10054, Energy Tax Policy. For more information
on federal production tax credits for biofuels, see CRS Report RL20758, Alternative
Transportation Fuels and Vehicles: Energy, Environment, and Development Issues.
CRS-27
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¢ credit for every
gallon of non-agri-biodiesel (i.e., recycled oils such as yellow grease).
Federal Production Tax Exemption for Wind Energy Systems
(Section 710). This provision renews a federal production tax credit that expired
on December 31, 2003. The renewed tax credit provides a 1.8¢ credit for a 10-year
period for each kilowatt-hour of electricity produced by qualifying turbines that are
built by the end of 2005.
Energy Provisions in the 2002 Farm Bill (P.L. 107-171)70
In the 2002 farm bill, Title IX: Energy, Title II: Conservation, and Title VI:
Rural Development each contain programs that 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, Jan. 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 FY2005, no funding had yet been
proposed; therefore, no implementation regulations have been developed.
Biodiesel Fuel Education Program (Title IX, Section 9004).
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. Legislation provides funding of $1 million
annually through the CCC for FY2003-FY2007 to fund the program. Final
implementation rules were published in the Federal Register (vol. 68, no. 189, Sept.
30, 2003).
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 FY2005 no funding has
been appropriated. As a result, no implementation regulations have been developed.
70 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.
CRS-28
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. 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 CCC for
FY2003-FY2007 for this program. Unspent money lapses at the end of each year.
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 May 5, 2004 (Federal Register, vol. 69, no. 87). Not all
grant applications are accepted. In FY2004, $21 million in grants were offered
(compared with $21.7 million in FY2003) for renewable energy projects, including
$9.5 million for 37 anaerobic digester projects, $7.9 million for 38 wind power
projects, $3.1 million for 13 biomass projects, and $467,167 for 6 geothermal,
hybrid, and solar projects.
In order to formalize the program guidelines for receiving and reviewing future
loan and loan guarantee applications, USDA published proposed rules in the Federal
Register (vol. 69, no. 192, Oct. 5, 2004) for a 60-day comment period. Final rules
are pending. As a result, no loans or loan guarantees have been offered under this
program. 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 a combination of
grants, loans, and loan guarantees could equate to as much as $200 million in annual
program support.71
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. No new budget authority
is provided. A draft memorandum of understanding between the two departments
has been prepared and is in review.
Biomass Research and Development (Title IX; Section 9008).72 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 extends the
budget authority through FY2007, but with new funding levels of $5 million in
71 GAO, Wind Power, GAO-04-756, Sept. 2004, p. 54-55.
72 For more information, see the joint USDA-DOE website at [http://www.bioproducts-
bioenergy.gov/].
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FY2002 and $14 million for FY2003-FY2007 — unspent funds may be carried
forward, making the funding total $75 million for FY2002-FY2007. An additional
$49 million annually in discretionary funding is also provided for FY2002-FY2007.
In FY2004, USDA and DOE awarded a combined total of $25 million in research
funding to 21 biomass projects, up from the $23 million awarded in FY2003. The
USDA share of this has remained at $14 million for FY2003, FY2004, and FY2005.
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. 211) 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 2002 farm bill
extended the program through FY2006 and expanded its funding by providing that
$150 million 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.
In FY2004, no limitations were imposed; however, a $50 million reduction from the
$150 million is contained in the FY2005 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 wind energy
generation and biomass harvesting for energy production.
Loans and Loan Guarantees for Renewable Energy Systems (Title
VI; Section 6013). This provision 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.
Business and Industry Direct and Guaranteed Loans (Title VI;
Section 6017(g)(A)). This provision amends Section 310B of CFRDA (7 U.S.C.
1932) to include farmer and rancher equity ownership in wind power projects. Limits
range from $25 million to $40 million per project.
Value-Added Agricultural Product Market Development Grants
(Title VI; Section 6401(a)(2)). This provision amends Section 231 of CFRDA (7
U.S.C. 1621 note; P.L.106-224) to include farm- or ranch-based renewable energy.
Competitive grants are available to assist producers with feasibility studies, business
plans, marketing strategies, and start-up capital. Maximum grant amount is $500,000
per project.
CRS-30
Agriculture-Related Provisions in 108th Congress
Omnibus Energy Legislation73
Major energy legislation (H.R. 6, H.Rept. 108-375, S. 2095) died at the
adjournment of the 108th Congress, after stalling in late 2003 and 2004, primarily
over high cost and a dispute related to a liability protection provision for MTBE
(ethanol’s principal oxygenate competitor). Major non-tax provisions in the
conference measure and S. 2095 included:74
! Renewable Fuels Standard (RFS) — Both versions of the energy
legislation included a national RFS requiring that 3.1 billion gallons
of renewable fuel be used in 2005, increasing to 5.0 billion gallons
by 2012.
! Energy Efficiency Standards — New statutory efficiency standards
would have been established for several consumer and commercial
products and appliances. For certain other products and appliances,
DOE would have been empowered to set new standards. For motor
vehicles, funding would have been authorized for the National
Highway Traffic Safety Administration (NHTSA) to set Corporate
Average Fuel Economy (CAFE) levels as provided in current law.
! Energy Production on Federal Lands — To encourage production
on federal lands, royalty reductions would have been provided for
marginal oil and gas wells on public lands and the outer continental
shelf. Provisions were also included to increase access to federal
lands by energy projects — such as drilling activities, electric
transmission lines, and gas pipelines.
Similar provisions may be considered in energy legislation in the 109th Congress.
State Laws and Programs75
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. 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 17 states now have laws instituting RPS’s, with New
York being the latest addition.
73 For additional related bill contents and more information on non-tax provisions in the
bills, see CRS Issue Brief IB10116, Energy Policy: The Continuing Debate and Omnibus
Energy Legislation. For a discussion of the tax provisions in the bills, see CRS Issue Brief
IB10054, Energy Tax Policy.
74 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; and CRS
Report RL32078, Omnibus Energy Legislation: Comparison of Major Provisions in House-
and Senate-Passed Versions of H.R. 6, Plus S. 14.
75 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].
CRS-31
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, Energy and Agriculture, [http://www.usda.gov/energy/links.html].
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/oepnu/].
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 RL30369, Fuel Ethanol: Background and Public Policy Issues.
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
J. M. Urbanchuk, 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]
J. M. Urbanchuk and J. Kapell, Ethanol and the Local Community, June 20, 2002,
available at [http://www.ncga.com/ethanol/pdfs/EthanolLocalCommunity.pdf].
CRS-32
John M. Urbanchuk, An Economic Analysis of Legislation for a Renewable Fuels
Requirement for Highway Motor Fuels, Nov. 7, 2001.
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.
Anaerobic Digestion Systems
The Agricultural Marketing Research Center, Bio-Mass/Forages, at [http://www.
agmrc.org/biomass/biomass.html].
Wind Energy Systems
American Wind Energy Association (AWEA), [http://www.awea.org/].
DOE, Wind Energy Program, [http://www.eren.doe.gov/re/wind].
The Utility Wind Interest Group, [http://www.uwig.org].