Order Code RL32712
Agriculture-Based Renewable Energy Production
Updated January 8, 2007
Randy Schnepf
Specialist in Agricultural Policy
Resources, Science, and Industry Division
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.
However, U.S. ethanol production capacity has been expanding rapidly. Current
ethanol production capacity is 5.4 billion gallons per year (as of December 29, 2006),
with another 6.0 billion gallons of capacity under construction and potentially online
by early 2008. 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
1,706 megawatts in 1997 to an estimated 10,492 megawatts by October 23, 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.
Key points that emerge from this report are:
! substantial federal and state programs and incentives have facilitated
the rapid development of agriculture’s renewable energy production
capacity (primarily as biofuels and wind);
! rising fossil fuel prices improve renewable energy’s market
competitiveness, whereas higher costs for feedstock and plant
operating fuel (e.g., natural gas) dampen profitability;
! improvement of existing technology and development of new
technology for biofuel production (e.g., cellulosic conversion)
further enhance its economic competitiveness with fossil fuels;
! 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 energy consumption; and
! ethanol-driven higher corn prices have raised concerns from certain
quarters (e.g., other corn users) over rising feed costs, as well as the
potential for increased soil erosion and chemical usage from
substantially expanded corn production.
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Ethanol Pricing Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Corn-Based Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Ethanol from Cellulosic Biomass Crops . . . . . . . . . . . . . . . . . . . . . . . 17
Methane from an Anaerobic Digester . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Biodiesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Public Laws That Support Agriculture-Based Energy Production and Use . . . . 35
Tariff on Imported Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Clean Air Act Amendments of 1990 (CAAA; P.L. 101-549) . . . . . . . . . . . 36
Energy Policy Act of 1992 (EPACT; P.L. 102-486) . . . . . . . . . . . . . . . . . . 36
Biomass Research and Development Act of 2000
(Biomass Act; Title III, P.L. 106-224) . . . . . . . . . . . . . . . . . . . . . . . . . 36
Energy Provisions in the 2002 Farm Bill (P.L. 107-171) . . . . . . . . . . . . . . 37
The Healthy Forest Restoration Act of 2003 (P.L. 108-148) . . . . . . . . . . . . 41
The American Jobs Creation Act of 2004 (P.L. 108-357) . . . . . . . . . . . . . . 41
Energy Policy Act of 2005 (EPACT; P.L. 109-58) . . . . . . . . . . . . . . . . . . . 42
Tax Relief and Health Care Act of 2006 (P.L. 109-432) . . . . . . . . . . . . . . . 44
Agriculture-Related Energy Bills in 110th Congress . . . . . . . . . . . . . . . . . . 45
State Laws and Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
For More Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Renewable Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
List of Figures
Figure 1. U.S. Ethanol Production: Actual & Projected, versus the
Renewable Fuels Standard (RFS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Figure 2. Ethanol versus Gasoline Prices, 1991-2006 . . . . . . . . . . . . . . . . . . . . . . 8
Figure 3. Corn versus Ethanol Prices, 1991-2006 . . . . . . . . . . . . . . . . . . . . . . . . 11
Figure 4. U.S. Biodiesel Production, 1998-2005 . . . . . . . . . . . . . . . . . . . . . . . . 23
Figure 5. Soybean Oil vs. Diesel Fuel Price, 1994-2006 . . . . . . . . . . . . . . . . . . . 25
Figure 6. U.S. Installed Wind Energy Capacity, 1981-2007P . . . . . . . . . . . . . . 29
Figure 7. Natural Gas Price, Wholesale, 1994-2006 . . . . . . . . . . . . . . . . . . . . . . 32
Figure 8. U.S. Areas with Highest Wind Potential . . . . . . . . . . . . . . . . . . . . . . . 35
List of Tables
Table 1. U.S. Energy Production and Consumption, 2005 . . . . . . . . . . . . . . . . . . 3
Table 2. Energy and Price Comparisons for Alternate Fuels,
September-October 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Table 3. Ethanol Production Capacity by State, December 29, 2006 . . . . . . . . . . 7
Table 4. Ethanol Dry Mill Cost of Production Estimates, 2002 . . . . . . . . . . . . . 10
Table 5. U.S. Diesel Fuel Use, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Table 6. U.S. Potential Biodiesel Feedstock, 2004-2005 . . . . . . . . . . . . . . . . . . 27
Table 7. Installed Wind Energy Capacity by State, Ranked by
Current Capacity, October 23, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
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 2005, 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 2005; wind energy systems for 25%; and biodiesel for 1%.
Historically, fossil-fuel-based energy has been 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
enhance rural incomes and employment opportunities, while encouraging greater
value-added for U.S. agricultural commodities.5
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 Renewable Fuels Association (RFA)
at [http://www.ethanolrfa.org], 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/].
5 Several studies have analyzed the positive gains to commodity prices, farm incomes, and
(continued...)
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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 has traditionally been 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, 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 feedstock 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.
The economics underlying agriculture-based renewable energy production
include decisions concerning capital investment, plant or turbine location (relative
to feedstock supplies and by-product markets or power grids), production technology,
and product marketing and distribution, as well as federal and state production
incentives and usage mandates.8 Several additional criteria may be used for
comparing different fuels, including performance, emissions, safety, and
infrastructure needs.9 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.
5 (...continued)
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
federal budget watchdog groups such as Citizens Against Government Waste and Taxpayers
for Common Sense.
7 For example, see 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.
8 For more information on the economics underlying the capital investment decision see D.
Tiffany and V. Eidman. Factors Associated with Success of Fuel Ethanol Producers, Dept
of Appl. Econ., Univ. of Minnesota, Staff Paper P03-7, Aug. 2003; hereafter referred to as
Tiffany and Eidman (2003). For a discussion of ethanol plant location economics see B.
Babcock and C. Hart, “Do Ethanol/Livestock Synergies Presage Increased Iowa Cattle
Numbers?” Iowa Ag Review, Vol. 12 No. 2, Spring 2006.
9 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.
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! 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.
Table 1. U.S. Energy Production and Consumption, 2005
Production
Consumption
Quadrillion
Quadrillion
% of
Energy source
Btu
% of total
Btu
total
Total
69.2
100.0%
99.9 100.0%
Fossil Fuels
55.0
79.5%
86.0
86.0%
Petroleum and products
10.8
15.7%
40.4
40.5%
Coal
23.0
33.3%
22.8
22.9%
Natural Gas
21.1
30.5%
22.6
22.7%
Nuclear
8.1
11.8%
8.1
8.1%
Renewables
6.1
8.8%
6.1
6.1%
Hydroelectric power
2.7
3.9%
2.7
2.7%
Biomass
2.8
4.0%
2.8
2.8%
Wood, waste, other
2.3
3.3%
2.3
2.3%
Ethanol
0.5
0.7%
0.5
0.5%
Biodiesel
0.0
0.0%
0.0
0.0%
Geothermal
0.4
0.5%
0.4
0.4%
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].
Agriculture’s Share of Energy Production
In 2005, the major agriculture-produced energy source — ethanol — accounted
for about 2% of U.S. gasoline motor-vehicle consumption10 and about 0.3% of total
U.S. energy consumption (see Table 1). In addition, the agricultural sector also
10 Based on a conversion rate of 1.73 GEG per bushel of corn (2.75 gallons of ethanol per
bushel of corn and 0.67 GEG per gallon of ethanol). Federal Highway Administration,
“Motor Fuel Use — 2005,” at [http://www.fhwa.dot.gov/policy/ohim/hs05/htm/mf21.htm];
and estimated ethanol use, Renewable Fuels Association, “Industry Statistics,” at
[http://www.ethanolrfa.org/industry/statistics/].
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produced several other types of renewable energy — biodiesel, wind, and methane
from anaerobic digesters and non-traditional biomass. Presently, the volume of
agriculture-based energy produced from these emerging renewable sources is small
relative to ethanol production.
Table 2. Energy and Price Comparisons for Alternate Fuels,
September-October 2006
National
National
Btu’s per
Avg. Price:
Avg. Price:
Fuel type
Unit
unita
$ per unit
GEGb
$ per GEG
Gasoline:
gallon
115,400
$2.22
1.00
$2.22
regular
Ethanol (E85)c
gallon
90,383
$2.11
0.71
$2.97
Diesel fuel
gallon
128,700
$2.62
1.11
$2.36
Biodiesel (B20)
gallon
126,940
$2.66
1.10
$2.42
Propane
gallon
83,500
$2.33
0.72
$3.24
Compressed
Natural Gasd
1,000 ft.3
960
$1.77
1.0
$1.77
Natural Gase
1,000 ft.3
1,030,000
$5.70
8.24
$0.69
Biogas
1,000 ft.3
10 x (% of
methane)f
na
na
na
Electricityg
kilowatt-
3,413
5.73¢
na
na
hour
Source: Prices are for Sept.-Oct. 2006; DOE, EIA, Clean Cities Alternative Fuel Price Report,
October 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, Alternative Fuel Price
Report, October 2006, p. 14. 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 115,400, and finally
multiplying each fuel’s volume by the resulting ratio.
c. 100% ethanol has an energy content of 75,670 Btu per gallon (see table source, p. 14).
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. Conversion data is
from DOE, Alternative Fuel Price Report, October 2006, p. 14.
e. Natural Gas prices, $ per 1,000 cu. ft., are industrial prices for the month of October 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 rates per kilowatt-hour for 2005; from DOE, EIA, available
at [http://www.eia.doe.gov/cneaf/electricity/epa/epat7p4.html].
Renewable energy sources must compete with a large number of conventional
petroleum-based fuels in the marketplace (see Table 2). However, an expanding list
of federal and state incentives, regulations, and programs that were enacted over the
CRS-5
past decade have helped to encourage more diversity in renewable energy production
and use. In late September 2006, the House Agriculture Committee expressed its
support for the continued expansion of energy production from renewable sources
when it reported favorably a resolution (H.Con.Res. 424) that expressed the sense of
Congress that, “not later than January 1, 2025, the agricultural, forestry, and working
land of the United States should provide from renewable resources not less than 25%
of the total energy consumed in the United States.”11
Agriculture-Based Biofuels
Biofuels are liquid fuels produced from biomass. Types of biofuels include
ethanol, biodiesel, methanol, and reformulated gasoline components.12 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 feedstock. 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 feedstock, which raises commodity prices,
farm incomes, and rural employment.
Ethanol
Ethanol, or ethyl alcohol, is an alcohol made by fermenting and distilling simple
sugars.13 As a result, ethanol can be produced from any biological feedstock that
contains appreciable amounts of sugar or materials that can be converted into sugar
such as starch or cellulose. Sugar beets and sugar cane are examples of feedstock
that contain sugar. Corn contains starch that can relatively easily be converted into
sugar. In the United States corn is the principal ingredient used in the production of
ethanol; in Brazil, sugar cane is the primary feedstock. Trees and grasses are made
up of a significant percentage of cellulose which can also be converted to sugar,
11 The resolution was also referred to the House Energy and Commerce Committee and the
House Resources Committee. Only the Agriculture Committed acted upon it. No further
action was taken on H.Con.Res. 424 by the 109th Congress.
12 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].
13 For more information, see CRS Report RL33290, Fuel Ethanol: Background and Public
Policy Issues, by Brent D. Yacobucci.
CRS-6
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
(Figure 1). In 2005, the United States surpassed Brazil as the world’s leading
producer of ethanol. Several events contributed to the historical growth of U.S.
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.14 Ethanol
production is projected to continue growing rapidly through at least 2010 on the
strength of both the extension of existing and the addition of new government
incentives including a per gallon tax credit of $0.51 and a Renewable Fuels Standard
(RFS) of 7.5 billion gallons by 2012 (described below).
Figure 1. U.S. Ethanol Production: Actual & Projected, versus
the Renewable Fuels Standard (RFS)
1 0
P r o j e c t e d
8
6
R F S
4
A c t u a l
2
0
1 9 8 0
1 9 8 5
1 9 9 0
1 9 9 5
2 0 0 0
2 0 0 5
2 0 1 0
S o u r c e : 1 9 8 0 - 2 0 0 5 , R e n e w a b le F u e l s A s s o c ia t io n ( R F A ) ; p r o je c ti o n s f o r
2 0 0 6 - 2 0 1 0 a r e fr o m F A P R I , J u ly 2 0 0 6 B a s e l in e U p d a te ; t h e R F S is
g ra p h e d a s if m e t e n tir e l y b y d o m e s t ic e th a n o l p ro d u c t io n .
U.S. ethanol production presently is underway or planned in 24 states based
primarily around the central and western Corn Belt, where corn supplies are most
plentiful (see Table 3).15 Corn accounts for about 98% of the feedstocks used in
ethanol production in the United States. As of December 29, 2006, existing U.S.
14 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.
15 See Renewable Fuels Association, Industry Statistics, at [http://www.ethanolrfa.org/
industry/statistics/].
CRS-7
ethanol plant capacity was a reported 5.4 billion gallons per year (BGPY), with an
additional capacity of 6.0 BGPY under construction. Thus, total annual U.S. ethanol
production capacity in existence or under construction as of December 29, 2006, was
11.4 billion gallons (well in excess of the 7.5 billion gallon RFS mandated for 2012).
Table 3. Ethanol Production Capacity by State,
December 29, 2006
Currently
Under
Total capacity
operating
construction
Million
Million
Million
Rank
State
gal/yr
%
gal/yr %
gal./yr.
1
Iowa
3,279
29%
1,744
32%
1,535
2
Illinois
1,357
12%
721
13%
636
3
Nebraska
1,351
12%
661
12%
690
4
South Dakota
900
8%
522
10%
378
5
Minnesota
782
7%
542
10%
241
6
Indiana
653
6%
102
2%
551
7
Wisconsin
502
4%
230
4%
230
8
Kansas
371
3%
207
4%
165
9
Texas
370
3%
0
0%
370
10
Ohio
273
2%
3
0%
270
11
Michigan
262
2%
155
3%
107
12
North Dakota
246
2%
46
1%
200
13
New York
164
1%
0
0%
164
14
Missouri
155
1%
155
3%
0
15
Oregon
143
1%
0
0%
143
Others
584
5%
300.8
6%
283
U.S. Total
11,391
100%
5,386
100%
6,005
Source: Renewable Fuels Association, Industry Statistics: U.S. Fuel Ethanol Production Capacity,
at [http://www.ethanolrfa.org/industry/statistics/], Dec. 29, 2006.
Ethanol Pricing Issues. From a national perspective, the ethanol industry
is still nascent. As a result, marketing channels, pricing arrangements, and
distribution networks are still evolving with both the rapid growth in production and
the federally mandated use requirements. In early 2006, several market circumstances
combined to push ethanol prices to levels substantially above gasoline prices (see
Figure 2). In May, the spot market price per gallon for ethanol reached $3.75 in
Chicago and $4.50 in New York, while the monthly average ethanol rack price, f.o.b.
Omaha, reached $3.58 in June 2006.
These price surges generated considerable concern among consumers regarding
possible price manipulation in the marketplace and the reliability of ethanol as a fuel
source. However, a review of the circumstances suggests that two market
phenomena appear to be the behind the rise in ethanol prices and the ethanol-to-
gasoline price disparity — the general price rise in petroleum and natural gas
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markets,16 and the elimination of the oxygen requirement for reformulated gasoline
(legislated by the Energy Policy Act of 2005, P.L. 109-58), which resulted in a rapid
shift from MTBE to ethanol by the automotive fuel industry and pushed near-term
demand substantially above available ethanol supplies.17
Most dry-mill ethanol plants typically employ one or more of three pricing
strategies for marketing their ethanol production: sell at the rack price to nearby
refinery and fuel blending sites; forward contract at a fixed price for future delivery;
and forward contract where the ethanol price is based on a monthly futures contract
price (e.g., the wholesale ethanol contract at either the Chicago or New York Boards
of Trade or the wholesale gasoline contract at the New York Mercantile Exchange)
plus a per-gallon premium.18 Because a large portion of ethanol is sold under
forward contract, the market is vulnerable to near-term, temporary price rises when
demand exceeds available non-contracted supplies — as was the case in late 2005
and 2006 when the MTBE-phase-out-induced demand surged above existing supplies
while the ethanol industry was already operating near full capacity.
Figure 2. Ethanol versus Gasoline Prices, 1991-2006
4
E t h a n o l
3
2
1
G a s o li n e
0
1 9 9 1
1 9 9 4
1 9 9 7
2 0 0 0
2 0 0 3
2 0 0 6
S o u r c e : E t h a n o l a n d u n le a d e d g a s o l i n e r a c k p r i c e s p e r g a ll o n , F . O . B . O m a h a
E th a n o l B o a r d , L i n c o l n , N E . N e b r a s k a E n e r g y O f f i c e , L i n c o l n , N E .
By October 2006, the Omaha rack price for ethanol had fallen to $1.89 per
gallon before rising again in November to $2.25; gasoline prices were at $1.65 per
gallon in November. The ethanol-to-gasoline price disparity is expected to diminish
gradually as more ethanol production capacity comes online.
16 For more information see CRS Report RL32530, World Oil Demand and its Effect on Oil
Prices, by Robert Pirog.
17 For more information, see CRS Report RL33564, Alternative Fuels and Advanced
Technology Vehicles: Issues in Congress, by Brent Yacobucci.
18 Tiffany and Eidman (2003), p. 20.
CRS-9
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.19 Ethanol’s
share of corn production is projected to expand to 20% (or 2.15 billion bushels) in
2006/07.20 The Food and Agricultural Policy Research Institute (FAPRI) projects
that by 2010, U.S. ethanol production will reach 9.2 billion gallons and use 27.6%
(3.5 billion bushels) of the U.S. corn crop (see Figure 1).21 However, the rapid
expansion of ethanol production capacity in the later half of 2006 suggests that corn-
for-ethanol use will likely exceed 3 billion bushels in 2007 and approach or possibly
exceed 4 billion bushels in 2008.
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 an estimated 140.3 billion gallons).22
Economic Efficiency. Apart from government incentives, the economics
underlying corn-based ethanol’s market competitiveness hinge primarily on the
following factors:
! the price of feedstock, primarily corn;
! the price of the processing fuel, primarily natural gas or electricity,
used at the ethanol plant;
! the cost of transporting feedstock 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 (DDGs); 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. Using 2002 data (see Table 4), USDA
estimated that the average production cost for a gallon of ethanol was $0.958 when
corn prices averaged about $2.32 per bushel and natural gas cost about $4.10 per
1,000 cubic feet (mcf). Feedstock costs are the largest expense item in the
production of ethanol, representing about 57% of total ethanol production costs (net
of by-product credits obtained by selling the DDGs and carbon dioxide) or about
$0.55 per gallon. Each $1.00 increase in the price of corn raises the per gallon
production cost of ethanol by about $0.36 per gallon ($0.54 per GEG).23
19 Corn use for ethanol: USDA, World Agricultural Outlook Board, World Agricultural
Supply and Demand Estimates, Dec. 11, 2006.
20 Ibid.
21 FAPRI, July 2006 Baseline Update for U.S. Agricultural Markets, FAPRI-UMC Report
#12-06, University of Missouri.
22 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). Federal Highway Administration,
“Motor Fuel Use — 2005,” at [http://www.fhwa.dot.gov/policy/ohim/hs05/htm/mf21.htm].
23 Based on CRS simulations of an ethanol dry mill spreadsheet model developed by Tiffany
(continued...)
CRS-10
Processing fuel (usually natural gas) is the second largest expense representing
about 14% of total costs or about $0.14 per gallon. Natural gas prices have risen
substantially since 2002 (see Figure 7). However, because of its smaller cost share,
each $1.00 increase in the price of natural gas only raises the per gallon production
cost of ethanol by about $0.034 per gallon ($0.051 per GEG).
Table 4. Ethanol Dry Mill Cost of Production Estimates, 2002
Item
Unit
Value
Share
PRICES
Ethanol (rack, f.o.b. Omaha)
$/gal.
$1.12
Corn (average farm price received)
$/bushel
$2.32
Distiller’s Dried Grain (Lawrenceburg, IN)
$/short ton
$82.44
COSTS
Feedstock (Corn, Sorghum, or Other)
$/gal.
$0.803
By-Product Credit
$/gal.
$0.258
Distiller’s Dried Grain
$/gal.
$0.252
Carbon Dioxide
$/gal.
$0.006
Net Feedstock Costs
$/gal.
$0.545
56.9%
Total Processing Costs
$/gal.
$0.413
43.1%
Processing Fuel Costs
$/gal.
$0.136
14.1%
Chemical Costs
$/gal.
$0.102
10.6%
Labor, Maintenance, & Repair Costs
$/gal.
$0.091
9.5%
Administrative & Miscellaneous Costs
$/gal.
$0.048
5.0%
Electricity Costs
$/gal.
$0.037
3.9%
Total Processing Costs & Net Feedstock Costs
$/gal.
$0.958
100.0%
Source: Ethanol prices from Nebraska Ethanol Board, Lincoln, NE. Nebraska Energy Office,
Lincoln, NE; Corn and DDGS prices from ERS, USDA; Natural Gas prices from DOE/EIA; Ethanol
cost of production data from Hosein Shapouri and Paul Gallagher, USDA’s 2002 Ethanol Cost-of-
Production Survey, AER 841, USDA, Office of Energy Policy and New Uses, July 2005.
These ethanol production costs ignore capital costs (e.g., depreciation, interest
charges, return on equity, etc.), which may play a significant role depending on
market conditions. Capital costs for a 40 million gallon per year ethanol plant with
an initial capital investment of $60 million (of which 60% is debt financed) have
been estimated at roughly $0.14 per gallon assuming a 12% rate of return on equity.24
23 (...continued)
and Eidman (2003).
24 Ibid.
CRS-11
Because ethanol delivers only about 67% of the energy of a gallon of gasoline,
the 2002 cost of production in gasoline equivalent gallons is $1.43. However, the
federal tax credit (see below) of $0.51 per gallon of pure (100%) ethanol is a direct
offset to the production costs. To date, ethanol has been used at low blend ratios (5%
or 10%) with gasoline, functioning primarily either as an oxygenate or as a fuel
extender. At higher blend ratios (e.g., 85% ethanol), ethanol competes directly with
gasoline as a motor fuel.
Since corn is the largest expense in the production of ethanol, the relative
relationship of corn to ethanol prices provides a strong indicator of the ethanol
industry’s well-being (see Figure 3). From mid-2005 through mid-2006, the general
trend was clearly in ethanol’s favor, as average monthly ethanol rack prices (f.o.b.
Omaha) surged above the $2.00 per gallon level while corn prices fluctuated around
the $2.00 per bushel level. Since each bushel of corn yields approximately 2.75
gallons of ethanol, the profitability of ethanol production has escalated rapidly with
the increase in ethanol prices. Since mid-2006, ethanol prices have fallen back near
the $2.00 per gallon level while corn prices have risen sharply. By November 2006,
corn prices had surged to $3.50 per bushel or higher in most cash markets, while
nearby futures contracts were trading near $4.00 per bushel.
Figure 3. Corn versus Ethanol Prices, 1991-2006
5
4
E th a n o l
4
3
C o r n
3
2
2
1
1
0
1 9 9 1
1 9 9 4
1 9 9 7
2 0 0 0
2 0 0 3
2 0 0 6
S o u r c e : P r i c e s a r e m o n t h l y a v e r a g e s : C o r n , N o . 2 , y e ll o w , C h ic a g o ; U S D A ,
A M S ; E t h a n o l a r e r a c k , f . o . b . O m a h a , N e b r a s k a E th a n o l B o a r d , L i n c o ln , N E .
N e b r a s k a E n e r g y O f f ic e , L i n c o l n , N E .
The federal production tax credit (PTC) of 51¢ per gallon of pure ethanol (see
below) further enhances the profitability of ethanol production and helps to explain
the surge in ethanol production capacity over the past two years. A model simulation
based on ethanol prices of $2.50 per gallon, corn prices of $2.20/bushel, and natural
gas of $6.00/mcf, suggests that a 40 million gallon-per-year ethanol plant with initial
capital of $60 million (of which 60% is debt financed) is able to entirely recover its
CRS-12
investment capital in substantially less than a year.25 When ethanol prices are
lowered to $2.00, while corn prices are raised to $3.50, the simulation model
suggests that the ethanol plant would recover its investment capital in about 18
months. After removing the ethanol PTC of 51¢ per gallon from the simulation, the
ethanol plant remains profitable but the investment recovery period extends to just
under four years.
Government Support. Federal subsidies have played an important role in
encouraging investment in the U.S. ethanol industry. The Energy Tax Act of 1978
first established a partial exemption for ethanol fuel from federal fuel excise taxes.26
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:27
! 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
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);
! a Renewable Fuels Standard (RFS) (Energy Policy Act of 2005, P.L.
109-58) that mandates renewable fuels blending requirements for
fuel suppliers — 4 billion gallons of renewable fuels must be
blended into gasoline in 2006; the blending requirement grows
annually until 7.5 billion gallons in 2012; and
! a 54¢ per gallon most-favored-nation tariff on most imported ethanol
(extended through December 2008 by a provision in P.L. 109-432).
Also important was USDA’s Bioenergy Program (7 U.S.C. 8108), which
provided incentive payments (contingent on annual appropriations) on year-to-year
production increases of renewable energy during the FY2001 to FY2006 period.
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.
25 Ibid.
26 For a legislative history of federal ethanol incentives, see GAO, Tax Incentives for
Petroleum and Ethanol Fuels, RCED-00-301R, Sept. 25, 2000.
27 For more information on federal incentives for biofuel production, see CRS Report
RL33572, Biofuels Incentives: A Summary of Federal Programs, by Brent D. Yacobucci,
or see section on “Public Laws That Support Agriculture-Based Energy Production and
Use,” later in this report.
CRS-13
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 (higher yields for a given level of inputs
improves ethanol’s energy efficiency);
! 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 —
clean burning natural gas is the primary processing fuel for most
ethanol plants, but several plants (including an increasing number of
new plants) are designed to use coal; and
! the energy value of corn by-products, which act as an offset by
substituting for the energy needed to produce market counterparts.
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. 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.28 All new plants under construction
or coming online are expected to dry mill corn into ethanol, thus the dry milling share
will continue to rise for the foreseeable future.
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.29 Other researchers have found much lower
NEB values under less optimistic assumptions, leading to some dispute over corn-to-
ethanol’s representative NEB.30 A recent study (Farrel et al, 2006) 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)
28 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.
29 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)).
30 Professor David Pimentel, Cornell University, College of Agriculture and Life Sciences,
has researched and published extensive criticisms of corn-based ethanol production.
CRS-14
and that the NEB is improving with technology.31 However, these studies clearly
imply that inefficient processes for producing corn (e.g., excessive reliance on
chemicals and fertilizer or bad tillage practices) or for processing ethanol (e.g., coal-
based processing), or extensive trucking of either the feedstock or the finished
ethanol long distances to plant or consumer, can result in a NEB less than 1.0.
Long-Run Supply Issues. The sharp rise in corn prices that has occurred
since July 2006 owes its origins largely to the rapid expansion of corn-based ethanol
production capacity that has occurred in the United States since 2004.32 With 5.4
billion gallons of annual ethanol production capacity currently online (as of Dec, 29,
2006) and another 6.0 billion gallons of capacity under construction and potentially
online by early 2008, the U.S. ethanol sector will need as much as 4.0 billion bushels
of corn as feedstock in 2007/08. This would be an 86% increase from the 2.15
billion bushels of corn projected as ethanol feedstock in 2006/07. Such a strong
jump in corn demand is highly unusual and could generate substantially higher
prices. Such a price rally has already been signaled by the futures contract for July
2007 corn on the Chicago Board of Trade, which hit a contract high of $4.13 per
bushel in early November 2006.
Market participants, economists, and biofuels skeptics have begun to question
the need for continued large federal incentives in support of ethanol production,
particularly when the sector would have been profitable during much of 2006 without
such subsidies. Their concerns focus on the potential for widespread unintended
consequences that might result from excessive federal incentives adding to the rapid
expansion of ethanol production capacity and the demand for corn to feed future
ethanol production.33 Such consequences include a rapid expansion of corn area
(crowding out other field crops and agricultural activities) and the likelihood of both
expanded fertilizer and chemical use and increased soil erosion. Growth in corn-for-
ethanol use would reduce both exports and domestic feed use unless accompanied by
offsetting growth in domestic production.
Rapidly Expanding Corn Planting. As corn prices rise, so too does the
incentive to expand corn production (whether by expanding onto more marginal soil
environments or by altering the traditional corn-soybean rotation that dominates Corn
Belt agriculture) at the expense of other crops (primarily soybeans) and agricultural
activities. Further, corn production is among the most energy-intensive of the major
field crops and an expansion would likely lead to an increase in fertilizer and
chemical use and soil erosion.
31 Alexander E. Farrel, Richard J. Pleven, Brian T. Turner, Andrew D. Jones, Michael
O’Hare, and Daniel M. Kammon, “Ethanol Can Contribute to Energy and Environmental
Goals,” Science, vol. 311 (Jan. 27, 2006), pp. 506-508.
32 International market factors such as the failure of the 2006 Australian wheat and barley
crops added psychological momentum to the corn price runup; however, ample U.S. feed
grain supplies at the time of the rising corn price (fall 2006) strongly imply that future corn
demand attributable to the rapid surge in investment in U.S. ethanol production capacity is
the principal factor behind higher corn prices.
33 For a list or related articles, see the Reference Section entitled, “Consequences of
Expanded Agriculture-Based Biofuel Production” at the end of this report.
CRS-15
Domestic Feed Market Distortions. Corn traditionally represents about
57% of feed concentrates and processed feedstuffs fed to animals in the United
States.34 As corn-based ethanol production increases, so does total corn demand and
corn prices. Dedicating an increasing share of the U.S. corn harvest to ethanol
production will likely lead to higher prices for all grains and oilseeds that compete
for the same land, resulting in higher feed costs for cattle, hog, and poultry producers.
In addition, distortions are likely to develop in protein-meal markets related to
expanding production of the ethanol processing by-product DDG, which averages
about 30% protein content and can substitute in certain feed and meal markets.35
While DDG use would substitute for some of the lost feed value of corn used in
ethanol processing, about 66% of the original weight of corn is consumed in
producing ethanol and is no longer available for feed.36 Furthermore, not all
livestock species are well adapted to dramatically increased consumption of DDGs
in their rations — dairy cattle appear to be best suited to expanding DDG’s share in
feed rations; poultry and pork are much less able to adapt.
U.S. Corn Exports. The United States is the world’s leading corn exporter,
with nearly a 66% share of world trade during the past decade. In 2006/2007, the
United States is expected to export about 20% of its corn production.37 Higher corn
prices would also likely result in lost export sales. It is unclear what type of market
adjustments would occur in global feed markets, since several different grains and
feedstuffs are relatively close substitutes. Price-sensitive corn importers may quickly
switch to alternate, cheaper sources of energy depending on the availability of
supplies and the adaptability of animal rations. In contrast, less price-sensitive corn
importers, such as Japan and Taiwan, may choose to pay a higher price in an attempt
to bid the corn away from ethanol plants.
Ethanol Processing Energy Needs. Furthermore, as ethanol production
increases, the energy needed to process the corn into ethanol (derived primarily from
natural gas) can be expected to 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.38 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
2005.39 The United States has been a net importer of natural gas since the early
34 USDA, ERS, Feed Situation and Outlook Yearbook, FDS-2003, Apr. 2003.
35 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.
36 Shapouri (2004), p. 4.
37 USDA, WAOB, WASDE Report, Nov. 9, 2006; available at [http://www.usda.gov/oce/].
38 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.
39 DOE, EIA, Annual Energy Outlook 2006 with Projections to 2030, Table 1-Total Energy
(continued...)
CRS-16
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.
Ethanol as a Substitute for Imported Fuel. 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
2025.40 Presently, ethanol production accounts for about 2% of U.S. gasoline
consumption while using about 14% of the U.S. corn production. If the entire 2005
U.S. corn crop of 11.1 billion bushels were used as ethanol feedstock, the resultant
30 billion gallons of ethanol (20.2 billion GEG) would represent about 14.5% of
estimated national gasoline use of 140.3 billion gallons (on a GEG basis).41 In 2005,
slightly more than 75 million acres of corn were harvested. Nearly 137 million acres
would be needed to produce enough corn (20.5 billion bushels) and subsequent
ethanol (56.4 billion gallons or 37.8 billion GEG) to substitute for 50% of petroleum
imports (or 27% of total U.S. petroleum consumption).42 Since 1950, U.S. 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.43
These supply issues suggest that corn’s long-run potential as an ethanol
feedstock is somewhat limited. The Department of Energy (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.44
In light of these growing concerns, particularly as relates to livestock feed
markets, the Nebraska Cattlemen, at their annual convention on November 30, 2006,
adopted two resolutions relating to federal policy intervention in the U.S. ethanol
sector that are perhaps indicative of the looming tradeoff between feed and fuel and
the types of policy options that will likely be debated in the coming months:45
39 (...continued)
Supply and Disposition Summary; at [http://www.eia.doe.gov/oiaf/aeo/index.html].
40 DOE, EIA, Annual Energy Outlook 2004 with Projections to 2025.
41 Based on USDA’s Nov. 12, 2004, WASDE, and using comparable conversion rates.
42 CRS calculations — which assume corn yields of 150 bushel per acre and an ethanol yield
of 2.75 gal/bu. — are for gasoline only. Petroleum imports are primarily unrefined crude
oil, which is then refined into a variety of products.
43 Two recent articles by economists at Iowa State examine the potential for obtaining a
10 million acre expansion in corn planting: Bruce Babcock and D. A. Hennessy, “Getting
More Corn Acres From the Corn Belt”; and Chad E. Hart, “Feeding the Ethanol Boom:
Where Will the Corn Come From?” Iowa Ag Review, Vol. 12, No. 4, Fall 2006.
44 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).
45 “Nebraska Cattlemen Adopts Ethanol Policy,” News Release, Dec. 1, 2006; available at
(continued...)
CRS-17
First Resolution: Nebraska Cattlemen support a transition to a market-based
approach for the usage and production of ethanol and are opposed to any
additional federal or state mandates for ethanol usage and/or production.
Second Resolution: Subsidies like those applicable to the current production of
ethanol tend to distort the price relationship between various agricultural
commodities as energy prices fluctuate. Because of this and other factors,
Nebraska Cattlemen favor the implementation of a variable import levy to
prevent the price of oil, and its derivatives from dropping below long-term
equilibrium prices. This should be the sole incentive for the development of
alternative energy facilities in the United States.
Ethanol from Cellulosic Biomass Crops.46 Besides corn, several other
agricultural products are viable feedstock and appear to offer long-term supply
potential — particularly cellulose-based feedstock. For example, 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 feedstock
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 gasifying
cellulose-based feedstock or converting them 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. Iogen — a Canadian firm —
is presently the only firm to engage in the commercial production of cellulosic
ethanol (from wheat straw) at a large-scale demonstration plant (capable of producing
up to 793,000 gallons of cellulose ethanol per year) in Ottawa.47 Iogen has
announced plans to begin construction of an industrial-scale cellulosic plant in
southeast Idaho using wheat and barley straw as feedstock.48
45 (...continued)
[http://www.nebraskacattlemen.org/home/News/NewsReleases/tabid/116/articleType/Art
icleView/articleId/142/Nebraska-Cattlemen-Adopts-Ethanol-Policy.aspx].
46 For more information on biomass from non-traditional crops as a renewable energy, see
the DOE, EERE, Biomass Program, “Biomass Feedstock,” 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].
47 For more information visit Iogen Corporation’s website at [http://www.iogen.ca/].
48 Testimony by Jeff Passmore, executive vice president, Iogen Energy, to the House
(continued...)
CRS-18
Economic Efficiency. The conversion of cellulosic feedstock 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 feedstock 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
50¢ per gallon of ethanol.49 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 feedstock 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 feedstock. 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 feedstock that are able to thrive on marginal lands. Another provision
(Section 9008) provides competitive funding for research and development projects
48 (...continued)
Committee on Agriculture, at a Hearing entitled, “Agriculture’s Role in the Renewable
Fuels Market,” June 29, 2006; available at [http://agriculture.house.gov/hearings/109/
10934.pdf]
49 DOE, EERE, Biomass Program, “Cellulase Enzyme Research,” available at [http://www1.
eere.energy.gov/biomass/cellulase_enzyme.html].
CRS-19
on biofuels and bio-based chemicals in an attempt to motivate further production and
use of non-traditional biomass feedstock.50 EPACT’s biomass provisions are
discussed later in the report (see “Public Laws That Support Agriculture-Based
Energy Production and Use,” below). House Agriculture Committee Chairman
Peterson has expressed an interest in adding 5 to 6 million acres to the CRP program
to grow cellulosic biofuel feedstock such as switchgrass. This proposal is likely to
be discussed as part of the 2007 farm bill debate.
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.51
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
experienced parallel gains for the same reasons — improved crop yields and
production practices, and improved processing technology.
Long-Run Supply Issues. Cellulosic feedstock 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 feedstock 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.52
A 2003 USDA 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.53 This would represent about 8% of U.S. gasoline use in 2005. 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.
50 For more information, see Biomass Research and Development Initiative, USDA/DOE,
at [http://www.biomass.govtools.us/].
51 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).
52 United Nations, Food and Agricultural Organization (FAO), FAOSTATS.
53 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].
CRS-20
In a 2005 study of U.S. biomass potential, USDA concluded that U.S. forest
land and agricultural land had the potential to produce over 1.3 billion dry tons per
year of biomass — 368 million dry tons from forest lands and 998 million dry tons
from agricultural lands — while still continuing to meet food, feed, and export
demands.54 According to the study, this volume of biomass would be more than
ample to displace 30% or more of current U.S. petroleum consumption.
USDA’s very optimistic assessment is tempered somewhat by a 2005 University
of Minnesota study that uses the results from three major biofuels studies to estimate
the potential supplies of biofuels from both corn-based ethanol and cellulosic-based
ethanol from biomass crops and crop residue.55 The analysis suggests that about
130.4 million tons of biomass could be produced directly from switchgrass with
another 130.5 million tons from crop residue. If the biomass total of 260.9 million
tons were converted to ethanol at a rate of 89.7 gallons per ton, it would produce 23.4
billion gallons of anhydrous ethanol. Adding 2% denaturant yields 23.9 billion
gallons. Adding an additional 7 billion gallons of corn-based ethanol brings the total
to 30.9 billion gallons or 20.7 billion GEG. This would represent about 22.7% of
total U.S. gasoline consumption in 2005.
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.56 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 early 2005, there were 100 digester systems in operation at commercial U.S.
livestock farms, with an additional 94 planned for construction.57 EPA estimates that
54 USDA and DOE. Biomass as Feedstock for a Bioenergy and Bioproducts Industry: The
Technical Feasibility of a Billion-Ton Annual Supply, April 2005; available at
[http://feedstockreview.ornl.gov/pdf/billion_ton_vision.pdf].
55 Eidman, Vernon R. Agriculture’s Role in Energy Production: Current Levels and Future
Prospects, paper presented at a conference, “Energy from Agriculture: New Technologies,
Innovative Programs and Success Stories,” Dec. 14-15, 2005, St. Louis, Missouri. The three
studies used to generate the estimate are listed in the “For More Information” section as
FAPRI (2005); Ugarte et al (2003); and Gallagher et al (2003).
56 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/].
57 U.S. Environmental Protection Agency (EPA), AgStar Digest, Winter 2006; available at
(continued...)
CRS-21
anaerobic digester biogas systems are technically feasible at about 7,000 dairy and
swine operations in the United States. The majority of existing systems are farm
owned and operated using only livestock manure, and are found in the dairy
production zones of California, Wisconsin, Pennsylvania, and New York. In 2005,
they are estimated to have generated over 130 million kWh and to have reduced
methane emissions by over 30,000 metric tons.
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). For example, in 2004 37 anaerobic digester proposals from 26
different states were awarded funding under the REP.58 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.59 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.60 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
valuable as a high-quality potting soil ingredient or mulch. Other cost savings
57 (...continued)
[http://www.epa.gov/agstar/].
58 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/].
59 EPA, OAR, Managing Manure with Biogas Recovery Systems, EPA-430-F-02-004, winter
2002.
60 ATTRA, Anaerobic Digestion of Animal Wastes: Factors to Consider, Oct. 2002.
CRS-22
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.
Government Support. Federal assistance in the form of grants, loans, and loan
guarantees is available under USDA’s Renewable Energy Program (2002 farm bill,
Title IX, Section 9006) and Rural Development Programs (Title VI, Sections 6013,
6017, and 6401). See the section below on public laws for more details.
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 EPA, biogas
production for generating cost effective electricity requires manure from more than
500 cows at a dairy operation or at least 2,000 head of swine at a pig feeding
operation. As animal feeding operations steadily increase in size, the opportunity for
anaerobic digestion systems will likewise increase. In addition, some digester
systems may qualify for cost-share funds under USDA’s Environmental Quality
Incentives Program (EQIP).
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.61 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.
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 4). 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
61 For more information, visit the National Biodiesel Board at [http://www.biodiesel.org].
CRS-23
vehicle transportation.62 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 5).
Figure 4. U.S. Biodiesel Production, 1998-2005
8 0
6 0
4 0
2 0
0
1 9 9 8
2 0 0 0
2 0 0 2
2 0 0 4
S o u r c e : 1 9 9 8 - 2 0 0 4 : D O E , E I A , [ h t tp :/ /w w w .e ia .d o e .g o v /
c n e a f /a lt e r n a t e / p a g e / d a ta ta b le s /a f t1 - 1 3 _ 0 3 .h tm l] ; a n d 2 0 0 5 :
N a ti o n a l B io d ie se l B o a r d ; [ w w w .b io d i e s e l .o r g. ]
According to the NBB, as of September 13, 2006, there were 85 companies
producing and marketing biodiesel commercially in the United States, another 65
new firms that are reportedly under construction or are scheduled to be completed
within the next 18 months, and 13 plants that are expanding their existing
operations.63 The NBB reported that current annual U.S. biodiesel production
capacity (within the oleochemical industry) was an estimated 580 million gallons per
year, but the additional construction/expansion activity would add another 1.4 billion
gallons. Because many of these plants also can produce other products such as
cosmetics, estimated total capacity (and capacity for expansion) is far greater than
actual biodiesel production.
Economic Efficiency. The cost of producing biodiesel is generally more
than the cost of producing its fossil fuel counterpart. A 2004 DOE study suggests
that, since the cost of the feedstock (whether vegetable oil or restaurant grease) is the
largest single component of biodiesel production, the cost of producing biodiesel
62 Biodiesel consumption estimates are from DOE, IEA, “Alternatives to Traditional
Transportation Fuels 2003, Estimated Data.”
63 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-24
varies substantially with the choice of feedstock.64 For example, in 2004/05 it cost
$0.67 to produce a gallon of petroleum-based diesel, compared with about $2.54 to
produce a gallon of biodiesel from soybean oil, and $1.41 from restaurant grease (all
prices are quoted in 2002 dollars).
Table 5. 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.
The production cost differentials generally manifest themselves at the retail
level as well. However, during September-October 2006, the retail price of B20 (a
blend of 20% biodiesel with 80% conventional diesel) averaged $2.66 per gallon,
compared with $2.62 for conventional diesel fuel (Table 2).
The prices of biodiesel feedstock, as well as petroleum-based diesel fuel, vary
over time based on domestic and international supply and demand conditions. About
7.5 pounds of soybean oil are needed to produce a gallon of biodiesel. A comparison
of the relative price relationship between soybean oil and petroleum diesel is
indicative of the general economic viability of biodiesel production (Figure 5). As
diesel fuel prices rise relative to biodiesel or biodiesel feedstock, 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.
Since late 2006, the soybean oil to diesel wholesale price comparison has turned
against the use of soybean oil for biodiesel production — soybean oil prices have
64 Radich, Anthony. “Biodiesel Performance, Costs, and Use,” Modeling and Analysis
Papers, DOE/EIA, June 2004; available at [http://www.eia.doe.gov/oiaf/analysispaper/
biodiesel/].
CRS-25
risen steadily (along with corn prices) above the 25¢ per pound ($1.93 per gallon)
range, while diesel fuel have fallen below $2 per gallon. Since early November
2006, the nearby CBOT futures contract for soybean oil has traded above 28¢ per
pound ($2.16 per gallon), while more deferred contracts have been at or above 30¢.
Figure 5. Soybean Oil vs. Diesel Fuel Price, 1994-2006
3 5
2 .5
3 0
2
2 5
1 .5
2 0
1
1 5
0 .5
D i e s e l F u e l
S o y b e a n O il
1 0
0
1 9 9 4 1 9 9 6 1 9 9 8 2 0 0 0 2 0 0 2 2 0 0 4 2 0 0 6
S o u r c e : N o . 2 d ie se l f u e l n a ti o n a l a v e r a g e w h o l e s a le p r i c e : D O E , E I A ;
s o yb e a n o i l, D e c a tu r , I L , U S D A , F A S “ O i ls e e d C ir c u la r .”
Government Support. The primary federal incentives for biodiesel
production are somewhat similar to ethanol and include the following.65
! 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). However, unlike
the ethanol tax credit, which was extended through 2010, the
biodiesel tax credit expires at the end of calendar year 2008.
! 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).
65 See also section on “Public Laws That Support Agriculture-Based Energy Production and
Use,” below.
CRS-26
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
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. 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.66
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.67 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 domestic oil
feedstock are relatively less abundant than ethanol feedstock, 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 5)
whereby 1% of current vehicle diesel fuel use were to originate from biodiesel
sources (excluding non-vehicle use). This hypothetical mandate would require about
439 million gallons of biodiesel (compared to current production of about 75 million
gallons) or approximately 3.3 billion pounds of vegetable oil. During 2004, a total
of 32.9 billion pounds of vegetable oils and animal fats were produced in the United
States (Table 6); however, most of this production was committed to other food and
industrial uses. Uncommitted biodiesel feedstock (as measured by the available
stock levels on September 30, 2004) were 2.1 billion pounds. Thus, after exhausting
all available feedstock, an additional 1.3 billion pounds of oil would be needed to
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.
If U.S. soybean oil exports were to remain unchanged, the deficit biodiesel
feedstock 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). Of course, any area expansion would likely come at the expense of some
other crop such as corn, cotton, or wheat. A further possibility is that U.S. oilseed
66 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.nrel.gov/docs/legosti/fy98/24772.pdf].
67 For more information, see NBB, “Ground-Breaking Biodiesel Tax Incentive Passes,” at
[http://www.biodiesel.org/resources/pressreleases/gen/20041011_ FSC_Passes_Senate.pdf].
CRS-27
producers could shift towards the production of higher-oil content crops such as
canola or sunflower.
Table 6. U.S. Potential Biodiesel Feedstock, 2004-2005
Oil Production,
Ending Stocks:
Wholesale
2004-05
Sept. 30, 2005
pricea
Million
Million
Million
Million
Oil type
$/lb
pounds
gallonsb
pounds
gallonsb
Crops
24,022
3,120
1,614
210
Soybean
28.6
19,360
2,514
1,076
140
Corn
27.7
2,392
311
153
20
Cottonseed
28.9
957
124
109
14
Sunflowerseed
34.1
265
34
40
5
Canola
33.1
601
78
68
9
Peanut
57.6
126
16
99
13
Flaxseed/linseed
48.5
265
34
45
6
Safflower
69
56
7
24
3
Animal fat & otherd
8,924
1,130
307
40
Lard
26.4
775
101
14
2
Edible tallow
19.7
1,779
231
22
3
Inedible tallow
na
4,847
629
231
30
Yellow grease
11.6
1,523
198
40
5
Total supply
32,946
4,279
1,921
249
Source: USDA, ERS, Oil Crops Yearbook, OCS-2006, March 2006, Table 31. 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 2005.
na = not available.
a. Average of monthly price quotes for vegetable oils are for 2004/05 marketing years (Oct. to Sept.).
USDA, ERS, Oil Crops Outlook, OCS-2006. Lard and edible tallow prices are for calendar
2004. Yellow grease price is 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.
d. Production and stock data for “Animal Fat & Other” is for calendar 2004.
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.68 Rising vegetable oil prices would reduce or eliminate
68 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
(continued...)
CRS-28
biodiesel’s competitive advantage vis-à-vis petroleum diesel, even with the federal
tax credit. At the same time, increased oilseed crushing 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.69 Also similar to ethanol production, natural gas demand would
likely rise with the increase in biodiesel processing.70
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%).71 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 10,492 MW by October 23, 2006 (Figure
6).72 According to the AWEA, an additional 7,942 MW of capacity is either under
construction or being planned by the U.S. wind industry. (See “Box: Primer on
68 (...continued)
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.
69 For a discussion of potential feed market consequences from domestic ethanol industry
expansion, see Wisner and Baumel in Feedstuffs, no. 30, vol. 76, July 26, 2004.
70 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.
71 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.
72 American Wind Energy Association (AWEA), at [http://www.awea.org/projects/].
CRS-29
Measuring Electric Energy,” later in this report, for a description of megawatts and
other energy terminology.)
Figure 6. U.S. Installed Wind Energy Capacity, 1981-2007P
1 6 0 0 0
1 4 0 0 0
1 2 0 0 0
1 0 0 0 0
8 0 0 0
6 0 0 0
4 0 0 0
2 0 0 0
0
1 9 8 1
1 9 8 6
1 9 9 1
1 9 9 6
2 0 0 1
2 0 0 6 P
S ou r c e : D O E a n d A W E A ; 20 0 6 a n d 2 0 0 7 a re p r o je c te d by A W E A .
About 86% of installed production capacity is in 10 predominantly midwestern
and western states (see Table 7). However, nearly 60% of potential capacity that is
either under construction or being planned is located in other states.
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.73 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. By
September 2005, renewable portfolio standards (RPSs) had 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.74 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.
73 AWEA, The Economics of Wind Energy, Mar. 2002.
74 AWEA, “State-Level Renewable Energy Portfolio Standards,” Sept. 2, 2005; available at
[http://www.awea.org/pubs/factsheets/0509-RPS_Progresses_in_States.pdf].
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Table 7. Installed Wind Energy Capacity by State,
Ranked by Current Capacity, October 23, 2006
UCa or
Current
Planned
Total
State
MW
Share
MW
MW
Share
1
Texas
2,634
25%
1,147
3,781
21%
2
California
2,323
22%
603
2,926
16%
3
Iowa
837
8%
222
1,059
6%
4
Minnesota
812
8%
83
895
5%
5
Oklahoma
475
5%
120
595
3%
6
Oregon
438
4%
240
678
4%
7
New Mexico
407
4%
90
497
3%
8
Washington
390
4%
428
818
4%
9
Kansas
364
4%
0
364
2%
10
Colorado
291
3%
321
612
3%
Others
1,521
14%
4,688
6,212
34%
U.S. Total
10,492
100%
7,942
18,437
100%
Source: AWEA, [http://www.awea.org/projects/].
aUC = Under construction.
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.75 For utility-scale
sources of wind power, a number of turbines are usually built close together to form
a wind farm.
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
75 GAO, Wind Power, GAO-04-756, Sept. 2004, p. 66.
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wind projects. In 2004, less than 1% of wind power capacity installed nationwide
was owned by farmers.76
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:77
! 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,78 especially threatened or endangered
species, could reduce wind energy’s economic competitiveness.
A modern wind turbine can produce electricity for about 4.3¢ to 5.8¢ per
kilowatt hour. 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.).79
Wellhead natural gas prices have shown considerable volatility since the late
1990s (Figure 7), 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 November 2005 peak
of $11.92 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.80 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.
76 Ibid., p. 6.
77 AWEA, The Economics of Wind Energy, at [http://www.awea.org].
78 Justin Blum, “Researchers Alarmed by Bat Deaths From Wind Turbines,” Washington
Post, by Jan. 1, 2005.
79 Rebecca Smith, “Not Just Tilting Anymore,” Wall Street Journal, Oct. 14, 2004.
80 For a discussion of natural gas market price factors, see CRS Report RL33714, Natural
Gas Markets in 2006, by Robert Pirog.
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Figure 7. Natural Gas Price, Wholesale, 1994-2006
1 2
1 0
8
6
4
2
0
1 9 9 4
1 9 9 6
1 9 9 8
2 0 0 0
2 0 0 2
2 0 0 4
2 0 0 6
S o u rc e : D O E , E IA ; m o n t h ly a v e r a g e w h o le sa le ( In d u s tr ia l) p ric e .
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 2008 for a 10-year period.81 The usefulness of the tax credit may be limited by a
restriction under current U.S. tax law (IRC § 469) whereby individuals are not
eligible to deduct losses incurred in businesses they do not actively participate in.
Legislation (H.R. 2007) was introduced in the 109th Congress to allow passive
investors that provide capital for wind energy facilities and projects to be eligible for
up to a $25,000 passive loss deduction in the Internal Revenue Code. Currently, the
$25,000 passive loss offset is only available for oil, gas, and real estate investments.
The inclusion of the federal tax credit reduces the cost of producing wind-
generated electricity to 2.5¢ to 4¢ per kilowatt hour. 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.82 To the extent that they offset a substantial portion (30% to 40%) of the
price risk and initial financing charges, government incentives often provide the
catalyst for stimulating new investments in rural wind energy systems.
81 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
through 2007 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. The tax
credit was further extended through 2008 by a provision in P.L. 109-432.
82 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)).
CRS-33
Box: Primer on Measuring Electric Energy
News stories covering electric generation topics often try to illustrate the worth of
a megawatt (MW) 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 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.
Source: Bob Bellemare, UtiliPoint International Inc., Issue Alert, June 24, 2003;
available at [http://www.utilipoint.com/issuealert/article.asp?id=1728].
CRS-34
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 8). 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.
Areas considered most favorable for wind power have average annual wind
speeds of about 16 miles per hour or more. The minimum wind velocity needed for
electricity production by a wind turbine is 10 miles per hour.83 The turbines operate
at higher capacity with increasing wind speed until a “cut-out speed” is reached at
about 50 miles per hour. At this speed the turbine is stopped and the blades are
turned 90 degrees out of the wind and parked to prevent damage.
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.
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.
83 Tiffany, Douglas G. Economic Analysis: Co-generation Using Wind and Biodiesel-
Powered Generators, Staff Paper P05-10, Dept of Applied Econ., Univ. of Minn., Oct. 2005.
CRS-35
Figure 8. U.S. Areas with Highest Wind Potential
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; user mandates, and a tariff on imported ethanol
from countries outside of the Caribbean Basin Initiative.84
Tariff on Imported Ethanol
A most-favored-nation tariff of 54 cents per gallon is imposed on most imported
ethanol. The tariff is intended to offset the 51-cents-per-gallon production tax credit
available for every gallon of ethanol blended in gasoline. Exceptions to the tariff are
ethanol imports from the Caribbean region and Central America under the Caribbean
Basin Initiative (CBI). The CBI — which is designed to promote development and
stability in the Caribbean region and Central America — allows the imports of most
84 For more information on federal incentives for biofuel production, see CRS Report
RL33572, Biofuels Incentives: A Summary of Federal Programs, by Brent D. Yacobucci.
CRS-36
products, including ethanol, duty-free. In many cases, the tariff presents a significant
barrier to imports as it negates lower production costs in other countries. For
example, by some estimates, Brazilian production costs are 40% to 50% lower than
in the United States.85 The tariff, which was set to expire October 1, 2007, was
extended through 2008 by a provision in P.L. 109-432.
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.86 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.87
! 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.
! (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.
85 For more information, see CRS Report RS21930,Ethanol Imports and theCaribbean Basin
Initiative, by Brent D. Yacobucci.
86 CRS Report RL33290, Fuel Ethanol: Background and Public Policy Issues, by Brent D.
Yacobucci.
87 NBB, “Biodiesel Emissions,” at [http://www.biodiesel.org/pdf_files/fuelfactsheets/
emissions.pdf].
CRS-37
! (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 (BRDI)
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.88
! (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.89
! (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; however, FY2006 funding was reduced to $12 million (P.L. 109-97; Title
VII, Sec. 759). 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)90
In the 2002 farm bill, three separate titles — 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.
88 The official website for the Biomass Research and Development Initiative may be found
at [http://www.brdisolutions.com/].
89 This report is available at [http://www.brdisolutions.com/].
90 USDA, 2002 Farm Bill, “Title IX — Energy,” online information available at [http://
www.ers.usda.gov/Features/Farmbill/titles/titleIXenergy.htm]. 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.
CRS-38
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.91
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.92 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. Final implementation rules, including program guidelines for receiving and
91 These awardees were selected in August 2003; more information is available at
[http://www.biodiesel.org/usda/].
92 For more information on this program, see [http://www.rurdev.usda.gov/rbs/farmbill/
index.html].
CRS-39
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 February 22, 2006, when the availability of $22.8 million
(half as competitive grants, and half for guaranteed loans) was announced. Not all
applications are accepted. On February 22, 2006, USDA announced that $11.8
million in grants for FY2006 and $176.5 million in loan guarantees were available
for renewable energy and energy efficient projects.93 USDA estimates that loans and
loan guarantees are 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).94
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).95 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). In November 2006, USDA
and DOE jointly announced the selection of 17 projects to receive total funding of
approximately $17.5 million from the agencies under the BRDI. Cost-sharing by
private sector partners increases the total value to over $27 million.96
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.
93 USDA News Release 0051.06, Feb. 22, 2006.
94 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.
95 For more information, see the joint USDA-DOE website at [http://www.biomass.
govtools.us/].
96 Ibid.
CRS-40
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. 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. The program is scheduled to end after FY2006.
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,
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
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Value-Added Producer Grants (VAPG).97 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. Most recently, on January 9, 2006,
Agriculture Secretary Johanns announced the availability of $19 million in grants in
support of the development of renewable energy projects and value-added
agricultural business ventures.98
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.99 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¢
credit for every gallon of non-agri-biodiesel (i.e., recycled oils such as yellow
97 For more information see [http://www.rurdev.usda.gov/rd/energy/].
98 USDA News Release 0002.06, Jan. 9, 2006.
99 For more information, see the American Coalition for Ethanol, Volumetric Ethanol Excise
Tax Credit (VEETC) at [http://www.ethanol.org/veetc.html]
CRS-42
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.100
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.
Funding Support for Research, Development, and Demonstration
of Alternate Biofuel Processes. Several alternate forms of assistance including
100 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.
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(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
gallons. Funding of $250 million, until expended, is authorized to carry out this
section subject to appropriations.
CRS-44
Section 943 expands the Biobased Procurement Program authorized under
Section 9002 of the 2002 farm bill by applying the provision to federal government
contractors. Currently the program requires only federal agencies to give preference
to biobased products for procurement exceeding $10,000 when suitable biobased
products are available at reasonable cost. Section 943 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 August
8, 2006), and analysis of economic indicators of the biobased economy (within two
years of enactment or by August 8, 2007).
Tax Relief and Health Care Act of 2006 (P.L. 109-432)
The Tax Relief and Health Care Act of 2006 — signed into law on December
20, 2006 — contains two major provisions related to agriculture-based renewable
energy production.
Extension of Production Tax Credit. The production tax credit available
for electricity produced from certain renewable resources including wind energy
(referred to earlier in P.L. 109-58; Section 1301) was extended by one year through
December 31, 2008.
Extension of Ethanol Import Tariff. The 54¢ per gallon most-favored-
nation tariff on most imported ethanol (referred to in the earlier section of this report
“Tariff on Imported Ethanol”) was extended through December 31, 2008.
CRS-45
Agriculture-Related Energy Bills in 110th Congress
A number of bills — including H.R. 196, H.R. 197, and S. 23 — have been
introduced in the 110th Congress that seek to enhance or extend current provisions in
existing law that support agriculture-based energy production and use.
Previously, the 109th Congress had also introduced bills that supported
agriculture-based energy production and use. 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. Similar
versions of many of these bills are likely to be reintroduced in the 110th Congress.
In addition, several bills will likely be introduced that seek to provide incentives
for the production and use of alternative fuel vehicles. See CRS Report RL33564,
Alternative Fuels and Advanced Technology Vehicles: Issues in Congress, by Brent
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.101 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.102
101 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].
102 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].
CRS-46
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
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Bio, Achieving Sustainable Production of Agricultural Biomass for Biorefinery
Feedstock, ©2006 Biotechnology Industry Organization; available at [http://www.
bio.org/ind/biofuel/SustainableBiomassReport.pdf].
CRS Report RL33290, Fuel Ethanol: Background and Public Policy Issues, by Brent
D. Yacobucci.
CRS Report RL33564, Alternative Fuels and Advanced Technology Vehicles: Issues
in Congress, by Brent D. Yacobucci.
CRS Report RL33572, Biofuels Incentives: A Summary of Federal Programs, by
Brent D. Yacobucci.
Distillery and Fuel Ethanol Worldwide Network, [http://www.distill.com/].
DOE, Energy Efficiency and Renewable Energy (EERE), Alternative Fuels Data
Center, [http://www.eere.energy.gov/afdc/].
Eidman, Vernon R. Agriculture’s Role in Energy Production: Current Levels and
Future Prospects, paper presented at a conference, “Energy from Agriculture: New
Technologies, Innovative Programs and Success Stories,” Dec. 14-15, 2005, St.
Louis, Missouri; available at [http://www.farmfoundation.org/projects/documents/
EIDMANpaperrevisedTOPOST12-19-05.pdf].
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Fuels, [http://www.epa.gov/otaq/consumer/fuels/altfuels/altfuels.htm].
CRS-47
Koplow, Doug. Biofuels — At What Cost? Government Support for Ethanol and
Biodiesel in the United States, Global Subsidies Initiative of the International
Institute for Sustainable Development, Geneva, Switzerland, October 2006; available
at [http://www.globalsubsidies.org].
National Biodiesel Board (NBB), [http://www.biodiesel.org/].
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States, Office of Energy Policy and New Uses (OEPNU), Office of the Chief
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available at [http://www.usda.gov/oce/reports/energy/EthanolSugarFeasibility
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USDA/Dept. Of Energy (DOE). Biomass as Feedstock for a Bioenergy and
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April 2005; available at [http://feedstockreview.ornl.gov/pdf/billion_ton_vision.pdf].
Economic Benefits of Biofuel Production
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Impacts of Bioenergy Crop Production on U.S. Agriculture, AER 816, USDA, Office
of the Chief Economist (OCE), Office of Energy Policy and New Uses (OEPNU),
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Ethanol Production for U.S. Agriculture, FAPRI-UMC Report #10-05, August 22,
2005; available at [http://www.fapri.missouri.edu/].
Gallagher, P. Otto, H. Shapouri, J. Price, G. Schamel, M. Dikeman, and H.
Brubacker, The Effects of Expanding Ethanol Markets on Ethanol Production, Feed
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Gallagher, P., E. Wailes, M. Dikeman, J. Fritz, W. Gauther, and H. Shapouri,
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Papers, DOE/EIA, June 2004; available at [http://www.eia.doe.gov/oiaf/
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CRS-48
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].
Swenson, Dave S. Input-Outrageous: The Economic Impacts of Modern Biofuels
Production, Iowa State University webpapers, June 2006; available at
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Fuel Ethanol Producers, Dept of Applied Economics, Univ. of Minnesota, Staff
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Agriculture, Food & Resource Issues, No. 5, 2004, pp. 204-211.
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Run Impact of Corn-Based Ethanol on the Grain, Oilseed, and Livestock Sectors: A
Preliminary Assessment,” CARD Briefing Paper 06-BP 49, Nov. 2006.
Hart, Chad E. “Feeding the Ethanol Boom: Where Will the Corn Come From?”
Iowa Ag Review, Vol. 12, No. 4, Fall 2006, pp. 2-3
CRS-49
Kohlmeyer, Bob. “The Other Side of Ethanol’s Bonanza,” Ag Perspectives (World
Perspectives, Inc.), Dec. 14, 2004.
McElroy, Michael B. “Chapter 12: Ethanol from Biomass: Can it Substitute for
Gasoline?” Draft from book in progress available at [http://www-as.harvard.edu/
people/faculty/mbm/Ethanol_chapter1.pdf]
Taylor, Richard D., J.W. Mattson, J. Andino, and W.W. Koo. Ethanol’s Impact on
the U.S. Corn Industry, Agribusiness & Applied Economics Report No. 580, Center
for Agricultural Policy and Trade Statistics, North Dakota St. Univ., March 2006.
Tokgaz, Simla, and Amani Elobeid. “An Analysis of the Link between Ethanol,
Energy, and Crop Markets,” Working Paper 06-EP 435, CARD, November 2006.
Wisner, R., and P. 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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American Wind Energy Association (AWEA), [http://www.awea.org/].
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Dept of Applied Econ., Univ. of Minnesota, Staff Paper P05-10, October 2005.