Agriculture-Based Renewable Energy Production

Congressional research reportOct 16, 2007

Ask Donna

What actually matters in this document.

Text

Order Code RL32712

Agriculture-Based Renewable Energy Production

Updated October 16, 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 nearly 4.9 billion gallons per year in

2006. The U.S. ethanol production capacity has also been expanding rapidly,

particularly since mid-2006, with important implications for the food and fuel

sectors. Current ethanol production capacity is 5.6 billion gallons per year

(February 28, 2007), with another 6.2 billion gallons of capacity under construction

and potentially online by late 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

386 million gallons in 2006. Wind energy systems production capacity has also

grown rapidly, rising from 1,706 megawatts in 1997 to an estimated 12,633

megawatts by July 1, 2007. Despite this rapid growth, agriculture- and rural-based

energy production accounted for only about 0.7% of total U.S. energy consumption

in 2006.

Key points that emerge from this report are:

substantial federal and state programs and incentives have facilitated

development of agriculture’s renewable energy production capacity;

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;

technological improvements for biofuel production (e.g., cellulosic

conversion) enhance its economic competitiveness with fossil fuels;

farm-based energy production is unlikely 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 corn

users over rising food and 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Corn-Based Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Ethanol from Cellulosic Biomass Crops . . . . . . . . . . . . . . . . . . . . . . . 20

Methane from an Anaerobic Digester . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Biodiesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Public Laws That Support Agriculture-Based Energy Production and Use . . . . 42

Tariff on Imported Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Clean Air Act Amendments of 1990 (CAAA; P.L. 101-549) . . . . . . . . . . . 42

Energy Policy Act of 1992 (EPACT; P.L. 102-486) . . . . . . . . . . . . . . . . . . 43

Biomass Research and Development Act of 2000 (Biomass Act; Title III,

P.L. 106-224) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Energy Provisions in the 2002 Farm Bill (P.L. 107-171) . . . . . . . . . . . . . . 44

The Healthy Forest Restoration Act of 2003 (P.L. 108-148) . . . . . . . . . . . . 47

The American Jobs Creation Act of 2004 (P.L. 108-357) . . . . . . . . . . . . . . 48

Energy Policy Act of 2005 (EPACT; P.L. 109-58) . . . . . . . . . . . . . . . . . . . 48

Tax Relief and Health Care Act of 2006 (P.L. 109-432) . . . . . . . . . . . . . . . 51

Agriculture-Related Energy Bills in 110th Congress . . . . . . . . . . . . . . . . . . 51

House-passed New Farm Bill — H.R. 2419 . . . . . . . . . . . . . . . . . . . . 51

State Laws and Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Administration Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

State of the Union (SOU) 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

State of the Union (SOU) 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

USDA’s New Farm Bill Proposal (January 2007) . . . . . . . . . . . . . . . . 53

For More Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Renewable Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Wind Energy Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

List of Figures

Figure 1. U.S. Motor Vehicle Fuel Use, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Figure 2. Ethanol Versus Gasoline Prices, 2000-2007 . . . . . . . . . . . . . . . . . . . . . 9

Figure 3. U.S. Ethanol Production: Actual and Projected,Versus the Renewable

Fuels Standard (RFS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Figure 4. Corn Versus Ethanol Prices, 2000-2007 . . . . . . . . . . . . . . . . . . . . . . . 13

Figure 5. U.S. Biodiesel Production, 1998-2007 . . . . . . . . . . . . . . . . . . . . . . . . 28

Figure 6. Soybean Oil Versus Diesel Fuel Price, 2000-2007 . . . . . . . . . . . . . . . 30

Figure 7. U.S. Installed Wind Energy Capacity, 1981-2007 . . . . . . . . . . . . . . . . 34

Figure 8. Natural Gas Price, Wholesale, 1994-2007 . . . . . . . . . . . . . . . . . . . . . . 37

Figure 9. U.S. Areas with Highest Wind Potential . . . . . . . . . . . . . . . . . . . . . . . 39

List of Tables

Table 1. U.S. Energy Production and Consumption, 2006 . . . . . . . . . . . . . . . . . . 3

Table 2. Energy and Price Comparisons for Alternate Fuels, July 2007 . . . . . . . 4

Table 3. Ethanol Production Capacity by State, October 1, 2007 . . . . . . . . . . . . . 8

Table 4. Ethanol Dry Mill Cost of Production Estimates, 2002 . . . . . . . . . . . . . 12

Table 5. U.S. Diesel Fuel Use, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Table 6. U.S. Potential Biodiesel Feedstock, 2005-2006 . . . . . . . . . . . . . . . . . . 33

Table 7. Installed Wind Energy Capacity by State, Ranked by Capacity as

of December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

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 2006, ethanol, biodiesel, and wind provided 0.7% of U.S. energy

consumption (Table 1). Ethanol accounted for about 78% of agriculture-based energy

production in 2006; wind energy systems for 19%; and biodiesel for 3%.

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 agriculturebased 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

For more information on energy use by the agricultural sector, see CRS Report RL32677,

Energy Use in Agriculture: Background and Issues, by Randy Schnepf.

Excluding the costs of externalities associated with burning fossil fuels such as air

pollution, environmental degradation, and illness and disease linked to emissions.

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.

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/].

Several studies have analyzed the positive gains to commodity prices, farm incomes, and

(continued...)

CRS-2

In contrast, petroleum industry critics of biofuel subsidies argue that

technological advances such as seismography, drilling, and extraction continue to

expand the fossil-fuel resource base, which has traditionally been cheaper and more

accessible than biofuel supplies.6 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.7 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.8 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.9 Several additional criteria may be used for

comparing different fuels, including performance, emissions, safety, and infrastructure

needs.10 This report will discuss and compare agriculture-based energy production of

ethanol, biodiesel, and wind energy based on three criteria:

(...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.

For example, see Elizabeth Ames Jones, “Energy Security 101,” editorial, The Washington

Post, October 9, 2007.

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.

For example, see James and Stephen Eaves, “Is Ethanol the ‘Energy Security’ Solution?”

editorial, Washingtonpost.com, October 3, 2007; or R. Wisner and P. Baumel, “Ethanol,

Exports, and Livestock: Will There be Enough Corn to Supply Future Needs?,” Feedstuffs,

no. 30, vol. 76, July 26, 2004.

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, August 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.

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 Yacobucci. For information concerning greenhouse gas emissions

associated with ethanol use, see CRS Report RL33290, Fuel Ethanol: Background and

Public Policy Issues by Brent Yacobucci.

CRS-3

Economic Efficiency compares the price of agriculture-based

renewable energy with the price of competing energy sources,

primarily fossil fuels.

Energy Efficiency compares energy output from agriculture-based

renewable energy relative to the fossil energy used to produce it.

Long-Run Supply Issues consider supply and demand factors that

are likely to influence the growth of agriculture-based energy

production.

Table 1. U.S. Energy Production and Consumption, 2006

Production & Imports

Consumption

Quadrillion

Btu

% of

total

Quadrillion

Btu

% of

total

Total

100.7

100.0%

100.7

100.0%

Fossil Fuels

Petroleum and products

Coal

Natural Gas

56.1

13.2

23.8

19.1

79.5%

13.1%

23.6%

19.0%

86.1

40.6

23.1

22.4

85.4%

40.3%

23.0%

22.2%

Nuclear

8.2

8.1%

8.2

8.1%

Renewables

6.8

6.7%

6.8

6.7%

Hydroelectric power

Biomass

Wood, waste, other

Ethanol

Biodiesel

2.8

3.0

2.4

0.6

0.0

2.8%

3.0%

2.4%

0.9%

0.0%

3.0

2.4

0.6

0.0

3.0%

2.4%

0.6%

0.0%

Geothermal

Solar

Wind

Total Domestic Production

0.4

0.1

0.2

71.1

0.3%

0.1%

0.2%

70.6%

0.4

0.2

0.1

0.3%

0.2%

0.1%

Net Imports

29.8

29.6%

Energy source

Source: For ethanol data: Renewable Fuels Association, [http://www.ethanolrfa.org]; for biodiesel data:

National Biodiesel Board, [http://www.biodiesel.org]; for all other data: DOE, Energy Information

Agency (EIA), Annual Energy Outlook 2007 (early release),

[http://www.eia.doe.gov/oiaf/aeo/index.html].

Agriculture’s Share of Energy Production

In 2006, the major agriculture-produced energy source — ethanol — accounted

for about 0.6% of total U.S. energy consumption (see Table 1) In addition, the

agricultural sector produced other types of renewable energy — biodiesel, wind, and

methane from anaerobic digesters and non-traditional biomass — although their

production volume remains small relative to ethanol’s.

CRS-4

Table 2. Energy and Price Comparisons for Alternate Fuels,

July 2007

National

Avg. Price:

$ per unit

GEGb

National

Avg. Price:

$ per GEG

Fuel type

Unit

Btu’s per

unita

Gasoline: regular

gallon

115,400

$3.03

1.00

$3.03

Ethanol (E85)c

gallon

81,630

$2.63

0.71

$3.70

Diesel fuel

gallon

128,700

$2.96

1.11

$2.67

Biodiesel (B20)

gallon

126,940

$2.96

1.10

$2.69

Biodiesel (B100)

gallon

117,093

$3.27

1.01

$3.24

Propane

gallon

83,500

$2.58

0.72

$3.58

Compressed

Natural Gasd

1,000 ft.3

960,000

$2.09

1.00

$2.09

Natural Gase

1,000 ft.3

1,030,000

$7.58

8.24

$0.92

Biogas

1,000 ft.3

10 x (% of

methane)f

Electricityg

kilowatthour

3,413

5.73¢

Source: Prices and conversion rates (unless otherwise cited in a footnote below) are for July 2007,

from DOE, EIA, Clean Cities Alternative Fuel Price Report, July 2007; available at

[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, July 2007, 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

Btu’s, then dividing each fuel’s Btu unit rate by gasoline’s Btu unit rate of 115,400, and finally

multiplying each fuel’s price 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, July 2007, p. 14.

e. Natural Gas prices, $ per 1,000 cu. ft., are industrial prices for the month of July 2007, 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

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

CRS-5

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; however, the

two principal biofuels are ethanol and biodiesel.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. Despite rapid growth in recent years

(as discussed below), the two major biofuels — ethanol and biodiesel — still account

for very small shares of U.S. motor-vehicle fuel consumption (Figure 1).

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.

The resolution was also referred to the House Energy and Commerce Committee and the

House Resources Committee. Only the Agriculture Committee acted upon it. No further

action was taken on H.Con.Res. 424 by the 109th Congress. The same bill has been

reintroduced in the 110th Congress in the House (Rep. Peterson) as H.Con.Res. 25 and in the

Senate (Sen. Salazar) as S.Con.Res. 3.

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].

For more information, see CRS Report RL33290, Fuel Ethanol: Background and Public

Policy Issues, by Brent D. Yacobucci.

CRS-6

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, 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.

Figure 1. U.S. Motor Vehicle Fuel Use, 2006

160

Ethanol (2.4% share)

Billion gallons

120

Biodiesel (0.5% share)

Gasoline

Diesel Fuel

Source: Motor vehicle fuel use: U.S. DOE, EIA, 2007 Annual Outlook: Ethanol use: Renewable Fuels

Association; Biodiesel use: National Biodiesel Board.

Note: Ethanol is in gasoline-equivalent gallons (GEG).

Ethanol production has shown rapid growth in the United States since 2001 and

expectations are for this trend to continue to at least 2010 (Figure 3). 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

USDA, Office of Energy Policy and New Uses, The Energy Balance of Corn Ethanol: An

(continued...)

CRS-7

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, a

Renewable Fuels Standard (RFS) of 7.5 billion gallons by 2012, and $0.51 per gallon

tariff on most imported ethanol.15

U.S. ethanol production presently is underway or planned in 28 states based

primarily around the central and western Corn Belt, where corn supplies are most

plentiful (see Table 3).16 Corn accounts for about 99% of the feedstock used in

ethanol production in the United States. As of October 1, 2007, existing U.S. ethanol

plant capacity was a reported 6.9 billion gallons per year (BGPY), with an additional

planned capacity of 7.6 BGPY under construction (as either new plants or expansion

of existing plants). Thus, total annual U.S. ethanol production capacity in existence

or under construction is nearly 14.5 billion gallons, well in excess of the 7.5 billion

gallon RFS mandated for 2012 (Figure 3).

(...continued)

Update, AER-813, by Hosein Shapouri, James A. Duffield, and Michael Wang, July 2002.

For more information, see CRS Report RL33572, Biofuels Incentives: A Summary of

Federal Programs by Brent D. Yacobucci.

The source for this data is “Ethanol Plant List,” The Ethanol Monitor; published by Oil

October 1, 2007. An additional reference with slightly different reported data is Renewable

Fuels Association, Industry Statistics, at [http://www.ethanolrfa.org/industry/statistics/].

CRS-8

Table 3. Ethanol Production Capacity by State,

October 1, 2007

Rank

State

Total planned

capacity

Million

gal/yr

Currently

operating

Million

gal/yr

Under

construction

Million

gal./yr.

Iowa

3,399

23%

1,979

29%

1,420

Nebraska

2,153

15%

955

14%

1,198

South Dakota

1188

750

11%

438

Illinois

1,180

834

12%

346

Minnesota

1,142

499

643

Indiana

977

382

595

Kansas

643

253

390

Ohio

551

548

Wisconsin

534

284

250

Texas

470

North Dakota

354

134

220

Michigan

257

157

100

California

253

174

Tennessee

205

138

New York

164

Others

1,008

488

520

U.S. Total

14,476 100%

6,863 100%

7,614

Source: “Ethanol Plant List,” The Ethanol Monitor; published by Oil Intelligence Link, Inc., Editor

Ethanol Pricing Issues. From a national perspective, marketing channels,

pricing arrangements, and distribution networks are still evolving in an attempt to

keep up with the ethanol industry’s rapid growth in production and the federally

mandated use requirements. These circumstances can contribute to substantial price

volatility. For example, in early 2006, several market circumstances combined to

push ethanol prices to levels substantially above gasoline prices (see Figure 2). In

May 2006, 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 markets,17 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

For more information see CRS Report RL32530, World Oil Demand and its Effect on Oil

Prices, by Robert Pirog.

CRS-9

to ethanol by the automotive fuel industry and pushed near-term demand substantially

above available ethanol supplies.18

Figure 2. Ethanol Versus Gasoline Prices, 2000-2007

Ethanol

$/gallong

Gasoline

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Jan-06

Jan-07

Source: Ethanol and unleaded gasoline rack prices per gallon. F.O.B. Omaha Ethanol Board, Lincoln,

NE. Nebraska Energy Office, Lincoln, NE.

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.19 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.

By May 2007 ethanol prices had fallen below the Omaha gasoline rack price; by

September 2007 they were below $2 per gallon and any concerns of price

manipulation had long since dissipated. The ethanol-to-gasoline price disparity is

expected to diminish gradually as more ethanol production capacity comes online.

For more information on the MTBE phase-out, see CRS Report RL33564, Alternative

Fuels and Advanced Technology Vehicles: Issues in Congress, by Brent Yacobucci.

Tiffany and Eidman (2003), p. 20.

CRS-10

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.20 Ethanol’s

share of corn production expanded to 20.2% (or 2.125 billion bushels) in 2006/07, and

is projected to reach 24.8% and 3.3 billion bushels in 2007/08.21 In its annual

baseline projections (February 2007), USDA projected that U.S. ethanol production

would reach 11 billion gallons and use 30% (3.9 billion bushels) of the corn crop.

However, the rapid expansion of ethanol production capacity in the later half of 2006

outpaced USDA projections. In August 2007, the Food and Agricultural Policy

Research Institute (FAPRI) — using more recent data — projected that by 2010 U.S.

ethanol production would reach 13.7 billion gallons and use 36.2% (4.9 billion

bushels) of the U.S. corn crop (see Figure 3).22 Even FAPRI’s more recent

projections appear to be behind the current pace of plant capacity expansion.

Figure 3. U.S. Ethanol Production: Actual and Projected,

Versus the Renewable Fuels Standard (RFS)

FAPRI

Aug. '07

Billion Gallons

Production capacity

under construction

(10-01-07)

Existing production

capacity

(10-01-07)

USDA

Feb. '07

RFS

Actual

Source: 1980-2006, Renewable Fuels Association (RFA); current and planned capacity are from The

Ethanol Monitor; projections are from FAPRI's August 2007 Baseline Update, and USDA's USDA Agr.

Projections to 2016, Feb. 2007.

Despite its rapid growth, ethanol production represents a minor part of U.S.

gasoline consumption (Figure 1). In calendar 2006, U.S. ethanol production of 4.9

billion gallons accounted for about a 2.4% projected share of national gasoline use

Corn use for ethanol: USDA, World Agricultural Outlook Board, World Agricultural

Supply and Demand Estimates, September 12, 2007.

Ibid.

FAPRI, August Baseline Update for U.S. Agricultural Markets, FAPRI-UMC Report

#28-076, University of Missouri.

CRS-11

(3.3 billion gasoline-equivalent gallons (GEG) out of an estimated 140.3 billion

gallons).23

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;24

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;

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); and

the price of gasoline, ethanol’s main competitor in the marketplace.

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).25

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 8). 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).

Based on a conversion rate of 0.67 GEG per gallon of ethanol.

Note that the price for corn and other major program crops grown in the United States are

directly influenced by the various federal farm programs which have been shown to

encourage over-production during periods of low prices by muting market signals.

Based on CRS simulations of an ethanol dry mill spreadsheet model developed by Tiffany

and Eidman (2003).

CRS-12

Table 4. Ethanol Dry Mill Cost of Production Estimates, 2002

Item

Unit

Value

$/gal.

$1.12

Corn (average farm price received)

$/bushel

$2.32

Distiller’s Dried Grain (Lawrenceburg, IN)

$/short ton

$82.44

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%

$/gal.

$0.958

100.0%

PRICESa

Ethanol (rack, f.o.b. Omaha)

COSTS

Total Processing Costs & Net Feedstock Costs

Prices are for 2002.

All costs are in 2002 dollars.

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.26

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.

Ibid.

CRS-13

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 4). 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 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 4. Corn Versus Ethanol Prices, 2000-2007

Ethanol: $/gallon

Corn: $/bushel

Ethanol

Corn

Jan-00

Jan-01

Jan-02

Jan-03

Jan-04

Jan-05

Jan-06

Jan-07

Source: Prices are monthly averages: Corn, No.2, yellow, Central Illinois; USDA, AMS; Ethanol are

rack, f.o.b. Omaha, Nebraska Ethanol Board, Lincoln, NE. Nebraska Energy Office, Lincoln, NE.

The price relationship that persisted between ethanol, corn, and natural gas

during late 2005 and through much of 2006, coupled with the federal production tax

credit (PTC) of 51¢ per gallon of pure ethanol, represented a period of enormous

profitability for ethanol producers and helps to explain the surge in ethanol production

capacity since late 2005. For example, a model simulation based on prices of $2.50

per gallon for ethanol, $2.20/bushel for corn, and $6.00/mcf for natural gas (as existed

during the summer of 2006) suggests that a 40 million gallon-per-year ethanol plant

with initial capital of $60 million (of which 60% is debt financed) would be able to

recover its entire capital investment in substantially less than a year.27 When ethanol

prices are lowered to $1.80, while corn prices are raised to $4.50, the simulation

Ibid. Note, the results of these scenarios are merely suggestive of an average plant’s

situation and are not intended to imply uniformity in profitability across all ethanol plants.

CRS-14

model suggests that the ethanol plant still remains profitable. After removing the

ethanol PTC of 51¢ per gallon from the simulation, the ethanol plant’s per unit

profitability falls to zero with corn prices of about $3.80 per bushel.

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.28

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:29

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 gal. for

the first 15 million gal. of production for ethanol producers whose

total output does not exceed 60 million gal. of ethanol per year;

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 now-expired Bioenergy Program (7 U.S.C. 8108),

which provided incentive payments (contingent on annual appropriations) on year-toyear 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.

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:

For a legislative history of federal ethanol incentives, see GAO, Tax Incentives for

Petroleum and Ethanol Fuels, RCED-00-301R, September 25, 2000.

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-15

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

82% of the corn used for ethanol is processed by “dry” milling (a grinding process)

and about 18% is processed by “wet” milling plants (a chemical extraction process).30

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 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.31 Other researchers have found much lower NEB values

under less optimistic assumptions, leading to some dispute over corn-to-ethanol’s

representative NEB.32 A review (Farrel et al., 2006) of several major corn-to-ethanol

NEB analyses found that, when by-products are properly accounted for, the corn-toethanol process has a positive NEB (i.e., greater than 1.0) and that the NEB is

improving with technology.33 This result was confirmed by another comprehensive

study (Hill et al., 2006) that found a NEB of 1.25 for corn ethanol.34 However, these

studies clearly imply that inefficient processes for producing corn (e.g., excessive

Dry milling and wet milling production shares are from the Renewable Fuels Association,

Ethanol Industry Outlook 2007. 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.

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)).

For example, Prof. David Pimentel, Cornell Univ., College of Agr. and Life Sciences, has

researched and published extensive criticisms of corn-based ethanol production.

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 (January 27, 2006), pp. 506-508.

Hill, J., E. Nelson, D. Tilman, S. Polasky, and D. Tiffany. “Environmental, economic,

and energetic costs and benefits of biodiesel and ethanol biofuels,” Proceedings of the

National Academy of Sciences, Vol. 103, No. 30, July 25, 2006, 11206-11210.

CRS-16

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 significantly

less than 1.0. In other words, not all ethanol production processes have a positive

energy balance.

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 2004.35 With

6.9 billion gallons of annual ethanol production capacity currently online (October 1,

2007) and another 7.6 billion gallons of capacity under construction and potentially

online by early 2009, the U.S. ethanol sector is projected to need over 4.2 billion

bushels of corn as feedstock in 2008/09 to service this capacity. This would be an

95% 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 has already fueled

substantially higher prices — for both current market prices (Figure 4) as well as for

long-run projected prices. In its February 2007 baseline report, USDA projects U.S.

farm-gate prices to remain in the $3.30 to $3.50 per bushel range through 2016.36

Questions Emerge Surrounding Further Subsidy-Fueled Corn

Ethanol Expansion. 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.37 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 cornfor-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), crowding out other field crops, primarily soybeans, and other

agricultural activities. Large-scale shifts in agricultural production activities will likely

have important regional economic consequences that have yet to be fully explored or

understood. Further, corn production is among the most energy-intensive of the major

field crops. An expansion of corn area would likely have important and unwanted

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.

USDA Agricultural Projections to 2016, OCE-2007-1, USDA, February 2007; available

at [http://www.ers.usda.gov/Briefing/Baseline/].

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-17

environmental consequences due to the resulting increase in fertilizer and chemical

use and soil erosion.

Domestic Feed Market Distortions. Corn traditionally represents about 57%

of feed concentrates and processed feedstuffs fed to animals in the United States.38

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 Distiller’s Dried Grains (DDG),

which averages about 30% protein content and can substitute in certain feed and meal

markets.39 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. Furthermore, not all livestock

species are well adapted to dramatically increased consumption of DDG 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. Also, DDG must be dried

before it can be transported long distances. Will large-scale movements of livestock

production occur to relocate near new feed sources? Such a relocation would likely

have important regional economic effects.

Domestic and International Food Markets. Most corn grown in the United

States is used for animal feed. Higher feed costs ultimately lead to higher meat prices.

The feed-price effect will first translate into higher prices for poultry and hogs, which

are less able to use alternate feedstuffs. Dairy and beef cattle are more versatile in

their ability to shift to alternate feed sources, but eventually a sustained rise in corn

prices will push their feed costs upward as well. The price of corn is also linked to the

price of other grains, including those destined for food markets, through their

competition in both the feed marketplace and the producer’s planting choices for his

(or her) limited acreage. The price runup in the U.S. corn market has already clearly

spilled over into the market for soybeans (and soybean oil).

Since food costs represent a relatively small share of consumer spending in the

United States, the price runup is more easily absorbed in the short run. However, the

situation is very different for lower-income households as well as in many foreign

markets, where food expenses can represent a substantial portion of the household

budget. This is becoming a concern since, because of trade linkages, the increase in

U.S. corn prices has carried into international markets as well. In January 2007,

Mexico experienced riots following a nearly 30% price increase for tortillas, the

country’s dietary staple. In China, where corn is also an important food source, the

government has recently put a halt to its planned ethanol plant expansion due to the

USDA, ERS, Feed Situation and Outlook Yearbook, FDS-2003, April 2003.

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.), December 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.

CRS-18

threat it poses to the country’s food security. Similarly, humanitarian groups have

expressed concern for the potential difficulties that higher grain prices imply for netfood-importing developing countries.

U.S. Corn Exports. The United States is the world’s leading producer and

exporter of corn. Since 1980 U.S. corn production has accounted for over 40% of

world production, while U.S. corn exports have represented nearly a 66% share of

world trade during the past decade. In 2006/2007, the United States exported about

20% of its corn production.40 Higher corn prices would 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. There

could be significant economic effects to U.S. grain companies and to the U.S.

agricultural sector if ethanol-induced higher corn prices cause a sustained reshaping

of international grain trade.

Ethanol Processing Energy Needs. As ethanol production increases, the

energy needed to process the corn into ethanol (derived primarily from natural gas in

the United States) can be expected to increase. For example, if the entire 4.9 billion

gallons of ethanol produced in 2006 used natural gas as a processing fuel, it would

have required an estimated 243 billion cu. ft. of natural gas.41 The energy needed to

process the entire 2006 corn crop of 10.5 billion bushels into ethanol would be

approximately 1.4 trillion cubic feet of natural gas. Total U.S. natural gas

consumption was an estimated 22.2 trillion cu. ft. in 2005.42 The United States has

been a net importer of natural gas since the early 1980s. Because natural gas is used

extensively in electricity production in the United States, a significant increase in its

use as a processing fuel in the production of ethanol would likely result in increases

of 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 U.S. ethanol production depends

almost entirely on corn as the primary feedstock. The import share of U.S. petroleum

consumption was estimated at 65% in 2004, and is expected to grow to 71% by

2030.43 Presently, ethanol production accounts for less than 3% of U.S. gasoline

consumption while using about 20% of the U.S. corn production. If the entire 2006

U.S. corn crop of 10.5 billion bushels were used as ethanol feedstock, the resultant 28

billion gallons of ethanol (18.9 billion gasoline-equivalent gallons (GEG)) would

USDA, WAOB, WASDE

[http://www.usda.gov/oce/].

Report,

October

12,

2007;

available

CRS calculations based on Shapouri (2004) energy usage rates of 49,733 Btu/gal of

ethanol.

DOE, EIA, Annual Energy Outlook 2007.

Ibid.

CRS-19

represent about 13.4% of estimated national gasoline use of approximately 140 billion

gallons.44 In 2006, an estimated 71 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.45 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.46

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.47

In light of these growing concerns, particularly as relates to livestock feed

markets, the Nebraska Cattlemen (NC), 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:48

First Resolution: NC 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: NC 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.

Similarly, the National Cattlemen’s Beef Association (NCBA), at their industry

convention on February 3, 2007, approved an interim policy calling for: a phase-out

of government incentives for ethanol production and an end to the 54 cent per gallon

Based on USDA’s February 9, 2007, World Agricultural Supply and Demand Estimates

(WASDE) Report, and using comparable conversion rates.

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.

Two recent articles by economists at Iowa State University 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.

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).

“Nebraska Cattlemen Adopts Ethanol Policy,” News Release, December 1, 2006;

[http://www.nebraskacattlemen.org/home/News/NewsReleases/tabid/116/articleType/Art

icleView/articleId/142/Nebraska-Cattlemen-Adopts-Ethanol-Policy.aspx].

CRS-20

tariff on imported ethanol; a transition to a market-based approach to renewable

energy production; and greater policy emphasis on transitioning from corn-based to

cellulosic ethanol. The NCBA also announced support for a segmentation of the RFS

whereby different biofuels would be given a specific portion of the RFS rather than

letting it be filled on a first-come, first-serve basis. This would involve carving out

a specific portion for cellulosic ethanol and biodiesel.

Ethanol from Cellulosic Biomass Crops.49 Besides corn, several other

agricultural products are viable feedstock and appear to offer attractive long-term

supply potential — particularly cellulose-based feedstock such as prairie grasses and

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.50

In particular, native prairie grasses such as switchgrass appear to offer large potential

as a cellulosic feedstock because they thrive on marginal lands (as well as on prime

cropland) and need little water and no fertilizer.51

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 cellulosebased feedstock or converting them into fermentable sugars). Currently, cellulosic

conversion technology is rudimentary and expensive. In 2002, the DOE estimated that

the cost of producing ethanol from cellulose was between $1.15 and $1.43 per gallon

in 1998 dollars ($1.43 and $1.78 per gallon in current January 2007 dollars).52 This

compares with USDA’s estimated cost of producing corn-based ethanol in 2002 of

$0.958 per gallon ($1.08 per gal. in current January 2007 dollars).53

The projected high cost of production coupled with the uncertainty surrounding

the commercial application of a new technology has inhibited commercial investments

into cellulosic ethanol production. In addition, the logistics of harvesting,

transporting, and storing large volumes of bulky cellulosic material for daily

processing at a central plant remain daunting. As of October 2007, no commercial

cellulose-to-ethanol facilities are in operation in the United States, although plans to

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].

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]; referred to hereafter as the

Billion Ton Study (2005).

Hill, Jason. Overcoming Barriers to Biofuels: Energy from Diverse Prairie Biomass,

presentation to staff of House Committee on Agriculture, Dept of Applied Economics and

Dept. of Ecology, Evolution, and Behavior, University of Minnesota, February 26, 2007.

DiPardo, Joseph. Outlook for Biomass Ethanol Production and Demand, DOE, undated:

available at [http://www.eia.doe.gov/oiaf/analysispaper/biomass.html].

Shapouri (2004).

CRS-21

build several facilities are underway.54 Private sector investment received a

substantial federal policy boost on February 28, 2007, when the DOE announced the

awarding of up to $385 million in cost-share funding for the construction of six

cellulosic ethanol plant projects.55 When fully operational, the six plants are expected

to produce up to 130 million gallons per year of cellulosic ethanol. The combined

cost-share plus federal funding for the six projects represents total planned investment

of more than $1.2 billion. The six companies (and their proposed funding levels) are:

Abengoa Bioenergy Biomass of Kansas, LLC of Chesterfield,

Missouri (up to $76 million). The proposed plant will be located in

Kansas. The plant will produce 11.4 million gallons of ethanol

annually and enough energy to power the facility, with any excess

energy being used to power the adjacent corn dry grind mill. The

plant will use 700 tons per day of corn stover, wheat straw, milo

stubble, switchgrass, and other feedstock.

ALICO, Inc. of LaBelle, Florida (up to $33 million). The proposed

plant will be in LaBelle, Florida. The plant will produce 13.9 million

gallons of ethanol a year and 6,255 kilowatts of electric power, as

well as 8.8 tons of hydrogen and 50 tons of ammonia per day. For

feedstock, the plant will use 770 tons per day of yard, wood, and

vegetative wastes and eventually energy cane.

BlueFire Ethanol, Inc. of Irvine, California (up to $40 million). The

proposed plant will be in Southern California. The plant will be sited

on an existing landfill and produce about 19 million gallons of

ethanol a year. As feedstock, the plant would use 700 tons per day of

sorted green waste and wood waste from landfills.

POET (originally Broin Companies) of Sioux Falls, South Dakota (up

to $80 million). The plant is in Emmetsburg, Iowa, and after

expansion, it will produce 125 million gallons of ethanol per year, of

which roughly 25% will be cellulosic ethanol. For feedstock in the

production of cellulosic ethanol, the plant expects to use 842 tons per

day of corn fiber, cobs, and stalks.

Iogen Biorefinery Partners, LLC, of Arlington, Virginia (up to $80

million). The proposed plant will be built in Shelley, Idaho, and will

produce 18 million gallons of ethanol annually. The plant will use

700 tons per day of agricultural residues including wheat straw,

barley straw, corn stover, switchgrass, and rice straw as feedstocks.

Range Fuels (formerly Kergy Inc.) of Broomfield, Colorado (up to

$76 million). The proposed plant will be constructed in Soperton,

Georgia. The plant will produce about 40 million gallons of ethanol

Perkins, Jerry. “New Crops Could Fuel New Wave of Ethanol,” Des Moines Register,

February 25, 2007.

For more information see the DOE news release at [http://www.doe.gov/news/4827.htm].

CRS-22

per year and 9 million gallons per year of methanol. As feedstock,

the plant will use 1,200 tons per day of wood residues and wood

based energy crops.

Celunol Corporation has a pilot cellulosic plant in Jennings, Louisiana, but is

currently building a demonstration plant at the same location that will use sugar cane

residues (called bagasse), as is done in Brazil, to fuel its ethanol production.56 Celunol

says that it will use the demonstration plant to train its plant operators in anticipation

of a commercial-scale plant scheduled for construction starting in late 2008.

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 similar to those of 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.57 The DOE is also

studying thermal hydrolysis as a potentially more cost-effective method for processing

cellulose into sugar. Iogen — a Canadian firm with a pilot-scale cellulosic ethanol

plant in Ottawa, Canada, and one of the six companies receiving a DOE award for

construction of a commercial-scale ethanol plant (see above) — uses recombinant

DNA-produced enzymes to break apart cellulose to produce sugar for fermentation

into ethanol.

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. 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, several federal laws support the development

For more information on Celunol, visit: [http://www.celunol.com/].

DOE, EERE, Biomass Program, “Cellulase Enzyme Research,” available at [http://www1.

eere.energy.gov/biomass/cellulase_enzyme.html].

CRS-23

of cellulose-based ethanol in the United States. These include various provisions

under the Biomass Research and Development Act of 2000, two provisions (Section

2101 and Section 9008) of the 2002 farm bill (P.L. 107-171), and several provisions

of the Energy Policy Act of 2005 (EPACT; P.L. 109-58).58 The specifics of these

provisions are discussed later in the report (see “Public Laws That Support

Agriculture-Based Energy Production and Use,” below). In addition to coordinating

the activities of USDA and DOE, these provisions provide competitive grants, loans,

and loan guarantees in support of research, education, extension, production, and

market development of cellulosic biomass-based ethanol. In addition, both the Senate

and House of passed new energy bills this year that include several provisions

supportive of cellulosic ethanol production.59

In addition to existing legislation, the 2007 farm bill is likely to retain an energy

title with updated and/or expanded provisions concerning agriculture-based renewable

energy.60 On July 27, 2007, the House approved a new farm bill — the Farm,

Nutrition, and Bioenergy Act of 2007 (H.R. 2419) — which includes an energy title

(Title IX). H.R. 2419, as amended and passed by the House, expands and extends

several provisions from the energy title of the enacted 2002 farm bill with substantial

increases in funding and a heightened focus on developing cellulosic ethanol

production. A key departure from current farm-bill related energy provisions is that

most new funding would be directed away from corn-starch-based ethanol production

and towards either cellulosic-based biofuels production or to new as-yet-undeveloped

technologies with some type of agricultural linkage. The Senate Agriculture

Committee (SAC) is expected to mark up its version of a 2007 farm bill in lateOctober.

President Bush has mentioned renewable energy in his past two State of the

Union (SOU) speeches. In his 2006 SOU, President Bush introduced the notion of

“switchgrass” as a potential energy source and announced the “Advanced Energy

Initiative,” which included a goal of making cellulosic ethanol cost competitive with

corn-based ethanol by 2012. In his 2007 SOU, President Bush announced his “20 in

10” plan, which calls for reducing U.S. gasoline consumption by 20% in 10 years (i.e.,

by 2017).

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.61 While

corn’s net energy balance (under optimistic assumptions concerning corn production

For more information, see Biomass Research and Development Initiative, USDA/DOE,

at [http://www.biomass.govtools.us/].

more information on these energy bills, see CRS Report RL34136, Biofuels Provisions

in H.R. 3221 and H.R. 6: A Side-by-Side Comparison, by Brent Yacobucci.

For more information, see CRS Report RL34130 Renewable Energy Policy in the 2007

Farm Bill by Randy Schnepf.

Argonne National Laboratory, Center for Transportation Research, Effects of Fuel Ethanol

Use on Fuel-Cycle Energy and Greenhouse Gas, ANL/ESD-38, by M. Wang, C. Saricks,

and D. Santini, January 1999, as referenced in DOE, DiPardo (2002).

CRS-24

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. A recent review of research on ethanol’s energy

efficiency found that cellulose-based ethanol had a NEB ratio of 10, i.e., a 1,000% net

gain.62 As with corn-based ethanol, the NEB varies based on the production process

used to grow, harvest, and process the feedstock.

Another factor that favors cellulosic ethanol’s energy balance over corn-based

ethanol relates to by-products. Corn-based ethanol’s by-products are valued as animal

feeds, whereas cellulosic ethanol’s by-products are expected to serve directly as a

processing fuel at the plant. This adaptation is expected to greatly improve both the

economic efficiency and the net energy balance of cellulose ethanol over corn-based

ethanol.

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 2006

about 78 million acres were planted to corn, of which 75%, or about 59 million acres,

were from the nine principal corn belts (IA, IL, IN, MN, MO, NE, OH, SD, WI). In

contrast, that same year the United States had 243 million acres planted to the eight

major field crops (corn, soybeans, wheat, cotton, barley, sorghum, oats, and rice), 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.63

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.64 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.

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

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 (January 27, 2006), pp. 506-508.

United Nations, Food and Agricultural Organization (FAO), FAOSTATS.

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., February 2003; available at [http://www.usda.gov/oce/reports/energy/index.htm].

CRS-25

agricultural lands — while still continuing to meet food, feed, and export demands.65

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.66 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.67 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.68 EPA estimates that

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,

USDA and DOE, Billion Ton Study (2005)

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,” December 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).

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, October 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/].

U.S. Environmental Protection Agency (EPA), AgStar Digest, Winter 2006; available at

[http://www.epa.gov/agstar/].

CRS-26

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.69 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.70

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.71 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 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,

USDA, News Release No. 0386.04, September 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/].

EPA, OAR, Managing Manure with Biogas Recovery Systems, EPA-430-F-02-004, winter

2002.

ATTRA, Anaerobic Digestion of Animal Wastes: Factors to Consider, October 2002.

CRS-27

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.72 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 386 million gallons in 2006

(Figure 5). However, U.S. biodiesel production remains small relative to national

diesel consumption levels. In 2005, estimated biodiesel production of 200 million

gallons represented 0.4% of the 44.9 billion gallons of diesel fuel used nationally for

vehicle transportation.73 In addition to vehicle use, 18.5 billion gallons of diesel fuel

were used for heating and power generation by residential, commercial, and industry,

and by railroad and vessel traffic in 2005, bringing total U.S. diesel fuel use to nearly

63.1 billion gallons.

For more information, visit the National Biodiesel Board at [http://www.biodiesel.org].

Diesel consumption estimates are from DOE, IEA, Annual Energy Outlook 2007.

CRS-28

Figure 5. U.S. Biodiesel Production, 1998-2007

600

Million Gallons

500

400

300

200

100

1998

1999

2000

2001

2002

2003

2004

2005 2006P 2007P

Source: 1998-2003: National Biodiesel Board; 2004-07 projected by FAPRI, March 2007.

According to the NBB, as of October 15, 2007, there were 165 companies in the

United States with the potential to produce biodiesel commercially that were either in

operation, under expansion, or under construction but scheduled to be completed

within the next 18 months.74 The NBB reported that the combined annual biodiesel

production capacity (within the oleochemical industry) of these 165 plants once fully

operational (including capacity under construction) would be an estimated 1.85 billion

gallons per year. Because many of these plants also can produce other products such

as cosmetics, estimated total capacity (and capacity for expansion) is far greater than

actual biodiesel production.

Economic Efficiency. Despite the rapid expansion of biodiesel production

capacity, there are two major economic impediments to future growth. First, biodiesel

production is not profitable under the current set of market prices for vegetable oil

feedstocks and the biodiesel produced. Second, the cost of producing biodiesel is

generally more than the cost of producing its fossil fuel counterpart making the

finished biodiesel uncompetitive with its fossil fuel counterpart in the marketplace.

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 varies substantially with the choice of feedstock.75 For

example, in 2004/05 it cost $0.75 to produce a gallon of petroleum-based diesel,

compared with about $2.86 to produce a gallon of biodiesel from soybean oil, and

$1.59 from restaurant grease (all prices are quoted in 2002 dollars). However,

wholesale soybean oil prices have doubled since 2002 — a pound of soybean oil sold

A description of biodiesel production capacity with maps of existing and proposed plants

is available at [http://www.biodiesel.org/resources/fuelfactsheets/default.shtm].

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-29

for $0.18 in U.S. wholesale markets in 2002 compared with the September 2007

average wholesale price of nearly $0.37.

The production cost differentials generally manifest themselves at the retail level

as well. During July 2007, the retail price of B100 (100% biodiesel) averaged $3.27

per gallon, compared with $2.96 for conventional diesel fuel (Table 2).

Table 5. U.S. Diesel Fuel Use, 2005

Hypothetical scenario:

2% of total useb

Total

U.S. Diesel Use in 2004

Million

gallonsa

Million

gallons

Soybean oil

equivalents:

million

poundsa

Total Vehicle Use

44,887

71%

898

6,733

On-Road

38,053

60%

761

5,708

Off-Road

3,030

455

Military

272

Farm

3,532

530

Total Non-vehicle Use

18,532

29%

365

2,736

All uses

63,129

100%

1263

9,469

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 7.5 pounds-to-gallon conversion rate.

b. Hypothetical scenario included for comparison purposes only.

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 6). 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 risen

steadily (along with corn prices) above the 35¢ per pound ($2.63 per gallon) range,

while diesel fuel have varied around $2 per gallon. Since early September 2007, the

nearby CBOT futures contract for soybean oil has traded near 40¢ per pound ($3.00

per gallon), while more deferred contracts have been at or above 40¢. At such high

soybean oil prices, biodiesel production is unprofitable even with the government

subsidy of $1.00 per gallon.

CRS-30

Figure 6. Soybean Oil Versus Diesel Fuel Price, 2000-2007

2.5

1.5

Soybean Oil

0.5

Diesel Fuel: $/gallon

Soybean Oil: cents/lb

Diesel Fuel

Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07

Source: No.2 diesel fuel national average wholesale price: DOE, EIA; soybean oil, Decatur, IL, USDA,

FAS "Oilseed Circular."

The tremendous surge in soybean oil prices in particular, and vegetable oil prices

in general that has occurred since 2001 is being driven in large part by rapid economic

growth in China and India. As incomes of the lower economic strata grow in these

countries, their demand for vegetable oil and other high quality food products has

grown commensurately. The long-run outlook, as projected by both USDA and

FAPRI, is for continued strong economic growth in China, India, and other developing

countries over the next ten years. As a consequence, sustained strong vegetable oil

prices are expected to curtail growth in the U.S. biodiesel sector under the current

policy and market setting.

Government Support. The primary federal incentives for biodiesel

production are somewhat similar to ethanol and include the following.76

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-agribiodiesel (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

See also section on “Public Laws That Support Agriculture-Based Energy Production and

Use,” below.

CRS-31

producers whose total output does not exceed 60 million gallons of

biodiesel per year.

Incentive payments (contingent on annual appropriations) on year-toyear production increases of renewable energy were previously

available under USDA’s Bioenergy Program (7 U.S.C. 8108);

however, funding for this program expired at the end of FY2006.

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.77

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.78 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 a 2% usage requirement for vehicle diesel fuel were to be adopted. (This

would replicate the European Union’s goal of 2% of transportation fuels originating

from biofuels by 2005, then growing to 5.75% by 2010). This hypothetical mandate

would require about 898 million gallons of biodiesel (compared to estimated 2006

production of about 386 million gallons) or approximately 6.7 billion pounds of

vegetable oil. During 2005/06, a total of 36.7 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, 2006) were

about 4 billion pounds. Thus, after exhausting all available feedstock, an additional

2.7 billion pounds of oil would be needed to meet the hypothetical 2% biodiesel

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].

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-32

blending requirement. This exceeds the 2 billion pounds of total vegetable oils

exported by the United States in 2005/06, and is nearly double the 1.3 billion pounds

of soybean oil exported that during same period.79

If U.S. soybean vegetable oil exports were to remain unchanged, the deficit

biodiesel feedstock could be obtained either by reducing U.S. exports of whole

soybeans by about 250 million bushels (then crushing them for their oil) or by

expanding soybean production by approximately 6 million acres (assuming a yield of

about 42 bushels of soybeans per acre).80 Of course, any area expansion would likely

come at the expense of some other crop such as corn, cotton, or wheat. Current high

corn prices make such an area shift seem unlikely, at least in the near term. A further

possibility is that U.S. oilseed producers could shift towards the production of higheroil content crops such as canola or sunflower.

The bottom line is that a small increase in demand of fats and oils for biodiesel

production could quickly exhaust available feedstock supplies and push vegetable oil

prices significantly higher due to the low elasticity of demand for vegetable oils in

food consumption.81 Rising vegetable oil prices would reduce or eliminate biodiesel’s

competitive advantage vis-à-vis petroleum diesel, even with the federal tax credit,

while 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 250 million bushels of soybeans for soybean oil would

produce over 7.5 million short tons (s.t.) of soybean meal. In 2005/06, the United

States produced 41.2 million s.t. of soybean meal. An additional 7.5 million s.t. of

soybean meal (an increase of over 18%) 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. Also similar to ethanol production, natural gas demand would likely

rise with the increase in biodiesel processing.82

U.S. export data is from USDA, FAS, PSD Online, February 9, 2007.

Assuming 18% oil content per bushel of soybeans.

ERS reported the U.S. own-price elasticity for “oils & fats” at -0.027 — i.e., a 10%

increase in price would result in a 0.27% decline in consumption. In other words, demand

declines only negligibly relative to a price rise. Such inelastic demand is associated with

sharp price spikes in periods of supply shortfall. USDA, ERS, International Evidence on

Food Consumption Patterns, Tech. Bulletin No. 1904, September 2003, p. 67.

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.

CRS-33

Table 6. U.S. Potential Biodiesel Feedstock, 2005-2006

Wholesale

pricea

$/lb

Oil Production,

2005-2006

Million

gallonsb

Million

pounds

Million

gallonsb

25827

3444

3711

495

20,393

2719

3020

403

Corn

28.4

2450

327

156

Cottonseed

28.9

950

127

101

Sunflowerseed

44.5

545

731

Canola

30.7

880

117

262

Peanut

50.6

219

298

Flaxseed/linseed

64.6

335

454

Safflower

72.2

10885

1451

326

21.1

795

106

19.4

1780

237

Inedible tallow

7110

948

238

Yellow greasec

11.6

1200

160

36,712

4895

4,037

538

Oil type

Crops

Soybean

Animal fat & other

Lard

Edible tallow

Total supply

Million

pounds

Ending Stocks:

Sept. 30, 2006

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, December 2006; [http://www.census.gov/cir/www/311/m311k.html].

na = not available.

a. Average of monthly wholesale price quotes for vegetable oils are for 2005 calendar from USDA,

FAS, Oilseeds: World Markets and Trade. Lard and edible tallow prices are for calendar 2005

from USDA, ERS, Oil Crops Yearbook, OCS-2006, March 2006, Tables 42 and 44. 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 7.5 pounds-to-gallon conversion rate.

c. CRS annual projections for production and stocks based on Dept of Commerce Dec. 2006 monthly

estimates from source cited above.

Wind Energy Systems

In 2006, electricity from wind energy systems accounted for about 0.1% of U.S.

total energy consumption (Table 1). However, wind-generated electricity has been

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%).83 According to the American Wind

Energy Association (AWEA), total installed wind energy production capacity has

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.

CRS-34

expanded rapidly in the United States since the late 1990s, rising from 1,848

megawatts (MW) in 1998 to a reported 12,634 MW by June 30, 2007 (Figure 7).84

According to the AWEA, on-line capacity is projected to expand to over 14,600 MW

by the end of 2007. (See “Box: Primer on Measuring Electric Energy,” later in this

report, for a description of megawatts and other energy terminology.)

Figure 7. U.S. Installed Wind Energy Capacity, 1981-2007

Megawatts per hour

16000

12000

8000

4000

*2007 is projected

Source: American Wind Energy Association (AWEA).

About 7% of installed production capacity is in 10 predominantly midwestern

and western states (see Table 7).

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.85 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.

American Wind Energy Association (AWEA), at [http://www.awea.org/projects/].

AWEA, The Economics of Wind Energy, March 2002.

CRS-35

Table 7. Installed Wind Energy Capacity by State,

Ranked by Capacity as of December 31, 2006

UCa or

Planned

Current

State

1 Texas

3,352

26.5%

California

Iowa

Minnesota

Washington

Oklahoma

2,376

967

897

818

595

7 New Mexico

8 Oregon

496

438

9 New York

10 Colorado

11 Kansas

12 Illinois

13 Wyoming

14 Pennsylvania

15 North Dakota

16 Montana

Other

U.S. Total

Total

1,246

4,599

23.7%

18.8%

7.7%

7.1%

6.5%

4.7%

565

203

406

140

2,941

1,170

1,303

958

689

15.2%

6.0%

6.7%

4.9%

3.6%

3.9%

3.5%

501

496

939

2.6%

4.8%

390

3.1%

366

2.9%

364

2.9%

305

2.4%

288

2.3%

179

1.4%

178

1.4%

146

1.2%

478

3.8%

12,634 100%

282

700

220

115

159

2,037

6,769

672

3.5%

1,066

5.5%

364

1.9%

385

2.0%

508

2.6%

294

1.5%

337

1.7%

166

0.9%

2,515 13.0%

19,403 100%

Source: AWEA, [http://www.awea.org/projects/].

UC = Under construction.

As of February 2007, renewable portfolio standards (RPSs) had been adopted by

21 states and the District of Columbia.86 An RPS requires that utilities must derive a

certain percentage of their overall electric generation from renewable energy sources

such as wind power. 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.

sLandowners have typically received annual lease fees that range from $2,000 to

$4000 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.

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

AWEA, “State-Level Renewable Energy Portfolio Standards (RPS),” downloaded March

7, 2007, from [http://www.awea.org/legislative/pdf/State_RPS_Fact_Sheet_UPdated.pdf].

CRS-36

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.87 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 wind projects. In 2004, less

than 1% of wind power capacity installed nationwide was owned by farmers.88

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:89

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,90 especially threatened or endangered

species, could reduce wind energy’s economic competitiveness.

GAO, Wind Power, GAO-04-756, September 2004, p. 66.

Ibid., p. 6.

AWEA, The Economics of Wind Energy, at [http://www.awea.org].

Justin Blum, “Researchers Alarmed by Bat Deaths From Wind Turbines,” Washington

Post, by January 1, 2005.

CRS-37

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.).91

Wellhead natural gas prices have shown considerable volatility since the late

1990s (Figure 8), 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.92 If natural gas

prices continue to be substantially higher than average levels in the 1990s, wind power

is likely to be competitive in parts of the country where good wind resources and

transmission access can be coupled with the federal production tax credit.

Figure 8. Natural Gas Price, Wholesale, 1994-2007

$ per 1,000 cubic feet (mcf)

Jan-94

Jan-96

Jan-98

Jan-00

Jan-02

Jan-04

Jan-06

Source: DOE, EIA; monthly average wholesale (Industrial) price.

According to a wind energy consultant, wind turbine ownership offers

substantially greater returns than crop farming.93 For example, installing two 1.5 MW

wind turbines producing 9 million kWh per year would generate about $325,000

(based on 3.5¢ per kWh and 16 miles per hour wind speed at 50 meters height). As

an example, this compares with a 160-acre corn and soybean farm with average annual

gross receipts of about $66,000 (80 acres of corn at 170 bushels/acre and $3.00 per

Rebecca Smith, “Not Just Tilting Anymore,” Wall Street Journal, October 14, 2004.

For a discussion of natural gas market price factors, see CRS Report RL33714, Natural

Gas Markets in 2006, by Robert Pirog.

Tom Wind, Wind Utility Consulting, “Wind Power,” presentation given on March 2,

2007, USDA Annual Outlook Forum 2007, Crystal City, VA.

CRS-38

bushel; and 80 acres of soybeans at 45 bushels at $7.00 per bushel). The consultant

also suggests that carbon trading could potentially add another $100,000 per year

within a decade.

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.94 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 that 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. The legislation

was referred to the House Committee on Ways and Means but no further action was

taken, and similar legislation has yet to be introduced in the 110th Congress.

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 windgenerated 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.95 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.

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 9). 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.96 The turbines operate

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.

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)).

Tiffany, Douglas G. Economic Analysis: Co-generation Using Wind and Biodiesel(continued...)

CRS-39

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.

Figure 9. U.S. Areas with Highest Wind Potential

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.

(...continued)

Powered Generators, Staff Paper P05-10, Dept of Applied Econ., Univ. of Minn., October

2005.

CRS-40

Environmental Concerns. Three potential environmental issues — impacts on

the visual landscape, bird and bat deaths, and noise issues — vary in importance based

on local conditions. In some rural localities, the merits of wind energy appear to have

split the environmental movement. For example, in the Kansas Flint Hills, local

chapters of the Audubon Society and Nature Conservancy oppose installation of wind

turbines, saying that they would befoul the landscape and harm wildlife; while Kansas

Sierra Club leaders argue that exploiting wind power would help to reduce America’s

dependence on fossil fuels.

CRS-41

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-42

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. It is noteworthy that many

of the federal programs that currently support renewable energy production in general,

and agriculture-based energy production in particular, are outside the purview of

USDA and have legislative origins outside of the farm bill.

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.97 In

addition, this section briefly reviews major proposals by the Administration and bills

introduced by the 110th Congress that relate to agriculture-based renewable energy.

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

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.98 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.99 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.

For more information on federal incentives for biofuel production, see CRS Report

RL33572, Biofuels Incentives: A Summary of Federal Programs, by Brent D. Yacobucci.

For more information, see CRS Report RS21930,Ethanol Imports and the Caribbean

Basin Initiative, by Brent D. Yacobucci.

CRS Report RL33290, Fuel Ethanol: Background and Public Policy Issues, by Brent D.

Yacobucci.

CRS-43

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.100

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.

(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.101

(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.102

100

NBB, “Biodiesel Emissions,” at [http://www.biodiesel.org/pdf_files/fuelfactsheets/

emissions.pdf].

101

The official website for the Biomass Research and Development Initiative may be found

at [http://www.brdisolutions.com/].

102

This report is available at [http://www.brdisolutions.com/].

CRS-44

(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 FY2003FY2007; 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)103

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.

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

103

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-45

the program. As of January 2006, only two awardees — the National Biodiesel Board

and the University of Idaho — had been selected.104

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.105 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

reviewing future loan and loan guarantee applications, were published in the Federal

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.106 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).107

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.

104

These awardees were selected in August 2003; more information is available at

[http://www.biodiesel.org/usda/].

105

For more information on this program, see [http://www.rurdev.usda.gov/rbs/farmbill/

index.html].

106

107

USDA News Release 0051.06, February 22, 2006.

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, September 2004, pp. 5455.

CRS-46

Biomass Research and Development (Title IX; Section 9008).108 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 FY2006FY2015 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.109

Cooperative Research and Development — Carbon Sequestration

(Title IX; Section 9009). This provision amends the Agricultural Risk Protection

Act of 2000 (P.L. 106-224, Sec. 221) to extend through FY2011 the one-time

authorization of $15 million of the Carbon Cycle Research Program, which provides

grants to land-grant universities for carbon cycle research with on-farm applications.

Bioenergy Program (Title IX; Section 9010). This is an existing program

(7 C.F.R. 1424) in which the Secretary makes payments from the CCC to eligible

bioenergy producers — ethanol and biodiesel — based on any year-to-year increase

in the quantity of bioenergy that they produce (fiscal year basis). The goal is to

encourage greater purchases of eligible commodities used in the production of

bioenergy (e.g., corn for ethanol or soybean oil for biodiesel). The Bioenergy Program

was initiated on August 12, 1999, by Executive Order 13134. On October 31, 2000,

then-Secretary of Agriculture Glickman announced that, pursuant to the executive

order, $300 million of discretionary CCC funds ($150 million in both FY2001 and

FY2002) would be made available to encourage expanded production of biofuels. The

2002 farm bill extended the program and its funding by providing that $150 million

would be available annually through the CCC for FY2003-FY2006. The final rule for

the Bioenergy Program was published in the Federal Register (vol. 68, no. 88, May

7, 2003).

The FY2003 appropriations act limited spending for the Bioenergy Program

funding for FY2003 to 77% ($115.5 million) of the $150 million; however, the full

$150 million was eventually spent. 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. Funding authority for this program ended after FY2006.

108

For more information, see the joint USDA-DOE website at [http://www.biomass.

govtools.us/].

109

Ibid.

CRS-47

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

Value-Added Producer Grants (VAPG).110 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.111

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 biomassrelated 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

110

For more information see [http://www.rurdev.usda.gov/rd/energy/].

111

USDA News Release 0002.06, January 9, 2006.

CRS-48

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.112 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 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.113

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.

112

For more information, see the American Coalition for Ethanol, Volumetric Ethanol

Excise Tax Credit (VEETC) at [http://www.ethanol.org/veetc.html]

113

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.

CRS-49

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). Agribiodiesel 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

(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 sugarcane, 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;

CRS-50

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.

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

CRS-51

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-favorednation tariff on most imported ethanol (referred to in the earlier section of this report

“Tariff on Imported Ethanol”) was extended through December 31, 2008.

Agriculture-Related Energy Bills in 110th Congress

As of October 15, 2007, numerous bills 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. For a listing of related legislation in the

110th Congress, see CRS Report RL33831, Energy Efficiency and Renewable Energy

Legislation in the 110th Congress by Fred Sissine.

House-passed New Farm Bill — H.R. 2419. On July 27, 2007, the House

approved a new farm bill — the Farm, Nutrition, and Bioenergy Act of 2007 (H.R.

2419) — which includes an energy title (Title IX). H.R. 2419, as amended and passed

by the House, expands and extends several provisions from the energy title of the

enacted 2002 farm bill with substantial increases in funding and a heightened focus

on developing cellulosic ethanol production. A key departure from current farm-bill

related energy provisions is that most new funding would be directed away from cornstarch-based ethanol production and towards either cellulosic-based biofuels

production or to new as-yet-undeveloped technologies with some type of agricultural

linkage. A funding complication relating to “pay-go” budget restrictions on new

energy funding arose during the House Agriculture Committee’s (HAC’s) bill

preparation because the Congressional Budget Office’s March baseline showed no

funding in the farm bill for a new energy title. However, the House Ways and Means

Committee resolved this issue for the HAC by finding $2.4 billion in revenue offsets

from outside of the agriculture budget.

The Senate Agriculture Committee (SAC) is expected to mark up its version of

a 2007 farm bill in late-October. The Senate is also expected to adhere to “pay-go”

budget restrictions which may, in and of themselves, lead to different funding choices

CRS-52

than made by the House. For more information, see CRS Report RL34130,

Renewable Energy Policy in the 2007 Farm Bill, by Randy Schnepf.

In addition to 2007 farm bill developments, both the House and Senate have

passed different versions of new energy bills that contain many biofuel provisions

similar to those contained in Title IX of the 2002 farm bill.114 The Senate approved

its version of an energy bill, H.R. 6 (the Renewable Fuels, Consumer Protection, and

Energy Efficiency Act of 2007) on June 21, 2007, while the House approved its own

energy bill, H.R. 3221 (the New Direction for Energy Independence, National

Security, and Consumer Protection Act of 2007) on August 4, 2007. In particular,

Title V of H.R. 3221 contains provisions similar or identical to provisions passed in

Title IX of H.R. 2419. For more information on these energy bills, see CRS Report

RL34136, Biofuels Provisions in H.R. 3221 and H.R. 6: A Side-by-Side Comparison,

by Brent Yacobucci.

Also, on October 15, 2007, the House approved H.Con.Res. 25 expressing the

sense of Congress that it is the goal of the United States 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 percent of the total energy consumed in the

United States and continue to produce safe, abundant, and affordable food, feed, and

fiber. A similar bill, S.Con.Res. 3, has been introduced in the Senate and referred to

the Agriculture Committee.

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.115 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

114

For more information on these energy bills, see CRS Report RL34136, Biofuels

Provisions in H.R. 3221 and H.R. 6: A Side-by-Side Comparison, by Brent Yacobucci.

115

For more information on state and federal programs, see State and Federal Incentives and

Laws, at the DOE’s Alternative Fuels Data Center, [http://www.eere.energy.gov/afdc/

laws/incen_laws.html].

CRS-53

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.116

Administration Proposals

State of the Union (SOU) 2006. In his 2006 SOU, President Bush

introduced the notion of “switchgrass” as a potential energy source and announced the

“Advanced Energy Initiative,” which included a goal of making cellulosic ethanol cost

competitive with corn-based ethanol by 2012.117

State of the Union (SOU) 2007. In his 2007 SOU, President Bush

announced his “20 in 10” plan, which calls for reducing U.S. gasoline consumption

by 20% in 10 years (i.e., by 2017).118 The President proposed two major approaches

for achieving his “20 in 10” goal.

Increasing the supply of renewable and alternative fuels by setting a

mandatory fuels standard to require 35 billion gallons of renewable

and alternative fuels in 2017. This would be nearly five times the

2012 RFS target of 7.5 billions now in law. If accomplished, the

Administration estimates that this would displace 15% of projected

annual gasoline use in 2017.

Reforming and modernizing corporate average fuel economy (CAFÉ)

standards for cars and extending the current light truck rule.

According to the Administration, this will reduce projected annual

gasoline use by up to 8.5 billion gallons by 2017, a further 5%

reduction that, in combination with increasing the supply of

renewable and alternative fuels, will bring the total reduction in

projected annual gasoline use to 20%.

According to the Administration, the President’s FY2008 budget will request

$2.7 billion for the advanced energy initiative — an increase of 26% above the 2007

request and 53% above 2006. President Bush has called for increased federal

investment in hydrogen fuel technology research, as well as increased investment in

advanced batteries for hybrids and plug-in hybrids, biodiesel fuels, and new methods

of producing ethanol and other biofuels.

USDA’s New Farm Bill Proposal (January 2007). On January 31, 2007,

Agriculture Secretary Mike Johanns announced USDA’s 2007 farm bill proposal. The

116

For more information on Minnesota vehicle fuel acquisition requirements, visit

[http://www.eere.energy.gov/afdc/laws/incen_laws.html].

117

More information on the Advanced Energy Initiative from the 2006 SOU is available at

[http://www.whitehouse.gov/stateoftheunion/2006/energy/index.html].

118

More information see the White House “Fact Sheet: Strengthening America’s Energy

Security and Improving the Environment,” January 24, 2007; available at [http://www.

whitehouse.gov/news/releases/2007/01/20070124-5.html].

CRS-54

proposal includes $1.6 billion in new funding over ten years for energy innovation,

including bio-energy research, energy efficiency grants, and $2 billion in loans for

cellulosic ethanol plants.119

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

American Coalition for Ethanol, [http://www.ethanol.org/].

Bio, Achieving Sustainable Production of Agricultural Biomass for Biorefinery

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/].

119

Title-by-Title details of USDA’s 2007 Farm Bill proposal are available at [http://www.

usda.gov/wps/portal/usdafarmbill?navtype=SU&navid=FARM_BILL_FORUMS].

CRS-55

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,” December 14-15, 2005, St.

Louis, Missouri; available at [http://www.farmfoundation.org/projects/documents/

EIDMANpaperrevisedTOPOST12-19-05.pdf].

Environmental Protection Agency (EPA), Fuels and Fuel Additives, Alternative Fuels,

[http://www.epa.gov/otaq/consumer/fuels/altfuels/altfuels.htm].

Hill, Jason, Erik Nelson, David Tilman, Stephen Polasky, and Douglas Tiffany.

“Environmental, economic, and energetic costs and benefits of biodiesel and ethanol

biofuels,” Proceedings of the National Academy of Sciences, Vol. 103, No. 30, July

25, 2006, 11206-11210.

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/].

Renewable Fuels Association (RFA), [http://www.ethanolrfa.org/].

USDA, The Economic Feasibility of Ethanol Production from Sugar in the United

States, Office of Energy Policy and New Uses (OEPNU), Office of the Chief

Economist (OCE), USDA, and Louisiana State University (LSU), July 2006; available

at [http://www.usda.gov/oce/reports/energy/EthanolSugarFeasibilityReport3.pdf].

USDA/Dept. Of Energy (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].

Economic Benefits of Biofuel Production

De La Torre Ugarte, D., M. Walsh, H. Shapouri, and S. Slinsky. The Economic

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),

February 2003; available at [http://www.usda.gov/oce/reports/energy/AER816Bi.pdf].

Food and Agricultural Policy Research Institute (FAPRI), Implications of Increased

Ethanol Production for U.S. Agriculture, FAPRI-UMC Report #10-05, August 22,

2005; available at [http://www.fapri.missouri.edu/].

FAPRI, Returns to Biofuels Production, FAPRI-UMC Report #06-07, March 2007.

FAPRI, Economic Impacts of Not Extending Biofuels Subsidies, FAPRI-UMC Report

#17-07, May 2007.

CRS-56

FAPRI, Impacts of a 15 Billion Gallon Biofuels Use Mandate, FAPRI-UMC Report

#22-07, June 2007.

Gallagher, P. Otto, H. Shapouri, J. Price, G. Schamel, M. Dikeman, and H. Brubacker,

The Effects of Expanding Ethanol Markets on Ethanol Production, Feed Markets, and

the Iowa Economy, Staff Paper #342, Dept. of Economics, Iowa St. Univ., June 30,

2001.

Gallagher, P., E. Wailes, M. Dikeman, J. Fritz, W. Gauther, and H. Shapouri, Biomass

From Crop Residues: Cost and Supply Estimates, AER 819, USDA, OCE, OEPNU,

March 2003; available at [http://www.usda.gov/oce/reports/energy/ AER819.pdf].

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]

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/].

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.

Shapour

This text is long and has been trimmed here. Open the source document for the complete record.

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.