DOE/EIA-0383(2010)

April 2010

Annual Energy Outlook 2010

With Projections to 2035
For Further Information...

The Annual Energy Outlook 2010 was prepared by the Energy Information Administration, under the direction of John J. Conti (john.conti@eia.doe.gov, 202-586-2222), Director, Integrated Analysis and Forecasting;

Paul D. Holtberg (paul.holtberg@eia.doe.gov, 202/586-1284), Director, Demand and Integration Division;

Joseph A. Beamon (jbeamon@eia.doe.gov, 202/586-2025), Director, Coal and Electric Power Division;

A. Michael Schaal (michael.schaal@eia.doe.gov, 202/586-5590), Director, Oil and Gas Division; Glen E.

Sweetnam (glen.sweetnam@eia.doe.gov, 202/586-2188), Director, International, Economic, and Greenhouse

Gases Division; and Andy S. Kydes (akydes@eia.doe.gov, 202/586-2222), Senior Technical Advisor.

For ordering information and questions on other energy statistics available from the Energy Information

Administration, please contact the National Energy Information Center. Addresses, telephone numbers, and

hours are as follows:

National Energy Information Center, EI-30

Energy Information Administration

Forrestal Building

Washington, DC 20585

Telephone: 202/586-8800 E-mail: infoctr@eia.doe.gov

FAX: 202/586-0727 Web Site: http://www.eia.doe.gov/

TTY: 202/586-1181 FTP Site: ftp://ftp.eia.doe.gov/

9 a.m. to 5 p.m., eastern time, M-F

Specific questions about the information in this report may be directed to:

Executive Summary ......... Paul D. Holtberg (paul.holtberg@eia.doe.gov, 202/586-1284)

Economic Activity . . . . . . . . . . Kay A. Smith (kay.smith@eia.doe.gov, 202/586-1132)

International Oil Production..... Lauren Mayne (lauren.mayne@eia.doe.gov, 202/586-3005)

International Oil Demand ...... Linda Doman (linda.doman@eia.doe.gov, 202/586-1041)

Residential Demand ......... Erin E. Boedecker (erin.boedecker@eia.doe.gov, 202/586-4791)

Commercial Demand ......... Erin E. Boedecker (erin.boedecker@eia.doe.gov, 202/586-4791)

Industrial Demand .......... Elizabeth D. Sendich (elizabeth.sendich@eia.doe.gov, 202/586-7145)

Transportation Demand ....... John D. Maples (john.maples@eia.doe.gov, 202/586-1757)

Electricity Generation, Capacity. . . Jeff S. Jones (jjones@eia.doe.gov, 202/586-2038)

Electricity Generation, Emissions . . Michael T. Leff (michael.leff@eia.doe.gov, 202/586-1297)

Electricity Prices ........... Lori B. Aniti (laniti@eia.doe.gov, 202/586-2867)

Nuclear Energy ............ Laura K. Martin (laura.martin@eia.doe.gov, 202/586-1494)

Renewable Energy .......... Chris R. Namovicz (chris.namovicz@eia.doe.gov, 202/586-7120)

Oil and Natural Gas Production . . . Eddie L. Thomas, Jr. (eddie.thomas@eia.doe.gov, 202/586-5877)

Natural Gas Markets ......... Philip M. Budzik (pbudzik@eia.doe.gov, 202/586-2847)

Oil Refining and Markets ...... William S. Brown (william.brown@eia.doe.gov, 202/586-8181)

Coal Supply and Prices ........ Michael L. Mellish (mmellish@eia.doe.gov, 202/586-2136)

Greenhouse Gas Emissions ..... Daniel H. Skelly (dskelly@eia.doe.gov, 202/586-2415)

The Annual Energy Outlook 2010 is available on the EIA web site at www.eia.doe.gov/oiaf/aeo/. Assumptions

underlying the projections, tables of regional results, and other detailed results will also be available, at web

sites www.eia.doe.gov/oiaf/assumption/ and /supplement/. Model documentation reports for the National

Energy Modeling System are available at web site http://tonto.eia.doe.gov/reports/reports_kindD.asp?type=

model documentation and will be updated for the Annual Energy Outlook 2010 during 2010.

Other contributors to the report include Justine Barden, Joseph Benneche, Tina Bowers, Steve Calopedis,

Nicholas Chase, John Cochener, Michael Cole, Owen Comstock, John Cymbalsky, Margie Daymude, Amelia

Elson, Robert Eynon, Adrian Geagla, Peter Gross, James Hewlett, Sean Hill, Diane Kearney, Stephanie Kette,

Paul Kondis, Marie LaRiviere, Thomas Lee, Phyllis Martin, Chetha Phang, Eugene Reiser, Sharon Shears,

Robert Smith, Mac Statton, John Staub, Russell Tarver, Diwakar Vashishat, Dana Van Wagener, Steven

Wade, and Peggy Wells.
DOE/EIA-0383(2010)

Annual Energy Outlook 2010

With Projections to 2035

April 2010

U.S. Energy Information Administration

Office of Integrated Analysis and Forecasting

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and

analytical agency within the U.S. Department of Energy. By law, EIA’s data, analyses, and forecasts are

independent of approval by any other officer or employee of the United States Government. The views in

this report therefore should not be construed as representing those of the Department of Energy or other

Federal agencies.

This publication is on the WEB at:

www.eia.doe.gov/oiaf/aeo/
The Annual Energy Outlook 2010 (AEO2010), prepared by the U.S. Energy Information Administration (EIA), presents long-term projections of energy

supply, demand, and prices through 2035, based on

results from EIA’s National Energy Modeling System

(NEMS). EIA published an “early release” version of

the AEO2010 Reference case in December 2009.

The report begins with an “Executive Summary” that

highlights key aspects of the projections. It is followed

by a “Legislation and Regulations” section that discusses evolving legislative and regulatory issues,

including a summary of recently enacted legislation,

such as the American Recovery and Reinvestment Act

of 2009 (ARRA). The next section, “Issues in Focus,”

contains discussions of selected energy topics. The

first discussion provides a comparison of the results

in two cases that adopt different assumptions about

the future course of existing policies: one case assumes the extension of a selected group of existing

public policies—corporate average fuel economy

(CAFE) standards, appliance standards, production

tax credits (PTCs), and the elimination of sunset provisions in existing energy policies; the other case assumes only the elimination of sunset provisions.

Other discussions include: end-use energy efficiency

trends; the sensitivity of the projection results to variations in assumptions about the size of the U.S. shale

gas resource; the implications of retiring nuclear

plants

after 60 years of operation; the relationship between

natural gas and oil prices; and the basis for world oil

price and production trends in AEO2010.

The “Market Trends” section summarizes the projections for energy markets. The analysis in AEO2010

focuses primarily on a Reference case, Low and High

Economic Growth cases, and Low and High Oil Price

cases. Results from a number of other alternative

cases also are presented, illustrating uncertainties

associated with the Reference case projections for

energy demand, supply, and prices. Complete tables

for the five primary cases are provided in Appendixes

A through C. Major results from many of the alternative cases are provided in Appendix D.

AEO2010 projections are based on Federal, State, and

local laws and regulations in effect as of the end of October 2009. The potential impacts of pending or proposed legislation, regulations, and standards (and

sections of existing legislation that require implementing regulations or funds that have not been

appropriated) are not reflected in the projections.

AEO2010 is published in accordance with Section

205c of the U.S. Department of Energy (DOE) Organization Act of 1977 (Public Law 95-91), which

requires the EIA Administrator to prepare annual

reports on trends and projections for energy use and

supply.

ii U.S. Energy Information Administration / Annual Energy Outlook 2010

Preface

Projections by EIA are not statements of what will

happen but of what might happen, given the assumptions and methodologies used for any particular

scenario. The Reference case projection is a businessas-usual trend estimate, given known technology and

technological and demographic trends. EIA explores

the impacts of alternative assumptions in other scenarios with different macroeconomic growth rates,

world oil prices, and rates of technology progress. The

main cases in AEO2010 generally assume that current

laws and regulations are maintained throughout the

projections. Thus, the projections provide policyneutral baselines that can be used to analyze policy

initiatives.

While energy markets are complex, energy models

are simplified representations of energy production

and consumption, regulations, and producer and

consumer behavior. Projections are highly dependent

on the data, methodologies, model structures, and

assumptions used in their development. Behavioral

characteristics are indicative of real-world tendencies

rather than representations of specific outcomes.

Energy market projections are subject to much uncertainty. Many of the events that shape energy markets

are random and cannot be anticipated. In addition,

future developments in technologies, demographics,

and resources cannot be foreseen with certainty.

Many key uncertainties in the AEO2010 projections

are addressed through alternative cases.

EIA has endeavored to make these projections as

objective, reliable, and useful as possible; however,

they should serve as an adjunct to, not a substitute

for, a complete and focused analysis of public policy

initiatives.
Page

Executive Summary ................................................................. 1

Legislation and Regulations .......................................................... 5

Issues in Focus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Market Trends. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

U.S. Energy Information Administration / Annual Energy Outlook 2010 iii

Contents

Moderate energy consumption growth and greater use of renewables ............................ 2

Declining reliance on imported liquid fuels .................................................. 3

Shale gas drives growth in natural gas production, offsetting declines in other sources .............. 3

Increases in energy-related carbon dioxide emissions slow...................................... 4

Trends in economic activity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

International oil markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

U.S. energy demand. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Residential sector energy demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Commercial sector energy demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Industrial sector energy demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Transportation sector energy demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Electricity demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Electricity prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Electricity generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Nuclear capacity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

Renewable generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

Natural gas prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

Natural gas supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Natural gas imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Liquid fuels supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

Liquid fuels consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Liquid fuels refinery capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Coal production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Coal prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Emissions from energy use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Endnotes for Market Trends. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Introduction ........................................................................... 6

American Recovery and Reinvestment Act of 2009: Summary of provisions........................ 7

Liquid fuels taxes and tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

CAFE standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

New EPA guidelines for review of surface coal mining operations in Appalachia. . . . . . . . . . . . . . . . . . . . 13

Clean Air Interstate Rule: Changes and modeling in AEO2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

State renewable energy requirements and goals: Update through 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Updated State air emissions regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Endnotes for Legislation and Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

No Sunset and Extended Policies cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

World oil prices and production trends in AEO2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Energy intensity trends in AEO2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Natural gas as a fuel for heavy trucks: Issues and incentives. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Factors affecting the relationship between crude oil and natural gas prices . . . . . . . . . . . . . . . . . . . . . . . . 37

Importance of low-permeability natural gas reservoirs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

U.S. nuclear power plants: Continued life or replacement after 60? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Accounting for carbon dioxide emissions from biomass energy combustion . . . . . . . . . . . . . . . . . . . . . . . . 46

Endnotes for Issues in Focus. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Comparison With Other Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Notes and Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Appendixes

A. Reference Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

B. Economic Growth Case Comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

C. Price Case Comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159

D. Results from Side Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174

E. NEMS Overview and Brief Description of Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195

F. Regional Maps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213

G. Conversion Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

Tables

Figures

iv U.S. Energy Information Administration / Annual Energy Outlook 2010

Contents

1. U.S. primary energy consumption, 1980-2035 ............................................. 2

2. U.S. liquid fuels supply, 1970-2035 ...................................................... 3

3. U.S. natural gas supply, 1990-2035 ...................................................... 3

4. U.S. energy-related carbon dioxide emissions, 2008 and 2035................................. 4

5. Projected average fleet-wide fuel economy and CO2-equivalent emissions compliance levels

for passenger cars, model year 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

6. Projected average fleet-wide fuel economy and CO2-equivalent emissions compliance levels

for light trucks, model year 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

7. Total energy consumption in three cases, 2005-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

8. Light-duty vehicle energy consumption in three cases, 2005-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

9. New light-duty vehicle fuel efficiency standards in two cases, 2005-2035 . . . . . . . . . . . . . . . . . . . . . . . 25

10. New light-duty vehicle fuel efficiency standards and fuel efficiency achieved

in two cases, 2005-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

11. Renewable electricity generation in three cases, 2005-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

12. Electricity generation from natural gas in three cases, 2005-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

13. Energy-related carbon dioxide emissions in three cases, 2005-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

14. Natural gas wellhead prices in three cases, 2005-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

15. Average electricity prices in three cases, 2005-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

1. Estimated average fleet-wide fuel economy and CO2-equivalent emissions compliance levels,

model years 2012-2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2. Renewable portfolio standards in the 30 States with current mandates . . . . . . . . . . . . . . . . . . . . . . . . 15

3. Key analyses from “Issues in Focus” in recent AEOs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

4. Average annual increases in economic output, population, and energy consumption indicators

in the buildings, industrial, and transportation sectors, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

5. Maximum market potential for natural gas heavy-duty vehicles in Base Market

and Expanded Market cases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

6. Levelized capital costs for natural gas fueling stations with and without assumed tax credits . . . . . . 35

7. Natural gas prices, supply, and consumption in four cases, 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

8. Comparison of key projections in the Reference and Nuclear 60-Year Life cases . . . . . . . . . . . . . . . . . 46

9. Projections of average annual economic growth rates, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

10. Projections of world oil prices, 2015-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

11. Projections of energy consumption by sector, 2007-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

12. Comparison of electricity projections, 2015 and 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

13. Comparison of natural gas projections, 2015, 2025, and 2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

14. Comparison of liquids projections, 2015, 2025, and 2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

15. Comparison of coal projections, 2015, 2025, and 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
Figures (Continued) Page

U.S. Energy Information Administration / Annual Energy Outlook 2010 v

Contents

16. Average annual world oil prices in three cases, 1980-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

17. Trends in U.S. oil prices, energy consumption, and economic output, 1950-2035 . . . . . . . . . . . . . . . . . 30

18. Projected changes in indexes of energy efficiency, energy intensity, and carbon intensity

in the AEO2010 Reference case, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

19. Structural and efficiency effects on primary energy consumption in the AEO2010 Reference case. . . 32

20. Energy efficiency and energy intensity in three cases, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

21. Delivered energy prices for diesel and natural gas transportation fuels

in the Reference case, 2000-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

22. Sales of new heavy-duty natural gas vehicles in Base Market and Expanded Market cases

with Reference case world oil prices, 2010-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

23. Natural gas fuel use by heavy-duty natural gas vehicles in Base Market and Expanded Market cases

with Reference case world oil prices, 2010-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

24. Reductions in petroleum product use by heavy-duty vehicles in Base Market and Expanded Market

cases with Reference case world oil prices, 2010-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

25. Annual cost of vehicle and fuel tax credits and net change in annual economy-wide

energy expenditures for the 2027 Phaseout Expanded Market case, 2010-2027 . . . . . . . . . . . . . . . . . . 37

26. Ratio of low-sulfur light crude oil prices to natural gas prices on an energy-equivalent basis,

1995-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

27. Ratio of natural gas volume to diesel fuel volume needed to provide the same energy content . . . . . . 38

28. Breakeven natural gas price relative to crude oil price required for investment

in new gas-to-liquids plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

29. U.S. nuclear power plants that will reach 60 years of operation by 2035 . . . . . . . . . . . . . . . . . . . . . . . . 45

30. Carbon dioxide emissions from biomass energy combustion, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . 47

31. Average annual growth rates of real GDP, labor force, and productivity in three cases, 2008-2035 . . 52

32. Average annual inflation, interest, and unemployment rates in three cases, 2008-2035. . . . . . . . . . . . 52

33. Sectoral composition of industrial output growth rates in three cases, 2008-2035 . . . . . . . . . . . . . . . . 53

34. Energy expenditures in the U.S. economy in three cases, 1990-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

35. Energy end-use expenditures as a share of gross domestic product, 1970-2035. . . . . . . . . . . . . . . . . . . 53

36. Average annual world oil prices in three cases, 1980-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

37. World liquids production shares by region in three cases, 2008 and 2035 . . . . . . . . . . . . . . . . . . . . . . . 54

38. Unconventional resources as a share of total world liquids production in three cases,

2008 and 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

39. Energy use per capita and per dollar of gross domestic product, 1980-2035 . . . . . . . . . . . . . . . . . . . . . 55

40. Primary energy use by end-use sector, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

41. Primary energy use by fuel, 1980-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

42. Residential delivered energy consumption per capita in four cases, 1990-2035 . . . . . . . . . . . . . . . . . . . 57

43. Change in residential electricity consumption for selected end uses in the Reference case,

2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

44. Energy intensity for selected end uses of electricity in the residential sector in three cases,

2008 and 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

45. Residential market saturation by renewable technologies in two cases, 2008, 2020, and 2035 . . . . . . 58

46. Commercial delivered energy consumption per capita in four cases, 1990-2035 . . . . . . . . . . . . . . . . . . 59

47. Average annual growth rates for selected electricity end uses in the commercial sector, 2008-2035 . . 59

48. Efficiency gains for selected commercial equipment in three cases, 2035 . . . . . . . . . . . . . . . . . . . . . . . 60

49. Additions to electricity generation capacity in the commercial sector in two cases, 2008-2035 . . . . . . 60

50. Industrial delivered energy consumption by application, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

51. Industrial consumption of fuels for use as feedstocks by fuel type, 2008-2035 . . . . . . . . . . . . . . . . . . . 61

52. Industrial energy consumption by fuel, 2003, 2008, and 2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

53. Cumulative growth in value of shipments by industrial subsector in three cases, 2008-2035 . . . . . . . 62

54. Change in delivered energy consumption for industrial subsectors in three cases, 2008-2035 . . . . . . . 63

55. Delivered energy consumption for transportation by mode, 2008 and 2035. . . . . . . . . . . . . . . . . . . . . . 63

56. Average fuel economy of new light-duty vehicles in five cases, 1980-2035 . . . . . . . . . . . . . . . . . . . . . . . 64
Figures (Continued) Page

vi U.S. Energy Information Administration / Annual Energy Outlook 2010

Contents

57. Market penetration of new technologies for light-duty vehicles, 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . 64

58. Sales of unconventional light-duty vehicles by fuel type, 2008, 2020, and 2035. . . . . . . . . . . . . . . . . . . 65

59. U.S. electricity demand growth, 1950-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

60. Average annual U.S. retail electricity prices in three cases, 1970-2035 . . . . . . . . . . . . . . . . . . . . . . . . . 66

61. Electricity generation by fuel in three cases, 2008 and 2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

62. Electricity generation capacity additions by fuel type, 2009-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

63. Levelized electricity costs for new power plants, 2020 and 2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

64. Electricity generating capacity at U.S. nuclear power plants in three cases, 2008, 2020, and 2035 . . . 68

65. Nonhydroelectric renewable electricity generation by energy source, 2008-2035 . . . . . . . . . . . . . . . . . 68

66. Grid-connected coal-fired and wind-powered generating capacity, 2003-2035 . . . . . . . . . . . . . . . . . . . . 69

67. Nonhydropower renewable generation capacity in three cases, 2015-2035 . . . . . . . . . . . . . . . . . . . . . . 69

68. Regional growth in nonhydroelectric renewable electricity generation capacity,

including end-use capacity, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

69. Annual average lower 48 wellhead and Henry Hub spot market prices for natural gas, 1990-2035. . . 70

70. Ratio of low-sulfur light crude oil price to Henry Hub natural gas price

on an energy equivalent basis, 1990-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

71. Annual average lower 48 wellhead prices for natural gas in three technology cases, 1990-2035 . . . . . 71

72. Annual average lower 48 wellhead prices for natural gas in three oil price cases, 1990-2035. . . . . . . . 71

73. Natural gas production by source, 1990-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

74. Total U.S. natural gas production in five cases, 1990-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

75. Lower 48 onshore natural gas production by region, 2008 and 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

76. Shale gas production by region, 2008, 2020, and 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

77. U.S. net imports of natural gas by source, 1990-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

78. Cumulative difference from Reference case natural gas supply and consumption

in the High LNG Supply case, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

79. Liquid fuels consumption by sector, 1990-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

80. Domestic crude oil production by source, 1990-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

81. Total U.S. crude oil production in five cases, 1990-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

82. Liquids production from biomass, coal, and oil shale, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

83. Net import share of U.S. liquid fuels consumption in three cases, 1990-2035 . . . . . . . . . . . . . . . . . . . . 77

84. EISA2007 RFS credits earned in selected years, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

85. U.S. motor gasoline and diesel fuel consumption, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

86. U.S. refinery capacity, 1970-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

87. U.S. production of cellulosic ethanol and other new biofuels, 2015-2035 . . . . . . . . . . . . . . . . . . . . . . . . 79

88. Coal production by region, 1970-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

89. U.S. coal production in six cases, 2008, 2020, and 2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

90. Average annual minemouth coal prices by region, 1990-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

91. Average annual delivered coal prices in four cases, 1990-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

92. Change in U.S. coal consumption by end use in two cases, 2008-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . 81

93. Carbon dioxide emissions by sector and fuel, 2008 and 2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

94. Sulfur dioxide emissions from electricity generation, 2000-2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

95. Nitrogen oxide emissions from electricity generation, 2000-2035. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
Executive Summary
In 2009, U.S. energy markets continued to show the

impacts of the economic downturn that began in late

2007. After falling by 1 percent in 2008, total electricity generation dropped by another 3 percent in 2009.

Although other factors, including weather, contributed to the decrease, it was the first time in the

60-year data series maintained by the EIA that electricity use fell in two consecutive years. Over the next

few years, the key factors influencing U.S. energy

markets will be the pace of the economic recovery,

any lasting impacts on capital-intensive energy projects from the turmoil in financial markets, and the

potential enactment of legislation related to energy

and the environment.

The projections in AEO2010 focus on the factors that

shape U.S. energy markets in the long term. Under

the assumption that current laws and regulations

remain unchanged throughout the projections, the

AEO2010 Reference case provides the basis for examination and discussion of energy market trends and

the direction they may take in the future. It also

serves as a starting point for the analysis of potential

changes in energy policies, rules, or regulations.

Unless otherwise noted, results refer to the Reference

case. But AEO2010 is not limited to the Reference

case. It also includes 38 sensitivity cases (see Appendix E, Table E1, on page 201), which explore important areas of market, technological, and policy

uncertainty in the U.S. energy economy.

Key results highlighted in AEO2010 include moderate growth in energy consumption, increased use of

renewables, declining reliance on imported liquid

fuels, strong growth in shale gas production, and projected slow growth in energy-related carbon dioxide

(CO2) emissions in the absence of new policies designed to mitigate greenhouse gas (GHG) emissions.

AEO2010 also includes in-depth discussions on topics

of special interest that may affect the energy market

outlook. They include: impacts of the continuing

renewal and updating of Federal and State laws and

regulations; end-use energy efficiency trends in the

AEO2010 Reference case; the sensitivity of projections to alternative assumptions about U.S. shale gas

development; the implications of retiring nuclear

plants after 60 years of operation; the relationship

between natural gas and oil prices in U.S. markets;

and the basis for world oil price and production trends

in AEO2010. Some of the highlights from those

discussions are mentioned in this Executive Summary. Readers interested in more detailed analyses

and discussions should refer to the “Legislation and

Regulations” and “Issues in Focus” sections of this

report.

Moderate energy consumption growth

and greater use of renewables

Total U.S. primary energy consumption increases by

14 percent from 2008 to 2035 in the Reference case

(Figure 1), representing an average annual growth

rate of 0.5 percent—only one-fifth of the projected

2.4-percent annual growth rate of the Nation’s economic output. The difference between the two rates is

the result of continuing improvement in the energy

intensity of the U.S. economy, measured as the

amount of energy consumed per dollar of gross

domestic product (GDP). From 2008 to 2035, energy

intensity falls by 1.9 percent per year in the Reference

case, as the most rapid growth in the U.S. economy

occurs in the less energy-intensive service sectors,

and as the efficiency of energy-consuming appliances,

vehicles, and structures improves.

EIA projects the strongest growth in fuel use for the

renewable fuels used to generate electricity and to

produce liquid fuels for the transportation sector. The

growth in consumption of renewable fuels is primarily a result of Federal and State programs—including

the Federal renewable fuels standard (RFS), various

State renewable portfolio standard (RPS) programs,

and funds in ARRA—together with rising fossil fuel

prices. Although fossil fuels continue to provide most

of the energy consumed in the United States over the

next 25 years in the Reference case, their share of

overall energy use falls from 84 percent in 2008 to 78

percent in 2035.

The role of renewables could grow still further if

current policies that support renewable fuels are

2 U.S. Energy Information Administration / Annual Energy Outlook 2010

Executive Summary

1980 1995 2008 2020 2035

0

20

40

60

80

100

120

Total

History Projections

Natural gas

Nuclear

Coal

Liquids

Biofuels

Renewables

Figure 1. U.S. primary energy consumption,

1980-2035 (quadrillion Btu)
extended. For example, the Reference case assumes

that the PTC available for electricity generation from

renewables sunsets in 2012 (wind) or 2013 (other

technologies) as specified in current law, but it has a

history of being renewed and could be extended again.

In the Reference case, renewable generation accounts

for 45 percent of the increase in total generation from

2008 to 2035. In alternative cases assuming the PTC

for renewable generation is extended through 2035,

the share of growth in total generation accounted for

by renewables is between 61 and 65 percent.

Declining reliance on imported

liquid fuels

Although U.S. consumption of liquid fuels continues

to grow over the next 25 years in the AEO2010 Reference case, reliance on petroleum imports decreases

(Figure 2). With government policies and rising oil

prices providing incentives for the continued development and use of alternatives to fossil fuels, biofuels

account for all the growth in liquid fuel consumption

in the United States over the next 25 years, while consumption of petroleum-based liquids is essentially

flat. Total U.S. consumption of liquid fuels, including

both fossil fuels and biofuels, rises from about 20 million barrels per day in 2008 to 22 million barrels per

day in 2035 in the Reference case.

The role played by petroleum-based liquids could be

further challenged if electric or natural-gas-fueled

vehicles begin to enter the market in significant numbers. Rising oil prices, together with growing concerns about climate change and energy security, are

leading to increased interest in alternative-fuel vehicles (AFVs), but both electric and natural gas vehicles

face significant challenges. Alternative cases in this

report examine the possible impacts of policies aimed

at increasing natural gas use in heavy trucks and

identify some of the key factors that will determine

the potential for petroleum displacement.

Shale gas drives growth in natural gas

production, offsetting declines

in other sources

The growth in shale gas production in recent years

is one of the most dynamic stories in U.S. energy

markets. A few years ago, most analysts foresaw a

growing U.S. reliance on imported sources of natural

gas, and significant investments were being made in

regasification facilities for imports of liquefied natural gas (LNG). Today, the biggest questions are the

size of the shale gas resource base (which by most

estimates is vast), the price level required to sustain

its development, and whether there are technical or

environmental factors that might dampen its development. Beyond those questions, the level of future

domestic natural gas production will also depend on

the level of natural gas demand in key consuming sectors, which will be shaped by prices, economic growth,

and policies affecting fuel choice.

In the Reference case, total domestic natural gas

production grows from 20.6 trillion cubic feet in 2008

to 23.3 trillion cubic feet in 2035. With technology

improvements and rising natural gas prices, natural

gas production from shale formations grows to 6 trillion cubic feet in 2035, more than offsetting declines

in other production. In 2035, shale gas provides 24

percent of the natural gas consumed in the United

States, up from 6 percent in 2008 (Figure 3).

Alternative cases in AEO2010 examine the potential

impacts of more limited shale gas development and of

more extensive development of a larger resource base.

In those cases, overall domestic natural gas production varies from 17.4 trillion cubic feet to 25.9 trillion

U.S. Energy Information Administration / Annual Energy Outlook 2010 3

Executive Summary

1970 1990 2008 2020 2035

0

5

10

15

20

25

Net petroleum imports

History Projections

Natural gas plant liquids

Petroleum supply

Biofuels, including imports

Figure 2. U.S. liquid fuels supply, 1970-2035

(million barrels per day)

1990 2000 2008 2015 2025 2035

0

5

10

15

20

25 History Projections

Net imports

Associated (with oil)

Non-associated offshore

Non-associated onshore

Coalbed methane

Shale gas

Alaska

Figure 3. U.S. natural gas supply, 1990-2035

(trillion cubic feet)
cubic feet in 2035, compared with 23.3 trillion cubic

feet in the Reference case. The wellhead price of natural gas in 2035 ranges from $6.92 per thousand cubic

feet to $9.87 per thousand cubic feet in the alternative

cases, compared with $8.06 per thousand cubic feet in

the Reference case.

There also are uncertainties about the potential role

of natural gas in various sectors of the economy. In

recent years, total natural gas use has been increasing, with a decline in the industrial sector more than

offset by growing use for electricity generation. In

the long run, the use of natural gas for electricity

generation continues growing in the Reference case.

However, over the next few years the combination of

relatively slow growth in total demand for electricity,

strong growth in generation from renewable sources,

and the completion of a number of coal-fired power

plants already under construction limits the potential

for increased use of natural gas in the electric power

sector. The near- to mid-term downturn could be

offset, of course, if policies were enacted that made

the use of coal for electricity generation less attractive, if the recent growth in renewable electricity

slowed, or if policies were enacted to make the use of

natural gas in other sectors, such as transportation,

more attractive.

Increases in energy-related carbon

dioxide emissions slow

The combination of modest growth in energy consumption and increasing reliance on renewable fuels

contributes to slow projected growth in U.S. CO2

emissions. (For purposes of the AEO2010 analysis,

biomass energy consumption is assumed to be CO2

neutral.) In the Reference case, which assumes no

explicit regulations to limit GHG emissions beyond

the recent vehicle GHG standards, CO2 emissions

from energy grow on average by 0.3 percent per year

from 2008 to 2035, or a total of about 9 percent. To

put the numbers in perspective, population growth is

projected to average 0.9 percent per year, overall

economic growth 2.4 percent per year, and growth in

energy use 0.5 percent per year over the same period.

Although total energy-related CO2 emissions increase

from 5,814 million metric tons in 2008 to 6,320

million metric tons in 2035 in the Reference case,

emissions per capita fall by 0.6 percent per year. Most

of the growth in CO2 emissions in the AEO2010

Reference case is accounted for by the electric power

and transportation sectors (Figure 4).

The projections for CO2 emissions are sensitive to

many factors, including economic growth, policies

aimed at stimulating renewable fuel use or

low-carbon power sources, and any policies that may

be enacted to reduce GHG emissions. In the AEO2010

Low and High Economic Growth cases, projections

for total primary energy consumption in 2035 are

104 quadrillion British thermal units (Btu) (9.5 percent below the Reference case) and 127 quadrillion

Btu (10.7 percent above the Reference case), and

projections for energy-related CO2 emissions in 2035

are 5,768 million metric tons (8.7 percent below the

Reference case) and 6,865 million metric tons (8.6

percent above the Reference case), respectively.

4 U.S. Energy Information Administration / Annual Energy Outlook 2010

Executive Summary

2035

2,634 (42%)

Electric

power

Buildings and

industrial

1,571 (25%)

Transportation

2,115 (33%)

2008

2,359 (41%)

Electric

power

Buildings and

industrial

1,530 (26%)

Transportation

1,925 (33%)

6,320

million

metric

tons

8.7% growth

0.3% per year

5,814

million

metric

tons

Figure 4. U.S. energy-related carbon dioxide

emissions, 2008 and 2035
Legislation and

Regulations
Introduction

The Reference case projections in AEO2010 generally

assume that current laws and regulations affecting

the energy sector remain unchanged throughout the

projection period (including the implication that laws

which include sunset dates do, in fact, become ineffective at the time of those sunset dates). The potential

impacts of pending or proposed legislation, regulations, and standards—or of sections of legislation that

have been enacted but that require regulations for

which the implementing agency will exercise major

discretion, or require appropriation of funds that are

not provided or specified in the legislation itself—are

not reflected in the Reference case projections. However, sensitivity cases that incorporate alternative

assumptions about the future of existing policies subject to periodic updates also are included. The Federal

and State laws and regulations included in AEO2010

are based on those in effect as of the end of October

2009. In addition, at the request of the Administration and Congress, EIA has regularly examined the

potential implications of proposed legislation in Service Reports (see box on page 7).

Examples of Federal and State legislation that has

been enacted over the past few years and incorporated in earlier Annual Energy Outlooks (AEOs)

include:

• The provisions of the ARRA (Public Law 111-5),

enacted in mid-February 2009 [1]. ARRA provides

significant new Federal funding, loan guarantees,

and tax credits to stimulate investments in energy

efficiency and renewable energy (see details

below).

• The tax provisions of the Energy Improvement

and Extension Act of 2008 (EIEA2008), signed

into law on October 3, 2008, as part of Public Law

110-343, the Emergency Economic Stabilization

Act of 2008 [2], which extends the residential

and business tax credits for renewable energy;

removes the cap on the tax credit for purchases

of residential solar photovoltaic (PV) installations; increases the tax credit for residential

ground-source heat pumps; adds a business

investment tax credit (ITC) for combined heat

and power (CHP), small wind systems, and commercial ground-source heat pumps; creates a tax

credit for the purchase of new, qualified, plug-in

electric drive motor vehicles; extends the income

and excise tax credits for biodiesel and renewable

diesel to the end of 2009 and increases the amount

of the tax credit for biodiesel and renewable diesel

produced from recycled feedstock; establishes a

tax credit for the production of liquid petroleum

gas, LNG, compressed natural gas (CNG), and

aviation fuels from biomass; creates an additional

tax credit for the elimination of CO2 emissions

that would otherwise be released into the atmosphere in enhanced oil recovery (EOR) and nonEOR operations; extends and modifies key renewable energy tax provisions that were scheduled to

expire at the end of 2008, including PTCs for

wind, geothermal, landfill gas, and certain biomass and hydroelectric facilities; and expands the

PTC-eligible technologies to include plants that

use energy from offshore, tidal, or river currents

(in-stream turbines), ocean waves, or ocean thermal gradients.

• The biofuel provisions of the Food, Conservation,

and Energy Act of 2008 (Public Law 110-234) [3],

which reduce the existing ethanol excise tax credit

in the first year after U.S. ethanol production and

imports exceed 7.5 billion gallons and add an income tax credit for the production of cellulosic

biofuels.

• The provisions of the Energy Independence and

Security Act of 2007 (EISA2007, Public Law 110-

140), including: an RFS requiring the use of

36 billion gallons of biofuels by 2022; an attribute-based minimum CAFE standard for cars and

trucks of 35 miles per gallon (mpg) by 2020; a program of CAFE credit trading and transfer; various

appliance efficiency standards; a lighting efficiency standard starting in 2012; and a number of

other provisions related to industrial waste heat

or natural gas efficiency, energy use in Federal

buildings, weatherization assistance, and manufactured housing.

• State RPS programs, representing laws and regulations of 30 States and the District of Columbia

that require renewable electricity generation.

Examples of recent Federal and State regulations, as

well as earlier provisions that have been affected

by court decisions that have been considered in earlier AEOs, include the following:

• Decision by the U.S. Court of Appeals for the

District of Columbia Circuit on December 23,

2008, to remand, but not vacate, the Clean Air

Interstate Rule (CAIR) [4]. The decision, which

overrides a previous decision by the D.C. Circuit

Court on February 8, 2008, to vacate and remand

6 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations
CAIR, allows CAIR to remain in effect, and provides time for the U.S. Environmental Protection

Agency (EPA) to modify CAIR to address the objections raised by the Court in its earlier decision

while leaving the rule in place (see details below).

• Decisions by the D.C. Circuit Court on February

8, 2008, to vacate and remand the Clean Air

Mercury Rule (CAMR).

• Release by the California Air Resources Board

(CARB) in October 2008 of updated regulations

for reformulated gasoline (RFG) that went into effect on August 29, 2008, allowing a 10-percent

ethanol blend, by volume, in gasoline.

Detailed information on more recent Federal and

State legislative and regulatory developments that

are considered in AEO2010 is provided below.

American Recovery and Reinvestment

Act of 2009: Summary of provisions

ARRA, signed into law in mid-February 2009, provides significant new Federal funding, loan guarantees, and tax credits to stimulate investments in

energy efficiency and renewable energy. The provisions of ARRA were incorporated initially as part

of a revision to the AEO2009 Reference case that

was released in April 2009 [5], and they also are included in AEO2010. However, provisions that require

U.S. Energy Information Administration / Annual Energy Outlook 2010 7

Legislation and Regulations

EIA Service Reports released since January 2009

The table below summarizes EIA Service Reports completed in 2009. Those reports, and others that were

completed before 2009, can be found on the EIA web site at www.eia.doe.gov/oiaf/service_rpts.htm.

Title

Date of

release Requestor

Availability on

EIA web site Focus of analysis

Energy Market and

Economic Impacts of

H.R. 2454, the

American Clean Energy

and Security Act of

2009

August

2009

Congressmen Henry

Waxman and Edward

Markey

www.eia.gov/oiaf/

servicerpt/hr2454/

index.html

Analysis of H.R. 2454, the American Clean

Energy and Security Act of 2009 (ACESA).

ACESA, as passed by the House of

Representatives on June 26, 2009, is a bill that

regulates emissions of greenhouse gases through

market-based mechanisms, efficiency programs,

and economic incentives.

Impacts of a 25-Percent

Renewable Electricity

Standard as Proposed

in the American Clean

Energy and Security

Act Discussion

April 2009 Congressman Edward

Markey

www.eia.doe.gov/

oiaf/servicerpt/

acesa/pdf/

sroiaf(2009)04.pdf

Analysis of a 25-percent Federal renewable

electricity standard (RES). The RES proposal

analyzed in this report is included in the

discussion draft of broader legislation—ACESA,

issued on the Energy and Commerce Committee

web site at the end of March 2009. The analysis

presented in this report starts from an updated

version of the Annual Energy Outlook 2009

(AEO2009) Reference case, which reflects the

projected impacts of the ARRA, enacted in

February 2009, and revised economic

assumptions.

An Updated Annual

Energy Outlook 2009

Reference Case

Reflecting Provisions of

the American Recovery

and Reinvestment Act

and Recent Changes in

the Economic Outlook

April 2009 NA www.eia.doe.gov/

oiaf/servicerpt/

stimulus/pdf/

sroiaf(2009)03.pdf

Updates the AEO2009 Reference case released in

December 2008, based on recently enacted

legislation and the changing macroeconomic

environment.

Light-Duty Diesel

Vehicles: Efficiency

and Emissions

Attributes and Market

Issues

February

2009

Senator Jeff Sessions www.eia.doe.gov/

oiaf/servicerpt/

lightduty/pdf/

sroiaf(2009)02.pdf

Analysis of the environmental and energy

efficiency attributes of light-duty diesel vehicles.

Specifically, the inquiry asked for a comparison of

the characteristics of diesel-fueled vehicles with

those of similar gasoline-fueled, E85-fueled, and

hybrid vehicles, as well as a discussion of any

technical, economic, regulatory, or other obstacles

to increasing the use of diesel-fueled vehicles in

the United States.

State Energy Data

Needs Assessment

January

2009

Required by EISA2007 www.eia.doe.gov/

oiaf/servicerpt/

energydata/pdf/

sremeu(2009)01.pdf

Response to EISA2007 Section 805(d), requiring

EIA to assess State-level energy data needs and

submit to Congress a plan to address those needs.
funding appropriations to be implemented, whose impact is highly uncertain, or that require further specification by Federal agencies or Congress, are not

included. Moreover, AEO2010 does not include any

provision that addresses a level of detail beyond that

modeled in NEMS.

This section provides a summary of the ARRA provisions and highlights those specific provisions incorporated in AEO2010, including:

• Weatherization and assisted housing programs

• Energy efficiency and conservation block grant

programs

• State energy programs

• Tax credits for plug-in hybrid electric vehicles

(PHEVs)

• Tax credits for electric vehicles

• Updated tax credits for renewables

• Loan guarantees for renewables and biofuels

• Support for carbon capture and storage (CCS)

• Smart grid expenditures.

The following discussion provides a summary of the

ARRA provisions included in AEO2010 and some of

the provisions that could be included if more complete

information were available about their funding and

implementation. This discussion is not a complete

summary of all the sections of ARRA.

ARRA end-use demand provisions

Residential and commercial buildings

Many of the provisions of ARRA target energy

efficiency and renewable energy use associated with

residential and commercial buildings. Federal funding is provided to assist State and local governments

in implementing energy efficiency programs; to

improve energy efficiency and renewable energy use

in Federal buildings and facilities; and to encourage

renovations of schools and college facilities. ARRA

also includes provisions that expand and revise tax

credits for renewable and energy-efficient property

purchased and installed in residential and commercial buildings.

Weatherization, assisted housing, and energy

efficiency and conservation block grants

ARRA Title IV, “Energy and Water Development,”

allocates a total of $9.45 billion to weatherize and/or

increase the energy efficiency of low-income housing

and assist local governments in implementing energy

efficiency programs, with a total of $4.75 billion

specifically for weatherization. The regional impacts

of weatherization funds are estimated on the basis

of DOE’s State allocation formula [6] and Oak

Ridge National Laboratory’s weatherization impact

analysis. Local governments also are allowed, and

assumed, to use some of the Conservation Block

Grant funding for PV and wind turbine installations.

State energy programs

ARRA Title IV, “Energy and Water Development,”

allocates $3.1 billion for States to implement or

enhance energy efficiency programs. Although the

money can be spent on a variety of programs, Section

410 specifically mentions the adoption of building

codes, citing the International Energy Conservation

Code (IECC) 2009. To account for the impact of the

funding in AEO2010, it is assumed that States will

adopt and enforce the IECC 2006 code by 2011 and

the IECC 2009 code by 2018. Likewise, States are

assumed to adopt and enforce the ASHRAE 90.1-2007

standard for nonresidential construction by 2018.

States and local governments also are assumed to

use the 10-year Treasury Note rate (3.7 percent in

2011) when purchasing energy-using equipment for

government-owned facilities during years when

ARRA funding is available. It is also assumed that

part of the funding for State energy programs will be

used for PV and wind turbine installations.

Federal buildings and green schools

ARRA Division A allocates $4.5 billion to the U.S.

General Services Administration (GSA) for measures

to convert GSA facilities to high-performance green

buildings, $2.3 billion for military construction, and

$4.3 billion for U.S. Department of Defense (DOD)

energy efficiency projects and modernization of facilities. Additional DOD funding is provided for energy

efficiency technology demonstrations and research.

Under the various titles included in ARRA, money is

also allocated to virtually every major Federal agency

for construction, repair, and/or modernization of

facilities. To account for the funding in AEO2010,

schools and Federal facilities are assumed to use the

10-year Treasury Note rate as a hurdle rate for new

construction and replacement of equipment in

years when ARRA funding is available. The 10-year

Treasury Note rate already was assumed for new construction of Federal facilities, based on earlier legislation. ARRA funding also broadens its use to include

8 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations
replacement equipment as well. Photovoltaic installations, wind turbines, and fuel cells also are added

where specified in expenditure plans.

Updated tax credits for renewables and

energy-efficient technologies

ARRA Division B expands and revises tax credits for

the purchase of renewable and energy-efficient property purchased and installed in residential and commercial buildings. Section 1103 removes the cap on

the 30-percent business ITC for small wind property

that was established in EIEA2008. Sections 1121 and

1122 extend by 1 year the tax credits for energyefficient nonbusiness property while increasing the

tax-deductible amount to $1,500. For renewable technologies, such as geothermal heat pumps and solar

water heaters, the tax deductible amount is unlimited, up to 30 percent of the cost.

Transportation sector

ARRA contains several changes to the PHEV tax

credit originally included in EIEA2008. Title I, “Tax

Provisions,” Section 1141, allows a $2,500 tax credit

for the purchase of qualified PHEVs with battery

capacity of at least 4 kilowatthours. Starting at a

battery capacity of 5 kilowatthours, PHEVs earn an

additional battery credit of $417 per kilowatthour, up

to a maximum of $5,000. The maximum total PHEV

credit that can be earned is capped at $7,500 per

vehicle.

The PHEV tax credit eligibility and phaseout are tied

to the sales of individual vehicle manufacturers. The

credits are phased out once a manufacturer’s cumulative sales of qualified vehicles reach 200,000. The

phaseout period begins two calendar quarters after

the first date in which a manufacturer’s sales reach

the cumulative sales maximum after December 31,

2009. The credit is reduced to 50 percent of its total

value for the first two calendar quarters of the

phaseout period, and then to 25 percent for the third

and forth calendar quarters, before being phased out

entirely thereafter. The credit applies to vehicles with

gross vehicle weight rating (GVWR) less than 14,000

pounds. To capture the phaseout period in AEO2010,

the PHEV tax credit has been incorporated across

representative manufacturer groups.

ARRA Title I, “Tax Provisions,” Section 1142, also

allows a tax credit of 10 percent against the cost of a

qualified electric vehicle with a battery capacity of at

least 4 kilowatthours, subject to the same phaseout

schedule applied to PHEVs. The new electric vehicle

tax credit has also been incorporated in AEO2010 by

manufacturer group.

ARRA electricity provisions

ARRA establishes Federal loan guarantees for certain

renewable fuel, biofuel, and electricity transmission

projects. The provisions for renewable projects are

included in the electricity modeling for AEO2010.

ARRA also extends and modifies Federal tax credit

incentives for new renewable generation capacity.

The NEMS electricity module also represents the

funding provided in ARRA for smart grid demonstration projects.

Extension of renewable production and

investment tax credits

ARRA Division B, Title 1, “Tax Provisions,” extends

and significantly modifies the Federal tax credits for

new renewable generation capacity. Before enactment of ARRA, wind, geothermal, landfill gas, and

certain hydroelectric and biomass technologies were

eligible to receive a PTC of up to 2.1 cents per

kilowatthour generated over the first 10 years of

plant operation [7]; wind was eligible to receive the

PTC for plants constructed before January 1, 2010;

and other eligible plants received the PTC if construction was completed before January 1, 2011. ARRA

Section 1101 extends those in-service deadlines to

January 1, 2013, for wind and January 1, 2014, for

other eligible technologies.

In addition, under Section 1102, ARRA allows projects that are eligible for the PTC to instead receive a

30-percent ITC on plant investment costs. Section

1603 also allows the owners of projects choosing the

ITC to receive the payment in the form of an after-tax

grant of equivalent value rather than as a tax credit,

which presumably will allow project owners with limited tax liabilities to claim the full value of the credit.

Solar technologies are not eligible for the ARRA PTC,

but EIEA2008 established a 30-percent ITC for solar

projects built through 2016, and the Energy Policy

Act of 1992 provided a permanent 10-percent ITC.

AEO2010 incorporates the ARRA provisions cited

above and generally assumes that renewable electricity projects will claim the more favorable tax credit

or grant option available to them during the eligibility period. Provisions extending tax credits for marine-based technologies are not reflected in AEO2010,

U.S. Energy Information Administration / Annual Energy Outlook 2010 9

Legislation and Regulations
because EIA assumes that those technologies will not

be in significant commercial use by 2035. ARRA also

extends funding for Clean Renewable Energy Bonds

(CREBs) used to fund renewable energy projects at

publicly owned utilities that do not pay taxes and cannot take advantage of tax credits. Because AEO2010

assumes that all new renewable capacity is developed

and owned by taxable entities, CREBs are not included in NEMS.

Loan guarantees for renewables and

transmission projects

ARRA Title IV, “Energy and Water Development,”

Section 406, provides $6 billion to pay the cost of

guarantees for loans authorized by the Energy Policy

Act of 2005 (EPACT2005). The purpose of the loan

guarantees is to stimulate the deployment of

conventional renewable technologies, conventional

transmission technologies, and innovative biofuels

technologies. To qualify, eligible projects must be

under construction by September 30, 2011, meaning

that projects with a long-term construction horizon

are unlikely to qualify. The face value of the loans

that may be guaranteed by the appropriation will

depend on the subsidy costs assigned to the projects

eventually selected. For example, if the average subsidy cost were 10 percent of the face value of the loans,

the $6 billion appropriated would support loan guarantees on $60 billion of debt financing. The Section

406 provision is represented in AEO2010 by a lower

cost of financing (by 2 percentage points) for all

eligible renewable projects brought on line by 2015.

The 2015 date, 4 years after the September 30, 2011,

cutoff date for start of construction, was chosen to

allow for the construction period associated with

most renewable generating technologies.

Smart grid expenditures

ARRA Title IV, “Energy and Water Development,”

Section 405, provides $4.5 billion to modernize, secure, and improve the reliability of electric energy

and storage infrastructure and to develop a Smart

Grid. While somewhat difficult to define, smart grid

technologies generally include a wide array of storage, measurement, communications, and control

equipment employed throughout the generation,

transmission, and distribution system to enable

real-time monitoring of the production, flow, and use

of power from generator to consumer. Among other

things, smart grid technologies, once deployed, are

expected to enable more efficient use of the transmission and distribution grid and lower line losses,

facilitate greater use of renewables, and provide

information to utilities and their customers that will

lead to greater investment in energy efficiency and reduction of peak load demands. The funds provided

will not cover the cost of widespread implementation

of smart grid technologies but could stimulate more

rapid investment than otherwise would occur.

Several changes were made throughout NEMS to

represent the impacts of the smart grid funding

provided in ARRA. For the electricity module, it was

assumed that line losses would decrease slightly, peak

loads would fall as customers shifted their usage

patterns, and customers would be more responsive to

price signals. Historically, line losses (expressed as

the percentage of electricity lost in transmission)

have fallen as utilities have made investments to expand the grid or replace aging or failing equipment.

That trend was incorporated in previous AEO Reference cases. After passage of ARRA, the time period for

improvements was extended, allowing for greater

declines in line losses. AEO2010 assumes that line

losses will be reduced from roughly 6.9 percent in

2008 to 5.3 percent in 2025.

Smart grid technologies also have the potential to

reduce peak demand through the increased deployment of demand response programs. AEO2010

assumes that efforts stimulated by Federal expenditures on smart grid technologies will reduce peak

demands in 2035 by 3 percent from what they otherwise would be. Because the load shifted to off-peak

hours is not eliminated, net energy consumed

remains largely constant.

It is also assumed that increased investment in smart

grid technologies—particularly, smart meters on

buildings and homes—will make consumers more responsive to changes in electricity prices. Accordingly,

the price elasticity of demand for residential and commercial electricity is increased for certain uses.

Coal

ARRA Title IV, “Energy and Water Development,”

provides $3.4 billion for additional research and

development of fossil energy technologies, including

$800 million to fund projects under the Clean Coal

Power Initiative program focusing on capture and

sequestration of GHGs [8]. In July 2009, a total of

$408 million was allocated to two projects—the Basin

Electric Power Cooperative’s Antelope Valley Station

in North Dakota and the Hydrogen Energy Project in California—to demonstrate the capability to

10 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations
capture 3 million tons of CO2 per year. In December

2009, two additional project awards were announced

through the Clean Coal Power Initiative program,

which will be funded in part through ARRA. The projects include American Electric Power’s Mountaineer

plant in West Virginia (235-megawatt flue gas

stream) and a new plant to be built by Summit Texas

Clean Energy in Texas. To reflect the impact of this

provision, the AEO2010 Reference case assumes that

an additional 1 gigawatt of coal-fired capacity with

CCS will be built by 2017.

Other ARRA provisions

Additional appropriations under ARRA Title IV, totaling $2.6 billion, are not included in AEO2010, because the activities funded have only indirect or

unknown impacts on energy use, or because insufficient program detail has been provided. The additional appropriations include $1 billion for research

and development projects to be established by the

Secretary of Energy; $80 million for geologic sequestration projects covering site characterization, training, research grants, and other administrative costs;

and $1.52 billion for industrial carbon capture and

energy efficiency projects or those developing innovative uses for CO2. As of October 2009, $112 million of

the $1.52 billion had been allocated to 14 industrial

projects demonstrating various combinations of carbon capture technologies, CO2 transport activities,

sequestration, and EOR.

Liquid fuels taxes and tax credits

This section provides a review of the treatment of

Federal fuels taxes and tax credits in AEO2010.

Excise taxes on highway fuel

The treatment of Federal highway fuel taxes remains

unchanged from the previous year’s AEO. Gasoline is

taxed at 18.4 cents per gallon, diesel fuel at 24.4 cents

per gallon, and jet fuel at 4.4 cents per gallon, consistent with current laws and regulations. Consistent

with Federal budgeting procedures, which dictate

that excise taxes dedicated to a trust fund, if expiring,

are assumed to be extended at current rates, these

taxes are maintained at their present levels, without

adjustment for inflation, throughout the projection

[9]. State fuel taxes are calculated on the basis of a

volume-weighted average for diesel, gasoline, and

jet fuels. The State fuel taxes were updated as of

July 2009 [10] and are held constant in real terms

over the projection period, consistent with historical

experience.

Biofuels tax credits and tariffs

No changes have been made in the treatment of

biofuels taxes and credits in AEO2010. The existing

ethanol excise tax credit of $0.45 per gallon, as specified in the Food, Conservation, and Energy Act of

2008 [11], is still scheduled to expire at the end of

2010. In addition, the PTC of $1.01 per gallon for

cellulosic biofuels [12], also specified in the Food,

Conservation, and Energy Act of 2008, remains set to

expire on January 1, 2013.

The $1.00-per-gallon excise tax credit for biodiesel

established in the Emergency Economic Stabilization

Act of 2008 [13] expired on December 31, 2009. The

credit applies to biodiesel made from recycled vegetable oils or recycled animals fats, as well as renewable

diesel (e.g., diesel derived from biomass).

Low-carbon fuel standard

In April 2009, the CARB passed the world’s first

low-carbon fuel standard (LCFS), which is scheduled

to go into effect on January 1, 2011 [14]. Because the

rules for the LCFS had not been finalized as of October 2009, they are not included in AEO2010. The regulation aims to reduce the carbon content of

transportation fuels sold in California by 10 percent

in 2020. The reductions will be applied to gasoline and

diesel fuel pools, as well as a number of their substitutes as defined by CARB’s eligible fuel pathways

[15], with providers of transportation fuels being the

regulated parties. Regulated parties will be able to

meet the LCFS by using a combination of fuel blends,

alternative fuels, and LCFS credits. By the end of

2010, the baseline carbon intensities for gasoline,

diesel fuel, and their substitutes will be calculated

and finalized in a full-life-cycle fuel analysis, which

will consider indirect land-use effects for certain

biofuels.

CAFE standards

Pursuant to the President’s announcement of a

National Fuel Efficiency Policy, the National Highway Traffic Safety Administration (NHTSA) and the

EPA have promulgated nationally coordinated standards for tailpipe CO2-equivalent emissions and fuel

economy for light-duty vehicles (LDVs) [16], which

includes both passenger cars and light-duty trucks. In

the joint rulemaking, EPA is enacting CO2-equivalent emissions standards under the Clean Air Act

(CAA), and NHTSA is enacting companion CAFE

standards under the Energy Policy and Conservation

Act, as amended by EISA2007.

U.S. Energy Information Administration / Annual Energy Outlook 2010 11

Legislation and Regulations
The initial harmonized standards will affect model

year (MY) 2012 vehicles, and compliance requirements will increase in stringency through MY 2016,

building on NHTSA’s enacted CAFE standard for

MY 2011. NHTSA has estimated the impact of the

new CAFE standards and has projected that the

proposed fleet-wide standards for LDVs will increase

fuel economy from 27.3 mpg in MY 2011 to 34.1 mpg

in MY 2016, an average annual increase of 4.3 percent. EPA projects a fleet-wide reduction in CO2-

equivalent emissions from 295 grams per mile for MY

2011 to 250 grams per mile for MY 2016 (Table 1).

Although the two separate standards were issued

jointly, there are important differences between

them. In lieu of increasing vehicle fuel economy,

EPA’s vehicle CO2-equivalent emissions standard

allows manufacturers to generate CO2-equivalent

credits by reducing emissions of hydrofluorocarbons

by improving air conditioner systems and alternative

fuel use capabilities. NHTSA estimates that adoption

of cost-effective technologies will enable manufacturers to achieve a fleet-wide minimum fuel economy

requirement of 34.1 mpg by 2016. Because the CO2-

equivalent standards cover all vehicle emissions related to GHGs, manufacturers who do not implement

technologies that address non-fuel-related emissions

will have to comply with a fuel economy standard of

35.5 mpg by 2016.

The fuel standards use an attribute-based methodology to determine the minimum fuel economy requirements and CO2-equivalent emissions standards for

vehicles based on footprint, defined as the wheelbase

(the distance from the center of the front axle to the

center of the rear axle) times the average track width

(the distance between the center lines of the tires) in

square feet.

For example, a passenger car with a footprint of 44

square feet in MY 2016 will face a fuel economy standard of 38.8 mpg and a CO2-equivalent emission standard of 218.6 grams per mile. Standards are revised in

subsequent model years to ensure improvement in

fuel economy and a reduction in CO2-equivalent emissions over time. Separate mathematical functions are

established for passenger cars and light trucks, reflecting their different design capabilities (Figures 5

and 6). As required by EISA2007, AEO2010 assumes

that CAFE standards will be increased, so that the

combined fuel economy of new LDVs will achieve the

required minimum of 35 mpg by 2020.

Manufacturer compliance is determined for CAFE by

a harmonically weighted average of sales of cars and

light trucks and for CO2-equivalent emissions by a

12 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations

Model year Passenger car Light truck Combined

NHTSA CAFE standard (miles per gallon)

2012 33.3 25.4 29.7

2013 34.2 26.0 30.5

2014 34.9 26.6 31.3

2015 36.2 27.5 32.6

2016 37.5 28.8 34.1

EPA CO2-equivalent emissions standard (grams per mile)

2012 263 346 295

2013 256 337 286

2014 247 326 276

2015 236 312 263

2016 225 298 250

Table 1. Estimated average fleet-wide fuel economy

and CO2-equivalent emissions compliance levels,

model years 2012-2016

39 41 44 48 52 56 60 64 68

0

10

20

30

40

50

Vehicle footprint

Emissions

CAFE

Figure 5. Projected average fleet-wide fuel

economy and CO2-equivalent emissions compliance

levels for passenger cars, model year 2016

(miles per gallon equivalent)

39 41 44 48 52 56 60 64 68

0

10

20

30

40

50

Vehicle footprint

Emissions

CAFE

Figure 6. Projected average fleet-wide fuel

economy and CO2-equivalent emissions compliance

levels for light trucks, model year 2016

(miles per gallon equivalent)
production-weighted average compliance across each

manufacturer’s fleet. Individual manufacturers face

different CAFE and CO2 equivalent compliance stringencies to the extent that their sales and production

distributions differ by footprint.

The NHTSA-EPA standards also include flexibility

provisions for compliance by individual manufacturers, such as: (1) allowing credit trading among manufacturers who exceed their standards and those who

do not; (2) allowing credit transfers among vehicle

fleets for a single manufacturer; (3) allowing manufacturers to “carry forward” credits earned from exceeding the standards in earlier model years and

“carry back” credits earned in later years to meet

shortfalls from earlier model years; and (4) allowing

manufacturers to earn CAFE credits by producing

AFVs, with credits for flex-fuel vehicles (FFVs) being

phased out by MY 2019, and earn CO2-equivalent

credits for FFVs until MY 2015 unless the manufacturer can prove that the vehicle is actually using an

alternative fuel. NHTSA and the EPA also differ in

their compliance flexibility provisions, such as EPA’s

air conditioner credits and a temporary lead-time allowance for manufactures who sell fewer than

400,000 vehicles in MY 2009.

The flexibility provisions do not, however, allow

manufacturers to deviate significantly from their

annual fuel economy targets. NHTSA retains a

required minimum fuel economy level for passenger

cars. Before any credit can be applied by a manufacturer, its passenger car fleet for the model year must

meet an average fuel economy standard—either

27.5 mpg or 92 percent of the CAFE for the industry-wide combined fleet of domestic and nondomestic

passenger cars for that model year, whichever is

higher. Based on NHTSA’s current market projection, its estimate of the minimum standard is

34.8 mpg in 2016. It is important to note that EPA

and NHTSA’s joint proposal is subject to change in

future rulemakings. Although the final CAFE standards have been enacted, only the proposed CAFE

standards and compliance schedule were available

when AEO2010 was finalized. At that time, the

proposal offered the best available insight into future

regulations implementing EISA2007 CAFE requirements through 2016. AEO2010 increases the MY

2016 fuel economy standards to ensure that the

EISA2007 mandated minimum requirements are met

through 2020.

New EPA guidelines for review of surface

coal mining operations in Appalachia

On April 1, 2010, the EPA issued a set of new guidelines to several of its Regional offices regarding

the compliance of surface coal mining operations

in Appalachia with the provisions of the Clean Water

Act (CWA), the National Environmental Policy Act,

and the environmental justice Executive Order (E.O.

12898). The stated purpose of the guidance was to explain more fully the approach that the EPA will be following in permit reviews, and to provide additional

assurance that its Regional offices use clear, consistent, and science-based standards in reviewing the

permits. Although the new guidelines go into effect

immediately, they will be subjected to review both by

the public and by the EPA’s Science Advisory Board,

with a set of final guidelines to be issued no later than

April 1, 2011.

Issuance of the new EPA guidelines is related primarily to the ongoing controversy over use of the mountaintop removal method at a number of surface coal

mining operations in Central Appalachia—primarily

in southern West Virginia and eastern Kentucky.

Although the guidelines propose a more rigorous

review for all new surface coal mines in Appalachia,

the EPA indicates that the practice of valley fills,

primarily associated with the mountaintop removal

method, is the aspect of Appalachian coal mining that

will be most scrutinized. In particular, the EPA

points to new scientific evidence that dissolved solids

in drainage from existing valley fills in Central Appalachia are adversely affecting downstream aquatic

systems.

Although the proposed use of valley fills at mining

sites will not necessarily preclude the issuance of

permits for surface mines under CWA Sections 402

and 404, the EPA guidelines recommend that all practicable efforts be made to minimize their use. Section

402 of the CWA pertains to the issuance of National

Pollution Discharge Elimination System permits.

Section 404 relates to the issuance of permits for the

discharge of dredge or fill material into the waters of

the United States, including wetlands. Issuance of

Section 404 permits comes under the authority of the

U.S. Army Corps of Engineers, but is subject to EPA

oversight.

Two recent actions by the EPA related to its review

of Section 404 permits for proposed mountaintop

U.S. Energy Information Administration / Annual Energy Outlook 2010 13

Legislation and Regulations
mining operations in West Virginia indicate the

agency’s heightened concern with regard to

valley fills. In January 2010, the EPA announced

its approval for the issuance of a Section 404 permit

for Patriot Coal’s proposed Hobet 45 mountaintop

mining operation. The EPA indicated that the

company was able to eliminate the need for any valley

fills and, as a result, reduce the estimated adverse

downstream impact by 50 percent. In contrast, in

March 2010, the EPA was not able to extend approval

of a Section 404 permit for Arch Coal Company’s proposed Spruce No. 1 mountaintop mining operation,

because the mine plan proposed the burial of 7.5 miles

of healthy headwater streams under the spoil of six

separate valley fills.

The EPA’s new guidelines for surface coal mining

operations are not represented in the AEO2010 projections, because they were issued after the cutoff

date for model simulations. The likely impact of representing the more intensive reviews of new mining

operations would be higher projected prices and

lower production for surface-mined coal from Central

Appalachia. In the AEO2010 Reference case, coal production at surface mines in Central Appalachia is

projected to decline from 115 million tons in 2008 to

71 million tons in 2020 and 63 million tons in 2035.

Clean Air Interstate Rule: Changes and

modeling in AEO2010

On December 23, 2008, the D.C. Circuit Court remanded but did not vacate CAIR [17], overriding

its previous decision on February 8, 2008, to remand

and vacate CAIR. The December decision, which

is reflected in AEO2010, allows CAIR to remain in

effect, providing time for the EPA to modify the rule

in order to address objections raised by the Court in

its earlier decision. A similar rule, referred to as the

CAMR, which was to set up a cap-and-trade system

for reducing mercury emissions by approximately 70

percent, is not represented in the AEO2010 projections, because it was vacated by the D.C. Circuit

Court in February 2008.

CAIR, which was promulgated by the EPA in 2005,

was designed to achieve further reductions in emissions of sulfur dioxide (SO2) and nitrogen oxides

(NOx) beyond those established in the 1990 CAA

Amendments. The emissions reductions mandated

by the rule were put in place to assist States in meeting their National Ambient Air Quality Standards for

ground-level ozone and particulate matter. The EPA

identified 28 States and the District of Columbia to

participate in the program, because they either were

not meeting the standards themselves or were contributing to emissions in downwind States that were

out of compliance. When fully implemented, CAIR

was designed to cap SO2 emissions at 2.5 million tons

and NOx emissions at 1.3 million tons in the affected

States [18]. States could comply with the limits either

by participating in a cap-and-trade system or by developing their own strategies to achieve their required reduction shares.

The annual NOx emissions trading program developed for CAIR commenced in 2009. SO2 emissions

caps under the rule will take effect in 2010. Meanwhile, the EPA is developing a new CAIR designed to

address the shortcomings identified by the court. The

EPA expects to release a proposal for the replacement

CAIR in May 2010 [19]. There is also a possibility that

legislative action could be taken to develop new

standards, but because the AEO does not anticipate

future laws or regulations, AEO2010 assumes that

the long-term reduction goals of CAIR will be met

through the existing cap-and-trade system specified

in the current rule.

State renewable energy requirements and

goals: Update through 2009

To the extent possible, AEO2010 incorporates the

impacts of State laws requiring the addition of renewable generation or capacity by utilities doing business

in the States. Currently, 30 States and the District

of Columbia have enforceable RPS or similar laws

(Table 2). Under such standards, each State determines its own levels of generation, eligible technologies, and noncompliance penalties. AEO2010 includes

the impacts of all laws in effect as of September 2009

(with the exception of Hawaii, because NEMS provides electricity market projections for the continental United States only).

In the AEO2010 Reference case, States generally

meet their ultimate RPS targets. RPS compliance in

most regions is approximated, because NEMS is not a

State-level model, and each State represents only a

portion of one of the NEMS regions, which are composed of multiple States. Compliance costs in each region are tracked, and the projection for total

renewable generation is checked for consistency with

any State-level cost-control provisions, such as caps

on renewable credit prices, limits on State compliance

funding, or impacts on consumer electricity prices.

14 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations
U.S. Energy Information Administration / Annual Energy Outlook 2010 15

Legislation and Regulations

State Program mandate

AZ Arizona Corporate Commission Decision No. 69127 requires 15 percent of electricity sales to be renewable by 2025, with

interim goals increasing annually. A specific percentage of the target must be from distributed generation. Multiple credits may

be provided to solar generation and in-State manufactured systems.

CA Public Utilities Code Sections 399.11-399.20 mandate that 20 percent of electricity sales must be renewable by 2010. There are

also goals for the longer term. Renewable projects with above-market costs will be funded by supplemental energy payments

from a dedicated fund, possibly limiting renewable generation to less than the 20-percent requirement.

CO House Bill 1281 sets the renewable target for investor-owned utilities at 20 percent by 2020. There is a 10-percent requirement

in the same year for cooperatives and municipals. Moreover, 2 percent of total sales must come from solar power. In-State

generation receives a 25-percent credit premium.

CT Public Act 07-242 mandates a 27-percent renewable sales requirement by 2020, including a 4-percent mandate from higher

efficiency or CHP systems. Of the overall total, 3 percent may be met by waste-to-energy facilities and conventional biomass.

DE Senate Bill 19 required an RPS target of 20 percent of sales by 2019. There is a separate requirement for solar generation

(2 percent of the total), and penalty payments for compliance failure. Solar technologies receive triple credits. Offshore wind

receives 3.5 times the credit amount.

HI Senate Bill 3185 sets the renewable mandate at 20 percent by 2020. All existing renewable facilities are eligible to meet the

target, which has two interim milestones.

IL Public Act 095-0481 created an agency responsible for overseeing the mandate of 25-percent renewable sales by 2025. There are

escalating annual targets, and 75 percent of the requirements must be generated from wind. The plan also includes a cap on the

incremental costs added from renewable penetration. In 2009, the rule was modified to cover sales outside a utility’s home

territory.

IA In 1983, an RPS mandating105 megawatts of renewable energy capacity was adopted. A voluntary goal of 1,000 megawatts of

renewable energy was adopted in 2001.

KS In 2009, House Bill 2369 established a requirement that 20 percent of installed capacity must use renewable resources by 2020.

ME In 2007, Public Law 403 was added to the State’s RPS requirements. The original mandate of 30 percent renewable generation

by 2000 was set below renewable generation at the time. The new law requires a 10-percent increase from the 2006 level of

renewable capacity by 2017, and that level must be maintained in subsequent years. The years leading up to 2017 also have new

capacity milestones. Generation from eligible community-owned facilities counts as 1.1 kilowatthours for every kilowatthour of

actual generation.

MD In April 2008, House Bill 375 revised the preceding RPS to contain a 20-percent target by 2022, including a 2-percent solar

target. H.B. 375 also raised penalty payments for “Tier 1” compliance shortfalls to 4 cents per kilowatthour.

MA The RPS has a goal of a 15-percent renewable share of total sales by 2020. The State also has necessary payments for

compliance shortfalls. As of December 2009, consideration of the eligibility of new biomass facilities was temporarily suspended

while the State studies the issue of the sustainability of biomass resources.

MI Public Act 295 established an RPS that will require 10 percent renewable generation by 2015. Bonus credits are given to solar

energy.

MN Senate Bill 4 created a 30-percent renewable requirement by 2020 for Xcel, the State’s largest supplier, and a 25-percent

requirement by 2025 for other suppliers. Also specified was the creation of a State cap-and-trade program that will assist the

program’s implementation. The 30-percent requirement for Excel consists of 24 percent that must be from wind, 1 percent that

can be from wind or solar, and 5 percent that can be from other resources.

MO In November 2008, Missouri voters approved Proposition C, which mandates a 2-percent renewable energy requirement in

2011, which will increase incrementally to 15 percent of generation in 2021. Bonus credits are given to renewable generation

within the State.

MT House Bill 681, approved in April 2008, expanded the RPS provisions to all suppliers. Initially the law covered only public

utilities. A 15-percent share of sales must be renewable by 2015. The State operates a renewable energy credit market.

NV The State has an escalating renewable target, established in 1997 and revised in 2005 and again in 2009 by Senate Bill 358.

The most recent requirement mandates a 25-percent renewable generation share of sales by 2025. Up to one-quarter of the

25-percent share may be met through efficiency measures. There is also a minimum requirement for photovoltaic systems,

which receive bonus credits.

NH House Bill 873, passed in May 2007, legislated that 23.8 percent of electricity sales must be met by renewables in 2025.

Compliance penalties vary by generation type.

NJ In 2006, the RPS was revised to increase renewable energy targets. Renewable generation is to provide 22.5 percent of sales by

2021, with interim targets. There are different requirements for different technologies, including a 2-percent solar mandate.

NM Senate Bill 418, passed in March 2007, directs investor-owned utilities to derive 20 percent of their sales from renewable

generation by 2020. The renewable portfolio must consist of diversified technologies, with wind and solar each accounting for 20

percent of the target. There is a separate standard of 10 percent by 2020 for cooperatives.

NY The Public Service Commission issued RPS rules in 2005 that call for an increase in renewable electricity sales to 25 percent of

the total by 2013, from the current level of 19 percent. The program is administered and funded by the State.

NC In 2007, Senate Bill 3 created an RPS of 12.5 percent by 2021 for investor-owned utilities. There is also a 10-percent

requirement by 2018 for cooperatives and municipals. Through 2018, 25 percent of the target may be met through efficiency

standards, increasing to 40 percent in later years.

(continued on page 16)

Table 2. Renewable portfolio standards in the 30 States with current mandates
States that have enacted new laws include the

following:

Kansas. House Bill 2369 [20] established a capacity-based renewable electricity goal that requires 20

percent of capacity to be from renewable resources by

2020. In-State renewable capacity resources will

count as 1.1 megawatts of capacity for every megawatt of nameplate capacity. Although other States,

such as Texas and Iowa, have had capacity-based renewable targets before, Kansas specifies the capacity

goal as a fraction of installed capacity rather than as a

fixed quantity of capacity. Most of the RPS programs

included in AEO2010 are based on electricity generation; however, for modeling purposes EIA converted

the capacity targets to approximate generation equivalents, assuming that wind will be the primary compliance resource.

West Virginia. In June 2009, the West Virginia legislation enacted House Bill 103 [21], an “alternative

and renewable energy portfolio standard.” The law

allows certain types of coal or coal-based gases to compete to meet the same target as wind and other renewable resources. Eligible resources must meet 25

percent of electricity sales by 2025. Although other

States have included nonrenewable resources in their

policies, they have a separate “tier” or target schedule

for the fossil resources. Because it lacks a distinct

renewable energy target and presents capacity expansion requirements largely consistent with the

underlying assumptions for AEO2010, the legislation

is not specifically reflected in AEO2010.

States with significant modifications to existing laws

include the following:

Illinois. The Illinois Commerce Commission issued

additional regulations in implementing the existing

Illinois RPS [22] with Order 09-0432 [23] and now

applies the renewable targets to sales outside an energy service provider’s territory, not just to sales by

default service providers.

Maine. With the passage of LD 1075 [24], Maine now

counts generation from eligible community-owned

resources toward meeting the RPS requirements, at a

rate of 1.5 kilowatthours for every kilowatthour of

actual generation.

Massachusetts. On December 3, 2009, the Massachusetts Department of Energy Resources [25] placed

a temporary hold on the consideration of certain new

biomass plants to meet the State’s RPS requirement.

Because the action occurred after the AEO2010 Reference case results were finalized, and because it is a

temporary measure, EIA did not include it in the current projections. Currently, the Massachusetts Department of Energy Resources is studying concerns

that have been raised over the sustainability of biomass resources; future consideration of biomass generation will be based on the results of that study.

16 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations

State Program mandate

OH Senate Bill 221, passed in May 2008, requires 25 percent of electricity sales to be produced from alternative energy resources by

2025, including low-carbon and renewable technologies. One-half of the target must come from renewable sources. Municipals

and cooperatives are exempt.

OR Senate Bill 838 (signed into law in June 2007) required renewable targets of 25 percent by 2025 for large utilities and 5 to 10

percent by 2025 for smaller utilities. Renewable electricity on line after 1995 is considered eligible. Compliance penalty caps

have not yet been determined.

PA The Alternative Energy Portfolio Standard, signed into law in November 2004, has an18-percent requirement by 2020. Most of

the qualifying generation must be renewable, but there is also a provision that allows waste coal resources to receive credits.

RI The Renewable Energy Standard was signed into law in 2004. The program requires that 16 percent of total sales be renewable

by 2019. The interim program targets escalate more rapidly in later years. If the target is not met, a generator must pay an

alternative compliance penalty. State utilities must also procure 90 megawatts of new renewable capacity, including 3

megawatts of solar, by 2014.

TX Senate Bill 20, passed in August 2005, strengthened the State RPS by mandating 5,880 megawatts of renewable capacity by

2015. There is also a target of 500 megawatts of renewable capacity other than wind.

WA In November 2006, Washington voters approved Initiative 937, which specifies that 15 percent of sales from the State’s largest

generators must come from renewable sources by 2020. There is an administrative penalty of 5 cents per kilowatthour for

noncompliance. Generation from any facility that came on line after 1999 is eligible.

WV House Bill 103, passed in June 2009, established a requirement that 25 percent of sales must come from alternative energy

resources by 2025. Alternative energy was defined to include various renewables, along with several different fossil energy

technologies.

WI Senate Bill 459, passed in March 2006, strengthened the State RPS with a requirement that, by 2015, each utility must

generate 10 percent of its electricity from renewable resources, up from the previous requirement of 2.2 percent in 2011. The

renewable share of total generation must be at least 6 percentage points above the average renewable share from 2001 to 2003.

Table 2. Renewable portfolio standards in the 30 States with current mandates (continued)
Minnesota. Among other changes resulting from the

passage of SF 550 [26], Minnesota now allows limited

amounts of solar generation to be included in the

wind-only generation provision applied to the State’s

largest utility. Whereas the prior law [27] required

the largest utility in Minnesota to produce 25 percent

of sales from wind generation and 5 percent from

other eligible resources, now it may produce 24 percent from wind, 1 percent from wind or solar, and 5

percent from other eligible resources.

Nevada. In May 2009, Nevada enacted Senate Bill

358 [28], which increased the renewable electricity

target to 25 percent of sales by 2025, of which 6 percent (1.5 percent of sales) must come from solar.

Rhode Island. In addition to its existing generation-based RPS schedule, with the enactment of

H 5002 [29] Rhode Island will now require utilities to

procure 90 megawatts of new renewable capacity, of

which 3 megawatts must be solar.

Updated State air emissions regulations

Regional Greenhouse Gas Initiative

The Regional Greenhouse Gas Initiative (RGGI) is a

program that includes 10 Northeast States that have

agreed to curtail and reverse growth in their CO2

emissions. The RGGI program includes all electricity

generating units with a capacity of at least 25 megawatts and requires an allowance for each ton of CO2

emitted [30]. The first year of mandatory compliance

was in 2009.

Each participating State was provided a CO2 budget

consisting of a history-based baseline with a cushion

for emissions growth, so that meeting the cap is expected to be relatively easy initially and become more

stringent in subsequent years. The requirements are

expected to cover 95 percent of CO2 emissions from

the region’s electric power sector. Overall, the RGGI

States as a whole must maintain covered emissions

at a level of 188 million tons CO2 for the next 4 years,

after which a mandatory 2.5-percent annual decrease

in CO2 emissions through 2018 is expected to reduce

the total for covered CO2 emissions in the RGGI

States to 10 percent below the initial calculated budget. Although each State was given its own emissions

budget, allowances are auctioned at a uniform price

across the entire region.

To preserve the program’s integrity, several rules

were agreed to by the participating States:

• Auctions are held quarterly and follow a singleround, sealed-bid format.

• Allowances are sold at a uniform price, which is

the highest price of the rejected bids.

• States may hold a small number of allowances for

their own use (however, most have decided to

auction all their allowances).

• Each emitter must buy one allowance for every

ton of CO2 emitted.

• Future allowances are made available for purchase up to 4 years before their official vintage

date, as a way to reduce price volatility.

• A reserve price floor of $1.86 per allowance [31] in

real dollars is in effect for each auction, as a way

to preserve allowance prices in auctions where

demand is low and to avoid collusion among emitters that could threaten a fair market. The floor

price is subject to change at the discretion of

RGGI officials.

• Revenue from the auctions can be spent at the

State’s discretion, but at least 25 percent must go

into a fund that benefits consumers and promotes

low-carbon energy development.

Since the first auction in September 2008, there have

been five subsequent RGGI auctions. At the most recent, in December 2009, 28.6 million allowances were

offered and sold at a clearing price of $2.05 [32].

RGGI’s impact on electricity markets is included in

the AEO2010 Reference case. Its impact on actual

emissions, especially in the early years, is minimal because of its relatively generous emissions budget.

Also, it is difficult to capture the nuances of initiatives

that cover only single States or groups of States that

do not correspond to the regions used in NEMS.

Therefore, EIA estimated generation for the MidAtlantic region and capped emissions from those

facilities. Pennsylvania’s emissions were not restricted, because Pennsylvania is an observing

member and is not participating in the cap-andtrade program or subject to any mandatory emission

reductions.

Western Climate Initiative

The Western Climate Initiative (WCI) [33] is a separate regional GHG emissions reduction program.

Participants include seven U.S. States (Arizona, California, Montana, New Mexico, Oregon, Utah, and

Washington) and four Canadian Provinces (British

U.S. Energy Information Administration / Annual Energy Outlook 2010 17

Legislation and Regulations
Columbia, Manitoba, Ontario, and Quebec), as well as

additional observer States and Provinces in the

United States, Canada, and Mexico. Unlike RGGI, the

WCI and California regulations are not included in

the AEO2010 Reference case, because their rules still

are subject to change.

The initiative seeks to reduce GHG to levels 15 percent below 2005 emissions by 2020. Although the

original plan was to achieve the reductions through

an allowance cap-and-trade program, the current

economic environment and changing political landscape have led some of the States to reevaluate their

participation. Each State must provide legislative

authority for the cap-and-trade system, and currently

only California has the required authority in place.

Consequently, the WCI has recently formed a complementary policy committee that will examine moving

beyond cap and trade to explore issues such as tightening building codes, instituting appliance efficiency

standards, and adopting RPS programs.

The WCI cap-and-trade structure is similar to RGGI

but with some important differences. For example,

the first phase of the program (2012-2015) would not

cover emissions produced by the combustion of fossil

fuels from smaller facilities or mobile sources, but all

fuels would be covered by 2015, including fuels used

in the residential, commercial, industrial, and transportation sectors. All fuels will be regulated at the

point where they enter commerce, which generally is

at a fuel distributor. This may vary, however, and the

exact point will be determined before 2015.

The 2015 fuel cap is an expansion in scope over the

first phase, which applies only to facilities emitting

more than 25,000 CO2-equivalent metric tons per

year. Although the second phase covers fuels at the

distributor level, the first phase regulates the larger,

stationary facilities at the emissions source. The WCI

recommends that States begin mandatory emissions

monitoring this year, so that reporting can begin in

2011. As of January 2010, Arizona and Montana had

not committed to the WCI reporting goals.

Another distinction between RGGI and WCI is that

the latter would cover emissions of nitrous oxide,

methane, hydrofluorocarbons, perfluorocarbons, and

sulfur hexafluoride in addition to CO2. Emissions of

the additional gases would be measured in terms of

their CO2-equivalent global warming potentials, and

allowances would be issued accordingly. WCI documents estimate that 90 percent of the region’s GHG

emissions would be subject to regulation after combustion fuels are included in 2015.

As noted above, California’s Assembly Bill (A.B.) 32

gives the CARB authority to regulate GHG emissions

and reduce them to 1990 levels by 2020. The Board recently released its draft regulations, which were open

to comment until January 2010 [34]. A public report

is expected to be issued in spring 2010, and a final version is due to be released in fall 2010. The State will

use a cap-and-trade program to cover 85 percent of its

GHG emissions— equivalent to covering the 600 largest stationary emissions sources as well as suppliers

of residential, commercial, industrial, and transportation fuels. Imported power also is subject to the

regulations.

Currently, three compliance periods are proposed:

2012-2014, 2015-2017, and 2018-2020. The first period will cover electricity generation and industrial

sources emitting more than 25,000 metric tons CO2

equivalent per year. The second period will begin a

phase-in of smaller industrial sources and fuels. The

third period will have a lower GHG ceiling that will

extend beyond 2020. It is important to note, however,

that this is tentative, and the compliance period may

be shortened to one year rather than the current

three. As of January 2010, the GHG caps for each

period had not been met.

Midwestern Greenhouse Gas Reduction Accord

The Midwestern Greenhouse Gas Reduction Accord

[35] is another regional initiative that seeks to curtail

emissions. Six States (Illinois, Iowa, Kansas, Michigan, Minnesota, and Wisconsin) and one Canadian

province (Manitoba) are members, and there are four

additional observer States. Its advisory group released a draft of final recommendations in June 2009

[36]. The program is similar in structure to the WCI,

and it seeks a 20-percent reduction from 2005 GHG

emission levels by 2020 and an 80-percent reduction

by 2050.

Although its final recommendations strongly urge

Federal action, the committee has stated that it will

proceed with a regional cap-and-trade system in the

absence of Federal legislation. Finalized rules for the

Accord have been delayed and are expected to be released sometime in 2010. The draft rules for the Midwestern Greenhouse Gas Reduction Accord are

detailed [37], but because they are preliminary they

are not included in AEO2010.

18 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations
Endnotes for Legislation and Regulations

U.S. Energy Information Administration / Annual Energy Outlook 2010 19

Legislation and Regulations

1. For complete text of the ARRA, see web site http://

frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=

111_cong_public_laws&docid=f:publ005.111.

2. For complete text of the Emergency Economic Stabilization Act of 2008, including Division B, “Energy

Improvement and Extension Act of 2008,” see web site

http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?

dbname=110_cong_bills&docid=f:h1424enr.txt.pdf.

3. For the complete text of the Food, Conservation, and

Energy Act of 2008, see web site http://frwebgate.

Access.gpo.gov/cgi-bin/getdoc.cgi?dbname=110_

cong_public_laws&docid=f:publ246.110.pdf.

4. U.S. Court of Appeals for the District of Columbia Circuit, No. 05-1244, web site www.epa.gov/airmarkets/

progsregs/cair/docs/CAIRRemandOrder.pdf.

5. See U.S. Energy Information Administration, An

Updated Annual Energy Outlook 2009 Reference Case

Reflecting Provisions of the American Recovery and

Reinvestment Act and Recent Changes in the Economic

Outlook, SR-OIAF/2009-03 (Washington, DC, April

2009), web site www.eia.doe.gov/oiaf/servicerpt/

stimulus/pdf/sroiaf(2009)03.pdf.

6. U.S. Department of Energy, “Weatherization Assistance Program,” web site http://apps1.eere.energy.

gov/weatherization/recovery_act.cfm and M. Schweitzer, Oak Ridge National Laboratory, Estimating the

National Effects of the U.S. Department of Energy’s

Weatherization Assistance Program with State-Level

Data: A Metaevaluation Using Studies from 1993 to

2005, ORNL/CON-493 (Oak Ridge, TN, September

2005), web site http://weatherization.ornl.gov/pdf/

CON-493FINAL10-10-05.pdf.

7. Certain types of biomass, municipal waste, and hydroelectric generation are eligible for only one-half of the

2.1-cent credit. The ITC alternative is not limited in

value for those technologies.

8. For information on the U.S. Department of Energy’s

implementation of ARRA through the Office of Fossil

Energy, see web site www.energy.gov/recovery.

9. Balanced Budget and Emergency Deficit Control Act

of 1985, Title 2, Section 907.

10. Defense Energy Support Center, “Compilation of

United States Fuel Taxes, Inspection Fees, and Environmental Taxes and Fees” (July 13, 2009).

11. 110th Congress, H.R. 2419, Food, Conservation, and

Energy Act of 2008, Sec. 15331, Modification of Alcohol Credit (January 2008), web site http://frwebgate.

access.gpo.gov/cgi-bin/getdoc.cgi?dbname=110_cong_

bills&docid=f:h2419enr.txt.pdf.

12. The cellulosic biofuels represented in NEMS are cellulosic ethanol, biomass-to-liquids (BTL) diesel, and

naphtha.

13. 110th Congress, H.R. 1424, Emergency Economic Stabilization Act of 2008, Division B, Energy Improvement and Extension Act of 2008, Sec. 202, Credits for

Biodiesel and Renewable Diesel (January 2008), web

site http://frwebgate.access.gpo.gov/cgi-bin/getdoc.

cgi?dbname=110_cong_bills&docid=f:h1424enr.txt.

pdf.

14. California Air Resources Board, Proposed Regulation

to Implement the Low Carbon Fuel Standard, Volume

I (March 5, 2009), web site www.arb.ca.gov/fuels/lcfs/

030409lcfs_isor_vol1.pdf.

15. California Air Resources Board, “Low Carbon Fuel

Standard Program,” Lifecycle Analysis, web site www.

arb.ca.gov/fuels/lcfs/lcfs.htm.

16. Vehicles with GVWR of 8,500 pounds or less.

17. U.S. Court of Appeals for the District of Columbia Circuit, No. 05-1244, web site www.epa.gov/airmarkets/

progsregs/cair/docs/CAIRRemandOrder.pdf.

18. U.S. Environmental Protection Agency, Fact Sheet:

Clean Air Interstate Rule (CAIR): Cleaner Air,

Healthier Air, and a Strong America (not dated), web

site www.epa.gov/interstateairquality/pdfs/cair_final_

fact.pdf.

19. ClimateWire, web site www.eenews.net/eenewspm/

2009/05/11/archive/2?terms=CAIR

(subscription site).

20. Legislature of the State of Kansas, Senate Substitute

for House Bill No. 2369 (May 22, 2009), web site www.

kslegislature.org/bills/2010/2369.pdf.

21. West Virginia Legislature, H.B. 103 (July 1, 2009),

web site www.legis.state.wv.us/Bill_Status/bills_text.

cfm?billdoc=hb103%20ENR.htm&yr=2009&

sesstype=1X&i=103.

22. Illinois General Assembly, Public Act 96-0159 (August

10, 2009), web site www.ilga.gov/legislation/

publicacts/fulltext.asp?Name=096-0159.

23. Illinois Commerce Commission, Order 09-0432 (July

29, 2009), web site www.dsireusa.org/documents/

Incentives/IL04R.pdf.

24. Maine Legislature, Public Law, Chapter 329 (June 9,

2009), web site www.mainelegislature.org/legis/bills/

bills_124th/chapters/PUBLIC329.asp.

25. Philip Giudice, Commissioner, Massachusetts Department of Energy Resources, Letter to Biomass Energy

Stakeholders (December 3, 2009), web site www.mass.

gov/Eoeea/docs//doer/rps/Mass%20Biomass%20Energ

y%20Stakeholders.pdf; and Massachusetts Department of Energy Resources, Clarification of Suspension

of Biomass Energy from Qualification in the Renewable Energy Portfolio Standard Program (December

22, 2009), web site www.mass.gov/Eoeea/docs/doer/

renewables/biomass/biomass-suspend-clarify2009dec22.pdf.

26. Minnesota Senate, S.F. 550, Sec. 13 (May 19, 2009),

web site https://www.revisor.mn.gov/bin/bldbill.php?

bill=S0550.3.html&session=ls86.

27. Minnesota Office of the Revisor of Statutes, 2009 Minnesota Statutes, 216B.1691 (2009), web site https://

www.revisor.mn.gov/statutes/?id=216B.1691.

28. Nevada Senate, SB 358 (May 28, 2009), web site www.

leg.state.nv.us/75th2009/Bills/SB/SB358_EN.pdf.
20 U.S. Energy Information Administration / Annual Energy Outlook 2010

Legislation and Regulations

29. State of Rhode Island General Assembly, H 5002

(June 26, 2009), web site www.rilin.state.ri.us/

PublicLaws/law09/law09051.htm.

30. Regional Greenhouse Gas Initiative, “About RGGI,”

web site www.rggi.org/about/documents.

31. Telephone call with Phillip Cherry, Delaware Department of Natural Resources and Environmental Concern (December 17, 2009).

32. Regional Greenhouse Gas Initiative, “Auction

Results,” web site www.rggi.org/co2-auctions/results.

33. Western Climate Initiative, Design Recommendations

for the WCI Regional Cap-and-Trade Program

(September 23, 2008), web site www.

westernclimateinitiative.org/the-wci-cap-and-tradeprogram/design-recommendations.

34. California Air Resources Board, “Preliminary Draft

Regulation for California Cap-and-Trade Program,”

web site www.arb.ca.gov/cc/capandtrade/meetings/

121409/pdr.pdf (November 2009).

35. Midwestern Greenhouse Gas Reduction Accord, web

site www.midwesternaccord.org.

36. Midwestern Greenhouse Gas Reduction Accord, Advisory Group Draft Final Recommendations (June

2009), web site http://midwesternaccord.org/GHG%20

Draft%20Advisory%20Group%20Recommendations.

pdf.

37. For further information, see Midwestern Greenhouse

Gas Reduction Accord, web site http://

midwesternaccord.org.
Issues in Focus
Introduction

Each year, the Issues in Focus section of the AEO provides an in-depth discussion on topics of special interest, including significant changes in assumptions and

recent developments in technologies for energy production, supply, and consumption. The first section

compares the results of two cases that adopt different

assumptions about the future course of existing

energy policies. One case assumes the elimination of

sunset provisions in existing energy policies. The

other case assumes the extension of a selected group

of existing policies—CAFE standards, appliance

standards, and PTCs—in addition to the elimination

of sunset provisions.

Other sections include a discussion of end-use energy

efficiency trends in AEO2010; an analysis of the impact of incentives on the use of natural gas in heavy

freight trucks; factors affecting the relationship between crude oil and natural gas prices; the sensitivity

of the projection results to variations in assumptions

about the availability of U.S. shale gas resources; the

implications of retiring nuclear plants after 60 years

of operation; and issues related to accounting for CO2

emissions from biomass energy combustion.

The topics explored in this section represent current,

emerging issues in energy markets; but many of

the topics discussed in AEOs published in recent

years also remain relevant today. Table 3 provides a

list of titles from the 2009, 2008, and 2007 AEOs that

are likely to be of interest to today’s readers. They can

be found on EIA’s web site at www.eia.doe.gov/oiaf/

aeo/otheranalysis/aeo_analyses.html.

No Sunset and Extended Policies cases

Background

The AEO2010 Reference case is best described as

a “current laws and regulations” case, because it generally assumes that existing laws and fully promulgated regulations will remain unchanged throughout

the projection period, unless the legislation establishing them specifically calls for them to end or change.

The Reference case often serves as a starting point for

the analysis of proposed legislative or regulatory

changes, a task that would be difficult if the Reference case included “projected” legislative or regulatory changes.

As might be expected, it is sometimes difficult to draw

a line between what should be included or excluded

from the Reference case. Areas of particular uncertainty include:

• Laws or regulations that have a history of being

extended beyond their legislated sunset dates. Examples include the various tax credits for renewable fuels and technologies, which have been

extended with or without modifications several

times since their initial implementation.

• Laws or regulations that call for the periodic updating of initial specifications. Examples include

appliance efficiency standards issued by the U.S.

DOE and CAFE standards for vehicles issued by

NHTSA.

• Laws or regulations that allow or require the

appropriate regulatory agency to issue new or

revised regulations under certain conditions.

22 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

AEO2009 AEO2008 AEO2007

Economics of Plug-In Hybrid Electric

Vehicles

Impacts of Uncertainty in Energy Project

Costs

Impacts of Rising Construction and

Equipment Costs on Energy Industries

Impact of Limitations on Access to Oil and

Natural Gas Resources in the Federal Outer

Continental Shelf

Limited Electricity Generation Supply and

Limited Natural Gas Supply Cases

Energy Demand: Limits on the Response to

Higher Energy Prices in the End-Use

Sectors

Expectations for Oil Shale Production Trends in Heating and Cooling DegreeDays: Implications for Energy DemandMiscellaneous Electricity Services in the

Buildings Sector

Bringing Alaska North Slope Natural Gas

to Market

Liquefied Natural Gas: Global Challenges Industrial Sector Energy Demand:

Revisions for Non-Energy-Intensive

Manufacturing

Natural Gas and Crude Oil Prices

in AEO2009

World Oil Prices and Production Trends

in AEO2008

World Oil Prices in AEO2007

Electricity Plant Cost Uncertainties Biofuels in the U.S. Transportation Sector

Greenhouse Gas Concerns and Power

Sector Planning

Loan Guarantees and the Economies of

Electricity Generating Technologies

Tax Credits and Renewable Generation Alaska Natural Gas Pipeline Developments

Coal Transportation Issues

Table 3. Key analyses from “Issues in Focus” in recent AEOs
Examples include the numerous provisions of the

CAA that require the EPA to issue or revise regulations if they find that some type of emission is

harmful to the public health, or that standards are

not being met.

To provide some insight into the sensitivity of results

to different characterizations of “current laws and

regulations,” two alternative cases are discussed in

this section. No attempt is made to cover the full

range of possible uncertainties in these areas, and

readers should not view the cases discussed as EIA

projections of how laws or regulations might or

should be changed.

Analysis cases

The two cases prepared—the No Sunset case and Extended Policies case—incorporate all the assumptions

from the AEO2010 Reference case, except as identified below. Changes from the Reference case assumptions in these cases include the following.

No Sunset case

• Extension of renewable PTCs, ITCs, and tax credits for energy-efficient equipment in the buildings

sector through 2035, including:

° The PTC of 2.1 cents per kilowatthour or the

30-percent ITC available for wind, geothermal,

biomass, hydroelectric, and landfill gas resources, currently set to expire at the end of

2012 for wind and 2013 for the other eligible

resources.

° For solar power investment, a 30-percent ITC

that is scheduled to revert to a 10-percent credit

in 2016 is, instead, assumed to be extended indefinitely at 30 percent.

° In the buildings sector, tax credits for the purchase of energy-efficient equipment, including

PV in new houses, are assumed to be extended

indefinitely, as opposed to ending in 2010 or

2016 as prescribed by current law. The business

ITC for commercial-sector generation technologies and geothermal heat pumps are assumed to

be extended indefinitely, as opposed to expiring

in 2016; and the business ITC for solar systems

is assumed to remain at 30 percent instead of

reverting to 10 percent.

° In the industrial sector, the ITC for CHP that

ends in 2016 in the AEO2010 Reference case is

assumed to be extended through 2035.

• Extension of the $0.45 per gallon blender’s tax

credit for ethanol through 2035; it is set to expire

at the end of 2010.

• Continued implementation of the RFS after the

2022 date currently specified in EISA2007 until

the renewable fuels target of 36 billion gallons is

met. After the 36 billion gallon level is met, the

mandate is assumed to continue increasing production in proportion to growth in overall transportation fuel use.

• Extension of the $1.00 per gallon biodiesel excise

tax credit through 2035; rather than expiring on

December 31, 2009.

• Extension of the $0.54 per gallon tariff on imported ethanol through 2035; it is set to expire at the

end of 2010.

• Extension of the $1.01 per gallon cellulosic biofuels PTC through 2035; rather than expiring at

the end of 2012.

Extended Policies case

With the exception of the blender’s and other biofuel

tax credits, the Extended Policies case adopts the

same assumptions as in the No Sunset case, plus the

following:

• Federal appliance efficiency standards are updated at particular intervals consistent with the

provisions in the existing law, with the levels

determined by the consumer impact tests under

DOE testing procedures, or under Federal Energy

Management Program (FEMP) purchasing guidelines.

The efficiency levels chosen for the updated residential standards are based on the technology

menu from the AEO2010 Reference case, and

whether or not the efficiency level passed the consumer impact test prescribed in DOE’s standards-setting process. The efficiency levels chosen

for the updated commercial equipment standards

are based on the technology menu from the

AEO2010 Reference case and FEMP-designated

purchasing specifications for Federal agencies.

• The implementation of rules proposed by NHTSA

and the EPA for national tailpipe CO2-equivalent

emission and fuel economy standards for LDVs,

including both passenger cars and light-duty

trucks, has been harmonized.

In the AEO2010 Reference case, which applies the

NHTSA and EPA rules, the new CAFE standards

lead to an increase in fleet-wide LDV standards

U.S. Energy Information Administration / Annual Energy Outlook 2010 23

Issues in Focus
from 27.1 mpg in MY 2011 to 34.0 mpg in MY

2016, based on projected sales of vehicles by type

and footprint. As required by EISA2007, the fuel

economy standards increase to 35 mpg in 2020.

The Extended Policies case assumes further increases in the standards, so that the minimum

fuel economy standard for LDVs increases to 45.6

mpg in 2035. In actual practice, the new CAFE

would need to meet a test of economic practicality.

• The extension of the blender’s and all biofuels excise tax credits through 2035 adopted in the No

Sunset case are not included in the Extended Policies case. The RFS enacted in EISA2007 is an

alternative instrument for stimulating demand

for biofuels, it already is represented in the AEO2010 Reference case, and it tends to be the binding

driver on biofuels rather than the tax credits.

Analysis results

The assumption changes made in the Extended Policies case generally lead to lower overall energy

consumption, increased use of renewable fuels,

particularly for electricity generation, and reduced

energy-related GHG emissions. While this case shows

lower energy prices because the impacts of the tax

credits and end-use efficiency standards lead to lower

energy demand and reduce the cost of renewable

fuels, consumers spend more on appliances that are

more efficient in order to comply with the tighter appliance standards, and the Government receives

lower tax revenues as consumers and businesses take

advantage of the tax credits.

Energy consumption

Total energy consumption in the No Sunset case is

close to the level in the Reference case (Figure 7).

Lower energy prices in the No Sunset case lead

to slightly higher energy consumption, but the

difference never reaches as much as 1 percent in any

year of the projections.

Total energy consumption in the Extended Policies

case, which assumes the issuance of more stringent

efficiency standards for end-use appliances and LDVs

in the future, is lower than in the Reference case. In

2035, total energy consumption in the Extended Policies case is nearly 3 percent below the projection in

the Reference case. As an example of individual end

uses, the assumed future standard for residential

electric water heating, which requires installation of

heat pumps starting in 2013, has the potential to reduce their electricity use by 60 percent from the Reference case level in 2035. Overall, delivered energy

use in the buildings sector in 2035 is 5 percent lower

in the Extended Policies case.

The impact on LDV energy use in the transportation

sector in the Extended Policies case is similar. In

2035, total LDV energy use in the Extended Policies

case is nearly 6 percent lower than in the Reference

case (Figure 8) and less than 0.5 percent above the

2007 level. Relative to the AEO2010 Reference case,

the efficiency standard for new LDVs in 2035 is 10

mpg higher in the Extended Policies case—46 mpg

versus 36 mpg (Figure 9); however, higher fuel prices

in the Reference case improve the cost competitiveness of advanced technologies, leading to improvements in fuel economy that are above the minimum

requirements (Figure 10). As a result, the average

fuel economy of new LDVs in the Reference case increases to 40 mpg in 2035 [Reference (achieved)],

which is 4 mpg above the required minimum. In the

Extended Policies case, the fuel economy standards

are binding [Extended Policies (achieved)], because

increases in fuel economy above the standards

24 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

2005 2010 2015 2020 2025 2030 2035

80

90

100

110

120

No Sunset

Extended Policies

Reference

Figure 7. Total energy consumption in three cases,

2005-2035 (quadrillion Btu)

2005 2010 2015 2020 2025 2030 2035

0

2

4

6

8

10

12

No Sunset

Extended Policies

Reference

Figure 8. Light-duty vehicle energy consumption

in three cases, 2005-2035 (million barrels

oil equivalent per day)
require advanced technologies that are not costeffective given the projected fuel prices.

Renewable electricity generation

The extension of tax credits for renewables through

2035 would lead to more rapid growth in renewable

generation than projected in the Reference case, particularly over the longer run. When the renewable tax

credits are extended without extending energy efficiency standards, as is assumed in the No Sunset case,

there is significant growth in renewable generation

throughout the projection period relative to the Reference case projection (Figure 11). Extending both renewable tax credits and energy efficiency standards

results in more modest growth in renewable generation, because renewable generation in the near term

is the primary source of new generation to meet load

growth, and enhanced energy efficiency standards

tend to reduce overall electricity consumption and the

need for new generation resources.

In the Reference case, growth in renewable generation accounts for 45 percent of total generation

growth from 2008 to 2035. In the No Sunset and

Extended Policies cases, growth in renewable generation accounts for 61 to 65 percent of total generation

growth. In 2035, the share of total electricity sales

accounted for by nonhydroelectric renewables is 13

percent in the Reference case, as compared with 17

percent in the No Sunset and Extended Policies cases.

In all three cases, the most rapid growth in renewable

capacity occurs in the near term, then slows through

2020, before picking up again. Before 2015, ample

supplies of renewable energy in relatively favorable

resource areas (windy lands, accessible geothermal

sites, and low-cost biomass), combined with the Federal incentives, make renewable generation competitive with conventional sources. If the rapid growth in

renewables is dampened because of the economic

downturn, more natural gas generation would be

expected. With slow growth in electricity demand and

the addition of capacity stimulated by renewable

incentives before 2015, little new capacity is needed

between 2015 and 2020. In addition, in many regions,

most attractive low-cost renewable resources already

have been exploited, leaving less-favorable sites that

may require significant investment in transmission

as well as other additional infrastructure costs. New

sources of renewable generation also appear on the

market as a result of cogeneration at biorefineries

built primarily to produce renewable liquid fuels to

meet the Federal RFS, where combustion of waste

products to produce electricity is an economically attractive option.

After 2020, renewable generation in the No Sunset

and Extended Policies cases increases more rapidly

than in the Reference case, and as a result

U.S. Energy Information Administration / Annual Energy Outlook 2010 25

Issues in Focus

2005 2010 2015 2020 2025 2030 2035

0

10

20

30

40

50 Extended Policies

Reference

Figure 9. New light-duty vehicle fuel efficiency

standards in two cases, 2005-2035 (miles per gallon)





                            





                            

2005 2010 2015 2020 2025 2030 2035

20

25

30

35

40

45

50

Extended Policies

Reference

Reference (achieved)

Extended Policies (achieved)

Figure 10. New light-duty vehicle fuel efficiency

standards and fuel efficiency achieved in two

cases, 2005-2035 (miles per gallon)

2005 2010 2015 2020 2025 2030 2035

0

200

400

600

800

1,000

1,200 Extended Policies

Reference

No Sunset

Figure 11. Renewable electricity generation

in three cases, 2005-2035 (billion kilowatthours)
generation from fossil fuels—particularly natural

gas—is reduced from the levels projected in the Reference case (Figure 12). In 2035, electricity generation

from natural gas in the No Sunset and Extended Policies cases is 13 percent and 16 percent lower, respectively, than in the Reference case.

Greenhouse gas emissions

In the No Sunset and Extended Policies cases, the

combination of lower overall energy demand and

greater use of renewable fuels leads to lower levels of

energy-related CO2 emissions than projected in the

Reference case. The difference grows over time, to

146 million metric tons (2 percent) in the No Sunset

case and 200 million metric tons (3 percent) in the

Extended Policies case in 2035 (Figure 13). From

2012 to 2035, energy-related CO2 emissions are reduced by a cumulative total of more than 1.9 billion

metric tons in the Extended Policies case relative to

the Reference case.

Energy prices and tax credit payments

With lower levels of overall energy use and more consumption of renewable fuels in the No Sunset and

Extended Policies cases, energy prices are lower than

projected in the Reference case. In 2035, natural gas

wellhead prices are $0.56 per thousand cubic feet (7

percent) and $0.70 per thousand cubic feet (9 percent)

lower in the No Sunset and Extended Policies cases,

respectively, than in the Reference case (Figure 14),

and electricity prices are 5 percent and 6 percent

lower than projected in the Reference case (Figure

15).

The reductions in energy consumption and CO2 emissions in the Extended Policies case require additional

equipment costs to consumers and revenue reductions for the Government. From 2010 to 2035,

residential and commercial consumers spend an additional $16 billion (real 2008 dollars) per year on

average for newly purchased end-use equipment, distributed generation systems, and residential shell

26 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

2005 2010 2015 2020 2025 2030 2035

0

200

400

600

800

1,000

1,200

Extended Policies

Reference

No Sunset

Figure 12. Electricity generation from natural gas

in three cases, 2005-2035 (billion kilowatthours)

2005 2010 2015 2020 2025 2030 2035

5,250

5,500

5,750

6,000

6,250

6,500

Extended Policies

Reference

No Sunset

Figure 13. Energy-related carbon dioxide emissions

in three cases, 2005-2035 (million metric tons)

2005 2010 2015 2020 2025 2030 2035

0

2

4

6

8

10

Extended Policies

Reference

No Sunset

Figure 14. Natural gas wellhead prices

in three cases, 2005-2035 (2008 dollars

per thousand cubic feet)

2005 2010 2015 2020 2025 2030 2035

8.0

8.5

9.0

9.5

10.0

10.5

No Sunset

Extended Policies

Reference

Figure 15. Average electricity prices in three cases,

2005-2035 (2008 cents per kilowatthour)
improvements in the Extended Policies case than in

the Reference case.

Tax credits paid to consumers in the buildings sector

in the Extended Policies case average $10.5 billion

more per year than in the Reference case, reaching a

cumulative total of $300 billion in revenue reductions

to the Government over the period from 2010 to 2035.

In comparison, cumulative revenue reductions as a

result of tax credits in the buildings sector total $27

billion over the same period in the Reference case.

The largest response to Federal PTC incentives for

new central-station renewable generation is seen in

the No Sunset case, with extension of the PTC resulting in cumulative reductions in Government tax revenues that total approximately $45 billion from 2010

to 2035, as compared with $24 billion in the Reference

case. Additional reductions in Government tax revenue in the No Sunset case result from extension of the

blenders tax credit, the biodiesel blenders tax credit,

and the cellulosic biofuels PTC, with cumulative total

tax revenue reductions from 2010 to 2035 of $156 billion, $32 billion, and $168 billion (all in 2008 dollars),

respectively, compared to the Reference case.

World oil prices and production trends in

AEO2010

In AEO2010, the price of light, low-sulfur (or

“sweet”) crude oil delivered at Cushing, Oklahoma, is

tracked to represent movements in world oil prices.

EIA makes projections of future supply and demand

for “total liquids,” which includes conventional petroleum liquids—such as conventional crude oil, natural

gas plant liquids, and refinery gain—in addition to

unconventional liquids, which include biofuels, bitumen, coal-to-liquids (CTL), gas-to-liquids (GTL),

extra-heavy oils, and shale oil.

World oil prices can be influenced by a multitude of

factors. Some tend to be short term, such as movements in exchange rates, financial markets, and

weather, and some are longer term, such as expectations concerning future demand and production decisions by the Organization of the Petroleum Exporting

Countries (OPEC ). In 2009, the interaction of market

factors led prompt month contracts (contracts for the

nearest traded month) for crude oil to rise relatively

steadily from a January average of $41.68 per barrel

to a December average of $74.47 per barrel [38].

Changes in the world oil market over the course of

2009 served to highlight the myriad factors driving

future liquids demand and supply and how a change

in these factors can reverberate through the world

liquids market. Over the long term, world oil prices in

EIA’s outlook are determined by four broad factors:

non-OPEC conventional liquids supply, OPEC investment and production decisions, unconventional

liquids supply, and world liquids demand. Uncertainty in long-term projections of world oil prices can

be explained largely by uncertainty about one or more

of these four broad factors.

Recent market trends

In 2009, world oil prices were especially sensitive to

demand expectations, with producers, consumers,

and traders constantly looking for any indication of a

possible recovery in the world’s economy and a likely

corresponding increase in oil demand.

On the supply side, OPEC demonstrated greater dedication to supporting prices in 2009 than it had in

other recent periods where it adopted restraints on

production. From February to June 2008, OPEC

maintained 70 percent or greater compliance as

measured by the actual aggregate production cuts

achieved by quota-restricted members as a percentage of the group’s agreed-upon production cut, before

falling to average levels of just above 60 percent

after September [39]. The above-average compliance

increased the group’s spare capacity to roughly 5 million barrels per day in December 2009, and helped

boost prices to a range of $70 to $80 per barrel [40].

Since June 2009, Iraq has held two rounds of bidding

for development of its oil resources. The sum of the

targeted production increase from the awarded fields

is about 9.5 million barrels per day, or almost four

times the country’s current production. Although

most industry analysts do not expect Iraq to achieve

those production targets in full, the likely increase

may cause changes in OPEC quota allocations and

long-term production decisions.

There were also significant developments for nonOPEC supply in 2009, some with potentially

long-lasting implications. Although oil prices rose

throughout 2009, many of the projects delayed during

the price slump that started in August 2008 have not

yet been revived. The time required for project development creates a lag between investment decisions

and increased oil deliveries, indicating that mediumterm supply growth may be constrained if delayed

projects are not restarted in the short term.

A related trend, which began in 2008 and continued

in 2009, was a decline in factor input costs—i.e.,

the costs of the materials, labor, and equipment

U.S. Energy Information Administration / Annual Energy Outlook 2010 27

Issues in Focus
necessary to develop liquids projects. The decline in

construction material costs and rig rates may have

encouraged the delay of some projects, as investors

played a wait-and-see game in order to secure contracts at the lowest possible cost. That trend appears

to have bottomed out at the end of 2009, however, after producing only a slight overall reduction in costs

[41]. Before the recent reduction in production costs,

an industry research group estimated that costs had

approximately doubled since 2000 [42].

Severe problems in the global credit market that began in 2008 and continued through 2009 have made it

difficult to finance some exploration and production

(E&P) projects. The full effect of limits on credit

availability for oil supply projects will not be realized

for some time, as the projects stalled due to a lack of

financing, particularly exploration projects, would

not have brought supply to the market for several

years. In addition to its impact on individual E&P

projects, the recent credit crisis may also have led to

an overall and possibly lasting change in risk tolerance on the part of both lenders and investors. Still,

while credit terms were being tightened and financial

risk was being trimmed, ongoing exploration efforts

in Africa resulted in a wave of discoveries and new

hope for unexplored and under-explored non-OPEC

resources.

Long-term prospects

Developments in 2008 and 2009 have demonstrated

the range of the uncertainties that underlie the four

broad factors underlying long-term world oil prices,

as described above. It remains unclear how the

world’s economy and the demand for liquids will recover, what non-OPEC resources will be brought to

market, what production targets OPEC will set or

meet, and whether or when individual unconventional liquids projects will come online. The price

path assumptions in AEO2010 encompass a broad

range of possible production levels and world oil price

paths, with a range of $160 per barrel (in real terms)

between the High Oil Price and Low Oil Price cases in

2035 (Figure 16). Consideration of Low and High Oil

Price cases allows EIA and others to analyze a variety

of future oil and energy market conditions in comparison with the Reference case.

Reference case oil prices

The global oil market projections in the AEO2010

Reference case are based on the assumption that current practices, politics, and levels of access will continue in the near to mid-term, whereas long-term

developments will be determined largely by

economics. The Reference case assumes that the

world economy— and liquids demand—experience

significant recovery in 2010, with total liquids consumption returning to the 2008 level of just under 86

million barrels per day.

Satisfying the growing world demand for liquids in

the next decade will require accessing higher cost supplies, particularly from non-OPEC producers. In the

Reference case, the higher cost of non-OPEC supply

supports average annual increases in real world oil

prices of approximately 0.7 percent from 2008 to 2020

and 1.4 percent from 2020 to 2035. Oil prices, in real

terms, rebound following the global recession, to $95

per barrel in 2015 and $133 per barrel in 2035 (real

2008 dollars). Although increases in OPEC production will meet a portion of the growing world demand,

the Reference case assumes that OPEC’s limits on

production growth will maintain its share of total

world liquids supply at approximately 40 percent,

where it has roughly been over the past 15 years.

Growth in non-OPEC production will come primarily

from high-cost conventional projects in regions

with unstable fiscal or political regimes and from relatively expensive unconventional liquids projects. The

return to higher price levels in the Reference case

results from limited access to prospective areas for

foreign investors, less attractive fiscal terms, and

higher exploration and production costs than have

been seen in the past.

Low Oil Price case

The AEO2010 Low Oil Price case assumes that

greater competition and international cooperation

will guide the development of political and fiscal

28 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

1980 1995 2008 2020 2035

0

50

100

150

200

250

Reference

Low Oil Price

History Projections

High Oil Price

Figure 16. Average annual world oil prices

in three cases, 1980-2035 (2008 dollars per barrel)
regimes in both consuming and producing nations,

facilitating coordination and cooperation among

them. Non-OPEC producing countries are assumed

to develop fiscal policies and investment regimes that

encourage private-sector participation in the development of their domestic resources; and OPEC is assumed to increase its production levels, providing

50 percent of the world’s liquids supply by 2035.

The availability of low-cost resources in both nonOPEC and OPEC countries allows for prices to stabilize at relatively low levels, $51 per barrel in real 2008

dollars, thereby reducing the incentive for consuming

nations to invest in unconventional liquids production as heavily as they do in the Reference case.

High Oil Price case

The AEO2010 High Oil Price case assumes not only a

rebound in world oil prices with the return of world

economic growth, but also a continued rapid escalation in prices as a result of long-term restrictions on

conventional liquids production. The restrictions result from both political decisions and resource characteristics: the major OPEC and non-OPEC producing

countries use quotas, fiscal regimes, and varying degrees of nationalization to further increase revenues

from oil production, and the consuming countries

turn to domestic production of high-cost unconventional liquids to satisfy demand. As a result, in the

High Oil Price case, world oil prices rise throughout

the projection period, to $210 per barrel in 2035.

Liquids demand is dampened by the high prices, but

is overshadowed by the severity of limitations on

access to and availability of lower cost conventional

resources. OPEC’s share of production falls to 35

percent.

Components of liquid fuels supply

In the AEO2010 Reference case, total world liquid

fuels consumption in 2035 is 112 million barrels per

day, or 26 million barrels per day higher than in 2008,

with production increases from OPEC and nonOPEC conventional sources totaling 15.5 million barrels per day. As a result, the conventional liquids

share of world liquids supply drops from 95 percent in

2008 to 87 percent in 2035.

Production of unconventional crude oils in the AEO2010 Reference case is 4.0 million barrels per day

higher in 2035 than in 2008 and represents 5.6 percent of global liquid fuels supply in 2035. Production

increases from Venezuela’s Orinoco belt and Canada’s oil sands are limited by access restrictions in

Venezuela and environmental concerns in Canada.

The relatively high world oil prices in the Reference

case encourage U.S. production of oil shale, with volumes reaching 0.4 million barrels per day in 2035.

Relatively high prices also encourage growth in global

CTL, GTL, and biofuel production, from a combined

total of 1.8 million barrels per day in 2008 to 8.4 million barrels per day in 2035, or 8 percent of total liquids supplied.

In the AEO2010 Low Oil Price case, oil prices are on

average more than 50 percent lower than in the Reference case from 2015 to 2035. In this case, conventional crude oil accounts for the largest share of total

liquids production in any of the three price cases in

2035, at about 90 percent. Production of conventional

crude oil totals 100.5 million barrels per day in 2035,

higher than the total for all conventional liquids in

the Reference case. Total conventional liquids production reaches 114.8 million barrels per day, and

total liquids production reaches 127 million barrels

per day, in the Low Oil Price case in 2035.

Despite their generally higher costs, production of

unconventional crude oils is also higher in the Low

Oil Price case than in the Reference case, as a result of

changes in economic access to resources. In the Low

Oil Price case, Venezuela’s production of extra-heavy

oil in 2035 increases from the Reference case projection of 1.3 million barrels per day to 3.4 million barrels per day—a 160-percent increase that more than

compensates for lower production of Canada’s oil

sands (0.6 million barrels per day in 2035) due to

reduced profitability. Total production of unconventional crude oil in the Low Oil Price case is 1.0 million

barrels per day higher in 2035 than projected in the

Reference case. Production of other unconventional

liquids (CTL, GTL, and biofuels) in 2035, primarily in

the United States, China, and Brazil, is 3.2 million

barrels per day lower than projected in the Reference

case, again due to reduced profitability.

In the High Oil Price case, oil prices from 2015 to

2035 are on average 66 percent higher than in the

Reference case. The higher prices are caused by

restrictions on economic access to non-OPEC conventional resources in countries such as Russia,

Kazakhstan, and Brazil, combined with reductions in

OPEC production. Conventional liquids production

in the High Oil Price case totals 71.8 million barrels

per day in 2035, 9.8 million barrels per day lower than

the 2008 total; total liquids production reaches only

91 million barrels per day in 2035.

U.S. Energy Information Administration / Annual Energy Outlook 2010 29

Issues in Focus
Access restrictions also limit the production of Venezuela’s extra-heavy oil from the Orinoco belt, which

totals 0.8 million barrels per day in 2035, as compared

with 1.3 million barrels per day in the Reference

case. Higher world oil prices support increased production from Canada’s oil sands, which totals 5.5

million barrels per day in 2035, as compared with 4.5

million barrels per day in the Reference case. Production of shale oil, predominantly in the United States,

does not change appreciably from the Reference case

level in the High Oil Price case, because the projects

are economically viable in the Reference case, and

even a 66-percent increase in prices does not stimulate additional production growth. With the increase

in oil sands production outweighing the decrease in

extra-heavy oil production through 2035, production

of unconventional crude oil from all sources is higher

in the High Oil Price case than in the Reference case.

Production of liquids from other unconventional

sources, including CTL, GTL, and biofuels, is almost

50 percent (3.9 million barrels per day) higher in the

High Oil Price case than in the Reference case in

2035. The increase results primarily from higher CTL

production in China (approximately 1.3 million barrels per day above the Reference case projection in

2035) and higher biofuels production in the United

States (0.9 million barrels per day above the Reference case in 2035). U.S. GTL production in the High

Oil Price case is notably different from the Reference

case projection, with production beginning in 2017

and reaching 0.5 million barrels per day in 2035.

Energy intensity trends in AEO2010

Energy intensity—energy consumption per dollar of

real GDP—indicates how much energy a country uses

to produce its goods and services. From the early

1950s to the early 1970s, U.S. total primary energy

consumption and real GDP increased at nearly the

same annual rate (Figure 17). During that period,

real oil prices remained virtually flat. In contrast,

from the mid-1970s to 2008, the relationship between

energy consumption and real GDP growth changed,

with primary energy consumption growing at less

than one-third the previous average rate and real

GDP growth continuing to grow at its historical rate.

The decoupling of real GDP growth from energy consumption growth led to a decline in energy intensity

that averaged 2.8 percent per year from 1973 to 2008.

In the AEO2010 Reference case, energy intensity continues to decline, at an average annual rate of 1.9 percent from 2008 to 2035.

Definitions and classifications

Energy efficiency is defined as the ratio of the amount

of energy services provided to the amount of energy

consumed [43]. Familiar examples of energy services

are the heat supplied by a furnace and the light output of a lamp.

Energy conservation is defined as the lowering of energy consumption by reducing energy services. For

example, lowering a thermostat’s setting during the

heating season is classified as energy conservation,

because less heating is provided. Because the ratio of

energy services to energy consumption is unchanged,

energy efficiency does not change in this example.

As indicated above, energy intensity is defined as

energy consumption per dollar of real GDP. Any

change in energy intensity that does not result from a

change in efficiency is referred to as a structural

change [44]. Examples of structural change include

energy conservation, a change in the mix of economic

activity among the sectors of the economy, a change

in the mix of activities within a sector, and a geographical change in population density. Energy use is

affected in these examples of structural change, but

not because of changes in energy efficiency.

CO2 emissions associated with energy production and

consumption are a growing concern. Carbon intensity

is the ratio of CO2 emissions to real GDP. The type of

fuel used to provide energy services—or in the case

of electricity, the fuel used to generate it—affects

carbon intensity.

As defined here, efficiency and intensity are inversely

related: increases in energy efficiency reduce energy

intensity. To facilitate comparisons among them, the

30 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

1950 1970 1990 2008 2020 2035

0.0

0.5

1.0

1.5

2.0

Real GDP

Real oil price

Total energy consumption

History Projections

Figure 17. Trends in U.S. oil prices, energy

consumption, and economic output, 1950-2035

(annual index, 2008 = 1.0)
efficiency index discussed below is calculated as the

inverse of the usual efficiency concept: energy consumption per unit of service demand. In this way,

both improvements in efficiency and improvements

in intensity are shown as decreases.

Results for the Reference case

Because the available data are limited, it is difficult to

determine the amount of historical decoupling of

energy consumption growth from real GDP growth

that was attributable to improvements in energy efficiency [45]. With the wealth of technology detail on

energy-using equipment in NEMS, efficiency can be

characterized readily [46]. Figure 18 compares indexes of the Reference case projections for energy efficiency, energy intensity, and carbon intensity. The

average rate of decline in the index for energy

intensity from 2008 to 2035 is almost quadruple the

Comparing efficiency projections

Realized improvements in energy efficiency generally rely on a combination of technology and economics [47]. The figure below illustrates the role of

technology assumptions in the AEO2010 projections for energy efficiency in the residential and

commercial buildings sector. Projected energy consumption in the Reference case is compared with

projections in the Best Available Technology, High

Technology, and 2009 Technology cases and an estimate based on an assumption of no change in efficiency for building shells and equipment (the cases

are defined in Appendix E).

With the exception of the constant efficiency estimate, the rate at which existing equipment stocks

rate of decline in the index for energy efficiency,

reflecting the dominant role of structural change. The

are replaced in each of the cases is governed by the

rate of stock turnover. The constant efficiency estimate assumes no stock turnover and no change in

efficiency from the 2009 existing stock. The 2009

Technology case assumes a normal rate of stock

turnover, but limits new equipment choices to what

is available in 2009. Comparing the two projections,

energy consumption in 2035 is 1.2 quadrillion Btu

lower in the 2009 Technology case. The difference—

about 4.5 percent—shows the effect of stock turnover even absent any technology improvements.

In the Best Available Technology case, with new construction materials and replacement equipment limited to the most energy-efficient available, energy

consumption in the buildings sector in 2035 is 8.6

percent lower than the 2009 level and 23 percent

lower than in the Reference case, even though total

floorspace grows by more than 50 percent. Even in

2035, however, not every piece of equipment or

every building shell reaches the maximum efficiency

that could be achieved as a result of technology

improvements, because some long-lived equipment

and building shells installed before 2009 still have

not been replaced at that point. Surpassing the efficiency levels projected in the Best Available Technology case would require policies designed to increase

the rate of stock turnover—for example, by incentivizing or mandating retrofits of existing buildings

and replacement of equipment with the most efficient models available.

U.S. Energy Information Administration / Annual Energy Outlook 2010 31

Issues in Focus

2008 2015 2020 2025 2030 2035

0.0

0.2

0.4

0.6

0.8

1.0

1.2

Energy efficiency

(decline indicates improvement)

Energy intensity

Carbon intensity

Figure 18. Projected changes in indexes of energy

efficiency, energy intensity, and carbon intensity

in the AEO2010 Reference case, 2008-2035

(index, 2008 = 1.0)



2008 2015 2020 2025 2030 2035

0

5

10

15

20

25

30

High Technology

Constant efficiency estimate

Reference

Best Available Technology

2009 Technology

Delivered energy consumption in the residential

and commercial buildings sector in five scenarios,

2008-2035 (quadrillion Btu)
larger reduction in the index for carbon intensity

reflects a shift toward less carbon-intensive energy

sources in the Reference case, especially wind,

biofuels, and solar. In the Reference case, the ratio

of carbon emissions to energy consumption in 2035 is

5 percent lower than its 2008 value.

Energy consumption increases at an average annual

rate of 0.5 percent from 2008 to 2035 in the AEO2010

Reference case. The portion of the energy intensity

decline projected in the Reference case that can be

attributed to structural changes and the portion that

can be attributed to changes in energy efficiency is

illustrated by comparing the growth of primary

energy use in the Reference case with estimates of

constant energy efficiency and constant energy intensity, calculated from the AEO2010 Reference case

(Figure 19).

Assuming no improvement in energy intensity beyond 2008, energy consumption would grow in the

Reference case at the rate of real GDP, 2.4 percent

annually, to 192 quadrillion Btu in 2035—77.6

quadrillion Btu (68 percent) higher than in the Reference case. Similarly, assuming no change in energy

efficiency beyond its 2008 level, energy consumption

would increase to 132.8 quadrillion Btu in 2035, or

18.3 quadrillion Btu (16 percent) higher than in the

Reference case. The intensity decline from structural

change in the Reference case, 59.2 quadrillion Btu, is

the difference between the projection for energy consumption in 2035 when no change in energy intensity

is assumed and the same projection when no change

in energy efficiency is assumed. Thus, structural

change accounts for 76 percent of the decline in

energy intensity in the Reference case, and efficiency

improvement accounts for 24 percent.

Table 4 shows average annual growth rates from 2008

to 2035 for real GDP, population, and major indicators for energy consumption in the end-use sectors in

the Reference case. Because the growth rate for real

GDP is higher than any of the other growth rates, energy consumption in each sector would be expected to

grow more slowly than real GDP, and energy intensity would be expected to decline, even in the absence

of efficiency gains.

In each of the end-use sectors, most of the improvement (decline) in energy intensity results from structural change: 82 percent in the buildings sectors,

where average annual increases in residential and

commercial floorspace are only about one-half the average increase in real GDP; 82 percent in the industrial sector, where output from non-energy-intensive

manufacturing grows at twice the rate of output from

energy-intensive manufacturing; and 53 percent in

the transportation sector, where structural change is

slower and improvements in fuel efficiency as a result

of tightening fuel economy standards account for

47 percent of the decline in energy intensity. (For

further discussion of efficiency in the AEO2010 buildings cases, see box on page 31.)

Results for the Integrated Technology cases

The AEO2010 Low Technology case assumes that the

efficiency of newly purchased equipment does not improve beyond what is currently available (although

end-use or process efficiency does improve to some extent as a result of stock turnover, because replacement equipment nearly always is more efficient than

the equipment it replaces). The High Technology case

32 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

2008 2015 2020 2025 2030 2035

0

50

100

150

200

76%

Constant energy intensity estimate

Constant energy efficiency estimate

Reference case

192.0

132.8

114.5

24%

Structural

Efficiency

Figure 19. Structural and efficiency effects on

primary energy consumption in the AEO2010

Reference case (quadrillion Btu) Real GDP 2.4

Population 0.9

Buildings sector

Number of households 1.0

Commercial floorspace 1.3

Industrial sector

Real value of industrial shipments

Nonmanufacturing 0.9

Energy-intensive manufacturing 0.8

Non-energy-intensive manufacturing 1.8

Transportation sector

Vehicle miles traveled

Light-duty vehicles 1.7

Freight trucks 1.7

Air seat-miles 1.3

Rail ton-miles 0.8

Table 4. Average annual increases in economic

output, population, and energy consumption

indicators in the buildings, industrial,

and transportation sectors, 2008-2035

(percent per year)
assumes earlier availability of high-efficiency technologies and lower technology costs than in the Reference case. Also, in a departure from previous AEOs,

the AEO2010 High Technology case assumes that

consumers are more likely to choose advanced technologies, because they evaluate efficiency investments at a 7-percent real discount rate, which is

generally lower than assumed in the Reference case.

In the Low Technology and High Technology cases,

projections for energy consumption in 2035 are 2.4

quadrillion Btu (2 percent) higher and 5.7 quadrillion

Btu (5 percent) lower, respectively, than in the Reference case. Energy efficiency and intensity trends in

the Reference, Low Technology, and High Technology cases are shown in Figure 20. From 2008 to 2035,

there is a 12- to 17-percent improvement in energy efficiency across the three cases and a 39- to 43-percent

reduction in intensity.

The relatively narrow range of projections in Figure

20 indicates that, although technology advances play

a role in reducing energy intensity and carbon intensity, structural components are much more significant. Population shifts to more moderate climates,

smaller households, less energy-intensive manufacturing, and more fuel-efficient LDVs and high-speed

rail could further reduce energy intensity. Policies

governing future CO2 emissions and deployment of

low- and no-carbon technologies will be the main

determinant of future carbon intensity.

Natural gas as a fuel for heavy trucks:

Issues and incentives

Environmental and energy security concerns related

to petroleum use for transportation fuels, together

with recent growth in U.S. proved reserves and technically recoverable natural gas resources, including

shale gas, have sparked interest in policy proposals

aimed at stimulating increased use of natural gas as a

vehicle fuel, particularly for heavy trucks. In 2008,

U.S. freight trucks used more than 2 million barrels

of petroleum-based diesel fuel per day. In the AEO2010 Reference case, they are projected to use 2.7 million barrels per day in 2035. Petroleum-based diesel

use by freight trucks in 2008 accounted for 15 percent

of total petroleum consumption (excluding biofuels

and other non-petroleum-based products) in the

transportation sector (13.2 million barrels per day)

and 12 percent of the U.S. total for all sectors (18.7

million barrels per day). In the Reference case, oil use

by freight trucks grows to 20 percent of total transportation use (13.7 million barrels per day) and 14

percent of the U.S. total (19.0 million barrels per day)

by 2035. The following analysis examines the potential impacts of policies aimed at increasing sales of

heavy-duty natural gas vehicles (HDNGVs) and the

use of natural gas fuels, and key factors that lead to

uncertainty in these estimates.

Historically, natural gas has played a limited role as

a transportation fuel in the United States. In 2008,

natural gas accounted for 0.2 percent of the fuel

used by all highway vehicles and 0.2 percent of the

fuel used by heavy trucks—the market that many

observers believe to be the most attractive for increasing the use of natural gas. Because there are relatively few heavy vehicles that use natural gas for fuel

currently, there has been very little development of

natural gas fueling infrastructure. Currently there

are 827 fueling stations for CNG and 38 fuel stations

for LNG in the United States. Most are privately

owned and are used for central refueling [48].

Further, they are not distributed evenly: 24 percent

(201) of the CNG facilities and 71 percent (27) of the

LNG facilities are in California. Unless more natural

gas vehicles enter the market, there will be little incentive to build more natural gas fueling infrastructure nationally or in local or regional corridors.

Despite the price advantage that natural gas has had

over diesel fuel in recent years (an advantage that is

projected to increase over time in the Reference case),

other factors—including higher vehicle costs, lower

operating range, and limited fueling infrastructure—

have severely limited market acceptance and penetration of natural gas vehicles. As of 2008, trucks powered by natural gas made up only 0.3 percent of the

heavy truck fleet, or about 27,000 of the 8.7 million

registered heavy trucks. Although their share grows

U.S. Energy Information Administration / Annual Energy Outlook 2010 33

Issues in Focus

2008 2015 2020 2025 2030 2035

0.5

0.6

0.7

0.8

0.9

1.0 Energy efficiency

Energy intensity

Reference

High Technology

Low Technology

High Technology

Reference

Low Technology

(decline indicates improvement)

Figure 20. Energy efficiency and energy intensity

in three cases, 2008-2035 (index, 2008 = 1.0)
in the Reference case projections, high incremental

costs keep the fleet of HDNGVs relatively small, at

1.7 percent (260,000 vehicles) of the total stock of 15

million heavy trucks on the road in 2035.

Characteristics and usage of heavy-duty

natural gas vehicles

HDNGVs have significant incremental costs relative

to their diesel-powered counterparts in the AEO2010

Reference case: $17,000 for light-heavy (class 3,

GVWR of 10,000 to 14,000 pounds), $40,000 for

medium-heavy (classes 4 through 6, GVWR of 14,001

to 26,000 pounds), and $60,000 for heavy trucks

(classes 7 and 8, GVWR of 26,001 pounds and

greater). By far the largest component of incremental

cost is the fuel storage system, which consists either

of cylindrical tanks to hold CNG at high pressure or of

highly insulated tanks to hold LNG. Because tank

technology is fairly mature and, in the case of cylindrical tanks to hold gases at high pressure, is already

widely deployed, the Reference case does not assume

significant reductions in incremental vehicle costs

over time.

Natural gas for use in transport vehicles currently

costs 42 percent less than diesel fuel (on an energyequivalent basis and considering only existing taxes),

and with oil prices rising at a significantly faster rate

than U.S. natural gas prices, the gap is projected to

widen to 50 percent in 2035 in the AEO2010 Reference case (Figure 21). Consequently, the payback period for incremental vehicle costs becomes shorter

when natural gas trucks are used more intensively.

The Department of Transportation’s Vehicle Inventory and Use Survey (VIUS), last completed in 2002,

suggests a wide range for the intensity of heavy truck

use. Notably, in the 2002 VIUS, trucks reporting a

primary range of operation that extended more than

500 miles from their base averaged 91,000 vehiclemiles traveled (VMT), or more than 5 times the average of 17,000 VMT for trucks reporting a primary

range of operation range within 100 miles of their

base.

Although long-distance trucking offers a potentially

faster payback of the incremental capital costs for

HDNGVs, their penetration and acceptance in the

long-distance freight market faces two significant

barriers: limited driving range without refueling and

a lack of available fueling infrastructure. A diesel

truck with one 150-gallon diesel tank and a fuel economy of 6 to 7 mpg can drive approximately 1,000 miles

without refueling, which can be extended readily with

an auxiliary fuel tank. In contrast, a CNG-fueled

truck with a frame-rail-mounted storage tank can

drive only about 150 miles without refueling, while

one with a back-of-cab frame-mounted storage tank

can drive about 400 miles without refueling, similar

to an LNG-fueled truck with frame-rail-mounted

tanks. In addition, regardless of fuel type, longdistance trucks are less likely to be fueled at central

bases, which makes them more dependent on fueling

infrastructure that is open to the public.

In addition to concerns about driving range and refueling, the residual value of HDNGVs in the secondary market is likely to be an important consideration

for buyers. Also, purchase decisions can be influenced

by other factors, such as weight limits on highways

and bridges, which can make the considerable additional weight of CNG or LNG tanks a significant

drawback in some market segments.

The importance of range and refueling infrastructure

barriers suggests that the best near-term market

penetration opportunity for HDNGVs, some of whose

incremental costs are already covered by tax credits,

could be in the market for centrally fueled fleets that

operate primarily within a limited distance from their

base. The 2002 VIUS reported a total of 145 billion

truck VMT (not counting light trucks used primarily

for personal transportation), of which about 50 percent was made up by trucks with a primary operating

range of 200 miles or less and about one-third by

trucks fueled at private facilities (presumably, with

considerable overlap between the two groups).

Accordingly, the following analysis focuses on “fleet

vehicles” in the short-range (less than 200 miles),

centrally fueled segment of the heavy truck market.

34 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

2000 2008 2015 2025 2035

0

1

2

3

4

History Projections

Diesel fuel

Natural gas

Figure 21. Delivered energy prices for diesel and

natural gas transportation fuels in the Reference

case, 2000-2035 (2008 dollars per gallon of diesel

equivalent)
Sensitivity cases with incentives for

heavy-duty natural gas vehicles

Policies that provide economic incentives—such as

tax credits for vehicles, fuel, and fueling infrastructure—could stimulate sales of HDNGVs and the

development of additional natural gas fueling

infrastructure. AEO2010 includes several sensitivity

cases that examine the potential impacts of such

incentives.

The Reference Case 2019 Phaseout With Base

Market Potential is a modified Reference case that

incorporates lower incremental costs for all classes

of HDNGVs (zero incremental cost relative to their

diesel-powered counterparts after accounting for

incentives) and tax incentives for natural gas refueling stations ($100,000 per new facility) and for

natural gas fuel ($0.50 per gallon of gasoline equivalent) that begin in 2011 and are phased out by 2019.

The Reference Case 2027 Phaseout With Expanded Market Potential is another modified

Reference case with the same added assumptions of

lower incremental costs for HDNGVs and subsidies

for fueling stations and natural gas fuel as in the first

modified Reference case, but with the subsidies

extended to 2027 before phaseout. In addition, it

assumes increases in the potential market for natural

gas vehicles, for both “fleet vehicles” and “nonfleet

vehicles” (see Table 5).

In the following text and data presentations, the cases

above are referred to more briefly as the 2019

Phaseout Base Market case and 2027 Phaseout Expanded Market case.

HDNGVs cannot gain a major share of the heavy

truck market in the absence of major investments in

natural gas fueling infrastructure. The assumed

$100,000 tax credit per filling station is a relatively

small percentage of the estimated $1 million to

$4 million cost for such facilities. Assuming an initial

cost of $2 million per station, Table 6 shows the

levelized capital cost of the station per gallon of diesel

equivalent refueling capacity with and without the

$100,000 tax credit, for station fuel throughput

capacities of 1,250, 5,000, and 12,500 gallons per day

[49].

As indicated in Table 6, increasing the throughput

capacity of a fueling station from 1,250 to 5,000 gallons diesel equivalent per day lowers the capital cost

recovery component of supplying natural gas fuel to

HDNGVs by more than $1.00 per gallon of diesel

equivalent. The infrastructure tax credit lowers the

capital cost recovery component by only an additional

8 cents per gallon for the smallest facility size shown

in the table and by only 1 cent per gallon for the

largest facility size. This suggests that throughput

capacity (demand) is a far more important consideration for decisions about investment in natural gas

fueling stations than are potential tax credits on the

order of about $100,000.

Impacts of incentives in the Base Market and

Expanded Market cases with Reference case

world oil price assumptions

In the 2019 Phaseout Base Market and 2027 Phaseout Expanded Market cases, both of which use oil

price assumptions from the AEO2010 Reference case,

HDNGV sales increase with the availability of incentives. Assuming a 2019 phaseout date for tax credits

and the base characterization of maximum penetration of the new truck market, sales of new HDNGVs

in the 2019 Phaseout Base Market case increase from

about 500 in 2008 to 32,500 in 2035, versus 22,000 in

the Reference case (Figure 22). Assuming a 2027

phaseout of tax credits and the expanded characterization of maximum market penetration, HDNGV

sales in the 2027 Phaseout Expanded Market case

increase to 270,000 in 2035, or roughly 35 percent of

U.S. Energy Information Administration / Annual Energy Outlook 2010 35

Issues in Focus

Vehicle type and class

Base

Market

Expanded

Market

Fleet vehicles

Class 3 10 35

Classes 4-6 10 45

Classes 7-8 10 60

Nonfleet vehicles

Class 3 3 10

Classes 4-6 3 25

Classes 7-8 3 25

Table 5. Maximum market potential for

natural gas heavy-duty vehicles in Base Market

and Expanded Market cases (percent of total

heavy-duty vehicle fleet)

Station capacity

(gallons equivalent per day)

Cost

without

credits

Cost

with

credits

1,250 1.47 1.39

5,000 0.37 0.35

12,500 0.15 0.14

Table 6. Levelized capital costs for natural gas

fueling stations with and without assumed

tax credits (2008 dollars per gallon of

diesel equivalent refueling capacity)
all new heavy truck sales. The HDNGV share of the

total U.S. heavy truck stock in 2035 is 2.8 percent in

the 2019 Phaseout Base Market case and 23.3 percent

in the 2027 Phaseout Expanded Market case (versus

1.7 percent in the Reference case).

As a result of the projected increases in new HDNGV

sales, natural gas demand in the heavy truck sector

increases from about 0.01 trillion cubic feet in 2008 to

0.15 trillion cubic feet in 2035 in the 2019 Phaseout

Base Market case and to 1.6 trillion cubic feet in 2035

in the 2027 Phaseout Expanded Market case (Figure

23). In the Reference case, the natural gas share of

total fuel consumption by heavy trucks increases

from 0.2 percent in 2008 to 1.8 percent in 2035; in

the 2019 Phaseout Base Market and 2027 Phaseout

Expanded Market cases, it increases to 3.3 percent

and 40.0 percent, respectively.

Roughly speaking, 1 trillion cubic feet of natural gas

replaces 0.5 million barrels per day of petroleum (predominantly, diesel fuel). Thus, natural gas consumption by HDNGVs in the 2027 Phaseout Expanded

Market case displaces about 0.67 million barrels

per day of petroleum product consumption in 2035

(Figure 24). Without a major impact on world oil

prices, which is not expected to result from the significant but gradual adoption of natural gas as a fuel

for U.S. heavy-duty vehicles, nearly all (more than

four-fifths) of the reduction in U.S. oil consumption

would result in a decline in oil imports.

In the longer term, increased demand for natural gas

in the transportation sector would tend to stimulate

increases in U.S. natural gas production and imports,

as well as higher natural gas prices in all the end-use

sectors. As a result, natural gas demand in the other

sectors would decrease—particularly in the electric

power sector, where some generators would switch to

coal—and expenditures for natural gas would increase. In the AEO2010 Reference case, total U.S.

natural gas consumption increases from 23.3 trillion

cubic feet in 2008 to 24.9 trillion cubic feet in 2035. In

the 2019 Phaseout Base Market case and 2027

Phaseout Expanded Market case, total natural gas

consumption increases by 0.4 percent, to 25.0 trillion

cubic feet, and by 4.8 percent, to 26.1 trillion cubic

feet, respectively, in 2035.

In the 2019 Phaseout Base Market case and 2027

Phaseout Expanded Market case, more than twothirds of the additional natural gas used by HDNGVs

is produced domestically, and less than one-third

is provided by increases in pipeline imports from

Canada and LNG imports. U.S. natural gas prices rise

modestly in both cases.

36 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus





             

        

2010 2015 2020 2025 2030 2035

0.0

0.5

1.0

1.5

2.0

2019 Phaseout Base Market

2027 Phaseout Expanded Market

Reference

0

Figure 23. Natural gas fuel use by heavy-duty

natural gas vehicles in Base Market and Expanded

Market cases with Reference case world oil prices,

2010-2035 (trillion cubic feet)





            









      

2010 2015 2020 2025 2030 2035

0

250

500

750

2019 Phaseout Base Market

2027 Phaseout Expanded Market

Figure 24. Reductions in petroleum product use by

heavy-duty vehicles in Base Market and Expanded

Market cases with Reference case world oil prices,

2010-2035 (thousand barrels per day)





     















         

2010 2015 2020 2025 2030 2035

0

100

200

300

2019 Phaseout Base Market

2027 Phaseout Expanded Market

Reference

Figure 22. Sales of new heavy-duty natural gas

vehicles in Base Market and Expanded Market

cases with Reference case world oil prices,

2010-2035 (thousands of vehicles)
Impacts of incentives in the Base Market and

Expanded Market cases with low world oil

price assumptions

Lower oil prices tend to make HDNGVs a less attractive option, and higher oil prices tend to make them

more attractive. In the two sensitivity cases discussed

above, which assumed Reference case world oil prices,

market penetration by HDNGVs reaches or nearly

reaches its assumed maximum market potential. As a

result, higher oil prices would not lead to further

increases in HDNGV sales, unless the large price

advantage of natural gas were sufficient to open additional segments of the heavy truck transportation

market to the use of natural-gas-fueled vehicles.

On the other hand, if oil prices were lower than projected in the Reference case, there would be less

incentive to switch from diesel to natural gas fuel in

heavy trucks. With no tax incentives or assumed market expansion for HDNGVs, there are almost no sales

of new HDNGVs in 2035 in the AEO2010 Low Oil

Price case. To analyze the impact of lower oil prices,

EIA ran two sensitivity cases that were identical to

those discussed earlier but instead used the Low Oil

Price case. In the 2019 Phaseout Base Market Low

Price case, sales of new HDNGVs total about 17,000

in 2035. In the 2027 Phaseout Expanded Market Low

Price case, sales of new HDNGVs total about 205,000

in 2035. Similarly, natural gas consumption by

HDNGVs increases to 0.1 trillion cubic feet in 2035

in the 2019 Phaseout Base Market Low Price case

and to 1.2 trillion cubic feet in the 2027 Phaseout

Expanded Market Low Price case, as compared with

almost no demand for natural gas in the heavy vehicle

sector in 2035 in the AEO2010 Low Oil Price case.

Incentive costs and impacts on energy

expenditures

Increased use of natural gas as a transportation fuel

changes the levels of demand for, and consequently

the prices of natural gas and other fuels used in

transportation and other sectors of the economy.

Depending on the amount of natural gas used in the

transportation sector, the sum of incentive payments

to the transportation sector plus higher energy costs

to other sectors may be more than offset by savings

in the transportation sector from fuel switching

from diesel to natural gas. Figure 25 shows annual

vehicle and fuel tax incentive payments and net

changes in economy-wide energy expenditures for

the 2027 Phaseout Expanded Market case [50]. The

graph shows how changes in transportation demand

for natural gas and petroleum products may affect

energy expenditures throughout the economy while

the incentives are in effect. The significant increase

in transportation natural gas use and associated reductions in petroleum product use result in increases

in economy-wide natural gas prices and expenditures

that are more than offset by economy-wide decreases

in petroleum product prices and expenditures.

The projections in Figure 25 do not reflect many of

the factors that could be important for policymakers’

evaluations of incentives for HDNGVs, such as the

cost of infrastructure tax credits, productivity losses

resulting from more frequent refueling, impacts on

net energy costs, incremental vehicle costs beyond

the period when incentives are provided, or environmental benefits of reducing emissions of conventional

pollutants and GHGs. Also, they do not consider

potential effects on royalty and severance payments

as a result of changes in domestic natural gas production or oil imports, or effects on GDP and other

relevant indicators of economic welfare and energy

security.

Factors affecting the relationship

between crude oil and natural gas prices

Background

Over the 1995-2005 period, crude oil prices and U.S.

natural gas prices tended to move together, which

U.S. Energy Information Administration / Annual Energy Outlook 2010 37

Issues in Focus

2010 2013 2016 2019 2022 2025 2027

0

5

10

15

20

-5

-10

-15

Annual cost of vehicle and fuel tax credits

Net change in annual energy expenditures

relative to the Reference case

Figure 25. Annual cost of vehicle and fuel tax

credits and net change in annual economy-wide

energy expenditures for the 2027 Phaseout

Expanded Market case, 2010-2027

(billion 2008 dollars)
supported the conclusion that the markets for the two

commodities were connected. Figure 26 illustrates

the fairly stable ratio over that period between

the price of low-sulfur light crude oil at Cushing,

Oklahoma, and the price of natural gas at the Henry

Hub on an energy-equivalent basis.

The AEO2010 Reference and High Oil Price cases,

however, project a significantly longer and persistent

disparity between the relative prices of low-sulfur

light crude oil and natural gas on an energyequivalent basis [51]. The apparent disconnect in

prices between seemingly similar commodities varies

over a wide range between 2010 and 2035 [52]. Over

much of the projection period in the Reference case,

the crude oil price is about 2.8 times the natural gas

price on an energy equivalent basis—115 percent

higher than the historical average price ratio of 1.3

from 1995 to 2005. In the High Oil Price case, the

ratio widens to as much as 4.8; in the Low Oil Price

case, it narrows from nearly 3.0 in 2009 to 1.1 in 2035.

Such an apparent lack of responsiveness of natural

gas prices to changes in crude oil prices in all cases

reflects the changes that have occurred in the underlying uses of the two commodities. The divergence of

crude oil and natural gas markets also reflects the

fact that opportunities for the substitution of natural

gas for crude oil products are limited by the large

infrastructure investments that would be required to

allow substitution on a significant scale and bring the

prices of the two commodities closer together in the

U.S. market in the Reference and High Oil Price

cases. In the absence of such investments, EIA expects the gap between oil and natural gas prices in

U.S. energy markets to remain wide.

Opportunities to substitute natural gas

for petroleum

In the United States, the capability to substitute

natural gas supplies directly for petroleum, particularly in the electric power sector, has eroded over

time. In 1978, 4.0 quadrillion Btu of petroleum was

consumed to produce electricity, representing nearly

17 percent of total energy use for U.S. electricity generation, as compared with 14 percent for natural gas

[53]. In 2008, only 0.5 quadrillion Btu of petroleum

was consumed for electricity generation, representing

1.2 percent of total energy use for generation [54, 55],

while natural gas has grown to 17 percent of generation. The trend has been similar in the commercial

and industrial sectors where there are a declining

number of opportunities to substitute natural gas for

petroleum.

Still, there are potential opportunities for natural

gas to displace petroleum. First, direct use of natural

gas in the U.S. transportation sector could provide an

opportunity for substitution. Second, natural gas

could be exported to countries where petroleum is

widely used for thermal applications. Third, natural

gas can be converted directly to petroleum-like liquid

fuels that could be substituted for diesel and gasoline

in the existing vehicle fleet using the existing distribution infrastructure.

The physical properties of natural gas are such that it

is more difficult and costly than liquid fuels to transport and consume. As shown in Figure 27, the energy

density of natural gas is much lower than that of most

liquid fuels. To match the energy equivalent of a

1-gallon container of diesel fuel, a balloon of natural

gas at atmospheric pressure would have to be nearly a

thousand times larger than the gallon container. At a

38 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

1995 2008 2015 2025 2035

0

1

2

3

4

5

History Projections

High Oil Price

Low Oil Price

Reference

Figure 26. Ratio of low-sulfur light crude oil prices

to natural gas prices on an energy-equivalent basis,

1995-2035

0 10 20 30 40 50 60 70

Diesel fuel (1.0)

Gasoline (1.1)

Liquefied natural gas (1.5)

Compressed natural gas, 3,600 psi (4.1)

Natural gas, 1,000 psi (14.7)

Natural gas, 300 psi (49.1)

Natural gas, 14.7 psi (999.4)

1,000 1,010

Figure 27. Ratio of natural gas volume to diesel

fuel volume needed to provide the same energy

content
pressure of 3,600 pounds per square inch (psi), however, which is the pressure rating for the fuel tanks

used in CNG vehicles, only 4 times as much space is

required to match the energy equivalent of 1 gallon of

diesel fuel. And when the gas is converted to LNG by

chilling to about -260 degrees Fahrenheit, its energy

density increases to the point where it requires only

50 percent more volume to match the energy content

of diesel fuel. However, the materials used for the

handling and storage of LNG differ significantly from

those used for CNG or petroleum-like liquid fuels.

An expanded market for CNG or LNG would require

additional investment in vehicles and infrastructure

for compression and storage of CNG or for liquefaction and storage of LNG. Some of the issues, challenges, and opportunities surrounding the use of

natural gas as a substitute for diesel fuel are

described in the Issues in Focus section, “Natural gas

as a fuel for heavy trucks: Issues and incentives.”

Barriers to U.S. exports of LNG

World crude oil and natural gas prices could converge

if barriers to the flow of natural gas between U.S. and

world markets were eliminated through the combined use of the existing pipeline network, existing

LNG terminals, and investment in new U.S. LNG

liquefaction capacity (and possibly LNG tankers) to

allow exports of U.S. natural gas when it is economical. Currently, there is one liquefaction facility in

Alaska that exports LNG from the United States.

Investment in new U.S. liquefaction capacity would

face significant risk, however, because there are large

quantities of “stranded gas” in remote regions of the

world that can be priced well below the expected cost

of resources in the lower 48 States.

Potential for production of liquid fuels from

natural gas

Another opportunity to substitute natural gas for

crude oil would be to convert it to petroleum-like

liquid products similar to gasoline and diesel fuel, for

use in the liquid fuel infrastructure and end-use

equipment. Such a transformation is possible

through use of the GTL process.

There are several GTL processes, the best known

using a Fischer-Tropsch reactor. The reactor produces a paraffin wax that is hydrocracked to form

liquid products that resemble petroleum liquids. Distillates, including diesel, heating oil, and jet fuel, are

the primary products, making up 50 to 70 percent of

the total volume produced, and naphtha usually represents about 25 percent of the volume. The process

efficiency is about 57 percent (43 percent of the

energy content of the natural gas is lost in the process) [56]. Thus, the price ratio of liquid products to

natural gas would have to exceed about 1.8 to justify

operation of the plant, excluding consideration of

other operating costs and the cost of capital investment. To appreciate the price risk faced by investors,

one can consider the effects of recent fluctuations in

energy prices on investments in U.S. natural gas

turbine and combined-cycle generating units and

ethanol production facilities [57]. Indeed, AEO2010

examines the potential impacts of lower energy prices

in the Low Oil Price case, which shows the ratio of

crude oil prices to natural gas prices declining to

1.1 in 2035, indicating that if any GTL plants were

built they would not be operated under those price

conditions.

The technologies and equipment used in the bestknown GTL technology are similar to those that have

been employed for decades in methanol and ammonia

plants, and most are relatively mature; however, the

scale on which previous GTL plants have been implemented is relatively small. The newest GTL plants

have been expanded to much larger sizes, including

one in excess of 100,000 barrels per day, to take

advantage of economies of scale, but recent attempts

to build projects at those larger sizes have encountered technology or project execution risks [58]. Currently, there are four GTL plants in operation

worldwide, with 96,200 barrels per day of total capacity [59]. In addition, two projects with 174,000 barrels

per day of capacity are under construction or ready

for startup [60]. However, the construction of GTL

plants at sites with available stranded gas reserves

has been limited, indicating investor reluctance to

pursue this option fervently, especially when investments in less capital-intensive LNG capacity are possible. Indeed, some GTL projects have been canceled

or deferred in the past few years [61].

The overnight capital costs for a new GTL plant situated on the U.S. Gulf Coast would range from $50,000

per barrel-stream day of capacity [62] to an estimated

$104,000 per barrel-stream day [63]. Accordingly, a

relatively modest unit with a capacity of 34,000

barrels per day represents an estimated overnight

capital cost [64] of $1.7 billion to $3.5 billion. With

financing included, the estimated total investment

would be $2.2 billion to $4.4 billion. In addition, construction of the facility would take 4 years or more,

imposing further market risk. The risk-adjusted

discount factor used by investors will be critical to

U.S. Energy Information Administration / Annual Energy Outlook 2010 39

Issues in Focus
determining whether investors would proceed with

GTL investments.

Figure 28 shows the maximum “breakeven” average

price of natural gas that could be tolerated over a 10-

year plant operating period [65] in order to justify the

risk associated with investing in a GTL facility, based

on the range of capital costs discussed above and a

10-percent hurdle rate [66]. Profitable cases lie below

the line. At $100 per barrel for crude oil, the breakeven price for natural gas that would justify investment in a GTL facility is -$1.20 to $5.80 per million

Btu. At higher crude oil prices, the range of the breakeven natural gas price also rises. At a crude oil price of

$200 per barrel, the breakeven price for natural gas is

$10.20 to $17.30 per million Btu. At a crude oil price

of $60 per barrel, the breakeven natural gas price

ranges from -$5.80 to $1.30 per million Btu, illustrating the substantial impact of oil price uncertainty on

the profitability of investment in a GTL facility.

Figure 28 also shows how investment in a GTL facility would fare with the natural gas and crude oil price

projections in the AEO2010 Reference, Low Oil Price,

and High Oil Price cases. With the prices in the

Low Oil Price case, GTL is a poor investment. With

the prices in the Reference case, GTL is a marginal

investment. Only with the highest prices in the

Reference case and the low end of GTL plant costs do

the breakeven economics favor the project. In the

High Oil Price case, however, the combination of

higher crude oil prices and lower natural gas prices

implies that investment in a GTL plant on the U.S.

Gulf Coast could be profitable.

A large investment in GTL would be needed in order

to produce an appreciable effect on worldwide prices

for crude oil and U.S. natural gas. Construction of

sufficient new GTL capacity to affect world crude oil

prices, about 1 million barrels per day, would require

a total investment between $50 billion and $135

billion. That level of capacity would still represent

only 1.2 percent of the 85.9 million barrels per day of

the world’s estimated total liquids production in 2007

[67], and less than 1 percent of projected 2035 production in the Reference case [68].

Another option is the potential use of stranded natural gas in Alaska to produce GTL. Because of Alaska’s

severe weather conditions, construction of GTL (or

any other) facilities is likely to be much more expensive than the construction of GTL plants on the U.S.

Gulf Coast or in the Middle East. Some estimates

suggest that doubling the construction costs and

extending the construction period by at least 2 years

would be reasonable assumptions. Construction of

GTL facilities in Alaska, therefore, seems unlikely

given the cost uncertainties mentioned above and the

crude oil price projections in the AEO2010 Reference

case.

Looking forward

A large disparity between crude oil and natural gas

prices, as projected in the AEO2010 Reference and

High Oil Price cases, will provide incentives for innovators and entrepreneurs to pursue opportunities

that, in the longer term, could increase domestic or

international markets for U.S. natural gas. For example, a scenario with relatively high oil prices would

tend to increase the value of CO2 used for EOR as well

as GTL production. Because GTL processing plants

can accommodate natural gas feedstocks with relatively high CO2 content and can target fields smaller

than those required for LNG production, such circumstances would provide incentives for the development of smaller GTL systems that produce both

liquid products and a valuable CO2 co-product. Because EIA cannot predict whether or when such innovations might arise, they are not included in the

AEO2010 analysis cases.

Importance of low-permeability

natural gas reservoirs

Introduction

Production from low-permeability reservoirs, including shale gas and tight gas, has become a major source

of domestic natural gas supply. In 2008, low-permeability reservoirs accounted for about 40 percent of

natural gas production and about 35 percent of natural gas consumption in the United States. Permeability is a measure of the rate at which liquids and gases

40 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

High Oil Price

Low Oil Price Reference

Low end of GTL plant cost range

High end of GTL plant cost range

Crude oil price

0 50 100 150 200 250

0

10

20

30

-10

-20

Henry Hub natural gas price

Figure 28. Breakeven natural gas price

(2008 dollars per million Btu) relative to crude oil

price (2008 dollars per barrel) required for

investment in new gas-to-liquids plants
can move through rock. Low-permeability natural

gas reservoirs encompass the shale, sandstone, and

carbonate formations whose natural permeability is

roughly 0.1 millidarcies or below. (Permeability is

measured in “darcies.”)

The use of hydraulic fracturing in conjunction with

horizontal drilling in shale gas formations and the use

of hydraulic fracturing in tight gas formations has

opened up natural gas resources that would not

be commercially viable without these technologies. As

shale gas production has expanded into more basins

and recovery technology has improved, the size of the

shale gas resource base in the AEO has increased

markedly. Because the exploitation of shale gas resources is still in its initial stages, and because many

shale beds have not yet been tested, there is a great

deal of uncertainty over the size of the recoverable

shale gas resource base. Low-permeability gas wells

typically produce at high initial flow rates, which decline rapidly and then stabilize at relatively low levels

for the remaining life of the wells.

To illustrate the importance of low-permeability

natural gas reservoirs for future U.S. natural gas supply, consumption, and prices, three alternative cases

were developed for AEO2010: a No Shale Gas Drilling

case, a No Low-Permeability Gas Drilling case, and a

High Shale Gas Resource case. The No Shale Gas

Drilling and No Low-Permeability Gas Drilling cases

examine the implications of no new drilling in lowpermeability formations. The High Shale Resource

case examines the possibility that shale gas resources

could be considerably greater than those represented

in the Reference case. The three alternative cases are

not intended to represent any expected future reality.

Rather, they are intended to illustrate the importance

of low-permeability formations for EIA’s projections

of future U.S. natural gas supply and are likely to be

extremes. All the cases assume no change from the

Reference case assumptions about the size of, and

access to, Canadian and other international natural

gas resources. Specific assumptions in the three cases

are as follows.

No Shale Gas Drilling case. Starting in 2010, in

this case no new onshore lower 48 shale gas production wells are drilled. Natural gas production from

shale gas wells drilled before 2010 declines continuously through 2035.

No Low-Permeability Gas Drilling case. Starting

in 2010, in this case no new onshore lower 48 lowpermeability natural gas production wells are drilled,

including shale gas wells and “tight” sandstone and

carbonate gas wells. Natural gas production from

low-permeability wells drilled before 2010 declines

continuously through 2035.

High Shale Gas Resource case. In this case, the

unexploited portion of each shale formation supports

twice as many new wells as in the Reference case. The

lower 48 shale gas resource base increases by 88 percent, from 347 trillion cubic feet in the Reference case

to 652 trillion cubic feet in the High Shale Gas Resource case. The estimated recovery per well in each

formation is the same as in the Reference case.

Natural gas supply, consumption, and prices

Low-permeability natural gas resources are more

abundant and less expensive than other domestic

natural gas supply alternatives that could replace

them, and they are expected to play a significant role

in future domestic natural gas markets. Consequently, their future absence or presence is expected

to have a significant impact on the average cost of natural gas production and prices, which in turn would

affect natural gas imports and consumption. In the

No Shale Gas Drilling and No Low-Permeability Gas

Drilling cases, lower 48 onshore natural gas productive capacity is less than in the Reference case, and as

a result average U.S. natural gas prices are higher,

more natural gas is imported, and natural gas consumption is reduced (Table 7). Conversely, in the

High Shale Gas Resource case, natural gas productive

capacity is higher, natural gas prices and imports are

lower, and consumption is higher than projected in

the Reference case.

No Shale Gas Drilling and

No Low-Permeability Gas Drilling cases

In the No Shale Gas Drilling and No Low-Permeability Gas Drilling cases, total domestic natural gas

production in 2035 is 18 percent and 25 percent

lower, respectively, and onshore lower 48 production

is 27 percent and 39 percent lower, respectively, than

in the Reference case. The loss of onshore lower 48

productive capacity leads to higher natural gas prices

and lower consumption levels. In the No Shale Gas

Drilling and No Low-Permeability Gas Drilling cases,

the Henry Hub spot price for natural gas in 2035 is

$1.49 and $2.00 per million Btu higher, respectively,

than the Reference case price of $8.88 per million Btu.

The significantly higher natural gas prices are a

result of the removal of considerable low-cost natural

gas resources, leaving a smaller natural gas resource

base that is more expensive to produce.

U.S. Energy Information Administration / Annual Energy Outlook 2010 41

Issues in Focus
Because higher domestic natural gas prices make

other supply sources more competitive, both offshore

Gulf of Mexico production and net natural gas imports increase in the No Shale Gas Drilling and No

Low-Permeability Gas Drilling cases. Offshore natural gas production levels in 2035 are 7 percent and 18

percent (0.3 trillion cubic feet and 0.8 trillion cubic

feet) higher, respectively, than in the Reference case,

and net imports are 154 percent and 207 percent

higher (2.2 trillion cubic feet and 3.0 trillion cubic

feet). In 2035, net imports make up 6 percent of total

U.S. natural gas supply in the Reference case, 16 percent in the No Shale Gas Drilling case, and 20 percent

in the No Low-Permeability Gas Drilling case. The

higher levels of net imports in the two alternative

cases are the result of increases in LNG imports

and imports from Canada, as well as a reduction in

exports to Mexico.

In 2035, net LNG imports in the No Shale Gas

Drilling and No Low-Permeability Gas Drilling cases

are more than double those in the Reference case

(1.8, 2.4, and 0.8 trillion cubic feet, respectively),

and net natural gas imports from Canada are 52 percent and 59 percent greater, respectively, in the two

alternative cases than in the Reference case. Because

the assumptions in these cases are not applied to

the Canadian natural gas resource base, higher U.S.

prices lead to more natural gas production in Canada

(including Canadian shale gas). In addition, Canada’s

Mackenzie Delta natural gas pipeline begins operating before 2035 in the two alternative cases, which

does not occur in the Reference case. Net natural gas

exports to Mexico in 2035 are 35 percent and 47 percent lower in the No Shale Gas Drilling and No

Low-Permeability Gas Drilling cases, respectively,

than in the Reference case.

The impact on natural gas consumption of restricted

drilling in low-permeability reservoirs is less pronounced than the impact on domestic supply, for two

reasons. First, the increase in net imports partially

offsets the reduction in domestic natural gas productive capacity. Second, long-lived natural gas

consumption equipment responds more slowly to

changes in natural gas prices than does natural gas

supply—although the electric power sector, where

natural gas consumption responds relatively quickly

to changes in natural gas prices, is an exception. In

2035, natural gas consumption in the electric power

sector is 1.3 trillion cubic feet (17 percent) lower in

the No Shale Gas Drilling case and 1.9 trillion cubic

feet (26 percent) lower in the No Low-Permeability

Gas Drilling case than the Reference case level of 7.4

trillion cubic feet.

42 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

Projection Reference

No Shale Gas

Drilling

No Low-Permeability

Gas Drilling

High Shale Gas

Resource

Henry Hub spot price

(2008 dollars per million Btu) 8.88 10.37 10.88 7.62

Total U.S. natural gas production

(trillion cubic feet) 23.3 19.1 17.4 25.9

Onshore Lower 48 17.1 12.5 10.4 20.0

Offshore Lower 48 4.3 4.7 5.1 4.0

Alaska 1.9 1.9 1.9 1.9

First year of operation for

the Alaska natural gas pipeline 2023 2020 2020 2030

Total net U.S. imports of natural gas

(trillion cubic feet) 1.5 3.7 4.5 0.8

Canada 1.7 2.5 2.7 1.4

Mexico -1.0 -0.7 -0.5 -1.3

Liquefied natural gas 0.8 1.8 2.4 0.8

Total U.S. natural gas consumption

(trillion cubic feet) 24.9 22.9 22.0 26.8

Electric power 7.4 6.1 5.5 8.7

Residential sector 4.9 4.8 4.7 5.0

Commercial sector 3.7 3.6 3.5 3.8

Industrial sector 6.7 6.5 6.4 7.0

Other 2.2 1.9 1.8 2.3

Table 7. Natural gas prices, supply, and consumption in four cases, 2035
High Shale Gas Resource case

Relative to the Reference case, both natural gas production costs and prices are reduced in the High Shale

Gas Resource case. Consequently, domestic natural

gas production is more competitive, and U.S. natural

gas consumption is higher. In 2035, onshore lower 48

and total natural gas production are 17 percent and

11 percent higher, respectively, in the High Shale Gas

Resource case than in the Reference case, and Henry

Hub spot prices are $1.26 per million Btu lower than

in the Reference case. Increased domestic production

and lower natural gas prices reduce net imports in

2035 by 44 percent from their level in the Reference

case, to 0.8 trillion cubic feet, and offshore natural gas

production in 2035 is reduced by 7 percent, to 4.0

trillion cubic feet. The decline in net imports results

from a 19-percent reduction in net imports from

Canada, an 8-percent reduction in net LNG imports,

and a 25-percent increase in net exports to Mexico in

the High Shale Gas Resource case, relative to the Reference case.

Because of the lower natural gas prices in the High

Shale Gas Resource case, U.S. natural gas use in 2035

is 2.0 trillion cubic feet (8 percent) higher than in the

Reference case. The majority of the increase is in the

electric power sector, which accounts for 1.3 trillion

cubic feet (18 percent) of the total increase.

U.S. nuclear power plants: Continued life

or replacement after 60?

Background

Nuclear power plants generate approximately 20 percent of U.S. electricity, and the plants in operation today are often seen as attractive assets in the current

environment of uncertainty about future fossil fuel

prices, high construction costs for new power plants

(particularly nuclear plants), and the potential enactment of GHG regulations. Existing nuclear power

plants have low fuel costs and relatively high power

output. However, there is uncertainty about how long

they will be allowed to continue operating.

The nuclear industry has expressed strong interest in

continuing the operation of existing nuclear facilities,

and no particular technical issues have been identified that would impede their continued operation. Recent AEOs had assumed that existing nuclear units

would be retired after 60 years of operation (the initial 40-year license plus one 20-year license renewal).

Maintaining the same assumption in AEO2010, with

the projection horizon extended to 2035, would result

in the retirement of more than one-third of existing

U.S. nuclear capacity between 2029 and 2035. Given

the uncertainty about when existing nuclear capacity

actually will be retired, EIA revisited the assumption

for the development of AEO2010 and modified it to

allow the continued operation of all existing U.S.

nuclear power plants through 2035 in the Reference

case.

The modified assumption in the Reference case implies that the operating lives of some nuclear plants

will be more than 60 years. To address the uncertainty about whether such life extensions will be allowed, an alternative Nuclear 60-Year Life case was

developed, assuming that all the existing U.S. nuclear

power plants will be retired after 60 years of

operation.

Discussion

The Atomic Energy Act of 1954 authorized the U.S.

Nuclear Regulatory Commission (NRC) to issue operating licenses for commercial nuclear power plants

for a period of 40 years. The 40-year time frame was

derived from accounting and anti-trust concerns, not

technical limitations [69]. The law allows the NRC to

issue operating license renewals in 20-year increments, provided that reactor owners demonstrate

that continued operations can be conducted safely. As

of July 2009, the NRC had granted license renewals to

50 of the 104 operating reactors in the United States,

allowing them to operate for 60 years. Fifteen additional applications are under review, and the owners

of 21 other units have announced that they intend to

file for 20-year license extensions. The NRC has yet to

deny an application for a 20-year extension [70]. Previous AEOs assumed that all of the 104 existing units

would operate for a total of 60 years, provided that

they remained economical.

In December 2009, the Oyster Creek Generating Station in Lacey Township, New Jersey, became the first

nuclear power plant in the United States to begin its

40th year of operation. With Oyster Creek and other

nuclear plants of similar vintage just beginning to

enter their first period of license renewal, it probably

will be at least 5 to 10 years before there is any clear

indication as to whether plant operators will be likely

to seek further extensions of their plants’ operating

lives.

For the AEO2010 Reference case, EIA assumed that

the operating lives of existing nuclear power plants

would be extended at least through 2035. Assuming

U.S. Energy Information Administration / Annual Energy Outlook 2010 43

Issues in Focus
that the NRC continues to approve license extensions, the decision to operate a facility is an economic

one made by plant owners. Aging plants may face increased operation and maintenance (O&M) costs and

capital expenditures, which generally decrease their

profitability. Revenue projections are dependent on

electricity prices, which are uncertain due to variations in fossil fuel prices, regional economic growth,

and environmental regulations. Thus, even if the

costs of operating nuclear plants do not change,

changes in electricity prices can affect their profitability when their generation is sold at market-based

rates.

Between 1974 and 1998, 14 commercial nuclear reactors in the United States were retired. The circumstances of each retirement were unique to the

particular plant, but the common thread was that the

expected cost of continued operation was higher than

expected revenues, and there were less costly generating options available. Highly competitive naturalgas-fired generation could have been a factor in those

retirements. Natural-gas-fired combined-cycle plants

were the favored option for new capacity during the

1990s, when natural gas prices were relatively low

and it was widely believed that they would remain low

for the foreseeable future. In contrast, real O&M

costs for nuclear power plants had increased by 77

percent during the 1980s [71], owners faced the risk

that new NRC regulations might require prohibitively expensive retrofits, and there was widespread

concern State public utility commissions would not

allow full cost recovery for expenditures on nuclear

plants.

The economics of existing nuclear power plants are

more favorable today, because natural gas prices are

higher, the nuclear plants are performing well, and

the potential enactment of GHG regulations increases uncertainty about fuel and operating costs for

power plants that burn coal and natural gas. To date,

there have been no announced plans to retire any of

the 104 operating U.S. commercial nuclear reactors.

To the contrary, the NRC and the nuclear power industry are preparing applications for license renewals

that would allow continued operation beyond 60

years, the first of which is scheduled to be submitted

by 2013. In February 2008, DOE and the NRC hosted

a joint workshop titled “Life Beyond 60,” with a broad

group of nuclear industry stakeholders meeting to

discuss this issue [72]. The workshop’s summary

report outlined many of the technical research needs

that participants agreed were important to extending

the life of the existing fleet of U.S. nuclear plants.

Several concerns were expressed at the DOE/NRC

workshop. Because heat, water, and radiation can

have long-term effects on the materials they are in

contact with in nuclear power plants, more effective

monitoring may be needed as the systems age, which

could require updates to instruments and controls.

Over the next several years, research is being focused

on identifying problems that aging facilities might encounter and formulating potential solutions. Until

that research has been completed, it will be difficult

to estimate any cost increases that may result from

extending the age of reactors.

Future cost increases may reflect only routine expenditures, or they could involve major capital projects,

such as the replacement of reactor vessels, containment structures, or buried piping and cables. To date,

no plans or cost estimates for such potential modifications have been made public; however, they have the

potential to be very expensive, and they could require

extended plant shutdowns. While a plant is out of operation, the generation lost will have to be replaced,

probably with expensive power purchased on the spot

electricity market.

For most existing nuclear plants, decisions about retirement or life extension ultimately will be based on

the cost and feasibility of all the measures needed for

a plant to continue to operate safely and economically. It is difficult to anticipate future operating

costs, but it can be helpful to compare current operating costs with the total levelized costs of new nuclear

power plants in order to gauge the magnitude of increases in O&M costs that would make retirement an

option from an economic standpoint. For instance,

with current O&M costs at the most expensive

nuclear units in operation averaging approximately

3.5 cents per kilowatthour [73] and total levelized

costs for new baseload capacity ranging from 8 cents

to 11 cents per kilowatthour, the operating costs of

existing nuclear power plants would have to increase

substantially before it would be economical to retire

even the most expensive units.

Nuclear plant owners also face the risk of future regulations that could require expensive upgrades. Such a

rule was recently the subject of the Supreme Court

case Entergy Corp v. Riverkeeper [74], which focused

on whether or not the EPA could conduct cost-benefit

analyses to determine whether a plant needed to

44 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus
replace open-cycle cooling water systems with closedcycle systems. A retrofit of such magnitude would be

costly and thus could alter the relicensing decision for

a particular facility.

The AEO2010 Reference case assumes an additional

O&M cost of $30 per kilowatt for nuclear power capacity after 30 years of operation, which is meant to

represent the various programs that must be undertaken in order to ensure continued safety. Even with

this added cost, no retirements of existing nuclear

power plants are projected by 2035 in the Reference

case.

Alternative case

If all the existing nuclear power plants in the United

States were retired after 60 years of operation, the

impacts on electricity markets, fuel use, and GHG

emissions would be substantial. Therefore, AEO2010

includes an alternative Nuclear 60-Year Life case,

which assumes that no existing nuclear power plant

will receive a second license extension, and all of them

will be retired after 60 years. The 60-year retirement

assumption is not meant as a hard-and-fast rule but

as a possibility that allows examination of the impact

of retiring existing nuclear capacity from the generation mix.

A total of 30.8 gigawatts of capacity at operating U.S.

nuclear power plants—or approximately one-third of

the existing fleet—will have been in operation for at

least 60 years by 2035. The Nuclear 60-Year Life case

assumes that all of that capacity will be retired between 2029 and 2035. Figure 29 shows the locations

of the plants that would be retired, which are spread

fairly evenly across the regions where nuclear power

capacity is prominent.

U.S. Energy Information Administration / Annual Energy Outlook 2010 45

Issues in Focus

Fort Calhoun

Cooper

Monticello

Kewaunee

Duane Arnold

Arkansas

Nuclear

One 1 Browns

Ferry

1 and 2

Hatch 1

Oconee

1, 2, and 3

H.B.

Robinson

Turkey Point 3 and 4

Brunswick 2

Surry 1 and 2

Calvert Cliffs 1

Indian

Point 2

Pilgrim

Ginna

FitzPatrick

Point Beach

1 and 2 Palisades

Cook 1

Nine Mile Point 1

Prairie Island 1 and 2

Quad Cities 1 and 2

Dresden

2 and 3

Vermont Yankee

Three Mile Island

Peach Bottom 2 and 3

Oyster Creek

Millstone 2

Figure 29. U.S. nuclear power plants that will reach 60 years of operation by 2035
In the Nuclear 60-Year Life case, retirement of the

plants shown in Figure 29 results in the construction

of additional replacement capacity beyond the capacity additions already projected in the Reference case

(Table 8). Of the additional capacity built in the

Nuclear 60-Year Life case, only about 2 gigawatts is

nuclear. Instead, the retired nuclear capacity is replaced almost exclusively with coal and natural gas

capacity, which in the absence of policies regulating

GHG emissions remains more economical than either

nuclear or renewable plants.

Reflecting the different projections for generating

capacity additions in the two cases, the projected

nuclear share of total generation in 2035 is only 13

percent in the Nuclear 60-Year Life case, compared

with 17 percent in the Reference case. Total generation in the Nuclear 60-Year Life case is 1 percent

lower than in the Reference case. CO2 emissions are

higher in the Nuclear 60-Year Life case, because

nuclear power is replaced with fossil fuels. Again,

however, the difference between the projections is

less than 1 percent, because most of the capacity

replacing the retired nuclear plants is fueled by

natural gas.

U.S. electricity prices in 2035 in the Nuclear 60-Year

Life case are 4 percent higher than those in the Reference case. In regions where the retirements are

scheduled to occur, the price increases are slightly

larger: compared to the Reference case, electricity

prices in 2035 are 7 percent higher in the North

American Electric Reliability Council (NERC) Midwest Reliability region and between 5 and 6 percent

higher in the NERC regions in the Northeast,

mid-Atlantic, and Southeast. In regions where no retirements occur, there are still small price increases

relative to the Reference case, because natural gas

prices are higher in the Nuclear 60-Year Life case.

Building new capacity to replace the retired nuclear

plants is more expensive than allowing their continued operation, and the higher costs are passed on to

consumers in the form of higher electricity prices.

Natural gas prices also are higher in the alternative

case than in the Reference case, by 5.4 percent, because the additional new capacity is predominantly

natural-gas-fired, and the increase in demand pushes

up the price of natural gas.

Finally, the assumed absence of new Federal policies

to limit GHG emissions is crucial to the results of

this analysis. In all likelihood, such policies would

increase the cost of generating electricity from fossil

fuels, improving the relative economics of new

nuclear power plants and favoring construction of

more nuclear capacity to replace the retired units.

Accounting for carbon dioxide emissions

from biomass energy combustion

CO2 emissions from the combustion of biomass [75]

to produce energy are excluded from the energyrelated CO2 emissions reported in AEO2010. According to current international convention [76], carbon

released through biomass combustion is excluded

from reported energy-related emissions. The release

of carbon from biomass combustion is assumed to be

balanced by the uptake of carbon when the feedstock

is grown, resulting in zero net emissions over some

period of time [77]. However, analysts have debated

whether increased use of biomass energy may result

in a decline in terrestrial carbon stocks, leading to a

net positive release of carbon rather than the zero net

release assumed by its exclusion from reported energy-related emissions.

For example, the clearing of forests for biofuel crops

could result in an initial release of carbon that is not

fully recaptured in subsequent use of the land for agriculture. To capture the potential net emissions, the

international convention for GHG inventories is to

report biomass emissions in the category “agriculture, forestry, and other land use,” usually based on

estimates of net changes in carbon stocks over time.

This indirect accounting of CO2 emissions from biomass can potentially lead to confusion in accounting

for and understanding the flow of CO2 emissions

within energy and non-energy systems. In recognition of this issue, reporting of CO2 emissions from

biomass combustion alongside other energy-related

CO2 emissions offers an alternative accounting treatment. It is important, however, to avoid misinterpreting emissions from fossil energy and biomass energy

46 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

Projection Reference

Nuclear 60-

Year Life

Generating capacity additions

by fuel type, 2008-2035 (gigawatts)

Coal 11 17

Natural gas 89 102

Nuclear 7 9

Renewable 57 57

Electricity price in 2035

(2008 cents per kilowatthour) 10.2 10.6

Natural gas price in 2035

(2008 dollars per thousand cubic feet) 8.69 9.16

Table 8. Comparison of key projections in the

Reference and Nuclear 60-Year Life cases
sources as necessarily additive. Instead, the combined

total of direct CO2 emissions from biomass and

energy-related CO2 emissions implicitly assumes that

none of the carbon emitted was previously or subsequently reabsorbed in terrestrial sinks or that other

emissions sources offset any such sequestration.

In the future, EIA plans to report CO2 emissions from

biomass combustion alongside other energy-related

CO2 emissions, but to exclude them from the total

unless their inclusion is dictated by regulation. As

shown in Figure 30, including direct CO2 emissions

from biomass energy combustion would increase the

2008 total for energy-related CO2 emissions by 353

million metric tons (6.1 percent). In the AEO2010

Reference case, including emissions from biomass

would increase the projected 2035 total for energy-related CO2 emissions by 813 million metric tons

(12.9 percent) [78]. If in fact these emissions are all

offset by biological sequestration, the net emissions

would be zero as assumed in EIA’s totals.

Endnotes for Issues in Focus

U.S. Energy Information Administration / Annual Energy Outlook 2010 47

Issues in Focus

2008 2015 2020 2025 2030 2035

0

200

400

600

800

1,000

Figure 30. Carbon dioxide emissions from biomass

energy combustion, 2008-2035 (million metric tons)

38. U.S. Energy Information Administration, “Table 2.

U.S. Energy Nominal Prices” (March 9, 2010), EIA

STEO Table Browser, web site http://tonto.eia.doe.

gov/cfapps/STEO_Query/steotables.cfm.

39. PFC Energy, “OPEC Output and Quotas—December

2009” (December 7, 2009).

40. “Oil Tops Obama’s Saudi Agenda,” UpstreamOnline

(June 3, 2009); “Venezuelan President: Hugo Chavez

Chavez Sets Sights on $80 Oil,” UpstreamOnline (May

27, 2009); “OPEC ‘Waiting on G20 Move’”

UpstreamOnline (March 17, 2009) (subscription site).

41. “Upstream Costs Bottoming Out,” UpstreamOnline

(December 8, 2009) (subscription site).

42. “Upstream Players Face More Costs Pain,”

UpstreamOnline (May 14, 2008) (subscription site).

43. For a thorough discussion of the issues involved in

measuring efficiency, see U.S. Energy Information

Administration, Measuring Energy Efficiency in the

United States’ Economy: A Beginning, DOE/EIA0555(95)/2 (Washington, DC, October 1995), web site

www.eia.doe.gov/emeu/recs/archive/arch_hist_pubs/

hp_pdf/DOE%20EIA-0555%2895%29-2.pdf; and S.J.

Battles and E.M. Burns, “United States Energy Usage

and Efficiency: Measuring Changes Over Time,” Presented at the 17th Congress of the World Energy Council, Houston, TX (September 14, 1998), web site www.

eia.doe.gov/emeu/efficiency/wec98.htm.

44. Energy efficiency and conservation are sometimes

considered closely related aspects of the same concept,

but the NEMS framework focuses on energy efficiency

and classifies all other sources of intensity reduction

as structural elements. The concepts are defined separately in NEMS so as not to overlap. For an alternative

view, see K. Gillingham, R. Newell, and K. Palmer,

“Energy Efficiency Economics and Policy,” Annual

Review of Resource Economics, Vol. 1 (2009), pp.

597–619.

45. Recent attempts to characterize the efficiency-related

factors behind the “California effect” attribute

roughly 25 percent of its lower energy consumption

per capita to efficiency differences. See A.H. Rosenfeld

and D. Poskanzer, “A Graph Is Worth a Thousand

Gigawatt-Hours: How California Came to Lead the

United States in Energy Efficiency,” Innovations, Vol.

4, No. 4 (Fall 2009). Another estimate attributes 23

percent of the 2001 difference in California energy

intensity to efficiency policies. See A. Sudarshan and

J. Sweeney, “Working Paper: Deconstructing the

‘Rosenfeld Curve’” (Precourt Energy Efficiency Center, Stanford University, June 2008), web site http://

piee.stanford.edu/cgi-bin/htm/Modeling/research/

Deconstructing_the_Rosenfeld_Curve.php.

46. S.H. Wade, “Measuring Changes in Energy Efficiency

for the Annual Energy Outlook 2002,” (Washington,

DC, 2002), web site www.eia.doe.gov/oiaf/

analysispaper/efficiency/index.html.

47. A. Jaffe and R. Stavins, “The Energy-Efficiency Gap,”

Energy Policy, Vol. 22, No. 10 (October 1994), pp.

804-810.

48. U.S. Department of Energy, Energy Efficiency and

Renewable Energy, Alternative Fuels and Advanced

Vehicles Data Center, “Alternative Fueling Station

Total Counts by State and Fuel Type,” web site

www.afdc.energy.gov/afdc/fuels/stations_counts.html

(updated on February 28, 2010).

49. The levelized cost calculation assumes that a

20-percent rate of return over a 5-year payback period

would be sufficient to motivate investment in a

standalone natural gas fueling station.

50. In the 2019 Phaseout Base Market case, HDNGV sales

and consequent fuel switching are small enough to fall

within the tolerance of the NEMS model used to produce AEO2010 and are not reported.
48 U.S. Energy Information Administration / Annual Energy Outlook 2010

Issues in Focus

51. Low-sulfur crude oil priced for delivery at Cushing,

Oklahoma, and natural gas priced at the Henry Hub.

52. While simple price comparisons assume the same

point of sale in retail markets, crude oil and natural

gas price comparison reflects unprocessed prices at a

supply node. To describe the ratio in terms of the retail

market, multiple delivered petroleum product prices

would have to be compared to delivered natural gas

prices in the same markets. Because making the comparison at the detailed retail level would require a far

more complex set of comparisons involving different

tax structures and processing costs, the comparison on

the supply side is a useful, if somewhat oversimplified,

comparison that accounts for most of the price divergence described.

53. U.S. Energy Information Administration, Annual

Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June 2009), Table 8.4a, web site www.eia.doe.

gov/emeu/aer.

54. U.S. Energy Information Administration, Annual

Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June 2009), Table 8.4a, web site www.eia.doe.

gov/emeu/aer.

55. Consistent with that reduction has been the abandonment of large-scale storage by electric utilities of

petroleum products for generation.

56. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2010, DOE/EIA0554(2010) (Washington, DC, April 2010), p. 137, web

site www.eia.doe.gov/oiaf/aeo/assumption/pdf/0554

(2010).pdf, p. 137.

57. Favorable natural gas prices in the late 1990s led to a

surge in investments in turbine and combined-cycle

units, to a level that could not be supported when natural gas prices increased. Many of those purchases

were resold at discounts, or installation was postponed

for years.

58. J. Macharia, “Sasol Oryx GTL Plant Has Problems,

Shares Hit,” Reuters (May 22, 2007), web site www.

reuters.com/article/idUSL2206595120070522.

59. Sasol I (2,500 barrels per day), Mossel Bay (45,000 barrels per day), Bintulu (14,700 barrels per day), and

Oryx (34,000 barrels per day).

60. Qatar’s Pearl GTL (140,000 barrels per day), which is

currently anticipated to begin production in 2011, and

Nigeria’s Escravos GTL (34,000 barrels per day),

which is also slated for a 2011 startup. See “Pearl GTL

Sets Milestone as Steam Boilers Start Up,” Gulf Times

(not dated), web site www.gulf-times.com/site/topics/

article.asp?cu_no=2&item_no=345533&version=1&

template_id=48; and J. Macharia and M. Whittaker,

“Update: 2-Sasol’s Nigeria Project Costs Up, Loses on

Oil Hedge,” Reuters (July 29, 2008), web site http://

uk.reuters.com/article/idUKL921344320080729.

61. Including Exxon’s Palm GTL in Qatar (154,000 barrels per day), which was cancelled in 2007. See

National Petroleum Council, “Facing the Hard Truths

About Energy, Topic Paper #9, Gas To Liquids

(GTL)” (July 18, 2007), page 2, web site www.

npchardtruthsreport.org/topic_papers.php.

62. U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2010, DOE/EIA0554(2010) (Washington, DC, April 2010), p. 137, web

site www.eia.doe.gov/oiaf/aeo/assumption/pdf/0554

(2010).pdf, p. 137.

63. S. Reed and R. Tuttle, “Shell Aims for ‘New Nigeria’ as

$19 Billion Qatar Plant Starts” Bloomberg Business

Week (March 3, 2010), web site www.businessweek.

com/news/2010-03-03/shell-aims-for-new-nigeria-as19-billion-qatar-plant-starts.html.

64. Overnight capital costs exclude financing costs during

construction.

65. A 10-year operating period is assumed as a maximum

private-sector investment horizon for such a project.

The 10-year period was chosen based on input from an

EIA workshop held in 2007 that looked at capital

investment decisionmaking. The papers resulting

from that workshop can be found at www.eia.doe.gov/

oiaf/emdworkshop/model_development.html. It is possible that a longer operating period would be appropriate with public financing or loan guarentees. This

would have the effect of lowering the effective

breakeven levels discussed in the article.

66. hydrocarbons-technology.com, “Pearl Gas-to-Liquids

Project, Ras Laffan, Qatar” (not dated), web site www.

hydrocarbons-technology.com/projects/pearl.

67. U.S. Energy Information Administration, Annual

Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June 2009), Table 11.10, web site www.eia.

doe.gov/emeu/aer.

68. U.S. Energy Information Administration, Short Term

Energy Outlook (March 9, 2010 Release), Table 3C,

web site www.eia.doe.gov/emeu/steo/pub/contents.

html.

69. U.S. Nuclear Regulatory Commission, “Reactor

License Renewal Overview” (February 2007), web site

www.nrc.gov/reactors/operating/licensing/renewal/

overview.html.

70. U.S. Nuclear Regulatory Commission, “Backgrounder

on Reactor License Renewal” (November 2009),

web site www.nrc.gov/reading-rm/doc-collections/factsheets/license-renewal-bg.html.

71. U.S. Energy Information Administration, An Analysis

of Nuclear Plant Operating Costs: A 1995 Update,

SR/OIAF/95-01 (Washington, DC, April 1995), web

site http://tonto.eia.doe.gov/ftproot/service/oiaf9501.

pdf.

72. U.S. Department of Energy and U.S. Nuclear Regulatory Commission, “NRC/DOE Workshop on U.S.

Nuclear Power Plant Life Extension Research

and Development: Life Beyond 60” (February

19-21, 2008), web site http://sites.energetics.com/

nrcdoefeb08.

73. Federal Energy Regulatory Commission, “Form 1 –

Electric Utility Annual Report: Data (Current and

Historical),” web site www.ferc.gov/docs-filing/forms/

form-1/data.asp.
U.S. Energy Information Administration / Annual Energy Outlook 2010 49

Issues in Focus

74. Supreme Court of the United States, “Entergy Corp. v.

Riverkeeper, Inc., et al.,” No. 07-588 (October Term,

2008), web site www.supremecourtus.gov/opinions/

08pdf/07-588.pdf.

75. “Biomass energy,” as used here, includes solid, liquid,

and gaseous energy produced from organic nonfossil

material of biological origin.

76. Intergovernmental Panel on Climate Change, 2006

IPCC Guidelines for National Greenhouse Gas Inventories, web site www.ipcc-nggip.iges.or.jp/public/

2006gl/index.html.

77. This is not to say that biomass energy is carbonneutral. Energy inputs are required in order to grow,

fertilize, and harvest the feedstock and to produce and

process the biomass into fuels.

78. Emissions estimates are based on biogenic energy

consumption (see Appendix A, Table A17, “Renewable

Energy by Sector and Source”) and CO2 emissions

factors of 88.45 kilograms CO2 per million Btu for biomass (including wood, wood waste, and biofuels heat

and coproducts), 90.65 kilograms CO2 per million Btu

for biogenic municipal solid waste, 65.88 kilograms

CO2 per million Btu for ethanol, 73.84 kilograms CO2

per million Btu for biodiesel, and 73.15 kilograms CO2

per million Btu for liquids from biomass and green

liquids.

Market Trends

The projections in AEO2010 are not statements

of what will happen but of what might happen,

given the assumptions and methodologies used. The

projections are business-as-usual trend estimates,

reflecting known technology and technological and

demographic trends. AEO2010 generally assumes

that current laws and regulations are maintained

throughout the projections. Thus, the projections

provide a baseline starting point that can be used to

analyze policy initiatives. However, EIA does not

propose or advocate future legislative or regulatory

changes.

While energy markets are complex, energy

models are simplified representations of energy

production and consumption, regulations, and

producer and consumer behavior. Projections are

highly dependent on the data, methodologies, model

structures, and assumptions used in their development. Behavioral characteristics are indicative of

real-world tendencies rather than representations

of specific outcomes.

EIA has endeavored to make these projections as

objective, reliable, and useful as possible; however,

energy markets are subject to much uncertainty.

Many of the events that shape energy markets

cannot be anticipated, including severe weather,

political disruptions, strikes, and technological

breakthroughs. In addition, future developments in

technologies, demographics, and resources cannot

be foreseen with certainty. Many key uncertainties

in the AEO2010 projections are addressed through

alternative cases.
Real gross domestic product returns

to its pre-recession level by 2011

Figure 31. Average annual growth rates of real

GDP, labor force, and productivity in three cases,

2008-2035 (percent per year)

AEO2010 presents three views of economic growth

(Figure 31). The rate of growth in real GDP depends

on assumptions about labor force growth and productivity. In the Reference case, growth in real GDP

averages 2.4 percent per year.

GDP growth is considerably slower in the near term

as a result of the recent recession. The U.S. economy

has seen 10 recessions since 1947 [78]. The 2007-2009

recession is projected to be the longest, with four consecutive quarters of negative growth, and also the

deepest since 1957. In the AEO2010 Reference case,

economic recovery accelerates in 2011, while employment recovers more slowly. Real GDP returns to its

pre-recessionary level by 2011, but unemployment

rates do not return to pre-recessionary levels until

2019.

The AEO2010 High and Low Economic Growth cases

examine the impacts of alternative assumptions

on the economy. The High Economic Growth case

includes more rapid expansion of the labor force, nonfarm employment, and productivity, with real GDP

growth averaging 3.0 percent per year from 2008 to

2035. With higher productivity gains and employment growth, inflation and interest rates are lower in

the High Economic Growth case than in the Reference case. In the Low Economic Growth case, real

GDP growth averages 1.8 percent per year from 2008

to 2035, with slower growth rates for the labor force,

nonfarm employment, and labor productivity. Consequently, the Low Economic Growth case shows

higher inflation and interest rates and slower growth

in industrial output.

Inflation, interest rates remain low,

unemployment exceeds 6 percent

Figure 32. Average annual inflation, interest, and

unemployment rates in three cases, 2008-2035

(percent per year)

In the Reference case, annual consumer price inflation averages 2.2 percent, the annual yield on the

10-year Treasury note averages 5.4 percent, and the

average unemployment rate is 6.3 percent (Figure

32). In the High Economic Growth case, population,

technological change, and productivity grow faster

than in the Reference case, leading to faster growth in

capital stock, labor force, and employment. Potential

output growth is faster, and as a result the real GDP

annual growth rate is 0.5 percent higher than in the

Reference case. In the Low Growth case, productivity,

technological change, population, labor force, and

capital stock grow more slowly, and real GDP growth

is 0.5 percent lower than in the Reference case.

In the first 2 years of the Reference case projection, as

the economy slowly recovers from the recession that

began at the end of 2007, inflation and interest rates

are below their 27-year projected averages of 2.2 and

5.4 percent, respectively, and unemployment rates

are above their long-term average of 6.3 percent. The

recession reduces household wealth, and unemployment remains high as people take longer than in past

recessions to find employment. The unemployment

rate returns to its 2007 rate of 5.8 percent in 2019.

Annual gains in labor productivity average 2.0 percent, underpinning the projections for inflation and

interest rates.

Energy prices for U.S. consumers grow by 2.4 percent

per year from 2008 to 2035 in the Reference case,

compared with 2.2-percent annual growth in overall

consumer prices. For energy commodities, annual

price increases average 2.5 percent per year.

52 U.S. Energy Information Administration / Annual Energy Outlook 2010

Trends in economic activity

Real GDP Labor force Productivity

0.0

1.0

2.0

3.0

4.0

Low Economic Growth

Reference

High Economic Growth

Inflation Interest rates Unemployment

0.0

2.0

4.0

6.0

8.0

10.0 Low Economic Growth

Reference High Economic Growth
Output growth for energy-intensive

industries slows

Figure 33. Sectoral composition of industrial

output growth rates in three cases, 2008-2035

(percent per year)

Industrial sector output has grown more slowly than

the overall economy in recent decades, as imports

have met a growing share of demand for industrial

goods, whereas the service sector has grown more

rapidly [79]. In the AEO2010 Reference case, real

GDP grows at an annual average rate of 2.4 percent

from 2008 to 2035, while the industrial sector and its

manufacturing component grow by 1.4 percent per

year and 1.5 percent per year, respectively (Figure

33). With higher energy prices and greater foreign

competition, the energy-intensive manufacturing sectors grow at a slower rate of 0.8 percent per year,

which reflects a 0.6-percent annual decline for bulk

chemicals and a 1.7-percent annual increase for food

processing.

As the economy recovers from the recent recession,

growth in U.S. manufacturing output in the Reference case accelerates from 2011 through 2020. After

2020, both GDP and manufacturing output return to

growth rates closer to trend. Increased foreign competition, slow expansion of domestic production capacity, and higher energy prices increase competitive

pressure on most manufacturing industries after

2020.

AEO2010 includes a range of possible economic outcomes resulting from different assumptions about

growth in productivity, labor force, and population.

Industrial output grows at annual average rates of

2.1 percent in the High Economic Growth case and

0.5 percent in the Low Economic Growth case.

Energy expenditures decline

relative to Gross Domestic Product

Figure 34. Energy expenditures in the

U.S. economy in three cases, 1990-2035

(trillion 2008 dollars)

Total end-use expenditures for energy in the U.S.

economy were $1.4 trillion in 2008. After falling in

2009, energy expenditures rise to $1.8 trillion (2008

dollars) in 2035 in the AEO2010 Reference case, $2.1

trillion in the High Economic Growth case, and $1.5

trillion in the Low Economic Growth case (Figure 34).

The energy intensity of the economy as a whole, measured as energy consumption (thousand Btu) per dollar of real GDP, was 8.6 in 2008. Structural shifts in

the economy, improvements in energy efficiency, and

rising world oil prices lead to a decline in U.S. energy

intensity to 5.1 in 2035.

Since 2003, rising oil prices have pushed the share of

energy expenditures as a percent of GDP upward; a

9.8-percent share in 2008 was the highest since 1986.

In the AEO2010 Reference case, as energy use

becomes more efficient, its share declines to 6.5 percent of GDP by 2035 (Figure 35).

Figure 35. Energy end-use expenditures as a share

of gross domestic product, 1970-2035 (nominal

expenditures as percent of nominal GDP)

U.S. Energy Information Administration / Annual Energy Outlook 2010 53

Trends in economic activity

1990 2000 2008 2015 2025 2035

0.0

0.5

1.0

1.5

2.0

2.5

Reference

High Economic Growth

Low Economic Growth

History Projections

Industrial sector total

Non-energy-intensive

manufacturing

Energy-intensive

manufacturing

Nonmanufacturing

0.0 1.0 2.0 3.0

Low Economic Growth

Reference

High Economic Growth

0

1970 1990 2008 2020 2035

0

5

10

15

20

25

All energy

Natural gas

Petroleum

History Projections

8.6

1973 2008 2035

Energy intensity

(thousand Btu per

real dollar of GDP)

5.1

17.4
Oil price cases depict uncertainty

in world oil markets

Figure 36. Average annual world oil prices

in three cases, 1980-2035 (2008 dollars per barrel)

World oil price projections in AEO2010, defined in

terms of the average price of low-sulfur, light crude oil

delivered to Cushing, Oklahoma, span a broad range

reflecting the inherent volatility and uncertainty of

world oil prices (Figure 36). The AEO2010 price paths

are not intended to reflect absolute bounds for future

oil prices, but rather to allow analysis of the implications of world oil market conditions that differ from

those assumed in the Reference case. The AEO2010

Reference case assumes a continuation of current

trends in terms of economic access to non-OPEC resources and OPEC market share of world production.

The High Oil Price case depicts a future world oil

market in which conventional production is restricted by political decisions and economic access to

resources: use of quotas, fiscal regimes, and various

degrees of access restrictions by the major producing

countries decrease their oil production, and consuming countries turn to high-cost unconventional

liquids production to satisfy demand. The OPEC

share of liquids production is lower than in the Reference case.

The Low Oil Price case depicts a future world oil market in which non-OPEC producing countries develop

stable fiscal policies and investment regimes directed

at encouraging development of their resources. In the

Low Price case, OPEC nations increase production in

order to achieve approximately a 50-percent market

share of total liquids production by 2035, up from

approximately 42 percent in 2008.

World liquids supply remains

geographically diversified

Figure 37. World liquids production shares

by region in three cases, 2008 and 2035 (percent)

OPEC production decisions are the most significant

factor underlying differences among the price cases.

In the Reference case, OPEC conventional production

maintains approximately a 40-percent share of total

world liquids production through 2035, consistent

with levels over the past 15 years. In the High Oil

Price case, OPEC’s share of world liquids production

declines to 35 percent; in the Low Oil Price case,

OPEC’s share expands to almost 50 percent (Figure

37). In all the cases, total liquids production by countries in the Organization for Economic Cooperation

and Development is between 21 and 27 million barrels per day in 2035, constrained mainly by resource

availability rather than price or political concerns.

In the High Oil Price case, several non-OPEC countries with large resource holdings (including Russia,

Brazil, Mexico, and Kazakhstan) either maintain or

further restrict opportunities for investment in domestic resource development, limiting their contribution to the total world liquids supply. Political, fiscal,

and resource conditions in each of those countries are

unique. However, all will require domestic and foreign investment to develop new projects and maintain

infrastructure, and all have recently either not

encouraged such investment or indicated that they

may enact future restrictions on foreign investment.

In the Low Oil Price case, several resource-rich

nations outside OPEC, including Russia and Brazil,

are assumed to change legislation or fiscal terms in

order to encourage foreign investment in the development of their liquids resources. As a result, the largest increases in liquids supply among the non-OPEC

countries occur in Russia, Brazil, and Kazakhstan.

54 U.S. Energy Information Administration / Annual Energy Outlook 2010

International oil markets

1980 1995 2008 2020 2035

0

50

100

150

200

250

Reference

Low Oil Price

History Projections

High Oil Price

2008 Low

OilPrice Reference

2035

High

Oil Price

0

20

40

60

80

100

Central/South America

Europe and Eurasia

North America

Far East

Africa/Middle East

Other OPEC

OPEC Persian Gulf
Unconventional liquids gain

market share as prices rise

Figure 38. Unconventional resources as a share of

total world liquids production in three cases,

2008 and 2035 (percent)

World production of liquid fuels from unconventional

resources in 2008 was 4.0 million barrels per day, or

about 5 percent of total liquids production. In the

AEO2010 projections, production from unconventional sources grows to about 13, 15, and 19 million

barrels per day in 2035 in the Low Oil Price, Reference, and High Oil Price cases, respectively, accounting for about 10, 13, and 21 percent of total world

liquids production (Figure 38).

The factors most likely to affect production levels

vary for the different types of unconventional liquid.

Price is the most important factor for bitumen production from Canadian oil sands, because the fiscal

regime and extraction technologies remain relatively

constant, regardless of world oil prices. Production of

Venezuela’s extra-heavy oil depends more on the prevailing investment environment and the assumed

government-imposed levels of economic access to

resources in the different price cases. In the Low Oil

Price case, with more foreign investment in extraheavy oil, production in 2035 climbs to nearly 3.4

million barrels per day. In the Reference and High Oil

Price cases, with growing investment restrictions,

extra-heavy oil production is limited to 1.3 and 0.8

million barrels per day, respectively, in 2035.

Production levels for biofuels, CTL, and GTL are

driven largely by the needs of consuming nations—

particularly, the United States and China, to compensate for restrictions on economic access to conventional liquid resources. In the Low Oil Price and High

Oil Price cases, production from those three sources

in 2035 totals 5.3 million barrels per day and 12.3 million barrels per day, respectively.

U.S. average energy use per person

declines through 2035

Figure 39. Energy use per capita and per dollar of

gross domestic product, 1980-2035 (index, 1980 = 1)

Growth in U.S. energy use is linked to population

growth through increases in demand for housing,

commercial floorspace, transportation, manufacturing, and services. This affects not only the level of energy use, but also the mix of fuels and consumption by

sector. Energy consumption per person has declined

sharply during the recent economic recession, and the

2009 level of 310 million Btu per person was the

lowest since 1968. In the AEO2010 Reference case,

energy use per capita increases slightly as the economy rebounds, then begins declining in 2013 as

higher efficiency standards for vehicles and lighting

begin to take effect (Figure 39). From 2013 to 2035,

energy use per capita declines by 0.3 percent per year

on average, to 293 million Btu in 2035.

Energy intensity (Btu of energy use per dollar of real

GDP) also falls as a result of structural changes and

efficiency improvements. Since 1990, a growing share

of U.S. output has come from services and less from

manufacturing. In 1990, 74 percent of the total value

of output came from services, 6 percent from energyintensive manufacturing industries, and the balance

from the non-energy-intensive manufacturing industries (e.g., agriculture, mining, and construction). In

2008, services accounted for 78 percent of total output

and energy-intensive manufacturing only 5 percent.

Services continue to play a growing role in the Reference case, accounting for 82 percent of total output in

2035, with energy-intensive manufacturing accounting for less than 4 percent. In combination with

improvements in energy efficiency, the shift away

from energy-intensive industries pushes overall

energy intensity down by an average of 1.9 percent

per year from 2008 to 2035.

U.S. Energy Information Administration / Annual Energy Outlook 2010 55

U.S. energy demand

1980 1995 2008 2020 2035

0.0

0.2

0.4

0.6

0.8

1.0

1.2 History Projections

Energy

use per

dollar

of GDP

Energy

use per

capita

2008 Low Oil Price Reference

2035

High Oil Price

0

5

10

15

20

25

GTL

Biofuel

Extra-heavy oil

Bitumen

CTL

Oil shale
Buildings and transportation sectors

lead increases in primary energy use

Figure 40. Primary energy use by end-use sector,

2008-2035 (quadrillion Btu)

Total primary energy consumption, including fuels

for electricity generation, grows by 0.5 percent per

year from 2008 to 2035, to 114.5 quadrillion Btu in

2035 in the Reference case (Figure 40). The fastest

growth (1.0 percent annually) is in the commercial

sector, which currently has the smallest share of

end-use energy demand but surpasses the residential

sector by the end of the period. Growth in commercial

sector energy use is propelled by growth in population

(0.9 percent per year) and commercial floorspace (1.3

percent per year), but it is constrained somewhat by

tightening efficiency standards.

Energy use for transportation grows by 0.6 percent

per year in the Reference case. LDVs have accounted

for more than 16 percent of total U.S. energy consumption since 2002; however, their share declines to

15.5 percent in 2020, when the average fuel economy

of new LDVs is required by EISA2007 to reach 35.5

mpg. Growth in energy consumption by LDVs averages 0.4 percent per year from 2008 to 2035.

Energy consumption in the industrial sector grows

only modestly through 2035, as U.S. output continues

to shift toward less energy-intensive industries. Use

of liquefied petroleum gas (LPG) feedstocks in the

production of ethylene, propylene, and ammonia,

which contributes to the small increase, declines

after 2020 as output from the chemical industry falls.

Energy consumption in the refining sector also grows,

as liquids consumption increases and more biofuels

are produced to meet the RFS required by EISA2007.

Renewable sources lead rise in

primary energy consumption

Figure 41. Primary energy use by fuel, 1980-2035

(quadrillion Btu)

Consumption of all fuels increases in the Reference

case, but the aggregate fossil fuel share of total energy

use falls from 84 percent in 2008 to 78 percent in 2035

as renewable fuel use grows rapidly (Figure 41). The

renewable share of total energy use increases from

8 percent in 2008 to 14 percent in 2035, in response to

the EISA2007 RFS, expansion of Federal tax credits

for renewable electricity generation and capacity, and

State RPS programs.

In the transportation sector, where almost all liquid

biofuels are used, petroleum’s share of liquid fuel use

declines as consumption of alternative fuels (biodiesel, E85, and ethanol for blending) increases.

Biofuels account for more than 80 percent of the

growth in liquid fuel consumption.

Overall, natural gas consumption grows by about 0.2

percent per year from 2008 to 2035, despite declines

of about 1.5 percent per year from 2008 through 2014,

when coal-fired power plants now under construction

or planned begin operation, and Federal tax credits

and State RPS programs spur additions of new electricity generation capacity fired by renewable fuels.

Coal consumption increases by 0.4 percent per year in

the Reference case. Several coal-fired power plants,

with combined capacity totaling 15.6 gigawatts, are

planned to come on line by 2012. More coal is

consumed for heat and power in the CTL process, offsetting declines in coal consumption for coking and

other industrial uses.

56 U.S. Energy Information Administration / Annual Energy Outlook 2010

U.S. energy demand

2008 2015 2020 2025 2030 2035

0

25

50

75

100

125

Transportation

Industrial

Commercial

Residential

1980 1995 2008 2020 2035

0

20

40

60

80

100

120

Total

History Projections

Natural gas

Nuclear

Coal

Liquids

Biofuels

Renewables
Residential energy use per capita

varies with technology assumptions

Figure 42. Residential delivered energy

consumption per capita in four cases, 1990-2035

(index, 1990 = 1)

Residential energy use per capita continues declining

in the AEO2010 Reference case, to 16 percent below

the 2008 level in 2035 (Figure 42). One cause of the

decline is a decrease in energy use for space heating

due to a projected shift in State populations from

colder to warmer regions. The reduced demand for

home heating fuels is offset in part by increased

demand for electric air conditioning.

Recent improvements in household energy efficiency

have been offset by growth in square footage and

the introduction of new electric appliances. Three

alternative cases show the potential role of energyefficient technologies in defining household energy

use. The 2009 Technology case assumes no change in

efficiency for equipment or building shells beyond

2009 levels. The High Technology case assumes more

purchases of energy-efficient appliances by consumers, and earlier availability, lower cost, and higher

efficiency for some advanced electric devices. The

Best Available Technology case limits purchases of

new appliances to the most efficient available and

assumes that new home construction applies the

most energy-efficient criteria among today’s common

building practices.

In the 2009 Technology case, household energy use

per capita falls by 10 percent from 2008 to 2035,

as gains in energy efficiency are limited to stock

turnover and more efficient new construction. With

greater gains for appliances and building shells in the

High Technology and Best Available Technology

cases, household energy use per capita declines by

30 percent and 39 percent, respectively, from 2008 to

2035.

Miscellaneous uses dominate growth

in electricity demand

Figure 43. Change in residential electricity

consumption for selected end uses in the Reference

case, 2008-2035 (billion kilowatthours)

Electricity accounted for 41 percent of total residential delivered energy consumption in 2008, and in the

AEO2010 Reference case that portion increases to 48

percent in 2035. The increase in electricity consumption results from a proliferation of new electric

devices. Comparatively few new devices powered by

natural gas or liquids have emerged in recent decades,

and few are anticipated in the Reference case. Electric

appliances have become increasingly prevalent, and

that trend continues as demand grows for largescreen televisions (TVs) and other electric devices.

Electricity use for TV sets and set-top boxes surpasses

that for refrigerators in 2010. Set-top boxes, including digital video recorders, are needed to decode

digital signals from cable or satellite providers and to

convert digital signals for older analog TVs. TVs on

the market today vary significantly with respect to

power draw, depending on technology and screen

size. The technology continues to evolve, and improvements in efficiency are expected with the introduction of light-emitting diode (LED) backlighting

for TV screens and with new efficiency standards

adopted in California.

Other electrically powered services include a range of

appliances and devices whose consumption, while

small individually, is significant in the aggregate

(Figure 43). Electricity use for “other” devices—

including microwave ovens, video and audio equipment, game systems, spas, security systems, and

coffee makers—increases on average by 1.9 percent

per year in the Reference case—slightly more

than the 1.6-percent annual growth in residential

floorspace.

U.S. Energy Information Administration / Annual Energy Outlook 2010 57

Residential sector energy demand

1990 2000 2008 2015 2025 2035

0.4

0.6

0.8

1.0

1.2

History Projections

2009 Technology

High Technology

Reference

Best Available

Technology

-100 -50 0 50 100 150 200

Lighting

PCs and related equipment

Laundry and dishwashing

Water heating

Refrigeration and cooking

TVs and set-top boxes

Heating, cooling, and ventilation

Other (miscellaneous)
New approaches to energy efficiency

standards show potential for gains

Figure 44. Energy intensity for selected end uses of

electricity in the residential sector in three cases,

2008 and 2035 (kilowatthours per year)

The energy efficiency of residential appliances plays a

key role in determining the amount of energy used in

buildings. In recent years, the implementation of

Federal standards has fallen behind legislated schedules, leading States and other groups to become more

active in promoting residential energy efficiency. In

2009, industry and efficiency advocate groups agreed

on a set of regional standards to supplant the national

standards currently in place. The new standards

would divide the Nation into three regions based on

climate characteristics for furnaces, heat pumps, and

central air conditioners [80].

The absence of appliance standards has implications

for energy use. Neither televisions nor set-top boxes

are covered by Federal standards today, although

some efficiency gains have been realized through

voluntary programs, such as Energy Star. In the

absence of standards, electricity use for personal

computers and related equipment (e.g., printers,

modems, and routers) grows at roughly the same rate

as population in the Reference case.

The potential effects of new efficiency standards are

most evident for lighting (Figure 44). Federal standards included in EISA2007 will require generalservice lighting to use about 30 percent less electricity

by 2014 for the same level of light output. In 2020, the

standard is tightened further, requiring generalservice lighting to use 60 percent less electricity than

today’s incandescent bulbs. Overall, in the AEO2010

Reference case, electricity use for lighting per household in 2035 is 44 percent lower than in 2008.

Tax credits encourage installation

of renewable technologies

Figure 45. Residential market saturation

by renewable technologies in two cases, 2008, 2020,

and 2035 (percent share of single-family homes)

More than one-half of the States have either binding RPS or nonbinding voluntary targets for renewable energy generation. The recent enactment of

Federal ITCs for distributed renewable technologies

through 2016 provides the greater assurance necessary for market development that will help States

achieve their renewable energy goals.

The AEO2010 Reference case assumes that Federal

tax credits for distributed renewable technologies

will expire as scheduled. The Extended Policies case

shows the implications of extending the tax credits

indefinitely. Whereas total installed PV capacity

reaches 9.5 gigawatts in 2035 in the Reference case, it

grows to 60.5 gigawatts in 2035 in the Extended

Policies case. The comparatively smaller distributed

wind turbine market is similarly affected, with 8.1

gigawatts installed in the Extended Policies case, as

compared with 1.7 gigawatts in the Reference case, in

2035.

Ground-source heat pumps are more energy efficient—but also more expensive—than conventional

technologies. In the Reference case, implementation

of current incentives increases the number of installations from 47,000 units in 2008 to an average of

more than 150,000 units per year through 2016, when

the Federal tax credit expires. Even with the increase

in installations, however, the market share of

ground-source heat pumps is only 2.3 percent in 2035

in the Reference case, up from 0.3 percent in 2008

(Figure 45). In the Extended Policies case—with the

tax credit extended through 2035—the market share

nearly doubles, to 4 percent in 2035.

58 U.S. Energy Information Administration / Annual Energy Outlook 2010

Residential sector energy demand

Lighting Central air

conditioners

Water

heating

TVs and PCs

0

500

1,000

1,500

2,000

2,500

3,000

2009 Technology

Reference

Technology

Best Available

2008

2035 Solar

Ground-source

Solar

Ground-source

Solar

Ground-source

0.0 2.0 4.0 6.0 8.0 10.0 12.0

Reference

Extended Policies

2008

2020

2035

photovoltaics

heat pumps

heat pumps

heat pumps

photovoltaics

photovoltaics

0
Efficiency improvements could lower

projected consumption growth

Figure 46. Commercial delivered energy

consumption per capita in four cases, 1990-2035

(index, 1990 = 1)

Growth in commercial floorspace averages 1.3 percent per year from 2008 to 2035 in the AEO2010 Reference case, exceeding the 0.9-percent average for

population growth over the period. Delivered commercial energy use per person remains virtually constant, however, as efficiency improvements largely

offset the increase in commercial floorspace (Figure

46). Recently updated standards for lighting and refrigeration account for much of the efficiency improvement. More stringent building codes in ARRA

further improve building efficiency in the long term.

Three alternative cases show the effects of different

assumptions about technology and energy efficiency

on energy consumption per capita. The 2009 Technology case limits equipment and building shell technologies to the options available in 2009. The High

Technology case assumes lower costs, higher efficiencies for equipment and building shells, and earlier

availability of some advanced equipment than in the

Reference case, as consumers place greater importance on the value of future energy savings. The Best

Available Technology case assumes more improvement in the efficiency of building shells than in the

High Technology case and limits future equipment

choices to a technology menu that includes only the

most efficient model for each type of technology available in a particular year, regardless of cost. In 2035,

commercial energy consumption per capita is 4.8 percent higher in the 2009 Technology case than in the

Reference case, and in the High Technology and

Best Available Technology cases it is 12.5 percent

and 17.5 percent lower than in the Reference case,

respectively.

Electricity leads expected growth

in commercial energy use

Figure 47. Average annual growth rates for

selected electricity end uses in the commercial

sector, 2008-2035 (percent per year)

Purchased electricity use accounts for 59 percent of

all commercial delivered energy consumption in 2035

in the Reference case, up from 54 percent in 2008. Despite growth in natural gas use for CHP, the natural

gas and liquids share of commercial energy use declines as the efficiency of building and equipment

stocks improves and demand for new electronic

equipment continues to grow.

Major commercial end uses, such as space heating

and cooling, water heating, and lighting, are covered

by Federal and State efficiency standards, limiting

growth in consumption to rates less than the

1.3-percent annual growth in commercial floorspace

(Figure 47). Other electric end uses, some of which

are not subject to Federal standards, account for most

of the growth in commercial electricity consumption.

Although the number of computers and related

devices (such as monitors and printers) grows more

rapidly than floorspace, with increasing purchases

and use of Energy Star equipment their electricity

use grows at less than half the rate of floorspace. As

reliance on the Internet for information and data

transfer increases, electricity use for “other” office

equipment—including servers and mainframe computers—surpasses that for commercial refrigeration

in 2018. Refrigeration is one of the few commercial

end uses for which electricity use declines in the Reference case, primarily as a result of new efficiency

standards. Electricity demand for other miscellaneous end uses (e.g., video displays and medical

devices) increases by an average of 2.3 percent per

year and, in 2035, accounts for 40 percent of end-use

electricity consumption in the commercial sector.

U.S. Energy Information Administration / Annual Energy Outlook 2010 59

Commercial sector energy demand

1990 2000 2008 2015 2025 2035

0.8

0.9

1.0

1.1

1.2

History Projections

Reference

High Technology

Best Available

Technology

2009 Technology

-0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0

Commercial floorspace (1.3 percent per year)

Refrigeration

Cooking

Lighting

Other (miscellaneous)

Office equipment: other

Office equipment: personal computers

Heating, cooling, and ventilation

0
Technology provides potential energy

savings in the commercial sector

Figure 48. Efficiency gains for selected commercial

equipment in three cases, 2035 (percent change

from 2008 installed stock efficiency)

Delivered energy consumption for space heating,

cooling, and water heating grows at an average

annual rate of 0.4 percent in the Reference case, as

compared with 1.3-percent annual growth in commercial floorspace. The remaining end uses in the

commercial sector grow by 1.2 percent per year as

a group in the Reference case, but by only 0.5 percent

in the Best Available Technology case.

Lighting improvements have consistently been a

source of efficiency gains, as standards for fluorescent

lamps and ballasts, incandescent reflector lamps, and

metal halide lamp fixtures have reduced their

electricity consumption. Incandescent bulbs, which

already are less common in the commercial sector, are

nearly eliminated by 2014 as compliance with

EISA2007 lighting standards increases. Significant

potential for further improvement remains, as shown

by the Best Available Technology case (Figure 48);

however, many of those best available technologies,

such as LED lighting, currently are too costly to be

practical in many commercial applications.

The energy efficiency of refrigeration equipment improves significantly in each of the cases, as a result of

EPACT2005 and EISA2007 standards, which are in

place for a wide range of commercial equipment that

accounts for a significant share of the sector’s total

electricity use for refrigeration. Additional efficiency

improvements could come from the actions of States

applying their own equipment standards for end uses

not covered by Federal mandates. In addition, at the

Federal level, new research and development funding

from ARRA may lead to efficiency improvements in

communication and information technology devices.

Tax credits, advanced technologies

could boost distributed generation

Figure 49. Additions to electricity generation

capacity in the commercial sector in two cases,

2008-2035 (gigawatts)

Recent legislation has extended or increased the ITCs

for distributed generation technologies and removed

the cap on credits for wind-powered generation. In

the Reference case, tax credits boost the near-term

expansion of distributed generation in the commercial sector, and its growth remains strong in later

years as technology costs decline, conversion efficiency improves, and electricity prices increase.

PV capacity benefits from a 30-percent ITC through

2016 and reverts to a 10-percent credit thereafter

(Figure 49). Conventional natural-gas-fired turbines

and engines account for the next-largest capacity increase, followed by microturbines and fuel cells. Wind

power also benefits from the ITC, growing by 8.7 percent per year. Conventional CHP technology receives

a 10-percent tax credit through 2016. Comparatively

expensive fuel cells receive a 30-percent ITC capped

at $3,000 per kilowatt.

In the Reference case, commercial distributed generating capacity grows from 2 gigawatts in 2008 to

almost 10 gigawatts in 2035. In the Extended Policies

case, which assumes that the ITC provisions are extended through 2035, total commercial generating capacity increases by 17 gigawatts. PV technology

benefits the most from the extension of the ITC provisions in the Extended Policies case, with installed

capacity in 2035 that is 125 percent higher than in the

Reference case. After 2016, with the extension of the

ITC, wind power capacity in the commercial sector

grows the fastest, averaging more than 16 percent

per year from 2016 to 2035.

60 U.S. Energy Information Administration / Annual Energy Outlook 2010

Commercial sector energy demand

LightingRefrigerationElectric

space

cooling

Natural gas

heating

Space Water

Ventilation

0

50

100

150

200

2009 Technology

Reference

Best Available Technology

Solar

photovoltaics

Wind Conventional

natural-gasfired CHP

MicroturbinesFuel

cells

0

2

4

6

8 Reference

Extended Policies
Heat and power energy consumption

increases in manufacturing industries

Figure 50. Industrial delivered energy consumption

by application, 2008-2035 (quadrillion Btu)

Industrial delivered energy consumption increases

by 8 percent from 2008 to 2035 in the AEO2010 Reference case—despite a 44-percent increase in industrial

shipments—as a result of slow growth or declines

in energy-intensive manufacturing output and strong

growth in high-value (but less energy-intensive)

industries, such as computers and electronics. In the

chemical industry, output declines by nearly 10 percent from 2008 to 2035 in the face of rising energy

prices and pressure from overseas competition.

In 2008, about two-thirds of delivered energy consumption in the industrial sector was used for heat

and power in manufacturing; that share increases to

three-quarters in 2035 (Figure 50). Heat and power

consumption in the nonmanufacturing industries

(agriculture, mining, and construction) remains

constant over the projection, accounting for about

one-sixth of total industrial energy consumption. The

remaining consumption consists of nonfuel uses of

energy products, primarily as feedstocks in chemical

manufacturing and asphalt for construction.

The rise in manufacturing heat and power consumption in the AEO2010 Reference case can be attributed

primarily to a relatively large 36-percent increase in

total energy use for the refining industry (although

the value of shipments produced by the refining industry grows by only 11 percent over the same period). The strong growth in fuel use for refining

results from higher industrial demand for lighter

feedstocks, changes in the production mix as demand

for diesel fuels increases, a shift by refineries from

lighter to heavier crude oils, and growth in biofuels

production.

Use of fuels as feedstocks declines

in the chemical industry

Figure 51. Industrial consumption of fuels

for use as feedstocks by fuel type, 2008-2035

(quadrillion Btu)

The use of fuels for feedstock in the industrial sector

involves the consumption of fuels as raw materials

for the production of various chemicals, as well as the

consumption of asphalt and road oil for the building

of roads in the construction industry. Most of the

consumption of fuel-based feedstocks occurs in the

chemical industry, primarily for the production of

ethylene, propylene, and butadiene—three chemicals

that are basic to the production of a variety of plastic

products.

Feedstock consumption trends in the AEO2010 Reference case reflect a switch from petrochemical feedstocks (naphtha and gas oils) to LPG feedstocks

(ethane, butane, and propane) and a decline in basic

chemical production. The shift occurs because of a

growing divergence between more rapidly rising

crude oil prices, which are the basis for petrochemical

feedstock prices, and the slow pace of increase in

natural gas prices—the primary basis for LPG prices.

From 2008 to 2035, total energy use as a feedstock

declines by 6 percent in the industrial sector (Figure

51). Virtually all the decline is in the use of natural

gas feedstocks, which drops by 21 percent as domestic

production of ammonia, hydrogen, and methanol

slows. Domestic ammonia production falls by 6 percent as a result of slow growth in agricultural

production and foreign competition in the ammonia

industry. Domestic outputs of hydrogen and methanol decline even more, by 74 percent and 32 percent,

respectively. Consumption of asphalt and road oil

remains flat in the Reference case, reflecting slow

growth in the construction industry.

U.S. Energy Information Administration / Annual Energy Outlook 2010 61

Industrial sector energy demand

2008 2015 2020 2025 2035

0

5

10

15

20

25

Nonfuel uses

Nonmanufacturing heat and power

Manufacturing heat and power

2008 2015 2020 2025 2035

0

1

2

3

Natural gas

Petrochemicals

Liquefied petroleum gas

Asphalt
Over time, more fuels are brought

into the mix of industrial energy use

Figure 52. Industrial energy consumption by fuel,

2003, 2008, and 2035 (quadrillion Btu)

Liquid fuels and natural gas currently account for

about two-thirds of industrial delivered energy use,

and electricity, coal, and renewables make up the

remainder (Figure 52). With fuel-switching opportunities often limited to boilers, kilns, and some feedstocks, changes in fuel shares tend to reflect longterm transitions among the mix of industries and

capital investment. Although their use is declining,

liquid fuels and natural gas are the leading industrial

fuel sources throughout the projections. Almost onehalf of industrial liquid fuel consumption is for use as

a feedstock for the production of petrochemicals.

Another large portion (28 percent) is generated as byproduct fuel and consumed at refineries. The decline

in industrial use of liquid fuels and natural gas reflects a drop in chemical production, which accounted

for a large share of industrial use of the two fuels

(excluding natural gas lease and plant fuel) in 2008.

Increased coal use for CTL production more than offsets a decline in traditional industrial applications of

coal, such as steam generation and coke production,

largely because of environmental concerns about

emissions from coal-fired boilers, along with improvements in manufacturing efficiency that reduce the

need for process steam. Metallurgical coal use also

declines, reflecting a decline in steel industry output

and the greater penetration of electric arc furnaces.

The flat outlook for industrial electricity use reflects

efficiency gains in many industries, due in part to

motor efficiency standards. In addition, consumption

of renewable energy in the industrial sector expands

with expected growth in the lumber, paper, and other

industries that consume biomass-based byproducts.

Output growth is strongest for food

and non-energy-intensive industries

Figure 53. Cumulative growth in value of

shipments by industrial subsector in three cases,

2008-2035 (percent)

Industrial shipments vary across the AEO2010 economic growth cases, both in aggregate and by industry. Total industrial shipments grow by 44 percent

from 2008 to 2035 in the Reference case, as compared

with 16 percent in the Low Economic Growth case

and 74 percent in the High Economic Growth case.

Near-term industrial activity is slowed by the economic recession, however, with shipments from 2008

to 2011 lower for most industries and in particular for

iron and steel, cement, aluminum, transportation

equipment, and machinery.

A few energy-intensive manufacturing industries

account for a large share of total industrial energy

consumption. Ranked by their 2008 total energy use,

the top five energy-consuming industries—bulk

chemicals, refining, paper, steel, and food—accounted

for about 60 percent of total industrial energy consumption but only 22 percent of total value of shipments. From 2008 to 2035, four of those top five

industries (with food products being the exception),

as well as the other energy-intensive industries

(glass, cement, and aluminum) grow more slowly

than the non-energy-intensive industries (Figure 53).

The relatively slow growth of energy-intensive manufacturing industries in the Reference case results

from increased foreign competition, reduced domestic

demand for the raw materials and basic goods they

produce, and movement of investment capital to

more profitable areas of the economy.

62 U.S. Energy Information Administration / Annual Energy Outlook 2010

Industrial sector energy demand

Bulk chemicals

Petroleum refineries

Paper products

Iron and steel

Food products

Other manufacturing

Agriculture,

construction, mining

-50 0 50 100 150

Low Economic Growth

Reference

High Economic Growth

2003 2008 2035

0

2

4

6

8

10

Electricity

Natural gas

Liquid fuels

Renewables

Coal
Energy consumption growth varies

widely across industry sectors

Figure 54. Change in delivered energy

consumption for industrial subsectors in three

cases, 2008-2035 (quadrillion Btu)

The projections for industrial energy consumption

vary by industry (Figure 54) and are subject to considerable uncertainty. Industrial delivered energy consumption grows by 8 percent from 2008 to 2035 in the

Reference case, declines by 9 percent in the Low

Economic Growth case, and increases by 25 percent

in the High Economic Growth case.

In absolute terms, the most significant changes in

energy use are in the three largest energy-consuming

industries: bulk chemicals, iron and steel, and refining. For the first two, declines in energy use in most

cases reflect changes in competition from countries

with access to less expensive energy sources, as well

as changes in product mix. Energy consumption in

the refining industry increases—despite a relatively

flat trend in overall petroleum demand—given the

industry’s needs to process heavier crude oils, comply

with low-sulfur fuel standards, and produce biofuels

as mandated in EISA2007. Energy use also increases

in the food and paper and pulp industries, where rising shipments reverse recent declines. For the

cement, aluminum, and “other nonmanufacturing”

industries, delivered energy consumption declines,

primarily as a result of relatively slow output growth

and long-term changes in production technology.

Aggregate industrial energy intensity, or consumption per real dollar of shipments, declines in all three

cases. When a higher rate of economic growth is

assumed the decline is more rapid, because nonenergy-intensive output grows relatively more rapidly: 1.4 percent in the High Economic Growth case, as

compared with 1.2 percent in the Reference case and

1.0 percent in the Low Economic Growth case.

Growth in transportation energy use

slows relative to historical trend

Figure 55. Delivered energy consumption for

transportation by mode, 2008 and 2035

(quadrillion Btu)

From 2008 to 2035, transportation sector energy consumption grows at an average annual rate of 0.6 percent (from 27.9 quadrillion Btu to 32.5 quadrillion

Btu), slower than the 1.3-percent average rate from

1980 to 2008. The slower growth is a result of changing demographics, improved fuel economy, and increased saturation of personal travel demand.

Energy demand for LDVs increases by 10 percent, or

1.7 quadrillion Btu (0.8 million barrels per day), from

16.7 quadrillion Btu in 2008 (Figure 55). Slower

growth in fuel prices compared with recent history

and rising real disposable income combine to increase

annual VMT. Delivered energy consumption by LDVs

is tempered by fuel economy improvements that result from more stringent standards for vehicle fuel

economy and CO2 emissions. Energy demand for

heavy-duty vehicles (including freight trucks and

buses) increases by 37 percent, as a result of only slow

improvement in fuel economy and modest increases

in industrial output.

Energy demand for air travel increases by 24 percent,

or 0.6 quadrillion Btu (0.3 million barrels per day),

from 2.6 quadrillion Btu in 2008. Growth in personal

air travel is driven by increases in income per capita

and relatively low fuel costs; however, gains in aircraft fuel efficiency and slow growth in air freight

movement (caused by slow growth in imports) combine to slow the increase in fuel use by aircraft. Energy consumption for marine and rail travel increases

slightly as industrial output rises and demand for coal

transport grows. Energy use for pipelines increases as

growing volumes of natural gas and biofuels are

transported.

U.S. Energy Information Administration / Annual Energy Outlook 2010 63

Transportation sector energy demand

Light-duty vehicles

Heavy-duty vehicles

Air

Marine

Rail

Pipeline

Total

0 10 20 30 40

2008

2035

Bulk chemicals

Liquids refining

Paper products

Iron and steel

Food products

Other manufacturing

Agriculture,

construction, mining

-2 -1 012

Low Economic Growth

Reference

High Economic Growth
New CAFE and emissions standards

boost vehicle fuel efficiency

Figure 56. Average fuel economy of new light-duty

vehicles in five cases, 1980-2035 (miles per gallon)

Light trucks (pickups, SUVs, and vans) have claimed

a rising share of U.S. LDV sales since the 1970s, peaking at over 55 percent of new LDV sales in 2004 before

dropping to just over 47 percent in 2009 [81]. Thus,

despite technology improvements, average fuel economy for new LDVs ranged between 24 and 26 mpg

from 1995 to 2006 after peaking at 26.2 mpg in 1987,

then rose to 26.6 mpg in 2007 with higher fuel prices

and introduction of tighter fuel economy standards.

NHTSA and EPA have proposed attribute-based

CAFE and emissions standards for MY 2012 to 2016.

In the Reference case, the average fuel economy of

new LDVs (including credits for AFVs and banked

credits) rises from 29 mpg in 2011 to 34 mpg in 2016

and 35.6 mpg in 2020, averaging 3.1 percent per year

from 2011 to 2016 and 1.2 percent per year from 2016

to 2020 (Figure 56). EISA2007 requires an average of

35 mpg in 2020.

LDV sales in 2035 are about 19 million units in all the

AEO2010 cases, but the mix of cars and light trucks

varies. In the Reference case, cars represent 66 percent of sales in 2035, and LDV fuel economy averages

40 mpg. In the High Oil Price case, cars are 69 percent

of sales in 2035, and LDV fuel economy averages 43

mpg. In the Low Oil Price case, cars are 57 percent of

sales in 2035, and LDV fuel economy averages 37

mpg. Economics of fuel-saving technologies improve

in the High Technology and High Oil Price cases, and

consumers buy more efficient vehicles. But average

fuel economy improves modestly, because the CAFE

standards assumed in the two cases already require

significant improvement in fuel economy performance and the penetration of advanced technologies.

New technologies promise

better vehicle fuel efficiency

Figure 57. Market penetration of new technologies

for light-duty vehicles, 2035 (percent)

In the AEO2010 Reference case, the fuel economy of

new LDVs improves from 27.6 mpg in 2008 to 40.0

mpg in 2035. Market adoption of advanced technologies facilitates the improvement in fuel economy that

will be needed to meet new, more stringent CAFE

standards (Figure 57).

In 2035, advanced drag reduction, which provides

significant fuel economy improvements by reducing

vehicle air resistance at higher speeds, is implemented in nearly 99 percent of new LDVs. With the

adoption of light-weight materials that reduce vehicle

mass, the average weight of new cars declines from

3,264 pounds in 2008 to 3,112 pounds in 2035, providing significant improvements in fuel economy. In

addition, adoption of advanced transmission technologies, such as continuous variable and automated

manual transmissions, grows from 5 percent of the

LDV market in 2008 to 43 percent in 2035.

Camless valve activation, which reduces engine friction and allows for infinitely variable valve timing

and lift, increases engine efficiency by approximately

14 percent. After its introduction in 2020, camless

valve activation is implemented in 30 percent of the

LDVs marketed by 2035. Other technologies that improve fuel economy—including turbocharging, supercharging, and cylinder deactivation—increase from a

5-percent share of new LDV sales in 2008 to 57 percent in 2035. Improvements in accessories, such as

the replacement of mechanical pumps with electric

pumps that increase fuel economy by up to 1.5 percent, are implemented in 24 percent of new LDV

sales in 2035, as compared with 0.1 percent of new

LDV sales in 2008.

64 U.S. Energy Information Administration / Annual Energy Outlook 2010

Transportation sector energy demand

1980 1995 2008 2020 2035

20

25

30

35

40

45

History Projections

High Technology

Reference

Low Oil Price

High Oil Price

Low Technology

0 20 40 60 80 100

Drag reduction

Material substitution

Aggressive shift logic

Turbocharging

Advanced transmission

Camless valve activation

Accessory improvements
Unconventional vehicle technologies

approach 50 percent of sales in 2035

Figure 58. Sales of unconventional light-duty

vehicles by fuel type, 2008, 2020, and 2035

(million vehicles sold)

With more stringent CAFE standards and higher fuel

prices, unconventional vehicles (vehicles that use alternative fuels, electric motors and advanced electricity storage, advanced engine controls, or other new

technologies) account for nearly 50 percent of new

LDV sales in 2035 in the Reference case. Unconventional vehicle technologies play a significant role in

meeting the new NHTSA CAFE standards for LDVs.

FFVs represent 41 percent of unconventional LDV

sales in 2035 (Figure 58), the largest share among

unconventional vehicle types. Manufacturers currently receive incentives for selling FFVs, through

fuel economy credits that count toward CAFE compliance. However, due to limitations on gasoline blending, FFVs will also play a critical role in meeting the

RFS mandate for biofuels. Although these credits are

phased out by 2020, FFVs make up more than 20 percent of all new LDV sales in 2035, in part because of

their increased availability.

Four types of hybrid vehicle are expected to be available for sale by 2035: standard gasoline-electric or

diesel-electric hybrid (HEV), plug-in hybrid with an

all-electric range of 10 miles (PHEV-10), plug-in

hybrid with an all-electric range of 40 miles (PHEV40), and micro hybrid (MHEV). MHEVs, in which the

gasoline engine is turned off only when switching to

battery power when the vehicle is idling, represent

53 percent of hybrid LDV sales and 13 percent of new

LDV sales in 2035. HEVs have the second-largest

share, at 37 percent of hybrid LDV sales. PHEV-10s

make up 9 percent and PHEV-40s make up 2 percent

of all hybrid LDV sales in 2035 in the Reference case,

or about 500,000 PHEVS in total.

Residential and commercial sectors

dominate electricity demand growth

Figure 59. U.S. electricity demand growth,

1950-2035 (percent, 3-year moving average)

Electricity demand increases in response to population growth and economic growth and fluctuates in

the short term in response to business cycles and

weather trends. Over the long term, electricity

demand growth has slowed progressively in each

decade since the 1950s. After growing by 9.8 percent

per year in the 1950s, electricity demand (including

retail sales and direct use) increased by 2.4 percent

per year in the 1990s, and from 2000 to 2008 it

grew on average by 0.9 percent per year. The slower

growth continues in the AEO2010 Reference case, as

increased demand for electricity services is offset by

efficiency gains from new appliance efficiency standards and investment in energy-efficient equipment.

Total electricity demand increases by 30 percent in

the Reference case (an average of 1.0 percent per

year), from 3,873 billion kilowatthours in 2008 to

5,021 billion kilowatthours in 2035 (Figure 59). The

largest percentage increase is in the commercial sector (42 percent), with the service industries continuing to lead the growth. Residential electricity demand

increases by 24 percent, due to growth in population

and disposable income and continued population

shifts to warmer regions with greater cooling requirements. Total industrial electricity demand grows by

only 3 percent from 2008 to 2035, as a result of efficiency gains and slow growth in industrial production, particularly in the energy-intensive industries.

In the transportation sector, penetration of PHEVs

by 2035 is not sufficient to reverse the slowing trend

in electricity demand growth, because for every

1 million PHEV-40 vehicles added, U.S. electricity

demand increases by only about 0.1 percent.

U.S. Energy Information Administration / Annual Energy Outlook 2010 65

Electricity demand

1950 1970 1990 2008 2020 2035

0

2

4

6

8

10

12

-2

History Projections

3-year moving average

Trend line

2008 2020 2035

0

2

4

6

8

10 Total

Diesel

Flex-fuel

Electric hybrid

Micro

Other
Electricity prices moderate in the

near term, then rise gradually

Figure 60. Average annual U.S. retail electricity

prices in three cases, 1970-2035

(2008 cents per kilowatthour)

Real electricity prices vary, depending on the economy, fuel prices, regulations, competition in wholesale and retail markets, and costs of new generation.

In the AEO2010 Reference case, average annual electricity prices fall from 9.8 cents per kilowatthour

(2008 dollars) in 2008 to 8.6 cents per kilowatthour in

2011 because of a drop in fossil fuel prices and lower

demand that coincides with the startup of new renewable, natural gas, and coal-fired capacity. After 2011,

prices rise to 10.2 cents per kilowatthour in 2035

(Figure 60) in response to rising fuel prices and the

construction of new power plants as demand rises.

Electricity prices are influenced by economic activity.

In the High Economic Growth case, electricity prices

rise to 10.9 cents per kilowatthour in 2035; in the

Low Growth case they rise to only 9.3 cents per

kilowatthour.

Electricity prices are based on generation, transmission, and distribution costs. Fuel costs account for

most of the generation costs for natural-gas- and oilfired plants but much less for coal and nuclear plants.

There are no fuel costs associated with wind and solar

plants. In competitive wholesale markets, natural gas

and liquid fuel costs often set hourly prices. With

natural-gas-fired generation increasing throughout

the Reference case projection, natural gas prices have

the greatest impact on electricity prices. Transmission costs rise by 33 percent from 2008 to 2035, as

new infrastructure is built but still make up only 9

percent of average electricity prices by the end of the

projection period. Distribution costs vary over time

and are about the same in 2035 as in 2008.

Coal-fired power plants provide

largest share of electricity supply

Figure 61. Electricity generation by fuel in

three cases, 2008 and 2035 (billion kilowatthours)

In the Reference case, without GHG regulations, coal

accounts for the largest share of total electricity generation (Figure 61). With slow growth in electricity

demand, little new coal-fired capacity is added, and

the coal share falls from 48 percent in 2008 to 44 percent in 2035. (A 3-percent premium is added to the

financing cost for CO2-intensive technologies to reflect the potential for CO2 regulation to reduce the

competitiveness of coal with other technologies.)

The natural gas share of generation, at 21 percent in

2008, rose in 2009 when natural gas prices fell. Over

the next few years, with slow growth in electricity demand, completion of coal plants under construction,

and addition of new renewable capacity, the gas share

falls, before trending up to 21 percent in 2035. The

near- to mid-term downturn in natural gas generation might be dampened if new policies made coal use

for electricity generation less attractive, or if growth

in renewable generation were slower than projected.

Renewable generation, supported by Federal and

State tax incentives and ARRA funding, shows the

strongest growth in the Reference case and is 2.4-fold

higher in 2035 than in 2008. The renewable share of

generation grows from 9 percent in 2008 to 17 percent

in 2035. Although generation from nuclear plants increases by 11 percent, their share of total generation

falls from 20 percent in 2008 to 17 percent in 2035.

Growth in demand for electricity varies with different

assumptions about future economic conditions. In

2035, total generation in the High Economic Growth

case is 9 percent above the Reference case projection,

and in the Low Economic Growth case it is 9 percent

below the Reference case.

66 U.S. Energy Information Administration / Annual Energy Outlook 2010

Electricity prices

2008

Low

Economic

Growth

2035

Reference High

Economic

Growth

0

1,000

2,000

3,000

4,000

5,000

6,000

Nuclear

Natural gas

Petroleum

Renewables

Coal

1970 1985 2000 2008 2020 2035

0

2

4

6

8

10

12

History Projections

Reference

High Economic Growth

Low Economic Growth
Most new capacity additions

use natural gas and renewables

Figure 62. Electricity generation capacity

additions by fuel type, 2009-2035 (gigawatts)

Decisions to add capacity and the choice of fuel type

depend on a number of factors [82]. With growing

electricity demand and the expected retirement of

45 gigawatts of existing capacity, 250 gigawatts of

new generating capacity (including end-use CHP)

will be needed between 2009 and 2035 (Figure 62).

Natural-gas-fired plants account for 46 percent of

capacity additions in the Reference case, as compared

with 37 percent for renewables, 12 percent for coalfired plants, and 3 percent for nuclear. Escalating

construction costs have the largest impact on the

more capital-intensive generation technologies,

including renewables, coal, and nuclear. However,

Federal tax incentives, State energy programs, and

rising prices for fossil fuels increase the competitiveness of renewable and nuclear capacity. In contrast,

uncertainty about future limits on GHG emissions

and other possible environmental regulations reduces

the competitiveness of coal (reflected in the AEO2010

Reference case by adding 3 percentage points to the

cost of capital for new coal-fired capacity). The incentives extended and expanded by the ARRA have previously resulted in considerable growth in renewable

capacity, and this trend is expected to continue.

Capacity additions also are affected by demand

growth and by fuel prices. Capacity additions from

2009 to 2035 range from 158 gigawatts in the Low

Economic Growth case to 341 gigawatts in the High

Economic Growth case. With higher fuel costs in the

AEO2010 High Oil Price case, fewer natural-gas-fired

plants are added, because fuel costs make up a relatively large share of their total expenditures.

Costs and regulatory uncertainties

vary across options for new capacity

Figure 63. Levelized electricity costs for new power

plants, 2020 and 2035 (2008 cents per kilowatthour)

Technology choices for new generating capacity typically are made to minimize costs while meeting local

and Federal emissions standards. Capacity expansion

decisions consider capital, operating, and transmission costs. Coal-fired, nuclear, and renewable plants

are capital-intensive, while operating (fuel) expenditures make up most of the costs for gas-fired capacity

(Figure 63) [83]. Capital costs depend on such factors

as equipment costs, interest rates, and cost-recovery

periods. Fuel costs can vary according to fuel prices,

plant operating efficiency, resource availability, and

transportation costs. Some technologies and fuels

also receive subsidies, such as PTCs and ITCs.

Regulatory uncertainty also affects capacity planning

decisions. New coal-fired plants could be required to

install CCS equipment, resulting in higher material,

labor, and operating costs. Alternatively, coal plants

without carbon controls could incur higher costs for

siting and permitting. Because nuclear and renewable power plants (including wind plants) do not emit

GHGs, however, their costs are not directly affected

by regulatory uncertainty in this area.

Capital costs can decline over time as developers gain

experience with a given technology. In the AEO2010

Reference case, capital costs of new technologies are

adjusted upward initially, to reflect the optimism inherent in early estimates of project costs. The costs

decline as project developers gain experience, and the

decline continues at a progressively slower rate as

more units are built. Operating efficiencies also are

assumed to improve over time, resulting in reduced

variable costs unless increases in fuel costs exceed the

savings from efficiency gains.

U.S. Energy Information Administration / Annual Energy Outlook 2010 67

Electricity generation

Natural gas

Wind

Coal

Nuclear

Natural gas

Wind

Coal

Nuclear

0 2 4 6 8 10 12

Fixed costs

Capital costs

2020

2035

combined cycle

combined cycle

Variable costs,

including fuel

Incremental

transmission

costs

2009-

2015

2016-

2020

2021-

2025

2026-

2030

2031-

2035

0

10

20

30

40

50

60

Nuclear

Coal

Natural gas

Renewables/

other
EPACT2005 tax credits

stimulate some nuclear builds

Figure 64. Electricity generating capacity at

U.S. nuclear power plants in three cases,

2008, 2020, and 2035 (gigawatts)

In the AEO2010 Reference case, nuclear power capacity increases from 100.6 gigawatts in 2008 to 112.9

gigawatts in 2035 (Figure 64), including 4.0 gigawatts

of expansion at existing plants and 8.4 gigawatts of

new capacity. The Reference case includes a second

unit at the Watts Bar site, where construction was

halted in 1988 when the plant was partially completed. Estimated costs for new nuclear plants have

continued to rise, making new investments in nuclear

power uncertain. In the Reference case, only about six

new nuclear power plants are completed by 2035.

All existing nuclear units continue to operate through

2035 in the Reference case, which assumes that they

will apply for, and receive, operating license renewals,

including in some cases a second 20-year extension

after they reach 60 years of operation. With costs for

natural-gas-fired generation rising and future regulation of GHG emissions uncertain, the economics of

keeping existing nuclear power plants in operation

are favorable.

Nuclear capacity additions vary with assumptions

about overall demand for electricity and the prices of

other fuels. The amount of nuclear capacity added

also is sensitive to assumptions about future plans

and policies for limiting or reducing GHG emissions.

Across the Oil Price and Economic Growth cases,

nuclear capacity additions from 2008 to 2035 vary

from 6 to 15 gigawatts. The first 6 gigawatts of new

nuclear capacity is built in all cases, based on tax

incentives and loan guarantees. More new nuclear capacity is built in the High Economic Growth and High

Oil Price cases, because overall capacity requirements

are higher and/or alternatives are more expensive.

Biomass and wind lead growth

in renewable generation

Figure 65. Nonhydroelectric renewable electricity

generation by energy source, 2008-2035

(billion kilowatthours)

Use of renewable energy resources in the electric

power sector increases sharply in the AEO2010 Reference case (Figure 65). Nonhydroelectric renewable

generation accounts for 41 percent of the growth in

total electricity generation from 2008 to 2035, supported by extension of Federal tax credits, State

requirements for renewable electricity generation,

and the loan guarantee program in EPACT2005 and

ARRA. Wind power and biomass provide the largest

share of the growth. Generation from wind power

increases from 1.3 percent of total generation in 2008

to 4.1 percent in 2035. Generation from biomass, both

in the electric power sector and from end-use cogeneration, grows from 0.9 percent of total generation in

2008 to 5.5 percent in 2035. A large portion of the

increase in biomass generation comes from increased

co-firing—a process in which biomass is mixed with

coal in existing coal-fired plants, displacing some of

the coal that would otherwise be burned.

Renewable electricity generation also grows in the

end-use sectors as a result of the EISA2007 RFS,

which requires increased use of biofuels produced at

biorefineries. At some BTL facilities, synthetic gas

from the biomass conversion process is used for electricity generation. As in previous AEOs, solar technologies are too costly for widespread use in wholesale

power applications, but demonstration programs and

State policies support some growth in central-station

PV. In addition, State programs, Federal tax rebates,

and utility programs encourage small-scale, distributed PV generation applications, which grow rapidly

over the projection period.

68 U.S. Energy Information Administration / Annual Energy Outlook 2010

Nuclear capacity

History

Low Economic Growth

Reference

High Economic Growth

Low Economic Growth

Reference

High Economic Growth

0 25 50 75 100 125

2020

2035

2008

2008 2020 2030 2035

0

200

400

600

MSW/LFG

Biomass

Wind

Solar

Geothermal
Wind power dominates renewable

capacity growth in the near term

Figure 66. Grid-connected coal-fired and

wind-powered generating capacity, 2003-2035

(gigawatts)

In the AEO2010 Reference case, renewable capacity—particularly, wind-powered capacity—increases

rapidly from 2008 to 2013 in response to the Federal

PTC for wind, ARRA funding, and State RPS legislation. Growth in renewable capacity slows dramatically after 2014 because of the expiration of the

Federal PTC for wind and the completion of projects

expected to be supported by ARRA funding. The

growth before 2013 is adequate to meet State RPSmandated renewable requirements through about

2030; however, renewable capacity begins to grow

again after 2030 to meet the State RPS mandates.

Installed wind capacity grew by about 19 gigawatts

from 2003 to 2008, a trend that continues in the Reference case with the installation of 39 gigawatts from

2008 to 2013, more than doubling wind capacity in

the United States (Figure 66). The near-term growth

of other renewable capacity, however, is limited. Geothermal capacity is restricted to a relatively small

number of suitable sites; solar capacity remains too

costly for widespread implementation; and energy

crops do not become economical before 2015. Other

biomass resources that could be used for electric

power generation are used instead to produce biofuels

in order to meet the Federal RFS, leading to a small

increase in electricity generation at biorefineries.

With new generation needed in the later years of the

projection, State RPS programs lead to the installation of more dedicated renewable capacity. Dedicated

biomass capacity increases by nearly 5 gigawatts from

2030 to 2035, largely using biomass feedstocks from

energy crops. As a result, co-firing of renewables in

coal-fired boilers decreases late in the projection.

Higher or lower costs affect growth

in renewable generation capacity

Figure 67. Nonhydropower renewable generation

capacity in three cases, 2015-2035 (gigawatts)

Renewable generation grows from a 9-percent share

of total electricity production in 2008 to a 17-percent

share in 2035 in the Reference case. The increase is

supported by Federal tax credits, State RPS programs, and a premium added to the cost of long-lived

carbon-intensive technologies, reflecting market

behavior with regard to potential carbon regulations.

In the Reference case, capital costs for renewable capacity in 2035 are 20 to 50 percent lower than in 2008.

Two additional cases show the effects of technology

costs on the use of renewables for generation (Figure

67). In the Low Renewable Cost case, costs for renewable generation technologies in 2035 are 25 percent

lower than in the Reference case, but in the High Renewable Cost case they do not change from their 2009

levels. In the Low Renewable Cost case, renewable

generation in 2035 totals 1,145 billion kilowatthours,

or a 22-percent share of all generation. In the High

Renewable Cost case, total renewable generation in

2035 is 786 billion kilowatthours and accounts for 15

percent of generation. Although the costs for renewable generation are higher in the High Renewable

Cost case, its growth is still supported by PTCs in

the early years of the projection and continued State

mandates for renewable electricity in the later years.

With lower costs, geothermal electricity generation in

the Low Renewable Cost case is almost 70 percent

higher than in the Reference case in 2035, and generation from biomass and wind also show significant

increases. In the High Renewable Cost case, wind

actually increases from its Reference case value in

2035, reflecting a decrease in biomass combustion at

biofuels plants.

U.S. Energy Information Administration / Annual Energy Outlook 2010 69

Renewable generation

2003 2008 2015 2025 2035

0

100

200

300

400

Coal

Wind

History Projections

2015 2020 2025 2030 2035

0

50

100

150

200

Low Renewable Cost

Reference

High Renewable Cost
State portfolio standards increase

renewable generating capacity

Figure 68. Regional growth in nonhydroelectric

renewable electricity generation capacity,

including end-use capacity, 2008-2035 (gigawatts)

Regional additions of renewable generating capacity

depend for the most part on State RPS programs.

As of October 31, 2009, there were mandatory RPS

programs in 30 States and nonbinding renewable

goals in 5 States [84]. From 2008 to 2035, California

installs the most renewable capacity, 22 gigawatts

(Figure 68), primarily new wind capacity but also

including 3.1 gigawatts of distributed PV capacity.

New England installs more than 8 gigawatts of

new wind capacity, representing the second-largest

regional growth of the technology (see Figure F2 in

Appendix F for a map of the regions). Florida and the

Mid-Atlantic account for 80 percent of the dedicated

biomass capacity installed by 2035 in the electric

power sector (mostly later in the period).

Distributed biomass capacity corresponds largely

with the location of cellulosic ethanol plants. Although the Southeast has ample biomass resources,

only small amounts of renewable capacity are installed in the region’s electric power sector in the

absence of State RPS programs, whereas distributed

biomass capacity increases by more than 6 gigawatts

from 2008 to 2035. Geothermal energy, which is constrained geographically by the availability of local

resources, is installed exclusively in the Southwest

and California. The same regions have the greatest

resource potential for large-scale solar capacity, but

because of its high cost only a small amount is

installed. Most of the increase in solar capacity consists of distributed PV, and some States in the Northeast (New Jersey, for example) have mandates or

provide other incentives for PV installations. Approximately 1.6 gigawatts of distributed PV capacity is

installed in the Mid-Atlantic region by 2035.

Natural gas prices rise but remain

attractive relative to oil

Figure 69. Annual average lower 48 wellhead and

Henry Hub spot market prices for natural gas,

1990-2035 (2008 dollars per million Btu)

Average natural gas prices generally increase in the

Reference case, as higher cost resources are brought

on line to meet demand growth (Figure 69). The price

increase is tempered by improvements in technology.

There is a great deal of uncertainty about the longterm trend in natural gas prices, however, particularly in light of the growing development of shale gas

resources.

The ratio of low-sulfur light crude oil prices to Henry

Hub natural gas prices on an energy equivalent basis

remains high relative to the historical average

throughout the projection (Figure 70). The ratio is

maintained by growing worldwide demand for transportation fuels and robust North American natural

gas supply relative to demand. Still, increased use of

natural gas as a substitute for petroleum in some

transportation uses and/or as a GTL feedstock could

increase natural gas prices and narrow the ratio.

Figure 70. Ratio of low-sulfur light crude oil price

to Henry Hub natural gas price on an energy

equivalent basis, 1990-2035

70 U.S. Energy Information Administration / Annual Energy Outlook 2010

Natural gas prices

1990 2000 2008 2015 2025 2035

0

2

4

6

8

10

History Projections

Henry Hub spot market

Lower 48 wellhead

NY

SPP

RA

ECAR

MAAC

FL

ERCOT

NWP

MAPP

MAIN

NE

SERC

CA

0 5 10 15 20 25 30

2008

2035

1990 2000 2008 2015 2025 2035

0

1

2

3

History Projections
Natural gas prices vary with economic

growth and technology progress

Figure 71. Annual average lower 48 wellhead prices

for natural gas in three technology cases, 1990-2035

(2008 dollars per thousand cubic feet)

The extent to which natural gas prices increase in the

AEO2010 Reference case and in the Rapid and Slow

Technology cases depends on assumptions about the

rate of improvement in natural gas exploration and

production technologies. Technology improvements,

in addition to reducing drilling and operating costs

and expanding the economically recoverable resource

base, also affect the timing of production increases

from sources such as shale gas.

Technology improvement is particularly important to

the production of natural gas from shale formations,

which can typically be produced at lower incremental

cost, but require relatively high capital expenditures.

The Reference case assumes that annual technology

improvements follow historical trends. In the Rapid

Technology case, exploration and development costs

per well decline at a faster rate, which accelerates

growth in production. Technology improvements also

lead to earlier initial production and higher production rates, which result in favorable economics that

encourage further growth. The downward pressure

placed on natural gas prices by more rapid technology

improvement is, however, offset somewhat by higher

levels of consumption.

In the Slow Technology case, slower declines in exploration and development costs lead to higher natural

gas prices and lower levels of consumption than

in the Reference case (Figure 71). In both the Slow

and Rapid Technology cases, as in the Reference case,

completion of the Alaska pipeline (in 2020 and 2027 in

the Slow Technology and Rapid Technology cases,

respectively) results in a temporary decline in natural

gas prices.

U.S. natural gas prices have limited

sensitivity to oil prices

Figure 72. Annual average lower 48 wellhead prices

for natural gas in three oil price cases, 1990-2035

(2008 dollars per thousand cubic feet)

Oil prices have small but measurable impacts on domestic natural gas production and prices, causing

them to increase in the High Oil Price case and

decrease in the Low Oil Price case. Higher or lower oil

prices lead to higher or lower levels of drilling activity, which affect the costs of labor and key commodities, such as steel, that factor into production costs for

both industries. As a result, domestic natural gas

prices rise and fall with oil prices (Figure 72). The

changes are offset in part by increased production of

liquids associated with natural gas production when

oil prices are higher, as well as the increase in recovery of associated gas that comes with increased oil

production.

Different oil price assumptions also affect domestic

natural gas supply through their effects on global

availability of natural gas exports. Although U.S.

natural gas consumption is lower in the High Oil

Price case, higher oil prices tend to increase natural

gas consumption in international markets, where it is

used instead of liquids and also to produce liquids,

thereby reducing the amount of natural gas, particularly LNG, available for export to U.S. markets.

Internationally, there is a greater potential for shifting between oil and natural gas than in the United

States. In addition, many European and Asian natural gas price contracts are tied to oil prices, and as a

result world natural gas prices tend to move with oil

prices. A stronger price linkage in the United States

could occur with the development of new markets,

such as GTL production, natural gas vehicles, or LNG

exports.

U.S. Energy Information Administration / Annual Energy Outlook 2010 71

Natural gas prices

1990 2000 2008 2015 2025 2035

0

2

4

6

8

10

History Projections

Rapid Technology

Slow Technology

Reference

1990 2000 2008 2015 2025 2035

0

2

4

6

8

10

History Projections

Low Oil Price

High Oil Price Reference
Shale gas provides largest source of

growth in U.S. natural gas supply

Figure 73. Natural gas production by source,

1990-2035 (trillion cubic feet)

The increase in U.S. natural gas production from

2008 to 2035 in the AEO2010 Reference case results

primarily from continued growth in production of

shale gas, recent discoveries in deep waters offshore,

and, to a lesser extent, stranded natural gas brought

to market after construction of the Alaska natural gas

pipeline is completed in 2023 (Figure 73). Shale gas

and coalbed methane make up 34 percent of total U.S.

production in 2035, doubling their 17-percent share

in 2008.

Shale gas is the largest contributor to the growth in

production, while production from coalbed methane

deposits remains relatively stable from 2008 to

2035. Advances in horizontal drilling and hydraulic

fracturing techniques—as well as improved drill bits,

steering systems, and instrumentation monitoring

equipment—have contributed to higher success and

recovery rates, reduced cycle times, lower costs, and

shorter times required to bring new shale gas production to market.

Offshore natural gas, the bulk of which is from deep

waters in the Gulf of Mexico, contributes significantly

to domestic supply. Fields that started producing

recently or are expected to start producing within the

next few years include Great White, Norman, Shenzi,

Tahiti, and Cascade. Production from the continued

development of recent discoveries, as well as new

discoveries, more than offsets production declines in

older fields, resulting in a net increase in offshore

production through 2035.

Economic growth and technology

progress affect natural gas supply

Figure 74. Total U.S. natural gas production

in five cases, 1990-2035 (trillion cubic feet)

Growth in domestic natural gas production is affected

by economic growth and advances in exploration and

production technology. The effect of economic growth

on domestic natural gas production results from its

impact on natural gas consumption and prices. Improvements in technology reduce natural gas drilling

and production costs, increase the productive capacity of natural gas wells, and increase the number of

successful wells.

Natural gas consumption in 2035 is 2.1 trillion cubic

feet higher in the High Economic Growth case than in

the Reference case. More than one-half of the increase

in the High Growth case is met by an increase of

1.3 trillion cubic feet in domestic production (Figure

74); the remainder is met by an increase in pipeline

imports from Canada, supported in part by the

introduction of Mackenzie Delta gas in 2032. Roughly

one-third of the increase in domestic production

comes from shale gas, one-third comes from other

lower 48 onshore production, excluding coalbed

methane production, and the balance comes from

coalbed methane, offshore, and Alaska.

Annual production of natural gas from 2008 to 2035

is, on average, 0.4 trillion cubic feet higher in the

Rapid Technology case than in the Reference case.

The additional production from the lower 48 States

places downward pressure on natural gas prices and

delays construction of the Alaska natural gas

pipeline—from 2023 in the Reference case to 2027 in

the Rapid Technology case. In the Slow Technology

case, average annual production of domestic natural

gas from 2008 to 2035 is 0.5 trillion cubic feet lower

than in the Reference case from 2008 to 2035.

72 U.S. Energy Information Administration / Annual Energy Outlook 2010

Natural gas supply

1990 2000 2008 2015 2025 2035

16

18

20

22

24

26

History Projections

High Economic Growth

Rapid Technology

Slow Technology

Low Economic Growth

Reference

0

1990 2000 2008 2015 2025 2035

0

5

10

15

20

25

History Projections

Alaska

Lower 48 offshore

Shale gas

Coalbed methane

Other lower 48 onshore

(including tight gas)
Natural gas production grows in

Northeast, Rocky Mountain regions

Figure 75. Lower 48 onshore natural gas

production by region, 2008 and 2035

(trillion cubic feet)

A 4-fold increase in shale gas production from 2008 to

2035 more than offsets a 31-percent decline in other

lower 48 onshore natural gas production in the AEO2010 Reference case. Significant increases in shale

gas production are expected in the Northeast, Gulf

Coast, and Midcontinent regions (Figure 75). (See

Figure F4 in Appendix F for a map of the regions.)

Coalbed methane production, which has grown rapidly over the past several decades, is relatively stable

through 2035 and is confined largely to the Rocky

Mountain region.

In the Northeast, natural gas production grows by 34

percent from 2008 to 2035 in the Reference case, led

by increased development of shale gas. The growth

has the potential to replace some of the Northeast’s

current natural gas supply that comes from the

U.S. Gulf Coast and from Canada, resulting in more

Gulf Coast supply available to other regions. This has

the potential to moderate natural gas prices at the

Henry Hub.

While U.S. shale gas production increases, total onshore natural gas production declines slightly in the

Gulf Coast region, by 27 percent in the Midcontinent

region, and by 9 percent in the Southwest from 2008

to 2035. The Rocky Mountain region is expected to

see an increase in total production (8 percent), largely

from tight sand formations (which are included in the

“other gas” category). The largest decline in total

natural gas production, about 63 percent, is projected

for the West Coast region, where no shale gas or coalbed methane is produced.

Shale gas production grows

substantially in most regions

Figure 76. Shale gas production by region,

2008, 2020, and 2035 (trillion cubic feet)

Growth in natural gas production from shale formations offsets declines in other supply sources

nationwide throughout the AEO2010 Reference case

projection. The growth depends, in part, on future

growth in demand for natural gas. With an assumed

347 trillion cubic feet of technically recoverable shale

gas, the potential for increased production is large.

The true potential of the U.S. shale gas resource

remains uncertain, however, as estimates vary and

experience continues to provide new information.

Shale gas production occurs in new and sometimes

previously abandoned areas, where its production

may require increases in processing, storage, and

pipeline capacity. Although production from the

Antrim shale has started declining, and development

in parts of the Marcellus shale has been inhibited

somewhat by limitations on the issuance of drilling

permits [85], shale gas production in the Northeast

region more than doubles from 2008 to 2035 in the

Reference case (Figure 76).

In the Gulf Coast region, where the Haynesville play

is expected to become a major contributor, shale gas

compensates for almost 91 percent of the decline in

other natural gas production. In the Midcontinent region, production from the Fayetteville and Woodford

shales offsets approximately 57 percent of the decline

in other natural gas production. And in the Southwest region, production from the older Barnett shale

play offsets approximately 66 percent of the decline

in other natural gas production. There is no projected

shale gas production in the West Coast region.

U.S. Energy Information Administration / Annual Energy Outlook 2010 73

Natural gas supply

0123

2008

2020

Northeast

Gulf Coast

Midcontinent

Southwest

Rocky Mountain

2035

01234567

2008

2035

Other gas

Shale gas

Coalbed methane

Northeast

Gulf Coast

Midcontinent

Southwest

Rocky Mountain

West Coast
U.S. net imports of natural gas

decline as domestic production rises

Figure 77. U.S. net imports of natural gas

by source, 1990-2035 (trillion cubic feet)

U.S. net imports of natural gas decline in the Reference case from 13 percent of total supply in 2008 to 6

percent in 2035. The reduction consists primarily of

lower imports from Canada and higher exports to

Mexico, as a result of demand growth in both countries that outpaces the growth in their production, as

well as increased U.S. production.

In the Reference case, imports from Canada decline

rapidly through 2014 (Figure 77), as increased production from growing sources, such as shale gas, is

not yet sufficient to offset the decline in other sources.

After 2014, U.S. imports from Canada stabilize at

1.7 to 1.9 trillion cubic feet per year through 2035.

However, the size of Canada’s shale gas resource

is uncertain at present. In the Low Technology and

High Economic Growth cases, which include higher

natural gas prices, a pipeline from the Mackenzie

Delta is constructed before 2035. With lower natural

gas prices, it is not completed by 2035.

U.S. imports of LNG increase to a high of 1.5 trillion

cubic feet in 2021 as new liquefaction capacity is built

in exporting countries, then decline as demand from

other importing countries grows to absorb more of

the output from the new capacity. Other importing

countries have few economical alternatives to LNG,

whereas the United States has ample supplies of

domestic natural gas. Therefore, U.S. import levels

depend primarily on the amount of excess liquefaction capacity available. Domestic production keeps

U.S. natural gas prices low relative to world LNG

prices, which remain tied to oil prices in many foreign

markets. Actual import volumes are likely to vary

notably around the trend line.

High LNG supply case illustrates

uncertainty in future import levels

Figure 78. Cumulative difference from Reference

case natural gas supply and consumption in the

High LNG Supply case, 2008-2035 (trillion cubic feet)

U.S. imports of LNG depend on world liquefaction

capacity, world demand for LNG, and U.S. natural

gas prices. When there is excess natural gas supply in

world markets (for example, during years with

warmer weather than normal), more LNG becomes

available for U.S. imports. The AEO2010 High LNG

case assumes the availability of more LNG imports to

North America than in the Reference case—up to

5 times more in 2035 and cumulatively 2.9 times more

from 2009 to 2035, or a total of 70 trillion cubic feet.

The increase in LNG imports results in lower wellhead prices, with annual wellhead prices lower in the

High LNG case than in the Reference case by 7 to 18

percent ($0.55 to $1.42 per thousand cubic feet)

during the period from 2020 to 2035. A major impact

of the increase in LNG imports in the High LNG case

is on the timing of the Alaska pipeline, which is

opened in 2023 in the Reference case but delayed

until 2033 in the High LNG case. In the lower 48

States, a major impact of increased LNG imports is

reduced production of onshore natural gas and an

even larger percentage reduction in offshore production, because lower prices imply that fewer U.S.

natural gas resources are economical to produce.

Effects on U.S. natural gas consumption in the High

LNG case are primarily in the price-responsive electricity generation sector, where natural gas competes

with coal and renewables. The electricity generation

sector accounts for 80 percent of the cumulative

difference in consumption between the two cases

(Figure 78).

74 U.S. Energy Information Administration / Annual Energy Outlook 2010

Natural gas imports

Net imports Consumption Production

0

25

50

75

-25

-50

Alaska

Offshore

Onshore lower 48

Pipeline

LNG

Other

Electric power

1990 2000 2008 2015 2025 2035

0

1

2

3

4

-1 Mexico

History Projections

Canada

Overseas LNG
Transportation uses spur growth

in liquid fuels consumption

Figure 79. Liquid fuels consumption by sector,

1990-2035 (million barrels per day)

U.S. consumption of liquid fuels—including fuels

from petroleum and, increasingly, those derived from

fuels such as biomass, coal, and natural gas—totals

22.1 million barrels per day in 2035 in the Reference

case, an increase of 2.5 million barrels per day over

the 2008 total (Figure 79). In all sectors except transportation, liquid fuel consumption remains at

roughly the same level over the projection period. As

a result, the transportation sector accounts for 74

percent of total liquid fuels consumption in 2035, up

from 71 percent in 2008.

Motor gasoline, ultra-low-sulfur diesel, and jet fuel

are the main fuels consumed in the transportation

sector. Although EIA expects that the most recent

increases in U.S. CAFE standards will increase the

fuel efficiency of motor vehicles, the growth in

demand for transportation services that results from

increases in population and GDP outpaces the

expected improvements in efficiency.

Growth in demand for transportation fuels is met

primarily by diesel fuel and biofuels. While motor gasoline consumption (including ethanol used in E10)

increases by 0.1 million barrels per day from 2008 to

2035 in the Reference case, consumption of diesel fuel

and E85 increases by 1.0 and 1.2 million barrels per

day, respectively, over the period. Growth in demand

for biofuels is primarily a result of the EISA2007 RFS.

Growth in demand for diesel fuel results from the

increasing sales of diesel LDVs that are needed to

meet the new CAFE standards, as well as an increase

in shipping that leads to more consumption of diesel

by heavy freight trucks.

U.S. crude oil production increases

as projected world oil prices rise

Figure 80. Domestic crude oil production by

source, 1990-2035 (million barrels per day)

Total U.S. crude production increases from 2008 to

2035, as rising world oil prices spur both onshore and

offshore drilling. In the short term, a vast majority of

the increase comes from deepwater offshore fields.

Fields that started producing in 2009 or are expected

to start in the next few years include Great White,

Norman, Tahiti, Gomez, Cascade, and Chinook. All

are in water deeper than 800 meters, and most are in

the Central Gulf of Mexico. Production from those

fields, combined with increased production from

fields that started producing in 2007 and 2008, contributes to the near-term growth in offshore production. Over the longer term, production from the

continued development of other recent discoveries, as

well as new discoveries, offsets production declines in

older fields, resulting in an increase in production

through 2035 (Figure 80).

Removal of the Congressional moratorium on drilling

in the Eastern Gulf of Mexico, Atlantic, and Pacific

regions of the Outer Continental Shelf also allows for

more crude oil production from offshore areas in the

Pacific after 2016, in the Atlantic after 2021, and in

the Eastern Gulf of Mexico after 2025 [86]. In 2035,

U.S. crude oil production includes 0.4 million barrels

per day from the Pacific offshore, 0.2 million from the

Atlantic offshore, and 0.1 million from the Eastern

Gulf of Mexico. Lower 48 onshore production of crude

oil continues to increase through 2035, primarily as a

result of wider application of CO2 EOR techniques.

EOR makes up 37 percent of total onshore production

in 2035, up from 12 percent in 2008. Continued exploitation of the Bakken shale formation and the

startup of oil shale liquids production after 2023 also

contribute to the growth in onshore oil production.

U.S. Energy Information Administration / Annual Energy Outlook 2010 75

Liquid fuels supply

1990 2000 2008 2015 2025 2035

0

5

10

15

20

Transportation

Industrial

Electricity generators

Buildings

History Projections

1990 2000 2008 2015 2025 2035

0

2

4

6

8

Total

Alaska

History Projections

Lower 48 offshore

Lower 48 onshore
U.S. oil production depends on prices

and technology

Figure 81. Total U.S. crude oil production

in five cases, 1990-2035 (million barrels per day)

U.S. crude oil production, both onshore and offshore,

is sensitive to future world oil prices and advances in

technology. The rate of growth in domestic crude oil

production depends largely on assumptions about

world oil prices (Figure 81), as remaining onshore resources typically require more costly secondary or

tertiary recovery techniques. Generally, high-cost

projects are more economical when world oil prices

are high. However, long lead times from discovery to

production limit the increase in production, particularly offshore, over the projection period. Production

from deepwater offshore projects and from lower 48

onshore EOR projects accounts for most of the variation in domestic production in the High and Low

World Oil Price cases.

Different assumptions about rates of technology

improvement also have significant effects on crude oil

production, through their effects on exploration and

development costs, success rates, and production

efficiencies. Advances in horizontal drilling and

hydraulic fracturing techniques, as well as improved

drill bits, steering systems, and instrumentation

monitoring equipment, are among the key advances

that have contributed to increases in domestic

production over the past few years, reversing the

historical trend of declining U.S. crude oil production.

Horizontal drilling, in particular, is regarded by many

as one of the most valuable technologies introduced in

the industry, because it can be used in many situations where conventional drilling is impossible or

prohibitively expensive.

Liquids production from biomass,

coal, and oil grows as oil prices rise

Figure 82. Liquids production from biomass, coal,

and oil shale, 2008-2035 (thousand barrels per day)

Liquids produced from BTL and CTL, as well as oil

shale production, become more significant as world

oil prices increase. BTL production shows the most

rapid rise in the AEO2010 Reference case (Figure 82),

as increases in the costs of petroleum-based

feedstocks make alternative feedstocks, such as biomass, more cost-competitive. In addition, the carbonmitigating potential of BTL fuels makes them more

attractive in a carbon-conscious environment. Financial and technical difficulties, however, continue to

provide major challenges to the penetration of BTL

technology in the liquid fuels industry.

CTL production also grows in the Reference case,

more rapidly than BTL in the early years but more

slowly after 2020, so that total CTL production in

2035 is less than one-half the total for BTL. Although

advances in coal liquefaction technology have made it

commercially available in other countries, including

South Africa, China, and Germany, the technical and

financial risks of building what would be essentially a

first-of-a-kind facility in the United States have discouraged significant investment thus far. In addition,

the possibility of new legislation aimed at reducing

U.S. GHG emissions creates further uncertainty for

future investment in CTL.

With ongoing improvement in oil shale technology,

commercial production starts in 2023 and increases

rapidly to 1.7 percent of total U.S. liquids supply in

2035. However, oil shale development suffers from

environmental, technical, and financial uncertainties

similar to those for CTL.

76 U.S. Energy Information Administration / Annual Energy Outlook 2010

Liquid fuels supply

2008 2015 2020 2025 2030 2035

0

250

500

750

Biomass-to-liquids

Coal-to-liquids

Oil shale

1990 2000 2008 2015 2025 2035

0

2

4

6

8

10

Slow Technology

Reference

Rapid Technology

History Projections

High Oil Price

Low Oil Price
Imports of liquid fuels vary

with world oil price assumptions

Figure 83. Net import share of U.S. liquid fuels

consumption in three cases, 1990-2035 (percent)

U.S. imports of liquid fuels, which grew steadily from

the mid-1980s to 2005, decline significantly from

2008 to 2035 in the AEO2010 Reference and High Oil

Price cases, even as they continue to provide a major

part of total U.S. liquids supply. Higher prices lead to

more domestic production of oil and in combination

with the RFS lead to more domestic biofuel production, while at the same time the higher energy prices

moderate growth in overall demand for liquids.

The net import share of U.S. liquid fuels consumption

fell from 60 percent in 2005 to 57 percent in 2008 and

about 54 percent in 2009. That trend continues in the

projections, with the net import share falling to 45

percent in the Reference case and to 30 percent in the

High Oil Price case in 2035. Increased domestic production of crude oil and biofuels reduces the need for

imports of crude oil and petroleum products in the

High Oil Price case, but the import share of total consumption is still substantial (Figure 83). In the Low

Oil Price case, the net import share rises to 62 percent

in 2035. With lower prices for liquid fuels, demand increases while domestic production decreases, and

more imports are needed to meet demand.

The above projections for net import shares are based

on total U.S. consumption of all liquid fuels, including

biofuels and other alternative fuels. When only petroleum consumption is considered (instead of total

liquid fuels consumption), the net import share of

petroleum declines from 57 percent in 2008 to 49 percent in 2035 in the Reference case.

EISA2007 RFS targets are not met

in 2022 but are surpassed later

Figure 84. EISA2007 RFS credits earned

in selected years, 2008-2035 (billion credits)

EISA2007 mandates a total RFS credit requirement

of 36 billion gallons in 2022. Credits are equal to

ethanol-equivalent gallons produced [87], except for

the biodiesel schedule, which is based on actual volumes. BTL distillates receive a 1.7-gallon credit for

each gallon produced, because the energy content of

BTL fuels is higher than the energy content of ethanol. In total, 15 billion gallons of credits from conventional biofuels and 21 billion gallons from advanced

biofuels—including 16 billion gallons from cellulosic

biofuels—are required in 2022.

If available biofuel quantities are inadequate to meet

the initial targets, EISA2007 provides for application

of waivers and modification of applicable credit volumes. In the Reference case only 25.7 billion gallons

of RFS credits are generated in 2022 (Figure 84), because economic and technological factors prevent cellulosic biofuel production from providing the credits

that would be needed to meet the requirement.

Corn ethanol makes the largest contribution toward

the RFS mandate, providing up to 14.2 billion credits

in 2022. Cellulosic ethanol contributes 2.1 billion

credits to the advanced and cellulosic biofuel requirement in 2022, and BTL contributes 2.5 billion credits.

The remaining 6.9 billion gallons of credits for

advanced biofuels in 2022 include ethanol imports,

biodiesel, and renewable diesel. As the technologies

mature, production of cellulosic ethanol and BTL

increases to 5.1 billion and 9.6 billion gallons of

credits, respectively, in 2035. Production of biofuels

ultimately surpasses the RFS requirement as higher

oil prices and lower production costs improve their

competitiveness.

U.S. Energy Information Administration / Annual Energy Outlook 2010 77

Liquid fuels consumption

2008 2012 2022 2035

0

10

20

30

40

50

Corn-based ethanol

Cellulosic ethanol

Imports

Biodiesel

Biomass-to-liquids

Other feedstocks

EISA2007 mandate

1990 2000 2008 2015 2025 2035

0

20

40

60

80

History Projections

Low Oil Price

High Oil Price

Reference
Refinery operations shift focus

to diesel fuel production

Figure 85. U.S. motor gasoline and diesel fuel

consumption, 2008-2035 (million barrels per day)

Diesel consumption increases steadily from 2008 to

2035 in the AEO2010 Reference case, while motor

gasoline consumption remains relatively flat (Figure

85). Increased consumption of ethanol in E85 is

the main reason for the absence of substantial growth

in petroleum-based gasoline consumption, which

increases by less than 0.1 million barrels per day. In

addition, however, the combination of increased

diesel output and decreased refinery capacity leads to

a shift in the product slate of U.S. refineries. Diesel

consumption increases by approximately 1.0 million

barrels per day from 2008 to 2035 in the Reference

case, and diesel exports increase by approximately

0.2 million barrels per day. The increase in domestic

demand for diesel fuel is a result of increased freight

shipping activity.

Despite recent decreases in both demand for petroleum products and capacity utilization rates, total

capacity expands in the near term as planned additions are completed. The planned additions are

focused on diesel output for use in both domestic and

foreign markets.

After peaking in 2012, refinery capacity is expected to

decline by a total of approximately 0.8 million barrels

per day from 2012 through 2035 as diesel fuel consumption continues to grow in the Reference case,

resulting in a growing diesel share of refinery output.

Near-term increase in refinery capacity

leads to a lower utilization rate

Figure 86. U.S. refinery capacity, 1970-2035

(million barrels per day)

New projects to add capacity are underway at some

domestic refineries, and most of those projects are

scheduled to come on line in the next several years,

adding approximately 500,000 barrels per day of new

refining distillation capacity by the end of 2012. Two

large expansion projects in Port Arthur, Texas, and

Garyville, Louisiana, make up the majority of the new

capacity [88]. The additional capacity will be added, in

part, to meet the increase in demand for ultra-low-sulfur diesel fuel from 2008 to 2035. Some of

it will be configured to process heavier and less desirable crude oils, capitalizing on their lower costs. In

the near term, however, because the current

economic downturn reduces demand for motor fuels,

capacity utilization falls to approximately 80 percent

in 2010 from 85 percent in 2008 (Figure 86).

After 2012, approximately 1.5 million barrels per day

of existing capacity is taken out of service by 2022 in

the AEO2010 Reference case. The reduction in operating capacity, coupled with growth in demand for

diesel fuel, increases capacity utilization to around

89 percent in 2020, and it remains at roughly that

level through 2035. Given the current economic

climate, the potential for future carbon mitigation

legislation that could affect refiners, and the overall

level of demand, EIA does not expect future capacity

additions after 2013 in the Reference case or Low Oil

Price case. Excess refinery capacity is fully utilized in

the Low Oil Price case, but no new capacity is built.

78 U.S. Energy Information Administration / Annual Energy Outlook 2010

Liquid fuels refinery capacity

2000 2008 2015 2025 2035

0

2

4

6

8

10

Gasoline

Diesel

History Projections

1970 1990 2008 2020 2035

0

5

10

15

20

Capacity

Gross input

History Projections

85%

1970 2035

Capacity utilization

96% 88%
New generation of biofuels helps

meet renewable fuels standard

Figure 87. U.S. production of cellulosic ethanol

and other new biofuels, 2015-2035

(billion gallons per year)

A number of new biofuels that begin to enter the U.S.

market for transportation fuels in the later years

of the AEO2010 projection period contribute to

meeting the EISA2007 RFS mandate. New BTL fuels

include Fischer-Tropsch liquids, renewable diesel

(also known as “green diesel”), and pyrolysis oils. The

new fuels are assumed to satisfy both the advanced

biofuel and cellulosic biofuel requirements in the

RFS, because their life-cycle GHG emissions are 60

percent lower than those from conventional gasoline

or diesel fuel. In 2035, production of those three fuels

totals approximately 9.2 billion gallons, compared

with 5.1 billion gallons of cellulosic ethanol (Figure

87).

Each of the other new biofuels has distinct advantages over cellulosic ethanol and first-generation

biofuels, primarily in that they can be used in existing

distribution networks and vehicle fleets, because

their constituent chemical compounds are similar to

those found in traditional petroleum-based fuels.

Thus, they do not have the corrosive properties that

limit the transportation of other biofuels through existing petroleum product pipelines, and the use of

higher blends is not restricted to FFVs. This potentially avoids the substantial resource expenditures

that would be required for development of new infrastructure for traditional biofuels and avoids a key

barrier that ethanol faces in use beyond E10 blends.

In addition, the technologies used to produce the new

fuels can exploit a variety of feedstocks, including

biomass and animal fats, which contributes to their

attractive GHG profiles and production costs.

Coal production increases at a

slower rate than in the past

Figure 88. Coal production by region, 1970-2035

(quadrillion Btu)

In the AEO2010 Reference case, increasing coal use

for electricity generation, along with the startup of

several CTL plants, leads to growth in coal production

averaging 0.2 percent per year from 2008 to 2035.

This is significantly less than the 0.9-percent average

growth rate for U.S. coal production from 1980 to

2008.

Western coal production increases through 2035

(Figure 88), but at a much slower rate than in the

past. Both new and existing electric power plants are

major sources of additional demand for Western coal.

Low-cost supplies of coal from the West satisfy most

of the additional fuel needs at coal-fired power plants

both west and east of the Mississippi River.

Coal production in the Interior region (see Figure F6

in Appendix F for a map of the regions), which has

trended downward since the early 1990s, rebounds

somewhat in the Reference case, primarily supplanting more expensive coal from Central Appalachia that

currently is consumed at coal-fired power plants in

the Southeast. Much of the additional output from

the Interior region originates from mines tapping

into the extensive reserves of mid- and high-sulfur

bituminous coal in Illinois, Indiana, and western

Kentucky. In addition, some of the growth in output

from the Interior region results from increased lignite

production in Texas and Louisiana. Total production

of Appalachian coal declines from current levels, as

output shifts from the extensively mined, higher cost

reserves of Central Appalachia to lower cost supplies

from the Interior region and the northern part of the

Appalachian basin.

U.S. Energy Information Administration / Annual Energy Outlook 2010 79

Coal production

2015 2020 2025 2030 2035

0

2

4

6

8

10 Other new biofuels

Cellulosic ethanol

1970 1985 1995 2008 2020 2035

0

10

20

30

Appalachia

West

Total

History Projections

Interior
Long-term outlook for coal production

varies considerably across cases

Figure 89. U.S. coal production in six cases,

2008, 2020, and 2035 (quadrillion Btu)

U.S. coal production varies across the AEO2010

cases, reflecting different assumptions about the

costs of producing and transporting coal, the outlook

for economic growth, and the outlook for world oil

prices (Figure 89). In addition, although they are not

shown in the figure, alternative assumptions about

restrictions on GHG emissions could have even larger

impacts on coal production over the projection period.

Assumptions about economic growth primarily affect

the projections for overall electricity demand, which

in turn determine the need for coal-fired generation.

In contrast, assumptions about the costs of producing

and transporting coal primarily affect the choice of

technologies for electricity generation, with coal

capturing a larger share of the U.S. electricity market

in the Low Coal Cost case and a smaller share in

the High Coal Cost case. In the High Oil Price case,

higher oil prices stimulate the demand for coal-based

synthetic liquids, leading to a substantial expansion

of coal use at CTL plants. Production of coal-based

synthetic liquids totals 919,000 barrels per day in

2035 in the High Oil Price case, nearly four times

more than in the Reference case.

Coal production in the Reference case increases by

6 percent from 2008 to 2035, whereas the alternative

cases show changes ranging from a decrease of 7 percent to an increase of 16 percent. In the earlier years

of the projection, from 2008 to 2020, variations in coal

production across the cases are smaller, ranging

from a decline of 4 percent to an increase of 4 percent,

primarily reflecting the smaller changes in overall

energy demand over the shorter time frame.

Minemouth coal prices in the Western

and Interior regions rise

Figure 90. Average annual minemouth coal prices

by region, 1990-2035 (2008 dollars per million Btu)

In the Western and Interior coal supply regions,

slight declines in mining productivity, combined with

projections of increasing production, result in higher

minemouth prices, with average annual price growth

of 0.5 percent and 0.7 percent, respectively, in the two

regions from 2008 to 2035 (Figure 90).

In contrast, after peaking in 2009, the average minemouth price for Appalachian coal declines by 0.5 percent per year through 2035, as a result of falling

demand for the region’s coal and a shift to lower cost

production in the northern part of the Appalachian

basin. Recent jumps in the average price of Appalachian coal, from $1.26 per million Btu in 2000 to $2.36

per million Btu in 2008, were in part a result of

significant declines in mining productivity during

the period. The price increases have substantially

reduced the competitiveness of Appalachian coal with

coal from the other producing regions.

In the Reference case, average U.S. minemouth coal

prices are roughly flat to slightly down overall, from

$1.55 per million Btu in 2008 to $1.51 in 2020 and

$1.44 in 2035—a decline of 0.3 percent per year over

the entire period but starting from an unusual rise in

2008. Sizable increases in prices from 2000 to 2008

averaged 5.9 percent per year, and sharper declines

from 1990 to 2000 averaged 4.2 percent per year. The

moderation of coal prices in the projection results

from a variety of factors, including a shift in production from Appalachia to the Interior and Western

regions, which have lower costs of production, and a

relatively flat outlook for coal mining productivity,

which in recent years has been declining at a substantial pace in all the major coal-producing regions.

80 U.S. Energy Information Administration / Annual Energy Outlook 2010

Coal prices

2020 - 2035 -

0

20

40

60

Reference

Low Economic Growth

High Coal Cost

2008

High Economic Growth

High Oil Price

Low Coal Cost

1990 2000 2008 2015 2025 2035

0.0

0.5

1.0

1.5

2.0

2.5

U.S. average

West

Appalachia

History Projections

Interior
Substantial changes in coal prices

have moderate effects on demand

Figure 91. Average annual delivered coal prices in

four cases, 1990-2035 (2008 dollars per million Btu)

Alternative assumptions for coal mining and transportation costs affect delivered coal prices and

demand. Two Coal Cost cases developed for AEO2010

examine the impacts on U.S. coal markets of alternative assumptions about mining productivity, labor

costs, mine equipment costs, and coal transportation

rates (Figure 91). Although alternative assumptions

about economic growth and world oil prices lead to

some variations in the price paths for coal, the differences from the Reference case are relatively small in

those cases.

In the High Coal Cost case, the average delivered coal

price is $3.72 per million Btu (2008 dollars) in 2035—

74 percent higher than in the Reference case. Because

the higher coal prices result in switching from coal to

natural gas and renewables in the electricity sector,

U.S. coal consumption in 2035 is 7 percent (1.8 quadrillion Btu) lower in the High Coal Cost case than in

the Reference case. In the Low Coal Cost case, delivered coal prices in 2035 average $1.32 per million

Btu—38 percent lower than in the Reference

case—and total coal consumption is 6 percent (1.5

quadrillion Btu) higher than in the Reference case.

Because the Economic Growth and Oil Price cases

use the Reference case assumptions for coal mining

and rail transportation costs, they show smaller variations in average delivered coal prices than do the two

coal cost cases. Differences in coal price projections in

the Economic Growth and Oil Price cases result

mainly from higher and lower levels of demand for

coal. In the Oil Price cases, higher and lower fuel costs

for both coal producers and railroads also contribute

to the slight variations in coal prices.

Long-term outlook for coal is shaped

by concerns about GHG legislation

Figure 92. Change in U.S. coal consumption

by end use in two cases, 2008-2035 (quadrillion Btu)

In the AEO2010 Reference case, the cost of capital for

investments in GHG-intensive technologies, including CTL plants and coal-fired power plants without

CCS, is increased by 3 percentage points to reflect the

behavior of utilities, other energy companies, and

regulators concerning the possible enactment of

GHG legislation which could mandate that owners

purchase allowances, invest in CCS, or invest in other

projects to offset their emissions in the future. A

No GHG Concern case, in which the additional 3 percentage points for GHG-intensive technologies is

removed, is used to evaluate the impact on energy

investments.

In the No GHG Concern case, coal use for both

electricity generation and production of coal-based

synthetic liquids is considerably higher than in the

Reference case (Figure 92), and 65 gigawatts of new

coal-fired generating capacity is added between 2009

and 2035, as compared with 31 gigawatts in the

Reference case. As a result, additions of both natural

gas and renewable generating capacity are somewhat lower in the No GHG Concern case than in

the Reference case. The production of coal-based synthetic liquids is also higher in the No GHG Concern

case, at 525,000 barrels per day in 2035, compared

with 243,000 barrels per day in the Reference case.

CO2 emissions increase to 6,488 million metric tons in

2035 in the No GHG Concern case, about 3 percent

higher than in the Reference case and 12 percent

higher than in 2008.

U.S. Energy Information Administration / Annual Energy Outlook 2010 81

Coal prices

1990 2000 2008 2015 2025 2035

0

1

2

3

4

High Coal Cost

High Oil Price

Reference

History Projections

Low Coal Cost

Electric power Coal-to-liquids Other

0

1

2

3

4

5

-1

Reference

No GHG Concern
Growth of carbon dioxide emissions

slows in the projections

Figure 93. Carbon dioxide emissions by sector and

fuel, 2008 and 2035 (million metric tons)

Federal and State energy policies recently enacted

will stimulate increased use of renewable technologies and efficiency improvements in the future, slowing the growth of energy-related CO2 emissions

through 2035. In the Reference case, emissions do not

exceed pre-recession 2007 levels until 2025. In 2035,

energy-related CO2 emissions total 6,320 million metric tons, about 6 percent higher than in 2007 and 9

percent higher than in 2008 (Figure 93). On average,

emissions in the Reference case grow by 0.3 percent

per year from 2008 to 2035, compared with 0.8 percent per year from 1980 to 2008.

Shares of the fossil fuels responsible for energyrelated CO2 emissions—coal, natural gas, and petroleum—do not vary substantially from 2008 to 2035.

Petroleum, used mainly in the transportation sector,

remains the largest source of CO2 emissions, accounting for 42 percent of the total in 2008 and 41 percent

in 2035. CAFE standards and RFS requirements

reduce consumption and slow the growth of CO2

emissions from petroleum. The coal share of CO2

emissions rises from 37 percent in 2008 to 38 percent

in 2035; the natural gas share is stable at 21 percent.

In 2008, 41 percent of total CO2 emissions came from

electricity generation. With its high carbon content

and 48-percent share of generation, coal accounted

for 82 percent of power sector CO2 emissions. Given

the uncertainty over future GHG regulations, higher

capital costs for coal-fired technologies, and new RPS

programs in many States, coal’s share of generation

falls to 44 percent in 2035. In addition, higher fuel

costs and improved efficiency slow the overall growth

of electricity demand and associated emissions.

Sulfur dioxide emissions decrease

due to the Clean Air Interstate Rule

Figure 94. Sulfur dioxide emissions from

electricity generation, 2000-2035

(million short tons)

In December 2008, the U.S. Court of Appeals for the

District of Columbia Circuit temporarily reinstated

CAIR, which includes a cap-and-trade system for SO2

and NOx emissions. The decision also required the

EPA to develop new rules to correct flaws cited in the

Court’s July 2008 ruling that vacated CAIR, but

because AEO2010 considers only current rules and

regulations, the projections for SO2 and NOx emissions are based on the current version of CAIR.

To comply with CAIR, SO2 emissions in 2035 are 50

percent below the 2008 total (Figure 94). Reductions

are achieved by more use of low-sulfur coal and flue

gas desulfurization (FGD) scrubbers. From 2009 to

2035, coal-fired plants with about 81 gigawatts total

capacity are retrofitted with scrubbers. Emissions

vary from year to year, because CAIR allows utilities

to bank unused allowances at the end of a year and

use them in future years. In the 2030-2035 period, the

amounts of banked allowances applied by utilities

allow actual emissions to rise slightly.

SO2 allowance prices increase from over $230 per ton

in 2008 to almost $1,500 per ton in the later years of

the projection. The price increase is a result of declining emissions caps, which lead to higher prices when

allowances become scarce.

In addition to CAIR, implementation of a GHG emissions control policy could significantly reduce SO2

emissions by forcing the retirement of older, less

efficient coal-fired plants without FGD equipment.

82 U.S. Energy Information Administration / Annual Energy Outlook 2010

Emissions from energy use

0

1,000

2,000

3,000

4,000

Electricity

Electricity generation

Natural gas

Coal

Petroleum

Residential

Commercial

Industrial

Transportation

2008

2035

2008 2035

Total carbon dioxide

6,320 5,814

emissions

1980

4,770

11.4

10.2

7.6

4.7 4.2 3.8 3.7 3.8

2000 2005 2008 2015 2020 2025 2030 2035

0

5

10

15

History Projections

4.2 3.8 3.7 3.8
Nitrogen oxide emissions also

decline in the Reference case

Figure 95. Nitrogen oxide emissions from

electricity generation, 2000-2035

(million short tons)

With the temporary reinstatement of CAIR, the

annual NOx emissions market officially began operating in 2009 (although provisions in the current CAIR

are temporary until the EPA releases the courtordered replacement rule). In AEO2010, NOx emissions decline from 3.0 million short tons in 2008 to

2.0 million short tons in 2017, then rise slowly after

2018, when more banked allowances are used to meet

the cap (Figure 95).

To reduce NOx emissions, coal-fired power plants

can be retrofitted with selective catalytic converter

(SCR), selective noncatalytic converter, or low-NOx

burner technologies. In the Reference case, 168

gigawatts of total capacity is retrofitted with one or

another of the three technologies. The amounts differ

in the High and Low Economic Growth cases. Higher

economic growth increases demand for electricity,

and more plants are retrofitted. Lower growth has

the opposite effect. In 2035, the NOx allowance price,

which is $3,268 per ton in the Reference case, is

higher in High Economic Growth case (because more

investment is required to comply with the cap)

and lower in the Low Economic Growth Case, where

demand for electricity is lower.

At the beginning of 2009, the EPA introduced an

annual market for NOx emissions to complement the

existing seasonal market. So far, allowance prices in

the annual market have been significantly higher

than in the seasonal market, suggesting that the

annual program may be more binding.

U.S. Energy Information Administration / Annual Energy Outlook 2010 83

Endnotes for Market Trends

5.3

3.6

3

2.1 2 2 2.1 2.1

2000 2005 2008 2015 2020 2025 2030 2035

0

2

4

6

8 History Projections

2.0 2.0

3.0

3.6

78. The National Bureau of Economic Research defines a

recession as “a significant decline in economic activity

spread across the economy, lasting more than a few

months, normally visible in real GDP, real income,

employment, industrial production, and wholesaleretail sales.” However, the shorthand version of a

recession is often given as two consecutive quarters of

negative growth in GDP. In December 2008, the

National Bureau of Economic Research declared that

the United States had entered a recession in December

2007.

79. The industrial sector includes manufacturing, agriculture, construction, and mining. The energy-intensive

manufacturing sectors include food, paper, bulk chemicals, petroleum refining, glass, cement, steel, and aluminum.

80. Air-Conditioning, Heating, and Refrigeration Institute, “Agreement on Legislative and Regulatory Strategy for Amending Federal Energy Efficiency Standards, Test Procedures, Metrics and Building Code

Provisions for Residential Central Air Conditioners,

Heat Pumps, Weatherized and Non-Weatherized

Furnaces and Related Matters” (October 13, 2009),

web site http://www.ahrinet.org/Admin/Pages/Util/

ShowDoc.aspx?doc=1635.

81. S.C. Davis and S.W. Diegel, Transportation Energy

Data Book: Edition 25, ORNL-6974 (Oak Ridge, TN,

May 2006), Chapter 4, “Light Vehicles and Characteristics,” web site http://cta.ornl.gov/data/chapter4.

shtml.

82. The factors that influence decisionmaking on capacity

additions include electricity demand growth, the need

to replace inefficient plants, the costs and operating

efficiencies of different generation options, fuel prices,

State RPS programs, and the availability of Federal

tax credits for some technologies.

83. Unless otherwise noted, the term “capacity” in the discussion of electricity generation indicates utility,

nonutility, and CHP capacity. Costs reflect the average of regional costs, except that a representative

region is used to estimate costs for wind plants.

84. Detailed qualifications for each of the 35 State programs represented in the AEO2010 modeling include

eligible technologies, funding limits, and penalties for

noncompliance.

85. For example, drilling permits are not currently being

issued in the State of New York, where concerns have

been raised about potential risks to drinking water

supplies.

86. Leasing in the Eastern Gulf of Mexico is restricted

until 2022 under the Gulf of Mexico Energy Security

Act of 2006.

87. One gallon of ethanol is equal to 0.65 gallon of regular

gasoline.

88. The Motiva plant in Port Arthur, TX, and the Marathon project in Garyville, LA.

Comparison With Other Projections
Only IHS Global Insights, Inc. (IHSGI) produces a

comprehensive energy projection with a time horizon

similar to that of AEO2010. Other organizations,

however, address one or more aspects of the U.S.

energy market. The most recent projection from IHSGI, as well as others that concentrate on economic

growth, international oil prices, energy consumption,

electricity, natural gas, petroleum, and coal, are compared here with the AEO2010 projections.

Economic growth

Projections of the average annual growth rate of real

GDP in the United States from 2008 to 2018 range

from 2.1 percent to 2.8 percent (Table 9). In the

AEO2010 Reference case, real GDP grows by an

average of 2.2 percent per year over the period, lower

than projected by the Office of Management and Budget (OMB), the Congressional Budget Office (CBO),

the Social Security Administration (SSA), and the Bureau of Labor Statistics (BLS)—although none of

those projections has been updated since August

2009. The AEO2010 projection is similar to the IHSGI projection and slightly higher than projections by

the Interindustry Forecasting Project at the University of Maryland (INFORUM). In March 2009, the

consensus Blue Chip projection was for 2.2-percent

average annual growth from 2008 to 2018.

The range of GDP growth rates is wider for the recovery period from 2018 to 2030, with projections

ranging from 2.2 to 2.7 percent per year. Uncertainty

about the timing and speed of recovery from the current recession contributes to the wide range of

projections over the 2018-2030 period. The 2.7-

percent average annual GDP growth rate in the

AEO2010 Reference case from 2018 to 2030 is on the

higher side of the estimates but similar to the IHSGI

projection. SSA, the International Energy Agency

(IEA), and INFORUM project lower growth, as a result of their lower projections for labor productivity.

AEO2010 projects productivity increases averaging

2.1 percent per year from 2018 to 2030, as compared

with the SSA and INFORUM projections of 1.7 and

1.6 percent per year, respectively, over the same

period.

There are few public or private projections of GDP

growth for the United States that extend to 2035. The

AEO2010 Reference case projects 2.4-percent average

annual GDP growth, consistent with the trends in

labor force and productivity growth. IHSGI projects

GDP growth averaging 2.5 percent per year from

2008 to 2035, and INFORUM projects an average of

2.3 percent from 2008 to 2030 (the last year of the

INFORUM projection). Both AEO2010 and IHSGI

project higher growth rates for productivity and labor

force growth than does INFORUM.

World oil prices

In the AEO2010 Reference case, world oil prices rise

from current levels to approximately $95 per barrel in

2015 and $108 per barrel in 2020 (Table 10). After

2020, prices increase slowly to $133 per barrel in

2035. The price trend is slightly lower than in last

year’s (AEO2009) Reference case.

Market volatility and different assumptions about the

future of the world economy are reflected in the range

of price projections for both the short and long term.

Most of the projections show prices rising throughout

the entire period. The projections for world oil prices

in 2030 range from $65 per barrel to $124 per barrel.

The range of the other projections is encompassed in

86 U.S. Energy Information Administration / Annual Energy Outlook 2010

Comparison with Other Projections

Table 9. Projections of average annual economic

growth rates, 2008-2035

Average annual percentage

growth rates

Projection

2008-

2018

2018-

2030

2030-

2035

AEO2009 (Reference case) 2.2 2.6 –

AEO2010 (Reference case) 2.2 2.7 2.4

IHSGI (May 2009) 2.2 2.7 2.5

OMB (July 2009) a 2.8 – –

CBO (August 2009) a 2.5 – –

INFORUM (December 2009) 2.1 2.4 –

SSA (May 2009) 2.3 2.1 2.2

BLS (December 2009) a 2.4 – –

IEA (2009) b 1.8 2.2 –

Blue Chip Consensus

(March 2009) 2.2 – –

aOMB and CBO projections end in 2019; BLS projection ends in

2018.

bIEA published U.S. growth rates for 2007-2015 (1.8 percent),

2015-2030 (2.2 percent), and 2007-2030 (2.1 percent).

– = not reported.

Table 10. Projections of world oil prices, 2015-2035

(2008 dollars per barrel)

Projection 2015 2020 2025 2030 2035

AEO2009 (Reference case) 112.91 117.99 124.62 133.29 –

AEO2010 (Reference case) 94.52 108.28 115.09 123.50 133.22

INFORUM 92.50 107.98 109.74 116.81 –

DB 93.18 105.48 114.65 121.16 125.42

IHSGI 85.07 81.93 74.86 77.27 80.03

IEA (Reference) – 100.00 – 115.00 –

EVA 80.35 84.45 90.98 100.45 –

SEER (Business-as-Usual) 79.20 74.31 69.73 65.43 –

SEER (Multi-Dimensional) 99.03 101.52 105.81 113.91 –

– = not reported.
the range of the AEO2010 Low and High Oil Price

cases: from $52 per barrel to $204 per barrel in 2030

and from $51 per barrel to $210 per barrel in 2035.

The world oil price measures are, by and large, comparable across projections. EIA reports the price of

imported low-sulfur, light crude oil, approximately

the same as the West Texas Intermediate (WTI)

prices that are widely cited as a proxy for world oil

prices in the trade press. Deutsche Bank (DB),

IHSGI, Energy Ventures Analysis, Inc. (EVA), and

Strategic Energy & Economic Research, Inc. (SEER)

report prices in WTI terms. IEA’s World Energy Outlook 2009 expresses prices as the IEA crude oil import

price; INFORUM expresses prices as the average U.S.

imported refiner acquisition cost of crude oil.

Total energy consumption

Two of the projections, IHSGI and INFORUM,

feature energy consumption by sector (although the

INFORUM projection does not include data for 2008

and does not extend to 2035). Energy prices in the

IHSGI projection are lower than those in the AEO2010 Reference case. Prices in the INFORUM projections for crude oil, natural gas, and coal also are

higher than in AEO2010, but electricity prices in

the end-use sectors are at the same level (industrial

and commercial) or lower (residential) than in

the AEO2010 Reference case. Both IHSGI and

INFORUM project slower growth in energy consumption than in the AEO2010 Reference case (Table 11).

Neither IHSGI nor INFORUM projects the introduction of Fischer-Tropsch fuels, nor do they include an

accounting for the difference between the energy contained in biofuels and the energy contained in the biomass feedstock used in their production. When the

AEO2010 projections are adjusted for those two items

(about 2.3 quadrillion Btu in 2030 and 3.1 quadrillion

Btu in 2035), energy consumption in 2030 in the

AEO2010 Reference case is similar to that in the

INFORUM projection, with differences of about 0.7

quadrillion Btu (lower) in the residential sector and

about 0.7 quadrillion Btu (higher) in the electric

power sector. For the residential sector, about

one-half of the difference between the INFORUM and

AEO2010 Reference case projections is related to

electricity consumption: INFORUM shows lower residential electricity prices but similar electricity prices

in the industrial and commercial sectors. Total natural gas demand in the INFORUM projection is similar

to that in the AEO2010 Reference case, despite natural gas prices that are 50 to 80 cents per thousand

cubic feet higher than in the AEO2010 Reference case

in 2020, 2025, and 2030.

Energy prices in the IHSGI projection generally are

lower than those in the AEO2010 Reference case. In

the IHSGI projection for 2035, average natural gas

wellhead prices are $2.20 per thousand cubic feet

lower, average delivered electricity prices are 7 mills

per kilowatthour lower, coal prices to the electric

power sector are about $0.20 per million Btu lower,

U.S. Energy Information Administration / Annual Energy Outlook 2010 87

Comparison with Other Projections

Table 11. Projections of energy consumption by sector, 2007-2035 (quadrillion Btu)

Sector

2007 2008 2030 2035

AEO2010INFORUM IHSGIAEO2010INFORUM IHSGIAEO2010INFORUM IHSGIAEO2010INFORUM IHSGI

Residential 11.3 11.3 10.8 11.3 – 10.9 11.9 12.6 11.8 12.1 – 11.9

Commercial 8.4 8.4 8.4 8.6 – 8.6 10.5 10.6 9.9 11.0 – 10.0

Industrial 25.2 – – 24.8 – – 26.1 – – 26.7 – –

Industrial excluding losses a 24.8 25.2 23.0 23.8 – 22.0 23.8 23.9 22.8 23.6 – 23.2

Transportation 29.0 28.9 28.6 27.8 – 27.3 31.3 31.0 29.1 32.5 – 30.6

Electric power 40.6 40.6 42.1 40.2 – 41.8 46.6 45.8 48.6 48.1 – 49.0

Less: electricity purchases b 12.8 12.8 12.8 12.7 – 12.8 15.3 15.3 15.8 15.9 – 16.3

Total primary energy 101.7 – – 100.1 – – 111.2 – – 114.5 – –

Total primary energy

excluding industrial

losses a

101.2 101.7 100.1 99.1 – 97.8 108.8 108.7 106.4 111.4 – 108.5

– = not reported.

aLosses in CTL and biofuel production.

bEnergy consumption in the end-use sectors includes electricity purchases from the electric power sector, which must be subtracted to avoid

double counting in the derivation of total primary energy consumption.
and light sweet crude oil prices are more than $50 per

barrel lower than in the AEO2010 projection. When

the energy contained in biofuels and biomass

feedstocks (which is not included in the IHSGI projection) is subtracted from the AEO2010 Reference case

projections, overall demand is about 3 quadrillion Btu

lower in the IHSGI projection, transportation sector

demand is about 2 quadrillion Btu lower, commercial

sector demand (mostly for natural gas) is about 1 quadrillion Btu lower, and there are smaller differences

in the industrial and residential sectors that more

than offset the difference of about 1 quadrillion Btu

between the higher IHSGI projection and the

AEO2010 Reference case projection for energy consumption in the electric power sector.

Electricity

Table 12 provides a summary of results from the

AEO2010 Reference case and compares them with

other projections. For 2015, electricity sales range

from a low of 3,870 billion kilowatthours in AEO2010

to a high of 3,998 billion kilowatthours in the IHSGI

projection. IHSGI shows higher sales in the residential and commercial sectors and slightly lower sales in

the industrial sector. For 2035, electricity sales in the

IHSGI projection are 4,734 billion kilowatthours,

somewhat higher than the 4,660 billion kilowatthours in AEO2010. IHSGI projects higher residential

and industrial sales and lower commercial sales of

electricity in 2035.

The AEO2010 Reference case shows declining real

electricity prices after 2008, with rising prices near

the end of the period, based on projected increases in

fuel costs for generation and capital expenditures for

construction of new capacity. The higher fossil fuel

prices and capital expenditures in the AEO2010 projection result in an increase in the average electricity

price, from 8.9 cents per kilowatthour in 2015 to 10.2

cents per kilowatthour in 2035. IHSGI shows electricity prices declining from 2015 to 2035.

Total generation and imports of electricity in 2015

are higher in the IHSGI projection than in the AEO2010 Reference case. The requirements for generating capacity are driven by growth in electricity sales

and the need to replace existing units that are uneconomical or are being retired for various reasons.

Consistent with its projections of electricity sales,

IHSGI shows higher growth in generation and imports through 2015 in comparison with the AEO2010

Reference case. For 2035, total generation and

imports are slightly lower in the IHSGI projection

than in AEO2010. The two projections for nuclear

power are similar, but those for generation from coal,

oil, hydroelectric/other, and electricity imports all are

lower, and the projection for natural gas is higher

in the IHSGI projections than in the AEO2010 Reference case.

The projections for generating capability in 2015

range from 1,032 gigawatts for IHSGI to 1,124

gigawatts for EVA, which shows more oil-fired and

natural-gas-fired capacity than in the other projections. The IHSGI projections for hydroelectric/other

capacity are lower than those from EVA and the

AEO2010 Reference case. The IHSGI and AEO2010

projections of generating capability in 2035 are similar, except that IHSGI expects much less oil- and natural-gas-fired capacity than is projected in AEO2010.

The AEO2010 projection includes 4.0 gigawatts of

uprates for nuclear capacity and expects all existing

nuclear units to continue operating through 2035,

based on the assumption that they will apply for and

receive operating license renewals, including, in some

cases, a second 20-year extension after they reach 60

years of operation. AEO2010 also includes a second

unit in 2014 at the Watts Bar site, where construction

of a partially completed reactor was halted in 1988.

Environmental regulations are important determinants in the selection of electricity generation technologies. The AEO2009 Reference case did not

include the SO2 and NOx cap-and-trade programs for

power plants called for in the EPA’s CAIR, because

the Circuit Court for the District of Columbia had vacated CAIR in a July 2008 ruling. On December 23,

2008, the Court temporarily reinstated the rule, however, and it is represented in the AEO2010 Reference

case. AEO2010 does not include the CAMR regulations, which were voided by the U.S. Court of Appeals

in February 2008. Also, because AEO2010 includes

only current laws and regulations, it does not assume

any cap or tax on CO2 emissions. Restrictions on CO2

emissions could change the mix of technologies used

to generate electricity.

Natural gas

The variation among projections of natural gas consumption, production, imports, and prices (Table 13)

can be significant. This variation results from differences among the assumptions that underlie the

different projection. For example, the AEO2010 Reference case generally assumes that current laws

88 U.S. Energy Information Administration / Annual Energy Outlook 2010

Comparison with Other Projections
U.S. Energy Information Administration / Annual Energy Outlook 2010 89

Comparison with Other Projections

Table 12. Comparison of electricity projections, 2015 and 2035 (billion kilowatthours, except where noted)

Projection 2008

AEO2010

Reference

case

Other projections

IHSGI EVA

2015

Average end-use price

(2008 cents per kilowatthour) 9.8 8.9 9.6 –

Residential 11.4 10.7 11.0 –

Commercial 10.4 9.1 10.1 –

Industrial 6.9 5.9 6.7 –

Total generation plus imports 4,148 4,300 4,383 –

Coal 1,995 2,037 2,070 –

Oil 45 46 46 –

Natural gas a 879 690 896 –

Nuclear 806 834 849 –

Hydroelectric/other b 391 672 504 –

Net imports 33 20 18 28

Electricity sales 3,720 3,870 3,998 –

Residential 1,379 1,400 1,512 –

Commercial/other c 1,359 1,473 1,517 –

Industrial 982 997 970 –

Capability, including CHP (gigawatts) d 1,008 1,069 1,032 1,124

Coal 312 325 323 323

Oil and natural gas 454 442 446 510

Nuclear 101 105 106 106

Hydroelectric/other 141 198 157 186

2035

Average end-use price

(2008 cents per kilowatthour) 9.8 10.2 9.5 –

Residential 11.4 11.8 10.8 –

Commercial 10.4 10.4 9.9 –

Industrial 6.9 7.1 6.5 –

Total generation plus imports 4,148 5,285 5,187 –

Coal 1,995 2,305 2,244 –

Oil 45 49 32 –

Natural gas a 879 1,093 1,148 –

Nuclear 806 898 900 –

Hydroelectric/other b 391 915 851 –

Net imports 33 25 12 –

Electricity sales 3,720 4,660 4,734 –

Residential 1,379 1,707 1,809 –

Commercial/other c 1,359 1,937 1,831 –

Industrial 982 1,016 1,094 –

Capability, including CHP (gigawatts) d 1,008 1,216 1,082 –

Coal 312 337 334 –

Oil and natural gas 454 531 399 –

Nuclear 101 113 116 –

Hydroelectric/other 141 236 233 –

aIncludes supplemental gaseous fuels. For EVA, represents total oil and natural gas. b“Other” includes conventional hydroelectric, pumped

storage, geothermal, wood, wood waste, municipal waste, other biomass, solar and wind power, batteries, chemicals, hydrogen, pitch,

purchased steam, sulfur, petroleum coke, and miscellaneous technologies. c

“Other” includes sales of electricity to government, railways,

and street lighting authorities. dEIA capacity is net summer capability, including CHP plants. IHSGI capacity is nameplate, excluding

cogeneration plants.

– = not reported.

Sources: 2008 and AEO2010: AEO2010 National Energy Modeling System, run AEO2010R.D111809A. IHSGI: IHS Global Insight, Inc.,

2009 Energy Outlook (Lexington, MA, September 2009). EVA: Energy Ventures Analysis, Inc., FUELCAST: Long-Term Outlook (February

2010).
and regulations will continue through the projection

period as enacted, whereas some of the other projections assume the enactment of new public policy over

the next 25 years. For example, the results of the

Altos projection reflect the inclusion of carbon mitigation legislation.

All but two of the projections (Altos and EVA) show

an initial decline and subsequent increase in natural

gas consumption from 2008 levels, but they differ in

terms of when, between 2015 and 2025, 2008 levels

are regained. The INFORUM projection for 2015 is

1.2 to 2.1 trillion cubic feet lower than the others but

recovers quickly by 2025. With the exception of the

SEER projection, which shows a decline in natural

gas consumption from 2025 to 2030, total natural gas

consumption grows in spite of increasing prices in the

later years of all the projections. Altos and EVA show

natural gas consumption exceeding 2008 levels by

2010 and continuing to increase at much more rapid

rates than in the other projections.

90 U.S. Energy Information Administration / Annual Energy Outlook 2010

Comparison with Other Projections

Table 13. Comparison of natural gas projections, 2015, 2025, and 2035 (trillion cubic feet, except where noted)

Projection 2008

AEO2010

Reference

case

Other projections

IHSGI EVA DB SEER Altos INFORUM

2015

Dry gas production a 20.56 19.29 22.63 24.47 19.29 20.01 19.19 19.71

Net imports 2.95 2.38 2.43 4.84 – 2.73 3.79 4.12

Pipeline 2.65 1.29 1.62 2.65 – 1.83 0.47 –

LNG 0.30 1.09 0.81 2.19 3.48 0.90 3.32 –

Consumption 23.25 21.74 22.63 24.84 – 22.80 24.18 b 18.86 b

Residential 4.87 4.71 4.71 5.07 – 4.87 4.75 4.76

Commercial 3.12 3.23 3.05 3.21 – 3.14 3.18 3.16

Industrial c 6.65 6.88 6.24 6.84 – 6.23 6.41 6.35

Electricity generators d 6.66 5.18 6.74 7.62 – 6.73 9.83 4.60

Other e 1.95 1.73 1.90 2.09 – 1.84 – –

Lower 48 wellhead price (2008 dollars

per thousand cubic feet) f 8.07 5.70 5.73 6.40 5.77 5.34 6.06 –

End-use prices (2008 dollars per thousand cubic feet)

Residential 13.87 11.89 12.15 – – 12.26 – –

Commercial 12.29 10.28 10.51 – – 11.08 – –

Industrial g 9.38 6.63 8.01 – – 7.11 – –

Electricity generators 9.34 6.24 6.44 – – 6.70 – –

2025

Dry gas production a 20.56 21.31 21.91 24.41 20.63 22.30 27.23 20.93

Net imports 2.95 2.17 2.34 2.89 – 2.18 3.67 5.77

Pipeline 2.65 0.89 1.42 2.52 – 1.25 -1.42 –

LNG 0.30 1.28 0.92 0.37 2.65 0.93 5.09 –

Consumption 23.25 23.57 24.22 27.84 – 24.35 27.72 b 21.82 b

Residential 4.87 4.89 4.62 5.16 – 4.90 4.85 4.86

Commercial 3.12 3.45 3.06 3.28 – 3.41 3.33 3.24

Industrial c 6.65 6.94 6.34 7.55 – 6.55 6.47 6.93

Electricity generators d 6.66 6.28 8.12 9.49 – 7.51 13.08 6.81

Other e 1.95 2.00 2.07 2.36 – 1.99 – –

Lower 48 wellhead price (2008 dollars

per thousand cubic feet) f 8.07 6.35 5.87 7.31 8.42 5.90 7.01 –

End-use prices (2008 dollars per thousand cubic feet)

Residential 13.87 12.65 12.08 – – 12.96 – –

Commercial 12.29 11.01 10.49 – – 11.87 – –

Industrial g 9.38 7.22 8.10 – – 7.70 – –

Electricity generators 9.34 6.94 6.57 – – 8.87 – –

– = not reported. See notes and sources at end of table.
For the residential and commercial sectors, natural

gas consumption patterns are similar across the

projections, with the exception of IHSGI, which

shows a decline in residential consumption and commercial consumption that remains below the 2008

level through 2035. Excluding IHSGI, the average

annual rate of growth in residential natural gas

consumption from 2008 to 2025 ranges from almost

no growth to 0.5 percent, and the average for commercial natural gas consumption varies from 0.2

percent (INFORUM) to 0.6 percent (AEO2010).

Three of the six projections (EVA, INFORUM, and

the AEO2010 Reference case) show industrial natural

gas consumption returning to 2008 levels or higher by

2015. In the AEO2010 projection, industrial natural

gas consumption exceeds 2008 levels in 2015, because

industrial natural gas prices are relatively low, and

there is a significant increase in the use of natural gas

at refineries for biofuel production. The AEO2010

Reference case and EVA projections show the strongest short-term growth in industrial natural gas consumption, averaging 0.5 percent per year from 2008

to 2015.

The differences among the projections for natural gas

consumption in the electric power sector can be attributed to two primary factors: assumptions about

carbon mitigation legislation and assumptions about

the costs and availability of hydroelectric and other

renewable energy resources. The AEO2010 Reference

case and INFORUM projections are the lowest, and

they are the only ones in which the sector’s consumption of natural gas in 2015 is lower than in 2008 (in

the AEO2010 Reference case, as a result of slow

growth in electricity demand, completion of planned

new coal-fired capacity, and construction of new renewable capacity in response to incentives and RFS

U.S. Energy Information Administration / Annual Energy Outlook 2010 91

Comparison with Other Projections

Table 13. Comparison of natural gas projections, 2015, 2025, and 2035 (continued)

(trillion cubic feet, except where noted)

Projection 2008

AEO2010

Reference

case

Other projections

IHSGI EVA DB SEER Altos INFORUM

2035

Dry gas production a 20.56 23.27 23.02 – 18.44 – 32.72 –

Net imports 2.95 1.46 1.84 – – – 1.70 –

Pipeline 2.65 0.64 0.92 – – – -4.46 –

LNG 0.30 0.83 0.92 – 3.91 – 6.16 –

Consumption 23.25 24.86 24.84 – – – 30.48 b –

Residential 4.87 4.87 4.45 – – – 4.85 –

Commercial 3.12 3.69 3.05 – – – 3.50 –

Industrial c 6.65 6.72 6.37 – – – 6.42 –

Electricity generators d 6.66 7.42 8.81 – – – 15.72 –

Other e 1.95 2.17 2.16 –––––

Lower 48 wellhead price (2008 dollars

per thousand cubic feet) f 8.07 8.06 5.87 – 9.91 – 7.89 –

End-use prices (2008 dollars per thousand cubic feet)

Residential 13.87 14.82 11.85 –––––

Commercial 12.29 13.03 10.31 –––––

Industrial g 9.38 8.99 8.05 –––––

Electricity generators 9.34 8.69 6.54 –––––

– = not reported.

aDoes not include supplemental fuels. bDoes not include natural gas use as fuel for lease and plants, pipelines, or natural gas vehicles. c

Includes consumption for industrial CHP plants, a small number of electricity-only plants, and GTL plants for heat and power production.

dIncludes consumption of energy by electricity-only and CHP plants whose primary business is to sell electricity, or electricity and heat, to

the public. Includes electric utilities, small power producers, and exempt wholesale generators. e

Includes lease, plant, and pipeline fuel and

fuel consumed in natural gas vehicles. f

2008 wellhead natural gas price for SEER is $7.65 per thousand cubic feet. gThe 2008 industrial

natural gas price for IHSGI and SEER are $10.30 and $9.80 per thousand cubic feet, respectively.

Sources: 2008 and AEO2010: AEO2010 National Energy Modeling System, run AEO2010R.D111809A. IHSGI: IHS Global Insight, Inc.,

2009 U.S. Energy Outlook (September 2009). EVA: Energy Ventures Analysis, Inc., FUELCAST: Long-Term Outlook (February 2010).

DB: Deutsche Bank AG, e-mail from Adam Sieminski (November 3, 2009). SEER: Strategic Energy and Economic Research, Inc., “Natural

Gas Outlook” (November 2009). Altos: Altos World Gas Trade Model (October 2009). INFORUM: INFORUM Base, e-mail from Douglas

Meade (January 15, 2010).
programs at the State level). The highest level of natural gas consumption in the electric power sector is in

the Altos projection, ranging from 29 percent to 114

percent above the other projections for 2015 and 38

percent to 108 percent above the others for 2025.

The natural gas supply projections from Altos and

EVA differ significantly from the other projections,

in part because of higher consumption levels. In addition, however, Altos also has a very different outlook

for net pipeline imports of natural gas. Whereas the

other projections show declines in pipeline imports,

Altos has a more aggressive outlook, projecting that

the United States will become a net exporter by 2020,

and that U.S. pipeline exports will total 4.5 trillion

cubic feet in 2035. As a result, the requirements for

additional supply from domestic production and LNG

imports in the Altos projection are significantly

greater than those in the other projections.

Wellhead natural gas prices in the Altos projection

are higher than those in the other projections, with

the exception of DB, but the differences are not proportional to the differences in domestic production.

Three of the seven projections (AEO2010 Reference

case, IHSGI, and SEER) present relatively similar

outlooks for supply sources, with domestic production

providing a growing percentage of total natural gas

supply over the projection period (with very similar

percentages). The AEO2010 Reference case, IHSGI,

and SEER also show a decline in net pipeline imports

of natural gas, but net imports remain positive over

the entire projection period, with growth in LNG imports to about 1 trillion cubic feet. The same three

projections also show generally lower natural gas

prices than the others, indicating a generally more optimistic view of domestic natural gas supply potential.

In contrast, EVA, DB, and Altos project greater reliance on net LNG imports, at 2.2 trillion cubic feet per

year and above. The DB wellhead natural gas prices

are the highest among the projections shown in Table

13, reflecting a more pessimistic view of the potential

for future domestic natural gas production.

Price margins for delivered natural gas (defined

as the difference between delivered and wellhead

natural gas prices) reflect average transportation and

delivery charges, as well as differences in what each

sector pays for natural gas at the supply point. Only

the AEO2010 Reference case, IHSGI, and SEER include projections for delivered natural gas prices.

For the residential and commercial sectors, IHSGI

projects an increase in margins over their 2008 levels,

followed by a decline. The AEO2010 Reference case

and SEER project continued increases in residential

and commercial margins over the projection period.

In the AEO2010 Reference case, the increases result

largely from a decline in natural gas consumption per

customer, which increases the per-unit-equivalent

charge for the fixed component of customers’ gas

bills.

End-use natural gas prices in the industrial sector are

difficult to compare because of apparent definitional

differences between the projections, which are obvious from a comparison of 2008 prices in the different

projections. In the IHSGI and SEER projections,

industrial natural gas prices in 2008 are, respectively,

$0.93 and $0.43 (2008 dollars) per thousand cubic feet

higher than in the AEO2010 Reference case, implying

some difference in the definition of industrial natural

gas prices (the definitions were not available to EIA).

The projected industrial margins remain relatively

stable in the IHSGI, SEER, and AEO2010 projections, but they differ significantly: the average industrial margins for IHSGI and SEER are $1.32 and

$0.87 per thousand cubic feet higher, respectively,

than the average industrial margin in the AEO2010

Reference case.

The AEO2010 Reference case and IHSGI margins for

the electric power sector are more similar, with

IHSGI showing slightly higher average margins consistent with the difference in the margins for 2008. In

the SEER projections, natural gas margins for the

electric power sector decline in the near term from

their 2008 level of $1.60 per thousand cubic feet (2008

dollars), then increase rapidly after 2013, exceeding

SEER’s industrial margin after 2018 and climbing to

$4.05 per thousand cubic feet in 2030. In the AEO2010 Reference case and IHSGI projections, margins

in the electric power sector also decline quickly after

2008, but they remain considerably lower than their

2008 levels, reaching a maximum of $0.64 per thousand cubic feet (2008 dollars) in 2029 in the AEO2010

Reference case and $0.72 per thousand cubic feet

(2008 dollars) in 2015 in the IHSGI projection.

Liquid fuels

In the AEO2010 Reference case, the world oil price is

assumed to be $95 per barrel in 2015, $115 in 2025,

and $133 in 2035 (see Table 10). This price projection

is similar to DB’s price projection for WTI ($93 per

barrel in 2015, $115 in 2025, and $125 in 2035). EVA,

IHSGI, and Purvin and Gertz, Inc. (P&G) project

much lower crude oil prices.

92 U.S. Energy Information Administration / Annual Energy Outlook 2010

Comparison with Other Projections
U.S. Energy Information Administration / Annual Energy Outlook 2010 93

Comparison with Other Projections

Table 14. Comparison of liquids projections, 2015, 2025, and 2035

(million barrels per day, except where noted)

Projection 2008

AEO2010

Reference

case

Other projections

IHSGI EVA DB P&G IEA

2015

Crude oil and NGL production 6.75 7.54 6.50 8.14 6.60 6.11 –

Crude oil 4.96 5.77 4.75 – 4.95 4.36 4.70

Natural gas liquids 1.78 1.77 1.75 – 1.65 1.75 –

Total net imports 11.14 10.12 10.42 – 10.40 11.58 –

Crude oil 9.75 8.88 9.68 – – 11.80 –

Petroleum products 1.39 1.24 0.74 – – -0.22 –

Petroleum demand 19.52 20.18 19.29 – 18.65 18.21 17.90

Motor gasoline 8.99 9.37 8.56 – 8.97 8.96 –

Jet fuel 1.54 1.57 1.58 – 1.40 1.62 –

Distillate fuel 3.94 4.08 4.08 – 3.61 4.14 –

Residual fuel 0.62 0.66 0.61 – 0.54 0.57 –

Other 4.43 4.49 4.45 – – 2.92 –

Net import share of

petroleum demand (percent) 62 57 54 – – 64 –

2025

Crude oil and NGL production 6.75 7.87 5.76 7.16 5.39 4.86 –

Crude oil 4.96 6.13 3.87 – 4.04 3.24 –

Natural gas liquids 1.78 1.74 1.90 – 1.35 1.62 –

Total net imports 11.14 9.70 11.19 – 10.70 12.03 –

Crude oil 9.75 8.60 10.57 – – 12.30 –

Petroleum products 1.39 1.10 0.62 – – -0.27 –

Petroleum demand 19.52 20.63 20.38 – 17.51 18.07 –

Motor gasoline 8.99 9.32 7.80 – 8.32 7.79 –

Jet fuel 1.54 1.75 1.98 – 1.36 1.81 –

Distillate fuel 3.94 4.41 5.23 – 3.34 4.70 –

Residual fuel 0.62 0.66 0.61 – 0.50 0.58 –

Other 4.43 4.50 4.75 – – 3.19 –

Net import share of

petroleum demand (percent) 62 55 55 – – 67 –

2035

Crude oil and NGL production 6.75 8.11 5.06 – 4.29 – –

Crude oil 4.96 6.27 3.07 – 3.22 – –

Natural gas liquids 1.78 1.83 1.99 – 1.07 – –

Total net imports 11.14 9.66 13.31 – 9.50 – –

Crude oil 9.75 8.65 11.72 ––––

Petroleum products 1.39 1.02 1.59 ––––

Petroleum demand 19.52 20.86 21.81 – 15.18 – –

Motor gasoline 8.99 9.06 7.33 – 6.80 – –

Jet fuel 1.54 1.84 2.29 – 1.29 – –

Distillate fuel 3.94 4.91 6.56 – 2.95 – –

Residual fuel 0.62 0.67 0.59 – 0.44 – –

Other 4.43 4.37 5.05 ––––

Net import share of

petroleum demand (percent) 62 54 61 ––––

– = not reported.

Sources: 2008 and AEO2010: AEO2010 National Energy Modeling System, run AEO2010R.D111809A. IHSGI: IHS Global Insight, Inc.,

2009 Energy Outlook (Lexington, MA, September 2009). EVA: Energy Ventures Analysis, Inc., FUELCAST: Long-Term Outlook (February

2010). DB: Deutsche Bank AG, e-mail from Adam Sieminski (November 3, 2009). P&G: Purvin and Gertz, Inc., 2009 Global Petroleum

Market Outlook, Vol. 2, Table III-2 (April 2009). IEA: International Energy Agency, World Energy Outlook 2009 (Paris, France, November

2009), Table 1.4.
A major difference between the AEO2010 Reference

case and all but the EVA projection is that the

AEO2010 projects much higher domestic crude oil

production throughout the projection (Table 14). In

addition, domestic production of crude oil increases

gradually over time in the AEO2010 projection,

whereas all the other projections show rapid decreases in domestic production. As a consequence, the

AEO2010 Reference case shows lower net imports of

crude oil.

Overall petroleum product demand in the AEO2010

Reference case is similar to that in the IHSGI projection but higher than those in the EVA, DB, P&G, and

IEA projections. The IHSGI projection shows a

higher ratio of distillate to motor gasoline consumption than in the AEO2010 Reference case, however,

especially in 2035, implying more distillate use than

in the AEO2010 projection.

AEO2010, IHSGI, DB, and P&G all show motor gasoline demand decreasing in absolute terms. For

AEO2010, the decline in motor gasoline demand is

the result of increased efficiency, tighter CAFE standards, and increased use of ethanol. All four projections also show increasing ratios of distillate fuel to

motor gasoline consumption.

In the AEO2010 Reference case, demand for jet fuel

increases at a gradual pace, averaging 0.8 percent per

year from 2015 to 2035. In the IHSGI projection, jet

fuel demand is at the same level as in the AEO2010 in

2015 but increases at a faster pace, averaging just

under 1.9 percent per year from 2015 to 2035. In the

DB projection, jet fuel demand gradually decreases

over time, by 0.4 percent per year on average from

2015 to 2035.

Coal

The outlook for coal markets varies considerably

across the projections compared in Table 15. Differences in assumptions about expectations for and

implementation of legislation aimed at reducing GHG

emissions can lead to significantly different projections for coal production, consumption, and prices.

In addition, different assumptions about world oil

prices, natural gas prices, and economic growth can

contribute to variation across the projections.

In the AEO2010 Reference case, total U.S. coal consumption increases from 1,122 million tons (22.4

quadrillion Btu) in 2008 to 1,235 million tons (23.6

quadrillion Btu) in 2025 and 1,319 million tons (25.1

quadrillion Btu) in 2035. Total coal consumption also

increases in the IEA projection, to 22.7 quadrillion

Btu in 2025. Total coal consumption decreases in both

the IHSGI and DB projections to 1,095 million tons

and 21.9 quadrillion Btu, respectively, in 2025 and to

1,086 million tons and 20.8 quadrillion Btu, respectively, in 2035.

In the AEO2010 projection, coal production increases

from 1,172 million tons (23.9 quadrillion Btu) to

1,234 million tons (24.4 quadrillion Btu) in 2025 and

to 1,285 million tons (25.2 quadrillion Btu) in 2035.

INFORUM projects a larger increase in coal production, to 1,465 million tons in 2025. In the Wood

Mackenzie Company (WM) projection, production

(excluding coking coal) remains relatively constant,

increasing to 1,180 million tons in 2025. In the IHSGI

projection, coal production falls to 1,109 million tons

in 2025 and 1,098 million tons in 2035.

U.S. coal exports decline from 82 million tons in 2008

to 48 million tons in 2025 in the AEO2010 Reference

case, and coal imports increase slightly from 32 million tons in 2008 to 34 million tons in 2025. In contrast to the other projections, AEO2010 projects that

the United States eventually will become a net importer of coal. U.S. coal exports fall to 33 million tons

in 2035 in the AEO2010 Reference case, and coal imports increase to 53 million tons. INFORUM projects

an increase in exports to 161 million tons, as well as

an increase in imports to 43 million tons, in 2025. In

the WM projection, both exports and imports (excluding coking coal) fall to 26 million tons in 2025. IHSGI

projects a decrease in exports to 49 million tons in

2025 and to 45 million tons in 2035, with little change

in coal imports, which total 35 million tons in 2025

and 33 million tons in 2035.

Minemouth coal prices in the AEO2010 Reference

case decline from $31.26 per ton ($1.55 per million

Btu) in 2008 to $28.19 per ton ($1.44 per million Btu)

in 2025 and remain relatively constant thereafter,

with a price of $28.10 per ton ($1.44 per million Btu)

projected for 2035. In the IHSGI projection, the average minemouth coal price falls to $26.08 per ton in

2025 and $25.81 per ton in 2035. Both WM and

INFORUM project slight decreases in minemouth

coal prices, to $31.14 per ton and $30.91 per ton in

2025, respectively.

94 U.S. Energy Information Administration / Annual Energy Outlook 2010

Comparison with Other Projections
U.S. Energy Information Administration / Annual Energy Outlook 2010 95

Comparison with Other Projections

Table 15. Comparison of coal projections, 2015, 2025, and 2035 (million short tons, except where noted)

Projection 2008

AEO2010

Reference

case

Other projections

IHSGI DB IEA WM INFORUM

2015

Production 1,172 1,155 1,141 – – 1,149 a 1,254

Consumption by sector

Electric power 1,042 1,044 1,042 – – – –

Coke plants 22 20 21 – – – –

Coal-to-liquids 0 21 – – – – –

Other industrial/buildings 58 56 57 – – – –

Total 1,122 1,141 1,120 23.0 b 21.8 b – –

Net coal exports 49 30 19 – – 3 a 65

Exports 82 60 57 – – 19 a 102

Imports 32 30 38 – – 16 a 37

Minemouth price

(2008 dollars per short ton) 31.26 30.38 27.26 c – – 27.42 d 31.15

(2008 dollars per million Btu) 1.55 1.52 1.32 – – 1.37 d –

Average delivered price

to electricity generators

(2008 dollars per short ton) 40.71 39.46 41.14 c – – 41.64 d 40.57

(2008 dollars per million Btu) 2.05 2.01 2.00 – – 2.09 d –

2025

Production 1,172 1,234 1,109 – – 1,180 a 1,465

Consumption by sector

Electric power 1,042 1,116 1,021 – – – –

Coke plants 22 19 20 – – – –

Coal-to-liquids 0 44 – – – – –

Other industrial/buildings 58 56 54 – – – –

Total 1,122 1,235 1,095 21.9 a 22.7 b – –

Net coal exports 49 14 14 – – 0 a 118

Exports 82 48 49 – – 26 a 161

Imports 32 34 35 – – 26 a 43

Minemouth price

(2008 dollars per short ton) 31.26 28.19 26.08 c – – 31.14 d 30.91

(2008 dollars per million Btu) 1.55 1.44 1.27 – – 1.57 d –

Average delivered price

to electricity generators

(2008 dollars per short ton) 40.71 38.49 39.33 c – – 46.01 d 40.25

(2008 dollars per million Btu) 2.05 1.99 1.91 – – 2.32 d –

Btu = British thermal unit. – = not reported. See notes and sources at end of table.
96 U.S. Energy Information Administration / Annual Energy Outlook 2010

Comparison with Other Projections

Table 15. Comparison of coal projections, 2015, 2025, and 2035 (continued)

(million short tons, except where noted)

Projection 2008

AEO2010

Reference

case

Other projections

IHSGI DB IEA WM INFORUM

2035

Production 1,172 1,285 1,098 ––––

Consumption by sector

Electric power 1,042 1,183 1,018 ––––

Coke plants 22 14 19 ––––

Coal-to-liquids 0 68

Other industrial/buildings 58 54 49 ––––

Total 1,122 1,319 1,086 20.8 b –––

Net coal exports 49 -20 12 ––––

Exports 82 33 45 ––––

Imports 32 53 33 ––––

Minemouth price

(2008 dollars per short ton) 31.26 28.10 25.81 c ––––

(2008 dollars per million Btu) 1.55 1.44 1.26 ––––

Average delivered price

to electricity generators

(2008 dollars per short ton) 40.71 40.74 39.02 c ––––

(2008 dollars per million Btu) 2.05 2.09 1.90 ––––

Btu = British thermal unit. – = not reported. aExcludes coking coal.

bReported in quadrillion Btu.

c

Imputed, using heat conversion factor implied by U.S. steam coal consumption figures for the electricity sector.

dConverted to 2008 dollars, using the AEO2010 GDP inflator.

Sources: 2008 and AEO2010: AEO2010 National Energy Modeling System, run AEO2010R.D111809A. IHSGI: IHS Global Insight, Inc.,

2009 U.S. Energy Outlook (September 2009). DB: Deutsche Bank AG, e-mail from Adam Sieminski (December 31, 2009). IEA:

International Energy Agency, World Energy Outlook 2009 (Paris, France, November 2009).WM: Wood Mackenzie Company, Fall 2009

Long Term Outlook Base Case. INFORUM: INFORUM Base, e-mail from Douglas Meade (January 15, 2010).
A.B. Assembly Bill

ACESA American Clean Energy and Security Act of 2009

AEO Annual Energy Outlook

AEO2007 Annual Energy Outlook 2007

AEO2008 Annual Energy Outlook 2008

AEO2009 Annual Energy Outlook 2009

AEO2010 Annual Energy Outlook 2010

AFV Alternative-fuel vehicle

ARRA American Recovery and Reinvestment Act of 2009

BLS Bureau of Labor Statistics

BTL Biomass-to-liquids

Btu British thermal unit

CAA Clean Air Act

CAFE Corporate Average Fuel Economy

CAIR Clean Air Interstate Rule

CAMR Clean Air Mercury Rule

CARB California Air Resources Board

CBO Congressional Budget Office

CCS Carbon capture and storage

CHP Combined heat and power

CNG Compressed natural gas

CO2 Carbon dioxide

CREB Clean and Renewable Energy Bonds

CTL Coal-to-liquids

CWA Clean Water Act

DB Deutsche Bank AG

DOE U.S. Department of Energy

DOD U.S. Department of Defense

E10 Fuel containing 10 percent ethanol and 90 percent

gasoline by volume

E85 Fuel containing a blend of 70 to 85 percent ethanol

and 30 to 15 percent gasoline by volume

EIA Energy Information Administration

EIEA2008 Energy Improvement and Extension Act of 2008

EISA2007 Energy Independence and Security Act of 2007

EOR Enhanced oil recovery

EPA U.S. Environmental Protection Agency

EPACT2005 Energy Policy Act of 2005

EVA Energy Ventures Analysis, Inc.

FEMP Federal Energy Management Program

FFV Flex-fuel vehicle

FGD Flue gas desulfurization

GDP Gross domestic product

GHG Greenhouse gas

GSA U.S. General Services Administration

GTL Gas-to-liquids

GVWR Gross vehicle weight rating

HDNGV Heavy-duty natural gas vehicle

HEV Hybrid electric vehicle

H.R. House of Representatives

IEA International Energy Agency

IECC International Energy Conservation Code

IHSGI IHS Global Insight

INFORUM Interindustry Forecasting Project at the

University of Maryland

ITC Investment tax credit

LCFS Low Carbon Fuel Standard (California)

LED Light-emitting diode

LDV Light-duty vehicle

LNG Liquefied natural gas

LPG Liquid petroleum gas

MHEV Micro hybrid electric vehicle

mpg Miles per gallon

MY Model year

NEMS National Energy Modeling System (EIA)

NERC North American Electric Reliability Council

NGL Natural gas liquids

NHTSA National Highway Traffic Safety Administration

NOx Nitrogen oxide

NRC U.S. Nuclear Regulatory Commission

O&M Operation and maintenance

OMB Office of Management and Budget

OPEC Organization of the Petroleum Exporting Countries

P&G Purvin and Gertz, Inc.

PHEV Plug-in hybrid electric vehicle

PHEV-10 PHEV designed to travel about 10 miles

on battery power alone

PHEV-40 PHEV designed to travel about 40 miles

on battery power alone

PTC Production tax credit

PV Solar photovoltaic

RFG Reformulated gasoline

RFS Renewable fuels standard

RGGI Regional Greenhouse Gas Initiative

RPS Renewable portfolio standard

SCR Selective catalytic control equipment

SEER Strategic Energy and Economic Research, Inc.

SO2 Sulfur dioxide

SSA Social Security Administration

SUV Sport utility vehicle

TAPS Trans Alaska Pipeline System

TV Television

VIUS Vehicle Inventory and Use Summary

VMT Vehicle miles traveled

WCI Western Climate Initiative

WM Wood Mackenzie Company

WTI West Texas Intermediate (crude oil)

U.S. Energy Information Administration / Annual Energy Outlook 2010 97

List of Acronyms
Table Notes and Sources

Note: Tables indicated as sources in these notes

refer to the tables in Appendixes A, B, C, and D

of this report.

Table 1. Estimated average fleet-wide fuel economy

and CO2-equivalent emissions compliance levels,

model years 2012-2016: Environmental Protection

Agency and National Highway Traffic Safety Administration, Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule, 40 CFR, Parts 85, 86, and 600, 49 CFR Parts 531,

533, 537, and 538 [EPA-HQ-OAR-2009-0472; FRL-_8959-4;

NHTSA-2009-0059], RIN 2060-AP58; RIN 2127-AK50

(Washington, DC, April 2010), web site www.nhtsa.dot.gov/

staticfiles/DOT/NHTSA/Rulemaking/Rules/

AssociatedFiles/CAFE-GHG-MY_2012-2016_Final_Rule_

v2. pdf.

Table 2. Renewable portfolio standards in the 30

States with current mandates: U.S. Energy Information Administration, Office of Integrated Analysis and

Forecasting. Based on a review of enabling legislation and

regulatory actions from the various States of policies identified by the Database of State Incentives for Renewable Energy (web site www.dsireuse.org) as of September 1, 2009.

Table 3. Key analyses from “Issues in Focus” in recent AEOs: U.S. Energy Information Administration, Annual Energy Outlook 2009, DOE/EIA-0383(2009) (Washington, DC, March 2009); U.S. Energy Information Administration, Annual Energy Outlook 2008, DOE/EIA-0383

(2008) (Washington, DC, June 2008); U.S. Energy Information Administration, Annual Energy Outlook 2007, DOE/

EIA-0383(2007) (Washington, DC, February 2007).

Table 4. Average annual increases in economic output, population, and energy consumption indicators

in the buildings, industrial, and transportation sectors, 2008-2035: AEO2010 National Energy Modeling System, run AEO2010R.D111809A.

Table 5. Maximum market potential for natural gas

heavy-duty vehicles in Base Market and Expanded

Market cases: U.S. Energy Information Administration,

Office of Integrated Analysis and Forecasting using data

from U.S. Department of Commerce, Bureau of Census, Vehicle Inventory and Use Survey, EC02TV (Washington, DC,

December 2004).

Table 6. Levelized capital costs for natural gas fueling stations with and without assumed tax credits:

U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.

Table 7. Natural gas prices, supply, and consumption

in four cases, 2035: AEO2010 National Energy Modeling

System, runs AEO2010R.D111809A, NOSHALE.

D021110A, NOLOPERM.D020510A, and HISHALE.

D012210A.

Table 8. Comparison of key projections in the Reference and Nuclear 60-Year Life cases: AEO2010 National Energy Modeling System, runs AEO2010R.

D111809A and NUCRET.D123009A.

Table 9. Projections of average annual economic

growth rates, 2008-2035: AEO2009 (Reference case):

AEO2009 National Energy Modeling System, run

AEO2009.D030208F. AEO2010 (Reference case):

AEO2010 National Energy Modeling System, run

AEO2010R.D111809A. IHSGI (May 2009): IHS/Global

Insight, Inc., U.S. Macroeconomic 30 Year Trend Forecast

(Lexington, MA, November 2009). OMB (July 2009): Office of Management and Budget, Mid-Session Review, Budget of the United States Government Fiscal Year 2009

(Washington, DC, June 2008). CBO (August 2009): Congressional Budget Office, The Budget and Economic Outlook (Washington, DC, January 2009) INFORUM (December 2009): INFORUM, email from Jeff Werling (December 8, 2008). SSA (May 2009): Social Security Administration, OASDI Trustees Report (Washington, DC, May

2008). BLS (December 2009): Bureau of Labor Statistics,

Macro Projections 2007. IEA (2009): International Energy

Agency, World Energy Outlook 2008 (Paris, France, September 2008). Blue Chip Consensus (March 2009): Blue

Chip Economic Indicators (Aspen Publishers, March 10,

2008).

Table 10. Projections of world oil prices, 2015-2035:

AEO2009 (Reference case): AEO2009 National Energy

Modeling System, run AEO2009.D030208F. AEO2010

(Reference case): AEO2010 National Energy Modeling

System, run AEO2010R.D111809A. DB: Deutsche Bank

AG, e-mail from Adam Sieminski (November 4, 2008).

IHSGI: IHS/Global Insight, Inc., U.S. Energy Outlook

(Lexington, MA, September 2008). IEA (reference): International Energy Agency, World Energy Outlook 2008

(Paris, France, September 2008), Reference Scenario. IER:

Institute of Energy Economics and the Rational Use of Energy at the University of Stuttgart, e-mail from Markus

Blesl (December 4, 2008). EVA: Energy Ventures Analysis,

Inc., e-mail from Roger Avalos (January 7, 2009). SEER:

Strategic Energy and Economic Research, Inc., e-mail from

Ron Denhardt (February 6, 2009).

Table 11. Projections of energy consumption by sector, 2007-2035: AEO2010: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A. IHSGI:

IHS/Global Insight, Inc., 2009 Energy Outlook (Lexington,

MA, September 2009). EVA: Energy Ventures Analysis,

Inc., FUELCAST: Long-Term Outlook (February 2010).

Table 12. Comparison of electricity projections, 2015

and 2035: AEO2010: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A. IHSGI: IHS/Global Insight, Inc., 2009 Energy Outlook (Lexington, MA, September 2009). EVA: Energy Ventures Analysis, Inc.,

FUELCAST: Long-Term Outlook (February 2010).

Table 13. Comparison of natural gas projections,

2015, 2025, and 2035: AEO2010: AEO2010 National Energy Modeling System, run AEO2010R.D111809A. IHSGI:

IHS/Global Insight, Inc., U.S. Energy Outlook (Lexington,

MA, September 2008). EVA: Energy Ventures Analysis,

Inc., FUELCAST: Long-Term Outlook (February 2010).

DB: Deutsche Bank AG, email from Adam Sieminski (November 3, 2009). SEER: Strategic Energy and Economic

Research, Inc., Natural Gas Outlook (November 2009).

Altos: Altos World Gas Trade Model (October 2009);

INFORUM: INFORUM Base, email from Douglas Meade

(Janauray15, 2010).

98 U.S. Energy Information Administration / Annual Energy Outlook 2010

Notes and Sources
Table 14. Comparison of liquids projections, 2015,

2025, and 2035: AEO2010: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A. IHSGI:

IHS/Global Insight, Inc., 2009 Energy Outlook (Lexington,

MA, September 2009). EVA: Energy Ventures Analysis,

Inc., FUELCAST: Long-Term Outlook (February 2010).

DB: Deutsche Bank AG, email from Adam Sieminski (November 3, 2009). P&G: Purvin and Gertz, Inc., 2009 Global

Petroleum Market Outlook, Vol. 2, Table III-2 (April 2009).

IEA: International Energy Agency, World Energy Outlook

2009 (Paris, France, November 2009), Table 1.4.

Table 15. Comparison of coal projections, 2015, 2025,

and 2035: AEO2010: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A. IHSGI: IHS/Global Insight, Inc., 2009 Energy Outlook (Lexington, MA, September 2009). DB: Deutsche Bank AG, email from Adam

Sieminski (November 3, 2009). IEA: International Energy

Agency, World Energy Outlook 2009 (Paris, France, November 2009), Table 1.4. WM: Wood Mackenzie Company,

Fall 2009 Long Term Outlook Base Case. INFORUM:

INFORUM Base, email from Douglas Meade (January15,

2010).

Figure Notes and Sources

Note: Tables indicated as sources in these notes refer

to the tables in Appendixes A, B, C, and D of this

report.

Figure 1. U.S. primary energy consumption, 1980-

2035: History: U.S. Energy Information Administration,

Annual Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National

Energy Modeling System, run AEO2010R. D111809A.

Figure 2. U.S. liquid fuels supply, 1970-2035: History:

U.S. Energy Information Administration, Annual Energy

Review 2008, DOE/EIA-0384(2008) (Washington, DC, June

2009). Projections: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 3. U.S. natural gas supply, 1990-2035: History:

U.S. Energy Information Administration, Annual Energy

Review 2008, DOE/EIA-0384(2008) (Washington, DC, June

2009). Projections: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 4. U.S. energy-related carbon dioxide emissions, 2008 and 2035: History: U.S. Energy Information

Administration, Annual Energy Review 2008, DOE/EIA0384(2008) (Washington, DC, June 2009). Projections:

U.S. Energy Information Administration, AEO2010

National Energy Modeling System, run AEO2010R.

D111809A.

Figure 5. Projected average fleet-wide fuel economy

and CO2-equivalent emissions compliance levels

for passenger cars, model year 2016: Environmental

Protection Agency and National Highway Traffic Safety

Administration, Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule, 40 CFR, Parts 85, 86, and 600, 49 CFR

Parts 531, 533, 537, and 538 [EPA-HQ-OAR-2009-0472;

FRL-_8959-4; NHTSA-2009-0059], RIN 2060-AP58; RIN

2127-AK50 (Washington, DC, April 2010), web site www.

nhtsa.dot.gov/staticfiles/DOT/NHTSA/Rulemaking/Rules/

Associated Files/CAFE-GHG-MY_2012-2016_Final_Rule_

v2.pdf.

Figure 6. Projected average fleet-wide fuel economy

and CO2-equivalent emissions compliance levels

for light trucks, model year 2016: Environmental Protection Agency and National Highway Traffic Safety Administration, Light-Duty Vehicle Greenhouse Gas Emission

Standards and Corporate Average Fuel Economy Standards; Final Rule, 40 CFR, Parts 85, 86, and 600, 49 CFR

Parts 531, 533, 537, and 538 [EPA-HQ-OAR-2009-0472;

FRL-_8959-4; NHTSA-2009-0059], RIN 2060-AP58; RIN

2127-AK50 (Washington, DC, April 2010), web site

www.nhtsa.dot.

gov/staticfiles/DOT/NHTSA/Rulemaking/Rules/

AssociatedFiles/CAFE-GHG-MY_2012-2016_Final_Rule_

v2.pdf.

Figure 7. Total energy consumption in three cases,

2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384(2008)

(Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs AEO2010R.

D111809A, NOSUNSET.D012510A, and EXTENDED.

D012410A.

Figure 8. Light-duty vehicle energy consumption

in three cases, 2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/

EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, NOSUNSET.D012510A, and

EXTENDED.D012410A.

Figure 9. New light-duty vehicle fuel efficiency standards in two cases, 2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008,

DOE/EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System,

runs AEO2010R.D111809A and EXTENDED.D012410A.

Figure 10. New light-duty vehicle fuel efficiency

standards and fuel efficiency achieved in two cases,

2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384

(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs AEO2010R.

D111809A, NOSUNSET.D012510A, and EXTENDED.

D012410A.

Figure 11. Renewable electricity generation in three

cases, 2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384

(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs AEO2010R.

D111809A, NOSUNSET.D012510A, and EXTENDED.

D012410A.

Figure 12. Electricity generation from natural gas in

three cases, 2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/

EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, NOSUNSET.D012510A, and

EXTENDED.D012410A.

Figure 13. Energy-related carbon dioxide emissions

in three cases, 2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/

EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, NOSUNSET.D012510A, and

EXTENDED.D012410A.

U.S. Energy Information Administration / Annual Energy Outlook 2010 99

Notes and Sources
Figure 14. Natural gas wellhead prices in three

cases, 2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384

(2008) (Washington, DC, June 2009). Projections:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, NOSUNSET.D012510A, and

EXTENDED.D012410A.

Figure 15. Average electricity prices in three cases,

2005-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384(2008)

(Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs AEO2010R.

D111809A, NOSUNSET.D012510A, and EXTENDED.

D012410A.

Figure 16. Average annual world oil prices in three

cases, 1980-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384

(2008) (Washington, DC, June 2009). Projections:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, LP2010.D011910A, and HP2010.

D011910A.

Figure 17. Trends in U.S. oil prices, energy consumption, and economic output, 1950-2035: History: U.S.

Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June

2009). Projections: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 18. Projected changes in indexes of energy efficiency, energy intensity, and carbon intensity in

the AEO2010 Reference case, 2008-2035: AEO2010 National Energy Modeling System, run AEO2010R.

D111809A.

Figure 19. Structural and efficiency effects on primary energy consumption in the AEO2010 Reference case: AEO2010 National Energy Modeling System,

run AEO2010R.D111809A, and U.S. Energy Information

Administration, Office of Integrated Analysis and Forecasting.

Figure 20. Energy efficiency and energy intensity in

three cases, 2008-2035: AEO2010 National Energy

Modeling System, runs AEO2010R.D111809A,

LTRKITEN.D020510A, and HTRKITEN.D020510A.

Figure 21. Delivered energy prices for diesel and

natural gas transportation fuels in the Reference

case, 2000-2035: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 22. Sales of new heavy-duty natural gas vehicles in Base Market and Expanded Market cases

with Reference case world oil prices, 2010-2035:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, ATHNG80S27.D033010A, and

ATHNG80SNM19.D032510A.

Figure 23. Natural gas fuel use by heavy-duty natural gas vehicles in Base Market and Expanded Market cases with Reference case world oil prices,

2010-2035: AEO2010 National Energy Modeling System,

runs AEO2010R.D111809A, ATHNG80S27.D033010A,

and ATHNG80SNM19.D032510A.

Figure 24. Reductions in petroleum product use by

heavy-duty vehicles in Base Market and Expanded

Market cases with Reference case world oil prices,

2010-2035: AEO2010 National Energy Modeling System,

runs AEO2010R.D111809A, ATHNG80S27.D033010A,

and ATHNG80SNM19.D032510A.

Figure 25. Annual cost of vehicle and fuel tax credits

and net change in annual economy-wide energy

expenditures for the 2027 Phaseout Expanded

Market case, 2010-2027: AEO2010 National Energy

Modeling System, runs ATHNG80LP27.D033110A,

ATHNG80SNM19.D032510A, ATHNG80LPNM19.

D032510A, and ATHNG80S27.D033010A.

Figure 26. Ratio of low-sulfur light crude oil prices

to natural gas prices on an energy-equivalent basis,

1995-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384(2008)

(Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, runs AEO2010R.

D111809A, LP2010.D011910A, and HP2010.D011910A.

Figure 27. Ratio of natural gas volume to diesel fuel

volume needed to provide the same energy content:

U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.

Figure 28. Breakeven natural gas price relative to

crude oil price required for investment in new

gas-to-liquids plants: AEO2010 National Energy

Modeling System, runs AEO2010R.D111809A, LP2010.

D011910A, and HP2010.D011910A; and U.S. Energy Information Administration, Office of Integrated Analysis and

Forecasting.

Figure 29. U.S. nuclear power plants that will reach

60 years of operation by 2035: U.S. Nuclear Regulatory

Commission, 2009-2010 Information Digest, NUREG-1350,

Vol. 1 (August 2009), web site www.nrc.gov/reading-rm/

doc-collections/nuregs/staff/sr1350/v21/sr1350v21.pdf.

Figure 30. Carbon dioxide emissions from biomass

energy combustion, 2008-2035: U.S. Energy Information Administration, Office of Integrated Analysis and

Forecasting.

Figure 31. Average annual growth rates of real GDP,

labor force, and productivity in three cases,

2008-2035: AEO2010 National Energy Modeling System,

runs AEO2010R.D111809A, HM2010.D020310A, and

LM2010.D011110A.

Figure 32. Average annual inflation, interest, and

unemployment rates in three cases, 2008-2035:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, HM2010.D020310A, and LM2010.

D011110A.

Figure 33. Sectoral composition of industrial output

growth rates in three cases, 2008-2035: AEO2010 National Energy Modeling System, runs AEO2010R.

D111809A, HM2010.D020310A, and LM2010.D011110A.

Figure 34. Energy expenditures in the U.S. economy

in three cases, 1990-2035: AEO2010 National Energy

Modeling System, runs AEO2010R.D111809A, HM2010.

D020310A, and LM2010.D011110A.

100 U.S. Energy Information Administration / Annual Energy Outlook 2010

Notes and Sources
Figure 35. Energy end-use expenditures as a share of

gross domestic product, 1970-2035: History: U.S. Department of Commerce, Bureau of Economic Analysis, and

U.S. Energy Information Administration, Annual Energy

Review 2008, DOE/EIA-0384(2008) (Washington, DC, June

2009). Projections: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 36. Average annual world oil prices in three

cases, 1980-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384

(2008) (Washington, DC, June 2009). Projections:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, LP2010.D011910A, and HP2010.

D011910A.

Figure 37. World liquids production shares by region

in three cases, 2008 and 2035: AEO2010 National Energy Modeling System, runs AEO2010R.D111809A,

LP2010.D011910A, and HP2010.D011910A.

Figure 38. Unconventional resources as a share of

total world liquids production in three cases, 2008

and 2035: 2008: Derived from U.S. Energy Information

Administration, International Energy Annual 2005

(June-October 2007), Table G.4, web site www.eia.doe.gov/

iea. Projections: Generate World Oil Balance (GWOB)

Model and AEO2010 National Energy Modeling System,

runs AEO2010R.D111809A, LP2010.D011910A, and

HP2010.D011910A.

Figure 39. Energy use per capita and per dollar of

gross domestic product, 1980-2035: History: U.S. Energy Information Administration, Annual Energy Review

2008, DOE/EIA-0384(2008) (Washington, DC, June 2009).

Projections: AEO2010 National Energy Modeling System, run AEO2010R.D111809A.

Figure 40. Primary energy use by end-use sector,

2008-2035: AEO2010 National Energy Modeling System,

run AEO2010R.D111809A.

Figure 41. Primary energy use by fuel, 1980-2035:

History: U.S. Energy Information Administration, Annual

Energy Review 2008, DOE/EIA-0384(2008) (Washington,

DC, June 2009). Projections: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 42. Residential delivered energy consumption per capita in four cases, 1990-2035: History: U.S.

Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June

2009). Projections: AEO2010 National Energy Modeling

System, runs AEO2010R.D111809A, BLDFRZN.

D012010A, BLDHIGH.D012010C, and BLDBEST.

D012010A.

Figure 43. Change in residential electricity consumption for selected end uses in the Reference

case, 2008-2035: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 44. Energy intensity for selected end uses of

electricity in the residential sector in three cases,

2008 and 2035: AEO2010 National Energy Modeling System, runs AEO2010R.D111809A, BLDFRZN.D012010A,

and BLDBEST.D012010A.

Figure 45. Residential market saturation by renewable technologies in two cases, 2008, 2020, and 2035:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A and EXTENDED.D122409A.

Figure 46. Commercial delivered energy consumption per capita in four cases, 1990-2035: History: U.S.

Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June

2009). Projections: AEO2010 National Energy Modeling

System, runs AEO2010R.D111809A, BLDFRZN.

D012010A, BLDHIGH.D012010C, and BLDBEST.

D012010A.

Figure 47. Average annual growth rates for selected

electricity end uses in the commercial sector,

2008-2035: AEO2010 National Energy Modeling System,

run AEO2010R.D111809A.

Figure 48. Efficiency gains for selected commercial

equipment in three cases, 2035: AEO2010 National Energy Modeling System, runs AEO2010R.D111809A;

BLDFRZN.D012010A, and BLDBEST.D012010A.

Figure 49. Additions to electricity generation capacity in the commercial sector in two cases, 2008-2035 :

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A and EXTENDED.D122409A.

Figure 50. Industrial delivered energy consumption

by application, 2008-2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 51. Industrial consumption of fuels for use as

feedstocks by fuel type, 2008-2035: AEO2010 National

Energy Modeling System, run AEO2010R.D111809A.

Figure 52. Industrial energy consumption by fuel,

2003, 2008, and 2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 53. Cumulative growth in value of shipments

by industrial subsector in three cases, 2008-2035:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, HM2010.D020310A, and LM2010.

D011110A.

Figure 54. Change in delivered energy consumption

for industrial subsectors in three cases, 2008-2035:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, HM2010.D020310A, and LM2010.

D011110A.

Figure 55. Delivered energy consumption for transportation by mode, 2008 and 2035: 2008: AEO2010 National Energy Modeling System, run AEO2010R.

D111809A.

Figure 56. Average fuel economy of new light-duty

vehicles in five cases, 1980-2035: History: U.S. Department of Transportation, National Highway Traffic Safety

Administration, Summary of Fuel Economy Performance

(Washington, DC, January 2008), web site www.nhtsa.dot.

gov/staticfiles/DOT/NHTSA/Vehicle%20Safety/Articles/

Associated%20 Files/SummaryFuelEconomyPerformance2008.pdf. Projections: AEO2010 National Energy

Modeling System, runs AEO2010R.D111809A, HP2010.

D011910A, LP2010.D011910A, TRNHIGH.D120409A, and

TRNLOW.D120409A.

Figure 57. Market penetration of new technologies

for light-duty vehicles, 2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

U.S. Energy Information Administration / Annual Energy Outlook 2010 101

Notes and Sources
Figure 58. Sales of unconventional light-duty vehicles by fuel type, 2008, 2020, and 2035: AEO2010 National Energy Modeling System, run AEO2010R.

D111809A.

Figure 59. U.S. electricity demand growth, 1950-

2035: History: U.S. Energy Information Administration,

Annual Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National

Energy Modeling System, run AEO2010R. D111809A.

Figure 60. Average annual U.S. retail electricity

prices in three cases, 1970-2035: History: U.S. Energy

Information Administration, Annual Energy Review 2008,

DOE/EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System,

runs AEO2010R.D111809A, LM2010.D011110A, and

HM2010.D020310A.

Figure 61. Electricity generation by fuel in three

cases, 2008 and 2035: AEO2010 National Energy

Modeling System, runs AEO2010R.D111809A, LM2010.

D011110A, and HM2010.D020310A.

Figure 62. Electricity generation capacity additions

by fuel type, 2009-2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 63. Levelized electricity costs for new power

plants, 2020 and 2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 64. Electricity generating capacity at U.S. nuclear power plants in three cases, 2008, 2020, and

2035: AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, LM2010.D011110A, and HM2010.

D020310A.

Figure 65. Nonhydroelectric renewable electricity

generation by energy source, 2008-2035: AEO2010 National Energy Modeling System, run AEO2010R.

D111809A.

Figure 66. Grid-connected coal-fired and windpowered generating capacity, 2003-2035: U.S. Energy

Information Administration, Annual Energy Review 2008,

DOE/EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, run

AEO2010R.D111809A.

Figure 67. Nonhydropower renewable generation

capacity in three cases, 2015-2035: AEO2010 National

Energy Modeling System, runs AEO2010R.D111809A,

LORENCST10.D011510A, and HIRENCST10.D011410A.

Figure 68. Regional growth in nonhydroelectric renewable electricity generation capacity, including

end-use capacity, 2008-2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 69. Annual average lower 48 wellhead and

Henry Hub spot market prices for natural gas,

1990-2035: History: U.S. Energy Information Administration, Natural Gas Annual 2007, DOE/EIA-0131(2007)

(Washington, DC, January 2009). Henry Hub natural

gas prices: U.S. Energy Information Administration,

Short-Term Energy Outlook Query System, Monthly Natural Gas Data, Variable NGHHUUS. Projections: AEO2010 National Energy Modeling System, run AEO2010R.

D111809A.

Figure 70. Ratio of low-sulfur light crude oil price to

Henry Hub natural gas price on an energy equivalent basis, 1990-2035: History: U.S. Energy Information

Administration, Annual Energy Review 2007, DOE/EIA0384(2007) (Washington, DC, June 2008). Henry Hub

natural gas prices: U.S. Energy Information Administration, Short-Term Energy Outlook Query System, Monthly

Natural Gas Data, Variable NGHHUUS. Projections:

AEO2010 National Energy Modeling System, run

AEO2010R.D111809A.

Figure 71. Annual average lower 48 wellhead prices

for natural gas in three technology cases, 1990-2035:

History: U.S. Energy Information Administration, Natural Gas Annual, 2007, DOE/EIA-0131(2007) (Washington,

DC, January 2009). Projections: AEO2010 National Energy Modeling System, runs AEO2010R.D111809A,

OGLTEC10.D121409A, and OGHTEC10.D121309A.

Figure 72. Annual average lower 48 wellhead prices

for natural gas in three oil price cases, 1990-2035:

History: U.S. Energy Information Administration, Natural Gas Annual, 2007, DOE/EIA-0131(2007) (Washington,

DC, January 2009). Projections: AEO2010 National Energy Modeling System, runs AEO2010R.D111809A,

HP2010.D011910A, LP2010.D011910A.

Figure 73. Natural gas production by source,

1990-2035: History: U.S. Energy Information Administration, Natural Gas Annual, 2007, DOE/EIA-0131(2007)

(Washington, DC, January 2009) and Office of Integrated

Analysis and Forecasting. Projections: AEO2010 National Energy Modeling System, run AEO2010R.

D111809A.

Figure 74. Total U.S. natural gas production in five

cases, 1990-2035: History: U.S. Energy Information Administration, Natural Gas Annual 2007, DOE/EIA-0131

(2007) (Washington, DC, January 2009). Projections:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, LM2010.D011110A, HM2010.

D020310A, OGLTEC10,D121409A, and OGHTEC10.

D121309A.

Figure 75. Lower 48 onshore natural gas production

by region, 2008 and 2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 76. Shale gas production by region, 2008,

2020, and 2035: AEO2010 National Energy Modeling System, run AEO2010R.D111809A.

Figure 77. U.S. net imports of natural gas by source,

1990-2035: History: U.S. Energy Information Administration, Natural Gas Annual 2007, DOE/EIA-0131 (2007)

(Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, run AEO2010R.

D111809A.

Figure 78. Cumulative difference from Reference

case natural gas supply and consumption in the

High LNG Supply case, 2008-2035: AEO2010 National

Energy Modeling System, run HILNG10.D112509A.

Figure 79. Liquid fuels consumption by sector, 1990-

2035: History: U.S. Energy Information Administration,

Annual Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National

Energy Modeling System, run AEO2010R. D111809A.

102 U.S. Energy Information Administration / Annual Energy Outlook 2010

Notes and Sources
Figure 80. Domestic crude oil production by source,

1990-2035: History: U.S. Energy Information Administration, Petroleum Supply Annual 2008, Volume 1,

DOE/EIA-0340(2008)/1 (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System, run

AEO2010R.D111809A.

Figure 81. Total U.S. crude oil production in five

cases, 1990-2035: History: U.S. Energy Information Administration, Annual Energy Review 2008, DOE/EIA-0384

(2008) (Washington, DC, June 2009). Projections:

AEO2010 National Energy Modeling System, runs

AEO2010R.D111809A, HP2010.D011910A, LP2010.

D011910A, OGLTEC10.D121409A, and OGHTEC10.

D121309A.

Figure 82. Liquids production from biomass, coal,

and oil shale, 2008-2035: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A.

Figure 83. Net import share of U.S. liquid fuels consumption in three cases, 1990-2035: History: U.S. Energy Information Administration, Annual Energy Review

2008, DOE/EIA-0384(2008) (Washington, DC, June 2009).

Projections: AEO2010 National Energy Modeling System, runs AEO2010R.D111809A, LP2010.D011910A, and

HP2010.D011910A.

Figure 84. EISA2007 RFS credits earned in selected

years, 2008-2035: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 85. U.S. motor gasoline and diesel fuel consumption, 2008-2035: AEO2010 National Energy Modeling System, run AEO2010R.D111809A.

Figure 86. U.S. refinery capacity, 1970-2035: History:

U.S. Energy Information Administration, Annual Energy

Review 2008, DOE/EIA-0384(2008) (Washington, DC, June

2009). Projections: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 87. U.S. production of cellulosic ethanol and

other new biofuels, 2015-2035: AEO2010 National Energy Modeling System, run AEO2010R.D111809A.

Figure 88. Coal production by region, 1970-2035: History (short tons): 1970-1990: U.S. Energy Information

Administration, The U.S. Coal Industry, 1970-1990: Two

Decades of Change, DOE/EIA-0559 (Washington, DC, November 2002). 1991-2000: U.S. Energy Information Administration, Coal Industry Annual, DOE/EIA-0584 (various years). 2001-2008: U.S. Energy Information Administration, Annual Coal Report 2008, DOE/EIA-0584(2008)

(Washington, DC, September 2009), and previous issues.

History (conversion to quadrillion Btu): 1970-2008:

Estimation Procedure: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting. Estimates of average heat content by region and year are

based on coal quality data collected through various energy

surveys (see sources) and national-level estimates of U.S.

coal production by year in units of quadrillion Btu, published in EIA’s Annual Energy Review. Sources: U.S. Energy Information Administration, Annual Energy Review

2008, DOE/EIA-0384(2008) (Washington, DC, June 2009),

Table 1.2; Form EIA-3, “Quarterly Coal Consumption and

Quality Report, Manufacturing Plants”; Form EIA-5,

“Quarterly Coal Consumption and Quality Report, Coke

Plants”; Form EIA-6A, “Coal Distribution Report”; Form

EIA-7A, “Coal Production Report”; Form EIA-423,

“Monthly Cost and Quality of Fuels for Electric Plants Report”; Form EIA-906, “Power Plant Report”; Form

EIA-920, “Combined Heat and Power Plant Report”; Form

EIA-923, “Power Plant Operations Report”; U.S. Department of Commerce, Bureau of the Census, “Monthly Report

EM 545”; and Federal Energy Regulatory Commission,

Form 423, “Monthly Report of Cost and Quality of Fuels for

Electric Plants.” Projections: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A. Note: For

1989-2030, coal production includes waste coal.

Figure 89. U.S. coal production in six cases, 2008,

2020, and 2035: AEO2010 National Energy Modeling System, runs AEO2010R.D111809A, LCCST10.D120909A,

HCCST10.D120909A, LM2010.D011110A, HM2010.

D020310A, and HP2010.D011910A. Note: Coal production

includes waste coal.

Figure 90. Average annual minemouth coal prices by

region, 1990-2035: History (dollars per short ton):

1990-2000: U.S. Energy Information Administration, Coal

Industry Annual, DOE/EIA-0584 (various years).

2001-2008: U.S. Energy Information Administration, Annual Coal Report 2008, DOE/EIA-0584(2008) (Washington,

DC, September 2009), and previous issues. History (conversion to dollars per million Btu): 1970-2008: Estimation Procedure: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting. Estimates of average heat content by region and year based on

coal quality data collected through various energy surveys

(see sources) and national-level estimates of U.S. coal production by year in units of quadrillion Btu published in

EIA’s Annual Energy Review. Sources: U.S. Energy Information Administration, Annual Energy Review 2008,

DOE/EIA-0384(2008) (Washington, DC, June 2009), Table

1.2; Form EIA-3, “Quarterly Coal Consumption and Quality Report, Manufacturing Plants”; Form EIA-5, “Quarterly Coal Consumption and Quality Report, Coke Plants”;

Form EIA-6A, “Coal Distribution Report”; Form EIA-7A,

“Coal Production Report”; Form EIA-423, “Monthly Cost

and Quality of Fuels for Electric Plants Report”; Form

EIA-906, “Power Plant Report”; and Form EIA-920, “Combined Heat and Power Plant Report”; Form EIA-923,

“Power Plant Operations Report”; U.S. Department of

Commerce, Bureau of the Census, “Monthly Report EM

545”; and Federal Energy Regulatory Commission, Form

423, “Monthly Report of Cost and Quality of Fuels for Electric Plants.” Projections: AEO2010 National Energy

Modeling System, run AEO2010R.D111809A. Note: Includes reported prices for both open-market and captive

mines.

Figure 91. Average annual delivered coal prices in

four cases, 1990-2035: History: 1990-2008: U.S. Energy

Information Administration, Quarterly Coal Report, October-December 2008, DOE/EIA-0121(2008/4Q) (Washington,

DC, March 2009), and previous issues; Electric Power

Monthly, October 2009, DOE/EIA-0226(2009/10) (Washington, DC, October 2009); and Annual Energy Review 2008,

DOE/EIA-0384(2008) (Washington, DC, June 2009). Projections: AEO2010 National Energy Modeling System,

runs AEO2010R.D111809A, LCCST10.D120909A,

HCCST10.D120909A, and HP2010.D011910A.

Figure 92. Change in U.S. coal consumption by end

use in two cases, 2008-2035: AEO2010 National Energy

Modeling System, runs AEO2010R.D111809A and

NORSK2010.D012510A.

U.S. Energy Information Administration / Annual Energy Outlook 2010 103

Notes and Sources
Figure 93. Carbon dioxide emissions by sector and

fuel, 2008 and 2035: AEO2010 National Energy Modeling

System, run AEO2010R.D111809A.

Figure 94. Sulfur dioxide emissions from electricity

generation, 2000-2035: History: 1995: U.S. Environmental Protection Agency, National Air Pollutant Emissions Trends, 1990-1998, EPA-454/R-00-002 (Washington,

DC, March 2000). 2000: U.S. Environmental Protection

Agency, Acid Rain Program Preliminary Summary Emissions Report, Fourth Quarter 2004, web site www.epa.gov/

airmarkets/emissions/prelimarp/index.html. 2008 and

Projections: AEO2010 National Energy Modeling System, run AEO2010R.D111809A.

Figure 95. Nitrogen oxide emissions from electricity

generation, 2000-2035: History: 1995: U.S. Environmental Protection Agency, National Air Pollutant Emissions Trends, 1990-1998, EPA-454/R-00-002 (Washington,

DC, March 2000). 2000: U.S. Environmental Protection

Agency, Acid Rain Program Preliminary Summary Emissions Report, Fourth Quarter 2004, web site www.epa.gov/

airmarkets/emissions/prelimarp/index.html. 2008 and

Projections: AEO2010 National Energy Modeling System, run AEO2010R.D111809A.

104 U.S. Energy Information Administration / Annual Energy Outlook 2010

Notes and Sources
Appendixes

U.S. Energy Information Administration / Annual Energy Outlook 2010 107

Appendix A

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108 U.S. Energy Information Administration / Annual Energy Outlook 2010

Reference Case

 

 


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U.S. Energy Information Administration / Annual Energy Outlook 2010 109

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110 U.S. Energy Information Administration / Annual Energy Outlook 2010

Reference Case

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U.S. Energy Information Administration / Annual Energy Outlook 2010 111

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Appendix C

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Price Case Comparisons

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Appendix D

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Results from Side Cases

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The National Energy Modeling System

Projections in the Annual Energy Outlook 2010

(AEO2010) are generated from the National Energy

Modeling System (NEMS) [1], developed and maintained by the Office of Integrated Analysis and

Forecasting (OIAF) of the U.S. Energy Information

Administration (EIA). In addition to its use in developing the Annual Energy Outlook (AEO) projections,

NEMS is also used in analytical studies for the U.S.

Congress, the Executive Office of the President, other

offices within the U.S. Department of Energy (DOE),

and other Federal agencies. The AEO projections are

also used by analysts and planners in other government agencies and nongovernment organizations.

The projections in NEMS are developed with the use

of a market-based approach to energy analysis. For

each fuel and consuming sector, NEMS balances

energy supply and demand, accounting for economic

competition among the various energy fuels and

sources. The time horizon of NEMS is the period

through 2035, approximately 25 years into the future.

In order to represent regional differences in energy

markets, the component modules of NEMS function

at the regional level: the nine Census divisions for the

end-use demand modules; production regions specific

to oil, natural gas, and coal supply and distribution;

the North American Electric Reliability Council

regions and subregions for electricity; and the

Petroleum Administration for Defense Districts

(PADDs) for refineries (see Appendix F for details).

NEMS is organized and implemented as a modular

system. The modules represent each of the fuel

supply markets, conversion sectors, and end-use

consumption sectors of the energy system. NEMS

also includes macroeconomic and international modules. The primary flows of information among the

modules are the delivered prices of energy to end

users and the quantities consumed, by product,

region, and sector. The delivered fuel prices encompass all the activities necessary to produce, import,

and transport fuels to end users. The information

flows also include other data on such areas as economic activity, domestic production, and international liquids supply.

The Integrating Module controls the execution of

each of the component modules. To facilitate modularity, the components do not pass information to

each other directly but communicate through a

central data structure. This modular design provides

the capability to execute modules individually, thus

allowing decentralized development of the system

and independent analysis and testing of individual

modules. The modular design also permits the use of

the methodology and level of detail most appropriate

for each energy sector. NEMS calls each supply, conversion, and end-use demand module in sequence

until the delivered prices of energy and the quantities

demanded have converged within tolerance, thus

achieving an economic equilibrium of supply and

demand in the consuming sectors. A solution is

reached annually through the projection horizon.

Other variables, such as petroleum product imports,

crude oil imports, and several macroeconomic indicators, also are evaluated for convergence.

Each NEMS component represents the impacts

and costs of legislation and environmental regulations that affect that sector. NEMS accounts for all

combustion-related carbon dioxide (CO2) emissions,

as well as emissions of sulfur dioxide (SO2), nitrogen

oxides (NOx), and mercury from the electricity generation sector.

The version of NEMS used for AEO2010 represents

current legislation and environmental regulations as

of October 31, 2009 (such as the American Recovery

and Reinvestment Act of 2009 [ARRA], which was

enacted in mid-February 2009; the Energy Improvement and Extension Act of 2008 [EIEA2008], signed

into law on October 3, 2008; the Food, Conservation,

and Energy Act of 2008; the Energy Independence

and Security Act of 2007 [EISA2007], which was

signed into law on December 19, 2007; the Energy

Policy Act of 2005 [EPACT2005]; the Working Families Tax Relief Act of 2004; and the American Jobs

Creation Act of 2004), and the costs of compliance

with regulations (such as the new stationary diesel

regulations issued by the U.S. Environmental Protection Agency [EPA] in July 2006). The AEO2010 models do not represent the Clean Air Mercury Rule,

which was vacated and remanded by the D.C. Circuit

Court of the U.S. Court of Appeals on February 8,

2008, but they do represent State requirements for

reduction of mercury emissions.

The AEO2010 Reference case reflects the temporary

reinstatement of the NOx and SO2 cap-and-trade

programs included in the Clean Air Interstate Rule

Appendix E

NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 195
(CAIR), according to the ruling issued by the U.S.

Court of Appeals for the District of Columbia on

December 23, 2008. The potential impacts of proposed Federal and State legislation, regulations, or

standards—or of sections of legislation that have

been enacted but require funds or implementing regulations that have not been provided or specified—

are not reflected in NEMS.

In general, the historical data used for the AEO2010

projections are based on EIA’s Annual Energy Review

2008, published in June 2009 [2]; however, data were

taken from multiple sources. In some cases, only

partial or preliminary data were available for 2008.

CO2 emissions were calculated by using CO2 coefficients from the EIA report, Emissions of Greenhouse

Gases in the United States 2008, published in December 2009 [3]. Historical numbers are presented for

comparison only and may be estimates. Source documents should be consulted for the official data values.

Footnotes to the AEO2010 appendix tables indicate

the definitions and sources of historical data.

The AEO2010 projections for 2009 and 2010 incorporate short-term projections from EIA’s September

2009 Short-Term Energy Outlook (STEO). For shortterm energy projections, readers are referred to

monthly updates of the STEO [4].

Component modules

The component modules of NEMS represent the

individual supply, demand, and conversion sectors of

domestic energy markets and also include international and macroeconomic modules. In general, the

modules interact through values representing the

prices or expenditures for energy delivered to the

consuming sectors and the quantities of end-use

energy consumption.

Macroeconomic Activity Module

The Macroeconomic Activity Module (MAM) provides

a set of macroeconomic drivers to the energy modules

and receives energy-related indicators from the

NEMS energy components as part of the macroeconomic feedback mechanism within NEMS. Key

macroeconomic variables used in the energy modules

include gross domestic product (GDP), disposable

income, value of industrial shipments, new housing

starts, sales of new light-duty vehicles (LDVs), interest rates, and employment. Key energy indicators fed

back to the MAM include aggregate energy prices and

costs. The MAM uses the following models from IHS

Global Insight: Macroeconomic Model of the U.S.

Economy, National Industry Model, and National

Employment Model. In addition, EIA has constructed

a Regional Economic and Industry Model to project

regional economic drivers, and a Commercial Floorspace Model to project 13 floorspace types in 9 Census

divisions. The accounting framework for industrial

value of shipments uses the North American Industry

Classification System (NAICS).

International Module

The International Energy Module (IEM) uses

assumptions of economic growth and expectations of

future U.S. and world petroleum liquids production

and consumption, by year, to project the interaction

of U.S. and international liquids markets. The IEM

computes world oil prices, provides a world crude-like

liquids supply curve, generates a worldwide oil

supply/demand balance for each year of the projection

period, and computes initial estimates of crude oil and

light and heavy petroleum product imports for the

United States.

The supply-curve calculations are based on historical

market data and a world oil supply/demand balance,

which is developed from reduced-form models of international liquids supply and demand, current investment trends in exploration and development, and

long-term resource economics for 221 countries/territories. The oil production estimates include both conventional and unconventional supply recovery technologies. In the interaction with the rest of NEMS,

the IEM changes the world oil price (WOP), which is

defined as the price of foreign light, low sulfur crude

oil delivered to Cushing, Oklahoma, (Petroleum Allocation Defense District 2), in response to changes in

expected crude and product liquids produced and consumed in the United States.

Residential and Commercial Demand Modules

The Residential Demand Module projects energy

consumption in the residential sector by housing type

and end use, based on delivered energy prices, the

menu of equipment available, the availability and

cost of renewable sources of energy, and housing

starts. The Commercial Demand Module projects

energy consumption in the commercial sector by

building type and nonbuilding uses of energy and by

category of end use, based on delivered prices of

energy, availability of renewable sources of energy,

and macroeconomic variables representing interest

rates and floorspace construction.

196 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases
Both modules estimate the equipment stock for the

major end-use services, incorporating assessments of

advanced technologies, including representations of

renewable energy technologies, and the effects of

both building shell and appliance standards, including the recent regional standards for furnaces, heat

pumps, and central air conditioners agreed to by

manufacturers and environmental interest groups.

The Commercial Demand Module incorporates combined heat and power (CHP) technology. The modules also include projections of distributed generation. Both modules incorporate changes to “normal”

heating and cooling degree-days by Census division,

based on a 10-year average and on State-level population projections. The Residential Demand Module

projects an increase in the average square footage of

both new construction and existing structures, based

on trends in the size of new construction and the

remodeling of existing homes.

Industrial Demand Module

The Industrial Demand Module projects the consumption of energy for heat and power, feedstocks,

and raw materials in each of 21 industries, subject to

the delivered prices of energy and the values of

macroeconomic variables representing employment

and the value of shipments for each industry. As

noted in the description of the MAM, the value of

shipments is based on NAICS. The industries are

classified into three groups—energy-intensive manufacturing, non-energy-intensive manufacturing, and

nonmanufacturing. Of the eight energy-intensive

industries, seven are modeled in the Industrial

Demand Module, with energy-consuming components for boiler/steam/cogeneration, buildings, and

process/assembly use of energy.

A new bulk chemical model was implemented for the

AEO2010. The new model calculates the production

(in physical units), process shares, and process energy

requirements for 26 specific chemicals and four

aggregate groups of bulk chemicals. Details are

included in the forthcoming Industrial Demand

Module documentation. A generalized representation

of CHP and a recycling component also are included.

The use of energy for petroleum refining is modeled

in the Petroleum Market Module (PMM), and the projected consumption is included in the industrial

totals.

Transportation Demand Module

The Transportation Demand Module projects

consumption of fuels in the transportation sector,

including petroleum products, electricity, methanol,

ethanol, compressed natural gas, and hydrogen, by

transportation mode, vehicle vintage, and size class,

subject to delivered prices of energy fuels and macroeconomic variables representing disposable personal

income, GDP, population, interest rates, and industrial shipments. Fleet vehicles are represented

separately to allow analysis of other legislation and

legislative proposals specific to those market segments. The Transportation Demand Module also

includes a component to assess the penetration of

alternative-fuel vehicles. Provisions of EPACT2005,

EIEA2008, and ARRA are reflected in the assessment

of the impacts of tax credits on the purchase of hybrid

gas-electric, plug-in electric, alternative-fuel, and

fuel-cell vehicles. The corporate average fuel economy

(CAFE) and biofuel representation in the module

reflect standards proposed by the National Highway

Traffic Safety Administration (NHTSA), the EPA,

and provisions in EISA2007.

The air transportation component of the Transportation Demand Module explicitly represents air travel

in domestic and foreign markets and includes the

industry practice of parking aircraft in both domestic

and international markets to reduce operating costs,

as well as the movement of aging aircraft from

passenger to cargo markets [5]. For passenger travel

and air freight shipments, the module represents

regional fuel use in regional, narrow-body, and widebody aircraft. An infrastructure constraint, which is

also modeled, can potentially limit overall growth in

passenger and freight air travel to levels commensurate with industry-projected infrastructure expansion and capacity growth.

Electricity Market Module

There are three primary submodules of the Electricity Market Module—capacity planning, fuel dispatching, and finance and pricing. To project the optimal

mix of new generation capacity that should be added

in future years, the Capacity Planning Submodule

uses the stock of existing generation capacity; the

menu, cost, and performance of future generation

capacity; expected fuel prices; expected financial

parameters; expected electricity demand; and

expected environmental regulations. The Fuel Dispatching Submodule uses the existing stock of generation equipment, their operating and maintenance

(O&M) costs and performance, fuel prices to the electricity sector, electricity demand, and all applicable

environmental regulations to determine the leastcost way to meet that demand; the submodule also

NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 197
projects transmission and pricing of electricity. The

Finance and Pricing Submodule uses capital costs,

fuel costs, macroeconomic parameters, and environmental regulations, along with load shapes, to estimate generation costs for each technology.

All specifically identified options promulgated by the

EPA for compliance with the Clean Air Act Amendments of 1990 (CAAA90) are explicitly represented in

the capacity expansion and dispatch decisions; those

that have not been promulgated (e.g., fine particulate

proposals) are not incorporated. All financial incentives for power generation expansion and dispatch

specifically identified in EPACT2005 have been implemented. Several States, primarily in the Northeast, have recently enacted air emission regulations

for CO2 that affect the electricity generation sector,

and those regulations are represented in AEO2010.

The AEO2010 Reference case reflects the temporary

reinstatement of the NOx and SO2 cap-and-trade programs included in CAIR, as well as State regulations

on mercury emissions.

Although currently there is no Federal legislation in

place that restricts greenhouse gas (GHG) emissions,

regulators and the investment community have

continued to push energy companies to invest in technologies that are less GHG-intensive. The trend is

captured in the AEO2010 Reference case through a

3-percentage-point increase in the cost of capital

when investments in new coal-fired power plants and

new coal-to-liquids (CTL) plants without carbon capture and sequestration (CCS) are evaluated.

Renewable Fuels Module

The Renewable Fuels Module (RFM) includes submodules representing renewable resource supply and

technology input information for central-station,

grid-connected electricity generation technologies,

including conventional hydroelectricity, biomass

(dedicated biomass plants and co-firing in existing

coal plants), geothermal, landfill gas, solar thermal

electricity, photovoltaics (PV), and wind energy. The

RFM contains renewable resource supply estimates

representing the regional opportunities for renewable energy development. Investment tax credits

(ITCs) for renewable fuels are incorporated, as currently enacted, including a permanent 10-percent

ITC for business investment in solar energy (thermal

nonpower uses as well as power uses) and geothermal

power (available only to those projects not accepting

the production tax credit [PTC] for geothermal

power). In addition, the module reflects the increase

in the ITC to 30 percent for solar energy systems

installed before January 1, 2017, and the extension

of the credit to individual homeowners under EIEA2008.

PTCs for wind, geothermal, landfill gas, and some

types of hydroelectric and biomass-fueled plants also

are represented. They provide a credit of up to 2.1

cents per kilowatthour for electricity produced in the

first 10 years of plant operation. For AEO2010, new

wind plants coming on line before January 1, 2013,

are eligible to receive the PTC; other eligible plants

must be in service before January 1, 2014. As part of

ARRA, plants eligible for the PTC may instead elect

to receive a 30-percent ITC or an equivalent direct

grant. AEO2010 also accounts for new renewable

energy capacity resulting from State renewable portfolio standard (RPS) programs, mandates, and goals,

as described in Assumptions to the Annual Energy

Outlook 2010 [6].

Oil and Gas Supply Module

The Oil and Gas Supply Module (OGSM) represents

domestic crude oil and natural gas supply within an

integrated framework that captures the interrelationships among the various sources of supply:

onshore, offshore, and Alaska by all production techniques, including natural gas recovery from coalbeds

and low-permeability formations of sandstone and

shale. The framework analyzes cash flow and profitability to compute investment and drilling for each of

the supply sources, based on the prices for crude oil

and natural gas, the domestic recoverable resource

base, and the state of technology. Oil and natural gas

production activities are modeled for 12 supply regions, including 6 onshore, 3 offshore and 3 Alaskan

regions.

The AEO2010 OGSM includes a revised representation of onshore oil and gas supply, the new Onshore

Lower 48 Oil and Gas Supply Submodule (OLOGSS),

which evaluates the economics of future exploration

and development projects for crude oil and natural

gas at the play level. Crude oil resources are divided

into known plays and undiscovered plays, and include

highly fractured continuous zones, such as the Austin

chalk and Bakken shale formations. Production

potential from advanced secondary recovery techniques (e.g., in-fill drilling, horizontal continuity, and

horizontal profile) and enhanced oil recovery (e.g.,

CO2 flooding, steam flooding, polymer flooding, and

profile modification) are explicitly represented. Natural gas resources are divided into known producing

198 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases
plays, known developing plays, and undiscovered

plays in high-permeability carbonate and sandstone,

tight gas, shale gas, and coalbed formations.

Domestic crude oil production quantities are used as

inputs to the PMM in NEMS for conversion and

blending into refined petroleum products. Supply

curves for natural gas are used as inputs to the Natural Gas Transmission and Distribution Module for determining natural gas wellhead prices and domestic

production.

Natural Gas Transmission and Distribution

Module

The Natural Gas Transmission and Distribution

Module represents the transmission, distribution,

and pricing of natural gas, subject to end-use demand

for natural gas, the potential for converting coal to

pipeline-quality natural gas, and the availability of

domestic natural gas and natural gas traded on the

international market. The module tracks the flows of

natural gas and determines the associated capacity

expansion requirements in an aggregate pipeline network, connecting the domestic and foreign supply

regions with 12 U.S. demand regions. The flow of

natural gas is determined for both a peak and off-peak

period in the year. Key components of pipeline and

distributor tariffs are included in separate pricing

algorithms. The module also represents foreign

sources and destinations of natural gas, including

pipeline imports and exports (Canada and Mexico)

and liquefied natural gas (LNG) imports and exports.

For AEO2010, an algorithm was added to project

the addition of compressed natural gas retail fueling

capability.

Petroleum Market Module

The PMM projects prices of petroleum products,

crude oil and product import activity, and domestic

refinery operations (including fuel consumption),

subject to the demand for petroleum products, the

availability and price of imported petroleum, and the

domestic production of crude oil, natural gas liquids,

and biofuels (ethanol, biodiesel, and biomass-toliquids [BTL]). The module represents refining

activities in the five PADDs, as well as a less detailed

representation of refining activities in the rest of the

world. It explicitly models the requirements of

EISA2007 and CAAA90 and the costs of automotive

fuels, such as conventional and reformulated gasoline, and includes the production of biofuels for blending in gasoline and diesel.

The PMM in NEMS represents regulations that limit

the sulfur content of all nonroad and locomotive/

marine diesel to 15 parts per million (ppm) by mid2012. The module also reflects the renewable fuels

standard (RFS) in EISA2007, which requires the

use of 36 billion ethanol-equivalent gallons per year

of biofuels by 2022 if achievable, with corn ethanol

credits limited to 15 billion gallons per year [7].

Demand growth and regulatory changes necessitate

capacity expansion for refinery processing units. U.S.

end-use prices for petroleum products are based on

the marginal costs of production, plus markups representing the costs of product marketing, importing,

transportation, and distribution, as well as applicable

State and Federal taxes [8]. Refinery capacity expansion at existing sites is permitted in each of the five refining regions modeled. Additional detailed information on the PMM can be found in Assumptions to the

Annual Energy Outlook 2010 [9].

Fuel ethanol and biodiesel are included in the PMM

because they are commonly blended into petroleum

products. The module allows ethanol blending into

gasoline at 10 percent or less by volume (E10) and

up to 85 percent by volume (E85) for use in flex-fuel

vehicles. Although blending into gasoline at 15 percent or less by volume (E15) is currently being considered for certification by the EPA as a viable motor

fuel, its use in LDVs has not been approved and thus

is not modeled for AEO2010. In addition, the model

reflects the allowable level of non-E85 ethanol blending in California, which has been raised from 5.7 percent to 10 percent in recent regulatory changes that

have set a framework for E10 emissions standards

starting in year 2010 [10].

Ethanol is produced primarily in the Midwest from

corn or other starchy crops, and in the future it may

be produced from cellulosic material, such as switchgrass, poplar, and crop residues. Biodiesel (diesel-like

fuel made in a transesterification process) is produced

from seed oil, imported palm oil, animal fats, or

yellow grease (primarily, recycled cooking oil). Renewable or “green” diesel is also modeled as a blending component in petroleum diesel. Unlike the more

common biodiesel, renewable diesel is made by hydrogenation of vegetable oils or tallow and is completely

fungible with petroleum diesel. Imports and limited

exports of these biofuels are modeled in the PMM.

Both domestic and imported ethanol count toward

the EISA2007 RFS. Domestic ethanol production

from three feedstock categories (corn, cellulosic, and

advanced) is modeled. Corn-based ethanol plants are

NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 199
numerous (more than 180 are now in operation, with

a total operating production capacity of more than

11 billion gallons annually) and are based on a wellknown technology that converts starch and sugar into

ethanol. Ethanol from cellulosic sources is a new technology, with only a few small pilot plants in operation.

Large-scale commercialization of the cellulosic technology is not expected to ramp up quickly enough to

meet the cellulosic ethanol mandate in EISA2007.

DOE and the U.S. Department of Agriculture

(USDA) have awarded numerous grants to biorefinery projects (over $600 million in 2009 alone),

and the USDA has provided a loan guarantee to a

small commercial-sized cellulosic biofuel plant scheduled to begin production next year; however, reduced

investment during the recent recession is expected to

cause significant delays in the startup of large commercial plants, and the delays are reflected in the projections. Imported ethanol can be produced from cane

sugar or from bagasse (the cellulosic byproduct of

sugar milling). For AEO2010, assumptions about

ethanol import availability have been reviewed and

updated from the previous Reference case, to reflect

greater expected availability of ethanol from sugar

cane. The sources of ethanol are modeled to compete

on an economic basis.

Fuels produced by gasification and Fischer-Tropsch

synthesis, or through a pyrolysis process, also are

modeled in the PMM, based on their economics relative to competing feedstocks and products. The four

processes modeled are CTL, gas-to-liquids (GTL),

BTL, and pyrolysis. CTL facilities are likely to be

built at locations close to coal supplies and water

sources, where liquid products and surplus electricity

could also be distributed to nearby demand regions.

In addition, a hybrid coal-biomass-to-liquids process

was implemented for AEO2010. GTL facilities may be

built in Alaska, but they would compete with the

Alaska Natural Gas Transportation System for available natural gas resources. BTL and pyrolysis facilities are likely to be built where there are large supplies of biomass, such as crop residues and forestry

waste. Because the BTL process uses cellulosic

feedstocks, it is also modeled as a choice to meet the

EISA2007 requirement for cellulosic biofuels.

Coal Market Module

The Coal Market Module (CMM) simulates mining,

transportation, and pricing of coal, subject to end-use

demand for coal differentiated by heat and sulfur content. U.S. coal production is represented in the

CMM by 40 separate supply curves—differentiated

by region, mine type, coal rank, and sulfur content.

The coal supply curves include a response to capacity

utilization of mines, mining capacity, labor productivity, and factor input costs (mining equipment, mining

labor, and fuel requirements). Projections of U.S. coal

distribution are determined by minimizing the cost of

coal supplied, given coal demand by region and sector,

environmental restrictions, and accounting for minemouth prices, transportation costs, and coal supply

contracts. Over the projection horizon, coal transportation costs in the CMM vary in response to changes

in the cost of rail investments.

The CMM produces projections of U.S. steam and

metallurgical coal exports and imports in the context

of world coal trade, determining the pattern of world

coal trade flows that minimizes the production and

transportation costs of meeting a specified set of

regional world coal import demands, subject to

constraints on export capacities and trade flows. The

international coal market component of the module

computes trade in 3 types of coal for 17 export regions

and 20 import regions. U.S. coal production and

distribution are computed for 14 supply regions and

16 demand regions.

Annual Energy Outlook 2010 cases

Table E1 provides a summary of the cases produced

as part of AEO2010. For each case, the table gives the

name used in this report, a brief description of the

major assumptions underlying the projections, the

mode in which the case was run in NEMS (either fully

integrated, partially integrated, or standalone), and a

reference to the pages in the body of the report and in

this appendix where the case is discussed. The text

sections following Table E1 describe the various

cases. The Reference case assumptions for each sector

are described in Assumptions to the Annual Energy

Outlook 2010 [11]. Regional results and other details

of the projections are available at web site www.

eia.doe.gov/oiaf/aeo/supplement.

Macroeconomic growth cases

In addition to the AEO2010 Reference case, the Low

Economic Growth and High Economic Growth cases

were developed to reflect the uncertainty in projections of economic growth. The alternative cases are

intended to show the effects of alternative growth

assumptions on energy market projections. The cases

are described as follows:

200 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases
NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 201

Table E1. Summary of the AEO2010 cases

Case name Description

Integration

mode

Reference

in text

Reference in

Appendix E

Reference Baseline economic growth (2.4 percent per year from 2008

through 2035), world oil price, and technology assumptions.

Complete projection tables in Appendix A.

Fully

integrated

— —

Low Economic

Growth

Real GDP grows at an average annual rate of 1.8 percent from

2008 to 2035. Other energy market assumptions are the same

as in the Reference case. Partial projection tables in Appendix

B.

Fully

integrated

p. 52 p. 204

High Economic

Growth

Real GDP grows at an average annual rate of 3.0 percent from

2008 to 2035. Other energy market assumptions are the same

as in the Reference case. Partial projection tables in Appendix

B.

Fully

integrated

p. 52 p. 204

Low Oil Price More optimistic assumptions for economic access to

non-OPEC resources and for OPEC behavior than in the

Reference case. World light, sweet crude oil prices are $51 per

barrel in 2035, compared with $133 per barrel in the Reference

case (2008 dollars). Other assumptions are the same as in the

Reference case. Partial projection tables in Appendix C.

Fully

integrated

p. 54 p. 205

High Oil Price More pessimistic assumptions for economic access to

non-OPEC resources and for OPEC behavior than in the

Reference case. World light, sweet crude oil prices are about

$210 per barrel (2008 dollars) in 2035. Other assumptions are

the same as in the Reference case. Partial projection tables in

Appendix C.

Fully

integrated

p. 54 p. 205

Extended Policies Begins with the Reference case and selectively extends PTC,

ITC, and other energy efficiency tax credit policies with sunset

provisions, and promulgates new efficiency standards as they

satisfy the consumer-related cost-effectiveness criteria of

DOE’s Office of Energy Efficiency and Renewable Energy.

Introduces new CAFE and tailpipe emissions proposal.

Partial projection tables in Appendix D.

Fully

integrated

p. 22 p. 210

No Sunset Begins with the Reference case and extends all energy

policies and legislation with sunset provisions, except those

requiring additional funding (e.g., loan guarantee programs).

Also extends the RFS requirement to 36 billion gallons by 2026

and continues increasing proportional to transport demand

thereafter. Partial projection tables in Appendix D.

Fully

integrated

p. 22 p. 210

Residential:

2009 Technology

Future equipment purchases based on equipment available in

2009. Existing building shell efficiencies fixed at 2009 levels.

Partial projection tables in Appendix D.

With

commercial

p. 31 p. 205

Residential:

High Technology

Earlier availability, lower costs, and higher efficiencies

assumed for more advanced equipment. Building shell

efficiencies for new construction meet ENERGY STAR

requirements after 2016. Consumers evaluate efficiency

investments at a 7-percent real discount rate. Partial projection

tables in Appendix D.

With

commercial

p. 31 p. 205

Residential:

Best Available

Technology

Future equipment purchases and new building shells based on

most efficient technologies available by fuel. Building shell

efficiencies for new construction meet the criteria for most

efficient components after 2009. Partial projection tables in

Appendix D.

With

commercial

p. 31 p. 205
202 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases

Table E1. Summary of the AEO2010 cases (continued)

Case name Description

Integration

mode

Reference

in text

Reference in

Appendix E

Commercial:

2009 Technology

Future equipment purchases based on equipment available in

2009. Building shell efficiencies fixed at 2009 levels. Partial

projection tables in Appendix D.

With

residential

p. 31 p. 205

Commercial:

High Technology

Earlier availability, lower costs, and higher efficiencies for more

advanced equipment. Energy efficiency investments evaluated

at a 7-percent real discount rate. Building shell efficiencies for

new and existing buildings increase by 17.4 and 7.5 percent,

respectively, from 2003 values by 2035. Partial projection

tables in Appendix D.

With

residential

p. 31 p. 205

Commercial:

Best Available

Technology

Future equipment purchases based on most efficient

technologies available by fuel. Building shell efficiencies for

new and existing buildings increase by 20.8 and 9.0 percent,

respectively, from 2003 values by 2035. Partial projection

tables in Appendix D.

With

residential

p. 31 p. 205

Industrial:

2010 Technology

Efficiency of plant and equipment fixed at 2010 levels. Partial

projection tables in Appendix D.

Standalone p. 176 p. 206

Industrial:

High Technology

Earlier availability, lower costs, and higher efficiencies for more

advanced equipment. Partial projection tables in Appendix D.

Standalone p. 176 p. 206

Transportation:

Low Technology

Advanced technologies are more costly and less efficient than

in the Reference case. Partial projection tables in Appendix D.

Standalone p. 64 p. 206

Transportation:

High Technology

Advanced technologies are less costly and more efficient than

in the Reference case. Partial projection tables in Appendix D.

Standalone p. 64 p. 206

Transportation:

Reference Case

2019 Phaseout

With Base

Market Potential

Modified Reference case incorporating lower incremental costs

for all classes of heavy-duty natural gas vehicles and tax

incentives for natural gas refueling stations and natural gas

fuel beginning in 2011 and phased out by 2019. Partial

projection tables in Appendix D.

Fully

integrated

p. 34 p. 206

Transportation:

Reference Case

2027 Phaseout

With Expanded

Market Potential

Modified Reference case incorporating lower incremental costs

for all classes of heavy-duty natural gas vehicles and tax

incentives for natural gas refueling stations and natural gas

fuel beginning in 2011 and phased out by 2027, with assumed

increases in the potential market for all classes of heavy-duty

natural gas vehicles. Partial projection tables in Appendix D.

Fully

integrated

p. 35 p. 207

Transportation:

Low Oil Price

Case 2019

Phaseout

With Base

Market Potential

Modified Low Oil Price case incorporating lower incremental

costs for all classes of heavy-duty natural gas vehicles and tax

incentives for natural gas refueling stations and natural gas

fuel beginning in 2011 and phased out by 2019. Partial

projection tables in Appendix D.

Fully

integrated

p. 35 p. 207

Transportation:

Low Oil Price

Case 2027

Phaseout

With Expanded

Market Potential

Modified Low Oil Price case incorporating lower incremental

costs for all classes of heavy-duty natural gas vehicles and tax

incentives for natural gas refueling stations and natural gas

fuel beginning in 2011 and phased out by 2027, with assumed

increases in the potential market for all classes of heavy-duty

natural gas vehicles. Partial projection tables in Appendix D.

Fully

integrated

p. 35 p. 207

Electricity:

Low Fossil

Technology Cost

Capital and operating costs for all new fossil-fired generating

technologies start 10 percent below the Reference case and

decline to 25 percent below the Reference case in 2035.

Partial projection tables in Appendix D.

Fully

integrated

p. 181 p. 207

Electricity:

High Fossil

Technology Cost

Costs for new advanced fossil-fired generating technologies do

not improve due to learning over time from 2010. Partial

projection tables in Appendix D.

Fully

integrated

p. 181 p. 207
NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 203

Table E1. Summary of the AEO2010 cases (continued)

Case name Description

Integration

mode

Reference

in text

Reference in

Appendix E

Electricity:

Low Nuclear Cost

Capital and operating costs for new nuclear capacity start 10

percent below the Reference case and decline to 25 percent

below the Reference case in 2035. Partial projection tables in

Appendix D.

Fully

integrated

p. 179 p. 207

Electricity:

High Nuclear

Cost

Costs for new nuclear technology do not improve due to

learning from 2010 levels in the Reference case.

Partial projection tables in Appendix D.

Fully

integrated

p. 179 p. 207

Electricity:

Nuclear 60-Year

Life

All existing nuclear plants are retired after 60 years of

operation. Partial projection tables in Appendix D.

Fully

integrated

p. 43 p. 208

Renewable

Fuels:

Low Renewable

Technology Cost

Levelized cost of energy for nonhydropower renewable

generating technologies start 10 percent below the Reference

case in 2010 and decline to 25 percent below the Reference

case in 2035. Partial projection tables in Appendix D.

Fully

integrated

p. 69 p. 208

Renewable

Fuels: High

Renewable

Technology Cost

New renewable generating technologies do not improve

through learning over time from 2010. Partial projection tables

in Appendix D.

Fully

integrated

p. 69 p. 208

Oil and Gas:

Slow

Technology

Improvements in exploration and development costs,

production rates, and success rates due to technological

advancement are reduced by 50 percent to reflect slower

improvement than in the Reference case. Partial projection

tables in Appendix D.

Fully

integrated

p. 71 p. 208

Oil and Gas:

Rapid

Technology

Improvements in exploration and development costs,

production rates, and success rates due to technological

advancement are increased by 50 percent to reflect more rapid

improvement than in the Reference case. Partial projection

tables in Appendix D.

Fully

integrated

p. 71 p. 208

Oil and Gas: No

Low-Permeability

Gas Drilling

No drilling is permitted in onshore, lower 48 low-permeability

natural gas reservoirs after 2009 (i.e., no new tight gas or

shale gas drilling). Partial projection tables in Appendix D.

Fully

integrated

p. 41 p. 209

Oil and Gas:

No Shale Gas

Drilling

No drilling is permitted in onshore, lower 48 shale gas

reservoirs after 2009 (i.e., no new shale gas drilling). Partial

projection tables in Appendix D.

Fully

integrated

p. 41 p. 209

Oil and Gas:

High Shale Gas

Resource

Shale gas resources in the onshore, lower 48 are assumed to

be higher than in the Reference case. Partial projection tables

in Appendix D.

Fully

integrated

p. 41 p. 209

Oil and Gas:

High LNG Supply

LNG imports into North America are set exogenously to a

factor times the levels projected in the Reference case from

2010 forward. The factor starts at 1.0 in 2010 and increases

linearly to 5.0 in 2035. Partial projection tables in Appendix D.

Fully

integrated

p. 74 p. 208

Coal:

Low Coal Cost

Productivity growth rates for coal mining are higher than in the

Reference case, and coal mining wages, mine equipment, and

coal transportation rates are lower. Partial projection tables in

Appendix D.

Fully

integrated

p. 80 p. 209

Coal:

High Coal Cost

Productivity growth rates for coal mining are lower than in the

Reference case, and coal mining wages, mine equipment, and

coal transportation rates are higher. Partial projection tables in

Appendix D.

Fully

integrated

p. 80 p. 209
• In the Reference case, population grows by 0.9

percent per year, nonfarm employment by 0.8 percent per year, and labor productivity by 2.0 percent per year from 2008 to 2035. Economic output

as measured by real GDP increases by 2.4 percent

per year from 2008 through 2035, and growth in

real disposable income per capita averages 1.8

percent per year.

• The Low Economic Growth case assumes lower

growth rates for population (0.5 percent per year)

and labor productivity (1.5 percent per year),

resulting in lower nonfarm employment (0.4 percent per year), higher prices and interest rates,

and lower growth in industrial output. In the Low

Economic Growth case, economic output as

measured by real GDP increases by 1.8 percent

per year from 2008 through 2035, and growth in

real disposable income per capita averages 1.7

percent per year.

• The High Economic Growth case assumes higher

growth rates for population (1.3 percent per year)

and labor productivity (2.4 percent per year),

resulting in higher nonfarm employment (1.2 percent per year). With higher productivity gains and

employment growth, inflation and interest rates

are lower than in the Reference case, and consequently economic output grows at a higher rate

(3.0 percent per year) than in the Reference case

(2.4 percent). Disposable income per capita grows

by 1.82 percent per year, compared with 1.8 percent in the Reference case.

Oil price cases

The world oil price in AEO2010 is defined as the

average price of light, low-sulfur crude oil delivered in

Cushing, Oklahoma, and is similar to the price for

light, sweet crude oil traded on the New York Mercantile Exchange. AEO2010 also includes a projection of

the U.S. annual average refiners’ acquisition cost of

imported crude oil, which is more representative of

the average cost of all crude oils used by domestic

refiners.

The historical record shows substantial variability in

world oil prices, and there is arguably even more uncertainty about future prices in the long term.

AEO2010 considers three price cases (Reference, Low

Oil Price, and High Oil Price) to allow an assessment

of alternative views on the course of future oil prices.

The Low and High Oil Price cases define a wide range

of potential price paths, reflecting different assumptions about decisions by OPEC members regarding

the preferred rate of oil production and about the

future finding and development costs and accessibility of conventional oil resources outside the United

States. Because the Low and High Oil Price cases are

not fully integrated with a world economic model, the

impact of world oil prices on international economies

is not accounted for directly.

• In the Reference case, real world oil prices rise

from a low of $70 per barrel (2008 dollars) in 2010

to $95 per barrel in 2015, then increase more

slowly to $133 per barrel in 2035. The Reference

case represents EIA’s current best judgment regarding exploration and development costs and

accessibility of oil resources outside the United

States. It also assumes that OPEC producers will

choose to maintain their share of the market and

will schedule investments in incremental production capacity so that OPEC’s conventional oil production will represent about 40 percent of the

world’s total liquids production.

204 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases

Table E1. Summary of the AEO2010 cases (continued)

Case name Description

Integration

mode

Reference

in text

Reference in

Appendix E

Integrated

Low Technology

Combination of the Residential, Commercial, and Industrial

2010 Technology cases and the Electricity High Fossil

Technology Cost, High Renewable Technology Cost, and High

Nuclear Cost cases. Partial projection tables in Appendix D.

Fully

integrated

p. 32 p. 209

Integrated

High Technology

Combination of the Residential, Commercial, Industrial, and

Transportation High Technology cases and the Electricity Low

Fossil Technology Cost, Low Renewable Technology Cost,

and Low Nuclear Cost cases. Partial projection tables in

Appendix D.

Fully

integrated

p. 32 p. 209

No GHG Concern No GHG emissions reduction policy is enacted, and market

investment decisions are not altered in anticipation of such a

policy.

Fully

integrated

p. 81 p. 209
• In the Low Oil Price case, real world oil prices are

$51 per barrel (2008 dollars) in 2035, compared

with $133 per barrel in the Reference case. The

Low Oil Price case assumes that OPEC countries

will increase their conventional oil production to

obtain a 47-percent share of total world liquids

production, and that oil resources outside the

United States will be more accessible and/or less

costly to produce (as a result of technology advances, more attractive fiscal regimes, or both)

than in the Reference case. With these assumptions, conventional oil production outside the

United States is higher in the Low Oil Price case

than in the Reference case.

• In the High Oil Price case, real world oil prices

reach about $210 per barrel (2008 dollars) in

2035. The High Oil Price case assumes that OPEC

countries will reduce their production from the

current rate, sacrificing market share as global

liquids production increases, and that oil

resources outside the United States will be less

accessible and/or more costly to produce than

assumed in the Reference case.

Buildings sector cases

In addition to the AEO2010 Reference case, three

standalone technology-focused cases using the

Residential and Commercial Demand Modules of

NEMS were developed to examine the effects of

changes in equipment and building shell efficiencies.

For the residential sector, the three technologyfocused cases are as follows:

• The 2009 Technology case assumes that all future

equipment purchases are based only on the range

of equipment available in 2009. Existing building

shell efficiencies are assumed to be fixed at 2009

levels (no further improvements). For new construction, building shell technology options are

constrained to those available in 2009.

• The High Technology case assumes earlier availability, lower costs, and higher efficiencies for

more advanced equipment [12]. For new construction, building shell efficiencies are assumed to

meet ENERGY STAR requirements after 2016.

Consumers evaluate investments in energy efficiency at a 7-percent real discount rate.

• The Best Available Technology case assumes that

all future equipment purchases are made from a

menu of technologies that includes only the most

efficient models available in a particular year for

each fuel, regardless of cost. For new construction, building shell efficiencies are assumed to

meet the criteria for the most efficient components after 2009.

For the commercial sector, the three technologyfocused cases are as follows:

• The 2009 Technology case assumes that all future

equipment purchases are based only on the range

of equipment available in 2009. Building shell efficiencies are assumed to be fixed at 2009 levels.

• The High Technology case assumes earlier availability, lower costs, and/or higher efficiencies for

more advanced equipment than in the Reference

case [13]. Energy efficiency investments are

evaluated at a 7-percent real discount rate. Building shell efficiencies for new and existing buildings in 2035 are assumed to be 17.4 percent and

7.5 percent higher, respectively, than their 2003

levels—a 25-percent improvement relative to the

Reference case.

• The Best Available Technology case assumes that

all future equipment purchases are made from a

menu of technologies that includes only the most

efficient models available in a particular year for

each fuel, regardless of cost. Building shell efficiencies for new and existing buildings in 2035 are

assumed to be 20.8 percent and 9.0 percent

higher, respectively, than their 2003 values—a

50-percent improvement relative to the Reference

case.

The Residential and Commercial Demand Modules of

NEMS were also used to complete the High and Low

Renewable Technology Cost cases, which are discussed in more detail below (see “Renewable Fuels

Cases”). In combination with assumptions for electricity generation from renewable fuels in the electric

power sector and industrial sector, these sensitivity

cases analyze the impacts of changes in generating

technologies that use renewable fuels and in the

availability of renewable energy sources. For the Residential and Commercial Demand Modules:

• The Low Renewable Technology Cost case

assumes greater improvements in residential and

commercial PV and wind systems than in the

Reference case. The assumptions result in capital

cost estimates that are 10 percent below Reference case assumptions in 2010 and decline to at

least 25 percent below Reference case costs in

2035.

NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 205
• The High Renewable Technology Cost case

assumes that costs and performance levels for

residential and commercial PV and wind systems

remain constant at 2009 levels through 2035.

Industrial sector cases

In addition to the AEO2010 Reference case, two

standalone cases using the Industrial Demand Module of NEMS were developed to examine the effects of

less rapid and more rapid technology change and

adoption. Because they are standalone cases, the energy intensity changes discussed in this section

exclude the refining industry. (Energy use in the

refining industry is estimated as part of the PMM.)

The Industrial Demand Module also was used as part

of the Integrated Low and High Renewable Technology Cost cases. For the industrial sector:

• The 2010 Technology case holds the energy efficiency of plant and equipment constant at the

2010 level over the projection period. In this case,

delivered energy intensity falls by 0.7 percent

annually from 2008 to 2035, as compared with 1.1

percent annually in the Reference case. Changes

in aggregate energy intensity may result both

from changing equipment and production efficiency and from changing composition of industrial output. Because the level and composition of

industrial output are the same in the Reference,

2010 Technology, and High Technology cases, any

change in energy intensity in the two technology

cases is attributable to efficiency changes.

• The High Technology case assumes earlier availability, lower costs, and higher efficiency for more

advanced equipment [14] and a more rapid rate

of improvement in the recovery of biomass byproducts from industrial processes (0.7 percent

per year, as compared with 0.4 percent per year in

the Reference case). The same assumption is

incorporated in the integrated Low Renewable

Technology Cost case, which focuses on electricity

generation. Although the choice of the 0.7-percent

annual rate of improvement in byproduct recovery is an assumption in the High Technology case,

it is based on the expectation that there would be

higher recovery rates and substantially increased

use of CHP in that case. Delivered energy intensity falls by 1.2 percent annually in the High Technology case.

The 2010 Technology case was run with only the

Industrial Demand Module, rather than in fully

integrated NEMS runs. Consequently, no potential

feedback effects from energy market interactions are

captured, and energy consumption and production in

the refining industry, which are modeled in the PMM,

are excluded.

Transportation sector cases

In addition to the AEO2010 Reference case, two

standalone cases using the NEMS Transportation

Demand Module were developed to examine the

effects of advanced technology costs and efficiency

improvement on technology adoption and vehicle fuel

economy [15]. For the transportation sector:

• In the Low Technology case, the characteristics

of conventional technologies, advanced technologies, and alternative-fuel LDVs, heavy-duty

vehicles, and aircraft reflect more pessimistic

assumptions about cost and efficiency improvements achieved over the projection. More pessimistic assumptions for fuel efficiency improvement also are reflected in the rail and shipping

sectors.

• In the High Technology case, the characteristics

of conventional and alternative-fuel LDVs reflect

more optimistic assumptions about incremental

improvements in fuel economy and costs. In the

freight truck sector, the High Technology case

assumes more rapid incremental improvement in

fuel efficiency for engine and emissions control

technologies. More optimistic assumptions for

fuel efficiency improvements also are made for the

air, rail, and shipping sectors.

The Low Technology and High Technology cases

were run with only the Transportation Demand

Module rather than as fully integrated NEMS runs.

Consequently, no potential macroeconomic feedback

related to vehicle costs or travel demand was captured, nor were changes in fuel prices incorporated.

• The Reference Case 2019 Phaseout With Base

Market Potential case is a modified Reference case

that incorporates lower incremental costs for all

classes of heavy-duty natural gas vehicles (zero incremental cost relative to their diesel-powered

counterparts after accounting for incentives) and

tax incentives for natural gas refueling stations

($100,000 per new facility) and for natural gas

fuel ($0.50 per gallon of gasoline equivalent) that

begin in 2011 and are phased out by 2019.

• The Reference Case 2027 Phaseout With Expanded Market Potential case is a modified Reference case with the same added assumptions of

206 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases
lower incremental costs for heavy-duty natural

gas vehicles and subsidies for fueling stations and

natural gas fuel as in the Reference Case 2019

Phaseout With Base Market Potential case but

with the subsidies extended to 2027 before

phaseout and, in addition, assumed increases in

the potential market for both “fleet” and “nonfleet” natural gas vehicles.

• The Low Oil Price Case 2019 Phaseout With Base

Market Potential case is a modified Low Oil Price

case that incorporates lower incremental costs for

all classes of heavy-duty natural gas vehicles (zero

incremental cost relative to their diesel-powered

counterparts after accounting for incentives) and

tax incentives for natural gas refueling stations

($100,000 per new facility) and for natural gas

fuel ($0.50 per gallon of gasoline equivalent) that

begin in 2011 and are phased out by 2019.

• The Low Oil Price Case 2027 Phaseout With Expanded Market Potential case is a modified Low

Oil Price case with the same added assumptions of

lower incremental costs for heavy-duty natural

gas vehicles and subsidies for fueling stations and

natural gas fuel as in the Reference Case 2019

Phaseout With Base Market Potential case but

with the subsidies extended to 2027 before

phaseout and, in addition, assumed increases in

the potential market for both “fleet” and “nonfleet” natural gas vehicles.

Electricity sector cases

In addition to the Reference case, several integrated

cases with alternative electric power assumptions

were developed to analyze uncertainties about the

future costs and performance of new generating

technologies. Two of the cases examine alternative

assumptions for nuclear power technologies, and two

examine alternative assumptions for fossil fuel technologies. Reference case values for technology characteristics are determined in consultation with industry

and government specialists; however, there is always

uncertainty surrounding the major component costs.

The electricity cases analyze what could happen if

costs of new plants were either higher or lower than

assumed in the Reference case. The cases are fully

integrated to allow feedback between the potential

shifts in fuel consumption and fuel prices.

In addition, for AEO2010 an alternate retirement

case was run for nuclear power plants, to address

uncertainties about the operating lives of existing

reactors. This scenario is discussed in the Issues in

Focus article, “U.S. nuclear power plants: Continued

life or replacement after 60?”

Nuclear technology cost cases

• The cost assumptions for the Low Nuclear Cost

case reflect an approximate 10-percent reduction

in capital and operating costs for advanced nuclear technology in 2010, relative to the Reference

case, and fall to 25 percent below the Reference

case in 2035. The Reference case projects a

35-percent reduction in the capital costs of nuclear power plants from 2010 to 2035; the Low

Nuclear Cost case assumes a 45-percent reduction

from 2010 to 2035.

• The High Nuclear Cost case assumes that capital

costs for advanced nuclear technology remain

fixed at the 2010 levels assumed in the Reference

case. The capital costs still are tied to key commodity price indices, so they change over time;

however, no cost improvement from “learningby-doing” effects is assumed.

Fossil cost technology cases

• In the Low Fossil Technology Cost case, capital

costs and operating costs for all coal- and naturalgas-fired generating technologies are assumed to

start 10 percent lower than Reference case levels

and fall to 25 percent lower than Reference case

levels in 2035. Because learning in the Reference

case reduces costs with manufacturing experience, costs in the Low Fossil Cost case are reduced

by 37 to 49 percent between 2010 and 2035,

depending on the technology.

• In the High Fossil Technology Cost case, capital

costs for all coal- and natural-gas-fired generating

technologies remain fixed at the 2010 values

assumed in the Reference case. Costs still are

adjusted year to year by the commodity price

index, but no learning-related cost reductions are

assumed.

Additional details about annual capital costs, operating and maintenance costs, plant efficiencies, and

other factors used in the High and Low Fossil Technology Cost cases will be provided in Assumptions to

the Annual Energy Outlook 2010 [16].

Alternative Nuclear Retirement Case

• In the Nuclear 60-Year Life case, all existing

nuclear plants are assumed to retire after 60 years

NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 207
of operation. In the Reference case, existing

plants are assumed to run as long as they continue

to be economic, implicitly assuming that a second

20-year license renewal will be obtained for those

plants reaching 60 years before 2035. This

case was run to analyze the impact of additional

nuclear retirements, which could occur if the oldest plants do not receive a second license extension. In this case, 31 gigawatts of nuclear capacity

is assumed to be retired by 2035.

Renewable fuels cases

In addition to the AEO2010 Reference case, two

integrated cases with alternative assumptions about

renewable fuels were developed to examine the effects

of less aggressive and more aggressive improvement

in the cost of renewable technologies. The cases are as

follows:

• In the High Renewable Technology Cost case, capital costs, O&M costs, and performance levels for

wind, solar, biomass, and geothermal resources

are assumed to remain constant at 2010 levels

through 2035. Costs still are tied to key commodity price indexes, but no cost improvement from

“learning-by-doing” effects is assumed. Although

biomass prices are not changed from the Reference case, this case assumes that dedicated energy

crops (also known as “closed-loop” biomass fuel

supply) do not become available.

• In the Low Renewable Technology Cost case, the

levelized costs of energy resources for generating

technologies using renewable resources are assumed to start at 10 percent below Reference case

levels in 2010 and decline to 25 percent below the

Reference case costs for the same resources in

2035. In general, lower costs are represented by

reducing the capital costs of new plant construction. Biomass fuel supplies also are assumed to be

25 percent less expensive than in the Reference

case for the same resource quantities used in the

Reference case. Assumptions for other generating

technologies are unchanged from those in the

Reference case. In the Low Renewable Technology Cost case, the rate of improvement in recovery

of biomass byproducts from industrial processes

also is increased.

Oil and gas supply cases

The sensitivity of the projections to changes in the

assumed rates of technological progress in oil and

natural gas supply and LNG imports is examined in

three cases:

• In the Rapid Technology case, the parameters

representing the effects of technological progress

on production rates, exploration and development

costs, and success rates for oil and natural gas

drilling in the Reference case are improved by 50

percent. Key supply parameters for Canadian

natural gas also are modified to simulate the

assumed impacts of more rapid natural gas technology penetration on Canadian supply potential.

All other parameters in the model are kept at the

Reference case values, including technology

parameters for other modules, parameters affecting foreign oil supply, and assumptions about

imports and exports of LNG and natural gas trade

between the United States and Mexico. Specific

detail by region and fuel category is provided in

Assumptions to the Annual Energy Outlook 2010

[17].

• In the Slow Technology case, the parameters representing the effects of technological progress on

production rates, exploration and development

costs, and success rates for oil and natural gas

drilling are 50 percent less optimistic than those

in the Reference case. Key Canadian supply

parameters also are modified to simulate the

assumed impacts of slow natural gas technology

penetration on Canadian supply potential. All

other parameters in the model are kept at the

Reference case values.

• The High LNG Supply case exogenously specifies

North American LNG import levels for 2010

through 2030 as being equal to a factor times the

Reference case levels. The factor starts at 1 in

2010 and increases linearly to 5 in 2035. The

intent is to project the potential impact on domestic natural gas markets if LNG imports turn out to

be higher than projected in the Reference case.

Three additional cases examine the importance of

low-permeability reservoirs on future domestic

natural gas supply:

• In the No Low-Permeability Drilling case, no new

onshore, lower 48 wells are drilled in low permeability natural gas reservoirs (includes shale gas

and tight sandstone gas) after 2009. Natural gas

production from low-permeability wells drilled before 2010 declines continuously through 2035.

• In the No Shale Gas Drilling case, no new onshore, lower 48 shale gas wells are drilled after

2009. Natural gas production from shale gas wells

208 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases
drilled before 2010 declines continuously through

2035.

• In the High Shale Gas Resource case, the resource

base for shale gas in the onshore, lower 48 States

is assumed to be higher than in the Reference

case. Each well can support twice as many shale

gas plays as in the Reference case, increasing the

resource base from 347 trillion cubic feet in the

Reference case to 652 trillion cubic feet in the

High Shale Gas Resource case. The estimated recovery from each well is the same as in the Reference case.

Coal market cases

Two alternative coal cost cases examine the impacts

on U.S. coal supply, demand, distribution, and prices

that result from alternative assumptions about

mining productivity, labor costs, mine equipment

costs, and coal transportation rates. The alternative

productivity and cost assumptions are applied in

every year from 2010 through 2035. For the coal cost

cases, adjustments to the Reference case assumptions

for coal mining productivity are based on variation in

the average annual productivity growth of 2.7 percent

observed since 2000. Transportation rates are

lowered (in the Low Coal Cost case) or raised (in the

High Coal Cost case) from Reference case levels to

achieve a 25-percent change in rates relative to the

Reference case in 2035. The Low and High Coal Cost

cases represent fully integrated NEMS runs, with

feedback from the macroeconomic activity, international, supply, conversion, and end-use demand

modules.

• In the Low Coal Cost case, the average annual

growth rates for coal mining productivity are

higher than those in the Reference case and are

applied at the supply curve level. As an example,

the average annual growth rate for Wyoming’s

Southern Powder River Basin supply curve is

increased from -0.5 percent in the Reference case

for the years 2010 through 2035 to 2.2 percent in

the Low Coal Cost case. Coal mining wages, mine

equipment costs, and other mine supply costs all

are assumed to be about 25 percent lower in 2035

in real terms in the Low Coal Cost case than in the

Reference case. Coal transportation rates, excluding the impact of fuel surcharges, are assumed to

be 25 percent lower in 2035.

• In the High Coal Cost case, the average annual

productivity growth rates for coal mining are

lower than those in the Reference case and are

applied as described in the Low Coal Cost case.

Coal mining wages, mine equipment costs, and

other mine supply costs in 2035 are assumed to be

about 30 percent higher than in the Reference

case, and coal transportation rates in 2035 are

assumed to be 25 percent higher.

Additional details about the productivity, wage, mine

equipment cost, and coal transportation rate assumptions for the Reference and alternative Coal Cost

cases are provided in Appendix D.

Cross-cutting integrated cases

In addition to the sector-specific cases described

above, a series of cross-cutting integrated cases are

used in AEO2010 to analyze specific scenarios

with broader sectoral impacts. For example, two

integrated technology progress cases combine the

assumptions from the other technology progress

cases to analyze the broader impacts of more rapid

and slower technology improvement rates. In addition, a No GHG Concern case was run that excludes

the 3-percent cost-of-capital adjustment for new

coal-fired generating capacity and for CTL plants

without CCS. In the Reference case, this adjustment

is included to simulate the reluctance of regulators

and the investment community to invest in

GHG-intensive technologies, given uncertainty about

the possible enactment of limits on GHG emissions.

Integrated technology cases

The Integrated Low Technology case combines the assumptions from the residential, commercial, and industrial 2010 Technology cases and the electricity

High Fossil Technology Cost, High Renewable Technology Cost, and High Nuclear Cost cases. The Integrated High Technology case combines the assumptions from the residential, commercial, industrial,

and transportation High Technology cases and the

electricity High Fossil Technology Cost, Low Renewable Technology Cost, and Low Nuclear Cost cases.

Extended Policies case

In addition to the AEO2010 Reference case, an additional case was run assuming that selected policies

with sunset provisions (such as the PTC, ITC, and tax

credits for energy-efficient equipment in the buildings sector) will be extended indefinitely rather than

allowed to sunset as the law currently prescribes.

Further, updates to Federal appliance efficiency

standards were assumed to occur at intervals

NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 209
provided by law and at levels determined by the

consumer impact test in DOE testing procedures or

Federal Energy Management Program (FEMP)

purchasing guidelines. Finally, proposed rules by

NHTSA and the EPA for national tailpipe CO2-equivalent emissions and fuel economy standards for

LDVs, including both passenger cars and light-duty

trucks, were harmonized and incorporated in this

case.

In the electricity market, tax credits for renewable

generation capacity that are available currently but

are scheduled to expire are instead assumed to be

extended indefinitely—including the PTC of 2.1 cents

per kilowatthour or, as appropriate, the 30-percent

ITC available for wind, geothermal, biomass, hydroelectric, and landfill gas resources. For solar capacity,

a 30-percent ITC that is scheduled to revert to a

10-percent tax credit in 2016 is, instead, assumed to

be extended indefinitely at 30 percent.

In the buildings sector, tax credits for the purchase of

energy-efficient equipment, including PV and new

houses, are extended indefinitely, as opposed to ending in 2010 or 2016 as prescribed by current law. The

business ITCs for commercial-sector generation technologies and geothermal heat pumps are extended

indefinitely, as opposed to expiring in 2016, and the

business ITC for solar systems is kept at 30 percent

instead of reverting to 10 percent. In addition, updates to appliance standards are assumed to occur as

prescribed by the timeline in DOE’s multiyear plan.

The efficiency levels chosen for the updated standard

were based on the technology menu in the AEO2010

Reference case and whether or not the efficiency level

passed the consumer impact test prescribed in DOE’s

standards-setting process. The efficiency levels chosen for updated commercial equipment standards are

based on the technology menu from the AEO2010

Reference case and FEMP-designated purchasing

specifications for Federal agencies.

NHTSA and the EPA have proposed rules for coordinated national CO2-equivalent tailpipe emissions and

fuel economy standards for LDVs, including both

passenger cars and light-duty trucks. The harmonized fuel economy standards begin in model year

(MY) 2012 and increase in stringency to MY 2016,

based on NHTSA’s recently proposed CAFE standards. NHTSA has estimated the impact of the new

CAFE standards and has projected that the proposed

fleet-wide standards for LDVs will increase fuel economy from 27.3 miles per gallon in MY 2011 to 34.1

miles per gallon in MY 2016, based on projected sales

of vehicles by type and footprint. Separate mathematical functions representing the CAFE standards are

established for passenger cars and light trucks,

reflecting their different design capabilities. As

required by EISA2007, the fuel economy standards

increase to 35 miles per gallon by 2020. The Extended

Policies case assumes that these standards are further increased so that the minimum fuel economy

standard achieved for LDVs increases to 45.6 miles

per gallon in 2035.

No Sunset case

Assumptions for extensions of the renewable energy

tax credit and the buildings tax credit are the same as

in the Extended Policies case described above. No

updates to appliance or CAFE standards are assumed.

This case also extends the RFS target to that

originally set by law (36 billion ethanol-equivalent

gallons) and assumes that the target is achieved by

2026 instead of 2022; after 2026, the RFS requirement continues to increase so that it remains at the

same percentage of total transport fuel demand as

achieved in 2026. Biofuel tax credits and the import

tariffs also are extended.

210 U.S. Energy Information Administration / Annual Energy Outlook 2010

NEMS Overview and Brief Description of Cases
Endnotes

NEMS Overview and Brief Description of Cases

U.S. Energy Information Administration / Annual Energy Outlook 2010 211

1.U.S. Energy Information Administration, The National Energy Modeling System: An Overview 2009, DOE/

EIA-0581(2009) (Washington, DC, March 2009), web

site http://www.eia.doe.gov/oiaf/aeo/overview/index.

html.

2.U.S. Energy Information Administration, Annual

Energy Review 2008, DOE/EIA-0384(2008) (Washington, DC, June 2009), web site www.eia.doe.gov/emeu/

aer/contents.html.

3.U.S. Energy Information Administration, Emissions

of Greenhouse Gases in the United States 2007, DOE/

EIA-0573(2008) (Washington, DC, December 2009),

web site www.eia.doe.gov/oiaf/1605/ggrpt/index.html.

4.U.S. Energy Information Administration, Short-Term

Energy Outlook, web site www.eia.doe.gov/emeu/steo/

pub/contents.html. Portions of the preliminary information were also used to initialize the NEMS Petroleum Market Module projection.

5.Jet Information Services, Inc., World Jet Inventory

Year-End 2006 (Utica, NY, March 2007); and personal

communication from Stuart Miller (Jet Information

Services).

6.U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2010, DOE/EIA0554(2010) (Washington, DC, March 2010), web site

www.eia.doe.gov/oiaf/aeo/assumption.

7.Corn ethanol production may exceed 15 billion gallons

if it is economical to do so without the RFS credit.

8.For gasoline blended with ethanol, the tax credit of 51

cents (nominal) per gallon of ethanol is assumed to be

available for 2008; however, it is reduced to 45 cents

starting in 2009 (the year after annual U.S. ethanol

consumption surpasses 7.5 billion gallons), as mandated by the Food, Conservation, and Energy Act of

2008 (the Farm Bill), and it is set to expire after 2010.

In addition, modeling updates include the Farm Bill’s

mandated extension of the ethanol import tariff, at 54

cents per gallon, to December 31, 2010. Finally, again

in accordance with the Farm Bill, a new cellulosic ethanol producer’s tax credit of $1.01 per gallon, valid

through 2012, is implemented in the model; however,

it is reduced by the amount of the blender’s tax credit.

Thus, in 2009 and 2010, the cellulosic ethanol producer’s tax credit is modeled as $1.01 - $0.45 = $0.56

per gallon, and in 2011 and 2012 it is set at $1.01 per

gallon. (Note: Taxes discussed in this footnote are in

nominal dollars.)

9.U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2010, DOE/EIA0554(2010) (Washington, DC, March 2010), web site

www.eia.doe.gov/oiaf/aeo/assumption.

10.California Environmental Protection Agency, Air

Resources Board, “Phase 3 California Reformulated

Gasoline Regulations,” web site www.arb.ca.gov/

regact/2007/carfg07/carfg07.htm.

11.U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2010, DOE/EIA0554(2010) (Washington, DC, March 2010), web site

www.eia.doe.gov/oiaf/aeo/assumption.

12.High technology assumptions for the residential sector

are based on Energy Information Administration,

EIA—Technology Forecast Updates—Residential and

Commercial Building Technologies—Advanced Case

Second Edition (Revised) (Navigant Consulting, Inc.,

September 2007), and EIA—Technology Forecast

Updates—Residential and Commercial Building

Technologies—Advanced Case: Residential and Commercial Lighting, Commercial Refrigeration, and

Commercial Ventilation Technologies (Navigant Consulting, Inc., September 2008).

13.High technology assumptions for the commercial sector are based on Energy Information Administration,

EIA—Technology Forecast Updates—Residential and

Commercial Building Technologies—Advanced Case

Second Edition (Revised) (Navigant Consulting, Inc.,

September 2007), and EIA—Technology Forecast

Updates—Residential and Commercial Building

Technologies—Advanced Case: Residential and Commercial Lighting, Commercial Refrigeration, and

Commercial Ventilation Technologies (Navigant Consulting, Inc., September 2008).

14.These assumptions are based in part on Energy Information Administration, Industrial Technology and

Data Analysis Supporting the NEMS Industrial Model

(FOCIS Associates, October 2005).

15.U.S. Energy Information Administration, Documentation of Technologies Included in the NEMS Fuel Economy Model for Passenger Cars and Light Trucks

(Energy and Environmental Analysis, September

2003).

16.U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2010, DOE/EIA0554(2010) (Washington, DC, March 2010), web site

www.eia.doe.gov/oiaf/aeo/assumption.

17.U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2010, DOE/EIA0554(2010) (Washington, DC, March 2010), web site

www.eia.doe.gov/oiaf/aeo/assumption.

U.S. Energy Information Administration / Annual Energy Outlook 2010 213

Appendix F

Regional Maps

Figure F1. United States Census Divisions

Pacific

East South Central

South Atlantic

Middle

Atlantic

New

England

West

South

Central

West

North

Central East

North

Central

Mountain

AK

WA

MT

ID WY

NV

UT

CO

AZ

NM

TX

OK

IA

KS MO

IL

IN

KY

TN

MS AL

FL

GA

SC

NC

WV

PA NJ

MD

DE

NY

CT

VT ME

RI

MA

NH

VA

WI

MI

OH

NE

SD

ND MN

AR

LA

OR

CA

HI

Middle Atlantic

New England

East North Central

West North Central

Pacific

West South Central

East South Central

South Atlantic

Mountain

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
214 U.S. Energy Information Administration / Annual Energy Outlook 2010

Regional Maps

Figure F1. United States Census Divisions (cont.)

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
U.S. Energy Information Administration / Annual Energy Outlook 2010 215

Regional Maps

Figure F2. Electricity Market Module Regions

1 East Central AreaReliability CoordinationAgreement (ECAR) 8 FloridaReliability CoordinatingCouncil (FL)

2 Electric Reliability Council of Texas (ERCOT) 9 Southeastern Electric Reliability Council (SERC)

3 Mid-AtlanticArea Council (MAAC) 10 Southwest Power Pool (SPP)

4 Mid-AmericaInterconnectedNetwork (MAIN) 11 Northwest Power Pool (NPP)

5Mid-Continent AreaPower Pool (MAPP) 12 Rocky MountainPower Area, Arizona, New

6 New York (NY) New Mexico,and SouthernNevada(RA)

7. NewEngland(NE) 13 California (CA)

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
216 U.S. Energy Information Administration / Annual Energy Outlook 2010

Regional Maps

Figure F3. Petroleum Administration for Defense Districts

AK

WA

NV

AZ

OR

CA

HI

V

MT

WY

ID

UT

CO

IV

OK

IA

KS

MO

IL

IN

KY

TN

WI

MI

OH

NE

SD

ND MN

II

NM

TX

MS

AL AR

LA III

NJ

CT

VT ME

RI

MA

NH

FL

GA

SC

NC

WV

MD

DE VA

NY

PA I

PAD District I - East Coast

PAD District II - Midwest

PAD District III - Gulf Coast

PAD District IV - Rocky Mountain

PAD District V - West Coast

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
U.S. Energy Information Administration / Annual Energy Outlook 2010 217

Regional Maps

Figure F4. Oil and Gas Supply Model Regions

Atlantic

WA MT

ID WY

NV

UT CO

AZ NM

TX

OK

IA

KS MO

IL

IN

KY

TN

MS AL

FL

GA

SC

NC

WV

PA NJ

MD

DE

NY

CT

ME

RI

MA

NH

VA

WI

MI

OH NE

SD

ND MN

AR

LA

OR

CA

VT

Northeast (1)

Gulf of Mexico

Gulf Coast (2)

Midcontinent (3)

Rocky Mountain (5)

West Coast (6)

Pacific

Offshore

North Slope

AK

TX

TX

NM

TX

Southwest (4)

Onshore

North Slope

Other

Alaska

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
218 U.S. Energy Information Administration / Annual Energy Outlook 2010

Regional Maps

Figure F5. Natural Gas Transmission and Distribution Model Regions

Pacific

(9)

Mountain

(8)

CA

(12)

AZ/NM

(11)

W. North Central

(4)

W. South Central

(7)

E. South

Central

(6)

E. North

Central

(3)

S. Atlantic

(5)

FL

(10)

Mid.

Atlantic

(2)

New

Engl.

(1)

W. Canada

E. Canada

MacKenzie

Alaska

Canada

Offshore

and LNG

Mexico

Bahamas

Primary Flows

Secondary Flows

Pipeline Border Crossing

LNG Imports

Pacific

(9)

Mountain

(8)

CA

(12)

AZ/NM

(11)

W. North Central

(4)

W. South Central

(7)

E. South

Central

(6)

E. North

Central

(3)

S. Atlantic

(5)

FL

(10)

Mid.

Atlantic

(2)

New

Engl.

(1)

W. Canada

E. Canada

MacKenzie

Alaska

Canada

Offshore

and LNG

Mexico

Bahamas

Primary Flows

Secondary Flows

Pipeline Border Crossing

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
U.S. Energy Information Administration / Annual Energy Outlook 2010 219

Regional Maps

Figure F6. Coal Supply Regions

WA

OR ID

CA

NV

UT

TX

OK

AR

MO

LA

MS

AL

GA

FL

TN SC

NC

KY VA

WV

WY

CO

SD

ND

MI

MN

WI

IL

IN OH

MD

PA NJ

DE

CT

MA

NH VT

NY

ME

RI

MT

NE IA

KS

MI

AZ

NM

500 0

SCALE IN MILES

APPALACHIA

Northern Appalachia

Central Appalachia

Southern Appalachia

INTERIOR

NORTHERN GREAT PLAINS

Eastern Interior

Western Interior

Gulf Lignite

Dakota Lignite

Western Montana

Wyoming, Northern Powder River Basin

Wyoming, Southern Powder River Basin

Western Wyoming

OTHER WEST

Rocky Mountain

Southwest

Northwest

KY

AK

1000 0

SCALE IN MILES

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
220 U.S. Energy Information Administration / Annual Energy Outlook 2010

Regional Maps

Figure F7. Coal Demand Regions

CT,MA,ME,NH,RI,VT

OH

1. NE

3. S1

4. S2

5. GF

6. OH

7. EN

AL,MS

MN,ND,SD

IA,NE,MO,KS

TX,LA,OK,AR

MT,WY,ID

CO,UT,NV

AZ,NM

9. AM

11. C2

12. WS

13. MT

14. CU

15. ZN

WV,MD,DC,DE

2. YP

Region Code Region Content

NY,PA,NJ

VA,NC,SC

GA,FL

IN,IL,MI,WI

Region Code Region Content

14. CU

13. MT

16. PC

15. ZN

12. WS

11. C2

9. AM 5. GF

8. KT

4. S2

7. EN

6. OH

2. YP

1. NE

3. S1

10. C1

8. KT 16. PC AK,HI,WA,OR,CA KY,TN

10. C1

CT,MA,ME,NH,RI,VT

OH

1. NE

3. S1

4. S2

5. GF

6. OH

7. EN

AL,MS

MN,ND,SD

IA,NE,MO,KS

TX,LA,OK,AR

MT,WY,ID

CO,UT,NV

AZ,NM

9. AM

11. C2

12. WS

13. MT

14. CU

15. ZN

WV,MD,DC,DE

2. YP

Region Code Region Content

NY,PA,NJ

VA,NC,SC

GA,FL

IN,IL,MI,WI

Region Code Region Content

14. CU

13. MT

16. PC

15. ZN

12. WS

11. C2

9. AM 5. GF

8. KT

4. S2

7. EN

6. OH

2. YP

1. NE

3. S1

10. C1

8. KT 16. PC AK,HI,WA,OR,CA KY,TN

10. C1

Source: U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting.
U.S. Energy Information Administration / Annual Energy Outlook 2010 221

Appendix G

Conversion Factors

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