SR/OIAF/2000-05

Analysis of Strategies for Reducing

Multiple Emissions from Power Plants:

Sulfur Dioxide, Nitrogen Oxides,

and Carbon Dioxide

December 2000

Energy Information Administration

Office of Integrated Analysis and Forecasting

U.S. Department of Energy

Washington, DC 20585

This Service Report was prepared by the Energy Information Administration, the independent statistical and

analytical agency within the Department of Energy. The information contained herein should be attributed to the

Energy Information Administration and should not be construed as advocating or reflecting any policy position of

the Department of Energy or of any other organization. Service Reports are prepared by the Energy Information

Administration upon special request and are based on assumptions specified by the requester.
Contacts

This report was prepared by the Office of Integrated

Analysis and Forecasting, Energy Information Administration. General questions concerning the report may be

directed to Mary J. Hutzler (202/586-2222, mhutzler

@eia.doe.gov), Director of the Office of Integrated

Analysis and Forecasting, and Scott B. Sitzer (202/586-

2308, ssitzer@eia.doe.gov), Director of the Coal and Electric Power Division of the Office of Integrated Analysis

and Forecasting. Specific questions about the report may

be directed to the following analysts:

Electricity

J. Alan Beamon . . . . . . . . 202/586-2025 jbeamon@eia.doe.gov

Jeff Jones . . . . . . . . . . . . . 202/586-2038 jjones@eia.doe.gov

Laura Martin. . . . . . . . . . 202/586-1494 laura.martin@eia.doe.gov

Renewables

Tom Petersik . . . . . . . . . . 202/586-6582 tpetersi@eia.doe.gov

Zia Haq . . . . . . . . . . . . . . 202/586-2869 zia.haq@eia.doe.gov

Natural Gas

Joe Benneche . . . . . . . . . . 202/586-6132 jbennech@eia.doe.gov

Jim Lockhart . . . . . . . . . . 202/586-2854 james.lockhart@eia.doe.gov

Coal

Mike Mellish . . . . . . . . . . 202/586-2136 mmellish@eia.doe.gov

Edward Flynn. . . . . . . . . 202/586-5748 eflynn@eia.doe.gov

Macroeconomic Impacts

Ron Earley. . . . . . . . . . . . 202/586-1398 rearley@eia.doe.gov

Comparisons

Tom Leckey. . . . . . . . . . . 202/586-9413 tleckey@eia.doe.gov

ii Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
Preface

Over the next decade, power plant operators may face

significant requirements to reduce emissions of sulfur

dioxide (SO2), nitrogen oxides (NOx), carbon dioxide

(CO2) and mercury (Hg). At present, neither the future

reduction requirements nor the complete timetable is

known for any of these airborne emissions, and compliance planning is difficult. Power plant operators are

wary of making investments that could prove uneconomical if and when new regulations are enacted. An

option that looks attractive to meet one set of SO2 and

NOx standards may not be attractive if further reductions are required in a few years. Similarly, economical

options for reducing SO2 and NOx may not be optimal if

Hg and/or CO2 emissions must also be reduced later.

Recently, some have proposed plans requiring coordinated multi-emission reductions. This analysis responds

to a request from the Subcommittee on National Economic Growth, Natural Resources, and Regulatory

Affairs of the U.S. House of Representatives Committee

on Government Reform to examine the costs of such

multi-emission reduction strategies (see Appendix J for

the requesting letters). In its request the Subcommittee

asked the Energy Information Administration (EIA) to

“analyze the potential costs of various multi-pollutant

strategies to reduce the air emissions from electric

power plants.” The Subcommittee requested that EIA

examine the impacts of cases (see Chapters 2 and 5 for

descriptions of the cases) incorporating NOx, SO2, CO2,

and Hg emission reduction requirements and renewable

portfolio standard (RPS) requirements.

In response to the Subcommittee’s request, EIA has prepared this report as the first of two volumes. This report

addresses NOx, SO2, and CO2 emission reductions. The

second volume will extend the analysis to Hg emission

reductions and RPS requirements. The projections and

quantitative analysis for this report were prepared using

the National Energy Modeling System (NEMS), an

energy-economy model of U.S. energy markets

designed, developed, and maintained by EIA, which is

used each year to provide projections for EIA’s Annual

Energy Outlook and for other analyses and service

reports. Chapter 1 of this report provides a brief introduction, Chapter 2 describes the analysis cases and

methodology, Chapter 3 provides electricity market

results, and Chapter 4 examines projections for coal, natural gas, and renewable fuels markets and for the U.S.

macroeconomy. Chapter 5 examines the impacts of

alternative assumptions about the possible outcomes of

ongoing litigation related to new source reviews, and

Chapter 6 compares the results of this analysis with

those of other analyses.

Within its Independent Expert Review Program, EIA

arranged for leading experts in the fields of energy and

economic analysis to review earlier versions of this

analysis and provide comment. The reviewers provided

comments on two draft versions of the report and discussed their comments in a joint meeting. All comments

from the reviewers either have been incorporated or

were thoroughly considered for incorporation. As is

always the case when peer reviews are undertaken, not

all the reviewers may be in agreement with all the methodology, inputs, and conclusions of the final report. The

contents of the report are solely the responsibility of EIA.

The assistance of the following reviewers in preparing

the report is gratefully acknowledged:

Dallas Burtraw

Resources for the Future

Howard Gruenspecht

Resources for the Future

David Hawkins

Natural Resources Defense Council

Gordon Hester

Electric Power Research Institute

Hill Huntington

Energy Modeling Forum

Henry Lee

Harvard University

Karen Palmer

Resources for the Future.

The legislation that established EIA in 1977 vested the

organization with an element of statutory independence. EIA does not take positions on policy questions. It

is the responsibility of EIA to provide timely, highquality information and to perform objective, credible

analyses in support of the deliberations of both public

and private decisionmakers. The information contained

herein should be attributed to the Energy Information

Administration and should not be construed as advocating or reflecting any policy position of the U.S. Department of Energy or any other organization.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants iii
The projections in the reference case in this report are not

statements of what will happen but of what might happen, given the assumptions and methodologies used.

The reference case projections are business-as-usual

trend forecasts, given known technology, technological

and demographic trends, and current laws and regulations. Thus, they provide a policy-neutral reference

case that can be used to analyze policy initiatives. EIA

does not propose, advocate, or speculate on future legislative and regulatory changes. All laws are assumed to

remain as currently enacted; however, the impacts of

emerging regulatory changes, when defined, are

reflected.

iv Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
Contents

Page

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2. Analysis Cases and Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Analysis Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

AEO2001 Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

NEMS Representation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

3. Electricity Market Impacts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Capacity Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Generation by Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Electricity Costs and Consumer Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Projected Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Uncertainty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

4. Fuel Market and Macroeconomic Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Coal Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Natural Gas Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Renewable Fuels Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Reference Case Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Emission Reduction Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Sensitivity Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Industry Employment Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Coal Industry Employment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Oil and Gas Employment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Renewables Employment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Macroeconomic Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

5. Potential Impacts of New Source Review Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Current Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Analysis Requested. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

NSR Base Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

Integrated Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants v
Contents (Continued) Page

6. Comparisons With Other Studies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Summary of Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

EPA’s 1999 Emission Reduction Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

EPRI’s Energy-Environment Policy Integration and Coordination Study . . . . . . . . . . . . . . . . . . . . 68

Recent Work: “Cleaner Power” Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

Reference Case Comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

Comparison of Integrated Cases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Selected Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

Appendixes

A. Tables for NOx Cap Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

B. Tables for SO2 Cap Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

C. Tables for CO2 Cap Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

D. Tables for Integrated Cases with 2005 Emission Caps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

E. Tables for Integrated Cases with 2008 Emission Caps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157

F. Tables for SO2 Sensitivity Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 177

G. Tables for CO2 and Integrated Sensitivity Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197

H. Tables for New Source Review Reference Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217

I. Tables for New Source Review Integrated Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 237

J. Letters from Subcommittee on National Economic Growth, Natural Resources, and Regulatory Affairs . . . . 257

K. Pollution Control Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267

Tables

ES1. Analysis Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi

ES2. Assumed Emission Caps for Electricity Generators in Sensitivity Cases . . . . . . . . . . . . . . . . . . . . . . xii

ES3. Projected Additions of Power Plant Emission Controls, 1999-2020 . . . . . . . . . . . . . . . . . . . . . . . . . xiii

ES4. Summary of Projections, 2010 and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xv

ES5. Projected Changes from Reference Case Estimate of Total Costs of Service for U.S. Electricity

Generators, 2005-2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xviii

ES6. Integrated NSR Case Projections, 2000, 2010, and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xxi

1. Congressional Bills With NOx, SO2, or CO2 Power Plant Reduction Requirements. . . . . . . . . . . . . . . . . . 2

2. Analysis Cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

3. 1990 and 1997 Emissions Levels and Assumed Emission Caps for Electricity Generators . . . . . . . . . . . . . . 9

4. Assumed Emission Caps for Electricity Generators in Sensitivity Cases . . . . . . . . . . . . . . . . . . . . . . . 9

5. National Energy Modeling System Energy Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

6. Projected Coal Plant Retirements, 2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

7. Projected Additions of Power Plant Emission Controls, 1999-2020. . . . . . . . . . . . . . . . . . . . . . . . . . 19

8. Projected Emissions from Electric Power Plants, 2010 and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

9. Projected Electricity Generation from Natural-Gas-Fired Power Plants, 2005-2020 . . . . . . . . . . . . . . . . 25

10. Projected Electricity Generation from Renewable Fuels, 2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . . 26

11. Projected Power Plant Emissions Allowance Prices, 2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

12. Projected Changes from Reference Case Estimate of Total Costs of Service for U.S. Electricity

Generators, 2005-2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

13. Projected Minemouth Coal Prices, 2005-2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

14. Projected Coal Production, 2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

15. Projected Delivered Coal Prices to Electricity Generators, 2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . 37

16. Projected Total Expenditures for Natural Gas in the Residential, Commercial, and Industrial Sectors,

2005-2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

17. Projected Impacts on Energy Industry Employment, 2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

18. Projected Macroeconomic Impacts in the Reference Case and Two Integrated Emission Reduction Cases,

2005-2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

19. Plants Named in the November 1999 New Source Review Litigation . . . . . . . . . . . . . . . . . . . . . . . . 58

20. NSR Reference Case Projections, 2000, 2010, and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

21. Integrated NSR Case Projections, 2000, 2010, and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

22. Key Reference Case Projections for Electricity Generation in Four Multi-Emission Studies, 2005, 2007,

and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

23. Key Projections for Integrated Emission Reduction Cases in Four Multi-Emission Reduction Studies,

2005 and 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

vi Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
Figures

ES1. Electricity Generation by Fuel, 1949-1998, and Projections for the Integrated 1990-7% 2005 Case,

1999-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xvi

ES2. Average Projected Changes in Annual Household Electricity Bills Relative to Reference Case Projections,

2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xvi

1. 1997 Emissions, Reference Case Projections for 2010 and 2020, and Target Caps for Electricity Generators . . . . 9

2. Electricity Generation by Fuel, 1949-1998, and Projections for the Reference Case, 1999-2020 . . . . . . . . . . . 17

3. Reference Case Projections of Levelized Costs for New Power Plants, 2005 . . . . . . . . . . . . . . . . . . . . . 18

4. Projected SO2 Allowance Prices, 2000-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

5. Projected SO2 Allowance Prices, 2000, 2010, and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

6. Projected Carbon Fees, 1999-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

7. Projected Capacity Additions by Fuel and Projected Retirements in the Integrated 1990-7% 2005 Case,

1999-2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

8. Projected Annual Capacity Additions in the Integrated 1990-7% 2005 Case, 2000-2020,

Compared with Historical Annual Capacity Additions, 1965-1985 . . . . . . . . . . . . . . . . . . . . . . . . . 23

9. Electricity Generation by Fuel, 1949-1998, and Projections for the Integrated 1990-7% 2005 Case, 1999-2020 . . 25

10. Projected Electricity Prices, 1999-2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

11. Projected Average Annual Changes from Reference Case Power Plant Costs and Revenues in the

SO2 and NOx 2005 Cap Cases, 2005-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

12. Projected Electricity Prices, 2000, 2010, and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

13. Projected Electricity Sales in 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

14. Total Projected U.S. Annual Electricity Bill, 2010 and 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

15. Average Projected Changes in Annual Household Electricity Bills Relative to Reference Case Projections,

2005-2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

16. Projected Sources of Electricity Sector Reductions in Carbon Dioxide Emissions in the

Integrated 1990-7% 2005 Case, 1999-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

17. Projected Natural Gas Consumption for Electricity Generation, 1999-2020 . . . . . . . . . . . . . . . . . . . . . 40

18. Projected Total U.S. Natural Gas Supply, 1999-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

19. Projected Annual Change in Domestic Natural Gas Production, 2000-2005 . . . . . . . . . . . . . . . . . . . . . 42

20. Projected Domestic Wellhead Natural Gas Prices, 1999-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

21. Projected Nonhydroelectric Renewable Generation by Fuel in the Reference Case, 2010 and 2020 . . . . . . . . 49

22. Projected Renewable Electricity Generation by Fuel in the Reference and CO2 1990-7% 2005 Cases, 2020 . . . . 49

23. Coal Mining and Oil and Gas Industry Employment, 1970-2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants vii
Executive Summary

Background

Over the next decade, power plant operators may face

significant requirements to reduce emissions of sulfur

dioxide (SO2), nitrogen oxides (NOx), carbon dioxide

(CO2) and mercury (Hg). At present, neither the future

reduction requirements nor the complete timetable is

known for any of these airborne emissions, and compliance planning is difficult. In response to the Clean Air

Act Amendments of 1990 (CAAA90), operators are now

in the process of making reductions in power plant emissions of SO2 and NOx. Phase II of the CAAA90 SO2

reduction program—lowering allowable SO2 emissions

to an annual cap of 8.95 million tons—became effective

on January 1, 2000, and more stringent NOx emissions

standards setting new emission limits for boilers also

took effect in 2000.

States are also beginning efforts to address visibility

problems (regional haze) in national parks and wilderness areas throughout the country. Because power plant

emissions of SO2 and NOx contribute to the formation of

regional haze, they may have to be further reduced to

improve visibility in some areas. In the near future, it is

expected that new national ambient air quality standards for ground-level ozone and fine particulates may

necessitate additional reductions in NOx and SO2.

To reduce ozone formation, the U.S. Environmental Protection Agency (EPA) has promulgated a multi-State

summer season cap on power plant NOx emissions that

would take effect in 2004. The fine particulate issue is

still being studied, but reduced SO2 emissions from

power plants could be required as early as 2007 to

address it. In addition, on December 15, 2000, the EPA

decided that Hg emissions need to be reduced; and if the

United States ratifies the Kyoto Protocol or a similar

international greenhouse gas mitigation treaty, energyrelated CO2 emissions would also have to be reduced.

With changing standards on different timetables, comprehensive compliance planning is difficult. It can take

several years to design, license, and construct new

power plants and emission control equipment, which

may then be in operation for 30 years or more. As a

result, power plant operators must look far into the

future to evaluate the economics of new investment

decisions. Changing emission standards with different

timetables add considerable uncertainty to investment

planning decisions. An option that looks attractive to

meet one set of SO2 and NOx standards may not be

attractive if further reductions are required in a few

years. Similarly, economical options for reducing SO2

and NOx may not be optimal if Hg and CO2 emissions

must also be reduced at a later date. Further complicating planning, some investments reduce multiple emissions simultaneously, such as SO2 and Hg, making such

investments more attractive under some circumstances.

As a result, power plant owners are wary of making

investments that may prove unwise a few years hence.

Recently, plans have been proposed requiring coordinated multi-emission reductions. Several bills that have

been introduced in Congress contain such provisions:

S. 1369, the Clean Energy Act of 1999, introduced by Senator Jeffords; S. 1949, the Clean Power Plant and Modernization Act of 1999, introduced by Senator Leahy;

H.R. 2900, the Clean Smokestacks Act of 1999, introduced by Congressman Waxman; H.R. 2645, the Consumer, Worker, and Environmental Protection Act of

1999, introduced by Congressman Kucinich; and H.R.

2980, the Clean Power Plant Act of 1999, introduced by

Congressman Allen. Each of these bills contains provisions to reduce power plant emissions of NOx, SO2, CO2

and Hg over the next decade. The bills use different

approaches—traditional technology-specific emission

standards, generation performance standards, explicit

emission caps, or combinations of the three—but all call

for significant emission reductions.

This report provides analysis of the potential impacts of

efforts to reduce NOx, SO2, and CO2 emissions from

power plants. It examines the potential costs, to the

energy sector and to consumers, of meeting the specified

emission caps. It does not address the potential benefits

of reduced emissions, such as might be associated with

reduced health care costs, because EIA does not have

expertise in this area. Readers should refer to the EPA

and others for analysis of the potential benefits of emissions reductions. The bibliography for this report

includes several studies that address the benefits of

reducing emissions.1

The results in this report should not be interpreted as

providing estimates of the electricity price changes and

other impacts that would result from the enactment of

the legislative proposals discussed previously. This

analysis assumes a cap-and-trade mechanism, patterned

after the system for SO2 allowances implemented in

CAAA90, for modeling all emission reductions in all

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants ix

1Reports by Burtraw, Chestnut, and the EPA cited in the bibliography of this report include discussions of health benefits.
scenarios. The legislative proposals cited above include

a variety of mechanisms to achieve emission reductions.

Because the policy mechanisms used to implement

emission reduction programs can affect compliance

decisions and the resulting electricity prices, analysis of

the specific policies called for in each proposal would be

required to address their impacts.

The analysis was conducted at the request of the Subcommittee on National Economic Growth, Natural

Resources, and Regulatory Affairs of the U.S. House of

Representatives Committee on Government Reform. In

its request the Subcommittee asked the Energy Information Administration (EIA) to analyze the potential costs

of various multi-emission reduction strategies to reduce

the air emissions from electric power plants. The Subcommittee requested that EIA examine cases with alternative NOx, SO2, CO2, and Hg emission reductions and

renewable portfolio standard (RPS) requirements. The

Subcommittee specified that the NOx, SO2, and CO2

analysis should be done first if the Hg analysis could not

be completed until a later date. This report examines

NOx, SO2, and CO2 emission limits. It does not address

the potential impact of requirements to reduce power

plant Hg emissions. A second volume, to be published in

early 2001, will examine Hg emission limits and RPS

requirements.

Cases Analyzed

A reference case and 10 basic analysis cases are examined in this report (Table ES1). Each case differs in terms

of the specific emission caps imposed on the power sector and when they are imposed. Two NOx cap cases look

at the impacts of reducing power sector NOx emissions

to 75 percent below the level emitted in 1997. In the NOx

2005 case, the cap on NOx emissions is assumed to take

effect in 2005; in the NOx 2008 case, the cap is assumed to

take effect in 2008. Two SO2 cap cases assume similar

reductions in power sector SO2 emissions. Two CO2 cap

cases examine the impacts of reducing power sector CO2

emissions to 1990 levels by 2005 or 2008 and, in both

cases, further reducing them to 7 percent below that

level, on average, between 2008 and 2012. Finally, four

integrated cases examine the impacts of combining the

various assumptions from the other cases for power sector emission caps on NOx, SO2, and CO2. In each of the

cases it is assumed that the emission reduction programs

would operate as “cap and trade” programs, with power

plant operators required to reduce their emissions or

purchase sufficient allowances to cover them.

Four additional cases with alternative assumptions

about the potential impacts of ongoing New Source

Review (NSR) litigation against the owners of coal-fired

power plants are also analyzed. The Subcommittee

requested these cases in a letter dated September 25,

2000 (see Appendix J). The first case, referred to as the

NSR 32 case, uses all of EIA’s reference case assumptions

combined with the assumption that the owners of each

of the 32 coal plants being sued for violating CAAA90

will be required to add emission control equipment to

reduce NOx and SO2 by 2005 in order to continue operating them. The second case, referred to as the NSR All

case, again uses all of EIA’s reference case assumptions

but assumes that all coal-fired plants in addition to the

32 being sued will be required to have control equipment added to reduce NOx and SO2 emissions by 2010.

The final two cases, referred to as the integrated NSR 32

and integrated NSR All cases, combine the assumptions

of the NSR 32 and NSR All cases with those of the integrated 1990-7% 2005 case. In both of the NSR All cases it

is assumed that the 32 plants currently being sued must

still make their compliance decisions by 2005.

In addition to the cases requested by the Subcommittee,

this report includes two cases that assume less stringent

emission caps for SO2 and CO2 and an integrated case

that combines the less stringent targets (Table ES2).

These cases were analyzed to examine the sensitivity of

the results to the emission targets chosen. The emission

cap in the SO2 sensitivity case was set halfway between

the estimated emissions for 2000 and the caps requested

by the Subcommittee—roughly a 50-percent reduction

from 1997 levels, rather than the 75-percent reduction

specified by the Subcommittee. For CO2 a similar

approach was used. The CO2 cap in 2005 in the CO2 sensitivity case was set to halfway between the estimated

emissions in 2000 and the 1990 level. The cap was then

lowered further over the 2008 to 2012 time period, to

halfway between the estimated 2000 emissions and 7

percent below the 1990 level. Using this approach, the

CO2 cap in 2005 in the CO2 sensitivity case was assumed

to be 12 percent above 1990 levels, before declining to 7

percent above 1990 levels over the 2008 to 2012 time

period.

Analysis Approach

In this analysis, it is assumed that the programs set up to

reduce NOx, SO2, and CO2 emissions from power plants

will operate like the existing SO2 program established in

Title IV of CAAA90. Marketable emission allowances or

permits are assumed to be allocated to power plant operators at no cost (and therefore no money would be collected by the government). No assumption is made

about the specific allocation methodology to be used,

other than that it is a fixed allocation (does not change

from year to year) and the total amount allocated equals

the national emission targets for NOx, SO2, and CO2.

Holders of allowances are assumed to be free to use

them to cover emissions from their own power plants or

sell them to others who need them.

x Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
The analysis presented in this report should be seen as

an examination of the steps that power suppliers and

consumers might take to meet the emission caps specified by the Subcommittee. The specific design of the

cases—timing, emission cap levels, policy instruments

used, etc.—are important and should be kept in mind

when the results are reviewed. For example, it is

assumed that the market participants—power suppliers, consumers, and coal, gas, and renewable fuel

suppliers—would become aware of the impending

emission caps before their target dates and begin to take

action to meet the future targets.

If the timing of market response were different, the

results would change. In previous EIA studies that

looked at alternative program start dates for imposing a

CO2 emissions cap (or carbon cap), an earlier start date

and longer phase-in period were found to smooth the

transition of the economy to the longer run target.2

In addition, this study is not intended to be an analysis

of any of the specific congressional bills that have been

proposed, and the impacts estimated here should not

be considered as indicating the consequences of

specific legislative proposals. All the proposals include

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants xi

Table ES1. Analysis Cases

Case Name

Electric Power Sector Emission Caps

Compliance Dates

RPS

NO Requirement x SO2 CO2 Hg

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . . . . . . 75% below

1997 level

CAAA90 cap None None Start 2002; meet

target by 2005

None

NOx 2008 . . . . . . . . . . . . . . . . . . . 75% below

1997 level

CAAA90 cap None None Start 2002; meet

target by 2008

None

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

75% below

1997

None None Start 2002; meet

target by 2005

None

SO2 2008 . . . . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

75% below

1997

None None Start 2002; meet

target by 2008

None

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap 7% below

1990 level

None Start 2002; 1990

level by 2005; 7%

below 1990 level in

2008-2012

None

CO2 1990-7% 2008 . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap 7% below

1990 level

None Start 2002; 1990

level by 2008; 7%

below 1990 level in

2008-2012

None

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . 75% below

1997 level

75% below

1997 level

1990 level None Start 2002; meet

target by 2005

None

Integrated 1990-7% 2005 . . . . . . . 75% below

1997 level

75% below

1997 level

7% below

1990 level

None Start 2002; NOx

/SO2

targets by 2005; CO2

1990 level by 2005;

7% below 1990 level

in 2008-2012

None

Integrated 2008 . . . . . . . . . . . . . . 75% below

1997 level

75% below

1997 level

1990 level None Start 2002; meet

target by 2008

None

Integrated 1990-7% 2008 . . . . . . . 75% below

1997 level

75% below

1997 level

7% below

1990 level

None Start 2002; NOx

/SO2

targets by 2008; CO2

1990 level by 2008,

7% below 1990 level

in 2008-2012

None

Notes: CAAA90 cap refers to the 8.95 million ton SO2 cap established in Title IV of the Clean Air Act Amendments of 1990. CAAA90 standards refer

to the boiler emission standards for NOx established in Title V of the Clean Air Act Amendments of 1990. NOx SIP Call refers to the 19-State summer

season cap on NOx emissions to begin in 2004. The time period for reaching the CO2 target of 7 percent below 1990 levels is between 2008 and 2012.

The cap is then held constant at that level through 2020. The emission caps are phased in gradually until the target cap is met on the specified date.

Source: See requesting letters in Appendix J.

2Energy Information Administration, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity, SR/OIAF/98-03 (Washington, DC, October 1998); and Analysis of the Impacts of an Early Start for Compliance with the Kyoto Protocol, SR/OIAF/99-02 (Washington,

DC, July 1999).
provisions other than the emission caps studied in

this analysis. Moreover, some of the actions projected to

be taken to meet the emission caps in this analysis may

eventually be required because of ongoing environmental programs whose requirements currently are

not specified but for which legislation has been

promulgated.

Key Findings

• When emissions caps are examined individually,

power companies are projected to invest primarily in

emission control equipment to comply with the NOx

and SO2 caps; however, to comply with the CO2 cap

they are expected to shift dramatically away from

coal to natural gas and, to a lesser extent, renewables.

• The stringency of the emission targets influences the

projected impact on electricity and natural gas

prices.

• The impacts of meeting the NOx and SO2 caps are not

projected to have a large effect on electricity

prices—generally 1 percent or so above the prices

expected in the reference case.

• The projected price impacts of meeting the CO2 cap

are much larger than those of meeting the NOx and

SO2 caps.

• The CO2 allowance prices (expressed in dollars per

metric ton carbon equivalent) projected in this analysis are generally lower than those projected in studies of efforts to meet the target from the Kyoto

Protocol over the whole economy rather than just in

the power sector.

• When emissions caps are examined together, actions

taken to meet the CO2 cap are expected to overshadow those taken to reduce NOx and SO2

emissions.

• Using an integrated approach—setting caps on

power sector NOx, SO2, and CO2 emissions at the

same time—is projected to lead to lower total costs

than addressing each emission one at a time.

• If existing coal plants are required to add emission

control equipment, NOx and SO2 emissions would

be dramatically reduced.

• There is considerable uncertainty about whether the

changes projected in this analysis could be accomplished in the relatively short time periods

assumed—particularly to meet 2005 emission

targets.

Electricity Market Impacts

The emission caps specified by the Subcommittee are

projected to affect all aspects of the electricity business,

especially in cases that include a CO2 cap. The caps affect

capacity planning and retirement decisions, investments in emission control equipment, fuel choices for

generation, and electricity prices. One issue that affects

all the cases, especially those with 2005 compliance

dates, is whether the time lines proposed are realistic. To

meet the emission caps specified by the Subcommittee,

electricity markets together with their associated fuel

markets—coal, natural gas, renewables, and other

fuels—would need to make rapid changes, which may

be difficult to accomplish in a short time.

xii Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table ES2. Assumed Emission Caps for Electricity Generators in Sensitivity Cases

Case Name

Electric Power Sector Emission Caps

Compliance Dates

RPS

NO Requirement x SO2 CO2 Hg

SO2 Sensitivity . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

50% below

1997 level

None None Start 2002; meet

target by 2005

None

CO2 Sensitivity . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap 7% above

1990 level

None Start 2002; reach

10% above 1990

CO2 level in 2005

and 7% above 1990

level in 2008-2012

None

Integrated Sensitivity. . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

50% below

1997 level

7% above

1990 level

None Start 2002; NOx/SO2

targets by 2005; for

CO2, reach 10%

above 1990 level in

2005 and 7% above

1990 level in

2008-2012

None

Notes: CAAA90 cap refers to the 8.95 million ton SO2 cap established in Title IV of the Clean Air Act Amendments of 1990. CAAA90 standards refer

to the boiler emission standards for NOx established in Title V of the Clean Air Act Amendments of 1990. NOx SIP Call refers to the 19-State summer

season cap on NOx emissions to begin in 2004. The time period for reaching the CO2 target 7 percent above 1990 levels is between 2008 and 2012.

The emission caps are phased in gradually until the target cap is met on the specified date.

Source: Office of Integrated Analysis and Forecasting.
Compliance Decisions

In all the analysis cases, emission caps are projected to

have significant impacts on coal-fired power plants,

generally leading to lower utilization rates and earlier

retirements of existing coal plants than those projected

in the reference case, especially when CO2 emission caps

are assumed. In the NOx and SO2 cap cases only a small

number of coal plants are expected to be retired; the vast

majority are projected to control emissions and continue

operating. The main compliance option in the NOx and

SO2 cap cases is the addition of emission control equipment: selective noncatalytic reduction (SNCR) and

selective catalytic reduction (SCR) equipment to reduce

NOx emissions, and flue gas desulfurization equipment

(scrubbers) to reduce SO2 (Table ES3). As expected, the

projected need for emission control equipment is sensitive to the assumptions about the levels at which emissions would be capped.

The amount of emission control equipment projected to

be needed in the NOx and SO2 cap cases, particularly

those with 2005 compliance dates, could cause system

operation problems under some conditions. Typically,

when new emissions controls are added, particularly

SCRs, a plant must be off line for a time so that final

connections can be made. The amount of capacity to

which emission control equipment is expected to be

added in these cases could lead to a concentration of

connection outages in the few years just before the

emission caps take effect. This could lead to a large

amount of capacity being temporarily unavailable,

increasing the possibility of short-term imbalances of

supply and demand caused by unexpected demand

spikes and/or unplanned outages of other units. Such

imbalances could have significant impacts on wholesale

power prices, and in extreme cases they could lead to

power outages.

Several recent studies have looked into whether the outage times (beyond normal maintenance outages)

required to make final connections for equipment

needed to meet the CAAA90 NOx State implementation

plan (SIP) call might lead to system operational and reliability problems. If a decision were made to pursue the

stringent NOx and SO2 caps analyzed in this report without a CO2 reduction requirement, additional analysis of

this issue would be needed.

In the SO2 sensitivity case, the less stringent emission

caps examined are projected to lead to a lower amount of

capacity to which emission control equipment would be

added, as compared with the amounts expected in the

more stringent cases. The need for new SO2 emission

control equipment is projected to be much lower in the

integrated sensitivity case, because the CO2 cap causes

enough switching from coal to gas to allow the electricity generation sector to meet the assumed SO2 caps

without adding much additional emission control

equipment.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants xiii

Table ES3. Projected Additions of Power Plant Emission Controls, 1999-2020

(Gigawatts)

Analysis Case

Emission Control Technology

SNCR SCR FGD

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 90 15

NOx Cap Cases

NOx 2005. . . . . . . . . . . . . . . . . . . . . . . . . . 59 252 14

NOx 2008. . . . . . . . . . . . . . . . . . . . . . . . . . 60 243 15

SO2 Cap Cases

SO2 2005. . . . . . . . . . . . . . . . . . . . . . . . . . 32 117 128

SO2 2008. . . . . . . . . . . . . . . . . . . . . . . . . . 27 124 130

SO2 Sensitivity. . . . . . . . . . . . . . . . . . . . . . 36 96 52

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . . . . . . . . 16 42 0

CO2 1990-7% 2008 . . . . . . . . . . . . . . . . . . 22 54 0

CO2 Sensitivity . . . . . . . . . . . . . . . . . . . . . 26 54 0

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . . . . . . . . 56 157 21

Integrated 1990-7% 2005 . . . . . . . . . . . . . 49 147 17

Integrated 2008 . . . . . . . . . . . . . . . . . . . . . 48 123 23

Integrated 1990-7% 2008 . . . . . . . . . . . . . 38 108 18

Integrated Sensitivity . . . . . . . . . . . . . . . . . 26 60 8

SNCR = selective noncatalytic reduction. SCR = selective catalytic reduction. FGD = flue gas desulfurization (scrubbers).

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, MCSO205H.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A, FDPOL05.D121300A,

FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.
Compliance decisions made by power plant operators

and their impacts on generation costs and consumer

electricity prices could be very different if the various

emissions caps were imposed together or one at a time

on different schedules. Power plant owners would be

expected to rely heavily on investments in emission control technologies to comply with the NOx and SO2 caps if

they were introduced individually; but if the NOx, SO2,

and CO2 caps were combined, heavy investments in

NOx and SO2 emission control equipment would not be

expected to be part of the most economical compliance

strategy. Rather, many of the coal-fired power plants

where such equipment might have been added are projected to be retired if a stringent CO2 cap is imposed.

New natural gas plants, and to a lesser extent renewable

plants, are projected to be built, and the lives of existing

nuclear plants are projected to be extended.

The projected impacts on capacity expansion and retirement, fuel use (generation), and consumer electricity

prices are similar in the CO2 cap and integrated cases

(Table ES4). When the three emission caps are assumed

to be imposed in concert, efforts to comply with the CO2

cap are projected to have the most significant effect, as

can be seen by comparing the results for the CO2 cap and

integrated cases. When a CO2 cap is assumed, large

investments in NOx and SO2 emission control equipment, beyond the levels added in the reference case, are

not expected to be needed, because the amount of

coal-fired capacity projected to be retired in order to

meet the hypothesized CO2 cap is sufficient to meet the

NOx and SO2 caps with little additional effort.

The move from coal to natural gas in the cases with CO2

caps is expected to be significant (Figure ES1). Increased

generation from natural gas is projected to be the primary compliance option in the cases that include CO2

caps. By 2010, natural gas consumption for electricity

generation is projected to be as high as 11.8 trillion cubic

feet in the integrated cases, much higher than the 6.7 trillion cubic feet projected in the reference case. The share

of generation coming from gas is projected to grow from

15 percent in 1999 to as high as 45 percent in 2010 and 56

percent in 2020 in the integrated cases. Again, electricity

markets and the associated markets for coal, natural gas,

renewables, and other fuels would need to make rapid

changes, which could prove difficult to accomplish in a

short time. In addition, increasing dependence on natural gas for electricity production could lead to greater

volatility in electricity prices as they move with changes

in gas prices.

Increased generation from renewables is expected to

play a role in cases with CO2 caps, but their contribution

is much smaller than that of natural gas. In cases without

a CO2 cap, projected additions of renewable generating

capacity are virtually unchanged from those projected in

the reference case. When a CO2 cap is assumed, carbon

allowance fees are expected to increase the costs of

building and operating generators using fossil fuels,

making renewable technologies more economically

attractive. Geothermal, biomass, and wind are expected

to show the largest generation increases in the cases with

CO2 caps, and total generation from nonhydroelectric

renewables is expected to provide as much as 8 percent

of total electricity generation in 2020 in the integrated

cases, substantially higher than the 3-percent share projected in the reference case.

Cost and Price Impacts

Power plant operators are expected to incur significant

costs to comply with the emission caps in the NOx and

SO2 cap cases, but they may not be able to pass all the

costs on to consumers through higher electricity prices.

In competitive markets, cost increases do not directly

translate into price increases. Electricity generation

prices in competitive markets are set by the operating

costs of the marginal plant—the plant running with the

highest cost during a given period. Cost increases that

do not affect the operating costs of the marginal plant

will not affect prices. In many cases, adding emission

control equipment to a plant involves mainly capital

expenditures and leads to little change in the plant’s

operating costs. In addition, many of the plants to which

the controls would be added are not price-setting plants.

As a result, the addition of emission control equipment

would not always lead directly to higher electricity

prices, even though significant investments would be

made.

In the NOx cap cases, power plant operators are projected to spend more than $17 billion to add emission

control equipment, much higher than the $10 billion

expected in the reference case. These expenditures represent the capital costs of installing the equipment. The

increased costs for power plant operators, if incurred in

generation markets with cost-of-service regulation,

would be passed on directly to consumers in electricity

prices. In competitively priced markets, however, the

higher costs would be passed on to consumers only if

they increased the operating costs of the generating

plants that set the market price for power. For example,

if SCR equipment were added to reduce NOx emissions

from a coal plant that did not set the market price for

power, the costs of installing and operating the equipment would not be passed on to consumers as long as

the plant’s operating costs remained below the market

price.

In the SO2 cap cases, SO2 allowance prices are projected

to rise dramatically, reaching as high as $735 per ton in

2010 and $1,125 per ton in 2020, because of the need to

add scrubbers to plants using relatively low-sulfur coal.

In competitive electricity markets, however, the costs of

adding and operating scrubbers would not affect the

xiv Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
price of electricity if the plant did not set the market

price. In such instances, the scrubber costs would reduce

the profitability of the plant, but it might still remain economical to operate the facility.

The projections for SO2 allowance prices are sensitive to

variations in the assumed SO2 emission target. SO2

allowance prices are projected to be $735 per ton in 2010

in the SO2 2005 case, but they are projected to be less

than half that value, $300 per ton, in the SO2 sensitivity

case. The differences in the projections result from the

less stringent emission target assumed in the SO2 sensitivity case, which reduces the expected need to add

emission controls at plants using relatively low-sulfur

coal.

In all the analysis cases, consumers are projected to see

higher electricity prices than those projected in the reference case (Figure ES2). In the NOx cap cases the overall

impact on electricity prices is projected to be fairly small,

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants xv

Table ES4. Summary of Projections, 2010 and 2020

Analysis Case

Coal-Fired

Electricity

Generation

(Billion

Kilowatthours)

Natural-GasFired

Electricity

Generation

(Billion

Kilowatthours)

Carbon

Allowance Fee

(1999 Dollars

per Metric Ton

Carbon

Equivalent)

Natural Gas

Wellhead Price

(1999 Dollars

per Thousand

Cubic Feet)

Electricity

Price

(1999 Cents

per

Kilowatthour)

Annual

Household

Electricity Bill

(1999 Dollars)

Total

Electricity

Revenues

(Billion 1999

Dollars)

2010 Results

Reference. . . . . . . . . . . . . . . . 2,284 1,123 NA 2.68 5.9 927 243

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . 2,237 1,161 NA 2.68 5.9 933 245

NOx 2008 . . . . . . . . . . . . . . 2,237 1,164 NA 2.72 5.9 934 245

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . 2,198 1,195 NA 2.67 5.9 937 246

SO2 2008 . . . . . . . . . . . . . . 2,259 1,146 NA 2.63 5.9 929 243

SO2 Sensitivity . . . . . . . . . . 2,237 1,169 NA 2.72 5.9 932 244

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . 1,113 1,859 143 4.36 8.3 1,126 319

CO2 1990-7% 2008 . . . . . . 1,055 1,922 139 4.13 8.2 1,126 318

CO2 Sensitivity . . . . . . . . . . 1,454 1,609 102 3.48 7.6 1,070 297

Integrated Cases

Integrated 2005 . . . . . . . . . 1,276 1,746 114 3.83 7.9 1,094 306

Integrated 1990-7% 2005. . 1,135 1,839 134 4.33 8.4 1,128 320

Integrated 2008 . . . . . . . . . 1,261 1,789 108 3.75 7.7 1,087 303

Integrated 1990-7% 2008. . 1,067 1,935 126 4.16 8.2 1,121 316

Integrated Sensitivity . . . . . 1,444 1,617 101 3.52 7.6 1,074 299

2020 Results

Reference. . . . . . . . . . . . . . . . 2,370 1,866 NA 3.14 6.0 993 288

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . 2,335 1,894 NA 3.18 6.0 996 289

NOx 2008 . . . . . . . . . . . . . . 2,328 1,902 NA 3.15 6.0 995 289

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . 2,329 1,911 NA 3.20 6.0 995 289

SO2 2008 . . . . . . . . . . . . . . 2,339 1,901 NA 3.25 6.1 1,005 293

SO2 Sensitivity . . . . . . . . . . 2,331 1,904 NA 3.17 6.0 996 289

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . 885 2,704 141 4.22 7.9 1,149 347

CO2 1990-7% 2008 . . . . . . 876 2,748 139 4.38 7.9 1,153 350

CO2 Sensitivity . . . . . . . . . . 1,191 2,591 112 4.00 7.5 1,121 337

Integrated Cases

Integrated 2005 . . . . . . . . . 1,000 2,752 113 4.04 7.6 1,127 338

Integrated 1990-7% 2005. . 852 2,774 130 4.30 7.8 1,146 345

Integrated 2008 . . . . . . . . . 998 2,746 116 4.32 7.7 1,140 343

Integrated 1990-7% 2008. . 834 2,816 129 4.42 7.9 1,148 347

Integrated Sensitivity . . . . . 1,159 2,623 115 4.06 7.6 1,129 339

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, MCSO205H.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A, FDPOL05.D121300A,

FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.
xvi Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

1950 1960 1970 1980 1990 2000 2010 2020

0

1,000

2,000

3,000

4,000

5,000

6,000

Billion Kilowatthours

Coal

Gas

Oil

Nuclear

Hydropower

Renewable/Other History Projections

Figure ES1. Electricity Generation by Fuel, 1949-1998, and Projections for the Integrated 1990-7% 2005

Case, 1999-2020

Sources: History: Energy Information Administration, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: National Energy Modeling System, run FDP7B05.D121300B.

2005 2010 2020

0

50

100

150

200

250

1999 Dollars per Year

NOx 2005 NOx 2008 SO2 2005 SO2 2008

CO2 1990-7% 2005 CO2 1990-7% 2008 Integrated 2005 Integrated 1990-7% 2005

Integrated 2008 Integrated 1990-7% 2008

Figure ES2. Average Projected Changes in Annual Household Electricity Bills Relative to Reference Case

Projections, 2005-2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.
approximately 1 percent above the reference case projection in 2010. Similarly, projected average electricity

prices in 2010 in the SO2 cap cases are only 1 percent

above the reference case projection. In these cases, the

projected costs of compliance are not large relative to the

size of the industry, and not all the costs of compliance

are expected to be passed on to consumers. As noted

previously, however, installing the amount of control

equipment projected to be needed in these cases could

cause problems if it has to be done over a relatively short

time period. The 2005 values shown in Figure ES2 do not

incorporate the potential impact on prices of a large

amount of capacity being out of service for retrofitting

with emission control equipment.

In the cases with CO2 caps, carbon allowance fees are

expected to vary depending on the stringency of the

emission cap. Among the cases with CO2 caps, carbon

allowance fees are projected to range between $71 and

$120 per metric ton carbon equivalent in 2005, between

$108 and $143 in 2010, and between $112 and $141 in

2020. In the CO2 sensitivity and integrated sensitivity

cases, the less stringent CO2 cap is projected to lead to

carbon allowance fees that are lower than those projected in the comparable CO2 1990-7% 2005 and integrated 1990-7% 2005 cases. In 2010, the carbon allowance

fees projected in the CO2 sensitivity case are between $37

and $41 per metric ton carbon equivalent less than those

projected in the comparable cases with the more stringent CO2 caps.

The impact on electricity prices is projected to be much

larger in the CO2 cap and integrated cases than in the

NOx and SO2 cap cases. Because there are currently no

commercially available technologies for removing and

storing (sequestering) CO2 and none is expected to be

available during the projection period, the only way to

make large reductions in CO2 emissions is to reduce the

consumption of fuels with relatively high carbon content and improve the efficiency of energy production

and use. The combination of the projected CO2 allowance costs, projected increases in operating costs for all

fossil-fired generators, and projected increases in wellhead natural gas prices as power companies switch from

coal to gas would lead to significantly higher electricity

prices. Unlike in the NOx and SO2 cases, the operating

costs for many of the plants setting the electricity market

price are expected to increase, and consumer electricity

prices are expected to increase with them.

In the integrated cases, projected electricity prices in

2010 range from 30 to 43 percent higher than in the reference case. Because electricity prices are expected to

decline in the reference case, the projected price changes

in the integrated cases are not as large when compared

with current prices. For example, when compared to the

1999 price, electricity prices in the integrated cases are

projected to be between 15 and 26 percent higher in 2010

and between 14 and 20 percent higher in 2020. The low

end of the range is projected in the cases that assume a

CO2 emission cap at the 1990 level; the high end is projected in the cases that assume a cap of 7 percent below

the 1990 level. For the average household, annual expenditures on electricity are projected to be between $147

and $201 (16 to 22 percent) higher than in the reference

case in the integrated cases in 2010 and between $134

and $160 (14 to 16 percent) higher in 2020.

The impact of the assumed CO2 emission caps on electricity prices is projected to be fairly sensitive to the

stringency of the caps. For example, in the CO2 1990-7%

2005 case, the price of electricity in 2010 is projected to be

42 percent above the reference case level. In the less

stringent CO2 sensitivity case, however, the difference is

expected to be only 29 percent. Similarly, average electricity prices in 2010 in the integrated 1990-7% 2005 case

are projected to be 43 percent higher than projected in

the reference case, but in the integrated sensitivity case

they are projected to be only 30 percent above the reference case projection.

Consumers are also projected to see higher natural gas

prices because of the power sector’s efforts to reduce

emissions, especially CO2 emissions. The increased use

of natural gas in the power sector is projected to cause

higher natural gas prices in all sectors of the economy,

including the residential, commercial, and industrial

sectors. In the integrated 1990-7% 2005 case, the Nation’s

natural gas bill, excluding gas used for electricity generation, is projected to be almost $25 billion higher than in

the reference case in 2010. The $25 billion total estimate

includes $6 billion for the residential sector, $4 billion for

the commercial sector, and $15 billion for the industrial

sector.

A coordinated approach to reducing power sector NOx,

SO2, and CO2 emissions such as that represented in the

integrated cases in this report should lead to lower

overall costs than would be incurred with different timetables for each of the emissions. As shown in this report,

the compliance decisions that are projected when the

NOx and SO2 caps are examined alone are different from

those projected when the three emission caps are

assumed to be combined. The exact savings would

depend on the particular scenarios analyzed. The key

factor is the timing of the NOx and SO2 caps relative to

the timing of the CO2 cap. On one hand, if NOx and SO2

caps were imposed and then followed shortly by a CO2

cap that was unexpected, substantial investments could

be made in control equipment that would later prove

uneconomical. On the other hand, if the CO2 cap preceded the NOx and SO2 caps, the potential for uneconomical investments in control equipment would

appear to be small.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants xvii
A rough measure of the maximum potential for savings

in a coordinated approach would be to compare the cost

increase projected in an integrated case with the sum of

the cost increases projected in the cases that impose

emission caps individually. Table ES5 shows the calculations for the integrated 1990-7% 2005 case and the

standalone NOx 2005, SO2 2005, and CO2 1990-7% 2005

cases with and without allowance fees. The values without allowance fees (often referred to as “resource costs”)

represent just the expected increases in expenditures on

fuel and other operating costs and the increased investments in new emission control equipment and new

capacity. The projected savings in total resource costs

are higher in the early years—as much as $6 billion in

2006—because in the integrated cases the expected

investments in control equipment to remove NOx and

SO2 to meet the respective 2005 caps are less than those

expected in the NOx and SO2 cap cases. After 2015, the

projected savings in total resource costs are small. In the

integrated case many of the plants to which controls

might have been added are expected to be retired.

The projected higher prices for electricity and natural

gas in the CO2 cap and integrated cases would be

expected to have an impact on the U.S. economy; however, because the emission caps are assumed to be

applied only to electricity producers rather than to all

energy producers and consumers, the impact is not

expected to be large. In 2005 the projected impact on the

U.S. unemployment rate in the integrated 1990-7% case

is 0.6 percentage points above the reference case. In the

same case, the projected impact on the Nation’s gross

domestic product (GDP) is projected to be a decline of

1.2 percent from the reference case projection. By 2020

the economic effect is projected to be reduced to a

decline of 0.2 percent from the reference case projection.

Fuel Market Impacts

Coal

Because coal-fired power plants are the major power

sector emitters of NOx, SO2, and CO2, compliance with

the emission caps modeled for this study would be

expected to have a major impact on coal consumption

and production, both nationally and regionally. The

impacts are projected to be relatively small in the NOx

xviii Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table ES5. Projected Changes from Reference Case Estimate of Total Costs of Service for U.S. Electricity

Generators, 2005-2015

(Billion 1999 Dollars)

Year NOx 2005 Case SO2 2005 Case CO2 2005 Case

Sum: NOx 2005,

SO2 2005, and

CO2 2005 Cases

Integrated 1990-7% Case

Projected Costs Projected Savings

Including Allowance Costs in Total Costs

2005 . . . . . . 3 3 77 82 77 5

2006 . . . . . . 4 3 70 77 68 9

2007 . . . . . . 3 4 77 83 74 9

2008 . . . . . . 3 3 89 96 87 8

2009 . . . . . . 2 4 86 92 88 5

2010 . . . . . . 2 4 88 94 86 9

2011 . . . . . . 2 4 87 94 84 9

2012 . . . . . . 3 5 90 97 87 11

2013 . . . . . . 2 3 89 94 89 5

2014 . . . . . . 3 3 89 96 87 9

2015 . . . . . . 2 3 85 90 86 5

Excluding Allowance Costs from Total Costs

2005 . . . . . . 2 3 21 26 24 2

2006 . . . . . . 3 4 20 28 22 6

2007 . . . . . . 2 4 22 28 23 5

2008 . . . . . . 3 3 27 32 28 4

2009 . . . . . . 2 3 26 30 28 2

2010 . . . . . . 2 3 28 33 28 5

2011 . . . . . . 1 3 28 32 29 3

2012 . . . . . . 1 3 29 34 29 5

2013 . . . . . . 1 2 30 33 30 3

2014 . . . . . . 2 2 31 36 31 4

2015 . . . . . . 1 2 29 33 32 1

Note: Totals may not equal sum of components due to independent rounding.

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCSO205.D121300A, FDC7B05.D121300A, and

FDP7B05.D121300B.
cap cases but more significant when SO2 or CO2 caps are

assumed.

In the two primary SO2 cap cases, reductions in coalfired generation and coal consumption (on a Btu basis)

are projected through 2020, as other fuels replace coal.

Coal mines that supply medium- or high-sulfur coal are

projected to have production declines, leading to lower

projected minemouth prices for coal from those sources

relative to the prices projected in the reference case. To

meet the SO2 emission caps, coal consumption is projected to shift dramatically to favor coal originating from

the Powder River Basin in Wyoming and Montana,

where surface mines working thick coal seams currently

achieve levels of labor productivity that are on the order

of 6 to 10 times greater than those in many other regions.

In the CO2 cap cases, substantial reductions in coal consumption are projected, with corresponding drops in the

projections for coal production. To reduce CO2 emissions, the power sector is expected to move from coal to

natural gas and, to a lesser extent, renewables. Because

coal has a carbon content more than 70 percent higher

per Btu than that of natural gas, the carbon allowance

fees in these cases are projected to make the continued

operation of many existing coal plants uneconomical.

To continue using coal in the CO2 cap cases, a power

plant operator would have to pay for the coal and for the

CO2 allowances needed to cover the emissions that

would result from burning it. In the CO2 1990-7% 2005

case, the delivered price of coal in 2010 is projected to

average $0.92 per million Btu, and CO2 allowances for

coal are projected to cost $3.65 per million Btu of energy

obtained from coal combustion ($143 per metric ton carbon equivalent). Thus, the effective cost of using coal is

projected to be $4.57 per million Btu in 2010 and $4.41

per million Btu in 2020 in the CO2 1990-7% 2005 case.

The corresponding costs in the reference case are projected to be $1.05 and $0.98 per million Btu in 2010 and

2020, respectively. In all the cases with CO2 caps, continued use of coal is projected to be uneconomical for many

plants.

Total coal consumption is projected to be approximately

60 percent below the reference case level in 2020 in the

cases with CO2 caps. As existing coal-fired power plants

become uneconomical in the CO2 cap cases, large blocks

of capacity are projected to be retired and replaced by

natural gas capacity. The combined effects of lower coal

capacity and lower utilization of the remaining coal

capacity is projected to reduce coal consumption for

electricity generation by 50 to 52 percent in 2010 relative

to the reference case projection. Even in the CO2 sensitivity and integrated sensitivity cases, coal use for electricity generation in 2020 is projected to be 35 percent lower

than projected in the reference case.

Natural Gas

For natural gas consumption and production, the projected effects of emission caps are nearly the opposite of

those for coal. Imposing emission caps on the power sector is expected to lead to greater use of natural gas, especially when a CO2 cap is included. For example, in the

integrated 1990-7% 2005 case, the electricity generation

sector is projected to consume 4.0 trillion cubic feet more

gas in 2005 than projected in the reference case,

increasing its consumption by 250 percent over the next

5 years. In the case with an assumed compliance date of

2008, the projected increase in natural gas consumption

is not as rapid, but it reaches nearly the same level by

2020.

To meet the expected growth in demand for natural gas,

both domestic production and imports are projected to

increase above the reference case levels. For example, in

the integrated 1990-7% 2005 case, domestic production

is projected to grow by 4.9 trillion cubic feet between

2000 and 2005, as compared with 2.1 trillion cubic feet in

the reference case. Achieving the required levels of natural gas production projected in the CO2 cap and integrated analysis cases would be a challenge to the

industry. Domestic natural gas production grew by 5.7

trillion cubic feet between 1965 and 1970, but there

has not been another period of such rapid growth since.

It is expected, however, that investors would recognize

that limits on CO2 emissions would lead to higher

demand for natural gas—and higher prices—for an

extended period, and that the necessary investment in

drilling equipment and other infrastructure would be

made.

Imports of natural gas from Canada are also expected to

play a role in reducing power sector CO2 emissions. In

the integrated 1990-7% 2005 case, imports from Canada

are projected to reach 6.1 trillion cubic feet per year in

2020, 0.7 trillion cubic feet more than projected in the reference case. (The projections include growth in Canadian imports as a result of increased gas production in

Alaska. New Alaskan gas that is not shipped directly to

the lower 48 States is used in Canada, freeing up additional Canadian gas for export to the United States.)

The increased demand for natural gas projected in the

cases that include CO2 emission caps is expected to

result in higher prices. For example, in the integrated

cases, natural gas wellhead prices are expected to range

from $3.75 per thousand cubic fee to $4.33 per thousand

cubic feet in 2010, much higher than the $2.68 price projected in the reference case. The highest prices are projected in the cases with 1990-7% CO2 emission caps

beginning in 2005, because of the more rapid increase in

consumption projected in those cases and, consequently, the need for rapid increases in production. In

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants xix
the CO2 sensitivity and integrated sensitivity cases, the

less stringent CO2 emission caps assumed are expected

to reduce the pressure on gas markets slightly and moderate the projected increase in natural gas wellhead

prices relative to the reference case projections. For

example, the projections of wellhead gas prices in 2020

are $4.00 per thousand cubic feet in the CO2 sensitivity

case and $4.06 in the integrated sensitivity case.

Renewables

Additional use of renewable energy sources is also

expected as a result of efforts to reduce power sector

emissions. As the cost of generating power from fossil

fuels increases in the emission reduction cases, renewable generation technologies are expected to become relatively more attractive. The projected changes are small

in the NOx and SO2 cap cases, where the costs of complying with the emission caps are expected to fall mainly on

existing fossil plants. In the cases that assume CO2 caps,

however, when carbon allowance fees are added to the

operating costs of fossil-fueled power plants, new

renewable generating plants and biomass co-firing

(mixing biomass with coal in an existing coal plant) are

expected to become economically attractive.

The largest increases in renewable electricity generation

in the integrated cases with CO2 caps relative to the reference case are projected for geothermal, biomass, and

wind. For example, geothermal electricity generation is

projected to increase to 104 billion kilowatthours by 2010

in the CO2 1990-7% 2005 case, as compared with the projection of 25 billion kilowatthours in 2010 in the reference case. The projection for biomass generation in 2010

(excluding cogeneration) increases from 22 billion kilowatthours in the reference case to 71 billion kilowatthours (17 billion kilowatthours from dedicated plants

and 54 billion kilowatthours from co-firing in coal

plants) in the CO2 1990-7% 2005 case. Similarly, generation from wind plants in the CO2 1990-7% 2005 case is

projected to reach 18 billion kilowatthours in 2010 and

86 billion kilowatthours in 2020, as compared with the

reference case projections of 12 and 13 billion kilowatthours, respectively. Overall, generation from nonhydroelectric renewables in the CO2 1990-7% 2005 case

is projected to make up 8.0 percent of total electricity

generation and 8.5 percent of total electricity sales in

2020.

In the CO2 sensitivity and integrated sensitivity cases,

the amount of renewable capacity added—above the

level projected in the reference case—is much less than

projected in the cases with more stringent CO2 caps. In

the projections, the relative economics of new renewable

capacity are sensitive to the projected carbon allowance

fees. In the CO2 sensitivity and integrated sensitivity

cases, only 16 to 18 gigawatts more new renewable

capacity is projected to be built than in the reference case

by 2020, whereas in the CO2 1990-7% 2005 case, which

assumes the most stringent emission caps in this

analysis, 46 gigawatts more new renewable capacity is

projected to be built by 2020 than in the reference case.

Potential Impacts of

New Source Review Actions

Requiring some or all coal-fired power plants to add

equipment to reduce NOx and SO2 emissions to continue

operating would have a significant impact on NOx and

SO2 emissions. If the 32 plants currently under suit by

the Department of Justice on behalf of the EPA are

required to be retrofitted with best available control

technology (BACT) to continue operating, as assumed in

the NSR 32 case, it is estimated that the SO2 allowance

price in 2010 would be cut by 19 percent relative to the

projection in the reference case, from $170 to $137 per

ton. Total SO2 emissions are expected to be 0.6 million

tons below the reference case level, because it is assumed

that the plants would surrender approximately half

their allowances under the terms of an agreement to end

the suit. In other words, the national SO2 emission cap

is expected to be lower, and to continue to be binding

even after the actions taken by the plants that are being

sued.

Similar behavior is expected in the NOx allowance market. The price impact of requiring the 32 plants to add

control equipment is projected to be small. As discussed

above, most of the control equipment is expected to be

added to plants that do not set the market prices for

power, and thus the costs would not be fully passed on

to consumers. Where equipment is added to plants in

regions with cost-of-service regulation, the projected

costs still are not large enough to have a significant

impact on electricity prices.

The projected impacts on NOx and SO2 emissions and

allowance prices are even larger in the NSR All case,

which assumes that all coal-fired power plants must be

retrofitted with control technology if they are to continue operating after 2010. In this case, both NOx and

SO2 allowance prices are expected to fall to zero, because

when new emission control equipment is added to all

operating coal plants, NOx and SO2 emissions are projected to be well under established emission caps. For

example, in the NSR All case, SO2 emissions in 2010 are

projected to be 1.9 million tons, well under the CAAA90

cap of 8.95 million tons.

A large number of coal plants—31 gigawatts (10 percent

of existing capacity)—are expected to be retired in the

NSR All case, because adding emission control equipment to them would not be economical. When those

plants are retired, however, there would be insufficient

baseload capacity (plants intended to run almost continuously) if they were not replaced. The vast majority of

xx Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
the plants retired are projected to be replaced by new

coal plants that comply with new source performance

standards. As a result, projected CO2 emissions in the

NSR All case are virtually unchanged from those in the

reference case. As in the NSR 32 case, electricity prices in

the NSR All case are expected to be only slightly above

those projected in the reference case. Power plant owners are projected to spend roughly $15 billion on SCR

NOx controls and $58 billion on SO2 controls, reducing

the profitability of the plants but not making them

uneconomical.

When the assumptions in the NSR 32 and NSR All cases

are combined with those used in the integrated 1990-7%

2005 case described above, the results in the three cases

are similar. Comparing the results in the integrated

1990-7% 2005, integrated NSR 32, and integrated NSR

All cases shows that, to meet the emissions targets specified by the Subcommittee, the power sector is projected

to reduce its use of coal dramatically and to increase its

use of natural gas and, to a lesser extent, renewables

(Table ES6).

The requirement that emission control equipment must

be added to coal-fired plants if they are to continue operating in the integrated NSR All case is projected to lead

to more coal plant retirements than projected in the integrated 1990-7% 2005 or integrated NSR 32 case, leading

in turn to a lower CO2 allowance fee in the integrated

NSR All case. It is also projected to lead to even greater

dependence on natural gas and, as a result, higher

natural gas prices. Projected electricity prices are similar

to those in the integrated 1990-7% 2005 case.

The NSR cases suggest that efforts to reduce NOx and

SO2 emissions at existing coal-fired power plants would

make a portion of the plants uneconomical, but the

majority would continue operating. Additional effort

would be needed to reduce power plant CO2 emissions.

Uncertainty

As with all projections, there is considerable uncertainty

in the results of this analysis. Among the key factors that

influence the results are the significance of the changes;

uncertainty about future fuel prices, particularly for natural gas; potential cost and performance improvements

in emission control and generating technologies; the

ability of the various energy markets to make the adjustments that would be needed over the next 5 to 8 years;

the impacts of the ongoing changes in the structure of

electricity markets; and the potential impacts of Hg

emission regulations. All these factors could affect the

results of this analysis.

Meeting the emission targets specified by the Subcommittee for this analysis would clearly be a challenge for

the electricity industry and its associated fuel markets.

The timing of the targets—only 5 to 8 years away—may

pose the greatest challenge. Planning, siting, obtaining

environmental permits for, and building the amount of

new gas-fired capacity projected to be needed, as well as

developing the natural gas resources that would be

required to supply them, could be difficult in the time

frame assumed here. Increasing reliance on natural gas

in the power sector could place considerable stress on

the gas production and delivery infrastructure, leading

to price volatility and substantial upward pressure on

gas prices. In addition, new technologies for electricity

generation, emission controls, and natural gas exploration and development that might be developed over a

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants xxi

Table ES6. Integrated NSR Case Projections, 2000, 2010, and 2020

Analysis Case

Coal-Fired

Generation

(Billion

Kilowatthours)

Gas-Fired

Generation

(Billion

Kilowatthours)

CO2 Emissions

(Million Metric Tons

Carbon Equivalent)

CO2 Allowance Price

(1999 Dollars per

Metric Ton Carbon

Equivalent)

Electricity Price

(1999 Cents per

Kilowatthour)

2000

Reference . . . . . . . . . . . . . . 1,942 599 570 0 6.8

Integrated 1990-7% 2005 . . 1,943 599 570 0 6.7

Integrated NSR 32. . . . . . . . 1,942 603 570 0 6.7

Integrated NSR All. . . . . . . . 1,940 607 569 0 6.7

2010

Reference . . . . . . . . . . . . . . 2,284 1,123 686 0 5.9

Integrated 1990-7% 2005 . . 1,135 1,839 443 134 8.4

Integrated NSR 32. . . . . . . . 1,086 1,903 438 132 8.4

Integrated NSR All. . . . . . . . 1,031 1,988 442 92 8.1

2020

Reference . . . . . . . . . . . . . . 2,370 1,866 776 0 6.0

Integrated 1990-7% 2005 . . 852 2,774 440 130 7.8

Integrated NSR 32. . . . . . . . 869 2,755 439 122 7.7

Integrated NSR All. . . . . . . . 802 2,856 442 112 7.8

SNCR = selective noncatalytic reduction. SCR = selective catalytic reduction.

Source: National Energy Modeling System, runs MCBASE.D121300A, FDP7B05.D121300B, FDP_N32.D121900A, and FDP_ALL.D121900A.
longer period would not be able to contribute significantly to meeting the challenge in the short term.

A key uncertainty with regard to competitive power

markets is how consumers and product developers

might respond to competitively priced electricity. One

feature that has been seen in newly competitive markets

is a large amount of price volatility. Because such volatility has not occurred historically, consumers (including

homeowners and commercial and industrial establishments) have not invested in equipment that could

reduce their exposure to higher prices. It remains to be

seen whether the market will become more responsive

in the future.

xxii Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
1. Introduction

Over the next decade, power plant operators may face

significant requirements to reduce emissions of sulfur

dioxide (SO2), nitrogen oxides (NOx), carbon dioxide

(CO2), and mercury (Hg). At present, neither the future

reduction requirements nor the complete timetable is

known for any of these airborne emissions, and compliance planning is difficult. In response to the Clean Air

Act Amendments of 1990 (CAAA90), power plant operators are now in the process of making reductions in

power plant emissions of SO2 and NOx. Phase II of the

CAAA90 SO2 reduction program—lowering allowable

SO2 emissions to an annual cap of 8.95 million

tons—became effective on January 1, 2000, and more

stringent NOx emissions standards for boilers also took

effect in 2000. States are also beginning efforts to address

visibility problems (regional haze) in national parks and

wilderness areas throughout the country. Because

power plant emissions of SO2 and NOx contribute to the

formation of regional haze, these emissions may have to

be further reduced to improve visibility in some areas. In

the near future, it is expected that new national ambient

air quality standards for ground-level ozone and fine

particulates may necessitate additional reductions in

NOx and SO2.

To reduce ozone formation, the U.S. Environmental Protection Agency (EPA) has promulgated a multi-State

summer season cap on power plant NOx emissions that

would take effect in 2004. Emissions of fine particles

(less than 10 microns in diameter) and their impacts on

health are currently being studied. Fine particles are

associated with power plant emissions of SO2, and further reductions in SO2 emissions could be required by as

early as 2007 in order to reduce emissions of fine particles. In addition, the EPA recently decided that Hg emissions need to be reduced, and proposed regulations will

be developed over the next 3 years. Further, if the United

States ratifies the Kyoto Protocol or a similar international greenhouse gas mitigation treaty, energy-related

CO2 emissions will also have to be reduced.

With comprehensive standards changing according to

different timetables, compliance planning is difficult. It

can take several years to design, license, and construct

new power plants and emission control equipment,

which may then be in operation for 30 years or more. As

a result, power plant operators must look far into the

future to evaluate the economics of new investment

decisions. Changing emission standards with different

timetables add considerable uncertainty to investment

planning decisions. An option that looks attractive to

meet one set of SO2 and NOx standards may not be

attractive if further reductions are required in a few

years. Similarly, economical options for reducing SO2

and NOx may not be optimal if Hg and CO2 emissions

must also be reduced. Further complicating planning,

some investments reduce multiple emissions simultaneously, such as flue gas desulfurization equipment that

reduces SO2 and Hg, making such investments more

attractive under some circumstances. As a result, power

plant owners currently are wary of making investments

that may prove unwise a few years hence.

Recently, plans have been proposed that would require

coordinated multi-emission reductions. Several bills

have been introduced in Congress to address these

issues: S. 1369, the Clean Energy Act of 1999, introduced

by Senator Jeffords; S. 1949, the Clean Power Plant and

Modernization Act of 1999, introduced by Senator

Leahy; H.R. 2900, the Clean Smokestacks Act of 1999,

introduced by Congressman Waxman; H.R. 2645, the

Consumer, Worker, and Environmental Protection Act

of 1999, introduced by Congressman Kucinich; and H.R.

2980, the Clean Power Plant Act of 1999, introduced by

Congressman Allen (Table 1). Each of these bills contains provisions to reduce power plant emissions of

NOx, SO2, CO2, and Hg over the next decade. The bills

use different approaches—traditional technologyspecific emission standards, generation performance

standards, explicit emission caps, or combinations of the

three—but all call for significant reductions.

H.R. 2900 calls for reducing power plant NOx and SO2

emissions by 75 percent from 1997 levels, reducing

power plant CO2 emissions to 1990 levels, and reducing

power plant Hg emissions by 90 percent, all by 2005. In

addition, it requires that older plants be modernized to

comply with the most recent new source performance

standards within 5 years of the bill’s passage.

S. 1369 has similar goals but takes a different approach,

establishing explicit emission caps on NOx, SO2, CO2,

and Hg. The proposed annual caps are 1,660,000 tons for

NOx (approximately 73 percent below the 1997 level),

3,580,000 tons for SO2 (approximately 73 percent below

the 1997 level), 1,914,000,000 tons for CO2 (the 1990

level), and 5 tons for Hg (a 90-percent reduction from the

estimated 1997 level). The bill uses these caps to establish generation performance standards (GPS) to allocate

emission allowances each year. For example, if the facilities subject to the emission cap generated a total of 2 billion megawatthours of electricity in a given year, the

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 1
generation performance standard for CO2 would be

approximately 1 metric ton carbon equivalent per

megawatthour (1,914,000,000 divided by 2,000,000,000).

As a result, each generator would be allocated slightly

less than 1 metric ton of emission allowances for each

megawatthour generated for that year. Generators

whose emissions exceeded their allocations of emission

allowances would have to purchase credits from others.

As generation changes over time, the GPS and the allocation of future allowances would also change.

S. 1369 also establishes a public benefits fund (PBF) created by collecting a small fee for each kilowatthour of

electricity sold and used to support energy efficiency

and renewable energy projects and to assist low-income

households in meeting their energy needs. In addition,

S. 1369 also would establish a renewable portfolio standard (RPS). The RPS requires that a specified share of

generation sold by covered generators (all nonhydroelectric generators) must come from renewable sources.

Those with qualifying renewable generation are to be

issued credits that they can use to meet their own

requirements or sell to others who do not generate the

required share themselves. The required share begins at

2.5 percent in 2000 and grows to 20 percent in 2020.

The analysis described in this report was conducted at

the request of the Subcommittee on National Economic

Growth, Natural Resources, and Regulatory Affairs of

the U.S. House of Representatives Committee on Government Reform.1 In its request the Subcommittee asked

the Energy Information Administration (EIA) to analyze

the potential costs of various multi-emission strategies

to reduce the air emissions from electric power plants.

The Subcommittee requested that EIA examine cases

with alternative NOx, SO2, CO2, and Hg emission reductions and RPS requirements. This report examines NOx,

SO2, and CO2 emission limits. A second volume, to be

published in early 2001, will examine Hg emission limits

and RPS requirements.

This report provides an analysis of the potential impacts

of efforts to reduce NOx, SO2, and CO2 emissions from

power plants, based on scenarios requested by the Subcommittee on June 29, August 17, and September 25,

2000. Expected costs to the energy sector and to consumers of meeting the specified emission caps are examined

(see Chapter 2 for a discussion of the specific scenarios

requested). The potential benefits of reduced emissions—such as might be associated with reduced health

care costs—are not addressed, because EIA does not

2 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 1. Congressional Bills With NOx, SO2, or CO2 Power Plant Reduction Requirements

Bill Number

NOx Target

(Tons per Year)

SO2 Target

(Tons per Year)

CO2 Target

(Tons per Year)

Hg Target

(Tons per Year) Other

S. 1369 . . . . . . . . . . 1,660,000 3,580,000 1,914,000,000

(approx. 1990 level)

90% reduction 20% RPS, GPS,

PBF

S. 1949 . . . . . . . . . . 90% removal at

each plant, and

no more than

0.15 pounds per

million Btu

95% removal at

each plant, and

no more than

0.3 pounds per

million Btu

GPS, 0.9 pounds CO2

per kilowatthour for

natural gas, 1.3 for oil,

and 1.55 for coal

90% reduction from

1997 level

None

S. 172, H.R. 25 . . . . 3,000,000

(70% below 1990

level)

4,500,000

(50% below

CAAA90 level)

No requirement Study NOx allowance

program

H.R. 2645 . . . . . . . . 1,660,000 3,580,000 1,710,000,000 in 2005

(10% below 1990 level);

1,425,000,000 in 2010

(25% below 1990 level);

380,000,000 in 2030

(80% below 1990 level)

Reduce to 0 by 2010 GPS, PBF, RPS,

nuclear waste

reductions

H.R. 2900 . . . . . . . . 1,548,000

(75% below 1997

level)

3,273,000

(75% below 1997

level)

1,914,000,000

(approx. 1990 level)

90% reduction from

1997 level

Plants required to

meet new plant

standards when they

reach 30 years of

age

H.R. 2980 . . . . . . . . Approximately

1,831,925

(1.5 pounds per

megawatthour using

1996-1998 average

generation)

Approximately

3,663,850

(3.0 pounds per

megawatthour using

1996-1998 average

generation)

1,914,000,000

(approx. 1990 level)

70% reduction from

level in flue gas

GPS for CO2

CAAA90 = Clean Air Act Amendments of 1990. GPS = Generation Performance Standard (output based allocation of emission allowances). PBF =

Public Benefits Fund. RPS = Renewable Portfolio Standard.

Sources: S. 1369, “Clean Energy Act of 1999,” 106th Congress, 1st Session (July 14, 1999); S. 1949, “Clean Power Plant and Modernization Act of

1999,” 106th Congress, 1st Session (November 17, 1999); S. 172, “Acid Deposition and Ozone Control Act,” 106th Congress, 1st Session (January

19, 1999); H.R. 2645, “Electricity Consumer, Worker, and Environmental Protection Act of 1999,” 106th Congress, 1st Session (July 29, 1999); H.R.

2900, “Clean Smokestacks Act of 1999,” 106th Congress, 1st Session (September 21, 1999); H.R. 2980, “The Clean Power Plant Act of 1999,” 106th

Congress, 1st Session (September 30, 1999).

1

The letters requesting this study are included in Appendix J.
have expertise in this area.2 The bibliography for this

report includes several studies that address the benefits

of reducing emissions. Readers should refer to the EPA

and others for analysis of the potential benefits of emissions reductions.

In response to a later request from the Subcommittee,

this analysis also includes four scenarios examining the

potential impacts of requiring older coal-fired power

plants either to be brought into compliance with current

new source performance standards or to be retired. The

EPA has taken action against the owners of 32 older coal

plants, accusing them of making modifications without

adding the emissions control equipment required by

CAAA90. The first of the four scenarios—referred to as

the New Source review (NSR) cases—assumes that the

owners of each of the 32 plants will be required to add

state-of-the-art emissions control equipment by 2005, or

retire the plant if that is the economical choice. The second NSR case assumes that all coal-fired plants that currently do not have such control equipment must make

the same decision by 2010. The third and fourth NSR

cases are the same as the first two, except that they

include caps on power sector emissions of NOx, SO2, and

CO2. Because Tampa Electric has settled its case, all the

scenarios in this report assume that control equipment

will be added to its Big Bend facility and that its F.J.

Gannon plant will be converted to natural gas.

The analysis presented in this report should be seen as

an examination of the steps that power suppliers might

take to meet the emission caps specified by the Subcommittee. The specific design of the cases—timing, emission cap levels, policy instruments used, etc.—is

important and should be kept in mind when the results

are reviewed. For example, all the analysis cases assume

that market participants—power suppliers, consumers,

and coal, gas, and renewable fuel suppliers—would

become aware of impending emission caps before their

target dates and would begin to take action. If market

participants do not anticipate the emission caps or foresee them earlier, the results would change. For example,

in earlier EIA studies that looked at alternative program

start dates for imposing a CO2 emissions cap (or carbon

cap), an earlier start date and longer phase-in period

were found to smooth the transition of the economy to

the longer run target.3

This study is not intended to be an analysis of any of the

specific congressional bills that have been proposed, and

the impacts estimated here should not be considered to

be consequences of specific legislative proposals. All the

proposals include provisions other than the emission

caps studied in this analysis, and several would use different policy instruments to meet the emission targets.

Moreover, some of the actions projected to be taken to

meet the emission caps in this analysis may eventually

be otherwise required as a result of ongoing environmental programs whose requirements currently are not

specified (see discussion in Chapter 2, page 6).

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 3

2Reports by Burtraw, Chestnut, and the EPA cited in the bibliography of this report include discussions of health benefits.

3Energy Information Administration, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity, SR/OIAF/98-03 (Washington, DC, October 1998); and Analysis of the Impacts of an Early Start for Compliance with the Kyoto Protocol, SR/OIAF/99-02 (Washington,

DC, July 1999).

2. Analysis Cases and Methodology

Analysis Cases

The House Subcommittee on National Economic

Growth, Natural Resources, and Regulatory Affairs

requested that EIA prepare an analysis to evaluate the

impacts of potential caps on power sector emissions of

NOx, SO2, CO2, and Hg, combined with a renewable

portfolio standard (RPS) requirement. The specific

assumptions and cases requested by the Subcommittee

are summarized in Table 2. To respond to the Subcommittee’s request in a timely manner, the analysis has

been divided into two volumes. This report addresses

scenarios with NOx, SO2, and CO2 emission caps, as well

as scenarios analyzing the potential impacts of ongoing

litigation that could require many existing coal plants to

add state-of-the-art emissions control equipment. The

latter cases, referred to as new source review (NSR)

cases, are discussed in Chapter 5.

The reference case for this analysis incorporates the laws

and regulations that were in place as of July 1, 2000, as

EIA’s Annual Energy Outlook 2001 (AEO2001) was being

prepared. It includes the CAAA90 SO2 emission cap and

NOx boiler standards. It also includes the 19-State summer season NOx emission cap program—referred to as

the “State Implementation Plan (SIP) Call.” The settlement agreement between the Tampa Electric Company

and the Department of Justice (acting for the U.S. Environmental Protection Agency) requiring the addition of

emissions control equipment at the Big Bend power

plant and the conversion of the F.J. Gannon plant to natural gas is incorporated in the analysis.

Table 2 summarizes the emission targets, timetables,

and RPS requirements for each case requested by the

Subcommittee. The emission caps (Table 3 and Figure 1)

are applied only to the electricity generation sector and

are assumed to cover emissions from both utility-owned

and independent power plants, excluding cogenerators.

If economical, cogenerators are allowed to compete

against other power plants to meet the demand for electricity. Because no requirements to reduce emissions in

the residential, commercial, industrial, and transportation sectors are assumed, the results of this analysis

should not be compared with the results of studies that

have examined the impacts of complying with the Kyoto

Protocol across all sectors of the economy.

In addition to the cases requested by the Subcommittee,

this report includes three cases that assume less stringent emission caps for SO2 and CO2 only, and a

combined integrated case that uses the less stringent targets (Table 4). These cases were analyzed to examine the

sensitivity of the results to the emission targets

requested by the Subcommittee for analysis. The emission caps in the SO2 sensitivity case were set roughly

halfway between the estimated emissions for 2000 and

the caps requested by the Subcommittee—roughly a

50-percent reduction from 1997 levels, rather than the

75-percent reduction specified by the Subcommittee. For

CO2 a similar approach was used. The CO2 cap in 2005 in

the CO2 sensitivity case was set to halfway between the

estimated emissions in 2000 and the 1990 level. The cap

was then lowered further over the 2008 to 2012 time

period to halfway between the estimated 2000 emissions

and 7 percent below the 1990 level. Using this approach,

the CO2 cap in 2005 in the CO2 sensitivity case was

assumed to be 10 percent above 1990 levels, before

declining to 7 percent above 1990 levels over the 2008 to

2012 time period.

Using data that recently have become available, the

National Energy Modeling System (NEMS) is currently

being modified to represent power sector Hg emissions.

The expected impacts of the other provisions in each

case on Hg emissions are mentioned in Chapter 3, but

the proposed Hg emission caps will be analyzed more

thoroughly in the subsequent report.

In all cases it is assumed that emission caps would be

phased in beginning in 2002. For the cases that require

that CO2 emissions average 7 percent below the 1990

level over the 2008 to 2012 time period, the cap is constructed so that emissions can be slightly above the

1990-7% level in the first year or two of the period and

slightly below it in the later years. After 2012, the cap is

held at 7 percent below the 1990 level through the

remainder of the projections.4 In addition, it is assumed

that the emission reduction programs will be operated

as market-based emission cap or fee programs, and the

emission allowance prices or emission fees are included

in the operating costs of plants that produce one or more

of the emissions.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 5

4The Kyoto Protocol requires the United States to reduce its greenhouse gas emissions to 7 percent below the 1990 level on average

between 2008 and 2012. Requirements for the post-2012 period have not been set. As requested by the Subcommittee, this analysis assumes

that the CO2 cap does not change after 2012.
6 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Representation of New Environmental Rules and Regulations

In Energy Information Administration (EIA) analyses,

the reference case incorporates rules and regulations in

place at the time of the preparation of the report. Rules

or regulations that are not finalized, are in early stages

of implementation (without specific guidelines), or are

still being developed or debated are not represented.

As an independent statistical and analytical agency,

EIA does not take positions on how legislative or regulatory issues will be resolved or how rules or regulations will, or should, be implemented.

The reference case for this analysis excludes several

potential environmental actions, such as new regulations affecting regional haze, for which States are

developing implementation plans; the implementation

of new National Ambient Air Quality Standards

(NAAQS) for fine particulates, which is still being

reviewed by the U.S. Environmental Protection

Agency (EPA) and the courts; and the possible ratification of the Kyoto Protocol. In addition, no effort is

made to predict the outcome of ongoing studies of the

need to reduce power plant mercury emissionsa or the

resolution of lawsuits against the owners of 32

coal-fired power plants accused of violating the Clean

Air Act (CAA).

In June 1999, the EPA issued regulations to improve

visibility (reduce regional haze) in 156 national parks

and wilderness areas across the United States. It is

expected that these rules will have an effect on power

plants, but the degree to which they will be affected is

not known. Power plant emissions of SO2 and NOx,

which contribute to the formation of regional haze,

may have to be reduced to improve visibility in some

areas. The regulations call for States to establish goals

and design plans for improving the visibility in

affected areas; however, State implementation plans

(SIPs) are not required until 2004 or later and therefore

are not represented in this analysis, because they have

not yet been promulgated.

The revised NAAQS, issued by the EPA in 1997, created a standard for fine particles smaller than 2.5

micrometers in diameter (PM2.5). As with regional

haze, power plant emissions of SO2 and NOx are a component of fine particulate emissions. At the request of

the President (memorandum July 16, 1997), the EPA is

now reviewing scientific data on fine particulate emissions to determine whether to revise or maintain the

standard. The review is expected to be completed in

2002. If the standard is maintained, States will be

required to submit plans to comply by 2005; however,

the NAAQS for fine particulates has been challenged in

court, and the resolution of the case is uncertain.

In December 1997, 160 countries met to negotiate binding limitations on greenhouse gas emissions for the

developed nations. CO2 emissions from fossil-fired

power plants are a key component of greenhouse gas

emissions. The developed nations agreed to limit their

greenhouse gas emissions to 5 percent below the levels

emitted in 1990, on average, between 2008 and 2012.

The target for the United States is 7 percent below the

1990 emission level for all greenhouse gases. Reductions would be required if the U.S. Senate ratified the

protocol. At this time, while 29 countries have ratified

the protocol, none of the Annex I countries (the developed countries) has ratified the agreement. Various

elements of the Protocol are still under negotiation.

The Clean Air Act Amendments of 1990 (CAAA90),

Section 112(n)(1)(A), required that the EPA prepare a

study of hazardous air emissions from steam generating units. The report was submitted to Congress on

February 24, 1998. Its key finding was that Hg emissions from coal-fired power plants posed the greatest

potential for harm. The EPA is now collecting and analyzing data on Hg emissions from specific power

plants. The data, together with continuing studies on

the health effects of mercury, will be used to determine

the extent to which emissions need to be reduced. The

EPA will be developing proposed regulations for

reducing Hg emissions over the next 3 years.

On November 3, 1999, the Justice Department, on

behalf of the EPA, filed suit against seven electric utility companies, accusing them of violating CAAA90 by

not installing state-of-the-art emissions control equipment on their power plants when major modifications

were made. CAAA90 requires that when major modifications are made to older power plants they must also

be upgraded to comply with the emissions standards

for new power plants. The EPA is arguing that the

seven companies and the Tennessee Valley Authority

made major modifications to 32 power plants but did

not add the required emissions control equipment. At

this time, one company, Tampa Electric, has settled the

case by agreeing to make modifications to its power

plants. The other cases have not been settled.

At the request of the Subcommittee four alternative reference cases with different assumptions about the outcome of the ongoing litigation were examined for this

analysis. In the first New Source Review (NSR) case, it

is assumed that the owners of each of the 32 plants

against which the EPA has taken action will be

required to add best available control technology to

remove SO2 and NOx or retire the plant by 2005. In the

(continued on page 7)

aOn December 15, 2000, the EPA announced that Hg emissions need to be reduced, and that regulations will be issued by 2004.
Because there is an existing national SO2 allowance program, it is assumed that power plant operators will be

able to use any SO2 allowances they have already accumulated. In other words, they can use allowances they

have banked. They are not allowed to bank additional

allowances after 2000. As a result, the power sector can

exceed the SO2 emission cap beyond the compliance

date until their banked allowances are exhausted.

For this analysis, it is assumed that the power sector

must explicitly reduce its emissions to meet the CO2 cap

and cannot rely on other mechanisms, such as the flexibility measures included in the Kyoto Protocol that

allow countries several options for meeting their emission reduction targets, including direct emissions reductions, land use changes, and forestry changes. For

example, a country could get credit for a project to plant

trees (reforestation) that absorb CO2 during their

growth. Emissions trading among countries with emission caps is also permitted by the Protocol. The Protocol

also covers six greenhouse gases—carbon dioxide,

methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride—and reductions in

any one of them count toward meeting a country’s emissions cap. At this time, rules about what type of land use

and forestry projects could be implemented and how

emissions trading programs might work have not been

finalized. If similar provisions were included in a program to reduce power sector CO2 emissions, the costs of

meeting the target most likely would be lower.

After its initial request, the Subcommittee asked that

EIA also examine the potential impacts of requiring

older coal-fired power plants either to be brought into

compliance with current new source performance standards or to be retired. The EPA has taken action against

the owners of 32 older coal plants accusing them of

making modifications without adding the emissions

control equipment required by CAAA90. The first of the

four cases—referred to as the New Source Review (NSR)

cases—assumes that the owners of each of the 32 plants

will be required to add state-of-the-art emissions control

equipment by 2005 or retire the plant. The second case

assumes that all coal-fired plants that currently do not

have such control equipment must make the same decision by 2010. The third and fourth cases combine the

assumptions of the first two with more stringent caps on

NOx, SO2, and CO2 emissions.

Methodology

AEO2001 Assumptions

The analysis in this report is based on the data and

NEMS algorithms used for the AEO2001.

5 Because the

AEO2001 forecasts are based on data available at the end

of August 2000, the results of this analysis should be

evaluated in terms of the relative differences between

cases rather than the absolute values.

NEMS Representation

NEMS is a computer-based, energy-economic model of

the U.S. energy system for the mid-term period, through

2020.6 NEMS projects production, imports, conversion,

consumption, and prices of energy, subject to assumptions about macroeconomic and financial factors, world

energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and

demographics. Domestic energy markets are modeled

by explicitly representing the economic decisionmaking

involved in the production, conversion, and consumption of energy products. For most sectors, NEMS

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 7

Representation of New Environmental Rules and Regulations (Continued)

second NSR alternative reference case it is assumed

that all coal-fired plants that do not have flue gas

desulfurization (FGD) or selective catalytic reduction

(SCR) equipment will be forced to add controls or retire

by 2010. The third and fourth NSR cases are the same as

the first two, except that they include caps on power

sector emissions of NOx, SO2, and CO2. The model

evaluates the economics of the retrofit versus retirement decision for each plant. The resolution of these

issues could have an impact on future power plant

emissions, especially SO2 and NOx emissions.

Readers should keep in mind that some of the projected actions and costs incurred to comply with the

emissions caps analyzed in this report may also result

from the other pending rules and regulations discussed above when they are finalized.

Projections in the reference case in this report are not

statements of what will happen but of what might happen, given the assumptions and methodologies used.

The reference projections are business-as-usual trend

forecasts, given known technology, technological and

demographic trends, and current laws and regulations.

Thus, they provide a policy-neutral reference case that

can be used to analyze policy initiatives. EIA does not

propose, advocate, or speculate on future legislative

and regulatory changes. All laws are assumed to remain as now enacted; however, the impacts of emerging regulatory changes, when defined, are reflected.

5For a summary of the AEO2001 assumptions, see web site www.eia.doe.gov/oiaf/assumption/.

6For a more detailed overview of NEMS, see Energy Information Administration, The National Energy Modeling System: An Overview 2000

(Washington, DC, March 2000), web site www.eia.doe.gov/oiaf/aeo/overview/index.html.
8 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 2. Analysis Cases

Case Name

Electric Power Sector Emission Caps

Compliance Dates

RPS

NO Requirement x SO2 CO2 Hg

Volume 1 Cases

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . . . . . . 75% below

1997 level

CAAA90 cap None None Start 2002; meet

target by 2005

None

NOx 2008 . . . . . . . . . . . . . . . . . . . 75% below

1997 level

CAAA90 cap None None Start 2002; meet

target by 2008

None

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

75% below

1997

None None Start 2002; meet

target by 2005

None

SO2 2008 . . . . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

75% below

1997

None None Start 2002; meet

target by 2008

None

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap 7% below

1990 level

None Start 2002; 1990 level

by 2005; 7% below

1990 level in

2008-2012

None

CO2 1990-7% 2008 . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap 7% below

1990 level

None Start 2002; 1990 level

by 2008; 7% below

1990 level in

2008-2012

None

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . 75% below

1997 level

75% below

1997 level

1990 level None Start 2002; meet

target by 2005

None

Integrated 1990-7% 2005 . . . . . . . 75% below

1997 level

75% below

1997 level

7% below

1990 level

None Start 2002; NOx

/SO2

targets by 2005; CO2

1990 level by 2005;

7% below 1990 level

in 2008-2012

None

Integrated 2008 . . . . . . . . . . . . . . 75% below

1997 level

75% below

1997 level

1990 level None Start 2002; meet

target by 2008

None

Integrated 1990-7% 2008 . . . . . . . 75% below

1997 level

75% below

1997 level

7% below

1990 level

None Start 2002; NOx

/SO2

targets by 2008; CO2

1990 level by 2008,

7% below 1990 level

in 2008-2012

None

Volume 2 Cases

Mercury Case . . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap None 90% below

1997 level

Start 2002; meet

target by 2005

None

RPS Case . . . . . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap None None None 5% 2005,

10% 2010,

20% 2020

Integrated Cases with Renewable Portfolio Standard

Integrated RPS 2005 . . . . . . . . . . 75% below

1997 level

75% below

1997 level

1990 level 90% below

1997 level

Start 2002; meet

target by 2005

5% 2005,

10% 2010,

20% 2020

Integrated RPS 1990-7% 2005. . . 75% below

1997 level

75% below

1997 level

7% below

1990 level

90% below

1997 level

Start 2002; NOx

/SO2/

Hg targets by 2005;

CO2 1990 level by

2005, 7% below 1990

level in 2008-2012

5% 2005,

10% 2010,

20% 2020

Integrated RPS 2008 . . . . . . . . . . 75% below

1997 level

75% below

1997 level

1990 level 90% below

1997 level

Start 2002; meet

target by 2008

5% 2005,

10% 2010,

20% 2020

Integrated RPS 1990-7% 2008. . . 75% below

1997 level

75% below

1997 level

7% below

1990 level

90% below

1997 level

Start 2002; NOx

/SO2/

Hg targets by 2008;

CO2 1990 level in

2008, 7% below 1990

level in 2008-2012

5% 2005,

10% 2010,

20% 2020

Notes: CAAA90 cap refers to the 8.95 million ton SO2 cap established in Title IV of the Clean Air Act Amendments of 1990. CAAA90 standards refer

to the boiler emission standards for NOx established in Title V of the Clean Air Act Amendments of 1990. NOx SIP Call refers to the 19-State summer

season cap on NOx emissions to begin in 2004. The time period for reaching the CO2 target of 7 percent below 1990 levels is between 2008 and 2012.

The cap is then held constant at that level through 2020. The emission caps are phased in gradually until the target cap is met on the specified date.

Source: See requesting letters in Appendix J.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 9

Table 3. 1990 and 1997 Emissions Levels and Assumed Emission Caps for Electricity Generators

Target

NOx

(Thousand Tons)

SO2

(Thousand Tons)

CO2

(Million Metric Tons

Carbon Equivalent)

Hg

(Tons)

1990 Level . . . . . . . . . . . . . . . . . . . . . . 6,663 15,909 475 50

1997 Level . . . . . . . . . . . . . . . . . . . . . . 6,191 13,090 533 50

Emission Caps . . . . . . . . . . . . . . . . . . . 1,548 3,273 440a 5 a

The integrated 2005 and integrated 2008 cases set CO2 emissions to the 1990 levels.

Source: 1997 levels from U.S. Environmental Protection Agency, National Air Pollutant Emission Trends, 1900-1998, EPA-454/R-00-002 (Washington, DC, March 2000).

Table 4. Assumed Emission Caps for Electricity Generators in Sensitivity Cases

Case Name

Electric Power Sector Emission Caps

Compliance Dates

RPS

NO Requirement x SO2 CO2 Hg

SO2 Sensitivity . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

50% below

1997 level

None None Start 2002; meet

target by 2005

None

CO2 Sensitivity . . . . . . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

CAAA90 cap 7% above

1990 level

None Start 2002; reach

10% above 1990

CO2 level in 2005

and 7% above 1990

level in 2008-2012

None

Integrated Sensitivity. . . . . . . . . . . . CAAA90

standards and

NOx SIP Call

50% below

1997 level

7% above

1990 level

None Start 2002; NOx

/SO2

targets by 2005; for

CO2, reach 10%

above 1990 level in

2005 and 7% above

1990 level in

2008-2012

None

Notes: CAAA90 cap refers to the 8.95 million ton SO2 cap established in Title IV of the Clean Air Act Amendments of 1990. CAAA90 standards refer

to the boiler emission standards for NOx established in Title V of the Clean Air Act Amendments of 1990. NOx SIP Call refers to the 19-State summer

season cap on NOx emissions to begin in 2004. The time period for reaching the CO2 target 7 percent above 1990 levels is between 2008 and 2012.

The emission caps are phased in gradually until the target cap is met on the specified date.

Source: Office of Integrated Analysis and Forecasting.

1997 2010 2020 Target

Cap

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Thousand Tons per Year

1997 2010 2020 Target

Cap

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Thousand Tons per Year

1997 2010 2020 Target

Cap

0

200

400

600

800

Million MetricTons Carbon Equivalent per Year

NOx SO2 CO2

Figure 1. 1997 Emissions, Reference Case Projections for 2010 and 2020, and Target Caps

for Electricity Generators

Sources: History: Energy Information Administration, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: National Energy Modeling System, run AEO2001.D101600A.
includes explicit representation of energy technologies

and their characteristics (Table 5). In each sector of

NEMS, economic agents—for example, representative

households in the residential demand sector—are

assumed to evaluate the cost and performance of various energy-consuming technologies when making their

investment and utilization decisions. The costs of making capital and operating changes to comply with laws

and regulations governing power plant and other emissions are included in the decisionmaking process.

The rich detail in NEMS makes it useful for evaluating

various energy policy options. Policies aimed at a particular sector of the energy market often have spillover

effects on other areas that can be important, and the

detail of NEMS makes the analysis of such impacts possible. The remainder of this chapter describes how the

cases for this analysis were implemented in the key

NEMS submodules for electricity, coal, and renewables.

Changes in assumptions and modeling approach for this

analysis are also explained.

10 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 5. National Energy Modeling System Energy Activities

Energy Activity Categories Regions

Residential Demand. . . . . . . . . . . . . . . . . . . . . Fourteen end-use services

Three housing types

Thirty-four end-use technologies

Nine Census divisions

Commercial Demand . . . . . . . . . . . . . . . . . . . . Ten end-use services

Eleven building types

Ten distributed generation technologies

Sixty-four end-use technologies

Nine Census divisions

Industrial Demand . . . . . . . . . . . . . . . . . . . . . . Seven energy-intensive industries

Eight non-energy-intensive industries

Cogeneration

Four Census regions

Transportation Demand . . . . . . . . . . . . . . . . . . Six car sizes

Six light truck sizes

Fifty-nine conventional fuel-saving

technologies for light-duty vehicles

Gasoline, diesel, and thirteen alternative-fuel

vehicle technologies for light-duty vehicles

Twenty vintages for light-duty vehicles

Narrow and wide body aircraft

Six advanced aircraft technologies

Medium and heavy freight trucks

Ten advanced freight truck technologies

Nine Census divisions

Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eleven fossil technologies

Seven renewable technologies

Conventional and advanced nuclear

Marginal and average cost pricing

Generation capacity expansion

Thirteen electricity supply regions

Nine Census divisions for demand

Renewables . . . . . . . . . . . . . . . . . . . . . . . . . . . Wind, geothermal, solar thermal, solar

photovoltaic, municipal solid waste,

biomass, conventional hydropower

Thirteen electricity supply regions

Oil Supply. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conventional onshore and shallow offshore

Conventional deep offshore

Enhanced oil recovery

Six lower 48 onshore regions

Three lower 48 offshore regions

Three Alaska regions

Natural Gas Supply . . . . . . . . . . . . . . . . . . . . . Conventional onshore and shallow offshore

Conventional deep offshore

Coalbed methane

Gas shales

Tight sands

Canadian, Mexican, and liquefied natural gas

Six lower 48 onshore regions

Three lower 48 offshore regions

Three Alaska regions

Five liquefied natural gas terminals

Natural Gas Transportation and Distribution . . Core vs. noncore

Peak vs. offpeak

Pipeline capacity expansion

Twelve lower 48 regions

Ten pipeline border points

Petroleum Refining . . . . . . . . . . . . . . . . . . . . . Five crude oil categories

Seven product categories

Thirty-three technologies

Refinery capacity expansion

Three refinery regions aggregated from

Petroleum Administration for District Districts

Coal Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . Three sulfur categories

Four thermal categories

Underground and surface mining types

Eleven supply regions

Thirteen demand regions

Sixteen export regions

Twenty import regions

Source: Energy Information Administration, National Energy Modeling System: An Overview 2000, DOE/EIA-0581(2000) (Washington, DC, March

2000).
Representation of NOx, SO2, and CO2

Emission Reduction Programs

In this analysis, it is assumed that the programs set up to

reduce NOx, SO2, and CO2 emissions from power plants

will operate like the existing SO2 program established in

Title IV of CAAA90, and that marketable emission

allowances or permits will be allocated to power plant

operators at no cost (no revenue will be collected by the

government). No assumption is made about the specific

allocation methodology to be used, other than that it will

be a fixed allocation (does not change from year to year)

and the total amounts allocated will equal the national

emission targets for NOx, SO2, and CO2. Holders of

allowances are assumed to be free to use them to cover

emissions from their own power plants or sell them to

others who need them.

As allowances are bought and sold, market prices will

develop for them and will become part of the operating

costs of plants producing the targeted emissions. For

example, the total operating costs of a plant that produced one ton of a targeted emission per unit of output

would be increased by the price of the allowance. Revenues associated with the sale of allowances go to the

seller of the allowances. In all cases it is assumed that the

allowance markets will operate as near perfect markets,

with low transaction costs and without information

asymmetries. In other words, there will be many buyers

and sellers of allowances and information needed to

evaluate their worth will be readily available. It should

be pointed out that there are numerous policy instruments (taxes, emissions standards, tradable permits,

etc.) that could be used to reach the proposed emission

targets (see box on page 12). The choice of policy instrument will have an impact on the costs of complying with

the emission targets and the electricity price and income

impacts seen by consumers. The analysis does not

employ a generation performance standard as is proposed in several bills (see box on page 14).

Electricity Market Module

The representation of laws and regulations governing

power plant emissions is particularly important in the

NEMS electricity market module (EMM). The EMM is

able to simulate emission caps on SO2, NOx, and CO2. In

the reference case for this analysis, the CAAA90 SO2

emission cap, both Phase I and Phase II, is included. The

summer season NOx emission cap (SIP Call) promulgated by the EPA is also included for 19 States, as discussed above. The EMM simulates the capacity planning

and retirement, operating, and pricing decisions that

occur in U.S. electricity markets. It operates at a

13-region level based on the North American Electric

Reliability Council (NERC) regions and subregions.

Based on the cost and performance of various generating technologies, the costs of fuels, and constraints on

emissions, the EMM chooses the most economical

approach for meeting consumer demand for electricity.

During each year of the analysis period, the EMM evaluates the need for new generating capacity to meet consumer needs reliably or to replace existing power plants

that are no longer economical. The cost of building new

capacity is weighed against the costs of continuing to

operate existing plants and consumers’ willingness to

pay for reliable service.7 For nuclear facilities the maintenance versus retirement decisions are made for each

plant when it reaches 30, 40, and 50 years of age. At the

request of the Subcommittee, the option of constructing

new nuclear plants is not considered in this analysis.

The EMM does represent improvements in the cost and

performance of new generating technologies as they

enter the market. Economic research has shown that successful new technologies tend to show declining costs as

they penetrate the market. In the EMM it is assumed that

the costs for new technologies decline with each doubling of capacity. As a result, if a policy stimulates the

development of a particular technology the EMM will

endogenously reduce the cost of that technology as it

enters the market in greater quantities. The rate of

decline depends on the level of penetration.

During each time period plants are brought on line (dispatched), starting with the unit with the lowest operating costs, until consumers’ demand is met. When faced

with an SO2 or NOx emission cap on electricity producers, the least expensive reduction options available are

chosen until the cap is met. The goal of the model is to

minimize the costs of producing electricity while complying with emissions constraints. For example, to

reduce SO2 emissions, the options include switching to a

lower sulfur fuel, reducing the utilization of relatively

high SO2 emitting plants, adding a flue gas desulfurization (FGD) system to an existing plant to remove SO2, or

retiring a relatively high emitting plant and replacing it

with a cleaner plant or, through higher prices, encouraging consumers to reduce their electricity use. This

approach allows for SO2 allowance trading and banking

for later use. The marginal cost of reducing emissions

sets the allowance price, which is included in the operating costs of plants producing the capped emissions.8 In

NEMS, SO2 allowance banking decisions can be specified exogenously, or the model can solve for them

endogenously. In this analysis, because of stability problems caused by the relationships among the emission

caps, banking patterns were specified exogenously for

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 11

7The capacity planning algorithm determines the appropriate reserve margins in each region by weighing the probability of blackouts

(loss of load) and consumers’ willingness to pay to avoid them against the cost of building new capacity.

8See Appendix K for control costs.
12 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Implementing Emission Caps: Cost and Price Impacts

When emission caps are imposed in the electricity sector, power suppliers can be expected to take actions to

reduce those emissions. In some cases they will add

emissions control equipment, such as flue gas

desulfurization equipment to reduce SO2 and selective

catalytic reduction equipment to reduce NOx emissions. Depending on the economics, they might also

choose to retire some existing generating plants and

replace them with plants that have lower emissions.

For example, they might retire existing coal-fired

plants and replace them with plants that use natural

gas or renewable fuels to reduce CO2 emissions. In

turn, in response to price changes, consumers would

be expected to reduce their consumption of electricity

by increasing their use of non-electric appliances,

changing their usage patterns for electric appliances,

and investing in more efficient electricity-using

equipment.

Each of these actions will have costs. For the power sector, there will be costs associated with increased investments in control equipment and new generating

plants. There may also be higher costs associated with

maintaining and operating new emission control

equipment. Similarly, if new plants require more

expensive fuel (i.e., natural gas rather than coal), total

fuel costs would also be higher. There also could be

costs associated with purchasing and holding emission

allowances (or paying fees) on unabated emissions.

The degree to which such costs are reflected in consumers’ electricity prices (inducing them to reduce

their consumption of electricity) and the impact on the

economy will be affected by numerous factors.

A variety of policy instruments may be used in efforts

to reduce electricity sector emissions. Possible

approaches include explicit emissions or technology

standards for all generators, a fee on targeted emissions, and marketable (tradable) emission permits

assigned or auctioned to generators based on historical

emissions (grandfathering) or current year output

(such as through the use of a generation performance

standard). Each of these policy instruments has cost

and price implications.a

This analysis assumes a marketable emission permit

approach modeled after the SO2 allowance program

created in CAAA90. It is assumed that emission permits or allowances would be provided to affected

sources by the regulatory authority, and that the total

number of allowances issued to all affected parties

would be equal to the national target emissions cap. To

be in compliance each year, the number of allowances

held for each affected source would have to be equal to

or larger than their emissions. Allowances held for an

affected source that are not needed could be sold to

others.

As allowances are bought and sold a market price will

develop for them. Power suppliers will use this price to

decide whether to reduce their emissions or purchase

allowances to cover them. When deciding whether or

not to operate a facility that produces emissions subject

to a cap, the owner will include the market price of the

allowance as part of the operating costs of the plant. As

with fuel, operating the plant will consume an asset—

the allowance—that could be sold if the plant were not

operated.

The costs associated with the investment and operating

decisions made by power suppliers to meet the emissions cap together with the costs of acquiring emission

allowances will affect the market price for electricity. In

competitive markets the generation price is based on

the variable operating costs (what economists refer to

as “marginal costs”) of the plant setting the market

price at any given point in time. In other words, the

running plant with the highest operating cost generally

sets the market price for power. Typically, for fossil

fuel plants, operating costs are dominated by fuel

costs, with only a small portion coming from other

operating and maintenance costs. If the costs of the

plant setting the market price for power are increased

by expenditures associated with running new pollution control equipment, using higher cost fuel, and/or

purchasing allowances to cover its emissions, the competitive market price for power will reflect those costs.

Thus, the total price impact of implementing the emission cap program will include changes in resource

costs (i.e., higher operating and maintenance costs and

higher fuel costs) together with the allowance purchase

costs that raise the operating costs of the plants setting

the market price.

While power marketsb in the United States are becoming increasingly competitive, they are not fully competitive today. In some areas of the country, prices are

not set by the marginal costs of producing power.

Rather, they are set by dividing the total costs (i.e., fuel

costs, operating maintenance costs, capital recovery

costs, and a regulated return on investment) by the

amount of power sold. In such markets, the costs

associated with adding emission control equipment, (continued on page 13)

aFor a discussion of the relative merits of alternative policy instruments, see Perman, Ma, and McGilvray, “Pollution Control Policy,”

in Natural Resource and Environmental Economics (Addison Wesley Longman, 1996). bThis discussion refers only to the generation sector of the electricity market. The transmission and distribution sectors are assumed to

continue to price their services on a cost-of-service basis.
each case. The bank of 11.6 million tons of SO2 allowances accumulated through 1999 was assumed to be

used between 2000 and 2015 in each case.

To reduce NOx emissions, the options include decreasing the utilization of relatively high emitting plants,

adding combustion controls that remove NOx from the

exhaust gases of a plant (i.e., low-NOx burners) and/or

post-combustion controls (i.e., selective noncatalytic

reduction [SNCR] or selective catalytic reduction [SCR]

equipment), retiring high emitting plants, or, through

higher prices, encouraging consumers to reduce their

electricity use. For this analysis the emission caps on SO2

and NOx specified by the Subcommittee are treated as

annual national caps, and allowance trading is allowed

among plants throughout the country. It is assumed that

the NOx program would operate like the existing SO2

allowance program. As with the SO2 program, the marginal cost of reducing NOx emissions sets the allowance

price.

To reach the power sector CO2 emissions target, the

model chooses among investments in lower emitting

technologies (mainly natural gas and renewables),

changes in operations of existing and new power plants

(using lower emitting resources more intensively than

higher emitting resources), and conservation activities

by consumers (induced by higher prices). The model

solves for the allowance price that encourages power

suppliers and consumers to make changes in investment, operations, and conservation activities.9 In this

analysis the CO2 cap is applied only to the power sector,

because emissions in other sectors of the economy are

not restricted in the cases specified by the Subcommittee. When multiple emissions caps are imposed, the

model solves for the most economical way to meet all of

them simultaneously.

The steps taken to reduce NOx, SO2, and CO2 emissions

affect the price of electricity. The EMM has the option to

price power (the generation component of the energy

business) in either a regulated cost-of-service environment or a competitive market environment. Generally,

in regions in which the majority of the electricity sales

are in States that have passed legislation or enacted regulations to open their retail markets, generation prices

are assumed to be derived competitively. The fully competitive regions include California, New York, New

England, the Mid-Atlantic Area Council (consisting of

Pennsylvania, Delaware, New Jersey, and Maryland),

and Texas.

In regions where only a portion of the States have

opened their retail markets, the regulated and competitive generation prices are weighted (by the share of sales

in the respective states) to derive an average regional

price. These regions include the East Central Area, the

Rocky Mountain-Arizona regions, the Mid-America

Interconnected Network, and the Southwest Power

Pool. In all the other regions power prices are assumed

to continue to be regulated; however, because wholesale

generation markets throughout the country are moving

toward competition, all new generators are assumed to

be built as merchant power plants that will sell their

power at market-based rates. For this reason, this analysis treats the allowance prices that arise when emission

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 13

Implementing Emission Caps: Cost, and Price Impacts (Continued)

switching fuels, and building replacement plants to

reduce emissions would be added to the aforementioned total costs and a new price would be derived.

The treatment of allowance costs will depend on how

they are allocated and whether the public service commission in a particular State requires costs (or profits)

from allowance transactions to be recovered from (or

returned to) customers or borne by shareholders.

However, because of the increasing role played by

wholesale power market transactions and the dominance of independent power producers (IPPs) in building new capacity this analysis assumes that allowance

costs will be included in the operating costs of power

producers in regulated markets.

It is expected that, even in regulated cost-of-service

regions, IPPs will dominate new power plant additions, and because they will have to purchase allowances to cover their emissions, the allowance costs will

be included in their competitively priced power contracts with utilities. In the latest data supplied to EIA,

utilities reported plans to add 10,623 megawatts of

capacity between 1999 and 2003. Over the same time

period nonutilities reported plans to add 61,456 megawatts, or 85 percent of the total. As a result, in this analysis it is assumed that IPPs will build all new power

plants and sell the electricity at market-based rates—

which will include the costs of needed emission

allowances.

If the pace of deregulation slows and electricity prices

continue to be set on a cost-of-service basis, then

assuming that allowance costs would be reflected in

the operating costs of all plants with the targeted emissions may overstate the price impacts. The operating

costs for existing regulated plants that received allowances at no cost would not include the opportunity

costs of holding allowances.

9The EMM represents coal- and gas-fired generating technologies with carbon removal and sequestration equipment, but the technologies are not cost-effective in the time frame of this analysis.
14 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Generation Performance Standards

Several of the bills proposing multi-emissions strategies for the electric power sector call for the use of a

policy instrument different from the allowance

allocations assumed in this analysis—an instrument

referred to as a generation performance standard

(GPS). The approach used in this report is based on the

existing SO2 program, where emission allowances are

allocated to generating plants at the beginning of the

program without charge, and the allocations do not

change over time. In contrast, under a dynamic GPS

approach, allowances would be reallocated each year,

based on a plant’s megawatthour output. For example,

if the national cap on CO2 emissions were set at 1.914

billion tons (the 1990 CO2 emission level for the electricity sector) and the total generation for all covered

plantsa equaled 4 billion megawatthours in a particular

year, the GPS would equal 0.479 tons CO2 per

megawatthour generated (0.119 metric tons carbon

equivalent). Because the generation from covered facilities is expected to change over time, the GPS would be

recalculated annually.

A dynamic GPS allowance allocation scheme as

described above (“dynamic” because the allocation is

revised each year) would lead to different cost and

price impacts from those shown in this report. The

one-time fixed allowance allocation scheme assumed

in this report results in the full allowance price becoming part of the operating costs for all plants producing

the targeted emission. For example, if a plant produced

0.200 metric tons of carbon (0.733 tons CO2) per megawatthour and the carbon allowance price was $100 per

metric ton, the operating costs of that plant would

increase by $20 per megawatthour ($100 × 0.2). Under

the dynamic GPS approach the impact on the same

plant’s operating costs would be lower. Using the GPS

value from the previous paragraph, the plant would

need to purchase allowances equal to the difference

between its emission rate and the GPS rate—or 0.200

minus 0.119. As a result, the plant’s operating costs

would only increase by $8 per megawatthour ($100 ×

[0.200 – 0.119]). If the sample plant were a price-setting

plant, the net effect of the dynamic GPS allowance allocation scheme would be that the full cost of holding

allowances for the plant ($20 per megawatthour)

would not be passed on to consumers. In effect, the

plant would receive an output rebate or subsidy of $12

for each megawatthour produced, and the subsidy

would be passed on to consumers in the form of lower

electricity prices.

Because the full marginal cost of reducing emissions

would not be passed on under the GPS scheme, consumers would have a smaller incentive to reduce their

electricity consumption than they would with the fixed

allowance allocation scheme used in this analysis. Consequently, power suppliers would need to take additional steps to meet the various emission targets, in

order to compensate for a smaller demand response

from consumers. They would have to reduce coal consumption and increase natural gas and renewable fuel

consumption more than they would under a fixed

allowance allocation program. The increased use of

natural gas can be expected to lead to higher gas prices

and, in turn, a higher allowance price to stimulate further reductions.

In comparison with the results presented in this report,

the use of a dynamic GPS allowance allocation scheme

would be expected to lead to a smaller increase in the

price of electricity but higher natural gas prices and a

higher CO2 allowance price. The degree to which natural gas and CO2 allowance prices would be higher

would depend on the expected responsiveness of consumers to higher electricity prices and the sensitivity of

the natural gas market to additional demand from the

electricity sector.

In this analysis, the natural gas sector is projected to

have to increase production by record levels to meet

the 2005 CO2 emission targets, and additional increases

in demand from the electricity sector could lead to significant price increases above those already projected.

As one expert puts it, “output based rebating sacrifices

some of the efficiencies of market-based environmental

policies. Allocating by market share essentially provides a subsidy to output, which creates a bias away

from output substitution and toward emissions rate

reduction. The result is a higher marginal cost of control, a lower equilibrium output price, and a greater

cost to achieving any given level of emissions reduction, compared to an efficient policy. The size of the

welfare loss from this distortion depends on how much

emissions reduction would normally be performed by

output substitution.”b

aThe definition of “covered units” can differ. In some cases allowances would be allocated to all generating plants; in others they

would be allocated only to fossil-fired plants. bC. Fischer, Rebating Environmental Policy Revenues: Output-based Allocations and Tradable Performance Standards (Washington, DC:

Resources for the Future, January 21, 1999).
caps are imposed as if they were imposed on competitive markets. The allowance prices become part of the

operating costs of power plants that produce the targeted emissions.10

In competitive regions, generation prices are based primarily on the operating costs of the power plant setting

the market-clearing price at any given time. In other

words, the plant producing power with the highest

operating costs sets the price of generation during each

time period. An additional adjustment is made to reflect

consumers’ willingness to pay for reliable service, especially during high usage periods. When emission caps

are imposed, the allowance costs or fees associated with

them become part of the operating costs for power

plants that produce the affected emissions. As a result, in

competitively priced regions, the fees or allowance costs

for SO2, NOx, and CO2 become part of the operating

costs for power plants that burn fossil fuels. When a

plant needing emission permits sets the market price for

power, the per-kilowatthour cost of holding the permits

is reflected in the retail electricity price. This can lead to

increased profits for companies owning plants for which

emission reduction costs are below the marginal reduction costs. Equally important is the assumption that

when the costs fall on plants that do not set the market

price, their owners will not be able to pass any of them

on to consumers. In regulated regions, the total costs

associated with adding emissions control equipment,

using higher cost fuels, and retiring or replacing plants

to reduce SO2, NOx, and CO2 emissions are recovered

along with the costs of holding allowances and other

costs.

To represent the RPS (to be analyzed in the forthcoming

volume), the EMM has the ability to require that generation from nonhydroelectric renewable facilities (including cogenerators) be greater than or equal to a specified

amount. In this analysis the required amount is determined by multiplying the specified share in a given year

by the total projected sales of electricity in that year. The

most economical nonhydroelectric renewable options

are constructed to meet the RPS requirement. As with

the emission cap programs described above, the RPS

program is operated as a market credit system. It is not

required that each power seller produce or purchase the

required renewable share. As an alternative, they must

hold renewable “credits” equal to the required share.

Credits are issued to those generating power from qualifying renewable facilities and, as in the case of SO2

allowances, may be sold to others. The projected price of

the credits becomes part of the operating costs of

nonqualifying facilities. In each of the RPS cases it is

assumed that the program continues through 2020 and

that there is no legislated limit on the credit price.11

Coal Market Module

The Coal Market Module (CMM) provides annual forecasts of prices, production, and distribution of coal to the

various consumption and energy transformation sectors

of NEMS. It simulates production from 11 coal supply

regions that meets demands for steam and metallurgical

coal from 13 U.S. demand regions and incorporates an

international coal trade component that projects world

coal trade, including U.S. coal exports and imports.

The CMM uses a linear programming algorithm to

determine the least-cost (minemouth price plus transportation cost) supplies of coal by supply region for a

given set of coal demands in each demand sector in each

demand region. Separate supply curves are developed

in the CMM for each of 11 supply regions and 12 coal

types (unique combinations of thermal grade, sulfur

content, and mine type). The modeling approach used to

construct the 35 regional coal supply curves represented

in the CMM addresses the relationship between the

minemouth price of coal and corresponding levels of

coal production, labor productivity, and the cost of factor inputs (mining equipment, mine labor, and fuel

requirements).

More than 90 percent of U.S. coal production is consumed domestically, and electric utilities and independent power producers account for approximately 90

percent of U.S. consumption. Steam coal is also consumed in the industrial sector to produce process heat,

steam, and synthetic gas and to cogenerate electricity.

Metallurgical coal is used to make coke for the iron and

steel industry. Approximately 6 million tons of steam

coal are consumed in the combined residential and commercial sector annually.

Coal is heterogeneous in terms of its energy, sulfur,

nitrogen, carbon, and mercury content. Thus, the geographic source of coal can be a significant factor in the

physical quantity of coal necessary to provide a given

quantity of energy and the resultant level of emissions.

Coal prices also vary significantly based on the heat content, quality, and regional source of the coal. For example, low-sulfur, low-Btu coal from the Powder River

Basin in Wyoming and Montana has a minemouth price

that is only about 20 percent that of some coal types

mined in the Appalachian region. The variation in

regional coal prices, coupled with shifts in the amount of

coal originating from each region, can lead to changes in

U.S. average minemouth prices across cases that are

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 15

10Competitive prices are applicable only to the generation sector of the electricity market. Prices for transmission and distribution services are assumed to continue to be based on cost-of-service regulation.

11The Administration’s proposed Comprehensive Electricity Competition Act (CECA) limits the credit price to 1.5 cents per

kilowatthour.
more related to altered distribution patterns than to the

level of aggregate coal demand.

During each year of the forecast period, the CMM

receives a set of coal demands, expressed in terms of

British thermal units (Btu), required by the different sectors in each region. The demands from the electricity

generation sector are further disaggregated into seven

categories within each demand region that depend on

boiler age, maximum allowable sulfur, and scrubber

availability. The EMM also provides the sulfur cap

(expressed in tons of SO2) that represents the maximum

emission level for that year. Based on these requirements, and subject to given coal contracts, a linear program within the CMM solves for a supply pattern that

meets all demands at minimum cost, subject to the sulfur

cap. The allowance price is calculated from this methodology; it is essentially the cost of reducing the last ton of

SO2 under the cap. This allowance price, in turn, is used

by the EMM to evaluate the economics of adding FGD

equipment to coal-fired generators.

For the most part, the CMM configuration used for the

reference case of this study is the same as was used for

the AEO2001. Certain sections of the linear program layout were restructured to provide a simplified format

and improved maintenance and reporting. Other sections of the linear programming code were redesigned

to accept case-specific factors to permit a generally

smooth drawdown of sulfur allowance banks from current levels (as of 2000) to zero in 2010 for all cases except

the sulfur cap cases, which reach zero in 2015. The latter

change results in different levels and timing for scrubber

retrofits relative to AEO2001.

All the analysis cases, with the exception of the NOx cap

cases (which have relatively minor impacts on U.S. coal

demand), incorporate two additional changes to the

CMM assumptions used for the reference case. All coal

contracts (between shippers and utilities) were modified

to be phased out no later than 2003. In addition, the set of

model constraints that gradually increases the fraction

of coal-burning capacity that can be converted to burn

low-sulfur, low-Btu subbituminous coal in a given year

was changed from the AEO2001 version to eliminate the

constraint by 2003. The two changes were made because

accelerated and more stringent emission restrictions are

assumed to be likely to constitute sufficient justification

to end contracts under force majeure provisions. The

changes also provide the necessary economic incentive

to install, on short notice, modifications to many power

plants that will permit the burning of coal blends containing substantial fractions of cheaper subbituminous

coal.

Renewable Fuels Module

The Renewable Fuels Module (RFM) consists of five

submodules that represent the major nonhydroelectric

renewable energy resources—biomass, landfill gas,

solar (thermal and photovoltaic), wind, and geothermal

energy. The RFM defines technology construction and

operating costs, fuel resource volumes and prices (biomass, landfill gas, and geothermal), and resource limitations for each renewable generating technology. These

characteristics are provided to the EMM for gridconnected central station electricity capacity planning

decisions.

Other renewable energy sources modeled elsewhere in

NEMS include conventional hydroelectric (in the EMM),

industrial and residential sector biomass, ethanol (in the

Petroleum Market Module), geothermal heat pumps,

solar hot water heating, and distributed (gridconnected) commercial and residential photovoltaics. In

addition to building new biomass plants, the EMM also

allows coal-fired power plants to use biomass (wood

and waste products) along with coal, a process referred

to as “co-firing.” The amount of biomass allowed in

co-firing varies from 0 to 5 percent on a heat input basis,

depending on the region in which the coal plant is

located. The share of biomass allowed is calculated on

the basis of its availability in a particular region. Biomass

co-firing gives coal-fired power plants the ability to meet

environmental regulations by using an alternative

low-emission fuel. It is assumed that the coal plants will

incur no additional capital or maintenance costs to consume up to 5 percent of their fuel as biomass. In addition, because the trees and plants that become biomass

consume CO2 during their growth, their net emissions

are assumed to be zero.

The price-quantity relationship for obtaining biomass

fuel is derived from aggregated biomass supply curves

that rely on data and modeling done by Oak Ridge

National Laboratory to project the quantities of four

types of biomass: agricultural residues, energy crops,

forestry residues, and urban wood waste/mill residues.

Because of recent legislative changes, this analysis (as in

AEO2001) assumes an extension of the production tax

credit under the Energy Policy Act of 1992 from December 31, 1999, through December 31, 2001, granting

tax-paying entities that build new wind or closed-loop

biomass facilities a tax credit of 1.7 cents per kilowatthour for the first 10 years of electricity generation from

qualifying facilities.

16 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
3. Electricity Market Impacts

Introduction

For the last 100 years, electricity production in the

United States has been dominated by power plants that

burn fossil fuels. Beginning with small hydroelectric

facilities in the early 20th century, the industry soon

turned to fossil fuels, particularly coal. An abundance of

economical coal has made it the dominant fuel in U.S.

electricity production since 1950 (Figure 2). Changes

occurred as relative fuel prices varied and new generating technologies evolved, but coal continued to account

for more than one-half of total generation. For example,

in the early 1970s oil use increased, but the price

increases of the late 1970s and early 1980s led to a rapid

decline in the use of oil by the mid-1980s. The role

played by nuclear power also grew in the 1970s and

1980s, when a large number of nuclear plants were constructed. The contribution from nuclear plants continued to grow in the 1990s because of performance

improvements at existing plants, but no new plants have

been ordered for a quarter century, and many previous

orders have been canceled. Renewables, predominantly

hydroelectric power, currently provide between 9 and

11 percent of total generation, depending on the availability of water from year to year.

Over the next 20 years coal use for power generation is

expected to continue to grow, but at a slower rate than in

the past. Although few new coal plants are expected to

be added, existing coal plants are projected to be used

more heavily as demand for electricity grows. Natural

gas is expected to be the dominant fuel when new plants

are needed. New natural-gas-fired combustion turbines

and combined-cycle plants are the most economical

options for most uses. New natural-gas-fired combined-cycle plants cost approximately half as much to

build as new coal plants, are substantially more efficient,

and have much lower emissions. These factors generally

offset the higher fuel cost for natural gas. Oil-fired generation is expected to continue to decline while total

renewable generation increases slightly in the overall

generation mix. Nuclear power is projected to continue

to contribute, but some older nuclear plants are expected

to be retired in the later years of the forecast, and no new

nuclear plants are forecast for the United States through

2020.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 17

1950 1960 1970 1980 1990 2000 2010 2020

0

1,000

2,000

3,000

4,000

5,000

6,000

Billion Kilowatthours

Coal

Gas

Oil

Nuclear

Hydropower

Renewable/Other History Projections

Figure 2. Electricity Generation by Fuel, 1949-1998, and Projections for the Reference Case, 1999-2020

Sources: History: Energy Information Administration, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: National Energy Modeling System, run MCBASE.D121300A.
In the NEMS projections, the imposition of the NOx, SO2,

and, especially, the CO2 emission caps analyzed in this

report has impacts on all aspects of the electricity generation business. The emission caps affect capacity planning and plant retirement decisions, investments in

emission control equipment, fuel choices for generation,

electricity supply sector costs, and consumer prices. In

turn, the change in electricity prices causes consumers to

alter their electricity use by buying more efficient appliances, switching to other fuels, or generating their own

electricity. This chapter discusses these issues together

with the potential impact on total CO2 emissions and

key uncertainties in the projections.

Capacity Planning

In the reference case for the analysis, more than 410

gigawatts of new capacity (roughly 1,367 new

300-megawatt plants) is projected to be needed to meet

the growing demand for electricity over the next 20

years and to replace 63 gigawatts of retiring power

plants. The vast majority, approximately 92 percent, of

the new capacity added is projected to be natural-gas-fired combustion turbines and combined-cycle

facilities,12 because their low construction costs and relatively high efficiencies make them economical for most

uses. In terms of levelized costs—the costs of building

and operating a new plant throughout its life—these

plants are less expensive than other options for most

uses (Figure 3). Other factors, such as their relatively

small, modular size, low initial capital costs and low

emission rates, also make them attractive.

New coal-fired plants can be economical when new

plants are needed to serve continuous (baseload) needs,

or when the difference between coal and natural gas

prices delivered to power plants widens beyond $2.50 or

so per million Btu. In the reference case this is projected

to occur early in the forecast period, before gas prices

begin declining from their current levels, and later in the

projections, as increasing natural gas use leads to higher

gas prices. For new renewable technologies, costs generally are projected to remain higher than those for coal

and gas plants. Although costs have declined for wind,

biomass, and solar generation technologies over the past

20 years, they still are not expected to be broadly competitive with new gas-fired plants for major capacity

additions, absent subsidies or other support of some

kind.

In the analysis cases, the dominant role of new gas-fired

plants is projected to continue with the imposition of

NOx, SO2, and CO2 emission caps; however, the projections suggest that the caps would alter the economics of

operating existing coal plants. Although coal plants are

the major emitters of CO2, SO2, and NOx in the power

sector, they are very economical to operate. Producing

some of the least expensive power available, the vast

majority are projected to continue operating through

2020 in the reference case. When tighter emission regulations are assumed, however, operating and retirement

decisions for the coal-fired plants now in operation are

expected to change. Owners of the facilities will have to

decide whether to pay the costs for emission allowances

and fees, invest in new emission control equipment, or

retire the facilities.

In the reference case, relatively few coal plants—10

gigawatts of capacity (just over 3 percent of total existing

coal-fired capacity in 1999)—are projected to be retired

(Table 6). In response to NOx emission caps alone,

whether imposed in 2005 or 2008, coal plant retirements

are expected to be nearly the same as in the reference

case. The primary compliance options to meet the NOx

emission caps are adding SNCR and SCR emission control equipment. In the reference case, SNCR and SCR

controls are expected to be added to nearly 128

gigawatts of capacity to comply with the 19-State summer season NOx cap beginning in 2004 (Table 7). In the

2005 and 2008 NOx cap cases, however, more than twice

that capacity—between 303 and 311 gigawatts—is projected to have one or the other post-combustion emission control technology added.

SNCR and SCR equipment can be expensive to add,

especially to smaller plants that are used infrequently;

but for many plants the projections indicate that it

would be more economical to add the emission controls

than to replace the plants. The EPA estimates used in

18 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Advanced

Combined Cycle

Advanced

Coal

Wind Nuclear

0

10

20

30

40

50

60

70

1999 Mills per Kilowatthour

Capital

O&M

Fuel

Figure 3. Reference Case Projections of Levelized

Costs for New Power Plants, 2005

Source: National Energy Modeling System, run MCBASE.

D121300A.

12See Appendixes A-I for detailed tables of the results for each of the cases.
this analysis show that adding SCR equipment to a

200-megawatt coal plant would cost approximately $72

per kilowatt and reduce NOx emissions by between 70

and 80 percent.13 Because only a few more coal plants

are expected to be retired in these cases than in the

reference case, there is little change in the projections for

natural-gas-fired generation.

The primary options for reducing SO2 emissions at coal

plants are switching to lower sulfur coal, adding flue gas

desulfurization (FGD) equipment (scrubbers), or retiring plants. In the reference case, to comply with the

CAAA90 phase II emission cap, switching coal and adding scrubbers both play important roles. Scrubbers are

expected to be added to approximately 15 gigawatts of

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 19

Table 6. Projected Coal Plant Retirements, 2005-2020

(Cumulative Gigawatts of Capacity Retired After 1998)

Analysis Case 1999-2005 1999-2008 1999-2010 1999-2015 1999-2020

Reference . . . . . . . . . . . . . . . . . . . . . . 7 9 9 10 10

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . . . . 9 10 10 11 11

SO2 2008 . . . . . . . . . . . . . . . . . . . . . 8 9 9 10 11

SO2 Sensitivity. . . . . . . . . . . . . . . . . 9 10 10 11 11

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . . . 9 23 45 63 66

CO2 1990-7% 2008 . . . . . . . . . . . . . 8 16 37 67 70

CO2 Sensitivity. . . . . . . . . . . . . . . . . 8 15 22 33 40

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . . . 7 20 41 58 66

Integrated 1990-7% 2005 . . . . . . . . 8 22 47 73 79

Integrated 2008 . . . . . . . . . . . . . . . . 7 16 35 62 68

Integrated 1990-7% 2008 . . . . . . . . 7 17 42 85 90

Integrated Sensitivity . . . . . . . . . . . . 9 17 26 37 44

Source: National Energy Modeling System, runs MCBASE.D121300A (reference), MCNOX05.D121300A (NOx 2005), MCNOX08.D121300A

(NOx 2008), MCSO205.D121300A (SO2 2005), MCSO208.D121300A (SO2 2008), MCSO205H.D121300A (SO2 sensitivity), FDC7B05.D121300A

(CO2 1990-7% 2005), FDC7B08.D121300A (CO2 1990-7% 2008), FDC7B05H.D121300A (CO2 sensitivity), FDPOL05.D121300A (integrated 2005),

FDP7B05. D121300B (integrated 1990-7% 2005), FDPOL08.D121500A (integrated 2008), FDP7B08.D121500A (integrated 1990-7% 2008), and

FDP7B05H. D121300A (integrated sensitivity).

Table 7. Projected Additions of Power Plant Emission Controls, 1999-2020

(Gigawatts)

Analysis Case

Emission Control Technology

SNCR SCR FGD

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 90 15

NOx Cap Cases

NOx 2005. . . . . . . . . . . . . . . . . . . . . . . . . . 59 252 14

NOx 2008. . . . . . . . . . . . . . . . . . . . . . . . . . 60 243 15

SO2 Cap Cases

SO2 2005. . . . . . . . . . . . . . . . . . . . . . . . . . 32 117 128

SO2 2008. . . . . . . . . . . . . . . . . . . . . . . . . . 27 124 130

SO2 Sensitivity. . . . . . . . . . . . . . . . . . . . . . 36 96 52

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . . . . . . . . 16 42 0

CO2 1990-7% 2008 . . . . . . . . . . . . . . . . . . 22 54 0

CO2 Sensitivity . . . . . . . . . . . . . . . . . . . . . 26 54 0

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . . . . . . . . 56 157 21

Integrated 1990-7% 2005 . . . . . . . . . . . . . 49 147 17

Integrated 2008 . . . . . . . . . . . . . . . . . . . . . 48 123 23

Integrated 1990-7% 2008 . . . . . . . . . . . . . 38 108 18

Integrated Sensitivity . . . . . . . . . . . . . . . . . 26 60 8

SNCR = selective noncatalytic reduction. SCR = selective catalytic reduction. FGD = flue gas desulfurization (scrubbers).

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, MCSO205H.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A, FDPOL05.D121300A,

FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.

13U.S. Environmental Protection Agency, Analyzing Electric Power Generators Under CAAA, web site www.epa.gov.
capacity through 2020, while the share of coal consumption coming from lower sulfur western mines is

projected to grow from 44 percent in 1999 to 58 percent

in 2020. The price of SO2 emission allowances is projected to be $170 per ton in 2010 and $246 per ton in 2020

in the reference case.

The requirements for tighter emission controls in the

SO2 cap cases are projected to lead to a slight increase in

the number of coal plant retirements and an increase in

scrubber additions among remaining coal plants. The

3,273,000-ton annual cap in the SO2 cap cases would be

difficult to meet primarily through switching to

low-sulfur coal. Assuming that coal plants were to continue to operate as they do in the reference case, the

8,950,000-ton CAAA90 cap implies an average emission

rate at coal plants of 0.8 pounds per million Btu—an

average rate that can be achieved by scrubbing some

plants and switching others to low-sulfur coal. Using the

same assumptions, the 3,273,000-ton cap implies an

average rate of approximately 0.3 pounds per million

Btu—a rate that would be difficult to meet at most plants

without adding scrubbers.

The 3,273,000-ton emission cap assumed in the SO2 cap

cases is not projected to be met until well after the effective dates of the caps, because it is assumed that power

plant owners would be able to use any allowances they

had accumulated through 1999. For this analysis it was

assumed that the banked allowances would be used by

2015. As a result, the cap would not be fully binding

until 2016 in the SO2 cap cases. Because of the stringent

cap in the SO2 cases, between 128 and 130 gigawatts of

capacity is projected to add scrubbers (Table 7). As in

other cases, natural-gas-fired plants are expected to

remain the most economical option when new plants are

needed. As a result, projected additions of renewable

plants are the same in the SO2 cap cases and the reference case.

The expected SO2 allowance prices in the SO2 cap cases

are much higher than those in the reference case (Figure

4). The initial response to the more stringent SO2 cap is

expected to include adding scrubbers to larger coal

plants; retiring older, smaller coal plants; and adding

new natural gas combined-cycle plants to replace them.

The projections for SO2 allowance prices are sensitive to

the variation in the assumed SO2 emission target. The

SO2 allowance prices are projected to reach $735 per ton

in 2010 in the SO2 2005 case and $300 per ton in the SO2

sensitivity case (Figure 5). Under the less stringent emission target assumed in the SO2 sensitivity case, the

expected need to add emission controls and switch to

lower sulfur coals is significantly reduced.

The amount of emission control equipment projected to

be needed in the NOx and SO2 cap cases, particularly

those with 2005 compliance dates, could cause system

operational problems under some conditions. Typically,

when new emissions controls are added, particularly

SCRs, a plant must be off line for a time so that final connections can be made. Several recent studies have

looked into whether the outage times (beyond normal

maintenance outages) required to make final connections for equipment needed to meet the NOx SIP call

might lead to system operational and reliability problems. While the results of the studies differed, several

factors were identified as critical to the analysis, including the calendar time between the announcement of the

program and the compliance date, the growth in

demand for electricity, the availability of sufficient

reserve capacity, coordination among companies performing work on their plants, and the interconnection

time needed for each plant.

In this analysis, new generating capacity is assumed to

be built as needed to meet customer demand and maintain reliability in all years and regions. While this

approach is reasonable in the long run, it is not meant to

capture the potential for market problems in the short

run. For example, if the demand for electricity grows

more rapidly than expected over the next few years

and/or delays occur in the siting and permitting of

needed new plants, the additional requirement of adding a large amount of emission control equipment could

exacerbate a tight market situation, leading to larger

near-term price impacts than are shown in this analysis.

In the CO2 cap cases, carbon allowance fees are expected

to make it uneconomical to continue operating a large

number of existing coal plants. In addition, no new coal

plants are expected to be added. Unlike the NOx and SO2

cap cases, the CO2 cap cases project that power plant

operators would not be able to use emission control

technologies to meet the assumed cap, at least not in the

time horizon of this analysis. Instead they are expected

to have to reduce their reliance on coal significantly and

turn to lower carbon fuels, primarily natural gas. By

2020, between 66 and 70 gigawatts (22 to 23 percent) of

existing coal plants are projected to be retired to comply

with the CO2 caps. The need for new NOx and SO2 emission control equipment is projected to be much lower in

the integrated sensitivity case, because the CO2 cap

causes enough switching from coal to gas to allow the

electricity generation sector to meet the assumed annual

NOx and SO2 caps without adding much additional

emission control equipment.

Carbon allowance fees in the CO2 cap cases are projected

to range from $139 and $143 per metric ton carbon

equivalent in 2010 to $139 and $141 in 2020 (Figure 6).

The integrated cases that set the carbon cap at 7 percent

below the 1990 level produce the largest number of

projected coal plant retirements and the largest projected increases in investments in new gas and renewable plants. The carbon allowance fee, which is assumed

to be added to the electricity production price of all

20 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
fossil-fired plants in proportion to the carbon content of

their fuels, makes relatively low-carbon natural gas and

carbon-free renewable and nuclear technologies more

economically attractive than coal or oil facilities. It also

makes maintaining existing nuclear plants more attractive than in the reference case. Relative to the reference

case, between 49 and 66 gigawatts more gas-fired capacity and 34 to 38 gigawatts more renewable capacity are

projected to be added,14 and 12 to 17 gigawatts less

nuclear capacity is projected to be retired.

In the CO2 sensitivity and integrated sensitivity cases,

the less stringent CO2 cap is projected to lead to carbon

allowance fees that are lower than those projected in the

comparable CO2 1990-7% 2005 and integrated 1990-7%

2005 cases. In 2010, the carbon allowance fees projected

in the CO2 sensitivity case are between $37 and $41 per

metric ton carbon equivalent less than those projected in

the comparable cases with the more stringent CO2 caps.

A large amount of new gas-fired capacity is still

expected to be needed in these cases to meet the caps,

but the amount of renewable capacity added—above the

level projected in the reference case—is much less than

projected in the cases with more stringent CO2 caps. The

relative economics of new renewable capacity are sensitive to the projected carbon allowance fees. In the CO2

sensitivity and integrated sensitivity cases, between 16

and 18 gigawatts more new renewable capacity is projected to be built than in the reference case.

The results in the integrated cases essentially mirror

those of the CO2 cap cases; the magnitude of the projected changes in power plant operations to comply

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 21

2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

0

200

400

600

800

1,000

1,200

1,400

1999 Dollars per Ton

Reference

NOx 2005

NOx 2008

SO2 2005

SO2 2008

CO2 1990-7% 2005

CO2 1990-7% 2008

Integrated 2005

Integrated 1990-7% 2005

Integrated 2008

Integrated 1990-7% 2008

Figure 4. Projected SO2 Allowance Prices, 2000-2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.

2000 2010 2020

0

200

400

600

800

1,000

1,200 1999 Dollars per Ton

Reference

SO2 2005

SO2 Sensitivity

Figure 5. Projected SO2 Allowance Prices, 2000,

2010, and 2020

Source: National Energy Modeling System, runs MCBASE.

D121300A, MCSO205.D121300A, and MCSO205H.D121300A.

14See Chapter 4 for a discussion of the specific renewables projected to be added.
with the CO2 cap generally overwhelms the projected

impacts of the NOx and SO2 caps. New natural gas

plants and, to a lesser extent, renewable plants are projected to be added to meet the growing demand for electricity and to replace retiring coal plants (Figure 7). The

need for new capacity in the integrated cases, especially

those with the 1990-7% CO2 cap, is projected to require

rapid construction of new plants. Almost 129 gigawatts

of new capacity is projected to be needed in the integrated 1990-7% 2005 case by 2005. That rate of construction— averaging 21 gigawatts per year—would be more

than double the rate of construction of new generating

plants during the 1990s, which averaged only 7

gigawatts per year, and 26 percent above the level

expected in the reference case.

Construction rates higher than 20 gigawatts per year

were last seen in the 1980s, indicating that such construction levels are achievable. Figure 8 superimposes

annual capacity additions for the period 1965 to 1985 on

the projected additions from 2000 through 2020 in the

integrated 1990-7% 2005 case, showing that the amount

of new capacity projected to be needed in this case

would be near the record levels seen in the past. This

would be a difficult challenge to meet in a short time

period. Combining the CO2 cap with the NOx and SO2

caps is expected to reduce the need to add SNCR, SCR,

and FGD equipment to reduce emissions from existing

plants (Table 7), because so many coal plants are projected to be retired to meet the CO2 cap.

The degree to which the CO2 cap overwhelms the

impacts of the other caps can be seen in the projections of

NOx and SO2 emissions in the CO2 cap cases (which

assume no additional restrictions on NOx and SO2 emissions beyond those assumed in the reference case) (Table

8). In the CO2 1990-7% 2005 case, power sector NOx

emissions in 2010 are projected to be 41 percent below

their projected level in the reference case and within 0.9

22 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

1999 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

0

20

40

60

80

100

120

140

160

1999 Dollars per Metric Ton Carbon Equivalent

CO2 1990-7% 2005

CO2 1990-7% 2008

Integrated 2005

Integrated 1990-7% 2005

Integrated 2008

Integrated 1990-7% 2008

CO2 Sensitivity

Integrated Sensitivity

Figure 6. Projected Carbon Fees, 1999-2020

Source: National Energy Modeling System, runs FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A, FDPOL05.

D121300A, FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.

1999-2000 2001-2005 2006-2010 2011-2015 2016-2020

0

50

100

150

-50

-100

Gigawatts

Gas Renewable Retirements

Figure 7. Projected Capacity Additions by Fuel and

Projected Retirements in the Integrated

1990-7% 2005 Case, 1999-2020

Source: National Energy Modeling System, run FDP7B05.

D121300B.
million tons of the more stringent NOx cap. Similarly,

SO2 emissions in 2010 in the CO2 1990-7% 2005 cap case

are projected to be 17 percent below their projected level

in the reference case.

As in the CO2 cap cases, fewer nuclear power plants are

projected to be retired in the integrated cases than in the

reference case. Approximately 26 gigawatts (27 percent)

of existing nuclear capacity is projected to be retired in

the reference case, because it is expected that it will

become less expensive to replace aging nuclear plants

than to maintain them. In the CO2 cap and integrated

cases, however, the combination of carbon allowance

fees and higher natural gas prices is projected to make

replacing nuclear plants with coal or gas plants more

expensive. As a result, fewer are expected to be retired.

Total operating nuclear capacity in 2020 is projected to

range between 84 and 89 gigawatts in the CO2 cap and

integrated cases, as compared with 72 gigawatts in the

reference case and 97 gigawatts today.

In both the CO2 cap and integrated cases, cogeneration

and distributed generation capacity (in buildings) are

projected to increase above the levels projected in the

reference case. This analysis assumes that the proposed

emission caps would not apply to cogeneration and

distributed technologies located at customer sites. As a

result, when the projected price of power from the grid

increases, the economics of building on-site cogeneration or distributed generation facilities improve. In the

reference case, cogeneration and distributed generation

capacity additions are projected to total 19 gigawatts

between 1999 and 2020. In the CO2 cap cases the 2020

level is projected to be as much as 47 gigawatts higher.

Similar changes from the reference case are projected in

the integrated cases.

The vast majority of the cogeneration and distributed

generation facilities projected to be built by 2020 in the

CO2 cap and integrated cases are expected to be fueled

by natural gas, despite projections of higher gas prices in

these cases than in the reference case as a result of projected increases in natural gas use for central station

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 23

Table 8. Projected Emissions from Electric Power Plants, 2010 and 2020

Analysis Case

2010 2020

NOx

(Million Tons)

SO2

(Million Tons)

CO2

(Million Metric

Tons Carbon

Equivalent)

NOx

(Million Tons)

SO2

(Million Tons)

CO2

(Million Metric

Tons Carbon

Equivalent)

Reference . . . . . . . . . . . . . . . . . . . . 4.20 9.70 686 4.37 8.95 776

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . . . . . 1.55 9.70 677 1.60 8.95 769

NOx 2008 . . . . . . . . . . . . . . . . . . 1.55 9.70 678 1.59 8.95 768

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . 4.04 3.67 676 4.25 3.27 776

SO2 2008 . . . . . . . . . . . . . . . . . . 4.16 4.12 688 4.28 3.27 781

CO2 Cap Cases

CO2 1990-7% 2005. . . . . . . . . . . 2.47 8.09 437 2.01 6.68 439

CO2 1990-7% 2008. . . . . . . . . . . 2.33 7.77 430 1.95 6.61 441

Integrated Cases

Integrated 2005. . . . . . . . . . . . . . 1.37 4.22 474 1.18 3.27 477

Integrated 1990-7% 2005 . . . . . . 1.30 3.92 443 1.12 3.27 440

Integrated 2008. . . . . . . . . . . . . . 1.42 4.52 476 1.22 3.27 477

Integrated 1990-7% 2008 . . . . . . 1.32 4.02 430 1.16 3.27 440

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.D121300B, FDPOL08.D121500A, and

FDP7B08.D121500A.

0

10

20

30

40

50 Gigawatts

Projections (2000-2020)

History (1965-1985)

Figure 8. Projected Annual Capacity Additions in

the Integrated 1990-7% 2005 Case,

2000-2020, Compared with Historical

Annual Capacity Additions, 1965-1985

Sources: History: Energy Information Administration, Annual

Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: National Energy Modeling System, run FDP7B05.

D121300B.
electricity generation. For industrial cogeneration systems, combustion turbines burning natural gas are

expected to be the preferred technology, although some

systems currently being installed will use petroleum distillate fuels or byproduct gases from refining or chemical

processes.

A number of factors make it unlikely that new coal-fired

cogeneration systems will be built. For example, on a

purely economic basis, the capital cost of new coal systems is significantly more than the cost of modern turbine-based natural gas systems—in many cases, more

than twice as much. In addition, although fuel costs are

higher, turbine-based systems cost less to operate and

maintain than comparably sized coal plants. From a

technical perspective, coal systems are appropriate only

for a small portion of industrial facilities. Because coal

systems use boilers and steam turbines, they generally

have a power to heat ratio less than 0.5, which means

that coal-fired generators can only be used at sites with

high thermal loads. In addition, these boiler/steam turbine systems do not benefit from economies of scale at

sizes below 40 megawatts, which restricts their market

to larger industrial facilities. In contrast, combustion turbines can be cost-effective in systems as small as 1 megawatt, and they can be configured with power to heat

ratios ranging from 0.5 to 4.0. Current environmental

regulations also discourage the use of coal, with most

new systems requiring significant secondary pollution

abatement technologies to meet the emissions standards

in their permits.

Generation by Fuel

The projected fuel mix for electricity generation in the

NOx and SO2 cap cases (including the SO2 sensitivity

case) is not very different from that in the reference case.

In the SO2 cap cases slightly less coal-fired generation is

expected (generally 1 to 2 percent less in 2020) and

slightly more gas generation, because existing gas plants

are projected to be used more intensively and new gas

plants are projected to be added to replace the small

number of coal plants that are expected to be retired.

In contrast, the projected shift from coal to natural gas

and renewables is much larger in the CO2 cap and integrated cases. Natural-gas-fired generation is projected

to be much higher in the cases with CO2 caps than in the

reference case (Table 9). In the reference case, the share

of generation coming from natural gas is projected to

increase from 15 percent in 1999 to 20 percent in 2005, 24

percent in 2010, and 35 percent in 2020. In the integrated

1990-7% 2005 case, however, the projected natural gas

shares are 34 percent in 2005, 43 percent in 2010, and 55

percent in 2020 (Figure 9). Because of the relatively high

carbon content of coal—more than 70 percent higher per

Btu than natural gas—the projected market-based carbon allowance fee would make it uneconomical to

continue operating many coal plants. In addition, coal

plants that are not retired are expected to be operated

less intensively than in the reference case. The projected

share of generation for coal-fired power plants in the

integrated 1990-7% 2005 case is less than 17 percent in

2020, compared with 45 percent in the reference case.

Although the impact of power sector Hg emissions caps

is not addressed in this report, the projected reduction in

coal use in the CO2 cap and integrated cases is expected

to lead to lower mercury emissions. It is estimated that

coal-fired power plants in the United States currently

produce approximately 50 tons of Hg emissions per

year, approximately one-third of total U.S. Hg emissions. Generation from other fuels produces much lower

Hg emissions. With coal-fired generation projected to

increase by 26 percent between 1999 and 2020 in the reference case, Hg emissions are projected to grow over

time absent restrictions; however, the CO2 cap and integrated cases are projected to lead to significant reductions in the use of coal and, hence, Hg emissions. In the

most stringent case, the integrated 1990-7% 2005 case,

coal-fired generation is projected to be 64 percent below

the reference case level in 2020. Although the associated

decline in Hg emissions would depend on the specific

coal plants that continued generating, in percentage

terms it could be similar to the change in coal-fired generation. As mentioned above, constraints on Hg emission will be examined in a later report.

Renewables are also projected to account for a much

larger share of generation in the CO2 cap and integrated

cases than in the other cases (Table 10). Because renewable fuels produce virtually no NOx, SO2, or CO2 emissions, their operating costs would not be affected by

emission fees. As a result, they are expected to become

more economical relative to fossil-based alternatives in

the emission cap cases. In the reference case, because

hydroelectric generation is expected to stay near today’s

level, the share of generation accounted for by renewable fuels is projected to change very little, falling

slightly from 11 percent in 1999 to 8 percent in 2020. Generation from nonhydroelectric renewables is expected to

grow, but not enough to increase the overall share from

renewables.

In the CO2 cap and integrated cases, generation from

renewables is expected to be much higher than projected

in the reference case. The share of total generation

coming from renewable facilities is projected to be as

high as 14 percent in 2020 in the CO2 1990-7% 2005 case.

As discussed in Chapter 4, the projected level of renewable energy development, especially for nonhydroelectric renewables, in the CO2 cap and integrated

cases would be unprecedented in the United States and

would require significant growth in the manufacturing

and construction firms associated with renewable

technologies.

24 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
As with renewable capacity, the projections for renewable generation are sensitive to the assumed stringency

of the CO2 cap and the resulting carbon allowance fee.

With the less stringent CO2 cap assumed in the CO2 sensitivity and integrated sensitivity cases, renewable generation is not projected to grow nearly as much from the

reference case projections as it does in the comparable

CO2 cap and integrated cases. For example, in the CO2

1990-7% 2005 case, generation from renewable facilities

is projected to reach 712 billion kilowatthours in

2020—269 billion kilowatthours (61 percent) above the

level expected in the reference case. In both the CO2

sensitivity and integrated sensitivity cases, however,

renewable generation is projected to reach between 586

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 25

1950 1960 1970 1980 1990 2000 2010 2020

0

1,000

2,000

3,000

4,000

5,000

6,000

Billion Kilowatthours

Coal

Gas

Oil

Nuclear

Hydropower

Renewable/Other History Projections

Figure 9. Electricity Generation by Fuel, 1949-1998, and Projections for the Integrated 1990-7% 2005 Case,

1999-2020

Sources: History: Energy Information Administration, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: National Energy Modeling System, run FDP7B05.D121300B.

Table 9. Projected Electricity Generation from Natural-Gas-Fired Power Plants, 2005-2020

(Billion Kilowatthours)

Analysis Case 2005 2008 2010 2015 2020

Reference . . . . . . . . . . . . . . . . . . . . 813 973 1,123 1,521 1,866

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . . . . . 819 1,000 1,161 1,552 1,894

NOx 2008 . . . . . . . . . . . . . . . . . . 828 1,003 1,164 1,560 1,902

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . 816 1,015 1,195 1,574 1,911

SO2 2008 . . . . . . . . . . . . . . . . . . 801 1,003 1,146 1,570 1,901

CO2 Cap Cases

CO2 1990-7% 2005. . . . . . . . . . . 1,339 1,666 1,859 2,304 2,704

CO2 1990-7% 2008. . . . . . . . . . . 1,083 1,560 1,922 2,344 2,748

Integrated Cases

Integrated 2005. . . . . . . . . . . . . . 1,369 1,525 1,746 2,301 2,752

Integrated 1990-7% 2005 . . . . . . 1,367 1,683 1,839 2,324 2,774

Integrated 2008. . . . . . . . . . . . . . 1,060 1,615 1,789 2,309 2,746

Integrated 1990-7% 2008 . . . . . . 1,098 1,590 1,935 2,365 2,816

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.D121300B, FDPOL08.D121500A, and

FDP7B08.D121500A.
and 595 billion kilowatthours—143 to 152 billion kilowatthours (32 to 34 percent) above the reference case

projection.

Electricity Costs and

Consumer Prices

The addition of emission control equipment projected in

the analysis cases, combined with the projected shift

from coal to natural gas and renewables to comply with

the emission caps, and the resultant emission allowance

prices, has an impact on the costs faced by power suppliers and the electricity prices faced by consumers (Figure

10). In turn, the changes in prices lead consumers to alter

their energy usage decisions, both for electricity and

other fuels.

In the NOx cap cases it is projected that $17 billion would

be spent by power plant operators between 1999 and

2020 for new emission control equipment. These costs

represent $7 billion above the projected expenditures in

the reference case to comply with the NOx SIP Call.

Given that the 1998 net book value for plant investments

for investor-owned utilities is over $363 billion, the

projected costs are not large. Additional costs—in

the form of lost revenue—would be faced by power

plant operators who are projected to retire currently

profitable plants rather than face the costs of upgrading

them.

The increased costs for power plant operators, if

incurred in generation markets with cost-of-service regulation, would be passed on directly to consumers in

electricity prices. In competitively priced markets, however, the higher costs would be passed on to consumers

only if they increased the operating costs of the generating plants that set the market price for power. For example, if SCR equipment were added to reduce NOx

emissions from a coal plant that did not set the market

price for power, the costs of installing and operating the

equipment would not be passed on to consumers as long

as the plant’s operating costs remained below the market price. In effect, the net profit from the plant would be

reduced. Conversely, a plant with relatively low NOx

emissions that does not set the market price could see

higher profits in these cases.

In the NOx cap cases, a portion of the projected increase

in electricity generation costs would fall on plants not

setting the market price for power. In the NOx 2005 case,

the difference between the costs incurred and the

increased revenue to power plant operators is projected

to average $1.0 billion per year between 2005 and 2020

(Figure 11). The overall impact on electricity prices,

however, is projected to be small. The price of electricity

in 2010 is projected to be 1 percent higher than in the reference case.

In the SO2 cap cases, as in the NOx cap cases, the projected total investment in new emission control equipment would not be large relative to the $363 billion net

plant investment for investor-owned utilities in 1998.

Higher projected SO2 allowance prices and greater

dependence on natural gas would lead to higher generation costs and higher electricity prices. However, also as

in the NOx cap cases, a portion of the projected increase

in generation costs would fall on plants not setting the

market price for electricity (and a large part of the costs

are fixed capital costs that do not affect operating costs),

and therefore the full costs of investments in emission

control equipment would not be passed on to consumers

in electricity prices. The price of electricity in the SO2

2005 case is projected to be roughly 1 percent above the

reference case projection in 2010 and between 1 and 2

percent higher in 2020. Again, as in the NOx cap cases,

plants with low or no SO2 emissions would see

increased profits in these cases.

The impact on electricity prices is projected to be much

larger in the CO2 cap and integrated cases than in the

NOx and SO2 cap cases, because there are currently no

commercially available technologies for removing and

storing (sequestering) CO2. The only ways to make large

26 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 10. Projected Electricity Generation from Renewable Fuels, 2005-2020

(Billion Kilowatthours)

Analysis Case 2005 2008 2010 2015 2020

Reference. . . . . . . . . . . . . . . . . . . 401 421 429 438 443

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . 477 542 574 620 712

CO2 1990-7% 2008 . . . . . . . . . 483 551 581 610 679

CO2 Sensitivity . . . . . . . . . . . . . 481 539 559 563 595

Integrated Cases

Integrated 2005 . . . . . . . . . . . . 475 541 559 570 608

Integrated 1990-7% 2005. . . . . 474 538 561 602 677

Integrated 2008 . . . . . . . . . . . . 481 532 553 561 607

Integrated 1990-7% 2008. . . . . 482 540 562 588 658

Integrated Sensitivity . . . . . . . . 479 532 553 558 586

Source: National Energy Modeling System, runs MCBASE.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A,

FDPOL05.D121300A, FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.
reductions in CO2 emissions are to reduce the consumption of fuels with relatively high carbon content or to

increase the efficiency of electricity production and consumption. In addition, the CO2 allowance price

(throughout this report given in dollars per metric ton

carbon equivalent) falls on all fossil fuel generators,

those using coal, oil, and natural gas. Unlike in the NOx

and SO2 cases, because all fossil plants are affected, the

operating costs for plants setting the electricity market

price are expected to increase, and consumer electricity

prices are expected to increase with them. In these cases,

owners of existing non-fossil-fuel plants—nuclear,

hydroelectric, and other renewables—would see higher

profits as market prices increased because of the CO2

allowance price. The owners of relatively low carbon

fossil plants, such as very efficient natural gas plants,

could also benefit to a lesser degree.

Across the CO2 cap and integrated cases, the price of

electricity is projected to range from 17 percent to 33 percent higher than the reference case projection in 2005.

Because the assumed compliance dates are less than 10

years away, markets would not have much time to

adjust and take advantage of normal capital turnover.

As a result, the largest differences in projected electricity

prices relative to the reference case generally are seen

from 2005 to 2009. In the later years of the projections,

when new gas-fired and renewable generation facilities

are expected to be in operation, the projected differences

from the reference case are smaller. By 2020, prices in the

CO2 cap and integrated cases are projected to be

between 26 and 32 percent higher than projected in the

reference case. Because of the higher prices expected in

the CO2 cap cases and integrated cases, electricity consumers are projected to reduce their consumption of

electricity by 5.5 to 7.5 percent on average relative to the

reference case over the 2005 to 2020 time period.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 27

1999 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

0

2

4

6

8

10

1999 Cents per Kilowatthour

Reference

NOx 2005

NOx 2008

SO2 2005

SO2 2008

CO2 1990-7% 2005

CO2 1990-7% 2008

Integrated 2005

Integrated 1990-7% 2005

Integrated 2008

Integrated 1990-7% 2008

Figure 10. Projected Electricity Prices, 1999-2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.

NOx 2005 Case SO2 2005 Case

0

1

2

3

4

5

Billion 1999 Dollars

Costs Revenues

Figure 11. Projected Average Annual Changes

from Reference Case Power Plant Costs

and Revenues in the SO2 and NOx 2005

Cap Cases, 2005-2020

Source: National Energy Modeling System, runs MCBASE.

D121300A, MCNOX05.D121300A, and MCSO205.D121300A.
In each of the analysis cases, particularly the cases with

CO2 emission caps, the total impacts on electricity prices

reflect both the change in resource costs (higher fuel and

operating and maintenance costs) and the allowance

costs on unabated emissions to the degree that they

affect the plants setting the price for power. For example, in the integrated 1990-7% 2005 case, CO2 emission

allowance costs represent roughly 69 percent of the

change in the total cost of service—all the costs incurred

by power suppliers to meet the demand for electricity,

including fuel costs, operating and maintenance costs,

capital investment costs, and emission allowance

costs—in 2010 and 2020.

The allowance prices for NOx, SO2, and CO2 are projected to vary considerably across the analysis cases

(Table 11). The differences result from the levels of and

interrelationships among the three emission caps in each

case. The prices for each emission allowance are inextricably linked, and caution should be used in trying to discern their individual impacts. The linkages among them

can be seen by comparing the projections in the reference case and the NOx, SO2, and CO2 cap cases with

those in the various integrated cases. For example, NOx

allowances prices in 2010 are projected to be $2,254 per

ton in the reference case, $1,081 per ton in the NOx 2005

case, $2,467 in the SO2 2005 case, and $0 to $85 per ton in

the CO2 cap and integrated cases (including sensitivity

cases).

It may seem surprising that the projected NOx allowance

price is higher in the reference case than in the NOx cap

case with a relatively stringent limit. This occurs because

the reference case cap is applied only to plants in 19

States over a 5-month summer season, and, at the margin, it is more expensive to meet than the nationwide

annual cap imposed in the NOx cap cases. The relatively

high NOx allowance prices projected in the SO2 cap

cases also occur partially because of the 19-State,

5-month season cap imposed. These cases assume the

same limits that are imposed in the reference case. The

NOx allowance prices in the SO2 cap cases are slightly

higher than those in the reference case, because efforts to

meet the stringent SO2 cap lead to changes in the way

particular plants are operated, increasing the cost of

NOx emission reduction options. The low NOx allowance prices projected in the CO2 cap and integrated

cases, especially in the later years of the forecast, occur

because efforts to meet the CO2 emission caps in these

cases lead to substantial reductions in NOx emissions.

Similar linkages can be seen in the projections of SO2

allowance prices. The reference, NOx cap, and CO2 cap

cases all incorporate the CAAA90 8.95 million ton

national SO2 emission cap promulgated. The projected

SO2 allowance prices in the reference and NOx cap cases

are similar. However, when a CO2 cap is incorporated

with the 8.95 million ton SO2 cap, as in the CO2 cap cases,

efforts expected to be made to meet the CO2 cap enable

28 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 11. Projected Power Plant Emissions Allowance Prices, 2005-2020

(1999 Dollars per Ton and 1999 Dollars per Metric Ton Carbon Equivalent)

Analysis Case

Allowance Prices

NOx SO2 CO2

2005 2008 2010 2020 2005 2008 2010 2020 2005 2008 2010 2020

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,374 1,296 2,254 2,071 178 173 170 246 NA NA NA NA

NOx Cap Cases

NOx 2005. . . . . . . . . . . . . . . . . . . . . . . . . . 1,196 769 1,081 1,098 178 173 181 247 NA NA NA NA

NOx 2008. . . . . . . . . . . . . . . . . . . . . . . . . . 1,102 1,136 1,189 1,225 178 173 182 247 NA NA NA NA

SO2 Cap Cases

SO2 2005. . . . . . . . . . . . . . . . . . . . . . . . . . 2,419 2,409 2,467 3,164 303 332 735 1,084 NA NA NA NA

SO2 2008. . . . . . . . . . . . . . . . . . . . . . . . . . 2,475 1,847 2,320 2,818 107 303 283 1,125 NA NA NA NA

SO2 Sensitivity. . . . . . . . . . . . . . . . . . . . . . 2,484 1,703 2,034 2,104 281 307 300 382 NA NA NA NA

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . . . . . . . . 1,981 0 0 0 0 0 0 0 120 148 143 141

CO2 1990-7% 2008 . . . . . . . . . . . . . . . . . . 2,114 0 0 0 21 0 0 0 79 108 139 139

CO2 Sensitivity . . . . . . . . . . . . . . . . . . . . . 2,191 79 85 0 4 10 5 0 95 95 102 112

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . . . . . . . . 1,000 141 0 0 247 231 221 162 115 112 114 113

Integrated 1990-7% 2005 . . . . . . . . . . . . . 969 0 0 0 201 192 226 99 113 138 134 130

Integrated 2008 . . . . . . . . . . . . . . . . . . . . . 888 936 0 0 61 254 213 165 71 102 108 116

Integrated 1990-7% 2008 . . . . . . . . . . . . . 801 876 0 0 74 168 141 95 71 87 126 129

Integrated Sensitivity . . . . . . . . . . . . . . . . . 2,253 27 64 37 104 103 101 51 94 97 101 115

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, MCSO205H.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A, FDPOL05.D121300A,

FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.
the power sector to meet the SO2 emissions limits without additional work. As a result, the SO2 allowance price

in these cases falls to zero. The SO2 cap and integrated

cases (excluding the sensitivity cases) incorporate the

3.27 million ton cap examined in this analysis. In the SO2

cap cases the more stringent standard is projected to

lead to much higher SO2 allowance prices, exceeding

$700 per ton in 2010 and $1,100 per ton in 2020. When the

3.27 million ton SO2 cap is combined with a CO2 cap in

the integrated cases, however, the SO2 allowance price is

expected to range between $141 and $226 per ton in 2010,

much lower than in the SO2 cap cases.

The CO2 allowance price also varies, but to a smaller

degree, when examined with the reference case NOx and

SO2 provisions than when examined with the more

stringent NOx and SO2 provisions analyzed in the integrated cases. For example, the CO2 allowance price

(given in dollars per metric ton carbon equivalent) in

2010 in the CO2 1990-7% 2005 case is projected to be

$143; however, in the integrated 1990-7% 2005 case,

which incorporates the same CO2 cap, it is projected to

reach only $134 per metric ton. The requirement to also

reduce NOx and SO2 emissions in the integrated cases

slightly reduces the incremental cost of reducing CO2

emissions.

A coordinated approach to reducing power sector NOx,

SO2, and CO2 emissions in the integrated cases should

lead to lower overall costs than one for each of the emissions individually. As shown in this report, the compliance decisions that are projected when the NOx and SO2

caps are examined alone are very different from those

expected when the three emission caps are combined.

The exact savings depend on the particular scenarios

analyzed. The key factor is the timing of the NOx and

SO2 caps relative to the timing of the CO2 cap. On one

hand, if NOx and SO2 caps were imposed and then

followed shortly by a CO2 cap that was unexpected, substantial investments could be made in control equipment that would later prove uneconomical. On the other

hand, if the CO2 cap preceded the NOx and SO2 caps,

the potential for uneconomical investments in control

equipment would appear to be small.

A rough measure of the maximum potential for savings

in a coordinated approach would be to compare the cost

increase projected in an integrated case with the sum of

the cost increases projected in the cases that impose each

emission cap individually. Table 12 shows the calculations for the integrated 1990-7% 2005 case and the

standalone NOx 2005, SO2 2005, and CO2 1990-7% 2005

cases with and without allowance fees. The values without allowance fees (often referred to as “resource costs”)

represent just the expected increases in expenditures

on fuel and other operating costs and the increased

investments in new emission control equipment and

new capacity. The projected savings in total resource

costs are higher in the early years—as much as $6 billion

in 2006—because in the integrated cases the expected

investments in control equipment to remove NOx and

SO2 to meet the respective 2005 caps are less than those

expected in the NOx and SO2 cap cases. After 2015, the

projected savings in total resource costs are small. In the

integrated case many of the plants to which controls

might have been added are expected to be retired.

As might be expected, the impact of the assumed CO2

emission caps on electricity prices is projected to be

fairly sensitive to the stringency of the caps (Figure 12).

For example, in the CO2 1990-7% 2005 case, the price of

electricity in 2010 is projected to be 42 percent above the

reference case level. In the less stringent CO2 sensitivity

case, however, the difference is expected to be 29 percent. Similarly, average electricity prices in 2010 in the

integrated 1990-7% 2005 case are projected to be 43 percent higher than projected in the reference case level, but

in the integrated sensitivity case they are projected to be

30 percent above the reference case projection.

The higher electricity prices projected in the analysis

cases, particularly those with CO2 caps, lead to lower

total consumption of electricity. In response to higher

projected prices, consumers are expected to make efforts

to reduce their electricity use (Figure 13). Efforts may

include switching to other fuels, buying more efficient

appliances and equipment, and simply reducing the

usage of electricity-using devices. The projected small

price changes in the NOx and SO2 cap cases are expected

to lead to little change in consumer electricity consumption. In these cases, total electricity sales in 2010 are projected to be only slightly lower than in the reference case.

The impact on consumer electricity use is expected to be

much larger in the cases with CO2 emission caps, where

the demand for electricity is expected to be between 5.8

and 7.6 percent (241 to 314 billion kilowatthours) below

the reference case in 2010.15

In some cases, consumers’ efforts to reduce their electricity consumption could partially offset the CO2 emissions

reductions in the electricity sector. For example, if an

industrial consumer reduces electricity consumption by

using more coal, oil, or gas on site, the CO2 emissions

reductions that occur in the power sector could be

partially offset by increases in the industrial sector.

“Leakage,” as it is commonly called, is always a possibility when emission caps are imposed on one sector of the

economy while other sectors are not similarly constrained. The degree to which it occurs will depend on

several factors, including the substitutability of other

fuels for electricity in the residential, commercial, and

industrial sectors and the overall economic impacts of

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 29

15The tendency of consumers to switch from electricity to natural gas is expected to be reduced somewhat by the increase in gas prices

that would result from increased use of natural gas by eleectricity generators to meet the emission targets.
higher electricity and natural gas prices and lower coal

prices resulting from the electricity sector emissions

caps.

As mentioned above, in this analysis projected higher

electricity prices in the cases with CO2 caps are expected

to cause consumers to reduce their electricity consumption. However, end-use consumers are also projected to

face higher natural gas prices as electricity producers

turn to gas to reduce their CO2 emissions. The net effect

of these price changes is a slight reduction in nonelectricity sector CO2 emissions relative to the reference

case. In other words, leakage of CO2 emissions is negative rather than positive. The decline in coal prices projected in the cases with CO2 caps is projected to be

relatively small and is not expected to increase the use of

coal in the non-electricity sectors. Coal use is virtually

nonexistent in the residential and commercial sectors,

and its use in the industrial sector is limited. In total, U.S.

energy-related CO2 emissions are projected to be 249

million metric tons carbon equivalent below the reference case level in 2010 and 333 million metric tons below

the reference case level in 2020 in the 1990-7% 2005 case.

Even after those changes, however, total U.S. energyrelated CO2 emissions are projected to remain 317 and

462 million metric tons above the target set in the Kyoto

Protocol in 2010 and 2020, respectively.

Overall, the Nation’s total electricity bill is expected to

be higher in the cases with CO2 caps than in the reference case (Figure 14). The change is smaller in percentage terms than the change in electricity prices because of

the projected reduction in electricity usage just discussed. In percentage terms, in 2010 the Nation’s annual

electricity bill is projected to range between 25 and 32

percent higher in the cases with CO2 caps than in the reference case. Because of the vast size of the electricity

market, these percentage changes translate to between

$60 billion and $77 billion per year.

For the average household the projected increases in

electricity prices could have a significant impact on

annual electricity bills (Figure 15). In the reference case,

the annual electricity bill for the average single-family

home is estimated to be just over $881 in 1999. It is

expected to increase over time, reaching $993 by 2020. In

the integrated 1990-7% 2005 case, the annual electricity

bill for the average single-family home is estimated to be

$1,128 in 2010, or $201 higher than projected in the reference case.

30 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 12. Projected Changes from Reference Case Estimate of Total Costs of Service for U.S. Electricity

Generators, 2005-2015

(Billion 1999 Dollars)

Year NOx 2005 Case SO2 2005 Case

CO21990-7%

2005 Case

Sum: NOx 2005,

SO2 2005, and

CO2 1990-7%

2005 Cases

Integrated 1990-7% Case

Projected

Costs

Projected

Savings

Including Allowance Costs in Total Costs

2005 . . . . . . 3 3 77 82 77 5

2006 . . . . . . 4 3 70 77 68 9

2007 . . . . . . 3 4 77 83 74 9

2008 . . . . . . 3 3 89 96 87 8

2009 . . . . . . 2 4 86 92 88 5

2010 . . . . . . 2 4 88 94 86 9

2011 . . . . . . 2 4 87 94 84 9

2012 . . . . . . 3 5 90 97 87 11

2013 . . . . . . 2 3 89 94 89 5

2014 . . . . . . 3 3 89 96 87 9

2015 . . . . . . 2 3 85 90 86 5

Excluding Allowance Costs from Total Costs

2005 . . . . . . 2 3 21 26 24 2

2006 . . . . . . 3 4 20 28 22 6

2007 . . . . . . 2 4 22 28 23 5

2008 . . . . . . 3 3 27 32 28 4

2009 . . . . . . 2 3 26 30 28 2

2010 . . . . . . 2 3 28 33 28 5

2011 . . . . . . 1 3 28 32 29 3

2012 . . . . . . 1 3 29 34 29 5

2013 . . . . . . 1 2 30 33 30 3

2014 . . . . . . 2 2 31 36 31 4

2015 . . . . . . 1 2 29 33 32 1

Note: Totals may not equal sum of components due to independent rounding.

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCSO205.D121300A, FDC7B05.D121300A, and

FDP7B05.D121300B.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 31

Reference NOx

2005

NOx

2008

SO2

2005

SO2

2008

CO2

1990-7%

2005

CO2

1990-7%

2008

Integrated

2005

Integrated

1990-7%

2005

Integrated

2008

Integrated

1990-7%

2008

0

1,000

2,000

3,000

4,000

5,000

Billion Kilowatthours

Figure 13. Projected Electricity Sales in 2010

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.

2000 2010 2020

0

2

4

6

8

10

1999 Cents per Kilowatthour

Reference CO2 1990-7% 2005 Integrated 1990-7% 2005 CO2 Sensitivity Integrated Sensitivity

Figure 12. Projected Electricity Prices, 2000, 2010, and 2020

Source: National Energy Modeling System, runs MCBASE.D121300A, FDC7B05.D121300A, FDC7B05H.D121300A, FDP7B05.

D121300B, and FDP7B05H.D121300A.
32 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

2010 2020

0

100

200

300

400

Billion 1999 Dollars

Reference CO2 1990-7% 2005 CO2 1990-7% 2008 Integrated 2005

Integrated 1990-7% 2005 Integrated 2008 Integrated 1990-7% 2008

Figure 14. Total Projected U.S. Annual Electricity Bill, 2010 and 2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

2005 2010 2020

0

50

100

150

200

250

1999 Dollars per Year

NOx 2005 NOx 2008 SO2 2005 SO2 2008

CO2 1990-7% 2005 CO2 1990-7% 2008 Integrated 2005 Integrated 1990-7% 2005

Integrated 2008 Integrated 1990-7% 2008

Figure 15. Average Projected Changes in Annual Household Electricity Bills Relative to Reference Case

Projections, 2005-2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.
Summary

Projected Impacts

Imposing NOx, SO2, and CO2 caps on the power sector is

expected to have impacts on all aspects of the electricity

generation sector, including capacity expansion and

retirement decisions, generation by fuel, and electricity

prices. A key result is that the compliance decisions

made by power plant operators could be very different if

the various emissions caps were imposed together or

one at a time on different schedules. Power plant owners

would be expected to rely heavily on investments in

emission control technologies to comply with the NOx

and SO2 caps if they were introduced individually or

well in advance of a CO2 cap; but if the NOx, SO2, and

CO2 caps were combined, heavy investments in NOx

and SO2 emission control equipment are not expected to

be cost-effective. Rather, many of the coal-fired power

plants where such equipment might have been added

are projected to be retired if a CO2 cap is imposed.

When the three emission caps are assumed to be

imposed in concert, efforts to comply with the CO2 cap

are projected to have the most significant effect, as can

seen by comparing the results for the CO2 cap and integrated cases. The projected impacts on capacity expansion and retirement, fuel use, and consumer electricity

prices are similar in the CO2 cap and integrated cases. In

particular, the most significant increases in consumer

electricity prices relative to the reference case projections

are seen in the analysis cases that include a CO2 cap. In

the cases without a CO2 cap, electricity prices are not

projected to be more than a few percentage points above

the reference case level in 2010 and 2020. In these cases

some of the costs associated with adding NOx and SO2

control equipment are not expected to be passed on to

consumers; rather, they would result in reduced profits

for the plant owners who made the investments. In cases

with a CO2 emission cap, electricity prices are expected

to be significantly higher. For example, in the integrated

1990-7% 2005 case, the projected electricity prices are 43

percent higher in 2010 and 31 percent higher in 2020

than those projected in the reference case.

Power plant operators and consumers are expected to

contribute to the reductions in CO2 emissions required

in the cases with CO2 caps. Power plant operators are

projected to make a dramatic switch from relatively carbon-intensive coal to less carbon-intensive natural gas

and carbon-free renewables (Figure 16). The plants built

to replace retiring coal plants are also expected to be

more efficient, further reducing their CO2 output per

kilowatthour of generation. Consumers are expected to

react to higher electricity prices by reducing their consumption of electricity in part through increased investments in more efficient end-use equipment.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 33

1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

0

50

100

150

200

250

300

350

Million Metric Tons Carbon Equivalent

Fuel Switching

Generation Efficiency

End-Use Efficiency

Figure 16. Projected Sources of Electricity Sector Reductions in Carbon Dioxide Emissions in the

Integrated 1990-7% 2005 Case, 1999-2020

Source: National Energy Modeling System, runs MCBASE.D121300A and FDP7B05.D121300B.
Uncertainty

As with all projections, there is considerable uncertainty

in the results of this analysis. Among the key factors that

influence the results are the significance of the changes;

uncertainty about future fuel prices, particularly for natural gas; changes in policies over the next 10 to 20 years;

potential cost and performance improvements in emission control and generating technologies; the ability of

the various energy markets to make the adjustments that

would be needed over the next 5 to 8 years; the impacts

of the ongoing changes in the structure of electricity

markets; and the potential impacts of Hg emission regulations. To comply with the emission caps—particularly

the CO2 cap—examined in this report, power suppliers

are projected to have to make a rapid shift away from

coal-fired plants, which have been the predominant

source of electric power in the United States for more

than 50 years.

While this analysis suggests that electricity suppliers

will be able to move to natural gas and renewable fuels,

the potential impacts of a shift of this size, especially

over a short time period, are difficult to predict. There is

no history to use as a guide for a change of such magnitude. During the transition period there could be significant volatility in the market-based prices of emission

allowances and in the wholesale and, potentially, retail

prices of electricity. In addition, planning, siting, obtaining environmental permits for, and building the amount

of new gas-fired capacity projected to be needed, as well

as developing the natural gas resources that would be

required to supply them, could be difficult in the time

frame assumed here.

Because new natural-gas-fired power plants are

expected to be the most important compliance option in

the CO2 cap and integrated cases, natural gas prices are

critical in determining the costs of meeting the emission

caps. Lower gas prices than those projected in this analysis would reduce the overall compliance costs, and

higher prices would increase them.

In the past, when new emissions regulations were

imposed, they stimulated research and development

that lowered the costs and improved the performance

of new emission control equipment and low-emission

generating technologies. Because the assumed caps in

this analysis would have to be met by 2005 or 2008, however, there would be little time to bring new or improved

technologies to the market. Given the normal pace of

environmental regulations and compliance dates, the

cases with 2005 dates may be unrealistic. With a later

compliance date, such improvements could be important. To meet the 2005 caps, however, power plant owners probably would have to rely on currently available

technology. There would not be sufficient time to install

and test new approaches. In the longer term, NEMS

incorporates assumed improvements in cost and performance for new generating and emission control technologies, which reduce the projected costs of complying

with the caps. This can be seen by comparing projected

compliance costs in 2020 with those in 2010.

The changing structure of U.S. electricity markets—

specifically the reliance on competitive markets to set

electricity prices—is likely to affect the way in which

power suppliers respond to emission caps. It is assumed

in this report that independent power producers will

dominate new power plant additions, and that wholesale power will be priced competitively.

A key uncertainty with regard to competitive power

markets is how consumers and product developers

might respond to competitively priced electricity. One

feature that has been seen in newly competitive markets

is a large amount of price volatility. Because such

volatility has not occurred historically, consumers

(including homeowners and commercial and industrial

establishments) have not invested in equipment that

could reduce their exposure to higher prices. It remains

to be seen whether the market will become more responsive in the future.

A subsequent EIA service report, to be issued in early

2001, will extend this analysis to examine the impacts of

a power sector cap on Hg emissions. It is not possible at

this time to predict the impact of the cap in the projections; however, because power sector Hg emissions

come almost entirely from coal-fired plants, it is

expected that controlling them will lead to higher projected operating costs for those plants. In some cases,

coal-fired plants may simply be retired rather than retrofitted with the controls that would be needed.

34 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
4. Fuel Market and Macroeconomic Impacts

Coal Markets

Consumption, Production, and Prices

The imposition of new, more stringent emission caps on

electricity power plants would affect coal consumption,

total and regional production, prices, and industry

employment. In general, the revised caps and the consequent need for introducing scrubbers, NOx reduction

equipment, and other measures necessary to achieve

compliance with the caps would raise the cost of electricity from coal-fired power plants relative to those using

other fuels, encourage fuel switching, and cause the

level of coal-fired generation to be reduced. In all the

analysis cases, impacts on national coal industry

employment levels are projected to be negative relative

to the reference case. The overall impacts depend on

both the extent of the projected decline in coal demand

and the types of coal expected to be used in the future

mix of coal-burning capacity.

In the NOx cap cases, the additional cost of adding and

operating emission control equipment is projected to

increase electricity prices slightly and reduce electricity

sales by a small amount. The projected coal share of

electricity generation by fuel and total projected

coal-fired generation in the NOx cap cases are essentially

unchanged from the reference case projections for 2020.

Minemouth coal prices in the NOx 2005 and NOx 2008

cases track each other closely and range from 5 to 30

cents per ton higher than in the reference case for most of

the 2005-2020 period.

In the two primary SO2 cap cases, slight reductions in

coal-fired generation are projected through 2020, as

other fuels replace coal. Coal mines that supply

medium- or high-sulfur coal are projected to have production declines, leading to lower projected minemouth

prices for coal from those sources relative to the prices

projected in the reference case (Table 13). To meet the

SO2 emission caps, coal consumption is projected to shift

dramatically to favor coal originating from the Powder

River Basin (PRB) in Wyoming and Montana, where surface mines working thick coal seams currently achieve

levels of labor productivity that are on the order of 6 to

10 times greater than those in many other regions. The

resultant low minemouth price of PRB coal and its low

sulfur content are projected to lead to additional consumption of PRB coal in the SO2 cap cases relative to the

reference case.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 35

Table 13. Projected Minemouth Coal Prices, 2005-2020

(1999 Dollars per Short Ton)

Analysis Case 2005 2008 2010 2015 2020

Reference. . . . . . . . . . . . . . . . . . . . . . 14.76 14.00 13.69 13.37 12.84

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . . . . . . . 14.88 14.21 13.99 13.38 12.94

NOx 2008 . . . . . . . . . . . . . . . . . . . . 14.82 14.11 13.94 13.44 12.95

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . . . 12.97 12.67 12.41 12.29 11.94

SO2 2008 . . . . . . . . . . . . . . . . . . . . 13.62 12.52 12.71 12.42 11.87

SO2 Sensitivity . . . . . . . . . . . . . . . . 13.53 12.67 12.59 12.40 12.25

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . . 14.78 14.19 13.77 12.94 12.55

CO2 1990-7% 2008 . . . . . . . . . . . . 14.82 14.27 13.72 12.89 12.54

CO2 Sensitivity . . . . . . . . . . . . . . . . 14.88 14.39 13.96 13.03 12.60

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . . 12.92 12.24 11.93 11.07 10.93

Integrated 1990-7% 2005. . . . . . . . 13.07 12.53 11.82 11.32 11.18

Integrated 2008 . . . . . . . . . . . . . . . 13.70 12.07 11.86 11.25 10.87

Integrated 1990-7% 2008. . . . . . . . 13.70 12.44 12.03 11.56 11.16

Integrated Sensitivity . . . . . . . . . . . 14.11 13.50 12.97 12.16 11.99

Source: National Energy Modeling System, runs MCBASE.D121300A (reference), MCNOX05.D121300A (NOx 2005), MCNOX08.D121300A

(NOx 2008), MCSO205.D121300A (SO2 2005), MCSO208.D121300A (SO2 2008), MCSO205H.D121300A (SO2 sensitivity), FDC7B05.D121300A

(CO2 1990-7% 2005), FDC7B08.D121300A (CO2 1990-7% 2008), FDC7B05H.D121300A (CO2 sensitivity), FDPOL05.D121300A (integrated 2005),

FDP7B05. D121300B (integrated 1990-7% 2005), FDPOL08.D121500A (integrated 2008), FDP7B08.D121500A (integrated 1990-7% 2008), and

FDP7B05H. D121300A (integrated sensitivity).
Because PRB coal has a lower energy content per ton

than the average coal now burned, more of it is needed

to produce comparable amounts of electricity, and its

minemouth price per ton reflects its lower energy value.

As a result, the quantity of PRB coal consumed for electricity generation and its minemouth price are projected

to increase over time in the SO2 cap cases, rising above

the projected levels in the reference case. The low projected minemouth price for PRB coal and the expected

increase in its market share combine to reduce both the

projected national average minemouth price and the

delivered price of coal to electricity generators relative to

the reference case projections.

Sustained growth in electricity demand over the forecast

period is projected in the SO2 cap cases, coupled with

projected higher natural gas prices and steady declines

in nuclear generation. As a result, continued small

annual increases in coal-fired generation are expected in

most years through 2020. Although some older coal

plants are expected to be retired, plants with scrubbers

and highly efficient, low-emitting advanced coal technology units are projected to be placed into service. Following sharp declines in the initial years of the forecast

in the SO2 cap cases, coal production east of the Mississippi River is projected to recover gradually, for consumption in plants that have been retrofitted with

scrubbers or in advanced coal plants. Eastern coal has a

relatively high energy content, which permits greater

generation of electricity per ton of coal burned. In the

SO2 sensitivity case, lower projected allowance prices

are expected to lead to approximately 52 gigawatts of

scrubber retrofits, as compared with 127 gigawatts projected in the SO2 2005 case.

In the CO2 cap cases, substantial reductions in coal consumption are projected, with corresponding drops in the

projections for coal production (Table 14). To continue

using coal in the CO2 cap cases, a power plant operator

would have to pay for the coal and for the CO2 allowances needed to cover the emissions that would result

from burning it. In the CO2 1990-7% 2005 case, the delivered price of coal in 2010 is projected to average $0.92 per

million Btu, and CO2 allowances are projected to cost

$3.65 on a per million Btu basis. Thus, the effective cost

of using coal is projected to be $4.57 per million Btu in

2010 and $4.41 per million Btu in 2020 in the CO2

1990-7% 2005 case. The corresponding costs in the reference case are projected to be $1.05 and $0.98 per million

Btu in 2010 and 2020, respectively.

In all the cases with CO2 caps, continued use of coal is

projected to be reduced sharply at many plants. When

the allowance price is accounted for, the effective delivered price of coal is quadrupled relative to the reference

case (Table 15). Although the average delivered price for

coal on a Btu basis still is projected to be below that for

natural gas (which has a lower carbon allowance fee),

the higher efficiency of natural gas generation is

expected to tip the balance away from coal generation in

many regional markets.

As existing coal-fired power plants become uneconomical in the CO2 cap cases, large blocks of capacity are projected to be retired and replaced by natural gas capacity.

The combined effects of lower coal capacity and lower

utilization of the remaining coal capacity is projected to

reduce coal consumption for electricity generation to

levels that are approximately one-third of those in the

36 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 14. Projected Coal Production, 2005-2020

(Million Short Tons)

Analysis Case 2005 2008 2010 2015 2020

Reference. . . . . . . . . . . . . . . . . . . . . . 1,235 1,283 1,297 1,310 1,342

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . . . . . . . 1,226 1,263 1,265 1,288 1,324

NOx 2008 . . . . . . . . . . . . . . . . . . . . 1,224 1,263 1,268 1,283 1,320

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . . . 1,268 1,296 1,283 1,317 1,346

SO2 2008 . . . . . . . . . . . . . . . . . . . . 1,262 1,304 1,310 1,324 1,359

SO2 Sensitivity . . . . . . . . . . . . . . . . 1,249 1,286 1,295 1,311 1,336

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . . 805 701 681 617 574

CO2 1990-7% 2008 . . . . . . . . . . . . 986 795 651 620 570

CO2 Sensitivity . . . . . . . . . . . . . . . . 932 885 859 793 731

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . . 821 827 793 725 663

Integrated 1990-7% 2005. . . . . . . . 816 727 721 655 574

Integrated 2008 . . . . . . . . . . . . . . . 988 824 799 720 660

Integrated 1990-7% 2008. . . . . . . . 998 828 655 635 565

Integrated Sensitivity . . . . . . . . . . . 940 900 869 797 726

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, MCSO205H.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A, FDPOL05.D121300A,

FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.
reference case projections. Total coal production is projected to decline at a slower rate than demand from the

electricity generation sector, however, because consumption in other sectors (including industrial and coking coal and coal exports, which are not subject to carbon

allowance fees) remains essentially unchanged from reference case values. With large reductions in coal-fired

generation projected as a result of the carbon allowance

fees, SO2 emissions are projected to be well below the

reference case caps, and no additional scrubber retrofits

are expected. In the CO2 sensitivity case, which assumes

less stringent CO2 emission caps, the lower projected

carbon allowance fees are expected to lead to higher coal

production than projected in the other carbon cap cases.

However, minemouth coal prices are projected to be

lower than in the reference case, reflecting overall production declines.

In the integrated cases, coal markets are affected primarily by the CO2 and SO2 caps. In these cases, carbon

allowance fees are projected to result in greatly reduced

demand for coal in the electricity generation sector,

reducing the expected coal share of total generation by

electricity generators and cogenerators in 2020 from 45

percent in the reference case to between 17 and 20 percent in the integrated cases. Total coal production in

2020 ranges from 42 percent to 49 percent of that projected in the reference case.

Natural Gas Markets

Introduction

Natural gas is an important fuel in all sectors of the U.S.

economy other than transportation. In 1999, natural gas

accounted for 23.7 percent of U.S. energy consumption,

making it second only to petroleum in terms of total consumption. U.S. natural gas consumption totaled 21.4 trillion cubic feet in 1999, 0.1 trillion cubic feet less than the

1998 total. The largest user of natural gas is the industrial

sector (including cogenerators), which consumed 44

percent of all gas delivered to consumers in 1999. Electricity generation (excluding cogenerators) accounted

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 37

Table 15. Projected Delivered Coal Prices to Electricity Generators, 2005-2020

(1999 Dollars per Million Btu)

Analysis Case 2005 2008 2010 2015 2020

Reference. . . . . . . . . . . . . . . . . . . . . . 1.13 1.07 1.05 1.01 0.98

NOx Cap Cases

NOx 2005 . . . . . . . . . . . . . . . . . . . . 1.13 1.08 1.06 1.03 0.99

NOx 2008 . . . . . . . . . . . . . . . . . . . . 1.13 1.08 1.06 1.02 0.99

SO2 Cap Cases

SO2 2005 . . . . . . . . . . . . . . . . . . . . 1.05 1.01 0.99 0.96 0.93

SO2 2008 . . . . . . . . . . . . . . . . . . . . 1.05 1.01 1.00 0.97 0.93

SO2 Sensitivity . . . . . . . . . . . . . . . . 1.10 1.05 1.02 0.99 0.96

CO2 Cap Cases

CO2 1990-7% 2005 . . . . . . . . . . . . 0.99 0.94 0.92 0.86 0.82

CO2 1990-7% 2008 . . . . . . . . . . . . 1.02 0.96 0.91 0.85 0.81

CO2 Sensitivity . . . . . . . . . . . . . . . . 1.04 1.01 0.97 0.91 0.85

Integrated Cases

Integrated 2005 . . . . . . . . . . . . . . . 0.97 0.95 0.92 0.85 0.80

Integrated 1990-7% 2005. . . . . . . . 0.96 0.92 0.90 0.84 0.78

Integrated 2008 . . . . . . . . . . . . . . . 1.00 0.93 0.91 0.84 0.80

Integrated 1990-7% 2008. . . . . . . . 1.00 0.92 0.87 0.84 0.77

Integrated Sensitivity . . . . . . . . . . . 1.04 0.99 0.96 0.90 0.85

CO2 Cap Cases (Adjusted)a

CO2 1990-7% 2005 . . . . . . . . . . . . 4.06 4.73 4.57 4.26 4.41

CO2 1990-7% 2008 . . . . . . . . . . . . 3.04 3.73 4.46 4.31 4.37

CO2 Sensitivity . . . . . . . . . . . . . . . . 3.47 3.44 3.58 3.52 3.71

Integrated Cases (Adjusted)a

Integrated 2005 . . . . . . . . . . . . . . . 3.91 3.83 3.85 3.39 3.71

Integrated 1990-7% 2005. . . . . . . . 3.87 4.45 4.35 4.10 4.13

Integrated 2008 . . . . . . . . . . . . . . . 2.83 3.55 3.68 3.48 3.79

Integrated 1990-7% 2008. . . . . . . . 2.83 3.15 4.11 4.13 4.07

Integrated Sensitivity . . . . . . . . . . . 3.46 3.48 3.56 3.42 3.80

a

Adjusted prices reflect the addition of carbon allowance fees to the delivered coal prices shown in the upper section of the table.

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A, MCSO205.D121300A,

MCSO208.D121300A, MCSO205H.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDC7B05H.D121300A, FDPOL05.D121300A,

FDP7B05.D121300B, FDPOL08.D121500A, FDP7B08.D121500A, and FDP7B05H.D121300A.
38 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Impacts on the Rail Industry

In addition to the substantial contraction of the U.S.

coal industry projected in the CO2 cases for this analysis, the U.S. rail industry, which has about 200,000

employees and derives considerable revenues from

coal shipments, also would be greatly affected. In 1999,

751 million tons of the 1,099 million tons of coal produced in the United States (68 percent) was transported to consumers partly or entirely by rail. Coal

freight provided Class I railroads with $7.7 billion in

revenues (1999 dollars), or 22 percent of all freight revenue earned. Coal freight car loadings and ton-miles

tend to be dominated by a handful of railroads. For the

major coal-hauling railroads, coal represented 38 percent of all carloadings during 1999. The average revenue received by Class I railroads for hauling coal was

$10.31 per ton (1999 dollars).a

The National Energy Modeling System does not project financial data for the rail industry in either the reference or analysis cases. On a qualitative basis,

however, certain impacts are likely. Particularly in the

cases that incorporate CO2 caps, railroads and other

shipping modes would be required to respond to

reduced coal traffic and excess transportation capacity

by making major, costly adjustments to routes, schedules, equipment, and employment levels. Decreases in

coal traffic and increased competitive pressures would

lead to lower freight rates and revenues. At the same

time, the inefficiencies associated with the reduced

scale of operation would increase unit costs of operation. Lower revenues, special charges, and increased

unit costs would sharply reduce rail earnings until new

sources of freight revenues were developed.

In this report, coal transportation rates, expressed in

1999 dollars per ton, are assumed to decline over time

in response to productivity gains. They are also

assumed to vary with fuel prices but otherwise to be

invariant across cases despite reductions or increases

in traffic along any given route. All modes of coal

transportation have achieved significant efficiencies

over the past 20 years and have been able to pass along

a portion of the savings to shippers in the form of lower

rates. New equipment, improved scheduling, maintenance, and operating procedures, and more efficient

use of labor have reduced average revenues for coal

shipments to 1.72 cents per ton-mile in 1998, nearly a

60-percent decline in real terms from 1981. In contrast,

average rail revenues for shipments of transportation

equipment and chemicals were 10.55 cents and 3.68

cents per ton-mile, respectively.b Already intense interregional competition among coal producers seeking

to offer the lowest possible delivered cost is another

key factor that has helped to push coal transportation

prices to lower levels. As a result, it would appear that

reducing coal transportation rates at a faster rate to preserve markets would represent a major challenge to

railroad managers.

Data published by the American Association of Railroads indicate that labor costs (wages, plus wage supplements) represent nearly 40 percent of total freight

operating expenses plus fixed charges for all Class I

railroads. Fuel costs, materials and supplies, and

equipment rentals are assigned weights of 7 percent, 5

percent, and 11 percent respectively.c Reductions in

coal traffic that are not offset by increases in traffic for

other commodities would be likely to lead to layoffs,

reducing wage costs, and to the adoption of other measures to reduce operating costs. However, fixed

charges such as depreciation, interest, and taxes would

then be distributed over a smaller traffic base, placing

upward pressure on rates. Replacing coal traffic with

other commodities would be difficult. For example, in

1998 coal accounted for four times more carloads than

either the second-place commodity, transportation

equipment, or the third-place commodity, chemicals.b

Both commodities use shipping routes and equipment

that are quite different from those for coal.

Progressively deregulated since the Staggers Rail Act

of 1980, railroads have made substantial progress in

improving productivity and reducing real costs by

investing in new and more powerful locomotives,

improved maintenance of main-line rights of way,

and more efficient use of labor. A major contribution

to achieving the joint goals of lower costs and maintenance of service has been made through a number of

mergers over the past decade. Mergers have resulted in

the emergence of four major railroad companies—two

in the East (CSX and Norfolk-Southern) and two in the

West (Burlington Northern-Santa Fe and Union

Pacific-Southern Pacific). In 1999, Burlington Northern-Santa Fe received 23.2 percent of all commodity

revenues from coal, and Union Pacific-Southern Pacific

received 20.7 percent.a

The adoption of CO2 emission restrictions is projected

to result in a reduction in domestic coal traffic handled

by the railroads. As suggested by the results of the CO2

cap and integrated cases in this analysis, reductions in

coal traffic could range from moderate to severe. In all

(continued on page 39)

aSource: Association of American Railroads, Freight Commodity Statistics.

bSource: Association of American Railroads, “The Rail Transportation of Coal” (January 2000).

cSource: Association of American Railroads, AAR Railroad Coal Indexes (September 2000).
for 16 percent of total consumption in 1999, and the residential and commercial sectors accounted for 24 percent

and 16 percent, respectively.

The vast majority of the natural gas consumed in the

United States is produced domestically. In 1999, the U.S.

natural gas industry produced 18.7 trillion cubic feet,

providing 87 percent of total gas consumption. Relative

to other fuels, natural gas is second only to coal in

domestic production. In 1999 it accounted for 35 percent

of the fossil fuels produced in the United States, as measured by energy content. Production of natural gas is

concentrated in the central regions of the country, and

an expanding system of pipelines allows gas produced

along the Gulf Coast to be consumed in the Midwest and

in the Northeast. The other element of gas supply is

imports. While the United States exported natural gas to

Mexico in 1999, it was a net importer from Canada,

importing 3.4 trillion cubic feet in 1999. A small amount

of liquefied natural gas (LNG) is also imported from

overseas, primarily from Algeria. In 1999, gross imports

of LNG accounted for less than 5 percent of all U.S. natural gas imports and less than 1 percent of total consumption. By 2020 LNG imports are expected to reach 0.77

trillion cubic feet, or about 13 percent of total gas

imports.

Over the next 20 years, the role of natural gas in U.S.

energy markets is expected to increase as its use in the

electricity generation sector grows. In the reference case

for this analysis, total natural gas consumption is projected to grow to 34.6 trillion cubic feet in 2020, a

57-percent increase over projected consumption in 2000.

With total energy use projected to grow by only 30 percent over the same interval, the share provided by natural gas is expected to increase. The largest component of

the projected increase in gas consumption in the reference case is the electricity generation sector, which is

expected to grow by 5.4 percent per year over the next

two decades, as compared with roughly 1-percent

annual growth in gas consumption projected for the residential, commercial, and industrial sectors.

The integrated, multi-emission strategies proposed to

reduce emissions of NOx, SO2, and especially CO2 are

expected to have significant impacts on domestic natural gas consumption, production, and prices. Although

the proposed caps are limited to the electricity generation sector, changes in fuel use for power generation

would be expected to have significant impacts on the

natural gas market as a whole. In the SO2 and NOx cap

cases, the natural gas market is projected to change only

slightly from the reference case, with slightly higher projections for domestic production and consumption in

the SO2 cap cases. Although there are some differences

from the reference case projections in these cases, they

are minor by comparison with the results of the CO2 cap

cases and the integrated cases, which also include CO2

caps. Therefore, the discussion that follows concentrates

on the CO2 and integrated cases. The projections for natural gas in the CO2 cap cases essentially mirror the

results of the integrated cases, as the electricity sector

switches from coal to natural gas to reduce CO2

emissions.

Consumption

When CO2 emission caps are assumed, natural gas consumption is projected to be higher than reference case

levels because of higher demand in the electricity generation sector (Figure 17). In the integrated 2005 case, the

volume of gas expected to be used for electricity generation increases by more than 5.5 trillion cubic feet (142

percent) from 2000 to 2005, as compared with a corresponding increase of 1.4 trillion cubic feet (35 percent) in

the reference case. By 2005, the projection for power

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 39

Impacts on the Rail Industry (Continued)

the cases with CO2 caps assumed, western coal, particularly subbituminous coal from the Powder River

Basin, is projected to be most severely restricted,

because of its dependence on long-distance rail transportation to reach its markets in locations up to 2,000

miles away.

Because the CO2 reduction cases analyzed in this study

project heavier losses in coal production for western

than for eastern coalfields, and because much of the

production from western coalfields is shipped over

long distances to midwestern and eastern markets to

satisfy demand for low-sulfur fuel, it is likely that the

burden of reduced coal transportation revenues would

fall most heavily on railroads in the West—particularly

on the Burlington-Northern and Union Pacific systems, which now include the St. Louis Southwestern,

the Chicago & Northwestern, the Denver & Rio Grande

Western, the Southern Pacific, and the Atchison,

Topeka & Santa Fe railroads.

Lignite production in Texas, Louisiana, and North

Dakota is also expected to be severely reduced by CO2

emission restrictions, but the effect on rail revenues is

expected to be minor. Because of its inherently low heat

content, lignite is predominantly consumed at or close

to the place of mining. Although the projected losses of

coal production in the individual CO2 reduction cases

are proportionately and absolutely less for Appalachian coal fields than for the Powder River Basin, the

two eastern rail systems (CSX and Norfolk Southern)

are also highly dependent on coal revenue. In the more

severe CO2 reduction cases, Appalachian coal production could be reduced by one-third to one-half, with

potentially serious financial consequences for the eastern rail carriers.
plant use of natural gas in the integrated 2005 case is

about 4.2 trillion cubic feet higher than in the reference

case. The projected difference between the reference

case and the integrated 2005 case narrows to 3.8 trillion

cubic feet in 2010, then expands to 4.4 trillion cubic feet

in 2020.

The projection for natural gas use by power generators

in 2005 in the integrated 2008 case is 2.3 trillion cubic feet

(25 percent) lower than in the integrated 2005 case. By

2010, however, the projection is higher in the integrated

2008 case than in the integrated 2005 case, and it continues to be higher for the rest of the forecast period. In the

integrated 2008 case, natural gas consumption for electricity generation is projected to grow by only 3.2 trillion

cubic feet between 2000 and 2005, but by 2020 the projections for gas use in the power generation sector are

nearly the same in these two integrated cases. The projected increases in natural gas consumption in the cases

that include CO2 caps, relative to the reference case, are

sensitive to the assumed levels of the emission caps. For

example, in the integrated sensitivity case, natural gas

consumption for electricity generation is projected to

reach 7.8 trillion cubic feet in 2005, 2.6 trillion cubic feet

higher than projected in the reference case but 1.5 trillion

cubic feet lower than projected in the integrated 1990-7%

2005 case.

Total natural gas consumption is not expected to

increase as rapidly as its use for electricity generation in

the integrated cases. Because the projected increase in

demand for natural gas in the power generation sector is

expected to result in higher gas prices, consumption in

other sectors of the economy is projected to be lower

than projected in the reference case. In general, facing

higher prices for natural gas, commercial and industrial

users are expected to consume less natural gas than

projected in the reference case, either increasing conservation or switching to other fuels. The projected second-order effects of demand from other sectors vary

from case to case, based on the level of price increase. In

general, however, demand for natural gas in the

non-electricity sectors is quite inelastic, and the projected change in natural gas prices between the cases

leads to only a limited change in the volumes expected

to be used. In the integrated 2005 case, combined commercial, residential, and industrial consumption is projected to be 19.9 trillion cubic feet in 2020, compared

with 15.6 trillion cubic feet projected to be consumed for

electricity generation. In contrast, commercial, residential, and industrial use in the reference case is estimated

to be nearly 0.4 trillion cubic feet higher, at 20.3 trillion

cubic feet in 2020. In the integrated cases, higher gas

prices and reduced use are projected for the commercial,

residential, and industrial sectors, which are not

included in the emission caps. The size of the reductions

in demand from the non-electricity sectors is dwarfed,

however, by the projected increases in gas use for electricity generation, and therefore total natural gas

demand is higher when carbon emissions are reduced.

40 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

1999 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

0

5

10

15

20

Trillion Cubic Feet

Reference NOx 2005 NOx 2008 SO2 2005

SO2 2008 CO2 1990-7% 2005 CO2 1990-7% 2008 Integrated 2005

Integrated 1990-7% 2005 Integrated 2008 Integrated 1990-7% 2008

Figure 17. Projected Natural Gas Consumption for Electricity Generation, 1999-2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.
Supply

To meet the expected growth in demand for natural gas,

both domestic production and imports are projected to

increase above the reference case levels in the integrated

cases. In the reference case, both imports and domestic

production of natural gas are projected to grow over

time, driven by a comparative price advantage for natural gas compared with petroleum and by continued economic growth. By 2020, domestic production is expected

to increase by 54 percent, or 10.2 trillion cubic feet, from

current levels. Over the same interval, net imports are

expected to grow by 66 percent, or 2.3 trillion cubic feet,

with most of the growth coming from an increase in

imports from Canada. Mexico is expected to remain a

net importer of natural gas from the United States in the

reference case, and net U.S. LNG imports are projected

to increase from 0.1 trillion cubic feet in 2000 to 0.8 trillion cubic feet in 2020.

Figure 18 shows the projected growth in natural gas supply by case between 1999 and 2020. Natural gas supply is

projected to increase more rapidly in the integrated

cases than in the reference case, as domestic producers

are expected to respond to the higher prices associated

with increased demand in the power generation sector.

The most rapid projected growth in supply is seen in the

integrated 2005 cases, but by 2020 natural gas supply is

projected to be between 38.5 and 39.0 trillion cubic feet in

the cases that include CO2 emission caps.

Domestic Production

The projected growth in natural gas production in the

reference case is much more rapid than has been seen in

recent years. Since 1988, the volume of gas produced

domestically has fluctuated between 18 and 20 trillion

cubic feet per year. In the reference case, domestic production is expected to expand from 18.6 trillion cubic

feet in 2000 to 28.8 trillion cubic feet in 2020. Growth is

expected to be fastest in the interval between 2010 and

2015, when annual domestic production is projected to

grow by 3.1 trillion cubic feet.

In the cases that include CO2 emission caps, the projected growth in domestic gas production is even stronger than in the reference case. For example, in the

integrated 2005 case, domestic production is projected to

grow by 5.1 trillion cubic feet between 2000 and 2005, as

compared with 2.1 trillion cubic feet in the reference

case. By 2020, however, the projected level of domestic

production is only 2.4 trillion cubic feet higher in the

integrated 2005 case than in the reference case, because

natural gas production after 2005 is projected to increase

more rapidly in the reference case than in the integrated

2005 case.

In the integrated 2008 case, gas production is not

expected to grow as rapidly as in the integrated 2005

case. Between 2000 and 2005, production in the integrated 2008 case grows by only 3.2 trillion cubic feet, 1.8

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 41

1999 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

0

10

20

30

40

50

Trillion Cubic Feet

Reference NOx 2005 NOx 2008 SO2 2005

SO2 2008 CO2 1990-7% 2005 CO2 1990-7% 2008 Integrated 2005

Integrated 1990-7% 2005 Integrated 2008 Integrated 1990-7% 2008

Figure 18. Projected Total U.S. Natural Gas Supply, 1999-2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.
trillion cubic feet less than projected in the integrated

2005 case. By 2010, however, annual production in the

integrated 2008 case is projected to be 25.5 trillion cubic

feet, 0.4 trillion cubic feet higher than projected in the

integrated 2005 case. By 2020, projected production in

the integrated 2008 case is 0.3 trillion cubic feet higher

than in the 2005 case. Earlier, sharper production

increases in the 2005 case are expected to lead to a poorer

reserve position in the first decade of the projection. Earlier and stronger shifts to renewable technologies in the

integrated 2005 case cause projected natural gas consumption, and therefore production, in the later years of

the forecast to be higher in the integrated 2008 case than

in the integrated 2005 case.

Over time, a much larger volume of gas is expected to be

withdrawn from the domestic resource base in the cases

with CO2 emission caps than in the reference case. For

example, by 2005, cumulative domestic production

(from 2000) in the integrated 2005 case is projected to be

6.4 trillion cubic feet higher than projected in the reference case—an amount equivalent to approximately 4

months of production at current levels. By 2020, the difference in cumulative dry gas production between the

integrated 2005 case and the reference case is projected

to increase to 36.6 trillion cubic feet, about twice the volume of current production in a typical year. In 2005,

cumulative production in the integrated 2005 case is

projected to be 4.6 trillion cubic feet higher than in the

integrated 2008 case. Although production is generally

higher in the integrated 2008 case each year after 2005,

cumulative production in 2020 is projected to be lower

than in the integrated 2005 case.

Meeting the gas production requirements projected in

the cases with stringent CO2 caps in 2005 would be a

challenge for the industry. Production increases of the

magnitude projected here have not been seen for many

years. The increase in production projected in the integrated 2005 case from 2000 to 2005, at 5.1 trillion cubic

feet, is considerably stronger than the recent trend in gas

production, which has been essentially flat through

most of the 1990s. The most recent period of comparable

growth was from 1965 to 1970, when domestic gas production increased by 5.7 trillion cubic feet. Although

higher prices would give producers additional revenue,

increasing natural gas production by the levels required

in the cases with CO2 emission caps would require considerable investment and effort on the part of the domestic natural gas industry.

On an annual basis, the projected increases in production are far greater than those seen in recent years.

Figure 19 shows projected average annual growth in

domestic natural gas production between 2000 and 2005

in the reference case and in the integrated cases. The

growth rates projected in the two cases with 2005 reduction targets average 1.0 trillion cubic feet per year. The

strongest annual growth in natural gas production

estimated in the integrated 2005 case is in 2003, when

production is projected to grow by 1.9 trillion cubic feet.

The projected growth in 2003 is slightly higher in the

integrated 1990-7% 2005 case, at 2.0 trillion cubic feet.

(Smaller annual increases in production are projected in

the integrated cases after 2003, when increases in

demand are also expected to slow.) Historically, the

largest annual increase in domestic natural gas production was 1.38 trillion cubic feet in 1984, but that increase

followed extremely low production in 1983 and therefore can be seen in part as a return to an existing growth

trend rather than a shift to a higher production level.

During the sustained period of rapid growth between

1965 and 1970, the peak annual increase in natural gas

production was 1.34 trillion cubic feet in 1969. The rate of

growth projected in the integrated 2005 case during the

first 5 years of the projection is unprecedented.

Several issues would need to be addressed for the

domestic natural gas industry to meet the high production levels projected in this analysis. One is investment.

Lower energy prices in recent years have led to

decreases in investment and drilling activity, which

have only recently begun to rebound as a result of higher

prices for oil and gas. Stimulating additional drilling in

the future will require significant additional investment,

which is unlikely to be made unless the industry foresees a prolonged period of higher revenues. Given the

projections of future domestic production in the integrated cases, however, it is likely that investors would

recognize that limits on CO2 emissions would lead to

higher demand for natural gas—and higher prices—for

an extended period. In response to those expectations,

additional funds are expected to be made available to

the industry, providing the necessary capital for

42 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

0.0

0.5

1.0

1.5

2.0 Trillion Cubic Feet per Year

Reference

Integrated 2005

Integrated 1990-7% 2005

Integrated 2008

Integrated 1990-7% 2008

Figure 19. Projected Annual Change in Domestic

Natural Gas Production, 2000-2005

Source: National Energy Modeling System, runs MCBASE.

D121300A, FDPOL05.D121300A, FDP7B05.D121300B, FDPOL08.

D121500A, and FDP7B08.D121500A.
additional investment in drilling rigs and field development. In contrast, short-term price increases in the early

and mid-1990s were not seen as sustainable in the longer

term and, therefore, have not led to more drilling.

Under any circumstances, bringing on the number of

drilling rigs needed to meet the levels of demand projected in this analysis would be a challenge. Historically,

the number of available rigs declined from more than

5,000 in 1982 to fewer than 1,500 in the late 1990s. In the

reference case projections, the number of rigs needed is

expected to increase by 304 (17 percent) between 2000

and 2005, and in the integrated 2005 case the projected

increase is 541 rigs (31 percent) over the same period.

However, the industry has shown that it can react

quickly to sustained higher prices. Between 1979 and the

peak in 1982, the number of oil and gas drilling rigs grew

by more than 2,300, an increase of more than 80 percent

in a 3-year period.

New oil and gas development technologies are expected

to play a role in increasing gas supplies in the reference

case. However, because the integrated cases (and especially the integrated 2005 cases) are expected to require

rapid production increases in the early years of the projections, they would have to depend more heavily on

existing technology and resources, and production costs

are projected to be higher in those cases. For example, in

the cases that assume CO2 emission caps in 2005, more

natural gas production is expected from offshore fields

and unconventional resources than in the reference case.

Production from these sources is relatively expensive

based on current technology. Thus, the increased production is projected to be more costly than that in the reference case, with corresponding increases in the prices

paid by natural gas users. When the CO2 caps are

assumed to go into effect in 2008 rather than 2005, the

projected increases in production are delayed accordingly, allowing the time needed for new technologies

and resources to come into play and slowing the projected price increases.

Although increasing production capacity is a challenge

for the industry, in the long term there are adequate

resources to allow production to expand as projected in

the most stringent cases in this analysis. The forecasts

assume that domestic resources of economically recoverable gas are roughly 1.2 quadrillion cubic feet. In the

reference case, cumulative dry gas production from 2000

through 2020 is estimated to be 491 trillion cubic feet,

compared with 528 trillion cubic feet in the integrated

2005 case. The additional 37 trillion cubic feet of production over the forecast period represents about 3 percent of the current estimated resource base. Therefore,

the difference in the absolute levels of depletion of natural gas resources does not seem to preclude the expansion of gas production projected in the integrated 2005

case.

Imports

Canadian imports make up nearly all the projected

increase in imports in the reference case, growing by a

projected 2 trillion cubic feet over the next 20 years to a

total of 5.5 trillion cubic feet in 2020. (The projections

include growth in Canadian imports as a result of

increased gas production in Alaska. New Alaskan gas

that is not shipped directly to the lower 48 States is used

in Canada, freeing up additional Canadian gas for

export to the United States.) In the integrated 2005 case,

Canadian imports are projected to grow by 2.6 trillion

cubic feet—to 6.0 trillion cubic feet in 2020—in response

to higher natural gas prices in the United States, and

one-half of that increase is expected to occur by 2005.

Higher U.S. gas prices in the integrated 2005 case are

also expected to stimulate net LNG imports, which are

projected to increase to 1.3 trillion cubic feet by 2020—

540 billion cubic feet higher than projected in the reference case. Although projected LNG imports are higher

in the integrated cases, LNG remains a relatively small

source of gas supply. The projected increase in LNG

imports is limited even in the integrated 2005 case,

because even with higher prices, additional expansion

of LNG capacity is not likely to be economically viable,

based on estimates of world supplies and existing technology. Stronger demand in the integrated case also is

expected to reverse the flow of gas between the United

States and Mexico. In the reference case, 176 billion cubic

feet of natural gas is projected to be exported from the

United States to Mexico in 2005. In the integrated 2005

case, however, net imports of natural gas from Mexico

are expected to total 300 billion cubic feet in 2005,

increasing to 360 billion cubic feet in 2020.

In order for imports to the lower 48 States to reach their

projected levels in the cases with CO2 emission caps, the

import transportation infrastructure would have to be

expanded more rapidly than projected in the reference

case. For LNG, the higher import levels projected in the

cases with CO2 emission caps would only require more

intensive use of existing regasification plants. In contrast, increasing imports from Canada and Mexico

above the levels projected in the reference case would

require additional pipeline and other infrastructure

development by 2005 and continuing infrastructure

development in Canada through 2020. Constructing the

infrastructure necessary to meet the demand for natural

gas imports projected in the integrated cases would

require investment in pipelines and other infrastructure

technology. Building the additional pipeline capacity

that would be needed to allow an additional 430 billion

cubic feet of gas across the Canada-U.S. border (beyond

the 730 billion cubic feet of new capacity projected to be

needed in the reference case after 1999) to be imported to

the lower 48 States by 2005 in the integrated 2005 case

would present a challenge to the industry that would

require careful planning.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 43
Using the past as a guide, the changes in production and

imports that would be needed to meet the projected supply requirements in the CO2 cap cases are large; however, the required growth is expected to be accompanied

by higher projected prices. Thus, although meeting the

projected requirements in the analysis cases that include

CO2 emission caps would require significant effort on

the part of domestic producers and importers, primarily

in the cases with 2005 CO2 caps, the higher prices projected in those cases are expected to provide the necessary incentives for the industry to add capacity.

Pipeline Capacity

To meet the increased demand projected in the CO2 cap

cases, interstate pipeline capacity is also projected to

increase. Additions to existing pipeline capacity are projected in all the cases, but more rapid expansion is

expected in the cases with CO2 emission caps. Between

2000 and 2005, interstate pipeline capacity (defined as

the sum of the pipeline volumes crossing State borders)

is projected to grow by 4.7 trillion cubic feet (5.1 percent)

in the reference case and by 5.4 trillion cubic feet (4.5 percent) in the integrated 2005 case. More rapid growth in

pipeline capacity is projected to continue in the integrated case, with the expected addition of 23.3 trillion

cubic feet (21 percent) to interstate capacity between

2005 and 2020, as compared with 14.5 trillion cubic feet

(13 percent) projected in the reference case over the same

interval.

The strongest annual growth in pipeline capacity in the

reference case is projected for 2001, at 2.9 trillion cubic

feet. The projected increase is based on recently completed projects and the expected completion of projects

currently under way, including the Alliance Pipeline

running from Canada to the Midwest and the

Maritimes/Northeast and Portland Natural Gas Transmission System pipelines running from Canada to the

northeastern United States.

Except for the early increase projected for 2001, interstate capacity is projected to grow by 1.84 trillion cubic

feet or less each year in the reference case. Greater

annual increases are projected in the integrated 2005

case between 2010 and 2020, with the highest annual

growth expected in 2014 at 2.1 trillion cubic feet.

The greatest single-year increase in interstate natural gas

pipeline capacity in recent years was in 1992, when 1.6

trillion cubic feet of capacity was added. The strong

short-term growth in capacity projected in the reference

case, including the projected increase of 2.9 trillion cubic

feet in 2001, is based on existing projects that are already

completed or underway. These projects show how the

industry is able to respond to the increased need for

pipeline capacity. None of the projected annual

increases after 2005 exceed the growth rate resulting

from the projects that are currently underway; however,

pipeline capacity expansion can require several years of

lead time.

Prices

The increased demand for natural gas projected in

the cases that include CO2 emission caps is expected to

result in higher prices. In the reference case, the average

lower 48 wellhead price of natural gas is projected to be

$2.49 per thousand cubic feet in 2005 (1999 dollars), rising to $3.14 per thousand cubic feet in 2020. In the reference case, natural gas wellhead prices of $3.32 and $3.34

per thousand cubic feet are projected for 2000 and 2001,

respectively. Although current prices are high, the forecast is based on yearly averages and is designed to capture long-term trends in prices rather than higher prices

that might stem from short-term market conditions.

However, higher prices in the short term could lead to

lower prices in later years of the projections, due to the

effects of increased drilling and the resulting higher levels of reserves.

Only minor changes from the gas prices projected in the

reference case are expected in the NOx and SO2 cap

cases. In the CO2 cap and integrated cases, however,

prices are projected to be much higher than in the reference case as a result of the projected rapid increases in

natural gas demand. In general, prices are expected to be

higher in the 2005 cap cases than in the 2008 cap cases in

the years immediately after the caps are assumed to be

imposed.

The projected changes in prices from 2000 to 2020 vary

by case (Figure 20). Projected wellhead gas prices in the

cases with CO2 caps rise more rapidly than projected in

the reference case and end up considerably higher. In

the integrated 2005 case, the wellhead price of natural

gas in 2005 is projected to be $3.45 per thousand cubic

feet, or $0.96 per thousand cubic feet higher than projected in the reference case. The projected prices in the

integrated 2005 case are also higher than those in the reference case in 2020, by $0.91 per thousand cubic feet.

By the end of the forecast period, the natural gas prices

projected in the integrated 2008 case are higher than

those in the integrated 2005 case. In 2010, prices in the

integrated 2008 case are expected to average $3.75 per

thousand cubic feet (compared with $3.83 in the integrated 2005 case), rising to $4.32 per thousand cubic feet

in 2020 (compared with $4.04 in the integrated 2005

case). The differences are due in part to the continued

stronger demand from power generators expected in the

integrated 2008 case. Higher prices earlier in the integrated 2005 case are also expected to improve the

reserve position and reduce the cost of production in the

later years of the forecast. The projected prices in the reference case remain within the historical range, but those

in the cases that assume CO2 caps are higher than they

have been in the past, exceeding the 1983 average

44 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
wellhead price of $3.94 per thousand cubic feet (1999

dollars), as a result of the projected increases in demand

for natural gas by electricity generators.

In the short term (through 2003), the projected increases

in natural gas prices in the analysis cases that include

CO2 caps (relative to the reference case projections)

result from projected rapid increases in demand for gas

in the electricity generation sector, as power plant operators are expected to dispatch gas-fired generators in lieu

of coal-fired generators. In the long term, the cumulative

market effects of the projected annual increases in

demand over the forecast period keep projected prices

higher in the cases that include CO2 emission caps. Thus,

although the total projected demand for natural gas in

2020 is only 8 percent higher in the integrated 2005 case

than in the reference case, the cumulative increase of 37

trillion cubic feet results in a projected wellhead gas

price that is $0.91 per thousand cubic feet, or 29 percent,

higher than projected in the reference case.

The projected high prices are expected to have three

major effects on the market:

• First, higher wellhead prices are expected to be

passed along to consumers as higher end-use prices,

reducing the demand for natural gas in other sectors

and moderating the expected increase in total

demand. For example, in 2005, residential consumers are projected to pay as much as 12 percent more

for natural gas in the cases with CO2 caps than in the

reference case. In the integrated 2005 case, electricity

generators are projected to pay about $3.91 per million Btu for natural gas, compared with $2.89 in the

reference case. Stronger demand and higher wellhead prices are projected to account for the price

increase. In addition, electricity generators are projected to pay a CO2 allowance fee of $1.65 per million

Btu. In 2020, the projected price of natural gas for

electricity generators in the integrated 2005 case is

$4.58 per million Btu plus an allowance fee of $1.63,

as compared with $3.68 and no allowance fee in the

reference case.

• Second, higher price projections also are expected to

result in higher projected revenues for the natural

gas industry. Total revenues for gas producers can

be estimated by multiplying the average projected

wellhead price by projected production. By this measure, estimated industry revenues from gas production are expected to be $52 billion in 2005 in the

reference case and $82 billion in the integrated 2005

case. While expanding production increases costs,

the increase in revenues should also lead to

increased profits for the industry.

• Third, the impact of increased natural gas use in the

electricity generation sector would also be felt by

consumers in other sectors, because gas prices

would increase. Homeowners and the owners of

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 45

1999 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

0

1

2

3

4

5

1999 Dollars per Thousand Cubic Feet

Reference NOx 2005 NOx 2008 SO2 2005

SO2 2008 CO2 1990-7% 2005 CO2 1990-7% 2008 Integrated 2005

Integrated 1990-7% 2005 Integrated 2008 Integrated 1990-7% 2008

Figure 20. Projected Domestic Wellhead Natural Gas Prices, 1999-2020

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCNOX08.D121300A,

MCSO205.D121300A, MCSO208.D121300A, FDC7B05.D121300A, FDC7B08.D121300A, FDPOL05.D121300A, FDP7B05.

D121300B, FDPOL08.D121500A, and FDP7B08.D121500A.
commercial buildings and industrial establishments

are projected to see increases in their gas bills in the

CO2 cap and integrated cases. For example, in the

integrated 1990-7% 2005 case, total expenditures for

natural gas in the non-electricity sectors nationwide

are projected to be nearly $25 billion higher in 2010

than projected in the reference case (Table 16). By

sector, increases in total expenditures for natural gas

relative to the reference case are projected to be $6

billion for the residential sector, $4 billion for the

commercial sector, and $15 billion for the industrial

sector.

Renewable Fuels Markets

Introduction

Renewable energy technologies, which are virtually

emission free, can be attractive alternatives to fossil

fuels, especially if emissions need to be reduced. This

section discusses the projected impacts of the emission

cap cases described in Chapter 2 on renewable capacity

additions and generation. The central station renewables analyzed here include biomass, conventional

hydroelectricity, geothermal, municipal solid waste,

solar energy, and wind.

Biomass fuels include agricultural residues, forestry

residues, energy crops, and urban wood waste and mill

residues. About 8,000 megawatts of dedicated biomassfired generating capacity is in use today.16 Of the total,

6,000 megawatts is used by industrial facilities to

produce cogenerated electricity and heat for their own

use, primarily in the pulp and paper industry. A new

advanced technology, integrated gasification combined-cycle technology, is now entering the market and

is assumed to be commercially available beginning in

2005. In addition, energy crops grown specifically to

serve as energy fuels are now being tested, and they are

assumed to become commercially available in 2010.

Among renewables, biomass-fired plants are especially

attractive because they can be run nearly continuously,

unlike wind and solar facilities that are dependent on

intermittent fuel sources. In addition, because biomass

growth sequesters CO2, the use of biomass for electricity

generation is considered a net zero CO2-emitting

technology.

In addition to its use in dedicated facilities, it is also

assumed that biomass can be used in place of or along

with coal in coal-fired plants where it is economically

attractive. A small number of coal-fired plants are now

using some biomass as part of the fuel mix, and studies

have suggested that coal plants could burn between 3

and 5 percent biomass fuel without expensive plant

changes. As a result, where biomass fuels are available,

it is assumed that up to 5 percent of the fuel used in a

coal plant can be biomass based. This level of biomass

46 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 16. Projected Total Expenditures for Natural Gas in the Residential, Commercial, and Industrial

Sectors, 2005-2020

(Billion 1999 Dollars)

Sector 2005 2008 2010 2015 2020

Reference Case

Residential . . . . . . . . . . . . . . . . . . . . 36.21 36.94 37.12 38.56 41.36

Commercial. . . . . . . . . . . . . . . . . . . . 19.72 20.77 21.35 22.29 23.58

Industrial . . . . . . . . . . . . . . . . . . . . . . 33.04 35.50 36.66 40.60 46.50

Total . . . . . . . . . . . . . . . . . . . . . . . . 88.97 93.20 95.13 101.45 111.44

Integrated 1990-7% 2005 Case

Residential . . . . . . . . . . . . . . . . . . . . 39.33 42.31 42.96 43.96 46.16

Commercial. . . . . . . . . . . . . . . . . . . . 21.76 24.08 24.94 25.92 27.10

Industrial . . . . . . . . . . . . . . . . . . . . . . 41.91 49.56 51.84 55.46 59.44

Total . . . . . . . . . . . . . . . . . . . . . . . . 103.01 115.95 119.74 125.34 132.71

Difference Between Cases

Residential . . . . . . . . . . . . . . . . . . . . 3.12 5.37 5.83 5.41 4.80

Commercial. . . . . . . . . . . . . . . . . . . . 2.04 3.31 3.60 3.63 3.52

Industrial . . . . . . . . . . . . . . . . . . . . . . 8.87 14.06 15.18 14.86 12.94

Total . . . . . . . . . . . . . . . . . . . . . . . . 14.04 22.74 24.61 23.89 21.27

Percentage Difference Between Cases

Residential . . . . . . . . . . . . . . . . . . . . 8.6 14.5 15.7 14.0 11.6

Commercial. . . . . . . . . . . . . . . . . . . . 10.4 15.9 16.9 16.3 14.9

Industrial . . . . . . . . . . . . . . . . . . . . . . 26.8 39.6 41.4 36.6 27.8

Total . . . . . . . . . . . . . . . . . . . . . . . . 15.8 24.4 25.9 23.6 19.1

Source: National Energy Modeling System, runs MCBASE.D121300A and FDP7B05.D121300B.

16Dedicated biomass plants are facilities designed specifically to burn biomass as their primary fuel.
co-firing in coal plants is an economically attractive CO2

emission reduction strategy, because it can be done at

relatively low cost and it displaces a high-carbon fuel.

However, because CO2 reduction scenarios typically

reduce expected coal use, opportunities for biomass

co-firing with coal are projected to be diminished in such

cases.

Geothermal power uses heat from the earth for electric

power generation. Accessible geothermal resources can

be found in the West and Northwest, although some are

near National parks and other environmentally sensitive areas. Nearly 3,000 megawatts of geothermal power

capacity is in service today. Like biomass facilities, geothermal plants can be run almost continuously, and they

are available whenever power is needed. Some geothermal plants emit small amounts of CO2.

Municipal solid waste (MSW) includes organic and

other combustible urban waste. About 3,000 megawatts

of MSW capacity is currently in operation in the United

States, most for direct electricity generation and some

for cogeneration. MSW conversion to electricity can

occur through either solid waste combustion or combustion of landfill gas. Although most of the MSW facilities

that exist today use solid waste, this analysis projects

that all new MSW capacity will use landfill gas.

Solar power includes solar photovoltaic (PV) and solar

thermal facilities. PV, which uses solar cells to convert

sunlight directly to electricity, provides grid-serving

power in central station plants, distributed units, and

modules installed on residences and commercial buildings. PV offers zero emissions, can be installed close to

customer loads, and is generally available during high

demand periods associated with hot, sunny conditions.

PV units are relatively expensive, however, and they are

unavailable when the sun is down or blocked. PV is

most competitive where solar conditions are best or

where peak electricity costs are very high.

Solar thermal concentrates sunlight to produce steam

for peaking electricity generation. Currently more than

330 megawatts of solar thermal capacity is in operation

in Southern California. When combined with energy

storage (such as molten salt), solar thermal can provide

reliable power when it is needed. Solar thermal offers

zero emissions and, like PV, is generally available during high demand periods associated with hot weather.

However, the technology is still in the early stages of

development, with relatively high costs and uncertain

performance, and inadequate solar conditions east of the

Mississippi River limit its potential market.

More than 78,000 megawatts of conventional hydroelectric capacity provides more than 75 percent of all U.S.

renewable electricity generation today. Hydroelectric

power is a proven, reliable technology with low operating costs. Although there are potential opportunities for

additional dams and for capacity additions or efficiency

improvements at existing facilities, building new hydroelectric is costly, and environmental objections are significant. The reference case for this analysis projects a

slight decline in electricity generation from existing

hydroelectric capacity through 2020. Public willingness

to accept the construction of new hydroelectric dams

currently appears to be low in light of environmental

tradeoffs.

Among the renewable generation technologies, central

station wind power has shown the most significant

growth in recent years, and it is expected to continue to

grow in the near future. Spurred by declining capital

costs, improving performance, and both Federal and

State incentives, total U.S. wind generating capacity is

estimated to have increased by nearly 70 percent from

1997 through 2000, to more than 2,700 megawatts. Further near-term additions are also projected.

Like other renewables, wind power produces no emissions, but there are factors that may limit its development. For example, wind resources are often far from

electricity customers, and if the wind is not blowing the

resources may not be available during peak daily or seasonal loads. Wind power also still costs more than fossil-fueled alternatives. The technology is fairly new and

untested on a large scale, and it faces environmental

objections, primarily for visual intrusion. In addition,

unpredictable variations in output from intermittent

generators like wind and solar affect other generators

and the overall stability of large interconnected electricity networks, leading to higher costs. The point at which

such problems might occur is unknown. For this analysis it is assumed that PV and wind power together can

provide no more than 12 percent of any region’s annual

electricity generation.

Despite some uncertainty about State programs, where

sufficient information is available, EIA projections

include estimates of new generating capacity using

renewable energy resources resulting from current State

renewable portfolio standards (RPS), other mandates,

green power, and other voluntary programs encouraging renewable energy technologies. State RPS and other

mandates are projected to add 5,065 megawatts of new

renewable energy capacity by 2020, including 4,377

megawatts from RPS alone. Total RPS and mandated

additions include 2,900 megawatts of new wind capacity, 1,145 megawatts of new landfill gas capacity, 840

megawatts of biomass, 117 megawatts of geothermal,

and 64 megawatts of new solar (photovoltaic and thermal). Voluntary programs contribute an additional 291

megawatts, 230 megawatts of which is from wind

plants, 41 megawatts from landfill gas, 16 megawatts

from biomass, and 4 megawatts from solar photovoltaics. The estimates are included in projections for all

the cases in this analysis.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 47
Projections of large increases in renewable energy use

should be viewed with caution. The availability of

renewable energy resources to support major growth

is often uncertain, particularly in the case of biomass,

geothermal, and wind resources, and the costs and performance of new technologies also are uncertain. Consumer tastes, environmental accommodation, and

market acceptance may be problematic, and the ability

of different suppliers and regions to integrate large proportions of renewables, especially intermittent sources

like solar and wind, into overall supply is not known.

Reference Case Projections

Because they cost more than fossil alternatives, renewable energy technologies are projected to account for

very little new generating capacity through 2020 in the

reference case, other than near-term builds in response

to State RPS or other requirements. In 2000, nonhydroelectric renewables, including both direct generation

and industrial cogeneration, are estimated to provide

79 billion kilowatthours (2.1 percent) of all U.S. gridconnected electricity generation and 2.4 percent of retail

sales.17 When the 290 billion kilowatthours of expected

conventional hydroelectric generation is included, the

total renewable share of U.S. electricity supply in 2000

generation is estimated to be 9.8 percent of generation

and 11.0 percent of retail sales. In the reference case, generation from nonhydroelectric renewables is projected

to increase to 141 billion kilowatthours in 2020, and its

share of total U.S. electricity supply is projected to be 2.7

percent of generation (Figure 21) and 2.9 percent of sales.

Generation from conventional hydroelectric capacity is

expected to remain essentially unchanged.

Emission Reduction Cases

As the cost of generating power from fossil fuels

increases in the emission reduction cases, renewable

generation technologies are expected to become more

attractive. The projected changes are small in the NOx

and SO2 cap cases, where the costs of complying with

the emission caps are expected to fall mainly on existing

fossil plants. New fossil plants, against which new

renewable plants would compete when capacity is

needed, are assumed to be built to meet current emission

standards. Because NOx and SO2 emissions from new

fossil technologies, especially natural gas facilities, are

low, the projected costs of NOx and SO2 allowances have

little impact on their economics. As a result, as in the reference case, fossil generating technologies (particularly

natural gas) continue to be more economical than new

renewable capacity in the NOx and SO2 cap cases.

The relative economics of new fossil versus new renewable generation technologies change in the CO2 cap and

integrated cases. Carbon allowance fees are expected to

raise the costs of all fossil technologies, both existing and

new. Natural gas generating technologies are expected

to play the key role in reducing CO2 emissions, but new

renewable technologies also are projected to contribute.

Renewables are expected to make their most significant

contributions in the most stringent cases, which assume

reductions in power sector CO2 emissions to their 1990

level by 2005 and further to 7 percent below the 1990

level on average over the 2008 to 2012 time period. The

CO2 1990-7% 2005 case projects the greatest increase in

renewable energy capacity. In this case, the share of total

power generation from nonhydroelectric renewables is

projected to increase to 8.0 percent of total generation

and 9.2 percent of sales in 2020, much higher than projected in the reference case (404 billion kilowatthours in

2020, as compared with 141 billion kilowatthours in the

reference case). Conventional hydroelectric generation

is also projected to increase slightly, by 6 billion kilowatthours over the reference case projection for 2020.

Nonhydroelectric renewable generating capacity is also

projected to make up a larger share of total capacity in

2020 in the CO2 1990-7% 2005 case than in the reference

case (6.3 percent and 2.3 percent, respectively).

The largest increases in renewable electricity generation

in the CO2 1990-7% 2005 case relative to the reference

case are projected for biomass, geothermal, and wind

(Figure 22). Biomass generation (excluding cogeneration) in 2020 is projected to increase from 22 billion

kilowatthours in the reference case to 119 billion

kilowatthours in the CO2 1990-7% 2005 case, with 65 percent of the increase coming from biomass use in dedicated plants and the rest from increased biomass

co-firing in coal plants. Geothermal generation in 2020 is

projected to increase from 25 billion kilowatthours in the

reference case to 113 billion kilowatthours in the CO2

1990-7% 2005 case. Wind generation in 2020 is projected

to increase from 13 billion kilowatthours in the reference

case to 86 billion kilowatthours in the CO2 1990-7% 2005

case, reaching the assumed limit of 12 percent (due to

system stability requirements) of total generation in two

regions by 2020. Smaller relative increases between the

reference case and the CO2 1990-7% 2005 case in 2020 are

projected for landfill gas generation (7 billion kilowatthours) and conventional hydropower (6 billion kilowatthours). Because large-scale central station solar

generating technologies are expected to remain more

costly than other alternatives in all the analysis cases,

they are not projected to provide additional generation

relative to the reference case levels.

Although biomass, geothermal, and wind all are projected to provide more electricity generation in the cases

with CO2 caps than in the reference case, their contributions are expected to occur during different parts of

48 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

17State renewable portfolio standards are variously defined relative to electricity generation or to sales.
the 2000-2020 time period. The vast majority of new

dedicated biomass and wind-powered plants are

projected to enter service well after 2010, in response to

both higher natural gas prices and decreased costs for

renewable energy technologies. In contrast, geothermal

power and biomass co-firing in coal plants are projected

to be economical when the emission caps are first introduced, increasing rapidly in the early years of the forecast. In the later years of the forecast, as less coal-fired

capacity remains available, the potential for co-firing

declines, and the most cost-effective geothermal opportunities are already taken.

In the CO2 1990-7% 2005 case, electricity generation

from biomass co-firing is projected to increase from 3

billion kilowatthours in 2000 to 38 billion kilowatthours

in 2005, peaking at 54 billion kilowatthours in 2010. By

comparison biomass co-firing is projected to provide

only 11 billion kilowatthours of electricity generation in

2010 in the reference case. After 2010, declining

coal-fired capacity is projected to result in reduced biomass co-firing, and its contribution in the CO2 1990-7%

2005 case slips to 43 billion kilowatthours in 2020. Landfill gas capacity and generation are projected to have

accessed almost all available cost-effective sites by 2010,

with the result that few additional cost-effective landfill

opportunities are expected to be available later in the

forecast period.

Most of the increase in renewable fuel use projected in

the in the CO2 1990-7% 2005 case is expected to occur in

the western States. The total projected increase in renewable capacity in the CO2 1990-7% 2005 case relative to the

reference case projection for 2020 is 46 gigawatts, of

which only 3 gigawatts (6.8 percent) is expected to be

located in the five regions along the Atlantic seaboard.

Sensitivity Cases

Because less expensive alternatives can meet most or all

of the remaining requirements, reduced mitigation

requirements in the sensitivity cases disproportionately

reduce—and in one case eliminate altogether—the

expansions of renewable energy capacity and generation projected in the integrated cases. In the SO2 sensitivity case, no additional renewable generating capacity is

projected beyond the reference case level. In the integrated sensitivity case, renewable capacity in 2020 is

projected to be 16 gigawatts greater than projected in the

reference case and 30 gigawatts lower than projected in

the CO2 1990-7% 2005 case.

In the CO2 1990-7% 2005 case, which assumes the most

stringent emission reduction targets in this analysis,

renewables enter the projections particularly heavily

after 2015, after other less costly alternatives are projected to be exhausted. When less stringent emission

caps are assumed, these late-period demands are eliminated, and with them most of the projected additions of

new renewable generating capacity in the forecasts. In

the electricity generating sector (excluding cogeneration), wind capacity, which is projected to reach 30

gigawatts in the CO2 1990-7% 2005 case, is projected to

reach only 13 gigawatts by 2020 in the integrated sensitivity case—8 gigawatts more than projected in the

reference case. Similarly, biomass capacity, which is projected to reach 12 gigawatts by 2020 in the CO2 1990-7%

2005 case, is projected to reach only 4 gigawatts in the

integrated sensitivity case—2 gigawatts more than projected in the reference case.

In contrast to other renewable energy options, biomass

co-firing is projected to increase in the integrated sensitivity case compared with the other cases, as most

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 49

2010 2020

0

40

80

120

160

Billion Kilowatthours

Geothermal

Municipal Solid Waste

Dedicated Biomass

Biomass Co-Firing

Solar Thermal

Solar Photovoltaic

Wind

Figure 21. Projected Nonhydroelectric Renewable

Generation by Fuel in the Reference

Case, 2010 and 2020

Source: National Energy Modeling System, run MCBASE.

D121300A.

Reference CO2

1990-7% 2005

0

200

400

600

800

Billion Kilowatthours

Hydroelectric

Geothermal

Municipal Solid Waste

Dedicated Biomass

Biomass Co-Firing

Solar

Wind

Figure 22. Projected Renewable Electricity

Generation by Fuel in the Reference

and CO2 1990-7% 2005 Cases, 2020

Source: National Energy Modeling System, runs MCBASE.

D121300A and FDC7B05.D121300A.
coal-fired capacity is projected to remain in operation

through 2020. Whereas in the reference case biomass

co-firing with coal produces a maximum of 12 billion

kilowatthours of electricity generation in 2011 and provides 9 billion kilowatthours in 2020, in the CO2 1990-7%

2005 case it is projected to increase to 54 billion kilowatthours in 2010 before declining to 43 billion kilowatthours in 2020. In the integrated sensitivity case,

generation from biomass co-fired with coal reaches a

projected maximum of 71 billion kilowatthours in 2010

before declining to 56 billion by 2020.

Industry Employment Impacts

The analysis cases in this report can be expected to produce both broad macroeconomic and specific fuel sector

impacts on employment. Macroeconomic impacts result

from increased energy prices that will in turn affect

industrial sectoral output, gross domestic product, overall productivity in the economy, and employment. In the

primary fuel sectors, emission limits and higher prices

are expected to alter the levels of overall and regional

production of the fuels used for electricity generation

and to change the levels of both direct employment and

employment in associated industries and the surrounding infrastructure. In particular, the coal industry is

expected to experience employment declines because of

reduced coal production, and the natural gas and

renewables industries are projected to show employment gains as electricity generators switch fuels. Relative to the reference case, projected employment gains in

the oil and gas sectors in 2020 generally match projected

employment losses in the coal sector in the NOx and SO2

cap cases but substantially exceed them in the CO2 cap

cases.

Coal Industry Employment

Between 1978 and 1999, the number of miners employed

in the U.S. coal industry fell by 5.4 percent per year,

declining from 246,000 to an estimated 77,000. The

decrease primarily reflected strong growth in labor productivity, which increased at an annual rate of 6.4 percent over the same period. An additional factor

contributing to the employment decline was the

increased output from large surface mines in the Powder River Basin, which require much less labor per ton of

output than mines located in the Interior and Appalachian regions. With improvements in productivity continuing over the forecast period, further declines in

employment of 1.8 and 0.5 percent per year are projected

from 1999 through 2010 and from 2010 through 2020,

respectively (Figure 23). In absolute terms, coal mine

employment is projected to decline in the reference case

from 77,000 in 1999 to 63,000 in 2010 and 60,000 in 2020.

50 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020

0

200

400

600

800

Thousand Jobs

History Projections

Reference

NOx 2005

SO2 2005

CO2 1990-7% 2005

Integrated 1990-7% 2005

Oil and Gas Industry

Coal Mining

Figure 23. Coal Mining and Oil and Gas Industry Employment, 1970-2020

Sources: History: Coal—Energy Information Administration (EIA), The U.S. Coal Industry, 1970-1990: Two Decades of Change,

DOE/EIA-0559 (Washington, DC, November 1992); and EIA, Coal Industry Annual 1998, DOE/EIA-0584(98) (Washington, DC,

June 2000), and previous issues. Oil and Gas—Bureau of Labor Statistics. Projections: National Energy Modeling System, runs

MCBASE.D121300A, MCNOX05. D121300A, MCSO205.D121300A, FDC7B05.D121300A, and FDP7B05.D121300B.
In the NOx and SO2 cases, overall U.S. coal consumption

and production are not significantly different from the

reference case. In the NOx cases the minor changes in

coal production, relative to the reference case, lead to

only slight changes in coal employment levels, as reductions in NOx emissions do not significantly affect

regional coal production patterns (Table 17). In the SO2

cases, however, differences in sulfur content by supply

region lead to some shifts in the regional distribution of

coal production, with output in the relatively

high-sulfur, labor-intensive coal fields in the Appalachian and Interior coal supply regions projected to be

lower than in the reference case forecast and output

from the low-sulfur, less labor-intensive coal mines in

the Powder River Basin projected to be higher. In the

SO2 2005 case, U.S. coal mine employment is projected to

decline by 1.6 percent per year, from 77,000 miners in

1999 to 55,000 in 2020, compared with a projected

decline of 1.2 percent per year in the reference case.

In the CO2 and integrated cases, lower levels of coal production in all supply regions relative to the reference

case result in lower coal industry employment in all

regions. In the integrated 1990-7% 2005 case, coal mine

employment is projected to decline by 4.7 percent a year,

to 28,000 by 2020.

It should also be noted that coal mines typically are

located away from cities and are a significant source of

income and employment in rural areas. In addition, with

substantial contraction of the U.S. coal industry projected in the CO2 cap cases, employment in the U.S. rail

industry, which derives considerable revenues from

coal shipments, also would be greatly affected (see box

on page 38).

Oil and Gas Employment

Employment in the oil and gas industries is expected to

grow in future decades, accompanying the projected

increases in drilling and production for natural gas.

Employment has fallen since reaching its peak of more

than 700,000 employees in 1982. In 1999, average annual

employment was 293,000 employees nationally, its lowest level since 1974. In 2000, employment at the end of

the third quarter is estimated to have been 20,000 workers higher than it was at the end of the third quarter of

1999, responding to higher prices and increased drilling

for oil and natural gas.

In the reference case, total annual average employment

in the oil and gas production industry is projected to

increase by 1.4 percent and 1.9 percent per year from

1999 to 2010 and from 2010 through 2020, respectively,

reaching 411,000 jobs by 2020.18 The increase is expected

to be concentrated in the oil and gas services industry

(which includes oil and gas exploration), rather than

production. Most of the expected increase is due to the

increased level of drilling required to meet the projected

strong demand for gas, and to a projected increase in the

number of offshore wells.

Projected increases in natural gas use as a result of CO2

emission caps would require increases in natural gas

production, with a significant impact on employment

levels in the gas industry. In the integrated 1990-7% 2005

case, average annual employment in 2005 in the oil and

gas industry is estimated to be 363,000, roughly 70,000

jobs higher than it was in 1999 and 49,000 higher than

projected in the reference case. The difference between

the integrated 1990-7% 2005 case and the reference case

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 51

Table 17. Projected Impacts on Energy Industry Employment, 2005-2020

(Thousand Jobs)

Industry Analysis Case 1999a 2005 2010 2020

Average Annual

Percent Change

Coal . . . . . . . . . . . . . . . . . Reference 77 68 63 60 -1.2

NOx 2005 77 68 63 59 -1.2

SO2 2005 77 60 56 55 -1.6

CO2 1990-7% 2005 77 49 39 31 -4.2

Integrated 1990-7% 2005 77 45 36 28 -4.7

Oil and Gas Extraction . . . Reference 293 314 341 411 1.6

NOx 2005 293 312 343 416 1.7

SO2 2005 293 313 341 417 1.7

CO2 1990-7% 2005 293 363 425 492 2.5

Integrated 1990-7% 2005 293 363 424 499 2.6

a

Preliminary estimates.

Source: National Energy Modeling System, runs MCBASE.D121300A, MCNOX05.D121300A, MCSO205.D121300A, FDC7B05.D121300A, and

FDP7B05.D121300B.

18This analysis uses the econometric forecasting model described in J. Kendell, “Employment Trends in Oil and Gas Extraction,” in

Energy Information Administration, Issues in Midterm Analysis and Forecasting 1999, DOE/EIA-0607(99) (Washington, DC, August 1999).
grows between 2005 and 2010. By 2010, employment in

the integrated case is 424,000—more than 83,000 higher

than projected in the reference case. Although this projection is more than 130,000 higher than the 1999

employment level, it still is lower than the levels of

employment in the oil and gas industry in the late 1970s

and early 1980s. By 2020, total employment in the oil and

gas industry is projected to reach 499,000 jobs in the integrated 1990-7% 2005 case.

In 2005, projected natural gas production in the integrated 1990-7% 2005 case is roughly 13 percent higher

than projected in the reference case, and total employment in the oil and gas industry is nearly 16 percent

higher. The difference in employment projections

between the scenarios results from an 8-percent increase

in the expected number of production workers and a

20-percent increase in the number of service workers relative to the reference case. Thus, the projected increase

in employment results primarily from the effort

required to bring the new natural gas production on

line, including infrastructure development and identification of new resources. Although technology advances

tend to reduce the number of workers required to bring

new resources into play, the increasing scarcity of new

resources makes it harder to bring them on line. Therefore, in the CO2 cap cases, the increasing difficulty of

finding new resources and bringing them to market is

expected to cause total oil and gas employment to grow

more quickly than total natural gas production.

Renewables Employment

Multi-emission strategies are likely to result in increased

U.S. employment in renewable energy industries, in

equipment manufacturing, in new facility construction,

and in ongoing operation and maintenance of generating facilities using renewable energy. These increases

are expected to be small, however, because most

renewables—geothermal, solar, and wind, for example—involve little ongoing extraction, preparation, or

transportation. Only biomass involves notable labor in

energy production, such as for energy crops or for waste

preparation. Biomass transportation, while significant,

remains local.

Much of the projected new employment in renewable

energy industries is expected to be in the manufacturing

and construction of new energy generating facilities. To

the extent that the United States gains comparative

advantage in exporting renewable energy technologies,

and to the (relatively small) extent that domestic manufacturing and construction replace imported fuels, U.S.

employment is also expected to increase. In addition,

some increase in employment is expected for the ongoing operation and maintenance of new renewable

energy generating facilities; however, the increase is

expected to be small relative to the projected employment increase in the oil and gas industry.

Macroeconomic Impacts

The imposition of new, more stringent emission caps is

expected to affect the U.S. economy fundamentally

through an increase in delivered energy prices. Higher

energy costs would reduce the use of energy by shifting

production toward less energy-intensive sectors, by

replacing energy with labor and capital in specific production processes, and by encouraging energy conservation. Although reflecting a more efficient use of higher

cost energy, the change would also tend to lower the

productivity of other factors in the production process

because of a shift in the relative prices of capital and

labor relative to energy. Moreover, a rise in energy

prices would raise non-energy intermediate and final

product prices and introduce cyclical behavior in the

economy, resulting in output and employment losses in

the short run. In the long run, however, the economy can

be expected to recover and move back to a more stable

growth path. Table 18 summarizes the projected macroeconomic impacts in the reference and two integrated

cases.

In the most stringent case—the integrated 1990-7% 2005

case—inflation in the economy is projected to rise rapidly above the rate projected in the reference case.

Higher projected electricity and natural gas prices initially affect only the energy portion of the consumer

price index (CPI). The higher projected energy prices are

expected to be accompanied by general price effects as

they are incorporated in the prices of other goods and

services. In this case, the level of the CPI is projected to

be about 1.0 percent above the reference case by 2005

and in 2010 is projected to be 1.2 percent above the reference case projection. After 2010, however, price inflation

is projected to abate, and the CPI is expected to begin

returning to reference case levels. By 2020, the projected

level of the CPI is 0.2 percent above the reference case

projection.

How would the projected changes in energy prices affect

the general economy? In both of the integrated cases,

energy prices are projected to continue increasing relative to the reference case projections through the target

year of the emission reduction. The most rapid increases

in energy prices are projected during the first 4 years of

the forecast period, because the power sector is expected

to turn quickly from coal to natural gas to comply with

the CO2 emission caps. Energy prices are projected to

continue rising after 2004, but the rate of increase is

expected to be more gradual. Capital, labor, and production processes in the economy would need to be

adjusted to accommodate the new, higher set of energy

and non-energy prices.

Higher energy prices would affect both consumers and

businesses. Households would face higher prices for

energy and the need to adjust spending patterns. Rising

52 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
expenditures for energy would take a larger share of the

family budget for goods and service consumption, leaving less for savings. Energy services also represent a key

input in the production of goods and services. As energy

prices increase, the costs of production rise, placing

upward pressure on the prices of all intermediate goods

and final goods and services in the economy. These transition effects tend to dominate in the short run, but dissipate over time.

Expectations on the part of power suppliers and consumers of energy play a key role. On the part of the

power suppliers, current investment decisions depend

on expectations about future markets. They will make

decisions by reviewing each technology’s current and

future capital, operations and maintenance, and fuel

costs. Both current and expected future costs are considered because generating assets require considerable

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 53

Table 18. Projected Macroeconomic Impacts in the Reference Case and Two Integrated Emission Reduction

Cases, 2005-2020

Projection 2005 2010 2015 2020

Real Gross Domestic Product

(Billion 1992 Dollars)

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,869 11,461 13,107 14,842

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . 9,754 11,401 13,104 14,813

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . 9,809 11,377 13,084 14,821

Real Gross Domestic Product

(Percent Change from Reference Case)

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . -1.2 -0.5 0.0 -0.2

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . -0.6 -0.7 -0.2 -0.1

Consumer Price Index

(Index, 1982-1984 = 100))

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193.2 219.7 250.9 295.8

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . 195.0 222.3 252.8 296.5

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . 194.1 222.0 253.0 297.0

Consumer Price Index

(Percent Change from Reference Case)

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . 1.0 1.2 0.8 0.2

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . 0.5 1.0 0.8 0.4

Unemployment Rate

(Percent)

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 4.7 4.5 4.1

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . 4.8 4.8 4.4 4.1

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . 4.5 5.0 4.5 4.1

Unemployment Rate

(Change in Rate from Reference Case)

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . 0.6 0.2 -0.1 0.0

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . 0.3 0.3 0.0 0.0

Disposable Income

(Billion 1992 Dollars)

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,053 8,242 9,494 10,858

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . 6,956 8,160 9,458 10,808

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . 7,000 8,150 9,445 10,813

Disposable Income

(Percent Change from Reference Case)

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . -1.4 -1.0 -0.4 -0.5

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . -0.8 -1.1 -0.5 -0.4

Non-agricultural Employment

(Million Employed)

Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140.3 148.6 154.8 161.3

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . 138.9 147.9 154.9 161.1

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . 139.5 147.6 154.6 161.2

Non-agricultural Employment

(Change from Reference Case, Million Employed)

Integrated 1990-7% 2005 . . . . . . . . . . . . . . . . . . . . . . . . -1.5 -0.7 0.1 -0.2

Integrated 1990-7% 2008 . . . . . . . . . . . . . . . . . . . . . . . . -0.8 -1.0 -0.2 -0.1

Note: All percent changes and changes from the reference case are rounded to one decimal point.

Source: Simulations of the Standard & Poor’s DRI Macroeconomic Model of the U.S. Economy.
investment and last many years. These forward-looking

decisions help to moderate the ultimate price effects

passed on to the rest of the economy. The views of consumers and businesses are also influenced by expectations of future price changes. Inflationary expectations

on the part of consumers and businesses are characterized as a function of recent rates of increase in prices and

spending.19 Thus, although expectations are important,

they are based in general on recent changes, not on forward-looking expectations in the absence of change. A

more forward-looking view would suggest that the

announcement of a policy would shape expectations

and decisions that could lead to reduced impacts on the

aggregate economy.

In the integrated 1990-7% 2005 case, the unemployment

rate is projected to rise by 0.6 percentage points, reaching 4.8 percent in 2005. Along with the rise in inflation

and unemployment, real output of the economy is projected to decline. Real gross domestic product (GDP) is

projected to fall by 1.2 percent relative to the reference

case in 2005, and employment in non-agricultural

54 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Macroeconomic Effects of Alternative Implementation Instruments

All the cases considered above assume a marketable

emission permit system, with a no-cost allocation of

the permits based on historical emissions. In meeting

the targets, power suppliers are free to buy and sell

allowances at a market-determined price for the permits, which represents the marginal cost of abatement

of any given pollutant. An alternative form of permit

system would auction the permits to power suppliers.

The price paid for the auctioned permits would equal

the price paid for traded permits under the no-cost

allocation system used for this study. However, the

two systems imply a different distribution of income.

In the no-cost allocation system, there would be a

redistribution of income flows between power suppliers in the form of purchases of emission permits. There

would be no net burden on the power suppliers as a

whole, only a transfer of funds between firms. While all

firms are expected to benefit from trading, the burden

would vary among firms. With a Federal auction system, in contrast, there would be a net transfer of

income from power suppliers to the Federal Government. In the integrated 1990-7% 2005 case, the magnitude of the transfer would be approximately $30 billion

(1992 dollars) in 2010 and almost $40 billion in 2020.

The key question at this juncture turns on the use of the

funds by the Federal Government. If the funds were

returned to the power suppliers, the effect would be

the same as in the no-cost allocation scheme, but with

the Federal Government establishing the permit market mechanism. Another use of the funds might be to

return them to consumers either in the form of a

lump-sum transfer or in the form of a personal income

tax cut, compensating consumers for the higher prices

paid for energy and non-energy goods and services.a

Relative to the no-cost allocation of permits, an auction

that transfers funds to consumers in a lump sum would

help to maintain their level of overall consumption.

With the transfer, however, total investment would

decline relative to the allocation system. The two

effects would tend to counterbalance each other, but

not completely. Returning collected auction funds to

the consumer would tend to have a slightly more positive effect than the negative effect on investment for the

first few years, but after 2005 investment would tend to

rebound faster and contribute increasingly to the

recovery. As a result, real GDP would be expected to

recover to reference case levels faster under the no-cost

allocation system. Over the entire period, however, the

net impacts on real GDP are expected to be similar in

both magnitude and pattern under the two potential

allocation schemes.

Another approach is to recycle the auctioned revenues

back to either consumers or business through a reduction in marginal tax rates on capital or labor. Unlike the

no-cost allocation or the lump-sum payment to consumers, this approach may lower the aggregate cost to

the economy by shifting the tax burden away from

distortionary taxes on labor and capital toward the taxation of an environmental pollutant. Most often this

research is based on a general equilibrium approach,

where all factors are assumed to be utilized fully, as in

the work by Goulder, Parry, and Burtraw.b Revenue

recycling benefits may also apply in a setting where

transition effects on the economy, such as considered

in the current EIA study, are the focus.c

aFor a discussion of the relative merits of alternative policy instruments, see Perman, Ma, and McGilvray, “Pollution Control Policy,”

in Natural Resource and Environmental Economics (Addison Wesley Longman, 1996). bL.H. Goulder, I.W.H. Parry, and D. Burtraw, “Revenue-Raising Versus Other Approaches to Environmental Protection: The Critical

Significance of Pre-existing Tax Distortions,” RAND Journal of Economics, Vol. 28. No. 4 (Winter 1997), pp. 708-731. cSee also Energy Information Administration, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic Activity,

SR/OIAF/98-03 (Washington, DC, October 1998), Chapter 6 “Assessment of Economic Impacts.”

19R.E. Brinner and M.J. Lasky, “Model Overview: Theory and Properties of the DRI Model of the U.S. Economy,” in U.S. Quarterly Model

Documentation, Version US97A.
establishments is projected to decline by 1.5 million jobs.

Similarly, real disposable income is expected to fall by

1.4 percent. As the economy adjusts to higher energy

prices, inflation begins to subside in the forecasts after

2005. At the same time, the economy begins to return to

its long-run growth path. By 2010, the projected unemployment rate is only 0.2 percentage points above the

reference case, and real GDP is projected to be only 0.5

percent below the reference case projection. The impact

on non-agricultural employment is projected to diminish to about 200,000 jobs relative to reference case in

2020. The adjustment process is expected to be nearly

complete in 2020, approaching the reference case path,

with the unemployment rate at the reference case level

and real GDP only 0.2 percent below the reference case

level.

In the integrated 1990-7% 2008 case, the energy price

impacts are projected to be both smoother and smaller

in magnitude. The effect on inflation is projected to

be smaller, and the CPI is projected to peak at about

1.0 percent above the reference case level in 2010. As a

result the impact on the measures of economic performance is moderated throughout the forecast period relative to that in the integrated 1990-7% 2005 case. The

unemployment rate is projected to be 0.3 percentage

points above the reference case in the 2005 through 2010

period. The impact on real GDP is projected to reach 0.7

percent below the reference case in 2010, and real disposable income is projected to reach its lowest point at

1.1 percent below the reference case in 2010. As with the

integrated 1990-7% 2005 case, the integrated 1990-7%

2008 case projects a strong recovery after 2010, and most

of the cyclical impacts are expected to dissipate by 2020,

with the unemployment rate returning to the reference

case level and real GDP only 0.1 percent below the reference case.

Three key observations follow from these cases:

• The faster the rise in the underlying energy prices,

the stronger the cycle introduced in the macroeconomy.

• Given that the emissions caps are assumed to reach a

plateau, the economy tends to revert back toward

the reference case values in the long run after adjusting to the caps.

• With smaller emission reductions, the projected

impacts on the economy are significantly smaller.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 55

5. Potential Impacts of New Source Review Actions

Background

On November 3, 1999, the U.S. Department of Justice, on

behalf of the U.S. Environmental Protection Agency

(EPA), filed lawsuits against seven electric utility companies in the Midwest and South, charging that 17 of the

companies’ power plants had illegally released significant amounts of pollutants for two decades.20 At the

same time, the EPA issued an administrative order

against the Tennessee Valley Authority (TVA), charging

the Federal agency with similar violations at another

seven power plants. In addition to the lawsuits and

administrative order, the EPA issued notices of violation, naming an additional eight plants owned by other

utilities as sites of similar violations of the Clean Air Act

(Table 19).

Passed in 1970, the Clean Air Act is the comprehensive

Federal law that regulates air emissions from area,

mobile, and stationary sources. Among its many provisions is the explicit authorization for the EPA to establish National Ambient Air Quality Standards (NAAQS)

in order to protect public health and the environment.

The goal of the Act was to achieve the NAAQS by 1975,

working in concert with the States through State Implementation Plans (SIPs).

The Clean Air Act was amended in 1977, primarily to set

new dates for meeting attainment standards. At the

same time, Congress eliminated existing facilities from

many of its requirements, exempting them from immediate actions to add pollution control equipment unless

they underwent major modifications. “Major modifications” would trigger New Source Review (NSR) standards, and the utilities would, in that event, be required

to obtain a permit for Prevention of Significant Deterioration (PSD), which would be granted only if the plants

used “best available control technology.” Failure to

obtain the permit under the conditions specified would

leave the utilities liable to legal action and civil penalties.21

The dispute in the lawsuits filed for the EPA in

November 1999 centers around whether certain modifications or capital improvements performed at the plants

named in the action were “major”—specifically,

whether the actions were aimed at increasing capacity,

regaining lost capacity, or extending the life of the units.

Correlatively, the EPA was also concerned with any

modifications that would have the effect of increasing

emissions.22 The utilities responded by claiming that the

modifications were “routine,” undertaken as an integral

part of maintaining standard operations at the plants,

and thus could not trigger the NSR standards, which

contain an explicit exemption for “routine maintenance,

repair and replacement.”23 EPA’s notice of violations

stated that, in some instances, the modifications in

question cost tens of millions of dollars and took years to

complete. The utilities, however, referenced original

plant capitalization costs that in some cases reached

$500 million.24

Current Status

To date only one of the original cases has been resolved,

and settlements have been reached with two other

companies accused of similar violations. On February

29, 2000, the U.S. Department of Justice and the EPA

jointly announced the settlement of a major Clean Air

Act enforcement action against the Tampa Electric Company (TECO). The settlement followed months of negotiations that involved the utility, the two Federal

agencies, the Florida Department of Environmental Protection, and the Florida Public Service Commission. The

six other utilities and the TVA indicated they would

defend themselves against the charges.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 57

20Named in the lawsuits were American Electric Power (AEP), Cinergy, FirstEnergy, Illinois Power, Southern Indiana Gas & Electric

Company, Southern Company, and Tampa Electric Company. U.S. Department of Justice, “U.S. Sues Electric Utilities in Unprecedented

Action To Enforce the Clean Air Act,” Press Release No. 524 (November 3, 1999).

21For the full text of the Clean Air Act (42 U.S.C. s/s 7401 et seq. (1970)), see U.S. Environmental Protection Agency, web site

www.epa.gov/oar/caa/contents.html. Section 109 establishes the NAAQS, Part C sets forth the requirements for the prevention of significant deterioration, Parts C and D define modifications, Section 165 defines major emitting facilities, and Section 113(b)(2) prescribes civil

penalties.

22Section 111(a) of the Clean Air Act, 42 U.S.C. § 7411(a).

2340 CFR Section 52.21(b) (2) (iii) (a). For an analysis of utility maintenance strategies, see, J.L. Golden, Tennessee Valley Authority,

“Routine Maintenance of Electric Generating Stations.”

24For example, Unit 6 at the Conesville plant, a 444-megawatt unit, was completed in 1978 at an estimated real capital cost of $197 million. See M. McCabe, An Empirical Analysis of Measurement Errors: Power Plant Construction Costs. Master’s thesis, Massachusetts Institute of

Technology (Cambridge, MA, June 1986), Table 1, p. 15.
EPA’s Notice of Violation against TECO stated that

modifications undertaken as early as 1979 violated the

Clean Air Act. Citing several specific instances at the

Gannon plant, EPA said that replacing the furnace floor

in 1996, the cyclone burners in 1994, and the second radiant superheater in 1992 constituted major modifications

at Gannon. Similarly, the replacement of steam drum

internals in both 1991 and 1994 as well as a high-temperature reheater replacement and a waterwall addition in

1994 without simultaneously installing pollution control

equipment constituted violations at Big Bend.25 EPA

argued that the law provided for penalties of roughly $9

million per year, per violation, which, for just the violations specifically mentioned, would indicate a civil penalty in excess of $300 million.

Under the terms of a Consent Decree, TECO admitted to

no violation of the Clean Air Act but agreed to undertake major efforts to bring its two large coal-fired plants

into compliance with the standards promulgated by

EPA. The entire Gannon facility, it was agreed, will

be repowered to burn natural gas by January 2004.

TECO also agreed to improve the use and operation of

the scrubbers in use at Big Bend, and to install new

combustion controls at Big Bend to reduce NOx emissions starting in 2002. Major NOx reductions must be

shown at Big Bend by 2007, or TECO may have to

repower or retire the units. TECO was forced to surrender its allocation “credits,” which it received under

Phase I of the SO2 reduction program in 1995, and to pay

a civil penalty of $3.5 million. TECO also agreed to contribute up to $2 million to study nitrogen deposition in

Tampa Bay.26

In November 2000, the EPA reached a similar agreement

with Dominion Virginia Power regarding three of its

coal-fired plants. Although Virginia Power was not

named in the November 1999 litigation, the EPA had

served a Notice of Violation to the utility in June 2000 for

Clean Air Act violations at its Mt. Storm power plant in

West Virginia. Under the agreement, Virginia Power

agreed to install scrubbers at Mt. Storm units 1 and 2 and

to add SCR equipment to all three units at the plant. The

utility also agreed to install scrubbers for two units and

SCR equipment for three units at its Chesterfield plant

and to install SCR equipment on two units at its Chesapeake plant. Virginia Power acceded to a civil penalty of

$5.3 million to resolve issues at Mt. Storm and agreed to

58 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 19. Plants Named in the November 1999 New Source Review Litigation

State and Plant Name

Year of First

Commercial

Operation

Coal-Fired

Capacity

(Megawatts) State and Plant Name

Year of First

Commercial

Operation

Coal-Fired

Capacity

(Megawatts)

Alabama Kentucky

James H Miller Jr . . 1978 2,686 Paradise . . . . . . . . . 1963 2,159

EC Gaston . . . . . . . 1960 1,884 Mississippi

Barry . . . . . . . . . . . . 1954 1,634 Jack Watson . . . . . . 1968 774

Widows Creek. . . . . 1952 1,610 Ohio

Gorgas . . . . . . . . . . 1951 1,302 W H Sammis . . . . . . 1959 2,220

Colbert . . . . . . . . . . 1955 1,179 Conesville . . . . . . . . 1957 1,925

Greene County . . . . 1965 255 Cardinal. . . . . . . . . . 1967 1,800

Florida Muskingum River . . 1953 1,365

Big Bend . . . . . . . . . 1970 1,683 Walter Beckjord. . . . 1952 1,118

F J Gannon . . . . . . . 1957 1,171 Tennessee

Crist. . . . . . . . . . . . . 1959 1,019 Cumberland . . . . . . 1973 2,448

Georgia Bull Run . . . . . . . . . 1967 879

Scherer . . . . . . . . . . 1982 3,352 Allen . . . . . . . . . . . . 1959 744

Bowen . . . . . . . . . . . 1971 3,187 John Sevier . . . . . . . 1955 704

Kraft . . . . . . . . . . . . 1958 217 West Virginia

Illinois Mitchell . . . . . . . . . . 1971 1,600

Baldwin . . . . . . . . . . 1970 1,751 Phil Sporn . . . . . . . . 1950 1,020

Indiana

Cayuga . . . . . . . . . . 1970 995

Tanners Creek . . . . 1951 980

Wabash River . . . . . 1953 753

R Gallagher. . . . . . . 1958 560

F B Culley . . . . . . . . 1955 388

Sources: Energy Information Administration, Form EIA-860A, “Annual Electric Generator Report” (1999); and U.S. Environmental Protection

Agency, “A Summary of the Targeted Utilities . . .,” Headquarters Press Release (November 3, 1999).

25U.S. Environmental Protection Agency, Notice of Violation, EPA-CAA-2000-04-0007.

26Consent Decree, Civil Action No. 99-2524 CIV-T-23F.
provide $13.9 million for additional environmental projects, as yet unspecified. Like TECO, Virginia Power

agreed to retire a portion of its allowances currently

authorized by the Acid Rain program, beginning in

2012.27

In December 2000 it was announced that a tentative

agreement had also been reached with Cinergy Corporation. Under the terms of the agreement, which must be

finalized by the court, Cinergy would shut down or

repower with natural gas approximately 600 megawatts

of coal-fired generating capacity in Indiana and Ohio

between 2004 and 2006; install new scrubbers on four

coal-fired units in Indiana between 2008 and 2013; begin

operating already-installed SCR units on a year-round

basis for two coal-fired plants beginning in 2004; and

meet a reduced system-wide NOx cap by 2008. It was

estimated that these actions would cost the company

approximately $1.37 billion, making it the largest of the

three settlements announced to date. In addition, the

company agreed to “retire” 50,000 tons of SO2 allowances between 2001 and 2005 and reduce its SO2 cap by

35 percent in 2013. Finally, the company agreed to pay

an $8.5 million fine, and to spend $21.5 million on additional environmental cleanup projects over the next 5

years.28

The outcome of the other pending lawsuits and regulatory actions is not known at this time. EIA takes no position on how these actions will or should be resolved;

however, if the result is that a large number of power

plants will be required to add state-of-the-art emissions

control equipment in the near future, it could have an

impact on the analyses discussed in Chapters 3 and 4 of

this report.

Analysis Requested

In light of the developments discussed above, the Subcommittee asked that EIA study the potential impacts of

two scenarios with different assumptions about the outcome of the ongoing legal and regulatory actions (see

letter of September 25, 2000, in Appendix J). In the first

scenario, the Subcommittee asked EIA to assume that

the owners of each of the 32 plants named in the NSR litigation must either install best available control technology, convert their coal-fired units to some other fuel

source, or retire those units by 2005. SO2 targets would

be reduced by amounts equal to the amount of allowances that would have been earned if the utilities had

installed scrubbers at the outset of Phase I of the SO2

trading program, modeling a “surrender” of allowances

as in the TECO settlement. In a second scenario, the Subcommittee asked EIA to assume that all coal-fired plants

in the power generation industry would be required to

add state-of-the-art emissions control technology,

switch to other fuel sources, or retire by 2010.

Four cases were prepared for the analysis described in

this chapter:

• Case 1, the NSR 32 case, includes all the assumptions

of the reference case described in Chapter 2, plus the

assumption that each of the 32 coal plants named in

the lawsuits by EPA would be required to add FGD

equipment to reduce SO2 and SCR equipment to

reduce NOx by 2005 in order to continue operating.

In addition it is assumed that these plants would be

required, as was TECO, to give up a portion of the

allowances allocated to them in the existing SO2 program. Although it remains unclear how the cases

will be resolved, this analysis case assumes that their

basic allowance allocations would be reduced by

half, or 600,000 tons.

• Case 2, the NSR All case, again includes all the

assumptions of the reference case described in Chapter 2, plus the assumption that all coal plants larger

than 25 megawatts would be required to add FGD

and SCR equipment by 2010 in order to continue

operating. As in the NSR 32 case, it is assumed that

the owners of the 32 plants named in EPA lawsuits

would have to make their decisions by 2005. In addition, it is assumed that when compliance decisions

are made in order to meet the summer season NOx

caps in 2004, a decision will also be made about adding NOx and SO2 controls, leading to the early addition of control equipment in this case.

• Case 3, the integrated NSR 32 case, combines the

assumptions of the NSR 32 case with the emission

caps assumed in the integrated 1990-7% 2005 case

described in Chapter 2. In other words, it is assumed

that power sector NOx and SO2 emissions would

have to be reduced by 75 percent below their 1997

level by 2005, and CO2 emissions would have to be

reduced to their 1990 level by 2005 and further to 7

percent below their 1990 level on average over the

2008 to 2012 period.

• Case 4, the integrated NSR All case, combines the

assumptions of the NSR All case with the emissions

caps assumed in the integrated 1990-7% 2005 case

described in Chapter 2.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 59

27“Dominion Virginia Power Reaches Major Agreement with EPA,” Electric News Release (November 15, 2000), web site

www.dom.com/news/elec2000/pr1115.html.

28“Cinergy, EPA, Other Parties Reach Agreement on Power Plant Lawsuit,” Cinergy Press Release, web site http://biz.yahoo.com/

bw/001221/oh_cinergy_2.html; “Cinergy Agrees to Pay $1.4 Billion to Settle Federal Pollution Lawsuit,” Wall Street Journal On-Line, web

site http://public.wsj.com/sn/y/SB977502597772054208.html.
In each of the NSR cases the National Energy Modeling

System determines the most economical way to comply

with the emissions reduction requirements, while at the

same time determining whether each of the affected coal

plants should be retrofitted with FGD and SCR equipment and continue operating or be retired. The model

has the option to add the control equipment to each

plant or replace it with one of the 31 new plant types represented. The model chooses the most economical of the

31 options when it decides to replace a plant. It can

replace a coal plant with another coal plant, a gas plant, a

renewable plant, etc. The option to convert an existing

coal plant to burn natural gas is not explicitly represented, because using relatively expensive gas in a plant

that is only about 33 percent efficient is generally not

economical. The model represents the conversion of a

coal plant to natural gas by building a new gas plant and

retiring the coal plant.

Results

NSR Base Cases

Table 20 provides summary information comparing the

projections in the NSR 32 and NSR All cases with those

in the reference case discussed in earlier chapters.

In terms of generation by fuel—coal, natural gas, and

renewables—the projections in the NSR base cases are

similar to those in the reference case, because the

requirement to add emission control equipment to some

or all existing coal plants does not change the relative

economics of operating most of them. In other words,

although adding scrubbers and SCR units can be expensive, the operating costs of most of the plants would continue to be competitive after they were retrofitted, and

they would continue to be used as they otherwise would

have been.

Some coal plants are projected to be retired rather than

retrofitted with the required control equipment. For

example, in the reference case, 10 gigawatts of coal-fired

capacity is expected to be retired between 1999 and 2020.

In the NSR 32 case, where retrofit decisions would have

to be made for approximately 45 gigawatts of coal-fired

capacity, an additional 4 gigawatts of coal-fired capacity

is projected to be retired. The vast majority of the plants

named in the EPA actions are expected to be retrofitted if

it is required. The projections are different in the NSR All

case, where retrofit decisions are required for all coal

plants. In the NSR All case, 31 gigawatts of coal-fired

capacity is projected to be retired by 2020—21 gigawatts

more than in the reference case.

An important issue in the NSR All case is the type of

capacity that would be built to replace retired coal

60 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 20. NSR Reference Case Projections, 2000, 2010, and 2020

Analysis Case

NOx Emissions

(Million Tons)

SO2 Emissions

(Million Tons)

CO2 Emissions

(Million Metric Tons

Carbon Equivalent)

Electricity Price

(1999 Cents

per Kilowatthour)

Coal-Fired Capacity

Retired

2000

Reference . . . . . . . . 4.57 11.43 570 6.80 0

2010

Reference . . . . . . . . 4.20 9.70 686 5.86 9

NSR 32 . . . . . . . . . . 3.78 9.10 689 6.01 13

NSR All . . . . . . . . . . 1.56 1.94 700 6.11 31

2020

Reference . . . . . . . . 4.37 8.95 776 6.00 10

NSR 32 . . . . . . . . . . 3.90 8.35 777 5.86 14

NSR All . . . . . . . . . . 1.62 1.90 784 5.96 31

Analysis Case

SO2 Scrubbers

Added

(Gigawatts)

SNCR Added

(Gigawatts)

SCR Added

(Gigawatts)

SO2 Allowance Price

(1999 Dollars

per Ton)

CO2 Allowance Price

(1999 Dollars per

Metric Ton Carbon

Equivalent)

2000

Reference . . . . . . . . 0 0 0 156 0

2010

Reference . . . . . . . . 11 29 86 170 0

NSR 32 . . . . . . . . . . 40 27 93 137 0

NSR All . . . . . . . . . . 195 19 276 0 0

2020

Reference . . . . . . . . 15 39 90 246 0

NSR 32 . . . . . . . . . . 40 32 99 162 0

NSR All . . . . . . . . . . 195 19 276 0 0

NA = not applicable. SNCR - selective noncatalytic reduction. SCR - selective catalytic reduction.

Source: National Energy Modeling System, runs MCBASE.D121300A, MC_NSR.D121900A, and NSR_ALL.D121900A.
plants. As discussed in Chapter 3, in the reference case

the vast majority of new capacity added—more than 90

percent—is expected to be fueled by natural gas. In that

case, however, only a small amount of coal capacity is

expected to be retired, and much of the new capacity

added is expected to be built to operate in an intermediate load fashion, rather than being built to operate at full

load for all hours of the year. New natural gas plants are

the most economical option when this intermediate load

capacity is needed. In the NSR All case, the retirement of

31 gigawatts of coal capacity is expected to lead to the

need for new capacity to operate in a baseload fashion, at

full load for most hours of the year. For this type of use,

new coal plants—all of which are expected to meet new

source emission standards—are projected to be competitive with natural gas plants in many parts of the country.

As a result, most of the 31 gigawatts of coal capacity

retired in the NSR All case is projected to be replaced

with new coal plants. Natural gas plants still are

expected to dominate capacity additions—386 gigawatts of 430 gigawatts of capacity added between 1999

and 2020 (90 percent of the total)—but new coal plants

are projected to play a bigger role than in the reference

case.

Relative to the reference case, the most significant

changes in the NSR 32 and NSR All cases are in the projections of power sector NOx and SO2 emissions. In both

cases, the requirement that coal plants add emissions

control equipment to continue operating leads to significant reductions in NOx and SO2 emissions relative to the

reference case—particularly in the NSR All case. For

example, in the NSR All case NOx emissions are projected to be 1.6 million tons in 2010, just over one-third

the level expected in the reference case. The change is

even more dramatic for SO2 emissions, which are projected to be 1.9 million tons in 2010, about 20 percent of

the level expected in the reference case. Because the NOx

and SO2 emission levels in the NSR All case are well

below the limits required by the summer season NOx

cap or the SO2 allowance program established in the

Clean Air Act Amendments of 1990, the allowance

prices are projected to fall to zero.

The impact on electricity prices is projected to be quite

small in the NSR base cases. As noted in the discussion

of the NOx and SO2 cap cases in Chapter 3, because the

costs of adding emissions controls generally do not

increase the operating costs of the plants setting the market price for power, the average price of electricity is not

expected to increase by much. The price impact is also

reduced as a result of the assumption that plants will be

forced to add the controls through “command and control” type regulation rather than through a cap and trade

program, which would be expected to lead to higher

NOx and SO2 allowance prices.

Although the price impacts are expected to be small, the

power companies required to add control equipment

would incur significant costs, particularly in the NSR All

case. Between 1999 and 2020, operators of coal-fired

power plants are projected to spend $58 billion to add

scrubbers to remove SO2 and $15 billion to add SCR NOx

emission control equipment.

Integrated Cases

Table 21 provides summary information comparing the

projections in the integrated NSR 32 and integrated NSR

All cases with those in the integrated 1990-7% 2005 case

discussed in earlier chapters. Again, the projections for

generation by fuel—coal, gas, and renewables—are similar among the three cases. The limit on CO2 emissions in

each of these cases is projected to lead to a rapid shift

from coal to natural gas and, to a lesser extent, renewable fuels for electricity generation. For example,

coal-fired generation in the reference case is projected to

be 2,284 billion kilowatthours in 2010, but in these cases

it is projected to range between 1,031 and 1,135 billion

kilowatthours, roughly 50 percent below the reference

case projection. Conversely, natural gas generation in

2010 is projected to be 1,123 billion kilowatthours in the

reference case but roughly 69 to 77 percent higher,

between 1,839 and 1,988 billion kilowatthours, in the

NSR integrated cases.

The major differences among these cases are expected to

be in NOx and SO2 emissions allowance prices, particularly in the NSR All case. For example, in the integrated

1990-7% 2005 case NOx emissions in 2010 are projected

to be 1.30 million tons, whereas they are projected to be

0.8 million tons in the integrated NSR All case. Similarly,

SO2 emissions are projected to be 3.9 million tons in 2010

in the integrated 1990-7% 2005 case but 1.0 million tons

in the integrated NSR All case.

NOx and SO2 allowance fees are projected to be lower in

the integrated NSR 32 and integrated NSR All cases than

they are in the integrated 1990-7% 2005 case, because the

requirement for coal plants that continue operating to

add emissions control equipment reduces the need for

other plant operators to take action to reduce their emissions. In the integrated NSR All case, both the NOx and

SO2 allowance prices are projected to fall to zero by 2010

and stay there through the rest of the forecast, because

the emission targets are assumed to remain at their 2008

levels through 2020.

Electricity prices in the three integrated cases are

expected to be similar. The projections for 2010 range

between 8.1 cents per kilowatthour and 8.4 cents per

kilowatthour, between 37 and 42 percent above the reference case projection. The lower level of coal-fired electricity generation expected in the integrated NSR All

case (because more coal plants are projected to be

retired) leads to greater dependence on new natural gas

plants, which in turn leads to higher projected natural

gas prices—$4.48 in 2020 in the integrated NSR All case

versus $4.30 in the integrated 1990-7% 2005 case.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 61
Summary

Requiring some or all coal-fired power plants to add

equipment to reduce NOx and SO2 emissions to continue

operating would have a significant impact on NOx and

SO2 emissions and their respective allowance prices. If

the 32 plants currently under suit by the Department of

Justice on behalf of the EPA are required to be retrofitted

with control equipment to continue operating, as

assumed in the NSR 32 case, it is estimated that the SO2

allowance price in 2010 would be cut by 19 percent relative to the projection in the reference case, from $170 to

$137 per ton. Total SO2 emissions are expected to be 0.6

million tons below the reference case level, because it is

assumed that the plants would surrender approximately half their allowances under the terms of an agreement to end the suit.

Similar behavior is expected in the NOx allowance market. The price impact of requiring the 32 plants to add

control equipment is projected to be small. As discussed

in Chapter 3, most of the control equipment is expected

to be added to plants that do not set the market prices for

power, and thus the costs would not be fully passed on

to consumers.

The projected impacts on NOx and SO2 emissions and

allowance prices are even larger in the NSR All case,

which assumes that all coal-fired power plants must be

retrofitted with control technology if they are to continue operating after 2010. In this case, both NOx and

SO2 allowance prices are expected to fall to zero, because

when new emission control equipment is added to all

operating coal plants, NOx and SO2 emissions are projected to be well under established emission caps. For

example, in the NSR All case, SO2 emissions in 2010 are

projected to be 1.9 million tons, well under the CAAA90

cap of 8.95 million tons.

A large number of coal plants—31 gigawatts (10 percent

of existing capacity)—are expected to be retired in the

NSR All case, because adding emission control equipment to them would not be economical. When those

plants are retired, however, there would be insufficient

baseload capacity (plants intended to run almost continuously) if they were not replaced. The vast majority of

the plants retired are projected to be replaced by new

coal plants that would comply with new source performance standards. As a result, projected CO2 emissions

in the NSR All case are virtually unchanged from those

in the reference case. As in the NSR 32 case, electricity

62 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 21. Integrated NSR Case Projections, 2000, 2010, and 2020

Analysis Case

Coal-Fired

Generation

(Billion

Kilowatthours)

Gas-Fired

Generation

(Billion

Kilowatthours)

NOx Emissions

(Million Tons)

SO2 Emissions

(Million Tons)

CO2 Emissions

(Million Metric

Tons Carbon

Equivalent)

Electricity Price

(1999 Cents per

Kilowatthour)

2000

Integrated 1990-7% 2005 . . 1,943 599 4.6 11.4 570 6.7

2010

Integrated 1990-7% 2005 . . 1,135 1,839 1.3 3.9 443 8.4

Integrated NSR 32. . . . . . . . 1,086 1,903 1.3 3.9 438 8.4

Integrated NSR All. . . . . . . . 1,031 1,988 0.8 1.0 442 8.1

2020

Integrated 1990-7% 2005 . . 852 2,774 1.1 3.3 440 7.8

Integrated NSR 32. . . . . . . . 869 2,755 1.1 3.3 439 7.7

Integrated NSR All. . . . . . . . 802 2,856 0.8 0.7 442 7.8

Analysis Case

Coal-Fired

Capacity

Retired

SO2 Scrubbers

Added

(Gigawatts)

SNCR Added

(Gigawatts)

SCR Added

(Gigawatts)

SO2 Allowance

Price (1999

Dollars per Ton)

CO2 Allowance

Price (1999

Dollars per Metric

Ton Carbon

Equivalent)

2000

Integrated 1990-7% 2005 . . 0 0 0 0 150 0

2010

Integrated 1990-7% 2005 . . 47 10 49 147 226 134

Integrated NSR 32. . . . . . . . 74 21 39 134 119 132

Integrated NSR All. . . . . . . . 133 103 34 232 0 92

2020

Integrated 1990-7% 2005 . . 79 17 49 147 99 130

Integrated NSR 32. . . . . . . . 94 21 39 134 86 122

Integrated NSR All. . . . . . . . 134 103 34 232 0 112

SNCR - selective noncatalytic reduction. SCR - selective catalytic reduction.

Source: National Energy Modeling System, runs FDP7B05.D121300B, FDP_N32.D121900A, and FDP_ALL.D121900A.
prices in the NSR All case are expected to be only

slightly above those projected in the reference case.

Power plant owners are projected to spend roughly $15

billion on SCR NOx controls and $58 billion on SO2 controls, reducing the profitability of the plants but not

making them uneconomical.

When the assumptions in the NSR 32 and NSR All cases

are combined with those used in the integrated 1990-7%

2005 case described in Chapter 2, the results are similar.

Comparing the results in the integrated 1990-7% 2005,

integrated NSR 32, and integrated NSR All cases shows

that, to meet the emissions targets specified by the Subcommittee, the power sector is projected to reduce its

use of coal dramatically and to increase its use of natural

gas and, to a lesser extent, renewables.

The requirement that emission control equipment must

be added to coal-fired plants if they are to continue operating in the integrated NSR All case is projected to lead

to more coal plant retirements than projected in the integrated 1990-7% 2000 or integrated NSR 32 case, leading

in turn to a lower CO2 allowance fee in the integrated

NSR All case. It is also projected to lead to even greater

dependence on natural gas and, as a result, higher natural gas prices. The projected electricity prices are similar

to those in the integrated 1990-7% 2005 case. This analysis suggests that efforts to reduce NOx and SO2 emissions at existing coal-fired power plants would make a

portion of the plants uneconomical, but the majority

would continue operating. Additional effort would be

needed to substantially reduce power plant CO2

emissions.

The analysis in this chapter assumes that affected

coal-fired plants would make compliance decisions

according to the schedule specified by the Subcommittee. The Subcommittee requested that EIA assume that

the 32 plants named in the Justice Department suit

would have to be retired or retrofitted with best available control technology by 2005, and that all other

coal-fired plants would need to follow suit by 2010. In

fact, it is likely that the terms of any settlements with the

owners of the affected plants will vary from this strict

timetable. The three settlements reached to date allow

the companies to take action on a schedule that is somewhat less restrictive than the assumptions made in this

analysis. To the extent that the owners of coal-fired

plants are required to take the actions assumed in this

analysis on a more or less restrictive timetable than EIA

has assumed, the cost impacts could also be more or less

severe. In addition, if all affected plants were forced to

install the required equipment in either 2005 or 2010, it is

possible that short-term bottlenecks in acquiring the

needed labor and materials could arise, potentially making the cost to the industry higher than indicated by the

analysis in this chapter.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 63

6. Comparisons With Other Studies

Introduction

In recent years, significant analysis has been devoted to

the problem of reducing individual airborne emissions

from electric power plants—either greenhouse gases, of

which carbon dioxide (CO2) is the most pervasive,29 or

any of several criteria pollutants,30 such as sulfur dioxide (SO2)31 and nitrogen oxides (NOx).32 Other studies

have focused on demand-side innovations, principally

in other sectors, that could alleviate power plant emissions.33 Less attention has been directed to the problem

of analyzing multi-emission reduction strategies. This

chapter provides a summary of four recent studies

addressing the joint reduction of SO2, NOx, CO2, and

mercury (Hg) emissions in some combination and compares them, where possible, with the findings of the

analysis described in this report.

Over the past several years, the U.S. Environmental Protection Agency (EPA) has used the Integrated Planning

Model (IPM) to analyze strategies for reducing emissions of SO2, NOx, CO2, and Hg, first under the Clean

Air Power Initiative in 1996 and again in 1999 after soliciting industry reaction and input.34,35 The Electric Power

Research Institute (EPRI) also took up the question of

reducing SO2, NOx, and CO2 emissions, examining

both cost effects and long-term sustainability.36 The

Environmental Law Institute (ELI) approached the

question differently, examining the economic impacts of

a 50-percent reduction in coal-fired generation by 2010

using the Resources for the Future (RFF) Haiku electricity market model.37 Although there are similarities

among the studies, they were prepared with different

objectives, incorporating different assumptions about

emission limits and using different methodologies. As a

result, comparisons among them must be made

cautiously.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 65

29For example, WEFA, Inc., Global Warming: The High Cost of the Kyoto Protocol, National and State Impacts (Eddystone, PA, 1998); H.D.

Jacoby, R. Eckhaus, A.D. Ellerman, et al., “CO2 Emission Limits: Economic Adjustments and the Distribution of Burdens,” Energy Journal,

Vol. 18, No. 3 (1997), pp. 31-58; S. Bernow et al., America’s Global Warming Solutions (Washington, DC: World Wildlife Fund and Energy

Foundation, August 1999); H. Geller, S. Bernow, and W. Dougherty, Meeting America’s Kyoto Protocol Target: Policies and Impacts (Washington, DC: American Council for an Energy-Efficient Economy, December 1999); Congressional Budget Office, Who Gains and Who Pays Under

Carbon-Allowance Trading? The Distributional Effects of Alternative Policy Designs (Washington, DC, June 2000).

30Other criteria pollutants include carbon monoxide, lead, particulate matter (PM10), and volatile organic compounds.

31D. Burtraw and E. Mansur, “Environmental Effects of SO2 Trading and Banking,” Environmental Science & Technology, Vol. 33, No. 20

(October 15, 1999), p. 3489; K.K. Dhana, “A Market-Based Solution to Acid Rain: The Case of the Sulfur Dioxide (SO2) Trading Program,”

Journal of Public Policy & Marketing, Vol. 18, No. 2 (Fall 1999), pp. 258-265; R.D. Lile, D. Bohi, and D. Burtraw, An Assessment of the EPA’s SO2

Emission Allowance Tracking System (Washington, DC: Resources for the Future, February 1997).

32U.S. Environmental Protection Agency, Regulatory Impact Analysis for the Final Section 126 Petition Rule (Washington, DC, December

1999); D. Burtraw, K. Palmer, and A. Paul, The Welfare Impacts of Restructuring and Environmental Regulatory Reform in the Electric Power Sector

(Washington, DC: Resources for the Future, October 1998), preliminary version; A. Krupnick, V. McConnell, M. Cannon, T. Stoessell, and M.

Batz, Cost-Effective NOx Control in the Eastern United States (Washington, DC: Resources for the Future, April 2000).

33Interlaboratory Working Group, Scenarios for a Clean Energy Future, ORNL/CON-476 and LBNL-44029 (Oak Ridge, TN: Oak Ridge

National Laboratory; Berkeley, CA: Lawrence Berkeley National Laboratory, November 2000); J. Koomey, R. Richey, S. Laitner, R. Markel,

and C. Marnay, Technology and Greenhouse Gas Emissions: An Integrated Scenario Analysis Using the LBNL-NEMS Model, LBNL-42054 (Berkeley, CA: Lawrence Berkeley National Laboratory September 1998); Alliance to Save Energy, American Council for an Energy-Efficient Economy, Natural Resources Defense Council, Tellus Institute, and Union of Concerned Scientists, Energy Innovations 1997: A Prosperous Path to a

Clean Environment (Washington, DC, June 1997). Modeling demand-side reductions in the end-use sectors can produce dramatic results. The

Clean Energy Future report projects carbon reductions similar to those identified here, with a carbon allowance fee of $50 per ton and limited

costs to consumers. Among the assumptions for the power sector necessary to achieve this result, however, are extension of the 1.5 cents per

kilowatthour production tax credit through 2004 and capital costs for wind technology of $611 per kilowatt (as compared with $993 per kilowatt in EIA’s analysis). Further, other policies in the study serve to reduce projected energy demand, so that energy consumption in 2020 is

projected to be about 95 quadrillion Btu, roughly equivalent to maintaining 1998 levels of consumption for the next 20 years.

34U.S. Environmental Protection Agency, EPA’s Clean Air Power Initiative (Washington, DC, October 1996).

35U.S. Environmental Protection Agency, Analysis of Emissions Reduction Options for the Electric Power Industry (Washington, DC, March

1999), web site www.epa.gov/capi/multipol/mercury.htm.

36Electric Power Research Institute, Energy-Environment Policy Integration and Coordination Study, TR-1000097 (Palo Alto, CA, 2000).

37Environmental Law Institute, Cleaner Power: The Benefits and Costs of Moving from Coal to Natural Gas Power Generation (Washington, DC,

November 2000).
The studies discussed here all contain extensive analysis

of impacts on the electricity generation sector.38 Among

the key variables examined are changes in capacity type,

changes in fuel use and the consequent fuel price

responses, changes in the overall generation mix,

responses of renewable technologies, and SO2 allowance

prices and carbon allowance fees. However, because the

studies assume caps of different levels, on different

emissions, over different time periods, and starting

from different baselines, straightforward comparisons

among the studies are difficult.

In this chapter, the reference cases from the studies are

compared, and two of the integrated cases from the EIA

analysis are compared with integrated cases from the

EPA, EPRI, and ELI studies. Generally speaking, all the

studies introduce various emission caps. Beyond that

immediate similarity, there are differences in the

assumptions made and in the methodologies and, to a

lesser extent, the initial baselines used that render highly

detailed comparisons difficult. These include:

• Integrated versus nonintegrated models. The models used in the studies by EIA, EPRI, EPA, and ELI all

have detailed representations of the electricity sector, but details in the representation of other sectors

of the energy economy and their interaction with the

electricity sector differ. For example, the EIA’s

National Energy Modeling System (NEMS) endogenously calculates consumer demand for each fuel

and the prices at which the fuels are expected to be

supplied in order to meet demand. When changes in

assumptions (such as adding pollution control

equipment or switching fuels to reduce emissions)

alter fuel production costs, the projections of fuel

prices and consumers’ responses to them are recalculated by the model. Because the EPRI analysis

used NEMS through 2020 it shares this behavior. In

the EPA analysis, electricity demand and a battery of

fuel supply curves are determined exogenously.

When emission caps are imposed on the electricity

generation sector, there are shifts in the demand for

different fuels, resulting in different fuel prices (e.g.,

the wellhead price for natural gas) in the reference

and integrated cases. Unlike in the NEMS model,

however, fuel supply and demand for the electricity

generation sector are not endogenously linked in an

integrated system in the EPA model. Thus, the EPA

analysis does not include a fuel price response to

higher demand or a decline in electricity demand in

response to higher prices. The Haiku model contains

endogenous electricity demand that responds to

changes in prices and upward-sloping fuel supply

curves for natural gas and coal.

• Treatment of nuclear power. Because nuclear generating units produce no emissions, assumptions

about their ability to remain in the generation mix

through 2020 can play a key role. In NEMS, maintenance versus retirement decisions for nuclear plants

are evaluated endogenously. NEMS weighs the costs

of maintaining each nuclear plant against the costs of

building a new plant to replace it. When the costs of

new fossil plants increase (as in the cases with CO2

caps in this analysis), the economics of maintaining

existing nuclear plants improves, and fewer are

retired. In the EPA analysis, nuclear capacity is

assumed to decrease from 87 gigawatts in 2005 to 50

gigawatts in 2020. Like NEMS, Haiku has an endogenous nuclear retirement algorithm.

• Knowledge and ability to react to changing market

conditions, including lead time. Decisionmakers, as

represented in models, may have perfect knowledge

or very little foresight. As an integrated model,

NEMS incorporates macroeconomic feedback in

response to the electric power industry’s response to

emission caps. The model used by EPA does not

incorporate this type of response mechanism.

• Treatment of Emission Caps: Both the IPM and

NEMS are able to model emission caps directly,

allowing investments in controls to be made ahead

of the control date. The explicit representation also

enables the projected allowance prices for each controlled pollutant to be obtained as direct model outputs. Haiku has the ability to model such caps, but

the ELI study employs a cap on total coal-fired

generation.

• Representation of Emission Control Technologies:

The IPM, NEMS, and Haiku models allow power

plants to choose from an array of control technologies for reducing SO2 and NOx; however, the IPM

includes a broader array of control technologies than

represented in either NEMS or Haiku.

The analyses reviewed here also have some important

similarities, the most important being a similar representation of available generating technologies and emission control technologies. All the models can choose to

introduce new technologies such as integrated coal gasification units, gas turbines, advanced combined-cycle

units, and renewable technologies. The models respond

to SO2 constraints in similar ways, either by means of

adding a scrubber retrofit, switching fuels, or economic

66 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

38The NEMS model does not analyze or forecast health benefits. One recent estimate projected direct health benefits stemming from the

Clean Air Act Amendments of $110 billion in 2010 (1999 dollars). See U.S. Environmental Protection Agency, The Benefits and Costs of the

Clean Air Act 1990 to 2010, EPA-410-R-99-001 (Washington, DC, November 1999).
retirement. NOx controls may be introduced during the

combustion phase or through post-combustion technologies.39 CO2 emissions are constrained through a carbon

cap.40 Finally, all the models show similar starting

points for key electric power industry statistics, including total generating capacity, coal-fired capacity, electricity demand, and baseline projections for CO2

emissions from the electric power industry.

Summary of Studies

EPA’s 1999 Emission Reduction Analysis

EPA’s Clean Air Power Initiative (CAPI), which began

in 1995, was intended to improve air pollution control

efforts by involving the power generating industry in

developing and analyzing alternative approaches to

reducing three major emissions: SO2, NOx, and, potentially, Hg. The analysis used the IPM, a detailed model

of the electric power industry in which plant operators

react to alternative levels of pollution controls. CAPI

proposed a “cap and trade” approach for the emissions

and modeled the proposed reductions on a national

scale. Initial NOx caps were set for both summer and

winter beginning in 2000, and the initial rate-based caps

were then reduced to the most stringent levels modeled,

0.15 pounds per million Btu in 2005. At the same time,

SO2 was reduced in 2010 by lowering the current Clean

Air Act Amendments of 1990 (CAAA90) Title IV SO2

allowance cap by 50 percent, to about 4.5 million tons

per year. A cap on Hg emissions was set in 2000 to the

amount expected in 2000, and then lowered in 2005 by 50

percent, and again in 2010 by another 50 percent (total

75-percent reduction). The results of the initial analysis

effort were published in 1996, and the EPA invited interested parties to comment.

EPA’s Office of Air and Radiation responded to comments received and modified CAPI in a new series of

modeling efforts in 1999. The emissions analyzed were

SO2, NOx, CO2, and Hg. Unlike the 1996 study, NOx

emissions were not reduced beyond then-current statutory requirements, such as Phases I and II of the Title IV

Acid Rain program or the NOx SIP (State Implementation Plan) Call, under which 22 States41 and the District

of Columbia must reduce NOx emissions by 2004. Hypothetical emission caps were developed for each of the

remaining emissions. This study allowed a variety of

compliance options to meet the emission caps, including

fuel switching, repowering, retrofitting or retiring units,

and adjusting dispatch.

EPA’s 1999 analysis modeled reductions of the emissions singly and, in certain combinations, jointly. SO2

emissions were reduced from current levels to four alternative levels (by 40 percent, 45 percent, 50 percent, and

55 percent) beginning in 2007, and the targets were

assumed to be met in 2010. The analysis cases used the

cap and trade approach, with banking of allowances

permitted from 2005 to 2007.

Two alternative cases in the EPA analysis examined CO2

reduction options. The first provided the power industry with 463 million metric tons carbon equivalent per

year in allowances and assumed that the industry would

find it most economical to purchase an additional 104

million metric tons carbon equivalent in allowances on

the international market, effectively capping emissions

from electricity generators at 567 million metric tons carbon equivalent per year. The second CO2 alternative

introduced high efficiency assumptions, whereby electricity demand was assumed to be 15 percent lower in

2010 than projected by the industry. Demand was

reduced by 1.5 percent annually during the years 2000 to

2010 and by 1 percent annually for the next 10 years. The

effective CO2 emission cap remained at 463 million metric tons carbon equivalent, and the industry was

assumed to find it most economical to purchase additional allowances of 52 million metric tons carbon equivalent, yielding a domestic carbon emission cap of 515

million metric tons carbon equivalent for electricity

generators.

Costs for controlling Hg emissions were analyzed by

assuming that coal-fired generators would install maximum achievable control technology (MACT) in conjunction with either the 50-percent SO2 reduction or the 515

million metric tons carbon equivalent CO2 / high efficiency scenario. Two cases considered SO2 and CO2

reductions jointly: (1) the 50-percent SO2 reduction with

a CO2 level of 567 million metric tons carbon equivalent,

and (2) the 50-percent SO2 reduction in combination

with a CO2 level of 515 million metric tons carbon equivalent and high efficiency constraints assumed to reduce

demand by 15 percent in 2010.

A key finding of EPA’s 1999 analysis was that a joint

SO2-CO2 reduction strategy would cost the industry less

than undertaking the reduction strategies separately. In

2010, reducing SO2 emissions by 50 percent of the base

projection was estimated to cost about $2.5 billion (1990

dollars), and meeting the CO2 cap of 515 million metric

tons carbon equivalent was estimated to cost about $2

billion, with the additional costs resulting from the

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 67

39Selective catalytic or noncatalytic reduction.

40The ELI study reduces CO2 emissions indirectly by capping coal-fired generation.

41In the EIA analysis cases, the SIP Call modeled applies to 19 States, because since it was first proposed, facilities in Wisconsin have been

removed from the program, and the caps on facilities in Missouri and Georgia are under review.
installation of scrubbers, introduction of natural gas

combined-cycle technology, and additional dispatch of

gas-fired units. Joint reduction lowered the projected

aggregate costs to $3.6 billion, or by about 20 percent.42

The EPA analysis concluded that the industry, when

faced with significant CO2 constraints over and above

SO2 caps, would avoid costly scrubber retrofits and

turn to natural gas generation in order to meet SO2

constraints.

EPRI’s Energy-Environment Policy

Integration and Coordination Study

The timing and coordination of multiple pollution

reduction strategies was the primary focus of EPRI’s

E-EPIC analysis. Observing that current policy requires

power generators to reduce NOx and SO2 emissions in

the short term, while the Kyoto Protocol calls for significant reductions in CO2 emissions over the period

2008-2012, EPRI suggested that two key questions

should be addressed. First, would the large investments

needed to meet the short-term NOx and SO2 reductions

become “stranded” (unproductive) in the event that

additional CO2 reductions were to be later stipulated?

Second, would the combined effects of sequential emission reduction policies lead to significant increases in the

price of electricity and other distortions in the national

energy system over the longer term to 2050?

EPRI used the NEMS model for the years through 2020

and then extended the NEMS Electricity Market Module

to 2050, using other econometric models for projecting

energy consumption, prices, and CO2 emissions.

In addition to a reference case,43 EPRI developed a

Current Policy Direction case. Modeling recent proposals addressing NOx, particulate matter, and CO2, the

Current Policy Direction case imposed a summer NOx

reduction of 85 percent below 1990 levels in 22 States, a

subsequent 50-percent reduction in SO2 emissions by

2007, and a CO2 emissions target of 9 percent above

1990 levels that would be phased in from 2005 through

2008.44 In contrast, EPRI’s third scenario, the “Carbon

Glide Path to 2030” assumed no further NOx or SO2

reductions beyond current policy and imposed a

gradual CO2 reduction strategy beginning in 2005,

increasing gradually to 2030, resulting in cumulative

CO2 emissions by 2050 that would be the same as in the 9

percent above 1990 case. As such, the Carbon Glide Path

did not directly examine the effects of multiple emission

reduction strategies.

The conclusions reached in EPRI’s E-EPIC analysis differ from those of EPA’s 1999 analysis. In the E-EPIC Current Policy Direction case, two-thirds of coal-fired

capacity would be retired by 2020, and the coal share of

generation would drop from a 2000 level of 55 percent to

less than 10 percent by 2020. Nearly 500 gigawatts of

gas-fired generating capacity would be added by 2020,

with the gas share of total generation rising from 15 percent in 2000 to 60 percent by 2020. Although E-EPIC was

tacit on total compliance costs, the study concluded that

investment in initial compliance with proposed reductions for SO2 in the short term would become stranded

over the mid-term if CO2 constraints were subsequently

introduced. The study implied that this “inefficiency”

could be costly to the electric power industry, and consequently to consumers, both in the short term and in the

long term.

Recent Work: “Cleaner Power” Studies

In a recent report issued by Harvard University’s John F.

Kennedy School, Lee and Verma examined the possible

effects of an integrated strategy of emissions reduction

in the Midwest.45 The report identified factors and quantified costs needed to induce coal-fired electricity generators in the Midwest to switch voluntarily from reliance

on coal to greater use of natural gas. The authors

assumed that coal plants in that region currently operate

at just over half the capital and operating cost of a new

gas-fired facility. Although the analysis did not cap

emissions at specific levels and examined only the rate at

which repowering from coal to gas might be induced,

the authors reached several conclusions relevant to the

EIA, EPA, and EPRI analyses. Their report concluded

that the costs associated with reducing NOx, SO2, and

particulate matter were not high enough to lead to

retirements of Midwest coal plants in favor of new natural gas plants. Only the introduction of moderate carbon

allowance fees in their analysis made significant

amounts of gas-fired generation more attractive than

coal-fired generation.

68 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

42The IPM calculates total cost as a total resource cost, thereby excluding allowance costs. EIA’s analysis in 2010 for the most stringent

integrated case includes about $58 billion for purchases of emission allowances in the estimated total compliance cost of $86 billion (in 1999

dollars). Higher projected prices for natural gas account for much of the remaining difference between the EPA and EIA estimates of total

compliance costs.

43EPRI used the reference case from the EIA’s Annual Energy Outlook 1999, DOE/EIA-0383(99) (Washington, DC, December 1998),

NEMS run AEO99B.D100198A. The case incorporated all environmental regulations in effect as of mid-1998, including Phase II of the Title

IV Acid Rain program and EPA’s proposed SIP Call summer NOx reductions for 22 States and the District of Columbia.

44EPRI assumed that the remainder of the Kyoto Protocol CO2 reductions would be met through international carbon permit trading and

sequestration. The 9 percent above 1990 level implies CO2 emissions of about 1,462 million metric tons carbon equivalent in 2010, of which

about 409 million metric tons carbon equivalent would be attributable to the electricity generation sector.

45H. Lee and S.K. Verma, “Coal or Gas: The Cost of Cleaner Power in the Midwest,” BCSIA Discussion Paper 2000-08, ENRP Discussion

Paper E-2000-08 (Kennedy School of Government, Harvard University, June 2000).
In order to analyze the rate of conversion from coal to

gas, the authors first estimated the marginal cost of

abatement for SO2 and the average abatement costs for

NOx, particulates, and Hg, arriving at a total cost for

conventional pollution abatement of about 1 cent per

kilowatthour.46 Assuming a long-term natural gas price

of $2.50 per thousand cubic feet, they concluded that a

carbon allowance fee of $60 to $70 per ton would prompt

about two-thirds of the coal capacity47 in the Midwest to

shift to gas-fired generation. When more favorable gas

prices of $2.00 per thousand cubic feet was assumed, a

carbon fee between $20 and $30 per ton was expected to

induce a two-thirds shift. Gas prices of $3.00 per thousand cubic feet were estimated to require a carbon allowance fee near $150 per ton in order to accomplish the

same shift away from coal-fired generation.48 The

authors projected that a carbon allowance fee in the

range of $60 to $85 per ton would increase retail electricity prices in the Midwest by 15 to 22 percent, to a range

of 10.0 to 10.7 cents per kilowatthour.

The impacts of carbon allowance fees estimated by Lee

and Verma are comparable to those in EIA’s analysis. In

EIA’s most stringent integrated case, cumulative coal

retirements nationally are projected to reach 47

gigawatts by 2010, about 15 percent of current coal

capacity, with a corresponding carbon allowance fee of

$134 per ton and a projected gas price of $4.33 per thousand cubic feet in 2010. Lee and Verma indicate that a

combination of high gas prices ($3.00 per thousand cubic

feet) and efficient conventional coal retrofits would force

the conversion of 21 to 30 percent of coal-fired generating resources,49 indicating a carbon allowance fee

between $120 and $130 per ton.

A recent report from the Environmental Law Institute

(ELI) arrived at findings similar to those of Lee and

Verma. Using the Haiku Electricity Market Module50

developed and maintained by Resources for the Future,

ELI modeled a scenario in which coal-fired generation

was reduced by 25 percent in 2005 and by an additional

25 percent by 2010, replacing the generation with electricity from gas-fired turbines and combined-cycle

units.51 The shift in generation produced dramatic

changes in emission patterns, reducing SO2 by 51 percent, NOx by 40 percent, and CO2 by 26 percent in 2010.52

ELI’s analysis projected that the retail price of electricity

would rise by 0.6 cents, to 6.63 cents per kilowatthour

(1997 dollars), leading to total economic costs, mostly

lost consumer surplus, estimated at $25.9 billion (1997

dollars) in 2010.53 Total electricity generation was projected to grow modestly over the 1998-2010 forecast

period but was projected to fall slightly in the policy case

from the “business as usual,” or reference, case. Total

nameplate coal-fired generating capacity was projected

to decline by about 9 percent, to 293 gigawatts in 2010,

indicating that decreased capacity utilization rates for

coal plants would not necessarily render them uneconomical. Natural gas prices were projected to increase

by 21 percent in the policy case, with prices in 2010

climbing from $3.30 per million Btu in the reference case

to $4.00 per million Btu in the policy case.54 The report

underscores the finding that integrated approaches to

emission reductions offer significant efficiencies.

Reference Case Comparisons

Reference case results for the four studies examined here

show reasonably similar starting points (Table 22).55 In

both the EPA and EPRI studies, the reference cases were

calibrated to earlier versions of EIA’s Annual Energy

Outlook. EPRI used the Annual Energy Outlook 1999 reference case, and EPA used the Annual Energy Outlook 1998.

Projections of coal-fired capacity in 2005 are nearly identical, ranging from a high of 319 gigawatts in ELI’s reference case to 303 gigawatts in the EPRI and ELI Business

As Usual cases. In EPRI’s Business As Usual case, coal

capacity is projected to increase slightly by 2010, but in

EPA’s 1999 reference case it declines slightly. Projections

of coal-fired generation are fairly divergent, ranging

from a low of 1,770 billion kilowatthours in 2005 in ELI’s

reference case to a high figure of 2,156 in EIA’s reference

case. ELI’s reference case, however, projects the lowest

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 69

46The authors put the upper bound at 1.36 cents per kilowatthour and the lower bound at 0.68 cents per kilowatthour (in 1998 dollars).

47Current coal capacity in East Central Area Reliability (ECAR) is about 84 gigawatts, suggesting a shift of about 56 gigawatts to gas.

48The high and low sensitivities incorporated the respective assumptions regarding high and low costs of conventional pollution abatement.

49In EIA’s analysis, some reductions are projected to be achieved by building new renewable sources of generation, a factor not

addressed in the Cleaner Power studies.

50Like NEMS, Haiku models some North American Electric Reliability Council regions as competitive; only in these regions are tradeable generation permits allowed.

51Small amounts of additional wind capacity were also projected.

52Reduced Hg levels were also projected in the ELI policy case, to 21 tons in 2010, or about a 75-percent reduction from the 1998 baseline

of 80 tons.

53The analysis also identified $26.4 billion in public health benefits from reductions in SO2 and NOx as a result of lower particulate concentrations.

54In 1999, natural gas deliveries to electric utilities averaged 1,022 Btu per cubic foot; corresponding prices per thousand cubic feet would

be about 2 percent lower.

55The study by Lee and Verma was regional in scope, preventing national comparisons.
coal share of generation in 2005, about 46 percent of total

generation. Coal’s share of generation is projected to

stay about the same in each of the four cases from 2005

through 2010.

Projections of generation from natural gas in 2005 vary

significantly in the reference cases, ranging from 561 billion kilowatthours in EPA’s reference case56 to 1,056

billion kilowatthours in ELI’s study. The share of generation from gas, however, is projected to increase in all of

the studies by 2010. ELI’s share of gas generation

expands the least, as both EIA and EPRI projections of

gas generation grow at a faster rate. Gas-fired generation

in the ELI reference case is substantially higher than in

the other studies, especially EPA’s 1999 reference case,

which ELI exceeds by 495 billion kilowatthours in 2005

and by 508 billion kilowatthours in 2010.

Projections of nuclear generation exhibit widely disparate baselines in 2005, with EIA projecting 740 billion

kilowatthours, EPA 609 billion kilowatthours, EPRI

projecting 627 billion kilowatthours, and ELI 670 billion kilowatthours. All the studies except ELI project

declining generation from nuclear sources, a trend that

is most pronounced in the EPRI study, at about 12 percent by 2010.

Generation from nonhydroelectric renewable sources

shows the largest response in the EIA reference case,

with a projected increase from 97 billion kilowatthours

in 2005 to 125 billion kilowatthours in 2010. Renewable

generation increases in both the EPRI and ELI reference

cases, from 61 billion kilowatthours to 66 billion kilowatthours in the former and from 35 billion kilowatthours to 39 billion kilowatthours in the latter. EPA’s

reference case projects no increase in renewable generation over the forecast period.

Electricity demand rises in all four reference cases, led

by a 10-percent increase in the EIA study, with both

EPRI and ELI projecting about a 7-percent increase and

EPA a 5-percent increase. The average projected electricity price falls by similar amounts in the three studies that

report prices,57 in part because coal prices are projected

to decline over the 2005-2010 period. Gas prices are projected to rise and coal prices are projected to fall across

70 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 22. Key Reference Case Projections for Electricity Generation in Four Multi-Emission Studies, 2005,

2007, and 2010

Projection

EIA

Reference Case

EPA

1999 Reference Case

EPRI E-EPIC

Business As

Usual Case

ELI

Business As

Usual Case

2005 2007 2010 2005 2007 2010 2005 2007 2010 2005 2010

Coal-Fired Capacity (Gigawatts) . . . . . . . . . 302 312 317 305 304 301 303 303 305 319 321

Electricity Generation by Fuel

(Billion Kilowatthours)

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,156 2,235 2,284 2,084 2,091 2,114 2,052 2,065 2,096 1,770 1,805

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . 813 907 1,123 561 626 759 838 1,006 1,175 1,056 1,267

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . 740 738 720 609 613 580 627 587 551 670 683

Renewablesa . . . . . . . . . . . . . . . . . . . . . . . 97 108 125 61 61 61 61 62 66 35 39

Electricity Demand

(Billion Kilowatthours) . . . . . . . . . . . . . . . . . 3,762 3,919 4,146 3,612 3,690 3,809 3,578 3,702 3,859 3,863 4,121

Electricity Price

(1999 Cents per Kilowatthour). . . . . . . . . . . 6.2 6.0 5.9 NA NA NA 6.3 6.1 6.0 6.5 6.1

Natural Gas Wellhead Price

(1999 Dollars per Thousand Cubic Feet) . . 2.49 2.60 2.68 2.05 2.05 2.05 2.41 2.52 2.61 NA 3.37

Coal Minemouth Price

(1999 Dollars per Short Ton) . . . . . . . . . . . . 14.76 14.23 13.69 NA NA NA 15.39 15.01 14.47 NA NA

Carbon Dioxide Emissions

(Million Metric Tons Carbon Equivalent) . . . 637 658 686 605 615 621 620 634 657 652 671

Sulfur Dioxide Emissions

(Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 10.4 10.1 9.7 11.0 10.9 9.7 10.5 9.8 9.2 10.1 9.0

Nitrogen Oxide Emissions

(Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 4.22 4.19 4.20 4.22 4.25 4.15 3.99 4.03 4.10 5.52 5.52

a

Excludes hydroelectric generation.

NA = not available.

Sources: EIA: National Energy Modeling System, run MCBASE.D121300A. EPA: U.S. Environmental Protection Agency, Analysis of Emissions

Reduction Options for the Electric Power Industry (Washington, DC, March 1999), run HGIPM9C. EPRI: Electric Power Research Institute,

Energy-Environment Policy Integration and Coordination Study: Executive Report (Washington, DC, April 2000), run Business As Usual. ELI: Environmental Law Institute, Cleaner Power: The Benefits and Costs of Moving from Coal to Natural Gas Power Generation (Washington, DC, November

2000), run Business As Usual.

56Includes generation from dual-fired facilities not otherwise specified.

57EPA’s 1999 analysis does not report end-use prices.
all the studies. CO2 emissions are projected to increase in

all the reference cases, with EIA projecting the largest

increase over the 2005-2010 period at just over 7 percent.

Comparison of Integrated Cases

In the cases that assume integrated multi-emission

reduction strategies, the electric power industry is projected to respond with similar changes in the four studies. All the integrated cases project reduced coal

capacity, reduced generation from coal, and increased

generation from natural gas (Table 23). In three of the

studies, gas prices are projected to rise over the relevant

forecast horizon, and coal prices are projected to fall.

EPA’s analysis does not model a fuel price response.

Differences in the assumed CO2 emission targets

account for some of the differences in the projected

industry response. From a reference case projection of

686 million metric tons carbon equivalent, EIA’s integrated 1990-7% 2005 case assumes a reduction to 443

million metric tons carbon equivalent by 2010. EPRI’s

Current Policy Direction case assumes CO2 emissions of

399 million metric tons carbon equivalent by 2010. The

CO2 targets of 567 million metric tons carbon equivalent

and 515 million metric tons carbon equivalent in EPA’s

1999 analysis are significantly more lenient.58 Both the

EIA and EPRI studies include a carbon allowance fee,

but their emission targets are different. EPA’s 1999 analysis did not report a carbon allowance fee.

The integrated cases in the four studies indicate that

when CO2 emissions are significantly reduced, the need

to address directly the remaining emissions, NOx and

SO2, is mitigated. In EIA’s study, NOx reductions of 75

percent below 1997 levels are projected to be achieved

with far fewer NOx equipment retrofits (only 197

gigawatts, compared with 312 gigawatts in the NOx 2005

case). SO2 equipment retrofits are projected to be 10

gigawatts in 2010 in EIA’s integrated 1990-7% 2005 case,

compared with 98 gigawatts in the SO2 2005 case. The

integrated cases in EPA’s 1999 analysis indicate a similar

industry response. Projected NOx retrofits fall in the

integrated cases relative to those in the NOx only cases.

Similarly, EPA projects greatly reduced need for scrubbers in the integrated cases, falling by more than half

from 93 gigawatts in the 55-percent SO2 reduction case

to 45 gigawatts in the integrated 50-percent SO2 reduction and the 515 million metric ton CO2 reduction case.

The EIA study projects the greatest reduction in

coal-fired capacity, from the reference case projection of

317 gigawatts in 2010 to 260 gigawatts in the integrated

1990-7% 2005 case in 2010. The EPA study, which projects steady levels of coal capacity when SO2 constraints

alone are assumed, projects about an 8-percent reduction in coal capacity to 279 gigawatts in 2010 when CO2

emissions are capped at 515 million metric tons carbon

equivalent. The EPRI study projects that coal capacity

would fall by about 35 gigawatts from the reference level

in 2010 in the Current Policy Direction case.

Coal-fired electricity generation is projected to decline in

the integrated cases in all the studies, but the reductions

vary in both magnitude and timing. In the EPA study,

which projects far more coal-fired generation in its most

stringent case than do the other studies, coal-fired generation still is projected to decline by 461 billion kilowatthours by 2010, to 1,653 billion kilowatthours. The

EIA study projects a decline of more than half, and EPRI

projects a drop of about 59 percent by 2010 in the Current Policy Direction case, virtually all of which occurs

between 2005 and 2010.59 Natural gas generation is

projected to address most of the shortfall in coal-fired

generation in all four studies. Renewable generation is

projected to increase in all the studies except EPA’s, and

nuclear generation is projected to increase above reference levels in the EIA and EPRI studies.

Electricity demand is projected to be reduced in three of

the studies, by about 8 percent in EIA’s most stringent

case, by about 7 percent in EPRI’s Current Policy Direction case, and by about 2 percent in the ELI study. EPA’s

study does not model an endogenous demand response.

Projected electricity prices are much higher in both the

EIA and EPRI analyses, and a more moderate price

increase is projected in the ELI study. EIA projects an

electricity price of 8.4 cents per kilowatthour in 2010 in

the integrated 1990-7% 2005 case, an increase of about 42

percent from the reference case projection. EPRI’s Current Policy Direction case projects an average electricity

price of 8.4 cents per kilowatthour in 2010, about a

37-percent increase over the reference level. In contrast,

ELI projects a smaller increase of about 11 percent, to 6.8

cents per kilowatthour, an increase that only partially

reflects the full cost of the coal phaseout, due to assumed

efficiency gains from industry restructuring. Electricity

prices are not reported in the EPA study.

In summary, although the four studies discussed in this

chapter examine the impacts of efforts to reduce power

sector emissions, they assume different emission targets

and use different analysis approaches. As a result, it is

difficult to compare the specific results of the studies.

The general results are similar, however. All the studies

find that efforts to reduce power plant emissions, particularly CO2, would be expected to lead to a shift from

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 71

58Although it is not an integrated emission reduction scenario, ELI’s cap on coal-fired generation results in significant reductions in projected CO2 emissions, from 671 million metric tons carbon equivalent to 499 in 2010.

59ELI imposed a 50-percent reduction on coal-fired generation as the constraint.
72 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table 23. Key Projections for Integrated Emission Reduction Cases in Four Multi-Emission Reduction

Studies, 2005 and 2010

Projection

EIA EPA

Reference

Integrated

1990-7%

2005

Integrated

1990-7%

2008 Reference

50% SO2

and CO2 567

MMT

50% SO2

and CO2 515

MMTa

2005 Projections

CO2 Emissions

(Million Metric Tons Carbon Equivalent) . . . . . . . . . . . . . . . . 637 473 536 605 602 593

Carbon Allowance Fee

(1999 Dollars per Metric Ton Carbon Equivalent) . . . . . . . . . 0 113 71 NA NA NA

NOx Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 110 196 60 199 196 194

SO2 Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 10 12 4 44 38

Coal-Fired Capacity (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . 302 299 300 304 303 301

Electricity Generation by Fuel (Billion Kilowatthours)

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,156 1,347 1,695 2,084 2,051 2,038

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 813 1,367 1,098 561 586 526

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 740 740 740 609 609 609

Renewablesb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 166 174 61 61 61

Natural Gas Wellhead Price (1999 Dollars per Million Btu). . 2.49 3.46 2.85 NA NA NA

Coal Minemouth Price (1999 Dollars per Ton) . . . . . . . . . . . 14.76 13.07 13.70 NA NA NA

Electricity Demand (Billion Kilowatthours) . . . . . . . . . . . . . . . 3,762 3,564 3,648 3,612 3,612 3,539

Electricity Price (1999 Cents per Kilowatthour) . . . . . . . . . . . 6.2 8.1 7.2 NA NA NA

SO2 Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 10.4 4.9 8.2 11.0 7.0 7.3

NOx Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 4.22 1.46 2.74 4.22 4.19 4.17

2010 Projections

CO2 Emissions

(Million Metric Tons Carbon Equivalent) . . . . . . . . . . . . . . . . 686 443 430 621 567 515

Carbon Allowance Fee

(1999 Dollars per Metric Ton Carbon Equivalent) . . . . . . . . . 0 134 126 NA NA NA

NOx Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 115 197 146 209 200 190

SO2 Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 10 12 6 63 45

Coal-Fired Capacity (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . 317 260 265 303 294 279

Electricity Generation by Fuel (Billion Kilowatthours)

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,284 1,135 1,067 2,114 1,812 1,653

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,123 1,839 1,935 759 1,054 972

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 720 741 741 580 580 580

Renewablesb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125 253 254 61 61 61

Natural Gas Wellhead Price (1999 Dollars per Million Btu). . 2.68 4.33 4.16 NA NA NA

Coal Minemouth Price (1999 Dollars per Ton) . . . . . . . . . . . 13.69 11.82 12.03 NA NA NA

Electricity Demand (Billion Kilowatthours) . . . . . . . . . . . . . . . 4,146 3,832 3,868 3,809 3,809 3,568

Electricity Price (1999 Cents per Kilowatthour) . . . . . . . . . . . 5.9 8.4 8.2 NA NA NA

SO2 Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 9.7 3.9 4.0 9.7 4.6 4.5

NOx Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 4.20 1.30 1.32 4.15 3.52 3.15

a

Includes high efficiency assumptions.

b

Excludes hydroelectric generation.

NA = not available.

Note: See Table 22 for EPA and EPRI reference case results.

Case constraints: EIA: CO2 reductions to 1990 levels met in either 2005 or 2008, with CO2 7% below 1990 level by 2010, NOx 75% below 1997,

and SO2 75% below 1997. EPA: carbon emissions capped at 567 MMT by 2008, and SO2 emissions capped at 50% of CAAA by 2010; and carbon

emissions capped at 515 MMT in 2008, and SO2 emissions capped at 50% of CAAA and electricity demand reduced gradually beginning in 2001.

Retrofits include units with both NOx and SO2 reduction technology. EPRI: Current Policy Direction—50% SO2 reduction by 2007, CO2 capped at 9%

above 1990 in 2005-2008, constant thereafter; Carbon Glide—SO2 emissions capped at 8.95 million metric tons carbon equivalent, CO2 restrictions

imposed in 2005, gradually increasing to 2030, so that cumulative CO2 emissions by 2050 equal those obtained in Current Policy Direction case. ELI:

coal-fired generation reduced by 25% from baseline (1998) levels by 2005, and by 50% from baseline by 2010.

Sources: EIA: National Energy Modeling System, runs MCBASE.D121300A, FDP7B05.D121300B, and FDP7B08.D121500A. EPA: U.S. Environmental Protection Agency, Analysis of Emissions Reduction Options for the Electric Power Industry (Washington, DC, March 1999), runs

HGIPM18B and HGIPM11C. EPRI: Electric Power Research Institute, Energy-Environment Policy Integration and Coordination Study: Executive

Report (Washington, DC, April 2000), runs Current Policy Direction and Carbon Glidepath. ELI: Environmental Law Institute, Cleaner Power: The

Benefits and Costs of Moving from Coal to Natural Gas Power Generation (Washington, DC, November 2000), runs “Business as Usual” and “Coal

Reduction.”
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 73

Table 23. Key Projections for Integrated Emission Reduction Cases in Four Multi-Emission Reduction

Studies, 2005 and 2010 (Continued)

Projection

EPRI ELI

Business

As Usual

Current Policy

Direction Carbon Glide

Business

As Usual

50% Coal

Reduction

2005 Projections

CO2 Emissions

(Million Metric Tons Carbon Equivalent) . . . . . . . . . . . . . . . . 620 588 581 652 558

Carbon Allowance Fee

(1999 Dollars per Metric Ton Carbon Equivalent) . . . . . . . . . 0 12 25 NA NA

NOx Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 179 133 149 NA NA

SO2 Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 0 0 NA NA

Coal-Fired Capacity (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . 303 286 290 319 308

Electricity Generation by Fuel (Billion Kilowatthours)

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,052 1,874 1,854 1,770 1,327

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 838 985 971 1,056 1,288

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 627 661 661 670 673

Renewablesb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 64 63 35 63

Natural Gas Wellhead Price (1999 Dollars per Million Btu). . 2.41 2.51 2.48 NA NA

Coal Minemouth Price (1999 Dollars per Ton) . . . . . . . . . . . 15.39 15.12 15.24 NA NA

Electricity Demand (Billion Kilowatthours) . . . . . . . . . . . . . . . 3,578 3,577 3,541 3,863 3,690

Electricity Price (1999 Cents per Kilowatthour) . . . . . . . . . . . 6.5 6.6 6.9 6.5 6.8

SO2 Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 10.5 10.4 10.2 10.1 7.7

NOx Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 3.99 3.92 3.85 5.52 4.43

2010 Projections

CO2 Emissions

(Million Metric Tons Carbon Equivalent) . . . . . . . . . . . . . . . . 657 399 482 671 499

Carbon Allowance Fee

(1999 Dollars per Metric Ton Carbon Equivalent) . . . . . . . . . 0 116 56 NA NA

NOx Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 185 133 149 NA NA

SO2 Retrofits (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 0 0 NA NA

Coal-Fired Capacity (Gigawatts) . . . . . . . . . . . . . . . . . . . . . . 305 269 276 321 293

Electricity Generation by Fuel (Billion Kilowatthours)

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,096 854 1,251 1,805 889

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,175 1,943 1,690 1,267 2,061

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 551 623 623 683 685

Renewablesb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 157 208 39 92

Natural Gas Wellhead Price (1999 Dollars per Million Btu). . 2.61 3.30 2.93 3.37 4.09

Coal Minemouth Price (1999 Dollars per Ton) . . . . . . . . . . . 14.47 16.13 15.43 NA NA

Electricity Demand (Billion Kilowatthours) . . . . . . . . . . . . . . . 3,859 3,587 3,732 4,121 4,051

Electricity Price (1999 Cents per Kilowatthour) . . . . . . . . . . . 6.1 8.4 7.2 6.1 6.8

SO2 Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 9.2 4.5 4.4 9.0 4.4

NOx Emissions (Million Tons) . . . . . . . . . . . . . . . . . . . . . . . . 9.23 2.26 2.86 5.52 3.30
coal-fired generation to natural-gas-fired generation. In

addition, they find that efforts to reduce CO2 emissions

would have the largest impacts, reducing the need to

invest in equipment to mitigate NOx and SO2 emissions

and making it easier, or less costly, to meet SO2 and

NOx constraints. Generally, the studies estimate that

compliance costs would vary directly with the stringency of the emission targets. Finally, the studies are in

agreement that meeting combined constraints would

ultimately cost less than meeting a series of individual

constraints.

74 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
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76 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants
Appendix A

Tables for NOx Cap Cases

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 79

Table A1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Production

 Crude Oil and Lease Condensate .... 12.45 11.85 11.85 11.85 10.90 10.89 10.89 10.61 10.65 10.65 

 Natural Gas Plant Liquids .......... 2.62 3.02 3.00 3.01 3.31 3.34 3.34 4.07 4.08 4.09 

 Dry Natural Gas .................. 19.16 21.26 21.15 21.22 23.63 23.81 23.82 29.59 29.65 29.71 

 Coal ........................... 23.12 25.43 25.29 25.22 26.47 25.95 25.98 27.21 26.89 26.83 

 Nuclear Power ................... 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.17 6.17 

 Renewable Energy1 ............... 6.50 6.98 6.99 7.00 7.65 7.62 7.63 8.20 8.17 8.18 

 Other2 ......................... 1.65 0.57 0.59 0.57 0.33 0.42 0.30 0.33 0.33 0.33 

 Total ........................ 73.30 77.01 76.78 76.77 79.98 79.72 79.65 86.18 85.93 85.95 

 Imports 

 Crude Oil3 ...................... 18.96 23.21 23.16 23.19 25.22 25.14 25.13 26.48 26.46 26.46 

 Petroleum Products4 .............. 4.14 4.85 4.85 4.84 6.46 6.44 6.51 10.77 10.74 10.71 

 Natural Gas ..................... 3.63 4.90 4.93 4.94 5.49 5.58 5.58 6.60 6.68 6.68 

 Other Imports5 ................... 0.64 1.11 1.11 1.11 0.96 0.96 0.96 0.96 0.96 0.96 

 Total ........................ 27.37 34.08 34.06 34.09 38.12 38.11 38.18 44.82 44.84 44.80 

 Exports

 Petroleum6 ...................... 1.98 1.81 1.81 1.81 1.79 1.78 1.78 1.90 1.91 1.90 

 Natural Gas ..................... 0.17 0.33 0.33 0.33 0.43 0.43 0.43 0.63 0.63 0.63 

 Coal ........................... 1.48 1.51 1.51 1.51 1.45 1.45 1.45 1.41 1.41 1.41 

 Total ........................ 3.62 3.64 3.64 3.64 3.67 3.66 3.66 3.94 3.95 3.94 

 Discrepancy7 ..................... 0.95 0.39 0.38 0.39 0.21 0.22 0.19 -0.03 -0.03 -0.02 

 Consumption

 Petroleum Products8 .............. 38.07 41.40 41.34 41.37 44.43 44.42 44.42 50.60 50.60 50.58 

 Natural Gas ..................... 21.90 25.78 25.72 25.77 28.52 28.78 28.80 35.40 35.52 35.60 

 Coal ........................... 21.46 24.37 24.24 24.16 25.54 25.06 25.05 26.48 26.14 26.06 

 Nuclear Power .................. . 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.17 6.17 

 Renewable Energy1 ............... 6.51 6.98 7.00 7.01 7.66 7.62 7.64 8.21 8.17 8.18 

 Other9 ......................... 0.35 0.61 0.61 0.61 0.38 0.38 0.38 0.25 0.25 0.25 

 Total ......................... 96.09 107.05 106.82 106.83 114.21 113.96 113.97 127.10 126.86 126.84 

 Net Imports - Petroleum ............ 21.12 26.26 26.20 26.23 29.88 29.80 29.86 35.36 35.30 35.27 

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 ... 17.35 20.83 20.83 20.83 21.37 21.37 21.37 22.41 22.41 22.41 

 Gas Wellhead Price (dollars per Mcf)11 2.08 2.49 2.47 2.49 2.68 2.68 2.72 3.14 3.18 3.15 

 Coal Minemouth Price (dollars per ton) 17.23 14.76 14.88 14.82 13.69 13.99 13.94 12.84 12.94 12.95 

 Average Electric Price (cents per Kwh) 6.6 6.2 6.2 6.2 5.9 5.9 5.9 6.0 6.0 6.0 

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
80 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

Energy Consumption

 Residential

 Distillate Fuel ........................ 0.86 0.88 0.88 0.88 0.81 0.81 0.81 0.75 0.75 0.75

 Kerosene ........................... 0.10 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas ............... 0.46 0.45 0.45 0.45 0.41 0.41 0.41 0.39 0.40 0.39

 Petroleum Subtotal .................. 1.42 1.42 1.42 1.42 1.29 1.29 1.29 1.21 1.21 1.21

 Natural Gas ......................... 4.85 5.46 5.47 5.46 5.69 5.70 5.69 6.30 6.30 6.30

 Coal ............................... 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

 Renewable Energy1 ................... 0.41 0.43 0.43 0.43 0.43 0.43 0.43 0.44 0.44 0.44

 Electricity ........................... 3.91 4.50 4.49 4.49 4.96 4.94 4.95 5.80 5.78 5.79

 Delivered Energy ................... 10.62 11.86 11.86 11.85 12.42 12.41 12.41 13.80 13.78 13.79

 Electricity Related Losses .............. 8.46 9.46 9.38 9.38 9.88 9.80 9.81 10.58 10.51 10.50

 Total ............................. 19.08 21.32 21.24 21.24 22.30 22.21 22.22 24.38 24.29 24.29

 Commercial

 Distillate Fuel ........................ 0.36 0.41 0.41 0.41 0.41 0.41 0.41 0.39 0.39 0.39

 Residual Fuel ........................ 0.10 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.11

 Kerosene ........................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas ............... 0.08 0.09 0.09 0.09 0.09 0.09 0.09 0.10 0.10 0.10

 Motor Gasoline2 ...................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal .................. 0.59 0.66 0.66 0.66 0.67 0.67 0.67 0.66 0.66 0.66

 Natural Gas ......................... 3.15 3.71 3.72 3.72 3.89 3.88 3.88 4.12 4.12 4.12

 Coal ............................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.08

 Renewable Energy3 ................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Electricity ........................... 3.70 4.35 4.34 4.34 4.89 4.87 4.88 5.61 5.60 5.60

 Delivered Energy ................... 7.59 8.87 8.87 8.87 9.60 9.58 9.58 10.55 10.53 10.54

 Electricity Related Losses .............. 8.00 9.15 9.08 9.08 9.74 9.67 9.68 10.23 10.17 10.15

 Total ............................. 15.59 18.02 17.95 17.95 19.34 19.25 19.25 20.79 20.70 20.69

 Industrial4

 Distillate Fuel ........................ 1.07 1.13 1.13 1.13 1.27 1.27 1.27 1.44 1.45 1.44

 Liquefied Petroleum Gas ............... 2.32 2.45 2.45 2.45 2.50 2.50 2.50 2.83 2.84 2.83

 Petrochemical Feedstock .............. 1.29 1.42 1.42 1.42 1.53 1.53 1.53 1.70 1.70 1.70

 Residual Fuel ........................ 0.22 0.22 0.22 0.22 0.25 0.25 0.25 0.27 0.27 0.27

 Motor Gasoline2 ...................... 0.21 0.23 0.23 0.23 0.25 0.25 0.25 0.28 0.28 0.28

 Other Petroleum5 ..................... 4.29 4.49 4.47 4.49 4.76 4.76 4.75 5.25 5.25 5.24

 Petroleum Subtotal .................. 9.39 9.95 9.92 9.94 10.55 10.55 10.55 11.78 11.79 11.77

 Natural Gas6 ........................ 9.43 10.42 10.45 10.43 11.11 11.13 11.12 12.33 12.34 12.35

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 1.73 1.82 1.82 1.82 1.85 1.85 1.86 1.89 1.90 1.90

 Net Coal Coke Imports ................ 0.06 0.12 0.12 0.12 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 2.54 2.62 2.63 2.63 2.61 2.62 2.62 2.62 2.62 2.62

 Renewable Energy7 ................... 2.15 2.42 2.42 2.42 2.64 2.64 2.64 3.08 3.08 3.08

 Electricity ........................... 3.63 3.90 3.90 3.90 4.19 4.17 4.18 4.81 4.80 4.80

 Delivered Energy ................... 27.15 29.32 29.31 29.32 31.10 31.11 31.11 34.62 34.63 34.63

 Electricity Related Losses .............. 7.85 8.22 8.15 8.15 8.34 8.27 8.29 8.78 8.72 8.71

 Total ............................. 35.00 37.53 37.46 37.47 39.45 39.38 39.39 43.40 43.35 43.33
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 81

Table A2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Transportation

 Distillate Fuel ........................ 5.13 6.28 6.27 6.27 6.99 6.98 6.99 8.21 8.20 8.20

 Jet Fuel8 ............................ 3.46 3.90 3.90 3.90 4.51 4.51 4.51 5.97 5.97 5.97

 Motor Gasoline2 ...................... 15.92 17.70 17.70 17.70 19.05 19.04 19.04 21.32 21.32 21.32

 Residual Fuel ........................ 0.74 0.85 0.85 0.85 0.85 0.85 0.85 0.87 0.87 0.87

 Liquefied Petroleum Gas ............... 0.02 0.03 0.03 0.03 0.04 0.04 0.04 0.06 0.06 0.06

 Other Petroleum9 ..................... 0.26 0.29 0.29 0.29 0.31 0.31 0.31 0.35 0.35 0.35

 Petroleum Subtotal .................. 25.54 29.06 29.06 29.05 31.75 31.74 31.73 36.77 36.76 36.76

 Pipeline Fuel Natural Gas .............. 0.66 0.77 0.76 0.77 0.89 0.89 0.90 1.08 1.08 1.09

 Compressed Natural Gas .............. 0.02 0.06 0.06 0.06 0.09 0.09 0.09 0.16 0.16 0.16

 Renewable Energy (E85)10 ............. 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 0.06 0.09 0.09 0.09 0.12 0.12 0.12 0.17 0.17 0.17

 Delivered Energy ................... 26.28 29.99 29.99 29.99 32.89 32.88 32.88 38.23 38.22 38.22

 Electricity Related Losses .............. 0.13 0.19 0.18 0.18 0.24 0.23 0.23 0.30 0.30 0.30

 Total ............................. 26.41 30.18 30.17 30.18 33.12 33.12 33.11 38.53 38.52 38.52

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ........................ 7.42 8.70 8.70 8.70 9.47 9.46 9.47 10.80 10.79 10.79

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ............................ 3.46 3.90 3.90 3.90 4.51 4.51 4.51 5.97 5.97 5.97

 Liquefied Petroleum Gas ............... 2.88 3.03 3.03 3.03 3.05 3.05 3.05 3.38 3.39 3.38

 Motor Gasoline2 ...................... 16.17 17.96 17.96 17.96 19.32 19.32 19.31 21.63 21.63 21.62

 Petrochemical Feedstock .............. 1.29 1.42 1.42 1.42 1.53 1.53 1.53 1.70 1.70 1.70

 Residual Fuel ........................ 1.05 1.17 1.17 1.17 1.21 1.21 1.21 1.25 1.25 1.25

 Other Petroleum12 .................... 4.53 4.76 4.74 4.76 5.04 5.04 5.04 5.58 5.58 5.57

 Petroleum Subtotal .................. 36.95 41.08 41.05 41.08 44.26 44.25 44.24 50.42 50.42 50.40

 Natural Gas6 ........................ 18.11 20.42 20.46 20.43 21.67 21.70 21.67 24.00 24.00 24.02

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 1.84 1.94 1.94 1.94 1.98 1.98 1.98 2.02 2.02 2.02

 Net Coal Coke Imports ................ 0.06 0.12 0.12 0.12 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 2.65 2.74 2.74 2.74 2.74 2.74 2.74 2.74 2.75 2.75

 Renewable Energy13 .................. 2.65 2.95 2.95 2.95 3.19 3.19 3.19 3.65 3.65 3.65

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 11.29 12.84 12.82 12.82 14.15 14.10 14.12 16.39 16.34 16.35

 Delivered Energy ................... 71.65 80.04 80.03 80.03 86.01 85.98 85.97 97.20 97.17 97.18

 Electricity Related Losses .............. 24.44 27.02 26.79 26.79 28.20 27.97 28.01 29.89 29.69 29.66

 Total ............................. 96.09 107.05 106.82 106.83 114.21 113.96 113.97 127.10 126.86 126.84

 Electric Generators14

 Distillate Fuel ........................ 0.06 0.05 0.05 0.05 0.04 0.04 0.04 0.04 0.04 0.04

 Residual Fuel ........................ 1.07 0.27 0.24 0.25 0.13 0.13 0.14 0.14 0.14 0.14

 Petroleum Subtotal .................. 1.13 0.32 0.29 0.29 0.17 0.17 0.18 0.19 0.18 0.18

 Natural Gas ......................... 3.79 5.36 5.27 5.34 6.84 7.09 7.13 11.40 11.52 11.57

 Steam Coal ......................... 18.81 21.63 21.49 21.42 22.80 22.32 22.31 23.73 23.40 23.32

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.17 6.17

 Renewable Energy15 .................. 3.86 4.03 4.05 4.05 4.47 4.44 4.45 4.56 4.52 4.53

 Electricity Imports16 ................... 0.35 0.61 0.61 0.61 0.37 0.37 0.37 0.24 0.24 0.24

 Total ............................. 35.73 39.85 39.61 39.62 42.35 42.08 42.13 46.28 46.03 46.01
82 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Total Energy Consumption

 Distillate Fuel ........................ 7.48 8.75 8.74 8.74 9.51 9.50 9.51 10.84 10.84 10.84

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ............................ 3.46 3.90 3.90 3.90 4.51 4.51 4.51 5.97 5.97 5.97

 Liquefied Petroleum Gas ............... 2.88 3.03 3.03 3.03 3.05 3.05 3.05 3.38 3.39 3.38

 Motor Gasoline2 ...................... 16.17 17.96 17.96 17.96 19.32 19.32 19.31 21.63 21.63 21.62

 Petrochemical Feedstock .............. 1.29 1.42 1.42 1.42 1.53 1.53 1.53 1.70 1.70 1.70

 Residual Fuel ........................ 2.12 1.44 1.42 1.42 1.34 1.34 1.34 1.39 1.38 1.38

 Other Petroleum12 .................... 4.53 4.76 4.74 4.76 5.04 5.04 5.04 5.58 5.58 5.57

 Petroleum Subtotal .................. 38.07 41.40 41.34 41.37 44.43 44.42 44.42 50.60 50.60 50.58

 Natural Gas ......................... 21.90 25.78 25.72 25.77 28.52 28.78 28.80 35.40 35.52 35.60

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 20.65 23.57 23.43 23.36 24.77 24.30 24.29 25.75 25.42 25.34

 Net Coal Coke Imports ................ 0.06 0.12 0.12 0.12 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 21.46 24.37 24.24 24.16 25.54 25.06 25.05 26.48 26.14 26.06

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.17 6.17

 Renewable Energy17 .................. 6.51 6.98 7.00 7.01 7.66 7.62 7.64 8.21 8.18 8.19

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 ................... 0.35 0.61 0.61 0.61 0.37 0.37 0.37 0.24 0.24 0.24

 Total ............................. 96.09 107.05 106.82 106.83 114.21 113.96 113.97 127.10 126.86 126.84

Energy Use and Related Statistics

 Delivered Energy Use ................... 71.65 80.04 80.03 80.03 86.01 85.98 85.97 97.20 97.17 97.18

 Total Energy Use ..................... 96.09 107.05 106.82 106.83 114.21 113.96 113.97 127.10 126.86 126.84

 Population (millions) .................... 273.13 288.02 288.02 288.02 300.17 300.17 300.17 325.24 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 10960 10960 10960 12667 12667 12667 16515 16515 16515

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) ... 1510.8 1694.3 1689.0 1688.1 1816.2 1807.3 1807.3 2045.4 2038.7 2037.2

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which produces electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

MCNOX05.D121300A, and MCNOX08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 83

Table A3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Residential ........................ 13.12 12.91 12.92 12.93 13.15 13.22 13.25 13.59 13.65 13.63

 Primary Energy1 .................... 6.72 7.12 7.10 7.11 7.00 6.99 7.05 7.02 7.06 7.04

 Petroleum Products2 ............... 7.55 9.18 9.18 9.18 9.37 9.23 9.38 9.66 9.65 9.65

 Distillate Fuel .................... 6.27 7.34 7.34 7.33 7.51 7.48 7.51 7.99 7.99 7.98

 Liquefied Petroleum Gas ........... 10.36 12.83 12.82 12.82 13.06 12.68 13.08 12.90 12.88 12.90

 Natural Gas ...................... 6.52 6.63 6.61 6.62 6.52 6.53 6.57 6.56 6.60 6.58

 Electricity ......................... 23.46 21.84 21.93 21.93 21.88 22.10 22.08 22.16 22.28 22.25

 Commercial ....................... 13.20 12.36 12.40 12.41 11.74 11.82 11.87 12.37 12.46 12.43

 Primary Energy1 .................... 5.22 5.35 5.34 5.35 5.53 5.52 5.56 5.76 5.79 5.77

 Petroleum Products2 ............... 5.00 6.01 6.01 6.01 6.17 6.10 6.17 6.52 6.50 6.50

 Distillate Fuel .................... 4.37 5.13 5.13 5.12 5.28 5.26 5.28 5.77 5.75 5.75

 Residual Fuel .................... 2.63 3.64 3.64 3.64 3.69 3.69 3.69 3.85 3.85 3.85

 Natural Gas3 ..................... 5.34 5.31 5.29 5.30 5.49 5.50 5.54 5.72 5.76 5.73

 Electricity ......................... 21.43 19.51 19.63 19.63 17.61 17.80 17.84 18.09 18.24 18.22

 Industrial4 ......................... 5.32 5.49 5.48 5.49 5.44 5.39 5.48 5.85 5.88 5.87

 Primary Energy .................... 3.92 4.25 4.23 4.24 4.37 4.30 4.39 4.73 4.74 4.73

 Petroleum Products2 ............... 5.55 5.95 5.94 5.94 6.05 5.89 6.06 6.28 6.27 6.28

 Distillate Fuel .................... 4.65 5.29 5.29 5.29 5.46 5.43 5.46 5.98 5.95 5.95

 Liquefied Petroleum Gas ........... 8.50 7.94 7.93 7.93 8.00 7.59 8.01 7.86 7.84 7.86

 Residual Fuel .................... 2.78 3.37 3.36 3.36 3.42 3.42 3.42 3.58 3.58 3.58

 Natural Gas5 ..................... 2.79 3.17 3.15 3.16 3.30 3.29 3.33 3.77 3.81 3.79

 Metallurgical Coal ................. 1.65 1.58 1.58 1.58 1.54 1.54 1.55 1.44 1.44 1.44

 Steam Coal ...................... 1.43 1.34 1.34 1.34 1.29 1.30 1.30 1.21 1.21 1.21

 Electricity ......................... 13.01 12.30 12.34 12.35 11.21 11.33 11.40 11.60 11.72 11.71

 Transportation ..................... 8.30 9.27 9.26 9.26 9.45 9.45 9.47 9.32 9.31 9.32

 Primary Energy .................... 8.29 9.25 9.25 9.24 9.44 9.44 9.46 9.30 9.29 9.30

 Petroleum Products2 ............... 8.28 9.25 9.24 9.24 9.44 9.44 9.45 9.30 9.29 9.29

 Distillate Fuel6 ................... 8.22 8.89 8.89 8.88 8.94 8.94 8.94 9.02 8.98 8.99

 Jet Fuel7 ........................ 4.70 5.24 5.25 5.23 5.46 5.46 5.47 5.88 5.88 5.88

 Motor Gasoline8 .................. 9.45 10.64 10.63 10.63 10.92 10.93 10.95 10.68 10.68 10.68

 Residual Fuel .................... 2.46 3.10 3.10 3.10 3.18 3.18 3.18 3.33 3.33 3.33

 Liquid Petroleum Gas9 ............. 12.87 14.19 14.17 14.18 14.24 13.92 14.29 13.88 13.86 13.88

 Natural Gas10 ..................... 7.02 6.80 6.77 6.79 7.03 7.05 7.08 7.33 7.37 7.34

 Ethanol (E85)11 ................... 14.42 19.12 19.08 19.07 19.00 19.00 19.01 19.36 19.37 19.36

 Methanol (M85)12 .................. 10.38 13.11 12.99 13.12 13.74 13.73 13.74 14.43 14.43 14.43

 Electricity ......................... 15.58 14.29 14.34 14.24 13.53 13.70 13.56 13.03 13.17 13.12

 Average End-Use Energy ............ 8.53 8.90 8.91 8.91 8.94 8.94 8.99 9.17 9.20 9.19

 Primary Energy .................... 6.33 7.00 6.99 6.99 7.18 7.15 7.20 7.31 7.32 7.32

 Electricity ......................... 19.40 18.10 18.18 18.19 17.18 17.36 17.38 17.57 17.70 17.68

 Electric Generators13

 Fossil Fuel Average ................. 1.49 1.50 1.49 1.50 1.52 1.55 1.56 1.85 1.89 1.88

 Petroleum Products ................ 2.50 3.70 3.68 3.68 4.06 4.07 4.07 4.33 4.35 4.35

 Distillate Fuel .................... 4.04 4.65 4.64 4.64 4.85 4.81 4.83 5.30 5.28 5.28

 Residual Fuel .................... 2.41 3.52 3.49 3.50 3.85 3.84 3.84 4.04 4.06 4.06

 Natural Gas ...................... 2.54 2.89 2.84 2.85 3.02 3.01 3.05 3.61 3.67 3.65

 Steam Coal ...................... 1.22 1.13 1.13 1.13 1.05 1.06 1.06 0.98 0.99 0.99
84 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Average Price to All Users14

 Petroleum Products2 ................ 7.43 8.43 8.43 8.43 8.63 8.59 8.64 8.62 8.61 8.62

 Distillate Fuel ..................... 7.27 8.07 8.07 8.06 8.18 8.17 8.18 8.41 8.38 8.38

 Jet Fuel ......................... 4.70 5.24 5.25 5.23 5.46 5.46 5.47 5.88 5.88 5.88

 Liquefied Petroleum Gas ............ 8.84 8.83 8.83 8.83 8.87 8.47 8.89 8.64 8.63 8.65

 Motor Gasoline8 ................... 9.45 10.64 10.63 10.63 10.92 10.92 10.95 10.68 10.68 10.68

 Residual Fuel ..................... 2.48 3.26 3.25 3.25 3.33 3.33 3.33 3.49 3.49 3.49

 Natural Gas ...................... 4.05 4.25 4.23 4.24 4.27 4.25 4.29 4.52 4.56 4.54

 Coal ............................. 1.24 1.15 1.15 1.15 1.07 1.08 1.08 1.00 1.01 1.01

 Ethanol (E85)11 .................... 14.42 19.12 19.08 19.07 19.00 19.00 19.01 19.36 19.37 19.36

 Methanol (M85)12 ................... 10.38 13.11 12.99 13.12 13.74 13.73 13.74 14.43 14.43 14.43

 Electricity ......................... 19.40 18.10 18.18 18.19 17.18 17.36 17.38 17.57 17.70 17.68

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential .......................... 134.05 147.53 147.68 147.78 157.75 158.34 158.75 181.60 182.19 182.01

 Commercial ......................... 99.10 108.63 108.98 109.04 111.63 112.29 112.70 129.48 130.17 130.02

 Industrial ........................... 110.62 121.27 121.17 121.31 126.35 125.43 127.42 151.05 151.78 151.62

 Transportation ....................... 212.64 270.40 270.29 270.19 301.90 301.82 302.30 345.30 344.98 345.09

 Total Non-Renewable Expenditures ..... 556.41 647.83 648.12 648.32 697.64 697.88 701.16 807.43 809.13 808.73

 Transportation Renewable Expenditures . 0.14 0.42 0.42 0.42 0.61 0.61 0.62 0.86 0.86 0.86

 Total Expenditures ................. 556.55 648.25 648.54 648.74 698.25 698.49 701.78 808.29 809.99 809.59

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report,

DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MCBASE.D082400A, MCNOX05.D082400A, and

MCNOX08.D082500A. 1999 electricity prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D082400A,

MCNOX05.D082400A, and MCNOX08.D082500A, Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and

MCNOX08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 85

Table A4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

Generation by Fuel Type

 Electric Generators1

 Coal ............................ 1835 2103 2094 2087 2232 2185 2185 2317 2283 2276

 Petroleum ....................... 104 32 29 30 18 18 18 19 19 19

 Natural Gas2 ..................... 365 574 580 588 867 903 906 1568 1590 1598

 Nuclear Power .................... 730 740 740 740 720 720 720 577 577 577

 Pumped Storage .................. -1 -1 -1 -1 -1 -1 -1 -1 -1 -1

 Renewable Sources3 ............... 353 362 363 363 384 383 384 390 389 389

 Total .......................... 3386 3811 3805 3806 4220 4208 4212 4872 4857 4859

 Non-Utility Generation for Own Use ... 16 16 16 16 16 16 16 16 16 16

 Distributed Generation .............. 0111333666

 Cogenerators4

 Coal ........................... 47 52 53 52 52 52 52 52 52 52

 Petroleum ...................... 9 10 10 10 10 10 10 10 10 10

 Natural Gas ..................... 206 239 240 240 256 259 258 298 304 304

 Other Gaseous Fuels5 ............. 4666777888

 Renewable Sources3 .............. 31 34 34 34 39 39 39 48 48 48

 Other6 ......................... 5555555555

 Total ......................... 302 347 347 348 369 372 372 421 428 427

 Other End-Use Generators7 ........ 5555555555

 Sales to Utilities .................. 150 171 171 171 176 176 176 200 201 201

 Generation for Own Use ........... 156 180 182 181 198 200 200 226 231 231

 Net Imports8 ...................... 33 57 57 57 35 35 35 23 23 23

Electricity Sales by Sector

 Residential ........................ 1146 1317 1316 1316 1452 1448 1450 1699 1695 1696

 Commercial ....................... 1083 1275 1273 1273 1432 1429 1430 1644 1640 1641

 Industrial ......................... 1063 1144 1142 1143 1227 1223 1224 1411 1406 1407

 Transportation ..................... 17 26 26 26 35 35 35 49 49 49

 Total ........................... 3309 3762 3757 3758 4146 4134 4139 4803 4790 4793

End-Use Prices (1999 cents per kwh)9

 Residential ........................ 8.0 7.5 7.5 7.5 7.5 7.5 7.5 7.6 7.6 7.6

 Commercial ....................... 7.3 6.7 6.7 6.7 6.0 6.1 6.1 6.2 6.2 6.2

 Industrial ......................... 4.4 4.2 4.2 4.2 3.8 3.9 3.9 4.0 4.0 4.0

 Transportation ..................... 5.3 4.9 4.9 4.9 4.6 4.7 4.6 4.4 4.5 4.5

 All Sectors Average ............... 6.6 6.2 6.2 6.2 5.9 5.9 5.9 6.0 6.0 6.0

 Prices by Service Category 9

 (1999 cents per kwh)

 Generation ........................ 4.1 3.6 3.6 3.6 3.2 3.2 3.2 3.4 3.4 3.4

 Transmission ...................... 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.7 0.7 0.7

 Distribution ........................ 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide ..................... 13.82 10.39 10.39 10.39 9.70 9.70 9.70 8.95 8.95 8.95

 Nitrogen Oxide ..................... 5.46 4.22 1.55 3.10 4.20 1.55 1.55 4.37 1.60 1.59

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

 Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
86 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

Electric Generators2

 Capability

 Coal Steam .................. 306.2 302.4 302.1 301.8 317.4 311.7 311.7 317.8 312.3 312.2

 Other Fossil Steam3 ............ 138.2 129.6 125.4 125.4 121.1 118.3 117.9 117.2 115.1 114.7

 Combined Cycle .............. 20.2 49.4 56.5 56.2 124.0 129.6 128.6 230.0 234.9 235.3

 Combustion Turbine/Diesel ...... 75.6 129.7 128.4 128.5 162.1 159.1 160.7 207.7 209.6 209.2

 Nuclear Power ................ 97.4 97.5 97.5 97.5 94.2 94.2 94.2 71.6 71.6 71.6

 Pumped Storage .............. 19.3 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ........... 88.1 91.5 91.5 91.6 94.8 94.6 94.7 96.3 96.2 96.2

 Distributed Generation5 ......... 0.0 2.0 2.2 2.2 6.1 6.3 6.2 14.0 13.8 13.2

 Total ...................... 745.0 821.5 823.1 822.6 939.4 933.3 933.6 1074.3 1073.2 1072.2

 Cumulative Planned Additions6

 Coal Steam .................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Combined Cycle .............. 0.0 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ...... 0.0 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

 Nuclear Power ................ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage .............. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ........... 0.0 2.4 2.4 2.4 4.3 4.3 4.3 5.4 5.4 5.4

 Distributed Generation5 ......... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Total ...................... 0.0 11.5 11.5 11.5 13.6 13.6 13.6 14.8 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam .................. 0.0 2.5 2.9 3.0 20.1 13.9 14.3 21.5 15.6 15.9

 Other Fossil Steam3 ............ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Combined Cycle .............. 0.0 20.8 27.9 27.6 95.7 101.2 100.2 201.6 206.5 206.9

 Combustion Turbine/Diesel ..... . 0.0 57.0 56.4 56.5 90.8 88.8 90.4 137.2 140.3 140.1

 Nuclear Power ................ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage .............. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ........... 0.0 0.6 0.6 0.7 1.9 1.7 1.8 2.4 2.2 2.3

 Distributed Generation5 ......... 0.0 2.0 2.2 2.2 6.1 6.3 6.2 14.0 13.8 13.2

 Total ...................... 0.0 82.9 90.0 90.0 214.6 211.9 213.0 376.7 378.4 378.4

 Cumulative Total Additions ..... 0.0 94.5 101.6 101.6 228.1 225.4 226.5 391.4 393.2 393.2

 Cumulative Retirements7 .......

 Coal Steam .................. 0.0 6.6 7.3 7.7 9.2 9.2 9.6 10.2 10.4 10.7

 Other Fossil Steam ............ 0.0 8.5 12.7 12.7 17.0 19.8 20.2 20.9 23.0 23.4

 Combined Cycle .............. 0.0 0.0 0.0 0.0 0.3 0.3 0.3 0.3 0.3 0.3

 Combustion Turbine/Diesel ...... 0.0 3.8 4.0 4.0 5.1 5.8 5.7 5.9 6.7 6.8

 Nuclear Power ................ 0.0 0.0 0.0 0.0 3.3 3.3 3.3 25.9 25.9 25.9

 Pumped Storage .............. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ........... 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total ...................... 0.0 19.0 24.2 24.5 34.9 38.5 39.2 63.4 66.4 67.2

 Cogenerators8

 Capability

 Coal Steam .................. 8.4 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9

 Petroleum ................... 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 2.8

 Natural Gas .................. 33.8 40.0 40.1 40.1 42.9 43.2 43.2 48.8 49.7 49.7

 Other Gaseous Fuels .......... 0.2 0.8 0.8 0.8 0.9 0.9 0.9 1.0 1.0 1.0

 Renewable Sources4 ........... 5.3 5.9 5.9 5.9 6.8 6.8 6.8 8.2 8.2 8.2

 Other ....................... 1.1 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

 Total ...................... 51.6 59.2 59.3 59.3 63.1 63.4 63.4 70.7 71.6 71.6

 Cumulative Additions6 .......... 0.0 7.5 7.7 7.7 11.4 11.8 11.7 19.0 20.0 19.9
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 87

Table A5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

Other End-Use Generators9

 Renewable Sources ............ 1.0 1.1 1.1 1.1 1.3 1.3 1.3 1.3 1.3 1.3

 Cumulative Additions ........... 0.0 0.1 0.1 0.1 0.3 0.3 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8

Nameplate capacity is reported for nonutilities on Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
88 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade .......... 182.2 125.3 125.3 125.3 102.9 102.9 102.9 0.0 0.0 0.0

 Gross Domestic Economy Trade ............ 147.8 202.8 201.7 191.2 183.2 192.8 187.6 206.7 211.7 213.0

 Gross Domestic Trade ................. 330.0 328.1 327.0 316.5 286.1 295.7 290.5 206.7 211.7 213.0

 Gross Domestic Firm Power Sales

 (million 1999 dollars) .................... 8588.1 5905.8 5905.8 5905.8 4851.2 4851.2 4851.2 0.0 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) .................... 4292.5 6044.9 5822.4 5626.3 4987.6 5229.0 5222.0 6227.5 6404.0 6456.3

 Gross Domestic Sales

 (million 1999 dollars) .................. 12880.6 11950.7 11728.2 11532.1 9838.8 10080.3 10073.2 6227.5 6404.0 6456.3

 International Electricity Trade

 Firm Power Imports From Canada and Mexico1

 27.0 10.7 10.7 10.7 5.8 5.8 5.8 0.0 0.0 0.0

 Economy Imports From Canada and Mexico1 . . 21.9 63.5 63.5 63.5 45.9 45.9 45.9 30.6 30.6 30.6

 Gross Imports From Canada and Mexico1 . . 48.9 74.1 74.1 74.1 51.7 51.7 51.7 30.6 30.6 30.6

 Firm Power Exports To Canada and Mexico ... 9.2 9.7 9.7 9.7 8.7 8.7 8.7 0.0 0.0 0.0

 Economy Exports To Canada and Mexico .... 6.3 7.0 7.0 7.0 7.7 7.7 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico ..... 15.5 16.7 16.7 16.7 16.4 16.4 16.4 7.7 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 89

Table A7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Production

 Dry Gas Production1 ........ 18.67 20.72 20.61 20.68 23.03 23.21 23.21 28.84 28.90 28.96

 Supplemental Natural Gas2 ... 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Net Imports ................ 3.38 4.47 4.50 4.51 4.94 5.03 5.03 5.83 5.90 5.90

 Canada .................. 3.29 4.28 4.31 4.32 4.68 4.77 4.77 5.46 5.53 5.53

 Mexico ................... -0.01 -0.18 -0.18 -0.18 -0.25 -0.25 -0.25 -0.40 -0.40 -0.40

 Liquefied Natural Gas ....... 0.10 0.37 0.37 0.37 0.51 0.50 0.50 0.77 0.77 0.78

 Total Supply ............... 22.15 25.30 25.23 25.30 28.03 28.29 28.30 34.72 34.85 34.92

 Consumption by Sector

 Residential ................ 4.72 5.32 5.32 5.32 5.54 5.55 5.54 6.14 6.13 6.14

 Commercial ............... 3.07 3.62 3.62 3.62 3.78 3.78 3.77 4.02 4.01 4.02

 Industrial3 ................. 7.95 8.80 8.84 8.81 9.33 9.34 9.33 10.17 10.18 10.19

 Electric Generators4 ......... 3.72 5.26 5.17 5.24 6.72 6.96 6.99 11.19 11.31 11.36

 Lease and Plant Fuel5 ....... 1.23 1.35 1.34 1.34 1.49 1.50 1.50 1.83 1.84 1.84

 Pipeline Fuel .............. 0.64 0.75 0.74 0.75 0.87 0.87 0.87 1.06 1.06 1.06

 Transportation6 ............ 0.02 0.05 0.05 0.05 0.09 0.09 0.09 0.15 0.15 0.15

 Total ................... 21.35 25.14 25.09 25.14 27.82 28.08 28.10 34.55 34.68 34.75

 Discrepancy7 .............. 0.80 0.16 0.14 0.16 0.21 0.21 0.20 0.17 0.17 0.17

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A. Other 1999

consumption: EIA, Short-Term Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption

levels for consumption of natural gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A,

and MCNOX08.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
90 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Source Price 

 Average Lower 48 Wellhead Price1 .... 2.08 2.49 2.47 2.49 2.68 2.68 2.72 3.14 3.18 3.15

 Average Import Price ............... 2.29 2.48 2.48 2.48 2.41 2.41 2.42 2.67 2.72 2.72

 Average2 ....................... 2.11 2.49 2.47 2.48 2.63 2.63 2.66 3.05 3.09 3.07

 Delivered Prices

 Residential ....................... 6.69 6.81 6.79 6.80 6.70 6.70 6.74 6.74 6.78 6.75

 Commercial ...................... 5.49 5.45 5.43 5.44 5.64 5.65 5.68 5.87 5.91 5.89

 Industrial3 ........................ 2.87 3.26 3.23 3.25 3.39 3.38 3.42 3.87 3.92 3.89

 Electric Generators4 ................ 2.59 2.94 2.89 2.91 3.08 3.07 3.11 3.68 3.74 3.72

 Transportation5 ................... 7.21 6.99 6.96 6.97 7.22 7.24 7.27 7.53 7.57 7.54

 Average6 ....................... 4.16 4.36 4.34 4.35 4.38 4.37 4.40 4.64 4.68 4.66

 Transmission & Distribution Margins7

 Residential ....................... 4.58 4.32 4.31 4.31 4.07 4.08 4.08 3.69 3.69 3.68

 Commercial ...................... 3.37 2.96 2.96 2.96 3.01 3.02 3.02 2.82 2.82 2.82

 Industrial3 ........................ 0.75 0.76 0.76 0.76 0.76 0.76 0.76 0.82 0.82 0.82

 Electric Generators4 ................ 0.48 0.45 0.42 0.42 0.45 0.45 0.45 0.63 0.64 0.64

 Transportation5 ................... 5.10 4.49 4.48 4.49 4.59 4.61 4.61 4.48 4.47 4.47

 Average6 ....................... 2.05 1.87 1.86 1.86 1.75 1.74 1.74 1.59 1.59 1.59

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ....................... 21.61 22.96 22.95 22.95 22.55 22.62 22.59 22.62 22.60 22.59

 Commercial ...................... 10.36 10.71 10.71 10.71 11.40 11.42 11.40 11.32 11.31 11.31

 Industrial3 ........................ 6.00 6.72 6.71 6.71 7.10 7.06 7.09 8.34 8.37 8.34

 Electric Generators4 ................ 1.77 2.35 2.17 2.21 3.03 3.10 3.11 7.00 7.28 7.31

 Transportation5 ................... 0.08 0.24 0.24 0.24 0.42 0.42 0.42 0.69 0.69 0.69

 Total .......................... 39.82 42.98 42.78 42.83 44.49 44.62 44.61 49.97 50.25 50.24

 1Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 91

Table A9. Oil and Gas Supply

Production and Supply 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ..................... 16.49 20.42 20.42 20.42 20.81 20.81 20.80 21.46 21.45 21.46

Production (million barrels per day)

2

 U.S. Total .................................. 5.88 5.60 5.60 5.60 5.15 5.14 5.14 5.01 5.03 5.03

 Lower 48 Onshore ........................... 3.27 2.75 2.75 2.75 2.49 2.48 2.48 2.63 2.65 2.64

 Conventional .............................. 2.59 2.15 2.15 2.15 1.82 1.82 1.82 1.91 1.91 1.91

 Enhanced Oil Recovery ...................... 0.68 0.61 0.61 0.61 0.66 0.66 0.66 0.72 0.74 0.73

 Lower 48 Offshore ........................... 1.56 2.05 2.05 2.05 2.02 2.02 2.02 1.75 1.75 1.75

 Alaska .................................... 1.05 0.79 0.79 0.79 0.64 0.64 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 . . 18.33 15.46 15.47 15.47 14.03 14.00 14.00 13.43 13.50 13.49

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ......... 2.08 2.49 2.47 2.49 2.68 2.68 2.72 3.14 3.18 3.15

Production (trillion cubic feet)3

 U.S. Total .................................. 18.67 20.72 20.61 20.68 23.03 23.21 23.21 28.84 28.90 28.96

 Lower 48 Onshore ........................... 12.83 14.33 14.28 14.28 16.32 16.41 16.45 21.20 21.24 21.29

 Associated-Dissolved4 ....................... 1.80 1.51 1.51 1.51 1.34 1.34 1.34 1.35 1.35 1.35

 Non-Associated ............................ 11.03 12.82 12.77 12.77 14.98 15.07 15.11 19.85 19.89 19.94

 Conventional ............................. 6.64 7.19 7.21 7.19 8.31 8.45 8.39 11.38 11.31 11.34

 Unconventional ........................... 4.39 5.62 5.57 5.58 6.66 6.62 6.72 8.48 8.58 8.60

 Lower 48 Offshore ........................... 5.43 5.93 5.86 5.93 6.21 6.30 6.26 7.07 7.08 7.10

 Associated-Dissolved4 ....................... 0.93 1.07 1.07 1.07 1.07 1.07 1.07 1.01 1.01 1.01

 Non-Associated ............................ 4.50 4.85 4.79 4.86 5.13 5.22 5.19 6.06 6.08 6.09

 Alaska .................................... 0.42 0.47 0.47 0.47 0.50 0.50 0.50 0.57 0.57 0.57

Lower 48 End of Year Reserves 3

 (trillion cubic feet) .......................... 157.41 166.23 166.32 166.30 174.58 174.32 175.12 188.20 188.66 189.57

 Supplemental Gas Supplies (trillion cubic feet)5 . . 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) .............. 17.94 24.11 23.94 24.06 28.67 28.82 29.15 39.25 39.89 39.44

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
92 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A10. Coal Supply, Disposition, and Prices

 (Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008 Reference NOx Cap2005

NOx Cap

2008

 Production1

 Appalachia ............................ 434 422 425 422 412 413 408 395 396 396

 Interior ............................... 185 180 180 178 177 179 179 163 161 162

 West ................................ 485 633 622 623 708 673 680 784 767 762

 East of the Mississippi ................... 561 554 557 553 545 549 544 525 524 524

 West of the Mississippi .................. 543 681 669 671 752 716 724 817 800 796

 Total ............................... 1105 1235 1226 1224 1297 1265 1268 1342 1324 1320

 Net Imports

 Imports ............................... 9 16 16 16 17 17 17 20 20 20

 Exports ............................... 58 60 60 60 58 58 58 56 56 56

 Total ................................ -49 -44 -44 -44 -40 -40 -40 -36 -36 -36

 Total Supply2 .......................... 1055 1191 1182 1180 1256 1225 1228 1306 1288 1284

 Consumption by Sector

 Residential and Commercial .............. 55 5 5 5 5 5 5 5 5

 Industrial3 ............................. 79 83 83 83 84 85 85 86 87 87

 Coke Plants ........................... 28 26 26 26 23 23 23 19 19 19

 Electric Generators4 ..................... 922 1078 1069 1066 1145 1115 1116 1198 1179 1174

 Total ............................... 1034 1192 1183 1180 1257 1228 1229 1308 1290 1285

 Discrepancy and Stock Change5

. .......... 21 -1 -1 -1 -1 -3 -1 -2 -2 -1

 Average Minemouth Price

 (1999 dollars per short ton) ................ 17.23 14.76 14.88 14.82 13.69 13.99 13.94 12.84 12.94 12.95 

 (1999 dollars per million Btu) .............. 0.82 0.72 0.72 0.72 0.67 0.68 0.68 0.63 0.64 0.64 

 Delivered Prices (1999 dollars per short ton)6

 Industrial ............................. 31.46 29.43 29.45 29.40 28.41 28.48 28.49 26.55 26.59 26.56 

 Coke Plants ........................... 44.20 42.47 42.45 42.39 41.29 41.33 41.42 38.57 38.52 38.65 

 Electric Generators

 (1999 dollars per short ton) .............. 24.78 22.62 22.68 22.62 20.84 21.20 21.18 19.40 19.67 19.62 

 (1999 dollars per million Btu) ............. 1.22 1.13 1.13 1.13 1.05 1.06 1.06 0.98 0.99 0.99 

 Average ............................ 25.82 23.53 23.59 23.53 21.72 22.08 22.06 20.15 20.41 20.37 

 Exports7 .............................. 37.43 36.32 36.32 36.25 35.54 35.58 35.66 33.13 33.11 33.18 

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A. Projections: EIA, AEO2001 National Energy Modeling System

runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 93

Table A11. Renewable Energy Generating Capability and Generation

 (Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999

Projections

2005 2010 2020

Reference NOx Cap

2005

NOx Cap

2008 Reference

NOx Cap

2005 

Case

NOx Cap

2008 

Case

Reference

NOx Cap

2005 

Case

NOx Cap

2008 

Case

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ........... 78.14 78.62 78.62 78.62 78.74 78.74 78.74 78.74 78.74 78.74

 Geothermal2 ..................... 2.87 3.16 3.21 3.24 4.31 4.17 4.22 4.34 4.23 4.26

 Municipal Solid Waste3 ............. 2.59 3.15 3.11 3.16 3.56 3.51 3.55 4.07 4.02 4.07

 Wood and Other Biomass4 .......... 1.52 1.68 1.68 1.68 2.04 2.04 2.04 2.37 2.37 2.37

 Solar Thermal .................... 0.33 0.35 0.35 0.35 0.40 0.40 0.40 0.48 0.48 0.48

 Solar Photovoltaic ................. 0.01 0.09 0.09 0.09 0.21 0.21 0.21 0.54 0.54 0.54

 Wind ........................... 2.60 4.43 4.43 4.43 5.51 5.51 5.51 5.78 5.78 5.78

 Total .......................... 88.07 91.47 91.48 91.56 94.76 94.57 94.67 96.33 96.16 96.24

 Generation (billion kilowatthours)

 Conventional Hydropower ........... 307.43 299.05 299.05 299.05 298.99 298.99 298.99 297.94 297.94 297.94

 Geothermal2 ..................... 13.07 15.90 16.32 16.58 24.98 23.90 24.28 25.33 24.43 24.63

 Municipal Solid Waste3 ............. 18.05 22.30 21.96 22.32 24.94 24.57 24.93 28.85 28.47 28.84

 Wood and Other Biomass4 .......... 8.86 14.45 14.98 14.49 21.55 21.73 21.82 22.15 22.11 22.12

 Dedicated Plants ................ 7.56 8.67 8.67 8.67 10.88 10.88 10.88 13.35 13.35 13.35

 Cofiring ........................ 1.30 5.78 6.31 5.82 10.67 10.85 10.94 8.80 8.76 8.77

 Solar Thermal .................... 0.89 0.96 0.96 0.96 1.11 1.11 1.11 1.37 1.37 1.37

 Solar Photovoltaic ................. 0.03 0.20 0.20 0.20 0.51 0.51 0.51 1.36 1.36 1.36

 Wind ........................... 4.46 9.42 9.42 9.42 12.33 12.33 12.33 13.10 13.10 13.10

 Total .......................... 352.79 362.28 362.89 363.03 384.41 383.13 383.97 390.09 388.78 389.36

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste .............. 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

 Biomass ......................... 4.65 5.17 5.17 5.17 6.06 6.06 6.06 7.54 7.54 7.54

 Total .......................... 5.35 5.87 5.87 5.87 6.76 6.76 6.76 8.23 8.23 8.23

 Generation (billion kilowatthours)

 Municipal Solid Waste .............. 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03

 Biomass ......................... 27.08 29.92 29.92 29.92 35.01 35.01 35.01 43.52 43.52 43.52

 Total .......................... 31.10 33.95 33.95 33.95 39.03 39.03 39.03 47.55 47.55 47.55

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 .......... 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................. 0.01 0.10 0.10 0.10 0.35 0.35 0.35 0.35 0.35 0.35

 Total .......................... 1.00 1.09 1.09 1.09 1.34 1.34 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 .......... 4.57 4.44 4.44 4.44 4.43 4.43 4.43 4.41 4.41 4.41

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................ 0.02 0.20 0.20 0.20 0.75 0.75 0.75 0.75 0.75 0.75

 Total ......................... 4.59 4.64 4.64 4.64 5.18 5.18 5.18 5.17 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
94 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference NOx Cap

2005 Case

NOx Cap

2008 Case Reference NOx Cap2005 Case

NOx Cap

2008 Case Reference NOx Cap2005 Case

NOx Cap

2008 Case

Marketed Renewable Energy2

 Residential ......................... 0.41 0.43 0.43 0.43 0.43 0.43 0.43 0.44 0.44 0.44

 Wood ............................. 0.41 0.43 0.43 0.43 0.43 0.43 0.43 0.44 0.44 0.44

 Commercial ........................ 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Biomass ........................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Industrial3 ......................... 2.15 2.42 2.42 2.42 2.64 2.64 2.64 3.08 3.08 3.08

 Conventional Hydroelectric ............ 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Biomass ........................... 1.97 2.23 2.23 2.23 2.46 2.46 2.46 2.90 2.90 2.90

 Transportation ...................... 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.23 0.24

 Ethanol used in E854 ................. 0.00 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Ethanol used in Gasoline Blending ...... 0.12 0.18 0.18 0.18 0.19 0.19 0.19 0.20 0.20 0.20

 Electric Generators5 ................. 3.86 4.03 4.05 4.05 4.47 4.44 4.45 4.56 4.52 4.53

 Conventional Hydroelectric ............ 3.17 3.08 3.08 3.08 3.08 3.08 3.08 3.06 3.06 3.06

 Geothermal ........................ 0.27 0.37 0.38 0.39 0.66 0.62 0.64 0.67 0.64 0.65

 Municipal Solid Waste6 ............... 0.25 0.30 0.30 0.30 0.34 0.33 0.34 0.39 0.39 0.39

 Biomass ........................... 0.12 0.18 0.18 0.18 0.26 0.26 0.26 0.27 0.27 0.27

 Dedicated Plants .................. 0.10 0.11 0.10 0.11 0.13 0.13 0.13 0.16 0.16 0.16

 Cofiring .......................... 0.02 0.07 0.08 0.07 0.13 0.13 0.13 0.11 0.11 0.11

 Solar Thermal ...................... 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Wind ............................. 0.05 0.10 0.10 0.10 0.13 0.13 0.13 0.13 0.13 0.13

 Total Marketed Renewable Energy ..... 6.61 7.16 7.18 7.18 7.84 7.80 7.82 8.40 8.36 8.38

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ........................ 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.03 0.03

 Solar Hot Water Heating .............. 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps .............. 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Commercial ........................ 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Thermal ...................... 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.19 0.19 0.19 0.19 0.16 0.16 0.17

 From Cellulose ..................... 0.00 0.01 0.01 0.01 0.02 0.02 0.02 0.07 0.07 0.07

 Total ............................ 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.23 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 95

Table A13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference NOx Cap

2005 Case

NOx Cap

2008 Case Reference NOx Cap2005 Case

NOx Cap

2008 Case Reference NOx Cap2005 Case

NOx Cap

2008 Case

 Residential

 Petroleum .......................... 26.0 26.8 26.9 26.9 24.4 24.4 24.4 22.9 22.9 22.9

 Natural Gas ......................... 69.5 78.6 78.7 78.7 82.0 82.0 81.9 90.8 90.7 90.7

 Coal ............................... 1.1 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3

 Electricity ........................... 192.6 223.2 221.3 221.0 240.4 237.1 237.4 274.7 272.3 271.9

 Total ............................. 289.3 330.0 328.1 327.8 348.1 344.9 345.0 389.6 387.1 386.8

 Commercial

 Petroleum .......................... 13.7 12.9 12.9 12.9 13.1 13.1 13.1 12.9 12.9 12.9

 Natural Gas ......................... 45.4 53.5 53.5 53.5 56.0 55.9 55.8 59.4 59.3 59.4

 Coal ............................... 1.7 1.8 1.8 1.8 1.9 1.9 1.9 2.0 2.0 2.0

 Electricity ........................... 182.1 216.0 214.1 213.8 237.0 234.0 234.1 265.8 263.5 263.0

 Total ............................. 242.9 284.1 282.3 282.0 307.9 304.9 304.8 340.0 337.6 337.2

 Industrial1

 Petroleum .......................... 104.2 99.0 98.9 98.9 104.7 104.6 104.7 115.6 115.7 115.5

 Natural Gas2 ........................ 141.6 147.8 147.9 147.9 157.6 157.9 157.6 174.9 175.1 175.2

 Coal ............................... 55.9 66.5 66.6 66.6 66.3 66.3 66.4 66.4 66.5 66.5

 Electricity ........................... 178.8 193.9 192.1 191.9 203.0 200.3 200.5 228.1 225.9 225.5

 Total ............................. 480.4 507.2 505.5 505.3 531.6 529.1 529.2 584.9 583.2 582.6

 Transportation

 Petroleum3 .......................... 485.8 556.8 556.7 556.7 608.6 608.5 608.3 705.1 704.9 704.8

 Natural Gas4 ........................ 9.5 11.8 11.8 11.8 14.1 14.2 14.2 17.9 17.9 17.9

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 2.9 4.4 4.4 4.3 5.7 5.7 5.7 7.9 7.8 7.8

 Total3 ............................. 498.2 573.1 573.0 573.0 628.6 628.4 628.3 730.9 730.7 730.6

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 .......................... 629.7 695.5 695.4 695.4 750.8 750.6 750.5 856.4 856.4 856.0

 Natural Gas ......................... 266.0 291.8 292.0 292.0 309.7 310.1 309.6 342.9 343.0 343.3

 Coal ............................... 58.8 69.6 69.6 69.6 69.5 69.5 69.5 69.6 69.7 69.7

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 556.3 637.5 631.9 631.1 686.1 677.1 677.6 776.5 769.5 768.1

 Total3 ............................. 1510.8 1694.3 1689.0 1688.1 1816.2 1807.3 1807.3 2045.4 2038.7 2037.2

 Electric Generators6

 Petroleum .......................... 20.0 6.8 6.1 6.2 3.5 3.6 3.7 3.9 3.8 3.8

 Natural Gas ......................... 45.8 77.1 75.8 76.9 98.6 102.1 102.6 164.1 166.0 166.7

 Coal ............................... 490.5 553.6 549.9 548.0 584.0 571.4 571.3 608.4 599.7 597.7

 Total ............................. 556.3 637.5 631.9 631.1 686.1 677.1 677.6 776.5 769.5 768.1

 Total Carbon Dioxide Emissions

 by Primary Fuel7

 Petroleum3 .......................... 649.7 702.2 701.5 701.6 754.3 754.2 754.2 860.3 860.2 859.8

 Natural Gas ......................... 311.8 368.9 367.8 368.9 408.2 412.1 412.2 507.1 508.9 509.9

 Coal ............................... 549.3 623.1 619.5 617.6 653.5 640.9 640.8 678.0 669.4 667.4

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total3 ............................. 1510.8 1694.3 1689.0 1688.1 1816.2 1807.3 1807.3 2045.4 2038.7 2037.2

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) .... 5.5 5.9 5.9 5.9 6.1 6.0 6.0 6.3 6.3 6.3

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 25 to 30 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
96 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table A14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999

Projections

2005 2010 2020

Reference NOx Cap

2005 Case

NOx Cap

2008 Case Reference NOx Cap2005 Case

NOx Cap

2008 Case Reference NOx Cap

2005 Case

NOx Cap

2008 Case

 

Scrubber Retrofits (gigawatts)1 ........ 0.00 10.76 9.46 8.95 10.76 9.46 8.95 15.24 14.07 14.74 

 SO2 Allowance Price

 (1999 dollars per ton) .............. 0.00 177.63 177.85 177.76 169.55 181.42 182.50 246.09 247.41 246.82 

NOx Controls (gigawatts)

 Combustion ....................... 0.00 65.84 116.86 116.20 66.93 118.01 117.66 67.57 118.06 117.70 

 SCR ............................. 0.00 84.31 244.32 84.00 85.97 246.67 231.61 89.75 251.97 242.85 

 SNCR ............................ 0.00 25.36 37.43 1.78 28.78 38.86 46.42 38.69 58.61 59.69 

Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ....... 472.31 598.07 589.51 590.48 656.33 623.93 628.46 730.01 712.19 705.95 

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) . . 433.55 451.27 451.83 449.68 453.06 454.07 451.48 438.05 435.90 437.15 

 High Sulfur (> 1.67 lbs. S/mmBtu) ...... 198.66 185.83 184.99 183.48 187.25 187.40 188.17 174.20 176.34 177.38 

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here. 

SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCNOX05.D121300A, and MCNOX08.D121300A.
Appendix B

Tables for SO2 Cap Cases

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 99

Table B1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Production

 Crude Oil and Lease Condensate ... 12.45 11.85 11.85 11.85 10.90 10.89 10.89 10.61 10.67 10.66

 Natural Gas Plant Liquids ......... 2.62 3.02 2.97 2.97 3.31 3.35 3.32 4.07 4.07 4.08

 Dry Natural Gas ................. 19.16 21.26 20.92 20.88 23.63 23.90 23.64 29.59 29.62 29.69

 Coal .......................... 23.12 25.43 25.52 25.63 26.47 25.82 26.43 27.21 27.07 27.27

 Nuclear Power .................. 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.05 5.96

 Renewable Energy1 .............. 6.50 6.98 7.13 7.02 7.65 7.69 7.68 8.20 8.23 8.22

 Other2 ........................ 1.65 0.57 0.57 0.57 0.33 0.54 0.52 0.33 0.32 0.33

 Total ....................... 73.30 77.01 76.86 76.82 79.98 79.87 80.17 86.18 86.03 86.22

 Imports

 Crude Oil3 ..................... 18.96 23.21 23.18 23.19 25.22 25.17 25.11 26.48 26.45 26.47

 Petroleum Products4 ............. 4.14 4.85 4.85 4.88 6.46 6.30 6.41 10.77 10.72 10.71

 Natural Gas .................... 3.63 4.90 4.94 4.93 5.49 5.62 5.56 6.60 6.72 6.71

 Other Imports5 .................. 0.64 1.11 1.11 1.11 0.96 0.96 0.96 0.96 0.96 0.96

 Total ....................... 27.37 34.08 34.09 34.11 38.12 38.04 38.04 44.82 44.85 44.85

 Exports

 Petroleum6 ..................... 1.98 1.81 1.80 1.81 1.79 1.78 1.78 1.90 1.91 1.91

 Natural Gas .................... 0.17 0.33 0.33 0.33 0.43 0.43 0.43 0.63 0.63 0.63

 Coal .......................... 1.48 1.51 1.52 1.51 1.45 1.45 1.45 1.41 1.38 1.38

 Total ....................... 3.62 3.64 3.65 3.64 3.67 3.65 3.65 3.94 3.92 3.93

 Discrepancy7 .................... 0.95 0.39 0.41 0.39 0.21 0.27 0.26 -0.03 -0.07 0.01

 Consumption

 Petroleum Products8 ............. 38.07 41.40 41.33 41.36 44.43 44.40 44.40 50.60 50.57 50.57

 Natural Gas .................... 21.90 25.78 25.48 25.43 28.52 28.91 28.60 35.40 35.54 35.60

 Coal .......................... 21.46 24.37 24.44 24.57 25.54 24.91 25.55 26.48 26.38 26.52

 Nuclear Power ................. . 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.05 5.96

 Renewable Energy1 .............. 6.51 6.98 7.13 7.02 7.66 7.70 7.69 8.21 8.23 8.23

 Other9 ........................ 0.35 0.61 0.61 0.61 0.38 0.38 0.38 0.25 0.25 0.25

 Total ........................ 96.09 107.05 106.89 106.90 114.21 113.99 114.30 127.10 127.02 127.13

 Net Imports - Petroleum ........... 21.12 26.26 26.23 26.26 29.88 29.69 29.74 35.36 35.26 35.27

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 . . 17.35 20.83 20.83 20.83 21.37 21.37 21.37 22.41 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 2.08 2.49 2.46 2.45 2.68 2.67 2.63 3.14 3.20 3.25

 Coal Minemouth Price (dollars per ton) 17.23 14.76 12.97 13.62 13.69 12.41 12.71 12.84 11.94 11.87

 Average Electric Price (cents per Kwh) 6.6 6.2 6.1 6.1 5.9 5.9 5.9 6.0 6.0 6.1

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
100 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

Energy Consumption

 Residential

 Distillate Fuel ........................ 0.86 0.88 0.88 0.88 0.81 0.81 0.80 0.75 0.75 0.75

 Kerosene ........................... 0.10 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas ............... 0.46 0.45 0.45 0.45 0.41 0.42 0.41 0.39 0.40 0.40

 Petroleum Subtotal .................. 1.42 1.42 1.42 1.42 1.29 1.30 1.29 1.21 1.22 1.22

 Natural Gas ......................... 4.85 5.46 5.47 5.47 5.69 5.69 5.70 6.30 6.29 6.28

 Coal ............................... 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

 Renewable Energy1 ................... 0.41 0.43 0.43 0.43 0.43 0.43 0.43 0.44 0.44 0.44

 Electricity ........................... 3.91 4.50 4.50 4.50 4.96 4.93 4.95 5.80 5.79 5.77

 Delivered Energy ................... 10.62 11.86 11.87 11.87 12.42 12.41 12.43 13.80 13.78 13.75

 Electricity Related Losses .............. 8.46 9.46 9.41 9.41 9.88 9.79 9.91 10.58 10.58 10.61

 Total ............................. 19.08 21.32 21.27 21.28 22.30 22.20 22.33 24.38 24.36 24.35

 Commercial

 Distillate Fuel ........................ 0.36 0.41 0.41 0.41 0.41 0.41 0.41 0.39 0.39 0.39

 Residual Fuel ....................... 0.10 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.11

 Kerosene ........................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas ............... 0.08 0.09 0.09 0.09 0.09 0.09 0.09 0.10 0.10 0.10

 Motor Gasoline2 ...................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal .................. 0.59 0.66 0.66 0.66 0.67 0.67 0.67 0.66 0.66 0.66

 Natural Gas ......................... 3.15 3.71 3.72 3.72 3.89 3.88 3.89 4.12 4.12 4.11

 Coal ............................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.08

 Renewable Energy3 ................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Electricity ........................... 3.70 4.35 4.35 4.36 4.89 4.88 4.89 5.61 5.60 5.59

 Delivered Energy ................... 7.59 8.87 8.88 8.89 9.60 9.58 9.60 10.55 10.53 10.51

 Electricity Related Losses .............. 8.00 9.15 9.10 9.10 9.74 9.68 9.79 10.23 10.23 10.28

 Total ............................. 15.59 18.02 17.98 17.99 19.34 19.26 19.39 20.79 20.76 20.79

 Industrial4

 Distillate Fuel ........................ 1.07 1.13 1.13 1.13 1.27 1.27 1.27 1.44 1.45 1.45

 Liquefied Petroleum Gas ............... 2.32 2.45 2.45 2.45 2.50 2.51 2.50 2.83 2.84 2.84

 Petrochemical Feedstock .............. 1.29 1.42 1.42 1.42 1.53 1.53 1.53 1.70 1.70 1.70

 Residual Fuel ....................... 0.22 0.22 0.22 0.22 0.25 0.25 0.25 0.27 0.28 0.28

 Motor Gasoline2 ...................... 0.21 0.23 0.23 0.23 0.25 0.25 0.25 0.28 0.28 0.28

 Other Petroleum5 ..................... 4.29 4.49 4.49 4.49 4.76 4.76 4.76 5.25 5.25 5.24

 Petroleum Subtotal .................. 9.39 9.95 9.94 9.94 10.55 10.55 10.55 11.78 11.79 11.79

 Natural Gas6 ........................ 9.43 10.42 10.41 10.41 11.11 11.12 11.11 12.33 12.32 12.34

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 1.73 1.82 1.82 1.82 1.85 1.85 1.85 1.89 1.90 1.90

 Net Coal Coke Imports ................ 0.06 0.12 0.12 0.12 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 2.54 2.62 2.62 2.62 2.61 2.61 2.61 2.62 2.62 2.62

 Renewable Energy7 ................... 2.15 2.42 2.42 2.42 2.64 2.64 2.64 3.08 3.08 3.08

 Electricity ........................... 3.63 3.90 3.90 3.91 4.19 4.17 4.18 4.81 4.79 4.80

 Delivered Energy ................... 27.15 29.32 29.29 29.29 31.10 31.11 31.09 34.62 34.61 34.63

 Electricity Related Losses .............. 7.85 8.22 8.16 8.16 8.34 8.29 8.37 8.78 8.76 8.83

 Total ............................. 35.00 37.53 37.45 37.45 39.45 39.39 39.46 43.40 43.37 43.46
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 101

Table B2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Transportation

 Distillate Fuel ........................ 5.13 6.28 6.28 6.28 6.99 6.99 6.99 8.21 8.20 8.21

 Jet Fuel8 ........................... 3.46 3.90 3.90 3.90 4.51 4.51 4.51 5.97 5.97 5.97

 Motor Gasoline2 ...................... 15.92 17.70 17.70 17.70 19.05 19.04 19.04 21.32 21.32 21.32

 Residual Fuel ....................... 0.74 0.85 0.85 0.85 0.85 0.85 0.85 0.87 0.87 0.87

 Liquefied Petroleum Gas ............... 0.02 0.03 0.03 0.03 0.04 0.04 0.04 0.06 0.06 0.06

 Other Petroleum9 ..................... 0.26 0.29 0.29 0.29 0.31 0.31 0.31 0.35 0.35 0.35

 Petroleum Subtotal .................. 25.54 29.06 29.06 29.06 31.75 31.75 31.75 36.77 36.76 36.77

 Pipeline Fuel Natural Gas .............. 0.66 0.77 0.76 0.76 0.89 0.90 0.89 1.08 1.09 1.09

 Compressed Natural Gas .............. 0.02 0.06 0.06 0.06 0.09 0.09 0.09 0.16 0.16 0.16

 Renewable Energy (E85)10 ............. 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 0.06 0.09 0.09 0.09 0.12 0.12 0.12 0.17 0.17 0.17

 Delivered Energy ................... 26.28 29.99 29.99 29.99 32.89 32.89 32.88 38.23 38.22 38.23

 Electricity Related Losses .............. 0.13 0.19 0.18 0.18 0.24 0.23 0.24 0.30 0.30 0.31

 Total ............................. 26.41 30.18 30.18 30.17 33.12 33.13 33.12 38.53 38.53 38.53

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ........................ 7.42 8.70 8.71 8.70 9.47 9.47 9.47 10.80 10.79 10.80

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.90 3.90 4.51 4.51 4.51 5.97 5.97 5.97

 Liquefied Petroleum Gas ............... 2.88 3.03 3.02 3.02 3.05 3.06 3.05 3.38 3.40 3.39

 Motor Gasoline2 ...................... 16.17 17.96 17.96 17.96 19.32 19.32 19.31 21.63 21.63 21.63

 Petrochemical Feedstock .............. 1.29 1.42 1.42 1.42 1.53 1.53 1.53 1.70 1.70 1.70

 Residual Fuel ....................... 1.05 1.17 1.17 1.17 1.21 1.21 1.21 1.25 1.25 1.25

 Other Petroleum12 .................... 4.53 4.76 4.76 4.76 5.04 5.04 5.04 5.58 5.58 5.57

 Petroleum Subtotal .................. 36.95 41.08 41.08 41.08 44.26 44.27 44.25 50.42 50.43 50.43

 Natural Gas6 ........................ 18.11 20.42 20.41 20.41 21.67 21.69 21.68 24.00 23.97 23.97

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 1.84 1.94 1.94 1.94 1.98 1.98 1.98 2.02 2.03 2.03

 Net Coal Coke Imports ................ 0.06 0.12 0.12 0.12 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 2.65 2.74 2.74 2.74 2.74 2.74 2.74 2.74 2.75 2.75

 Renewable Energy13 .................. 2.65 2.95 2.95 2.95 3.19 3.19 3.19 3.65 3.65 3.65

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 11.29 12.84 12.85 12.86 14.15 14.10 14.13 16.39 16.34 16.31

 Delivered Energy ................... 71.65 80.04 80.03 80.04 86.01 85.99 86.00 97.20 97.14 97.12

 Electricity Related Losses .............. 24.44 27.02 26.85 26.86 28.20 28.00 28.30 29.89 29.88 30.01

 Total ............................. 96.09 107.05 106.89 106.90 114.21 113.99 114.30 127.10 127.02 127.13

 Electric Generators14

 Distillate Fuel ........................ 0.06 0.05 0.03 0.04 0.04 0.02 0.03 0.04 0.03 0.03

 Residual Fuel ....................... 1.07 0.27 0.21 0.23 0.13 0.11 0.12 0.14 0.11 0.11

 Petroleum Subtotal .................. 1.13 0.32 0.24 0.28 0.17 0.13 0.14 0.19 0.14 0.14

 Natural Gas ......................... 3.79 5.36 5.07 5.02 6.84 7.22 6.91 11.40 11.57 11.63

 Steam Coal ......................... 18.81 21.63 21.69 21.83 22.80 22.17 22.81 23.73 23.63 23.77

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.05 5.96

 Renewable Energy15 .................. 3.86 4.03 4.18 4.07 4.47 4.51 4.50 4.56 4.58 4.58

 Electricity Imports16 ................... 0.35 0.61 0.61 0.61 0.37 0.37 0.37 0.24 0.24 0.24

 Total ............................. 35.73 39.85 39.70 39.71 42.35 42.10 42.43 46.28 46.22 46.33
102 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Total Energy Consumption

 Distillate Fuel ........................ 7.48 8.75 8.74 8.74 9.51 9.49 9.50 10.84 10.82 10.83

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.90 3.90 4.51 4.51 4.51 5.97 5.97 5.97

 Liquefied Petroleum Gas ............... 2.88 3.03 3.02 3.02 3.05 3.06 3.05 3.38 3.40 3.39

 Motor Gasoline2 ...................... 16.17 17.96 17.96 17.96 19.32 19.32 19.31 21.63 21.63 21.63

 Petrochemical Feedstock .............. 1.29 1.42 1.42 1.42 1.53 1.53 1.53 1.70 1.70 1.70

 Residual Fuel ....................... 2.12 1.44 1.38 1.41 1.34 1.32 1.32 1.39 1.36 1.36

 Other Petroleum12 .................... 4.53 4.76 4.76 4.76 5.04 5.04 5.04 5.58 5.58 5.57

 Petroleum Subtotal .................. 38.07 41.40 41.33 41.36 44.43 44.40 44.40 50.60 50.57 50.57

 Natural Gas ......................... 21.90 25.78 25.48 25.43 28.52 28.91 28.60 35.40 35.54 35.60

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 20.65 23.57 23.63 23.77 24.77 24.14 24.78 25.75 25.66 25.79

 Net Coal Coke Imports ................ 0.06 0.12 0.12 0.12 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 21.46 24.37 24.44 24.57 25.54 24.91 25.55 26.48 26.38 26.52

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.69 7.69 6.17 6.05 5.96

 Renewable Energy17 .................. 6.51 6.98 7.13 7.02 7.66 7.70 7.69 8.21 8.24 8.23

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 ................... 0.35 0.61 0.61 0.61 0.37 0.37 0.37 0.24 0.24 0.24

 Total ............................. 96.09 107.05 106.89 106.90 114.21 113.99 114.30 127.10 127.02 127.13

Energy Use and Related Statistics

 Delivered Energy Use .................. 71.65 80.04 80.03 80.04 86.01 85.99 86.00 97.20 97.14 97.12

 Total Energy Use ..................... 96.09 107.05 106.89 106.90 114.21 113.99 114.30 127.10 127.02 127.13

 Population (millions) .................... 273.13 288.02 288.02 288.02 300.17 300.17 300.17 325.24 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 10960 10960 10960 12667 12667 12667 16515 16515 16515

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) .... 1510.8 1694.3 1691.9 1694.9 1816.2 1806.4 1818.0 2045.4 2045.4 2050.0

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which produces electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed

renewable energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy. 

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal

sources. Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel

source of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol

components of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for

geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Consumption values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC,

April 1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy

Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 103

Table B3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Residential ......................... 13.12 12.91 12.87 12.83 13.15 13.25 13.14 13.59 13.67 13.81

 Primary Energy1 .................... 6.72 7.12 7.09 7.08 7.00 6.98 6.95 7.02 7.08 7.12

 Petroleum Products2 ................ 7.55 9.18 9.17 9.17 9.37 9.16 9.20 9.66 9.65 9.66

 Distillate Fuel ..................... 6.27 7.34 7.33 7.33 7.51 7.48 7.49 7.99 7.98 7.98

 Liquefied Petroleum Gas ............ 10.36 12.83 12.82 12.82 13.06 12.42 12.57 12.90 12.85 12.90

 Natural Gas ....................... 6.52 6.63 6.60 6.59 6.52 6.53 6.49 6.56 6.63 6.67

 Electricity .......................... 23.46 21.84 21.79 21.70 21.88 22.22 21.97 22.16 22.26 22.57

 Commercial ........................ 13.20 12.36 12.29 12.23 11.74 11.83 11.69 12.37 12.47 12.64

 Primary Energy1 .................... 5.22 5.35 5.32 5.32 5.53 5.51 5.49 5.76 5.81 5.85

 Petroleum Products2 ................ 5.00 6.01 6.00 6.00 6.17 6.06 6.09 6.52 6.50 6.50

 Distillate Fuel ..................... 4.37 5.13 5.12 5.12 5.28 5.25 5.26 5.77 5.75 5.75

 Residual Fuel .................... 2.63 3.64 3.63 3.64 3.69 3.69 3.69 3.85 3.85 3.85

 Natural Gas3 ...................... 5.34 5.31 5.28 5.27 5.49 5.50 5.46 5.72 5.78 5.83

 Electricity .......................... 21.43 19.51 19.41 19.29 17.61 17.83 17.56 18.09 18.24 18.52

 Industrial4 .......................... 5.32 5.49 5.45 5.44 5.44 5.36 5.34 5.85 5.88 5.95

 Primary Energy ..................... 3.92 4.25 4.23 4.22 4.37 4.25 4.26 4.73 4.75 4.77

 Petroleum Products2 ................ 5.55 5.95 5.93 5.94 6.05 5.81 5.86 6.28 6.27 6.28

 Distillate Fuel ..................... 4.65 5.29 5.28 5.28 5.46 5.43 5.44 5.98 5.95 5.94

 Liquefied Petroleum Gas ............ 8.50 7.94 7.93 7.93 8.00 7.33 7.48 7.86 7.82 7.87

 Residual Fuel .................... 2.78 3.37 3.36 3.36 3.42 3.42 3.42 3.58 3.58 3.58

 Natural Gas5 ...................... 2.79 3.17 3.14 3.13 3.30 3.29 3.25 3.77 3.84 3.88

 Metallurgical Coal .................. 1.65 1.58 1.58 1.58 1.54 1.53 1.54 1.44 1.43 1.43

 Steam Coal ....................... 1.43 1.34 1.30 1.32 1.29 1.25 1.26 1.21 1.18 1.18

 Electricity .......................... 13.01 12.30 12.21 12.11 11.21 11.36 11.16 11.60 11.73 12.00

 Transportation ...................... 8.30 9.27 9.25 9.25 9.45 9.43 9.47 9.32 9.31 9.31

 Primary Energy ..................... 8.29 9.25 9.24 9.24 9.44 9.41 9.45 9.30 9.29 9.29

 Petroleum Products2 ................ 8.28 9.25 9.24 9.24 9.44 9.41 9.45 9.30 9.29 9.29

 Distillate Fuel6 .................... 8.22 8.89 8.87 8.87 8.94 8.94 8.94 9.02 8.99 8.98

 Jet Fuel7 ........................ 4.70 5.24 5.23 5.23 5.46 5.46 5.47 5.88 5.88 5.88

 Motor Gasoline8 ................... 9.45 10.64 10.63 10.63 10.92 10.88 10.94 10.68 10.68 10.68

 Residual Fuel .................... 2.46 3.10 3.10 3.10 3.18 3.17 3.18 3.33 3.33 3.33

 Liquid Petroleum Gas9 .............. 12.87 14.19 14.17 14.17 14.24 13.70 13.83 13.88 13.84 13.88

 Natural Gas10 ...................... 7.02 6.80 6.76 6.75 7.03 7.04 7.01 7.33 7.39 7.44

 Ethanol (E85)11 .................... 14.42 19.12 19.06 19.06 19.00 18.97 18.99 19.36 19.37 19.37

 Methanol (M85)12 ................... 10.38 13.11 13.11 13.11 13.74 13.72 13.74 14.43 14.43 14.43

 Electricity .......................... 15.58 14.29 14.19 14.12 13.53 13.79 13.66 13.03 13.16 13.33

 Average End-Use Energy ............. 8.53 8.90 8.87 8.86 8.94 8.93 8.90 9.17 9.20 9.26

 Primary Energy ..................... 6.33 7.00 6.98 6.98 7.18 7.12 7.13 7.31 7.33 7.34

 Electricity .......................... 19.40 18.10 18.02 17.92 17.18 17.42 17.18 17.57 17.70 17.98

 Electric Generators13

 Fossil Fuel Average .................. 1.49 1.50 1.41 1.41 1.52 1.50 1.47 1.85 1.84 1.86

 Petroleum Products ................. 2.50 3.70 3.69 3.68 4.06 4.14 4.11 4.33 4.40 4.41

 Distillate Fuel ..................... 4.04 4.65 4.69 4.64 4.85 4.89 4.88 5.30 5.30 5.29

 Residual Fuel .................... 2.41 3.52 3.54 3.51 3.85 3.97 3.94 4.04 4.19 4.19

 Natural Gas ....................... 2.54 2.89 2.85 2.83 3.02 3.02 2.98 3.61 3.68 3.72

 Steam Coal ....................... 1.22 1.13 1.05 1.05 1.05 0.99 1.00 0.98 0.93 0.93
104 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Average Price to All Users14

 Petroleum Products2 ................. 7.43 8.43 8.43 8.43 8.63 8.55 8.59 8.62 8.61 8.62

 Distillate Fuel ...................... 7.27 8.07 8.06 8.05 8.18 8.18 8.18 8.41 8.38 8.38

 Jet Fuel .......................... 4.70 5.24 5.23 5.23 5.46 5.46 5.47 5.88 5.88 5.88

 Liquefied Petroleum Gas ............. 8.84 8.83 8.83 8.82 8.87 8.22 8.36 8.64 8.61 8.66

 Motor Gasoline8 .................... 9.45 10.64 10.63 10.63 10.92 10.88 10.94 10.68 10.68 10.68

 Residual Fuel ..................... 2.48 3.26 3.25 3.25 3.33 3.33 3.33 3.49 3.49 3.49

 Natural Gas ....................... 4.05 4.25 4.23 4.23 4.27 4.25 4.23 4.52 4.58 4.62

 Coal .............................. 1.24 1.15 1.07 1.08 1.07 1.01 1.02 1.00 0.95 0.95

 Ethanol (E85)11 ..................... 14.42 19.12 19.06 19.06 19.00 18.97 18.99 19.36 19.37 19.37

 Methanol (M85)12 .................... 10.38 13.11 13.11 13.11 13.74 13.72 13.74 14.43 14.43 14.43

 Electricity .......................... 19.40 18.10 18.02 17.92 17.18 17.42 17.18 17.57 17.70 17.98

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ........................... 134.05 147.53 147.20 146.85 157.75 158.74 157.68 181.60 182.29 183.81

 Commercial .......................... 99.10 108.63 108.17 107.72 111.63 112.42 111.24 129.48 130.24 131.76

 Industrial ............................ 110.62 121.27 120.46 120.08 126.35 124.81 124.11 151.05 151.86 153.86

 Transportation ........................ 212.64 270.40 270.13 270.10 301.90 300.96 302.24 345.30 345.00 345.03

 Total Non-Renewable Expenditures ..... 556.41 647.83 645.97 644.75 697.64 696.93 695.27 807.43 809.39 814.46

 Transportation Renewable Expenditures . . 0.14 0.42 0.42 0.42 0.61 0.61 0.62 0.86 0.86 0.86

 Total Expenditures .................. 556.55 648.25 646.38 645.17 698.25 697.55 695.89 808.29 810.25 815.32

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt

wholesale generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report,

DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and

MCSO208.D121300A. 1999 electricity prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

MCSO205.D121300A, and MCSO208.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and

MCSO208.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 105

Table B4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

Generation by Fuel Type

 Electric Generators1

 Coal ............................ 1835 2103 2101 2124 2232 2146 2207 2317 2277 2287

 Petroleum ....................... 104 32 24 28 18 14 15 19 15 15

 Natural Gas2 ..................... 365 574 579 564 867 939 891 1568 1605 1595

 Nuclear Power .................... 730 740 740 740 720 720 720 577 567 558

 Pumped Storage .................. -1 -1 -1 -1 -1 -1 -1 -1 -1 -1

 Renewable Sources3 ............... 353 362 372 362 384 388 386 390 392 391

 Total .......................... 3386 3811 3815 3818 4220 4206 4218 4872 4855 4846

 Non-Utility Generation for Own Use ... 16 16 16 16 16 16 16 16 16 16

 Distributed Generation ............. 0111332666

 Cogenerators4

 Coal ........................... 47 52 52 53 52 52 52 52 52 52

 Petroleum ...................... 9 10 10 10 10 10 10 10 10 10

 Natural Gas ..................... 206 239 238 237 256 256 255 298 307 306

 Other Gaseous Fuels5 ............. 4666777888

 Renewable Sources3 .............. 31 34 34 34 39 39 39 48 48 48

 Other6 ......................... 5555555555

 Total ......................... 302 347 345 345 369 370 368 421 430 429

 Other End-Use Generators .......... 5555555555

 Sales to Utilities .................. 150 171 170 170 176 176 175 200 201 202

 Generation for Own Use ............ 156 180 180 180 198 199 198 226 234 231

 Net Imports8 ...................... 33 57 57 57 35 35 35 23 23 23

Electricity Sales by Sector

 Residential ........................ 1146 1317 1319 1320 1452 1446 1450 1699 1696 1690

 Commercial ....................... 1083 1275 1276 1277 1432 1429 1432 1644 1640 1637

 Industrial ......................... 1063 1144 1144 1145 1227 1223 1225 1411 1404 1406

 Transportation ..................... 17 26 26 26 35 35 35 49 49 49

 Total ........................... 3309 3762 3765 3768 4146 4133 4142 4803 4788 4781

End-Use Prices (1999 cents per kwh)9

 Residential ........................ 8.0 7.5 7.4 7.4 7.5 7.6 7.5 7.6 7.6 7.7

 Commercial ....................... 7.3 6.7 6.6 6.6 6.0 6.1 6.0 6.2 6.2 6.3

 Industrial ......................... 4.4 4.2 4.2 4.1 3.8 3.9 3.8 4.0 4.0 4.1

 Transportation ..................... 5.3 4.9 4.8 4.8 4.6 4.7 4.7 4.4 4.5 4.5

 All Sectors Average .............. 6.6 6.2 6.1 6.1 5.9 5.9 5.9 6.0 6.0 6.1

 Prices by Service Category9

 (1999 cents/kwh)

 Generation ....................... 4.1 3.6 3.6 3.5 3.2 3.2 3.2 3.4 3.4 3.5

 Transmission ..................... 0.6 0.6 0.6 0.6 0.7 0.7 0.7 0.7 0.7 0.7

 Distribution ...................... 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide ..................... 13.82 10.39 5.27 8.79 9.70 3.67 4.12 8.95 3.27 3.27

 Nitrogen Oxide .................... 5.46 4.22 4.13 4.15 4.20 4.04 4.16 4.37 4.25 4.28

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2

Includes electricity generation by fuel cells. 3

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
106 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

Electric Generators2

 Capability

 Coal Steam ................... 306.2 302.4 307.6 307.3 317.4 315.8 316.8 317.8 317.6 317.2

 Other Fossil Steam3 ............ 138.2 129.6 126.1 125.9 121.1 116.8 117.1 117.2 111.1 114.4

 Combined Cycle ............... 20.2 49.4 63.7 61.2 124.0 136.5 133.0 230.0 234.0 226.8

 Combustion Turbine/Diesel ....... 75.6 129.7 119.9 121.7 162.1 149.5 157.8 207.7 210.7 212.7

 Nuclear Power ................. 97.4 97.5 97.5 97.5 94.2 93.7 94.2 71.6 70.5 68.9

 Pumped Storage ............... 19.3 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 88.1 91.5 91.7 91.6 94.8 94.8 94.7 96.3 96.3 96.3

 Distributed Generation5 ......... 0.0 2.0 1.8 1.8 6.1 6.1 5.6 14.0 14.7 13.1

 Total ....................... 745.0 821.5 827.9 826.4 939.4 932.9 938.8 1074.3 1074.7 1069.2

 Cumulative Planned Additions6

 Coal Steam ................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Combined Cycle ............... 0.0 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ....... 0.0 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 0.0 2.4 2.4 2.4 4.3 4.3 4.3 5.4 5.4 5.4

 Distributed Generation5 .......... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Total ....................... 0.0 11.5 11.5 11.5 13.6 13.6 13.6 14.8 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam ................... 0.0 2.5 9.0 8.6 20.1 19.7 19.2 21.5 22.4 21.7

 Other Fossil Steam3 ............ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Combined Cycle ............... 0.0 20.8 35.1 32.6 95.7 108.2 104.6 201.6 205.6 198.4

 Combustion Turbine/Diesel ...... . 0.0 57.0 48.6 50.6 90.8 79.5 87.9 137.2 141.0 143.7

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ............ 0.0 0.6 0.9 0.7 1.9 1.9 1.8 2.4 2.4 2.4

 Distributed Generation5 .......... 0.0 2.0 1.8 1.8 6.1 6.1 5.6 14.0 14.7 13.1

 Total ....................... 0.0 82.9 95.4 94.3 214.6 215.4 219.1 376.7 386.1 379.2

 Cumulative Total Additions ...... 0.0 94.5 107.0 105.9 228.1 228.9 232.7 391.4 400.9 394.0

 Cumulative Retirements7 ........

 Coal Steam ................... 0.0 6.6 9.0 7.9 9.2 10.4 8.9 10.2 11.3 10.9

 Other Fossil Steam3 ............ 0.0 8.5 11.9 12.2 17.0 21.3 21.0 20.9 27.0 23.7

 Combined Cycle ............... 0.0 0.0 0.0 0.0 0.3 0.3 0.3 0.3 0.3 0.3

 Combustion Turbine/Diesel 0.0 3.8 4.7 4.7 5.1 5.9 5.9 5.9 6.2 6.8

 Nuclear Power ................ 0.0 0.0 0.0 0.0 3.3 3.7 3.3 25.9 27.0 28.6

 Pumped Storage 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ........... 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total 0.0 19.0 25.8 24.9 34.9 41.7 39.4 63.4 71.9 70.3

Cogenerators8

 Capability

 Coal ......................... 8.4 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9

 Petroleum .................... 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 2.8

 Natural Gas ................... 33.8 40.0 39.9 39.9 42.9 43.0 42.8 48.8 50.2 49.8

 Other Gaseous Fuels ........... 0.2 0.8 0.8 0.8 0.9 0.9 0.9 1.0 1.0 1.0

 Renewable Sources4 ............ 5.3 5.9 5.9 5.9 6.8 6.8 6.8 8.2 8.2 8.2

 Other ........................ 1.1 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

 Total ....................... 51.6 59.2 59.1 59.1 63.1 63.2 63.0 70.7 72.1 71.6

 Cumulative Additions6 .......... 0.0 7.5 7.5 7.4 11.4 11.6 11.4 19.0 20.4 20.0
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 107

Table B5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

Other End-Use Generators9

 Renewable Sources ............. 1.0 1.1 1.1 1.1 1.3 1.3 1.3 1.3 1.3 1.3

 Cumulative Additions ............ 0.0 0.1 0.1 0.1 0.3 0.3 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8

Nameplate capacity is reported for nonutilities on EIA-860B: “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
108 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade .......... 182.2 125.3 125.3 125.3 102.9 102.9 102.9 0.0 0.0 0.0

 Gross Domestic Economy Trade ........... 147.8 202.8 200.2 203.4 183.2 177.6 182.0 206.7 207.6 201.1

 Gross Domestic Trade ................. 330.0 328.1 325.4 328.6 286.1 280.5 284.9 206.7 207.6 201.1

 Gross Domestic Firm Power Sales

 (million 1999 dollars) .................... 8588.1 5905.8 5905.8 5905.8 4851.2 4851.2 4851.2 0.0 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) .................... 4292.5 6044.9 5669.3 5661.5 4987.6 4884.3 4808.8 6227.5 6413.8 6319.6

 Gross Domestic Sales

 (million 1999 dollars) .................. 12880.6 11950.7 11575.1 11567.3 9838.8 9735.6 9660.0 6227.5 6413.8 6319.6

 International Electricity Trade

 Firm Power Imports From Canada and Mexico1

 27.0 10.7 10.7 10.7 5.8 5.8 5.8 0.0 0.0 0.0

 Economy Imports From Canada and Mexico1 . . 21.9 63.5 63.5 63.5 45.9 45.9 45.9 30.6 30.6 30.6

 Gross Imports From Canada and Mexico1 . . 48.9 74.1 74.1 74.1 51.7 51.7 51.7 30.6 30.6 30.6

 Firm Power Exports To Canada and Mexico . . 9.2 9.7 9.7 9.7 8.7 8.7 8.7 0.0 0.0 0.0

 Economy Exports To Canada and Mexico .... 6.3 7.0 7.0 7.0 7.7 7.7 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico .... 15.5 16.7 16.7 16.7 16.4 16.4 16.4 7.7 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 109

Table B7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Production

 Dry Gas Production1 ......... 18.67 20.72 20.39 20.35 23.03 23.29 23.04 28.84 28.87 28.94

 Supplemental Natural Gas2 .... 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Net Imports ................ 3.38 4.47 4.51 4.50 4.94 5.07 5.01 5.83 5.94 5.93

 Canada ................... 3.29 4.28 4.32 4.31 4.68 4.81 4.76 5.46 5.57 5.56

 Mexico .................... -0.01 -0.18 -0.18 -0.18 -0.25 -0.25 -0.25 -0.40 -0.40 -0.40

 Liquefied Natural Gas ........ 0.10 0.37 0.37 0.37 0.51 0.51 0.50 0.77 0.78 0.78

 Total Supply ................ 22.15 25.30 25.01 24.96 28.03 28.42 28.11 34.72 34.87 34.92

 Consumption by Sector

 Residential ................. 4.72 5.32 5.32 5.33 5.54 5.54 5.55 6.14 6.12 6.11

 Commercial ................ 3.07 3.62 3.62 3.62 3.78 3.78 3.79 4.02 4.01 4.00

 Industrial3 .................. 7.95 8.80 8.80 8.81 9.33 9.33 9.33 10.17 10.17 10.18

 Electric Generators4 ......... 3.72 5.26 4.98 4.93 6.72 7.08 6.78 11.19 11.35 11.41

 Lease and Plant Fuel5 ........ 1.23 1.35 1.33 1.33 1.49 1.50 1.49 1.83 1.83 1.84

 Pipeline Fuel ............... 0.64 0.75 0.74 0.74 0.87 0.88 0.87 1.06 1.06 1.06

 Transportation6 ............. 0.02 0.05 0.05 0.05 0.09 0.09 0.09 0.15 0.15 0.15

 Total .................... 21.35 25.14 24.85 24.80 27.82 28.21 27.90 34.55 34.69 34.76

 Discrepancy7 ............... 0.80 0.16 0.16 0.16 0.21 0.21 0.21 0.17 0.17 0.17

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A. Other 1999

consumption: EIA, Short-Term Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption

levels for consumption of natural gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A,

and MCSO208.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
110 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Source Price 

 Average Lower 48 Wellhead Price1 .... 2.08 2.49 2.46 2.45 2.68 2.67 2.63 3.14 3.20 3.25

 Average Import Price ............... 2.29 2.48 2.48 2.48 2.41 2.41 2.41 2.67 2.75 2.75

 Average2 ....................... 2.11 2.49 2.46 2.46 2.63 2.62 2.59 3.05 3.12 3.16

 Delivered Prices

 Residential ....................... 6.69 6.81 6.77 6.77 6.70 6.70 6.67 6.74 6.81 6.85

 Commercial ...................... 5.49 5.45 5.42 5.41 5.64 5.64 5.61 5.87 5.94 5.99

 Industrial3 ........................ 2.87 3.26 3.22 3.21 3.39 3.38 3.34 3.87 3.94 3.99

 Electric Generators4 ............... 2.59 2.94 2.90 2.89 3.08 3.08 3.04 3.68 3.75 3.79

 Transportation5 ................... 7.21 6.99 6.94 6.93 7.22 7.23 7.20 7.53 7.59 7.64

 Average6 ....................... 4.16 4.36 4.34 4.34 4.38 4.36 4.34 4.64 4.70 4.74

 Transmission & Distribution Margins7

 Residential ....................... 4.58 4.32 4.31 4.31 4.07 4.08 4.08 3.69 3.69 3.69

 Commercial ...................... 3.37 2.96 2.95 2.95 3.01 3.02 3.02 2.82 2.82 2.83

 Industrial3 ........................ 0.75 0.76 0.76 0.76 0.76 0.76 0.75 0.82 0.82 0.83

 Electric Generators4 ............... 0.48 0.45 0.44 0.43 0.45 0.46 0.45 0.63 0.63 0.63

 Transportation5 ................... 5.10 4.49 4.48 4.48 4.59 4.61 4.61 4.48 4.47 4.48

 Average6 ....................... 2.05 1.87 1.88 1.88 1.75 1.74 1.75 1.59 1.59 1.58

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ....................... 21.61 22.96 22.95 22.96 22.55 22.62 22.63 22.62 22.60 22.58

 Commercial ...................... 10.36 10.71 10.70 10.71 11.40 11.42 11.43 11.32 11.32 11.30

 Industrial3 ........................ 6.00 6.72 6.66 6.66 7.10 7.05 7.01 8.34 8.36 8.43

 Electric Generators4 ............... 1.77 2.35 2.18 2.12 3.03 3.24 3.04 7.00 7.16 7.20

 Transportation5 ................... 0.08 0.24 0.24 0.24 0.42 0.42 0.42 0.69 0.69 0.69

 Total .......................... 39.82 42.98 42.73 42.69 44.49 44.75 44.53 49.97 50.13 50.21

1

Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 111

Table B9. Oil and Gas Supply

Production and Supply 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ..................... 16.49 20.42 20.41 20.41 20.81 20.84 20.81 21.46 21.44 21.46

Production (million barrels per day)

2

 U.S. Total .................................. 5.88 5.60 5.60 5.60 5.15 5.14 5.14 5.01 5.04 5.04

 Lower 48 Onshore ........................... 3.27 2.75 2.75 2.75 2.49 2.48 2.48 2.63 2.65 2.66

 Conventional .............................. 2.59 2.15 2.15 2.15 1.82 1.82 1.82 1.91 1.91 1.91

 Enhanced Oil Recovery ..................... 0.68 0.61 0.61 0.61 0.66 0.66 0.66 0.72 0.74 0.74

 Lower 48 Offshore ........................... 1.56 2.05 2.05 2.05 2.02 2.02 2.02 1.75 1.75 1.74

 Alaska .................................... 1.05 0.79 0.79 0.79 0.64 0.64 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 . 18.33 15.46 15.46 15.46 14.03 14.00 14.00 13.43 13.53 13.53

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ......... 2.08 2.49 2.46 2.45 2.68 2.67 2.63 3.14 3.20 3.25

Production (trillion cubic feet)3

 U.S. Total .................................. 18.67 20.72 20.39 20.35 23.03 23.29 23.04 28.84 28.87 28.94

 Lower 48 Onshore ........................... 12.83 14.33 14.10 14.09 16.32 16.46 16.25 21.20 21.24 21.32

 Associated-Dissolved4 ....................... 1.80 1.51 1.51 1.51 1.34 1.34 1.34 1.35 1.35 1.35

 Non-Associated ............................ 11.03 12.82 12.60 12.58 14.98 15.13 14.91 19.85 19.89 19.96

 Conventional ............................. 6.64 7.19 7.11 7.10 8.31 8.56 8.43 11.38 11.27 11.34

 Unconventional ........................... 4.39 5.62 5.49 5.48 6.66 6.56 6.49 8.48 8.61 8.63

 Lower 48 Offshore ........................... 5.43 5.93 5.81 5.80 6.21 6.32 6.29 7.07 7.06 7.05

 Associated-Dissolved4 ....................... 0.93 1.07 1.07 1.07 1.07 1.07 1.07 1.01 1.01 1.01

 Non-Associated ............................ 4.50 4.85 4.74 4.73 5.13 5.25 5.22 6.06 6.05 6.04

 Alaska .................................... 0.42 0.47 0.47 0.47 0.50 0.50 0.50 0.57 0.57 0.57

Lower 48 End of Year Reserves3

 (trillion cubic feet) .......................... 157.41 166.23 166.49 166.54 174.58 173.17 172.87 188.20 188.97 188.05

 Supplemental Gas Supplies (trillion cubic feet)5 . . 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) .............. 17.94 24.11 23.97 23.74 28.67 28.69 27.86 39.25 40.11 40.39

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
112 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Production1

 Appalachia ............................. 434 422 383 408 412 379 400 395 388 389

 Interior ................................ 185 180 145 163 177 154 156 163 145 141

 West ................................. 485 633 739 691 708 751 753 784 813 829

 East of the Mississippi .................... 561 554 484 519 545 491 515 525 504 500

 West of the Mississippi ................... 543 681 784 743 752 793 795 817 843 859

 Total ................................ 1105 1235 1268 1262 1297 1283 1310 1342 1346 1359

 Net Imports

 Imports ................................ 9 16 16 16 17 17 17 20 20 20

 Exports ................................ 58 60 60 60 58 57 57 56 55 55

 Total ................................. -49 -44 -45 -44 -40 -40 -40 -36 -36 -36

 Total Supply2 ........................... 1055 1191 1223 1218 1256 1243 1270 1306 1311 1323

 Consumption by Sector

 Residential and Commercial ............... 5555555555

 Industrial3 .............................. 79 83 83 83 84 84 84 86 87 87

 Coke Plants ............................ 28 26 26 26 23 23 23 19 19 19

 Electric Generators4 ..................... 922 1078 1109 1105 1145 1133 1160 1198 1204 1213

 Total ................................ 1034 1192 1223 1219 1257 1245 1273 1308 1315 1324

 Discrepancy and Stock Change5

. .......... 21 -1 -0 -1 -1 -2 -3 -2 -4 -1

 Average Minemouth Price

 (1999 dollars per short ton) ................ 17.23 14.76 12.97 13.62 13.69 12.41 12.71 12.84 11.94 11.87

 (1999 dollars per million Btu) ............... 0.82 0.72 0.64 0.67 0.67 0.62 0.63 0.63 0.59 0.59

 

 Delivered Prices (1999 dollars per short ton)6

 Industrial .............................. 31.46 29.43 28.50 29.04 28.41 27.34 27.62 26.55 25.95 25.95

 Coke Plants ............................ 44.20 42.47 42.46 42.33 41.29 41.11 41.19 38.57 38.40 38.43

 Electric Generators

 (1999 dollars per short ton) ............... 24.78 22.62 20.53 20.79 20.84 19.30 19.56 19.40 18.30 18.30

 (1999 dollars per million Btu) ............. 1.22 1.13 1.05 1.05 1.05 0.99 1.00 0.98 0.93 0.93

 Average ............................. 25.82 23.53 21.53 21.81 21.72 20.25 20.48 20.15 19.09 19.09

 Exports7 ............................... 37.43 36.32 35.75 36.07 35.54 34.82 34.94 33.13 32.44 32.47

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators. 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A. Projections: EIA, AEO2001 National Energy Modeling System

runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 113

Table B11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ........... 78.14 78.62 78.62 78.62 78.74 78.74 78.74 78.74 78.74 78.74

 Geothermal2 ..................... 2.87 3.16 3.42 3.41 4.31 4.32 4.36 4.34 4.36 4.42

 Municipal Solid Waste3 ............. 2.59 3.15 3.15 3.01 3.56 3.55 3.41 4.07 4.07 3.98

 Wood and Other Biomass4 .......... 1.52 1.68 1.68 1.68 2.04 2.04 2.04 2.37 2.37 2.37

 Solar Thermal .................... 0.33 0.35 0.35 0.35 0.40 0.40 0.40 0.48 0.48 0.48

 Solar Photovoltaic ................. 0.01 0.09 0.09 0.09 0.21 0.21 0.21 0.54 0.54 0.54

 Wind ........................... 2.60 4.43 4.43 4.43 5.51 5.51 5.51 5.78 5.78 5.77

 Total .......................... 88.07 91.47 91.74 91.58 94.76 94.77 94.67 96.33 96.33 96.30

 Generation (billion kilowatthours)

 Conventional Hydropower ........... 307.43 299.05 299.05 299.05 298.99 298.99 298.99 297.94 297.94 297.94

 Geothermal2 ..................... 13.07 15.90 17.99 17.88 24.98 25.09 25.41 25.33 25.42 25.93

 Municipal Solid Waste3 ............. 18.05 22.30 22.29 21.15 24.94 24.92 23.80 28.85 28.83 28.15

 Wood and Other Biomass4 .......... 8.86 14.45 22.25 13.62 21.55 24.89 23.85 22.15 24.28 23.37

 Dedicated Plants ................ 7.56 8.67 8.67 8.67 10.88 10.88 10.88 13.35 13.35 13.36

 Cofiring ........................ 1.30 5.78 13.59 4.96 10.67 14.01 12.97 8.80 10.93 10.02

 Solar Thermal .................... 0.89 0.96 0.96 0.96 1.11 1.11 1.11 1.37 1.37 1.37

 Solar Photovoltaic ................. 0.03 0.20 0.20 0.20 0.51 0.51 0.51 1.36 1.36 1.36

 Wind ........................... 4.46 9.42 9.42 9.42 12.33 12.33 12.33 13.10 13.10 13.05

 Total .......................... 352.79 362.28 372.16 362.29 384.41 387.83 386.00 390.09 392.30 391.17

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste .............. 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

 Biomass ......................... 4.65 5.17 5.17 5.17 6.06 6.06 6.06 7.54 7.54 7.54

 Total .......................... 5.35 5.87 5.87 5.87 6.76 6.76 6.76 8.23 8.23 8.23

 Generation (billion kilowatthours)

 Municipal Solid Waste .............. 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03

 Biomass ......................... 27.08 29.92 29.92 29.92 35.01 35.01 35.01 43.52 43.52 43.52

 Total .......................... 31.10 33.95 33.95 33.95 39.03 39.03 39.03 47.55 47.55 47.55

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 .......... 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................. 0.01 0.10 0.10 0.10 0.35 0.35 0.35 0.35 0.35 0.35

 Total .......................... 1.00 1.09 1.09 1.09 1.34 1.34 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 .......... 4.57 4.44 4.44 4.44 4.43 4.43 4.43 4.41 4.41 4.41

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................ 0.02 0.20 0.20 0.20 0.75 0.75 0.75 0.75 0.75 0.75

 Total ......................... 4.59 4.64 4.64 4.64 5.18 5.18 5.18 5.17 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
114 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

Marketed Renewable Energy2

 Residential ......................... 0.41 0.43 0.43 0.43 0.43 0.43 0.43 0.44 0.44 0.44

 Wood ............................. 0.41 0.43 0.43 0.43 0.43 0.43 0.43 0.44 0.44 0.44

 Commercial ........................ 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Biomass ........................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Industrial3 ......................... 2.15 2.42 2.42 2.42 2.64 2.64 2.64 3.08 3.08 3.08

 Conventional Hydroelectric ............ 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Biomass ........................... 1.97 2.23 2.23 2.23 2.46 2.46 2.46 2.90 2.90 2.90

 Transportation ...................... 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.23 0.24

 Ethanol used in E854 ................. 0.00 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Ethanol used in Gasoline Blending ...... 0.12 0.18 0.18 0.18 0.19 0.19 0.19 0.20 0.20 0.20

 Electric Generators5 ................. 3.86 4.03 4.18 4.07 4.47 4.51 4.50 4.56 4.58 4.58

 Conventional Hydroelectric ............ 3.17 3.08 3.08 3.08 3.08 3.08 3.08 3.06 3.06 3.06

 Geothermal ........................ 0.27 0.37 0.43 0.43 0.66 0.66 0.67 0.67 0.67 0.69

 Municipal Solid Waste6 ............... 0.25 0.30 0.30 0.29 0.34 0.34 0.32 0.39 0.39 0.38

 Biomass ........................... 0.12 0.18 0.26 0.17 0.26 0.29 0.28 0.27 0.30 0.29

 Dedicated Plants .................. 0.10 0.11 0.10 0.11 0.13 0.13 0.13 0.16 0.16 0.16

 Cofiring .......................... 0.02 0.07 0.16 0.06 0.13 0.16 0.15 0.11 0.13 0.12

 Solar Thermal ...................... 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Wind ............................. 0.05 0.10 0.10 0.10 0.13 0.13 0.13 0.13 0.13 0.13

 Total Marketed Renewable Energy ..... 6.61 7.16 7.31 7.20 7.84 7.88 7.87 8.40 8.42 8.42

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ........................ 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.03 0.03

 Solar Hot Water Heating .............. 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps .............. 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Commercial ........................ 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Thermal ...................... 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.19 0.19 0.19 0.19 0.16 0.16 0.16

 From Cellulose ..................... 0.00 0.01 0.01 0.01 0.02 0.02 0.02 0.07 0.07 0.07

 Total ............................ 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.23 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be

marketed, and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 115

Table B13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Residential

 Petroleum .......................... 26.0 26.8 26.9 26.8 24.4 24.5 24.4 22.9 23.0 22.9

 Natural Gas ......................... 69.5 78.6 78.7 78.8 82.0 82.0 82.1 90.8 90.5 90.4

 Coal ............................... 1.1 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3

 Electricity ........................... 192.6 223.2 222.5 223.6 240.4 236.5 240.9 274.7 274.9 276.0

 Total ............................. 289.3 330.0 329.4 330.5 348.1 344.3 348.7 389.6 389.7 390.6

 Commercial

 Petroleum .......................... 13.7 12.9 12.9 12.9 13.1 13.1 13.1 12.9 12.9 12.9

 Natural Gas ......................... 45.4 53.5 53.6 53.6 56.0 55.9 56.0 59.4 59.3 59.1

 Coal ............................... 1.7 1.8 1.8 1.8 1.9 1.9 1.9 2.0 2.0 2.0

 Electricity ........................... 182.1 216.0 215.3 216.3 237.0 233.7 237.9 265.8 265.9 267.4

 Total ............................. 242.9 284.1 283.5 284.6 307.9 304.6 308.9 340.0 340.0 341.4

 Industrial1

 Petroleum .......................... 104.2 99.0 98.8 98.8 104.7 104.7 104.5 115.6 115.9 115.8

 Natural Gas2 ........................ 141.6 147.8 147.6 147.6 157.6 157.8 157.6 174.9 174.8 175.0

 Coal ............................... 55.9 66.5 66.5 66.6 66.3 66.3 66.3 66.4 66.5 66.6

 Electricity ........................... 178.8 193.9 193.0 193.9 203.0 200.1 203.5 228.1 227.7 229.7

 Total ............................. 480.4 507.2 506.0 506.8 531.6 528.9 531.9 584.9 584.9 587.1

 Transportation

 Petroleum3 .......................... 485.8 556.8 556.9 556.9 608.6 608.6 608.6 705.1 705.0 705.0

 Natural Gas4 ........................ 9.5 11.8 11.7 11.7 14.1 14.3 14.1 17.9 17.9 17.9

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 2.9 4.4 4.4 4.4 5.7 5.7 5.7 7.9 7.9 7.9

 Total3 ............................. 498.2 573.1 573.1 573.0 628.6 628.6 628.5 730.9 730.9 730.9

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 .......................... 629.7 695.5 695.5 695.4 750.8 750.9 750.6 856.4 856.6 856.6

 Natural Gas ......................... 266.0 291.8 291.6 291.6 309.7 310.0 309.9 342.9 342.5 342.5

 Coal ............................... 58.8 69.6 69.6 69.6 69.5 69.5 69.5 69.6 69.8 69.8

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 556.3 637.5 635.2 638.2 686.1 675.9 688.0 776.5 776.4 781.0

 Total3 ............................. 1510. 1694.3 1691.9 1694.9 1816.2 1806.4 1818.0 2045.4 2045.4 2050.0

 Electric Generators6

 Petroleum .......................... 20.0 6.8 5.1 5.8 3.5 2.8 3.0 3.9 2.9 3.0

 Natural Gas ......................... 45.8 77.1 73.0 72.3 98.6 103.9 99.6 164.1 166.6 167.5

 Coal ............................... 490.5 553.6 557.1 560.1 584.0 569.2 585.4 608.4 606.9 610.6

 Total ............................. 556.3 637.5 635.2 638.2 686.1 675.9 688.0 776.5 776.4 781.0

 Total Carbon Dioxide Emissions

 by Primary Fuel7

 Petroleum3 .......................... 649.7 702.2 700.6 701.2 754.3 753.7 753.6 860.3 859.6 859.5

 Natural Gas ......................... 311.8 368.9 364.7 363.9 408.2 414.0 409.5 507.1 509.1 510.0

 Coal ............................... 549.3 623.1 626.6 629.7 653.5 638.7 654.9 678.0 676.7 680.3

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total3 ............................. 1510. 1694.3 1691.9 1694.9 1816.2 1806.4 1818.0 2045.4 2045.4 2050.0

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) .... 5.5 5.9 5.9 5.9 6.1 6.0 6.1 6.3 6.3 6.3

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 25 to 30 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
116 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table B14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999

Projections

2005 2010 2020

Reference SO2 Cap

2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008 Reference SO2 Cap2005

SO2 Cap

2008

 Scrubber Retrofits (gigawatts)1 ............... 0.00 10.76 64.30 30.62 10.76 98.37 95.25 15.24 127.53 129.99

 SO2 Allowance Price

 (1999 dollars per ton) ...................... 0.00 177.63 303.38 106.69 169.55 735.49 283.12 246.09 1083.65 1124.54

 NOx Controls (gigawatts)

 Combustion ............................... 0.00 65.84 65.18 66.07 66.93 66.73 67.23 67.57 67.11 67.45

 SCR ..................................... 0.00 84.31 89.88 92.09 85.97 97.21 97.02 89.75 116.67 124.29

 SNCR ................................... 0.00 25.36 19.69 14.65 28.78 23.45 18.06 38.69 32.32 27.34

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ............... 472.31 598.07 701.98 650.36 656.33 691.47 693.56 730.01 751.46 767.60

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) ......... 433.55 451.27 388.13 438.72 453.06 385.95 401.41 438.05 409.08 408.53

 High Sulfur (> 1.67 lbs. S/mmBtu) .............. 198.66 185.83 177.39 173.09 187.25 205.93 214.85 174.20 185.68 182.71

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here. 

 SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, MCSO205.D121300A, and MCSO208.D121300A.
Appendix C

Tables for CO2 Cap Cases

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 119

Table C1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Production

 Crude Oil and Lease Condensate ... 12.45 11.85 11.78 11.76 10.90 10.93 10.82 10.61 11.46 11.34

 Natural Gas Plant Liquids ......... 2.62 3.02 3.41 3.16 3.31 3.62 3.73 4.07 4.35 4.35

 Dry Natural Gas ................. 19.16 21.26 24.06 22.28 23.63 25.91 26.65 29.59 31.60 31.62

 Coal .......................... 23.12 25.43 17.02 20.61 26.47 14.44 13.86 27.21 12.16 12.07

 Nuclear Power .................. 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.37 7.32

 Renewable Energy1 .............. 6.50 6.98 8.26 8.31 7.65 10.75 11.09 8.20 12.71 12.49

 Other2 ........................ 1.65 0.57 0.35 0.36 0.33 0.30 0.30 0.33 0.34 0.33

 Total ....................... 73.30 77.01 72.78 74.39 79.98 73.87 74.36 86.18 79.99 79.53

 Imports

 Crude Oil3 ..................... 18.96 23.21 22.66 22.99 25.22 24.93 24.98 26.48 25.66 25.74

 Petroleum Products4 ............. 4.14 4.85 4.85 4.79 6.46 6.58 6.44 10.77 10.88 11.04

 Natural Gas .................... 3.63 4.90 5.71 5.50 5.49 6.63 6.70 6.60 8.07 7.98

 Other Imports5 .................. 0.64 1.11 1.02 1.02 0.96 0.89 0.88 0.96 0.82 0.82

 Total ....................... 27.37 34.08 34.25 34.30 38.12 39.03 38.99 44.82 45.43 45.58

 Exports

 Petroleum6 ..................... 1.98 1.81 1.77 1.79 1.79 1.78 1.77 1.90 1.93 1.92

 Natural Gas .................... 0.17 0.33 0.12 0.12 0.43 0.12 0.12 0.63 0.12 0.12

 Coal .......................... 1.48 1.51 1.51 1.51 1.45 1.43 1.42 1.41 1.44 1.44

 Total ....................... 3.62 3.64 3.40 3.43 3.67 3.33 3.32 3.94 3.48 3.48

 Discrepancy7 .................... 0.95 0.39 0.22 0.24 0.21 0.20 0.21 -0.03 0.03 0.07

 Consumption

 Petroleum Products8 ............. 38.07 41.40 41.11 41.09 44.43 44.59 44.52 50.60 50.95 51.01

 Natural Gas .................... 21.90 25.78 29.58 27.61 28.52 32.21 33.03 35.40 39.36 39.29

 Coal .......................... 21.46 24.37 15.94 19.50 25.54 13.38 12.76 26.48 11.14 11.05

 Nuclear Power ................. . 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.37 7.32

 Renewable Energy1 .............. 6.51 6.98 8.26 8.31 7.66 10.76 11.10 8.21 12.72 12.50

 Other9 ........................ 0.35 0.61 0.62 0.61 0.38 0.52 0.51 0.25 0.38 0.38

 Total ........................ 96.09 107.05 103.41 105.02 114.21 109.37 109.82 127.10 121.91 121.56

 Net Imports - Petroleum ........... 21.12 26.26 25.74 25.99 29.88 29.73 29.64 35.36 34.62 34.85

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 . . 17.35 20.83 20.83 20.83 21.37 21.37 21.37 22.41 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 2.08 2.49 3.45 2.97 2.68 4.36 4.13 3.14 4.22 4.38

 Coal Minemouth Price (dollars per ton) 17.23 14.76 14.78 14.82 13.69 13.77 13.72 12.84 12.55 12.54

 Average Electric Price (cents per Kwh) 6.6 6.2 8.2 7.3 5.9 8.3 8.2 6.0 7.9 7.9

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
120 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

Energy Consumption

 Residential

 Distillate Fuel ........................ 0.86 0.88 0.89 0.89 0.81 0.81 0.81 0.75 0.77 0.77

 Kerosene ........................... 0.10 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas ............... 0.46 0.45 0.46 0.46 0.41 0.42 0.42 0.39 0.41 0.41

 Petroleum Subtotal .................. 1.42 1.42 1.43 1.42 1.29 1.31 1.31 1.21 1.25 1.24

 Natural Gas ......................... 4.85 5.46 5.30 5.38 5.69 5.37 5.44 6.30 6.04 6.02

 Coal ............................... 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

 Renewable Energy1 ................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Electricity ........................... 3.91 4.50 4.24 4.34 4.96 4.55 4.57 5.80 5.38 5.38

 Delivered Energy ................... 10.62 11.86 11.44 11.62 12.42 11.71 11.79 13.80 13.13 13.10

 Electricity Related Losses .............. 8.46 9.46 8.55 8.95 9.88 8.68 8.76 10.58 9.27 9.18

 Total ............................. 19.08 21.32 20.00 20.57 22.30 20.39 20.55 24.38 22.40 22.29

 Commercial

 Distillate Fuel ........................ 0.36 0.41 0.42 0.41 0.41 0.47 0.44 0.39 0.51 0.49

 Residual Fuel ....................... 0.10 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.11

 Kerosene ........................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas ............... 0.08 0.09 0.09 0.09 0.09 0.09 0.09 0.10 0.10 0.10

 Motor Gasoline2 ...................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal .................. 0.59 0.66 0.67 0.66 0.67 0.72 0.70 0.66 0.77 0.75

 Natural Gas ......................... 3.15 3.71 3.57 3.64 3.89 3.59 3.65 4.12 4.01 3.98

 Coal ............................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.08

 Renewable Energy3 ................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Electricity ........................... 3.70 4.35 4.07 4.20 4.89 4.49 4.53 5.61 5.16 5.17

 Delivered Energy ................... 7.59 8.87 8.46 8.65 9.60 8.96 9.03 10.55 10.11 10.06

 Electricity Related Losses .............. 8.00 9.15 8.22 8.64 9.74 8.57 8.70 10.23 8.90 8.84

 Total ............................. 15.59 18.02 16.69 17.29 19.34 17.53 17.73 20.79 19.01 18.90

 Industrial4

 Distillate Fuel ........................ 1.07 1.13 1.12 1.12 1.27 1.29 1.27 1.44 1.46 1.46

 Liquefied Petroleum Gas ............... 2.32 2.45 2.47 2.45 2.50 2.64 2.66 2.83 3.01 3.09

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.52 1.70 1.69 1.69

 Residual Fuel ....................... 0.22 0.22 0.33 0.23 0.25 0.39 0.38 0.27 0.41 0.41

 Motor Gasoline2 ...................... 0.21 0.23 0.22 0.23 0.25 0.24 0.24 0.28 0.28 0.28

 Other Petroleum5 ..................... 4.29 4.49 4.49 4.49 4.76 4.84 4.85 5.25 5.41 5.42

 Petroleum Subtotal .................. 9.39 9.95 10.04 9.93 10.55 10.93 10.92 11.78 12.26 12.36

 Natural Gas6 ........................ 9.43 10.42 10.33 10.45 11.11 10.81 10.83 12.33 12.30 12.02

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.60 0.60 0.50 0.50 0.50

 Steam Coal ......................... 1.73 1.82 1.84 1.83 1.85 1.93 1.91 1.89 2.00 2.00

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.15 0.22 0.23 0.23

 Coal Subtotal ....................... 2.54 2.62 2.64 2.63 2.61 2.69 2.67 2.62 2.72 2.72

 Renewable Energy7 ................... 2.15 2.42 2.39 2.40 2.64 2.64 2.63 3.08 3.12 3.12

 Electricity ........................... 3.63 3.90 3.77 3.82 4.19 3.94 3.96 4.81 4.29 4.34

 Delivered Energy ................... 27.15 29.32 29.17 29.24 31.10 31.01 31.01 34.62 34.70 34.55

 Electricity Related Losses .............. 7.85 8.22 7.60 7.88 8.34 7.51 7.59 8.78 7.40 7.41

 Total ............................. 35.00 37.53 36.77 37.12 39.45 38.51 38.60 43.40 42.09 41.96
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 121

Table C2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Transportation

 Distillate Fuel ........................ 5.13 6.28 6.13 6.19 6.99 6.87 6.84 8.21 8.09 8.08

 Jet Fuel8 ........................... 3.46 3.90 3.85 3.87 4.51 4.49 4.48 5.97 5.96 5.96

 Motor Gasoline2 ...................... 15.92 17.70 17.59 17.64 19.05 18.94 18.94 21.32 21.24 21.25

 Residual Fuel ....................... 0.74 0.85 0.85 0.85 0.85 0.85 0.85 0.87 0.86 0.86

 Liquefied Petroleum Gas ............... 0.02 0.03 0.03 0.03 0.04 0.04 0.04 0.06 0.06 0.06

 Other Petroleum9 ..................... 0.26 0.29 0.29 0.29 0.31 0.31 0.31 0.35 0.35 0.35

 Petroleum Subtotal .................. 25.54 29.06 28.75 28.88 31.75 31.50 31.47 36.77 36.57 36.56

 Pipeline Fuel Natural Gas .............. 0.66 0.77 0.87 0.82 0.89 0.98 1.00 1.08 1.20 1.20

 Compressed Natural Gas .............. 0.02 0.06 0.05 0.06 0.09 0.09 0.09 0.16 0.15 0.15

 Renewable Energy (E85)10 ............. 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 0.06 0.09 0.09 0.09 0.12 0.12 0.12 0.17 0.17 0.17

 Delivered Energy ................... 26.28 29.99 29.78 29.86 32.89 32.72 32.71 38.23 38.13 38.13

 Electricity Related Losses .............. 0.13 0.19 0.18 0.18 0.24 0.22 0.23 0.30 0.29 0.28

 Total ............................. 26.41 30.18 29.96 30.04 33.12 32.94 32.94 38.53 38.41 38.41

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ........................ 7.42 8.70 8.56 8.61 9.47 9.44 9.37 10.80 10.82 10.79

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.85 3.87 4.51 4.49 4.48 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.05 3.03 3.05 3.20 3.22 3.38 3.58 3.66

 Motor Gasoline2 ...................... 16.17 17.96 17.84 17.89 19.32 19.21 19.22 21.63 21.55 21.56

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.52 1.70 1.69 1.69

 Residual Fuel ....................... 1.05 1.17 1.28 1.18 1.21 1.34 1.34 1.25 1.38 1.38

 Other Petroleum12 .................... 4.53 4.76 4.76 4.76 5.04 5.12 5.13 5.58 5.74 5.75

 Petroleum Subtotal .................. 36.95 41.08 40.89 40.89 44.26 44.46 44.40 50.42 50.85 50.91

 Natural Gas6 ........................ 18.11 20.42 20.12 20.34 21.67 20.84 21.00 24.00 23.70 23.36

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.60 0.60 0.50 0.50 0.50

 Steam Coal ......................... 1.84 1.94 1.96 1.95 1.98 2.05 2.04 2.02 2.12 2.12

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.15 0.22 0.23 0.23

 Coal Subtotal ....................... 2.65 2.74 2.76 2.75 2.74 2.81 2.80 2.74 2.85 2.85

 Renewable Energy13 .................. 2.65 2.95 2.92 2.93 3.19 3.18 3.17 3.65 3.66 3.67

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 11.29 12.84 12.16 12.45 14.15 13.10 13.17 16.39 15.00 15.05

 Delivered Energy ................... 71.65 80.04 78.85 79.37 86.01 84.39 84.54 97.20 96.06 95.85

 Electricity Related Losses .............. 24.44 27.02 24.56 25.65 28.20 24.98 25.28 29.89 25.85 25.71

 Total ............................. 96.09 107.05 103.41 105.02 114.21 109.37 109.82 127.10 121.91 121.56

 Electric Generators14

 Distillate Fuel ........................ 0.06 0.05 0.04 0.03 0.04 0.03 0.03 0.04 0.02 0.02

 Residual Fuel ....................... 1.07 0.27 0.17 0.17 0.13 0.10 0.09 0.14 0.08 0.08

 Petroleum Subtotal .................. 1.13 0.32 0.22 0.20 0.17 0.13 0.12 0.19 0.10 0.10

 Natural Gas ......................... 3.79 5.36 9.46 7.26 6.84 11.38 12.03 11.40 15.65 15.93

 Steam Coal ......................... 18.81 21.63 13.19 16.75 22.80 10.57 9.97 23.73 8.29 8.21

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.37 7.32

 Renewable Energy15 .................. 3.86 4.03 5.34 5.38 4.47 7.58 7.93 4.56 9.06 8.83

 Electricity Imports16 ................... 0.35 0.61 0.62 0.61 0.37 0.51 0.50 0.24 0.37 0.37

 Total ............................. 35.73 39.85 36.72 38.10 42.35 38.08 38.45 46.28 40.85 40.76
122 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Total Energy Consumption

 Distillate Fuel ........................ 7.48 8.75 8.60 8.64 9.51 9.46 9.40 10.84 10.84 10.81

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.85 3.87 4.51 4.49 4.48 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.05 3.03 3.05 3.20 3.22 3.38 3.58 3.66

 Motor Gasoline2 ...................... 16.17 17.96 17.84 17.89 19.32 19.21 19.22 21.63 21.55 21.56

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.52 1.70 1.69 1.69

 Residual Fuel ....................... 2.12 1.44 1.45 1.35 1.34 1.44 1.43 1.39 1.46 1.46

 Other Petroleum12 .................... 4.53 4.76 4.76 4.76 5.04 5.12 5.13 5.58 5.74 5.75

 Petroleum Subtotal .................. 38.07 41.40 41.11 41.09 44.43 44.59 44.52 50.60 50.95 51.01

 Natural Gas ......................... 21.90 25.78 29.58 27.61 28.52 32.21 33.03 35.40 39.36 39.29

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.60 0.60 0.50 0.50 0.50

 Steam Coal ......................... 20.65 23.57 15.15 18.70 24.77 12.62 12.01 25.75 10.42 10.33

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.15 0.22 0.23 0.23

 Coal Subtotal ....................... 21.46 24.37 15.94 19.50 25.54 13.38 12.76 26.48 11.14 11.05

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.37 7.32

 Renewable Energy17 .................. 6.51 6.98 8.26 8.31 7.66 10.76 11.10 8.21 12.72 12.50

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 ................... 0.35 0.61 0.62 0.61 0.37 0.51 0.50 0.24 0.37 0.37

 Total ............................. 96.09 107.05 103.41 105.02 114.21 109.37 109.82 127.10 121.91 121.56

Energy Use and Related Statistics

 Delivered Energy Use .................. 71.65 80.04 78.85 79.37 86.01 84.39 84.54 97.20 96.06 95.85

 Total Energy Use ..................... 96.09 107.05 103.41 105.02 114.21 109.37 109.82 127.10 121.91 121.56

 Population (millions) .................... 273.13 288.02 288.02 288.02 300.17 300.17 300.17 325.24 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 10960 10834 10885 12667 12628 12606 16515 16521 16523

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) ..... 1510.8 1694.3 1528.0 1589.9 1816.2 1560.6 1555.1 2045.4 1714.7 1712.6

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which provides electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDC7B05.D121300A, and FDC7B08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 123

Table C3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Residential ......................... 13.12 12.91 15.21 14.24 13.15 16.55 16.38 13.59 16.27 16.39

 Primary Energy1 .................... 6.72 7.12 7.74 7.44 7.00 8.23 8.03 7.02 7.92 8.02

 Petroleum Products2 ................ 7.55 9.18 9.18 9.18 9.37 9.36 9.29 9.66 9.73 9.79

 Distillate Fuel ..................... 6.27 7.34 7.33 7.33 7.51 7.46 7.46 7.99 8.01 8.01

 Liquefied Petroleum Gas ............ 10.36 12.83 12.85 12.84 13.06 13.09 12.88 12.90 13.03 13.23

 Natural Gas ....................... 6.52 6.63 7.41 7.04 6.52 8.02 7.79 6.56 7.59 7.71

 Electricity .......................... 23.46 21.84 27.16 24.96 21.88 28.85 28.80 22.16 27.66 27.76

 Commercial ........................ 13.20 12.36 16.10 14.48 11.74 16.45 16.16 12.37 15.67 15.88

 Primary Energy1 .................... 5.22 5.35 6.00 5.69 5.53 6.72 6.55 5.76 6.59 6.70

 Petroleum Products2 ................ 5.00 6.01 5.99 6.00 6.17 6.07 6.07 6.52 6.41 6.46

 Distillate Fuel ..................... 4.37 5.13 5.11 5.12 5.28 5.22 5.22 5.77 5.75 5.77

 Residual Fuel .................... 2.63 3.64 3.62 3.62 3.69 3.69 3.69 3.85 3.84 3.84

 Natural Gas3 ...................... 5.34 5.31 6.09 5.72 5.49 6.96 6.74 5.72 6.73 6.85

 Electricity .......................... 21.43 19.51 26.78 23.64 17.61 25.95 25.53 18.09 24.23 24.41

 Industrial4 .......................... 5.32 5.49 6.54 6.07 5.44 6.91 6.78 5.85 6.86 6.98

 Primary Energy ..................... 3.92 4.25 4.62 4.43 4.37 5.05 4.94 4.73 5.22 5.32

 Petroleum Products2 ................ 5.55 5.95 5.94 5.95 6.05 6.10 6.04 6.28 6.36 6.45

 Distillate Fuel ..................... 4.65 5.29 5.29 5.29 5.46 5.41 5.40 5.98 5.98 6.01

 Liquefied Petroleum Gas ............ 8.50 7.94 8.00 7.96 8.00 8.21 8.00 7.86 8.15 8.35

 Residual Fuel .................... 2.78 3.37 3.25 3.35 3.42 3.34 3.33 3.58 3.49 3.49

 Natural Gas5 ...................... 2.79 3.17 4.05 3.62 3.30 4.84 4.64 3.77 4.84 4.97

 Metallurgical Coal .................. 1.65 1.58 1.59 1.59 1.54 1.54 1.54 1.44 1.43 1.44

 Steam Coal ....................... 1.43 1.34 1.27 1.31 1.29 1.19 1.18 1.21 1.07 1.06

 Electricity .......................... 13.01 12.30 17.44 15.27 11.21 17.65 17.32 11.60 16.46 16.54

 Transportation ...................... 8.30 9.27 9.31 9.29 9.45 9.56 9.54 9.32 9.34 9.34

 Primary Energy ..................... 8.29 9.25 9.29 9.27 9.44 9.53 9.52 9.30 9.31 9.32

 Petroleum Products2 ................ 8.28 9.25 9.29 9.27 9.44 9.52 9.51 9.30 9.30 9.31

 Distillate Fuel6 .................... 8.22 8.89 8.90 8.90 8.94 8.92 8.92 9.02 9.03 9.07

 Jet Fuel7 ........................ 4.70 5.24 5.23 5.23 5.46 5.46 5.46 5.88 5.88 5.88

 Motor Gasoline8 ................... 9.45 10.64 10.70 10.66 10.92 11.07 11.05 10.68 10.68 10.68

 Residual Fuel .................... 2.46 3.10 3.11 3.10 3.18 3.18 3.18 3.33 3.33 3.33

 Liquid Petroleum Gas9 .............. 12.87 14.19 14.30 14.24 14.24 14.37 14.22 13.88 14.03 14.22

 Natural Gas10 ...................... 7.02 6.80 7.63 7.22 7.03 8.50 8.33 7.33 8.31 8.41

 Ethanol (E85)11 .................... 14.42 19.12 19.21 19.15 19.00 19.27 19.22 19.36 19.50 19.51

 Methanol (M85)12 ................... 10.38 13.11 13.84 13.27 13.74 14.25 14.24 14.43 14.42 14.42

 Electricity .......................... 15.58 14.29 16.82 15.66 13.53 16.57 16.54 13.03 15.08 15.12

 Average End-Use Energy ............. 8.53 8.90 10.02 9.54 8.94 10.45 10.35 9.17 10.22 10.31

 Primary Energy ..................... 6.33 7.00 7.26 7.13 7.18 7.65 7.58 7.31 7.61 7.67

 Electricity .......................... 19.40 18.10 23.95 21.47 17.18 24.38 24.12 17.57 23.14 23.24

 Electric Generators13

 Fossil Fuel Average .................. 1.49 1.50 2.21 1.75 1.52 2.85 2.84 1.85 3.37 3.48

 Petroleum Products ................. 2.50 3.70 3.80 3.79 4.06 4.13 4.18 4.33 4.62 4.66

 Distillate Fuel ..................... 4.04 4.65 4.68 4.68 4.85 4.82 4.82 5.30 5.26 5.27

 Residual Fuel .................... 2.41 3.52 3.59 3.62 3.85 3.94 3.98 4.04 4.44 4.48

 Natural Gas ....................... 2.54 2.89 3.89 3.35 3.02 4.63 4.43 3.61 4.72 4.85

 Steam Coal ....................... 1.22 1.13 0.99 1.02 1.05 0.92 0.91 0.98 0.82 0.81
124 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Average Price to All Users14

 Petroleum Products2 ................. 7.43 8.43 8.46 8.46 8.63 8.68 8.66 8.62 8.63 8.66

 Distillate Fuel ...................... 7.27 8.07 8.06 8.07 8.18 8.12 8.13 8.41 8.39 8.43

 Jet Fuel .......................... 4.70 5.24 5.23 5.23 5.46 5.46 5.46 5.88 5.88 5.88

 Liquefied Petroleum Gas ............. 8.84 8.83 8.89 8.86 8.87 9.03 8.81 8.64 8.89 9.07

 Motor Gasoline8 .................... 9.45 10.64 10.70 10.66 10.92 11.07 11.05 10.68 10.68 10.68

 Residual Fuel ..................... 2.48 3.26 3.23 3.25 3.33 3.31 3.31 3.49 3.48 3.48

 Natural Gas ....................... 4.05 4.25 4.93 4.58 4.27 5.60 5.38 4.52 5.47 5.60

 Coal .............................. 1.24 1.15 1.02 1.05 1.07 0.96 0.96 1.00 0.87 0.86

 Ethanol (E85)11 ..................... 14.42 19.12 19.21 19.15 19.00 19.27 19.22 19.36 19.50 19.51

 Methanol (M85)12 .................... 10.38 13.11 13.84 13.27 13.74 14.25 14.24 14.43 14.42 14.42

 Electricity .......................... 19.40 18.10 23.95 21.47 17.18 24.38 24.12 17.57 23.14 23.24

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ........................... 134.05 147.53 167.57 159.41 157.75 186.79 186.11 181.60 206.82 207.83

 Commercial .......................... 99.10 108.63 134.92 124.07 111.63 146.05 144.67 129.48 157.13 158.50

 Industrial ............................ 110.62 121.27 145.04 134.69 126.35 162.03 158.69 151.05 178.64 181.09

 Transportation ........................ 212.64 270.40 268.97 269.40 301.90 302.66 302.02 345.30 343.93 344.18

 Total Non-Renewable Expenditures ..... 556.41 647.83 716.50 687.57 697.64 797.53 791.49 807.43 886.52 891.60

 Transportation Renewable Expenditures . . 0.14 0.42 0.41 0.41 0.61 0.62 0.61 0.86 0.86 0.86

 Total Expenditures .................. 556.55 648.25 716.91 687.99 698.25 798.15 792.10 808.29 887.38 892.46

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report,

DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and

FDC7B08.D121300A. 1999 electricity prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDC7B05.D121300A, and FDC7B08.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and

FDC7B08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 125

Table C4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

Generation by Fuel Type

 Electric Generators1

 Coal ............................ 1835 2103 1319 1656 2232 1061 1003 2317 835 825

 Petroleum ....................... 104 32 23 21 18 14 13 19 11 11

 Natural Gas2 ..................... 365 574 1075 827 867 1527 1603 1568 2201 2271

 Nuclear Power .................... 730 740 740 740 720 741 741 577 690 686

 Pumped Storage .................. -1 -1 -1 -1 -1 -1 -1 -1 -1 -1

 Renewable Sources3 ............... 353 362 439 444 384 530 537 390 659 626

 Total .......................... 3386 3811 3594 3687 4220 3872 3896 4872 4396 4418

 Non-Utility Generation for Own Use ... 16 16 22 21 16 21 20 16 20 20

 Distributed Generation ............. 0100300600

 Cogenerators4

 Coal ........................... 47 52 52 52 52 52 52 52 51 51

 Petroleum ...................... 9 10 10 10 10 10 10 10 10 10

 Natural Gas ..................... 206 239 265 256 256 331 319 298 503 477

 Other Gaseous Fuels5 ............. 4666777888

 Renewable Sources3 .............. 31 34 33 34 39 39 39 48 48 48

 Other6 ......................... 5555555555

 Total ......................... 302 347 372 363 369 444 432 421 626 600

 Other End-Use Generators7 ......... 5555555555

 Sales to Utilities .................. 150 171 179 177 176 191 191 200 246 239

 Generation for Own Use ............ 156 180 197 191 198 258 246 226 384 366

 Net Imports8 ...................... 33 57 59 57 35 49 47 23 35 35

Electricity Sales by Sector

 Residential ........................ 1146 1317 1242 1273 1452 1335 1339 1699 1576 1575

 Commercial ....................... 1083 1275 1194 1230 1432 1317 1329 1644 1513 1516

 Industrial ......................... 1063 1144 1104 1121 1227 1154 1159 1411 1258 1271

 Transportation ..................... 17 26 26 26 35 34 34 49 48 48

 Total ........................... 3309 3762 3565 3649 4146 3839 3861 4803 4396 4411

End-Use Prices (1999 cents per kwh)9

 Residential ........................ 8.0 7.5 9.3 8.5 7.5 9.8 9.8 7.6 9.4 9.5

 Commercial ....................... 7.3 6.7 9.1 8.1 6.0 8.9 8.7 6.2 8.3 8.3

 Industrial ......................... 4.4 4.2 6.0 5.2 3.8 6.0 5.9 4.0 5.6 5.6

 Transportation ..................... 5.3 4.9 5.7 5.3 4.6 5.7 5.6 4.4 5.1 5.2

 All Sectors Average .............. 6.6 6.2 8.2 7.3 5.9 8.3 8.2 6.0 7.9 7.9

 Prices by Service Category 9

 (1999 cents per kwh)

 Generation ....................... 4.1 3.6 5.5 4.7 3.2 5.5 5.4 3.4 5.2 5.2

 Transmission ..................... 0.6 0.6 0.7 0.7 0.7 0.8 0.8 0.7 0.7 0.7

 Distribution ...................... 2.0 2.0 2.0 2.0 2.0 2.1 2.1 2.0 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide ..................... 13.82 10.39 9.30 10.39 9.70 8.09 7.77 8.95 6.68 6.61

 Nitrogen Oxide .................... 5.46 4.22 3.07 3.58 4.20 2.47 2.33 4.37 2.01 1.95

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
126 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

Electric Generators2

 Capability

 Coal Steam ................... 306.2 302.4 297.9 298.2 317.4 261.9 269.3 317.8 240.6 236.7

 Other Fossil Steam3 ............ 138.2 129.6 124.5 124.0 121.1 102.6 105.2 117.2 96.3 93.0

 Combined Cycle ............... 20.2 49.4 85.7 70.5 124.0 182.0 185.6 230.0 269.9 282.4

 Combustion Turbine/Diesel ....... 75.6 129.7 106.7 111.8 162.1 111.8 123.1 207.7 157.6 163.7

 Nuclear Power ................. 97.4 97.5 97.5 97.5 94.2 96.9 96.9 71.6 89.2 88.4

 Pumped Storage ............... 19.3 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 88.1 91.5 97.0 96.3 94.8 108.7 109.4 96.3 142.2 134.2

 Distributed Generation5 .......... 0.0 2.0 1.8 2.3 6.1 2.8 4.0 14.0 5.8 6.7

 Total ....................... 745.0 821.5 830.5 820.0 939.4 886.1 913.0 1074.3 1021.4 1024.9

 Cumulative Planned Additions6

 Coal Steam ................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Combined Cycle ............... 0.0 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ....... 0.0 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 0.0 2.4 2.4 2.4 4.3 4.3 4.3 5.4 5.4 5.4

 Distributed Generation5 .......... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Total ....................... 0.0 11.5 11.5 11.5 13.6 13.6 13.6 14.8 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam ................... 0.0 2.5 0.0 0.0 20.1 0.0 0.0 21.5 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Combined Cycle ............... 0.0 20.8 57.1 41.9 95.7 153.9 157.2 201.6 242.0 254.4

 Combustion Turbine/Diesel ...... . 0.0 57.0 35.3 40.3 90.8 43.7 53.5 137.2 89.9 95.8

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ............ 0.0 0.6 6.1 5.4 1.9 15.8 16.6 2.4 48.3 40.3

 Distributed Generation5 0.0 2.0 1.8 2.3 6.1 2.8 4.0 14.0 5.8 6.7

 Total ....................... 0.0 82.9 100.3 89.9 214.6 216.3 231.2 376.7 386.0 397.2

 Cumulative Total Additions ...... 0.0 94.5 111.9 101.5 228.1 229.8 244.8 391.4 400.8 412.0

 Cumulative Retirements7 ........

 Coal Steam ................... 0.0 6.6 8.6 8.3 9.2 44.6 37.2 10.2 65.9 69.8

 Other Fossil Steam3 ............ 0.0 8.5 13.6 14.1 17.0 35.5 32.9 20.9 41.8 45.1

 Combined Cycle ............... 0.0 0.0 0.0 0.0 0.3 0.6 0.3 0.3 0.8 0.6

 Combustion Turbine/Diesel ....... 0.0 3.8 4.6 4.5 5.1 7.9 6.4 5.9 8.2 8.1

 Nuclear Power ................. 0.0 0.0 0.0 0.0 3.3 0.6 0.6 25.9 8.3 9.1

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total ....................... 0.0 19.0 26.9 27.1 34.9 89.4 77.5 63.4 125.1 132.8

Cogenerators8

 Capability

 Coal ......................... 8.4 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9

 Petroleum .................... 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 2.8

 Natural Gas ................... 33.8 40.0 42.7 41.7 42.9 52.6 50.7 48.8 76.6 73.2

 Other Gaseous Fuels ........... 0.2 0.8 0.8 0.8 0.9 0.9 0.9 1.0 1.1 1.1

 Renewable Sources4 ............ 5.3 5.9 5.8 5.8 6.8 6.8 6.7 8.2 8.3 8.4

 Other ........................ 1.1 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

 Total ....................... 51.6 59.2 61.8 60.8 63.1 72.8 70.9 70.7 98.6 95.3

 Cumulative Additions6 .......... 0.0 7.5 10.1 9.2 11.4 21.2 19.3 19.0 47.0 43.7
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 127

Table C5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

Other End-Use Generators9

 Renewable Sources ............. 1.0 1.1 1.1 1.1 1.3 1.3 1.3 1.3 1.3 1.3

 Cumulative Additions ............ 0.0 0.1 0.1 0.1 0.3 0.3 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 6

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31,1999.

 7

Cumulative total retirements after December 31, 1999.

 8

Nameplate capacity is reported for nonutilities on Form EIA-860B, “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
128 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade .......... 182.2 125.3 125.3 125.3 102.9 102.9 102.9 0.0 0.0 0.0

 Gross Domestic Economy Trade ........... 147.8 202.8 55.9 93.3 183.2 125.6 103.1 206.7 162.0 159.6

 Gross Domestic Trade ................. 330.0 328.1 181.2 218.5 286.1 228.5 206.0 206.7 162.0 159.6

 Gross Domestic Firm Power Sales

 (million 1999 dollars) .................... 8588.1 5905.8 5905.8 5905.8 4851.2 4851.2 4851.2 0.0 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) .................... 4292.5 6044.9 2690.3 3715.2 4987.6 6058.6 4798.0 6227.5 7388.7 7277.4

 Gross Domestic Sales

 (million 1999 dollars) .................. 12880.6 11950.7 8596.1 9621.0 9838.8 10909.8 9649.2 6227.5 7388.7 7277.4

 International Electricity Trade

 Firm Power Imports From Canada and Mexico1

 27.0 10.7 11.8 10.7 5.8 19.1 17.9 0.0 12.1 12.1

 Economy Imports From Canada and Mexico1 . . 21.9 63.5 63.5 63.5 45.9 45.9 45.9 30.6 30.6 30.6

 Gross Imports From Canada and Mexico1 . . 48.9 74.1 75.3 74.1 51.7 65.0 63.8 30.6 42.7 42.7

 Firm Power Exports To Canada and Mexico . . 9.2 9.7 9.7 9.7 8.7 8.7 8.7 0.0 0.0 0.0

 Economy Exports To Canada and Mexico .... 6.3 7.0 7.0 7.0 7.7 7.7 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico .... 15.5 16.7 16.7 16.7 16.4 16.4 16.4 7.7 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 129

Table C7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Production

 Dry Gas Production1 ......... 18.67 20.72 23.46 21.72 23.03 25.25 25.98 28.84 30.79 30.82

 Supplemental Natural Gas2 .... 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Net Imports ................ 3.38 4.47 5.46 5.26 4.94 6.36 6.43 5.83 7.77 7.68

 Canada ................... 3.29 4.28 4.69 4.51 4.68 5.27 5.36 5.46 6.10 6.11

 Mexico .................... -0.01 -0.18 0.30 0.30 -0.25 0.32 0.32 -0.40 0.36 0.36

 Liquefied Natural Gas ........ 0.10 0.37 0.47 0.45 0.51 0.77 0.74 0.77 1.31 1.22

 Total Supply ................ 22.15 25.30 29.03 27.09 28.03 31.67 32.46 34.72 38.62 38.56

 Consumption by Sector

 Residential ................. 4.72 5.32 5.16 5.24 5.54 5.23 5.29 6.14 5.88 5.86

 Commercial ................ 3.07 3.62 3.48 3.55 3.78 3.50 3.55 4.02 3.91 3.87

 Industrial3 .................. 7.95 8.80 8.58 8.78 9.33 8.93 8.91 10.17 10.06 9.78

 Electric Generators4 ......... 3.72 5.26 9.28 7.13 6.72 11.17 11.80 11.19 15.36 15.63

 Lease and Plant Fuel5 ........ 1.23 1.35 1.48 1.39 1.49 1.60 1.63 1.83 1.93 1.93

 Pipeline Fuel ............... 0.64 0.75 0.84 0.80 0.87 0.95 0.98 1.06 1.17 1.17

 Transportation6 ............. 0.02 0.05 0.05 0.05 0.09 0.09 0.09 0.15 0.14 0.14

 Total .................... 21.35 25.14 28.87 26.94 27.82 31.46 32.25 34.55 38.44 38.38

 Discrepancy7 ............... 0.80 0.16 0.16 0.15 0.21 0.21 0.21 0.17 0.18 0.18

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A. Other 1999

consumption: EIA, Short-Term Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption

levels for consumption of natural gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A,

and FDC7B08.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
130 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Source Price 

 Average Lower 48 Wellhead Price1 .... 2.08 2.49 3.45 2.97 2.68 4.36 4.13 3.14 4.22 4.38

 Average Import Price ............... 2.29 2.48 2.82 2.71 2.41 2.92 2.85 2.67 3.23 3.25

 Average2 ....................... 2.11 2.49 3.33 2.92 2.63 4.07 3.87 3.05 4.02 4.15

 Delivered Prices

 Residential ....................... 6.69 6.81 7.61 7.23 6.70 8.23 8.00 6.74 7.80 7.92

 Commercial ...................... 5.49 5.45 6.26 5.87 5.64 7.15 6.93 5.87 6.91 7.04

 Industrial3 ........................ 2.87 3.26 4.16 3.72 3.39 4.97 4.76 3.87 4.97 5.11

 Electric Generators4 ............... 2.59 2.94 3.97 3.41 3.08 4.72 4.51 3.68 4.81 4.95

 Transportation5 ................... 7.21 6.99 7.83 7.41 7.22 8.73 8.55 7.53 8.53 8.64

 Average6 ....................... 4.16 4.36 5.05 4.70 4.38 5.75 5.52 4.64 5.61 5.74

 Transmission & Distribution Margins7

 Residential ....................... 4.58 4.32 4.28 4.31 4.07 4.16 4.13 3.69 3.78 3.77

 Commercial ...................... 3.37 2.96 2.93 2.96 3.01 3.08 3.05 2.82 2.90 2.88

 Industrial3 ........................ 0.75 0.76 0.83 0.80 0.76 0.90 0.89 0.82 0.95 0.95

 Electric Generators4 ............... 0.48 0.45 0.63 0.50 0.45 0.65 0.64 0.63 0.79 0.79

 Transportation5 ................... 5.10 4.49 4.50 4.49 4.59 4.66 4.68 4.48 4.51 4.49

 Average6 ....................... 2.05 1.87 1.72 1.78 1.75 1.68 1.65 1.59 1.59 1.59

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ....................... 21.61 22.96 22.10 22.59 22.55 21.77 21.85 22.62 22.22 22.07

 Commercial ...................... 10.36 10.71 10.17 10.49 11.40 10.76 10.84 11.32 11.32 11.17

 Industrial3 ........................ 6.00 6.72 7.11 7.04 7.10 8.01 7.91 8.34 9.56 9.33

 Electric Generators4 ............... 1.77 2.35 5.89 3.55 3.03 7.28 7.56 7.00 12.10 12.40

 Transportation5 ................... 0.08 0.24 0.24 0.24 0.42 0.40 0.41 0.69 0.64 0.64

 Total .......................... 39.82 42.98 45.51 43.91 44.49 48.22 48.58 49.97 55.85 55.60

1

Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 131

Table C9. Oil and Gas Supply

Production and Supply 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ..................... 16.49 20.42 20.39 20.39 20.81 20.72 20.73 21.46 21.46 21.46

Production (million barrels per day)

2

 U.S. Total .................................. 5.88 5.60 5.56 5.56 5.15 5.16 5.11 5.01 5.42 5.36

 Lower 48 Onshore ........................... 3.27 2.75 2.77 2.76 2.49 2.56 2.53 2.63 2.74 2.75

 Conventional .............................. 2.59 2.15 2.17 2.16 1.82 1.95 1.90 1.91 2.10 2.10

 Enhanced Oil Recovery ..................... 0.68 0.61 0.60 0.60 0.66 0.61 0.63 0.72 0.64 0.65

 Lower 48 Offshore ........................... 1.56 2.05 2.00 2.00 2.02 1.95 1.94 1.75 2.04 1.97

 Alaska .................................... 1.05 0.79 0.79 0.79 0.64 0.64 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 . 18.33 15.46 15.43 15.39 14.03 14.17 14.10 13.43 14.44 14.40

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ......... 2.08 2.49 3.45 2.97 2.68 4.36 4.13 3.14 4.22 4.38

Production (trillion cubic feet)3

 U.S. Total .................................. 18.67 20.72 23.46 21.72 23.03 25.25 25.98 28.84 30.79 30.82

 Lower 48 Onshore ........................... 12.83 14.33 16.43 15.03 16.32 18.24 18.93 21.20 22.66 22.54

 Associated-Dissolved4 ....................... 1.80 1.51 1.51 1.51 1.34 1.41 1.37 1.35 1.42 1.42

 Non-Associated ............................ 11.03 12.82 14.92 13.52 14.98 16.84 17.56 19.85 21.24 21.11

 Conventional ............................. 6.64 7.19 8.72 7.74 8.31 9.37 9.71 11.38 10.70 10.86

 Unconventional ........................... 4.39 5.62 6.20 5.79 6.66 7.47 7.85 8.48 10.54 10.25

 Lower 48 Offshore ........................... 5.43 5.93 6.56 6.22 6.21 6.51 6.55 7.07 7.57 7.72

 Associated-Dissolved4 ....................... 0.93 1.07 1.07 1.07 1.07 1.05 1.05 1.01 1.07 1.06

 Non-Associated ............................ 4.50 4.85 5.49 5.15 5.13 5.46 5.50 6.06 6.50 6.66

 Alaska .................................... 0.42 0.47 0.46 0.46 0.50 0.50 0.50 0.57 0.57 0.57

Lower 48 End of Year Reserves3

 (trillion cubic feet) .......................... 157.41 166.23 167.30 168.05 174.58 187.43 183.45 188.20 224.01 219.68

 Supplemental Gas Supplies (trillion cubic feet)5 . . 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) .............. 17.94 24.11 29.88 28.03 28.67 39.70 38.22 39.25 50.71 52.47

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
132 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Production1

 Appalachia ............................. 434 422 318 362 412 270 262 395 220 218

 Interior ................................ 185 180 135 161 177 109 105 163 97 96

 West ................................. 485 633 352 463 708 302 284 784 256 256

 East of the Mississippi .................... 561 554 418 477 545 357 349 525 298 295

 West of the Mississippi ................... 543 681 387 508 752 323 302 817 276 275

 Total ................................ 1105 1235 805 986 1297 681 651 1342 574 570

 Net Imports

 Imports ................................ 9 16 12 12 17 9 9 20 9 9

 Exports ................................ 58 60 60 60 58 57 56 56 57 57

 Total ................................. -49 -44 -48 -48 -40 -48 -47 -36 -48 -48

 Total Supply2 ........................... 1055 1191 757 938 1256 633 604 1306 525 521

 Consumption by Sector

 Residential and Commercial ............... 5555555555

 Industrial3 .............................. 79 83 84 84 84 88 87 86 92 92

 Coke Plants ............................ 28 26 26 26 23 23 23 19 19 19

 Electric Generators4 ..................... 922 1078 646 825 1145 518 488 1198 410 406

 Total ................................ 1034 1192 761 939 1257 634 603 1308 525 521

 Discrepancy and Stock Change5

. .......... 21 -1 -4 -2 -1 -1 1 -2 0 0

 Average Minemouth Price

 (1999 dollars per short ton) ................ 17.23 14.76 14.78 14.82 13.69 13.77 13.72 12.84 12.55 12.54

 (1999 dollars per million Btu) ............... 0.82 0.72 0.70 0.71 0.67 0.65 0.64 0.63 0.59 0.59

 Delivered Prices (1999 dollars per short ton)6

 Industrial .............................. 31.46 29.43 27.89 28.74 28.41 26.08 25.86 26.55 23.28 23.21

 Coke Plants ............................ 44.20 42.47 42.55 42.62 41.29 41.31 41.18 38.57 38.38 38.57

 Electric Generators

 (1999 dollars per short ton) ............... 24.78 22.62 20.12 20.79 20.84 18.75 18.55 19.40 16.51 16.35

 (1999 dollars per million Btu) ............. 1.22 1.13 0.99 1.02 1.05 0.92 0.91 0.98 0.82 0.81

 Average ............................. 25.82 23.53 21.74 22.10 21.72 20.58 20.47 20.15 18.48 18.37

 Exports7 ............................... 37.43 36.32 35.65 36.14 35.54 34.33 34.07 33.13 31.13 31.23

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000.. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators. 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 133

Table C11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ........... 78.14 78.62 80.14 79.92 78.74 80.26 80.21 78.74 80.46 80.26

 Geothermal2 ..................... 2.87 3.16 5.73 5.59 4.31 13.08 15.03 4.34 14.22 15.10

 Municipal Solid Waste3 ............. 2.59 3.15 3.92 3.76 3.56 4.37 4.33 4.07 4.90 4.90

 Wood and Other Biomass4 .......... 1.52 1.68 1.98 1.92 2.04 2.99 2.55 2.37 11.74 7.89

 Solar Thermal .................... 0.33 0.35 0.35 0.35 0.40 0.40 0.40 0.48 0.48 0.48

 Solar Photovoltaic ................. 0.01 0.09 0.09 0.09 0.21 0.21 0.21 0.54 0.54 0.54

 Wind ........................... 2.60 4.43 4.76 4.64 5.51 7.37 6.71 5.78 29.85 25.06

 Total .......................... 88.07 91.47 96.96 96.28 94.76 108.68 109.42 96.33 142.19 134.24

 Generation (billion kilowatthours)

 Conventional Hydropower ........... 307.43 299.05 304.22 303.50 298.99 304.14 303.97 297.94 303.61 303.06

 Geothermal2 ..................... 13.07 15.90 45.69 44.67 24.98 103.65 118.99 25.33 112.69 119.63

 Municipal Solid Waste3 ............. 18.05 22.30 28.28 27.04 24.94 31.36 30.99 28.85 35.39 35.40

 Wood and Other Biomass4 .......... 8.86 14.45 49.07 58.04 21.55 71.33 65.91 22.15 118.76 92.51

 Dedicated Plants ................ 7.56 8.67 10.71 10.35 10.88 17.28 14.32 13.35 75.87 50.17

 Cofiring ........................ 1.30 5.78 38.36 47.70 10.67 54.05 51.59 8.80 42.89 42.33

 Solar Thermal .................... 0.89 0.96 0.96 0.96 1.11 1.11 1.11 1.37 1.37 1.37

 Solar Photovoltaic ................. 0.03 0.20 0.20 0.20 0.51 0.51 0.51 1.36 1.36 1.36

 Wind ........................... 4.46 9.42 10.35 10.02 12.33 17.63 15.73 13.10 85.87 72.59

 Total .......................... 352.79 362.28 438.78 444.45 384.41 529.74 537.22 390.09 659.04 625.92

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste .............. 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

 Biomass ......................... 4.65 5.17 5.09 5.13 6.06 6.06 6.04 7.54 7.61 7.66

 Total .......................... 5.35 5.87 5.79 5.83 6.76 6.76 6.74 8.23 8.31 8.36

 Generation (billion kilowatthours)

 Municipal Solid Waste .............. 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03

 Biomass ......................... 27.08 29.92 29.43 29.68 35.01 34.95 34.83 43.52 43.86 44.21

 Total .......................... 31.10 33.95 33.46 33.71 39.03 38.98 38.86 47.55 47.88 48.23

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 .......... 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................. 0.01 0.10 0.10 0.10 0.35 0.35 0.35 0.35 0.35 0.35

 Total .......................... 1.00 1.09 1.09 1.09 1.34 1.34 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 .......... 4.57 4.44 4.44 4.44 4.43 4.43 4.43 4.41 4.41 4.41

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................ 0.02 0.20 0.20 0.20 0.75 0.75 0.75 0.75 0.76 0.76

 Total ......................... 4.59 4.64 4.64 4.64 5.18 5.18 5.18 5.17 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
134 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

Marketed Renewable Energy2

 Residential .................................. 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Wood ...................................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Commercial ................................. 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Biomass .................................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Industrial3 .................................. 2.15 2.42 2.39 2.40 2.64 2.64 2.63 3.08 3.12 3.12

 Conventional Hydroelectric ..................... 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ......................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Biomass .................................... 1.97 2.23 2.21 2.22 2.46 2.46 2.45 2.90 2.93 2.93

 Transportation ............................... 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

 Ethanol used in E854 .......................... 0.00 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.03 0.03

 Ethanol used in Gasoline Blending ............... 0.12 0.18 0.18 0.18 0.19 0.19 0.19 0.20 0.21 0.21

 Electric Generators5 .......................... 3.86 4.03 5.34 5.38 4.47 7.58 7.93 4.56 9.06 8.83

 Conventional Hydroelectric ..................... 3.17 3.08 3.13 3.12 3.08 3.13 3.13 3.06 3.12 3.12

 Geothermal ................................. 0.27 0.37 1.19 1.16 0.66 3.08 3.51 0.67 3.38 3.53

 Municipal Solid Waste6 ........................ 0.25 0.30 0.39 0.37 0.34 0.43 0.42 0.39 0.48 0.48

 Biomass .................................... 0.12 0.18 0.52 0.61 0.26 0.74 0.69 0.27 1.17 0.93

 Dedicated Plants ........................... 0.10 0.11 0.11 0.11 0.13 0.18 0.15 0.16 0.75 0.51

 Cofiring ................................... 0.02 0.07 0.41 0.51 0.13 0.56 0.54 0.11 0.42 0.43

 Solar Thermal ............................... 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ............................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Wind ...................................... 0.05 0.10 0.11 0.10 0.13 0.18 0.16 0.13 0.88 0.75

 Total Marketed Renewable Energy .............. 6.61 7.16 8.44 8.49 7.84 10.94 11.28 8.40 12.92 12.70

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ................................. 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.03 0.03

 Solar Hot Water Heating ....................... 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps ....................... 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Commercial ................................. 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Thermal ............................... 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.19 0.19 0.19 0.19 0.16 0.17 0.17

 From Cellulose ..................... 0.00 0.01 0.01 0.01 0.02 0.02 0.02 0.07 0.07 0.07

 Total ............................ 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 135

Table C13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Residential

 Petroleum .......................... 26.0 26.8 26.9 26.9 24.4 24.7 24.7 22.9 23.5 23.4

 Natural Gas ......................... 69.5 78.6 76.4 77.4 82.0 77.3 78.3 90.8 86.9 86.6

 Coal ............................... 1.1 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.2 1.2

 Electricity ........................... 192.6 223.2 166.3 187.3 240.4 151.8 149.2 274.7 157.6 157.6

 Total ............................. 289.3 330.0 270.9 292.9 348.1 255.2 253.5 389.6 269.3 268.9

 Commercial

 Petroleum .......................... 13.7 12.9 13.1 12.9 13.1 14.2 13.7 12.9 15.1 14.8

 Natural Gas ......................... 45.4 53.5 51.4 52.5 56.0 51.7 52.5 59.4 57.8 57.3

 Coal ............................... 1.7 1.8 1.8 1.8 1.9 1.9 1.9 2.0 2.0 2.0

 Electricity ........................... 182.1 216.0 159.9 181.0 237.0 149.7 148.1 265.8 151.2 151.7

 Total ............................. 242.9 284.1 226.2 248.1 307.9 217.5 216.1 340.0 226.2 225.7

 Industrial1

 Petroleum .......................... 104.2 99.0 102.0 99.4 104.7 112.2 112.1 115.6 124.6 126.3

 Natural Gas2 ........................ 141.6 147.8 146.5 148.1 157.6 153.3 153.6 174.9 174.6 170.5

 Coal ............................... 55.9 66.5 66.9 66.7 66.3 68.2 67.8 66.4 69.0 69.0

 Electricity ........................... 178.8 193.9 147.9 164.9 203.0 131.2 129.2 228.1 125.8 127.1

 Total ............................. 480.4 507.2 463.2 479.1 531.6 464.9 462.6 584.9 494.0 492.8

 Transportation

 Petroleum3 .......................... 485.8 556.8 550.9 553.3 608.6 603.7 603.2 705.1 700.9 700.9

 Natural Gas4 ........................ 9.5 11.8 13.3 12.6 14.1 15.4 15.7 17.9 19.4 19.4

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 2.9 4.4 3.4 3.8 5.7 3.9 3.8 7.9 4.8 4.9

 Total3 ............................. 498.2 573.1 567.7 569.7 628.6 623.1 622.8 730.9 725.3 725.2

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 .......................... 629.7 695.5 692.9 692.6 750.8 754.9 753.7 856.4 864.2 865.3

 Natural Gas ......................... 266.0 291.8 287.5 290.6 309.7 297.7 300.1 342.9 338.7 333.8

 Coal ............................... 58.8 69.6 69.9 69.7 69.5 71.4 70.9 69.6 72.2 72.2

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 556.3 637.5 477.6 537.0 686.1 436.5 430.3 776.5 439.5 441.2

 Total3 ............................. 1510.8 1694.3 1528.0 1589.9 1816.2 1560.6 1555.1 2045.4 1714.7 1712.6

 Electric Generators6

 Petroleum .......................... 20.0 6.8 4.5 4.2 3.5 2.6 2.5 3.9 2.1 2.1

 Natural Gas ......................... 45.8 77.1 136.2 104.6 98.6 163.9 173.2 164.1 225.4 229.4

 Coal ............................... 490.5 553.6 336.8 428.2 584.0 270.1 254.6 608.4 211.9 209.8

 Total ............................. 556.3 637.5 477.6 537.0 686.1 436.5 430.3 776.5 439.5 441.2

 Total Carbon Dioxide Emissions

 by Primary Fuel7

 Petroleum3 .......................... 649.7 702.2 697.5 696.8 754.3 757.5 756.2 860.3 866.3 867.4

 Natural Gas ......................... 311.8 368.9 423.7 395.2 408.2 461.5 473.3 507.1 564.1 563.2

 Coal ............................... 549.3 623.1 406.8 497.9 653.5 341.5 325.6 678.0 284.1 282.0

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total3 ............................. 1510.8 1694.3 1528.0 1589.9 1816.2 1560.6 1555.1 2045.4 1714.7 1712.6

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) .... 5.5 5.9 5.3 5.5 6.1 5.2 5.2 6.3 5.3 5.3

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 25 to 30 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
136 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table C14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999

Projections

2005 2010 2020

Reference CO2 Cap

2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008 Reference CO2 Cap2005

CO2 Cap

2008

 Scrubber Retrofits (gigawatts)1 ............... 0.00 10.76 0.00 0.00 10.76 0.00 0.00 15.24 0.00 0.00

 SO2 Allowance Price

 (1999 dollars per ton) ...................... 0.00 177.63 0.00 21.31 169.55 0.00 0.00 246.09 0.00 0.00

 NOx Controls (gigawatts)

 Combustion ............................... 0.00 65.84 55.88 60.28 66.93 56.02 60.28 67.57 56.02 60.28

 SCR post-combustion ....................... 0.00 84.31 41.57 54.06 85.97 41.57 54.06 89.75 41.57 54.06

 SNCR Post-combustion ...................... 0.00 25.36 15.94 22.31 28.78 15.94 22.31 38.69 15.94 22.31

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ............... 472.31 598.07 348.71 449.97 656.33 291.08 272.88 730.01 246.70 245.87

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) ......... 433.55 451.27 312.81 372.09 453.06 267.92 259.29 438.05 222.16 219.38

 High Sulfur (> 1.67 lbs. S/mmBtu) .............. 198.66 185.83 143.59 163.51 187.25 121.68 119.01 174.20 105.06 104.28

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here. 

SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05.D121300A, and FDC7B08.D121300A.
Appendix D

Tables for Integrated Cases with 2005 Emission Caps

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 139

Table D1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Production

 Crude Oil and Lease Condensate ... 12.45 11.85 11.78 11.78 10.90 10.93 10.95 10.61 11.28 11.47

 Natural Gas Plant Liquids ......... 2.62 3.02 3.43 3.41 3.31 3.60 3.60 4.07 4.41 4.37

 Dry Natural Gas ................. 19.16 21.26 24.24 24.09 23.63 25.70 25.73 29.59 32.02 31.79

 Coal .......................... 23.12 25.43 16.90 16.83 26.47 16.24 14.79 27.21 13.55 11.89

 Nuclear Power .................. 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.20 7.32

 Renewable Energy1 .............. 6.50 6.98 8.23 8.20 7.65 10.22 10.34 8.20 11.11 11.95

 Other2 ........................ 1.65 0.57 0.35 0.35 0.33 0.30 0.30 0.33 0.34 0.34

 Total ....................... 73.30 77.01 72.83 72.58 79.98 74.90 73.62 86.18 79.90 79.14

 Imports

 Crude Oil3 ..................... 18.96 23.21 22.62 22.64 25.22 24.94 24.96 26.48 25.96 25.66

 Petroleum Products4 ............. 4.14 4.85 4.87 4.85 6.46 6.52 6.61 10.77 10.64 10.98

 Natural Gas .................... 3.63 4.90 5.73 5.71 5.49 6.61 6.68 6.60 7.97 8.09

 Other Imports5 .................. 0.64 1.11 1.02 1.02 0.96 0.89 0.89 0.96 0.82 0.82

 Total ....................... 27.37 34.08 34.24 34.23 38.12 38.96 39.14 44.82 45.39 45.55

 Exports

 Petroleum6 ..................... 1.98 1.81 1.78 1.77 1.79 1.78 1.80 1.90 1.93 1.94

 Natural Gas .................... 0.17 0.33 0.12 0.12 0.43 0.12 0.12 0.63 0.12 0.12

 Coal .......................... 1.48 1.51 1.52 1.52 1.45 1.50 1.50 1.41 1.44 1.44

 Total ....................... 3.62 3.64 3.42 3.42 3.67 3.40 3.42 3.94 3.50 3.50

 Discrepancy7 .................... 0.95 0.39 0.37 0.24 0.21 0.19 0.20 -0.03 0.19 0.08

 Consumption

 Petroleum Products8 ............. 38.07 41.40 41.10 41.10 44.43 44.52 44.62 50.60 50.84 51.02

 Natural Gas .................... 21.90 25.78 29.77 29.59 28.52 31.99 32.11 35.40 39.68 39.57

 Coal .......................... 21.46 24.37 15.64 15.73 25.54 15.11 13.64 26.48 12.39 10.85

 Nuclear Power ................. . 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.20 7.32

 Renewable Energy1 .............. 6.51 6.98 8.24 8.21 7.66 10.23 10.34 8.21 11.12 11.96

 Other9 ........................ 0.35 0.61 0.62 0.62 0.38 0.52 0.52 0.25 0.38 0.38

 Total ........................ 96.09 107.05 103.28 103.15 114.21 110.27 109.14 127.10 121.60 121.10

 Net Imports - Petroleum ........... 21.12 26.26 25.72 25.73 29.88 29.68 29.77 35.36 34.67 34.70

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 . . 17.35 20.83 20.83 20.83 21.37 21.37 21.37 22.41 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 2.08 2.49 3.45 3.46 2.68 3.83 4.33 3.14 4.04 4.30

 Coal Minemouth Price (dollars per ton) 17.23 14.76 12.92 13.07 13.69 11.93 11.82 12.84 10.93 11.18

 Average Electric Price (cents per Kwh) 6.6 6.2 8.2 8.1 5.9 7.9 8.4 6.0 7.6 7.8

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
140 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

Energy Consumption

 Residential

 Distillate Fuel ........................ 0.86 0.88 0.89 0.89 0.81 0.81 0.81 0.75 0.77 0.77

 Kerosene ........................... 0.10 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas ............... 0.46 0.45 0.46 0.46 0.41 0.42 0.42 0.39 0.42 0.41

 Petroleum Subtotal .................. 1.42 1.42 1.43 1.43 1.29 1.31 1.31 1.21 1.25 1.24

 Natural Gas ......................... 4.85 5.46 5.31 5.30 5.69 5.46 5.38 6.30 6.09 6.02

 Coal ............................... 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

 Renewable Energy1 ................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Electricity ........................... 3.91 4.50 4.23 4.24 4.96 4.61 4.55 5.80 5.45 5.38

 Delivered Energy ................... 10.62 11.86 11.44 11.44 12.42 11.86 11.70 13.80 13.26 13.12

 Electricity Related Losses .............. 8.46 9.46 8.51 8.46 9.88 8.86 8.61 10.58 9.06 9.03

 Total ............................. 19.08 21.32 19.95 19.90 22.30 20.72 20.31 24.38 22.32 22.15

 Commercial

 Distillate Fuel ........................ 0.36 0.41 0.42 0.42 0.41 0.46 0.47 0.39 0.48 0.51

 Residual Fuel ....................... 0.10 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.11

 Kerosene ........................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas ............... 0.08 0.09 0.09 0.09 0.09 0.09 0.09 0.10 0.10 0.10

 Motor Gasoline2 ...................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal .................. 0.59 0.66 0.67 0.67 0.67 0.71 0.72 0.66 0.74 0.77

 Natural Gas ......................... 3.15 3.71 3.57 3.57 3.89 3.68 3.60 4.12 4.00 3.98

 Coal ............................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.08

 Renewable Energy3 ................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Electricity ........................... 3.70 4.35 4.06 4.07 4.89 4.55 4.48 5.61 5.25 5.16

 Delivered Energy ................... 7.59 8.87 8.45 8.45 9.60 9.09 8.96 10.55 10.14 10.08

 Electricity Related Losses .............. 8.00 9.15 8.16 8.12 9.74 8.74 8.48 10.23 8.73 8.66

 Total ............................. 15.59 18.02 16.61 16.58 19.34 17.83 17.44 20.79 18.87 18.74

 Industrial4

 Distillate Fuel ........................ 1.07 1.13 1.12 1.12 1.27 1.27 1.29 1.44 1.45 1.45

 Liquefied Petroleum Gas ............... 2.32 2.45 2.47 2.47 2.50 2.59 2.65 2.83 3.03 3.09

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.53 1.70 1.69 1.69

 Residual Fuel ....................... 0.22 0.22 0.33 0.33 0.25 0.37 0.39 0.27 0.31 0.41

 Motor Gasoline2 ...................... 0.21 0.23 0.22 0.22 0.25 0.24 0.24 0.28 0.28 0.28

 Other Petroleum5 ..................... 4.29 4.49 4.49 4.49 4.76 4.80 4.85 5.25 5.39 5.42

 Petroleum Subtotal .................. 9.39 9.95 10.04 10.04 10.55 10.81 10.95 11.78 12.16 12.35

 Natural Gas6 ........................ 9.43 10.42 10.34 10.33 11.11 11.03 10.78 12.33 12.32 12.08

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.60 0.50 0.50 0.50

 Steam Coal ......................... 1.73 1.82 1.85 1.85 1.85 1.92 1.92 1.89 1.99 2.00

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.16 0.22 0.22 0.23

 Coal Subtotal ....................... 2.54 2.62 2.64 2.64 2.61 2.68 2.68 2.62 2.71 2.72

 Renewable Energy7 ................... 2.15 2.42 2.39 2.39 2.64 2.64 2.64 3.08 3.08 3.12

 Electricity ........................... 3.63 3.90 3.76 3.77 4.19 3.96 3.93 4.81 4.39 4.30

 Delivered Energy ................... 27.15 29.32 29.18 29.17 31.10 31.12 30.98 34.62 34.67 34.58

 Electricity Related Losses .............. 7.85 8.22 7.57 7.53 8.34 7.61 7.45 8.78 7.31 7.22

 Total ............................. 35.00 37.53 36.74 36.70 39.45 38.73 38.43 43.40 41.97 41.80
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 141

Table D2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Transportation

 Distillate Fuel ........................ 5.13 6.28 6.14 6.14 6.99 6.89 6.88 8.21 8.10 8.08

 Jet Fuel8 ........................... 3.46 3.90 3.85 3.85 4.51 4.49 4.49 5.97 5.96 5.96

 Motor Gasoline2 ...................... 15.92 17.70 17.59 17.60 19.05 18.96 18.95 21.32 21.26 21.25

 Residual Fuel ....................... 0.74 0.85 0.85 0.85 0.85 0.85 0.85 0.87 0.86 0.86

 Liquefied Petroleum Gas ............... 0.02 0.03 0.03 0.03 0.04 0.04 0.04 0.06 0.06 0.06

 Other Petroleum9 ..................... 0.26 0.29 0.29 0.29 0.31 0.31 0.31 0.35 0.35 0.35

 Petroleum Subtotal .................. 25.54 29.06 28.76 28.76 31.75 31.55 31.51 36.77 36.59 36.56

 Pipeline Fuel Natural Gas .............. 0.66 0.77 0.87 0.87 0.89 0.97 0.98 1.08 1.20 1.21

 Compressed Natural Gas .............. 0.02 0.06 0.05 0.05 0.09 0.09 0.09 0.16 0.15 0.15

 Renewable Energy (E85)10 ............. 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 0.06 0.09 0.09 0.09 0.12 0.12 0.12 0.17 0.17 0.17

 Delivered Energy ................... 26.28 29.99 29.80 29.80 32.89 32.76 32.73 38.23 38.16 38.13

 Electricity Related Losses .............. 0.13 0.19 0.18 0.18 0.24 0.23 0.22 0.30 0.28 0.28

 Total ............................. 26.41 30.18 29.98 29.97 33.12 32.99 32.95 38.53 38.44 38.41

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ........................ 7.42 8.70 8.57 8.57 9.47 9.43 9.44 10.80 10.79 10.81

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.85 3.85 4.51 4.49 4.49 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.05 3.05 3.05 3.15 3.21 3.38 3.60 3.65

 Motor Gasoline2 ...................... 16.17 17.96 17.85 17.85 19.32 19.23 19.22 21.63 21.57 21.56

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.53 1.70 1.69 1.69

 Residual Fuel ....................... 1.05 1.17 1.28 1.28 1.21 1.33 1.34 1.25 1.28 1.38

 Other Petroleum12 .................... 4.53 4.76 4.75 4.76 5.04 5.08 5.13 5.58 5.72 5.75

 Petroleum Subtotal .................. 36.95 41.08 40.90 40.90 44.26 44.38 44.49 50.42 50.74 50.93

 Natural Gas6 ........................ 18.11 20.42 20.15 20.12 21.67 21.23 20.82 24.00 23.76 23.44

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.60 0.50 0.50 0.50

 Steam Coal ......................... 1.84 1.94 1.96 1.96 1.98 2.04 2.05 2.02 2.11 2.13

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.16 0.22 0.22 0.23

 Coal Subtotal ....................... 2.65 2.74 2.76 2.76 2.74 2.80 2.81 2.74 2.84 2.85

 Renewable Energy13 .................. 2.65 2.95 2.92 2.92 3.19 3.18 3.18 3.65 3.64 3.67

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 11.29 12.84 12.14 12.16 14.15 13.23 13.07 16.39 15.25 15.02

 Delivered Energy ................... 71.65 80.04 78.87 78.86 86.01 84.83 84.37 97.20 96.23 95.91

 Electricity Related Losses .............. 24.44 27.02 24.41 24.29 28.20 25.44 24.77 29.89 25.37 25.20

 Total ............................. 96.09 107.05 103.28 103.15 114.21 110.27 109.14 127.10 121.60 121.10

 Electric Generators14

 Distillate Fuel ........................ 0.06 0.05 0.04 0.04 0.04 0.03 0.03 0.04 0.02 0.02

 Residual Fuel ....................... 1.07 0.27 0.16 0.16 0.13 0.11 0.11 0.14 0.08 0.08

 Petroleum Subtotal .................. 1.13 0.32 0.21 0.20 0.17 0.14 0.14 0.19 0.10 0.10

 Natural Gas ......................... 3.79 5.36 9.62 9.48 6.84 10.75 11.29 11.40 15.92 16.13

 Steam Coal ......................... 18.81 21.63 12.89 12.97 22.80 12.30 10.83 23.73 9.55 8.00

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.20 7.32

 Renewable Energy15 .................. 3.86 4.03 5.31 5.29 4.47 7.05 7.16 4.56 7.49 8.29

 Electricity Imports16 ................... 0.35 0.61 0.62 0.62 0.37 0.51 0.51 0.24 0.37 0.37

 Total ............................. 35.73 39.85 36.55 36.45 42.35 38.67 37.84 46.28 40.62 40.21
142 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Total Energy Consumption

 Distillate Fuel ........................ 7.48 8.75 8.61 8.61 9.51 9.46 9.47 10.84 10.81 10.83

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.85 3.85 4.51 4.49 4.49 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.05 3.05 3.05 3.15 3.21 3.38 3.60 3.65

 Motor Gasoline2 ...................... 16.17 17.96 17.85 17.85 19.32 19.23 19.22 21.63 21.57 21.56

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.53 1.70 1.69 1.69

 Residual Fuel ....................... 2.12 1.44 1.44 1.44 1.34 1.44 1.45 1.39 1.36 1.45

 Other Petroleum12 .................... 4.53 4.76 4.75 4.76 5.04 5.08 5.13 5.58 5.72 5.75

 Petroleum Subtotal .................. 38.07 41.40 41.10 41.10 44.43 44.52 44.62 50.60 50.84 51.02

 Natural Gas ......................... 21.90 25.78 29.77 29.59 28.52 31.99 32.11 35.40 39.68 39.57

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.60 0.50 0.50 0.50

 Steam Coal ......................... 20.65 23.57 14.85 14.93 24.77 14.35 12.88 25.75 11.67 10.13

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.16 0.22 0.22 0.23

 Coal Subtotal ....................... 21.46 24.37 15.64 15.73 25.54 15.11 13.64 26.48 12.39 10.85

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.20 7.32

 Renewable Energy17 .................. 6.51 6.98 8.24 8.21 7.66 10.23 10.34 8.21 11.12 11.96

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 ................... 0.35 0.61 0.62 0.62 0.37 0.51 0.51 0.24 0.37 0.37

 Total ............................. 96.09 107.05 103.28 103.15 114.21 110.27 109.14 127.10 121.60 121.10

Energy Use and Related Statistics

 Delivered Energy Use .................. 71.65 80.04 78.87 78.86 86.01 84.83 84.37 97.20 96.23 95.91

 Total Energy Use ..................... 96.09 107.05 103.28 103.15 114.21 110.27 109.14 127.10 121.60 121.10

 Population (millions) .................... 273.13 288.02 288.02 288.02 300.17 300.17 300.17 325.24 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 10960 10837 10838 12667 12638 12629 16515 16521 16521

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) .... 1510.8 1694.3 1524.3 1523.7 1816.2 1601.6 1567.5 2045.4 1750.1 1712.4

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which produces electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDPOL05.D121300A, and FDP7B05.D121300B.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 143

Table D3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Residential ......................... 13.12 12.91 15.23 15.20 13.15 15.85 16.57 13.59 15.83 16.28

 Primary Energy1 .................... 6.72 7.12 7.74 7.75 7.00 7.85 8.20 7.02 7.76 7.98

 Petroleum Products2 ................ 7.55 9.18 9.18 9.18 9.37 9.31 9.37 9.66 9.66 9.75

 Distillate Fuel ..................... 6.27 7.34 7.33 7.33 7.51 7.47 7.46 7.99 7.97 8.00

 Liquefied Petroleum Gas ............ 10.36 12.83 12.84 12.84 13.06 12.91 13.12 12.90 12.83 13.11

 Natural Gas ....................... 6.52 6.63 7.41 7.42 6.52 7.56 7.99 6.56 7.42 7.67

 Electricity .......................... 23.46 21.84 27.23 27.12 21.88 27.69 28.97 22.16 26.77 27.55

 Commercial ........................ 13.20 12.36 16.10 16.03 11.74 15.50 16.50 12.37 15.13 15.62

 Primary Energy1 .................... 5.22 5.35 6.00 6.01 5.53 6.35 6.70 5.76 6.46 6.66

 Petroleum Products2 ................ 5.00 6.01 5.99 5.99 6.17 6.06 6.07 6.52 6.41 6.42

 Distillate Fuel ..................... 4.37 5.13 5.11 5.12 5.28 5.22 5.22 5.77 5.74 5.76

 Residual Fuel .................... 2.63 3.64 3.62 3.62 3.69 3.69 3.69 3.85 3.84 3.84

 Natural Gas3 ...................... 5.34 5.31 6.09 6.10 5.49 6.51 6.93 5.72 6.57 6.81

 Electricity .......................... 21.43 19.51 26.83 26.64 17.61 24.47 26.13 18.09 23.09 24.01

 Industrial4 .......................... 5.32 5.49 6.54 6.53 5.44 6.55 6.92 5.85 6.69 6.90

 Primary Energy ..................... 3.92 4.25 4.61 4.62 4.37 4.81 5.04 4.73 5.13 5.28

 Petroleum Products2 ................ 5.55 5.95 5.93 5.93 6.05 6.02 6.11 6.28 6.34 6.41

 Distillate Fuel ..................... 4.65 5.29 5.29 5.29 5.46 5.42 5.41 5.98 5.98 6.00

 Liquefied Petroleum Gas ............ 8.50 7.94 8.00 8.00 8.00 7.98 8.23 7.86 7.94 8.24

 Residual Fuel .................... 2.78 3.37 3.25 3.25 3.42 3.33 3.34 3.58 3.57 3.49

 Natural Gas5 ...................... 2.79 3.17 4.05 4.06 3.30 4.36 4.81 3.77 4.66 4.92

 Metallurgical Coal .................. 1.65 1.58 1.59 1.59 1.54 1.53 1.54 1.44 1.43 1.43

 Steam Coal ....................... 1.43 1.34 1.24 1.24 1.29 1.18 1.16 1.21 1.06 1.04

 Electricity .......................... 13.01 12.30 17.50 17.37 11.21 16.54 17.75 11.60 15.55 16.26

 Transportation ...................... 8.30 9.27 9.31 9.32 9.45 9.56 9.55 9.32 9.33 9.34

 Primary Energy ..................... 8.29 9.25 9.29 9.29 9.44 9.53 9.52 9.30 9.31 9.32

 Petroleum Products2 ................ 8.28 9.25 9.29 9.29 9.44 9.53 9.52 9.30 9.30 9.31

 Distillate Fuel6 .................... 8.22 8.89 8.90 8.90 8.94 8.93 8.92 9.02 9.04 9.05

 Jet Fuel7 ........................ 4.70 5.24 5.23 5.23 5.46 5.46 5.46 5.88 5.87 5.88

 Motor Gasoline8 ................... 9.45 10.64 10.70 10.70 10.92 11.08 11.06 10.68 10.68 10.68

 Residual Fuel .................... 2.46 3.10 3.11 3.11 3.18 3.18 3.18 3.33 3.32 3.33

 Liquid Petroleum Gas9 .............. 12.87 14.19 14.29 14.29 14.24 14.23 14.43 13.88 13.89 14.11

 Natural Gas10 ...................... 7.02 6.80 7.63 7.63 7.03 8.07 8.47 7.33 8.16 8.37

 Ethanol (E85)11 .................... 14.42 19.12 19.21 19.21 19.00 19.20 19.27 19.36 19.47 19.51

 Methanol (M85)12 ................... 10.38 13.11 13.84 13.84 13.74 13.99 14.31 14.43 14.43 14.42

 Electricity .......................... 15.58 14.29 16.90 16.83 13.53 16.23 16.91 13.03 14.64 15.04

 Average End-Use Energy ............. 8.53 8.90 10.03 10.01 8.94 10.13 10.46 9.17 10.05 10.23

 Primary Energy ..................... 6.33 7.00 7.26 7.26 7.18 7.51 7.65 7.31 7.56 7.65

 Electricity .......................... 19.40 18.10 24.01 23.86 17.18 23.15 24.51 17.57 22.14 22.96

 Electric Generators13

 Fossil Fuel Average .................. 1.49 1.50 2.24 2.22 1.52 2.44 2.80 1.85 3.17 3.47

 Petroleum Products ................. 2.50 3.70 3.83 3.83 4.06 4.08 4.08 4.33 4.59 4.64

 Distillate Fuel ..................... 4.04 4.65 4.67 4.69 4.85 4.82 4.81 5.30 5.25 5.26

 Residual Fuel .................... 2.41 3.52 3.61 3.62 3.85 3.89 3.88 4.04 4.43 4.47

 Natural Gas ....................... 2.54 2.89 3.91 3.91 3.02 4.15 4.60 3.61 4.58 4.80

 Steam Coal ....................... 1.22 1.13 0.97 0.96 1.05 0.92 0.90 0.98 0.80 0.78
144 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Average Price to All Users14

 Petroleum Products2 ................. 7.43 8.43 8.46 8.46 8.63 8.67 8.68 8.62 8.62 8.64

 Distillate Fuel ...................... 7.27 8.07 8.06 8.07 8.18 8.14 8.13 8.41 8.40 8.41

 Jet Fuel .......................... 4.70 5.24 5.23 5.23 5.46 5.46 5.46 5.88 5.87 5.88

 Liquefied Petroleum Gas ............. 8.84 8.83 8.88 8.88 8.87 8.82 9.05 8.64 8.69 8.96

 Motor Gasoline8 .................... 9.45 10.64 10.70 10.70 10.92 11.08 11.06 10.68 10.68 10.68

 Residual Fuel ..................... 2.48 3.26 3.23 3.23 3.33 3.31 3.31 3.49 3.49 3.47

 Natural Gas ....................... 4.05 4.25 4.93 4.94 4.27 5.16 5.58 4.52 5.31 5.54

 Coal .............................. 1.24 1.15 1.00 1.00 1.07 0.96 0.94 1.00 0.85 0.83

 Ethanol (E85)11 ..................... 14.42 19.12 19.21 19.21 19.00 19.20 19.27 19.36 19.47 19.51

 Methanol (M85)12 .................... 10.38 13.11 13.84 13.84 13.74 13.99 14.31 14.43 14.43 14.42

 Electricity .......................... 19.40 18.10 24.01 23.86 17.18 23.15 24.51 17.57 22.14 22.96

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ........................... 134.05 147.53 167.72 167.40 157.75 181.24 186.99 181.60 203.13 206.66

 Commercial .......................... 99.10 108.63 134.78 134.19 111.63 139.57 146.41 129.48 152.25 156.14

 Industrial ............................ 110.62 121.27 145.16 144.79 126.35 153.71 162.13 151.05 173.87 178.67

 Transportation ........................ 212.64 270.40 269.07 269.14 301.90 303.24 302.62 345.30 344.08 344.08

 Total Non-Renewable Expenditures ..... 556.41 647.83 716.73 715.53 697.64 777.76 798.15 807.43 873.33 885.54

 Transportation Renewable Expenditures . . 0.14 0.42 0.41 0.41 0.61 0.62 0.61 0.86 0.86 0.86

 Total Expenditures .................. 556.55 648.25 717.14 715.94 698.25 778.37 798.77 808.29 874.19 886.40

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report,

DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and

FDP7B05.D121300B. 1999 electricity prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDPOL05.D121300A, and FDP7B05.D121300B. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and

FDP7B05.D121300B.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 145

Table D4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

Generation by Fuel Type

 Electric Generators1

 Coal ............................ 1835 2103 1286 1295 2232 1224 1084 2317 949 801

 Petroleum ....................... 104 32 22 21 18 15 15 19 11 11

 Natural Gas2 ..................... 365 574 1103 1102 867 1419 1509 1568 2294 2285

 Nuclear Power .................... 730 740 740 740 720 741 741 577 674 686

 Pumped Storage .................. -1 -1 -1 -1 -1 -1 -1 -1 -1 -1

 Renewable Sources3 ............... 353 362 437 436 384 515 516 390 556 624

 Total .......................... 3386 3811 3587 3593 4220 3913 3863 4872 4483 4405

 Non-Utility Generation for Own Use ... 16 16 22 22 16 20 20 16 20 20

 Distributed Generation ............. 0100300600

 Cogenerators4

 Coal ........................... 47 52 52 52 52 51 51 52 50 51

 Petroleum ...................... 9 10 10 10 10 10 10 10 10 10

 Natural Gas ..................... 206 239 265 265 256 327 331 298 458 490

 Other Gaseous Fuels5 ............. 4666777888

 Renewable Sources3 .............. 31 34 33 33 39 39 39 48 48 48

 Other6 ......................... 5555555555

 Total ......................... 302 347 372 372 369 440 443 421 580 613

 Other End-Use Generators7 ......... 5555555555

 Sales to Utilities .................. 150 171 179 179 176 191 190 200 235 240

 Generation for Own Use ............ 156 180 198 197 198 254 258 226 350 377

 Net Imports8 ...................... 33 57 59 59 35 49 49 23 35 35

Electricity Sales by Sector

 Residential ........................ 1146 1317 1240 1242 1452 1351 1332 1699 1597 1578

 Commercial ....................... 1083 1275 1190 1192 1432 1332 1312 1644 1538 1513

 Industrial ......................... 1063 1144 1103 1104 1227 1160 1153 1411 1287 1261

 Transportation ..................... 17 26 26 26 35 34 34 49 49 48

 Total ........................... 3309 3762 3559 3564 4146 3878 3832 4803 4471 4401

End-Use Prices (1999 cents per kwh)9

 Residential ........................ 8.0 7.5 9.3 9.3 7.5 9.4 9.9 7.6 9.1 9.4

 Commercial ....................... 7.3 6.7 9.2 9.1 6.0 8.3 8.9 6.2 7.9 8.2

 Industrial ......................... 4.4 4.2 6.0 5.9 3.8 5.6 6.1 4.0 5.3 5.5

 Transportation ..................... 5.3 4.9 5.8 5.7 4.6 5.5 5.8 4.4 5.0 5.1

 All Sectors Average .............. 6.6 6.2 8.2 8.1 5.9 7.9 8.4 6.0 7.6 7.8

 Prices by Service Category 9

 (1999 cents per kwh)

 Generation ........................ 4.1 3.6 5.6 5.5 3.2 5.1 5.6 3.4 4.9 5.1

 Transmission ...................... 0.6 0.6 0.7 0.7 0.7 0.7 0.8 0.7 0.7 0.7

 Distribution ....................... 2.0 2.0 2.0 2.0 2.0 2.1 2.1 2.0 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide ..................... 13.82 10.39 4.67 4.87 9.70 4.22 3.92 8.95 3.27 3.27

 Nitrogen Oxide .................... 5.46 4.22 1.38 1.46 4.20 1.37 1.30 4.37 1.18 1.12

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
146 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

Electric Generators2

 Capability

 Coal Steam ................... 306.2 302.4 299.4 299.0 317.4 265.8 260.2 317.8 240.9 228.4

 Other Fossil Steam3 ............ 138.2 129.6 126.1 126.4 121.1 112.8 111.9 117.2 103.7 90.5

 Combined Cycle ............... 20.2 49.4 89.3 93.3 124.0 162.5 177.4 230.0 285.7 277.4

 Combustion Turbine/Diesel ....... 75.6 129.7 105.7 106.9 162.1 117.8 115.4 207.7 162.9 188.5

 Nuclear Power ................. 97.4 97.5 97.5 97.5 94.2 96.9 96.9 71.6 86.1 88.4

 Pumped Storage ............... 19.3 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 88.1 91.5 96.6 96.5 94.8 104.7 106.5 96.3 118.1 133.9

 Distributed Generation5 .......... 0.0 2.0 1.5 1.5 6.1 2.5 2.4 14.0 7.0 5.2

 Total ....................... 745.0 821.5 835.6 840.6 939.4 882.5 890.4 1074.3 1024.3 1031.9

 Cumulative Planned Additions6

 Coal Steam ................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Combined Cycle ............... 0.0 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ....... 0.0 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 0.0 2.4 2.4 2.4 4.3 4.3 4.3 5.4 5.4 5.4

 Distributed Generation5 .......... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Total ....................... 0.0 11.5 11.5 11.5 13.6 13.6 13.6 14.8 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam ................... 0.0 2.5 0.0 0.0 20.1 0.0 0.0 21.5 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Combined Cycle ............... 0.0 20.8 60.7 64.7 95.7 134.4 149.4 201.6 257.6 249.4

 Combustion Turbine/Diesel ...... . 0.0 57.0 34.2 35.4 90.8 49.7 46.6 137.2 95.1 120.4

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ............ 0.0 0.6 5.8 5.6 1.9 11.8 13.6 2.4 24.2 40.0

 Distributed Generation5 .......... 0.0 2.0 1.5 1.5 6.1 2.5 2.4 14.0 7.0 5.2

 Total ....................... 0.0 82.9 102.2 107.3 214.6 198.5 212.1 376.7 383.9 414.9

 Cumulative Total Additions ...... 0.0 94.5 113.8 118.9 228.1 212.0 225.6 391.4 398.6 429.7

 Cumulative Retirements7

 Coal Steam ................... 0.0 6.6 7.1 7.5 9.2 41.2 46.8 10.2 66.1 78.7

 Other Fossil Steam3 ............ 0.0 8.5 12.0 11.7 17.0 25.3 26.2 20.9 34.3 47.6

 Combined Cycle ............... 0.0 0.0 0.0 0.0 0.3 0.6 0.6 0.3 0.6 0.6

 Combusion Turbine/Diesel ....... 0.0 3.8 4.6 4.5 5.1 8.0 7.1 5.9 8.2 7.9

 Nuclear Power ................. 0.0 0.0 0.0 0.0 3.3 0.6 0.6 25.9 11.3 9.1

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total ....................... 0.0 19.0 23.8 23.9 34.9 75.9 81.5 63.4 120.7 144.0

Cogenerators8

 Capability

 Coal ......................... 8.4 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9

 Petroleum .................... 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 2.8

 Natural Gas ................... 33.8 40.0 42.7 42.7 42.9 51.9 52.5 48.8 70.5 75.2

 Other Gaseous Fuels ........... 0.2 0.8 0.8 0.8 0.9 0.9 0.9 1.0 1.1 1.1

 Renewable Sources4 ............ 5.3 5.9 5.8 5.8 6.8 6.8 6.8 8.2 8.3 8.3

 Other ........................ 1.1 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

 Total ....................... 51.6 59.2 61.8 61.8 63.1 72.1 72.7 70.7 92.5 97.3

 Cumulative Additions6 .......... 0.0 7.5 10.2 10.1 11.4 20.5 21.1 19.0 40.9 45.7
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 147

Table D5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

Other End-Use Generators9

 Renewable Sources ............. 1.0 1.1 1.1 1.1 1.3 1.3 1.3 1.3 1.3 1.3

 Cumulative Additions ............ 0.0 0.1 0.1 0.1 0.3 0.3 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8

Nameplate capacity is reported for nonutilities on Form EIA-860B, “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
148 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade .......... 182.2 125.3 125.3 125.3 102.9 102.9 102.9 0.0 0.0 0.0

 Gross Domestic Economy Trade ........... 147.8 202.8 56.4 56.1 183.2 100.5 100.8 206.7 150.4 156.7

 Gross Domestic Trade ................. 330.0 328.1 181.7 181.4 286.1 203.5 203.7 206.7 150.4 156.7

 Gross Domestic Firm Power Sales

 (million 1999 dollars) .................... 8588.1 5905.8 5905.8 5905.8 4851.2 4851.2 4851.2 0.0 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) .................... 4292.5 6044.9 2715.4 2674.9 4987.6 4548.8 4965.5 6227.5 6405.5 6967.3

 Gross Domestic Sales

 (million 1999 dollars) .................. 12880.6 11950.7 8621.2 8580.7 9838.8 9400.0 9816.7 6227.5 6405.5 6967.3

 International Electricity Trade

 Firm Power Imports From Canada and Mexico1

 27.0 10.7 11.8 11.8 5.8 19.1 19.1 0.0 12.1 12.1

 Economy Imports From Canada and Mexico1 . . 21.9 63.5 63.5 63.5 45.9 45.9 45.9 30.6 30.6 30.6

 Gross Imports From Canada and Mexico1 . . 48.9 74.1 75.3 75.3 51.7 65.0 65.0 30.6 42.7 42.7

 Firm Power Exports To Canada and Mexico . . 9.2 9.7 9.7 9.7 8.7 8.7 8.7 0.0 0.0 0.0

 Economy Exports To Canada and Mexico .... 6.3 7.0 7.0 7.0 7.7 7.7 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico .... 15.5 16.7 16.7 16.7 16.4 16.4 16.4 7.7 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 149

Table D7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Production

 Dry Gas Production1 ......... 18.67 20.72 23.62 23.48 23.03 25.05 25.08 28.84 31.21 30.98

 Supplemental Natural Gas2 .... 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Net Imports ................ 3.38 4.47 5.47 5.46 4.94 6.34 6.41 5.83 7.67 7.79

 Canada ................... 3.29 4.28 4.71 4.70 4.68 5.26 5.32 5.46 6.01 6.12

 Mexico .................... -0.01 -0.18 0.30 0.30 -0.25 0.32 0.32 -0.40 0.36 0.36

 Liquefied Natural Gas ........ 0.10 0.37 0.47 0.46 0.51 0.75 0.77 0.77 1.31 1.32

 Total Supply ................ 22.15 25.30 29.21 29.06 28.03 31.44 31.54 34.72 38.94 38.83

 Consumption by Sector

 Residential ................. 4.72 5.32 5.17 5.16 5.54 5.32 5.24 6.14 5.93 5.86

 Commercial ................ 3.07 3.62 3.48 3.47 3.78 3.58 3.50 4.02 3.89 3.88

 Industrial3 .................. 7.95 8.80 8.59 8.58 9.33 9.16 8.91 10.17 10.05 9.83

 Electric Generators4 ......... 3.72 5.26 9.44 9.30 6.72 10.55 11.08 11.19 15.62 15.83

 Lease and Plant Fuel5 ........ 1.23 1.35 1.48 1.48 1.49 1.59 1.59 1.83 1.95 1.94

 Pipeline Fuel ............... 0.64 0.75 0.85 0.85 0.87 0.95 0.95 1.06 1.17 1.18

 Transportation6 ............. 0.02 0.05 0.05 0.05 0.09 0.09 0.09 0.15 0.14 0.14

 Total .................... 21.35 25.14 29.06 28.89 27.82 31.23 31.35 34.55 38.76 38.65

 Discrepancy7 ............... 0.80 0.16 0.15 0.17 0.21 0.21 0.19 0.17 0.18 0.18

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B. Other 1999

consumption: EIA, Short-Term Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption

levels for consumption of natural gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A,

and FDP7B05.D121300B. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
150 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Source Price 

 Average Lower 48 Wellhead Price1 .... 2.08 2.49 3.45 3.46 2.68 3.83 4.33 3.14 4.04 4.30

 Average Import Price ............... 2.29 2.48 2.82 2.82 2.41 2.81 2.92 2.67 3.15 3.26

 Average2 ....................... 2.11 2.49 3.33 3.34 2.63 3.62 4.04 3.05 3.87 4.09

 Delivered Prices

 Residential ....................... 6.69 6.81 7.61 7.62 6.70 7.76 8.20 6.74 7.62 7.88

 Commercial ...................... 5.49 5.45 6.26 6.27 5.64 6.68 7.12 5.87 6.74 6.99

 Industrial3 ........................ 2.87 3.26 4.16 4.17 3.39 4.48 4.94 3.87 4.79 5.05

 Electric Generators4 ............... 2.59 2.94 3.98 3.99 3.08 4.23 4.69 3.68 4.67 4.89

 Transportation5 ................... 7.21 6.99 7.84 7.84 7.22 8.29 8.69 7.53 8.38 8.60

 Average6 ....................... 4.16 4.36 5.05 5.07 4.38 5.29 5.72 4.64 5.45 5.69

 Transmission & Distribution Margins7

 Residential ....................... 4.58 4.32 4.28 4.28 4.07 4.14 4.16 3.69 3.76 3.78

 Commercial ...................... 3.37 2.96 2.93 2.93 3.01 3.06 3.08 2.82 2.88 2.90

 Industrial3 ........................ 0.75 0.76 0.83 0.83 0.76 0.86 0.90 0.82 0.92 0.96

 Electric Generators4 ............... 0.48 0.45 0.65 0.65 0.45 0.61 0.64 0.63 0.81 0.80

 Transportation5 ................... 5.10 4.49 4.50 4.50 4.59 4.66 4.65 4.48 4.52 4.51

 Average6 ....................... 2.05 1.87 1.72 1.73 1.75 1.67 1.68 1.59 1.58 1.59

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ....................... 21.61 22.96 22.11 22.10 22.55 22.03 21.79 22.62 22.26 22.18

 Commercial ...................... 10.36 10.71 10.18 10.17 11.40 10.96 10.78 11.32 11.20 11.24

 Industrial3 ........................ 6.00 6.72 7.12 7.12 7.10 7.84 8.01 8.34 9.27 9.45

 Electric Generators4 ............... 1.77 2.35 6.12 6.01 3.03 6.44 7.14 7.00 12.59 12.64

 Transportation5 ................... 0.08 0.24 0.24 0.24 0.42 0.41 0.40 0.69 0.65 0.64

 Total .......................... 39.82 42.98 45.76 45.64 44.49 47.68 48.13 49.97 55.97 56.14

 1

Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 151

Table D9. Oil and Gas Supply

Production and Supply 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated

2005

Integrated 

-7 2005

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ..................... 16.49 20.42 20.39 20.39 20.81 20.79 20.70 21.46 21.45 21.46

Production (million barrels per day)

2

 U.S. Total .................................. 5.88 5.60 5.56 5.56 5.15 5.16 5.17 5.01 5.33 5.42

 Lower 48 Onshore ........................... 3.27 2.75 2.77 2.77 2.49 2.54 2.57 2.63 2.72 2.75

 Conventional .............................. 2.59 2.15 2.17 2.17 1.82 1.93 1.95 1.91 2.05 2.10

 Enhanced Oil Recovery ..................... 0.68 0.61 0.60 0.60 0.66 0.62 0.62 0.72 0.67 0.64

 Lower 48 Offshore ........................... 1.56 2.05 2.00 2.00 2.02 1.98 1.96 1.75 1.97 2.03

 Alaska .................................... 1.05 0.79 0.79 0.79 0.64 0.64 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 . 18.33 15.46 15.43 15.43 14.03 14.25 14.22 13.43 14.28 14.51

 Natural Gas

 Lower 48 Average Wellhead Price3

 (1999 dollars per thousand cubic feet) ......... 2.08 2.49 3.45 3.46 2.68 3.83 4.33 3.14 4.04 4.30

Production (trillion cubic feet)3

 U.S. Total .................................. 18.67 20.72 23.62 23.48 23.03 25.05 25.08 28.84 31.21 30.98

 Lower 48 Onshore ........................... 12.83 14.33 16.57 16.46 16.32 18.05 18.09 21.20 22.93 22.74

 Associated-Dissolved4 ....................... 1.80 1.51 1.51 1.51 1.34 1.40 1.41 1.35 1.40 1.42

 Non-Associated ............................ 11.03 12.82 15.05 14.94 14.98 16.65 16.68 19.85 21.53 21.32

 Conventional ............................. 6.64 7.19 8.81 8.73 8.31 9.15 9.30 11.38 11.13 10.79

 Unconventional ........................... 4.39 5.62 6.24 6.21 6.66 7.51 7.38 8.48 10.40 10.53

 Lower 48 Offshore ........................... 5.43 5.93 6.59 6.56 6.21 6.50 6.49 7.07 7.72 7.68

 Associated-Dissolved4 ....................... 0.93 1.07 1.07 1.07 1.07 1.05 1.05 1.01 1.05 1.07

 Non-Associated ............................ 4.50 4.85 5.52 5.49 5.13 5.44 5.44 6.06 6.66 6.61

 Alaska .................................... 0.42 0.47 0.46 0.46 0.50 0.50 0.50 0.57 0.57 0.57

Lower 48 End of Year Reserves 

 (trillion cubic feet) .......................... 157.41 166.23 167.12 167.03 174.58 188.57 187.82 188.20 215.38 223.35

 Supplemental Gas Supplies (trillion cubic feet)5 . . 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) .............. 17.94 24.11 29.88 29.94 28.67 36.99 39.50 39.25 48.36 51.52

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
152 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Production1

 Appalachia ............................. 434 422 292 297 412 271 252 395 219 208

 Interior ................................ 185 180 94 95 177 82 74 163 74 65

 West ................................. 485 633 435 424 708 440 395 784 370 302

 East of the Mississippi .................... 561 554 352 357 545 325 301 525 268 255

 West of the Mississippi ................... 543 681 469 459 752 468 419 817 395 319

 Total ................................ 1105 1235 821 816 1297 793 721 1342 663 574

 Net Imports

 Imports ................................ 9 16 12 12 17 9 9 20 9 9

 Exports ................................ 58 60 60 60 58 59 59 56 58 58

 Total ................................. -49 -44 -48 -48 -40 -50 -50 -36 -49 -49

 Total Supply2 ........................... 1055 1191 773 767 1256 743 670 1306 614 526

 Consumption by Sector

 Residential and Commercial ............... 55 5 5 5 5 5 5 5 5

 Industrial3 .............................. 79 83 84 84 84 88 88 86 91 92

 Coke Plants ............................ 28 26 26 26 23 23 23 19 19 18

 Electric Generators4 ..................... 922 1078 654 656 1145 628 555 1198 493 410

 Total ................................ 1034 1192 769 771 1257 744 670 1308 609 525

 Discrepancy and Stock Change5

. .......... 21 -1 4 -3 -1 -1 -0 -2 6 0

 Average Minemouth Price

 (1999 dollars per short ton) ................ 17.23 14.76 12.92 13.07 13.69 11.93 11.82 12.84 10.93 11.18 

 (1999 dollars per million Btu) ............... 0.82 0.72 0.63 0.63 0.67 0.58 0.58 0.63 0.54 0.54 

 Delivered Prices (1999 dollars per short ton)6 

 Industrial .............................. 31.46 29.43 27.06 27.14 28.41 25.79 25.40 26.55 23.08 22.73 

 Coke Plants ............................ 44.20 42.47 42.61 42.61 41.29 41.13 41.24 38.57 38.36 38.35 

 Electric Generators

 (1999 dollars per short ton) ............... 24.78 22.62 19.05 19.07 20.84 18.03 17.56 19.40 15.54 15.17 

 (1999 dollars per million Btu) ............. 1.22 1.13 0.97 0.96 1.05 0.92 0.90 0.98 0.80 0.78 

 Average ............................. 25.82 23.53 20.72 20.75 21.72 19.66 19.40 20.15 17.38 17.33 

 Exports7 ............................... 37.43 36.32 35.45 35.51 35.54 34.16 34.01 33.13 31.26 31.00 

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators. 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B. Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 153

Table D11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ........... 78.14 78.62 79.92 79.92 78.74 80.04 80.04 78.74 80.04 80.05

 Geothermal2 ..................... 2.87 3.16 5.71 5.56 4.31 11.14 11.74 4.34 11.21 12.20

 Municipal Solid Waste3 ............. 2.59 3.15 3.92 3.91 3.56 4.36 4.36 4.07 4.88 4.90

 Wood and Other Biomass4 .......... 1.52 1.68 2.03 2.03 2.04 2.48 3.25 2.37 5.51 11.98

 Solar Thermal .................... 0.33 0.35 0.35 0.35 0.40 0.40 0.40 0.48 0.48 0.48

 Solar Photovoltaic ................. 0.01 0.09 0.09 0.09 0.21 0.21 0.21 0.54 0.54 0.54

 Wind ........................... 2.60 4.43 4.59 4.63 5.51 6.04 6.47 5.78 15.43 23.75

 Total .......................... 88.07 91.47 96.61 96.49 94.76 104.66 106.48 96.33 118.08 133.90

 Generation (billion kilowatthours)

 Conventional Hydropower ........... 307.43 299.05 303.48 303.48 298.99 303.40 303.39 297.94 302.33 302.33

 Geothermal2 ..................... 13.07 15.90 45.56 44.36 24.98 88.34 93.12 25.33 88.95 96.79

 Municipal Solid Waste3 ............. 18.05 22.30 28.28 28.25 24.94 31.23 31.27 28.85 35.21 35.38

 Wood and Other Biomass4 .......... 8.86 14.45 48.32 48.58 21.55 76.11 71.94 22.15 82.56 118.20

 Dedicated Plants ................ 7.56 8.67 11.09 11.08 10.88 13.83 19.00 13.35 34.30 77.46

 Cofiring ........................ 1.30 5.78 37.23 37.50 10.67 62.28 52.94 8.80 48.26 40.73

 Solar Thermal .................... 0.89 0.96 0.96 0.96 1.11 1.11 1.11 1.37 1.37 1.37

 Solar Photovoltaic ................. 0.03 0.20 0.20 0.20 0.51 0.51 0.51 1.36 1.36 1.36

 Wind ........................... 4.46 9.42 9.88 9.98 12.33 13.85 15.11 13.10 43.86 68.39

 Total .......................... 352.79 362.28 436.68 435.82 384.41 514.54 516.46 390.09 555.64 623.82

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste .............. 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

 Biomass ......................... 4.65 5.17 5.09 5.09 6.06 6.06 6.07 7.54 7.56 7.65

 Total .......................... 5.35 5.87 5.79 5.79 6.76 6.76 6.76 8.23 8.26 8.35

 Generation (billion kilowatthours)

 Municipal Solid Waste .............. 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03

 Biomass ......................... 27.08 29.92 29.43 29.44 35.01 34.95 34.96 43.52 43.62 44.12

 Total .......................... 31.10 33.95 33.46 33.46 39.03 38.97 38.99 47.55 47.65 48.14

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 .......... 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................. 0.01 0.10 0.10 0.10 0.35 0.35 0.35 0.35 0.35 0.35

 Total .......................... 1.00 1.09 1.09 1.09 1.34 1.34 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 .......... 4.57 4.44 4.44 4.44 4.43 4.43 4.43 4.41 4.41 4.41

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................ 0.02 0.20 0.20 0.20 0.75 0.75 0.75 0.75 0.75 0.76

 Total ......................... 4.59 4.64 4.64 4.64 5.18 5.18 5.18 5.17 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
154 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

Marketed Renewable Energy2

 Residential .................................. 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Wood ...................................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Commercial ................................. 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Biomass .................................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Industrial3 .................................. 2.15 2.42 2.39 2.39 2.64 2.64 2.64 3.08 3.08 3.12

 Conventional Hydroelectric ..................... 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ......................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Biomass .................................... 1.97 2.23 2.21 2.21 2.46 2.45 2.46 2.90 2.90 2.94

 Transportation ............................... 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

 Ethanol used in E854 .......................... 0.00 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.03 0.03

 Ethanol used in Gasoline Blending ............... 0.12 0.18 0.18 0.18 0.19 0.19 0.19 0.20 0.21 0.21

 Electric Generators5 .......................... 3.86 4.03 5.31 5.29 4.47 7.05 7.16 4.56 7.49 8.29

 Conventional Hydroelectric ..................... 3.17 3.08 3.12 3.12 3.08 3.12 3.12 3.06 3.11 3.11

 Geothermal ................................. 0.27 0.37 1.18 1.15 0.66 2.55 2.69 0.67 2.56 2.81

 Municipal Solid Waste6 ........................ 0.25 0.30 0.39 0.39 0.34 0.43 0.43 0.39 0.48 0.48

 Biomass .................................... 0.12 0.18 0.51 0.51 0.26 0.80 0.75 0.27 0.86 1.16

 Dedicated Plants ........................... 0.10 0.11 0.12 0.12 0.13 0.15 0.20 0.16 0.36 0.76

 Cofiring ................................... 0.02 0.07 0.39 0.40 0.13 0.66 0.55 0.11 0.50 0.40

 Solar Thermal ............................... 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ............................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Wind ...................................... 0.05 0.10 0.10 0.10 0.13 0.14 0.16 0.13 0.45 0.70

 Total Marketed Renewable Energy .............. 6.61 7.16 8.41 8.39 7.84 10.41 10.52 8.40 11.32 12.16

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ................................. 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.03 0.03

 Solar Hot Water Heating ....................... 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps ....................... 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Commercial ................................. 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Thermal ............................... 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.19 0.19 0.19 0.19 0.16 0.17 0.17

 From Cellulose ..................... 0.00 0.01 0.01 0.01 0.02 0.02 0.02 0.07 0.07 0.07

 Total ............................ 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 155

Table D13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005 Reference Integrated2005

Integrated 

-7 2005

 Residential

 Petroleum .......................... 26.0 26.8 26.9 26.9 24.4 24.7 24.7 22.9 23.5 23.5

 Natural Gas ......................... 69.5 78.6 76.4 76.3 82.0 78.7 77.4 90.8 87.6 86.7

 Coal ............................... 1.1 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.2 1.2

 Electricity ........................... 192.6 223.2 165.0 164.8 240.4 165.0 154.2 274.7 170.2 157.6

 Total ............................. 289.3 330.0 269.6 269.4 348.1 269.8 257.7 389.6 282.7 269.0

 Commercial

 Petroleum .......................... 13.7 12.9 13.1 13.1 13.1 14.0 14.2 12.9 14.5 15.2

 Natural Gas ......................... 45.4 53.5 51.5 51.4 56.0 52.9 51.8 59.4 57.6 57.3

 Coal ............................... 1.7 1.8 1.8 1.8 1.9 1.9 1.9 2.0 2.0 2.0

 Electricity ........................... 182.1 216.0 158.2 158.2 237.0 162.7 151.9 265.8 164.0 151.2

 Total ............................. 242.9 284.1 224.6 224.5 307.9 231.5 219.7 340.0 238.0 225.7

 Industrial1

 Petroleum .......................... 104.2 99.0 101.9 101.9 104.7 109.9 112.6 115.6 122.2 126.1

 Natural Gas2 ........................ 141.6 147.8 146.7 146.5 157.6 156.5 152.6 174.9 175.0 171.3

 Coal ............................... 55.9 66.5 67.0 67.0 66.3 67.9 68.0 66.4 68.7 69.1

 Electricity ........................... 178.8 193.9 146.7 146.6 203.0 141.7 133.4 228.1 137.3 126.0

 Total ............................. 480.4 507.2 462.3 462.0 531.6 476.1 466.6 584.9 503.2 492.5

 Transportation

 Petroleum3 .......................... 485.8 556.8 551.1 551.1 608.6 604.7 604.0 705.1 701.4 700.8

 Natural Gas4 ........................ 9.5 11.8 13.3 13.3 14.1 15.3 15.3 17.9 19.5 19.6

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 2.9 4.4 3.4 3.4 5.7 4.2 4.0 7.9 5.2 4.8

 Total3 ............................. 498.2 573.1 567.9 567.9 628.6 624.3 623.4 730.9 726.2 725.3

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 629.7 695.5 693.0 693.1 750.8 753.3 755.5 856.4 861.7 865.5

 Natural Gas 266.0 291.8 287.9 287.5 309.7 303.4 297.2 342.9 339.7 334.9

 Coal ............................... 58.8 69.6 70.0 70.0 69.5 71.1 71.2 69.6 72.0 72.3

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 556.3 637.5 473.4 473.0 686.1 473.7 443.5 776.5 476.7 439.6

 Total3 ............................. 1510.8 1694.3 1524.3 1523.7 1816.2 1601.6 1567.5 2045.4 1750.1 1712.4

 Electric Generators6

 Petroleum .......................... 20.0 6.8 4.3 4.2 3.5 2.9 2.8 3.9 2.1 2.0

 Natural Gas ......................... 45.8 77.1 138.6 136.5 98.6 154.8 162.6 164.1 229.2 232.3

 Coal ............................... 490.5 553.6 330.5 332.4 584.0 315.9 278.1 608.4 245.4 205.3

 Total ............................. 556.3 637.5 473.4 473.0 686.1 473.7 443.5 776.5 476.7 439.6

 Total Carbon Dioxide Emissions

 by Primary Fuel7

 Petroleum3 .......................... 649.7 702.2 697.3 697.2 754.3 756.2 758.3 860.3 863.8 867.5

 Natural Gas ......................... 311.8 368.9 426.5 423.9 408.2 458.2 459.8 507.1 568.9 567.2

 Coal ............................... 549.3 623.1 400.4 402.4 653.5 387.0 349.3 678.0 317.3 277.6

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total3 ............................. 1510.8 1694.3 1524.3 1523.7 1816.2 1601.6 1567.5 2045.4 1750.1 1712.4

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) .... 5.5 5.9 5.3 5.3 6.1 5.3 5.2 6.3 5.4 5.3

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 25 to 30 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
156 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table D14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999

Projections

2005 2010 2020

Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated

2005

Integrated 

-7 2005 Reference Integrated

2005

Integrated 

-7 2005

 Scrubber Retrofits (gigawatts)1 .............. 0.00 10.76 12.55 9.94 10.76 15.36 9.94 15.24 20.56 16.68

 SO2 Allowance Price

 (1999 dollars per ton) ..................... 0.00 177.63 246.62 201.24 169.55 220.81 226.44 246.09 162.29 98.67

 NOx Controls (gigawatts)

 Combustion .............................. 0.00 65.84 113.11 112.22 66.93 113.11 112.22 67.57 113.11 112.22

 SCR Post-combustion ...................... 0.00 84.31 157.37 146.83 85.97 157.37 147.16 89.75 157.37 147.16

 SNCR Post-combustion ..................... 0.00 25.36 55.96 49.31 28.78 55.96 49.48 38.69 55.96 49.48

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) .............. 472.31 598.07 440.89 427.09 656.33 442.65 395.78 730.01 356.86 288.60

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) ........ 433.55 451.27 275.34 282.45 453.06 254.48 236.49 438.05 216.69 204.51

 High Sulfur (> 1.67 lbs. S/mmBtu) ............. 198.66 185.83 105.20 106.26 187.25 95.98 88.25 174.20 89.75 81.27

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here.

 SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL05.D121300A, and FDP7B05.D121300B.
Appendix E

Tables for Integrated Cases with 2008 Emission Caps

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 159

Table E1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Production

 Crude Oil and Lease Condensate ... 12.45 11.85 11.81 11.81 10.90 10.92 10.84 10.61 11.21 11.36

 Natural Gas Plant Liquids ......... 2.62 3.02 3.17 3.19 3.31 3.66 3.72 4.07 4.36 4.40

 Dry Natural Gas ................. 19.16 21.26 22.37 22.46 23.63 26.16 26.63 29.59 31.70 31.99

 Coal .......................... 23.12 25.43 20.35 20.54 26.47 16.33 13.58 27.21 13.47 11.69

 Nuclear Power .................. 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.06 7.32

 Renewable Energy1 .............. 6.50 6.98 8.29 8.30 7.65 10.10 10.52 8.20 11.06 11.88

 Other2 ........................ 1.65 0.57 0.59 0.58 0.33 0.30 0.30 0.33 0.33 0.33

 Total ....................... 73.30 77.01 74.49 74.79 79.98 75.38 73.50 86.18 79.19 78.99

 Imports

 Crude Oil3 ..................... 18.96 23.21 22.90 22.90 25.22 24.85 24.90 26.48 25.87 25.70

 Petroleum Products4 ............. 4.14 4.85 4.68 4.68 6.46 6.44 6.44 10.77 11.02 11.01

 Natural Gas .................... 3.63 4.90 5.47 5.48 5.49 6.51 6.70 6.60 7.93 8.04

 Other Imports5 .................. 0.64 1.11 1.02 1.02 0.96 0.88 0.88 0.96 0.82 0.82

 Total ....................... 27.37 34.08 34.07 34.07 38.12 38.68 38.93 44.82 45.63 45.57

 Exports

 Petroleum6 ..................... 1.98 1.81 1.80 1.80 1.79 1.79 1.77 1.90 1.93 1.92

 Natural Gas .................... 0.17 0.33 0.12 0.12 0.43 0.12 0.12 0.63 0.12 0.12

 Coal .......................... 1.48 1.51 1.51 1.51 1.45 1.51 1.43 1.41 1.44 1.44

 Total ....................... 3.62 3.64 3.43 3.43 3.67 3.42 3.32 3.94 3.49 3.48

 Discrepancy7 .................... 0.95 0.39 -0.07 0.40 0.21 0.45 -0.25 -0.03 0.13 0.03

 Consumption

 Petroleum Products8 ............. 38.07 41.40 41.08 41.07 44.43 44.42 44.48 50.60 51.00 51.04

 Natural Gas .................... 21.90 25.78 27.64 27.75 28.52 32.30 32.99 35.40 39.33 39.72

 Coal .......................... 21.46 24.37 19.68 19.38 25.54 14.95 12.95 26.48 12.37 10.68

 Nuclear Power ................. . 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.06 7.32

 Renewable Energy1 .............. 6.51 6.98 8.30 8.30 7.66 10.10 10.53 8.21 11.06 11.89

 Other9 ........................ 0.35 0.61 0.61 0.61 0.38 0.51 0.51 0.25 0.38 0.38

 Total ........................ 96.09 107.05 105.20 105.02 114.21 110.19 109.36 127.10 121.20 121.04

 Net Imports - Petroleum ........... 21.12 26.26 25.79 25.78 29.88 29.50 29.58 35.36 34.96 34.79

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 . . 17.35 20.83 20.83 20.83 21.37 21.37 21.37 22.41 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 2.08 2.49 2.85 2.85 2.68 3.75 4.16 3.14 4.32 4.42

 Coal Minemouth Price (dollars per ton) 17.23 14.76 13.70 13.70 13.69 11.86 12.03 12.84 10.87 11.16

 Average Electric Price (cents per Kwh) 6.6 6.2 7.3 7.2 5.9 7.7 8.2 6.0 7.7 7.9

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
160 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

Energy Consumption

 Residential

 Distillate Fuel ........................ 0.86 0.88 0.89 0.89 0.81 0.81 0.81 0.75 0.76 0.77

 Kerosene ........................... 0.10 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas ............... 0.46 0.45 0.46 0.46 0.41 0.42 0.42 0.39 0.41 0.41

 Petroleum Subtotal .................. 1.42 1.42 1.43 1.43 1.29 1.31 1.31 1.21 1.24 1.24

 Natural Gas ......................... 4.85 5.46 5.40 5.40 5.69 5.50 5.42 6.30 6.05 6.00

 Coal ............................... 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

 Renewable Energy1 ................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Electricity ........................... 3.91 4.50 4.33 4.34 4.96 4.64 4.57 5.80 5.41 5.39

 Delivered Energy ................... 10.62 11.86 11.63 11.65 12.42 11.92 11.78 13.80 13.17 13.10

 Electricity Related Losses .............. 8.46 9.46 9.01 8.93 9.88 8.80 8.62 10.58 9.00 8.99

 Total ............................. 19.08 21.32 20.64 20.58 22.30 20.72 20.39 24.38 22.17 22.09

 Commercial

 Distillate Fuel ........................ 0.36 0.41 0.41 0.41 0.41 0.44 0.44 0.39 0.46 0.49

 Residual Fuel ....................... 0.10 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.11

 Kerosene ........................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas ............... 0.08 0.09 0.09 0.09 0.09 0.09 0.09 0.10 0.10 0.10

 Motor Gasoline2 ...................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal .................. 0.59 0.66 0.66 0.66 0.67 0.69 0.70 0.66 0.73 0.76

 Natural Gas ......................... 3.15 3.71 3.66 3.66 3.89 3.70 3.63 4.12 3.97 3.95

 Coal ............................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.08

 Renewable Energy3 ................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Electricity ........................... 3.70 4.35 4.18 4.20 4.89 4.59 4.54 5.61 5.22 5.19

 Delivered Energy ................... 7.59 8.87 8.65 8.67 9.60 9.14 9.03 10.55 10.08 10.05

 Electricity Related Losses .............. 8.00 9.15 8.69 8.64 9.74 8.71 8.56 10.23 8.68 8.66

 Total ............................. 15.59 18.02 17.34 17.31 19.34 17.85 17.59 20.79 18.76 18.71

 Industrial4

 Distillate Fuel ........................ 1.07 1.13 1.12 1.12 1.27 1.27 1.28 1.44 1.46 1.46

 Liquefied Petroleum Gas ............... 2.32 2.45 2.45 2.44 2.50 2.58 2.63 2.83 3.10 3.10

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.52 1.52 1.70 1.69 1.69

 Residual Fuel ....................... 0.22 0.22 0.22 0.22 0.25 0.37 0.38 0.27 0.41 0.41

 Motor Gasoline2 ...................... 0.21 0.23 0.23 0.23 0.25 0.24 0.24 0.28 0.28 0.28

 Other Petroleum5 ..................... 4.29 4.49 4.49 4.49 4.76 4.79 4.84 5.25 5.40 5.45

 Petroleum Subtotal .................. 9.39 9.95 9.92 9.92 10.55 10.77 10.90 11.78 12.34 12.39

 Natural Gas6 ........................ 9.43 10.42 10.48 10.47 11.11 11.02 10.79 12.33 11.98 11.97

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.60 0.50 0.50 0.50

 Steam Coal ......................... 1.73 1.82 1.83 1.83 1.85 1.90 1.90 1.89 1.99 1.99

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.15 0.15 0.22 0.22 0.23

 Coal Subtotal ....................... 2.54 2.62 2.63 2.63 2.61 2.66 2.66 2.62 2.71 2.72

 Renewable Energy7 ................... 2.15 2.42 2.40 2.40 2.64 2.63 2.63 3.08 3.09 3.13

 Electricity ........................... 3.63 3.90 3.81 3.81 4.19 3.98 3.97 4.81 4.40 4.35

 Delivered Energy ................... 27.15 29.32 29.24 29.23 31.10 31.07 30.95 34.62 34.52 34.55

 Electricity Related Losses .............. 7.85 8.22 7.93 7.84 8.34 7.56 7.48 8.78 7.32 7.26

 Total ............................. 35.00 37.53 37.17 37.07 39.45 38.64 38.43 43.40 41.84 41.82
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 161

Table E2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Transportation

 Distillate Fuel ........................ 5.13 6.28 6.20 6.20 6.99 6.88 6.84 8.21 8.09 8.08

 Jet Fuel8 ........................... 3.46 3.90 3.88 3.88 4.51 4.49 4.48 5.97 5.96 5.96

 Motor Gasoline2 ...................... 15.92 17.70 17.64 17.64 19.05 18.97 18.95 21.32 21.27 21.25

 Residual Fuel ....................... 0.74 0.85 0.85 0.85 0.85 0.85 0.85 0.87 0.86 0.86

 Liquefied Petroleum Gas ............... 0.02 0.03 0.03 0.03 0.04 0.04 0.04 0.06 0.06 0.06

 Other Petroleum9 ..................... 0.26 0.29 0.29 0.29 0.31 0.31 0.31 0.35 0.35 0.35

 Petroleum Subtotal .................. 25.54 29.06 28.89 28.89 31.75 31.53 31.48 36.77 36.59 36.56

 Pipeline Fuel Natural Gas .............. 0.66 0.77 0.82 0.82 0.89 0.98 1.01 1.08 1.20 1.22

 Compressed Natural Gas .............. 0.02 0.06 0.06 0.06 0.09 0.09 0.09 0.16 0.15 0.15

 Renewable Energy (E85)10 ............. 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 0.06 0.09 0.09 0.09 0.12 0.12 0.12 0.17 0.17 0.17

 Delivered Energy ................... 26.28 29.99 29.87 29.88 32.89 32.76 32.73 38.23 38.15 38.14

 Electricity Related Losses .............. 0.13 0.19 0.18 0.18 0.24 0.22 0.22 0.30 0.28 0.28

 Total ............................. 26.41 30.18 30.06 30.06 33.12 32.99 32.95 38.53 38.43 38.42

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ........................ 7.42 8.70 8.61 8.61 9.47 9.39 9.37 10.80 10.78 10.79

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.88 3.88 4.51 4.49 4.48 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.03 3.03 3.05 3.14 3.19 3.38 3.67 3.66

 Motor Gasoline2 ...................... 16.17 17.96 17.89 17.90 19.32 19.24 19.22 21.63 21.58 21.56

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.52 1.52 1.70 1.69 1.69

 Residual Fuel ....................... 1.05 1.17 1.18 1.17 1.21 1.32 1.34 1.25 1.38 1.38

 Other Petroleum12 .................... 4.53 4.76 4.76 4.76 5.04 5.07 5.12 5.58 5.73 5.78

 Petroleum Subtotal .................. 36.95 41.08 40.89 40.89 44.26 44.31 44.38 50.42 50.90 50.95

 Natural Gas6 ........................ 18.11 20.42 20.41 20.40 21.67 21.30 20.94 24.00 23.34 23.29

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.60 0.50 0.50 0.50

 Steam Coal ......................... 1.84 1.94 1.95 1.95 1.98 2.03 2.03 2.02 2.12 2.12

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.15 0.15 0.22 0.22 0.23

 Coal Subtotal ....................... 2.65 2.74 2.75 2.75 2.74 2.79 2.79 2.74 2.84 2.84

 Renewable Energy13 .................. 2.65 2.95 2.94 2.94 3.19 3.17 3.17 3.65 3.64 3.68

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 11.29 12.84 12.41 12.45 14.15 13.32 13.20 16.39 15.19 15.09

 Delivered Energy ................... 71.65 80.04 79.40 79.43 86.01 84.89 84.48 97.20 95.92 95.85

 Electricity Related Losses .............. 24.44 27.02 25.81 25.59 28.20 25.30 24.88 29.89 25.28 25.19

 Total ............................. 96.09 107.05 105.20 105.02 114.21 110.19 109.36 127.10 121.20 121.04

 Electric Generators14

 Distillate Fuel ........................ 0.06 0.05 0.03 0.03 0.04 0.03 0.02 0.04 0.02 0.02

 Residual Fuel ....................... 1.07 0.27 0.15 0.15 0.13 0.09 0.08 0.14 0.08 0.08

 Petroleum Subtotal .................. 1.13 0.32 0.18 0.18 0.17 0.11 0.10 0.19 0.10 0.10

 Natural Gas ......................... 3.79 5.36 7.23 7.35 6.84 11.00 12.04 11.40 15.99 16.44

 Steam Coal ......................... 18.81 21.63 16.93 16.63 22.80 12.17 10.16 23.73 9.53 7.84

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.06 7.32

 Renewable Energy15 .................. 3.86 4.03 5.36 5.37 4.47 6.93 7.36 4.56 7.42 8.21

 Electricity Imports16 ................... 0.35 0.61 0.61 0.61 0.37 0.50 0.50 0.24 0.37 0.37

 Total ............................. 35.73 39.85 38.22 38.04 42.35 38.62 38.08 46.28 40.47 40.28
162 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Total Energy Consumption

 Distillate Fuel ........................ 7.48 8.75 8.64 8.64 9.51 9.42 9.40 10.84 10.79 10.81

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.88 3.88 4.51 4.49 4.48 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.03 3.03 3.05 3.14 3.19 3.38 3.67 3.66

 Motor Gasoline2 ...................... 16.17 17.96 17.89 17.90 19.32 19.24 19.22 21.63 21.58 21.56

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.52 1.52 1.70 1.69 1.69

 Residual Fuel ....................... 2.12 1.44 1.33 1.32 1.34 1.41 1.42 1.39 1.46 1.46

 Other Petroleum12 .................... 4.53 4.76 4.76 4.76 5.04 5.07 5.12 5.58 5.73 5.78

 Petroleum Subtotal .................. 38.07 41.40 41.08 41.07 44.43 44.42 44.48 50.60 51.00 51.04

 Natural Gas ......................... 21.90 25.78 27.64 27.75 28.52 32.30 32.99 35.40 39.33 39.72

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.60 0.50 0.50 0.50

 Steam Coal ......................... 20.65 23.57 18.88 18.58 24.77 14.19 12.19 25.75 11.64 9.96

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.15 0.15 0.22 0.22 0.23

 Coal Subtotal ....................... 21.46 24.37 19.68 19.38 25.54 14.95 12.95 26.48 12.37 10.68

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.06 7.32

 Renewable Energy17 .................. 6.51 6.98 8.30 8.30 7.66 10.10 10.53 8.21 11.07 11.89

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 ................... 0.35 0.61 0.61 0.61 0.37 0.50 0.50 0.24 0.37 0.37

 Total ............................. 96.09 107.05 105.20 105.02 114.21 110.19 109.36 127.10 121.20 121.04

Energy Use and Related Statistics

 Delivered Energy Use .................. 71.65 80.04 79.40 79.43 86.01 84.89 84.48 97.20 95.92 95.85

 Total Energy Use ..................... 96.09 107.05 105.20 105.02 114.21 110.19 109.36 127.10 121.20 121.04

 Population (millions) .................... 273.13 288.02 288.02 288.02 300.17 300.17 300.17 325.24 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 10960 10888 10888 12667 12618 12606 16515 16523 16523

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) .... 1510.8 1694.3 1589.8 1589.6 1816.2 1602.8 1553.8 2045.4 1747.7 1710.6

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which produces electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDPOL08.D121500A, and FDP7B08.D121500A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 163

Table E3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Residential ......................... 13.12 12.91 14.14 14.10 13.15 15.68 16.35 13.59 16.15 16.36

 Primary Energy1 .................... 6.72 7.12 7.35 7.34 7.00 7.78 8.07 7.02 7.96 8.06

 Petroleum Products2 ................ 7.55 9.18 9.12 9.08 9.37 9.31 9.30 9.66 9.79 9.79

 Distillate Fuel ..................... 6.27 7.34 7.33 7.33 7.51 7.47 7.46 7.99 8.01 8.02

 Liquefied Petroleum Gas ............ 10.36 12.83 12.62 12.48 13.06 12.92 12.91 12.90 13.20 13.19

 Natural Gas ....................... 6.52 6.63 6.94 6.94 6.52 7.47 7.83 6.56 7.63 7.76

 Electricity .......................... 23.46 21.84 24.91 24.79 21.88 27.37 28.63 22.16 27.25 27.59

 Commercial ........................ 13.20 12.36 14.34 14.28 11.74 15.22 16.11 12.37 15.52 15.81

 Primary Energy1 .................... 5.22 5.35 5.61 5.61 5.53 6.29 6.58 5.76 6.64 6.74

 Petroleum Products2 ................ 5.00 6.01 5.97 5.96 6.17 6.09 6.07 6.52 6.48 6.46

 Distillate Fuel ..................... 4.37 5.13 5.12 5.12 5.28 5.23 5.22 5.77 5.77 5.77

 Residual Fuel .................... 2.63 3.64 3.62 3.62 3.69 3.69 3.69 3.85 3.84 3.84

 Natural Gas3 ...................... 5.34 5.31 5.62 5.62 5.49 6.43 6.78 5.72 6.78 6.90

 Electricity .......................... 21.43 19.51 23.50 23.35 17.61 23.91 25.35 18.09 23.65 24.18

 Industrial4 .......................... 5.32 5.49 5.97 5.94 5.44 6.47 6.77 5.85 6.90 6.97

 Primary Energy ..................... 3.92 4.25 4.35 4.33 4.37 4.77 4.94 4.73 5.30 5.34

 Petroleum Products2 ................ 5.55 5.95 5.87 5.82 6.05 6.02 6.03 6.28 6.44 6.43

 Distillate Fuel ..................... 4.65 5.29 5.29 5.29 5.46 5.42 5.41 5.98 6.00 6.00

 Liquefied Petroleum Gas ............ 8.50 7.94 7.72 7.58 8.00 7.98 8.01 7.86 8.31 8.30

 Residual Fuel .................... 2.78 3.37 3.34 3.34 3.42 3.33 3.33 3.58 3.49 3.50

 Natural Gas5 ...................... 2.79 3.17 3.52 3.52 3.30 4.28 4.67 3.77 4.93 5.03

 Metallurgical Coal .................. 1.65 1.58 1.59 1.59 1.54 1.54 1.53 1.44 1.43 1.43

 Steam Coal ....................... 1.43 1.34 1.29 1.29 1.29 1.18 1.15 1.21 1.05 1.04

 Electricity .......................... 13.01 12.30 15.13 15.02 11.21 16.10 17.14 11.60 15.93 16.32

 Transportation ...................... 8.30 9.27 9.30 9.30 9.45 9.54 9.56 9.32 9.34 9.34

 Primary Energy ..................... 8.29 9.25 9.28 9.28 9.44 9.52 9.53 9.30 9.32 9.31

 Petroleum Products2 ................ 8.28 9.25 9.28 9.28 9.44 9.51 9.52 9.30 9.31 9.31

 Distillate Fuel6 .................... 8.22 8.89 8.90 8.90 8.94 8.93 8.92 9.02 9.06 9.07

 Jet Fuel7 ........................ 4.70 5.24 5.22 5.23 5.46 5.46 5.46 5.88 5.88 5.88

 Motor Gasoline8 ................... 9.45 10.64 10.68 10.69 10.92 11.05 11.07 10.68 10.68 10.67

 Residual Fuel .................... 2.46 3.10 3.10 3.10 3.18 3.18 3.18 3.33 3.33 3.33

 Liquid Petroleum Gas9 .............. 12.87 14.19 14.04 13.93 14.24 14.22 14.23 13.88 14.21 14.20

 Natural Gas10 ...................... 7.02 6.80 7.12 7.12 7.03 8.01 8.36 7.33 8.36 8.45

 Ethanol (E85)11 .................... 14.42 19.12 19.14 19.14 19.00 19.17 19.24 19.36 19.50 19.52

 Methanol (M85)12 ................... 10.38 13.11 13.05 13.05 13.74 13.85 14.25 14.43 14.42 14.42

 Electricity .......................... 15.58 14.29 15.77 15.70 13.53 16.06 16.51 13.03 14.94 14.98

 Average End-Use Energy ............. 8.53 8.90 9.48 9.46 8.94 10.05 10.34 9.17 10.21 10.29

 Primary Energy ..................... 6.33 7.00 7.09 7.08 7.18 7.48 7.60 7.31 7.65 7.68

 Electricity .......................... 19.40 18.10 21.36 21.25 17.18 22.71 23.94 17.57 22.60 23.03

 Electric Generators13

 Fossil Fuel Average .................. 1.49 1.50 1.69 1.70 1.52 2.42 2.83 1.85 3.32 3.58

 Petroleum Products ................. 2.50 3.70 3.83 3.84 4.06 4.24 4.29 4.33 4.57 4.60

 Distillate Fuel ..................... 4.04 4.65 4.68 4.69 4.85 4.83 4.81 5.30 5.26 5.26

 Residual Fuel .................... 2.41 3.52 3.66 3.67 3.85 4.07 4.14 4.04 4.44 4.46

 Natural Gas ....................... 2.54 2.89 3.23 3.24 3.02 4.07 4.48 3.61 4.81 4.92

 Steam Coal ....................... 1.22 1.13 1.00 1.00 1.05 0.91 0.87 0.98 0.80 0.77
164 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Average Price to All Users14

 Petroleum Products2 ................. 7.43 8.43 8.44 8.43 8.63 8.67 8.67 8.62 8.66 8.65

 Distillate Fuel ...................... 7.27 8.07 8.07 8.08 8.18 8.15 8.14 8.41 8.42 8.42

 Jet Fuel .......................... 4.70 5.24 5.22 5.23 5.46 5.46 5.46 5.88 5.88 5.88

 Liquefied Petroleum Gas ............. 8.84 8.83 8.63 8.49 8.87 8.82 8.84 8.64 9.04 9.02

 Motor Gasoline8 .................... 9.45 10.64 10.68 10.68 10.92 11.05 11.07 10.68 10.68 10.67

 Residual Fuel ..................... 2.48 3.26 3.25 3.24 3.33 3.31 3.31 3.49 3.48 3.48

 Natural Gas ....................... 4.05 4.25 4.48 4.47 4.27 5.08 5.42 4.52 5.55 5.65

 Coal .............................. 1.24 1.15 1.03 1.03 1.07 0.95 0.92 1.00 0.84 0.83

 Ethanol (E85)11 ..................... 14.42 19.12 19.14 19.14 19.00 19.17 19.24 19.36 19.50 19.52

 Methanol (M85)12 .................... 10.38 13.11 13.05 13.05 13.74 13.85 14.25 14.43 14.42 14.42

 Electricity .......................... 19.40 18.10 21.36 21.25 17.18 22.71 23.94 17.57 22.60 23.03

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ........................... 134.05 147.53 158.44 158.17 157.75 180.21 185.56 181.60 205.85 207.40

 Commercial .......................... 99.10 108.63 122.81 122.69 111.63 137.79 144.07 129.48 155.18 157.62

 Industrial ............................ 110.62 121.27 132.61 131.82 126.35 151.37 158.01 151.05 178.67 180.56

 Transportation ........................ 212.64 270.40 269.78 269.89 301.90 302.62 302.53 345.30 344.36 344.02

 Total Non-Renewable Expenditures ..... 556.41 647.83 683.63 682.56 697.64 771.98 790.16 807.43 884.07 889.61

 Transportation Renewable Expenditures . . 0.14 0.42 0.41 0.41 0.61 0.61 0.62 0.86 0.86 0.86

 Total Expenditures .................. 556.55 648.25 684.05 682.98 698.25 772.59 790.78 808.29 884.93 890.46

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report,

DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and

FDP7B08.D121500A. 1999 electricity prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDPOL08.D121500A, and FDP7B08.D121500A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and

FDP7B08.D121500A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 165

Table E4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

Generation by Fuel Type

 Electric Generators1

 Coal ............................ 1835 2103 1671 1643 2232 1210 1016 2317 947 784

 Petroleum ....................... 104 32 19 19 18 12 11 19 11 11

 Natural Gas2 ..................... 365 574 804 843 867 1475 1623 1568 2296 2349

 Nuclear Power .................... 730 740 740 740 720 741 741 577 661 686

 Pumped Storage .................. -1 -1 -1 -1 -1 -1 -1 -1 -1 -1

 Renewable Sources3 ............... 353 362 443 443 384 509 518 390 554 604

 Total .......................... 3386 3811 3677 3687 4220 3946 3907 4872 4468 4433

 Non-Utility Generation for Own Use ... 16 16 22 22 16 21 21 16 20 20

 Distributed Generation ............. 0100300600

 Cogenerators4

 Coal ........................... 47 52 52 52 52 51 51 52 51 50

 Petroleum ...................... 9 10 10 10 10 10 10 10 10 10

 Natural Gas ..................... 206 239 256 255 256 314 312 298 450 467

 Other Gaseous Fuels5 ............. 4666777888

 Renewable Sources3 .............. 31 34 34 34 39 39 39 48 48 49

 Other6 ......................... 5555555555

 Total ......................... 302 347 363 363 369 427 424 421 572 590

 Other End-Use Generators7 ......... 5555555555

 Sales to Utilities .................. 150 171 176 176 176 189 185 200 232 235

 Generation for Own Use ............ 156 180 192 192 198 243 243 226 346 359

 Net Imports8 ...................... 33 57 57 57 35 47 47 23 35 35

Electricity Sales by Sector

 Residential ........................ 1146 1317 1270 1273 1452 1359 1340 1699 1586 1579

 Commercial ....................... 1083 1275 1225 1231 1432 1344 1331 1644 1530 1520

 Industrial ......................... 1063 1144 1117 1118 1227 1167 1163 1411 1289 1275

 Transportation ..................... 17 26 26 26 35 34 34 49 49 48

 Total ........................... 3309 3762 3638 3648 4146 3905 3868 4803 4453 4422

End-Use Prices (1999 cents per kwh)9

 Residential ........................ 8.0 7.5 8.5 8.5 7.5 9.3 9.8 7.6 9.3 9.4

 Commercial ....................... 7.3 6.7 8.0 8.0 6.0 8.2 8.6 6.2 8.1 8.2

 Industrial ......................... 4.4 4.2 5.2 5.1 3.8 5.5 5.8 4.0 5.4 5.6

 Transportation ..................... 5.3 4.9 5.4 5.4 4.6 5.5 5.6 4.4 5.1 5.1

 All Sectors Average .............. 6.6 6.2 7.3 7.2 5.9 7.7 8.2 6.0 7.7 7.9

 Prices by Service Category9

 (1999 cents per kwh)

 Generation ........................ 4.1 3.6 4.7 4.6 3.2 5.0 5.4 3.4 5.0 5.2

 Transmission ...................... 0.6 0.6 0.7 0.7 0.7 0.7 0.8 0.7 0.7 0.7

 Distribution ....................... 2.0 2.0 2.0 2.0 2.0 2.1 2.1 2.0 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide ..................... 13.82 10.39 8.23 8.24 9.70 4.52 4.02 8.95 3.27 3.27

 Nitrogen Oxide .................... 5.46 4.22 2.79 2.74 4.20 1.42 1.32 4.37 1.22 1.16

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
166 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

Electric Generators2

 Capability

 Coal Steam ................... 306.2 302.4 299.2 299.5 317.4 271.8 265.3 317.8 239.1 217.4

 Other Fossil Steam3 ............ 138.2 129.6 125.5 125.6 121.1 115.1 115.3 117.2 97.6 94.3

 Combined Cycle ............... 20.2 49.4 69.6 71.1 124.0 170.0 198.6 230.0 280.9 288.5

 Combustion Turbine/Diesel ....... 75.6 129.7 112.2 113.9 162.1 120.7 120.3 207.7 183.0 193.9

 Nuclear Power ................. 97.4 97.5 97.5 97.5 94.2 96.9 96.9 71.6 84.1 88.4

 Pumped Storage ............... 19.3 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 88.1 91.5 96.3 96.5 94.8 104.0 106.9 96.3 117.9 130.0

 Distributed Generation5 .......... 0.0 2.0 2.0 2.4 6.1 3.6 3.9 14.0 6.7 6.9

 Total ....................... 745.0 821.5 821.7 826.0 939.4 901.6 926.8 1074.3 1029.1 1039.2

 Cumulative Planned Additions6

 Coal Steam ................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Combined Cycle ............... 0.0 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ....... 0.0 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 0.0 2.4 2.4 2.4 4.3 4.3 4.3 5.4 5.4 5.4

 Distributed Generation5 .......... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Total ....................... 0.0 11.5 11.5 11.5 13.6 13.6 13.6 14.8 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam ................... 0.0 2.5 0.0 0.0 20.1 0.0 0.0 21.5 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Combined Cycle ............... 0.0 20.8 41.0 42.5 95.7 141.7 170.3 201.6 252.5 261.3

 Combustion Turbine/Diesel ...... . 0.0 57.0 41.1 42.8 90.8 51.6 51.0 137.2 115.4 127.6

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ............ 0.0 0.6 5.5 5.6 1.9 11.1 14.1 2.4 24.0 36.1

 Distributed Generation5 .......... 0.0 2.0 2.0 2.4 6.1 3.6 3.9 14.0 6.7 6.9

 Total ....................... 0.0 82.9 89.5 93.3 214.6 208.0 239.2 376.7 398.6 432.0

 Cumulative Total Additions ...... 0.0 94.5 101.0 104.9 228.1 221.5 252.8 391.4 413.4 446.8

 Cumulative Retirements7

 Coal Steam ................... 0.0 6.6 7.4 7.0 9.2 35.3 41.7 10.2 67.9 89.6

 Other Fossil Steam3 ............ 0.0 8.5 12.5 12.5 17.0 23.0 22.8 20.9 40.5 43.8

 Combined Cycle ............... 0.0 0.0 0.0 0.0 0.3 0.3 0.3 0.3 0.3 1.4

 Combustion Turbine/Diesel ...... 0.0 3.8 4.6 4.6 5.1 6.7 6.4 5.9 8.2 9.5

 Nuclear Power ................ 0.0 0.0 0.0 0.0 3.3 0.6 0.6 25.9 13.4 9.1

 Pumped Storage .............. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total ...................... 0.0 19.0 24.7 24.2 34.9 66.0 72.0 63.4 130.4 153.6

Cogenerators8

 Capability

 Coal ......................... 8.4 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9

 Petroleum .................... 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 2.8

 Natural Gas ................... 33.8 40.0 41.8 41.7 42.9 50.1 50.2 48.8 69.7 72.1

 Other Gaseous Fuels ........... 0.2 0.8 0.8 0.8 0.9 0.9 0.9 1.0 1.1 1.1

 Renewable Sources4 ............ 5.3 5.9 5.8 5.8 6.8 6.7 6.7 8.2 8.3 8.4

 Other ........................ 1.1 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

 Total ....................... 51.6 59.2 60.9 60.9 63.1 70.3 70.4 70.7 91.7 94.2

 Cumulative Additions6 .......... 0.0 7.5 9.3 9.2 11.4 18.7 18.8 19.0 40.0 42.6
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 167

Table E5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

Other End-Use Generators9

 Renewable Sources ............. 1.0 1.1 1.1 1.1 1.3 1.3 1.3 1.3 1.3 1.3

 Cumulative Additions ............ 0.0 0.1 0.1 0.1 0.3 0.3 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8Nameplate capacity is reported for nonutilities on Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
168 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade .......... 182.2 125.3 125.3 125.3 102.9 102.9 102.9 0.0 0.0 0.0

 Gross Domestic Economy Trade ........... 147.8 202.8 103.4 95.6 183.2 81.8 92.6 206.7 149.6 155.6

 Gross Domestic Trade ................. 330.0 328.1 228.7 220.9 286.1 184.7 195.5 206.7 149.6 155.6

 Gross Domestic Firm Power Sales

 (million 1999 dollars) .................... 8588.1 5905.8 5905.8 5905.8 4851.2 4851.2 4851.2 0.0 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) .................... 4292.5 6044.9 4015.4 3686.4 4987.6 3534.1 4257.2 6227.5 6527.5 6898.6

 Gross Domestic Sales

 (million 1999 dollars) .................. 12880.6 11950. 9921.2 9592.2 9838.8 8385.3 9108.4 6227.5 6527.5 6898.6

 International Electricity Trade

 Firm Power Imports From Canada and Mexico1

 27.0 10.7 10.7 10.7 5.8 17.9 17.9 0.0 12.1 12.1

 Economy Imports From Canada and Mexico1 . . 21.9 63.5 63.5 63.5 45.9 45.9 45.9 30.6 30.6 30.6

 Gross Imports From Canada and Mexico1 . . 48.9 74.1 74.1 74.1 51.7 63.8 63.8 30.6 42.7 42.7

 Firm Power Exports To Canada and Mexico . . 9.2 9.7 9.7 9.7 8.7 8.7 8.7 0.0 0.0 0.0

 Economy Exports To Canada and Mexico .... 6.3 7.0 7.0 7.0 7.7 7.7 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico .... 15.5 16.7 16.7 16.7 16.4 16.4 16.4 7.7 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 169

Table E7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Production

 Dry Gas Production1 ......... 18.67 20.72 21.80 21.89 23.03 25.49 25.95 28.84 30.90 31.18

 Supplemental Natural Gas2 .... 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Net Imports ................ 3.38 4.47 5.23 5.23 4.94 6.25 6.43 5.83 7.64 7.74

 Canada ................... 3.29 4.28 4.49 4.49 4.68 5.19 5.37 5.46 6.06 6.17

 Mexico .................... -0.01 -0.18 0.30 0.30 -0.25 0.32 0.32 -0.40 0.36 0.36

 Liquefied Natural Gas ........ 0.10 0.37 0.44 0.44 0.51 0.73 0.74 0.77 1.22 1.22

 Total Supply ................ 22.15 25.30 27.14 27.24 28.03 31.79 32.44 34.72 38.59 38.98

 Consumption by Sector

 Residential ................. 4.72 5.32 5.25 5.26 5.54 5.35 5.28 6.14 5.89 5.84

 Commercial ................ 3.07 3.62 3.56 3.56 3.78 3.61 3.53 4.02 3.87 3.85

 Industrial3 .................. 7.95 8.80 8.81 8.79 9.33 9.12 8.88 10.17 9.73 9.71

 Electric Generators4 ......... 3.72 5.26 7.10 7.21 6.72 10.80 11.82 11.19 15.69 16.13

 Lease and Plant Fuel5 ........ 1.23 1.35 1.40 1.40 1.49 1.61 1.63 1.83 1.93 1.95

 Pipeline Fuel ............... 0.64 0.75 0.80 0.80 0.87 0.96 0.98 1.06 1.17 1.19

 Transportation6 ............. 0.02 0.05 0.05 0.05 0.09 0.09 0.09 0.15 0.14 0.14

 Total .................... 21.35 25.14 26.97 27.08 27.82 31.53 32.22 34.55 38.42 38.81

 Discrepancy7 ............... 0.80 0.16 0.17 0.16 0.21 0.26 0.22 0.17 0.17 0.18

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A. Other 1999

consumption: EIA, Short-Term Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption

levels for consumption of natural gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A,

and FDP7B08.D121500A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
170 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Source Price 

 Average Lower 48 Wellhead Price1 .... 2.08 2.49 2.85 2.85 2.68 3.75 4.16 3.14 4.32 4.42

 Average Import Price ............... 2.29 2.48 2.65 2.64 2.41 2.76 2.88 2.67 3.23 3.29

 Average2 ....................... 2.11 2.49 2.81 2.81 2.63 3.55 3.90 3.05 4.10 4.19

 Delivered Prices

 Residential ....................... 6.69 6.81 7.13 7.13 6.70 7.67 8.04 6.74 7.84 7.97

 Commercial ...................... 5.49 5.45 5.77 5.77 5.64 6.60 6.96 5.87 6.96 7.09

 Industrial3 ........................ 2.87 3.26 3.61 3.61 3.39 4.40 4.79 3.87 5.06 5.16

 Electric Generators4 ............... 2.59 2.94 3.30 3.30 3.08 4.15 4.56 3.68 4.91 5.01

 Transportation5 ................... 7.21 6.99 7.31 7.31 7.22 8.23 8.58 7.53 8.58 8.68

 Average6 ....................... 4.16 4.36 4.59 4.59 4.38 5.21 5.56 4.64 5.69 5.79

 Transmission & Distribution Margins7

 Residential ....................... 4.58 4.32 4.32 4.31 4.07 4.12 4.15 3.69 3.74 3.78

 Commercial ...................... 3.37 2.96 2.96 2.96 3.01 3.05 3.07 2.82 2.86 2.90

 Industrial3 ........................ 0.75 0.76 0.80 0.80 0.76 0.85 0.89 0.82 0.95 0.97

 Electric Generators4 ............... 0.48 0.45 0.48 0.49 0.45 0.60 0.66 0.63 0.80 0.82

 Transportation5 ................... 5.10 4.49 4.50 4.50 4.59 4.67 4.69 4.48 4.48 4.48

 Average6 ....................... 2.05 1.87 1.78 1.78 1.75 1.65 1.66 1.59 1.59 1.60

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ....................... 21.61 22.96 22.67 22.69 22.55 22.06 21.89 22.62 21.99 22.09

 Commercial ...................... 10.36 10.71 10.54 10.55 11.40 10.99 10.83 11.32 11.06 11.14

 Industrial3 ........................ 6.00 6.72 7.02 7.01 7.10 7.71 7.94 8.34 9.29 9.43

 Electric Generators4 ............... 1.77 2.35 3.43 3.55 3.03 6.46 7.84 7.00 12.58 13.23

 Transportation5 ................... 0.08 0.24 0.24 0.24 0.42 0.41 0.41 0.69 0.65 0.64

 Total .......................... 39.82 42.98 43.90 44.04 44.49 47.63 48.91 49.97 55.57 56.53

1

Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 171

Table E9. Oil and Gas Supply

Production and Supply 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated

2008

Integrated 

-7 2008

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ..................... 16.49 20.42 20.43 20.43 20.81 20.84 20.77 21.46 21.47 21.47

Production (million barrels per day)

2

 U.S. Total .................................. 5.88 5.60 5.58 5.58 5.15 5.16 5.12 5.01 5.29 5.37

 Lower 48 Onshore ........................... 3.27 2.75 2.76 2.76 2.49 2.53 2.53 2.63 2.73 2.76

 Conventional .............................. 2.59 2.15 2.16 2.16 1.82 1.90 1.90 1.91 2.07 2.11

 Enhanced Oil Recovery ..................... 0.68 0.61 0.60 0.61 0.66 0.63 0.63 0.72 0.66 0.65

 Lower 48 Offshore ........................... 1.56 2.05 2.03 2.03 2.02 1.99 1.95 1.75 1.92 1.97

 Alaska .................................... 1.05 0.79 0.79 0.79 0.64 0.64 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 . 18.33 15.46 15.46 15.46 14.03 14.22 14.13 13.43 14.23 14.41

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ......... 2.08 2.49 2.85 2.85 2.68 3.75 4.16 3.14 4.32 4.42

Production (trillion cubic feet)3

 U.S. Total .................................. 18.67 20.72 21.80 21.89 23.03 25.49 25.95 28.84 30.90 31.18

 Lower 48 Onshore ........................... 12.83 14.33 15.09 15.16 16.32 18.56 18.89 21.20 22.80 22.90

 Associated-Dissolved4 ....................... 1.80 1.51 1.51 1.51 1.34 1.38 1.37 1.35 1.41 1.42

 Non-Associated ............................ 11.03 12.82 13.58 13.64 14.98 17.18 17.51 19.85 21.40 21.47

 Conventional ............................. 6.64 7.19 7.76 7.80 8.31 9.46 9.71 11.38 11.22 11.02

 Unconventional ........................... 4.39 5.62 5.82 5.85 6.66 7.72 7.80 8.48 10.17 10.45

 Lower 48 Offshore ........................... 5.43 5.93 6.24 6.27 6.21 6.43 6.56 7.07 7.53 7.72

 Associated-Dissolved4 ....................... 0.93 1.07 1.07 1.07 1.07 1.05 1.05 1.01 1.04 1.05

 Non-Associated ............................ 4.50 4.85 5.17 5.20 5.13 5.38 5.52 6.06 6.49 6.67

 Alaska .................................... 0.42 0.47 0.46 0.46 0.50 0.50 0.50 0.57 0.57 0.57

Lower 48 End of Year Reserves3

 (trillion cubic feet) .......................... 157.41 166.23 168.33 168.01 174.58 184.36 182.87 188.20 212.04 219.65

 Supplemental Gas Supplies (trillion cubic feet)5 . . 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) .............. 17.94 24.11 27.70 27.65 28.67 36.69 38.39 39.25 51.62 52.60.5

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
172 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Production1

 Appalachia ............................. 434 422 344 348 412 269 242 395 215 204

 Interior ................................ 185 180 130 131 177 84 73 163 75 65

 West ................................. 485 633 514 519 708 446 340 784 371 297

 East of the Mississippi .................... 561 554 430 434 545 325 292 525 267 249

 West of the Mississippi ................... 543 681 558 564 752 474 363 817 393 316

 Total ................................ 1105 1235 988 998 1297 799 655 1342 660 565

 Net Imports

 Imports ................................ 9 16 12 12 17 9 9 20 9 9

 Exports ................................ 58 60 60 60 58 60 57 56 58 58

 Total ................................. -49 -44 -48 -48 -40 -51 -48 -36 -49 -49

 Total Supply2 ........................... 1055 1191 940 950 1256 748 607 1306 611 516

 Consumption by Sector

 Residential and Commercial ............... 55 5 5 5 5 5 5 5 5

 Industrial3 .............................. 79 83 84 84 84 87 87 86 91 91

 Coke Plants ............................ 28 26 26 26 23 23 23 19 19 18

 Electric Generators4 ..................... 922 1078 850 835 1145 623 516 1198 493 402

 Total ................................ 1034 1192 965 950 1257 738 631 1308 608 517

 Discrepancy and Stock Change5

. .......... 21 -1 -24 0 -1 10 -23 -2 3 -1 

 Average Minemouth Price

 (1999 dollars per short ton) ................ 17.23 14.76 13.70 13.70 13.69 11.86 12.03 12.84 10.87 11.16 

 (1999 dollars per million Btu) ............... 0.82 0.72 0.67 0.67 0.67 0.58 0.58 0.63 0.53 0.54 

 Delivered Prices (1999 dollars per short ton)6

 Industrial .............................. 31.46 29.43 28.25 28.26 28.41 25.79 25.21 26.55 23.00 22.68 

 Coke Plants ............................ 44.20 42.47 42.58 42.68 41.29 41.25 40.95 38.57 38.42 38.41 

 Electric Generators

 (1999 dollars per short ton) ............... 24.78 22.62 19.91 19.86 20.84 17.73 17.13 19.40 15.40 14.99 

 (1999 dollars per million Btu) ............. 1.22 1.13 1.00 1.00 1.05 0.91 0.87 0.98 0.80 0.77 

 Average ............................. 25.82 23.53 21.24 21.23 21.72 19.42 19.12 20.15 17.26 17.21 

 Exports7 ............................... 37.43 36.32 36.00 36.06 35.54 34.29 33.38 33.13 31.23 31.03 

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators. 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A. Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 173

Table E11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ........... 78.14 78.62 79.92 79.92 78.74 80.04 80.04 78.74 80.04 80.05

 Geothermal2 ..................... 2.87 3.16 5.61 5.60 4.31 10.80 12.86 4.34 10.95 12.86

 Municipal Solid Waste3 ............. 2.59 3.15 3.76 3.92 3.56 4.18 4.37 4.07 4.84 4.90

 Wood and Other Biomass4 .......... 1.52 1.68 2.03 2.03 2.04 2.40 2.56 2.37 5.60 8.78

 Solar Thermal .................... 0.33 0.35 0.35 0.35 0.40 0.40 0.40 0.48 0.48 0.48

 Solar Photovoltaic ................. 0.01 0.09 0.09 0.09 0.21 0.21 0.21 0.54 0.54 0.54

 Wind ........................... 2.60 4.43 4.54 4.58 5.51 5.97 6.47 5.78 15.50 22.43

 Total .......................... 88.07 91.47 96.31 96.48 94.76 103.99 106.90 96.33 117.95 130.03

 Generation (billion kilowatthours)

 Conventional Hydropower ........... 307.43 299.05 303.50 303.50 298.99 303.41 303.40 297.94 302.33 302.34

 Geothermal2 ..................... 13.07 15.90 44.80 44.71 24.98 85.65 101.91 25.33 86.89 101.96

 Municipal Solid Waste3 ............. 18.05 22.30 27.07 28.29 24.94 29.84 31.30 28.85 34.88 35.36

 Wood and Other Biomass4 .......... 8.86 14.45 56.87 55.89 21.55 74.65 64.24 22.15 83.38 96.45

 Dedicated Plants ................ 7.56 8.67 11.09 11.06 10.88 13.30 14.37 13.35 34.90 56.14

 Cofiring ........................ 1.30 5.78 45.78 44.83 10.67 61.35 49.87 8.80 48.48 40.30

 Solar Thermal .................... 0.89 0.96 0.96 0.96 1.11 1.11 1.11 1.37 1.37 1.37

 Solar Photovoltaic ................. 0.03 0.20 0.20 0.20 0.51 0.51 0.51 1.36 1.36 1.36

 Wind ........................... 4.46 9.42 9.73 9.84 12.33 13.61 15.07 13.10 44.24 64.99

 Total .......................... 352.79 362.28 443.12 443.39 384.41 508.78 517.54 390.09 554.45 603.82

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste .............. 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

 Biomass ......................... 4.65 5.17 5.13 5.13 6.06 6.05 6.04 7.54 7.59 7.72

 Total .......................... 5.35 5.87 5.83 5.83 6.76 6.74 6.74 8.23 8.28 8.42

 Generation (billion kilowatthours)

 Municipal Solid Waste .............. 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03

 Biomass ......................... 27.08 29.92 29.69 29.69 35.01 34.86 34.82 43.52 43.78 44.58

 Total .......................... 31.10 33.95 33.71 33.71 39.03 38.88 38.85 47.55 47.80 48.61

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 .......... 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................. 0.01 0.10 0.10 0.10 0.35 0.35 0.35 0.35 0.35 0.35

 Total .......................... 1.00 1.09 1.09 1.09 1.34 1.34 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 .......... 4.57 4.44 4.44 4.44 4.43 4.43 4.43 4.41 4.41 4.41

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................ 0.02 0.20 0.20 0.20 0.75 0.75 0.75 0.75 0.75 0.76

 Total ......................... 4.59 4.64 4.64 4.64 5.18 5.18 5.18 5.17 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
174 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

Marketed Renewable Energy2

 Residential ......................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Wood ............................. 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.42 0.42

 Commercial ........................ 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Biomass ........................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Industrial3 ......................... 2.15 2.42 2.40 2.40 2.64 2.63 2.63 3.08 3.09 3.13

 Conventional Hydroelectric ............ 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Biomass ........................... 1.97 2.23 2.22 2.22 2.46 2.45 2.45 2.90 2.90 2.94

 Transportation ...................... 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

 Ethanol used in E854 ................. 0.00 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.03 0.03

 Ethanol used in Gasoline Blending ...... 0.12 0.18 0.18 0.18 0.19 0.19 0.19 0.20 0.21 0.21

 Electric Generators5 ................. 3.86 4.03 5.36 5.37 4.47 6.93 7.36 4.56 7.42 8.21

 Conventional Hydroelectric ............ 3.17 3.08 3.12 3.12 3.08 3.12 3.12 3.06 3.11 3.11

 Geothermal ........................ 0.27 0.37 1.15 1.15 0.66 2.46 2.96 0.67 2.50 2.96

 Municipal Solid Waste6 ............... 0.25 0.30 0.37 0.39 0.34 0.41 0.43 0.39 0.47 0.48

 Biomass ........................... 0.12 0.18 0.60 0.59 0.26 0.79 0.68 0.27 0.86 0.97

 Dedicated Plants .................. 0.10 0.11 0.12 0.12 0.13 0.14 0.15 0.16 0.36 0.56

 Cofiring .......................... 0.02 0.07 0.49 0.48 0.13 0.65 0.53 0.11 0.50 0.40

 Solar Thermal ...................... 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Wind ............................. 0.05 0.10 0.10 0.10 0.13 0.14 0.15 0.13 0.45 0.67

 Total Marketed Renewable Energy ..... 6.61 7.16 8.47 8.48 7.84 10.28 10.71 8.40 11.26 12.09

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ........................ 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.03 0.03

 Solar Hot Water Heating .............. 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps .............. 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Commercial ........................ 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Thermal ...................... 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.19 0.19 0.19 0.19 0.16 0.17 0.17

 From Cellulose ..................... 0.00 0.01 0.01 0.01 0.02 0.02 0.02 0.07 0.07 0.07

 Total ............................ 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 175

Table E13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008 Reference Integrated2008

Integrated 

-7 2008

 Residential

 Petroleum .......................... 26.0 26.8 27.0 27.0 24.4 24.7 24.7 22.9 23.4 23.4

 Natural Gas ......................... 69.5 78.6 77.7 77.8 82.0 79.2 78.1 90.8 87.1 86.4

 Coal ............................... 1.1 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.2 1.2

 Electricity ........................... 192.6 223.2 187.0 187.0 240.4 165.6 149.1 274.7 169.9 157.0

 Total ............................. 289.3 330.0 293.0 293.0 348.1 270.8 253.1 389.6 281.6 268.1

 Commercial

 Petroleum .......................... 13.7 12.9 12.9 12.9 13.1 13.6 13.7 12.9 14.3 14.8

 Natural Gas ......................... 45.4 53.5 52.7 52.7 56.0 53.3 52.3 59.4 57.2 56.9

 Coal ............................... 1.7 1.8 1.8 1.8 1.9 1.9 1.9 2.0 2.0 2.0

 Electricity ........................... 182.1 216.0 180.5 180.8 237.0 163.8 148.1 265.8 163.9 151.2

 Total ............................. 242.9 284.1 247.8 248.2 307.9 232.6 215.9 340.0 237.3 224.9

 Industrial1

 Petroleum .......................... 104.2 99.0 99.0 99.0 104.7 108.1 111.7 115.6 125.9 126.8

 Natural Gas2 ........................ 141.6 147.8 148.6 148.5 157.6 157.3 153.1 174.9 169.8 169.7

 Coal ............................... 55.9 66.5 66.7 66.7 66.3 67.5 67.5 66.4 68.8 68.9

 Electricity ........................... 178.8 193.9 164.6 164.2 203.0 142.3 129.4 228.1 138.1 126.9

 Total ............................. 480.4 507.2 479.0 478.3 531.6 475.2 461.6 584.9 502.6 492.2

 Transportation

 Petroleum3 .......................... 485.8 556.8 553.5 553.6 608.6 604.5 603.3 705.1 701.4 700.8

 Natural Gas4 ........................ 9.5 11.8 12.6 12.6 14.1 15.5 15.8 17.9 19.4 19.7

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 2.9 4.4 3.8 3.8 5.7 4.2 3.8 7.9 5.2 4.8

 Total3 ............................. 498.2 573.1 570.0 570.1 628.6 624.2 623.1 730.9 726.1 725.4

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 .......................... 629.7 695.5 692.4 692.4 750.8 750.8 753.4 856.4 865.0 865.9

 Natural Gas ......................... 266.0 291.8 291.6 291.6 309.7 305.2 299.2 342.9 333.5 332.7

 Coal ............................... 58.8 69.6 69.7 69.7 69.5 70.7 70.7 69.6 72.0 72.1

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................... 556.3 637.5 535.9 535.8 686.1 475.9 430.4 776.5 477.1 439.9

 Total3 ............................. 1510.8 1694.3 1589.8 1589.6 1816.2 1602.8 1553.8 2045.4 1747.7 1710.6

 Electric Generators6

 Petroleum .......................... 20.0 6.8 3.9 3.7 3.5 2.3 2.1 3.9 2.0 2.0

 Natural Gas ......................... 45.8 77.1 104.2 105.8 98.6 158.4 173.4 164.1 230.3 236.7

 Coal ............................... 490.5 553.6 427.9 426.2 584.0 315.1 254.8 608.4 244.8 201.2

 Total ............................. 556.3 637.5 535.9 535.8 686.1 475.9 430.4 776.5 477.1 439.9

 Total Carbon Dioxide Emissions

 by Primary Fuel7

 Petroleum3 .......................... 649.7 702.2 696.3 696.2 754.3 753.2 755.6 860.3 867.0 867.9

 Natural Gas ......................... 311.8 368.9 395.7 397.4 408.2 463.6 472.7 507.1 563.7 569.4

 Coal ............................... 549.3 623.1 497.7 495.9 653.5 385.9 325.5 678.0 316.8 273.3

 Other5 ............................. 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total3 ............................. 1510.8 1694.3 1589.8 1589.6 1816.2 1602.8 1553.8 2045.4 1747.7 1710.6

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) .... 5.5 5.9 5.5 5.5 6.1 5.3 5.2 6.3 5.4 5.3

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 20 to 25 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
176 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table E14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999

Projections

2005 2010 2020

Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated

2008

Integrated 

-7 2008 Reference Integrated

2008

Integrated 

-7 2008

 Scrubber Retrofits (gigawatts)1 ............... 0.00 10.76 12.01 11.65 10.76 12.01 11.65 15.24 19.91 17.65

 SO2 Allowance Price

 (1999 dollars per ton) ...................... 0.00 177.63 60.64 73.94 169.55 213.14 141.12 246.09 164.91 95.11

 NOx Controls (gigawatts)

 Combustion ............................... 0.00 65.84 109.98 109.45 66.93 112.45 110.83 67.57 112.45 110.83

 SCR Post-combustion ...................... 0.00 84.31 55.86 56.32 85.97 123.37 107.53 89.75 123.37 107.53

 SNCR Post-combustion 0.00 25.36 1.72 4.01 28.78 47.56 38.31 38.69 47.56 38.31

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ............... 472.31 598.07 498.19 501.28 656.33 446.35 332.32 730.01 358.87 283.21

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) ......... 433.55 451.27 349.70 353.58 453.06 255.41 234.99 438.05 206.58 201.64

 High Sulfur (> 1.67 lbs. S/mmBtu) .............. 198.66 185.83 140.41 143.28 187.25 97.17 87.88 174.20 94.60 80.11

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here. 

SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDPOL08.D121500A, and FDP7B08.D121500A.
Appendix F

Tables for SO2 Sensitivity Case

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 179

Table F1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Production

 Crude Oil and Lease Condensate ................. 12.45 11.85 11.85 10.90 10.88 10.61 10.66

 Natural Gas Plant Liquids ....................... 2.62 3.02 3.00 3.31 3.34 4.07 4.10

 Dry Natural Gas ............................... 19.16 21.26 21.16 23.63 23.82 29.59 29.77

 Coal ........................................ 23.12 25.43 25.36 26.47 26.14 27.21 26.96

 Nuclear Power ................................ 7.79 7.90 7.90 7.69 7.69 6.17 6.13

 Renewable Energy1 ............................ 6.50 6.98 7.01 7.65 7.59 8.20 8.15

 Other2 ...................................... 1.65 0.57 0.57 0.33 0.33 0.33 0.33

 Total ..................................... 73.30 77.01 76.85 79.98 79.78 86.18 86.09

 Imports

 Crude Oil3 ................................... 18.96 23.21 23.20 25.22 25.18 26.48 26.44

 Petroleum Products4 ........................... 4.14 4.85 4.84 6.46 6.46 10.77 10.72

 Natural Gas .................................. 3.63 4.90 4.95 5.49 5.57 6.60 6.69

 Other Imports5 ................................ 0.64 1.11 1.11 0.96 0.96 0.96 0.96

 Total ..................................... 27.37 34.08 34.11 38.12 38.17 44.82 44.80

 Exports

 Petroleum6 ................................... 1.98 1.81 1.81 1.79 1.78 1.90 1.89

 Natural Gas .................................. 0.17 0.33 0.33 0.43 0.43 0.63 0.63

 Coal ........................................ 1.48 1.51 1.52 1.45 1.49 1.41 1.42

 Total ..................................... 3.62 3.64 3.65 3.67 3.70 3.94 3.94

 Discrepancy7 .................................. 0.95 0.39 0.39 0.21 0.22 -0.03 -0.05

 Consumption

 Petroleum Products8 ........................... 38.07 41.40 41.37 44.43 44.41 50.60 50.59

 Natural Gas .................................. 21.90 25.78 25.73 28.52 28.78 35.40 35.66

 Coal ........................................ 21.46 24.37 24.29 25.54 25.17 26.48 26.21

 Nuclear Power ............................... . 7.79 7.90 7.90 7.69 7.69 6.17 6.13

 Renewable Energy1 ............................ 6.51 6.98 7.01 7.66 7.60 8.21 8.16

 Other9 ...................................... 0.35 0.61 0.61 0.38 0.38 0.25 0.25

 Total ...................................... 96.09 107.05 106.91 114.21 114.03 127.10 127.00

 Net Imports - Petroleum ......................... 21.12 26.26 26.24 29.88 29.86 35.36 35.27

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 ................ 17.35 20.83 20.83 21.37 21.37 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 .............. 2.08 2.49 2.48 2.68 2.72 3.14 3.17

 Coal Minemouth Price (dollars per ton) .............. 17.23 14.76 13.53 13.69 12.59 12.84 12.25

 Average Electric Price (cents per Kwh) 6.6 6.2 6.2 5.9 5.9 6.0 6.0

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, and MCSO205H.D121300A.
180 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

Energy Consumption

 Residential

 Distillate Fuel ..................................... 0.86 0.88 0.88 0.81 0.81 0.75 0.75

 Kerosene ........................................ 0.10 0.08 0.08 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas ............................ 0.46 0.45 0.45 0.41 0.41 0.39 0.39

 Petroleum Subtotal ............................... 1.42 1.42 1.42 1.29 1.29 1.21 1.21

 Natural Gas ...................................... 4.85 5.46 5.46 5.69 5.69 6.30 6.30

 Coal ............................................ 0.04 0.05 0.05 0.05 0.05 0.05 0.05

 Renewable Energy1 ................................ 0.41 0.43 0.43 0.43 0.43 0.44 0.44

 Electricity ........................................ 3.91 4.50 4.49 4.96 4.95 5.80 5.79

 Delivered Energy ................................ 10.62 11.86 11.86 12.42 12.41 13.80 13.79

 Electricity Related Losses ........................... 8.46 9.46 9.41 9.88 9.83 10.58 10.55

 Total .......................................... 19.08 21.32 21.27 22.30 22.24 24.38 24.33

 Commercial

 Distillate Fuel ..................................... 0.36 0.41 0.41 0.41 0.41 0.39 0.39

 Residual Fuel .................................... 0.10 0.10 0.10 0.11 0.11 0.11 0.11

 Kerosene ........................................ 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas ............................ 0.08 0.09 0.09 0.09 0.09 0.10 0.10

 Motor Gasoline2 ................................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal ............................... 0.59 0.66 0.66 0.67 0.67 0.66 0.66

 Natural Gas ...................................... 3.15 3.71 3.72 3.89 3.88 4.12 4.12

 Coal ............................................ 0.07 0.07 0.07 0.07 0.07 0.08 0.08

 Renewable Energy3 ................................ 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Electricity ........................................ 3.70 4.35 4.34 4.89 4.88 5.61 5.60

 Delivered Energy ................................ 7.59 8.87 8.87 9.60 9.58 10.55 10.53

 Electricity Related Losses ........................... 8.00 9.15 9.10 9.74 9.69 10.23 10.20

 Total .......................................... 15.59 18.02 17.97 19.34 19.26 20.79 20.74

 Industrial4

 Distillate Fuel ..................................... 1.07 1.13 1.13 1.27 1.27 1.44 1.45

 Liquefied Petroleum Gas ............................ 2.32 2.45 2.45 2.50 2.50 2.83 2.84

 Petrochemical Feedstock ........................... 1.29 1.42 1.42 1.53 1.53 1.70 1.70

 Residual Fuel .................................... 0.22 0.22 0.22 0.25 0.25 0.27 0.27

 Motor Gasoline2 ................................... 0.21 0.23 0.23 0.25 0.25 0.28 0.28

 Other Petroleum5 .................................. 4.29 4.49 4.49 4.76 4.76 5.25 5.24

 Petroleum Subtotal ............................... 9.39 9.95 9.94 10.55 10.55 11.78 11.78

 Natural Gas6 ..................................... 9.43 10.42 10.43 11.11 11.12 12.33 12.34

 Metallurgical Coal ................................. 0.75 0.69 0.69 0.61 0.61 0.50 0.50

 Steam Coal ...................................... 1.73 1.82 1.82 1.85 1.85 1.89 1.90

 Net Coal Coke Imports ............................. 0.06 0.12 0.12 0.16 0.16 0.22 0.22

 Coal Subtotal .................................... 2.54 2.62 2.63 2.61 2.62 2.62 2.62

 Renewable Energy7 ................................ 2.15 2.42 2.42 2.64 2.64 3.08 3.08

 Electricity ........................................ 3.63 3.90 3.90 4.19 4.18 4.81 4.81

 Delivered Energy ................................ 27.15 29.32 29.32 31.10 31.11 34.62 34.63

 Electricity Related Losses ........................... 7.85 8.22 8.17 8.34 8.30 8.78 8.77

 Total .......................................... 35.00 37.53 37.49 39.45 39.41 43.40 43.40
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 181

Table F2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Transportation

 Distillate Fuel ..................................... 5.13 6.28 6.28 6.99 6.99 8.21 8.21

 Jet Fuel8 ........................................ 3.46 3.90 3.90 4.51 4.51 5.97 5.97

 Motor Gasoline2 ................................... 15.92 17.70 17.70 19.05 19.04 21.32 21.32

 Residual Fuel .................................... 0.74 0.85 0.85 0.85 0.85 0.87 0.87

 Liquefied Petroleum Gas ............................ 0.02 0.03 0.03 0.04 0.04 0.06 0.06

 Other Petroleum9 .................................. 0.26 0.29 0.29 0.31 0.31 0.35 0.35

 Petroleum Subtotal ............................... 25.54 29.06 29.06 31.75 31.75 36.77 36.77

 Pipeline Fuel Natural Gas ........................... 0.66 0.77 0.76 0.89 0.89 1.08 1.09

 Compressed Natural Gas ........................... 0.02 0.06 0.06 0.09 0.09 0.16 0.16

 Renewable Energy (E85)10 .......................... 0.01 0.02 0.02 0.03 0.03 0.04 0.04

 Methanol (M85)11 .................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................................ 0.06 0.09 0.09 0.12 0.12 0.17 0.17

 Delivered Energy ................................ 26.28 29.99 30.00 32.89 32.89 38.23 38.23

 Electricity Related Losses ........................... 0.13 0.19 0.19 0.24 0.23 0.30 0.30

 Total .......................................... 26.41 30.18 30.18 33.12 33.12 38.53 38.53

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ..................................... 7.42 8.70 8.70 9.47 9.47 10.80 10.80

 Kerosene ........................................ 0.15 0.14 0.14 0.13 0.13 0.12 0.12

 Jet Fuel8 ........................................ 3.46 3.90 3.90 4.51 4.51 5.97 5.97

 Liquefied Petroleum Gas ............................ 2.88 3.03 3.02 3.05 3.05 3.38 3.39

 Motor Gasoline2 ................................... 16.17 17.96 17.96 19.32 19.31 21.63 21.63

 Petrochemical Feedstock ........................... 1.29 1.42 1.42 1.53 1.53 1.70 1.70

 Residual Fuel .................................... 1.05 1.17 1.17 1.21 1.21 1.25 1.25

 Other Petroleum12 ................................. 4.53 4.76 4.76 5.04 5.04 5.58 5.57

 Petroleum Subtotal ............................... 36.95 41.08 41.08 44.26 44.25 50.42 50.41

 Natural Gas6 ..................................... 18.11 20.42 20.43 21.67 21.67 24.00 24.00

 Metallurgical Coal ................................. 0.75 0.69 0.69 0.61 0.61 0.50 0.50

 Steam Coal ...................................... 1.84 1.94 1.94 1.98 1.98 2.02 2.02

 Net Coal Coke Imports ............................. 0.06 0.12 0.12 0.16 0.16 0.22 0.22

 Coal Subtotal .................................... 2.65 2.74 2.74 2.74 2.74 2.74 2.75

 Renewable Energy13 ............................... 2.65 2.95 2.95 3.19 3.19 3.65 3.65

 Methanol (M85)11 .................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................................ 11.29 12.84 12.83 14.15 14.12 16.39 16.36

 Delivered Energy ................................ 71.65 80.04 80.04 86.01 85.98 97.20 97.18

 Electricity Related Losses ........................... 24.44 27.02 26.87 28.20 28.05 29.89 29.82

 Total .......................................... 96.09 107.05 106.91 114.21 114.03 127.10 127.00

 Electric Generators14

 Distillate Fuel ..................................... 0.06 0.05 0.05 0.04 0.04 0.04 0.04

 Residual Fuel .................................... 1.07 0.27 0.24 0.13 0.13 0.14 0.14

 Petroleum Subtotal ............................... 1.13 0.32 0.29 0.17 0.16 0.19 0.18

 Natural Gas ...................................... 3.79 5.36 5.30 6.84 7.11 11.40 11.66

 Steam Coal ...................................... 18.81 21.63 21.54 22.80 22.43 23.73 23.46

 Nuclear Power .................................... 7.79 7.90 7.90 7.69 7.69 6.17 6.13

 Renewable Energy15 ............................... 3.86 4.03 4.06 4.47 4.41 4.56 4.51

 Electricity Imports16 ................................ 0.35 0.61 0.61 0.37 0.37 0.24 0.24

 Total .......................................... 35.73 39.85 39.70 42.35 42.18 46.28 46.18
182 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Total Energy Consumption

 Distillate Fuel .................................... 7.48 8.75 8.75 9.51 9.51 10.84 10.83

 Kerosene ....................................... 0.15 0.14 0.14 0.13 0.13 0.12 0.12

 Jet Fuel8 ....................................... 3.46 3.90 3.90 4.51 4.51 5.97 5.97

 Liquefied Petroleum Gas ........................... 2.88 3.03 3.02 3.05 3.05 3.38 3.39

 Motor Gasoline2 .................................. 16.17 17.96 17.96 19.32 19.31 21.63 21.63

 Petrochemical Feedstock .......................... 1.29 1.42 1.42 1.53 1.53 1.70 1.70

 Residual Fuel ................................... 2.12 1.44 1.41 1.34 1.33 1.39 1.38

 Other Petroleum12 ................................ 4.53 4.76 4.76 5.04 5.04 5.58 5.57

 Petroleum Subtotal .............................. 38.07 41.40 41.37 44.43 44.41 50.60 50.59

 Natural Gas ..................................... 21.90 25.78 25.73 28.52 28.78 35.40 35.66

 Metallurgical Coal ................................ 0.75 0.69 0.69 0.61 0.61 0.50 0.50

 Steam Coal ..................................... 20.65 23.57 23.48 24.77 24.41 25.75 25.49

 Net Coal Coke Imports ............................ 0.06 0.12 0.12 0.16 0.16 0.22 0.22

 Coal Subtotal ................................... 21.46 24.37 24.29 25.54 25.17 26.48 26.21

 Nuclear Power ................................... 7.79 7.90 7.90 7.69 7.69 6.17 6.13

 Renewable Energy17 .............................. 6.51 6.98 7.01 7.66 7.60 8.21 8.16

 Methanol (M85)11 ................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 ............................... 0.35 0.61 0.61 0.37 0.37 0.24 0.24

 Total ......................................... 96.09 107.05 106.91 114.21 114.04 127.10 127.00

Energy Use and Related Statistics

 Delivered Energy Use .............................. 71.65 80.04 80.04 86.01 85.98 97.20 97.18

 Total Energy Use ................................. 96.09 107.05 106.91 114.21 114.04 127.10 127.00

 Population (millions) ................................ 273.13 288.02 288.02 300.17 300.17 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) ............ 8876 10960 10960 12667 12667 16515 16515

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) ................ 1510.8 1694.3 1692.0 1816.2 1811.4 2045.4 2042.8

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which produces electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and

MCSO205H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 183

Table F3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Residential ....................................... 13.12 12.91 12.91 13.15 13.23 13.59 13.65

 Primary Energy1 .................................. 6.72 7.12 7.10 7.00 7.04 7.02 7.04

 Petroleum Products2 .............................. 7.55 9.18 9.18 9.37 9.37 9.66 9.64

 Distillate Fuel ................................... 6.27 7.34 7.33 7.51 7.51 7.99 7.98

 Liquefied Petroleum Gas .......................... 10.36 12.83 12.82 13.06 13.07 12.90 12.85

 Natural Gas ..................................... 6.52 6.63 6.62 6.52 6.56 6.56 6.59

 Electricity ........................................ 23.46 21.84 21.87 21.88 22.04 22.16 22.27

 Commercial ...................................... 13.20 12.36 12.35 11.74 11.82 12.37 12.43

 Primary Energy1 .................................. 5.22 5.35 5.34 5.53 5.56 5.76 5.78

 Petroleum Products2 .............................. 5.00 6.01 6.01 6.17 6.17 6.52 6.49

 Distillate Fuel ................................... 4.37 5.13 5.12 5.28 5.28 5.77 5.75

 Residual Fuel .................................. 2.63 3.64 3.64 3.69 3.69 3.85 3.85

 Natural Gas3 .................................... 5.34 5.31 5.30 5.49 5.53 5.72 5.75

 Electricity ........................................ 21.43 19.51 19.52 17.61 17.74 18.09 18.21

 Industrial4 ........................................ 5.32 5.49 5.48 5.44 5.46 5.85 5.87

 Primary Energy ................................... 3.92 4.25 4.24 4.37 4.38 4.73 4.73

 Petroleum Products2 .............................. 5.55 5.95 5.94 6.05 6.05 6.28 6.26

 Distillate Fuel ................................... 4.65 5.29 5.29 5.46 5.46 5.98 5.94

 Liquefied Petroleum Gas .......................... 8.50 7.94 7.93 8.00 8.00 7.86 7.81

 Residual Fuel .................................. 2.78 3.37 3.36 3.42 3.42 3.58 3.58

 Natural Gas5 .................................... 2.79 3.17 3.16 3.30 3.33 3.77 3.80

 Metallurgical Coal ................................ 1.65 1.58 1.58 1.54 1.54 1.44 1.44

 Steam Coal ..................................... 1.43 1.34 1.32 1.29 1.27 1.21 1.19

 Electricity ........................................ 13.01 12.30 12.30 11.21 11.30 11.60 11.71

 Transportation .................................... 8.30 9.27 9.26 9.45 9.47 9.32 9.31

 Primary Energy ................................... 8.29 9.25 9.24 9.44 9.45 9.30 9.29

 Petroleum Products2 .............................. 8.28 9.25 9.24 9.44 9.45 9.30 9.29

 Distillate Fuel6 .................................. 8.22 8.89 8.88 8.94 8.94 9.02 8.98

 Jet Fuel7 ...................................... 4.70 5.24 5.23 5.46 5.46 5.88 5.88

 Motor Gasoline8 ................................. 9.45 10.64 10.63 10.92 10.94 10.68 10.68

 Residual Fuel .................................. 2.46 3.10 3.10 3.18 3.18 3.33 3.33

 Liquid Petroleum Gas9 ............................ 12.87 14.19 14.18 14.24 14.25 13.88 13.83

 Natural Gas10 .................................... 7.02 6.80 6.78 7.03 7.08 7.33 7.36

 Ethanol (E85)11 .................................. 14.42 19.12 19.07 19.00 19.01 19.36 19.36

 Methanol (M85)12 ................................. 10.38 13.11 13.11 13.74 13.74 14.43 14.43

 Electricity ........................................ 15.58 14.29 14.21 13.53 13.62 13.03 13.17

 Average End-Use Energy ........................... 8.53 8.90 8.90 8.94 8.97 9.17 9.19

 Primary Energy ................................... 6.33 7.00 6.99 7.18 7.19 7.31 7.31

 Electricity ........................................ 19.40 18.10 18.11 17.18 17.31 17.57 17.68

 Electric Generators13

 Fossil Fuel Average ................................ 1.49 1.50 1.47 1.52 1.53 1.85 1.87

 Petroleum Products ............................... 2.50 3.70 3.69 4.06 4.09 4.33 4.32

 Distillate Fuel ................................... 4.04 4.65 4.64 4.85 4.85 5.30 5.28

 Residual Fuel .................................. 2.41 3.52 3.50 3.85 3.88 4.04 4.05

 Natural Gas ..................................... 2.54 2.89 2.85 3.02 3.07 3.61 3.66

 Steam Coal ..................................... 1.22 1.13 1.10 1.05 1.02 0.98 0.96
184 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Average Price to All Users14

 Petroleum Products2 ............................... 7.43 8.43 8.43 8.63 8.64 8.62 8.61

 Distillate Fuel .................................... 7.27 8.07 8.06 8.18 8.18 8.41 8.38

 Jet Fuel ........................................ 4.70 5.24 5.23 5.46 5.46 5.88 5.88

 Liquefied Petroleum Gas ........................... 8.84 8.83 8.83 8.87 8.88 8.64 8.60

 Motor Gasoline8 .................................. 9.45 10.64 10.63 10.92 10.94 10.68 10.68

 Residual Fuel ................................... 2.48 3.26 3.25 3.33 3.33 3.49 3.49

 Natural Gas ..................................... 4.05 4.25 4.24 4.27 4.29 4.52 4.55

 Coal ............................................ 1.24 1.15 1.12 1.07 1.04 1.00 0.98

 Ethanol (E85)11 ................................... 14.42 19.12 19.07 19.00 19.01 19.36 19.36

 Methanol (M85)12 .................................. 10.38 13.11 13.11 13.74 13.74 14.43 14.43

 Electricity ........................................ 19.40 18.10 18.11 17.18 17.31 17.57 17.68

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ......................................... 134.05 147.53 147.55 157.75 158.52 181.60 182.16

 Commercial ........................................ 99.10 108.63 108.54 111.63 112.17 129.48 129.97

 Industrial .......................................... 110.62 121.27 121.07 126.35 126.91 151.05 151.64

 Transportation ...................................... 212.64 270.40 270.24 301.90 302.23 345.30 344.94

 Total Non-Renewable Expenditures ................... 556.41 647.83 647.40 697.64 699.83 807.43 808.71

 Transportation Renewable Expenditures ................ 0.14 0.42 0.42 0.61 0.61 0.86 0.86

 Total Expenditures ................................ 556.55 648.25 647.82 698.25 700.45 808.29 809.57

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report,

DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A. 1999

electricity prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.

Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 185

Table F4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

Generation by Fuel Type

 Electric Generators1

 Coal ......................................... 1835 2103 2095 2232 2184 2317 2279

 Petroleum .................................... 104 32 29 18 17 19 18

 Natural Gas2 .................................. 365 574 583 867 911 1568 1604

 Nuclear Power ................................. 730 740 740 720 720 577 574

 Pumped Storage ............................... -1 -1 -1 -1 -1 -1 -1

 Renewable Sources3 ............................ 353 362 363 384 381 390 388

 Total ....................................... 3386 3811 3809 4220 4213 4872 4862

 Non-Utility Generation for Own Use ................ 16 16 16 16 16 16 16

 Distributed Generation .......................... 0113366

 Cogenerators4

 Coal ........................................ 47 52 52 52 52 52 52

 Petroleum ................................... 9 10 10 10 10 10 10

 Natural Gas .................................. 206 239 239 256 257 298 300

 Other Gaseous Fuels5 .......................... 4667788

 Renewable Sources3 ........................... 31 34 34 39 39 48 48

 Other6 ...................................... 5555555

 Total ...................................... 302 347 347 369 371 421 423

 Other End-Use Generators7 ...................... 5555555

 Sales to Utilities ............................... 150 171 171 176 176 200 200

 Generation for Own Use ......................... 156 180 181 198 199 226 228

 Net Imports8 ................................... 33 57 57 35 35 23 23

Electricity Sales by Sector

 Residential ..................................... 1146 1317 1317 1452 1450 1699 1696

 Commercial .................................... 1083 1275 1273 1432 1429 1644 1641

 Industrial ...................................... 1063 1144 1143 1227 1225 1411 1410

 Transportation .................................. 17 26 26 35 35 49 49

 Total ........................................ 3309 3762 3760 4146 4139 4803 4795

End-Use Prices (1999 cents per kwh)9

 Residential ..................................... 8.0 7.5 7.5 7.5 7.5 7.6 7.6

 Commercial .................................... 7.3 6.7 6.7 6.0 6.1 6.2 6.2

 Industrial ...................................... 4.4 4.2 4.2 3.8 3.9 4.0 4.0

 Transportation .................................. 5.3 4.9 4.8 4.6 4.6 4.4 4.5

 All Sectors Average ........................... 6.6 6.2 6.2 5.9 5.9 6.0 6.0

 Prices by Service Category9

 (1999 cents per kwh)

 Generation ..................................... 4.1 3.6 3.6 3.2 3.2 3.4 3.4

 Transmission ................................... 0.6 0.6 0.6 0.7 0.7 0.7 0.7

 Distribution .................................... 2.0 2.0 2.0 2.0 2.0 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide .................................. 13.82 10.39 8.37 9.70 6.87 8.95 6.38

 Nitrogen Oxide ................................. 5.46 4.22 4.17 4.20 4.17 4.37 4.33

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
186 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

Electric Generators2

 Capability

 Coal Steam ................................ 306.2 302.4 302.2 317.4 311.9 317.8 312.5

 Other Fossil Steam3 ......................... 138.2 129.6 126.9 121.1 118.6 117.2 115.9

 Combined Cycle ............................ 20.2 49.4 55.5 124.0 132.6 230.0 234.1

 Combustion Turbine/Diesel .................... 75.6 129.7 127.4 162.1 158.8 207.7 209.9

 Nuclear Power .............................. 97.4 97.5 97.5 94.2 93.7 71.6 71.6

 Pumped Storage ............................ 19.3 19.5 19.5 19.5 19.5 19.5 19.5

 Fuel Cells ................................. 0.0 0.0 0.0 0.1 0.1 0.3 0.3

 Renewable Sources4 ......................... 88.1 91.5 91.6 94.8 94.6 96.3 96.2

 Distributed Generation5 ....................... 0.0 2.0 2.0 6.1 6.0 14.0 13.0

 Total .................................... 745.0 821.5 822.6 939.4 935.8 1074.3 1072.9

 Cumulative Planned Additions6

 Coal Steam ................................ 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ......................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1

 Combined Cycle ............................ 0.0 8.3 8.3 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel .................... 0.0 0.7 0.7 0.7 0.7 0.7 0.7

 Nuclear Power .............................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............................ 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ................................. 0.0 0.0 0.0 0.1 0.1 0.3 0.3

 Renewable Sources4 ......................... 0.0 2.4 2.4 4.3 4.3 5.4 5.4

 Distributed Generation5 ....................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Total .................................... 0.0 11.5 11.5 13.6 13.6 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam ................................ 0.0 2.5 4.2 20.1 15.6 21.5 17.4

 Other Fossil Steam3 ......................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Combined Cycle ............................ 0.0 20.8 26.9 95.7 104.2 201.6 205.8

 Combustion Turbine/Diesel ................... . 0.0 57.0 55.9 90.8 88.5 137.2 140.5

 Nuclear Power .............................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............................ 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ................................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ......................... 0.0 0.6 0.7 1.9 1.8 2.4 2.3

 Distributed Generation5 ....................... 0.0 2.0 2.0 6.1 6.0 14.0 13.0

 Total .................................... 0.0 82.9 89.8 214.6 216.0 376.7 378.9

 Cumulative Total Additions ................... 0.0 94.5 101.4 228.1 229.6 391.4 393.7

 Cumulative Retirements7

 Coal Steam ................................ 0.0 6.6 8.5 9.2 10.1 10.2 11.4

 Other Fossil Steam3 ......................... 0.0 8.5 11.2 17.0 19.5 20.9 22.2

 Combined Cycle ............................ 0.0 0.0 0.0 0.3 0.3 0.3 0.3

 Combustion Turbine/Diesel ................... 0.0 3.8 4.5 5.1 5.7 5.9 6.6

 Nuclear Power ............................. 0.0 0.0 0.0 3.3 3.7 25.9 25.9

 Pumped Storage ........................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ................................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources ......................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1

 Total ................................... 0.0 19.0 24.3 34.9 39.5 63.4 66.5

Cogenerators8

 Capability

 Coal ...................................... 8.4 8.9 8.9 8.9 8.9 8.9 8.9

 Petroleum ................................. 2.7 2.7 2.7 2.8 2.8 2.8 2.8

 Natural Gas ................................ 33.8 40.0 40.0 42.9 43.0 48.8 49.2

 Other Gaseous Fuels ........................ 0.2 0.8 0.8 0.9 0.9 1.0 1.0

 Renewable Sources4 ......................... 5.3 5.9 5.9 6.8 6.8 8.2 8.2

 Other ..................................... 1.1 0.9 0.9 0.9 0.9 0.9 0.9

 Total .................................... 51.6 59.2 59.2 63.1 63.2 70.7 71.0

 Cumulative Additions6 ....................... 0.0 7.5 7.6 11.4 11.6 19.0 19.4
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 187

Table F5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

Other End-Use Generators9

 Renewable Sources .......................... 1.0 1.1 1.1 1.3 1.3 1.3 1.3

 Cumulative Additions ......................... 0.0 0.1 0.1 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8

Nameplate capacity is reported for nonutilities on Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
188 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade ....................... 182.2 125.3 125.3 102.9 102.9 0.0 0.0

 Gross Domestic Economy Trade ........................ 147.8 202.8 195.9 183.2 189.1 206.7 208.4

 Gross Domestic Trade .............................. 330.0 328.1 321.2 286.1 292.0 206.7 208.4

 Gross Domestic Firm Power Sales

 (million 1999 dollars) ................................. 8588.1 5905.8 5905.8 4851.2 4851.2 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) ................................. 4292.5 6044.9 5698.0 4987.6 5172.9 6227.5 6363.6

 Gross Domestic Sales

 (million 1999 dollars) ............................... 12880.6 11950.7 11603.8 9838.8 10024.2 6227.5 6363.6

 International Electricity Trade

 Firm Power Imports From Canada and Mexico1 ............ 27.0 10.7 10.7 5.8 5.8 0.0 0.0

 Economy Imports From Canada and Mexico1 ............... 21.9 63.5 63.5 45.9 45.9 30.6 30.6

 Gross Imports From Canada and Mexico1 ............... 48.9 74.1 74.1 51.7 51.7 30.6 30.6

 Firm Power Exports To Canada and Mexico ............... 9.2 9.7 9.7 8.7 8.7 0.0 0.0

 Economy Exports To Canada and Mexico ................. 6.3 7.0 7.0 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico ................. 15.5 16.7 16.7 16.4 16.4 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 189

Table F7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Production

 Dry Gas Production1 ....................... 18.67 20.72 20.62 23.03 23.21 28.84 29.02

 Supplemental Natural Gas2 .................. 0.10 0.11 0.11 0.06 0.06 0.06 0.06

 Net Imports .............................. 3.38 4.47 4.51 4.94 5.02 5.83 5.91

 Canada ................................. 3.29 4.28 4.32 4.68 4.77 5.46 5.54

 Mexico .................................. -0.01 -0.18 -0.18 -0.25 -0.25 -0.40 -0.40

 Liquefied Natural Gas ...................... 0.10 0.37 0.37 0.51 0.51 0.77 0.77

 Total Supply .............................. 22.15 25.30 25.25 28.03 28.29 34.72 34.98

 Consumption by Sector

 Residential ............................... 4.72 5.32 5.32 5.54 5.54 6.14 6.13

 Commercial .............................. 3.07 3.62 3.62 3.78 3.78 4.02 4.01

 Industrial3 ................................ 7.95 8.80 8.81 9.33 9.33 10.17 10.18

 Electric Generators4 ....................... 3.72 5.26 5.20 6.72 6.98 11.19 11.44

 Lease and Plant Fuel5 ...................... 1.23 1.35 1.34 1.49 1.50 1.83 1.84

 Pipeline Fuel ............................. 0.64 0.75 0.74 0.87 0.87 1.06 1.06

 Transportation6 ........................... 0.02 0.05 0.05 0.09 0.09 0.15 0.15

 Total .................................. 21.35 25.14 25.09 27.82 28.08 34.55 34.81

 Discrepancy7 ............................. 0.80 0.16 0.16 0.21 0.21 0.17 0.17

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A. Other 1999 consumption: EIA,

Short-Term Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption levels for

consumption of natural gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.

Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
190 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Source Price 

 Average Lower 48 Wellhead Price1 ................. 2.08 2.49 2.48 2.68 2.72 3.14 3.17

 Average Import Price ............................ 2.29 2.48 2.48 2.41 2.42 2.67 2.72

 Average2 .................................... 2.11 2.49 2.48 2.63 2.66 3.05 3.08

 Delivered Prices

 Residential .................................... 6.69 6.81 6.80 6.70 6.74 6.74 6.77

 Commercial ................................... 5.49 5.45 5.44 5.64 5.68 5.87 5.90

 Industrial3 ..................................... 2.87 3.26 3.24 3.39 3.42 3.87 3.90

 Electric Generators4 ............................ 2.59 2.94 2.90 3.08 3.12 3.68 3.73

 Transportation5 ................................ 7.21 6.99 6.97 7.22 7.27 7.53 7.56

 Average6 .................................... 4.16 4.36 4.35 4.38 4.40 4.64 4.67

 Transmission & Distribution Margins7

 Residential .................................... 4.58 4.32 4.31 4.07 4.08 3.69 3.68

 Commercial ................................... 3.37 2.96 2.96 3.01 3.02 2.82 2.82

 Industrial3 ..................................... 0.75 0.76 0.76 0.76 0.76 0.82 0.82

 Electric Generators4 ............................ 0.48 0.45 0.42 0.45 0.46 0.63 0.65

 Transportation5 ................................ 5.10 4.49 4.48 4.59 4.61 4.48 4.47

 Average6 .................................... 2.05 1.87 1.86 1.75 1.74 1.59 1.58

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential .................................... 21.61 22.96 22.95 22.55 22.59 22.62 22.58

 Commercial ................................... 10.36 10.71 10.70 11.40 11.40 11.32 11.30

 Industrial3 ..................................... 6.00 6.72 6.71 7.10 7.08 8.34 8.34

 Electric Generators4 ............................ 1.77 2.35 2.19 3.03 3.24 7.00 7.39

 Transportation5 ................................ 0.08 0.24 0.24 0.42 0.42 0.69 0.69

 Total ....................................... 39.82 42.98 42.79 44.49 44.73 49.97 50.30

 1Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 191

Table F9. Oil and Gas Supply

Production and Supply 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ................................. 16.49 20.42 20.42 20.81 20.80 21.46 21.44

Production (million barrels per day)

2

 U.S. Total .............................................. 5.88 5.60 5.60 5.15 5.14 5.01 5.03

 Lower 48 Onshore ....................................... 3.27 2.75 2.75 2.49 2.48 2.63 2.65

 Conventional .......................................... 2.59 2.15 2.15 1.82 1.82 1.91 1.91

 Enhanced Oil Recovery ................................. 0.68 0.61 0.61 0.66 0.66 0.72 0.74

 Lower 48 Offshore ....................................... 1.56 2.05 2.05 2.02 2.02 1.75 1.75

 Alaska ................................................ 1.05 0.79 0.79 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 ............. 18.33 15.46 15.47 14.03 14.00 13.43 13.51

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ..................... 2.08 2.49 2.48 2.68 2.72 3.14 3.17

Production (trillion cubic feet)3

 U.S. Total .............................................. 18.67 20.72 20.62 23.03 23.21 28.84 29.02

 Lower 48 Onshore ....................................... 12.83 14.33 14.23 16.32 16.47 21.20 21.35

 Associated-Dissolved4 ................................... 1.80 1.51 1.51 1.34 1.34 1.35 1.35

 Non-Associated ........................................ 11.03 12.82 12.72 14.98 15.13 19.85 20.00

 Conventional ......................................... 6.64 7.19 7.17 8.31 8.39 11.38 11.37

 Unconventional ....................................... 4.39 5.62 5.55 6.66 6.74 8.48 8.62

 Lower 48 Offshore ....................................... 5.43 5.93 5.93 6.21 6.24 7.07 7.10

 Associated-Dissolved4 ................................... 0.93 1.07 1.07 1.07 1.07 1.01 1.01

 Non-Associated ........................................ 4.50 4.85 4.85 5.13 5.17 6.06 6.09

 Alaska ................................................ 0.42 0.47 0.47 0.50 0.50 0.57 0.57

Lower 48 End of Year Reserves3

 (trillion cubic feet) ...................................... 157.41 166.23 166.41 174.58 175.12 188.20 189.34

 Supplemental Gas Supplies (trillion cubic feet)5 .............. 0.10 0.11 0.11 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) .......................... 17.94 24.11 24.15 28.67 29.12 39.25 39.91

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3Market production (wet) minus extraction losses.

 4Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
192 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Production1

 Appalachia ......................................... 434 422 382 412 376 395 372

 Interior ............................................ 185 180 160 177 157 163 155

 West ............................................. 485 633 707 708 762 784 809

 East of the Mississippi ................................ 561 554 496 545 490 525 495

 West of the Mississippi ............................... 543 681 753 752 805 817 841

 Total ............................................ 1105 1235 1249 1297 1295 1342 1336

 Net Imports

 Imports ............................................ 9 16 16 17 17 20 20

 Exports ............................................ 58 60 60 58 59 56 57

 Total ............................................. -49 -44 -45 -40 -42 -36 -37

 Total Supply2 ....................................... 1055 1191 1204 1256 1254 1306 1299

 Consumption by Sector

 Residential and Commercial ........................... 5555555

 Industrial3 .......................................... 79 83 83 84 85 86 87

 Coke Plants ........................................ 28 26 26 23 23 19 19

 Electric Generators4 ................................. 922 1078 1091 1145 1142 1198 1191

 Total ............................................ 1034 1192 1205 1257 1255 1308 1302

 Discrepancy and Stock Change5

. ...................... 21 -1 -1 -1 -1 -2 -2

 Average Minemouth Price

 (1999 dollars per short ton) ............................ 17.23 14.76 13.53 13.69 12.59 12.84 12.25

 (1999 dollars per million Btu) ........................... 0.82 0.72 0.67 0.67 0.62 0.63 0.61

 Delivered Prices (1999 dollars per short ton)6

 Industrial .......................................... 31.46 29.43 28.92 28.41 27.88 26.55 26.18

 Coke Plants ........................................ 44.20 42.47 42.35 41.29 41.33 38.57 38.46

 Electric Generators

 (1999 dollars per short ton) ........................... 24.78 22.62 21.66 20.84 20.08 19.40 18.92

 (1999 dollars per million Btu) ......................... 1.22 1.13 1.10 1.05 1.02 0.98 0.96

 Average ......................................... 25.82 23.53 22.60 21.72 20.99 20.15 19.69

 Exports7 ........................................... 37.43 36.32 36.07 35.54 35.23 33.13 32.85

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators. 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

and MCSO205H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 193

Table F11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ........................ 78.14 78.62 78.62 78.74 78.74 78.74 78.74

 Geothermal2 .................................. 2.87 3.16 3.28 4.31 4.16 4.34 4.20

 Municipal Solid Waste3 .......................... 2.59 3.15 3.15 3.56 3.56 4.07 4.07

 Wood and Other Biomass4 ....................... 1.52 1.68 1.68 2.04 2.04 2.37 2.37

 Solar Thermal ................................. 0.33 0.35 0.35 0.40 0.40 0.48 0.48

 Solar Photovoltaic .............................. 0.01 0.09 0.09 0.21 0.21 0.54 0.54

 Wind ........................................ 2.60 4.43 4.43 5.51 5.51 5.78 5.78

 Total ....................................... 88.07 91.47 91.60 94.76 94.61 96.33 96.18

 Generation (billion kilowatthours)

 Conventional Hydropower ........................ 307.43 299.05 299.05 298.99 298.99 297.94 297.94

 Geothermal2 .................................. 13.07 15.90 16.88 24.98 23.82 25.33 24.17

 Municipal Solid Waste3 .......................... 18.05 22.30 22.28 24.94 24.93 28.85 28.84

 Wood and Other Biomass4 ....................... 8.86 14.45 13.89 21.55 18.94 22.15 20.96

 Dedicated Plants ............................. 7.56 8.67 8.67 10.88 10.88 13.35 13.35

 Cofiring ..................................... 1.30 5.78 5.22 10.67 8.05 8.80 7.61

 Solar Thermal ................................. 0.89 0.96 0.96 1.11 1.11 1.37 1.37

 Solar Photovoltaic .............................. 0.03 0.20 0.20 0.51 0.51 1.36 1.36

 Wind ........................................ 4.46 9.42 9.42 12.33 12.33 13.10 13.10

 Total ....................................... 352.79 362.28 362.68 384.41 380.62 390.09 387.74

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste ........................... 0.70 0.70 0.70 0.70 0.70 0.70 0.70

 Biomass ...................................... 4.65 5.17 5.17 6.06 6.06 7.54 7.54

 Total ....................................... 5.35 5.87 5.87 6.76 6.76 8.23 8.23

 Generation (billion kilowatthours)

 Municipal Solid Waste ........................... 4.03 4.03 4.03 4.03 4.03 4.03 4.03

 Biomass ...................................... 27.08 29.92 29.92 35.01 35.01 43.52 43.52

 Total ....................................... 31.10 33.95 33.95 39.03 39.03 47.55 47.55

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 ....................... 0.99 0.99 0.99 0.99 0.99 0.99 0.99

 Geothermal ................................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic .............................. 0.01 0.10 0.10 0.35 0.35 0.35 0.35

 Total ....................................... 1.00 1.09 1.09 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 ....................... 4.57 4.44 4.44 4.43 4.43 4.41 4.41

 Geothermal ................................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ............................. 0.02 0.20 0.20 0.75 0.75 0.75 0.75

 Total ...................................... 4.59 4.64 4.64 5.18 5.18 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
194 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

Marketed Renewable Energy2

 Residential ....................................... 0.41 0.43 0.43 0.43 0.43 0.44 0.44

 Wood ........................................... 0.41 0.43 0.43 0.43 0.43 0.44 0.44

 Commercial ...................................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Biomass ......................................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Industrial3 ....................................... 2.15 2.42 2.42 2.64 2.64 3.08 3.08

 Conventional Hydroelectric .......................... 0.18 0.18 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste .............................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Biomass ......................................... 1.97 2.23 2.23 2.46 2.46 2.90 2.90

 Transportation .................................... 0.12 0.20 0.20 0.21 0.21 0.23 0.24

 Ethanol used in E854 ............................... 0.00 0.02 0.02 0.03 0.03 0.04 0.04

 Ethanol used in Gasoline Blending .................... 0.12 0.18 0.18 0.19 0.19 0.20 0.20

 Electric Generators5 ............................... 3.86 4.03 4.06 4.47 4.41 4.56 4.51

 Conventional Hydroelectric .......................... 3.17 3.08 3.08 3.08 3.08 3.06 3.06

 Geothermal ...................................... 0.27 0.37 0.40 0.66 0.62 0.67 0.63

 Municipal Solid Waste6 ............................. 0.25 0.30 0.30 0.34 0.34 0.39 0.39

 Biomass ......................................... 0.12 0.18 0.17 0.26 0.23 0.27 0.26

 Dedicated Plants ................................ 0.10 0.11 0.11 0.13 0.13 0.16 0.17

 Cofiring ........................................ 0.02 0.07 0.06 0.13 0.10 0.11 0.10

 Solar Thermal .................................... 0.01 0.01 0.01 0.02 0.02 0.03 0.03

 Solar Photovoltaic ................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Wind ........................................... 0.05 0.10 0.10 0.13 0.13 0.13 0.13

 Total Marketed Renewable Energy ................... 6.61 7.16 7.19 7.84 7.78 8.40 8.35

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ...................................... 0.02 0.03 0.03 0.03 0.03 0.04 0.04

 Solar Hot Water Heating ............................ 0.01 0.01 0.01 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps ............................ 0.02 0.02 0.02 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Commercial ...................................... 0.02 0.02 0.02 0.03 0.03 0.03 0.03

 Solar Thermal .................................... 0.02 0.02 0.02 0.02 0.02 0.03 0.03

 Solar Photovoltaic ................................. 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ....................................... 0.12 0.19 0.19 0.19 0.19 0.16 0.17

 From Cellulose ................................... 0.00 0.01 0.01 0.02 0.02 0.07 0.07

 Total .......................................... 0.12 0.20 0.20 0.21 0.21 0.23 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 195

Table F13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Residential

 Petroleum ....................................... 26.0 26.8 26.8 24.4 24.4 22.9 22.9

 Natural Gas ...................................... 69.5 78.6 78.7 82.0 81.9 90.8 90.7

 Coal ............................................ 1.1 1.3 1.3 1.3 1.3 1.3 1.3

 Electricity ........................................ 192.6 223.2 222.4 240.4 238.7 274.7 273.7

 Total .......................................... 289.3 330.0 329.2 348.1 346.3 389.6 388.5

 Commercial

 Petroleum ....................................... 13.7 12.9 12.9 13.1 13.1 12.9 12.9

 Natural Gas ...................................... 45.4 53.5 53.5 56.0 55.8 59.4 59.3

 Coal ............................................ 1.7 1.8 1.8 1.9 1.9 2.0 2.0

 Electricity ........................................ 182.1 216.0 215.0 237.0 235.3 265.8 264.7

 Total .......................................... 242.9 284.1 283.2 307.9 306.0 340.0 338.9

 Industrial1

 Petroleum ....................................... 104.2 99.0 98.9 104.7 104.6 115.6 115.7

 Natural Gas2 ..................................... 141.6 147.8 147.9 157.6 157.7 174.9 175.0

 Coal ............................................ 55.9 66.5 66.6 66.3 66.4 66.4 66.5

 Electricity ........................................ 178.8 193.9 193.1 203.0 201.7 228.1 227.5

 Total .......................................... 480.4 507.2 506.4 531.6 530.4 584.9 584.6

 Transportation

 Petroleum3 ....................................... 485.8 556.8 556.9 608.6 608.6 705.1 704.9

 Natural Gas4 ..................................... 9.5 11.8 11.8 14.1 14.2 17.9 18.0

 Other5 .......................................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................................ 2.9 4.4 4.4 5.7 5.7 7.9 7.8

 Total3 .......................................... 498.2 573.1 573.1 628.6 628.6 730.9 730.8

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 ....................................... 629.7 695.5 695.5 750.8 750.7 856.4 856.3

 Natural Gas ...................................... 266.0 291.8 291.9 309.7 309.7 342.9 343.0

 Coal ............................................ 58.8 69.6 69.6 69.5 69.5 69.6 69.7

 Other5 .......................................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity ........................................ 556.3 637.5 634.9 686.1 681.4 776.5 773.7

 Total3 .......................................... 1510.8 1694.3 1692.0 1816.2 1811.4 2045.4 2042.8

 Electric Generators6

 Petroleum ....................................... 20.0 6.8 6.1 3.5 3.4 3.9 3.7

 Natural Gas ...................................... 45.8 77.1 76.3 98.6 102.4 164.1 167.9

 Coal ............................................ 490.5 553.6 552.5 584.0 575.6 608.4 602.1

 Total .......................................... 556.3 637.5 634.9 686.1 681.4 776.5 773.7

 Total Carbon Dioxide Emissions by

 Primary Fuel7

 Petroleum3 ....................................... 649.7 702.2 701.6 754.3 754.1 860.3 860.0

 Natural Gas ...................................... 311.8 368.9 368.2 408.2 412.1 507.1 510.8

 Coal ............................................ 549.3 623.1 622.1 653.5 645.1 678.0 671.8

 Other5 .......................................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1

 Total3 .......................................... 1510.8 1694.3 1692.0 1816.2 1811.4 2045.4 2042.8

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) ................. 5.5 5.9 5.9 6.1 6.0 6.3 6.3

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 25 to 30 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
196 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table F14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999

Projections

2005 2010 2020

Reference SO2

Sensitivity Reference SO2Sensitivity Reference SO2Sensitivity

 Scrubber Retrofits (gigawatts)1 ............................... 0.00 10.76 17.93 10.76 40.77 15.24 52.28

 SO2 Allowance Price

 (1999 dollars per ton) ...................................... 0.00 177.63 281.39 169.55 300.15 246.09 382.46

 NOx Controls (gigawatts)

 Combustion .............................................. 0.00 65.84 65.31 66.93 66.42 67.57 66.92

 SCR Post-combustion ...................................... 0.00 84.31 87.18 85.97 87.18 89.75 96.31

 SNCR Post-combustion ..................................... 0.00 25.36 25.38 28.78 25.38 38.69 35.51

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ............................... 472.31 598.07 690.82 656.33 706.89 730.01 750.85

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) ......................... 433.55 451.27 393.82 453.06 416.79 438.05 412.04

 High Sulfur (> 1.67 lbs. S/mmBtu) .............................. 198.66 185.83 164.23 187.25 171.66 174.20 173.11

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here.

 SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, and MCSO205H.D121300A.
Appendix G

Tables for CO2 and Integrated Sensitivity Cases

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 199

Table G1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Production

 Crude Oil and Lease Condensate ... 12.45 11.85 11.78 11.79 10.90 10.93 10.95 10.61 11.12 11.13

 Natural Gas Plant Liquids ......... 2.62 3.02 3.25 3.25 3.31 3.59 3.59 4.07 4.36 4.38

 Dry Natural Gas ................. 19.16 21.26 22.95 22.92 23.63 25.69 25.69 29.59 31.66 31.83

 Coal .......................... 23.12 25.43 19.51 19.46 26.47 17.97 17.93 27.21 15.23 14.97

 Nuclear Power .................. 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.10 7.10

 Renewable Energy1 .............. 6.50 6.98 8.31 8.27 7.65 10.05 9.87 8.20 10.81 10.60

 Other2 ........................ 1.65 0.57 0.36 0.36 0.33 0.30 0.30 0.33 0.33 0.34

 Total ....................... 73.30 77.01 74.06 73.94 79.98 76.46 76.25 86.18 80.61 80.35

 Imports

 Crude Oil3 ..................... 18.96 23.21 22.93 22.92 25.22 24.89 24.88 26.48 25.92 25.94

 Petroleum Products4 ............. 4.14 4.85 4.70 4.72 6.46 6.39 6.41 10.77 10.83 10.85

 Natural Gas .................... 3.63 4.90 5.54 5.55 5.49 6.42 6.42 6.60 7.50 7.56

 Other Imports5 .................. 0.64 1.11 1.02 1.01 0.96 0.89 0.88 0.96 0.82 0.82

 Total ....................... 27.37 34.08 34.19 34.20 38.12 38.59 38.59 44.82 45.06 45.17

 Exports

 Petroleum6 ..................... 1.98 1.81 1.79 1.79 1.79 1.77 1.77 1.90 1.93 1.94

 Natural Gas .................... 0.17 0.33 0.12 0.12 0.43 0.12 0.12 0.63 0.12 0.12

 Coal .......................... 1.48 1.51 1.51 1.51 1.45 1.44 1.44 1.41 1.46 1.46

 Total ....................... 3.62 3.64 3.43 3.43 3.67 3.33 3.34 3.94 3.51 3.52

 Discrepancy7 .................... 0.95 0.39 0.29 0.25 0.21 0.18 0.20 -0.03 -0.11 -0.02

 Consumption

 Petroleum Products8 ............. 38.07 41.40 41.03 41.05 44.43 44.36 44.39 50.60 50.82 50.89

 Natural Gas .................... 21.90 25.78 28.30 28.27 28.52 31.80 31.80 35.40 38.86 39.07

 Coal .......................... 21.46 24.37 18.37 18.35 25.54 16.89 16.81 26.48 14.30 13.98

 Nuclear Power ................. . 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.10 7.10

 Renewable Energy1 .............. 6.51 6.98 8.31 8.28 7.66 10.06 9.88 8.21 10.82 10.60

 Other9 ........................ 0.35 0.61 0.62 0.61 0.38 0.52 0.51 0.25 0.38 0.38

 Total ........................ 96.09 107.05 104.53 104.47 114.21 111.54 111.29 127.10 122.26 122.02

 Net Imports - Petroleum ........... 21.12 26.26 25.83 25.85 29.88 29.51 29.52 35.36 34.82 34.86

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 . . 17.35 20.83 20.83 20.83 21.37 21.37 21.37 22.41 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 2.08 2.49 3.14 3.15 2.68 3.48 3.52 3.14 4.00 4.06

 Coal Minemouth Price (dollars per ton) 17.23 14.76 14.88 14.11 13.69 13.96 12.97 12.84 12.60 11.99

 Average Electric Price (cents per Kwh) 6.6 6.2 7.7 7.7 5.9 7.6 7.6 6.0 7.5 7.6

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
200 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

Energy Consumption

 Residential

 Distillate Fuel ........................ 0.86 0.88 0.89 0.89 0.81 0.81 0.81 0.75 0.76 0.76

 Kerosene ........................... 0.10 0.08 0.08 0.08 0.07 0.07 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas ............... 0.46 0.45 0.46 0.46 0.41 0.42 0.42 0.39 0.41 0.41

 Petroleum Subtotal .................. 1.42 1.42 1.43 1.43 1.29 1.30 1.30 1.21 1.24 1.24

 Natural Gas ......................... 4.85 5.46 5.35 5.35 5.69 5.53 5.53 6.30 6.12 6.11

 Coal ............................... 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05

 Renewable Energy1 ................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.43 0.43

 Electricity ........................... 3.91 4.50 4.30 4.29 4.96 4.66 4.66 5.80 5.45 5.44

 Delivered Energy ................... 10.62 11.86 11.55 11.54 12.42 11.97 11.96 13.80 13.29 13.27

 Electricity Related Losses .............. 8.46 9.46 8.84 8.83 9.88 9.19 9.13 10.58 9.25 9.18

 Total ............................. 19.08 21.32 20.39 20.37 22.30 21.16 21.09 24.38 22.53 22.45

 Commercial

 Distillate Fuel ........................ 0.36 0.41 0.41 0.41 0.41 0.44 0.44 0.39 0.44 0.45

 Residual Fuel ....................... 0.10 0.10 0.10 0.10 0.11 0.11 0.11 0.11 0.11 0.11

 Kerosene ........................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas ............... 0.08 0.09 0.09 0.09 0.09 0.09 0.09 0.10 0.10 0.10

 Motor Gasoline2 ...................... 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal .................. 0.59 0.66 0.66 0.66 0.67 0.69 0.70 0.66 0.71 0.71

 Natural Gas ......................... 3.15 3.71 3.62 3.61 3.89 3.74 3.73 4.12 4.04 4.02

 Coal ............................... 0.07 0.07 0.07 0.07 0.07 0.07 0.07 0.08 0.08 0.08

 Renewable Energy3 ................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Electricity ........................... 3.70 4.35 4.15 4.14 4.89 4.62 4.60 5.61 5.27 5.25

 Delivered Energy ................... 7.59 8.87 8.58 8.57 9.60 9.21 9.18 10.55 10.17 10.14

 Electricity Related Losses .............. 8.00 9.15 8.54 8.51 9.74 9.11 9.02 10.23 8.94 8.86

 Total ............................. 15.59 18.02 17.12 17.07 19.34 18.32 18.20 20.79 19.11 19.00

 Industrial4

 Distillate Fuel ........................ 1.07 1.13 1.12 1.12 1.27 1.27 1.27 1.44 1.45 1.45

 Liquefied Petroleum Gas ............... 2.32 2.45 2.44 2.45 2.50 2.57 2.58 2.83 2.98 3.01

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.53 1.70 1.69 1.69

 Residual Fuel ....................... 0.22 0.22 0.23 0.23 0.25 0.26 0.26 0.27 0.37 0.40

 Motor Gasoline2 ...................... 0.21 0.23 0.22 0.22 0.25 0.24 0.24 0.28 0.28 0.28

 Other Petroleum5 ..................... 4.29 4.49 4.49 4.49 4.76 4.78 4.79 5.25 5.38 5.39

 Petroleum Subtotal .................. 9.39 9.95 9.91 9.92 10.55 10.65 10.67 11.78 12.16 12.23

 Natural Gas6 ........................ 9.43 10.42 10.48 10.46 11.11 11.22 11.19 12.33 12.36 12.27

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 1.73 1.82 1.83 1.84 1.85 1.90 1.90 1.89 1.99 1.99

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 2.54 2.62 2.63 2.63 2.61 2.66 2.67 2.62 2.71 2.71

 Renewable Energy7 ................... 2.15 2.42 2.40 2.40 2.64 2.64 2.64 3.08 3.08 3.08

 Electricity ........................... 3.63 3.90 3.80 3.80 4.19 4.00 3.99 4.81 4.40 4.41

 Delivered Energy ................... 27.15 29.32 29.21 29.20 31.10 31.17 31.16 34.62 34.72 34.70

 Electricity Related Losses .............. 7.85 8.22 7.81 7.81 8.34 7.88 7.82 8.78 7.47 7.43

 Total ............................. 35.00 37.53 37.02 37.01 39.45 39.04 38.98 43.40 42.19 42.14
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 201

Table G2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Transportation

 Distillate Fuel ........................ 5.13 6.28 6.16 6.17 6.99 6.90 6.90 8.21 8.10 8.10

 Jet Fuel8 ........................... 3.46 3.90 3.86 3.86 4.51 4.49 4.49 5.97 5.96 5.96

 Motor Gasoline2 ...................... 15.92 17.70 17.62 17.62 19.05 18.97 18.98 21.32 21.26 21.26

 Residual Fuel ....................... 0.74 0.85 0.85 0.85 0.85 0.85 0.85 0.87 0.86 0.86

 Liquefied Petroleum Gas ............... 0.02 0.03 0.03 0.03 0.04 0.04 0.04 0.06 0.06 0.06

 Other Petroleum9 ..................... 0.26 0.29 0.29 0.29 0.31 0.31 0.31 0.35 0.35 0.35

 Petroleum Subtotal .................. 25.54 29.06 28.82 28.83 31.75 31.57 31.58 36.77 36.60 36.60

 Pipeline Fuel Natural Gas .............. 0.66 0.77 0.83 0.83 0.89 0.97 0.97 1.08 1.18 1.19

 Compressed Natural Gas .............. 0.02 0.06 0.06 0.06 0.09 0.09 0.09 0.16 0.15 0.15

 Renewable Energy (E85)10 ............. 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.04

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 0.06 0.09 0.09 0.09 0.12 0.12 0.12 0.17 0.17 0.17

 Delivered Energy ................... 26.28 29.99 29.82 29.83 32.89 32.78 32.79 38.23 38.15 38.16

 Electricity Related Losses .............. 0.13 0.19 0.18 0.18 0.24 0.23 0.23 0.30 0.28 0.28

 Total ............................. 26.41 30.18 30.00 30.01 33.12 33.01 33.02 38.53 38.43 38.44

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ........................ 7.42 8.70 8.58 8.59 9.47 9.42 9.42 10.80 10.76 10.77

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.86 3.86 4.51 4.49 4.49 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.02 3.03 3.05 3.13 3.14 3.38 3.55 3.58

 Motor Gasoline2 ...................... 16.17 17.96 17.88 17.88 19.32 19.24 19.25 21.63 21.57 21.57

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.53 1.70 1.69 1.69

 Residual Fuel ....................... 1.05 1.17 1.18 1.18 1.21 1.22 1.22 1.25 1.34 1.37

 Other Petroleum12 .................... 4.53 4.76 4.75 4.75 5.04 5.06 5.07 5.58 5.71 5.72

 Petroleum Subtotal .................. 36.95 41.08 40.82 40.84 44.26 44.22 44.25 50.42 50.71 50.79

 Natural Gas6 ........................ 18.11 20.42 20.33 20.30 21.67 21.55 21.51 24.00 23.86 23.75

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 1.84 1.94 1.95 1.95 1.98 2.03 2.03 2.02 2.11 2.11

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 2.65 2.74 2.75 2.75 2.74 2.79 2.79 2.74 2.83 2.84

 Renewable Energy13 .................. 2.65 2.95 2.93 2.93 3.19 3.18 3.18 3.65 3.64 3.64

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity ........................... 11.29 12.84 12.34 12.32 14.15 13.39 13.36 16.39 15.28 15.26

 Delivered Energy ................... 71.65 80.04 79.16 79.14 86.01 85.13 85.09 97.20 96.33 96.27

 Electricity Related Losses .............. 24.44 27.02 25.37 25.33 28.20 26.41 26.20 29.89 25.93 25.75

 Total ............................. 96.09 107.05 104.53 104.47 114.21 111.54 111.29 127.10 122.26 122.02

 Electric Generators14

 Distillate Fuel ........................ 0.06 0.05 0.04 0.04 0.04 0.03 0.03 0.04 0.02 0.02

 Residual Fuel ....................... 1.07 0.27 0.18 0.18 0.13 0.11 0.12 0.14 0.08 0.08

 Petroleum Subtotal .................. 1.13 0.32 0.21 0.22 0.17 0.14 0.14 0.19 0.10 0.10

 Natural Gas ......................... 3.79 5.36 7.97 7.97 6.84 10.26 10.29 11.40 15.00 15.33

 Steam Coal ......................... 18.81 21.63 15.62 15.60 22.80 14.10 14.02 23.73 11.46 11.14

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.10 7.10

 Renewable Energy15 .................. 3.86 4.03 5.38 5.35 4.47 6.88 6.70 4.56 7.18 6.97

 Electricity Imports16 ................... 0.35 0.61 0.62 0.61 0.37 0.51 0.50 0.24 0.37 0.37

 Total ............................. 35.73 39.85 37.71 37.65 42.35 39.80 39.57 46.28 41.21 41.01
202 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1998

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Total Energy Consumption

 Distillate Fuel ........................ 7.48 8.75 8.62 8.63 9.51 9.45 9.45 10.84 10.78 10.79

 Kerosene ........................... 0.15 0.14 0.14 0.14 0.13 0.13 0.13 0.12 0.12 0.12

 Jet Fuel8 ........................... 3.46 3.90 3.86 3.86 4.51 4.49 4.49 5.97 5.96 5.96

 Liquefied Petroleum Gas ............... 2.88 3.03 3.02 3.03 3.05 3.13 3.14 3.38 3.55 3.58

 Motor Gasoline2 ...................... 16.17 17.96 17.88 17.88 19.32 19.24 19.25 21.63 21.57 21.57

 Petrochemical Feedstock .............. 1.29 1.42 1.41 1.41 1.53 1.53 1.53 1.70 1.69 1.69

 Residual Fuel ....................... 2.12 1.44 1.36 1.36 1.34 1.33 1.34 1.39 1.42 1.46

 Other Petroleum12 .................... 4.53 4.76 4.75 4.75 5.04 5.06 5.07 5.58 5.71 5.72

 Petroleum Subtotal .................. 38.07 41.40 41.03 41.05 44.43 44.36 44.39 50.60 50.82 50.89

 Natural Gas ......................... 21.90 25.78 28.30 28.27 28.52 31.80 31.80 35.40 38.86 39.07

 Metallurgical Coal .................... 0.75 0.69 0.69 0.69 0.61 0.61 0.61 0.50 0.50 0.50

 Steam Coal ......................... 20.65 23.57 17.57 17.56 24.77 16.13 16.05 25.75 13.57 13.25

 Net Coal Coke Imports ................ 0.06 0.12 0.11 0.11 0.16 0.16 0.16 0.22 0.22 0.22

 Coal Subtotal ....................... 21.46 24.37 18.37 18.35 25.54 16.89 16.81 26.48 14.30 13.98

 Nuclear Power ....................... 7.79 7.90 7.90 7.90 7.69 7.91 7.91 6.17 7.10 7.10

 Renewable Energy17 .................. 6.51 6.98 8.31 8.28 7.66 10.06 9.88 8.21 10.82 10.61

 Methanol (M85)11 ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen ..................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 ................... 0.35 0.61 0.62 0.61 0.37 0.51 0.50 0.24 0.37 0.37

 Total ............................. 96.09 107.05 104.53 104.47 114.21 111.54 111.29 127.10 122.26 122.02

Energy Use and Related Statistics

 Delivered Energy Use .................. 71.65 80.04 79.16 79.14 86.01 85.13 85.09 97.20 96.33 96.27

 Total Energy Use ..................... 96.09 107.05 104.53 104.47 114.21 111.54 111.29 127.10 122.26 122.02

 Population (millions) .................... 273.13 288.02 288.02 288.02 300.17 300.17 300.17 325.24 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 10960 10855 10855 12667 12639 12639 16515 16521 16521

 Total Carbon Dioxide Emissions 

 (million metric tons carbon equivalent) ..... 1510.8 1694.3 1570.0 1570.3 1816.2 1640.0 1639.2 2045.4 1785.8 1782.5

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDC7B05H.D121300A, and FDP7B05H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 203

Table G3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Residential ......................... 13.12 12.91 14.63 14.64 13.15 15.35 15.42 13.59 15.72 15.84

 Primary Energy1 .................... 6.72 7.12 7.56 7.57 7.00 7.60 7.63 7.02 7.70 7.74

 Petroleum Products2 ................ 7.55 9.18 9.18 9.19 9.37 9.33 9.30 9.66 9.68 9.68

 Distillate Fuel ..................... 6.27 7.34 7.33 7.33 7.51 7.48 7.48 7.99 8.00 8.00

 Liquefied Petroleum Gas ............ 10.36 12.83 12.83 12.85 13.06 12.96 12.86 12.90 12.84 12.85

 Natural Gas ....................... 6.52 6.63 7.18 7.19 6.52 7.25 7.29 6.56 7.35 7.40

 Electricity .......................... 23.46 21.84 25.85 25.88 21.88 26.81 26.94 22.16 26.62 26.85

 Commercial ........................ 13.20 12.36 15.11 15.12 11.74 14.83 14.92 12.37 15.07 15.21

 Primary Energy1 .................... 5.22 5.35 5.81 5.82 5.53 6.12 6.14 5.76 6.41 6.45

 Petroleum Products2 ................ 5.00 6.01 6.00 6.00 6.17 6.10 6.08 6.52 6.45 6.45

 Distillate Fuel ..................... 4.37 5.13 5.12 5.12 5.28 5.25 5.24 5.77 5.76 5.76

 Residual Fuel .................... 2.63 3.64 3.62 3.62 3.69 3.69 3.69 3.85 3.84 3.84

 Natural Gas3 ...................... 5.34 5.31 5.86 5.87 5.49 6.21 6.25 5.72 6.50 6.55

 Electricity .......................... 21.43 19.51 24.84 24.88 17.61 23.32 23.52 18.09 23.00 23.24

 Industrial4 .......................... 5.32 5.49 6.24 6.25 5.44 6.33 6.35 5.85 6.64 6.70

 Primary Energy ..................... 3.92 4.25 4.49 4.50 4.37 4.69 4.69 4.73 5.09 5.12

 Petroleum Products2 ................ 5.55 5.95 5.93 5.95 6.05 6.06 6.04 6.28 6.31 6.31

 Distillate Fuel ..................... 4.65 5.29 5.29 5.29 5.46 5.43 5.43 5.98 5.99 5.99

 Liquefied Petroleum Gas ............ 8.50 7.94 7.93 7.97 8.00 8.01 7.91 7.86 7.93 7.95

 Residual Fuel .................... 2.78 3.37 3.35 3.35 3.42 3.42 3.42 3.58 3.51 3.49

 Natural Gas5 ...................... 2.79 3.17 3.78 3.78 3.30 4.04 4.08 3.77 4.61 4.66

 Metallurgical Coal .................. 1.65 1.58 1.59 1.59 1.54 1.55 1.54 1.44 1.44 1.44

 Steam Coal ....................... 1.43 1.34 1.30 1.29 1.29 1.24 1.22 1.21 1.10 1.09

 Electricity .......................... 13.01 12.30 16.09 16.12 11.21 15.70 15.83 11.60 15.46 15.67

 Transportation ...................... 8.30 9.27 9.30 9.30 9.45 9.56 9.55 9.32 9.33 9.33

 Primary Energy ..................... 8.29 9.25 9.28 9.28 9.44 9.54 9.53 9.30 9.31 9.31

 Petroleum Products2 ................ 8.28 9.25 9.28 9.28 9.44 9.54 9.52 9.30 9.30 9.30

 Distillate Fuel6 .................... 8.22 8.89 8.90 8.90 8.94 8.94 8.94 9.02 9.05 9.05

 Jet Fuel7 ........................ 4.70 5.24 5.23 5.22 5.46 5.47 5.47 5.88 5.88 5.88

 Motor Gasoline8 ................... 9.45 10.64 10.68 10.68 10.92 11.09 11.06 10.68 10.67 10.67

 Residual Fuel .................... 2.46 3.10 3.10 3.10 3.18 3.18 3.18 3.33 3.33 3.33

 Liquid Petroleum Gas9 .............. 12.87 14.19 14.25 14.26 14.24 14.25 14.17 13.88 13.88 13.89

 Natural Gas10 ...................... 7.02 6.80 7.37 7.38 7.03 7.78 7.82 7.33 8.10 8.15

 Ethanol (E85)11 .................... 14.42 19.12 19.17 19.18 19.00 19.15 19.15 19.36 19.46 19.47

 Methanol (M85)12 ................... 10.38 13.11 13.31 13.32 13.74 13.84 13.83 14.43 14.42 14.42

 Electricity .......................... 15.58 14.29 16.16 16.18 13.53 15.86 15.90 13.03 14.79 14.88

 Average End-Use Energy ............. 8.53 8.90 9.72 9.73 8.94 9.92 9.94 9.17 10.01 10.06

 Primary Energy ..................... 6.33 7.00 7.18 7.18 7.18 7.43 7.43 7.31 7.53 7.55

 Electricity .......................... 19.40 18.10 22.44 22.47 17.18 22.20 22.35 17.57 22.03 22.25

 Electric Generators13

 Fossil Fuel Average .................. 1.49 1.50 1.90 1.90 1.52 2.16 2.18 1.85 2.91 2.98

 Petroleum Products ................. 2.50 3.70 3.78 3.78 4.06 4.08 4.07 4.33 4.57 4.59

 Distillate Fuel ..................... 4.04 4.65 4.67 4.67 4.85 4.83 4.82 5.30 5.27 5.26

 Residual Fuel .................... 2.41 3.52 3.60 3.59 3.85 3.90 3.89 4.04 4.40 4.42

 Natural Gas ....................... 2.54 2.89 3.54 3.55 3.02 3.77 3.81 3.61 4.47 4.51

 Steam Coal ....................... 1.22 1.13 1.04 1.04 1.05 0.97 0.96 0.98 0.86 0.85
204 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Average Price to All Users14

 Petroleum Products2 ................. 7.43 8.43 8.46 8.46 8.63 8.70 8.68 8.62 8.62 8.62

 Distillate Fuel ...................... 7.27 8.07 8.07 8.07 8.18 8.16 8.16 8.41 8.42 8.42

 Jet Fuel .......................... 4.70 5.24 5.23 5.22 5.46 5.47 5.47 5.88 5.88 5.88

 Liquefied Petroleum Gas ............. 8.84 8.83 8.84 8.87 8.87 8.85 8.76 8.64 8.69 8.70

 Motor Gasoline8 .................... 9.45 10.64 10.68 10.68 10.92 11.09 11.06 10.68 10.67 10.67

 Residual Fuel ..................... 2.48 3.26 3.25 3.25 3.33 3.33 3.33 3.49 3.48 3.47

 Natural Gas ....................... 4.05 4.25 4.70 4.71 4.27 4.84 4.88 4.52 5.25 5.29

 Coal .............................. 1.24 1.15 1.07 1.07 1.07 1.01 1.00 1.00 0.90 0.89

 Ethanol (E85)11 ..................... 14.42 19.12 19.17 19.18 19.00 19.15 19.15 19.36 19.46 19.47

 Methanol (M85)12 .................... 10.38 13.11 13.31 13.32 13.74 13.84 13.83 14.43 14.42 14.42

 Electricity .......................... 19.40 18.10 22.44 22.47 17.18 22.20 22.35 17.57 22.03 22.25

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ........................... 134.05 147.53 162.69 162.79 157.75 177.31 177.88 181.60 202.13 203.36

 Commercial .......................... 99.10 108.63 128.37 128.26 111.63 135.33 135.83 129.48 152.03 152.96

 Industrial ............................ 110.62 121.27 138.34 138.65 126.35 148.68 149.19 151.05 172.97 174.35

 Transportation ........................ 212.64 270.40 269.28 269.26 301.90 303.67 303.26 345.30 344.16 344.20

 Total Non-Renewable Expenditures ..... 556.41 647.83 698.68 698.96 697.64 764.99 766.15 807.43 871.29 874.87

 Transportation Renewable Expenditures . . 0.14 0.42 0.41 0.41 0.61 0.62 0.62 0.86 0.86 0.86

 Total Expenditures .................. 556.55 648.25 699.09 699.37 698.25 765.61 766.77 808.29 872.15 875.73

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report,

DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and

FDP7B05H.D121300A. 1999 electricity prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A,

FDC7B05H.D121300A, and FDP7B05H.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and

FDP7B05H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 205

Table G4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

Generation by Fuel Type

 Electric Generators1

 Coal ............................ 1835 2103 1551 1547 2232 1402 1392 2317 1140 1108

 Petroleum ....................... 104 32 22 23 18 15 15 19 12 11

 Natural Gas 2 ..................... 365 574 893 895 867 1292 1299 1568 2134 2168

 Nuclear Power .................... 730 740 740 740 720 741 741 577 665 665

 Pumped Storage .................. -1 -1 -1 -1 -1 -1 -1 -1 -1 -1

 Renewable Sources3 ............... 353 362 443 441 384 515 509 390 542 533

 Total .......................... 3386 3811 3648 3645 4220 3963 3955 4872 4492 4485

 Non-Utility Generation for Own Use ... 16 16 21 22 16 21 21 16 21 21

 Distributed Generation ............. 01 0 0 3 0 0 6 0 0

 Cogenerators4

 Coal ........................... 47 52 52 52 52 52 52 52 51 51

 Petroleum ...................... 9 10 10 10 10 10 10 10 10 10

 Natural Gas ..................... 206 239 260 261 256 317 318 298 456 454

 Other Gaseous Fuels5 ............. 46 6 6 7 7 7 8 8 8

 Renewable Sources3 .............. 31 34 34 34 39 39 39 48 48 48

 Other6 ......................... 55 5 5 5 5 5 5 5 5

 Total ......................... 302 347 367 367 369 430 431 421 579 577

 Other End-Use Generators 7 ........ 55 5 5 5 5 5 5 5 5

 Sales to Utilities .................. 150 171 178 179 176 191 191 200 236 235

 Generation for Own Use ............ 156 180 194 194 198 244 245 226 348 347

 Net Imports8 ...................... 33 57 59 57 35 49 47 23 35 35

Electricity Sales by Sector

 Residential ........................ 1146 1317 1260 1259 1452 1366 1364 1699 1597 1595

 Commercial ....................... 1083 1275 1216 1213 1432 1354 1348 1644 1544 1538

 Industrial ......................... 1063 1144 1113 1113 1227 1171 1169 1411 1290 1291

 Transportation ..................... 17 26 26 26 35 34 34 49 48 49

 Total ........................... 3309 3762 3615 3611 4146 3926 3916 4803 4479 4472 

End-Use Prices (1999 cents per kwh)9

 Residential ........................ 8.0 7.5 8.8 8.8 7.5 9.1 9.2 7.6 9.1 9.2 

 Commercial ....................... 7.3 6.7 8.5 8.5 6.0 8.0 8.0 6.2 7.8 7.9 

 Industrial ......................... 4.4 4.2 5.5 5.5 3.8 5.4 5.4 4.0 5.3 5.3 

 Transportation ..................... 5.3 4.9 5.5 5.5 4.6 5.4 5.4 4.4 5.0 5.1 

 All Sectors Average .............. 6.6 6.2 7.7 7.7 5.9 7.6 7.6 6.0 7.5 7.6 

 

 Prices by Service Category 9

 (1999 cents per kwh)

 Generation ........................ 4.1 3.6 5.0 5.0 3.2 4.8 4.9 3.4 4.9 4.9 

 Transmission ...................... 0.6 0.6 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 

 Distribution ....................... 2.0 2.0 2.0 2.0 2.0 2.1 2.1 2.0 2.0 2.0 

Emissions (million short tons)

 Sulfur Dioxide ..................... 13.82 10.39 10.39 7.97 9.70 9.70 7.03 8.95 8.21 6.38 

 Nitrogen Oxide .................... 5.46 4.22 3.42 3.37 4.20 3.15 3.10 4.37 2.55 2.48 

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power

to the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel

source of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
206 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

Electric Generators2

 Capability

 Coal Steam ................... 306.2 302.4 298.4 297.7 317.4 284.6 280.7 317.8 266.1 262.0

 Other Fossil Steam3 ............ 138.2 129.6 123.6 122.7 121.1 105.8 106.3 117.2 103.4 102.3

 Combined Cycle ............... 20.2 49.4 70.8 71.4 124.0 135.6 136.6 230.0 259.8 258.5

 Combustion Turbine/Diesel ....... 75.6 129.7 109.7 108.0 162.1 133.0 130.7 207.7 173.3 176.7

 Nuclear Power ................. 97.4 97.5 97.5 97.5 94.2 96.9 96.9 71.6 84.6 84.6

 Pumped Storage ............... 19.3 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 88.1 91.5 96.3 96.1 94.8 103.5 102.8 96.3 114.0 112.7

 Distributed Generation5 ......... 0.0 2.0 2.2 1.8 6.1 4.3 3.9 14.0 8.6 9.0

 Total ....................... 745.0 821.5 818.1 814.7 939.4 883.2 877.5 1074.3 1029.5 1025.5

 Cumulative Planned Additions6

 Coal Steam ................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Combined Cycle ............... 0.0 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ....... 0.0 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.3 0.3 0.3

 Renewable Sources4 ............ 0.0 2.4 2.4 2.4 4.3 4.3 4.3 5.4 5.4 5.4

 Distributed Generation5 .......... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Total ....................... 0.0 11.5 11.5 11.5 13.6 13.6 13.6 14.8 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam ................... 0.0 2.5 0.0 0.0 20.1 0.0 0.0 21.5 0.0 0.0

 Other Fossil Steam3 ............ 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Combined Cycle ............... 0.0 20.8 42.2 42.8 95.7 107.1 108.1 201.6 231.4 230.0

 Combustion Turbine/Diesel ...... . 0.0 57.0 38.6 36.9 90.8 63.7 61.4 137.2 104.7 108.1

 Nuclear Power ................. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Pumped Storage ............... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ............ 0.0 0.6 5.5 5.3 1.9 10.7 9.9 2.4 20.1 18.8

 Distributed Generation5 .......... 0.0 2.0 2.2 1.8 6.1 4.3 3.9 14.0 8.6 9.0

 Total ....................... 0.0 82.9 88.6 86.8 214.6 185.7 183.4 376.7 364.7 365.9

 Cumulative Total Additions ...... 0.0 94.5 100.1 98.4 228.1 199.2 197.0 391.4 379.5 380.6

 Cumulative Retirements7

 Coal Steam ................... 0.0 6.6 8.1 8.8 9.2 21.9 25.8 10.2 40.4 44.4

 Other Fossil Steam3 ............ 0.0 8.5 14.5 15.4 17.0 32.3 31.8 20.9 34.7 35.8

 Combined Cycle ............... 0.0 0.0 0.0 0.0 0.3 0.2 0.2 0.3 0.2 0.2

 Combustion Turbine/Diesel ...... 0.0 3.8 4.7 4.7 5.1 6.5 6.5 5.9 7.2 7.2

 Nuclear Power ................ 0.0 0.0 0.0 0.0 3.3 0.6 0.6 25.9 12.9 12.9

 Pumped Storage .............. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Fuel Cells .................... 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ........... 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total ...................... 0.0 19.0 27.5 29.1 34.9 61.6 65.0 63.4 95.5 100.6

Cogenerators8

 Capability

 Coal ......................... 8.4 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9

 Petroleum .................... 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 2.8

 Natural Gas ................... 33.8 40.0 42.1 42.1 42.9 50.3 50.5 48.8 70.2 70.0

 Other Gaseous Fuels ........... 0.2 0.8 0.8 0.8 0.9 0.9 0.9 1.0 1.1 1.1

 Renewable Sources4 ............ 5.3 5.9 5.8 5.8 6.8 6.8 6.8 8.2 8.3 8.3

 Other ........................ 1.1 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

 Total ....................... 51.6 59.2 61.2 61.2 63.1 70.6 70.7 70.7 92.2 92.0

 Cumulative Additions6 .......... 0.0 7.5 9.6 9.6 11.4 18.9 19.1 19.0 40.6 40.3
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 207

Table G5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

Other End-Use Generators9

 Renewable Sources ............. 1.0 1.1 1.1 1.1 1.3 1.3 1.3 1.3 1.3 1.3

 Cumulative Additions ............ 0.0 0.1 0.1 0.1 0.3 0.3 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8Nameplate capacity is reported for nonutilities on Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
208 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade .......... 182.2 125.3 125.3 125.3 102.9 102.9 102.9 0.0 0.0 0.0

 Gross Domestic Economy Trade ........... 147.8 202.8 71.5 79.0 183.2 91.3 103.0 206.7 147.5 139.4

 Gross Domestic Trade ................. 330.0 328.1 196.8 204.3 286.1 194.2 205.9 206.7 147.5 139.4

 Gross Domestic Firm Power Sales

 (million 1999 dollars) .................... 8588.1 5905.8 5905.8 5905.8 4851.2 4851.2 4851.2 0.0 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) .................... 4292.5 6044.9 3094.6 3427.9 4987.6 3866.3 4397.7 6227.5 6296.5 6048.5

 Gross Domestic Sales

 (million 1999 dollars) .................. 12880.6 11950.7 9000.4 9333.7 9838.8 8717.5 9249.0 6227.5 6296.5 6048.5

 International Electricity Trade

 Firm Power Imports From Canada and Mexico1

 27.0 10.7 11.8 10.7 5.8 19.1 17.9 0.0 12.1 12.1

 Economy Imports From Canada and Mexico1 . . 21.9 63.5 63.5 63.5 45.9 45.9 45.9 30.6 30.6 30.6

 Gross Imports From Canada and Mexico1 . . 48.9 74.1 75.3 74.1 51.7 65.0 63.8 30.6 42.7 42.7

 Firm Power Exports To Canada and Mexico . . 9.2 9.7 9.7 9.7 8.7 8.7 8.7 0.0 0.0 0.0

 Economy Exports To Canada and Mexico .... 6.3 7.0 7.0 7.0 7.7 7.7 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico .... 15.5 16.7 16.7 16.7 16.4 16.4 16.4 7.7 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 209

Table G7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Production

 Dry Gas Production1 ......... 18.67 20.72 22.37 22.34 23.03 25.04 25.04 28.84 30.86 31.02

 Supplemental Natural Gas2 .... 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Net Imports ................ 3.38 4.47 5.29 5.30 4.94 6.15 6.15 5.83 7.21 7.27

 Canada ................... 3.29 4.28 4.55 4.55 4.68 5.13 5.12 5.46 5.93 5.93

 Mexico .................... -0.01 -0.18 0.30 0.30 -0.25 0.32 0.32 -0.40 0.36 0.36

 Liquefied Natural Gas ........ 0.10 0.37 0.45 0.45 0.51 0.71 0.71 0.77 0.93 0.99

 Total Supply ................ 22.15 25.30 27.77 27.75 28.03 31.25 31.25 34.72 38.12 38.35

 Consumption by Sector

 Residential ................. 4.72 5.32 5.21 5.21 5.54 5.39 5.38 6.14 5.96 5.95

 Commercial ................ 3.07 3.62 3.52 3.52 3.78 3.64 3.63 4.02 3.93 3.92

 Industrial3 .................. 7.95 8.80 8.78 8.76 9.33 9.34 9.32 10.17 10.11 10.01

 Electric Generators4 ......... 3.72 5.26 7.82 7.82 6.72 10.06 10.10 11.19 14.72 15.04

 Lease and Plant Fuel5 ........ 1.23 1.35 1.42 1.42 1.49 1.58 1.58 1.83 1.93 1.94

 Pipeline Fuel ............... 0.64 0.75 0.81 0.81 0.87 0.94 0.94 1.06 1.15 1.16

 Transportation6 ............. 0.02 0.05 0.05 0.05 0.09 0.09 0.09 0.15 0.15 0.15

 Total .................... 21.35 25.14 27.61 27.59 27.82 31.05 31.04 34.55 37.95 38.17

 Discrepancy7 ............... 0.80 0.16 0.16 0.16 0.21 0.21 0.21 0.17 0.17 0.18

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A. Other 1999

consumption: EIA, Short-Term Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption

levels for consumption of natural gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A,

and FDP7B05H.D121300A. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
210 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Source Price 

 Average Lower 48 Wellhead Price1 .... 2.08 2.49 3.14 3.15 2.68 3.48 3.52 3.14 4.00 4.06

 Average Import Price ............... 2.29 2.48 2.76 2.77 2.41 2.72 2.73 2.67 3.05 3.07

 Average2 ....................... 2.11 2.49 3.07 3.08 2.63 3.33 3.36 3.05 3.82 3.87

 Delivered Prices

 Residential ....................... 6.69 6.81 7.38 7.39 6.70 7.45 7.49 6.74 7.55 7.60

 Commercial ...................... 5.49 5.45 6.02 6.03 5.64 6.38 6.41 5.87 6.67 6.72

 Industrial3 ........................ 2.87 3.26 3.88 3.89 3.39 4.15 4.19 3.87 4.73 4.79

 Electric Generators4 ............... 2.59 2.94 3.61 3.61 3.08 3.84 3.88 3.68 4.56 4.60

 Transportation5 ................... 7.21 6.99 7.57 7.58 7.22 7.99 8.03 7.53 8.32 8.37

 Average6 ....................... 4.16 4.36 4.82 4.83 4.38 4.97 5.00 4.64 5.39 5.43

 Transmission & Distribution Margins7

 Residential ....................... 4.58 4.32 4.31 4.31 4.07 4.12 4.12 3.69 3.73 3.73

 Commercial ...................... 3.37 2.96 2.95 2.95 3.01 3.05 3.05 2.82 2.85 2.85

 Industrial3 ........................ 0.75 0.76 0.81 0.81 0.76 0.82 0.83 0.82 0.91 0.92

 Electric Generators4 ............... 0.48 0.45 0.54 0.54 0.45 0.52 0.52 0.63 0.74 0.73

 Transportation5 ................... 5.10 4.49 4.50 4.50 4.59 4.66 4.67 4.48 4.50 4.50

 Average6 ....................... 2.05 1.87 1.76 1.76 1.75 1.65 1.64 1.59 1.57 1.56

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ....................... 21.61 22.96 22.45 22.44 22.55 22.22 22.20 22.62 22.23 22.18

 Commercial ...................... 10.36 10.71 10.40 10.39 11.40 11.11 11.09 11.32 11.23 11.19

 Industrial3 ........................ 6.00 6.72 7.12 7.10 7.10 7.70 7.70 8.34 9.23 9.21

 Electric Generators4 ............... 1.77 2.35 4.23 4.20 3.03 5.23 5.21 7.00 10.86 10.95

 Transportation5 ................... 0.08 0.24 0.24 0.24 0.42 0.41 0.41 0.69 0.66 0.66

 Total .......................... 39.82 42.98 44.43 44.37 44.49 46.66 46.61 49.97 54.21 54.19

1

Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 211

Table G9. Oil and Gas Supply

Production and Supply 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ..................... 16.49 20.42 20.43 20.43 20.81 20.84 20.80 21.46 21.43 21.43

Production (million barrels per day)

2

 U.S. Total .................................. 5.88 5.60 5.57 5.57 5.15 5.17 5.17 5.01 5.25 5.26

 Lower 48 Onshore ........................... 3.27 2.75 2.77 2.77 2.49 2.53 2.54 2.63 2.71 2.71

 Conventional .............................. 2.59 2.15 2.16 2.17 1.82 1.89 1.90 1.91 2.02 2.03

 Enhanced Oil Recovery ..................... 0.68 0.61 0.60 0.60 0.66 0.63 0.64 0.72 0.69 0.69

 Lower 48 Offshore ........................... 1.56 2.05 2.01 2.01 2.02 1.99 1.99 1.75 1.90 1.91

 Alaska .................................... 1.05 0.79 0.79 0.79 0.64 0.64 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 . 18.33 15.46 15.44 15.43 14.03 14.22 14.24 13.43 14.08 14.10

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ......... 2.08 2.49 3.14 3.15 2.68 3.48 3.52 3.14 4.00 4.06

Production (trillion cubic feet)3

 U.S. Total .................................. 18.67 20.72 22.37 22.34 23.03 25.04 25.04 28.84 30.86 31.02

 Lower 48 Onshore ........................... 12.83 14.33 15.59 15.58 16.32 18.01 18.02 21.20 22.79 22.92

 Associated-Dissolved4 ....................... 1.80 1.51 1.51 1.51 1.34 1.38 1.38 1.35 1.39 1.39

 Non-Associated ............................ 11.03 12.82 14.08 14.06 14.98 16.63 16.64 19.85 21.40 21.53

 Conventional ............................. 6.64 7.19 8.13 8.10 8.31 8.99 9.02 11.38 11.38 11.41

 Unconventional ........................... 4.39 5.62 5.95 5.96 6.66 7.63 7.62 8.48 10.02 10.12

 Lower 48 Offshore ........................... 5.43 5.93 6.31 6.30 6.21 6.54 6.52 7.07 7.51 7.53

 Associated-Dissolved4 ....................... 0.93 1.07 1.07 1.07 1.07 1.06 1.06 1.01 1.04 1.04

 Non-Associated ............................ 4.50 4.85 5.24 5.23 5.13 5.48 5.47 6.06 6.46 6.49

 Alaska .................................... 0.42 0.47 0.46 0.46 0.50 0.50 0.50 0.57 0.57 0.57

Lower 48 End of Year Reserves3

 (trillion cubic feet) .......................... 157.41 166.23 168.11 168.42 174.58 188.80 188.32 188.20 206.82 207.43

 Supplemental Gas Supplies (trillion cubic feet)5 . . 0.10 0.11 0.11 0.11 0.06 0.06 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) .............. 17.94 24.11 28.74 28.72 28.67 35.40 35.49 39.25 48.03 48.12

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
212 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Production1

 Appalachia ............................. 434 422 351 342 412 317 306 395 257 250

 Interior ................................ 185 180 156 128 177 142 111 163 121 100

 West ................................. 485 633 426 470 708 401 451 784 353 375

 East of the Mississippi .................... 561 554 463 427 545 425 383 525 349 322

 West of the Mississippi ................... 543 681 470 513 752 434 486 817 382 403

 Total ................................ 1105 1235 932 940 1297 859 869 1342 731 726

 Net Imports

 Imports ................................ 9 16 12 12 17 9 9 20 9 9

 Exports ................................ 58 60 60 60 58 57 57 56 58 58

 Total ................................. -49 -44 -48 -48 -40 -48 -48 -36 -49 -50

 Total Supply2 ........................... 1055 1191 884 892 1256 811 820 1306 682 676

 Consumption by Sector

 Residential and Commercial ............... 55 5 5 5 5 5 5 5 5

 Industrial3 .............................. 79 83 84 84 84 87 87 86 91 91

 Coke Plants ............................ 28 26 26 26 23 23 23 19 19 19

 Electric Generators4 ..................... 922 1078 770 780 1145 697 705 1198 573 564

 Total ................................ 1034 1192 885 894 1257 812 820 1308 688 679

 Discrepancy and Stock Change5

. .......... 21 -1 -0 -2 -1 -1 1 -2 -6 -3

 Average Minemouth Price

 (1999 dollars per short ton) ................ 17.23 14.76 14.88 14.11 13.69 13.96 12.97 12.84 12.60 11.99 

 (1999 dollars per million Btu) ............... 0.82 0.72 0.71 0.68 0.67 0.67 0.63 0.63 0.60 0.58 

 Delivered Prices (1999 dollars per short ton)6

 Industrial .............................. 31.46 29.43 28.56 28.29 28.41 27.12 26.71 26.55 24.09 23.89 

 Coke Plants ............................ 44.20 42.47 42.71 42.70 41.29 41.41 41.33 38.57 38.57 38.66 

 Electric Generators

 (1999 dollars per short ton) ............... 24.78 22.62 21.15 20.76 20.84 19.70 19.16 19.40 17.13 16.75 

 (1999 dollars per million Btu) ............. 1.22 1.13 1.04 1.04 1.05 0.97 0.96 0.98 0.86 0.85 

 Average ............................. 25.82 23.53 22.48 22.10 21.72 21.11 20.58 20.15 18.65 18.32 

 Exports7 ............................... 37.43 36.32 36.03 36.07 35.54 34.87 34.91 33.13 31.74 31.80 

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators. 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A. Projections: EIA, AEO2001 National Energy Modeling System

runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 213

Table G11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ........... 78.14 78.62 79.92 79.92 78.74 80.04 80.04 78.74 80.04 80.04

 Geothermal2 ..................... 2.87 3.16 5.80 5.67 4.31 10.17 9.46 4.34 10.24 9.52

 Municipal Solid Waste3 ............. 2.59 3.15 3.85 3.80 3.56 4.28 4.24 4.07 4.80 4.76

 Wood and Other Biomass4 .......... 1.52 1.68 1.77 1.76 2.04 2.48 2.53 2.37 3.92 3.92

 Solar Thermal .................... 0.33 0.35 0.35 0.35 0.40 0.40 0.40 0.48 0.48 0.48

 Solar Photovoltaic ................. 0.01 0.09 0.09 0.09 0.21 0.21 0.21 0.54 0.54 0.54

 Wind ........................... 2.60 4.43 4.54 4.54 5.51 5.92 5.90 5.78 13.94 13.41

 Total .......................... 88.07 91.47 96.32 96.13 94.76 103.50 102.78 96.33 113.97 112.68

 Generation (billion kilowatthours)

 Conventional Hydropower ........... 307.43 299.05 303.50 303.49 298.99 303.42 303.41 297.94 302.33 302.33

 Geothermal2 ..................... 13.07 15.90 46.28 45.22 24.98 80.74 75.14 25.33 81.31 75.69

 Municipal Solid Waste3 ............. 18.05 22.30 27.75 27.39 24.94 30.65 30.30 28.85 34.62 34.28

 Wood and Other Biomass4 .......... 8.86 14.45 54.09 54.11 21.55 84.88 84.99 22.15 81.44 80.09

 Dedicated Plants ................ 7.56 8.67 9.32 9.27 10.88 13.85 14.20 13.35 23.74 23.72

 Cofiring ........................ 1.30 5.78 44.77 44.84 10.67 71.03 70.79 8.80 57.70 56.37

 Solar Thermal .................... 0.89 0.96 0.96 0.96 1.11 1.11 1.11 1.37 1.37 1.37

 Solar Photovoltaic ................. 0.03 0.20 0.20 0.20 0.51 0.51 0.51 1.36 1.36 1.36

 Wind ........................... 4.46 9.42 9.74 9.73 12.33 13.46 13.42 13.10 39.49 37.78

 Total .......................... 352.79 362.28 442.52 441.11 384.41 514.76 508.88 390.09 541.92 532.89

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste .............. 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70 0.70

 Biomass ......................... 4.65 5.17 5.10 5.10 6.06 6.06 6.06 7.54 7.56 7.56

 Total .......................... 5.35 5.87 5.80 5.80 6.76 6.76 6.76 8.23 8.26 8.26

 Generation (billion kilowatthours)

 Municipal Solid Waste .............. 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03 4.03

 Biomass ......................... 27.08 29.92 29.52 29.52 35.01 34.95 34.95 43.52 43.62 43.62

 Total .......................... 31.10 33.95 33.55 33.55 39.03 38.98 38.98 47.55 47.65 47.65

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 .......... 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99 0.99

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................. 0.01 0.10 0.10 0.10 0.35 0.35 0.35 0.35 0.35 0.35

 Total .......................... 1.00 1.09 1.09 1.09 1.34 1.34 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 .......... 4.57 4.44 4.44 4.44 4.43 4.43 4.43 4.41 4.41 4.41

 Geothermal ...................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................ 0.02 0.20 0.20 0.20 0.75 0.75 0.75 0.75 0.75 0.75

 Total ......................... 4.59 4.64 4.64 4.64 5.18 5.18 5.18 5.17 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
214 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

Marketed Renewable Energy2

 Residential .................................. 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.43 0.43

 Wood ...................................... 0.41 0.43 0.43 0.43 0.43 0.42 0.42 0.44 0.43 0.43

 Commercial ................................. 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Biomass .................................... 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08

 Industrial3 .................................. 2.15 2.42 2.40 2.40 2.64 2.64 2.64 3.08 3.08 3.08

 Conventional Hydroelectric ..................... 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ......................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Biomass .................................... 1.97 2.23 2.21 2.21 2.46 2.45 2.45 2.90 2.90 2.90

 Transportation ............................... 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

 Ethanol used in E854 .......................... 0.00 0.02 0.02 0.02 0.03 0.03 0.03 0.04 0.03 0.03

 Ethanol used in Gasoline Blending ............... 0.12 0.18 0.18 0.18 0.19 0.19 0.19 0.20 0.20 0.21

 Electric Generators5 .......................... 3.86 4.03 5.38 5.35 4.47 6.88 6.70 4.56 7.18 6.97

 Conventional Hydroelectric ..................... 3.17 3.08 3.12 3.12 3.08 3.12 3.12 3.06 3.11 3.11

 Geothermal ................................. 0.27 0.37 1.20 1.17 0.66 2.30 2.12 0.67 2.31 2.14

 Municipal Solid Waste6 ........................ 0.25 0.30 0.38 0.37 0.34 0.42 0.41 0.39 0.47 0.47

 Biomass .................................... 0.12 0.18 0.57 0.58 0.26 0.89 0.89 0.27 0.86 0.84

 Dedicated Plants ........................... 0.10 0.11 0.10 0.10 0.13 0.15 0.15 0.16 0.25 0.25

 Cofiring ................................... 0.02 0.07 0.48 0.48 0.13 0.74 0.74 0.11 0.61 0.59

 Solar Thermal ............................... 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ............................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Wind ...................................... 0.05 0.10 0.10 0.10 0.13 0.14 0.14 0.13 0.41 0.39

 Total Marketed Renewable Energy .............. 6.61 7.16 8.49 8.45 7.84 10.24 10.06 8.40 11.01 10.80

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ................................. 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.03 0.03

 Solar Hot Water Heating ....................... 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps ....................... 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Photovoltaic ............................ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Commercial ................................. 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03

 Solar Thermal ............................... 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.19 0.19 0.19 0.19 0.16 0.17 0.17

 From Cellulose ..................... 0.00 0.01 0.01 0.01 0.02 0.02 0.02 0.07 0.07 0.07

 Total ............................ 0.12 0.20 0.20 0.20 0.21 0.21 0.21 0.23 0.24 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 215

Table G13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Residential

 Petroleum ................................... 26.0 26.8 26.9 26.9 24.4 24.6 24.6 22.9 23.4 23.4

 Natural Gas .................................. 69.5 78.6 77.0 77.0 82.0 79.7 79.6 90.8 88.2 88.0

 Coal ........................................ 1.1 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.2 1.2

 Electricity .................................... 192.6 223.2 180.7 180.9 240.4 177.8 177.8 274.7 182.3 181.3

 Total ...................................... 289.3 330.0 285.9 286.0 348.1 283.5 283.4 389.6 295.1 293.9

 Commercial

 Petroleum ................................... 13.7 12.9 13.0 13.0 13.1 13.6 13.7 12.9 13.8 13.9

 Natural Gas .................................. 45.4 53.5 52.1 52.0 56.0 53.8 53.7 59.4 58.2 58.0

 Coal ........................................ 1.7 1.8 1.8 1.8 1.9 1.9 1.9 2.0 2.0 2.0

 Electricity .................................... 182.1 216.0 174.4 174.3 237.0 176.3 175.7 265.8 176.2 174.8

 Total ...................................... 242.9 284.1 241.2 241.0 307.9 245.6 245.0 340.0 250.2 248.6

 Industrial1

 Petroleum ................................... 104.2 99.0 99.1 99.4 104.7 106.8 107.0 115.6 122.7 123.8

 Natural Gas2 ................................. 141.6 147.8 148.6 148.3 157.6 159.1 158.8 174.9 175.3 174.2

 Coal ........................................ 55.9 66.5 66.7 66.7 66.3 67.6 67.6 66.4 68.7 68.8

 Electricity .................................... 178.8 193.9 159.6 159.9 203.0 152.5 152.4 228.1 147.3 146.8

 Total ...................................... 480.4 507.2 474.1 474.3 531.6 485.9 485.8 584.9 514.0 513.5

 Transportation

 Petroleum3 ................................... 485.8 556.8 552.3 552.4 608.6 605.2 605.3 705.1 701.6 701.6

 Natural Gas4 ................................. 9.5 11.8 12.8 12.8 14.1 15.2 15.2 17.9 19.2 19.3

 Other5 ...................................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity .................................... 2.9 4.4 3.7 3.7 5.7 4.5 4.5 7.9 5.5 5.5

 Total3 ...................................... 498.2 573.1 568.8 568.9 628.6 624.9 625.1 730.9 726.4 726.5

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 ............................ 629.7 695.5 691.3 691.7 750.8 750.2 750.6 856.4 861.6 862.7

 Natural Gas .................................. 266.0 291.8 290.5 290.0 309.7 307.9 307.4 342.9 340.8 339.4

 Coal ........................................ 58.8 69.6 69.7 69.7 69.5 70.7 70.8 69.6 71.9 72.0

 Other5 ...................................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Electricity .................................... 556.3 637.5 518.4 518.8 686.1 511.1 510.4 776.5 511.4 508.3

 Total3 ...................................... 1510.8 1694.3 1570.0 1570.3 1816.2 1640.0 1639.2 2045.4 1785.8 1782.5

 Electric Generators6

 Petroleum ................................... 20.0 6.8 4.5 4.6 3.5 3.0 3.0 3.9 2.2 2.2

 Natural Gas .................................. 45.8 77.1 114.7 114.8 98.6 147.7 148.2 164.1 216.0 220.7

 Coal ........................................ 490.5 553.6 399.2 399.4 584.0 360.5 359.2 608.4 293.2 285.5

 Total ...................................... 556.3 637.5 518.4 518.8 686.1 511.1 510.4 776.5 511.4 508.3

 Total Carbon Dioxide Emissions

 by Primary Fuel7

 Petroleum3 ................................... 649.7 702.2 695.8 696.2 754.3 753.1 753.6 860.3 863.8 864.9

 Natural Gas .................................. 311.8 368.9 405.2 404.8 408.2 455.6 455.5 507.1 556.8 560.1

 Coal ........................................ 549.3 623.1 468.9 469.2 653.5 431.2 430.0 678.0 365.1 357.5

 Other5 ...................................... 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

 Total3 ...................................... 1510.8 1694.3 1570.0 1570.3 1816.2 1640.0 1639.2 2045.4 1785.8 1782.5

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) ............. 5.5 5.9 5.5 5.5 6.1 5.5 5.5 6.3 5.5 5.5

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 20 to 25 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
216 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table G14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999

Projections

2005 2010 2020

Reference CO2

Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity Reference CO2Sensitivity

Integrated 

Sensitivity

 Scrubber Retrofits (gigawatts)1 ............... 0.00 10.76 0.00 8.36 10.76 0.00 8.36 15.24 0.00 8.36

 SO2 Allowance Price

 (1999 dollars per ton) ...................... 0.00 177.63 4.26 104.12 169.55 5.20 101.20 246.09 0.00 51.01

 NOx Controls (gigawatts)

 Combustion .............................. 0.00 65.84 60.68 59.86 66.93 61.20 59.86 67.57 61.20 59.86

 SCR Post-combustion 0.00 84.31 54.34 60.13 85.97 54.34 60.13 89.75 54.34 60.13

 SNCR Post-combustion ..................... 0.00 25.36 26.16 25.75 28.78 26.16 25.75 38.69 26.16 25.75

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ............... 472.31 598.07 405.41 447.19 656.33 377.53 429.60 730.01 329.97 348.82

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) ......... 433.55 451.27 363.52 350.73 453.06 327.80 312.51 438.05 269.85 262.83

 High Sulfur (> 1.67 lbs. S/mmBtu) .............. 198.66 185.83 163.35 141.70 187.25 153.91 126.57 174.20 131.38 113.93

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here.

 SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MCBASE.D121300A, FDC7B05H.D121300A, and FDP7B05H.D121300A.
Appendix H

Tables for New Source Review Reference Cases

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 219

Table H1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Production

 Crude Oil and Lease Condensate ....... 12.45 10.90 10.90 10.61 10.63

 Natural Gas Plant Liquids ............. 2.62 3.31 3.31 4.08 4.10

 Dry Natural Gas ..................... 19.16 23.61 23.64 29.69 29.79

 Coal .............................. 23.11 26.60 26.97 27.23 27.41

 Nuclear Power ...................... 7.79 7.69 7.69 6.17 6.08

 Renewable Energy1 .................. 6.50 7.62 7.59 8.17 8.15

 Other2 ............................ 1.65 0.30 0.31 0.33 0.33

 Total ........................... 73.29 80.03 80.40 86.28 86.50

 Imports

 Crude Oil3 ......................... 18.96 25.11 25.22 26.55 26.54

 Petroleum Products4 ................. 4.14 6.58 6.50 10.64 10.65

 Natural Gas ........................ 3.63 5.46 5.43 6.59 6.64

 Other Imports5 ...................... 0.64 0.96 0.96 0.96 0.96

 Total ........................... 27.37 38.10 38.12 44.74 44.79

 Exports

 Petroleum6 ......................... 1.98 1.78 1.78 1.88 1.90

 Natural Gas ........................ 0.17 0.43 0.43 0.63 0.63

 Coal .............................. 1.48 1.45 1.45 1.41 1.38

 Total ........................... 3.62 3.67 3.66 3.92 3.92

 Discrepancy7 ........................ 0.95 0.17 0.22 -0.04 -0.03

 Consumption

 Petroleum Products8 ................. 37.99 44.43 44.47 50.59 50.58

 Natural Gas ........................ 21.98 28.47 28.47 35.48 35.64

 Coal .............................. 21.46 25.69 26.04 26.48 26.69

 Nuclear Power ..................... . 7.79 7.69 7.69 6.17 6.08

 Renewable Energy1 .................. 6.51 7.62 7.59 8.18 8.16

 Other9 ............................ 0.35 0.38 0.38 0.25 0.25

 Total ............................ 96.09 114.29 114.64 127.14 127.40

 Net Imports - Petroleum ............... 21.12 29.91 29.94 35.32 35.29

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 ...... 17.35 21.37 21.37 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 .... 2.08 2.69 2.76 3.12 3.09

 Coal Minemouth Price (dollars per ton) .... 17.22 14.48 15.79 13.48 14.28

 Average Electric Price (cents per Kwh) 6.6 6.0 6.1 5.9 6.0

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

MC_NSR.D121900A, NSR_ALL.D121900A.
220 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

Energy Consumption

 Residential

 Distillate Fuel ....................... 0.86 0.81 0.81 0.75 0.75

 Kerosene .......................... 0.10 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas .............. 0.46 0.41 0.41 0.39 0.39

 Petroleum Subtotal ................. 1.42 1.29 1.29 1.21 1.21

 Natural Gas ........................ 4.85 5.69 5.68 6.31 6.32

 Coal .............................. 0.04 0.05 0.05 0.05 0.05

 Renewable Energy1 .................. 0.41 0.43 0.43 0.44 0.44

 Electricity .......................... 3.91 4.95 4.92 5.81 5.79

 Delivered Energy .................. 10.62 12.41 12.37 13.82 13.81

 Electricity Related Losses ............. 8.46 9.94 10.06 10.57 10.69

 Total ............................ 19.09 22.35 22.43 24.39 24.50

 Commercial

 Distillate Fuel ....................... 0.36 0.41 0.41 0.39 0.39

 Residual Fuel ...................... 0.10 0.11 0.11 0.11 0.11

 Kerosene .......................... 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas .............. 0.08 0.09 0.09 0.10 0.10

 Motor Gasoline2 ..................... 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal ................. 0.59 0.67 0.67 0.66 0.66

 Natural Gas ........................ 3.15 3.88 3.87 4.13 4.14

 Coal .............................. 0.07 0.07 0.07 0.08 0.08

 Renewable Energy3 .................. 0.08 0.08 0.08 0.08 0.08

 Electricity .......................... 3.70 4.86 4.86 5.64 5.62

 Delivered Energy .................. 7.59 9.57 9.56 10.58 10.57

 Electricity Related Losses ............. 8.00 9.77 9.95 10.27 10.37

 Total ............................ 15.59 19.34 19.50 20.85 20.94

 Industrial4

 Distillate Fuel ....................... 1.07 1.27 1.27 1.44 1.45

 Liquefied Petroleum Gas .............. 2.32 2.50 2.50 2.83 2.83

 Petrochemical Feedstock ............. 1.29 1.53 1.53 1.70 1.70

 Residual Fuel ...................... 0.22 0.25 0.25 0.27 0.27

 Motor Gasoline2 ..................... 0.21 0.25 0.25 0.28 0.28

 Other Petroleum5 .................... 4.29 4.75 4.75 5.24 5.24

 Petroleum Subtotal ................. 9.39 10.54 10.55 11.77 11.77

 Natural Gas6 ....................... 9.43 11.13 11.10 12.33 12.36

 Metallurgical Coal ................... 0.75 0.61 0.61 0.50 0.50

 Steam Coal ........................ 1.73 1.85 1.77 1.89 1.82

 Net Coal Coke Imports ............... 0.06 0.16 0.16 0.22 0.22

 Coal Subtotal ...................... 2.54 2.62 2.54 2.61 2.54

 Renewable Energy7 .................. 2.15 2.64 2.64 3.08 3.08

 Electricity .......................... 3.63 4.17 4.18 4.82 4.80

 Delivered Energy .................. 27.15 31.11 31.02 34.62 34.56

 Electricity Related Losses ............. 7.85 8.38 8.56 8.76 8.86

 Total ............................ 35.00 39.49 39.58 43.38 43.42
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 221

Table H2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Transportation

 Distillate Fuel ....................... 5.13 6.99 6.98 8.20 8.20

 Jet Fuel8 .......................... 3.46 4.51 4.51 5.97 5.97

 Motor Gasoline2 ..................... 15.92 19.03 19.05 21.31 21.32

 Residual Fuel ...................... 0.74 0.85 0.85 0.87 0.87

 Liquefied Petroleum Gas .............. 0.02 0.04 0.04 0.06 0.06

 Other Petroleum9 .................... 0.26 0.31 0.31 0.35 0.35

 Petroleum Subtotal ................. 25.54 31.73 31.74 36.76 36.77

 Pipeline Fuel Natural Gas ............. 0.66 0.89 0.90 1.09 1.09

 Compressed Natural Gas ............. 0.02 0.09 0.09 0.16 0.16

 Renewable Energy (E85)10 ............ 0.01 0.03 0.03 0.04 0.04

 Methanol (M85)11 .................... 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................... 0.00 0.00 0.00 0.00 0.00

 Electricity .......................... 0.06 0.12 0.12 0.17 0.17

 Delivered Energy .................. 26.28 32.87 32.88 38.22 38.23

 Electricity Related Losses ............. 0.13 0.24 0.24 0.30 0.31

 Total ............................ 26.41 33.11 33.13 38.52 38.54

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ....................... 7.42 9.47 9.47 10.79 10.79

 Kerosene .......................... 0.15 0.13 0.13 0.12 0.12

 Jet Fuel8 .......................... 3.46 4.51 4.51 5.97 5.97

 Liquefied Petroleum Gas .............. 2.88 3.05 3.05 3.38 3.39

 Motor Gasoline2 ..................... 16.17 19.31 19.32 21.62 21.63

 Petrochemical Feedstock ............. 1.29 1.53 1.53 1.70 1.70

 Residual Fuel ...................... 1.05 1.21 1.21 1.25 1.25

 Other Petroleum12 ................... 4.53 5.03 5.04 5.57 5.57

 Petroleum Subtotal ................. 36.95 44.24 44.25 50.40 50.41

 Natural Gas6 ....................... 18.11 21.69 21.64 24.01 24.07

 Metallurgical Coal ................... 0.75 0.61 0.61 0.50 0.50

 Steam Coal ........................ 1.84 1.98 1.90 2.01 1.94

 Net Coal Coke Imports ............... 0.06 0.16 0.16 0.22 0.22

 Coal Subtotal ...................... 2.65 2.74 2.66 2.74 2.67

 Renewable Energy13 ................. 2.65 3.19 3.19 3.65 3.65

 Methanol (M85)11 .................... 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................... 0.00 0.00 0.00 0.00 0.00

 Electricity .......................... 11.29 14.10 14.08 16.44 16.37

 Delivered Energy .................. 71.65 85.96 85.83 97.24 97.17

 Electricity Related Losses ............. 24.44 28.33 28.82 29.90 30.23

 Total ............................ 96.09 114.29 114.64 127.14 127.40

 Electric Generators14

 Distillate Fuel ....................... 0.05 0.04 0.02 0.04 0.02

 Residual Fuel ...................... 0.99 0.16 0.20 0.15 0.15

 Petroleum Subtotal ................. 1.05 0.20 0.22 0.19 0.17

 Natural Gas ........................ 3.88 6.78 6.82 11.47 11.57

 Steam Coal ........................ 18.80 22.95 23.38 23.74 24.02

 Nuclear Power ...................... 7.79 7.69 7.69 6.17 6.08

 Renewable Energy15 ................. 3.86 4.43 4.40 4.53 4.51

 Electricity Imports16 .................. 0.35 0.37 0.37 0.24 0.24

 Total ............................ 35.73 42.43 42.89 46.34 46.60
222 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Total Energy Consumption

 Distillate Fuel ....................... 7.47 9.51 9.49 10.83 10.81

 Kerosene .......................... 0.15 0.13 0.13 0.12 0.12

 Jet Fuel8 .......................... 3.46 4.51 4.51 5.97 5.97

 Liquefied Petroleum Gas .............. 2.88 3.05 3.05 3.38 3.39

 Motor Gasoline2 ..................... 16.17 19.31 19.32 21.62 21.63

 Petrochemical Feedstock ............. 1.29 1.53 1.53 1.70 1.70

 Residual Fuel ...................... 2.05 1.37 1.41 1.39 1.40

 Other Petroleum12 ................... 4.53 5.03 5.04 5.57 5.57

 Petroleum Subtotal ................. 37.99 44.43 44.47 50.59 50.58

 Natural Gas ........................ 21.98 28.47 28.47 35.48 35.64

 Metallurgical Coal ................... 0.75 0.61 0.61 0.50 0.50

 Steam Coal ........................ 20.65 24.93 25.28 25.76 25.96

 Net Coal Coke Imports ............... 0.06 0.16 0.16 0.22 0.22

 Coal Subtotal ...................... 21.46 25.69 26.04 26.48 26.69

 Nuclear Power ...................... 7.79 7.69 7.69 6.17 6.08

 Renewable Energy17 ................. 6.51 7.62 7.59 8.18 8.16

 Methanol (M85)11 .................... 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................... 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 .................. 0.35 0.37 0.37 0.24 0.24

 Total ............................ 96.09 114.29 114.64 127.14 127.40

Energy Use and Related Statistics

 Delivered Energy Use ................. 71.65 85.96 85.83 97.24 97.17

 Total Energy Use .................... 96.09 114.29 114.64 127.14 127.40

 Population (millions) ................... 273.13 300.17 300.17 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 12667 12667 16515 16515

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) ... 1510.8 1818.8 1827.5 2045.6 2052.2

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which produces electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A,

NSR_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 223

Table H3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Residential .......................... 13.12 13.28 13.49 13.46 13.55

 Primary Energy1 ..................... 6.72 7.02 7.07 7.00 6.98

 Petroleum Products2 ................. 7.55 9.38 9.33 9.63 9.62

 Distillate Fuel ...................... 6.27 7.51 7.48 7.97 7.97

 Liquefied Petroleum Gas ............. 10.36 13.09 13.00 12.86 12.85

 Natural Gas ........................ 6.52 6.53 6.60 6.54 6.51

 Electricity ........................... 23.47 22.19 22.67 21.86 22.17

 Commercial ......................... 13.21 12.04 12.18 12.10 12.23

 Primary Energy1 ..................... 5.22 5.54 5.59 5.74 5.71

 Petroleum Products2 ................. 5.00 6.18 6.15 6.49 6.48

 Distillate Fuel ...................... 4.37 5.28 5.26 5.74 5.74

 Residual Fuel ..................... 2.63 3.70 3.70 3.85 3.85

 Natural Gas3 ....................... 5.34 5.51 5.57 5.70 5.67

 Electricity ........................... 21.45 18.22 18.44 17.57 17.89

 Industrial4 ........................... 5.32 5.51 5.56 5.77 5.81

 Primary Energy ...................... 3.92 4.39 4.40 4.71 4.71

 Petroleum Products2 ................. 5.55 6.07 6.01 6.26 6.26

 Distillate Fuel ...................... 4.65 5.46 5.44 5.94 5.93

 Liquefied Petroleum Gas ............. 8.50 8.04 7.94 7.82 7.81

 Residual Fuel ..................... 2.78 3.43 3.43 3.58 3.58

 Natural Gas5 ....................... 2.79 3.31 3.38 3.75 3.72

 Metallurgical Coal ................... 1.66 1.55 1.54 1.44 1.44

 Steam Coal ........................ 1.43 1.31 1.32 1.22 1.22

 Electricity ........................... 13.02 11.62 11.80 11.20 11.45

 Transportation ....................... 8.30 9.50 9.45 9.31 9.30

 Primary Energy ...................... 8.29 9.49 9.43 9.30 9.29

 Petroleum Products2 ................. 8.28 9.49 9.43 9.29 9.28

 Distillate Fuel6 ..................... 8.22 8.94 8.94 8.97 8.96

 Jet Fuel7 ......................... 4.70 5.47 5.46 5.88 5.88

 Motor Gasoline8 .................... 9.45 11.01 10.92 10.69 10.67

 Residual Fuel ..................... 2.46 3.18 3.18 3.33 3.33

 Liquid Petroleum Gas9 ............... 12.87 14.28 14.19 13.81 13.82

 Natural Gas10 ....................... 7.02 7.05 7.11 7.31 7.28

 Ethanol (E85)11 ..................... 14.42 19.03 19.01 19.36 19.35

 Methanol (M85)12 .................... 10.38 13.76 13.73 14.43 14.43

 Electricity ........................... 15.60 13.40 13.74 12.96 13.05

 Average End-Use Energy .............. 8.53 9.04 9.08 9.10 9.14

 Primary Energy ...................... 6.33 7.21 7.20 7.30 7.29

 Electricity ........................... 19.41 17.62 17.91 17.17 17.47

 Electric Generators13

 Fossil Fuel Average ................... 1.49 1.52 1.52 1.85 1.83

 Petroleum Products .................. 2.49 3.97 3.80 4.28 4.15

 Distillate Fuel ...................... 4.05 4.84 4.89 5.27 5.27

 Residual Fuel ..................... 2.41 3.76 3.69 4.01 4.01

 Natural Gas ........................ 2.53 3.05 3.13 3.62 3.60

 Steam Coal ........................ 1.21 1.05 1.03 0.98 0.96
224 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Average Price to All Users14

 Petroleum Products2 .................. 7.44 8.67 8.61 8.61 8.60

 Distillate Fuel ....................... 7.27 8.18 8.18 8.36 8.36

 Jet Fuel ........................... 4.70 5.47 5.46 5.88 5.88

 Liquefied Petroleum Gas .............. 8.84 8.91 8.81 8.61 8.59

 Motor Gasoline8 ..................... 9.45 11.01 10.91 10.69 10.67

 Residual Fuel ...................... 2.48 3.33 3.34 3.49 3.49

 Natural Gas ........................ 4.05 4.29 4.36 4.51 4.48

 Coal ............................... 1.23 1.07 1.06 1.00 0.98

 Ethanol (E85)11 ...................... 14.42 19.03 19.01 19.36 19.35

 Methanol (M85)12 ..................... 10.38 13.76 13.73 14.43 14.43

 Electricity ........................... 19.41 17.62 17.91 17.17 17.47

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ............................ 134.10 159.17 161.07 180.05 181.22

 Commercial ........................... 99.17 114.23 115.40 127.02 128.27

 Industrial ............................. 110.67 128.27 129.01 148.87 149.52

 Transportation ......................... 212.64 303.38 301.68 344.91 344.68

 Total Non-Renewable Expenditures ...... 556.57 705.06 707.17 800.86 803.69

 Transportation Renewable Expenditures ... 0.14 0.62 0.61 0.86 0.86

 Total Expenditures ................... 556.71 705.68 707.78 801.72 804.55

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report

, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A. 1999 electricity

prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A, Projections: EIA,

AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 225

Table H4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

Generation by Fuel Type

 Electric Generators1

 Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1835 2235 2228 2307 2290

 Petroleum ......................... 97 20 23 20 18

 Natural Gas2 ....................... 372 849 857 1594 1607

 Nuclear Power ...................... 730 720 720 577 570

 Pumped Storage .................... -1 -1 -1 -1 -1

 Renewable Sources3 . . . . . . . . . . . . . . . . . 353 383 377 389 385

 Total ............................ 3386 4207 4204 4886 4867

 Non-Utility Generation for Own Use ..... 16 17 16 16 16

 Distributed Generation ............... 02 3 7 7

 Cogenerators4

 Coal ............................. 47 52 46 52 46

 Petroleum ........................ 9 10 10 10 10

 Natural Gas ....................... 206 261 257 297 305

 Other Gaseous Fuels5 ............... 47 7 8 8

 Renewable Sources3 . . . . . . . . . . . . . . . . 31 39 39 48 48

 Other6 ........................... 55 5 5 5

 Total ........................... 302 375 365 420 422

 Other End-Use Generators7 .......... 55 5 5 5

 Sales to Utilities .................... 150 178 171 199 195

 Generation for Own Use ............. 156 202 199 226 232

 Net Imports8 ........................ 33 35 35 23 23

Electricity Sales by Sector

 Residential .......................... 1146 1451 1441 1703 1696

 Commercial ......................... 1083 1426 1424 1654 1646

 Industrial ........................... 1063 1223 1226 1412 1406

 Transportation . . . . . . . . . . . . . . . . . . . . . . . 17 35 35 49 49

 Total ............................. 3309 4134 4126 4817 4797

End-Use Prices (1999 cents per kwh)9

 Residential .......................... 8.0 7.6 7.7 7.5 7.6

 Commercial . . . . . . . . . . . . . . . . . . . . . . . . . 7.3 6.2 6.3 6.0 6.1

 Industrial ........................... 4.4 4.0 4.0 3.8 3.9

 Transportation ....................... 5.3 4.6 4.7 4.4 4.5

 All Sectors Average ................ 6.6 6.0 6.1 5.9 6.0

 Prices by Service Category9

 (1999 cents per kwh)

 Generation .......................... 4.1 3.3 3.4 3.2 3.3

 Transmission ........................ 0.6 0.7 0.7 0.7 0.7

 Distribution ......................... 2.0 2.0 2.0 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide ....................... 13.84 9.10 1.94 8.35 1.90

 Nitrogen Oxide ...................... 5.45 3.78 1.56 3.90 1.62

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

 Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
226 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

Electric Generators2

 Capability

 Coal Steam ........................ 306.2 314.4 305.9 315.1 309.1

 Other Fossil Steam3 ................. 138.2 124.3 124.8 122.3 122.5

 Combined Cycle .................... 20.2 124.1 128.3 241.3 243.5

 Combustion Turbine/Diesel ............ 82.4 145.8 153.4 209.3 208.6

 Nuclear Power ...................... 97.4 94.2 94.2 71.6 70.5

 Pumped Storage .................... 19.3 19.5 19.5 19.5 19.5

 Fuel Cells ......................... 0.0 0.1 0.1 0.3 0.3

 Renewable Sources4 ................. 88.1 94.6 94.6 96.2 96.4

 Distributed Generation5 ............... 0.0 5.4 6.3 16.3 15.8

 Total ............................ 751.8 922.5 927.1 1091.9 1086.1

 Cumulative Planned Additions6

 Coal Steam ........................ 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ................. 0.0 0.1 0.1 0.1 0.1

 Combined Cycle .................... 0.0 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ............ 0.0 0.7 0.7 0.7 0.7

 Nuclear Power ...................... 0.0 0.0 0.0 0.0 0.0

 Pumped Storage .................... 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ......................... 0.0 0.1 0.1 0.3 0.3

 Renewable Sources4 ................. 0.0 4.3 4.3 5.4 5.4

 Distributed Generation5 ............... 0.0 0.0 0.0 0.0 0.0

 Total ............................ 0.0 13.6 13.6 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam ........................ 0.0 20.6 29.8 22.3 33.0

 Other Fossil Steam3 ................. 0.0 0.0 0.0 0.0 0.0

 Combined Cycle .................... 0.0 95.6 99.9 212.8 215.1

 Combustion Turbine/Diesel ........... . 0.0 67.4 73.3 131.9 129.8

 Nuclear Power ...................... 0.0 0.0 0.0 0.0 0.0

 Pumped Storage .................... 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ......................... 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ................. 0.0 1.8 1.7 2.3 2.5

 Distributed Generation5 ............... 0.0 5.4 6.3 16.3 15.8

 Total ............................ 0.0 190.7 211.1 385.5 396.3

 Cumulative Total Additions ........... 0.0 204.2 224.7 400.3 411.0

 Cumulative Retirements7

 Coal Steam ........................ 0.0 12.6 31.4 13.7 31.4

 Other Fossil Steam .................. 0.0 13.8 14.3 15.8 16.6

 Combined Cycle .................... 0.0 0.2 0.3 0.2 0.3

 Combustion Turbine/Diesel ........... 0.0 4.7 5.1 5.8 6.4

 Nuclear Power ..................... 0.0 3.3 3.3 25.9 27.0

 Pumped Storage ................... 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ......................... 0.0 0.0 0.0 0.0 0.0

 Renewable Sources ................. 0.0 0.1 0.1 0.1 0.1

 Total ........................... 0.0 34.7 54.5 61.4 81.8

Cogenerators8

 Capability

 Coal .............................. 8.4 8.9 7.9 8.9 7.9

 Petroleum ......................... 2.7 2.8 2.8 2.8 2.8

 Natural Gas ........................ 33.8 43.4 43.0 48.8 49.8

 Other Gaseous Fuels ................ 0.2 0.9 0.9 1.0 1.0

 Renewable Sources4 ................. 5.3 6.8 6.8 8.2 8.2

 Other ............................. 1.1 0.9 0.9 0.9 0.9

 Total ............................ 51.6 63.6 62.2 70.7 70.7

 Cumulative Additions6 ............... 0.0 12.0 10.5 19.0 19.1
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 227

Table H5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

Other End-Use Generators9

 Renewable Sources .......................... 1.0 1.3 1.3 1.3 1.3

 Cumulative Additions . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8

Nameplate capacity is reported for nonutilities on Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
228 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade . . . . . . . . . 182.2 102.9 102.9 0.0 0.0

 Gross Domestic Economy Trade .......... 146.6 199.8 209.6 197.4 200.2

 Gross Domestic Trade ................ 328.8 302.7 312.5 197.4 200.2

 Gross Domestic Firm Power Sales

 (million 1999 dollars) ................... 8588.1 4851.2 4851.2 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) ................... 4208.2 5394.7 5798.0 5876.0 5927.5

 Gross Domestic Sales

 (million 1999 dollars) ................. 12796.4 10246.0 10649.3 5876.0 5927.5

 International Electricity Trade

 Firm Power Imports From Canada and 27.0 5.8 5.8 0.0 0.0

 Economy Imports From Canada and Mexico1 . 21.9 45.9 45.9 30.6 30.6

 Gross Imports From Canada and Mexico1 . 48.9 51.7 51.7 30.6 30.6

 Firm Power Exports To Canada and Mexico . 9.2 8.7 8.7 0.0 0.0

 Economy Exports To Canada and Mexico ... 6.3 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico ... 15.5 16.4 16.4 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 229

Table H7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Production

 Dry Gas Production1 ................. 18.67 23.01 23.04 28.94 29.04

 Supplemental Natural Gas2 ............ 0.10 0.06 0.06 0.06 0.06

 Net Imports ........................ 3.38 4.91 4.88 5.81 5.87

 Canada ........................... 3.29 4.65 4.62 5.44 5.50

 Mexico ............................ -0.01 -0.25 -0.25 -0.40 -0.40

 Liquefied Natural Gas ................ 0.10 0.51 0.51 0.77 0.77

 Total Supply ........................ 22.15 27.98 27.98 34.81 34.96

 Consumption by Sector

 Residential ......................... 4.72 5.54 5.53 6.14 6.15

 Commercial ........................ 3.07 3.78 3.77 4.02 4.03

 Industrial3 .......................... 7.95 9.36 9.33 10.17 10.20

 Electric Generators4 ................. 3.80 6.66 6.70 11.26 11.35

 Lease and Plant Fuel5 ................ 1.23 1.49 1.48 1.84 1.84

 Pipeline Fuel ....................... 0.64 0.87 0.87 1.06 1.07

 Transportation6 ..................... 0.02 0.09 0.09 0.15 0.15

 Total ............................ 21.44 27.78 27.77 34.64 34.79

 Discrepancy7 ....................... 0.71 0.20 0.21 0.17 0.17

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1999 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A. Other 1999 consumption: EIA, Short-Term

Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption levels for consumption of natural

gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A. Projections: EIA, AEO2001

National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
230 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Source Price 

 Average Lower 48 Wellhead Price1 ...... 2.08 2.69 2.76 3.12 3.09

 Average Import Price . . . . . . . . . . . . . . . . . 2.29 2.41 2.46 2.66 2.68

 Average2 ......................... 2.11 2.64 2.70 3.04 3.01

 Delivered Prices

 Residential ......................... 6.69 6.71 6.78 6.72 6.69

 Commercial . . . . . . . . . . . . . . . . . . . . . . . . 5.49 5.66 5.72 5.85 5.82

 Industrial3 .......................... 2.87 3.40 3.47 3.85 3.82

 Electric Generators4 ................. 2.58 3.11 3.19 3.68 3.67

 Transportation5 ..................... 7.21 7.24 7.30 7.51 7.48

 Average6 ......................... 4.15 4.40 4.47 4.63 4.60

 Transmission & Distribution Margins7

 Residential ......................... 4.58 4.07 4.08 3.68 3.68

 Commercial ........................ 3.37 3.01 3.02 2.82 2.81

 Industrial3 .......................... 0.75 0.76 0.77 0.82 0.81

 Electric Generators4 . . . . . . . . . . . . . . . . . 0.47 0.47 0.49 0.65 0.66

 Transportation5 ..................... 5.10 4.59 4.60 4.48 4.47

 Average6 ......................... 2.04 1.76 1.77 1.59 1.59

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ......................... 21.61 22.55 22.54 22.62 22.63

 Commercial ........................ 10.36 11.40 11.39 11.31 11.33

 Industrial3 .......................... 6.00 7.14 7.17 8.32 8.28

 Electric Generators4 ................. 1.78 3.11 3.29 7.30 7.47

 Transportation5 . . . . . . . . . . . . . . . . . . . . . 0.08 0.42 0.42 0.69 0.69

 Total ............................ 39.83 44.62 44.80 50.24 50.39

1

Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 231

Table H9. Oil and Gas Supply

Production and Supply 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) .................... 16.49 20.80 20.82 21.43 21.45

Production (million barrels per day)

2

 U.S. Total ................................. 5.88 5.15 5.15 5.01 5.02

 Lower 48 Onshore .......................... 3.27 2.48 2.48 2.62 2.63

 Conventional ............................. 2.59 1.83 1.82 1.90 1.91

 Enhanced Oil Recovery .................... 0.68 0.66 0.66 0.72 0.72

 Lower 48 Offshore .......................... 1.56 2.02 2.02 1.75 1.75

 Alaska ................................... 1.05 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion barrels)2 18.33 14.03 14.03 13.42 13.47

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ........ 2.08 2.69 2.76 3.12 3.09

Production (trillion cubic feet)3

 U.S. Total ................................. 18.67 23.01 23.04 28.94 29.04

 Lower 48 Onshore .......................... 12.83 16.31 16.12 21.22 21.36

 Associated-Dissolved4 ...................... 1.80 1.34 1.34 1.35 1.35

 Non-Associated ........................... 11.03 14.97 14.78 19.88 20.01

 Conventional ............................ 6.64 8.27 8.04 11.40 11.47

 Unconventional .......................... 4.39 6.70 6.74 8.48 8.53

 Lower 48 Offshore .......................... 5.43 6.20 6.41 7.14 7.11

 Associated-Dissolved4 ...................... 0.93 1.07 1.07 1.01 1.01

 Non-Associated ........................... 4.50 5.12 5.34 6.13 6.10

 Alaska ................................... 0.42 0.50 0.50 0.57 0.57

Lower 48 End of Year Reserves 3

 (trillion cubic feet) ......................... 157.41 175.79 175.29 188.23 192.67

 Supplemental Gas Supplies (trillion cubic feet)5 . 0.10 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) ............. 17.94 28.80 28.71 38.82 38.85

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
232 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Production1

 Appalachia .................................. 433 440 465 416 434

 Interior . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186 189 234 183 219

 West ...................................... 485 660 590 730 672

 East of the Mississippi ......................... 561 584 657 563 623

 West of the Mississippi ........................ 543 704 632 766 702

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1104 1288 1289 1329 1325

 Net Imports

 Imports ..................................... 9 17 17 20 20

 Exports ..................................... 58 58 57 56 55

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -49 -40 -40 -36 -36

 Total Supply2 ................................ 1055 1248 1249 1293 1289

 Consumption by Sector

 Residential and Commercial .................... 5 5 5 5 5

 Industrial3 ................................... 79 84 81 86 83

 Coke Plants ................................. 28 23 23 19 19

 Electric Generators4 .......................... 922 1137 1140 1184 1183

 Total ..................................... 1034 1250 1249 1294 1290

 Discrepancy and Stock Change5

. ............... 21 -2 -0 -2 -1

 Average Minemouth Price

 (1999 dollars per short ton) ..................... 17.22 14.48 15.79 13.48 14.28

 (1999 dollars per million Btu) . . . . . . . . . . . . . . . . . . . . 0.82 0.70 0.75 0.66 0.69

 Delivered Prices (1999 dollars per short ton)6

 Industrial ................................... 31.44 28.75 28.82 26.84 26.62

 Coke Plants ................................. 44.38 41.42 41.19 38.51 38.49

 Electric Generators

 (1999 dollars per short ton) .................... 24.76 21.19 21.20 19.65 19.40

 (1999 dollars per million Btu) .................. 1.21 1.05 1.03 0.98 0.96

 Average .................................. 25.80 22.07 22.06 20.41 20.15

 Exports7 .................................... 37.54 35.73 35.13 33.14 32.57

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A. Projections: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A,

NSR_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 233

Table H11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower .................. 78.14 78.74 78.74 78.74 78.74

 Geothermal2 ............................ 2.87 4.16 4.36 4.22 4.43

 Municipal Solid Waste3 .................... 2.59 3.56 3.33 4.07 3.89

 Wood and Other Biomass4 ................. 1.52 2.04 2.04 2.37 2.59

 Solar Thermal ........................... 0.33 0.40 0.40 0.48 0.48

 Solar Photovoltaic ........................ 0.01 0.21 0.21 0.54 0.54

 Wind .................................. 2.60 5.51 5.51 5.78 5.78

 Total ................................. 88.07 94.61 94.59 96.20 96.45

 Generation (billion kilowatthours)

 Conventional Hydropower .................. 307.43 298.99 298.99 297.95 297.95

 Geothermal2 ............................ 13.07 23.79 25.39 24.32 25.99

 Municipal Solid Waste3 .................... 18.05 24.97 23.18 28.88 27.46

 Wood and Other Biomass4 ................. 9.16 21.26 15.56 22.18 17.37

 Dedicated Plants ....................... 7.56 10.88 10.88 13.35 14.79

 Cofiring ............................... 1.60 10.38 4.67 8.83 2.59

 Solar Thermal ........................... 0.89 1.11 1.11 1.37 1.37

 Solar Photovoltaic ........................ 0.03 0.51 0.51 1.36 1.36

 Wind .................................. 4.46 12.33 12.33 13.10 13.10

 Total ................................. 353.09 382.97 377.07 389.16 384.60

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste ..................... 0.70 0.70 0.70 0.70 0.70

 Biomass ................................ 4.65 6.06 6.06 7.54 7.54

 Total ................................. 5.35 6.76 6.76 8.23 8.23

 Generation (billion kilowatthours)

 Municipal Solid Waste ..................... 4.03 4.03 4.03 4.03 4.03

 Biomass ................................ 27.08 35.01 35.01 43.52 43.52

 Total ................................. 31.10 39.03 39.03 47.55 47.55

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 ................. 0.99 0.99 0.99 0.99 0.99

 Geothermal ............................. 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ........................ 0.01 0.35 0.35 0.35 0.35

 Total ................................. 1.00 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 ................. 4.57 4.43 4.43 4.41 4.41

 Geothermal ............................. 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ....................... 0.02 0.75 0.75 0.75 0.75

 Total ................................ 4.59 5.18 5.18 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
234 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

Marketed Renewable Energy2

 Residential ......................... 0.41 0.43 0.43 0.44 0.44

 Wood ............................. 0.41 0.43 0.43 0.44 0.44

 Commercial ........................ 0.08 0.08 0.08 0.08 0.08

 Biomass ........................... 0.08 0.08 0.08 0.08 0.08

 Industrial3 ......................... 2.15 2.64 2.64 3.08 3.08

 Conventional Hydroelectric ............ 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ................ 0.00 0.00 0.00 0.00 0.00

 Biomass ........................... 1.97 2.46 2.46 2.90 2.90

 Transportation ...................... 0.12 0.21 0.21 0.24 0.24

 Ethanol used in E854 ................. 0.00 0.03 0.03 0.04 0.04

 Ethanol used in Gasoline Blending ...... 0.12 0.19 0.19 0.21 0.21

 Electric Generators5 ................. 3.86 4.43 4.40 4.53 4.51

 Conventional Hydroelectric ............ 3.17 3.08 3.08 3.06 3.06

 Geothermal ........................ 0.27 0.62 0.67 0.64 0.69

 Municipal Solid Waste6 ............... 0.25 0.34 0.32 0.39 0.37

 Biomass ........................... 0.12 0.25 0.20 0.27 0.22

 Dedicated Plants .................. 0.10 0.13 0.14 0.17 0.19

 Cofiring .......................... 0.02 0.12 0.06 0.11 0.03

 Solar Thermal ...................... 0.01 0.02 0.02 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00

 Wind ............................. 0.05 0.13 0.13 0.13 0.13

 Total Marketed Renewable Energy ..... 6.62 7.80 7.77 8.38 8.36

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ........................ 0.02 0.03 0.03 0.04 0.03

 Solar Hot Water Heating .............. 0.01 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps .............. 0.02 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00

 Commercial ........................ 0.02 0.03 0.03 0.03 0.03

 Solar Thermal ...................... 0.02 0.02 0.02 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.17 0.17

 From Cellulose ..................... 0.00 0.02 0.02 0.07 0.07

 Total ............................ 0.12 0.21 0.21 0.24 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 235

Table H13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Residential

 Petroleum ......................... 26.0 24.4 24.4 22.9 22.9

 Natural Gas ........................ 69.5 81.9 81.8 90.8 91.0

 Coal .............................. 1.1 1.3 1.3 1.3 1.3

 Electricity .......................... 192.6 241.7 244.4 274.7 277.4

 Total ............................ 289.3 349.4 352.0 389.7 392.5

 Commercial

 Petroleum ......................... 13.7 13.1 13.1 12.9 12.9

 Natural Gas ........................ 45.4 55.9 55.8 59.4 59.6

 Coal .............................. 1.7 1.9 1.9 2.0 2.0

 Electricity .......................... 182.1 237.6 241.6 266.8 269.2

 Total ............................ 242.9 308.5 312.3 341.0 343.6

 Industrial1

 Petroleum ......................... 104.2 104.7 104.8 115.5 115.5

 Natural Gas2 ....................... 141.6 157.8 157.5 174.9 175.4

 Coal .............................. 55.9 66.3 64.3 66.3 64.5

 Electricity .......................... 178.8 203.8 208.0 227.7 230.0

 Total ............................ 480.4 532.6 534.5 584.4 585.3

 Transportation

 Petroleum3 ......................... 485.8 608.4 608.5 704.7 704.8

 Natural Gas4 ....................... 9.5 14.1 14.2 17.9 18.0

 Other5 ............................ 0.0 0.1 0.1 0.1 0.1

 Electricity .......................... 2.9 5.8 5.9 7.8 8.0

 Total3 ............................ 498.2 628.3 628.7 730.5 730.8

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 ......................... 629.7 750.5 750.7 855.9 856.1

 Natural Gas ........................ 266.0 309.8 309.3 343.1 344.0

 Coal .............................. 58.8 69.5 67.5 69.5 67.7

 Other5 ............................ 0.0 0.1 0.1 0.1 0.1

 Electricity .......................... 556.3 688.9 699.9 777.0 784.4

 Total3 ............................ 1510.8 1818.8 1827.5 2045.6 2052.2

 Electric Generators6

 Petroleum ......................... 20.0 4.1 4.6 4.0 3.6

 Natural Gas ........................ 45.8 97.7 98.2 165.2 166.6

 Coal .............................. 490.5 587.1 597.0 607.9 614.3

 Total ............................ 556.3 688.9 699.9 777.0 784.4

 Total Carbon Dioxide Emissions by

 Primary Fuel7

 Petroleum3 ......................... 649.7 754.6 755.4 859.9 859.7

 Natural Gas ........................ 311.8 407.5 407.5 508.3 510.5

 Coal .............................. 549.3 656.6 664.5 677.3 681.9

 Other5 ............................ 0.0 0.1 0.1 0.1 0.1

 Total3 ............................ 1510.8 1818.8 1827.5 2045.6 2052.2

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) ... 5.5 6.1 6.1 6.3 6.3

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 25 to 30 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
236 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table H14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999 2010 2020

NSR 32 NSR All NSR 32 NSR All

 Scrubber Retrofits (gigawatts)1 ........ 0.00 40.23 195.23 40.23 195.23

 SO2 Allowance Price

 (1999 dollars per ton) ............... 0.00 137.26 0.00 162.35 0.00

 NOx Controls (gigawatts)

 Combustion ....................... 0.00 64.01 82.26 64.51 82.26

 SCR Post-combustion ............... 0.00 93.10 276.12 98.71 276.12

 SNCR Post-combustion .............. 0.00 26.81 19.19 31.72 19.19

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ........ 472.18 612.42 491.75 675.10 565.24

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) . . 432.67 475.21 496.67 461.05 476.50

 High Sulfur (> 1.67 lbs. S/mmBtu) ....... 199.58 200.48 300.20 192.98 282.84

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here.

 SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs MC_NSR.D121900A, NSR_ALL.D121900A.
Appendix I

Tables for New Source Review Integrated Cases

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 239

Table I1. Total Energy Supply and Disposition Summary

(Quadrillion Btu per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Production

 Crude Oil and Lease Condensate ....... 12.45 10.96 10.95 11.44 11.49

 Natural Gas Plant Liquids . . . . . . . . . . . . . 2.62 3.67 3.71 4.34 4.39

 Dry Natural Gas ..................... 19.16 26.24 26.53 31.55 31.92

 Coal .............................. 23.11 14.41 14.14 12.06 11.64

 Nuclear Power ...................... 7.79 7.91 7.91 7.32 7.24

 Renewable Energy1 .................. 6.50 10.48 10.34 12.78 12.00

 Other2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.65 0.30 0.30 0.33 0.34

 Total ........................... 73.30 73.97 73.88 79.83 79.02

 Imports

 Crude Oil3 ......................... 18.96 24.82 24.86 25.72 25.63

 Petroleum Products4 . . . . . . . . . . . . . . . . . 4.14 6.64 6.62 10.90 11.04

 Natural Gas ........................ 3.63 6.64 6.66 7.97 8.06

 Other Imports5 ...................... 0.64 0.75 0.75 0.69 0.69

 Total ........................... 27.37 38.86 38.89 45.28 45.42

 Exports

 Petroleum6 ......................... 1.98 1.77 1.78 1.93 1.93

 Natural Gas ........................ 0.17 0.12 0.12 0.12 0.12

 Coal .............................. 1.48 1.51 1.46 1.44 1.44

 Total ........................... 3.62 3.41 3.36 3.49 3.49

 Discrepancy7 ........................ 0.95 0.25 0.31 0.01 0.14

 Consumption

 Petroleum Products8 ................. 38.03 44.62 44.65 50.98 51.09

 Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . 21.95 32.55 32.87 39.21 39.66

 Coal .............................. 21.45 13.21 12.94 11.07 10.55

 Nuclear Power ..................... . 7.79 7.91 7.91 7.32 7.24

 Renewable Energy1 .................. 6.51 10.49 10.35 12.79 12.01

 Other9 ............................ 0.35 0.38 0.38 0.25 0.25

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96.09 109.17 109.10 121.61 120.81

 Net Imports - Petroleum ............... 21.12 29.69 29.70 34.69 34.74

 Prices (1999 dollars per unit)

 World Oil Price (dollars per barrel)10 . . . . . . 17.35 21.37 21.37 22.41 22.41

 Gas Wellhead Price (dollars per Mcf)11 .... 2.08 4.33 4.33 4.23 4.48

 Coal Minemouth Price (dollars per ton) .... 17.21 12.44 13.92 11.47 12.82

 Average Electric Price (cents per Kwh) 6.6 8.4 8.1 7.7 7.8

1

Includes grid-connected electricity from conventional hydroelectric; wood and wood waste; landfill gas; municipal solid waste; other biomass; wind; photovoltaic and solar

thermal sources; non-electric energy from renewable sources, such as active and passive solar systems, and wood; and both the ethanol and gasoline components of E85, but not

the ethanol components of blends less than 85 percent. Excludes electricity imports using renewable sources and nonmarketed renewable energy. 2

Includes liquid hydrogen, methanol, supplemental natural gas, and some domestic inputs to refineries. 3

Includes imports of crude oil for the Strategic Petroleum Reserve. 4

Includes imports of finished petroleum products, imports of unfinished oils, alcohols, ethers, and blending components. 5

Includes coal, coal coke (net), and electricity (net). 6

Includes crude oil and petroleum products.

7

Balancing item. Includes unaccounted for supply, losses, gains, and net storage withdrawals. 8

Includes natural gas plant liquids, crude oil consumed as a fuel, and nonpetroleum based liquids for blending, such as ethanol. 9

Includes net electricity imports, methanol, and liquid hydrogen. 10Average refiner acquisition cost for imported crude oil. 11Represents lower 48 onshore and offshore supplies.

Btu = British thermal unit.

Mcf = Thousand cubic feet.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 natural gas values: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). 1999 petroleum values:

EIA, Petroleum Supply Annual 1999, DOE/EIA-0340(99/1) (Washington, DC, June 2000). Other 1999 values: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington,

DC, July 2000) and EIA, Quarterly Coal Report, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000). Projections: EIA, AEO2001 National Energy Modeling System runs

FDP_N32.D121900A, FDP_ALL.D121900A.
240 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I2. Energy Consumption by Sector and Source

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

Energy Consumption

 Residential

 Distillate Fuel ....................... 0.86 0.81 0.81 0.77 0.77

 Kerosene .......................... 0.10 0.07 0.07 0.07 0.07

 Liquefied Petroleum Gas .............. 0.46 0.42 0.42 0.41 0.41

 Petroleum Subtotal ................. 1.42 1.31 1.31 1.25 1.24

 Natural Gas ........................ 4.85 5.38 5.38 6.03 5.98

 Coal .............................. 0.04 0.05 0.05 0.05 0.05

 Renewable Energy1 .................. 0.41 0.42 0.42 0.42 0.42

 Electricity .......................... 3.91 4.55 4.59 5.41 5.39

 Delivered Energy .................. 10.62 11.71 11.75 13.15 13.08

 Electricity Related Losses ............. 8.46 8.61 8.65 9.19 9.02

 Total ............................ 19.09 20.32 20.40 22.34 22.10

 Commercial

 Distillate Fuel ....................... 0.36 0.47 0.47 0.51 0.52

 Residual Fuel ...................... 0.10 0.11 0.11 0.11 0.11

 Kerosene .......................... 0.03 0.03 0.03 0.03 0.03

 Liquefied Petroleum Gas .............. 0.08 0.09 0.09 0.10 0.10

 Motor Gasoline2 ..................... 0.03 0.03 0.03 0.03 0.03

 Petroleum Subtotal ................. 0.59 0.72 0.73 0.77 0.78

 Natural Gas ........................ 3.15 3.60 3.59 3.99 3.91

 Coal .............................. 0.07 0.07 0.07 0.08 0.08

 Renewable Energy3 .................. 0.08 0.08 0.08 0.08 0.08

 Electricity .......................... 3.70 4.48 4.52 5.18 5.18

 Delivered Energy .................. 7.59 8.96 8.99 10.11 10.03

 Electricity Related Losses ............. 8.00 8.48 8.52 8.81 8.67

 Total ............................ 15.59 17.44 17.52 18.91 18.70

 Industrial4

 Distillate Fuel ....................... 1.07 1.29 1.28 1.46 1.46

 Liquefied Petroleum Gas .............. 2.32 2.67 2.68 3.04 3.11

 Petrochemical Feedstock ............. 1.29 1.53 1.53 1.69 1.69

 Residual Fuel ...................... 0.22 0.39 0.38 0.41 0.41

 Motor Gasoline2 ..................... 0.21 0.24 0.24 0.28 0.28

 Other Petroleum5 .................... 4.29 4.85 4.83 5.41 5.44

 Petroleum Subtotal ................. 9.39 10.96 10.95 12.29 12.39

 Natural Gas6 ....................... 9.43 10.77 10.74 12.18 11.94

 Metallurgical Coal ................... 0.75 0.60 0.60 0.50 0.49

 Steam Coal ........................ 1.73 1.92 1.70 2.00 1.78

 Net Coal Coke Imports ............... 0.06 0.16 0.16 0.23 0.23

 Coal Subtotal ...................... 2.54 2.69 2.46 2.72 2.50

 Renewable Energy7 .................. 2.15 2.64 2.64 3.12 3.15

 Electricity .......................... 3.63 3.94 3.96 4.32 4.35

 Delivered Energy .................. 27.15 31.00 30.75 34.62 34.33

 Electricity Related Losses ............. 7.85 7.46 7.46 7.33 7.28

 Total ............................ 35.00 38.45 38.21 41.96 41.61
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 241

Table I2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Transportation

 Distillate Fuel ....................... 5.13 6.87 6.87 8.09 8.08

 Jet Fuel8 .......................... 3.46 4.49 4.49 5.96 5.96

 Motor Gasoline2 ..................... 15.92 18.94 18.94 21.25 21.24

 Residual Fuel ...................... 0.74 0.85 0.85 0.86 0.86

 Liquefied Petroleum Gas .............. 0.02 0.04 0.04 0.06 0.06

 Other Petroleum9 .................... 0.26 0.31 0.31 0.35 0.35

 Petroleum Subtotal ................. 25.54 31.50 31.50 36.57 36.55

 Pipeline Fuel Natural Gas ............. 0.66 0.99 1.01 1.19 1.21

 Compressed Natural Gas ............. 0.02 0.09 0.09 0.15 0.15

 Renewable Energy (E85)10 ............ 0.01 0.03 0.03 0.04 0.04

 Methanol (M85)11 .................... 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................... 0.00 0.00 0.00 0.00 0.00

 Electricity .......................... 0.06 0.12 0.12 0.17 0.17

 Delivered Energy .................. 26.28 32.73 32.75 38.12 38.12

 Electricity Related Losses ............. 0.13 0.22 0.22 0.28 0.28

 Total ............................ 26.41 32.96 32.97 38.40 38.40

 Delivered Energy Consumption for

 All Sectors

 Distillate Fuel ....................... 7.42 9.44 9.43 10.82 10.82

 Kerosene .......................... 0.15 0.13 0.13 0.12 0.12

 Jet Fuel8 .......................... 3.46 4.49 4.49 5.96 5.96

 Liquefied Petroleum Gas .............. 2.88 3.23 3.24 3.61 3.67

 Motor Gasoline2 ..................... 16.17 19.21 19.22 21.56 21.55

 Petrochemical Feedstock ............. 1.29 1.53 1.53 1.69 1.69

 Residual Fuel ...................... 1.05 1.34 1.34 1.38 1.38

 Other Petroleum12 ................... 4.53 5.13 5.12 5.74 5.77

 Petroleum Subtotal ................. 36.95 44.49 44.48 50.87 50.97

 Natural Gas6 ....................... 18.11 20.82 20.81 23.54 23.18

 Metallurgical Coal ................... 0.75 0.60 0.60 0.50 0.49

 Steam Coal ........................ 1.84 2.05 1.82 2.12 1.91

 Net Coal Coke Imports ............... 0.06 0.16 0.16 0.23 0.23

 Coal Subtotal ...................... 2.65 2.81 2.59 2.85 2.63

 Renewable Energy13 ................. 2.65 3.18 3.18 3.67 3.69

 Methanol (M85)11 .................... 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................... 0.00 0.00 0.00 0.00 0.00

 Electricity .......................... 11.29 13.10 13.19 15.07 15.08

 Delivered Energy .................. 71.65 84.40 84.25 96.00 95.56

 Electricity Related Losses ............. 24.44 24.76 24.85 25.61 25.25

 Total ............................ 96.09 109.17 109.10 121.61 120.81

 Electric Generators14

 Distillate Fuel ....................... 0.05 0.03 0.02 0.02 0.02

 Residual Fuel ...................... 1.03 0.11 0.15 0.08 0.10

 Petroleum Subtotal ................. 1.08 0.13 0.17 0.10 0.11

 Natural Gas ........................ 3.85 11.74 12.07 15.67 16.48

 Steam Coal ........................ 18.80 10.40 10.36 8.22 7.93

 Nuclear Power ...................... 7.79 7.91 7.91 7.32 7.24

 Renewable Energy15 ................. 3.86 7.31 7.17 9.12 8.32

 Electricity Imports16 .................. 0.35 0.37 0.37 0.24 0.24

 Total ............................ 35.73 37.86 38.04 40.68 40.32
242 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I2. Energy Consumption by Sector and Source (Continued)

(Quadrillion Btu per Year, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Total Energy Consumption

 Distillate Fuel ....................... 7.47 9.46 9.45 10.84 10.84

 Kerosene .......................... 0.15 0.13 0.13 0.12 0.12

 Jet Fuel8 .......................... 3.46 4.49 4.49 5.96 5.96

 Liquefied Petroleum Gas .............. 2.88 3.23 3.24 3.61 3.67

 Motor Gasoline2 ..................... 16.17 19.21 19.22 21.56 21.55

 Petrochemical Feedstock ............. 1.29 1.53 1.53 1.69 1.69

 Residual Fuel ...................... 2.08 1.45 1.49 1.46 1.48

 Other Petroleum12 ................... 4.53 5.13 5.12 5.74 5.77

 Petroleum Subtotal ................. 38.03 44.62 44.65 50.98 51.09

 Natural Gas ........................ 21.95 32.55 32.87 39.21 39.66

 Metallurgical Coal ................... 0.75 0.60 0.60 0.50 0.49

 Steam Coal ........................ 20.64 12.45 12.18 10.35 9.83

 Net Coal Coke Imports ............... 0.06 0.16 0.16 0.23 0.23

 Coal Subtotal ...................... 21.45 13.21 12.94 11.07 10.55

 Nuclear Power ...................... 7.79 7.91 7.91 7.32 7.24

 Renewable Energy17 ................. 6.51 10.49 10.35 12.79 12.01

 Methanol (M85)11 .................... 0.00 0.00 0.00 0.00 0.00

 Liquid Hydrogen .................... 0.00 0.00 0.00 0.00 0.00

 Electricity Imports16 .................. 0.35 0.37 0.37 0.24 0.24

 Total ............................ 96.09 109.17 109.10 121.61 120.81

Energy Use and Related Statistics

 Delivered Energy Use ................. 71.65 84.40 84.25 96.00 95.56

 Total Energy Use .................... 96.09 109.17 109.10 121.61 120.81

 Population (millions) ................... 273.13 300.17 300.17 325.24 325.24

 Gross Domestic Product (billion 1996 dollars) 8876 12630 12632 16521 16521

 Total Carbon Dioxide Emissions

 (million metric tons carbon equivalent) ... 1510.8 1562.5 1560.0 1711.9 1706.5

1

Includes wood used for residential heating. 2

Includes ethanol (blends of 10 percent or less) and ethers blended into gasoline. 3

Includes commercial sector electricity cogenerated by using wood and wood waste, landfill gas, municipal solid waste, and other biomass. 4

Fuel consumption includes consumption for cogeneration, which produces electricity and other useful thermal energy. 5

Includes petroleum coke, asphalt, road oil, lubricants, still gas, and miscellaneous petroleum products. 6

Includes lease and plant fuel and consumption by cogenerators, excludes consumption by nonutility generators. 7

Includes consumption of energy from hydroelectric, wood and wood waste, municipal solid waste, and other biomass; includes cogeneration, both for sale to the grid and for

own use.

 8Includes only kerosene type. 9

Includes aviation gas and lubricants. 10E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 11M85 is 85 percent methanol and 15 percent motor gasoline. 12Includes unfinished oils, natural gasoline, motor gasoline blending compounds, aviation gasoline, lubricants, still gas, asphalt, road oil, petroleum coke, and miscellaneous

petroleum products. 13Includes electricity generated for sale to the grid and for own use from renewable sources, and non-electric energy from renewable sources. Excludes nonmarketed renewable

energy consumption for geothermal heat pumps, buildings photovoltaic systems, and solar thermal hot water heaters. 14Includes consumption of energy by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy.

Includes small power producers and exempt wholesale generators. 15Includes conventional hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, petroleum coke, wind, photovoltaic and solar thermal sources.

Excludes cogeneration. Excludes net electricity imports. 16In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 17Includes hydroelectric, geothermal, wood and wood waste, municipal solid waste, other biomass, wind, photovoltaic and solar thermal sources. Includes ethanol components

of E85; excludes ethanol blends (10 percent or less) in motor gasoline. Excludes net electricity imports and nonmarketed renewable energy consumption for geothermal heat pumps,

buildings photovoltaic systems, and solar thermal hot water heaters.

Btu = British thermal unit. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Consumption

values of 0.00 are values that round to 0.00, because they are less than 0.005.

Sources: 1999 electric utility fuel consumption: Energy Information Administration, (EIA) Electric Power Annual 1998, Volume 1, DOE/EIA-0348(98)/1 (Washington, DC, April

1999). 1999 nonutility consumption estimates: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999 values: EIA, Short-Term Energy Outlook,

September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf. Projections: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A,

FDP_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 243

Table I3. Energy Prices by Sector and Source

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Residential .......................... 13.12 16.57 16.31 16.11 16.41

 Primary Energy1 ..................... 6.72 8.19 8.18 7.91 8.10

 Petroleum Products2 ................. 7.55 9.32 9.34 9.72 9.80

 Distillate Fuel ...................... 6.27 7.45 7.46 7.99 8.03

 Liquefied Petroleum Gas ............. 10.36 12.97 13.03 13.02 13.23

 Natural Gas ........................ 6.52 7.97 7.97 7.59 7.80

 Electricity ........................... 23.46 28.99 28.25 27.24 27.62

 Commercial ......................... 13.20 16.51 16.09 15.44 15.80

 Primary Energy1 ..................... 5.22 6.68 6.68 6.59 6.77

 Petroleum Products2 ................. 5.00 6.05 6.06 6.41 6.44

 Distillate Fuel ...................... 4.37 5.21 5.21 5.75 5.77

 Residual Fuel ..................... 2.63 3.69 3.69 3.84 3.85

 Natural Gas3 ....................... 5.34 6.92 6.92 6.73 6.94

 Electricity ........................... 21.44 26.13 25.23 23.71 24.12

 Industrial4 ........................... 5.32 6.90 6.86 6.80 7.02

 Primary Energy ...................... 3.92 5.02 5.07 5.22 5.40

 Petroleum Products2 ................. 5.55 6.06 6.09 6.37 6.45

 Distillate Fuel ...................... 4.65 5.40 5.40 5.99 6.01

 Liquefied Petroleum Gas ............. 8.50 8.10 8.16 8.14 8.34

 Residual Fuel ..................... 2.78 3.34 3.34 3.49 3.50

 Natural Gas5 ....................... 2.79 4.81 4.81 4.84 5.06

 Metallurgical Coal ................... 1.65 1.54 1.53 1.44 1.43

 Steam Coal ........................ 1.43 1.17 1.18 1.05 1.05

 Electricity ........................... 13.02 17.72 16.93 15.94 16.22

 Transportation ....................... 8.30 9.58 9.57 9.34 9.34

 Primary Energy ...................... 8.29 9.55 9.55 9.31 9.32

 Petroleum Products2 ................. 8.28 9.54 9.54 9.31 9.31

 Distillate Fuel6 ..................... 8.22 8.92 8.93 9.05 9.06

 Jet Fuel7 ......................... 4.70 5.46 5.46 5.88 5.88

 Motor Gasoline8 .................... 9.45 11.11 11.10 10.68 10.68

 Residual Fuel ..................... 2.46 3.18 3.18 3.33 3.33

 Liquid Petroleum Gas9 ............... 12.87 14.28 14.32 14.01 14.26

 Natural Gas10 ....................... 7.02 8.47 8.47 8.30 8.49

 Ethanol (E85)11 ..................... 14.42 19.28 19.28 19.50 19.52

 Methanol (M85)12 .................... 10.38 14.33 14.26 14.42 14.42

 Electricity ........................... 15.60 16.75 15.70 14.78 14.76

 Average End-Use Energy .............. 8.53 10.46 10.38 10.16 10.32

 Primary Energy ...................... 6.33 7.65 7.68 7.61 7.72

 Electricity ........................... 19.40 24.51 23.71 22.65 22.99

 Electric Generators13

 Fossil Fuel Average ................... 1.49 2.88 2.95 3.41 3.66

 Petroleum Products .................. 2.49 4.09 3.93 4.58 4.41

 Distillate Fuel ...................... 4.05 4.80 4.83 5.26 5.28

 Residual Fuel ..................... 2.41 3.92 3.80 4.42 4.28

 Natural Gas ........................ 2.54 4.62 4.71 4.77 5.03

 Steam Coal ........................ 1.21 0.89 0.88 0.79 0.78
244 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I3. Energy Prices by Sector and Source (Continued)

(1999 Dollars per Million Btu, Unless Otherwise Noted)

Sector and Source 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Average Price to All Users14

 Petroleum Products2 .................. 7.44 8.69 8.69 8.63 8.65

 Distillate Fuel ....................... 7.27 8.12 8.13 8.40 8.42

 Jet Fuel ........................... 4.70 5.46 5.46 5.88 5.88

 Liquefied Petroleum Gas .............. 8.84 8.92 8.97 8.88 9.06

 Motor Gasoline8 ..................... 9.45 11.11 11.10 10.68 10.68

 Residual Fuel ...................... 2.48 3.31 3.32 3.48 3.48

 Natural Gas ........................ 4.05 5.57 5.60 5.49 5.71

 Coal ............................... 1.23 0.94 0.93 0.84 0.84

 Ethanol (E85)11 ...................... 14.42 19.28 19.28 19.50 19.52

 Methanol (M85)12 ..................... 10.38 14.33 14.26 14.42 14.42

 Electricity ........................... 19.40 24.51 23.71 22.65 22.99

Non-Renewable Energy Expenditures

 by Sector (billion 1999 dollars)

 Residential ............................ 134.06 187.16 184.84 205.19 207.73

 Commercial ........................... 99.15 146.52 143.43 154.75 157.20

 Industrial ............................. 110.64 161.79 158.90 176.47 180.28

 Transportation ......................... 212.64 303.38 303.22 343.98 343.96

 Total Non-Renewable Expenditures ...... 556.48 798.85 790.39 880.39 889.17

 Transportation Renewable Expenditures ... 0.14 0.62 0.62 0.86 0.86

 Total Expenditures ................... 556.62 799.46 791.01 881.24 890.02

1

Weighted average price includes fuels below as well as coal. 2 This quantity is the weighted average for all petroleum products, not just those listed below. 3

Excludes independent power producers.

4

Includes cogenerators. 5

Excludes uses for lease and plant fuel.

6 Low sulfur diesel fuel. Price includes Federal and State taxes while excluding county and local taxes. 7

Kerosene-type jet fuel. Price includes Federal and State taxes while excluding county and local taxes. 8

Sales weighted-average price for all grades. Includes Federal and State taxes and excludes county and local taxes. 9Includes Federal and State taxes while excluding county and local taxes. 10Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes. 11E85 is 85 percent ethanol (renewable) and 15 percent motor gasoline (nonrenewable). 12M85 is 85 percent methanol and 15 percent motor gasoline. 13Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 14Weighted averages of end-use fuel prices are derived from the prices shown in each sector and the corresponding sectoral consumption.

Btu = British thermal unit.

Note: Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 prices for gasoline, distillate, and jet fuel are based on prices in various issues of Energy Information Administration (EIA), Petroleum Marketing Monthly, DOE/EIA0380 (99/03-2000/04) (Washington, DC, 1999-2000). 1999 prices for all other petroleum products are derived from the EIA, State Energy Price and Expenditure Report 1997,

DOE/EIA-0376(97) (Washington, DC, July 2000). 1999 industrial gas delivered prices are based on EIA, Manufacturing Energy Consumption Survey 1994. 1999 residential and

commercial natural gas delivered prices: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999 coal prices based on EIA, Quarterly Coal Report

, DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A. 1999 electricity

prices for commercial, industrial, and transportation: EIA, AEO2001 National Energy Modeling System runs MCBASE.D082400A, MCNOX05.D082400A, and MCNOX08.D082500A,

Projections: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 245

Table I4. Electricity Supply, Disposition, Prices, and Emissions

(Billion Kilowatthours, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

Generation by Fuel Type

 Electric Generators1

 Coal .............................. 1834 1035 997 818 768

 Petroleum ......................... 100 14 17 11 12

 Natural Gas2 ....................... 370 1575 1668 2267 2388

 Nuclear Power ...................... 730 741 741 686 678

 Pumped Storage .................... -1 -1 -1 -1 -1

 Renewable Sources3 ................. 353 519 513 652 610

 Total ............................ 3386 3884 3935 4434 4457

 Non-Utility Generation for Own Use ..... 16 20 22 20 22

 Distributed Generation ............... 00 0 0 0

 Cogenerators4

 Coal ............................. 47 51 34 51 34

 Petroleum ........................ 9 10 10 10 10

 Natural Gas ....................... 206 328 320 487 468

 Other Gaseous Fuels5 ............... 47 7 8 8

 Renewable Sources3 ................ 31 39 39 48 49

 Other6 ........................... 55 5 5 5

 Total ........................... 302 441 416 610 575

 Other End-Use Generators7 .......... 55 5 5 5

 Sales to Utilities .................... 150 190 171 240 222

 Generation for Own Use ............. 156 255 250 375 358

 Net Imports8 ........................ 33 35 35 23 23

Electricity Sales by Sector

 Residential .......................... 1146 1334 1345 1584 1580

 Commercial ......................... 1083 1314 1325 1519 1518

 Industrial ........................... 1063 1156 1160 1265 1274

 Transportation ....................... 17 34 34 48 48

 Total ............................. 3309 3839 3866 4416 4419

End-Use Prices (1999 cents per kwh)9

 Residential .......................... 8.0 9.9 9.6 9.3 9.4

 Commercial ......................... 7.3 8.9 8.6 8.1 8.2

 Industrial ........................... 4.4 6.0 5.8 5.4 5.5

 Transportation ....................... 5.3 5.7 5.4 5.0 5.0

 All Sectors Average ................ 6.6 8.4 8.1 7.7 7.8

 Prices by Service Category9

 (1999 cents per kwh)

 Generation .......................... 4.1 5.6 5.3 5.0 5.2

 Transmission ........................ 0.6 0.8 0.8 0.7 0.7

 Distribution ......................... 2.0 2.1 2.1 2.0 2.0

Emissions (million short tons)

 Sulfur Dioxide ....................... 13.79 3.92 0.98 3.27 0.73

 Nitrogen Oxide ...................... 5.46 1.31 0.85 1.14 0.78

1

Includes grid-connected generation at all utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators. 2 Includes electricity generation by fuel cells. 3

 Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar, and wind power. 4

Cogenerators produce electricity and other useful thermal energy. Includes sales to utilities and generation for own use. 5

Other gaseous fuels include refinery and still gas. 6

Other includes hydrogen, sulfur, batteries, chemicals, fish oil, and spent sulfite liquor. 

 7

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. 8

In 1998 approximately 70 percent of the U.S. electricity imports were provided by renewable sources (hydroelectricity); EIA does not project future proportions for the fuel source

of imported electricity. 9

Prices represent average revenue per kilowatthour.

Kwh = Kilowatthour.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
246 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I5. Electricity Generating Capability

(Gigawatts)

Net Summer Capability1 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

Electric Generators2

 Capability

 Coal Steam ........................ 306.2 232.8 174.6 213.2 173.9

 Other Fossil Steam3 ................. 138.2 105.0 100.6 97.8 97.3

 Combined Cycle .................... 20.2 185.6 210.7 288.9 305.8

 Combustion Turbine/Diesel ............ 79.9 118.0 140.2 163.2 191.2

 Nuclear Power . . . . . . . . . . . . . . . . . . . . . . 97.4 96.9 96.9 88.4 87.3

 Pumped Storage .................... 19.3 19.5 19.5 19.5 19.5

 Fuel Cells ......................... 0.0 0.1 0.1 0.3 0.3

 Renewable Sources4 ................. 88.1 107.0 106.2 137.7 129.7

 Distributed Generation5 ............... 0.0 1.7 2.1 5.2 7.1

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 749.4 866.6 851.0 1014.1 1012.1

 Cumulative Planned Additions6

 Coal Steam ........................ 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ................. 0.0 0.1 0.1 0.1 0.1

 Combined Cycle . . . . . . . . . . . . . . . . . . . . 0.0 8.3 8.3 8.3 8.3

 Combustion Turbine/Diesel ............ 0.0 0.7 0.7 0.7 0.7

 Nuclear Power ...................... 0.0 0.0 0.0 0.0 0.0

 Pumped Storage .................... 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ......................... 0.0 0.1 0.1 0.3 0.3

 Renewable Sources4 . . . . . . . . . . . . . . . . . 0.0 4.3 4.3 5.4 5.4

 Distributed Generation5 ............... 0.0 0.0 0.0 0.0 0.0

 Total ............................ 0.0 13.6 13.6 14.8 14.8

 Cumulative Unplanned Additions6

 Coal Steam . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.0 0.0 0.0

 Other Fossil Steam3 ................. 0.0 0.0 0.0 0.0 0.0

 Combined Cycle .................... 0.0 157.5 182.7 260.8 278.1

 Combustion Turbine/Diesel ........... . 0.0 45.3 66.6 90.9 118.0

 Nuclear Power ...................... 0.0 0.0 0.0 0.0 0.0

 Pumped Storage . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.0 0.0 0.0

 Fuel Cells ......................... 0.0 0.0 0.0 0.0 0.0

 Renewable Sources4 ................. 0.0 14.2 13.4 43.8 35.8

 Distributed Generation5 ............... 0.0 1.7 2.1 5.2 7.1

 Total ............................ 0.0 218.7 264.8 400.7 438.9

 Cumulative Total Additions ........... 0.0 232.3 278.4 415.5 453.7

 Cumulative Retirements7 .............

 Coal Steam ........................ 0.0 74.2 133.4 93.8 134.0

 Other Fossil Steam . . . . . . . . . . . . . . . . . . 0.0 33.1 38.5 40.3 41.8

 Combined Cycle .................... 0.0 0.5 0.6 0.6 0.9

 Combustion Turbine/Diesel ........... 0.0 8.2 8.9 8.5 9.2

 Nuclear Power ..................... 0.0 0.6 0.6 9.1 10.2

 Pumped Storage ................... 0.0 0.0 0.0 0.0 0.0

 Fuel Cells . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.0 0.0 0.0

 Renewable Sources ................. 0.0 0.1 0.1 0.1 0.1

 Total ........................... 0.0 116.7 182.2 152.5 196.3

Cogenerators8

 Capability

 Coal .............................. 8.4 8.9 5.8 8.9 5.8

 Petroleum ......................... 2.7 2.8 2.8 2.8 2.8

 Natural Gas ........................ 33.8 52.1 51.5 74.8 72.1

 Other Gaseous Fuels . . . . . . . . . . . . . . . . 0.2 0.9 0.9 1.1 1.1

 Renewable Sources4 ................. 5.3 6.8 6.8 8.3 8.5

 Other ............................. 1.1 0.9 0.9 0.9 0.9

 Total ............................ 51.6 72.3 68.7 96.9 91.2

 Cumulative Additions6 . . . . . . . . . . . . . . . 0.0 20.7 17.1 45.2 39.5
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 247

Table I5. Electricity Generating Capability (Continued)

(Gigawatts)

Net Summer Capability1 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

Other End-Use Generators9

 Renewable Sources .................. 1.0 1.3 1.3 1.3 1.3

 Cumulative Additions . . . . . . . . . . . . . . . . . 0.0 0.3 0.3 0.3 0.3

 1Net summer capability is the steady hourly output that generating equipment is expected to supply to system load (exclusive of auxiliary power), as demonstrated by tests during

summer peak demand.

 2

Includes grid-connected utilities and nonutilities except for cogenerators. Includes small power producers and exempt wholesale generators.

 3

Includes oil-, gas-, and dual-fired capability.

 4

Includes conventional hydroelectric, geothermal, wood, wood waste, municipal solid waste, landfill gas, other biomass, solar and wind power.

 5

Primarily peak-load capacity fueled by natural gas.

 6

Cumulative additions after December 31, 1999.

 7

Cumulative total retirements after December 31, 1999.

 8

Nameplate capacity is reported for nonutilities on Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Nameplate capacity is designated by the manufacturer. The

nameplate capacity has been converted to the net summer capability based on historic relationships.

 9

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators to be consistent with capability for electric utility generators.

 Source: Energy Information Administration, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
248 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I6. Electricity Trade

(Billion Kilowatthours, Unless Otherwise Noted)

Electricity Trade 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Interregional Electricity Trade

 Gross Domestic Firm Power Trade ......... 182.2 102.9 102.9 0.0 0.0

 Gross Domestic Economy Trade .......... 147.3 90.5 156.3 148.4 169.2

 Gross Domestic Trade ................ 329.5 193.4 259.2 148.4 169.2

 Gross Domestic Firm Power Sales

 (million 1999 dollars) ................... 8588.1 4851.2 4851.2 0.0 0.0

 Gross Domestic Economy Sales

 (million 1999 dollars) ................... 4264.5 4416.1 7037.4 6311.3 7444.6

 Gross Domestic Sales

 (million 1999 dollars) ................. 12852.7 9267.4 11888.7 6311.3 7444.6

 International Electricity Trade

 Firm Power Imports From Canada and 27.0 5.8 5.8 0.0 0.0

 Economy Imports From Canada and Mexico1 . 21.9 45.9 45.9 30.6 30.6

 Gross Imports From Canada and Mexico1 . 48.9 51.7 51.7 30.6 30.6

 Firm Power Exports To Canada and Mexico . 9.2 8.7 8.7 0.0 0.0

 Economy Exports To Canada and Mexico ... 6.3 7.7 7.7 7.7 7.7

 Gross Exports To Canada and Mexico ... 15.5 16.4 16.4 7.7 7.7

1

Historically electricity imports were primarily from renewable resources, principally hydroelectric. 

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Firm Power

Sales are capacity sales, meaning the delivery of the power is scheduled as part of the normal operating conditions of the affected electric systems. Economy Sales are subject to

curtailment or cessation of delivery by the supplier in accordance with prior agreements or under specified conditions.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 249

Table I7. Natural Gas Supply and Disposition

(Trillion Cubic Feet per Year)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Production

 Dry Gas Production1 ................. 18.67 25.57 25.86 30.75 31.11

 Supplemental Natural Gas2 ............ 0.10 0.06 0.06 0.06 0.06

 Net Imports ........................ 3.38 6.37 6.39 7.68 7.76

 Canada ........................... 3.29 5.28 5.30 6.00 6.09

 Mexico ............................ -0.01 0.32 0.32 0.36 0.36

 Liquefied Natural Gas ................ 0.10 0.77 0.77 1.32 1.32

 Total Supply ........................ 22.15 32.00 32.31 38.48 38.93

 Consumption by Sector

 Residential ......................... 4.72 5.24 5.24 5.87 5.82

 Commercial ........................ 3.07 3.50 3.50 3.89 3.81

 Industrial3 .......................... 7.95 8.87 8.83 9.94 9.69

 Electric Generators4 ................. 3.77 11.52 11.84 15.38 16.17

 Lease and Plant Fuel5 ................ 1.23 1.61 1.63 1.92 1.94

 Pipeline Fuel ....................... 0.64 0.97 0.98 1.16 1.18

 Transportation6 ..................... 0.02 0.09 0.09 0.14 0.14

 Total ............................ 21.41 31.79 32.11 38.30 38.75

 Discrepancy7 ....................... 0.74 0.21 0.20 0.18 0.18

 1Marketed production (wet) minus extraction losses.

 2

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Represents natural gas used in the field gathering and processing plant machinery.

 6

Compressed natural gas used as vehicle fuel. 

 7

Balancing item. Natural gas lost as a result of converting flow data measured at varying temperatures and pressures to a standard temperature and pressure and the merger of

different data reporting systems which vary in scope, format, definition, and respondent type. In addition, 1998 values include net storage injections.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 supplemental natural gas: Energy Information Administration (EIA), Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). 1999

transportation sector consumption: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A. Other 1999 consumption: EIA, Short-Term

Energy Outlook, September 2000, http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/sep00.pdf with adjustments to end-use sector consumption levels for consumption of natural

gas by electric wholesale generators based on EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A. Projections: EIA, AEO2001

National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
250 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I8. Natural Gas Prices, Margins, and Revenue

(1999 Dollars per Thousand Cubic Feet, Unless Otherwise Noted)

Prices, Margins, and Revenue 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Source Price 

 Average Lower 48 Wellhead Price1 ...... 2.08 4.33 4.33 4.23 4.48

 Average Import Price ................. 2.29 2.88 2.88 3.19 3.27

 Average2 ......................... 2.11 4.04 4.04 4.02 4.24

 Delivered Prices

 Residential ......................... 6.69 8.19 8.18 7.79 8.01

 Commercial ........................ 5.49 7.10 7.10 6.91 7.13

 Industrial3 .......................... 2.87 4.94 4.94 4.97 5.20

 Electric Generators4 ................. 2.59 4.71 4.80 4.86 5.13

 Transportation5 ..................... 7.21 8.70 8.70 8.52 8.72

 Average6 ......................... 4.16 5.71 5.74 5.64 5.86

 Transmission & Distribution Margins7

 Residential ......................... 4.58 4.15 4.14 3.77 3.78

 Commercial ........................ 3.37 3.07 3.06 2.88 2.89

 Industrial3 .......................... 0.75 0.90 0.90 0.95 0.97

 Electric Generators4 ................. 0.47 0.67 0.76 0.84 0.89

 Transportation5 ..................... 5.10 4.66 4.66 4.50 4.48

 Average6 ......................... 2.04 1.68 1.70 1.61 1.63

 Transmission & Distribution Revenue

 (billion 1999 dollars)

 Residential ......................... 21.61 21.75 21.70 22.14 21.98

 Commercial ........................ 10.36 10.74 10.71 11.21 11.01

 Industrial3 .......................... 6.00 7.99 7.97 9.42 9.35

 Electric Generators4 ................. 1.79 7.77 9.03 12.91 14.44

 Transportation5 ..................... 0.08 0.40 0.40 0.64 0.63

 Total ............................ 39.84 48.65 49.82 56.31 57.42

1

Represents lower 48 onshore and offshore supplies.

 2

Quantity-weighted average of the average lower 48 wellhead price and the average price of imports at the U.S. border.

 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators.

 5

Compressed natural gas used as a vehicle fuel. Price includes estimated motor vehicle fuel taxes.

 6

Weighted average prices and margins. Weights used are the sectoral consumption values excluding lease, plant, and pipeline fuel.

 7

Within the table, “transmission and distribution” margins equal the difference between the delivered price and the source price (average of the wellhead price and the price of

imports at the U.S. border) of natural gas and, thus, reflect the total cost of bringing natural gas to market. When the term “transmission and distribution” margins is used in today's

natural gas market, it generally does not include the cost of independent natural gas marketers or costs associated with aggregation of supplies, provisions of storage, and other

services. As used here, the term includes the cost of all services and the cost of pipeline fuel used in compressor stations.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 industrial delivered prices based on Energy Information Administration (EIA), Manufacturing Energy Consumption Survey 1994. 1999 residential and commercial

delivered prices, average lower 48 wellhead price, and average import price: EIA, Natural Gas Monthly, DOE/EIA-0130(2000/06) (Washington, DC, June 2000). Other 1999 values,

and projections: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 251

Table I9. Oil and Gas Supply

Production and Supply 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

Crude Oil

 Lower 48 Average Wellhead Price1

 (1999 dollars per barrel) ............... 16.49 20.72 20.71 21.46 21.47

Production (million barrels per day)

2

 U.S. Total ............................ 5.88 5.18 5.17 5.41 5.43

 Lower 48 Onshore ..................... 3.27 2.56 2.56 2.74 2.77

 Conventional ........................ 2.59 1.95 1.95 2.10 2.12

 Enhanced Oil Recovery ............... 0.68 0.61 0.61 0.64 0.64

 Lower 48 Offshore ..................... 1.56 1.97 1.96 2.02 2.02

 Alaska .............................. 1.05 0.64 0.64 0.64 0.64

 Lower 48 End of Year Reserves (billion 18.33 14.32 14.22 14.48 14.43

 Natural Gas

 Lower 48 Average Wellhead Price1

 (1999 dollars per thousand cubic feet) ... 2.08 4.33 4.33 4.23 4.48

Production (trillion cubic feet)3

 U.S. Total ............................ 18.67 25.57 25.86 30.75 31.11

 Lower 48 Onshore ..................... 12.83 18.49 18.65 22.49 22.73

 Associated-Dissolved4 ................. 1.80 1.41 1.41 1.42 1.43

 Non-Associated ...................... 11.03 17.09 17.24 21.07 21.30

 Conventional ....................... 6.64 9.47 9.64 10.60 10.82

 Unconventional ..................... 4.39 7.61 7.60 10.47 10.49

 Lower 48 Offshore ..................... 5.43 6.58 6.71 7.69 7.81

 Associated-Dissolved4 ................. 0.93 1.05 1.05 1.07 1.07

 Non-Associated ...................... 4.50 5.52 5.65 6.62 6.74

 Alaska .............................. 0.42 0.50 0.50 0.57 0.57

Lower 48 End of Year Reserves 3

 (trillion cubic feet) .................... 157.41 186.99 187.02 223.15 221.84

 Supplemental Gas Supplies (trillion cubic 0.10 0.06 0.06 0.06 0.06

 Total Lower 48 Wells (thousands) ........ 17.94 39.46 39.41 50.85 52.51

 1

Represents lower 48 onshore and offshore supplies.

 2

Includes lease condensate.

 3

Market production (wet) minus extraction losses.

 4

Gas which occurs in crude oil reserves either as free gas (associated) or as gas in solution with crude oil (dissolved).

 5

Synthetic natural gas, propane air, coke oven gas, refinery gas, biomass gas, air injected for Btu stabilization, and manufactured gas commingled and distributed with natural

gas.

 Btu = British thermal unit.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

 Sources: 1999 lower 48 onshore, lower 48 offshore, and Alaska crude oil production: Energy Information Administration (EIA), Petroleum Supply Annual 1999, DOE/EIA-0340(99/1)

(Washington, DC. June 2000). 1999 natural gas lower 48 average wellhead price, Alaska and total natural gas production, and supplemental gas supplies: EIA, Natural Gas

Monthly, DOE/EIA-0130(2000/06)(Washington, DC, June 2000). Other 1999 values: EIA, Office of Integrated Analysis and Forecasting. Projections: EIA, AEO2001 National Energy

Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
252 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I10. Coal Supply, Disposition, and Prices

(Million Short Tons per Year, Unless Otherwise Noted)

Supply, Disposition, and Prices 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Production1

 Appalachia ......................... 434 257 260 213 214

 Interior ............................ 185 84 132 72 107

 West ............................. 485 353 282 296 231

 East of the Mississippi ................ 561 313 351 264 291

 West of the Mississippi ............... 543 381 323 317 261

 Total ............................ 1104 695 674 581 552

 Net Imports

 Imports ............................ 99 9 9 9

 Exports ............................ 58 60 58 58 58

 Total ............................. -49 -51 -49 -49 -49

 Total Supply2 ....................... 1055 644 625 532 503

 Consumption by Sector

 Residential and Commercial ........... 55 5 5 5

 Industrial3 .......................... 79 88 78 92 82

 Coke Plants ........................ 28 23 23 19 18

 Electric Generators4 ................. 922 527 515 419 394

 Total ............................ 1034 642 621 534 500

 Discrepancy and Stock Change5

. ...... 22 1 4 -2 3

 Average Minemouth Price

 (1999 dollars per short ton) ............ 17.21 12.44 13.92 11.47 12.82

 (1999 dollars per million Btu) ........... 0.82 0.60 0.66 0.55 0.61

 Delivered Prices (1999 dollars per short

 Industrial .......................... 31.44 25.51 25.59 22.92 22.80

 Coke Plants ........................ 44.27 41.16 40.99 38.58 38.36

 Electric Generators

 (1999 dollars per short ton) ........... 24.76 17.56 17.70 15.45 15.72

 (1999 dollars per million Btu) ......... 1.21 0.89 0.88 0.79 0.78

 Average ......................... 25.81 19.50 19.55 17.55 17.74

 Exports7 ........................... 37.45 34.12 33.44 31.20 30.85

1

Includes anthracite, bituminous coal, lignite, and waste coal delivered to independent power producers. Waste coal deliveries totaled 8.5 million tons in 1995, 8.8 million tons

in 1996, 8.1 million tons in 1997, 8.6 million tons in 1998, and are projected to reach 9.6 million tons in 1999, and 12.2 million tons in 2000. 2

Production plus net imports and net storage withdrawals. 3

Includes consumption by cogenerators.

 4

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. 5

Balancing item: the sum of production, net imports, and net storage minus total consumption. 6

Sectoral prices weighted by consumption tonnage; weighted average excludes residential/ commercial prices and export free-alongside-ship (f.a.s.) prices. 7

F.a.s. price at U.S. port of exit.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 data based on Energy Information Administration (EIA), Quarterly Coal Report , DOE/EIA-0121(2000/1Q) (Washington, DC, August 2000), and EIA, AEO2001

National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A. Projections: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A,

FDP_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 253

Table I11. Renewable Energy Generating Capability and Generation

(Gigawatts, Unless Otherwise Noted)

Capacity and Generation 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

Electric Generators1

 (excluding cogenerators) 

 Net Summer Capability

 Conventional Hydropower ............. 78.14 80.21 80.04 80.21 80.05

 Geothermal2 ....................... 2.87 12.14 11.81 15.25 13.10

 Municipal Solid Waste3 ............... 2.59 4.37 4.31 4.90 4.90

 Wood and Other Biomass4 ............ 1.52 3.17 3.40 12.05 10.81

 Solar Thermal ...................... 0.33 0.40 0.40 0.48 0.48

 Solar Photovoltaic ................... 0.01 0.21 0.21 0.54 0.54

 Wind ............................. 2.60 6.54 6.05 24.30 19.85

 Total ............................ 88.07 107.03 106.23 137.73 129.73

 Generation (billion kilowatthours)

 Conventional Hydropower ............. 307.43 303.96 303.41 302.90 302.34

 Geothermal2 ....................... 13.07 96.22 93.62 120.79 103.85

 Municipal Solid Waste3 ............... 18.05 31.32 30.89 35.39 35.34

 Wood and Other Biomass4 ............ 9.52 71.10 69.90 120.00 108.64

 Dedicated Plants .................. 7.56 18.46 20.02 77.93 69.69

 Cofiring .......................... 1.96 52.65 49.88 42.07 38.95

 Solar Thermal ...................... 0.89 1.11 1.11 1.37 1.37

 Solar Photovoltaic ................... 0.03 0.51 0.51 1.36 1.36

 Wind ............................. 4.46 15.20 13.87 70.21 57.32

 Total ............................ 353.45 519.42 513.32 652.01 610.23

 Cogenerators5

 Net Summer Capability

 Municipal Solid Waste ................ 0.70 0.70 0.70 0.70 0.70

 Biomass ........................... 4.65 6.06 6.07 7.65 7.81

 Total ............................ 5.35 6.76 6.77 8.34 8.51

 Generation (billion kilowatthours)

 Municipal Solid Waste ................ 4.03 4.03 4.03 4.03 4.03

 Biomass ........................... 27.08 34.95 34.98 44.10 45.16

 Total ............................ 31.10 38.97 39.00 48.12 49.19

Other End-Use Generators6

 Net Summer Capability

 Conventional Hydropower7 ............ 0.99 0.99 0.99 0.99 0.99

 Geothermal ........................ 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic ................... 0.01 0.35 0.35 0.35 0.35

 Total ............................ 1.00 1.34 1.34 1.34 1.34

 Generation (billion kilowatthours)

 Conventional Hydropower7 ............ 4.57 4.43 4.43 4.41 4.41

 Geothermal ........................ 0.00 0.00 0.00 0.00 0.00

 Solar Photovoltaic .................. 0.02 0.75 0.75 0.75 0.75

 Total ........................... 4.59 5.18 5.18 5.17 5.17

 1Includes grid-connected utilities and nonutilities other than cogenerators. These nonutility facilities include small power producers and exempt wholesale generators.

 2

Includes hydrothermal resources only (hot water and steam).

 3

Includes landfill gas.

 4

Includes projections for energy crops after 2010.

 5

Cogenerators produce electricity and other useful thermal energy. 

 6

Includes small on-site generating systems in the residential, commercial, and industrial sectors used primarily for own-use generation, but which may also sell some power to

the grid. Excludes off-grid photovoltaics and other generators not connected to the distribution or transmission systems.

 7

Represents own-use industrial hydroelectric power.

 Notes: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports. Net summer

capability has been estimated for nonutility generators for AEO2001. Net summer capability is used to be consistent with electric utility capacity estimates. Additional retirements

are determined on the basis of the size and age of the units.

 Sources: 1999 electric utility capability: Energy Information Administration (EIA), Form EIA-860A: “Annual Electric Generator Report - Utility.” 1999 nonutility and cogenerator

capability: EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” 1999 generation: EIA, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July

2000). Projections: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
254 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I12. Renewable Energy Consumption by Sector and Source1

(Quadrillion Btu per Year)

Sector and Source 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

Marketed Renewable Energy2

 Residential ......................... 0.41 0.42 0.42 0.42 0.42

 Wood ............................. 0.41 0.42 0.42 0.42 0.42

 Commercial ........................ 0.08 0.08 0.08 0.08 0.08

 Biomass ........................... 0.08 0.08 0.08 0.08 0.08

 Industrial3 ......................... 2.15 2.64 2.64 3.12 3.15

 Conventional Hydroelectric ............ 0.18 0.18 0.18 0.18 0.18

 Municipal Solid Waste ................ 0.00 0.00 0.00 0.00 0.00

 Biomass ........................... 1.97 2.46 2.46 2.93 2.96

 Transportation ...................... 0.12 0.21 0.21 0.24 0.24

 Ethanol used in E854 ................. 0.00 0.03 0.03 0.03 0.03

 Ethanol used in Gasoline Blending ...... 0.12 0.19 0.19 0.21 0.21

 Electric Generators5 ................. 3.86 7.31 7.17 9.12 8.32

 Conventional Hydroelectric ............ 3.17 3.13 3.12 3.11 3.11

 Geothermal ........................ 0.27 2.84 2.72 3.59 3.03

 Municipal Solid Waste6 ............... 0.25 0.43 0.42 0.48 0.48

 Biomass ........................... 0.12 0.75 0.75 1.18 1.09

 Dedicated Plants .................. 0.10 0.19 0.21 0.77 0.70

 Cofiring .......................... 0.03 0.55 0.53 0.41 0.39

 Solar Thermal ...................... 0.01 0.02 0.02 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00

 Wind ............................. 0.05 0.16 0.14 0.72 0.59

 Total Marketed Renewable Energy ..... 6.62 10.67 10.53 12.99 12.21

Non-Marketed Renewable Energy7

 Selected Consumption

 Residential ........................ 0.02 0.03 0.03 0.03 0.04

 Solar Hot Water Heating .............. 0.01 0.00 0.00 0.00 0.00

 Geothermal Heat Pumps .............. 0.02 0.03 0.03 0.03 0.03

 Solar Photovoltaic 0.00 0.00 0.00 0.00 0.00

 Commercial ........................ 0.02 0.03 0.03 0.03 0.03

 Solar Thermal ...................... 0.02 0.02 0.02 0.03 0.03

 Solar Photovoltaic ................... 0.00 0.00 0.00 0.00 0.00

 Ethanol

 From Corn ......................... 0.12 0.19 0.19 0.17 0.17

 From Cellulose ..................... 0.00 0.02 0.02 0.07 0.07

 Total ............................ 0.12 0.21 0.21 0.24 0.24

1

Actual heat rates used to determine fuel consumption for all renewable fuels except hydropower, solar, and wind. Consumption at hydroelectric, solar, and wind facilities

determined by using the fossil fuel equivalent of 10,280 Btu per kilowatthour. 2

Includes nonelectric renewable energy groups for which the energy source is bought and sold in the marketplace, although all transactions may not necessarily be marketed,

and marketed renewable energy inputs for electricity entering the marketplace on the electric power grid. Excludes electricity imports. 3

Includes all electricity production by industrial and other cogenerators for the grid and for own use. 4

Excludes motor gasoline component of E85. 5

Includes renewable energy delivered to the grid from electric utilities and nonutilities. Renewable energy used in generating electricity for own use is included in the individual

sectoral electricity energy consumption values. 6

Includes landfill gas. 7

Includes selected renewable energy consumption data for which the energy is not bought or sold, either directly or indirectly as an input to marketed energy. The Energy

Information Administration does not estimate or project total consumption of nonmarketed renewable energy.

Btu = British thermal unit.

Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 ethanol: Energy Information Administration (EIA), Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000). 1999 electric generators: EIA,

Form EIA-860A: “Annual Electric Generator Report - Utility,” and EIA, Form EIA-860B: “Annual Electric Generator Report - Nonutility.” Other 1999: EIA, Office of Integrated Analysis

and Forecasting. Projections: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 255

Table I13. Carbon Dioxide Emissions by Sector and Source

(Million Metric Tons Carbon Equivalent per Year)

Sector and Source 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Residential

 Petroleum ......................... 26.0 24.8 24.7 23.5 23.5

 Natural Gas ........................ 69.5 77.5 77.4 86.9 86.1

 Coal .............................. 1.1 1.3 1.3 1.2 1.2

 Electricity .......................... 192.6 152.3 153.8 157.3 158.0

 Total ............................ 289.3 255.9 257.3 269.0 268.8

 Commercial

 Petroleum ......................... 13.7 14.2 14.2 15.1 15.4

 Natural Gas ........................ 45.4 51.8 51.7 57.5 56.3

 Coal .............................. 1.7 1.9 1.9 2.0 2.0

 Electricity .......................... 182.1 150.1 151.5 150.8 151.8

 Total ............................ 242.9 217.9 219.3 225.4 225.5

 Industrial1

 Petroleum ......................... 104.2 112.7 112.4 125.1 126.9

 Natural Gas2 ....................... 141.6 152.7 152.3 172.8 169.3

 Coal .............................. 55.9 68.1 62.4 69.0 63.4

 Electricity .......................... 178.8 131.9 132.6 125.6 127.4

 Total ............................ 480.4 465.4 459.8 492.4 487.1

 Transportation

 Petroleum3 ......................... 485.8 603.8 603.8 700.9 700.6

 Natural Gas4 ....................... 9.5 15.5 15.8 19.3 19.6

 Other5 ............................ 0.0 0.1 0.1 0.1 0.1

 Electricity .......................... 2.9 3.9 3.9 4.8 4.9

 Total3 ............................ 498.2 623.4 623.6 725.1 725.1

 Total Carbon Dioxide Emissions by

 Delivered Fuel

 Petroleum3 ......................... 629.7 755.4 755.2 864.6 866.4

 Natural Gas ........................ 266.0 297.4 297.2 336.4 331.3

 Coal .............................. 58.8 71.3 65.6 72.2 66.6

 Other5 ............................ 0.0 0.1 0.1 0.1 0.1

 Electricity .......................... 556.3 438.3 441.9 438.6 442.1

 Total3 ............................ 1510.8 1562.5 1560.0 1711.9 1706.5

 Electric Generators6

 Petroleum ......................... 20.0 2.7 3.5 2.1 2.4

 Natural Gas ........................ 45.8 169.0 173.8 225.6 237.3

 Coal .............................. 490.5 266.5 264.6 210.8 202.4

 Total ............................ 556.3 438.3 441.9 438.6 442.1

 Total Carbon Dioxide Emissions by

 Primary Fuel7

 Petroleum3 ......................... 649.7 758.2 758.7 866.8 868.8

 Natural Gas ........................ 311.8 466.4 471.0 562.0 568.5

 Coal .............................. 549.3 337.8 330.2 283.0 269.1

 Other5 ............................ 0.0 0.1 0.1 0.1 0.1

 Total3 ............................ 1510.8 1562.5 1560.0 1711.9 1706.5

 Carbon Dioxide Emissions

 (tons carbon equivalent per person) ... 5.5 5.2 5.2 5.3 5.2

1

Includes consumption by cogenerators. 2

Includes lease and plant fuel.

3

This includes international bunker fuel which, by convention are excluded from the international accounting of carbon dioxide emissions. In the years from 1990 through 1998,

international bunker fuels accounted for 25 to 30 million metric tons carbon equivalent of carbon dioxide annually. 4

Includes pipeline fuel natural gas and compressed natural gas used as vehicle fuel. 5

Includes methanol and liquid hydrogen. 6

Includes all electric power generators except cogenerators, which produce electricity and other useful thermal energy. Includes small power producers and exempt wholesale

generators. Does not include emissions from the nonbiogenic component of municipal solid waste because under international guidelines these are accounted for as waste not

energy. 7

Emissions from electric power generators are distributed to the primary fuels.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Sources: 1999 emissions and emission factors: Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1999, DOE/EIA-0573(99),

(Washington, DC, October 2000). Projections: EIA, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
256 Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants

Table I14. Impacts of the Clean Air Act Amendments of 1990

Impacts 1999 2010 2020

NSR 32 Integrated NSR All Integrated NSR 32 Integrated NSR All Integrated

 Scrubber Retrofits (gigawatts)1 ........ 0.00 21.36 102.69 21.36 102.69

 SO2 Allowance Price

 (1999 dollars per ton) ............... 0.00 118.61 0.00 86.27 0.00

 NOx Controls (gigawatts)

 Combustion ....................... 0.00 102.50 64.97 102.50 64.97

 SCR Post-combustion ............... 0.00 133.89 231.88 133.89 231.88

 SNCR Post-combustion .............. 0.00 39.15 34.03 39.15 34.03

 Coal Production by Sulfur Category

 (million tons)

 Low Sulfur (< .61 lbs. S/mmBtu) ........ 472.15 348.60 242.14 286.63 199.19

 Medium Sulfur (.61-1.67 lbs. S/mmBtu) . . 433.19 243.91 268.18 208.06 217.87

 High Sulfur (> 1.67 lbs. S/mmBtu) ....... 198.95 102.12 163.82 86.05 135.00

1

Represents scrubbers added by the model. Planned scrubbers added by utilities are not shown here.

 SO2 = Sulfur dioxide.

 lbs. S/mmBtu = Pounds sulfur per million British thermal units.

 Note: Totals may not equal sum of components due to independent rounding. Data for 1999 are model results and may differ slightly from official EIA data reports.

Source: Energy Information Administration, AEO2001 National Energy Modeling System runs FDP_N32.D121900A, FDP_ALL.D121900A.
Appendix J

Letters from Subcommittee on National Economic Growth,

Natural Resources, and Regulatory Affairs

CLICK HERE FOR PDF CONTAINING SCANS OF LETTERS (8 pages, 1.4 MB)
Appendix K

Pollution Control Costs

Appendix K

Pollution Control Costs

The costs for adding flue gas desulfurization equipment

(scrubbers) are specific to each plant in the model. The

costs generally vary with plant size (it is less expensive

for larger plants) and an assessment of the difficulty of

retrofitting the specific plant. On average, scrubber

retrofits cost $195 per kilowatt (in 1997 dollars).

The cost assumptions for NOx controls are from the U.S.

Environmental Protection Agency (EPA) report, Analyzing Electric Power Generation Under the CAAA.

60 Table

K1, reproduced from the EPA report, provides the cost

and performance parameters assumed for postcombustion NOx controls for coal-fired power plants.

Energy Information Administration / Strategies for Reducing Multiple Emissions from Power Plants 269

Table K1. Post-Combustion NOx Controls for Coal-Fired Power Plants

Post-Combustion Control

Technology

Capital

(1997 Dollars

per Kilowatt)

Fixed O&M

(1997 Dollars per

Kilowatt per Year)

Variable O&M

(1997 Mills per

Kilowatthour) Percent Gas Use Percent Removal

SCR (Low NOx Rate) . . . . . . . . . . . . . 69.70 6.12 0.24 — 70

SCR (High NOx Rate) . . . . . . . . . . . . 71.80 6.38 0.40 — 80

SNCR (Low NOx Rate). . . . . . . . . . . . 16.60 0.24 0.82 — 40

SNCR (High NOx Rate, Cyclone). . . . 9.60 0.14 1.27 — 35

SNCR (High NOx Rate, Other). . . . . . 19.00 0.29 0.88 — 35

Assumptions: Low NOx Rate <0.5 lb/MMBtu; High NOx Rate 0.5 lb/MMBtu. Scaling factor for coal SCR = (200/MW)0.35, economies of scale

assumed up to 500 MW. Scaling factor for low-NOx coal SNCR = (200/MW)0.577, economies of scale assumed up to 500 MW. Scaling factor for High

NOx Coal SNCR, cyclone = (100/MW)0.577; variable O&M costs = 1.27 for 300 MW, 1.27 – ((MW – 300)/100) x 0.015 for >300 MW. Scaling factor for

high-NOx coal SNCR, Other = (100/MW)0.681; variable O&M costs = 0.88 for 480 MW, 0.89 for >480 MW. Gas Reburn includes $5.2/kW charge for

pipeline.

Sources: All estimates taken from the Bechtel report, except gas reburn, which is based on the Acurex Report.

60U.S. Environmental Protection Agency, Analyzing Electric Power Generation Under the CAAA (Washington, DC, March 1998).