DOE/EIA-0615

Distribution Category UC-950

Petroleum 1996

Issues and Trends

September 1997

Energy Information Administration

Office of Oil and Gas

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the Energy Information Administration, the independent statistical and analytical agency within the Department

of Energy. The information contained herein should not be construed as advocating or reflecting any policy position of the Department of

Energy or any other organization.
Energy Information Administration / Petroleum 1996: Issues and Trends iii

Preface

Contacts

Petroleum 1996: Issues and Trends was prepared by the

Energy Information Administration (EIA) Office of Oil and

Gas, Kenneth A. Vagts, Director (202/586-6401), and the

EIA Office of Energy Markets and End Use, Webster C.

Kilgore, Director (202/586-1617). Specific information

concerning the report may be obtained from Craig H.

Cranston, Acting Chief of the Publication and Analysis

Branch (Telephone: 202/586-6023; Fax: 202/586-4913; Email: craig.cranston@eia.doe.gov) or from Charles P.

Shirkey (202/586-6567).

Primary analytical contributions to the report were made by

the following individuals:

Chapter 1 - Charles Dale and Joanne Shore; section above your reaction to this report and your thoughts

Chapter 2 - Joanne Shore; with respect to future petroleum analysis.

Chapter 3 - David Morehouse;

Chapter 4 - Heather Rowland; For further information concerning analysis of petroleum and

Chapter 5 - Aileen Bohn; other energy issues, see the Energy Information

Chapter 6 - Charles Dale and John Zyren; Administration’s home page on the World Wide Web at

Chapter 7 - John Hackworth and Joanne Shore; and http://www.eia.doe.gov.

Chapter 8 - Jon Rasmussen.

Significant analytical contributions were also made by Laura

Knight and John Ostrich.

Editorial support was provided by Dick Richards. Desktop

publishing support was provided by Margareta Bennett.

Future Analysis

This report addresses the phenomenon of volatility, which

involves every aspect of the petroleum sector to differing

degrees. More analysis of this and other petroleum-related

topics can be conducted using the combination of data

collected by EIA and available trade data. What EIA will

address in the future, and how, depends on both market

developments and on you, customers of the Energy

Information Administration and users of this first edition of

Petroleum 1996: Issues and Trends. You are invited to

convey to any of the contributors listed in the Contacts
Energy Information Administration / Petroleum 1996: Issues and Trends v

Contents

Page

1. Industry Overview ........................................................................... 1

Overview of the Petroleum Sector ............................................................... 3

World Crude Oil Markets ...................................................................... 5

World Petroleum Supply and Demand ............................................................ 7

U.S. Petroleum Supply ........................................................................ 9

U.S. Petroleum Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

U.S. Petroleum Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

U.S. Refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

U.S. Gasoline Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

U.S. Distillate Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Clean and Alternative Transportation Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Petroleum Futures Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Financial Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

2. Spring ‘96 Gasoline Price Runup: An Example of Petroleum Market Dynamics . . . . . . . . . . . . . . . . . . . . . . . . . 27

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Crude Oil Market in Spring 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Normal Gasoline Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Unusual Gasoline Market In First Quarter ‘96 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

The April Runup: Distillate and Gasoline Markets Clash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Gasoline Price Progress Through Summer 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Price Reversal in Spring 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

3. Oil Supply: U.S. Perspective on a Global Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Oil Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Oil Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Oil Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Future Implications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

4. Crude Oil Imports: Growing U.S. Dependence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

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

U.S. Total Oil Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

An Overview of Crude Oil Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Sources Of U.S. Crude Oil Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Where In The U.S. Does the Imported Crude Oil Go? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

Quality Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Crude Sources for the Largest Importers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Seasonality of Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Crude Oil Exports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

5. Petroleum Stocks: Causes and Effects of Lower Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Distillate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Motor Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

Expected Price Drop Discouraged Stock Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
vi Energy Information Administration / Petroleum 1996: Issues and Trends

Long-Term Influences on Petroleum Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Conclusion/Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

6. Petroleum Futures Markets: Volatile Prices, Controversial Functions, Stagnant Volumes . . . . . . . . . . . . . . . . 101

The Uses of Futures Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Petroleum Futures Market Trading Volume Slowed in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

Futures and Spot Price Correlations May Be Highly Seasonal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

The Basis May Also Be Highly Seasonal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

High Prices in 1996 Led to High Visibility for Futures Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110

Maximizing Profits Means Hedgers Try to Follow Price Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

1996 Brought Attention to Heating Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

Announcement Effects Are Small and Short-Lived . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

7. U.S. Refining Cash Margin Trends: Factors Affecting the Margin Component of Price . . . . . . . . . . . . . . . . . . 121

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

Refining Margin Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

Background for Interpreting the Margin Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Margin Variations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

Spring 1996 and Future Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138

8. Financial Performance: Low Profitability in U.S. Refining and Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

Margins, Operating Costs, and Profitability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

Investment and Capital Intensity in U.S. Refining and Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

Petroleum Price Rises Yield Profit Gains in First Half of 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147
Energy Information Administration / Petroleum 1996: Issues and Trends vii

Tables

1. Spring 1997 and Spring 1996 Summary Market Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

2. Worldwide Crude Oil Production of 20 Leading Companies, 1972 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . 56

3. Distribution of Crude Oil Reserves and Production with Corresponding Local R/P Ratios, 1994 . . . . . . . . . . . . 62

4. Estimates of Worldwide Cumulative Production, Identified Reserves, and Undiscovered Technical

Recoverable Resources of Conventional Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

5. The Top Six Sources of U.S. Crude Oil Imports, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

6. Crude Oil, Distillate, and Total Gasoline Stocks, January 1981-December 1996 . . . . . . . . . . . . . . . . . . . . . . . 86

7. Average Crude Oil Inventories by Industry Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

8. Average Distillate Inventories by Industry Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

9. Average Gasoline Inventories by Industry Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

10. U.S. Electric Utility Distillate Consumption and Ending Stocks - October . . . . . . . . . . . . . . . . . . . . . . . . . . 100

11. Price Correlations for Spot and Futures Prices Squared Correlation Coefficients . . . . . . . . . . . . . . . . . . . . . . 109

12. Price Basis for Heating Oil Futures, Monthly Average -- Nearby Futures Price Minus Spot Price,

June 1986 - November 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109

13. Price Basis for Propane Futures, Monthly Average -- Nearby Futures Price Minus Spot Prices . . . . . . . . . . . 110

14. Refinery Cash Margin Calculation East Coast Refinery Using Brent Crude Oil Summer 1995 . . . . . . . . . . . 125

15. Distillation Volume Percent Yields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

16. Quarterly Margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

17. U.S. Refined Product Margins and Costs per Barrel Sold for FRS Companies, Selected Years, 1979 - 1995 . 144

18. Quarterly Income in U.S. Refining and Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

19. Refined Product Resale Prices, Margins, and Products Supplied, First and Second Quarters, 1995 and 1996 . 150

Figures

1. U.S. Petroleum Flow ..................................................................... 2

2. 1996 Crude Oil Prices Rose Due To Tight Supply/Demand Balance ................................ 4

3. World Oil Supply Grew Lighter, but Lagged Demand ............................................ 6

4. U.S. Increases Dependence on Crude Oil Imports .............................................. 8

5. Petroleum Import Levels and Sources Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

6. Light Transportation Fuels Drove U.S. Demand Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

7. Refinery Utilization and Downstream Capacity Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

8. Gasoline Prices Draw Public Attention . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

9. World Distillate Demand Keeps Pressure on Crude Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

10. Clean and Alternative Transportation Fuels Continue to Grow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

11. Futures Markets Are Turbulent in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

12. Downstream Performance in 1996 Is Modest Despite High Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

13. U.S. Average Retail Regular Gasoline Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

14. Price and Cost Relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

15. Crude Oil and Gasoline Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

16. Gasoline Price Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

17. Monthly Average Spot Crude Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

18. World Supply and Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

19. Changing Term Structure for Crude Oil Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

20. The Seasonal Price Component (New York Harbor Spot 5-Year Average Spot Gasoline and

Distillate Spreads) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

21. Gasoline and Distillate Counter-Cyclical Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

22. Relying on Stocks to Meet Peak Demand: Distillate Supply and Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

23. 1996 Gasoline Imports Have Been Strong . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

24. Spot and Retail Gasoline Prices (Excluding Taxes) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

25. Gasoline Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

26. Gasoline Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
viii Energy Information Administration / Petroleum 1996: Issues and Trends viii

27. Total Motor Gasoline Stocks (End of Month) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

28. Distillate Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

29. Distillate Stocks (End of Month) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

30. Distillate Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

31. Gasoline Spot Spreads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

32. Spring 1996 Gasoline Price Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

33. Spring 1997 Gasoline Price Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

34. Weekly Conventional Gasoline and Crude Oil Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

35. Real Domestic Oil Price, 1959-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

36. World Oil Price and Related Events, 1970-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

37. U.S. Petroleum Supply and Demand, 1970-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

38. U.S. Crude Oil Production by Site, 1985 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

39. Direct Oil and Gas Lifting Costs for FRS Companies, 1981-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

40. Exploration Expenditures by FRS Firms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

41. Development Expenditures by FRS Firms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

42. Majors and Nonmajors, U.S. Oil Production by Region, 1985-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

43. World, OPEC, and Persian Gulf Oil Production, 1985 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

44. Leading World Oil Producers, 1985-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

45. Domestic Crude Oil Proved Reserves, 1985-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

46. Crude Oil Proved Reserves by Area, 1985 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

47. Domestic Oil and Gas Well Completions, 1985-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

48. Domestic Exploratory Oil Well Completions, 1985-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

49. Domestic Crude Oil Discoveries per Exploratory Oil Well Completion, 1985-1995 . . . . . . . . . . . . . . . . . . . . 60

50. U.S. Oil Imports, 1975-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

51. U.S. Petroleum Supply and Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

52. Regional Supply and Demand Balance, 1985 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

53. Crude Oil Dominates U.S. Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

54. U.S. Crude Oil Imports: Net and Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

55. Origin of U.S. Crude Oil Imports, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

56. Changing Regional Patterns for U.S. Crude Oil Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

57. U.S. Regional Dependence on Crude Oil Imports, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

58. U.S. Regional Dependence on Crude Oil Imports Over Time, 1975-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

59. A Comparison Between Imported and Domestic Crude Oil Quality in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 79

60. The Quality of U.S. Crude Oil by Supply Region, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

61. Quality Trends in U.S. Crude Oil Imports and Refinery Inputs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

62. U.S. Crude Oil Imports by the Top Nine Importing Refiners and by Supply Region, 1996 . . . . . . . . . . . . . . . 81

63. Quarterly Volumes of U.S. Crude Oil Imports by Sulfur Content . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

64. U.S. Crude Oil Exports by Exporting Region, 1985-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

65. Aggregate Crude Oil, Distillate, and Total Gasoline Stocks, January 1981-December 1996 . . . . . . . . . . . . . . 86

66. Crude Oil, Distillate, and Total Gasoline Stocks, January 1981-December 1996 . . . . . . . . . . . . . . . . . . . . . . . 89

67. Days Supply of Crude Oil, Distillate, and Total Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

68. Crude Oil, Distillate, and Total Gasoline Stocks by PADD Region, 1994-1996 . . . . . . . . . . . . . . . . . . . . . . . . 92

69. Crude Oil Stock Levels and Differential in Expected Future Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

70. Growth Slows in U.S. Oil Futures Trading - Annual Volume . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

71. Established Contracts Are Hard to Beat - leaded Versus Unleaded Gasoline Futures . . . . . . . . . . . . . . . . . . . 104

72. Monthly Crude Oil Stocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

73. Monthly Total Gasoline Stocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

74. Monthly Distillate Fuel Oil Stocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

75. Monthly Propane Stocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

76. Changing Term Structure for Crude Oil Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

77. Changing Term Structure for Heating Oil Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

78. Changing Term Structure for Propane Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

79. Spot and Futures Heating Oil Prices - End-of-Week Closing Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

80. Large Commercials Share of Open Interest - Crude Oil Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

81. Large Commercials Share of Open Interest - Unleaded Gasoline Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . 115
Energy Information Administration / Petroleum 1996: Issues and Trends ix

82. Large Commercials Share of Open Interest - Heating Oil Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

83. Large Commercials Share of Open Interest - Propane Futures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

84. Heating Oil Net Futures Holdings - End-of-Week Large Positions, May - October 1995 . . . . . . . . . . . . . . . . 116

85. Heating Oil Net Futures Holdings - End-of-Week Large Positions, May - October 1996 . . . . . . . . . . . . . . . . 117

86. Refiners Holdings of Heating Oil Futures - End-of-Week Large Positions, May - October 1996 . . . . . . . . . . 117

87. Cash Margin Component of Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

88. Quarterly Margins East and Gulf Coasts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

89. Quarterly Gulf Coast Refining Margin and Gasoline Spread . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

90. Total Gasoline Stocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

91. Light Minus Heavy Crude Price Difference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

92. Light Minus Heavy Product Price Difference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

93. U.S. Petroleum Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

94. Decline in Heavy Fuel Oil Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

95. U.S. Downstream Processing Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

96. Western European Downstream Processing Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

97. Gasoline Spread Comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

98. Value of Upgrading: Heavy Crude Margin - Light Crude Margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

99. Value of Upgrading: Margin with Coker Minus Margin Without Coker . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

100. Atmospheric Distillation Unit Capacity Utilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

101. East Versus Gulf Coast Margins Running Brent and WTI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

102. Annual Return on Equity for Petroleum Companies and U.S. Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

103. FRS Companies’ Return on Investment in U.S. Refining/Marketing and All Other Lines of Business . . . . . . 142

104. U.S. Refining/Marketing Return on Investment and Refined Product Margins for FRS

Companies, 1977-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

105. Net PP&E per Unit of U.S. Refinery Capacity for FRS Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

106. U.S. Refining Capital Expenditures for FRS Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

107. Majors’ First and Second Quarter U.S. Refining/Marketing Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

108. Independent Refiners’ First and Second Quarter Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151
Energy Information Administration / Petroleum 1996: Issues and Trends xi

Introduction

Purpose of the Report

Increasingly, users of the Energy Information Administration's petroleum data and analytical reports have expressed

an interest in a recurring report that takes a broad view of the

petroleum sector. What is sought is some perspective on the

complex interrelationships that comprise an industry and

markets accounting for 40 percent of the energy consumed

in the United States and ranging from the drilling rig in the

oil field to the pump at the local gasoline station.

This report comprehensively examines historical trends, and

selectively focuses on major issues and the events they

represent. It analyzes different dimensions of the industry

and related markets in terms of how they relate to a common

theme, in this case, the volatility in petroleum markets. 

Theme — Volatility

One notable development in petroleum product markets has supply and demand occur suddenly or unexpectedly, they

been volatility, as reflected in the rapid and conspicuous can lead to sharp market reactions. The resulting rapid price

change in petroleum product prices. An instance of volatility, changes are symptoms of these reactions — evidence of a

the turbulence in motor gasoline wholesale and retail market imbalance, and the signal that a market correction is

markets in the spring of 1996, made this a matter of national underway.

concern. At the time, the Energy Information Administration

co-authored a report undertaken at the request of President

Clinton, which examined the market conditions that

impacted the supply-demand balance leading up to the motor

gasoline season, and how the wholesale, commodity, and

retail markets responded. In a sense, this report, Petroleum *

1996: Issues and Trends, picks up where that report left off.

More recently, the issue of volatility in petroleum markets

was addressed by Secretary of Energy Federico Peña in a

message to Department of Energy employees throughout the

country on the day after he was sworn into office. In

outlining the first of four priorities for the Department,

Secretary Peña underscored a major long-term source of

uncertainty in the world supply/demand balance:

“First, we will develop a realistic strategy for

strengthening our nation’s energy security. Recent history

has demonstrated how vulnerable we are to a disruption

in the flow of imported oil or volatility in its price.”**

The volatility, the sharp and rapid fluctuation, in oil prices

is a symptom of a combination of underlying market

developments. Sharp price movements reflect a high level of

uncertainty in all sectors of supply and their associated

markets. Thus, more insight may be gleaned from assessment

of the supply and demand conditions that led to the shift in

prices, in addition to analyzing the impacts on participants in

the petroleum markets--suppliers, consumers, investors.

Over the past few decades, the petroleum industry in the

United States has undergone some fundamental changes in

its operations. These changes range from declines in

domestic oil production, and in crude and product inventory

levels, to emerging new technologies; from new

environmental requirements that affect the costs of its

operations, to new financial markets that affect the prices of

its products. When such changes evolve gradually, they can

be absorbed smoothly in the markets. But when changes in

Outline of the Report

The first chapter of the report presents, in summary terms, a

broad overview of trends in petroleum markets. The other

seven chapters present, in greater depth, analyses of key

issues and the underlying trends that influence petroleum

markets today and in the future.

! Chapter 1, “Industry Overview,” reviews the broad trends

in supply and demand of petroleum. It highlights recent

events and summarizes their effects on the markets.

! Chapter 2, “Spring ‘96 Gasoline Price Runup: An

Example of Petroleum Market Dynamics,” recaps the

factors that led to last year’s jump in motor gasoline

prices, and tracks the resumption of more stable market

conditions since then. This chapter serves as a case study

in dynamics of wholesale and retail product markets and

U.S. Department of Energy, An Analysis of Gasoline Markets Spring *

1996, DOE/PO-0046 (June 1996).

U.S. Department of Energy, “Secretary Federico Peña’s Greetings to **

DOE Employees,” DOECAST (3/14/97).
xii Energy Information Administration / Petroleum 1996: Issues and Trends xii

the interaction with other sectors of the petroleum ! Chapter 6, “Petroleum Futures Markets: Volatile Prices,

industry and their related markets. Controversial Functions, Stagnant Volumes,” discusses

! Chapter 3, “Oil Supply: U.S. Perspective on a Global petroleum products over the past two decades. It

Market,” identifies factors that have contributed to describes how they are used by petroleum industry

historical volatility in world oil prices. It examines participants to hedge their price risk, and by the

declining domestic oil production and rising global noncommercial traders that provide liquidity for the

production over the past decade. Future shifts in the hedgers. It addresses several controversial issues related

sources of world oil supply, based on current reserves, are to futures markets.

projected. It addresses resource potential, development

costs, and technological advancements in the U.S. and ! Chapter 7, “U.S. Refining Cash Margin Trends: Factors

overseas. Affecting the Margin Component of Price,” investigates

! Chapter 4, “Crude Oil Imports: Growing U.S. factors that influence margin fluctuations. In particular,

Dependence,” describes the conditions that have driven it examines the effects on margins of refinery

the steep rise in U.S. oil imports over the past decade, configuration and location, crude oil quality, and

and addresses issues related to increasing reliance on environmental regulations.

foreign suppliers. It covers regional shifts in domestic

demand and foreign supply, patterns in the quality of ! Chapter 8, “Financial Performance: Low Profitability in

imported crude oil, and the economic, logistical, and U.S. Refining and Marketing,” draws upon data from

political implications of these changes. EIA’s Financial Reporting System to explore profitability

! Chapter 5, “Petroleum Stocks: Causes and Effects of major oil companies. It concludes that their profitability

Lower Inventories,” reviews EIA’s survey data on stocks over the past 10 years has been volatile and frequently

to determine the underlying trends in the recent decline lower than U.S. industry in general.

in inventory levels. Forces that influence petroleum

inventory levels, such as current and expected prices and

refinery margins, are assessed.

the evolution of futures markets in crude oil and

margin behavior over the past decade to identify the

in domestic refining and marketing operations of the
Energy Information Administration / Petroleum 1996: Issues and Trends 1

1. Industry Overview

This section provides an overview of the petroleum industry, ! U.S. Petroleum Demand

summarizing recent trends in some of the major petroleum ! U.S. Refining

markets and major industry sectors. Each summary focuses ! U.S. Gasoline Markets

on 1996, but puts the year in historical perspective. The areas ! U.S. Distillate Markets

reviewed are: ! Clean and Alternative Transportation Fuels

! Petroleum Futures Markets

! Overview of the Petroleum Sector ! Financial Performance

! World Crude Oil Markets

! World Petroleum Supply and Demand The remaining sections of the report examine, in greater

! U.S. Petroleum Supply depth, issues relating to the major petroleum markets and

! U.S. Petroleum Net Imports major industry sectors.
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2 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 1. U.S. Petroleum Flow, 1996

(Million Barrels per Day)

Source: Energy Information Administration, Petroleum Supply Annual, DOE/EIA-0340 (June 1997), Table 3.
Energy Information Administration / Petroleum 1996: Issues and Trends 3

Overview of the Petroleum Sector

This overview highlights recent events and trends in major hydrocarbon products such as sulfur and vanadium.

petroleum markets and segments of the petroleum industry, Different crude oils can be used to produce different

including: amounts of these products depending on their original

! The United States Uses More Energy from Petroleum

than from Any Other Energy Source. Petroleum

supplies over 50 percent more energy than natural gas,

close to twice the energy of coal and 2.5 times the energy

coming from all other energy resources. The United

States is also one of the largest petroleum producers in

the world, but consumes more than it produces, requiring

net imports of both crude oil and products to meet

demand. 

! Petroleum Markets and the Industry That Serves

Them Are Complex. The oil business is very capitalintensive, is international in scope, and requires a

complex transportation and storage infrastructure to

operate. Crude oil resources are found worldwide, with

many crude-producing regions (e.g., the Middle East)

being some distance away from large consuming areas

like the United States, Europe and Asia. Crude oil is

shipped to refineries worldwide using tankers and

pipelines. Generally refineries are located near large

consuming areas, but substantial international movements

of refined petroleum products also occur as

supply/demand balances and market opportunities

change.

! Crude Oils Are Heterogeneous. Crude oils differ as to

the relative quantities of light and heavy hydrocarbons

and content of other materials, such as heavy metals and

sulfur. Each barrel of crude oil is processed in refineries

to produce a wide range of hydrocarbon products,

including gasoline, heating oil, diesel fuel, residual fuel,

coke, lubricants, asphalt, and waxes, as well as noncomposition and the type of equipment used by the

refinery to process the crude oils. Crude oils with higher

percentages of light hydrocarbons are more valuable than

those with a lower light hydrocarbon content because

they yield larger percentages of high-valued products

such as gasoline with less processing equipment

investment. 

! Changing Regulations and Economics Have Affected

the Domestic Refinery Business. Since the early 1980's,

the number of U.S. refineries has fallen by almost 50

percent, but the remaining refineries have improved their

efficiencies and flexibility to process heavier crude oils

by incorporating improved technology and by adding

upgrading units downstream of the distillation units. In

the 1990's, investments were driven mainly by new clean

fuel requirements and the need to improve on the

environmental impacts of operations. 

! The Many Products Coming from the Refineries

Travel Down Complex Distribution Systems to Very

Different End-Use Markets. Products leave refineries by

different routes to reach their end-use customers. Each

end-use market has its own supply, demand and price

factors. Products such as residual fuel oil are subject to

direct competition from alternative fuels like natural gas,

while in other cases, such as gasoline, no viable shortterm alternatives exist. Gasoline consumption varies with

factors such as vehicle efficiency, miles driven and the

number of vehicles using this fuel, rather than by

consumers’ ability to switch fuels. Long-term factors,

such as the evolution of alternative fuels and the use of

more efficient vehicles, can affect the gasoline market. 
0

12.00

14.00

16.00

18.00

20.00

22.00

24.00

26.00

Monthly Average Spot Crude Oil Prices

Brent

West Texas Intermediate

1991 1992 1993 1994 1995 1996

(Dollars per Barrel)

1991 1992 1993 1994 1995 1996 1997

0

6 4

6 6

6 8

7 0

7 2

7 4

7 6

C rude O il Supply and Dem and

Demand

Stock Draw

(M illion Barrels per Day)

Supply

Stock Build

4 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 2. 1996 Crude Oil Prices Rise Due To Tight Supply/Demand

Balance

Increasing World Demand Tightens Crude Oil Markets

Sources: World Supply and Demand: Energy Information Administration (EIA), 1991—EIA, International Petroleum Statistics (March 1995),

Table 2.1. 1992-1996—EIA, International Petroleum Statistics (May 1997). 1997—Estimates of actual and projected derived from Oil Market

Intelligence, publisher Edward L. Morse, New York, NY, p. 1 (June 2, 1997). World Petroleum Supply and Demand Balance: EIA,

1991—International Petroleum Statistics (March 1995), Table 2.1. 1992-1996—International Petroleum Statistics (May 1997). Spot Crude Oil:

Standard and Poor’s Platts.

Even Iraqi Sales in December 1996

Have Little Effect on Prices

World Petroleum Supply and Demand Balance

(Million Barrels Per Day)

Year Supply Demand

 Stock 

Change

1991 66.6 66.7 -0.1

1992 66.9 66.7 +0.2

1993 67.3 67.0 +0.3

1994 68.2 68.3 -0.1

1995 69.9 70.2 -0.3

1996 71.7 71.7 -0

Supply Demand Balance in 1996

Keeps Pressure on Crude Oil Prices
Energy Information Administration / Petroleum 1996: Issues and Trends 5

World Crude Oil Markets

Following the Gulf War in 1991, world petroleum supply brought buying pressure to the world crude market, and

increased, while demand languished through a recession, and prices began to rise well before the heating season got

crude oil prices weakened. As the recession ended, demand underway. In late October, markets questioned whether

began growing again, and the petroleum supply/demand the concerns about distillate were exaggerated, and the

balance tightened, bringing prices up. As 1996 began, the price fell back briefly. Then, cold weather in Europe

world supply demand balance had tightened further, setting caused the market to end the year on a high note. Crude

the stage for the price increases that occurred during the oil prices increased approximately $6 per barrel over the

year. course of 1996.

! Increasing World Demand Tightens Crude Oil ! Expectations and Backwardation Discourage Stock

Markets. Prices increase when the balance between Building. Throughout 1996, with new supply on the

supply and demand is tight. A tight balance develops horizon, analysts expected the tight oil markets to loosen.

when demand exceeds supply, and stocks are pulled In believing that a supply surplus would develop, these

down. Stock levels serve as an indicator of tightness, analysts anticipated a weakening in crude oil prices.

representing immediate short-term supply. When they are Given this expectation with current tight markets, the

low, and demand is increasing, buyers tend to bid more futures markets exhibited fairly strong backwardation

aggressively to assure supply. In 1992 and 1993, supply throughout the year. "Backwardation" occurs when the

exceeded demand, petroleum stocks were building, and price of crude oil for future delivery is less than the

prices were on a downward trend. That situation began to prompt (current) price. Backwardation can be expected

reverse in 1994 as the world economy improved and to occur when prompt prices are bid up relative to future

demand growth increased. In 1994 and 1995 demand prices, reflecting expectations that prices will

exceeded supply and stocks were drawn down. As 1996 subsequently fall off. In 1996, the outlook for a supply

began, demand was high and continued to exceed surplus, coupled with tight prompt markets, kept crude

production. The stock draw in the first quarter was a very oil prices virtually always in fairly deep backwardation,

strong 1.8 million barrels per day, setting the stage for and the persistent expectation that prices would fall

price increases. provided a disincentive to stock building. Buyers did not

! Supply/Demand Balance in 1996 Keeps Pressure on to be several dollars cheaper within a month or two.

Crude Oil Prices. The winter of 1995-96 was cold,

which pushed distillate demand up and pulled inventories

down as demand surged ahead of production. Thus, 1996

began with oil inventories already depleted. As the cold in 1996 was the return of Iraq to the market as a result of

weather continued, crude prices rose in March and U.N. negotiations. When Iraqi sales finally began in

peaked in April when a late cold snap drove refiners to December 1996, the West Texas Intermediate (WTI)

the market to meet the distillate demand surge when they price fell about $2.50 per barrel, but within about a

would normally be preparing for the gasoline season. week’s time, the price came back to the level before sales

Strong petroleum demand growth continued through the began and pushed to new heights. In the strong world

2nd and 3rd quarters. World petroleum stocks normally demand period of the fourth quarter, the Iraqi volumes of

build in these quarters. Although the 1996 stock build about 500 thousand barrels per day were readily absorbed

was normal, it was not large enough to offset the effects by the market. In the medium term, however, the Iraqi

of the previous winter’s drawdown, so world petroleum volumes, in combination with growing non-OPEC

stocks remained low at the end of summer. As production, could be a factor in creating surplus supply,

preparation for the 1996-97 heating season began, the eroding market supply/demand tightness and bringing

low state of distillate stocks both in Europe and the U.S. down prices.

want to fill their storage with crude oil that was expected

! Iraqi Sales in December 1996 Have Little Immediate

Effect on Prices. One of the anticipated supply increases
1991 1992 1993 1994 1995 1996 1997

0

25

30

35

40

45

Crude Oil Production

(Million Barrels per Day)

Non-OPEC Production

OPEC Production

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 

0

2

4

6

8

10

12

14

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAA AAA

AAA AAA AAA AAA AAA AAA AAA

AAA AAA AAA AAA AAA AAA AAA

AAA AAA

AAA AAA AAA AAA AAA

AAA AAA

AAA AAA AAA AAA AAA

Light Sweet Crude Oil Production

AAA AAA

AAA

AAA

Africa

Latin America Sweet

North Sea

(Million Barrels per Day)

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

2.00

4.00

6.00

8.00

10.00

Spot Crude Price Difference

(Dollars per Barrel)

Bonny Light - Arab Light

Bonny Light - Arab Heavy

6 Energy Information Administration / Petroleum 1996: Issues and Trends

Both OPEC and Non-OPEC Sources

Increase Production

Figure 3. World Oil Supply Grows Lighter, but Falls Behind Demand

Light-Heavy Crude Oil Price

Differentials Fell in 1991-1994, But

Began to Recover in 1995

Production of Atlantic Basin

Light-Sweet Crude Oil Increases

Actual and Predicted World Petroleum Supply and

Demand

1995

Actual

1996

Actual Increase

Demand OECD 40.5 41.2 +0.7

Non-OECD 29.7 30.5 +0.8

Total 70.2 71.7 +1.5

Supply OECD 19.2 19.7 +0.5

Other NonOPEC23.1 23.7 +0.6

OPEC 27.6 28.3 +0.7

Total 69.9 71.7 +1.8

Stock

Change

-0.3 0 N/A

1996 Supply-Demand Balance Keeps

Market Tight

Sources: OPEC and Non-OPEC Production: Energy Information Administration (EIA), 1991-1996—EIA, International Petroleum Statistics

(various issues), Table 2.1. Estimate of First Quarter 1997 Actual—Oil Market Intelligence Update (New York, NY) (June 2, 1997), p. 1. Actual and

Predicted World Petroleum Supply and Demand: EIA, Actual—International Petroleum Statistics (May 1997), Table 2.1. Predicted—International

Energy Agency (December 1995) and Oil and Gas Journal (January 29, 1996), p. 68. Light Sweet Crude Oil: EIA, derived from Form EIA-814 data.

Spot Crude Price Differences: Standard and Poor’s Platts.
Energy Information Administration / Petroleum 1996: Issues and Trends 7

World Petroleum Supply and Demand

World demand and supply have both been growing since day. The North Sea alone fell short of predictions by over

1994, but demand has grown more strongly than supply, 300 thousand barrels per day. Non-OPEC and OPEC

keeping the world supply/demand balance tight. Both OPEC production together just met demand for the year,

and non-OPEC production rose to help meet this growing keeping crude oil markets tight.

demand, with particularly strong growth coming from the

non-OPEC light sweet crude oil producing regions of the ! Atlantic Basin Production of Light Sweet Crude

Atlantic Basin. This increase in light sweet crude oils served

to depress the light heavy crude price differences that affect

refinery economics worldwide.

! World Demand Growth Continues to Be Strong. Initial

estimates indicate world petroleum demand grew 2.2 much of this new production was light sweet crude. From

percent in 1996, which was lower than the 2.8 percent 1985 to 1995, world crude production increased by 16

growth experienced in 1995, but still strong. U.S. percent. At the same time, crude production from sweet

demand, which represents over 25 percent of the world crude producing areas of the Atlantic Basin (North Sea,

total, increased 2.9 percent, but Western Europe only Africa, Colombia, and Argentina) increased by 48

rose by 1.3 percent. OECD countries in total grew 1.6 percent. The area with the greatest volume increase was

percent in 1996 as their economies continued to expand. the North Sea, where production increases are expected

Non-OECD countries, however, experienced a 2.9 to continue for a few years. Africa also showed large

percent increase in 1996 as their economies flourished increases, with Nigeria and Angola together adding over

and as developing countries continued to evolve and use 900 thousand barrels per day to the market from 1985-

more energy. Non-OECD countries now account for 43 1995. Sweet crude oil production also increased in Latin

percent of world demand. America, and greater increases are coming in the next

! Both OPEC and Non-OPEC Sources Increase

Production. OPEC production increased by about 700

thousand barrels per day in 1996. The largest part of the

increase came from Venezuela, where production rose

about 330 thousand barrels per day, followed by Nigeria,

where it rose about 180 thousand barrels per day. Many

of the OPEC member countries are producing above their

OPEC-established quotas, which have not been changed

for several years. Growing world oil demand and

increasing crude prices have allowed OPEC to avoid

confronting the difficult task of changing quotas.

Production from non-OPEC countries increased about

1,150 thousand barrels per day, with the largest increases

coming from the North Sea (up from about 400 thousand

barrels per day) and Latin America (Mexico, up 250

thousand barrels per day and Brazil, up 100 thousand

barrels per day). 

! 1996 Supply-Demand Balance Keeps Market Tight.

Demand in 1996 was slightly below forecasted levels.

Non-OPEC supply, however, fell well below

expectations. It was expected to increase 1.9 million

barrels per day, but only increased 1.1 million barrels per

Increases at a Faster Rate than World Production.

The rate of growth of light sweet crude oil production in

the Atlantic Basin since 1985 greatly exceeded world

crude production growth. Growth in crude oil production

since 1985 came largely from the Atlantic Basin, and

few years as Colombia attains full production of Cusiana.

The strong growth in Atlantic Basin light sweet crude

production had significant impacts on the relative market

value of crudes in the region and on other world markets.

! Recovery of Light-Heavy Crude Price Differential

Continues. Increased availability of light sweet crude in

the Atlantic Basin drove light-heavy crude oil and

product price differences down. From 1990 to 1994, the

price differential between light and heavy crude narrowed

because of the increased availability of light crude oil in

the region. The light-heavy difference has a major impact

on refining margins, as discussed in Chapter 7. Beginning

in 1995, the price difference widened slightly due to a

sharp increase in light crude oil shipments from Africa to

Asia. The differential had declined to the point that, in

spite of the long haul, African crudes became attractive

to meet Asia's growing light product needs. The Asian

market effectively sets the floor price for the light

African crude oils, which in turn provides a price floor

for the other Atlantic Basin light crude oils. Production

increases in Atlantic Basin light sweet crude oils should

continue for the next few years, keeping downward

pressure on the light-heavy price differential. 
1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1996 

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Product Net Imports

Total Product Net Imports

Residual Fuel

1995 

(Thousand Barrels per Day)

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1996 

0

2

4

6

8

10

12

14

16

18

20

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAA

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAA

A

A

A

A

A

A

A

A

A

U.S. Petroleum Supply

AAA AAA

AAA

AAA AAA

AAA

AAA Domestic Production Crude Net Imports

Product Net Imports Other

1995 

(Million Barrels per Day)

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA

AAA AAA AAA AAA AAA

AAA AAA AAA AAA AAA AAA AAA

AAA AAA AAA AAA AAA AAA AAA

AAA AAA

AAA AAA

U.S. Crude and NGL Production

Lower 48 Onshore

Lower 48 Offshore

Alaska

(Thousand Barrels per Day)

198519861987198819891990199119921993199419951996

0

280

300

320

340

360

380

400

End of Month Crude Oil Stocks (Excluding SPR)

(Million Barrels)

8 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 4. U.S. Increases Dependence on Crude Oil Imports

The U.S. Is Growing More Dependent

on Imported Crude Oil

New Offshore Sources Are

Slowing Domestic Production Decline

Residual Fuel Leads Product

Import Decline

U.S. Crude Oil Stocks Are Down

Again in 1996

Sources: Energy Information Administration (EIA). Petroleum Supply: 1985-1995—Petroleum Supply Annual (Vol. 1), Table S1.

1996—Petroleum Supply Monthly (February 1997), Tables 26 and 49. Net Imports: 1985-1995—Petroleum Supply Annual (Vol 1), Table 29.

1996—Petroleum Supply Monthly (February 1997), Table 49. Crude Oil and NGL Production: 1985-1995—Petroleum Supply Monthly, Table 26.

1996— Petroleum Supply Annual (Vol. 1), Table 14. Crude Oil Stocks: 1985-1995—Petroleum Supply Annual (Vol. 1), Table S2. 1996—Petroleum

Supply Monthly, Table 2.
Energy Information Administration / Petroleum 1996: Issues and Trends 9

U.S. Petroleum Supply

Growing U.S. petroleum product demand and declining area has been the Gulf of Mexico, the source of most of

domestic crude oil production have combined to make the the lower 48 offshore production. Crude oil production in

United States increasingly dependent on crude oil imports. the Gulf increased about 300 thousand barrels per day

Although total net petroleum imports (imports minus from 1990 to 1995, which helped to slow the overall

exports) have been increasing, net product imports have production decline rate in the U.S. A large number of oil

decreased. Domestic production of crude oil is declining in projects are under development in the Gulf of Mexico,

virtually all U.S. production areas with the exception of the many of which are large projects in deep water. A joint

Gulf of Mexico, where there is much current activity — Petroleum Economist and IEA estimate projects Gulf of

especially in the deep water areas. During 1996, while

imports continued to increase, crude oil inventories declined,

partially due to the tight crude market that produced high

crude oil prices.

! The U.S. Is Growing More Dependent On Imported

Crude Oil. Decreasing domestic crude oil production

combined with rising demand are causing the United buffer against demand and price changes. A number of

States to become more dependent on imports of crude oil factors can affect stock levels, including price

and refined products. Since the crude oil price collapse in expectations, demand surges, supply problems, and even

1986, domestic production has declined as high-cost how the crude oil is delivered to refiners. Pipeline

wells were closed. In 1985, net imports of crude oil and delivery of domestic crude oil requires the least storage,

products were 4.3 million barrels per day and provided 27 but much more tankage is required to accommodate the

percent of oil product supply. By 1996, net imports of infrequent deliveries of large batches of crude by very

crude and products had nearly doubled to 8.4 million large, long-haul tankers. Increased reliance on short haul

barrels per day and represented 46 percent of U.S. supply. crude oils can produce a reduction in stock levels simply

Other domestic sources rose slightly, primarily as the due to the use of smaller tankers. Crude oil stocks are

result of growth in the use of oxygenates in gasoline. also affected by variations in the tightness or looseness of

! Residual Fuel Leads Product Import Decline. The as discussed in Chapters 2 (Spring ‘96 Gasoline Price

large increase in oil imports has been in the form of crude

oil rather than products. Net product imports have

declined both on a percentage and a volume basis. From

1985 to 1990, product imports averaged 1,434 thousand

barrels per day, but from 1991 to 1996 the average

dropped 484 thousand barrels per day to 950 thousand

barrels per day. At the same time, product imports’

average share of total imports fell from 24 percent to 13

percent. A large part of the decline in product imports

came from the drop in net imports of residual fuel, which

fell 220 thousand barrels per day as demand for residual

fuel diminished. Another important part of the net import

decline derived from an increase in exports of distillate

fuel oil and petroleum coke. 

! New Offshore Sources Are Slowing the Domestic

Production Decline. From 1985 to 1995, U.S. production

of crude oil and natural gas liquids fell from

approximately 9 million barrels per day to 6.6 million

barrels per day. Production in the onshore lower 48 states

declined steadily over the entire period, while Alaskan

production rose between 1985 to 1988, but declined since

then. In recent years the most promising U.S. production

1

Mexico oil production to increase by 1 million barrels per

day between 1995 and 2000. Overall U.S. production will

still decline at about 2 perecent per year.

! U.S. Crude Oil Stocks Are Down Again in 1996.

Inventories or “stocks” of crude oil are maintained to

provide working volumes in the system and to provide a

the crude markets, both seasonally and for longer periods

Runup) and 5 (Stocks). From 1984 to 1995, crude oil

stocks fluctuated around 320-360 million barrels, but fell

considerably in 1995 and again in 1996. While it looked

like stocks might be leveling off during the second and

third quarters of 1996, they plunged again during the

fourth quarter to end the year at a record December low

of 285 million barrels. In addition to crude oil, many

other petroleum product stocks were lower than normal.

During the fourth quarter 1996, refiners increased their

runs to meet distillate needs, pulling down crude oil

stocks in the process. In general, the low stocks in 1996

cannot be explained by any one of the factors affecting

stocks mentioned above, but the refiners’ reluctance to

build stocks was at least partially due to current and

expected prices. Prompt (current) crude oil prices

remained strong, but future prices were expected to

decline.

"Shell Leads Rush to Deeper Waters," Petroleum Economist (January 1

1997), pp. 5-10.
1993 1994 1995 1996

0

50

100

150

200

250

300

350

400

450

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

A

Distillate Exports by Destination

(Thousand Barrels per Day)

AAAA AAAA

AAAA

AAAA

Europe

Asia/Pacific

Latin America

1991 1992 1993 1994 1995 1996

0

100

200

300

400

500

600

Gasoline and Distillate Imports

Gasoline and Blending 

Components

Distillate

(Thousand Barrels per Day)

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

(Thousand Barrels per Day)

AAA

AAA

AAA

AAA AAA

AAA

AAA AAA

AAA

AAA AAA

AAA

Middle East Latin America Africa

Europe Asia Canada

Crude Oil Imports by Region

10 Energy Information Administration / Petroleum 1996: Issues and Trends

Crude Oil Imports From

Atlantic Basin Are Increasing 

Sulfur Content and Gravity of Imported Crude Oil

Sulfur Gravity

1990

MB/D

1990

Percent

1995 

MB/D

1995 

Percent

<=0.5 %S >36 API 1,041 16.7 1,341 17.6

<=0.5 %S 30-36 API 804 12.9 1,016 13.4

<=0.5 %S <30 API 535 8.6 639 8.4

>0.5<=2.0 %S >36 API 547 8.8 469 6.2

>0.5<=2.0 %S 30-36 API 839 13.5 1,057 13.9

>0.5<=2.0 %S <30 API 474 7.6 730 9.6

>2.0 %S >36 API 5 0.1 16 0.2

>2.0 %S 30-36 API 726 11.7 776 10.2

>2.0 %S <30 API 1,253 20.1 1,557 20.5

Quality of Crude Imports

Has Not Changed Much

Figure 5. Petroleum Import Levels and Sources Change

Product Imports Help to Meet

Seasonal Demand Swings

Market Opportunities Drive Changes

in Distillate Export Patterns

Sources: Energy Information Administration (EIA). Crude Oil Imports: 1985-1995—Petroleum Supply Annual (Vol. 1), Table 21.

1996—Petroleum Supply Monthly (February 1997), Table S3. Sulfur Content and Gravity of Imported Crude Oil: EIA, Petroleum Supply Annual

(Vol. 1), Table 16. Gasoline and Distillate Imports: 1991-1995—Petroleum Supply Annual (Vol 1), Table 21. 1996—Petroleum Supply Monthly

(various issues), Table 35. Distillate Exports: EIA, 1993-1995—Petroleum Supply Annual (Vol. 1), Table 28. 1996—Petroleum Supply Monthly,

Table 47.
Energy Information Administration / Petroleum 1996: Issues and Trends 11

U.S. Petroleum Imports

From the late 1980's into the 1990's, supply sources of U.S. ! Gasoline Imports Rise in 1996 with Europe Picking

crude oil imports shifted from the Middle East towards Latin

America. While light sweet crude oil availability increased

dramatically in the Atlantic Basin, U.S. light sweet crude

imports did not increase proportionally. Gasoline product

imports increased from marginal sources, such as Europe and

the Middle East, when the United States market presented

price opportunities. Conversely, export opportunities for

distillate grew during the 1990's as world markets changed.

! Crude Oil Imports from the Atlantic Basin Are

Increasing. From 1985 to 1990, total crude imports

increased from 3.2 million barrels per day to 5.9 million total imports for a given month can reach 400-500

barrels per day. Saudi Arabia accounted for nearly 60 thousand barrels per day. The strong prices in the United

percent of the additional imports. Since 1990, the supply States in April 1996 drew gasoline and blending

sources for U.S. crude imports have shifted toward Latin component imports of 573 thousand barrels per day.

America. Imports from Mexico, Venezuela, and other Europe supplied 139 thousand barrels per day for the

Latin American countries nearly doubled from 1990 to year, compared to 68 thousand barrels per day in 1995.

1996, rising from 1.6 million barrels per day to nearly 3.0 The increase in European imports represented 46 percent

million barrels per day. This increase can, in large of the total increase for 1996.

measure, be attributed to the competitive advantage of

short-haul crudes, and to the downstream integration of ! Three Countries Are Major Suppliers of Distillate

Venezuela and Mexico into the U.S. refining business.

The Venezuelan state oil company (PDVSA) acquired

and expanded CITGO, which now has 650 thousand

barrels per day of U.S. refining capacity. The

Venezuelans also acquired a stake in the 265 thousand

barrels per day Lyondell refinery. After making these

acquisitions, PDVSA invested in process upgrading to

handle the Venezuelan crude oils, many of which are

heavy. The Mexican state oil company (PEMEX) has

acquired a share of the Shell Deer Park refinery with a

capacity of 215 thousand barrels per day, which also was

upgraded to run heavy-sour Mexican crude oils.

! Quality of Crude Imports Has Not Changed Much.

From 1985 to 1990, imports of light sweet crude oil

increased as a percent of total. But from 1990 to 1995,

the shares of crude imports by quality attribute have not

changed much. Despite increased availability of light

sweet crude oils in the Atlantic Basin, and a decline in

the price difference between light and heavy crude oils,

the U.S. light sweet crude oil imports have only risen in

proportion with the total imports. As discussed in Chapter

7 (Refinery Margins), once refiners have invested in

heavy-sour crude processing facilities, it takes a large

drop in the light-heavy price difference to cause refiners

to switch back to the light sweet crude oils.

Up a Large Piece of the Growth. The need for gasoline

imports varies significantly from year to year. In 1996

gasoline imports and blending components averaged 469

thousand barrels per day compared to 313 thousand

barrels per day in 1995. Over 50 percent of the gasoline

imported into the United States comes from three areas:

Canada, the Virgin Islands, and Venezuela. These

provide a fairly steady source of gasoline imports,

averaging 200-280 thousand barrels per day annually. If

gasoline prices are attractive in the United States relative

to Europe, gasoline volumes flow across the Atlantic, and

Imports. Over 90 percent of U.S. distillate imports come

from three areas: the Virgin Islands, Canada and

Venezuela. For the past several years, distillate imports

averaged about 200 thousand barrels per day, with each

of the three areas providing about 30 percent of the total.

! Market Opportunities Drive Changes in Distillate

Export Patterns. While sources of distillate imports

have not changed much, distillate exports varied by both

volume and country of destination, based on market

opportunities. Some distillate exports flowed to regional

Latin American markets on a steady basis, but exports to

the Asia/Pacific region and to Europe rose and fell

dramatically. In the early 1990's, the Asian market for

distillate was tight, and U.S. production was a marginal

source of Asian supply. Then, exports to Asian markets

fell as Asian refining capacity expanded. During the

second half of 1996, high distillate prices in Europe drew

strong export volumes from the United States. For the

months of September, October and November, distillate

exports to Europe averaged about 100 thousand barrels

per day, increasing from just 42 thousand barrels per day

for the same months in 1995. The strong distillate export

volumes in the fall of 1996 occurred when U.S.

inventories were low and U.S. prices were high, but not

as attractive as European prices. 
1983 1985 1987 1989 1991 1993 1995 Q1 1997

Grade Share of Market (Percent)

Regular Share (Leaded and Unleaded)

Midgrade Share

Premium Share

0

20

40

60

80

100

Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun

0

200

400

600

800

1,000

1,200

1,400

1,600

Winter Heating Oil Demand

1994-95

1995-96

1996-97

(Thousand Barrels per Day)

1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996*

0

2,000

4,000

6,000

8,000

10,000

12,000

AAAA AAAA

AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

AAAA

Transportation Fuel Consumption

AAA AAA

AAAJet Fuel

On-Highway Diesel

Gasoline

(Thousand Barrels per Day)

1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

U.S. Petroleum Product Demand

Gasoline

Distillate

Kero-Jet

Residual Fuel

Other

(Thousand Barrels per Day)

12 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 6. Light Transportation Fuels Drive U.S. Demand Growth

Premium Grade Loses Market

Share with Gasoline Price Increase

U.S. Petroleum Product Demand

Continues to Rise

Mild Winter 1996-97 Dampens

Heating Oil Demand

Diesel Fuel Leads

Transportation Growth

Note: In bottom left graph leaded gasoline is included under regular grade gasoline.

Sources: Petroleum Product Demand: Energy Information Administration (EIA), 1983-1995—Petroleum Supply Annual (Vol. 1), Tables S1,

S4, S5, S6, and S7. 1996—Petroleum Supply Monthly (February 1997), Tables S1, S4, S5, S6, and S7. Other: Petroleum Supply Monthly Tables S4

and S7. Transportation Fuels: EIA,Fuel Oil and Kerosene Sales. Gasoline by Grade: EIA, 1983-1994—Petroleum Supply Annual (Vol. 1), Table 7.

1995-1996—Petroleum Supply Monthly, Table 7. Winter Heating Fuel Demand: EIA, 1994—Petroleum Marketing Annual (Vol. 1), Table 50. 1995-

1997—Petroleum Marketing Monthly, Table 50.
Energy Information Administration / Petroleum 1996: Issues and Trends 13

U.S. Petroleum Demand

U.S. demand for petroleum continued to climb in 1996, distillate (mainly high sulfur diesel and heating oil) and

reaching an annual average of 18.2 million barrels per day. residual fuel.

The growth comes from the transportation sector, which has

little economic alternative to petroleum-based fuel. ! Premium Grade Loses Market Share with Gasoline

Transportation growth was countered somewhat by

continuing declines in use of residual fuel.

! U.S. Petroleum Product Demand Continues to Rise. In

1996, U.S. demand for petroleum products rose 2.9

percent, with the transportation sector continuing to

provide primary support to overall long-term growth.

While higher product prices had a noticeable impact on

gasoline demand, which increased just 0.8 percent in

1996, a strong economy helped buoy kerosene jet fuel

and on-highway diesel demand, up 5.1 percent and 5.5

percent, respectively. Another long-run trend that

persisted in 1996 was the further weakening of residual

fuel demand, down 1.3 percent in 1996, as cheaper,

alternative energy sources continue to erode residual

fuel’s market share.2

! Diesel Fuel Leads Transportation Growth. In 1984,

light transportation fuels held a 63 percent share of total

finished petroleum product demand; by 1996, it had risen ! Mild Winter Dampens 1996-97 Heating Oil Demand.

to 69 percent. On-highway diesel fuel showed the

greatest growth, gaining 3 percentage points in market

share, to reach about 11 percent of the market in 1996.

The growth in gasoline and jet fuel were more modest,

both gaining about 1.5 points in market share since 1984

to attain 49 and 11 percent total shares, respectively. A

contributing factor in moderating the growth in gasoline

demand has been the improvements in passenger car fuel

efficiency. In 1984, passenger cars averaged 17.8 miles

per gallon, but by 1996 they averaged well over 22 miles

per gallon. This trend has stopped, partially due to

increased use of minivans and sport utility vehicles. Most

of the market share growth in light transportation fuels

was made possible at the expense of off-highway

Price Increase. After stabilizing between 1992 and 1995,

prices increased in 1996, and had a noticeable impact on

the composition of gasoline grade demand. The more

price sensitive (i.e., higher demand elasticity) high octane

grades lost share to the lower priced regular grade. Prior

to 1989, regular grade lost share as leaded gasoline was

phased out and as premium and midgrade gained

popularity. The decline was halted by sharply higher

gasoline prices in the latter half of 1990 resulting from

the Iraqi invasion of Kuwait. Premium’s share peaked in

1988 at 24 percent, but then fell back, first with the

advent of midgrade and later in response to the higher

prices precipitated by the Gulf War. The recent price

increase induced consumers to use more regular, whose

share rose almost 3 percentage points to 70 percent in

1996. In contrast, premium’s share fell by 2.4 percentage

points to a 17-percent share in 1996, the lowest level

since 1986.

While demand for total distillate was very strong in 1996,

up 4.7 percent from the prior year, the heating oil (No. 2

fuel oil) component was relatively weak, up just 2.4

percent. Most of this increase was due to severe cold

weather in the first four months of 1996, which resulted

in a 9.9 percent increase over the unusually mild weather

occurring over the same period in 1995. However, mild

weather in most of the country for the last quarter of

1996, representing the first half of the 1996-97 heating

season, caused heating oil demand to drop by 4.4 percent

compared to the same period in 1995. Typically, heating

oil comprises about 35 percent of total distillate demand

during the peak heating months, and falls to less than 20

percent during the summer. Approximately 80 percent of

heating oil demand is based in the Northeast, MidAtlantic and Midwestern States (PADDs 1A, 1B, and 2).

For a detailed discussion on the long-term trends in residual fuel 2

demand, refer to Energy Information Administration, Fuel Oil and Kerosene

Sales 1995 (September 1996), pp. 11-12.
19811982 198319841985 198619871988 198919901991 199219931994 19951996

0

70

80

90

100

Gross Inputs/Operable Distillation Capacity

(Percent)

1981198219831984198519861987198819891990199119921993199419951996

0

31

32

33

34

API Gravity of U.S. Crude Runs

(Degrees API)

14 Energy Information Administration / Petroleum 1996: Issues and Trends

Move to Heavy Crude Slate Slows

Figure 7. Refinery Utilization and Downstream Capacity Increase

Sources: Gross Inputs/Operable Distillation Capacity and API Gravity: Energy Information Administration (EIA), 1981-1995—Petroleum

Supply Annual (Vol. 1), Table 16. 1996—Petroleum Supply Monthly (February 1997), Table 28.

U.S. Refining Capacity as of January 1

Year

Number of

Operable

Refineries

Operable

Crude Oil

Distillation

(MB/CD)

Operable

Crude Oil

Distillation

(MB/SD)

Fresh Feed

Catalytic

Cracking

(MB/SD)

Coking

(MB/SD)

Hydrocracking

(MB/SD)

Hydrotreating

(MB/SD)

Alkylation

(MB/SD)

Isomerization

(MB/SD)

1981 324 18,400 18,621 5,543 1,021 909 8,487 974 131

1985 223 15,659 16,504 5,232 1,407 1,053 8,897 917 219

1990 205 15,572 16,507 5,441 1,549 1,282 9,537 1,030 456

1995 175 15,434 16,326 5,583 1,785 1,386 10,916 1,105 502

1996 171 15,286 16,169 5,599 1,842 1,385 11,050 1,122 505

Change 1981-1996 -153 -3,114 -2,452 56 821 476 2,563 148 374

Percent Change

1981-1996

-47% -17% -13% 1% 80% 52% 30% 15% 285%

Sources: 1981-1995: Energy Information Administration (EIA), Form EIA-820 "Annual Refinery Report." 1995: The stream day capacities are

projected capacities reported on Form EIA-820 "Annual Refinery Report” (1995)." 1996: Number of refineries and crude distillation capacity from

Form EIA-810 "Monthly Refinery Report" (January 1996). 

Bottoms Processing Capacity Continues to Grow, While the Number of

Refineries Declines

 Domestic Refinery Utilization

Continues to Rise
Energy Information Administration / Petroleum 1996: Issues and Trends 15

U.S. Refining

Since 1980, refining capacity utilization has increased as ! Bottoms Processing Capacity Continues to Grow.

U.S. refining capacity has declined and demand for

petroleum products has increased. Refinery distillation

utilization rates are now well above 90 percent, but capacity

constraints are not yet evident in the marketplace. Much of

recent refinery facility investment has been for expansion

and debottlenecking of units downstream of the distillation

units, partially in response to environmental requirements. 

! Domestic Refinery Utilization Rates Continue to Rise. The continuing high utilization rates for cokers in the

The utilization rate for U.S. refineries rose in 1996 to

meet rising oil demand with virtually unchanged refinery

capacity. The average monthly utilization rate increased

from 92.0 percent to 93.4 percent from 1995 to 1996.

Normally, utilization rates are lower in February and

March because of refinery maintenance, and highest in Decisions in the 1990's. Refiners' investment decisions

summer when throughput increases to meet gasoline

requirements. In the last several years peak utilization

rates exceeded 95 percent, while the minimum was under

90 percent. Utilization rates in excess of 95 percent

caused some market analysts to suggest that utilization

rates are approaching an upper limit and may result in

heightened market stress. Using EIA's definition of

utilization, 95 percent still leaves room for significant

production. EIA defines refinery utilization rate as input

divided by calendar day capacity, which means that 100

percent is the theoretical maximum average rate. The

calendar day rate has already been adjusted down from

the stream day capacity to account for shutdown and

production disruptions. In months with few shutdowns,

rates can exceed 100 percent.3

! Move to a Heavier Crude Slate Slows. The average API

gravity of crude oils run in U.S. refineries fell for many capacity in the U.S. was 269 thousand barrels per day,

years, but leveled off in recent years. While crude input compared to 120 thousand barrels per day estimated

grew heavier and then stabilized, production of heavy capacity in 1990.

products decreased. In 1980, heavy residual fuel

represented 11.7 percent of the product barrel. By 1985 ! The Number of Refineries Continues to Decline.

residual fuel yield fell to 7.1 percent, and in 1995, it was

only 5.4 percent. As crude oil gravity decreases, the

fraction of heavy material in the crude increases;

however, this heavy material can be converted to light

product with one of several bottoms conversion

processes. In the U.S., coking is the bottoms conversion

process most commonly used.

Coker unit capacity grew rapidly in the early 1980's, and

continues to grow, but at a more modest rate. From 1990

to 1996 coker capacity increased 19 percent. Utilization

rates for cokers are the highest of all the process units

EIA tracks. The decline of the price differential between

light and heavy crudes and light and heavy products

(discussed in Chapter 7) has reduced the economic

attractiveness of investing in additional coker capacity.

1990's suggests that, on a variable cost basis, continued

operation is justified; however, investment return may

have declined or disappeared entirely at times.

! Environmental Requirements Drive Facilities

in the 1990's were driven by requirements for cleaner

fuels and stricter environmental regulation of refineries.

The Clean Air Act Amendments (CAAA) of 1990

resulted in new requirements for gasoline and diesel fuel.

In California, state regulations required even greater

changes to product quality. A CAAA requirement to

reduce diesel sulfur content to 0.05 weight percent caused

a 827 thousand barrels per day increase in middle

distillate hydrotreating capacity from 1990 to 1995.

Additionally, a substantial number of process revamp

projects enabled units to achieve the 0.05 wt percent

product sulfur level. The CAAA reformulated gasoline

requirement resulted in an increase of 7.3 percent in

alkylation capacity and of 10 percent in isomerization

capacity from 1990 to 1996. The most dramatic increase

in the period was the increase in oxygenate production

facilities. In 1995 ether (MTBE & TAME) production

Between January 1, 1990 and January 1, 1997, the

number of operable refineries in the U.S. declined from

205 to 164; although capacity remained roughly the

same. Thirty-five refineries with a total capacity of 571

thousand barrels per day capacity were shut down and not

reactivated, and the primary distillation capacity of a

large refinery (Transamerican) decreased from 300

thousand barrels per day to 0. There were seven new or

reactivated refineries that added 131 thousand barrels per

day to distillation capacity. That means that existing

refineries increased capacity by about 304 thousand

barrels per day. Most of the focus of U.S. refiners was on

downstream facilities, but as part of refinery projects

there was some debottlenecking and expansion of

primary distillation facilities.

Tancred Lidderdale, Nancy Masterson, Nicholas Dazzo, "Secondary 3

Process Key to Gauging U.S. Refining Capacity," Oil and Gas Journal

(February 5, 1996), pp. 54-57.
1991 1992 1993 1994 1995 1996

0

5

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Gasoline Spot Spreads

AA

AAAA AAAAAAA AAA

Actual

5-Year Average

(Cents Per Gallon)

1991 1992 1993 1994 1995 1996

0

5,500

6,000

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7,000

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(Thousand Barrels per Day)

Production and Net Imports

Demand

Gasoline Demand and Supply

1991 1992 1993 1994 1995 1996

0

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Regular Gasoline and Crude Oil Prices

West Texas Intermediate Crude Oil

New York Harbor Regular Conventional Gas

Conventional Resale PADD 1

(Cents per Gallon)

1993 1994 1995 1996

0

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Gasoline Stocks

Normal Range AAAA AAAA AAAA

Actual

(Thousand Barrels)

16 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 8. Gasoline Prices Draw Public Attention

Spring Price Increase

Draws Attention

Gasoline Spot Spreads Are Weak

for Much of 1996

Gasoline Demand Reaches a Record

High in 1996, But Growth Slows

Gasoline Stocks Remain

Unusually Low in 1996

Sources: Spot Prices: Standard and Poor’s Platts. Resale Prices: Energy Information Administration (EIA), 1991-1994—Petroleum Supply

Annual (Vol. 1), Table 31. 1994-1996—Petroleum Supply Monthly (February 1997), Table 32. Spot Spreads: Standard and Poor’s Platts. Gasoline

Demand and Supply and Gasoline Stocks: EIA, 1991-1995—Petroleum Supply Annual (Vol. 1), Table S4. 1996—Petroleum Supply Monthly,

Table S4.
Energy Information Administration / Petroleum 1996: Issues and Trends 17

U.S. Gasoline Markets

The sharp increase in gasoline prices in the spring of 1996 barrels per day, a record high, rising from 7.79 million

aroused much public concern. Although gasoline demand barrels per day in 1995. 

was strong and stocks were low, it was high crude oil prices

that caused much of the spring price increase and drove ! Gasoline Production in 1996 Is Stable but Imports Are

gasoline prices up again later in the year. 

! Spring Gasoline Price Increase Draws Attention. The

usual seasonal spring increase in gasoline prices was

given a large boost this year from rising crude oil prices.

As the winter of 1995-96 drew to a close, gasoline and

petroleum stocks were low worldwide. Colder weather

lingered, and winter heating fuel demand persisted,

pushing crude oil prices higher beginning in February.

Finally a late, unexpected cold snap hit both Europe and

the United States, sending refiners into the market for

additional crude oil to meet the spurt in demand for

heating fuel. Crude prices experienced a final burst, with

WTI topping $25 per barrel in April 1996, just when

gasoline markets are normally tightening at the beginning

of the summer driving season. 

! Gasoline Spot Spreads Are Weak for Much of 1996.

The seasonal spring increase in gasoline spot spread (spot ! Gasoline Stocks Remain Unusually Low in 1996.

gasoline price minus crude oil price) was not much

different than average, in spite of the low gasoline stocks.

But the extra push from the underlying crude oil price

increase raised the total spring gasoline price

substantially. Spot Gulf Coast gasoline prices rose from

48.0 cents per gallon in December 1995 to peak at 66.2

cents in April 1996. Retail gasoline prices, which lag

behind crude oil price increases, did not peak until May.

Retail conventional regular gasoline prices rose from a

low of $1.06 in mid-February to a high of over $1.25 on

May 17. Crude oil prices and gasoline prices fell back

after the spring increase, but by fall, crude oil prices were

again climbing (see World Oil Markets page), and

gasoline prices followed. By the end of December,

gasoline prices were back at levels seen during the spring

runup. 

! Gasoline Demand Reaches a Record High in 1996, but

Growth Slows. Gasoline demand began the 1990's with declining crude prices led to a strong increase in U.S.

little growth as the United States experienced a recession.

However, growth resumed in 1992, averaging 2.3 percent

annually through 1995. Growth slowed again in 1996.

Gasoline consumption only grew 0.8 percent in 1996 as

bad weather slowed travel in the first quarter and high

prices discouraged consumption. Despite this slow

growth, U.S. gasoline demand in 1996 was 7.85 million

Higher. The increase in gasoline demand in 1996 was

satisfied overall by increases in net imports. Total

production in both 1995 and 1996 averaged 7.59 million

barrels per day. Imports, on the other hand, were stronger

in 1996 than 1995. This happened for several reasons (see

Chapter 2), including a glut of gasoline production in

Europe. While exports in 1996 were almost the same as

in 1995, imports of finished gasoline and blending

components averaged 469 thousand barrels per day in

1996 compared to 313 thousand barrels per day in 1995.

Reformulated gasoline (RFG) represented 37 percent of

gasoline and blending component imports in 1995 and 39

percent in 1996. (The East Coast is the main area using

gasoline imports, and much of this region converted to

RFG.) Lackluster price premiums for the costlier RFG

and regulatory uncertainties were some of the factors

keeping imports down in 1995.

Although total gasoline stocks have been exhibiting a

long-term downward trend (see Chapter 6), stocks in

1996 were even lower than the trend would indicate.

Stocks began the year low at 202.3 million barrels

(ending December 1995), which was 11 million barrels (5

percent) lower than the previous December minimum that

occurred at the end of 1989. Stocks returned to the low

end of the normal range by the end of April, and high

imports and production kept them at the lower edge of

the normal range through the driving season. In October,

refinery problems caused stocks to drop to 188.8 million

barrels, the lowest observed minimum in any month since

EIA began collecting data in 1981. Stocks did not recover

in November, and buyers, concerned over supply

availability, drove prices up. Crude prices, on the other

hand, fell back briefly in November as European refiners

slowed their pursuit of distillate-rich crude oils. The

combination of increased gasoline market pressures and

spot gasoline spreads for the month of November.

According to trade press reports, the gasoline price rally

attracted more cargoes of imports, and the spread soon

declined, but increasing crude oil prices pushed total

prices higher in December. Stocks remained abnormally

low through December, ending the year at 195.5 million

barrels, the lowest December stock level recorded by

EIA.
1991 1992 1993 1994 1995 1996

0

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100,000

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Distillate End-of-Month Stocks

Normal Range AAAA AAAA

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Actual

(Thousand Barrels)

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0

July

July

July

1991 1992 1993 1994 1995 1996

Demand

Production and Net Imports

0

1991 1992 1993 1994 1995 1996

1,800

2,000

2,200

2,400

2,600

2,800

3,000

3,200

3,400

3,600

3,800

Thousand Barrels per Day (Thousand Barrels per Day)

Distillate Demand and Supply

0

1991 1992 1993 1994 1995 1996

0

10

20

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60

70

80

No. 2 Fuel Oil and Crude Oil Prices

West Texas Intermediate Crude Oil

New York Harbor Spot No. 2

PADD 1 No. 2 Resale

(Cents per Gallon)

1991 1992 1993 1994 1995 1996

0

2

4

6

8

10

12

14

16

18

20

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NY Harbor No. 2 Heating Oil Minus WTI

AAAA AAAAAAA

AAA Actual

5-Year Average

(Cents per Gallon)

18 Energy Information Administration / Petroleum 1996: Issues and Trends

Tight Distillate Market Pulls

Crude Prices Up . . .

. . . and Boosts Spot Spreads

Above Average for Most of 1996

Strong Distillate Demand Reinforces

Market Tightness

Figure 9. World Distillate Demand Keeps Pressure on Crude Prices

Distillate Stocks Drop to

Record Low Levels in Fall 1996

Sources: Spot Prices: Standard and Poor’s Platts. Resale Prices: Energy Information Administration (EIA), 1991-1993—Petroleum Supply

Annual (Vol. 1), Table 40. 1994-1996—Petroleum Supply Monthly (February 1997), Table 40. Spot Spreads: Standard and Poor’s Platts. Distillate

Demand and Supply and Distillate Stocks: EIA, 1991-1995—Petroleum Supply Annual (Vol. 1), Table S5. 1996—Petroleum Supply Monthly,

Table S5.
Energy Information Administration / Petroleum 1996: Issues and Trends 19

U.S. Distillate Markets

A cold winter worldwide in 1995-96 drove up distillate 1995 due to both cold weather in early 1996 and high

demand. Refiners drew down petroleum inventories, and transportation demand.

then increased crude oil purchases and runs to produce

additional distillate, pulling crude oil prices higher. In the ! Jet Kerosene Demand Is Also High. Not only did

U.S., distillate demand did not let up over the summer, and

inventories never recovered. As fall approached, crude

markets worldwide remained tight and crude oil prices again

climbed. With distillate markets in the U.S. still tight, prices

stayed strong throughout the year. 

! Tight World Distillate Market Pulls Crude Oil Prices

Up and Boosts Spot Spreads Above Average for Most ! Production and Net Imports Increase, but Still Fall

of 1996. While gasoline prices drew the most publicity in Short of Demand. Distillate demand rose 161 thousand

the spring of 1996, distillate prices also increased. As barrels per day in 1996 to average 3,368 thousand barrels

winter 1995-96 progressed, distillate demand increased, per day. Production rose 170 thousand barrels per day to

and distillate markets worldwide tightened. The growing 3,325 thousand barrels per day and net imports increased

tightness was reflected in lower than normal inventories 24 thousand barrels per day, requiring 9 thousand barrels

and higher than normal price spreads over crude oil (spot per day to be met from stocks. While total net imports

distillate price minus crude oil price). Winter continued only increased 24 thousand barrels per day over 1995, the

into March, depleting distillate inventories, so European trading patterns were much different, which is explained

and U.S. refiners turned to the crude markets for further on the Import Overview page.

additional oil to produce more distillate. Crude prices

were pulled higher. The higher crude prices and higher ! Distillate Stocks Drop to Record Low Levels in the

than normal price spreads continued until distillate

demand let up after the April cold snap.

! Distillate Market Tightness Spreads to Crude Market

in Fall. Price spreads fell back below normal in June and

July, but began to pick up again in August, even before cold snap, stocks were still low at 90.0 million barrels,

the heating season was underway. Strong demand well below the normal range for that time of year. By

coupled with the low inventories resulted in early June, inventories looked like they might have a chance to

distillate price pressure. With worldwide petroleum climb back, but strong July demand prevented the needed

inventories still low, crude prices again were pulled stock increase. Distillate stock build is usually highest in

higher as the distillate heating oil season got underway. July, averaging 11.4 million barrels, but in 1996, the

Tight U.S. distillate markets kept distillate price spreads stock build was only 4.7 million barrels, the lowest July

above average through the remainder of 1996. The higher stock build since EIA began collecting data. The gap only

spreads coupled with high crude oil prices resulted in grew through October, with fuel oil inventories closing

high distillate prices throughout 1996. the month at 115 million barrels, 6 million barrels below

! Strong Distillate Demand Reinforces Market history. Distillate stocks are an important supply source

Tightness. Distillate fuel oil serves several end uses. Onhighway transportation represents almost 50 percent of

demand. Residential heating, the next largest end-use

category, represents more than 13 percent of annual

distillate use, but is concentrated in the winter months. 4

Annual distillate fuel oil demand grew 4.7 percent over

distillate fuel oil demand grow at a brisk pace, but

kerosene-type jet fuel also showed strength, averaging

6.0 percent growth in 1996. This product and distillate

come from essentially the same boiling range of the

crude oil barrel, so its high growth put further pressure on

distillate supply. 

Fall. The most unusual feature of the distillate market in

1996 was the very low inventory levels that persisted

throughout the year. U.S. distillate inventories bottomed

out in March at 89.7 million barrels, the lowest level

since EIA began collecting data in 1981. After the April

the next lowest stock level recorded for October in

during the peak winter demand months, and on average

satisfy about 12 percent of demand from December

through February. Thus, low inventories going into

winter are a concern. Any early cold snap would have

caused prices to soar, as happened in December 1989,

when stocks also were low and an early cold spell drove

prices up. Fortunately, in 1996, no such cold spell

occurred, but the continued high demand, high

production, and low stocks kept price spreads well over

average. 

Energy Information Administration, Fuel Oil and Kerosene Sales 1995 4

(September 1996), Table HL1.
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

110

120

130

140

150

1996

Monthly Average Retail Motor Gasoline Prices, Including Taxes

Conventional

All Gasoline

RFG

(Cents Per Gallon)

LPG Natural Gas Alcohols Electricity

0

50

100

150

200

250

1996 Consumption of Alternative Fuels

(Million Gasoline-Equivalent Gallons)

US Northeast Mid-AtlanticSoutheast Mountains West

0

20

40

60

80

100

120

140

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1996

Gasoline Consumption by Formulation and Region

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Conventional

Oxygenate

RFG

1995 1996 1995 1996 1995 1996 1996 1995 19951996 1995

(Billion Gallons)

Jul Jan Jul Jan Jul Jan Jul Jan Jul Jan

0

50

100

150

200

1992

Gulf Coast Oxygenate Prices

Spot MTBE

Spot Ethanol

Spot Methanol

1993 1996 1994 1995 1997

(Cents Per Gallon)

20 Energy Information Administration / Petroleum 1996: Issues and Trends

Sources: Gasoline Consumption: Energy Information Administration (EIA), Prime Supplier Report, December 1996. Gasoline Prices: EIA,

Weekly Petroleum Status Report (various issues). Oxygenate Prices: Octane Week (various issues). Consumption of Alternative Fuels: EIA,

Alternatives to Transportation Fuels (December 1996).

Reformulated Gasoline Increases

Market Share

Switching to Cleaner Gasolines

Has a Price

Oxygenate Prices Rise Steadily

for Much of 1996

Figure 10. Clean and Alternative Transportation Fuels Continue to

Grow

Propane Is the Dominant Alternative

Transportation Fuel
Energy Information Administration / Petroleum 1996: Issues and Trends 21

Clean and Alternative Transportation Fuels

The use of cleaner transportation fuels to improve air quality California. Gulf Coast monthly average spot RFGcontinued to grow in 1996. Smog-reducing reformulated conventional differences averaged 2.3 cents per gallon in

gasolines were chiefly responsible for this increase. While 1996, varying between 3.9 cents per gallon in April and

the use of alternative fuels also increased, it will be many 0.8 cents in October. Adding on the 2-cent RFG regional

years before alternative fuel vehicles become a significant differences and 1 cent logistical costs, retail customers

factor in the transportation sector. outside of California probably paid on average a little

! Reformulated Gasoline Increases Market Share.

Reformulated gasoline (RFG), which is designed to

reduce harmful exhaust emissions that cause smog, Oxygenates are an important component of reformulated

accounted for 31 percent of total motor gasoline usage in gasolines. Oxygenate prices in 1996 were less volatile

1996, up from 27 percent in 1995. On the other hand, than in the previous few years, but nevertheless they were

oxygenated gasoline, which is designed to reduce affected by numerous special circumstances. The price of

emissions of carbon monoxide, comprised only 3 percent corn reached $5.00 per bushel in June 1996, compared to

of motor gasoline sales in 1996, down from 4.4 percent $2.00 per bushel as recently as October 1994. This

in 1995. The Northeast and the West Coast are the affected ethanol prices, which rose steadily on the Gulf

biggest users of RFG. Coast from $1.05 per gallon in September 1995 to as high

as $1.49 per gallon in September 1996. Methanol prices

! The Switch to Cleaner Gasolines Has a Price. In areas

where RFG is used, consumers sometimes pay

significantly more for this fuel than they would for

conventional gasolines. Gasoline prices are generally

relatively high to begin with in these areas, which tend to

be more densely populated. Prior to the introduction of

RFG, these areas showed about a 2-cent-per-gallon price

premium over attainment (non-RFG) areas. Adding in the

incremental cost of producing RFG, which EIA

calculated to be about 3 cents per gallon, and the extra

increase in logistics and other costs, which the National

Petroleum Council estimated at about 1 cent per gallon,

the typical spread between RFG and conventional propane, are by far the dominant alternative fuel,

gasoline is expected to average about 6 cents per gallon. although the use of other alternative fuels is growing. In

California’s RFG has more stringent requirements than 1992, natural gas, including both compressed natural gas

the Federally mandated RFG, and its production costs are and liquefied natural gas, comprised less than 6 percent

also higher, leading this spread to be even wider in of alternative fuels use, but by 1995, EIA estimates its

California. California also has had supply problems due share had risen to almost 15 percent. The use of alcohols

to refinery operating difficulties and the limited number is small, involving various mixtures of ethanol and

of refineries that can produce the gasoline, which has methanol with gasoline. Electricity will be a small factor

driven RFG prices there up even further. California in the market for the foreseeable future. Overall, most of

consumes over 35 percent of the nation’s RFG, so its the growth in alternative fuel usage is the result of the

prices affect national average figures. The differences Energy Policy Act of 1992, which mandated the use of

between the Gulf Coast spot prices for reformulated and alternative fuels in Federal government fleets in 1993 and

conventional regular gasoline provide an indication of the in state and local government fleets over the next few

RFG premium being paid by consumers outside of years.

over 5 cents more for RFG in 1996.

! Oxygenate Prices Rise Steadily for Much of 1996.

were much more stable in 1996 than in recent years, but

tight supplies, worsened by idled plants, including the

Callowness plant in Alberta, Canada, in early October

and the Hoechst-Celanese plant in Clear Lake, Texas in

December, drove methanol prices to a high of 51 cents

per gallon in December. Because methanol is a feedstock

for MTBE, higher methanol prices in turn pushed up the

price of MTBE, which traded as high as 89 cents per

gallon in October.

! Propane Is the Dominant Alternative Transportation

Fuel. Liquefied petroleum gases (LPG), predominantly

5

Energy Information Administration, Alternatives to Traditional 5

Transportation Fuels 1994 (February 1996), Volume 1, Table 14.
Jan Jul Jan Jul Jan Jul

0

290

300

310

320

330

340

350

360

Crude Oil Stocks

1994 1995 1996

(Millions of Barrels)

Nov Mar Jul Nov Mar Jul

0

16.00

18.00

20.00

22.00

24.00

26.00

2 Oct 1995

15 Apr 1996

1 Jul 1996

3 Sep 1996

10 Dec 1996

Futures Contract Prices

1995 1996 1997

(Dollars Per Barrel)

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1986 1988 1990 1992 1994 1996

0

10

20

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50

Contracts (M illions)

Crude Oil

Heating Oil

Unleaded Gasoline

AAAA

AA

Jan Jul Jan Jul Jan Jul

0

80

90

100

110

120

130

140

150

160

Heating Oil Stocks

1994 1995 1996

(Millions of Barrels)

22 Energy Information Administration / Petroleum 1996: Issues and Trends

Sources: Futures Trading Volume and Futures Contract Prices: New York Mercantile Exchange. Crude Oil and Heating Oil Stocks: Energy

Information Administration, Petroleum Supply Monthly (various issues).

Futures Trading Volume Levels Off Trading Is Inhibited by Low

Crude Oil Stocks

Trading Is Also Inhibited by

Low Heating Oil Stocks

Figure 11. Futures Markets Are Turbulent in 1996

Expectations Are Reflected in

Pricing of Futures Contracts
Energy Information Administration / Petroleum 1996: Issues and Trends 23

Petroleum Futures Markets

By any measure, petroleum futures markets were extremely differently, making the futures markets less useful for

volatile in 1996. Volatility frequently attracts increasing hedging and thereby causing a slowing in the volume of

amounts of both speculative and hedging activity in futures futures trading.

markets; however, this has not occurred recently. Trading

volume in energy futures grew at a remarkably rapid rate in ! Numerous Factors Contribute to Low Stock Levels of

the late 1980's, but volume growth has slowed considerably

in recent years. There are many reasons for this. An

important reason is that commercial traders historically have

been attracted to futures markets as a device for hedging

their price risk. But futures contracts that do not accurately

reflect the product being hedged may have price movements

that differ greatly from spot price movements, diminishing

the usefulness of the futures contract as a hedging device. 

! Futures Trading Volume Levels Off. Uncertainty in

unleaded gasoline futures trading is one of the major

reasons why futures market trading volume has leveled

off since 1994. Unleaded gasoline futures are specified in

terms of reformulated gasoline but must serve as a

hedging device for numerous types of reformulated,

oxygenated, and conventional gasolines. The fragmented

gasoline market causes great uncertainty as to how

closely futures prices will follow the spot prices of the

type of gasoline being hedged. That uncertainty has led

to a slowing in trading volume in unleaded gasoline

futures. After large increases in volume as recently as

1988 (60 percent) and in 1989 (36 percent), trading in

gasoline futures actually decreased by 5.3 percent in 1995

and another 0.5 percent in 1996.

! Low Oil Stocks Also Inhibit Trading. Another reason

for the slowdown in futures trading volume is the effect

that low oil stocks have on the markets. Price structures

in energy futures markets depend upon a variety of

factors. The most important factor by far is the balance

between supply and demand that is reflected in the level

of stocks. Low stock levels in a tight market can

adversely affect the relationship between futures prices

and spot prices almost as much as having an inadequately

defined futures contract. Heating oil and crude oil stocks

reached historically low levels in 1996. In March 1996,

heating oil stocks reached a low of 89.7 million barrels,

down 22 percent from the previous year, and at a very

low level to begin building stocks for the heating season.

Also, crude oil stocks were only 299.6 million barrels in

March 1996, down 11.6 percent from a year earlier. Low

stock levels can make the markets very jittery, and

futures prices and spot prices may behave very

Petroleum and Products. One factor affecting stocks is

loosely called "just-in-time" inventory practices. The

industry has made a conscious effort to lower inventory

costs by holding as few stocks as possible. At least part

of the low stocks in 1996 were simply an extension of a

long-term trend in the industry to hold fewer stocks.

Additionally, a number of supply and demand factors

contributed to low stock levels in 1996. Those factors

include: an industry-wide reflection of expectations about

the possibility of the resumption of oil sale from Iraq;

cold weather in the spring; strong global oil demand;

supply shortfalls from non-OPEC sources; and strong

gasoline demand. All those factors made it difficult for

refiners to build inventories.

! Pricing of Futures Contracts Reflects Stock Levels

and Supply Expectations. Through 1996, the futures

markets reflected changing stock levels and expectations

of future supply (market factors that are not independent).

In late 1995, the crude oil market showed only mild

"backwardation," a situation in which crude oil for future

month delivery is priced lower than crude oil for nearby

month delivery. On October 2, crude oil for delivery in

November was $17.64 per barrel, while crude oil for

December 1996 delivery was only 30 cents per barrel

lower. But by April 1996, the backwardation in the crude

oil futures market had increased sharply. On April 15,

1996, crude oil for May delivery was $25.06 per barrel,

but oil for June delivery was $2.58 per barrel lower,

driven largely by expectations of imminent oil sales from

Iraq. In early December 1996 the backwardation

decreased after Iraqi oil sales were finally announced, as

the spread between January and February 1997 futures

prices dropped to 50 cents per barrel. The announcement

of the Iraqi sales removed much of the uncertainty in

expectations that had caused market backwardation.

Futures markets will continue to be a good measure of

both perceived adequacy of petroleum stock levels to

cushion supply/demand swings and market expectations.

They may also cause some controversy, as analysts

disagree on the exact nature of the cause-and-effect

relationships between futures market backwardation,

stock levels, and expectations.
Jan Apr Jul Dec

0

1.00

2.00

3.00

4.00

5.00

6.00

7.00

Marketers' Margins

1995

Distillate

1995

1996

1996

Motor Gasoline

(Dollars per Barrel)

Jan Apr Jul Dec

0

2.00

4.00

6.00

8.00

10.00

Refiners' Margins

1995

1996

(Dollars per Barrel)

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

-10

0

10

20

30

40

Annual Return on Equity (Percent)

S&P Industrials 

Nonenergy

Independent Refiners

Majors

Jan Apr Jul Dec

-200.00

0

200.00

400.00

600.00

800.00

1000.00

1200.00

1400.00

(Million Dollars)

1995

1996

1995

1996

U.S. Refining/Marketing Income

Independent Refiners' Net 

Income

Majors' U.S. Refining/ 

Marketing Income

24 Energy Information Administration / Petroleum 1996: Issues and Trends

Note: Profitability: Return on equity = net income as a percent of stockholders' equity. Results for 1996 are through the third quarter.

Sources: Refiners’ and Marketer’s Margins: Energy Information Administration, Petroleum Marketing Monthly (April 1997) (Washington, DC).

U.S. Refining Income and Profits: Company quarterly reports to shareholders. Profitability: Standard and Poor's Compustat.

Price Runup Boosts Refiners’

Margins

But Not Marketers’ Margins

U.S. Refining Profits Improve in

the First Half of 1996

Figure 12. Downstream Performance in 1996 Is Modest Despite High

Prices

Yet Profitability Remains Below

U.S. Industry Norm
Energy Information Administration / Petroleum 1996: Issues and Trends 25

Financial Performance

Increases in gasoline and distillate margins raised refinery second quarter’s level. The gross margin in the third

margins slightly higher in 1996, but lower retail margins quarter of 1996 almost matched 1995's third-quarter

dampened growth in downstream income. While total margin, while the margin in the fourth quarter was 8

profitability of the major and independent refining percent above the comparable value in 1995. The modest

companies was up in 1996, it remained below the uptick in margins was largely due to higher gasoline and

profitability of overall U.S. industry. diesel fuel demand stemming from a surge in U.S.

 economic growth in the last quarter of 1996.

! Price Runup Boosts Margins in the First Half of 1996.

The spread between product prices and crude oil input

costs (the gross refining margin) realized by refiners for

distillate and gasoline was nearly a dollar per barrel

higher in both the first and second quarters of 1996 than

corresponding 1995 levels. It should be noted that the

gross refining margin in the first quarter of 1995 was at

a 6-year low. The increase in the first-quarter margin in

1996 reflected the effects of an especially cold winter,

particularly in March, with heating oil prices up 17

percent and propane prices up 22 percent compared to

prices in the first quarter of 1995. However, the firstquarter rise in gasoline prices merely matched the rise in

crude oil input prices. In the second quarter of 1996,

gasoline price rises out paced the continued rise in crude

oil input costs, as did distillate prices, thereby U.S. Industry Norm. On balance, the profitability of the

contributing to higher margins.

! U.S. Refining Profits Improve in the First Half of

1996. Quarterly financial results are available for a profitability is return on equity, defined as net income as

consistent group of 13 specialized refiner/marketers and

13 major integrated petroleum companies that separately

report data for their U.S. refining/marketing line of

business. Total first-quarter income from U.S.

refining/marketing operations for both groups of

companies in 1996 was over $400 million above the very

poor first-quarter results of 1995. The first-quarter results

in 1995 were the worst for U.S. refining operations over

the 1987-1996 decade. The rise in downstream profits

continued through the second quarter of 1996. The

majors’ second-quarter financial results for their U.S.

refining/marketing operations were at a 10-year peak,

surpassing the previous peak in 1990, when a crude oil

market glut yielded record refining margins. Independent

refiners also registered a 10-year peak in second quarter

net income.

! High Margins Are Not Sustained in the Second Half of

1996. In contrast to the first-half results, refiners’ margins

in the second half of 1996 were only slightly above prior

year's margins. Gross margins showed the typical

seasonal pattern, dropping in the third quarter from the

Refiners registered a year-over-year drop in income in

the second half of 1996, even though margins were

slightly higher and overall U.S. refined product demand

was up 3 percent. Reduced retail margins appear to be a

source of lower downstream earnings in the second half

of 1996. The retail margin for gasoline (calculated as the

difference in the price to end users and the resale price)

was clearly lower in the second half of 1996 compared

with 1995. Since most of the majors and independent

refiners are involved in retail gasoline marketing to

varying degrees, a large drop in retail margins will be

reflected in their bottom-line results.

! Refiners’ Profitability Improves, but Remains Below

U.S. major and independent refining companies in 1996

was up slightly, but still well below the profitability of

U.S. industry overall. An often-used measure of corporate

a percent of stockholders’ equity. Although the annual

profitability of both the majors and independent refiners

rose in 1996, this improvement was mainly attributable

to lines of activity other than U.S. refining and marketing

operations. Major U.S. petroleum companies’ upswing in

overall profitability was traceable to higher oil and

natural gas prices realized from upstream operations. For

example, the majors disclosing separate financial results

for U.S. oil and gas production reported that income from

these operations for all of 1996 was up 88 percent

compared with results for 1995. For their U.S. refining

and marketing operations, the majors reported a much

smaller 15-percent increase in income over the same

period.

The independent refiners’ increased profitability in 1996

in part reflected recent large downstream acquisitions

(Clark USA and Tosco) and improved results from other

lines of activity including nonenergy businesses

(Ashland) and the production and marketing of natural

gas and natural gas liquids (MAPCO, LL&E, and Valero

Energy).
Energy Information Administration / Petroleum 1996: Issues and Trends 27

The rapid increase in gasoline prices during spring 1996 focused attention on petroleum markets. Petroleum

product prices have not drawn much public attention since the Gulf War, but the spring increase renewed

interest in the changing petroleum marketplace and raised questions about what caused the increase and the

potential for more such price increases in the future. 

2. Spring '96 Gasoline Price Runup:

An Example of Petroleum Market Dynamics

Introduction

Retail gasoline prices in the United States rose sharply over

the early months of 1996, increasing by 21 cents between

mid-February and mid-May (Figure 13). While gasoline 6

prices usually rise somewhat at this time of year, the

extraordinary speed and magnitude of the increase surprised

and even alarmed many consumers.

The spring 1996 price increases resulted from a confluence

of factors, some of which were unusual but not

unprecedented. Rising crude oil prices and the normal

seasonal increase in gasoline prices accounted for most of

the retail price increase. However, gasoline markets were

also affected by unusual factors, including: a late-winter cold

spell causing refiners to focus on producing distillate

(heating oil, diesel fuel and kerosene-jet fuel) instead of

gasoline longer than usual; lower-than-normal gasoline

stocks; continuing high gasoline demand and high refinery

capacity utilization; and persistent expectations that both

crude oil and gasoline prices would fall several months in the

future, which discouraged production of gasoline in excess

of demand to build stocks.

In order to assess the main factors influencing gasoline

prices, crude oil price movements are separated from the

gasoline prices, and spot prices will be explored separately Crude oil, the raw material for gasoline and other petroleum

from retail prices. The difference between gasoline price and products, represents by far the largest cost component of

crude oil cost is referred to as the price spread. Figure 14 those products. The increase in crude oil prices from

shows the relationships between spot and retail prices and December 1995 through April 1996 explains about half of

the underlying costs that prices must cover, excluding taxes. the increase in retail gasoline prices. Light and heavy crudes

The full retail price of gasoline paid by consumers provides alike rose rapidly in March and April (Figure 17). West

the revenues to cover the costs of crude oil, refining, storage Texas Intermediate (WTI) crude oil averaged $19.03 per

and distribution, marketing and retail expenditures, taxes barrel in December, fell back to under $18 towards the end

(federal, State and local), and to generate a return on of January, and peaked at $25.15 per barrel during April

investment (profits). The two largest single costs are crude

oil and taxes (Figure 15). For example, West Texas

Intermediate spot prices averaged 45.3 cents per gallon

during December 1995. Taxes averaged 40.8 cents per

gallon. 

Average monthly spot prices peaked in April at over 65 cents

per gallon, and retail prices, which lag spot price changes,

peaked a month later in May at $1.24. Figures 15 and 16

show that the crude oil price increase explains a large part of

the gasoline price increase. However, gasoline spreads also

increased. Spot gasoline spreads normally increase between

December and May, followed shortly by increases in retail

prices. Figure 16 shows what spot prices would have been,

had average spot spreads been experienced. 7

This chapter describes the influence of various market

factors on gasoline prices and how these factors combined to

cause the unusual price increases in the spring of 1996. The

analysis focuses on the changes that occurred from

December, the normal seasonal low point for spot gasoline

markets, through April, when spot prices peaked, follows the

progress of gasoline markets prices through the summer

driving season, and concludes with the price reversal in

spring 1997.

Crude Oil Market in Spring 1996

Regular gasoline, all formulations: Energy Information Administration 6

(EIA), Form EIA-878, “Motor Gasoline Price Survey.” (June 1996).

Different data series (e.g., Platts versus Reuters) and different crude oils 7

(e.g., Brent versus WTI) will produce different numbers, but the trend and

conclusion remain the same. That is, crude oil and normal spread patterns

explain most of the price increase. Other combinations of gasoline and crude

oil prices were inspected and more in depth analyses were performed and

discussed in An Analysis of Gasoline Markets Spring 1996, DOE/PO-0046
1994

100

110

120

130

140

Nominal Cents per Gallon

1990 1991 1992 1993 1995 1996 1997

Crude Oil Costs

Refining

Operating

Costs 

Refining

Profit (1) 

Storage and

Distribution

Costs 

Delivery

Costs 

Marketing

Operating

Costs

Marketing

Profit (1) 

 (1) Profits may be positive or negative, based on market conditions.

Retail Price

Spot Price

Crude Price

28 Energy Information Administration / Petroleum 1996: Issues and Trends

Source: Energy Information Administration, Annual Energy Review 1995 (January 1996), pp. 17, 161, and 179.

Figure 13. U.S. Average Retail Regular Gasoline Price

Figure 14. Price and Cost Relationships

Source: Energy Information Administration.
0

20

40

60

80

100

120

140

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65.3

Cents per Gallon

AAAA AAAA AAAA

Spot Spread

Taxes

Crude Oil Spot Price (W TI)

56.0

50.6 50.6

45.3 45.3

56.0

52.1

105.1

120.9

64.3

124.4

Spot Retail Retail Spot Spot Retail

December 1995 April 1996 May 1996

AAAA AAAA AAAA AAAA

Retail Excl. Tax Spread

Dec Jan Feb Mar Apr May Jun Jul

0

10

20

30

40

50

60

70

80

1996

C ents per Gallon

W est Te xas Interm ed iate C rude (W T I)

Average Spread (NYH G asoline M inus W TI)

Actual

45.3 44.8 45.5

50.8

56.0

50.6

48.7

50.8

52.1 49.9 52.8

58.3

65.3 64.3 57.3 61.1

1995

Energy Information Administration / Petroleum 1996: Issues and Trends 29

Note: Retail Excl. Tax Spread = retail price excluding taxes minus crude oil price. Spot Spread = spot price minus crude oil price.

Sources: Spot Prices: Standard & Poor’s Platts. Retail Prices: Energy Information Administration (EIA), Form EIA-878, “Motor Gasoline Price

Survey.”

Figure 15. Crude Oil and Gasoline Prices

Source: Standard & Poor’s Platts.

Figure 16. Gasoline Price Summary

(NY Harbor Spot Conventional Regular)
1991 1992 1993 1994 1995 1996

0

5.00

10.00

15.00

20.00

25.00

30.00

Dollars per Barrel

Arab Heavy

Brent

Nigerian Bonny Light

W est Texas Interm ediate

30 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 17. Monthly Average Spot Crude Prices

Source: Standard & Poor’s Platts.

before starting to fall again. Although a similar increase in normal patterns and falling (i.e., demand is greater than

crude oil prices occurred in 1994, consumers were not as production), market participants worry that production levels

sensitive to the change because gasoline prices were very may be too low to meet future demand. When stocks are

low at the start of the climb, and the increase occurred more limited, increases in demand elevate buyers’ concerns over

gradually. supply availability, and cause them to bid higher prices in

The rise in crude prices in the spring of 1996 can be

attributed to a tight crude oil supply/demand balance in The Organization of Petroleum Exporting Countries (OPEC)

world markets. A tight petroleum balance occurs when plays an important role in the crude oil market’s movement

demand exceeds production and when crude oil and product between tight and loose conditions. Non-OPEC producers

stocks are low, providing little cushion to meet unexpected generally produce at their maximum capability, but OPEC

demand surges or supply disruptions. historically has members who produce at less than capacity

Importance of Supply/Demand Balance

to Prices

As in all commodity markets, crude oil prices respond to the

fundamental market forces underlying the crude oil

supply/demand balance. For example, when little or no

excess short-term supply exists to satisfy demand, markets

tighten, producing upward pressure on prices.

Stocks are a closely watched barometer of market balance —

or tightness — for both product and crude oil markets.

Changes in stocks reflect imbalances in production and An important factor in the spring crude price increase was

demand and signal when supplies might be growing short or expanding world demand. Figure 18 shows world petroleum

long relative to demand. When stocks are low relative to supply and demand for 1991 through 1996. By the end of

order to assure supply.

to help maintain price levels. OPEC’s success at controlling

production when prices weaken has been limited. Demand

for OPEC crude oil varies both as a function of world

demand and non-OPEC supply. When the call on OPEC

crude oil is high relative to OPEC capacity to produce, the

market tends to support higher prices. When demand falls

off, OPEC production does not always follow, creating

downward pressure on prices due to oversupply.

Strong World Petroleum Demand Hit

New Peaks in Winter 1995-96
1991 1992 1993 1994 1995 1996 1997

0

64

66

68

70

72

74

76

Crude Oil Supply and Demand

Demand

Stock Draw

(Million Barrels per Day)

Supply

Stock Build

Energy Information Administration / Petroleum 1996: Issues and Trends 31

Figure 18. World Supply and Demand

Sources: Energy Information Administration (EIA), International Petroleum Statistics. First Quarter 1997: Actual—Oil Market Intelligence (May

1997), Vol. II, No. 5, p. 3. Second Quarter 1997: Projected—Oil Market Intelligence Update (June 2, 1997), p.1.

1993, the global economy was recovering from the recession prior winter was one of the highest during the last five years.

of the early 1990's. Demand began increasing and grew The strength was attributed to an extended winter in the

robustly in 1994 and 1995. Average daily consumption rates Atlantic Basin, continued strong Asian economic growth,

since 1993 have risen each year by about 1.6 million barrels and apparent stabilization of consumption in the former

per day (which represented 2 percent growth in 1995). Soviet Union countries.

World petroleum demand is seasonal, peaking during winter

in the northern hemisphere when world distillate needs are

greatest. (This differs from the U.S., where demand peaks in

summer because gasoline is the dominant product in the U.S.

market.) In 1992 and 1993, excess supply caused petroleum

stocks to build for two years in a row. Rising demand began

to eat into this surplus in 1994 as stock draws exceeded stock

builds for the year. As might be expected, crude oil prices

dropped substantially during this time of over-supply,

starting from about $22.37 monthly average (WTI) in June

1992 and bottoming out at an average $14.49 in December

of 1993. The increases in demand in 1994 tightened the

balance and brought prices up to an average of $19.70 in

July 1994.

Demand was very high during the winter of 1995-96,

exceeding most forecasts for the period prepared only

months before. Actual demand in the first quarter 1996

exceeded the November International Energy Agency (IEA)

forecast by 500 thousand barrels per day. The demand

increase during winter 1995-96 over summer and over the

Winter 1995-96 Crude Supply Affected

by Bad Weather

Demand growth alone cannot make a market tight. It is the

balance between the supply and demand that determines the

tightness or looseness of a market. Therefore, the

explanation for increased tightness must include the inability

or failure of crude oil supply to respond to demand growth.

World oil supply increased 1.5 million barrels per day during

the winter of 1995-96, but fell short of predictions. Like

demand, oil supply was also affected by weather. In early

November 1995, the International Energy Agency predicted

first quarter 1996 non-OPEC supply would be 43.9 million

barrels per day. Actual supply was only 43.1 million barrels

per day, or 800 thousand barrels per day short of

expectations. Part of the shortfall was caused by bad weather

conditions and operating problems in the North Sea and the

Gulf of Mexico, areas located near markets (U.S. and

Europe) where consumption was higher than expected.
32 Energy Information Administration / Petroleum 1996: Issues and Trends

While an 800 thousand barrels per day shortfall is less than The expectation of softening prices was further strengthened

2 percent of world supply, it can put significant pressure on in late January, as the potential for Iraq returning to the

prices in a tight market, since the shortfall must be made up market seemed to increase with the scheduling of the initial

from stocks or increases in OPEC production. Stocks were round of UN/Iraq discussions on limited oil sales for early

low and OPEC was already producing at high levels. OPEC February. Expectations of falling prices discouraged refiners

increased crude oil production from 25.4 million barrels per from building or maintaining stocks despite high demands.

day fourth quarter 1995 to average 25.6 million barrels per

day during the first four months of 1996. This was 1.1 As winter proceeded, distillate demand grew, and stocks

million barrels per day over its self-imposed quota of 24.5 disappeared. Prices began climbing again in February and

million barrels per day. March. Backwardation in the futures market steepened to

Tightening Winter World Petroleum

Balance Set Stage for Spring Crude

Runup

At the beginning of the 1995-96 winter, market analysts

expected growing supply to more than offset strong demand

growth. The world petroleum supply/demand balance as

reflected in world stocks was not a concern. However,

widespread, sustained winter weather served both to reduce

some of the anticipated supply and to boost winter demand

above expectations. Even with increased OPEC output over

the winter, OECD countries experienced the largest decline

in stocks over the fourth and first quarters in the last five

years. Winter 1995-96 demand was up by 2.1 million barrels

per day over winter 1994-95, while supply was up 1.5

million barrels per day. The OECD winter 1995-96 stock 8

draw was 1.1 million barrels per day compared to the 0.8

million barrels per day the prior winter. The 1.1 million

barrels per day draw is large and significant in light of the

low beginning stock levels. With low stocks and demand still

outstripping supply, markets tightened. WTI prices rose from

$17.44 in October to over $19 in December. Prices relaxed

a bit in January, partially due to increased OPEC production.

Another factor was at work affecting market behavior.

Throughout the winter, forecasters were predicting the

arrival of significant new non-OPEC supply during the third

and fourth quarters of 1996. Also, the low world demand

season occurs in the second and third quarters. With prompt

month (near-term) oil prices high due to scarce supply

relative to demand, and the market expecting increasing

supplies from non-OPEC (as well as from some OPEC)

sources, future prices were expected to fall, as reflected in

the futures markets. The situation where near-term prices are

higher than future months’ prices is called backwardation.

unusual levels as the prompt market tightened and the supply

outlook still reflected expectations for new supplies in the

short term (Figure 19).

The late cold spell in April affected Europe as well as the

U.S., and sent the already-tight markets skyrocketing. Both

regions were left with low crude and product stocks

following the long winter, eliminating stocks as a supply

source to meet the late surge in distillate demand. Refiners

responded by increasing crude oil purchases and increasing

refinery runs, which pushed the WTI price up over $25 per

barrel. 

Finally, in mid-April, as cold weather abated and demand for

crude oil began to recede, prices began to weaken. WTI

prices fell to about $21 per barrel by the end of the month

and hovered around that price until the end of August.

Normal Gasoline Markets

While crude oil price increases explained most of the

gasoline price increase in spring 1996, the behavior of

gasoline markets was responsible for the remainder. As

background for discussion of the unusual gasoline market

events of this past spring, a brief overview of normal market

behavior is presented below. Two major characteristics of

normal gasoline markets are particularly relevant: the

relationship between spot and retail prices and the usual

seasonal changes in the market.

Spot Spread is the Seasonal

Component of Price

The effect of the gasoline market on prices is revealed in the

spot spread (spot gasoline price minus crude price) and in the

retail spread (retail price minus spot price). The gasoline spot

spread gives an indication of the dollars being generated by

refiners to cover their costs to process crude oil into gasoline

and gasoline’s contribution to refiners’ taxes, financing

costs, corporate overheads, and profits. Spot spreads tend to

be low in winter and high in summer (Figure 20).

The Organization for Economic Cooperation and Development is the 8

international organization of the industrialized, market-economy countries.

The following countries are members of OECD: Austria, Belgium, Czech

Republic, Denmark, Finland, France, Germany, Greece, Hungary, Iceland,

Ireland, Italy, Luxembourg, Netherlands, Norway, Poland, Portugal, Spain,

Sweden, Switzerland, Turkey, United Kingdom, Canada, United States,

Mexico, Japan, Australia, New Zealand, and Korea.
Oct

1996

18.00

21.00

24.00

27.00

Dollars per Barrel

10/2/1995

4/15/1996

7/1/1996

9/3/1996

12/26/1996

Nov Jul Apr Jan Apr Jan Oct Jul

0

1995 1997

Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan

0

3

6

9

12

15

1995

Cents per Gallon

1994 1996

Gasoline

Distillate

Energy Information Administration / Petroleum 1996: Issues and Trends 33

Figure 19. Changing Term Structure for Crude Oil Futures

Source: New York Mercantile Exchange.

Figure 20. The Seasonal Price Component (New York Harbor Spot 5-Year Average Spot Gasoline and

Distillate Spreads)

Source: Energy Information Administration, data calculated using Standard & Poor’s Platts.
34 Energy Information Administration / Petroleum 1996: Issues and Trends

Historically, spot spreads typically increase by 5 to 10 cents 1995 imports averaged less than 350 thousand barrels per

per gallon between their lows in December and their peaks day after averaging 481 thousand barrels per day for the

in April and May. Although these spreads exhibit some same period in 1994 (Figure 23).

regional variation, they follow a similar pattern throughout

the U.S.

The seasonal pattern in gasoline spot spreads corresponds to

the cyclical tightening and loosening of gasoline supply and

demand. The gasoline supply and demand balance is, in turn,

affected by the market for distillate (heating oil, diesel fuel

and kerosene-jet fuel).

Price Seasonality Stems from

Seasonality in Supply and Demand

Gasoline and distillate demands are highly seasonal, but environmental regulations requiring different summer and

counter-cyclical (Figure 21). Distillate demand peaks in the winter specifications. But now, there is even more need to

winter when heating oil requirements are highest, and draw down excess winter gasoline stocks, since winter

gasoline peaks in the summer during the high driving season. gasoline does not meet summer gasoline specifications, and

Refiners co-produce gasoline and distillate and have a gasoline stocks are required to meet peak summer demand.

limited ability to change the relative quantities being

produced. Production of either product can be changed by March and April are crucial months for both gasoline and

shifting a small amount of material from the crude oil that is distillate markets. At the end of March, following refinery

in a boiling range acceptable to either product, and also by maintenance, gasoline stock levels are assessed for their

changing operating conditions on process units downstream ability to help meet summer demand. At the same time,

from the distillation tower. The limits of the changes require distillate stocks have been depleted by the end of the winter

refiners to build and use stocks to meet seasonal peak season. As a result, any extended-cold-weather distillate

demands (Figure 22). demand will have to be met through production, since stocks

Gasoline stocks build in the fall as distillate production is additional supply.

increased and gasoline co-production exceeds demand. Since

the advent of clean fuels, gasoline stocks have experienced By early April, gasoline demand begins to pick up. Gasoline

a slight drop in October as they are used to meet demand stocks usually continue to fall because refiners are still

while refineries convert to winter gasoline fuel production. coming back on stream, increasing imports lag behind the

Gasoline stocks then continue their climb as production rising demand, and refiners and terminals are converting

outstrips declining demand. Stocks usually peak in January from winter to summer gasoline. With low stocks and

when demand is at its lowest point. During the peak demand increasing demand, buyers bid higher prices for product,

months of June, July, and August, stocks provide about 2 thereby increasing spot spreads. These increasing spreads

percent of demand. (Stocks play an even more important role help to attract marginal imports. Sometime in late April or

in the distillate market, typically providing almost 12 percent May, refiners return to full production, imports are strong,

of demand during the peak winter months of December, and the market is in better balance. Spreads frequently drop

January and February). back, jumping again slightly in August before continuing

In addition to domestic production, imports help meet U.S.

gasoline demand. Some areas, such as Canada, Venezuela,

and the U.S. Virgin Islands, provide the U.S. with gasoline

imports on a regular basis. Europe and Saudi Arabia are

examples of marginal suppliers, because their economics of

selling product to the United States are not always attractive.

Imports from marginal suppliers tend to increase during the

second and third quarters as both demand and gasoline price

spreads grow. However, import volumes can vary

significantly from year to year. For example, second quarter

Seasonal Supply/Demand Balance

Impact on Gasoline and Crude Spread

In January, as gasoline production exceeds demand and

stocks reach their peak, the oversupply of gasoline pushes

the gasoline spreads to their lowest seasonal levels. During

the first quarter, crude input to refineries declines and both

gasoline and distillate production fall as refineries are shut

down for routine, annual maintenance around March. Excess

gasoline stocks accumulated over the fall and winter begin

to decrease at this time. This pattern existed prior to

must be used before summer begins. Still, some extra

are close to minimum working levels and cannot provide

their downward path to their December lows.

Prices Moving Through the System

Show Lag Between Spot and Retail

In addition to seasonality, the pace of price changes moving

through the system from refineries to end users helps explain

some of the timing of the 1996 spring gasoline price

increase. Price changes move through the system at different
1991 1992 1993 1994 1995 1996

0

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

Thousand Barrels per Day

Gasoline

Distillate

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Thousand Barrels per Day

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Stock Draws

Demand

Production and Net Imports

Stock Builds

1991 1992 1993 1994 1995 1996

0

2,200

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2,600

2,800

3,000

3,200

3,400

3,600

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y

1991 1992 1993 1994 1995 1996

Energy Information Administration / Petroleum 1996: Issues and Trends 35

Figure 21. Gasoline and Distillate Counter-Cyclical Demand

(Thousand Barrels per Day)

Sources: Energy Information Administration (EIA), 1991-1995: Petroleum Supply Annual, Vol. 2, Table 2. 1996: Petroleum Supply Monthly

(various issues), Table 2.

Figure 22. Relying on Stocks to Meet Peak Demand: Distillate Supply and Demand

Sources: Energy Information Administration (EIA), 1991-1995: Petroleum Supply Annual, Vol. 2, Table 2. 1996: Petroleum Supply Monthly

(various issues), Table 2.
1991 1992 1993 1994 1995 1996

0

100

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Finished Gasoline Excl. RFG

Reformulated Gasoline

Gasoline Blending Components

36 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 23. Gasoline Imports

Sources: Energy Information Administration (EIA), 1991-1995: Petroleum Supply Annual, Vol. 2, Table 2. 1996: Petroleum Supply Monthly

(various issues), Table 2.

rates. Spot gasoline prices, which change minute to minute, maintenance and draw down winter specification gasoline.

respond rapidly to crude oil price changes and reflect current So low stocks can become a concern towards the end of

perceptions of market tightness or looseness. Retail price March as the market assesses the industry's ability to meet

changes, however, lag significantly behind spot price peak summer demand.

changes due both to competition and to the way in which the

product works its way through the system to the consumer. Despite unusually low stocks throughout the first quarter

This lag can be seen from the alignment of peaks in 1996, gasoline spreads were weak for the time of year.

Figure 24. Activity and prices increase in wholesale markets Through March, the unusual increases in gasoline prices

in May in anticipation of the retail gasoline demand peak in could be explained by crude oil price increases alone. The

June through August. When crude prices are stable, spot seasonal spread increases through March were below normal

gasoline prices normally peak in May, while retail prices and added very little to spot gasoline price increases.

peak in June. 

The retail price lag results in a price squeeze for retailers

when wholesale prices are rising; however, the same lag

keeps retail prices up while wholesale prices begin to fall. 

Unusual Gasoline Market In First

Quarter '96 

Gasoline markets during the first quarter of 1996 were

unusual in several ways. While first quarter demand was

strong, and both production and imports were fairly high,

stocks were unusually low. During the first quarter, marginal

demand is normally met by stocks. Fairly large stock draws

can occur in March as refineries undergo scheduled

Gasoline Demand Growth Was Modest 

High gasoline demand is one of the factors that can

contribute to upward pressure to prices. From 1992 through

1995, gasoline demand grew strongly, mainly because an

increasing number of drivers and a stronger economy

resulted in an increase in the total miles driven. Overall fleet

efficiency (measured in miles per gallon) remained relatively

flat. However, demand growth slowed in 1996. First quarter

demand in 1996 was 7.5 million barrels per day, 0.4 percent

higher than the high first quarter 1995 (Figure 25). Demand

was higher than the previous year in both January and

February, keeping a check on stock growth that normally

occurs during this period. However, demand growth fell

slightly in March compared to the previous year, which put
0

1996

60

70

80

90

100

Cents per Gallon

New York Harbor Spot

Average Retail (excl. taxes)

50

1995 1997

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

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AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAAA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

Thousand Barrels per Day

AAAA AAAA

AAAA

AAAA

1994

1995

1996

Energy Information Administration / Petroleum 1996: Issues and Trends 37

Figure 24. Spot and Retail Gasoline Prices (Excluding Taxes)

Sources: Spot Prices: Standard & Poor’s Platts. Retail Prices (Excluding Taxes): Energy Information Administration (EIA), Form EIA-878,

“Motor Gasoline Price Survey.”

Figure 25. Gasoline Demand

Source: Energy Information Administration, Petroleum Supply Monthly (February 1997), Table S4.
38 Energy Information Administration / Petroleum 1996: Issues and Trends

less pressure than normal on the low stocks that help to meet downward trend might have predicted (Figure 27).

demand in March. Gasoline stock draws in spring 1996 were smaller than

Gasoline Production and Imports Were

High

Since 1992, U.S. gasoline production has increased in

conjunction with demand. Production increases are a result

of higher refinery utilization, addition of oxygenates to

produce reformulated gasoline (RFG), and some yield

increase from process improvements. Since 1993, summer

refinery distillation capacity utilization has averaged well

over 90 percent. 

Total gasoline production averaged 7.3 million barrels per

day for first quarter 1996 (Figure 26), which was 54

thousand barrels per day over first quarter production in

1995. This production increase was only slightly higher than

the gasoline demand increase of 34 thousand barrels per day

for the same period. However, gasoline stocks were very low

at the beginning of 1996, so production did little to improve

the stock levels through the first quarter.9

High gasoline imports supplemented production in 1996 (see

Figure 23 and box, p. 39). These imports prevented stocks

from dropping as much as they normally would have

dropped during the first quarter.

Gasoline Stocks Remained Low But

Spreads Were Weak

Gasoline stocks started to drop below the historical seasonal

range beginning in August 1995 and fell even further below

this range over the winter. Gasoline stocks have exhibited a

long term downward trend, partially due to companies

managing inventories more efficiently (see Chapter 5). But

stocks were lower in winter 1995-96 than even the long-term

10

normal, mainly because of high imports, but stock levels

remained below the average seasonal range through March.

Low gasoline stocks do not usually generate much price

pressure over the winter months when supply is in excess of

demand. Through March, gasoline price spreads remained

weak, indicating little market concern with supply. A

combination of low spreads, prospects for continued high

imports, and expectations of falling crude oil feedstock cost

discouraged refiners and wholesale buyers from holding any

more stocks than necessary. Furthermore, winterspecification gasoline cannot be used during the summer and

so must be drawn down before building summer gasoline

stocks. This situation changed in April.

The April Runup: Distillate and

Gasoline Markets Clash

In April 1996, crude prices jumped considerably and,

simultaneously, gasoline markets tightened more than

expected. This drove the gasoline spread to, or above,

normal levels in different parts of the country on top of the

crude price increases. The following factors set the stage for

the April runup:

! Crude prices had been strengthening prior to April due

to low stocks and continued strong demand, which drove

buyers to purchase crude oil as they waited for prices to

weaken in the future.

! April began with lower than normal gasoline stocks, but

gasoline spreads were a little weak in expectation that

high imports and domestic production would satisfy the

upcoming summer demand.

! Futures markets reflected expectations that the gasoline

market would tighten as usual in April as demand

increased towards its normal June-August peak season,

but would decline in subsequent months, in response to

declining crude prices. Expectations that prices would

fall discouraged gasoline wholesalers from holding any

more stocks than necessary. The shutdown and sale of the BP Marcus Hook refinery to Tosco in 9

January was observed to have little impact on availability of fuel supplies to

the Northeast. From the Bayway, New Jersey refinery, Tosco was able to

supply the needs of the BP retail marketing assets acquired. Marcus Hook

was a merchant refinery (i.e., sold most of its products to other companies)

and buyers of its products had ample time to arrange for other supply sources,

since possible shutdown had been a matter of public speculation for months.

Despite relatively high utilization rates of U.S. refineries, there was still the

capability to deal with the loss of capacity the size of the Marcus Hook

refinery in the Northeast. Had the refinery been in operation, its production

may have replaced some Gulf Coast production and some imports.

The weak gasoline build that occurred in the fall and winter 1996 was 10

mainly due to the combined effects of cold weather and expectations of

falling prices (backwardation). The crude oil price backwardation transferred

to the product markets, resulting in gasoline buyers expecting gasoline prices

to fall in conjunction with crude oil price declines several months in the

future. (For more discussion, see, An Analysis of Gasoline Markets Spring

1996, DOE/PO-0046 (June 1996).)
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

6,600

6,800

7,000

7,200

7,400

7,600

7,800

8,000

8,200

8,400

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

Thousand Barrels per Day

AAAA AAAA

AAAA

AAAA

1994

1995

1996

Energy Information Administration / Petroleum 1996: Issues and Trends 39

Figure 26. Gasoline Production

Source: Energy Information Administration, Petroleum Supply Monthly (February 1997), Table S4.

Gasoline Imports Were Expected to Be High in 1996, Due to Several

Factors

! Europe was experiencing excess gasoline production as European refiners produced distillate products for their own

markets. European refiners have been adding fluid catalytic cracking units to increase gasoline and distillate production,

but they are producing too much gasoline versus distillate relative to regional demand. This provided a ready source

of gasoline that flowed to the United States in 1996 when price differences between Europe and the United States

exceeded transportation costs (approximately 5 cents per gallon).

! The tight U.S. gasoline market (high demand and capacity utilization with low stocks) pushed prices up relative to

Europe. Although Europe was affected by higher crude prices, it did not experience tight seasonal gasoline markets

affecting the spread between gasoline and crude oil prices.

! Asia has been a primary market for Saudi exports of refined products; however, Asian refining capacity has expanded

rapidly, decreasing its product import needs. As a result, Saudi Arabia, a marginal supplier of product to the United

States during the summer, was expected potentially to have extra product to sell here.
1993 1994 1995 1996

0

190,000

200,000

210,000

220,000

230,000

240,000

250,000

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA

Thousand Barrels

AAAA AAAAAAA AAA

Normal Range

Actual

40 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 27. Total Motor Gasoline Stocks (End of Month)

Sources: Energy Information Administration (EIA), 1993-1995: Petroleum Supply Annual, Vol. 2, Table 2. 1996: Petroleum Supply Monthly

(various issues), Table 2.

When the late cold spell hit the Atlantic Basin, the distillate in February and March, about 2 cents of the increase could

market unexpectedly clashed with the gasoline market. The be attributed to the tight market. 

cold weather created extra demand for distillate on both

sides of the Atlantic at a time when this demand is usually Spot gasoline prices rose with increasing crude oil prices and

bottoming out (Figure 28) and distillate stocks are at their increasing spreads, peaking in April along with crude oil

seasonal low point (Figure 29). As distillate stocks were prices. These increases eventually made their way to the

unusually low in 1996 following the long winter , the retail market. As retail markets lag behind spot markets, 11

unexpected April demand had to be met through increased retail regular conventional prices peaked at almost $1.29 on

production (Figure 30). Thus, refiners refocused on distillate May 17, after the April spot price peak. Crude oil price

production at a time when they normally would be increases accounted for about 10.7 cents of the 13.2 cent per

maximizing gasoline output (Figures 25 and 26). gallon increase in New York Harbor spot prices from

Low gasoline stocks combined with refiners focusing in gasoline prices accounted for most of the remainder, with

unusually on producing distillate in April to meet demand perhaps 2 cents per gallon being attributable to unusual

from the late cold spell added pressure to the gasoline tightness of gasoline markets since spreads had been running

markets. The New York Harbor spot gasoline spread, which low at the beginning of the year, but climbed rapidly to

had been running below normal (Figure 31), suddenly average levels.

jumped from 2.6 cents below average in March to 1 cent

below in April. By May, the actual New York Harbor spread The increase in gasoline prices during the spring of 1996 was

was at its normal level. Given the spread’s low starting point more pronounced in some regions of the country. The box on

12

December 1995 to April 1996. The normal seasonal increase

p. 43 discusses the unusual circumstances in gasoline

markets in California.

Distillate demand was up 4.3 percent in the first quarter over 1995 due 11

to continued cold weather. In spite of the increase in distillate production,

distillate fuel stock draw from the end of October through March was 13

percent above normal (as measured by the normal stock range published in

the EIA’s Weekly Petroleum Status Report). Gasoline Markets Spring 1996, DOE/PO-0046 (June 1996).

This graphical New York Harbor and WTI display is supported by a 12

more in-depth regression analysis using average resale gasoline prices and

refiners’ acquisition cost of crude oil. This is discussed in An Analysis of
1993 1994 1995 1996

0

90,000

100,000

110,000

120,000

130,000

140,000

150,000

160,000

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

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AAAA AAAA

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AAAA AAAA AAAA

AAAA AAAA AAAA

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AAAA AAAA AAAA

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AAAA AAAA

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AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

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AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAA AAAA

Thousand Barrels

Normal Range

Boundaries

Actual

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

2,200

2,400

2,600

2,800

3,000

3,200

3,400

3,600

3,800

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

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AAA

AAA

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AAA

AAA

AAA

AAA

AAA

AAA

AAA

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AAA

AAA

AAA AAA

AAA

AAA

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AAA

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AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

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AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

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AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

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AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

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AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

AAA

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Thousand Barrels per Day

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1994

1995

1996

Energy Information Administration / Petroleum 1996: Issues and Trends 41

Figure 28. Distillate Demand

Source: Energy Information Administration, Petroleum Supply Monthly (February 1997), Table S5.

Figure 29. Distillate Stocks (End of Month)

Sources: Energy Information Administration (EIA), 1993-1995: Petroleum Supply Annual, Vol. 2, Table 2. 1996: Petroleum Supply Monthly

(various issues), Table 2.
1993 1994 1995 1996 1997

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C ents Per Gallon

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5-Year Average 1995-96

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0

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1996

42 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 30. Distillate Production

Source: Energy Information Administration, Petroleum Supply Monthly (February 1997), Table S5.

Figure 31. Gasoline Spot Spreads

(NY Harbor Spot Conventional - WTI)

Source: Standard & Poor’s Platts.
Energy Information Administration / Petroleum 1996: Issues and Trends 43

A Special Case: California

California introduced its own new and unique Phase 2 reformulated gasoline (CaRFG) during the spring of 1996. CaRFG

has more stringent requirements than Federal RFG, making it more difficult and more expensive to produce than Federal

RFG. The California Energy Commission estimates the additional cost to produce CaRFG at between 5 and 15 cents more

per gallon. Although the higher costs translate to higher prices, consumers will benefit from significant smog reduction.

Average CaRFG demand was projected at 896 thousand barrels per day for the first year (March 1, 1996 through

February 28, 1997), taking into consideration the fuel efficiency loss (about 1-2 percent lower than Federal RFG). Average

production was projected 906 thousand barrels per day, providing a 10 thousand barrels per day cushion. While not large,

this cushion was expected to be adequate.* Some supply potential exists outside of California. However, most refiners are

not equipped to produce the new fuel in any large amounts, if at all. Refineries in California are expected to use 85-90

percent of their gasoline capacity to produce the new fuel.

Unfortunately, supply problems developed as a number of California refineries experienced operating problems and had

to shutdown for repairs. Spot prices shot up, driven by uncertainties around potential shortages. Unlike the rest of the

country, the supply problems in California affected spreads strongly. Conventional gasoline prices were also affected by

the supply problems, since California refiners also serve neighboring states. 

The price increase experienced in California in 1996 reflected a market stress situation, illustrating price response when

supply disruptions occur in a very tight market. With little or no immediate supply alternatives, the loss of expected supply

resulted in the market bidding prices up at panic rates. Consumers paid an average of $1.15 per gallon for regular gasoline

in December 1995. By April 1996, the average was $1.40, or 25 cents per gallon higher due to crude price increases, the

changeover to CaRFG, and the refinery operating difficulties. 

_____________

*California Air Resources Board and California Energy Commission’s February 1996 Supply/Demand Analysis.

Gasoline Price Progress Through

Summer 1996

As expected, crude oil prices fell during April after the cold balance. They stayed below the 5-year average spreads with

weather abated, distillate demand relaxed, and the short-term the exception of July, when preliminary data indicated

demand for crude oil subsided. The decline of WTI prices stronger than normal demand with falling stocks. Since

ended in June, when it began hovering around $21 per barrel, stocks were still at low levels, the market reacted quickly to

down from its peak of over $25 per barrel in April. The $4 the unexpected tightening by pushing prices higher. Still

per barrel decline is equivalent to about 9.5 cents per gallon. gasoline spreads in July only exceeded the 5-year average by

Weekly average spot gasoline prices declined over 13 cents 0.7 cents per gallon. The supply/demand balance adjusted

per gallon during this time. Crude oil prices began to show and spreads fell well below normal in August and

renewed vigor in August and continued to climb through September, although gasoline price rose along with crude oil

September, as Northern Hemisphere demand began to price. 

increase in preparation for winter heating fuel needs, putting

upward pressure on all petroleum product prices. Monthly average spot prices fell from their peak of 65.3

. cents per gallon in April to bottom out in June at 57.3 cents.

Gasoline stocks, which began the year low, had risen to very Prices then began to rise as crude oil prices strengthened,

near the normal seasonal range in May, and stayed at the low countering declining spreads. By September, the end of the

end of the normal range through September, the end of the traditional driving season, New York Harbor spot prices had

summer driving season. Imports of gasoline and blending increased by 4 cents per gallon over the June price, and Gulf

components in 1996 were very high, as had been expected, Coast spot prices were up 2.4 cents per gallon. Retail

averaging 355 thousand barrels per day compared to 202 in conventional regular gasoline fell from its monthly average

1995 and 274 in 1994, which was another year with high

imports.

Gasoline price spreads reflected the gasoline supply/demand

peak of $1.24 in May to $1.18 in August. But retail prices
44 Energy Information Administration / Petroleum 1996: Issues and Trends

began to increase in September with the underlying increase months. This discouraged suppliers from building stocks

in crude oil price. By year end, retail prices had returned to because they could not lock in a profit on stocks being

levels seen the prior spring. held, and might even have to sell stocked product at a

Gasoline Markets Affected Distillate

In spring 1996, distillate markets affected the normal

behavior of gasoline markets. But strong gasoline imports

affected distillate markets as the year progressed. Greater

reliance on gasoline imports to meet gasoline demand

resulted in changed gasoline and distillate production and

stocking patterns in the United States. Figure 28 shows that

1996 distillate stocks have been low since the draw down

during the winter of 1995-96. Although distillate stock levels

were low as summer 1996 began, they increased normally in

May and June. But in July, which is normally the peak

re-build month, historically averaging over 11 million barrels

increase, stocks only increased 2.4 million barrels. 

Since part of gasoline supply in 1996 was being met from

higher imports rather than increased refinery runs, refiners

increased the yields of kerosene jet fuel and distillate (heating

fuel and diesel) to adjust to the new balance between refinery

production and demand. But the yield increase of distillate

was not uniform throughout the year. In the first quarter, the

yield increase provided 27 thousand barrels per day more

heating fuel and diesel than in 1995; in the second and third

quarters, the higher yield produced 115 thousand barrels per

day more distillate; and in the fourth quarter, when distillate

stocks were very low, the volume increase from higher yields

was to 226 thousand barrels per day. The distillate volume in

the fourth quarter versus the second and third quarters was

achieved by changing the yield split between kerosene jet fuel

and distillate and by increasing crude runs. The uneven

increase in distillate yields over the year did not provide

enough distillate production to build stocks to normal levels

over the summer, but the extra jump in yield and increased

crude throughput during the fourth quarter allowed

production to meet distillate demand without as much stock

draw as might normally have occurred. 

The affect of gasoline imports on distillate stocks was only in 1997 (Figures 31 through 34).

one of several factors contributing to the low distillate stock

situation in 1996. Other factors included: The explanation of the spring 1997 price decline lies mainly 13

! Distillate stocks began the year low. the main factors behind the spring 1996 price increase. WTI

! Continued backwardation in crude oil markets caused 1996. New York Harbor spot gasoline prices also averaged

suppliers to expect distillate prices to fall in the out 9 cents lower in April 1997 than in April 1996. From

loss.

! Unusually high demand for distillate occurred in July,

which detracted from the strong build in stocks that

normally occurs in this month.

In spite of increased crude runs during the fourth quarter, the

increased distillate yields lowered gasoline production from

crude oil over that produced from crude oil fourth quarter

1995. Only by increasing inputs of imported blending

components was refinery gasoline production brought back

to levels similar to those in 1995. Finished gasoline imports

also added to supply, but gasoline stocks dropped much

lower than normal in October and declined even further in

November when they traditionally increase. December and

January builds in stocks were more typical, but by this time,

gasoline stocks were running well below normal levels.

Price Reversal in Spring 1997

The petroleum markets in spring 1997 completed the story

of the spring 1996 runup with a price reversal, providing an

excellent opportunity to watch the dynamics described in this

chapter work when crude market factors moved in the

opposite direction. Table 1 summarizes some major market

factors for comparison. (The following box on p. 46 presents

a discussion of whether the crude price increase in the spring

of 1996 heralds increased volatility in the future.)

In qualitative terms, the supply/demand balance for gasoline

in spring 1997 was almost the same as in spring 1996:

demand growth was low to modest; levels of gasoline

production from January through April supplied about 96

percent of demand in both years; imports were very high in

1996 and even higher in 1997; and stocks were low. Prices,

on the other hand, behaved very differently. Prices rose

dramatically during spring 1996, but fell during spring 1997,

even though gasoline spot price spreads were slightly higher

with crude oil prices and normal seasonal spread changes —

crude oil prices in April averaged 9 cents lower than in April

December 1996 through April 1997, crude oil prices fell 13.5

cents per gallon, and spot gasoline prices fell 11.3 cents as

the impact from declining crudes price was moderated by

normal increases in seasonal spreads.

Energy Information Administration (EIA), “Distillate Fuel Oil 13

Assessment for Winter 1996-1997,” Petroleum Supply Monthly, DOE/EIA0109(96/11) (Washington, DC, November 1996), pp. xv-xxiii.
Energy Information Administration / Petroleum 1996: Issues and Trends 45

Table 1. Spring 1997 and Spring 1996 Summary Market Comparison

Market Factor January-April 1996 January-April 1997

World Petroleum Supply/ Winter stock draw was high. Winter stock draw was low.

Demand Balance

Strong world economy supported petroleum Strong world economy supported petroleum

demand. demand.

Cold weather increased winter demand more Winter demand was held in check by milder

than expected (3 percent higher than in winter weather (1.8 percent higher than in winter

1994-95). 1995-96).

Supply growth was less than expected. Supply growth was strong.

Crude Supply Iraqi entry into market was delayed. Iraq began sales in December ‘96.

Non-OPEC additions were expected, but did Non-OPEC supply increased, and more was

not arrive. expected.

Light crude was abundant. Abundance of light crude grew.

Crude Markets Prices began 1996 under $20.00 per barrel. Prices began 1997 about $26.00 per barrel

after high demand fourth quarter.

Tight: Prices rose February thru April with Weakening: Prices fell January through April

cold weather and lack of expected supplies. with strong supplies relative to demand.

Futures market backwardation was steep. Term structure of crude futures flattened.

Light-heavy price differentials were modest. Light-heavy price differentials were very small.

U.S. Winter Distillate Winter began with stocks normal, but ended Winter began with stocks low. Demand was

March with stocks lower than normal due to met through extra production, and winter ended

cold weather. with stocks at normal levels due to mild

weather.

April: With little or no discretionary stocks, April: Although demand was strong, no

late cold weather caused refiners to re-focus unexpected re-focusing on distillate production

on distillate production. occurred. 

U.S. Gasoline Stocks were low. Stocks were very low.

Supply/Demand Balance

Demand growth was modest (1.1 percent). Demand growth was low to modest (0.8

percent).

Demand level was high (7,601 thousand Demand level was high (7,710 thousand

barrels per day). barrels per day).

Production growth was modest. Production growth was modest.

Imports were high (meeting 5.8 percent of Imports were very high (meeting 7.6 percent of

demand). demand).

Gasoline Market Increasing crude oil prices pushed gasoline Falling crude oil prices brought gasoline prices

prices up. down.

Spreads were mainly at or below seasonal Spreads were slightly above seasonal norms.

norms.

Source: Energy Information Administration.
1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

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Cents per Gallon

Bonny Light Crude Oil

Gulf Coast Regular Gasoline

46 Energy Information Administration / Petroleum 1996: Issues and Trends

Weekly Average Spot Prices

Source: Standard & Poor’s Platts.

Was the Spring Crude Price Increase a Sign of Future Increased Volatility?

Is the situation experienced in Spring 1996 just another sign of growing price volatility, and will we see more of the same

in the future? In short, the crude market supply/demand balance was fairly tight in 1996, which creates an environment for

exaggerated price swings. Demand was high, excess production capacity was not available, and world petroleum stocks

were lower than average. When unexpected events occur in tight markets, such as the late winter cold snap in 1996, that

affect the perceived availability of crude oil, buyers are more likely to over-react, creating large price swings. 

In spring 1996, a number of unusual factors acted simultaneously to increase buyers concern over crude availability,

including unusual late cold weather and expectations for large price declines in the near future, which encouraged keeping

low stocks. While these specific triggers may not occur again to drive prices up temporarily, other factors can create the

same effect during a tight market. As discussed in this chapter, the transition time between the end of winter, when world

crude and product stocks are low, and the beginning of the U.S. high gasoline demand season is a vulnerable period. Events

during that crucial time period can have a large influence on the market.

In the short-term, crude inventories began to recover worldwide over the winter. World petroleum demand only increased

1.4 million barrels per day over winter 1995-96, while supply increased 2.3 million barrels per day (preliminary estimates).

Crude oil prices averaged $25.41 per barrel in December, but began falling in January. By April, WTI averaged $19.75.

Although the crude market is loosening, world petroleum stocks do not seem to be in excess, so there is still some potential

for price increases. As new supply grows, the probability of sharp price movements will diminish, since buyers will perceive

higher crude availability, and thus no need to bid prices higher to assure supply when unexpected events occur.

When viewed over the long term (see figure), crude prices were strong in 1996, but not especially more volatile than many

other times in history. The short-term price swing that occurred last spring was a little sharper and higher than most swings

seen in Figure 14, but was not dramatically out of line with past price variations. It occurred at a time that was very visible

to consumers — just when gasoline prices normally increase, and the market had not seen the magnitude of such swings

for several years. 
Dec Jan Feb Mar Apr

0

10

20

30

40

50

60

70

80

1997

C ents per Gallon

67.6 67.2 62.0 60.7

56.3

60.5 59.8

52.8

49.9

47.0

1996

W es t Te xas Interm edia te C rude (W T I)

Average Spread (NYH G asoline M inus W TI)

Actual

Dec Jan Feb Mar Apr

0

10

20

30

40

50

60

70

80

1996

C ents per Gallon

52.1 52.8

58.3

65.3

W es t Te xas Interm edia te C rude (W T I)

Average Spread (NYH G asoline M inus W TI)

Actual

49.9

1995

45.3 44.8 45.5

50.8

56.0

Energy Information Administration / Petroleum 1996: Issues and Trends 47

Figure 32. Spring 1996 Gasoline Price Summary

(NY Harbor Spot Conventional Regular)

Source: Standard & Poor’s Platts.

Figure 33. Spring 1997 Gasoline Price Summary

(NY Harbor Spot Conventional Regular)

Source: Standard & Poor’s Platts.
1993 1994 1995 1996 1997

0

10

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30

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60

70

80

90

Cents per Gallon

U.S. Average Regular Retail 

Excl. Taxes

New 

York 

Harbor 

Regular 

Spot

WTI Spot

48 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 34. Weekly Conventional Gasoline and Crude Oil Prices

Sources: Spot Prices: Standard & Poor’s Platts. Retail Prices: Energy Information Administration (EIA), Form EIA-878, “Motor Gasoline Price

Survey.”

In spring 1997, crude oil markets finally seemed to be ending per day during winter 1996-97, compared to 2.0 million

the tight supply/demand cycle that drove prices up in 1996. barrels per day the previous winter. With world stock levels

During the winter of 1995-96, oil product demand was high appearing to recover to more normal levels, crude oil prices

due to cold weather, while supplies of crude oil were less fell considerably through the spring of 1997, pulling gasoline

than expected. Prompt markets were tight during the spring, prices down. While strong backwardation persisted

pushing crude oil prices higher, when a late cold snap caused throughout most of 1996, crude oil term structures in March

prices to leap even higher to peak in April. Strong and April 1997 were relatively flat. 

backwardation in crude oil futures persisted through 1996 as

buyers kept expecting the tight prompt markets to loosen Gasoline stocks in spring 1997 were even lower than in

with new supplies and lower demand. With buyers expecting spring 1996, which put more pressure on gasoline spreads in

prices to fall, building stocks was discouraged. 1997 than in 1996. While gasoline spreads were relatively

Winter 1996-97 was almost a mirror image of winter 1995- slightly above average in 1997, reflecting the extra tightness.

96. As winter 1996-97 began, world petroleum stocks were

still low, so increased demand in the fourth quarter, coupled Retail prices averaged 17.9 cents higher in December 1996

with sluggish supply growth, again pushed crude prices up, than in 1995, but by April, were 3.3 cents lower in 1997 than

reaching levels at the end of December higher than in April in 1996. Retail prices, which lag behind the change in spot

1996. But the weather in winter 1996-97 was not as severe prices, had fallen 5.5 cents from December 1996 through

as the prior winter. In addition, Iraqi production entered the April 1997. Thus, consumers in the spring of 1997

market in December and other supplies increased, taking the experienced falling gasoline prices, after the dramatic

pressure off prices. EIA preliminary estimates indicate that increase in prices experienced in spring 1996.

the world petroleum stock draw was only 1.1 million barrels

low during the first part of 1996, they have been at or
Energy Information Administration / Petroleum 1996: Issues and Trends 49

The U.S. is heavily reliant on the world crude oil market, which has been subject to huge inter-annual volatility

since 1973. Neither of these facts is likely to change. Domestic crude oil production declined over the past

decade, while domestic crude oil demand increased. The difference was satisfied by increased crude oil

imports. The United States’ proved crude oil reserves declined more than 21 percent from 1985 to 1995. Its

technically recoverable crude oil resources beyond proved reserves are estimated to be about 6 times more

than the year-end 1995 proved reserves. However, excepting the Gulf of Mexico and the Alaskan offshore,

many of the most promising oil-prone regions of the country are presently off-limits to exploration. Over the

long term — beyond 2020 or so — the United States will be increasingly unable to satisfy its crude oil

requirements from domestic sources. Imported volumes and world oil prices can both be expected to rise over

time, and much of the new imports will have to be obtained from the Persian Gulf region.

3. Oil Supply: U.S. Perspective on a Global Market

The market for crude oil is global. To varying degrees, every rise, however, from 16.3 billion barrels in 1986 to 18.2

continent on Earth except Antarctica is both a producer and billion barrels in 1996. The difference was satisfied by

a consumer of crude oil. For a host of reasons having to do increased imports, which have exceeded domestic production

with factors such as how supply and demand evolved over since 1994.

time relative to the location and discovery sequence of

commercially exploitable conventionally reservoired The U.S. is the most intensely explored and developed oildeposits, as well as rates of progress in the geosciences and productive nation on Earth. In 1986 there were 623,000

petroleum engineering, the price of crude oil remained producing oil wells with an average daily production rate of

remarkably stable from the early 1900's through 1973 at less 13.9 barrels of oil. By 1995, both the number of producing

than $15 per barrel in constant 1992 U.S. dollars (Figure 35). wells and their quality had declined. Eight percent fewer

For much of the time prior to 1959 the real (inflation wells (574,000) were producing at an average daily rate of

adjusted) price was substantially less. 11.3 barrels of oil (down almost 19 percent). The petroleum

After 1973 the coupling of significant concentrations of summarized in the box on p. 51.

supply-side market power with short-term inelasticity of

demand and regional conflicts rendered the world crude oil Regionally, while relative levels of production for the lower

market subject to huge inter-annual volatility. The resulting 48 States and Alaska remained about the same, total

post-1970 world crude oil price path, represented by the production fell 26 percent in the former and 21 percent in the

nominal U.S. refiner acquisition cost of imported crude oil, latter over the 1985-1996 period. Onshore production fell 30

is shown in Figure 36. It is annotated with significant events percent over the period and its share of total production also

that affected the market, the U.S. actions taken in response fell by 6 percent, while offshore production increased by

to them, and the domestic environmental and energy almost 8 percent (Figure 38).

conservation measures referred to or discussed in the other

chapters. In keeping with the other chapters’ short-term The above statistics in part reflect continuing depletion of

horizon, the following sections of this chapter primarily the Nation’s crude oil resource endowment, but other factors

address the past decade, which began with the crude oil price are influencing this trend. The size of new field discoveries

collapse of 1986. is economically important because lifting costs per unit of

Oil Production

Domestic Production Is Declining

While Demand Is Increasing

Domestic crude oil production declined over the past decade

from a level of 10.2 billion barrels in 1986 to 8.6 billion

barrels in 1996 (Figure 37). Domestic demand continued to

products that can be refined from this crude oil are

production fall in response to increasing field size. In

general, the largest fields in a new exploration area are

among the first to be discovered. Therefore, since the

onshore lower 48 States are the most intensively explored

area on Earth, the remaining undiscovered oil resources

occur in mostly small- to medium-size fields. During the

1985-1995 period oil exploration was prohibited or restricted

in most of the few remaining domestic areas where large

fields remain to be found, such as the 1002 Area within the

Arctic National Wildlife Refuge (ANWR) and the southern

California offshore. These restrictions resulted in an inability
1959 1964 1969 1974 1979 1984 1989 1996

0

10.00

20.00

30.00

40.00

50.00

Real Dom estic Oil Price

(1992 Dollars per Barrel)

1994

1991:

Dissolution

 of USSR

1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996

0

10.00

20.00

30.00

40.00

(Dollars per Barrel)

1970

1996:

Spring Gasoline

 Price Jump

1992:

Energy Policy Act

Phase II RVP

 Regulations Implemented

CAAA's CO2 Nonattainment

 Program Implemented

1978:

Iranian Revolution

CAFE Standards

 Implemented Under EPCA

Airlines Deregulation Act

Power Plant and Industrial

 Fuel Use Act

U.S. Petroleum Demand

 Peaks

1973:

Arab Oil Embargo

Emergency Petroleum

 Allocation Act (EPAA)

1990:

Persian Gulf Crisis

CAA Amendments

Oil Pollution Act

1981:

Petroleum Price and

 Allocation Decontrol

1985:

Netback Pricing

1986:

Crude Oil Price Collapse

1974:

Introduction of Unleaded

 Motor Gasoline per CAA

Additional EPAA Programs

1989:

Valdez Oil Spill

Phase I RVP

 Regulations

 Implemented

1970:

Clean Air Act

 (CAA)

U.S. Crude Oil

 Production

 Peaks

Nominal World Oil Price

1975:

Energy Policy and

 Conservation Act

 (EPCA)

50 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 35. Real Domestic Oil Price, 1959-1996

Note: Price taken to be the crude oil domestic first purchase price.

Sources: Energy Information Administration (EIA), Annual Energy Review, 1995; and EIA, Monthly Energy Review (March 1997).

Figure 36. World Oil Price and Related Events, 1970-1996

Note: World oil price taken to be the U.S. refiner acquisition cost of imported oil.

Source: Energy Information Administration, Annual Energy Review, 1995; and Monthly Energy Review (March 1997). Adapted from The

U.S. Petroleum Industry: Past as Prologue, 1970-1992.
1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996

0

4

8

12

16

20

M illion Barrels per Day

Net Imports

Dem and (Assumed to Equal

Products Supplied)

Total Production

Energy Information Administration / Petroleum 1996: Issues and Trends 51

Source: Energy Information Administration, Annual Energy Review, 1995.

Figure 37. U.S. Petroleum Supply and Demand, 1970-1996

The Average 1995 U.S. Oil Well Gave Us:

Production of 11.3 barrels per day, which a refinery converted into:

6 barrels per day of motor gasoline

1.1 barrels per day of jet fuel

2.5 barrels per day of distillate fuel oil

0.6 barrels per day of residual fuel oil

2 barrels per day of heavier refined products (lubes, waxes, asphalt, road oil, etc.)

Simultaneous use of these refined products could have provided:

5,292 miles of highway travel in the average U.S. automobile. (Equivalent to the shortest round trip

between Miami and San Francisco plus 56 in-town miles, or to 2000 2.6 mile utility trips.)

 24 miles of air travel in a B737-700 passenger jet

62 average oil-heated homes kept comfortable on an average day

78 kilowatt hours of electricity generated with steam produced by a residual fuel oil fired boiler.

(Enough electricity to power 269 light bulbs of 75 watts through one four-hour evening.)

Minimal amounts of some of the thousands of useful things made from the heavier refined

petroleum products listed above

The Bottom Line Is:

A day’s production from the average U.S. oil well provides many useful products, but it does not provide much of them. Due to its

very large number of low yield wells, the United States nevertheless ranked second in the world in 1995 oil production. In Saudi

Arabia, the number one oil producing nation in 1995, the average oil well produced 5,800 barrels per day, or 516 times more than

the average U.S. well.
O nshore O ffshore Low er 48 A laska

0

1

2

3

4

5

6

7

8

9

M illion B arrels per D ay

1985

1996

52 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 38. U.S. Crude Oil Production by Site, 1985 and 1996

Sources: 1985: Energy Information Administration, Annual Energy Review, 1995. 1996: Monthly Energy Review (March 1997).

to maintain domestic lifting costs associated with new fields increase is largely attributable to the member states of the

at a worldwide competitive level from 1983 to 1991. The Organization of Petroleum Exporting Countries (OPEC),

largest U.S. exploration and production firms — and many where production increased 46.5 percent. The production of

smaller ones — therefore increasingly focused their the Persian Gulf members of OPEC, which accounted for 65

exploration and development effort and budgets on more percent of 1996 OPEC production, increased by 48.5 percent

economically promising prospects located abroad. Trends in in the same period. There was a slight decline in non-OPEC

lifting costs, exploration, and development expenditures are production because increased output from such areas as the

portrayed by the Energy Information Administration’s North Sea and the Pacific Rim was more than offset by

Financial Reporting System, an annual survey of major U.S. declining production in mature producing areas such as the

energy-producing companies (see Figures 39, 40, and 41). former Soviet Union and the United States (Figure 43).

The majors’ shift away from the United States is also Figure 44 shows the recent production trends of the four

mirrored in Figure 42, which shows the quantities and largest oil producing countries. Saudi Arabia’s production

location of production for majors and non-majors in the U.S. more than doubled during the first part of the past decade,

The majors’ share of domestic onshore production has fallen while the Soviet Union/former Soviet Union’s production

steadily since 1985, by about 25 percent or 300 million decreased by half. Table 2 shows the worldwide production

barrels per year overall. Some of that production was taken of the 20 leading companies in 1972 and 1995, when they

over by smaller operating firms that had lower overheads. respectively accounted for 74.6 and 63.1 percent of world

The majors invested the proceeds from the sale of some of production. The change in the names and rankings of the top

their onshore U.S. properties primarily in frontier exploration 20 firms reflects the spate of nationalizations or

and development projects located abroad and in the deep expropriations that took place in the mid-1970s. 

water Gulf of Mexico.

OPEC Leads Increase in International

Production

Over the past decade world crude oil production increased

almost 14 percent to 64 million barrels per day in 1996. This

Oil Reserves

Proved reserves are those volumes of oil that geological and

engineering data demonstrate with reasonable certainty to be

recoverable in future years from know reservoirs under

existing economic and operating conditions.
1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

2

4

6

8

10

12

14

16

Billion (1995 Dollars)

Domestic

Foreign

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

3.00

3.50

4.00

4.50

5.00

5.50

6.00

6.50

7.00

1995 Dollars per Barrel of O il Equivalent

U nited States

Foreign

Energy Information Administration / Petroleum 1996: Issues and Trends 53

Figure 39. Direct Oil and Gas Lifting Costs for FRS Companies, 1981-1995

Note: Includes expenditures for unproved acreage.

Source: Energy Information Administration, Financial Reporting System (FRS), Form EIA-28.

Figure 40. Exploration Expenditures by FRS Firms, 1985-1995

Source: Energy Information Administration, Financial Reporting System (FRS), Performance Profiles of Major Energy Producers 1995.
1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

2

4

6

8

10

12

14

16

18

20

22

Billion (1995 Dollars)

Domestic

Foreign

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

200

400

600

800

1,000

1,200

1,400

Million Barrels per Day

Lower 48 Majors Onshore

Lower 48 Nonmajors O nshore

Alaska (Majors)

Lower 48 Majors Offshore

Lower 48 Nonm ajors Offshore

54 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 41. Development Expenditures by FRS Firms, 1985-1995

Source: Energy Information Administration, Oil and Gas Development in the United States in the Early 1990's (October 1995), and Financial

Reporting System. 

Figure 42. Majors and Nonmajors, U.S. Oil Production by Region, 1985-1995

Note: Includes expenditures for proved acreage.

Source: Energy Information Administration, Financial Reporting System (FRS), Form EIA-28.
1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

2

4

6

8

10

12

14

Million Barrels per Day

Iran

Saudi Arabia

Russia

United States

Former U. S. S. R.

W orld Tota l O P E C P ersian G ulf O P E C N on-O P E C

0

10

20

30

40

50

60

70

M illion Barrels per Day

1985

1996

Energy Information Administration / Petroleum 1996: Issues and Trends 55

Figure 43. World, OPEC, and Persian Gulf Oil Production, 1985 and 1996

Source: Energy Information Administration, Monthly Energy Review (March 1997).

Figure 44. Leading World Oil Producers, 1985-1996

Source: Energy Information Administration, Monthly Energy Review (March 1997).
56 Energy Information Administration / Petroleum 1996: Issues and Trends

Table 2. Worldwide Crude Oil Production of 20 Leading Companies, 1972 and 1995

(Thousand Barrels per Day)

1972 1995

Company Production Total Company Production Total

Percent of Percent of

Worldwide Worldwide

Exxon Corp. 4,968 10.8 Saudi Arabian Oil 8,585 13.8

British Petroleum 4,664 10.1 National Iranian Oil Co. 3,720 6.0

Royal Dutch/Shell 4,169 9.0 Petroleos de Venezuela 2,885 4.6

Texaco Inc. 3,777 8.2 China National Petroleum 2,796 4.5

Chevron Corp. 3,232 7.0 Petroleos Mexicanos 2,722 4.4

Gulf Oil 3,214 7.0 Royal Dutch/Shell 2,254 3.6

Mobil Corp. 2,316 5.0 Kuwait Petroleum Corp. 2,070 3.3

Communist Bloc 1,301 2.8 Exxon Corp. 1,726 2.8 a

CFP (Total - France) 977 2.1 Libya National Oil Company 1,345 2.2

Sonatrach (Algeria) 925 2.0 Abu Dhabi National Oil Co. 1,300 2.1

Amoco Corp. 815 1.8 Sonatrach (Algeria) 1,283 2.1

ARCO 652 1.4 British Petroleum 1,283 2.1

DuPont (Conoco) 594 1.3 Nigerian National Petroleum 1,200 1.9

USX Corp. (Marathon) 453 1.0 LUKoil (Russia) 1,116 1.8

Petroleos Mexicanos 440 1.0 Pertamina (Indonesia) 1,065 1.7

Occidental Petroleum 443 0.9 Chevron Corp. 1,001 1.6

Getty Oil 443 0.9 Mobil Corp. 810 1.3

Sun Co. 369 0.8 Elf Aquitaine (France) 764 1.2

Unocal Corp. 365 0.8 Texaco Inc. 762 1.2

Phillips Petroleum Co. 337 0.7 Yokos (Russia) 722 1.2

Top 20 Total 34,434 74.6 Top 20 Total 39,409 63.1

Worldwide Total 46,170 100.0 Worldwide Total 62,446 100.00 a

For 1972, only non-communist world oil production and communist bloc (including China) exports to the non-communist world are included, while a

1995 includes total world production. Sum of components may not equal totals due to independent rounding. Shares were calculated based on

unrounded data.

Sources: Energy Information Administration (EIA). 1972: EIA, Performance Profiles of Major Energy Producers 1993. 1995: EIA, Financial

Reporting System.

Domestic Reserves Declined Over the

Past Decade

In the past decade, the United States’ proved reserves of

crude oil have fallen gradually, declining over 21 percent

from 28.4 billion barrels in 1985 to 22.3 billion barrels in

1995 (Figure 45). The last inter-annual increase, amounting

to about 400 million barrels, occurred between 1986 and

1987. As Figure 46 indicates, proved reserves of crude oil

increased only in the offshore Gulf of Mexico during the

decade.

This reserves record is primarily attributable to the sharp

decrease in drilling caused by the 1986 collapse of crude oil

prices, which declined 49 percent worldwide and 51 percent

in the domestic market (Figure 47). Domestic crude oil 14

well completions dropped 47 percent in 1986 alone, from

35,021 in 1985 to 18,701, while exploratory oil well

completions similarly declined from 1,879 in 1985 to 988

(Figure 48). A secondary factor was the shift toward gas

drilling that took place during the period. After 1992 natural

gas rather than crude oil became the dominant domestic

drilling target.

Restrictions on oil exploration in many of the most

prospective oil-prone places left in the United States, due to

environmental considerations, also contributed to the decline

of domestic proved crude oil reserves. Alaska on- and

offshore, the Gulf of Mexico, and the far western United

States are the only regions of the country in which 15

undiscovered conventional oil and gas resources sufficiently

large to be of long term national supply significance remain

to be found and converted to supply at low levels of unit cost

relative to other current and foreseeable oil and gas supply

alternatives. This is consistently shown by:

Energy Information Administration, U.S. Crude Oil, Natural Gas, and 14

Natural Gas Liquids Reserves, Annual Report 1995, DOE/EIA-0216(95),

Table 3, p. 10. offshore California, Idaho, Nevada, and parts of Utah and New Mexico.

On- and offshore Washington, on- and offshore Oregon, on- and 15
1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

5

10

15

20

25

30

Billion Barrels

Lower 48 Onshore

Lower 48 O ffshore

Alaska

U S Total

Alaska Gulf of M exico

O ffshore

0

1

2

3

4

5

6

7

8

Billion Barrels per Day

1985

1996

Te xas C alifornia All Other

Areas

Energy Information Administration / Petroleum 1996: Issues and Trends 57

Figure 45. Domestic Crude Oil Proved Reserves, 1985-1995

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1995.

Figure 46. Crude Oil Proved Reserves by Area, 1985 and 1996

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1995.
1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

10

20

30

40

Number of Wells (Thousands)

Oil Completions

Gas Completions

Dry Holes

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

400

800

1,200

1,600

2,000

Well Completions

58 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 47. Domestic Oil and Gas Well Completions, 1985-1996

Source: Energy Information Administration, Monthly Energy Review (March 1997).

Figure 48. Domestic Exploratory Oil Well Completions, 1985-1995

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1995.
Energy Information Administration / Petroleum 1996: Issues and Trends 59

! periodic estimates of domestic undiscovered oil and gas end reserves to annual production (R/P) was 49.2. This

resources produced by the United States Geological statistic, often inaccurately and misleadingly termed a

Survey and the Minerals Management Service; “reserve life index,” does NOT imply that the world’s year- 16

! biennial estimates of natural gas resources prepared by

the industry-based Potential Gas Committee; 17

and is demonstrated in the EIA publication Geologic

Distributions of U.S. Oil and Gas. However, the most oil- production and provides some location-specific R/P ratios. 18

prospective areas of onshore Alaska and offshore California

have for years been administratively or legislatively declared

off-limits to oil and gas exploration. 

A factor that prevented the Nation’s 1995 crude oil reserves

situation from being worse was that discoveries per

exploratory well completion generally increased over the

decade (Figure 49). This occurred in part because the lower

overall level of drilling permitted “high grading” of the

portfolio of prospects available to the industry, and in part

was due to the introduction of several new technologies that

increased the drilling success rate or otherwise reduced

either the risk or cost of upstream operations (see box, p. 61).

International Reserves Are Much

Larger Than U.S. Reserves

Crude oil resources and the reserves derived from them are

unevenly distributed over the globe. Based on country-bycountry estimates of crude oil reserves and production

compiled from multiple sources by DeGolyer and

MacNaughton , the world’s reserves of crude oil were 19

1,114.7 billion barrels at year-end 1994 while 1994 world

production was 22.632 billion barrels. The distribution of

these quantities is shown in Table 3 for the continents and

the Middle East region. The 1994 worldwide ratio of yearend 1994 reserves will be exhausted in 49.2 years. The 1994

reserves base will instead produce at generally decreasing

levels to well beyond 2050. The R/P statistic is more useful

for comparative purposes. Table 3 indicates the general

worldwide 1994 distribution of crude oil reserves and

The United States’ R/P of 9.3 was the lowest of any major

oil- producing country or area. This reflects the fact that the

United States is the most intensively explored country in the

world, having been the first to achieve an annual production

rate of a billion barrels per year.

Oil Resources

Estimates of recoverable oil resources are subject to a greater

degree of uncertainty than are estimates of proved reserves.

They include, in addition to proved reserves, oil that is yet to

be discovered and other classes of reserves that are generally

less precisely quantifiable than proved reserves. Their

eventual recovery is less assured.

Domestic

Based on year-end 1993 data for onshore and state

jurisdiction offshore areas and year-end 1994 data for

Federal jurisdiction offshore areas, the Department of the

Interior’s 1995 mean (expected value) estimate of

undiscovered recoverable plus inferred resources of domestic

crude oil was 132 billion barrels. This volume includes 20

both anticipated new field discoveries and the expected

appreciation of the ultimate recovery estimates of existing

fields for both conventional and unconventional types of

deposits. It is about 6 times larger than year-end 1995 proved

reserves.

International

The Federal government’s estimates of world oil and gas

resources are produced by the United States Geological

Survey’s (USGS’s) World Energy Resources Program

(WERP). The latest estimate, dated January 1, 1993, is that

a mean (expected value) of 547 billion barrels of technically

United States Geological Survey, Geological Estimates of Undiscovered 16

Recoverable Oil and Gas Resources in the United States, Circular 725

(Washington, DC, 1975); United States Geological Survey, Estimates of

Undiscovered Recoverable Conventional Oil and Gas Resources in the

United States, Circular 860 (Washington, DC, 1981); United States

Department of the Interior, U.S. Geological Survey, and Minerals

Management Service, Estimates of Undiscovered Conventional Oil and Gas

Resources in the United States -- A Part of the Nation’s Energy Endowment

(Washington, DC, 1989); United States Geological Survey, 1995 National

Assessment of United States Oil and Gas Resources, Circular 1118

(Washington, DC, 1995); Minerals Management Service, An Assessment of

the Undiscovered Hydrocarbon Potential of the Nation’s Outer Continental

Shelf, OCS Report MMS 96-0034 (Washington, DC, 1996). 

Potential Gas Committee, Potential Supply of Natural Gas in the United 17

States, biennial series through 1996, (Golden, CO). 

Energy Information Administration, Geologic Distributions of U.S. Oil 18

and Gas, DOE/EIA-0557 (Washington, DC, July 1992).

DeGolyer and MacNaughton, “Estimates of Petroleum Reserves in Minerals Management Service, An Assessment of the Undiscovered 19

Principal Producing Countries and Crude Oil Production in 1994,” Twentieth

Century Petroleum Statistics, (Dallas, TX, 1995), p. 1.

United States Geological Survey, 1995 National Assessment of United 20

States Oil and Gas Resources, Circular 1118, (Washington, DC, 1995);

Hydrocarbon Potential of the Nation’s Outer Continental Shelf, OCS Report

MMS 96-0034 (Washington, DC, 1996). 
1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0.0

0.5

1.0

1.5

2.0

M illion Barrels per Well

60 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 49. Domestic Crude Oil Discoveries per Exploratory Oil Well Completion, 1985-1995

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1995.

recoverable crude oil remains to be discovered worldwide ! 3-D seismic surveying technology has within the past

(Table 4). There is a 19 in 20 chance that at least 43 billion decade made it possible to accurately image reservoirs

barrels remain to be discovered, and a 1 in 20 chance that at located in the deep Gulf (i.e., in more than 1000 feet of

least 945 billion barrels remain to be discovered. water) and beneath the extensive salt sheets that occur in 21

The geographic distribution of the mean estimate is as

follows: 30.1 percent is expected to be located in the ! the development of new production technologies

Americas, 22.3 percent in the Middle East, 18.5 percent in applicable to deep water, such as tethered floating

the former Soviet Union, 14.8 percent in Asia-Oceania, 8.8 drilling and production platforms (tension leg platforms),

percent in Africa ex the Middle East, and just 5.5 percent in spar buoy-shaped production facilities, and sub-sea well

Europe, Western, and Eastern.

It should also be noted that those places with the highest

current R/P ratios, as shown in Table 3, also usually have the

highest estimated volumes of undiscovered oil resources.

This reflects two facts about these places: they are very oilrich; and, in most instances, exploration and development

began much later in them than in the United States.

Future Implications

The United States’ proved crude oil reserves could exhibit a

modest increase commencing this year or next given recent

developments in the Gulf of Mexico where:

the shallower portions of the Gulf;

completion and production systems, has made it

profitable to develop large deep water fields.

Also contributing to the possibility of a modest near-term

increase in domestic oil reserves are the efforts now

underway to find and/or develop the so-called “smaller” oil

reservoirs and fields peripheral to the existing giant

producing fields on the North Slope of Alaska, each of which

is a big field by lower 48 States-standards. However, in view

of the remaining undiscovered resource situation, the

continued restrictions on oil exploration in many highly

prospective oil-prone areas, and the inexorable if slow

growth of demand, this increase can only be temporary,

lasting a few years at most.

The industry is also engaged in a large effort to increase its

proved crude oil reserves in South America, which has shorthaul access to the United States market. Over the mid-term C.D. Masters, D.H. Root and E.D. Attanasi, Resource Constraints in 21

Petroleum Production Potential, Science, v. 253 (12 July 1991).
Energy Information Administration / Petroleum 1996: Issues and Trends 61

New Upstream Technologies: What They Deliver

Three-Dimensional Seismic Surveying

Three-dimensional seismic surveying (3-D), made possible by the computer revolution, improves the precision and content of geological

interpretations of the earth’s subsurface far beyond what the traditional two dimensional (2-D) seismic surveying methods provided. Widespread

implementation of 3-D in the past decade has led to a much higher ratio of successful wells to dry holes, particularly for exploratory wells. 

Horizontal Drilling, Measurement-While-Drilling, and Logging-While-Drilling

Horizontally-oriented wells typically produce at 3 to 5 times the rates achieved by conventional vertical wells drilled into the same reservoir. While

they are more difficult and expensive to drill, using them tends to approximately halve the average unit cost of development. They, along with

other kinds of directional drilling, also allow the industry to have a much smaller surface “footprint” because areas up to several square miles can

be tapped from a single drilling site. This characteristic of horizontal drilling is particularly important in frontier areas such as the Arctic and the

deep offshore, and in environmentally sensitive areas.

New downhole technologies which enabled the drilling of horizontal holes that stay within the target formation include measurement-while-drilling

(MWD) and logging-while-drilling (LWD) systems. MWD systems allow real-time acquisition of previously unavailable data related to the drilling

operation itself such as weight-on-bit, mud pressure, torque, vibration, and hole caliper, angle and direction. LWD systems allow real-time

acquisition of downhole resistivity and sonic and gamma ray measurements that rival those attainable via traditional progress-interrupting wireline

logging. These geophysical measurements can be simultaneously interpreted to determine rock type (sandstone versus shale versus carbonates)

and pore content (water versus hydrocarbons). Having this knowledge in real time allows path correction commands to be sent back down the

hole to a steerable motor located just behind the drill bit and just in front of the MWD and LWD tools. Thus, the position of the bit can now often

be controlled to within 2 feet of the intended (design) position.

Slim Hole Drilling

Slim hole drilling, the drilling of wells with smaller diameter bores than those drilled over the past several decades, is rapidly increasing. Major

technological strides have been made in downsizing the traditional suite of downhole instruments and tools without loss of effectiveness during

the last few years. The principal advantage of slim hole drilling is reduced cost. For example, steel is priced by the ton and 1,000 feet of

conventional 12.25 inch hole casing weighs 59 tons, while the equivalent length of 8.5 inch casing weighs only 29 tons. Similarly, lower costs

are associated with drill pipe, drill bits, fuel costs, mud chemicals, cement, cuttings cleaning and disposal, and elapsed drilling time to total depth.

Drilling With Coiled Tubing

Standard drill pipe comes in 30 foot lengths with threaded connections at the ends. It is typically stored on a drilling rig’s pipe rack in 90 foot

stands made up of 3 joints, which must be sequentially added to the drill string while drilling. Similarly the stands must be sequentially decoupled

to change the downhole tools and drill bit. “Tripping” to do so is a laborious, time consuming, expensive way to drill. Thanks to recent

developments in the material sciences standard drill pipe is being replaced in many drilling applications with coiled tubing. This is a continuous

length of pipe which is stored wrapped around a large reel. It is straightened off the reel over a curved guide to and through a motorized injector

head mounted atop the well control stack, and thence down the well. Coiled tubing wall thickness ranges from 0.2 to 0.5 inches depending on the

tubing’s diameter and the required load-bearing characteristics. Several thousand feet of coiled tubing can be run down or withdrawn from a hole

in tens of minutes rather than the many hours required to “trip” with standard drill pipe, providing substantial cost savings. Another advantage

over standard drilling technique is that fluid circulation in the hole can be maintained at all times, which helps to avoid a number of well control,

drilling, and well completion problems.

Nuclear Magnetic Resonance Borehole Imaging

Downhole tools have recently been developed that perform nuclear magnetic resonance (NMR) analysis of the hydrogen-containing fluids located

in near-borehole rock. NMR can quantitatively differentiate between (1) hydrogen atoms bound to clays, (2) hydrogen atoms included in water

molecules, and (3) hydrogen atoms included in hydrocarbon molecules. This knowledge enables both better well completion design and the

completion of thinner productive zones than before. 

Integrated Teams and Petroleum System Modeling

Prior to the 1980s, most oil and gas firms were structured in such a way that their exploration geologists and their geophysicists had minimal

contact with each other and neither group talked to the development geologists and production staff. Each had separate sets of data and there was

little communication. This situation has radically changed, in most firms, for the better. Exploration and development teams consisting of all

disciplines operate off the same computer-housed data base, thereby avoiding disconnects and bringing the best thinking of all involved in finding,

developing and producing a field or reservoir to bear at the same time. Adjunct to this approach is the developing area of petroleum systems

modeling, which has been made possible by the advent of fast computers capable of massive processing tasks. A petroleum system consists of

the source rocks, migration pathways, traps, and seals required to generate, accumulate, and preserve oil or gas in the subsurface. These elements

of a petroleum system have to have occurred in an appropriate time relationship for a commercially exploitable oil or gas reservoir to be present.

It has now become possible to model the generation of oil and/or gas from the kerogen present in the source rocks, the formation of overlying

traps and their seals, the expulsion of oil or gas from the source rocks, and migration to the traps. While such models are as yet fairly rudimentary,

and much more data and therefore even faster computers are needed to improve them, only individual components had been modeled before.

Integrated petroleum system modeling is a major improvement that helps to avoid technical disconnects in the analysis of the system. In several

instances it has demonstrably reduced the required exploration expenditures and speeded the exploration process by accurately indicating what

traps within the target system were likely to be commercially productive.
62 Energy Information Administration / Petroleum 1996: Issues and Trends

Table 3. Distribution of Crude Oil Reserves and Production with Corresponding Local R/P Ratios, 1994

Area/Country Reserves Production R/P Ratio

Percent of World Percent of World

North America 7.28 18.11 20.0

United States 2.01 10.74 9.3

South America 7.33 8.20 43.1

Venezuela 5.82 4.17 68.5

Europe 3.28 9.38 17.2

United Kingdom and 2.91 8.1 17.6

Norway

Former Soviet Union 17.15 11.84 71.6

Africa 6.53 10.73 30.2

Nigeria 1.54 3.06 25.0

Middle East 53.69 30.69 86.0

Saudi Arabia 23.32 12.86 89.3

Asia-Oceania 4.75 11.04 21.0

Note: R/P = Year-end reserves divided by annual production.

Source: Derived from DeGolyer and MacNaughton, “Estimates of Petroleum Reserves in Principal Producing Countries and Crude Oil Production

in 1994," Twentieth Century Petroleum Statistics (Dallas, TX, 1995), p.1.

this source of crude oil supply, particularly from Venezuela, limited long-term domestic capability to produce crude oil

will be significant for the United States. However, South and increasing demand, the United States will become

America is estimated to have only about 7 percent of the increasingly reliant on imported crude oil.

world’s undiscovered conventional crude oil resources. It is

not therefore expected to be a major source of long-term There continues to be a lack of economical substitutes for the

supply unless and until means can be developed to the products derived from crude oil, most particularly motor

economically tap its large known resources of heavy oil. gasoline. This, in concert with the anticipated rapid growth

Regardless of what transpires in relation to exploitation of lead to increasing international competition for crude oil.

the United States’ remaining domestic crude oil resources, it Future crude oil imports will therefore likely be obtained at

is clear that the upstream sector of the petroleum industry increasing prices until such time as a cap is placed on world

has increasingly focused on foreign opportunities over the crude oil prices by one or more of the emerging natural gaspast decade. As noted earlier and shown in Figure 39, the to-liquids, coal-to-liquids, or heavy oil recovery

direct lifting costs of EIA’s Financial Reporting System technologies.

(FRS) companies, which include all of the domestic majors,

were lower abroad than they were in the United States from As a consequence of the natural distribution of petroleum

1983 to 1991. Since 1991 there has been no important resources, much of the United States’ out year-supply will

distinction between foreign and domestic lifting costs, but have to be imported from the Persian Gulf region, which has

there has been no change in the emphasis on foreign a history of supply disruptions induced by political events.

operations. And, as shown in Figures 40 and 41,

expenditures by the majors on foreign operations increased

for both exploration and development from 1987 through

1990-1991, flattened out or declined slightly for two to three

years, and then began to increase again slightly. The majors

are simply following the available resource base on a world

scale, enabled by the liberalization/rationalization of

ownership, leasing, and tax policies that was initiated by

many oil-prospective countries during the past decade.

Over the long term — beyond 2020 or so — the United

States will be increasingly unable to satisfy from domestic

sources its requirements for crude oil. Considering the

22

of petroleum product demand in developing countries, will23

Comparison of crude runs to domestic stills with domestic crude oil 22

production indicates that the U.S. has not come within 10 percent of being

crude oil self-sufficient since 1957, and that there has been a pronounced

reduction of self-sufficiency since 1982, to the point that 53 percent of 1995's

crude runs were of a foreign origin. While it is highly improbable that the

U.S. can attain crude oil self-sufficiency again, it remains possible to assert

some control over the magnitude and timing of future insufficiencies.

Energy Information Administration, International Energy Outlook 23

1997, DOE/EIA-0484(97), (Washington, DC, April 1997).
Energy Information Administration / Petroleum 1996: Issues and Trends 63

Table 4. Estimates of Worldwide Cumulative Production, Identified Reserves, and Undiscovered

Technically Recoverable Resources of Conventional Crude Oil

(Billion Barrels)

Area 1/1/93 1/1/93 Resources

Cumulative Production Identified Reserves Mean Undiscovered

North America 182.8 83.0 121

Canada 14.3 7.0 33

Mexico 15.7 27.4 37

United States 152.7 48.5 49

Other 0.1 0.1 1

South America 57.9 43.8 44

Argentina 4.9 2.3 2

Brazil 2.5 2.8 9

Venezuela-Trinidad 43.9 34.4 20

Other 6.7 4.3 14

Europe 22.5 28.9 30

Netherlands 0.5 0.2 0

Norway 3.1 11.0 13

United Kingdom 8.6 13.5 11

Other Western Europe 3.5 2.2 4

Eastern Europe 6.8 2.0 2

Former Soviet Union 103.6 80.0 101

Africa 46.4 58.7 48

Algeria 9.1 8.4 2

Angola 1.3 2.0 2

Egypt 4.4 4.6 5

Libya 15.9 22.4 8

Nigeria 12.4 16.0 9

Other 3.2 5.3 21

Middle East 160.2 584.8 122

Iran 36.1 63.0 22

Iraq 19.9 99.0 45

Kuwait 23.3 96.0 3

Saudi Arabia 55.8 255.0 41

United Arab Emirates 11.0 56.2 27

Other 14.2 15.6 4

Asia-Oceania 36.8 42.8 81

Australia-New Zealand 3.0 2.4 5

China 13.0 22.0 48

India 2.6 4.5 3

Indonesia 13.3 8.4 10

Malaysia-Brunei 3.9 4.6 6

Other 0.9 1.0 8

World 610.2 922.1 547

Source: From Masters, C.D., Root, D.H., and Attanasi, E.D., Resource Constraints in Petroleum Production Potential, Science, v. 253

(12 July 1991), p. 147.
Energy Information Administration / Petroleum 1996: Issues and Trends 65

U.S. petroleum import dependency has almost doubled since the mid-1980’s, to 8.4 million barrels a day.

Crude oil import dependency has risen even faster. By 1996, crude oil accounted for nearly 90 percent of net

imports, and U.S. refiners were running over 1 million barrels a day more imported than domestic crude. This

chapter examines the decade of growth in U.S. crude oil imports, and describes the role that factors such as

the regional shifts in the U.S. and world supply/demand balances, the expanded capability of the U.S. refinery

complex, and environmental legislation have played in changing the quality and sources of these imports.

4. U.S. Crude Oil Imports: Growing U.S. Dependence

Introduction

Total U.S. imports of crude oil and petroleum products have

increased dramatically since the mid-1980’s, reaching a

record 9.4 million barrels a day last year and accounting for

over half the oil used domestically. Petroleum exports also

increased over the same period, but only modestly. Thus, net

U.S. petroleum import dependency has risen sharply, to 8.4

million barrels a day, and cost the U.S. nearly $60 billion

last year. Both the country’s thirst for and dependence on

imports are still growing.

The majority of the imports – but the minority of exports –

are crude oil. The U.S. has been a net importer of crude for

almost half a century, but it was not until 1994 that it

imported more than it produced. Since then, the gap has

widened to almost 1.0 million barrels per day. Also since

then, exports of Alaskan North Slope crude have been

liberalized.

This chapter looks at how crude oil imports have evolved

over the last ten years, focusing not only on what has driven

the volume growth but also on the role that crude quality,

regional shifts in U.S. and global supply/demand balances,

and environmental legislation have played in the changing

mix of crude sources. It also considers some of the

economic, logistical, and political implications of these

changes. While the focus of this chapter is therefore on crude

oil (rather than products) and on imports (rather than

exports), the discussion must begin with a broader view of

the import-export picture to provide the necessary context

for understanding the relative role of crude oil imports.

U.S. Total Oil Imports

The record 9.4 million barrels per day of crude oil and

petroleum products imported by the U.S. last year keep it

firmly at the top of the world importer rankings (Figure 50).

In the mid-80’s, the U.S. was only importing 5.0 million

barrels per day, barely half of today’s level. But the trend has

not always been up. Gross imports had reached 8.8 millions

of barrels per day back in 1977, before collapsing over the

following six years. Because of the substantial growth in

exports, net imports (imports minus exports) just failed to set

a new record in 1996, averaging 70 thousand barrels a day

less than in 1977. 

Imports Driven by Increasing Demand

and Declining Production

U.S. gross import dependency has fluctuated broadly in line

with the fluctuations in import volumes. It reached a peak of

48 percent back in 1977, dropped to 32-35 percent between

1982 and 1985, and then picked up fairly steadily to reach 52

percent last year. While this was a new record, it was not the

first time the politically sensitive 50 percent level had been

exceeded. That also happened in both 1993 and 1994. Net

imports dependency reached 46 percent of demand, nearly

equaling the 1977 record.

Net imports fill the gap between U.S. demand for oil and the

country’s capability to produce it. These swings in import

levels are therefore driven by the relative swings in U.S.

supply and demand.

U.S. Demand: Approaching Its Late 1970's

Record High

Demand is the more variable of the two factors (Figure 51).

It reached its all-time high of 18.8 million barrels per day

almost 20 years ago, in 1978. By the early 1980’s, it had

plunged to 15.2 million barrels per day, but by last year, it

had rebounded to 18.2 million barrels per day. This

represents an increase of 3.0 million barrels per day, or 20

percent, over the mid-1980's low point, and a new peak in

this current growth phase.

The primary driver for these oil demand swings over the last

20 years has been the level of economic activity, which is

itself, in part, a function of oil prices. Each of the last three
1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1996

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M illion Barrels per Day (Cumulative)

Supply

1995

All Other

Net Imports

Domestic Field Production of Crude

Oil and Natural Gas Plant Liquids

66 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 50. U.S. Gross Oil Imports, 1975-1995

Sources: 1975-1980: Energy Information Administration (EIA), Petroleum Supply Monthly (February 1993), Table S3. 1981 Forward: EIA,

Petroleum Supply Monthly (February 1997), Table S3.

Figure 51. U.S. Petroleum Supply and Demand

Note: All Other Supply includes refinery processing gain, unaccounted for crude, stock change, and field production of other hydrocarbons.

Sources: 1975-1980: Energy Information Administration (EIA), Petroleum Supply Monthly (February 1993), Table S1. 1981 Forward: EIA,

Petroleum Supply Monthly (February 1997), Table S1.
Energy Information Administration / Petroleum 1996: Issues and Trends 67

U.S. recessions (1974-75, 1980, and 1991) was immediately Gasoline demand therefore recovered to a new record high

preceded by a sharp increase in the price of oil that, in the of 7.6 million barrels per day last year, 40 percent of total oil

latter two cases, was subsequently eroded. Oil use stumbled demand.

as economic activity dipped, and then subsequently

recovered as the economy picked up speed again. Each time,

the recovery in demand for oil was only partial, resulting in

a steady loss of market share to other fuels that was not

reversed until quite recently. These earlier losses and the

current gain can be understood by dividing markets for oil

into two categories — captive and multi-fuel — according to

their vulnerability to substitution. 

In the early 1980’s, after two oil price shocks and fears of

more to come, and after the decontrol of domestic oil prices,

newly attractive alternatives like coal and nuclear were not

just gaining a major share of the new multi-fuel markets, like

power generation, but were also rapidly displacing oil from

many of the existing multi-fuel markets. This further

amplified the demand losses triggered by the 1980-82

recession. Gradually, this displacement pendulum lost

momentum. With the capital investment made and with low

operating costs, coal and nuclear could not easily be

dislodged from their newly won markets, even when oil

prices fell. But they have been making few new inroads. The

trickle of ongoing gains has been centered on natural gas. 

Captive markets are not immune to economic and price

signals. However, devoid of ready alternatives, the oil

demand elasticity of such markets is necessarily limited. For

a period in the 70’s and 80’s, price signals and the

introduction of more efficient vehicles significantly

influenced the transportation sector (passenger cars, trucks,

planes, trains, and buses) which currently accounts for over

two-thirds of total consumption. This further contributed to

the sharp downturn in oil demand in the early 1980’s. But

prices and price expectations receded, and many of the older

less efficient vehicles have been replaced. Growth in the

captive markets has reemerged, as can be illustrated by

looking at gasoline, and there are no longer significant losses

in the multi-fuel markets to mask it.

The CAFE (Corporate Average Fuel Efficiency) standards

institutionalized fuel efficiency improvements for onhighway vehicles, helping reduce gasoline demand from a

peak of nearly 7.2 million barrels per day in 1977 to 6.3-6.4

in the first half of the 1980’s. But the momentum was not

maintained. Today, Americans own more vehicles than ever,

and with a greater proportion than ever being gas-guzzling

sport utility vehicles and mini-vans. Since, headlines to the

contrary, gasoline is cheap — 1996’s average pump price,

adjusted for inflation, was one of the lowest of the post-war

period, and only about one-third of the price in Europe —

Americans are also driving their vehicles further and faster.

U.S. Supply: Gradual Decline from Its Early

1970's Peak

U.S. production of crude oil and natural gas plant liquids has

been declining since the early 1970’s from its 11.3 million

barrel-per-day peak, despite temporary relief provided by the

1977 start-up of Alaskan North Slope production (centered

on Prudhoe Bay, the largest field ever found in the U.S., with

12 billion barrels of recoverable reserves). The decline has

occurred mainly because the U.S. is the most mature

producing region in the world, with over three million oil

and gas wells completed since the first was drilled in

Pennsylvania in 1859. Given the declining resource base,

domestic oil resources are in constant need of exploration

and development to sustain production (see Chapter 3). Yet

the U.S. has steadily been de-emphasized by many

companies, as the rest of the world has opened up to

upstream activity, providing more attractive investment

opportunities.

However, with production still averaging 8.3 million barrels

per day, the U.S. remains a world leader, second only to

Saudi Arabia. With the breakup of the Soviet Union, Russia

has dropped to third, and is struggling to stay within 2.0

million barrels per day of the U.S. level.

Oil production, which covers crude oil, condensate, and

natural gas liquids, accounts for the vast majority (85

percent) of the 9.8 million barrels per day of domestic

supply. The rest comes from a variety of sources, the most

important of which is processing gain, the volume gain that

occurs at refineries as crude is processed into a stream of

products that have, on average, lower densities. The more

complex the refining system is, i.e. the greater the proportion

of light products it is able to make, the greater the processing

gain. The U.S., with the largest and most complex refining

system in the world, achieves a processing gain of 800

thousand barrels per day, which is over 8 percent of all

domestic supply. Synthetic hydrocarbons, such as ethanol or

MTBE, are another supply source, averaging 300 thousand

barrels per day.

In total, these non-production sources of domestic supply

averaged over 1.5 million barrels per day last year, more

than three times their level in the mid-70’s and mid-80’s.

Without this contribution, the decline in domestic supply and

the growth in imports over the last decade would have been

even more dramatic.
68 Energy Information Administration / Petroleum 1996: Issues and Trends

Outlook For Imports: More Growth, More

Records

Now that substitution losses are offsetting so little of the

growth in the captive markets, U.S. demand is moving back

up toward its record high. By 1998, the EIA forecasts it will

reach 18.6 million barrels per day, 0.4 million barrels per

day higher than last year, and only 0.2 million barrels per

day below the 1978 record.

Over the next couple of years, the non-production sources of

supply are expected to grow more slowly, largely because

there is now little regulatory incentive either to continue

expanding oxygenate production or to upgrade aggressively

(and thus boost processing gain). However, despite the

growth in Gulf of Mexico flows, the decline in domestic

production is expected to continue unchecked. Thus, the

decline in total domestic supply will accelerate slightly,

falling to 9.4 million barrels per day by 1998, the lowest

level since 1965.

In the near term, with the expectation that consumption will

continue to grow and that supply will continue to decline,

there is only one direction for imports to go: up, to new

record highs in terms of both volume and dependency. By

1998, EIA expects gross crude oil and petroleum product

imports to breach the 10 million barrel a day level for the

first time ever.

U.S. Import Dependency Is Modest in

Global Terms

Figure 52 places the U.S. dependence on imports in a global

context. Both world oil consumption and supply are

displayed on a regional basis, with each region’s “gap”

indicating whether it is a net importer or exporter. To

simplify, the U.S. has been combined with its two NAFTA

partners, Canada and Mexico, to comprise North America

(while also still being separately identifiable). These partners

are two of the top oil suppliers to the U.S. The net import

dependence for North America is therefore very much less

than for the U.S. alone.

On a regional basis, North America is the number one

consumer, as it has been for decades. Asia/Oceania has

recently leapt into second place ahead of Europe, growing by

70 percent in ten years and even outstripping the U.S. in

1996. This alone would have pulled the center of gravity of

world oil demand eastward, but this shift was given

additional momentum by the unprecedented demand collapse

in the Former Soviet Union (FSU). Demand there almost

halved in the first half of the 1990’s, falling by over

4 million barrels per day. 

The picture for supply is in sharp contrast to that for

consumption. North America is important, but the Middle

East dominates the picture. The dominance would be even

greater if the region’s major producers were to use all their

production capacity, as every other producer in the world

does. Iraq cannot, because of the U.N. imposed embargo; a

few others choose not to, limiting their production to their

OPEC quota level instead. The Middle East’s dominance has

increased significantly over the last ten years, not only

because production there has nearly doubled but also because

of declines in both the U.S. and the Former Soviet Union

(FSU). The latter is primarily one dramatic consequence of

the delay in the FSU’s attempted transition to a new

political, economic, and social order. All the other regions

have enjoyed growth, particularly those that have made the

greatest efforts to attract private and foreign investment.

When the two parts of the regional balances are put together,

it shows that all three main consuming regions are net oil

importers, while all the major producing areas (except North

America) are net exporters.

The honor of being the largest regional importer falls to

Asia/Oceania. This region’s net import requirement now

exceeds over 10 million barrels per day, for an overall

import dependency of over 60 percent. On both counts, it has

greater import exposure than the U.S. However, the regional

dependency is not really representative of any of the

individual countries. A few, such as Indonesia, are net

exporters; others, such as China, have just become net

importers; most are almost totally import dependent. This

latter group includes Japan, a very distant second to the U.S.

in the rankings of consuming countries, using almost 6

million barrels per day. 

Europe has the next highest need for imports. Unlike

Asia/Oceania, its need has been declining, thanks to the

tripling of Norway’s production and, to a minor degree,

Eastern Europe’s demand collapse, and is now under 9

million barrels per day. But like Asia/Oceania, regional

import dependency is an unrepresentative 60 percent. Most

of Europe’s production comes from the North Sea, shared

between the U.K. and Norway. That leaves most European

countries in a position similar to Japan’s: almost entirely

dependent on imports.

Thus, although U.S. oil imports are an important force in the

world oil trade, they do not constitute an unprecedented

regional flow. Also, U.S. oil import dependency is much less

than that of most of its major allies, who tend to be less well

endowed geologically.
North

America

Far East and

Oceania

Oil Consum ption 

Soviet Union

Middle East

Oil Production

Europe

Central and Africa

South America

CAN

MEX

U.S.

CAN

U.S.

MEX

North

Am erica

Far East and

O ceania

O il C onsum ption 

Form er 

S oviet U nion

M iddle East

Europe

Central and Africa

South America

CAN

MEX

U.S.

CAN

U.S.

MEX

O il P roduction

Energy Information Administration / Petroleum 1996: Issues and Trends 69

Figure 52. Regional Supply and Demand Balance, 1985 and 1995

1985

Notes: Oil production includes crude oil, natural gas plant liquids, other liquids, and refinery processing gains. Oil consumption includes internal

consumption of all refined products, refinery fuel and loss, and bunkering.

Sources: 1985: Energy Information Administration (EIA), International Energy Annual 1986 (October 1987), pp. 30-31. 1995: EIA, International

Energy Annual 1995 (December 1996), pp. 5-7 and 207-209.

1995
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Million Barrels per Day (Cumulative)

1995

U.S. Petroleum Product Imports

U.S. Crude Oil Imports

70 Energy Information Administration / Petroleum 1996: Issues and Trends

Sources: 1975-1980: Energy Information Administration (EIA), Petroleum Supply Monthly (February 1993), Table S1. 1981 Forward: EIA,

Petroleum Supply Monthly (February 1997), Table S1.

Figure 53. Crude Oil Dominates U.S. Imports

Crude Oil Dominates U.S. Imports

The U.S. imports both crude oil and products. Crude oil has

consistently dominated the flows (Figure 53). Last year,

crude oil accounted for 80 percent of all U.S. oil imports,

averaging 7.5 million barrels per day.

This preference for crude oil in part reflects history. The

domestic refining industry has long-established roots because

the U.S. was one of the pioneers of the modern oil era, with

enough crude oil of its own to be a net exporter for the first

one hundred of its one hundred and fifty years as a producer.

It also reflects the basic economics of the industry

worldwide: it is generally more cost-effective to refine

products close to the point of consumption. This is confirmed

by the composition of world trade in petroleum: 80 percent

by volume is crude (and the share is even larger in ton-mile

terms). Governments also often intervene in the market to

swing the economics even more in favor of domestic

refining, justifying it as enhancing supply security. 

The growth of crude imports over the last decade sharply

underscores the incentive for U.S. refiners to maximize runs,

particular since there have been no new, “grassroots”

refineries built in the Lower-48 during this period. Runs

were raised through a combination of refinery restarts,

expansions, debottlenecking, and improved operating

practices such as extending the time between turnarounds.

Product imports primarily play a balancing role in world oil

markets, with their flows varying depending on factors like

weather, refinery turnarounds, or accidents. They can also be

the consequence of local resistance to refineries. The U.S.

East Coast provides one of the clearest examples of this. It

refines only one-third of the products it consumes. To fill the

gap, it takes products from other regions while also

importing three-quarters of all the finished products coming

to the U.S. 

As would be expected from the foregoing, crude has borne

the brunt of the swings in U.S. imports over the last twenty

years, but its share has never dropped below 60 percent.

Between the mid-1980’s low in total imports and last year,

total crude oil imports increased by over 4.0 million barrels

per day while product imports increased by less than 100

thousand barrels. Ranges better capture the volatility of

imports, particularly of products. Even so, they show product

flows varying between 1.6 and 2.3 million barrels per day

during the last twenty years, while crude varied between 3.2

and 7.5 million. Crude’s variability has been six times that

of products.

Some of the main characteristics of product imports are

highlighted in the box on p. 71. The rest of this chapter

concentrates on crude oil.
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Energy Information Administration / Petroleum 1996: Issues and Trends 71

Product Imports

Product imports have followed a very different trend from crude imports in the last decade. They rose to a peak of 2.3 million barrels

per day in the late 1980’s as U.S. refiners struggled to keep up with the rapid growth in oil consumption, particularly of light products.

They then slipped back, undermined first by the 1990/91 recession and then by the surge in refinery upgrading capacity that resulted

largely from the requirements for cleaner fuels in the Clean Air Act Amendments (1990) and other environmental legislation. Aided

also by steadily increasing refinery utilization rates and by the growth in production of synthetic hydrocarbons, like MTBE, domestic

production has met a growing percentage of U.S. oil demand. The low point for product imports was reached in 1995, when imports

dipped to 1.6 million barrels per day, undermined by the fierce inter-fuel competition that drove residual fuel oil demand to a post World

War II low. In 1996, product imports recovered to 1.9 million barrels per day, in line with 1991-1994, but only slightly higher than

1985's level.

U.S. Gross and Net Product Imports, 1985-1996

Over the same period, product exports took another step up. Until the early 1980’s, they consisted primarily of petroleum coke, since

most other products were tightly regulated. As export license requirements were eliminated, exports started to grow. Light product

exports received a particularly strong boost after Iraq’s destruction of Kuwait’s refining capacity in 1990 led to a significant shortfall

of products into Asia, just as oil demand there started to soar. U.S. exports of both gasoline and distillate doubled. Even though Kuwait’s

capacity has been fully restored, the higher export levels have been sustained. Having had a crash lesson in how to export such products

successfully, and having experienced no political backlash, U.S. refiners and marketers now move their surpluses to whichever overseas

market is most attractive at a particular time. Thus, distillate exports to western Europe averaged less than 5 thousand barrels per day

during the first eight months of 1996, but jumped to about 80 thousand barrels per day in the final four, when the trans-Atlantic arbitrage

window was wide open.

As a consequence of these two disparate trends, net product imports in 1995 were less than half their 1988 peak of 1.6 million barrels

per day. Net imports have declined for all main products, but most notably for distillate where, in a break with the past, the U.S. has

been theoretically self-sufficient in distillate since 1991, i.e. net imports have been approximately zero. The overall downtrend was

reversed in 1996 when, aided by the exceptionally cold 1995-1996 winter and by the European gasoline glut, net product imports jumped

back up over 1 million barrels per day. Capital investment in the refining sector is expected to slow, now there is a lull in

environmentally-driven, mandated investment, leaving domestic refiners unable to keep pace with the expected growth in consumption.

Thus, further increases in net product imports are expected over at least the next few years.

The reduction in net imports has been another negative for the U.S. refining sector because it has undermined margins. Price in an

importing region is the balancing market price plus transportation. In an exporting region, it is that price minus transportation. As

imports shrink, their balancing, or price-setting, market moves closer; as exports grow, theirs moves further away. In each case, this

reduces the relative price in the price-taking market. This is what has been happening in U.S. main product markets over the last few

years. For example, in the late 1980’s, imports of distillate reached about 300 thousand barrels per day, and came from a wide variety

of sources. Now, imports have dropped by about a third, to around 200 thousand barrels per day, with 90-95 percent coming from just

three nearby locations: E. Canada, the Virgin Islands, and Venezuela. Simultaneously, exports have doubled, also to around 200

thousand barrels per day, with a significant proportion of Gulf Coast volumes having to go as far as Asia. Consequently, both Gulf coast

and East Coast distillate prices are lower relative to the world market, and to crude, than they would have been if there had been no

change in product flows.
72 Energy Information Administration / Petroleum 1996: Issues and Trends

An Overview of Crude Oil Imports

Imports of crude oil have grown dramatically since the mid1980’s, when domestic crude production began its most

recent decline phase. Crude oil now accounts for over 80

percent of total petroleum imports.

Imports Have Set Four Consecutive

Record Highs...

U.S. gross crude oil imports averaged 7.5 million barrels per

day last year, the fourth consecutive record high (Figure 54),

and the third consecutive year that they have exceeded

domestic crude production. This puts crude imports more

than 1.0 million barrels per day above the prior cycle’s 1977

peak of 6.6 million, and 4.5 million above its 1985 low. 

Back in the late 70’s and early 80’s, crude oil imports

received a boost of about 150 thousand barrels per day from

the building of the Strategic Petroleum Reserve (SPR). There

have not been any imports for the SPR for nearly three years

now. The government has recently started to sell limited

volumes of SPR oil for both operational and fiscal reasons

(see Chapter 5).

U.S. crude flows are not entirely one way. Exports occur, but

are just a fraction of imports because they are largely

precluded by highly restrictive regulations. Exports mainly

consist of Alaskan North Slope crude delivered to U.S.

possessions and territories, particularly the Virgin Islands.

Because of these exports, U.S. net dependency on the global

crude oil market has been 1-2 percent lower than its gross

dependency.

... And Will Continue to Increase

Total U.S. imports will continue to grow in the near term,

increasing by around 900 thousand barrels per day over the

next two years. As in the past, most of this increase will be

crude — over 80 percent for this period. Thus, the rate of

growth of crude imports will be slower than over the last

decade, but the average annual volume increment will be

higher. Both gross and net crude oil imports will continue to

set new record highs.

As domestic crude production continues to decline, more

questions are being asked about the appropriateness of

existing marker crudes for the U.S., particularly inland ones 24

like West Texas Intermediate (WTI). Will rising imports

present new alternatives? Many imported crudes, like those

from Saudi Arabia, Mexico, and Venezuela, are hamstrung

by resale restrictions, so growth in their flows will not

increase liquidity in the Gulf Coast crude market.

Colombia’s Cusiana crude seems a possibility on the face of

it, with volumes expected to jump to 450 thousand barrels

per day before the end of 1998, with the U.S. being its target

market, and with the equity owners willing to trade.

Cusiana’s big drawback is the proven vulnerability of its

export pipeline to guerrilla attacks and, therefore, repeated

force majeure. The best alternative may lie even closer to

home in the rapidly rising flows from the Gulf of Mexico,

typified by the sour Mars Blend stream.

Sources Of U.S. Crude Oil Imports

Economics drive the flow of crude oil — unless there are

political constraints such as embargoes. A crude flows first

to its most profitable market, the one that nets back the best

value. Then, as volumes grow, it spreads out to steadily less

profitable markets. Logistics are one of the prime

determinants of such profitability rankings. Thus, crude

tends to be sold to nearby, or short-haul, markets first, and

then to progressively more distant, or medium- and longhaul, markets, other things being equal.

Short-haul Crudes Now Dominate 

Figure 55 shows the main flows of crude into the U.S. in

1996, with the width of the arrows proportional to the annual

volume on any given route. All these flows move by tanker,

with the exception of Canadian imports, which move by

pipeline.

Short-haul imports, defined here as those from Canada,

Mexico, and Central and South America, clearly dominate,

accounting for 4.0 million of the total 7.5 million barrels per

day. This is the first time ever that the U.S. has obtained the

majority of its crude from the Western Hemisphere.

The Crude Mix Used To Be Different

The mix of supply sources for U.S. crude oil imports has

changed significantly as volumes have risen, shifting away

from regions frequently cited as politically unstable

(Figure 56). Some have concluded that this makes the U.S.

less vulnerable to price shocks. It is important to understand,

though, that it is not the degree of U.S. dependence that will

24A marker crude is one used as a basis for the pricing of other crudes. determine the impact on price of any disruption in a
1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1996

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Crude Oil Imports (excluding imports for SPR)

Crude Oil Im ports for SPR

Crude Oil Exports (shown as negative im port)

1995

Energy Information Administration / Petroleum 1996: Issues and Trends 73

Figure 54. U.S. Crude Oil Imports: Net and Gross

Sources: 1975-1980: Energy Information Administration (EIA), Petroleum Supply Monthly (February 1993), Tables S1 and S2. 1981 Forward:

EIA, Petroleum Supply Monthly (February 1997), Tables S1 and S2.

Figure 55. Origin of U.S. Crude Oil Imports, 1996

(Thousands of Barrels per Day)

Source: Energy Information Administration (EIA), Form EIA-814 data.
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AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAA

AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAA AAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAAA

Million Barrels per Day (Cumulative)

AAAA

AAAA

AAAA

AAAA AAAA

AAAA

AAA AAA

AAA

AAAA AAAA

AAAA

AAA

AAA

AAA

North Sea

Africa

Middle East

Far East & Oceania

Canada

Mexico

Central and 

South America

74 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 56. Changing Regional Patterns for U.S. Crude Oil Imports

Source: Energy Information Administration (EIA), derived from Form EIA-814 data.

particular region. Rather, it is that region’s role in the global overemphasized. It has been subsidiary to the main issue,

market. which is the establishment of a new paradigm for the

Only one major region supplies less to the U.S. than it did in

the mid-80’s: the Far East & Oceania. This reflects the Thanks to the aggressive implementation of new technology,

increased refining flexibility that has made the West Coast the radical restructuring of operating practices, and the

less reliant on the high quality crudes that are characteristic almost universal opening up of the upstream, the global

of this regional source, together with the increased crude oil supply curve has been shifted significantly to the

willingness of integrated companies to optimize their crude right, i.e., the volume of crude that can be economically

slates on a global basis, and not just within their own produced at a given price has risen. Hence, despite prices

company systems. that have been lower than were expected from the viewpoint

One of the most significant developments in the 1990’s has Middle Eastern members, have been called on to produce

been the decline in importance of Middle East crudes to the much less in the 1990's than was then expected because

U.S. market. They were the fastest growing import stream production almost everywhere else has soared.

between 1985 and 1990, rising to account for nearly onethird of all U.S. crude oil imports. The consensus view was Therefore, the sources of short-haul crudes have enjoyed

that this share would continue to grow. Not only has the rising production that has left them able to increase exports,

share declined, to just 20 percent in 1996, but the absolute and their preferred target, logically, has been the U.S. Latin

volume has declined too. America has been the star performer, with imports to the

Politics have played a role in this. Since mid-1990, Iraqi the medium and long-haul exporters to the U.S. market have

exports have been subject to a near total global embargo, lost ground to some degree. It has been particularly hard for

only partially lifted in December 1996. Also, the U.S. has

maintained a unilateral embargo on Iranian crude that dates

back to October 1987. These limit the possibilities for

Middle East crudes coming to the U.S. But the role of

politics in determining the crude mix should not be

upstream sector of the oil industry. 

25

at the end of the 1980’s, OPEC, and most particularly its

U.S. growing by 1.4 million barrels per day since 1990. All

Opening up of the upstream refers to the broad-ranging political, 25

economic, institutional, and contractual changes that have occurred in

virtually every oil-producing nation making their oil resources increasingly

accessible to world oil markets.
Energy Information Administration / Petroleum 1996: Issues and Trends 75

the Middle East to compete because its crude is of the same ! the historic links between Saudi Arabia and the exquality, heavy sour, as the majority of short-haul grades. The Aramco partners: Mobil, Chevron, Exxon, and Texaco

less voluminous, light, sweet, short-haul grades, such as (see also Figure 62); 

Olmeca (Mexico) and Cusiana (Colombia), have been partly

responsible for the North Sea and Africa’s shrinking share of ! ongoing embargoes of two of its Middle East rivals, and

U.S. crude imports in the last few years.

These changes in the long-haul/short-haul mix of imported U.S. customers by using the Caribbean as a

crudes tend to lower the volume of stocks held onshore in the transshipment center, and selling FOB out of there. 

U.S. Firstly, a just-in-time inventory strategy argues for

lower stocks if a supply source is nearer – a somewhat This last strategy has two side benefits. Saudi Arabia benefits

specious argument, perhaps, if those suppliers are already because it raises the netback value of its sales in a

producing at maximum, have no buffer stocks themselves, backwardated market, the prevailing condition of the last

and have a history of interruptions. Secondly, parcel sizes for couple of years (see chapter on futures). Its customers benefit

short-haul crudes are generally smaller than those for long- because Saudi Arabia is, in effect, now holding some of their

haul crudes, meaning more frequent deliveries and a lower operating stocks in the Caribbean, reducing their working

average stock level (see Chapter 5). capital needs and reducing onshore U.S. stocks in the process

Six Countries Supply 80 Percent of

U.S. Crude Imports

Not all countries in a region are the same, at least from the

standpoint of being crude suppliers to the U.S. market. U.S.

import dependency is much more concentrated than the

regional analysis might suggest (Table 5).

The U.S. gets almost two-thirds of its crude oil imports from

just four countries, each of which supplied over 1.0 million

barrels per day last year: Canada, Mexico, and Venezuela,

all short-haul sources, and Saudi Arabia, a long-haul source.

Adding in the next two in the rankings, Nigeria and the

North Sea (really Norway and the UK, but generally counted The U.S. regional crude oil supply/demand balances are far

together in oil supply terms), takes the proportion up to 80 from homogeneous (Figure 57). At one extreme is the East

percent. The remaining 20 percent is split between 32 other Coast, the most supply deficient of all the regions, which

countries. refines much less than it consumes. It is also dependent on

It is more than just physical closeness and geology that has is the Gulf Coast, with substantially more refinery capacity

made the three leading short-haul suppliers so dominant. than needed to meet its own consumption. It is the country’s

Firstly, Canada has no viable export market other than the swing refining region, sending its surplus to fill in deficits

U.S. Secondly, both PDVSA, and, more recently, Pemex elsewhere, mainly on the East Coast and in the Midwest. 

(respectively the Venezuelan and Mexican national oil

companies) have shrewdly invested via joint ventures in One of the few common threads between the regions is that,

increasing the complexity of U.S. refineries. By enlarging to a greater or lesser degree, they all import crude. The Gulf

the nearby, higher valued market for their poor quality Coast imports the most, receiving 4.3 million barrels per day

crudes — referred to as increasing their fungibility — last year, almost 60 percent of the total. Next comes the

Venezuela and Mexico have leveraged the value of large Midwest, closely followed by the East Coast. Both take less

segments of their crude production. than a third of the Gulf Coast volume. 

There are several reasons why Saudi Arabia, alone among The Gulf Coast’s role in crude oil imports is even larger than

long-haul suppliers, has been able to remain a significant these data imply because, except for flows from Canada, all

exporter to the U.S. market, including: of the Midwest’s imports move via the Gulf Coast, using the

! sheer size — the world’s largest importer and the world’s as the volumes that the Gulf Coast refines itself. Last year,

largest exporter want to do business together; 

! its transformation into a short-haul source for many of its

(see chapter on stocks).

Where In The U.S. Does the

Imported Crude Oil Go?

Every region in the U.S. imports some crude oil, but the

regional similarities tend to end there because the different

regions have distinctly different crude oil needs and choices.

Crude Oil Import Dependency Varies

Regionally

imports for almost all the crude it runs. At the other extreme

same ports and some of the same distribution infrastructure
KY

NC

GA

FL MS AL

TN

AR

MN

WI

IL IN

MI

OH

GA

NY

CT

MA

VT

NH

ME

RI

VA

PA

MD

DE DC

CA

AZ

NV

OR

WA

ID

WV

NM

TX

OK

LA

WY

UT CO

NJ

MT

NE IA

MO

SD

KS

ND

II

III

I

V IV

2,498 353

469 124

3,2541,397

6,6294,337

1,3311,271

SC

Regional Dependence on Crude Oil Imports

(Thousands of Barrels per Day)

**By PADD where processed.

Crude Oil Demand*

Crude Oil Imports**

*Crude oil inputs to refinery.

76 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 57. U.S. Regional Dependence on Crude Oil Imports, 1996

Source: Energy Information Administration (EIA), derived from Form EIA-814 data.

Table 5. The Top Six Sources of U.S. Crude Oil Imports, 1996

(Thousand Barrels per Day)

Year Venezuela Arabia Mexico Canada Nigeria North Sea of the World Total

Saudi Rest

1985 306 132 715 468 280 309 991 3,201

1986 416 618 621 570 437 370 1,145 4,178

1987 488 642 602 608 529 374 1,432 4,674

1988 439 902 674 681 607 316 1,489 5,107

1989 495 1,116 716 630 800 278 1,808 5,843

1990 666 1,195 689 643 784 250 1,668 5,894

1991 668 1,703 759 743 683 180 1,044 5,782

1992 826 1,597 787 797 665 319 1,091 6,083

1993 1,010 1,282 863 900 722 449 1,561 6,787

1994 1,034 1,297 939 983 624 586 1,600 7,063

1995 1,151 1,260 1,027 1,040 621 599 1,533 7,230

1996 1,305 1,248 1,207 1,068 592 509 1,553 7,482

Source: Energy Information Administration, Petroleum Supply Monthly (February 1997), Table S3.
Energy Information Administration / Petroleum 1996: Issues and Trends 77

almost 600 thousand barrels per day of crude moved to the ! Sulfur content, which measures a crude oil’s sulfur by

Midwest this way. percent weight. A low sulfur crude is ‘sweet’, and a high

Crude Imports Have Shifted East and

South Since the 1970's

The pressure the record high U.S. crude import level puts on

different regions varies (Figure 58). Three regions still lag

their prior peaks, all of which were set in the late 1970’s.

The West Coast has the most leeway; only importing one- A refiner is interested in a crude for the value of the products

third of its 1977 pre-Prudhoe Bay level of 1.1 million barrels it yields. His aim is to turn the crude into as much of the

per day last year. Declining production and rising throughput lighter, higher priced products and as little of the heavier,

have pushed the Midwest to within sight of its 1977 peak, lower priced products as is cost-effectively possible. In the

while the restart of Tosco’s Trainer Refinery in Philadelphia U.S. market, that usually means maximizing gasoline while

in mid-1997 could be enough to take the East Coast to new minimizing the residual fuel oils and other residues that sell

highs. But it is PADD III, the Gulf Coast, and to a lesser for less than the price of the crude.

degree PADD IV, the Rocky Mountains, that have already

been presented with new challenges from record import Refineries, like crudes, differ. A simple refinery produces

flows. products that reflect the natural characteristics of the crude.

Well before even the current levels of crude oil imports were light ends and less residual oil, because the heavier materials

reached in these two regions, concerns were being raised are reprocessed into feedstocks for additional, and generally

about the adequacy of both the ports and the pipeline high capital investment, processing units. 

systems to handle the flows. The reality has been that the

infrastructure has shown an unprecedented degree of The yield, or mix, of products a refiner produces therefore

flexibility. Pipelines have been reversed (Mobil), depends on his choice of crude and the operating

debottlenecked (Arco), extended (Diamond Shamrock), built configuration of his refinery. Thus, taking value as the

(Express), newly connected (Amoco), or even switched from aggregate revenue from the products produced from the

natural gas to crude oil service (Seaway). While getting crude less the cost of refining it, different crudes can have

sufficient crude supply to the U.S. might at times be a different values for the same refiner, while the same crude

legitimate concern, handling it once it reaches the U.S. can have different values for different refiners. (Note: in

should not be, barring accidents. choosing which crude to buy, a refiner would need to

Quality Issues

Crudes are not all alike. They differ considerably in their

physical properties, with the important differences being the

proportions of the various hydrocarbon fractions that can be

turned into the different products and the levels of various

contaminants, such as sulfur or metals. These properties

affect the ease with which refiners can process various crude

oils into the different products required by consumers. The

two physical properties that are most often quoted for crude

oil are:

! API gravity, which is a measure of a crude oil’s density

or specific gravity. A high gravity crude is ‘light’ and a

low gravity one is ‘heavy’. Other things being equal, a

light crude yields more light products than a heavy crude.

sulfur one is ‘sour’. Sulfur is a pollutant. Its level in

finished products is increasingly being limited in the

U.S., mostly by Clean Air Act regulations.

Crude Oil Values Vary Directly with

Quality

As a refinery becomes more sophisticated, it produces more

compare this value with the delivered cost of the crude to

calculate its marginal value, and rank the results.) In general,

light crudes are more valuable than heavy ones, and sweet

crudes more valuable than sour. These quality differentials,

or differences in value between light and heavy, and between

sweet and sour crudes, vary between refiners, between

regions, and over time (see Chapter 7).

Hence quality, like logistics, is a prime determinant of crude

flows. The demand curve for a particular crude therefore

varies as both the transportation cost and the quality

differential vary, making the curve non-linear with respect to

logistics. In other words, to progressively place a crude, a

producer can be moving back and forth between closer and

more distant markets, depending on the relative trade off

between the cost of transportation and the quality premium

for the crude in each market at that time. The resultant

market clearing price will not necessarily be set either in the

same market each time, or in the most distant market that

takes the crude.
1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1996

0

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Million Barrels per Day (Cumulative)

AAAA AAAA AAAA

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PADD 1

PADD 2

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PADD 4

PADD 5

1995

78 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 58. U.S. Regional Dependence on Crude Oil Imports Over Time, 1975-1996

Sources: 1975-1980: Energy Information Administration (EIA), Energy Data Reports, Petroleum Statement Annual. 1981-1995: EIA, Petroleum

Supply Annual (February 1997), Table 34.

Imports Are Poorer In Quality Than

Domestic Crudes

Refiners aim to find the most cost effective way to meet

demand within the constraints of their own facilities. As the

U.S. refining system is the most complex in the world, and

as U.S. crude quality is better than the world average, it is

hardly surprising that imported crudes lower the quality of

the crude slate that U.S. refiners run (Figure 59). This

deterioration is particularly pronounced for sulfur, with

imports having double the unusually low level in domestic

crudes. 

The West Coast is the only region where imports do not

reduce the quality of the crude slate. The quality of its own

production is very much worse, at 24 degree API and 1.2

percent sulfur, than that in any other region in the U.S. It has

therefore long imported crudes toward the high end of the

quality spectrum, pulling its quality average closer to the

U.S. norm. Historically, these crudes generally came from U.S. crude oil imports fall into two clear quality groups,

Asia, particularly Indonesia and Malaysia. Over time, the sweet and sour (Figure 60). Canada, Mexico, Venezuela and

West Coast refiners upgraded, lessening their need for such Saudi Arabia supply the poorer quality, sour, predominantly

extremely light sweet crudes. An increasingly large heavy grades, while the North Sea, Africa, and the rest of

proportion of their imports then gradually shifted toward Latin America supply the better quality, sweet, frequently

Alaskan North Slope ‘look-alike’ grades, to give themselves light grades. 

purchasing leverage in an oligopolistic market for a crude

whose production was steadily declining. There is strong competition between suppliers within each of

On a simultaneous gravity and sulfur ranking, PADD III

imports the worst crudes. A major influence here are the

joint venture investments that heavy crude producers like

Venezuela and Mexico have been successfully pursuing to

improve the fungibility of their crudes in U.S. markets. Their

main target has been the Gulf Coast. 

PADD IV, the Rocky Mountains, comes a surprisingly close

second, considering it is a market dominated by smaller,

niche refineries. Logistics make Western Canada its

preferred — and, currently, its only nondomestic — crude

supplier. As production there got heavier, the economic

imperative to upgrade became overwhelming for the Rocky

Mountain refiners accessing those crudes.

Different Regions Supply Different

Quality Crudes

these two groups, with logistics generally being the deciding
22 24 26 28 30 32 34 36 38

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

API Gravity (Degrees)

Sulfur (Percent)

Domestic Production and

Stocks of Crude Oil

PADD 2

Imports of Crude Oil

PADD 1

PADD 5

PADD 3

PADD 4

PADD 4

PADD 1

PADD 3

PADD 5

PADD 2

North Sea

24 26 28 30 32 34 36

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Weighted Average API Gravity (Degrees)

Weighted Average Sulfur (Percent)

22

Africa

Other 

Latin 

America

Canada

Rest of the World

Venezuela

Saudi Arabia

Mexico

Energy Information Administration / Petroleum 1996: Issues and Trends 79

Figure 59. A Comparison Between Imported and Domestic Crude Oil Quality in 1996

Sources: Energy Information Administration (EIA). Imports: derived from Form EIA-814 data. Domestic: derived from Forms EIA-810 and EIA814 data.

Figure 60. The Quality of U.S. Crude Oil Imports by Supply Region, 1996

Source: Energy Information Administration (EIA). Form EIA-814, with imputed values for 1 to 4 percent of data.
80 Energy Information Administration / Petroleum 1996: Issues and Trends

factor between winners and losers. Saudi Arabia’s low. Venezuela and Mexico actively sought joint venture

competitive disadvantage in the sour group has already been upgrading investments in the U.S. market.

noted. In the light sweet group, the competitive

disadvantage, vis-a-vis the U.S. market, lies with the African This upgrading allowed the short-haul suppliers to win an

producers, particularly West African countries like Nigeria even larger share of the U.S. market, by allowing them to

and Angola. Of course, these countries have a competitive compete successfully with suppliers of light sweet crudes,

advantage over the North Sea vis-a-vis the Asian market. like Africa. Thus the observed swing in the U.S. from

This has made them the swing source for the world light, medium and long-haul toward short-haul crudes was not

sweet crude market, just as the Middle East is for the heavy, purely the result of logistics.

sour market. West African crudes are now routinely pulled

or pushed between the Americas and the Far East, depending Most of the deterioration in import quality had occurred by

on the relative strengths of their respective markets. This the early 1990’s. The subsequent leveling off came about

competition is reflected in the price of Asian quality crudes largely because the quality of the crude being produced

relative to Brent, which depends on many factors, including worldwide improved, due to a major production shift by

the time of the year, accidents at refineries or oil fields, and Saudi Arabia from its medium and heavy to its lighter

the pace of tightening quality standards. grades, coupled with the geologic coincidence that the surge

There is also competition between the quality groups. This biased toward light sweet crudes. 

influences, and is influenced by, the level of the quality

differentials. This competition has contributed to the

changing quality of U.S. imports over time.

The Quality of U.S. Imports Has

Deteriorated

The quality of U.S. crude imports today is lower than it was

in the mid-1980’s, as is the quality of U.S. refinery runs as

a whole (Figure 61). This is mainly the result of aggressive

capital investment by the U.S. refining sector that has raised

the complexity of the whole system and made it capable of

running a higher proportion of poorer quality crudes despite

a lightening of the mix of products being consumed and a

tightening of product quality standards. But why did U.S.

refiners choose to do this?

! The U.S. is the world’s leading importer. Its refiners need

flexibility if they are not to be held hostage by suppliers,

particularly in the light of two trends that have long been

expected to prevail: that U.S. imports will continue to

grow, and that world crude quality will deteriorate (an

expectation that has not always been fulfilled). 

! U.S. demand is significantly more skewed to light

products, especially gasoline, and away from residual

fuel oil, than the norm elsewhere in the world. Refiners

therefore have a relatively greater economic incentive to

invest aggressively in residual destruction units. 

! Environmental legislation, such as the 1990 Clean Air

Act Amendments, effectively forced investment in

upgrading. The marginal cost of adding upgrading

capability beyond that required by cutting edge U.S.

environmental restrictions has been frequently relatively

in non-OPEC production in the first half of the 1990’s was

Crude Sources for the Largest

Importers

Nine U.S. refining companies each imported more than 300

thousand barrels per day of crude last year, accounting for

almost two-thirds of all U.S. crude imports. Leading the pack

was Citgo, closely followed by Mobil and Texaco. Beyond

size, the top nine’s crude import slates had little in common

(Figure 62). 

(Note: imports made by joint venture refining companies are

combined with those of the U.S. based parent company most

responsible for supply, i.e. Star with Texaco, Lyondell and

Unoven with Citgo, the wholly-owned U.S. subsidiary of

PDVSA, and Deer Park, a limited partnership of Pemex with

Shell Oil, with Shell Oil.)

Many, frequently interdependent, factors contributed to this

lack of homogeneity. The most obvious one is

ownership/vertical integration through a joint venture

relationship with a producer, because this resulted in

importers that were especially single minded about their

crude sources:

! Citgo: Last year, 85 percent of its crude imports were

from Venezuela. Another 7 percent were from Mexico,

indicating that Citgo was already capable of running an

unusually heavy slate. This year, with Lyondell’s new

coker up and running, the proportion of heavy, Latin

American crudes could move even higher.

! Texaco: Its joint venture partner in Star is Saudi Arabia,

which accounted for three quarters of Texaco’s imports

in 1996. Such a strong link with a long-haul supplier
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

30.25

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0.90

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1.60

API Gravity in Degrees

Sulfur in Percent

Gravity Refinery Inputs

Gravity Imports

Sulfur Refinery Inputs

Sulfur Imports

Citgo Mobil Texaco Amoco Exxon Chevron Sun Co Shell Koch

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Thousand Barrels per Day

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Venezuela

Mexico

Other Latin America

Canada

Africa

North Sea

Saudi Arabia

Rest of World

Energy Information Administration / Petroleum 1996: Issues and Trends 81

Figure 61. Quality Trends in U.S. Crude Oil Imports and Refinery Inputs

Sources: Import Data: Energy Information Administration (EIA), derived from Form EIA-814. Refinery Inputs: EIA, Petroleum Supply Annual

(1986-1995) and EIA, Petroleum Supply Monthly (March 1996-February 1997).

Figure 62. U.S. Crude Oil Imports by the Top Nine Importing Refiners and by Supply Region, 1996

Source: Energy Information Administration, Form EIA-814 data.
82 Energy Information Administration / Petroleum 1996: Issues and Trends

could be a competitive disadvantage in a U.S. market they lead or lag stock policy, and by how much, is a function

dominated by short-haul imports. of price, particularly the inter-month spreads, as well as

! Shell Oil: Its joint venture arrangement with Pemex at its supply disruptions (see Chapters 5 and 6).

Deer Park refinery included installation of a new coker.

Last year, two thirds of its imports were from Mexico.

The others on the Top Nine list have more diverse crude

import portfolios, but the factors driving many of the choices

are still frequently easy to determine. These factors include:

! Location is why Koch Industries took half its crude

from Canada. Its main refinery in Minnesota has gained

significant competitive advantage from maximizing its

use of Canadian Heavy, which has frequently traded in a

buyer’s market. Amoco and Mobil’s propensity for

Canadian crude has the same derivation.

! Equity production — either present or past — is why

Amoco is the only significant importer of Trinidadian

crude, and Chevron and Exxon are the largest importers

from Saudi Arabia after Texaco/Star.

! Refinery configuration constraints mean Sun’s slate is

dominated by West African and North Sea crudes

because its refineries are relatively simple by U.S.

standards. Sun adopted a policy last year of minimizing

capital investment, dropping out of the asphalt market,

and restricting its crude slate to quality crudes.

Sun would probably have had the company of one other light

sweet oriented importer on the Top Nine list if either British

Petroleum had not sold its Marcus Hook, Pennsylvania,

refinery to Tosco in February 1996, or Tosco had chosen to

run it last year. But that would still place such importers in

the distinct minority. If size is in any sense an indicator of

success, then this analysis confirms a strong correlation

between success and the ability to run significant proportions

of poor quality, imported crudes.

The list of the largest crude importers has changed over time

as mergers and acquisitions have reshaped the downstream

sector. With a new wave of restructuring sweeping through

the industry, further changes are inevitable. In particular, the

top nine importers, whoever they are, will become even

more dominant.

Seasonality of Imports

U.S. crude oil import requirements are seasonal (Figure 63),

tied to, but not precisely in step with, the seasonality of U.S.

oil consumption. Since imports are the marginal source of

supply for the U.S. market, they can be thought of as an

indicator of both refinery runs and consumption. Whether

other factors, such as refinery turnarounds, accidents, and

In general, the volume of total and of the better quality, light

sweet crude imports varies seasonally. U.S. consumption’s

summer peak is driven primarily by gasoline, as people take

to the road during the traditional vacation season. This peak

consumption coincides with the tightest seasonal quality

specifications for gasoline, and presents a challenge to the

U.S. refining sector, for which its upgrading capacity for the

cheaper, poorer quality crudes is inadequate, even when fully

utilized and with no turnarounds. Refiners turn for their

marginal barrel to grades with a naturally high gasoline

fraction, which means they turn to the light sweet crudes.

U.S. consumption is counter seasonal to global consumption,

which is strongly winter peaking, with a 3-4 million barrel a

day swing from quarterly peak to trough. These regional

differences cause crude flows to swing west into the Atlantic

Basin in the spring and summer, and east into the Pacific

Basin in the winter. Such flows are accompanied by, if not

initiated by, swings in relative crude prices. This causes the

relative strength in U.S. domestic crude prices that typically

occurs in the spring and early summer. With the U.S.

particularly dependent at that time of year on light sweet

crudes, that relative strength is most pronounced for grades

such as the U.S. marker crude, West Texas Intermediate

(WTI). In years when mid-continent crude stocks are low, or

pipeline capacity is tight, the result can be price spikes and

disconnects with world prices.

Crude Oil Exports

Crude oil exports play a minor role in the U.S. crude oil

balance, averaging just 100-200 thousand barrels per day

since 1985 (Figure 64), because they have essentially been

banned for most grades most of the time. However, even if

there were no restrictions at all, the status of the U.S. as the

world’s largest net importer of crude would ensure that

exports would remain small in almost all circumstances. 

Export Ban Diverted Alaskan Oil to

East of the Rockies and the Virgin

Islands

This would not entirely have been the case when Alaskan

North Slope (ANS) production was in its prime. Its

substantial West Coast surplus would have moved primarily

to Asia if normal supply economics had applied. Instead, an

ANS-specific export ban meant effectively that it could only
Jan Apr Oct DecJan Apr OctDecJan Apr OctDecJan Apr Oct DecJan Apr Oct Dec

0

2,000

4,000

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1996

M illion Barrels per Day

Sweet

Sour

1992 1995 1993 1994

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

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Thousand Barrels per Day

PADD 5

Other

Energy Information Administration / Petroleum 1996: Issues and Trends 83

Figure 63. Quarterly Volumes of U.S. Crude Oil Imports by Sulfur Content

Source: Energy Information Administration, Form EIA-814 data.

Figure 64. U.S. Crude Oil Exports by Exporting Region, 1985-1996

Sources: Energy Information Administration (EIA), Petroleum Supply Monthly and EIA, Petroleum Supply Annual (various issues).
84 Energy Information Administration / Petroleum 1996: Issues and Trends

be moved either east of the Rockies or, under a special barrels per day in the previous three and a half years; and

exemption for U.S. territories and possessions, to the Virgin significant parcels of ANS have moved to four Asian

Islands or Puerto Rico –- with both the latter still counting as countries, although these movements have been intermittent

exports in the statistics. None of these destinations would except for the 50 thousand barrels per day to Korea. 

have been natural choices in a free market because of the

significant freight costs attached to such moves due to either The ongoing decline in the West Coast surplus of ANS crude

Jones Act restrictions or sheer distance. For example, the was gradually eroding ANS in-transit stocks of this crude.

voyage from Valdez, Alaska to the Virgin Islands is the Lifting the export ban has caused a further, sharp reduction

longest regular voyage in the world oil market, covering since ANS in transit overseas to destinations other than the

around 15,000 (nautical) miles and taking up to 50 days. But Virgin Islands is not included in this calculation. This

all these markets, particularly the Virgin Islands, helped at contributed to the exceptionally low crude stock levels seen

times to increase the producers’ total net revenue relative to in the U.S. in 1996 (see Chapter 5).

the alternatives of either swamping the West Coast or

limiting ANS production.

It was therefore ANS flows to the Virgin Islands that

accounted for the overwhelming majority of U.S. crude oil

exports over the last decade, which is also why almost all

exports flowed out of the West Coast. And it was primarily

the decline in both ANS and Californian production, together

with the increased flexibility of West Coast refiners to run

greater volumes of these poorer quality crudes, that led to the

halving of exports in the second half of the 1980’s. 

With the Ban Lifted, Alaskan Crude Is

Moving to Asia

After nearly twenty years of production, and with volumes

only 70 percent of peak flows, a Bill lifting the ban on ANS

exports was finally passed in November 1995 and

implemented in July 1996. On the surface, nothing appears

to have changed, with ANS exports in 1996 equal to those in

1995. But the absence of any increase is due to the

continuing decline in ANS production, which was down

another 90 thousand barrels per day in 1996. The new reality

is being reflected in the flows. Waterborne, and almost all

pipeline, flows of ANS to the Gulf Coast have ceased;

exports to the Virgin Islands have plunged to 10 thousand

barrels per day in the last five months from over 90 thousand

Non-ANS Exports Are Minor

The non-ANS component of U.S. exports has included

intermittent, minor flows from other special case sources on

the West Coast, such as Cook Inlet production from Alaskan

state waters and, since 1991, Californian heavy crude. There

has also usually been some U.S. crude moving north by

pipeline or truck into eastern Canada. The very modest

baseload comes from production near the border, augmented,

when the economics are favorable, by more widely traded

crudes like West Texas Intermediate. (Note that crude oil in

transit through the U.S. for Canada, such as via the Portland

pipeline to Montreal, does not show up in these export

statistics.)

U.S. Crude Exports Will Always Be

Modest

As Asian refiners adjust to ANS crude, become more

comfortable with U.S. tanker legislation, and more market

oriented as their markets become more open, then crude oil

exports from the U.S. could temporarily grow modestly

again. But U.S. exports will never be a significant force in

world crude markets.
Energy Information Administration / Petroleum 1996: Issues and Trends 85

Stocks are needed to keep petroleum supplies moving smoothly from wellhead to end user. As an immediate

source of supply, stocks provide a cushion against normal and unexpected demand and supply fluctuations.

Crude oil, distillate, and total gasoline stocks dropped in 1995 and reached new lows in 1996, drawing

attention to the long-term downward trend. This led to questions as to whether the lower stocks caused greater

price volatility, whether the stock cushion was adequate (particularly in light of more efficient industry

operations), whether the reformulated gasoline program in 1995 influenced stock levels, and whether the

decline in stocks is short lived or lasting. The following chapter reviews the trends in EIA's comprehensive

survey data on petroleum stocks in conjunction with other information on prices and industry activity to provide

the background required to begin answering these questions. This chapter also identifies and assesses the

short and long term factors that influence stock levels.

5. Petroleum Stocks: Causes and Effects of Lower Inventories

Introduction

Total U.S. gasoline stocks have been shrinking since the

early 1990s. Near the beginning of 1995, stocks of crude oil,

distillate, and gasoline started to decline so precipitously

that, by May of that year, stocks fell below the 1991-1995

average level and have yet to recover (Figure 65). In March 26

1996 crude oil, distillate, and total gasoline inventories were

593 million barrels, the lowest recorded in more than 15

years. When stocks are low, demand surges or supply

shortfalls cause buyers to turn to spot markets for immediate

supplies while waiting for production and/or imports. During

such times, buyers tend to bid up prices to assure supply in

a tight market. This occurred in spring 1996 when low crude

oil, distillate, and total gasoline inventories forced refiners

and marketers to rely more heavily on spot markets to meet

unexpected heating oil and seasonally rising gasoline

demands. This event contributed to the rise in the price of

crude oil. 27

Table 6 shows the recent changes in petroleum stocks

disaggregated by type (crude oil, distillate, and total

gasoline), industry sector (mainly refineries, tank farms/bulk

terminals, and pipelines), and Petroleum Administration for

Defense District (PADD). Of the 64-million-barrel 1994 to

1996 decline in stocks, the greatest volumetric decrease

occurred in crude oil (32 million barrels) while the greatest

percentage decline occurred in distillate (15 percent). Much

of the decline in crude oil, distillate, and total gasoline stocks

occurred at bulk terminals/tank farms where more

discretionary stocking takes place. The drop in stocks is most

evident in PADD I (East Coast), where consumption is

concentrated, and PADD III (Gulf Coast), a major refining

area. 

Prior to 1995, it was refinery closures, caused in part by the

decontrol of the oil industry, that had the most important

impact on petroleum stocks. Between 1981 and 1986, 108

refineries closed and inventories declined as the storage

capacity associated with these facilities was

decommissioned. Since the beginning of 1995, price risk,

where the commodity stored is expected to be less valuable

in the future because prices are overvalued in the present,

appears to be one of the most important factors behind the

reduction in stocks. Poor profitability, driven by low gross

refining margins, also contributed to the drop in inventories.

The forces that influence petroleum inventory levels can be

divided into two categories. The first category consists of

short term forces that influence refiners’ (and to some extent,

marketers’) day-to-day decisions concerning inventory

levels. These forces include current and expected prices,

refining margins, the cost of storage, and the risk of

stockouts, along with seasonal changes in product demand

levels. The second category includes long term forces such

as increased offshore stocks, enhanced inventory

management through improved information technology,

consolidation of petroleum storage facilities, the shift to

short-haul crude oil sources, the introduction of clean

products, and the change in secondary stocks.28

Only crude oil, distillate, and total gasoline (finished gasoline plus 26

blending components) stocks are addressed in this analysis. Excluded are

stocks of all other petroleum products including jet fuel, residual fuel oil, and

propane. Stocks held in the Federally owned Strategic Petroleum Reserve

(SPR) are discussed separately (see box, p. 87).

U.S. Department of Energy, An Analysis of Gasoline Markets Spring 27

1996, DOE/PO-0046 (Washington, DC, June 1996), p. 4.

Primary stocks include crude oil or petroleum products held in storage 28

at leases, refineries, natural gas processing plants, pipelines, tank farms, and

bulk terminals that can store at least 50,000 barrels of petroleum products or

that can receive petroleum products by tanker, barge, or pipeline. Secondary

stocks include stocks at facilities having less than 50,000 barrels capacity or

supplied strictly by tanker truck. Tertiary stocks are stocks held by end users.
1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

600

650

700

750

800

850

900

Million Barrels

Total

5-year Average

86 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 65. Aggregate Crude Oil, Distillate, and Total Gasoline Stocks , January 1981-December 1996 1

(Million Barrels)

Includes crude oil, distillate, and total gasoline (finished gasoline plus blending components) only. 1

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-811 “Monthly Bulk Terminal Report,” EIA-812

“Monthly Product Pipeline Report,” and EIA-813 “Monthly Crude Oil Report.”

Table 6. Crude Oil, Distillate, and Total Gasoline Inventories by Industry Sector and PADD, 1994-1996

(Million Barrels)

1994 1995 1996 (1996-1994)

Difference

Petroleum Type - Total 676 654 612 -64

Crude Oil 336 322 304 -32

Distillate 126 126 107 -19

Total Gasoline 214 206 201 -13 1

Crude Oil, Distillate and Total Gasoline Stocks by

Industry Sector2

Refineries 208 206 195 -13

Bulk Terminals 155 149 131 -24

Pipelines 77 78 77 0

Crude Oil Tank Farms and Pipelines 198 184 177 -21

Crude Oil Leases 18 17 17 -1

Alaska Crude Oil in Transit 20 21 15 -5

Crude Oil, Distillate and Total Gasoline Stocks

by PADD

East Coast (I) 128 124 106 -22

Midwest (II) 159 154 145 -14

Gulf Coast (III) 253 239 231 -22

Mountain (IV) 21 21 20 -1

Pacific (V) 115 115 110 -5

Finished gasoline plus blending components. 1

In other published EIA data, bulk terminals that make finished gasoline by mixing blend stocks and/or oxygenates are included in the “Refinery” 2

category. In the following entries, EIA data for distillate and gasoline were adjusted by removing the stocks these blenders report from the “Refinery”

category and including the volumes in the “Bulk Terminals” category.

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-811 “Monthly Bulk Terminal Report,” EIA-812

“Monthly Product Pipeline Report,” and EIA-813 “Monthly Crude Oil Report.”
Energy Information Administration / Petroleum 1996: Issues and Trends 87

The Status of the U.S. Strategic Petroleum Reserve

The Strategic Petroleum Reserve (SPR) was created pursuant to the Energy Policy and Conservation Act of 1975 to mitigate

the impact of disruptions in petroleum supplies and to carry out obligations of the United States under the Agreement on

an International Energy Program. The reserves can be drawn down when the President determines that an energy supply

emergency exists or could exist, and is of significant enough nature to adversely affect the economy.

The SPR facilities are designed to hold 680 million barrels of petroleum in three storage complexes in Texas and Louisiana.

The SPR crude can be delivered to refineries in the Gulf Coast and Midwest through various connections to the U.S.

petroleum pipeline network. The SPR crude can also be delivered by tanker or barge.

Persian Gulf War

On January 16, 1991, in conjunction with the beginning of Operation Desert Storm, President Bush ordered a drawdown

and distribution of SPR petroleum as part of a coordinated plan agreed to by member countries of the International Energy

Agency. The Department of Energy issued a Notice of Sale for 33.75 million barrels. 28

In total, 17.2 million barrels of oil was sold from the SPR to a total of 13 purchasers between January 17 and March 31,

1991. This event marked the first emergency drawdown and sale of SPR oil. Even though the volumes sold were small, the

use of the SPR at the onset of Operation Desert Storm provided an instantaneous counter force to expected market panic.29

Current Sales and Stock Levels

In 1996, under Congressional direction, the U.S. Department of Energy sold 5.1 million barrels of petroleum from Weeks

Island to 4 buyers between February 26 and March 21. The proceeds from the sale, totaling $97 million, were used to

relocate oil from the geologically unstable Weeks Island facility.

Again in May, pursuant to the Fiscal Year 1996 budget bill, the U.S. Department of Energy undertook an expedited release

of up to 15 million barrels to raise an additional $227 million. The expedited nature of the sale was in response to the

increase in petroleum prices in Spring 1996. Between April 29 and mid-May, the announcement of this sale along with other

factors lowered petroleum prices by $1.60 per barrel. The last contract under this sales effort was awarded in August. In 30

total, the government sold 12.8 million barrels of petroleum from SPR at an average price of $17.77 per barrel to

9 companies.

The Fiscal Year 1997 appropriations act directed the sale of SPR oil to raise $220 million to fund the Reserve’s facility

requirements for that year. Sales pursuant to this act began in October and ended December 1996 with 10.2 million barrels

sold for $220.6 million.

Following these sales, the Reserve had an inventory of approximately 563 million barrels of oil, enough to cover 66 days

of net U.S. oil imports. Commercial petroleum and product stocks add another 109 days. The total, 175 days, is well in

excess of the 90 minimum required in the Agreement on an International Energy Program. The U.S. ability to cover its

agreement is negatively affected by the expected growth in imports and the decline in commercial stocks, as well as sales

from the SPR.

U.S. Department of Energy/Office of Fossil Energy, Strategic Petroleum Reserve Quarterly Report, DOE/FE-0220P-1 (Washington, DC, May 15, 1991), 28

p. 7.

Petroleum Intelligence Weekly, “President Clinton and How Not to Use the SPR,” Vol. 35 #19 (May 6, 1996), p. 7. 29

U.S. Department of Energy, An Analysis of Gasoline Markets Spring 1996, DOE/PO-0046 (Washington, DC, June 1996), p. 7. 30
88 Energy Information Administration / Petroleum 1996: Issues and Trends

Background

Inventories are necessary to ensure the uninterrupted

operation of each step of the petroleum supply system from

wells and seaports through refineries to wholesalers and

retailers and, ultimately, the consumer. Refiners use

inventories as a means to improve production scheduling,

and suppliers use inventories to buffer against expected and

unexpected supply or demand variations. Inventories can

also serve as a hedge against price fluctuations. The focus of

this analysis is on primary stocks, the target of EIA data

collection efforts. Stocks in secondary and tertiary (end user)

storage facilities are excluded from this analysis.

EIA collects data on crude oil stocks for four segments of the

industry: refining, tank farms and pipelines, production lease

sites, and Alaskan supplies in transit. Crude oil is first stored

in tanks that accumulate oil from producing wells. The

volumes held on the leased property awaiting transportation

are included in EIA’s “leases” category. Small pipelines or

tank trucks collect the crude oil and deliver it to intermediate

storage for pooling before transport via major pipelines.

Large diameter pipelines carry the crude oil to hubs, focal

points for a number of pipelines, where the crude oil is

collected for batching and redistribution to other pipelines.

The volume of crude oil progressing through the pipeline

system is included in EIA’s “pipeline fill” category. 

Tankers deliver crude oil imports to marine terminals and

refineries. The volumes associated with this activity are

included in EIA’s “tank farm” and “refinery” categories,

along with domestic volumes. Storage is required at this

juncture because tankers are off-loaded at a rate that differs

from the rate of crude oil input to refineries. Also included 31

in EIA’s inventory statistics is Alaskan crude oil being

shipped to the lower 48 states, Hawaii, and the U.S. Virgin

Islands, referred to as “Alaska in Transit.” Segregation of

crude oil by quality necessitates substantial storage capacity

throughout the supply system.32

EIA collects data on distillate and gasoline stocks from three

segments of the industry: refining, bulk terminals, and

pipelines. Domestic supplies of distillate and gasoline are

produced mainly in the Mid-Atlantic, upper Midwest,

California and the Gulf Coast, with the Gulf Coast producers

acting as the supplemental suppliers to the Northeast and

Midwest. In 1996, Gulf Coast production accounted for

around 60 percent of the distillate and gasoline consumed in

PADD I and around 15 percent of the distillate and gasoline

consumed in PADD II. Depending on price incentives,

imports can also supplement these supplies. 

Taken together, crude oil, gasoline, and distillate inventories

are usually at an annual peak in November as the heating

season gets underway. As indicated in Figure 66, distillate

stocks show more seasonality than crude oil and gasoline.

Much of the variation in distillate demand results from the

demand for heating oil, which accounted for a little over one

third of total distillate fuel oil demand in 1996. In particular,

PADDs I and II increase their demand for heating oil

considerably during the winter because central heating

systems that use heating oil are concentrated in those

regions. PADD I swings from about 30 percent of total U.S.

distillate demand in the summer to as much as 50 percent of

U.S. demand in the coldest months (usually January through

March). Stocks are especially important to winter distillate

supply. During the winter months, stocks represent 12

percent of demand. The remainder of distillate consumption

is in the form of diesel fuel for transportation applications,

which has a flatter usage pattern over the course of the year,

but cycles that run counter to the heating oil consumption

pattern. In total, distillate stocks usually peak in November

in preparation for high winter demand.

By contrast, all gasoline is consumed in the transportation

sector. This fact introduces a different set of seasonalities.

Gasoline consumption peaks during the summer vacation

period and drops off in the winter as weather conditions

inhibit travel. Therefore, gasoline stocks are high in January

and February, when demand is low and supplies are

produced as a by-product of distillate production. Gasoline

stocks are normally depleted at the primary level in August,

near the end of the driving season.

Crude oil does not show as much seasonality as distillate and

gasoline. Whatever seasonality is present is driven by

combined gasoline and distillate demand. According to data

for the 1991-1995 period, crude oil stocks peak in May to

assure that enough feedstock is on hand during the busy

"Very Large Crude Carriers” (VLCC’s) and “Ultra Large Cargo 31

Carriers” (ULCC’s) carry up to 4 million barrels of crude oil and can be

offloaded at rates that exceed 500 thousand barrels per day. The average

refinery processes about 100 thousand barrels per day. Storage is required

due to the differences in these rates.

National Petroleum Council, Petroleum Storage and Transportation, 32

Volume IV (Washington, DC, April 1989), p. 21-28.
1981198219831984198519861987198819891990199119921993199419951996

0

100

200

300

400

500

Million Barrels

Distillate

Total Gasoline

Crude Oil

Energy Information Administration / Petroleum 1996: Issues and Trends 89

Figure 66. Crude Oil, Distillate, and Total Gasoline Stocks, January 1981-December 1996

(Million Barrels)

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-811 “Monthly Bulk Terminal Report,” EIA-812

“Monthly Product Pipeline Report,” and EIA-813 “Monthly Crude Oil Report.”

gasoline season. By December, crude oil stocks are depleted when it became apparent that other countries could make up

for physical and operational reasons. the crude oil that would no longer be supplied by Kuwait and

Crude Oil

A closer look at crude oil stocks reveals a generally

declining trend in the early 1980's (Figure 66). This decline

coincided with the permanent closure of 108 refineries

between 1981 and 1986. In the ensuing nine years, crude oil

stocks remained fairly constant with two notable exceptions.

Crude oil stocks rose in July 1987 and stayed high for a year

because of the bargain prices brought on by OPEC

overproduction and discount pricing. A contributing factor

may have been the rising political tensions in the Persian

Gulf that portended a possible supply disruption and higher

prices. 

In March 1990, U.S. crude oil inventories jumped 31 million

barrels to a level 13.6 percent higher than the previous year,

due to the expectation of rising crude oil prices. Stocks

stayed at or above the average 1991-1995 level after the

August 2, 1990 Iraqi invasion of Kuwait until late fall 1990,

Iraq. During 1995 and 1996, crude oil stocks dropped

precipitously mainly due to high winter 1995-96 demand and

relatively high crude oil prices combined with an expectation

for price decreases in the future and low refining margins.

The following sections describe where the declines in

inventory occurred.

Looking beyond seasonal ups and downs, days supply of 33

crude oil reveals a different pattern of near constant decline

(Figure 67). Although crude oil input to refineries has

increased by an average of almost 1 percent per year since

1981, days supply of crude oil in inventory has gradually

decreased because stocks have failed to keep pace with the

growth of inputs to refineries. In 1996, there were an average

22 days supply of crude oil resident at various segments of

the industry compared to 24 at the end of 1994.

Days supply of crude oil is defined as end-of-month inventory divided 33

by the following month’s crude oil input to refineries. Not all of this volume

is available as input to refineries.
1981198219831984198519861987198819891990199119921993199419951996

0

20

40

60

80

100

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C rude Oil 

D istillate

To tal G as oline

90 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 67. Days Supply of Crude Oil, Distillate, and Total Gasoline

(Days)

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-811 “Monthly Bulk Terminal Report,” EIA-812

“Monthly Product Pipeline Report,” and EIA-813 “Monthly Crude Oil Report.”

Crude Oil Stocks Declined at Tank

Farms

Stocks in EIA’s tank farms and pipelines category represent

almost 60 percent of all crude oil held in inventory (Table 7).

These stocks declined 14 million barrels during 1995 and a

further 7 million barrels in 1996. A considerable portion of

the reduction was recorded in PADDs III and V, where crude

oil is produced domestically. The decline in this category is

more appropriately associated with tank farms. Stocks at

pipelines represent pipeline fill and, therefore, are

operational (rather than discretionary) in nature. As such,

pipeline fill stays fairly stable from year to year. 

Almost a third of all crude oil stocks are maintained at

refineries. These stocks were essentially unchanged during

1995, but then decreased 5 million barrels in 1996. The

decline was spread fairly evenly across the PADD regions.

This reduction translated into lower days supply of crude oil

in inventory. Several big refiners pared back to 4 to 5 days

of supply on hand. The average for all refiners was 6 days 34

at the end of 1996, down from 7 at the end of 1994. With the

lower stocks, refiners risked cuts in refining runs when

supply disruptions occur. In January 1996, a reduction in

refinery runs was forced on a number of Gulf Coast refiners

when imports from Mexico and the North Sea were briefly

disrupted at the end of the previous year.35

The crude oil stored on leases awaiting transportation is

recorded in EIA’s “Leases” category. The drop in domestic

production has resulted in less inventory being held at

production leases. These stocks decreased from 18 million

barrels in 1994 to 17 million barrels in 1995, and remained

at 17 million barrels in 1996. 

A drop-off in crude oil deliveries from Alaska to refiners in

Hawaii, California, the Gulf Coast, and the U.S. Virgin

Islands was evident in 1996, when a decline from 1994 of

roughly 5 million barrels in stocks was recorded (Table 7).36

Apart from the normal variation in this series, deliveries of

Alaskan crude oil to the Far East started in July 1996 at a

rate that averaged 73 thousand barrels per day through the

end of the year, providing the basis for some of this decline.

Petroleum Intelligence Weekly, “Refiners Test Limits of Lean Inventory 34

Strategy,” Vol. 35 #03, (January 15, 1996), p. 1.

Petroleum Intelligence Weekly, “Refiners Test Limits of Lean Inventory 35

Strategy,” p. 1.

A company was added to the survey frame in 1994 resulting in a higher 36

estimate for Alaskan crude in transit compared to 1993.
Energy Information Administration / Petroleum 1996: Issues and Trends 91

Table 7. Average Crude Oil Inventories by Industry Sector

(Million Barrels)

Sector 1994 1995 1996

Difference

(1996-1994)

Refiners 100 100 95 -5

Tank Farms and Pipelines 198 184 177 -21

Leases 18 17 17 -1

Alaska in Transit 20 21 15 -5

Total 336 322 304 -32

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

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,”and EIA-813 “Monthly Crude Oil Report.”

Crude Oil Stocks Declined in Gulf

Coast Area

Of the 32 million barrel decline in crude oil inventories from

1994 to 1996, 19 million barrels occurred in PADD III, the

Gulf Coast area (Figure 68) where crude oil production and

refining are concentrated. Some of the 7 million barrel drop

in PADD II (Midwest) stocks may be related to a reduction

in stocks in Cushing, Oklahoma, the spot market for sales of

West Texas Intermediate crude oil. 

Days supply of crude oil varies from PADD to PADD. The

regional difference can be traced as far back as 1981. In

1996, PADD I, the East Coast, had 11 days of crude oil

supply, while PADD V (West Coast) had 28 days supply.

The average for all PADDs was 21 days. One explanation for

this difference is the lack of oil production (and the

associated stocks at leases, tank farms and pipelines) in any

significant volumes in PADD I. Furthermore, PADD I

receives all of its supplies by tanker or barge that, unlike

pipeline supplies, are unaccounted for in EIA’s data

collection efforts while in transit. Over 90 percent of the 37

crude oil inventories in PADD I are stored directly at

refineries, compared to less than a third in other PADDs.

Distillate

During the early- to mid-1980's, distillate stocks were on a prices. Average distillate stock levels for 1996 finished 19

generally declining path (Figure 66) due largely to petroleum million barrels below the 1994 level. 

industry downsizing. In the late 1980's, three consecutive

winters with unusually cold weather produced unexpected In terms of days supply, inventories of distillate have 38

demand for distillate that was supplied largely through decreased slowly since 1981, due to an ever increasing

inventory withdrawals and resulted in historically low demand for this product (Figure 67). This decline accelerated

inventory levels. The following two winters were warmer

than normal, causing a decline in demand and, thus,

requiring less from inventory. By 1993, prices for distillate

were expected to rise with the introduction of low sulfur

diesel in October 1993. The increase in price induced a stock

build at a time when environmental regulations imposed by

the Clean Air Act Amendments of 1990 reduced the

fungibility of diesel fuel and heating oil inventories. While

the loss in fungibility may have increased stocks for a while

after the introduction of the low sulfur diesel fuel, other

market forces have acted to lower distillate stocks from

levels seen before the introduction of the new product.

The decline in inventories that started in 1995 accelerated in

1996 when cold weather in January and February forced

refiners to place a huge call on distillate inventories, leaving

those inventories well below the 1991-1995 average. A late

cold spell in April 1996 drove distillate demand to relatively

high levels at a time when gasoline production should have

been rising and distillate production declining. Strong diesel

demand in the summer of 1996, attributable in part to robust

economic growth, slowed the normal seasonal rebuilding of

distillate stocks. Distillate production and imports were

strong but not strong enough to rebuild stocks to the 1991-

1995 average levels. The lack of normal storage

replenishment in July, historically the biggest build month of

the year, began to raise concerns. Through the end of the

year replenishments were smaller than normal as prices for

distillate in the future were expected to be less than current

in 1996. As Figure 67 illustrates, the days supply for

distillate is higher than for either crude oil and gasoline,

primarily due to the more seasonal nature of distillate

consumption. Also, a large share of distillate consumption

takes place away from the Gulf Coast refining center,

The one exception is supplies from Alaska, referred to as “Alaska In 37

Transit”, which are included as such in totals for PADD V.

The winters of 1987-1988 and 1988-1989 were colder than normal, and 38

a severe cold shock occurred during December of the winter of 1989-1990.
1994 1995 1996 1994 1995 1996 1994 1995 1996

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92 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 68. Crude Oil, Distillate, and Total Gasoline Stocks by PADD Region, 1994-1996

(Million Barrels)

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-811 “Monthly Bulk Terminal Report,” EIA-812

“Monthly Product Pipeline Report,” and EIA-813 “Monthly Crude Oil Report.”

necessitating proportionately more stocks in reserve. In little discretionary storage capacity in comparison to bulk

1996, the industry had an average of 33 days supply of terminals which are sized to accommodate large seasonal

distillate on hand at various segments of the industry. swings in supply and demand. Furthermore, bulk terminal

Distillate Stocks Declined at Bulk

Terminals

Looking at the distillate primary inventory series , several 39

things are clear (Table 8). Pipeline and refinery inventory

levels changed very little compared to bulk terminal

inventories. Due to the physical and operational

requirements, pipeline fill rarely shows a significant change.

Much of the stocking done at refineries is operational in

nature, as well, with tanks collecting distillate production to

create batches for shipping. As such, refineries have very

operations seem to be the target of cost-cutting efforts

because of the direct variable costs associated with storage

in this segment of the logistics system. Unlike storage space

at refineries or in pipelines, which is viewed as a sunk cost

and does not represent either a direct expense or opportunity

cost to refiners (apart from the interest costs of carrying

working capital), storage at bulk terminals has a variable cost

of about 1 cent per gallon per month.40

Although not indicated in Table 8, U.S. distillate inventories

were low in 1989, much of which can be attributed to a

reduction in bulk terminal holdings. After that, bulk terminal

inventories increased, perhaps in response to the shortages

that occurred at the end of 1989. The overall distillate

inventory decrease in 1996 occurred primarily at bulk

terminals.

EIA collects primary inventory data from three groups of petroleum 39

product inventory holders: refiners, pipelines, and bulk terminals. Included

in the “Refinery” category are bulk terminals that make finished gasoline by

mixing blend stocks and/or oxygenates. These facilities are required by EIA EIA calculation based on discussions with energy industry sources.

to report their inventories as “Refinery” inventories using the EIA-810 Form, These costs are not completely variable in that each gallon not stored leads

“Monthly Refinery Report.” Although blending operations do not affect the to a penny saved; some contract terms require a lease of multiple weeks or

middle distillates, EIA data are adjusted in the following section so that the months regardless of whether the tankage is used. Furthermore, in order for

distillate stocks these blenders report are included in the “Bulk Terminal” the facility to remain economically viable, sometimes fixed tankage costs

category. The purpose of this is to more accurately reflect operations. have to be prorated to a smaller stored volume.

40
Energy Information Administration / Petroleum 1996: Issues and Trends 93

Table 8. Average Distillate Inventories by Industry Sector

(Million Barrels)

Sector 1994 1995 1996 (1996-1994) 1

Difference

Refinery 34 32 31 -3

Bulk Terminal 67 68 51 -17

Pipeline 25 26 25 1

Total 126 126 107 -19

In other published EIA data, bulk terminals that make finished gasoline by mixing blend stocks and/or oxygenates are included in the “Refinery” 1

category. In the following entries, EIA data were adjusted by removing the gasoline stocks these blenders report from the “Refinery” category and

including the volumes in the “Bulk Terminals” category. 

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

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-811 “Monthly Bulk Terminal Report,” and EIA812 “Monthly Product Pipeline Report.”

Distillate Stocks Declined on the East

Coast

Distillate inventories at bulk terminals did not decline

uniformly throughout the U.S. Much of the change occurred

in PADD I, the East Coast, where there is a concentration in

bulk terminals (Figure 68). The seasonal swings in total U.S.

distillate inventories are mainly due to the seasonal swings

in PADD I. The annual U.S. inventory average had shown an

increase from 123.2 million barrels in 1989 to 136.3 million

barrels in 1990. The year-to-year change in PADD I, where

these inventories increased by about 15 million barrels, alone

accounted for more than the U.S. total build.

In 1994, distillate stocks in PADD I (and the nation as a

whole) were high, and a modest draw down occurred over

the winter of 1994-95. With little need to build stocks,

refiners drew off the excess and entered the winter of 1995-

96 slightly below average. A combination of extended cold

weather in winter 1995-96, high diesel demand, high crude

oil prices, and expectations that prices would be falling

depleted stocks and discouraged rebuilding. The annual

averages for U.S. distillate stocks declined from 126 million

barrels in 1994 to 107 million barrels in 1996. Eighty percent

of the change was recorded in PADD I.

Days supply of distillate for the PADDs I, II, and III, which

are integrated by the pipeline system that connects the

refineries in PADD III with the consumption areas in PADDs

I, II, and III, averaged 33 days in 1996. In 1994, the eastern

half of the country averaged 42 days supply and 41 days in

1995. The western half of the country had 27 days supply in

1996 compared to 29 days in 1994. This calculation is

influenced by the close proximity of refining and

consumption in California.

Motor Gasoline

Like crude oil and distillate, gasoline stocks were on a

generally declining path in the early 1980's (Figure 66)

because of petroleum industry downsizing. This downward

trend continued in the 1990's, with significant declines

observed during the early 1990's and again in 1995 and 1996.

Almost one-half of the decline between 1990 and 1996 in

total domestic gasoline stocks occurred in 1990 and 1991

when crude oil and petroleum product prices rose and

gasoline demand fell. Between July 1990, just before Iraq

invaded Kuwait, and September 1990, the world price of

crude oil climbed from about $16 per barrel to $36 per

barrel. The wholesale price of gasoline rose from 70 cents 41

per gallon to almost $1 per gallon over this same period. The

high product prices in the second half of 1990 and the

economic recession that lasted through most of 1991 caused

gasoline demand to decline from an average 7.3 million

barrels per day in 1989 to an average 7.2 million barrels per

day in 1992. Total gasoline inventories during 1991 averaged

about 16 million barrels less than inventories during 1990.

Between 1992 and 1993, inventories of total gasoline slowly

recovered. This occurred despite a large drawdown of

finished gasoline inventory during the third quarter of 1992

to prepare for the first winter season for oxygenated gasoline.

Tanks of conventional unleaded gasoline were emptied to

make room for oxygenated gasoline. The third quarter stock

draw was quickly reversed in the fourth quarter of 1992

because of the extra oxygenates required during the winter

months. 

Energy Information Administration, The U.S. Petroleum Industry Past 41

as Prologue 1970-1992, DOE/EIA-0572 (Washington, DC, September 1993),

p. 57.
94 Energy Information Administration / Petroleum 1996: Issues and Trends

Although stocks were lower than normal in early 1995,

following the startup of the reformulated gasoline program,

inventories did not recover in late 1995 and early 1996 as

they normally do following the end of the summer driving

season. By that time, the industry was anticipating price

declines in the crude oil feedstock as indicated by

backwardation in the futures market (i.e., the price of crude

oil several months in the future is less than in the current

month). This provided an incentive to hold-off making 42

gasoline to stock. One cause for the anticipated lower crude

oil prices was the possible sale of Iraqi crude oil. Gasoline

stocks remained below average 1991-1995 levels throughout

1996.

Days supply of total gasoline has decreased (Figure 67) since

1981 because stock levels have failed to keep pace with a 1.1

percent per year growth in gasoline consumption. The

decline in the days supply accelerated after 1995. In 1996,

the United States had 26 days supply of total gasoline stocks,

compared to 29 in 1994.

Inclusion of oxygenates increased the total days supply by 2

days at the end of 1996. Oxygenates — primarily methyl

tertiary butyl ether (MTBE) and fuel ethanol — did not play

a significant role in gasoline supply until late 1992, when the

oxygenated gasoline program started. In January 1993, EIA

stepped up efforts to collect data on oxygenates stocks to

supplement the information on gasoline and gasoline

blending components already collected. Inventories of

oxygenates reported by EIA increased by about 8 million

barrels between December 1992 and January 1993, primarily

because of the extension of EIA oxygenate surveys to

pipelines, bulk terminals, and oxygenate producers.43

Nevertheless, even with the inclusion of oxygenates in the

accounting of all gasoline stocks, these stocks still declined

in 1995 and 1996. 

Gasoline Stocks Declined at Refineries

and Bulk Terminals

In 1994, total gasoline stocks (finished gasoline plus gasoline

blending components) averaged 214 million barrels. By

1996, the average dropped 6 percent to 201 million barrels.

A comparison of annual average stock levels for the refining,

pipeline, and bulk terminals segments of the industry

indicates that a majority of the reduction in gasoline stocks

has taken place at refineries and bulk terminals (Table 9). 

Refinery inventories of total gasoline stocks represent about

a third of total domestic gasoline stocks. Refineries also

account for about 35 percent of total oxygenate inventories.

Large drops in refinery inventories occurred in late 1995,

causing the average for the year to decline from 74 million

barrels in 1994 to 69 million barrels in 1996. 

A reduction in gasoline stocks also occurred at the bulk

terminal level, which accounts for about 40 percent of the

total gasoline stocks. The reduction at bulk terminals

represents an effort to lower direct variable costs associated

with storage in this segment of the logistics system. In 1994,

88 million barrels of total gasoline stocks were stored in bulk

terminals compared to 80 million barrels in 1996. As shown

in Table 9, most of this reduction occurred in 1995.

Between 50 and 60 million barrels of gasoline are required

to fill the domestic pipeline system so that refineries can

supply remote bulk terminals on an ongoing basis. Pipeline

fill shows little variance from month-to-month and year-toyear and represents about a quarter of total gasoline

inventories. For the most part, gasoline inventories in

pipelines consist of finished product since blending

components stocks are held mainly at refineries.

Gasoline Stocks Declined in Eastern

Half of Country

The overall downward trend in total gasoline stocks appeared

predominantly in PADDs I, II, and III, which account for

over 80 percent of bulk terminal gasoline supplies

(Figure 68). Clearly, the decline in stocks at the bulk

terminals impacted the totals recorded in these PADDs. 

Days supply of total gasoline for the PADDs I, II, and III,

averaged 32 days in 1996. In 1994, the eastern half of the

country averaged 36 days supply and 34 days in 1995. The

western half of the county had 26 days supply in 1996,

unchanged from 1994.

Energy Information Administration, “Summer 1996 Gasoline 42

Assessment,” Weekly Petroleum Status Report, DOE/EIA-0209(96/14)

(Washington, DC, April 10, 1996), p. xi.

Before January 1993, only refineries were required to report stocks of 43

oxygenates. Refinery oxygenate stocks were reported by EIA in various

publications under the category “Other Hydrocarbons/Alcohols.” Beginning

in January 1993, the sample frame for oxygenate inventories was expanded

to include pipelines, bulk terminals, and oxygenate producers. The inventory

of “Other Hydrocarbons/Hydrogen/Oxygenates” on January 31, 1993, was

14,016 thousand barrels. By comparison, the inventory of other

hydrocarbons/alcohol at refineries on December 31, 1992, was 6,876

thousand barrels. Sources: Energy Information Administration, Petroleum

Supply Annual 1993, Volume 2, DOE/EIA-0340(93)/2 (Washington DC, June

1994), pp. 26, 458 and Petroleum Supply Annual 1992, Volume 1, DOE/EIA0340(92)/1 (Washington DC, May 1993), p. 69.
Energy Information Administration / Petroleum 1996: Issues and Trends 95

Table 9. Average Gasoline Inventories by Industry Sector

(Million Barrels)

Sector 1994 1995 1996 (1996-1994) 1

Difference

Refinery 74 74 69 -5

Bulk Terminal 88 81 80 -7

Pipeline 52 52 51 -1

Total 214 206 201 -13

In other published EIA data, bulk terminals that make finished gasoline by mixing blend stocks and/or oxygenates are included in the “Refinery” 1

category. In the following entries, EIA data were adjusted by removing the gasoline stocks these blenders report from the “Refinery” category and

including the volumes in the “Bulk Terminals” category. 

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

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-811 “Monthly Bulk Terminal Report,” and EIA-812

“Monthly Product Pipeline Report.”

Short-Term Influences on Petroleum

Inventories

The short-term influences of expected crude oil and product somewhat in the summer of 1996 when it became apparent

prices, refining margins, the cost of inventories, and the risk that extra crude oil would not be supplied to the market, but

of stockouts affect refinery managers’ day-to-day decisions persisted throughout 1996. 

about inventory levels. Some of these influence marketers’

inventory decisions as well. The impact of the 1995-96 shortterm events on stock levels is discussed below.

Expected Price Drop Discouraged

Stock Building

Figure 69 shows the difference between prices for crude oil

on the New York Mercantile Exchange for delivery three

months into the future minus prices for crude oil for delivery

one month into the future. Stock levels are also provided.

Since prices for delivery one month in the future are similar

to current prices, the difference highlighted in the figure is

equivalent to the expected change in the price of crude oil.

Figure 69 shows that, from the end of 1995 and through

1996, the decline in stocks followed the decline in the

expected price of crude oil. 

In 1995, the expected price for crude oil never exceeded the

current price and the market was “backward.” By December

1995, the petroleum supply/demand balance had grown tight

as crude oil exports from Mexico were reduced by damage

from Hurricane Roxanne. However, petroleum traders

expected the supply situation to ease, causing prices to

decline. With the expectation for significantly lower

petroleum prices in the future, it appeared more cost

effective to forego purchases until prices came down. This

strategy minimized the price risk associated with purchasing

a commodity that is overvalued in the present, only to have

it become less valuable in the future. In February 1996, the

U.N. opened discussion of Iraq’s oil-for-food proposal. The

ongoing talks and other market developments drove the

market into further backwardation. Backwardation eased

44

Low Margins and Poor Profitability

Forced Industry to Trim Costs

A barometer of the relative profitability of refining is the

gross refining margin, i.e., the difference between the cost of

the crude oil feedstocks and the price refiners receive for

petroleum products produced. Gross refining margins are

expected to cover not only refining costs but other costs as

well, including logistics and marketing cost. While refiners

may realize revenues from other activities, refining margins

remain the most important source. Low margins forced

refiners to trim costs in such areas as inventories.45

In 1994, gross refining margins edged downwards as

increases in product prices failed to match increases in crude

Chapter 6 provides a more detailed review of backwardation and the 44

futures market.

Inventory cost reduction is frequently referred to as a “just-in-time” 45

inventory program. However, this does not correspond to the conventional

use of the term in economic theory. Just-in-time inventory programs involve

the sharing of both the benefits (i.e., lower inventory carrying costs) and the

risks (e.g., running out of stocks) between suppliers and a manufacturer.

Inventory reduction programs in the petroleum industry are generally not

characterized by risk sharing but represent the recognition by individual firms

that the benefits of carrying lower inventories are greater than the incremental

risk assumed or that the risks of stocking out for a given inventory level are

now lower.
Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec

0

100

200

300

400

M illio n B arrels

1992 1993 1994 1995 1996

Sep Dec M ar Jun Sep Dec M ar Jun Sep Dec M ar Jun Sep Dec M ar Jun Sep Dec

-6.00

-5.00

-4.00

-3.00

-2.00

-1.00

0

1.00

2.00

D o lla rs

1992 1993 1994 1995 1996

96 Energy Information Administration / Petroleum 1996: Issues and Trends

Crude Oil Stock Levels

Figure 69. Crude Oil Stock Levels and Differential in Expected Future Prices

(Dollars and Million Barrels)

Source: Energy Information Administration (EIA), Forms EIA-810 “Monthly Refinery Report,” EIA-813 “Monthly Crude Oil Report,” and Reuters

News Service, various dates.

Differential in Expected Futures Prices
Energy Information Administration / Petroleum 1996: Issues and Trends 97

oil prices. The 1995 refining margins were at their lowest 46

since 1987 and the industry turned to trimming inventories.

Results for 1996 suggest refining margins were improved

over 1995.47

Cost of Maintaining Inventories

Escalated In 1996

The cost of maintaining petroleum inventories is calculated

by multiplying the current price of the material (crude oil,

distillate, or gasoline) by the interest rate and adding the

operating cost of tankage, about 30 cents per barrel for crude

oil and 42 cents per barrel for product. The cost of 48 49

inventories has increased since the beginning of 1994,

mainly due to increases in prices for both crude oil and

refined products. In spring 1996, these prices were driven up

by marketers purchasing petroleum products to fill

immediate needs. The price of crude oil (measured as the

U.S. refiners average acquisition cost of imported and

domestic crude) grew from $17.75 per barrel in January 1996

to $21.60 per barrel in April 1996. Over the same time

period, distillate heating oil spot prices rose from 50.73 cents

per gallon to 80.00 cents per gallon, and (reformulated)

gasoline spot prices rose from 51.05 cents per gallon to 77.54

cents per gallon. 50

Multiplying these prices by interest rates and adding tankage

(operating) costs gave a figure of 42 cents per barrel per

month for maintaining crude oil inventories in January 1995.

The increase in the acquisition cost of crude oil pushed the

inventory cost to as much as 45 cents per barrel in April

1996. The cost of distillate and gasoline inventories were 57

cents and 60 cents per barrel, respectively, in January 1995.

By April 1996, these costs went to 61 cents per barrel for

distillate and 62 cents per barrel for gasoline. This upward

trend in costs, while small in comparison to the influence of

expected lower prices in the future, could only effect

petroleum inventory levels negatively.

Risk of Stockouts Was Reassessed

Refiners keep crude oil, distillate, and total gasoline stocks

on hand to ensure a constant flow of product to consumers.

The risks associated with supplies include embargoes and

strikes as well as logistical problems in production,

pipelines, and tanker/barge movements. Refiners and

marketers informally assess risk of supply disruptions on an

ongoing basis and prepare inventories accordingly. Demand

surges, such as the one produced by the cold snap in January

1994, can also lead to stockouts if too little supply is in

place.

The lower number of days supply on hand may suggest that

petroleum supplies are believed to be more secure than

previously thought and the risk of a disruption is lower. It

may be that information systems and operational changes

allow refiners to work with lower inventories without

increasing risk of stockouts. The lower days supply may also

be indicative of a belief that, thus far, decrements to

inventories have not been large enough to increase the

probability of product stockouts appreciably. Refiners’

attitude toward risk is also a determinant of petroleum stock

levels. Refiners may simply be willing to shoulder more risk

than before, again leading to lower stocks. As previously

documented, a policy of lower crude oil inventories has led

to several reductions in runs at refineries.

Long-Term Influences on Petroleum

Inventories

There are a variety of long-term influences affecting

inventory levels, including increased offshore stocks,

enhanced inventory management through improved

information technology, consolidation of storage facilities,

the shift to short-haul crude oil, the introduction of clean

products, and the increase in secondary stocks. These trends

are subtle and have almost no impact on the day-to-day

inventory level decisions, but do affect inventory levels over

time. Some of these forces represent reactions to the

persistently poor financial performance in the refining

industry.51

Offshore Stocks Also Declined

One explanation for some of the decline in petroleum stocks

is the growth of stocks in facilities in the Caribbean.

According to the Weekly Petroleum Argus, though, stocks at

Energy Information Administration, U.S. Energy Industry Financial 46

Developments 1995 First Quarter, DOE/EIA-0543(95/1Q) (Washington, DC,

June 1995), p. 9.

A thorough discussion of the 1996 refining margin is contained in 47

Chapter 7.

Energy Information Administration, Petroleum Supply Monthly, 48

DOE/EIA-0109(96/03) (Washington, DC, March 1996), p. xix. Estimated

cost of leasing commercial storage space.

Estimated cost of leasing commercial storage space, according to 49

discussions with industry sources.

Reuters News Service, various dates. 50

U.S. Department of Energy, An Analysis of Gasoline Markets Spring 51

1996, DOE/PO-0046 (Washington, DC, June 1996), p. 58-61.
98 Energy Information Administration / Petroleum 1996: Issues and Trends

independent storage terminals there went from 27.1 million to shorter transit times, short-haul crude oil allows refiners

barrels at the end of 1994 to 17.1 million barrels at the end to reduce inventories because of the smaller cargo sizes. Less

of 1995 then 15.5 million barrels at the end of 1996. storage is required because the smaller vessels used are 52

Therefore, the activity in the Caribbean cannot substantiate offloaded at slower rates that more closely approximate

the decline in U.S. crude oil, distillate, and total gasoline refinery input rates. The ability for quick resupply also

stocks. It appears that the same forces causing stocks to factors into a reduction in stocks.

decline in the United States have affected Caribbean stocks

as well. In order to have a negative impact on inventory levels,

Improved Information Systems May

Have Facilitated Decline in Stocks

Improved information technology has given managers better

tools needed to optimize stock levels. Computer programs

and tracking systems for monitoring sales, production and

inventories have become more sophisticated in recent years.

While the availability of more accurate and more timely data

may permit maintenance of lower inventories, the impact 53

of these technological improvements is difficult to quantify

because of the presence of other trends in EIA data.

Closure of Storage Facilities May Have

Reduced Stocks

Information on specific tank farm and bulk terminal sites is

scarce. In an effort to reduce reporting burden, EIA collects

stock information on a PADD basis, not by individual

terminal. Without site-specific data to monitor trends, it is

difficult to determine to what extent the decline in stocks is

attributable to the closure of terminals. 

Several industry publications have indicated that major oil

companies are divesting their oil terminals and that

independent terminal operators are buying some of these

properties. However, it is unknown how much storage is

being decommissioned by the new owners.54

Shift to Short-Haul Crude Oil Had Little

Impact

With the decline in domestic production, crude oil imports

have been increasing, particularly imports from the Western

Hemisphere, referred to as “short-haul” crudes. In addition

imports from long-haul sources would have had to decline

from one period to the next. Imports from outside the

Western Hemisphere decreased only 190 thousand barrels

per day in 1995 and another 124 thousand barrels per day in

1996. The reduction in stock requirements attributable to this

shift to short haul sources is small, particularly in

comparison to what stocks should have been given the

growth in demand and a decline in domestic sources of crude

oil.

Product Quality Regulations Had Little

Long-Term Influence

Beginning in 1992, the introduction of various air quality

regulations has had broad ranging impacts on the petroleum

industry, including storage management. These regulations 55

covered Reid vapor pressure of gasoline (June 1989 and

January 1992), the oxygenated gasoline program in carbon

monoxide nonattainment areas (November 1, 1992), low

sulfur diesel fuel (October 1, 1993), and reformulated

gasoline (January 1, 1995).

Previously, distillate grades (heating oil and diesel fuel)

could be stored together because of their similar

specifications. Inventory planners could build total distillate

inventories on the basis of demand expectations for heating

oil and diesel fuel. Any unexpected demand for either

product could be pulled from the other’s inventories and

production streams. With segregation, a cushion against

unexpected demand had to be maintained for each product,

which led to an increase in inventories. The increase in 56

distillate stocks after the start of the low sulfur diesel

program in October 1993 (4 percent rise in 1994) may, in

part, be attributable to the inefficiencies introduced by the

legislation. It is more likely, though, that this increase was

related to the expectation that distillate prices would rise,

thus making inventories more valuable. Since then, average

Weekly Petroleum Argus, various issues. 52

Fuel Technology and Management, “Lower Gasoline Inventories Do 53

Not Mean Higher Prices," (March/April 1996), p. 9.

Energy Information Administration, Storage and Transportation 54

Changes Since 1989, DOE/EIA-Draft Report (Washington, DC, June 1996),

p. 5. Sidebar.

A more thorough discussion of the impacts of environmental regulations 55

is contained in Energy Information Administration, “Recent Trends in Motor

Gasoline Stock Levels” and “Recent Distillate Fuel Oil Inventory Trends,

What EIA Data Show,” Petroleum Marketing Monthly, DOE/EIA0380(96/06) (Washington, DC, June 1996), pp. xxi-xxiv.

Energy Information Administration, Petroleum Marketing Monthly, 56

“Distillate Fuel Oil Assessment for Winter 1995 - 1996,” November 1995,
Energy Information Administration / Petroleum 1996: Issues and Trends 99

distillate stocks declined, meaning that other influences have

outstripped the effects of environmental regulations. In some

situations, suppliers have found it economical to substitute

a clean fuel for a conventional fuel, rather than maintain

additional stocks of the conventional fuel.

Fuel specification regulations have had an even smaller

influence on gasoline stocks. EIA survey data for both

refineries and bulk terminals indicate that the oxygenated

and reformulated gasoline programs, required by the Clean

Air Act Amendments of 1990, have changed the seasonality

of stocking patterns from a third quarter build to a draw. The

third quarter draw is necessary to draw down stocks for

oxygenate blending in preparation for the start of the

oxygenated season. Further research failed to identify any

meaningful differences in stocking patterns between

refineries that produce oxygenated and reformulated

gasolines and refineries that produce only conventional

gasolines, or between states that require the new clean

gasoline and states that do not. The overall downward trend

in inventories was apparently greater than any of the

inefficiencies introduced by the Clean Air Act Amendments.

Refiners and bulk terminal operators made operational

changes to meet the challenge of providing the additional

gasoline types required by the Clean Air Act Amendments

while still reducing stocks. For example, some oxygenate

was moved from refineries to terminals, and in-line blending

was added at bulk terminals, allowing operators to eliminate

mid-grade storage in some cases. (Bulk terminal operators

are able to make midgrade gasoline by blending premium

and regular grades.) The willingness of companies to

participate in exchange agreements and shared storage also

may have allowed suppliers to accommodate new, clean

products without increasing storage requirements.

Stocks Declined at Electric Utilities

An obvious cause of decline in distillate and gasoline stocks

at the primary level may be an increase in stocks at the

secondary and consumer levels. At the consumer level, EIA

collects information on distillate stocks at electric utilities.

Electric utilities accounted for less than 2 percent of

distillate consumption in October 1996. The pattern of stocks

since 1992, though, shows a definite decline in 1996, when

consumption increased (Table 10). Higher prices served as

a disincentive to replenishing stocks. Although utility stocks

declined, this cannot be extended to other consuming sectors

since utilities have some flexibility regarding the fuels they

burn. Information on other secondary and tertiary stock

levels is sketchy, at best.

Conclusion/Outlook

The 1995-96 decline in crude oil, distillate, and gasoline

inventories occurred mostly at tank farms and bulk terminals,

the point in the supply system most able to respond to

changing supply economics. The declines in regional stocks,

therefore, reflect the geographic distribution of these

facilities, with the greatest reductions occurring in stocks of

crude oil on the Gulf Coast and of products in the Northeast

and Midwest.

The main determinant of inventory levels over this period

was expected to be the increasingly stringent environmental

regulations, requiring industry to stock a growing number of

grades, thereby putting upward pressure on inventories. But

this was overwhelmed by the downward pressure exerted by

two other factors: the lower expected prices for crude,

gasoline, and distillate; and the ongoing, poor financial

performance of the downstream industry. Many other factors,

such as the shift to shorter-haul crudes, offshore storage, and

the cost of borrowing, had a much more minor impact on the

industry's stock policy, but generally encouraged further

reductions. The net result was new record lows for stocks of

crude oil, distillate, and gasoline, which, in turn, contributed

to higher price volatility.

Still, many questions concerning petroleum inventories

remain unanswered. The most notable question is to what

extent stock levels drive price volatility. The question of

adequacy also persists, since the lower stock levels were

untested during the mild 1996-97 winter. Lastly, the outlook

for stocks brings into question the relative influences of

expected prices and financial performance. Definitive

answers to these questions must await quantitative analyses

of the correlation between stock levels and prices, cost, and

events such as the start of the clean fuels program. The

downstream mergers recently announced (Texaco/Shell,

Marathon/Ashland) give evidence that the industry expects

low margins to continue, meaning that discretionary stocks

will be minimized. From the standpoint of prices, changes in

the supply situation are expected to stimulate stock building,

since future prices are predicted to be equal to, or greater

than, current prices.

With the flow of Iraqi crude oil and the end of the world’s

peak petroleum consumption season (winter), expected

prices are already more in line with current prices for

February 1997 (after adjusting for seasonal trends). The

futures prices on the New York Mercantile Exchange

provides evidence of this trend. EIA forecasts that as the 57

crude oil supply situation eases and current and expected

prices remain comparable, crude oil inventories are expected

Reuters News Service, various dates. 57
100 Energy Information Administration / Petroleum 1996: Issues and Trends

Table 10. U.S. Electric Utility Distillate Consumption and Ending Stocks - October

(Million Barrels)

1992 1993 1994 1995 1996

Stocks 15.4 14.8 15.6 15.6 14.5

Daily Consumption 0.792 0.897 0.811 0.932 1.477 

Source: Energy Information Administration (EIA), Form EIA-759 “Monthly Power Plant Report.”

to go from 12 percent to within 3 percent of the 1991-1995 If the financial performance proves to be a more important

average levels by the end of the of 1998 while gasoline will factor than shown historically, then stocks may not recover

go from 9 percent to within 4 percent of the historic average. to the extent forecast. Data for 1997 indicate the recovery in

A continuing tightness in world distillate markets, however, stocks may have already started; EIA’s projections are

may cause distillate inventories to remain low (about 10 predicated on normal weather. If the intervening heating

percent below the 1991-1995 average at the end of 1998). seasons prove to be unusually cold or if logistical problems 58

occur, particularly with distillate, inventories could be tested

and prices may go higher.

Energy Information Administration, Short-Term Energy Outlook, 58

DOE/EIA-0202(97/Q2) (Washington, DC, April 997), p. 29.
Energy Information Administration / Petroleum 1996: Issues and Trends 101

The development of futures markets in crude oil and petroleum products was one of the most important

changes to oil and gas markets over the past two decades. As trading volume has grown, the ability of oil

industry participants to hedge their price risk has improved since the increased volume has made it possible

to take or liquidate a position without creating undue volatility in the futures price. But with the growth of futures

trading, the same questions and concerns that pertain to futures markets for other commodities have arisen:

Why and how do traders use the futures markets? Do large traders manipulate prices? This chapter examines

these questions while focusing on an important trend: the end — at least for now — of the phenomenal growth

in crude oil and petroleum product futures trading.

6. Petroleum Futures Markets:

Volatile Prices, Controversial Functions, Stagnant Volumes

The Uses of Futures Markets

The Energy Information Administration is interested in

futures markets because of the profound impacts that those

markets have had on the marketing of crude oil and

petroleum products. This chapter describes some

fundamental investigations into the workings of the futures

market that found that energy futures markets have

performed as economic theory has predicted.

The theory of how futures markets are used and prices

determined was originally derived for agricultural

commodities. That theory should also apply to any storable

commodity, such as crude oil and petroleum products. Grain

markets and petroleum markets are subject to similar types

of empirical testing because they both have large variations

in stock levels every year due to periods of stockbuilding

followed by gradual stock depletions. In spite of the fact that

the stocking pattern in energy markets is more complex than

in grain markets, using the same type of stocking and price

correlation analysis as are used in grain markets shows that

energy futures markets behave similarly to agricultural

commodities, in a manner consistent with economic theory.

To understand this behavior, it is first necessary to

understand the reasons for the existence of futures markets.

To the casual observer, futures markets appear irrational and

mysterious. However, the basic workings of futures markets

are rational and easy to understand. Fundamental to

understanding the futures markets is knowing how they are

used in "hedging," to minimize the risk of price changes (see

box, p. 102). 

Economic theory asserts that decisions to hedge depend 60

upon several factors:

! The futures contract should accurately reflect the

product being hedged. If the futures contract specifies

delivery of a commodity that differs greatly from the

commodity being hedged, the futures price movements

may not eventually converge to the corresponding spot

market price, making the futures contract much less

useful as a hedging device.

! There should be a close correlation between changes

in the spot price and changes in the futures price.

Even if a futures contract gives a very close specification

of the product being hedged, if the futures and spot

prices do not change at approximately the same rate, the

futures contract will not be an effective hedging

instrument. For example, a newly listed futures contract

may have such small trading volume that there can be a

large jump in futures prices compared to spot prices.

Only after volume gradually increases over time will the

spot and futures price changes move closely together.

! The basis should be relatively stable. The "price basis"

is the difference between the futures price and the spot

price. The size of this difference is one measure of the

risk of hedging. Noncommercial traders are almost

solely interested in the expected direction of price

movements. In contrast, commercial traders that have

opposite positions in spot and futures prices are

primarily interested in the stability of the basis. 

See, for example, Working, H., "Hedging Reconsidered," Journal of 60

Farm Economics, 35, 1953, pp. 544-561, or Houthakker, H., "Normal

Backwardation," Chapter 7, Wolfe, J. N., ed., Value, Capital, and Growth

(Chicago: Aldine Publishing Co., 1968), pp. 193-214.
102 Energy Information Administration / Petroleum 1996: Issues and Trends

An Example of a Short, or Selling, Hedge Using Actual Prices 

Successful futures markets must have active participation by "hedgers," or "commercials," who use the futures market to

offset an existing or anticipated physical position, in an attempt to limit risk or to lock in a cost or profit margin. For

example, a jobber may buy 42,000 gallons of heating oil on July 15, 1996 at a price of 57.5 cents per gallon and put it into

storage. He expects to sell it to customers during the winter and may want to protect himself from inventory devaluation.

He might sell (put on a "short hedge") a heating oil futures contract for December delivery, for 42,000 gallons, on July 15

at a price of 58.79 cents per gallon. On, say, October 15, 1996 he will buy back his December futures contract at 71.20 cents

per gallon. The price of the futures contract has risen while spot prices have also risen to 71.44 cents per gallon. The

jobber's hedge has resulted in a loss of $5212.20 ($420 for each 1-cent per gallon rise) in the futures contract and a gain

of $5854.80 in the spot market, for a net gain of $642.60. He would have had a much larger net gain if he had not used the

futures market, but he was willing to forgo the extra gain to protect himself from a possible very large loss if prices had

declined. Also, the loss on the futures contract may have been a speculator's gain (see next sidebar).

There are several types of basis risk which can have effects on the riskiness of hedging. First, the key to minimizing risk

is having a stable "price basis," which is the difference between the futures price and the spot price. The more stable the

price basis is, the more likely the futures market position will result in small net gains or losses, thus minimizing the

riskiness of the position. Second, besides price risk there is also "quality basis risk." If the futures contract does not exactly

match the specifications of the product being hedged, then there may be an unstable relationship between the cost of the

physical commodity being hedged and the futures price, increasing the riskiness of the position. Third, there is "location

basis risk." The heating oil futures contract specifies delivery in New York Harbor. If the relationship between the price

difference between New York and the price where the physical product being hedged is located is unstable, this would also

increase the riskiness of the futures market position.

It is important to note also that, while the futures contract itself could be used as a delivery mechanism, in practice

deliveries occur very infrequently. Most short contracts, for delivery at a future date, are liquidated in a manner similar to

this example, where the seller buys back a contract. Using futures contracts as delivery devices involves numerous

complications. For example, when the December heating oil futures contract expires at the end of November, the buyer then

decides at what time during December he will call for delivery from the seller. The transaction then corresponds to what

is called an "any" cash market price, referring to any time during the month. This contrasts with the "spot," or "prompt"

price which refers to delivery within 1 to 10 days. The uncertainty of delivery times and confusion about what prices are

actually being used causes most companies to liquidate their futures position before their contracts expire.

While in practice the different types of basis risk, cash market prices and delivery possibilities complicate the hedging

decision, they do not obscure one of the fundamental concepts of hedging, which is that a company will ask itself, "How

much price risk are we willing to accept, and is it worthwhile to use the futures market to try to minimize that price risk?"

! Hedgers want more than to minimize price risks. This paper considers each of these factors below, and

They want to use futures markets to maximize profits.

Most companies don't hedge their entire inventories.

Even when they do hedge, they don't take all their

futures positions at one time and simply hope that their

risk will be exactly offset. Companies often take their

total futures positions gradually. A profit-maximizing

company may take a futures position by observing price

trends. “Long hedgers," i.e., commercials who buy

futures contracts, will buy futures during periods of

declining prices and "short hedgers," i.e., commercials

who sell futures contracts, will sell futures contracts

during periods of extended price rallies.

discusses how each factor might contribute to the slowdown

in futures trading volume. 

Petroleum Futures Market Trading

Volume Slowed in 1996

Energy futures were traded on at least 20 exchanges in the

19th century, and there were numerous attempts to trade

them early in this century. Mainly due to relatively small

price fluctuations through most of this century, energy
Energy Information Administration / Petroleum 1996: Issues and Trends 103

futures markets were unsuccessful until 1978. Today, the gasoline futures went nowhere, even as the NYMEX

largest energy futures market in the world is the New York encouraged traders to switch out of the leaded gasoline

Mercantile Exchange (NYMEX). Their markets include contracts. Traders were willing to accept the leaded gasoline

heating oil futures contracts since 1978, crude oil since 1983, specifications to hedge unleaded gasoline, because the

and unleaded gasoline since 1984. As Figure 70 shows, trading volume in the leaded gasoline was so much greater

petroleum and product futures market trading volume grew and the price differential between leaded and unleaded gas

at a remarkably rapid rate in the 1980's. Crude oil futures was fairly stable over time. 

accounted for the bulk of the growth. 

Overall trading growth in petroleum and product futures has terminate trading in the leaded gasoline futures contract, and

slowed considerably during the 1990's, as shown in Figure 6- the results were dramatic. As Figure 71 shows, early in 1986

1. One important reason is that commercial traders have trading volume in leaded gasoline dominated unleaded

historically been attracted to futures markets as a device for gasoline, but after leaded gas futures were terminated

hedging their price risk. But, the first factor above stresses unleaded gasoline trading volume took off. This is also an

the importance of having a futures contract that closely example of why duplicative futures contracts have a high

matches the commodity being hedged. Unleaded gasoline failure rate. Other examples abound. Gulf Coast gasoline 61

futures illustrate this point. Heating oil and propane futures futures on the NYMEX were unsuccessful. Although those

contracts are used to hedge a fairly narrow range of product contracts were better specified than the New York Harbor

specifications. In contrast, unleaded gasoline futures are delivery contracts for certain purposes, they couldn't

specified in terms of reformulated gasoline but must serve as compete with the volume of the existing contracts.

a hedging device for numerous types of reformulated,

oxygenated, and conventional gasolines, and which have

been subject to changing regulatory requirements. The

fragmented gasoline market causes great uncertainty as to

how closely futures prices will follow the spot prices of the

type of gasoline being hedged, which may have very

unstable relationships with each other, reflecting regional Another important factor in hedging decisions is the

supply and demand differences. That uncertainty has led to correlation of spot and futures price changes. Hedgers only

a slowing in trading volume in unleaded gasoline futures. rarely hold futures contracts until their expiration date to use

After annual increases in gasoline futures trading volume of them as a delivery mechanism. Most hedgers will buy or sell

60 percent as recently as 1988 and 36 percent in 1989, contracts and then subsequently liquidate their positions

trading volume actually decreased by 5.3 percent in 1995 before the contracts expire, when they wish to complete their

and another 0.5 percent in 1996. spot market transactions. Before a contract expires there

Even as seemingly obvious a point as having a well-defined with no net price gains or losses, only if the basis is the same

futures contract can be deceptive in futures markets. If a when the futures contract is liquidated as it was when the

contract has become established, it may be extremely position was initiated. So it is important to both long

difficult to start a similar contract, even if the new contract hedgers and short hedgers that spot and futures prices move

unquestionably gives a better specification of the spot

commodity. A good example of this again comes from the

gasoline futures market. When trading in gasoline futures

began on the New York Mercantile Exchange (NYMEX) in

1981, the contract specified leaded gasoline. As it became

apparent that unleaded gasoline would eventually sell far

more than leaded gasoline, the NYMEX in 1984 also listed 62

an unleaded gasoline futures contract. But, as sales of

unleaded gasoline grew, trading volume in the new unleaded

Eventually, the NYMEX announced that it would simply

63

Futures and Spot Price Correlations

May Be Highly Seasonal

64

will be a transfer of risk from the hedger to the speculator,

65

The trade press has also attributed the drop in futures trading volume to 61

everything from small futures price movements to large futures price

movements. See "Stable Prices Dull 'Interest' In NYMEX Crude Futures,"

Petroleum Intelligence Weekly (December 11, 1995), p. 5, and "Extreme

Volatility Rattles Industry's Trust In Futures," Petroleum Intelligence Weekly considered here, but all the same ideas still apply.

(April 1, 1996), p. 1.

In 1984 unleaded gasoline was already 59.6 percent of the total gasoline 62

market. (Washington, DC, September 1991), pp. 5-18. 

For a theoretical description of the growth in trading volume in new 63

futures contracts see Dale, C., "Brownian Motion in the Treasury Bill Futures

Market," Business Economics (May 1981), pp. 47-54.

The special case of an "exchange of futures for physicals" will not be 64

For detailed examples of this, see Dale, C., "Economics of Energy 65

Futures Markets," Petroleum Marketing Monthly, DOE/EIA-0380(91/09)
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1986 1988 1990 1992 1994 1996

0

10

20

30

40

50

Contracts (Millions)

Crude Oil

Heating Oil

Unleaded Gas

AAA AAA

Jan

1986

May Jul Sep Nov Dec

0

20

40

60

80

100

120

140

160

Thousands of Contracts Traded

Unleaded Gas

Leaded Gas

Mar

104 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 70. Growth Slows in U.S. Oil Futures Trading - Annual Volume

Source: New York Mercantile Exchange.

Figure 71. Established Contracts Are Hard to Beat - Leaded Versus Unleaded Gasoline Futures

Note: Leaded gasoline futures were terminated November 1986.

Source: New York Mercantile Exchange.
Energy Information Administration / Petroleum 1996: Issues and Trends 105

together. But spot and futures price correlations, like many calling for delivery during the same time period.

other aspects of futures markets, depend upon stock levels. Nevertheless, the economic analysis from hedging prompt 66

 

Stocks of crude oil and petroleum products are shown in

Figures 72, 73, 74, and 75. Stock levels for crude oil and

petroleum products all exhibit seasonal patterns; however,

these patterns are most pronounced in refined products —

gasoline, heating oil, and propane — while crude oil shows

a less pronounced seasonal pattern (see box, p. 108). As

noted above, gasoline has problems during the year as a

hedging device because of the fragmented marketplace and

unstable price relationships between different types of

gasoline. Heating oil and propane have the strictest

definitions of deliverable grades of the commodity, so they

provide the most stringent test of how stock levels affect the

correlation of spot and futures prices.

Traditionally, hedgers using NYMEX take advantage of the

strong price correlation between cash market transactions

calling for delivery during specified future months (forward

contracts) and futures contracts calling for delivery during sidebar). The longer comparisons are subject then to various

the same time period. When cash market participants are

highly confident as to the creditworthiness of their

counterparts, and if the delivery point for their contracts is

New York Harbor, similar to the NYMEX heating oil and

unleaded gasoline futures contracts, in most instances there

is no material difference between cash market prices and

futures market prices. This holds because of the performance

of arbitrage, i.e., taking advantages of price differentials in

closely related markets, by participants who are active in

both markets. If the price in one market is cheaper than in

the other, these participants purchase the cheaper product

and sell the more expensive product. This results in profits

for the arbitragers and reduces any differences in price by

increasing the lower price and decreasing the higher price.

Arbitrage continues until any material differences between

prices are eliminated.

More recently, there has been increased interest in the levels

of inventory for petroleum products, heating oil especially.

It is possible to evaluate the effectiveness of hedging

increases and decreases in inventory using NYMEX futures,

focussing on the current prompt value of the commodity.

This differs from more traditional hedging in that it does not

protect against price risk associated with value determined

by a future commitment to make or take delivery, but instead

on fluctuations in value associated with immediate delivery

obligations. Clearly, the price correlation between a futures

contract calling for delivery in a future month, i.e., next

month, and prompt prices calling for delivery now cannot be

as strong as that between futures and forward contracts

with futures gives interesting results that provide useful

market insights. This type of analysis is discussed below.

Large stocks improve spot and futures price correlations,

which can decrease price volatility and make the futures

market more effective as a hedging device. Figure 74 67

shows that, for 1995 and 1996, heating oil stocks were at

their lowest levels in March and at their highest levels at the

end of the year. Similarly, Figure 75 shows that, for both

these years, propane stocks reached a low in February and

peaked in September. Table 11 shows that these correlations

were exactly as expected from hedging theory: the

correlations are high when inventories are large and low

when inventories are small. As noted above, the correlations

used were the spot price and the nearby futures price. In 68

practice, the futures price would be measured against a more

distant spot price, depending upon the length of the hedging

period (for an example of an actual hedge, see the first

seasonal and other complicating factors. For this reason,

academic research frequently analyzes these very short-term

arbitrages for illustrative purposes, and this is done here in

Tables 11 through 13. For heating oil, the squared correlation

coefficient between the spot price and nearby futures

contract price was 0.88 (perfect correlation would be 1.0) in

the low stock month of March 1995 and 0.67 in March 1996,

but improved to 0.95 in the high stock month of November

1995 and 0.99 in November 1996. The correlation is not

quite as dramatic for propane. The squared price correlation

in the low stock month of February was only 0.48 in 1995

and 0.27 in 1996, but improved in the high stock month of

September to 0.52 in 1995 and 0.66 in 1996. A possible

conclusion is that maintaining low stocks as part of what is

loosely called "just-in-time inventory management" may

lower inventory holding costs for an individual refiner, but

when done on an industry-wide basis it can increase futures

market hedging risks by lowering the correlation between

spot and futures prices.69

 Hedging theory states that spot and futures price correlations generally due to inventory management strategies. Large exports in September and 66

are proportional to the level of inventories, which has been empirically October caused by an unusually large price differential between New York

verified for many agricultural commodity futures. and Northwest Europe also helped to draw down inventories.

This paper follows the practice of using the broad term hedging to 67

include both typical hedging and short-term arbitrage.

The "nearby" futures contract is the one with the earliest expiration date, 68

typically the next month.

Of course, in 1996 low heating oil inventories weren't necessarily all 69
Jan Jul Jan Jul Jan Jul

0

290

300

310

320

330

340

350

360

M illions of Barrels

1994 1995 1996

Jan Jul Jan Jul Jan Jul

180

190

200

210

220

230

240

M illions of Barrels

1994 1995 1996

106 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 72. Monthly Crude Oil Stocks

Source: Energy Information Administration, Petroleum Supply Monthly (various issues). 

Figure 73. Monthly Total Gasoline Stocks

Source: Energy Information Administration, Petroleum Supply Monthly (various issues).
Jan Jul Jan Jul Jan Jul

0

80

90

100

110

120

130

140

150

160

M illions of Barrels

1994 1995 1996

0

M ill oi ns of B

arrels

1995

10

20

30

40

50

60

70

Jan Jul Jan Jul Jul Jan

 1994 1996

Energy Information Administration / Petroleum 1996: Issues and Trends 107

Figure 75. Monthly Propane Stocks

Figure 74. Monthly Distillate Fuel Oil Stocks

Source: Energy Information Administration, Petroleum Supply Monthly (various issues).

Source: Energy Information Administration, Petroleum Supply Monthly (various issues).
108 Energy Information Administration / Petroleum 1996: Issues and Trends

Making Money On Seasonal Price Movements -- How Easy Is It?

The existence of an energy futures market provides companies and traders the theoretical opportunity to benefit from

knowledge of recurring seasonal price movements. For example, gasoline prices are typically highest during the summer

driving season, while heating oil prices typically reach their highest levels in the winter. Can the futures market be used

to profit from these simple facts?

In 1992, Bloomberg Oil Buyers Guide noted that the purchase of a December heating oil futures contract at the end of July,

and its sale in mid-October, would have made a profit in 11 of the previous 13 years. That relationship still holds. Buying

a contract at the end of July and selling in mid-October would have made a profit (ignoring commissions) in 12 of the 17

years from 1980 through 1996. The net gain over that period was 94.54 cents per gallon. Since each 1-cent gain represents

a $420 gain on a contract that might have as little as a $1500 margin deposit, the potential gains from such trades are large

indeed.

In practice, the last business day of the month is the expiration of a futures contract, and there may be increased price

volatility on those days, so many companies and traders are reluctant to take positions at the end of the month. So,

examining the same years from 1980 through 1996, but with the purchase made in mid-July instead of the end of the month,

the result is that there would have been a profit in 11 of the 17 years (1995 was a tiny loss of only .01 cent per gallon), for

a net gain of 93.28 cents per gallon.

Why, then, doesn't everyone in the industry make these trades? There are many reasons. First, most of the 93.28 cent per

gallon gain was made in a few years, when there was a war or unusually cold weather, e.g., in 1990 the gain during the Gulf

War was 44.92 cents per gallon. Companies may not want to tie up capital for extended periods waiting for infrequent gains,

no matter how large. Second, and for similar reasons, the price doesn't move straight up even in profitable years. Futures

contracts are "marked-to-the-market," or evaluated, on a daily basis, meaning that if the price drops it might be necessary

to deposit additional hundreds or even thousands of dollars for each contract to maintain the position, tying up even more

capital. Third, simply buying without having an anticipated sale in the future would be pure speculation, which most

companies want to avoid, regardless of how profitable a trade appears to be.

This sample trade is a good illustration of information that companies and traders use to decide how to use futures markets.

Marketers with existing forward contracts to sell oil might use this kind of information to decide when to establish a long,

or buying, hedge. Regardless of numerous other complicating factors, such as determining a company's cash flow needs,

their accounting requirements, whether to use complex trades involving futures and options, etc., the concepts of futures

market trading are not mysterious. Traders and companies use their knowledge of the industry combined with the amount

of risk they are willing to take to determine how to use futures markets to maximize their profits.

The Basis May Also Be Highly

Seasonal

Arbitrage trading ensures that spot prices and nearby futures

contract prices converge at the expiration of the contracts. Table 12 shows that the basis for heating oil has a highly

Since the price basis will therefore become zero at the seasonal pattern. The data are separated into pre-Gulf War,

contract expiration, the size of the basis is a measure of the post-Gulf War, and Entire Period (including the war). As

risk for a hedger. For example, a short hedger would prefer noted above, low stocks themselves discourage any type of

to take a position when the basis (defined here as nearby hedging, so hedging theory predicts relatively low levels of

futures price minus spot price) has a large positive value, hedging in heating oil futures in the late winter and early

since the eventual convergence of spot and futures prices spring. The basis is highly negative (meaning market

could result in a net profit on the short futures contract. As "backwardation"), in the late winter months, so short hedging

the futures contract expires, the short futures contract will is discouraged at that time by the basis. As heating oil stock

eventually fall faster or rise slower than the spot price,

giving the hedger a trading profit in addition to transferring

his price risk. The opposite is true for long hedgers, who

would prefer to buy futures contracts when the basis is a

large negative value.
Energy Information Administration / Petroleum 1996: Issues and Trends 109

Table 11. Price Correlations for Spot and Futures Prices

Squared Correlation Coefficients

Heating Oil Propane

Month March 1991- August 1992-

1995 1996 November 1996 1995 1996 November 1996

January .95 .92 .97 .80 .70 .88

February .91 .89 .87 .48 .27 .51

March .88 .67 .78 .79 .60 .78

April .94 .76 .85 .39 .36 .61

May .96 .67 .89 .80 .68 .77

June .99 .98 .97 .57 .19 .71

July .90 .97 .98 .44 .53 .76

August .82 .88 .97 .85 .84 .82

September .94 .92 .95 .52 .66 .80

October .90 .99 .98 .36 .85 .89

November .95 .99 .98 .73 .81 .89

December .82 .95 .68 .80

Source: Energy Information Administration calculations from Reuters and New York Mercantile Exchange data.

Table 12. Price Basis for Heating Oil Futures, Monthly Average -- Nearby Futures Price Minus Spot Price,

June 1986 - November 1996

(Cents Per Gallon)

Month 1996 Pre-Gulf War Post-Gulf War Entire Period

January -0.205 -2.452 0.334 -1.017

February -4.571 -0.686 -2.038 -1.904

March -7.182 -2.086 -2.736 -2.473

April -8.125 -2.062 -1.700 -1.844

May -3.357 -2.296 -0.415 -1.169

June 0.258 -0.322 0.282 0.005

July 0.322 0.325 0.361 0.345

August 0.110 0.738 0.534 0.659

September 0.070 0.734 0.623 0.766

October 0.023 0.729 0.614 0.726

November 0.237 0.342 0.798 0.650

December 0.103* -1.429 0.944 -0.138

* = December 1995.

Notes: Pre-Gulf War = June 1986-July 1990. Post-Gulf War = March 1991-November 1996. Entire Period = June 1986-November 1996 (including

war period.

Source: Energy Information Administration calculations from Reuters and New York Mercantile Exchange data.

levels become relatively larger and the basis becomes occurring in the fall. Thus, low stocks and backwardation

positive, short hedging is encouraged. both discouraged short hedging in propane futures markets.

Table 13 shows that propane futures also have a seasonal

pattern. Volume in propane futures was very small through

the Gulf War period, so results are only shown for 1996 and

the period 1992 through 1996. There is again a clear seasonal

pattern, with backwardation in the winter and early spring.

It is important to note that 1996 was an exceptional year,

since below normal stock levels led to backwardation also

70

 Before the war similar results held for gasoline futures, as the basis was 70

positive when stocks were built in the spring and negative as stocks fell

during the summer driving season. Gasoline futures results are not shown

here because the numerous changes in specifications to meet Clean Air

requirements after the Gulf War make it technically very difficult to match

the gasoline futures contract with the appropriate spot price.
110 Energy Information Administration / Petroleum 1996: Issues and Trends

Table 13. Price Basis for Propane Futures, Monthly Average -- Nearby Futures Price

Minus Spot Price

(Cents per Gallon)

Nearby Futures Price Minus Spot Price

Month 1996 1992-1996

January -0.780 -0.528

February -3.622 -1.404

March -2.253 -1.006

April -0.710 -0.211

May -0.408 -0.011

June 0.124 0.238

July 0.033 0.196

August -0.069 0.250

September -0.593 0.191

October -0.092 0.205

November -0.713 0.113

December 0.523* 0.391

* = December 1995.

Source: Energy Information Administration calculations from Reuters and New York Mercantile Exchange data.

High Prices in 1996 Led to High

Visibility for Futures Markets

Both crude oil prices and heating oil prices were strong in fall sharply in price. In early December 1996 the

1996. Spot prices of West Texas Intermediate crude oil rose backwardation decreased after Iraqi oil sales were finally

from $17.33 per barrel in late January to $25.15 by mid- announced. On December 10, 1996, crude oil futures were

April. Spot heating oil prices rose steadily from 50.63 cents $24.42 per barrel for January delivery and $23.92 per barrel

per gallon at the end of May to 76.73 cents per gallon in for February delivery. The announcement of Iraqi oil sales

early October The combination of low stocks of crude oil thus lessened the backwardation in the futures market

and petroleum products and rising spot prices led to sharply from the April structure, because of changed

questions about the influence futures markets were having on expectations. However, the overall price level was still much

petroleum markets. higher than in October 1995, because of lower stocks. 

The futures markets reflected changing stock levels and The extended period of backwardation in crude oil futures is

expectations of an increase in supply throughout 1996. As frequently given as another reason for the overall decline in

shown in Figure 76, in late 1995 the crude oil market showed futures trading volume. A popular method of hedging longonly mild backwardation, in which crude oil for delivery in term inventory positions is called "stacking and rolling," in

distant months is priced lower than crude oil for delivery in which hedgers would extend the length of a hedge by buying

nearby months, a situation which is associated with a back short futures contracts in expiring months and 71

relatively low supply of stocks. On October 2, 1995, crude simultaneously short-selling new futures contracts in more

oil for delivery in November was $17.64 per barrel, while distant months. If market backwardation continues for

crude oil for December 1995 delivery was only 30 cents per extended periods, this will lead to numerous situations of

barrel lower. But in 1996 crude oil stocks continued to fall selling futures contracts at relatively low prices and being

for a number of reasons: cold weather in the spring; strong forced later to buy them back at higher prices. Fears of the

global oil demand; supply shortfalls from non-OPEC potentially huge unprofitability of stacking and rolling from

sources; and strong gasoline demand. By April 1996, the market backwardation is thus given as a reason for the drop

backwardation in the crude oil futures market had increased in energy futures trading volume in 1996.

sharply. On April 15, 1996, crude oil for May delivery was

$25.06 per barrel, but oil for June delivery was $2.58 per

barrel lower, driven largely by expectations of imminent oil

sales from Iraq. The industry did not want to increase stock

holdings of crude oil that the futures market showed could

72

"Contango," by contrast, is the case of distant futures contracts priced one of the primary reasons Germany's Metallgesellschaft lost nearly $2 71

higher than nearby futures contracts. billion in futures trading in 1993.

Stacking and rolling, although with a long hedge, is frequently given as 72
Nov Mar Jul Nov Mar Jul

0

16.00

18.00

20.00

22.00

24.00

26.00

2 Oct 1995

15 Apr 1996

1 Jul 1996

3 Sep 1996

10 Dec 1996

Dollars Per Barrel

1995 1996 1997

Energy Information Administration / Petroleum 1996: Issues and Trends 111

Figure 76. Changing Term Structure for Crude Oil Futures

Source: New York Mercantile Exchange.

While market backwardation seems at first to be a plausible side, end users like airlines could give up profits if they

explanation for the drop in futures trading volume, in reality hedge fuel costs by buying heating oil futures as a proxy for

this is not the case. While backwardation discourages short jet fuel, if fuel costs subsequently fall. But oil traders are

hedging from those with existing positions in the physical involved in both buying and selling both crude oil and

market, there is no reason for it to discourage long hedging, products, in contrast to refiners who are involved in buying

from companies who are short in the cash market and want crude oil and selling products, so traders are involved in both

to hedge by buying distant futures contracts. In fact, the buying and selling side of futures markets. Their

historically crude oil futures have been in backwardation decisions on how much to hedge will depend upon the

more than 75 percent of the time, but it was only until current term structure of the futures markets. 73

recently that crude oil futures trading stopped its steady

annual increases. Figures 77 and 78 show a variety of term structures for 74

So, who does most of the hedging in futures markets? David futures were in backwardation because of expectations

Long argues that it is traders and refiners, who are involved regarding the resumption of sales of Iraqi crude oil, the 75

on both the buying and selling side of the market. On the heating oil futures market, which is closely tied to crude oil

upstream side, producers who hedge could give up profits by futures, also was in backwardation for the first few delivery

hedging and then having oil prices rise. On the downstream months. But the shape of the curve gradually switched to

highly seasonal commodities. In April 1996, when crude oil

where more distant futures were priced higher than nearby

futures, the situation called "contango." In July, the heating

oil futures market was in contango in the first delivery

months, reflecting ample supplies of heating oil stocks in the

summer months, but it switched to backwardation in later

months, reflecting the normal situation of lower inventories

in the fall and winter months. 

The propane futures market also showed a varying pattern.

There was very little market backwardation in this thinly

traded futures market in April, reflecting little expected

impact from Iraqi oil sales. But in December, with both

crude oil and heating oil in mild backwardation, propane

Litzenberger, R. H. and Rabinowitz, N., "Backwardation In Oil Futures 73

Markets: Theory And Empirical Evidence," Journal of Finance, Vol. L, No. 5

(December 1995), pp. 1517-1545.

If backwardation alone caused drops in trading volume, it would be 74

because short hedgers primarily determine the volume of trading. But a

simple correlation of monthly trading volume and stock levels for crude oil

from 1983 to 1996 gave a correlation coefficient of only 0.01, showing that

short hedgers do not determine the trading volume. Even a more stringent

test of monthly volume changes and monthly stock changes gave a

correlation coefficient of only 0.15, an indication of only a very small net

influence on trading volume of short hedgers. 

Long, D., "Hedging Revisited," Global Oil Report, Vol. 8, No. 1, Centre 75

for Global Energy Studies (London, UK, January-February 1997), pp. 40-54.
Nov Mar Jul Nov Mar Jul

0

0.45

0.50

0.55

0.60

0.65

0.70

0.75

Cents Per Gallon

2 Oct 1995

15 Apr 1996

1 Jul 1996

3 Sep 1996

10 Dec 1996

1995 1996 1997

Nov Mar Jul Nov Mar Jul 

0

0.30

0.35

0.40

0.45

0.50

0.55

0.60

2 Oct 95

15 Apr 96

1 Jul 96

3 Sep 96

10 Dec 96

Cents Per Gallon

1995 1996 1997

112 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 77. Changing Term Structure for Heating Oil Futures

Source: New York Mercantile Exchange.

Figure 78. Changing Term Structure for Propane Futures

Source: New York Mercantile Exchange.
Energy Information Administration / Petroleum 1996: Issues and Trends 113

futures were in steep backwardation because of very low

seasonal propane stocks and the expectation of what bad

weather in the U.S. and abroad would do to deplete those

inventories. The steep backwardation on December 10 ended

abruptly in contracts for delivery of propane during the Low stocks and high prices of heating oil generated

spring and summer months of 1997. Clearly, the energy considerable attention in the fall of 1996. There were

futures markets at any given time can give a great deal of questions about the role of low stocks and the possible role

information about the current state of stocks and market of futures markets in causing high prices. In response, the

expectations. Commodity Futures Trading Commission compiled the data

Maximizing Profits Means Hedgers

Try to Follow Price Trends

As noted in the section on the theory of hedging, hedgers try commercial traders bought during periods of declining

to maximize profits by observing persistent price trends. prices. As the year progressed and prices rose, large

They can then sell futures contracts as prices rise, or buy commercials sold into the price rise and became net short.

futures contracts as prices fall. A good example is heating Noncommercials showed the opposite trading patterns. 76

oil futures which had some persistent price trends in 1995

and 1996, as shown on Figure 79. In 1996, low stocks coincided with higher prices in the May

To track the behavior of hedgers, it is necessary to use the prices, so that large commercial traders were never net long.

Commitment of Trader reports compiled by the Commodity Again, however, they generally sold and became

Futures Trading Commission. Figures 80, 81, 82, and 83 increasingly net short as prices rose into the fall of 1996. 77

show the percentage of the total number of long and short

contracts held by large commercial traders for crude oil, Proponents of the view that refiners engaged in a low

unleaded gasoline, heating oil and propane futures. These stockholding conspiracy and misused the heating oil futures

graphs illustrate two points. First, large commercial traders market will have to explain carefully the message of

hold the majority of energy futures contracts, averaging 60 Figures 79, 85, and 86. Those graphs show that large

to 80 percent of the total number of contracts outstanding. commercial traders in general and refiners in particular were

Second, there were significantly more large commercial heavy net sellers of heating oil futures at a time of rising

holders of short contracts than long contracts during periods prices, which would have the effect of slowing the price

of generally rising prices. For example, in Figure 82 shorts increases. For example, Figure 86, which shows total rather

increased faster than longs during the 1995-1996 price rise than net positions, indicates that both long and short hedging

in heating oil. These results are consistent with hedging were relatively small when stocks were low in the Spring of

theory. Commercials were net sellers, not buyers, as prices 1996. Refiners held more short positions throughout the May

rose, so their trading activities in 1995 and 1996 had a to October 1996 period, and they greatly increased their

tendency to hold heating oil prices down. short positions as prices rose in the fall. This is exactly the

1996 Brought Attention to Heating

Oil

shown on Figures 84, 85, and 86. Figure 84 together with the

prices on Figure 79 show typical hedging behavior. In the

summer of 1995, the basis was very narrow and this had a

minimal effect on hedging decisions. But prices in July were

near seasonally low levels, so commercial net positions for

large traders were net long in summer 1995, as large 78

through October period that were never as low as the 1995

result that would be expected if the futures markets are

functioning efficiently and refiners are behaving in

accordance with well-established hedging theories. 

Announcement Effects Are Small

and Short-Lived

One other possibility for the decrease in the volume in

energy futures trading is for traders to be wary of

Noncommercial traders may also follow price trends, but with the 76

opposite trading behavior. They will buy price rallies and sell price dips. See

Dale, C., and Zyren, J., "Noncommercial Trading in the Energy Futures

Market," Petroleum Marketing Monthly, DOE/EIA-0380(96/05)(Washington,

DC, May 1996), pp. xiii-xxiv.

The CFTC requires traders to have their brokers report their holdings if 77

they have more than 300 futures contracts for any delivery month of crude

oil, 250 contracts of heating oil, or 150 contracts of gasoline. Those reporting Net positions are total long contracts minus total short contracts, so a

levels may change if total volume of trading in each type of contract changes. positive number on Figure 84 means a net long position.

78
Jan Apr Jul Oct Jan Apr Jul Oct

Long

Short

End of Month Data

0

20

40

60

80

100

Percentage Share of Market

1995 1996

Jan Apr Jul Oct Jan Apr Jul Oct

0

40

45

50

55

60

65

70

75

80

Cents per Gallon

Spot Heating Oil

Futures Heating Oil

1995 1996

114 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 79. Spot and Futures Heating Oil Prices - End-of-Week Closing Prices

Sources: Futures Prices: New York Mercantile Exchange. Spot Prices: Reuters.

Figure 80. Large Commercials Share of Open Interest - Crude Oil Futures

Source: Commodity Futures Trading Commission.
Jan Apr Jul Oct Jan Apr Jul Oct

End of Month Data

0

20

40

60

80

100

Percentage Share of Market

Long

Short

1995 1996

Jan Apr Jul Oct Jan Apr Jul Oct

End of Month Data

0

20

40

60

80

100

Percentage Share of Market

Long

Short

1995 1996

Energy Information Administration / Petroleum 1996: Issues and Trends 115

Figure 81. Large Commercials Share of Open Interest - Unleaded Gasoline Futures

Source: Commodity Futures Trading Commission.

Figure 82. Large Commercials Share of Open Interest - Heating Oil Futures

Source: Commodity Futures Trading Commission.
Jan Apr Jul Oct Jan Apr Jul Oct

End of Month Data

0

20

40

60

80

100

Percentage Share of Market

Long

Short

1995 1996

1995

July Sep

0

20

40

-20

-40

-60

Contracts (Thousands)

Noncom

Com

May

116 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 83. Large Commercials Share of Open Interest - Propane Futures

Source: Commodity Futures Trading Commission.

Figure 84. Heating Oil Net Futures Holdings - End-of-Week Large Positions, May - October 1995

Source: Commodity Futures Trading Commission.
1996

May Sep

0

10

20

30

-10

-20

-30

-40

-50

Contracts (Thousands)

Noncom

Com

July

1996

July Sep

0

20

40

-20

-40

-60

Contracts (Thousands)

Refiners - Long

Refiners - Short

May

Energy Information Administration / Petroleum 1996: Issues and Trends 117

Figure 85. Heating Oil Net Futures Holdings - End-of-Week Large Positions, May - October 1996

Source: Commodity Futures Trading Commission.

Figure 86. Refiners Holdings of Heating Oil Futures - End-of-Week Large Positions, May - October 1996

Source: Commodity Futures Trading Commission.
118 Energy Information Administration / Petroleum 1996: Issues and Trends

"announcement effects." For example, every week the There are other reasons for unpredictable price movements,

American Petroleum Institute (API) and the Energy especially near the expiration of contracts. But none of

Information Administration report stock levels of crude oil these effects has been shown to be either recurring or longand petroleum products. Traders might be wary of using the lived, so their effects on the overall drop in energy futures

futures markets if these announcements were to cause a long trading volume has been minimal.

lasting and sharp increase in price volatility. One-time 79

announcement effects are commonly reported in the trade

press. EIA tested several years of daily energy futures data

to see if the weekly stock announcements have a consistent

effect on price volatility.

There was a change in the reporting time of EIA stock data

in 1994 that provided a convenient way to try to measure

announcement effects. The American Petroleum Institute

reports its data on Tuesdays at 5:00 p.m. Until February

1994, EIA reported stock levels at 5:00 p.m. Wednesday.

After that time, EIA moved its reporting period earlier, to

9:00 a.m. Wednesday. These changes permitted a variety of

statistical tests to compare the effects of each announcement

on price volatility. Few consistent announcement effects

were detected over the period January 1991 through May

1996, a period chosen to cover both EIA reporting times.

Opening and closing prices were used to examine price

volatility, day-to-day price changes, same day close versus

open price changes, and opening price versus previous day’s

closing price. The measurable statistical effects were very

weak, and it was not possible to distinguish between effects

caused by API and EIA. The announcement effects did not 80

last long enough to be detected by the use of only opening

and closing, and sometimes high and low, prices. There is

considerable anecdotal evidence in the trade press to indicate

that traders do react to stock level reports, but those reactions

clearly subside very quickly and occur infrequently enough

to be statistically undetectable as long-term consistent

effects. Therefore, they can be dismissed as a possible 81

cause for the decrease in energy futures trading volume over

the entire time period.

82

Noncommercial Trading -- No Cause

for Alarm

Noncommercial trading is an important part of any futures

market. Speculators provide liquidity for hedgers, i.e., they

provide enough volume for hedgers to enter and leave the

market without unduly disturbing the price. In 1996 there

was much discussion in the trade press about how

noncommercial traders might be disrupting the futures

markets. Those ideas were debunked, however, by David

Long and Dale and Zyren (see footnote 76). Long presented 83

a theory which showed why commercial traders would buy

heavily during periods of price declines and sell during price

rises, with noncommercials behaving in exactly the opposite

way. He hypothesizes this behavior because commercial

traders change their price expectations more slowly than

speculators. Dale and Zyren provided empirical support for

Long's theory, by analyzing data for large traders collected

by the Commodity Futures Trading Commission. They also

drew the following conclusions: First, noncommercial

traders follow price trends, they don't set them. Second,

noncommercial traders are likely to switch between markets

quickly, which may result in amplifications of existing price

trends. Since these conclusions are to be expected from

noncommercials in any futures market, there is no reason to

believe that their behavior had anything to do with the

slowing of overall trading volume in petroleum futures

markets.

The Future Could Become More

Complicated

This paper has concentrated only on futures markets. In

practice there are a myriad of new and increasingly complex

instruments available for hedgers and speculators, such as

options on futures, crack spreads, and swaps. These devices

are beyond the scope of this article. It is difficult to get data

For example, in the Eurodollar market, volatility in the 5-minute interval 79

after the Government releases the monthly unemployment report is roughly

87 times the normal 5-minute volatility. See Ederington, L. H., and Lee, J. H.,

"How Markets Process Information: News Releases and Volatility," Journal

of Finance 48 (September 1993), pp. 1161-1191.

Regressions were used with time series of daily data over the time 80

period from 1991 thru May 1996, with the data subdivided when EIA

changed its reporting time in February 1994. Various combinations of

reported stock levels, differences between API and EIA stocks, and

deviations from historical stock levels were used to describe different

measures of volatility. Autoregressive conditional heteroskedasticity

(ARCH) models were estimated when necessary. Even these sophisticated

techniques produced only weak statistical evidence of announcement effects.

This result is consistent with results for securities markets. Analyzing 81

data available every second, volatility after scheduled announcements usually

returned to normal after 30 minutes, and volatility after surprise

announcements returned to normal after only 2 hours. See Ederington, L. H.

and Lee, J. H., "The Short-Run Dynamics of the Price Adjustment to New

Information," Journal of Financial and Quantitative Analysis 30 (March Oil Report, Vol. 7, No. 4, Centre for Global Energy Studies (London, UK,

1995), pp. 117-134. July-August 1996), pp. 36-50.

For examples of end-of-contract effects for crude oil and heating oil, see 82

Dale, C., "The Effects of Energy Futures Markets on the Worldwide

Marketing of Oil," in Proceedings of the Fourteenth Annual International

Conference, International Association For Energy Economics, Honolulu, HI,

Vol. II (July 8-10, 1991), pp. 786-795.

Long, D., "What Drives Oil Futures? Hedging or Speculation," Global 83
Energy Information Administration / Petroleum 1996: Issues and Trends 119

on all of these new areas, and also difficult to analyze how market. Low stocks of crude oil and petroleum products

some companies could use several of them at once. But to tend to discourage hedging because the relationship 84

the extent that these instruments are substitutes for futures between futures prices and spot prices becomes less

contracts, their increasing acceptance could also result in a stable.

slowing in the growth of petroleum futures trading volume.

Conclusions

This chapter has examined the fundamental behavior of

energy futures markets and reached the following

conclusions.

! The petroleum futures markets functioned normally and

effectively in 1996. Commercial and noncommercial

traders behaved as predicted by long-established hedging

theory. There is no evidence that large funds of money

from noncommercial traders have been setting the price

of crude oil or petroleum product futures. In the

memorable phrase of analyst David Long (see

footnote 83), "the forces which drive futures prices have

more to do with the fundamentals than the funds."

! Trading volume in energy futures has fallen off for a

variety of reasons. Unleaded gasoline futures are an

imperfect hedge for the greatly segmented gasoline

! Steep backwardation in prices, where future month

contracts have lower prices than nearby contracts, is not

an explanation for the drop in futures trading volume.

Historically, the crude oil futures market has been in

backwardation more than 75 percent of the time and,

until recently, crude oil futures continued to make new

volume records.

! Commercial traders in general, and refiners in particular,

were net sellers of heating oil as prices rose. This

behavior does not support a theory of a conspiracy to

keep stocks low and create price backwardation;

contrarily, the additional selling pressure from refiners

and other commercial traders would have the effect of

mitigating price increases.

! Announcements of stock levels by the American

Petroleum Institute and the Energy Information

Administration do not have large and significant effects

on futures prices, so those announcements did not

contribute to the slowdown of trading volume in energy

futures.

In fact, large integrated oil companies may increasingly decide that they 84

are "self-hedged," i.e., parts of the company may be long in physicals and

other parts short in the physical market, so on a company wide basis the need

to use futures markets might be minimal.
Cash Margin '

j

N

i

(Price Producti x Yield Producti)

& Crude Cost

& Other Feedstock Cost

& Fuel plus Other Variable Costs

& Operating, Maintenance Cost

Energy Information Administration / Petroleum 1996: Issues and Trends 121

Gasoline prices rose rapidly in the spring of 1996, renewing interest in petroleum market dynamics. Since

gasoline price has a major influence on refinery cash margins, these increases raised concerns about refiners

earning excess profits. This chapter focuses on refinery cash margins over the past decade to determine what

factors have influenced margin fluctuations. It concludes by looking at refinery cash margins in the spring of

1996 with an understanding of margin performance over the past decade to provide perspective. 

7. U.S. Refining Cash Margin Trends: Factors Affecting the

Margin Component of Price

Introduction

While there are different kinds of refining margins, this

chapter focuses on cash margins. The refining cash margin

per barrel of crude oil (Figure 87) represents all product

revenues minus the costs of feedstocks (crude oil plus other

feedstocks) and minus other operating costs per barrel of

crude oil. Margins at U.S. refineries are affected over time The cash margin (dollars per barrel of crude oil processed)

by crude oil and product markets. But they also vary is defined as:

according to facility configuration (complexity), scale, and

efficiency, the nature of the crude processed, and the region

where the facility is located. In addition, margins can be

affected by regulations such as the Clean Air Act

Amendments of 1990 (CAAA) that required changes in

product specifications to produce cleaner fuels.

Three refinery types are used to explore the historical cash

margin trends for the U.S. refining industry: two typical Gulf

Coast refineries and one East Coast refinery. The two Gulf

Coast refineries have complex configurations containing where,

fluid catalytic cracking, coking and hydrotreating. One is

designed to process light, sweet crude oil, and the second has ! N represents all products produced, including gasoline,

a larger coking unit and more extensive hydrotreating than

the first in order to process high sulfur (sour) crude oils. The

East Coast refinery has a fluid catalytic cracking unit, but no

coking capability, and is designed to process only low sulfur

crude oils. 85

In this chapter, five margins are explored to explain

historical refinery margin trends. Figure 88 shows how two

of these margins, one each for an East Coast and a Gulf

Coast refinery, have varied historically on a quarterly basis.

This chapter uses the East Coast and Gulf Coast refinery

configurations to understand those variations, addressing the

seasonal changes and underlying growth in margins from

1985 through the early 1990's and their subsequent decline.

Finally, the chapter will discuss briefly the cash margins

occurring early in 1996, as both crude oil and product prices

rose sharply.

Refining Margin Definition

diesel fuel, heating fuel, residual fuel oil, petroleum coke

and other products;

! Price product is the spot price per barrel of product i i

received by the refiner.

! The yield of product is the volume percent of product i i

per barrel of crude charge. It is a function of the refinery

configuration, the crude type being used in the refinery,

and refinery operating conditions;

! Crude cost is the price paid for a barrel of delivered

crude oil;

! Other feedstock costs include costs for MTBE and

purchased butane and iso-butane;

While West Coast refiners experienced the same types of underlying 85

economics, they also were preparing for unique California clean fuel

specifications. As a result, they are not considered in this report.
-2.00

-1.00

0

1.00

2.00

3.00

4.00

5.00

6.00

D o lla rs p e r B a rre l

E ast C oast 

(B o n n y L ig h t)

G u lf C o a st (A ra b L ig h t)

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

5.00

10.00

15.00

20.00

25.00

AAAA AAAA

AAAA AAAA

AAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAAAAAA AAAA AAAA AAAAAAAA

AAAA

AAAA

AAAA

$19.45

D o lla rs pe r B arrel

AAAA AAAA

AAAA C a sh M a rg in

O p e ra tin g C o s ts

C rude O il & F eedstock

C osts

$1.87

$1.56

122 Energy Information Administration / Petroleum 1996: Issues and Trends

Sources: Crude Oil, Natural Gas Liquid, and Product Prices: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News, Hart/IRI Fuels

Information Services (Arlington, VA). Crude Oil Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus, Petroleum

Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum and Economic Publications (Nicosia, Cyprus) and

Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company sources and

downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various public

literature sources. Cost Escalation: Based on Nelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell Publishing

Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA), price delivered to industrial customers in Louisiana and

Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.

Sources: Crude Oil, Natural Gas Liquid, and Product Prices: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News, Hart/IRI Fuels

Information Services (Arlington, VA). Crude Oil Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus, Petroleum

Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum and Economic Publications (Nicosia, Cyprus) and

Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company sources and

downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various public

literature sources. Cost Escalation: Based on Nelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell Publishing

Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA), price delivered to industrial customers in Louisiana and

Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.

Figure 88. Quarterly Margins East and Gulf Coasts

(Based on Spot Product Prices)

Figure 87. Cash Margin Component of Price

(East Coast Refinery Running Brent Crude Oil, Summer 1995)
Energy Information Administration / Petroleum 1996: Issues and Trends 123

! Fuel and other variable operating costs include fuel affecting industry margin trends. For example, this approach

burned during processing, electricity, steam, cooling provides the information to explore:

water, catalysts and chemicals required to process the

crude oil; and ! how refinery complexity affects performance; 

! Operating and maintenance costs include all personnel ! how light-heavy crude oil and product price differences

(operations, engineering, maintenance, supervisory, impact margins; and

laboratory, clerical), maintenance materials, property ! how variation in regional product demand and product

taxes, insurance and corporate overhead. specifications affect margins.

This margin represents the cash per barrel of crude oil charge While the refining cash margins presented in this chapter are

remaining to recover refinery investment (i.e., depreciation), not actual cash margins for the entire industry, they reflect

interest expense, taxes, extraordinary cash items, and return the variations and trends experienced by U.S. refineries in

on investment (or financial profit) (see box, p. 124). Thus, general. The analysis uses realistic yield structures for major

the cash margin is a key determinant of refining profitability refinery types on the East and Gulf Coasts, and cost

(see Chapter 8). structures for each type that allow for accurate analysis of

Refining cash margins are complex in that they involve a

multi-product process. Given a particular quality crude oil, The East Coast refinery type is represented by a 170

a specific refinery produces many different products thousand barrel per day, single train refinery with reforming,

simultaneously from that crude oil. Table 14 illustrates some fluid catalytic cracking (FCC), alkylation, and hydrotreating

of the major components of a refinery margin for an East of naphtha and middle distillate streams. The Gulf Coast

Coast refinery running Brent crude oil. The revenues are a refineries are similar in size, but also include coking

function of both the prices of different products and the capability. The Gulf Coast has two refinery variations, one

refinery yields for those products. Yield varies with refinery allowing processing of light crude oils with low or

configuration, operating decisions, and crude oil being used. moderate sulfur content, and a second allowing processing of

Product prices vary according to their respective markets. more sour crude oils by having a larger coking unit and

Operating and maintenance costs vary mainly with refinery additional hydrotreating capability, including a vacuum-gasconfiguration, labor costs, and price of fuel required to oil hydrotreater for the FCC unit feedstock. 

produce the products.

For the East Coast refinery in Table 14, gasoline contributed a larger financial investment than the East Coast refineries.

59 percent to total revenues, although it only made up 53 The larger investment is premised on the expectation that

percent of the total product barrel . Gasoline is an important larger cash margins will be obtained to provide funds for 86

determinant of refiners’ margin level in any given year. An capital recovery and an adequate return for the incremental

entire year’s financial success can be made or broken with a investment. The additional investments are aimed at

larger than normal variation in gasoline prices alone. increasing light product yields and/or running cheaper sour,

Similarly, crude oil constitutes over 3/4 of all out-of-pocket heavy crude oils. The extra coking and sulfur removal

refining costs. Relatively small swings in the price of crude capability of the more complex Gulf Coast refiner allows this

oil, unless quickly passed through to the prices of petroleum facility to convert most of the heavy materials in crude oil to

products, can produce large changes in cash margins and, higher valued gasoline and distillate, thereby improving

thus, in refiners’ profits. margins. Unfortunately, the price discount for these low

Background for Interpreting the

Margin Calculation

The refinery cash margins analyzed in this chapter provide

the detail required to explore specific factors that may be

! how different crude types affect margin levels; 

margin trends.

87

The two Gulf Coast refineries are more complex and require

quality crude oils relative to light sweet crude oils is not

always sufficient to allow these more complex refineries to

earn competitive returns on the added conversion equipment,

an issue that is discussed in detail in a later section of this

chapter.

The yields in Table 14 are based on crude oil input, not product output. light, sweet crude oils are considered high quality crude oils, and they 86

As a result, the Table 14 product yields will be larger than yields based on command a price premium over the heavier, higher sulfur (sour) content

total product produced. crude oils.

Light, sweet (low sulfur) crude oils contain a higher percentage of low 87

boiling point materials than heavy crude oils and therefore more gasoline and

distillate (high value products) can be produced from these crude oils without

needing expensive upgrading equipment. In addition, the low sulfur content

diminishes the need for expensive sulfur removing processes. As a result,
124 Energy Information Administration / Petroleum 1996: Issues and Trends

Spread, Gross Margin, Cash Margin and Profit per Barrel

Four different variables are used in this Issues and Trends publication that are each sometimes described as “margins” by

petroleum analysts: spread, gross margin, cash margin and profit per barrel. These variables all capture a measure of

revenues minus costs on a “per barrel” basis. They vary in (1) what is included in the revenues (2) which costs are

subtracted, and (3) the barrel basis, which usually is either barrel of product sold or barrel of crude oil input.

A spread is the difference between petroleum product price(s) and crude price. For example, gasoline spread is the

difference between gasoline price and a specific crude oil price. In addition to single product spreads, there are multiple

product spreads. For example, a 3-2-1 crack spread assumes 3 barrels of crude oil can be used to produce 2 barrels of

gasoline and 1 barrel of distillate. Thus:

3-2-1 Crack Spread ($/Bbl) = (2 x Gasoline Price

+1 x Distillate Price

-3 x Crude Oil Price)/3

Note that spread does not take into consideration all product revenues and excludes refining costs other than the cost of

crude oil. 

Gross refining margin is similar to a crack spread, but takes into consideration all product revenues and all raw material

input costs (i.e., crude oil, oxygenates, butanes, catalysts, etc.). In this publication, the unit basis for the gross margin is

barrel of product sold, rather than barrel of crude oil input. The gross margin is calculated on an individual refinery level,

on a company level, or on an industry level. Gross margin is used on a company level in this document. It represents all

product revenues received by a company per barrel of product sold minus all raw material costs and products purchased

per barrel of product sold. Revenues reported by refining and marketing companies are mainly derived from wholesale sales

(branded and unbranded rack, dealer tank wagon, and bulk commercial sales), but they generally would include some spot

and retail sales as well.

Refining cash margin considers all product revenues and cash operating costs to produce the products. Like gross margins,

cash margins can be calculated at a refinery level, company level or industry level. Refining cash margins are calculated

both at a company level and at a refinery level in this document. 

! The company level cash margin is all refining and marketing revenues per barrel of product sold minus all cash

operating costs per barrel of product sold. As in the case of gross margins, revenues are derived mainly from wholesale

sales with some spot and retail sales. The costs include all raw material inputs, and other cash operating costs such as

fuel, electricity, labor, and general and administrative costs including corporate overhead. While most retail outlets

are not owned by refining and marketing companies, some marketing and distribution costs are incurred by these

companies and are included in the cash margin calculation. Costs do not include non-cash items such as depreciation.

! Refinery level cash margins in this report are calculated per barrel of crude oil input to the facility. The refinery cash

margin represents revenues generated by an individual refinery selling its product at the refinery gate minus its

individual cash refining costs. The revenues and raw material costs were generated from spot prices, and were

calculated per barrel of crude oil charged to the refinery. The other cash operating costs are limited to refining costs

(i.e., no distribution or marketing costs) and include fuel, electricity, maintenance materials and labor. 

Downstream profits are also sometimes estimated on a per barrel of product sold or per barrel of crude oil input. Operating

net income includes both cash costs and non cash costs such as depreciation, and downstream “net income” includes

financing costs, income taxes and other non operating costs as well as non-operating revenues. 
Energy Information Administration / Petroleum 1996: Issues and Trends 125

Table 14. Refinery Cash Margin Calculation

East Coast Refinery Using Brent Crude Oil Summer 1995

Price

($/Barrel)

Volume Revenues

(Fraction of ($/Barrel

Crude Charge) Crude Charge)

REVENUES

LPG 14.12 .061 0.86

Naphtha 19.31 .026 0.50

Premium Gasoline Conventional 23.27 .065 1.52

Regular Gasoline Conventional 21.28 .131 2.78

Premium Gasoline RFG 24.58 .131 3.21

Regular Gasoline RFG 22.90 .261 5.98

Jet Fuel 20.56 .090 1.85

No. 2 Heating Fuel 19.55 .055 1.08

Diesel Fuel - Low Sulfur 20.35 .111 2.26

No. 6 Fuel Oil - 1.0% S 15.39 .156 2.40

Total NA 1.115 22.87

COST

Crude Oil FOB Cost 16.05

Crude Transportation Cost 0.92

Other Feedstock Cost 2.48

Revenues minus Feedstock Cost 3.42

VARIABLE COST

Steam Cost 0.05

Cooling Water Cost 0.11

Electric Power Cost 0.22

Catalyst, Chemicals Cost 0.14

Total Fuel Burned 0.61

 Total Variable Cost 1.13

Other Operating Cost 0.43

Net Margin 1.87

Note: Total yield is greater than crude input alone due to additional feedstocks (e.g., MTBE and butanes) and processing gain.

Sources: Crude Oil, Natural Gas Liquid, and Product Prices: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News, Hart/IRI Fuels

Information Services (Arlington, VA). Crude Oil Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus, Petroleum

Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum and Economic Publications (Nicosia, Cyprus) and

Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company sources and

downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various public

literature sources. Cost Escalation: Based on Nelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell Publishing

Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA), price delivered to industrial customers in Louisiana and

Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.
126 Energy Information Administration / Petroleum 1996: Issues and Trends

Each of the refinery types represented is a single train ! Seasonal: Margins peak frequently in the second or third

refinery (i.e., with no unit duplication), and thus has a

reasonably efficient cost structure that probably represents

better-than-average real-world margin performance.

Nevertheless, these representations effectively illustrate

margin trends over time and allow exploration of the major

factors influencing their rise and fall. Operating cost data for

actual individual refineries can vary considerably, even for

refineries of comparable complexity. The operating costs

used in the margin calculation are process-unit based, and

were derived from a variety of industry and reference

economic source documents.

Crude oil throughput, other feedstock volumes, such as

butanes, and product yields were varied quarterly to reflect

the seasonal transitions between the high distillate demand

and high gasoline demand seasons and to meet seasonal

product quality specification requirements (e.g., gasoline

Reid vapor pressure). Regulatory compliance costs were

captured by making appropriate configuration, operating,

and cost adjustments as regulations affecting product

specifications changed.

In order to reflect the effect of different reformulated

gasoline (RFG) market requirements after 1995, different

mixes of gasoline formulations were used for the East Coast

refinery calculations than for the Gulf Coast. The East Coast

refineries produced 2/3 RFG and 1/3 conventional gasoline,

while the Gulf Coast refineries produced 1/3 RFG and 2/3

conventional gasoline. 

Spot prices (both crude oil and product) were used in

deriving the Gulf Coast and East Coast refinery margins

discussed and displayed throughout this chapter. Spot prices

represent marginal product and crude oil being bought and

sold on the market. Spot prices can vary significantly with

short-term supply/demand fluctuations, and therefore

probably reflect more variation in price than a company

might actually experience. Most companies use a mix of

contract and spot markets for both feedstock purchases and

product sales. Contract market prices are usually more

stable, even though many contracts use spot prices in their

pricing formula. 

Margin Variations

Figure 88 displays the margin calculation for the Gulf Coast

refinery running a sour, moderately heavy crude oil (Arab

Light) and for the East Coast refinery running a light sweet

crude oil (Nigerian Bonny Light). These margins exhibit

several typical variations: 

quarters and hit their low points during the winter (fourth

or first quarters);

! Long-term: A general upward trend underlies the margins

from 1985 through 1990, followed by a subsequent

weakening in margins from 1990 through 1995, with the

possibility of a turnaround in 1996;

! Regional: The Gulf Coast refinery margins exhibit a

larger variation in the underlying long-term trend than

East Coast refinery margins, rising faster and

overshooting the East Coast margin, then reversing and

falling back below the East Coast margin by 1993.

This section discusses market factors that explain these

variations, including product and crude supply/demand

balances, the interactions of light versus heavy product

demand, light versus heavy crude availability, the

availability of conversion capacity, and changing product

specifications brought about by the need for cleaner fuels.

Seasonal Margin Variations Stem

Mainly From Gasoline Market

U.S. refining margins are highest in the spring and summer

months (second and third quarters) because they are heavily

influenced by gasoline markets. Gasoline provides the

highest contribution to cash margin of any single product.

For the East Coast refinery processing Brent crude oil, in the

example of Table 14, gasoline comprises about 53 percent of

the total product slate produced and contributes about 59

percent of total revenues. The gasoline market is highly

seasonal, with price spreads (spot gasoline minus crude oil

prices) generally cresting in late spring or early summer as

the industry prepares to meet peak driving demand, which

usually occurs around June (see Chapter 2). The rising

gasoline spreads are reflected in rising cash margins.

Consequently, the seasonal swings of refinery margins

correspond to price variation in the gasoline market (Figure

89). In fact, the spring margin increase is a primary

determinant of a refiner’s performance for an entire year. 

Distillate has a counter-cyclical demand and price pattern

from gasoline. The distillate price rise in the fall tends to

moderate the margin’s seasonal pattern, but it does not

counterbalance the gasoline market’s strong seasonal

influence on refining margins. Distillate’s smaller influence

is primarily a result of its small volume relative to gasoline.

(Distillate’s share of the product barrel produced by an East

Coast refinery using Brent crude oil is about 23 percent,

while gasoline’s share is about 53 percent.)
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

-1.00

0

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

Dollars per Barrel

Gasoline Spread

Gulf Coast 

(Arab Light)

Energy Information Administration / Petroleum 1996: Issues and Trends 127

Figure 89. Quarterly Gulf Coast Refining Margin and Gasoline Spread

(Based on Spot Product Prices)

Sources: Crude Oil, Natural Gas Liquid, Product Prices, and Spot Spreads: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News,

Hart/IRI Fuels Information Services (Arlington, VA). Crude Oil Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus,

Petroleum Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum and Economic Publications (Nicosia,

Cyprus) and Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company

sources and downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various

public literature sources. Cost Escalation: Based on Nelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell

Publishing Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA), price delivered to industrial customers in

Louisiana and Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.

Refining margins are generally lowest during the winter gasoline prices relative to crude oil. The weak gasoline

quarters (fourth and first quarters) when gasoline demand spreads in those years contributed to the low seasonal swings

and prices have fallen and inventories are building. The in margins and to lower annual refining margins. The longerweather’s impact on distillate prices tends to determine if the term variation in world crude oil supply/demand balance

first quarter or the fourth quarter is the lowest margin seems to play a role in the strength or weakness of the

quarter. Early cold weather can drive distillate prices up in product market seasonal variation, which is discussed below.

the fourth quarter, pushing fourth quarter margins higher

than first quarter, and vice versa (e.g., fourth quarter 1988

margins were higher than first quarter 1989 margins, but

fourth quarter 1993 margins were lower than first quarter

1994.)

Seasonal swings vary in magnitude. For example, the spring

seasonal increase in margins was low in 1992 and 1993.

Again, the strong influence of gasoline markets on refinery

cash margins can partially explain the margin behavior.

Gasoline spreads also showed little seasonal climb in 1992

and 1993. In the United States, the slow growth of gasoline

demand in the early 1990's coupled with strong supply kept

gasoline stocks relatively high throughout the summers of

1992 and 1993 (Figure 90). The market responded with weak

Long-Term Margin Trends Driven By

Multiple Factors

In addition to seasonal factors, several long-term factors can

affect margins. Such factors include crude market tightness

which sometimes influences product market tightness for

extended periods, the light-heavy crude oil and product

supply demand balance, refining capacity utilization, and

implementing the reformulated gasoline (RFG) program.

However, not all of these factors had a significant effect on

margins over the past decade.
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

190,000

200,000

210,000

220,000

230,000

240,000

250,000

260,000

Thousand Barrels

128 Energy Information Administration / Petroleum 1996: Issues and Trends

Sources: Energy Information Administration (EIA), 1986-1995: Petroleum Supply Annual, Vol. 2, Table 2. 1996: Petroleum Supply Monthly

(various issues), Table 2.

Figure 90. Total Gasoline Stocks

Product Market Tightness Can Be Related to

World Crude Market Tightness

The weak seasonal increases in margins and gasoline spreads

in 1992 and 1993 can be related to crude market

supply/demand balance. During 1992 and 1993, the world

experienced an oversupply of crude oil and products as

demand worldwide languished from a recession. Petroleum

demand recovered and grew substantially in 1994, but crude

oil supply grew strongly as well, keeping markets from

tightening very rapidly, and preventing a strong price The underlying upward movement in refining margins from

resurgence. During periods when crude markets are loose the mid-1980's until the early 1990's, and their subsequent 88

(excess supply relative to demand), product markets are less decline, can be explained in part by the changing light-heavy

likely to tighten. The wide surplus availability of crude oil to balance for both crude oil supply and product demand and

respond to any product demand requirements can keep the availability of conversion capacity to upgrade heavy

product price spreads relatively weak. Conversely, tight materials to light products. Over the last decade, the lightcrude markets can be accompanied by tight product markets. heavy price difference for both crude (Figure 91) and

When crude markets are tight, crude oil prices can be pulled product (Figure 92) have tracked the increase and decrease

higher by tightening product markets as happened in early in refinery margins. 

1996 when distillate demand pulled crude oil prices up at the

end of winter. However, in either case, product markets do

not necessarily follow in lock step. Both crude and product

markets were tight in 1996, but in early 1997, crude markets

loosened while product markets remained tight. If crude

markets remain loose, product markets will likely follow.

Light Versus Heavy Balances for Crude and

Products Affect Margins

The price differences between light and heavy crude oils and

light and heavy products are among the most important

variables affecting refinery margins. These differentials are

the incentives for installing expensive processing facilities in

a refinery, including fluid catalytic cracking (FCC),

hydrocracking, coking and other residual conversion

The increasing, light-to-heavy crude oil supply ratio had a depressing 88

effect on margins during the 1990's, as discussed in more detail under longterm trends. Light sweet crude supply was especially abundant during this

time, and the light-heavy crude price difference continued to drop

substantially, with Bonny Light crude oil falling to near parity with Arab

Light crude oil in early 1995. (Despite its name, Arab Light is an intermediate

crude oil based on bottoms content.)
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

1.00

2.00

3.00

4.00

5.00

6.00

Dollars per Barrel

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

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12.00

14.00

16.00

Dollars per Barrel

Energy Information Administration / Petroleum 1996: Issues and Trends 129

Figure 91. Light Minus Heavy Crude Price Difference

Spot Bonny Light - Arab Light

Source: Standard & Poor’s Platts.

Source: Standard & Poor’s Platts.

Figure 92. Light Minus Heavy Product Price Difference

(Spot Gulf Regular Conventional Gasoline - 1 Percent S Residual Fuel)
130 Energy Information Administration / Petroleum 1996: Issues and Trends

facilities that convert the heavy material in crude oil to covering the added variable operating cost of refineries

lighter, higher-valued products such as gasoline and diesel. newly equipped to run heavy sour crude oil. During the first

Crude oils vary in quality primarily based on how much small light-heavy price differentials allowed virtually no

heavy material they contain. In Table 15, a light, high added margin for heavy crude refiners to generate return on

quality crude oil, Nigerian Bonny Light, is compared with a their recently installed conversion facilities.

heavier, lower quality Saudi Arabian crude oil. The Bonny

Light crude oil contains only 3.4 percent of heavy bottoms After the crude oil prices dropped below $20 per barrel in

fraction compared to 27.2 percent heavy bottoms fraction for 1986, demand for crude oil began to grow again. Demand for

Arab Heavy. The heavy material in crude oil can be made heavy products continued to decline in the United States as

into heavy product or can be converted into light product if well as in other major world oil markets (Figure 94), but at

a refinery has the conversion facilities. The price of heavy a slower rate. Addition of new residual oil conversion

oil products is determined in lower valued market projects fell drastically. As Figures 91 and 92 show, lightapplications where residual fuel oils compete with coal and heavy crude and product differentials began to increase in

natural gas. When demand and price of residual oil decline the late 1980's and grew until 1991 with corresponding

relative to other refined products, light crude oils become improvements in refinery margins.

more attractive. Light-heavy product and crude price

differentials increase. As the differentials increase, the In the early 1990's, light-heavy differentials again declined.

incentive for refiners to install more heavy crude conversion In part, excess world conversion capacity contributed to the

equipment increases. But markets move in both directions. decline. Two major sour crude processing facilities were

Over time, the relative demand for light and heavy products begun in the United States. These projects were joint

may shift, more light crude oil may become available, or ventures of U.S. refiners and heavy crude oil exporting

refiners may install too much conversion equipment. Each of countries. When complete, a Lyondell/PDVSA project will

these circumstances will tend to push the light and heavy increase heavy crude processing at its Houston refinery from

prices closer together, reducing the differential. The impact 120 thousand barrels per day to 200 thousand barrels per day,

on refinery margins of variations in light-heavy differentials and a Shell/Pemex project will allow its Deer Park refinery

have had profound impacts on U.S. refiner margins over the to run 100 thousand barrels per day of heavy Mexican Maya

past two decades. A brief review of this time period provides crude. Conversion capacity in Europe has also grown, but at

an illustration of these important margin variables. a much more modest rate in the 1990's compared to the mid

In the late 1970's, widening light-heavy crude oil price

differentials and forecasts of crude oil supply becoming In the 1990's, conversion capacity was only part of the

heavier as product demand grew spurred a serious movement downward pressure on light-heavy differentials. The primary

to install heavy crude oil processing facilities. At this time, factor driving the decline was a substantial increase in light,

domestic crude oil production was relatively constant and the sweet crude oil production in the Atlantic Basin market

mix was growing heavier (Figure 93). Crude oil prices had region. The largest part of the increase came from the North

risen dramatically, but demand growth was still strong. Sea, where production increased by 60 percent (2160

Light-heavy crude oil price differentials increased, rising thousand barrels per day) from 1990 to 1995. West African

each time crude supply tightened. Many U.S. refiners countries and the new light sweet Cusiana area in Colombia

expected import levels to grow, and they thought that also contributed increased supplies of light sweet crude oil.

additional imports would probably come increasingly from Saudi Arabia added to the growing differential by limiting

the larger world producing areas, which supplied mostly production of its heavy crude (Arab Heavy) and raising its

heavy sour crude. Thus, as the 1980's began, many U.S. price to encourage use of Arab Super Light. This policy

refiners were engaged in adding residual conversion added increased downward pressure on the light-heavy

capabilities. differentials in 1994. The Saudi limitations on their heavy

But from 1981 to 1986, oil markets did not evolve as Atlantic Basin drove the price differential down to the point

forecasted. Product demand fell, and crude import in 1994 that the West African crude oils became attractive to

requirements diminished. Product demand also fell the Asian market, despite the long freight haul. The trade

worldwide, so the supply of light crude oil was ample at the press reported that movements from West Africa to Asia in

resulting reduced crude oil demand levels. Conversion the summer 1996 reached 800 thousand barrels per day.

capacity planned in the late seventies was now coming on Since 1994, in fact, the demand pull from the Asian markets

stream in the United States and Europe. Consequently, the has provided some price support for the value of Atlantic

light-heavy differentials dropped dramatically, barely Basin light-sweet crudes, in effect providing a price floor.

half of the 1980's, total refining margins were low, and the

1980's (Figures 95 and 96).

crude together with the glut of light-sweet crude in the
1975 1980 1985 1990 1995

0

4

8

12

16

20

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Thousand Barrels per Day

C rude Oil Imports

Product Im ports and Other

C rude Oil and NGL Production

Energy Information Administration / Petroleum 1996: Issues and Trends 131

Figure 93. U.S. Petroleum Supply

Note: NGL = Natural gas liquids.

Sources: Energy Information Administration (EIA), 1975-1995: Annual Energy Review (1995), Table 5.1. 1996: Petroleum Supply Monthly

(February 1997), Table 5.

Table 15. Distillation Volume Percent Yields

Fuel Type Arab Heavy Arab Light Bonny Light

Nigerian 

Light Ends 6.3 7.7 6.6

Gasoline 15.5 18.6 20.7

Kerosene 7.2 8.6 9.5

Diesel 16.2 20.3 30.6

Heavy Atmospheric Gas Oil 27.6 28.9 29.2

Bottoms (1,050 EF+) 27.2 15.9 3.4

Source: Energy Information Administration, estimates based on crude assays from company sources.

Before showing the full margin impact of similar refineries heavy. The price spread is lowest for the highest valued,

processing light versus heavy crude oils, the link between the light, sweet crude oil (Bonny Light), and is highest for the

light-heavy differential and average refinery margins can be lower valued, heavy, sour crude oil (Arab Heavy). Markets

explored by observing the simple spread between gasoline weakened in 1992 when world crude oil supply outstripped

prices and light and heavy crude prices. Due to gasoline’s petroleum demand, and both gasoline price spreads fell, but

strong influence over cash margins, the gasoline price spread the heavier crude spread fell more than the lighter crude

should provide an indication of margin performance. Both spread. As the 1990's progressed, the supply of light, sweet

the full margin and gasoline spread observations will crude oils in the Atlantic Basin increased, and the heavy

illustrate the small premiums received by those processing crude oil-gasoline price spread fell closer to the light crude

heavier crude oils. Figure 97 shows the difference between oil-gasoline price spread. In 1995, the Arab Heavy spread

gasoline price and two crude oil prices, one light and one was almost at parity with the Bonny Light gasoline price
1975 1980 1985 1990 1995

0

10

20

30

40

50

60

(Percent of Total Consumption)

Japan

Europe

United States

Heavy Fuel Oil Weight

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

5

10

15

20

25

30

35

40

Prim ary Distillation Capacity (Percent)

Cat C racking

Reform ing

Thermal

132 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 94. Decline in Heavy Fuel Oil Consumption

(Percent of Total Petroleum Products Consumed in Each Country or Region)

Source: British Petroleum, Statistical Review of World Energy, 1996.

Sources: 1981-1995: Energy Information Administration (EIA), Form EIA-820 "Annual Refinery Report." 1995: The stream day capacities are

projected capacities reported on Form EIA-820 "Annual Refinery Report” (1995)." 1996: Number of refineries and crude distillation capacity from Form

EIA-810 "Monthly Refinery Report" (January 1996). 

Figure 95. U.S. Downstream Processing Capacity
1980 1982 1984 1986 1988 1990 1992 1994 1996

0

2

4

6

8

10

12

14

16

18

Primary Distillation Capacity (Percent)

Cat Cracking

Reform ing

Thermal

1991 1992 1993 1994 1995 1996

0

2

4

6

8

10

12

14

16

18

Dollars per Barrel

Nigerian Bonny Light

Arab Heavy

Energy Information Administration / Petroleum 1996: Issues and Trends 133

Source: Energy Information Administration (EIA). Calendar Day Capacity as of January 1 of Each Year: EIA, International Energy Annual

(various issues), Table 3.6.

Figure 96. Western European Downstream Processing Capacity

Source: Standard & Poor’s Platts.

Figure 97. Gasoline Spread Comparisons

(Spot Gulf Regular Conventional - Spot Crude)
134 Energy Information Administration / Petroleum 1996: Issues and Trends

spread. Because of gasoline’s strong effect on refining boiling materials that can be upgraded to lighter, higher

margins, one might expect to find that, as light-heavy crude valued products. This type of investment is driven only by

differentials decline, the less complex refiners running light- light-heavy product price differentials; however, as discussed

sweet crude oils would see little change in margins, but more above, light-heavy product price differences are intimately

complex refiners running heavy-sour crudes would tied to light-heavy crude price differentials. From 1986 to

experience a decline. Hence, average industry margins would 1990, the Brent coking refinery earns an increasing margin

decline. premium over the non-coking refinery. However, the coking

Now consider the full margin variation seen over the past

decade as a result of light/heavy crude and product market

variations. Two cases are used to explore the impacts. The

first case compares two similar refineries processing

different crude oils, one light and one heavy. This case

illustrates the advantage to refiners of investing so as to be

able to use lower priced, heavier crude oils without much

change in product slate. The second illustration compares

two refineries processing the same crude oil to produce

different product slates, thus showing the advantage gained

by investing to produce a lighter product slate. 

The first case (Figure 98) compares the margins for Arab

Light and West Texas Intermediate (WTI) crude oils

processed in a cracking and coking refinery on the Gulf

Coast. The figure shows the difference between the two

margins. While both of these crude oils are being run

through similar refineries, the Arab Light crude oil has a

higher percent of heavy residual boiling range material than

WTI, and therefore requires a substantially larger coking unit

and also added hydrotreating to remove sulfur from the fluid

catalytic cracking unit feedstock. The extra investment in

equipment needed to process Arab Light requires a higher

margin to make that investment economically viable.

However, in 1986 and 1987, and again in 1994 and 1995, the

margins for processing Arab Light in the more expensive

refinery were smaller than those for processing WTI in the

same refinery. From 1986 to 1990, Arab Light margins

increased relative to WTI because the light-heavy crude

price difference grew, providing increased contributions to

the upgrading investment. But then the Arab Light margins

declined relative to WTI until 1995, as the light-heavy crude

oil price differences narrowed again. Over the last decade,

refiners serving the same markets but using heavier crude

oils have not earned a significant premium over refiners with

less capital invested and using lighter crude oils. 

The second case, which shows the historical advantage to

refiners of investing to produce a lighter product slate, looks

at two refineries producing different product slates from the

same crude oil. A comparison of the margins for processing

Brent crude oil in a Gulf Coast refinery with a coker and in

an East Coast refinery containing no coking unit shows some

of the benefits of upgrading to achieve a higher mix of

lighter, higher-valued products (Figure 99). Although

refinery upgrading is normally discussed in conjunction with

heavy, sour crude oils, lighter crude oils also contain residual

refinery’s premium falls from 1990 to 1995. This difference

also is affected by other factors such as regional product

price differences, but the influence of the rise and fall in

light-heavy crude oil and light-heavy product price

differences is clearly evident. 

In summary, the market dynamics surrounding the

interactions of light versus heavy product demand, light

versus heavy crude availability, and availability of

conversion capacity all contributed to the long-term margin

variations over the past decade. These market dynamics

affected not only those refiners who installed heavy material

conversion capacity, but all refiners in the industry.

Refining Capacity Utilization’s Influence on

Margins Not Always Evident

Apart from product and crude prices, refinery capacity

utilization is another variable that potentially can affect

margin behavior as discussed above. In the United States,

capacity utilization has increased significantly, averaging

well over 90 percent since 1992, for the atmospheric

distillation units. Utilization also increased for conversion

units downstream of the distillations units, such as cokers

and catalytic cracking units. Generally, as production levels 89

in any manufacturing industry approach capacity limits,

marginal costs to produce a product increase. For example,

idle capacity with high variable costs may be brought online

to help meet rising demand. As marginal costs per unit of

product increase, prices increase, and the manufacturing

industry can experience an increase in average margin (price

minus cost). In refining, costs per unit of product may

increase at high utilization because downstream units can be

fully loaded before distillation inputs reach maximum levels.

(At this point, the refiner is getting hydroskimming yields on

the last increments of capacity.) But refiners don’t suddenly

hit a capacity constraint. They have flexibility to avoid

constraint-driven fast cost increases at high utilizations by

changing operations, by using lighter crude oil mixes that

don’t require as much downstream unit capacity, and by

purchasing product from other world refining areas. As a

result, the importance of utilization only becomes apparent

when refiners push to the last few increments of capacity,

and then the results can be dramatic. California has

Lidderdale, Tancred, Nancy Masterson, Nicholas Dazzo, “U.S. Refining 89

Capacity Utilization,” Energy Information Administration, Petroleum Supply

Monthly, DOE/EIA-0109 (95/10) (October 1995), pp. xxxiii-xxxix.
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

-2.50

-2.00

-1.50

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0

0.50

1.00

1.50

D o lla rs p e r B a rre l

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

-0.50

0.00

0.50

1.00

1.50

2.00

D o lla rs p e r B a rre l

Energy Information Administration / Petroleum 1996: Issues and Trends 135

Figure 98. Value of Upgrading: Heavy Crude Margin - Light Crude Margin

(Arab Light (Heavy) and WTI (Light) Crude Processed in Complex Refinery)

Sources: Crude Oil, Natural Gas Liquid, and Product Prices: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News, Hart/IRI Fuels

Information Services (Arlington, VA). Crude Oil Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus, Petroleum

Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum and Economic Publications (Nicosia, Cyprus) and

Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company sources and

downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various public

literature sources. Cost Escalation: Based on Nelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell Publishing

Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA), price delivered to industrial customers in Louisiana and

Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.

Figure 99. Value of Upgrading: Margin with Coker Minus Margin Without Coker

Sources: Crude Oil, Natural Gas Liquid, and Product Prices: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News, Hart/IRI Fuels

Information Services (Arlington, VA). Crude Oil Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus, Petroleum

Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum and Economic Publications (Nicosia, Cyprus) and

Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company sources and

downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various public

literature sources. Cost Escalation: Based on Nelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell Publishing

Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA), price delivered to industrial customers in Louisiana and

Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.
136 Energy Information Administration / Petroleum 1996: Issues and Trends

experienced this problem with the introduction of its unique

RFG that few other refiners outside of the area can produce

in large quantities.

With the exception of California, the U.S. refining industry

has not exhibited increases in margin with corresponding

increases in capacity utilization. While distillation capacity

utilization and capacity utilization for downstream units

grew strongly throughout the 1990's, margins declined

(Figure 100). From an economic viewpoint, this observation

implies the industry is not hitting capacity constraints where

the downstream units are fully loaded, or at least any effects

of capacity utilization are relatively small and masked by

other, more dominant margin drivers. 

In recent years, analysts have begun to focus on the U.S. refinery utilization must also be viewed in the context

utilization of downstream capacity, which represents a far of world refining capacity. In the future, even if U.S.

larger investment per barrel than distillation capacity, to refineries begin to feel capacity constraints, other countries

explain margin behavior. Demand increased and distillation may be able to produce products in excess of their own needs

capacity utilization increased in the 1990's, and downstream and ship them to the United States more cheaply than U.S.

units were added and improved to be able to increase refiners can produce the products. In this case, the U.S. will

production of light products and to respond to changing not see much of an increase in operating costs until world

environmental regulations. The underlying cost structure of industry excess capacity diminishes. 

the industry changed. While more expensive units were

being expanded, efficiencies were also being incorporated. Eventually, world petroleum demand likely will grow until

This change resulted in debottlenecking and, in some cases, capacity bottlenecks are experienced. If the industry reaches

improvements in variable costs. But here again, it has proven a point where the most expensive downstream units are fully

difficult to establish a good quantitative relationship between loaded, refiners will begin using more light crude oils that do

capacity utilization and margins. Regardless, we cannot not require as much downstream capacity to produce the

conclude from lack of a simple correlation that capacity higher valued products if light crude oil supplies are

utilization is not an important variable. In the future it could available. The increase in light crude oil demand will, in

have a significant impact on margins. turn, drive up the light crude oil price relative to heavy crude

A better understanding of the capacity utilization/margin

relationship can be gained by reviewing how refiners operate

residual conversion facilities. Once refiners install cokers or

heavy oil crackers, they tend to operate these units near full

capacity, seemingly without regard to crude or product price

variation. But full utilization is generally a rational economic

decision. Most of the cost of the facilities are fixed costs, such

as the sunk investment cost and labor used to run and

maintain the units. Fuel, utilities, catalysts and chemical

costs are functions of throughput. Thus, based on variable

costs, the refiner may find it more economic to buy heavier

crude oils and run the conversion units at full utilization most

of the time, even though the difference between light and

heavy crude prices may have contracted significantly. The

smaller price differences diminish the ability of the refiner to

recoup the investment in the conversion equipment and earn

a competitive return. The result is that downstream units may

be run at high utilizations both when margins are rising and

when they are falling. 

The measures of the need for more or less bottoms conversion

capacity are the light-heavy crude and product price

differentials. There is no fixed demand volume for residual

fuel oil, and when bottom conversion capacity is short and

light crude availability is tight, residual fuel production is

large. To clear the market, residual fuel producers must drop

the price and sell into less attractive markets. The economics

during such situations favor installing more conversion

equipment to reduce residual fuel production. But if too many

refiners install conversion equipment, or the quality balance

of available supply changes, prices will shift. In all these

cases, capacity utilization will not indicate if a capacity

surplus exists or more is needed, but the light-heavy price

differences are clear indicators. 

oil and the light product prices relative to heavy products.

Margins would be expected to increase as well. That increase

in margins will provide the incentive to build new capacity.

Reformulated Gasoline Margin Impacts Were

Overwhelmed By Other Factors 

One of the most significant regulatory factors affecting

refining costs was the implementation of the Clean Air Act

Amendments of 1990 (CAAA). Investments were made to

lower the sulfur content of diesel fuel and to comply with the

specifications of reformulated gasoline. Many of the refining

facility improvements made during the 1990's were

prompted by the need to meet the new clean fuel

requirements. (The oxygenated gasoline requirement only

required refiners to add oxygenates to the gasoline and adjust

how some units were run in order to correct for the

additional octane provided by the oxygenates.)
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

80

85

90

95

100

Percent

Energy Information Administration / Petroleum 1996: Issues and Trends 137

Figure 100. Atmospheric Distillation Unit Capacity Utilization

Sources: Distillation Capacity: Energy Information Administration (EIA), 1981-1995—Petroleum Supply Annual (Vol. 1), Table 16.

1996—Petroleum Supply Monthly (February 1997), Table 28.

EIA previously analyzed the effect of RFG on refiners and containing benzene for sale as naphtha product. Arab Light

reported the results in the Petroleum Marketing Monthly. crude oil, on the other hand, benefits from the RFG oxygen 90

The result of the current analysis is similar to the earlier EIA

study in that the margins are based on specific crude oils

used in specific U.S. regions. Yield and cost data pre-RFG

and post-RFG introduction were developed, which allowed

for separation of RFG cost impacts from market changes that

occurred simultaneously. 

Not all refiners were equally affected by the regulatory

change. Bonny Light crude oil was considered a very good

crude oil for producing gasoline in the pre-RFG era. It

contains high yields of good quality naphtha, which is

reformed to produce gasoline. Unfortunately, the naphtha

derived from many light crude oils also contains relatively

high levels of benzene and material that yields benzene when

the naphtha is processed. While benzene has a high octane

value, it is also carcinogenic and RFG specifications limit its

level in gasoline. In order to meet RFG specifications,

refiners historically using only Bonny Light or Brent had to

invest in new processes such as isomerization to remove

benzene from the naphtha or to separate some of the naphtha

requirement. Arab Light naphtha has a low aromatic content,

including low benzene content, so benzene removal is less

problematic than with Bonny Light. However, Arab Light’s

low aromatic content results in a relatively poor octane

gasoline pool. Fortunately, the oxygenates required in RFG

not only improve fuel cleanliness, but also boost octane,

countering the lack of aromatics. WTI sits in the middle

between Bonny Light or Brent and Arab Light.

A close examination reveals that the change in refining costs

attributable to RFG had no major impact on margin behavior

between 1993 and 1995. In fact other market factors

overwhelmed any impact of the introduction of RFG. For

example, Arab Light margins fell much more between 1993

and 1995 than either Bonny Light or WTI, in spite of its

RFG benefit (Figure 98). The rapidly declining light-heavy

crude difference had more influence over the relative margin

changes than did RFG. When gasoline margin contributions

were broken out separately, Arab Light crude processors

showed slightly higher contributions to margins from this

product, as expected, but this advantage is overwhelmed by

factors affecting costs. As stated in the earlier study, across

the spectrum of refineries, very little additional margin

appears to have been generated to cover the increased

John Zyren, Charles Dale, and Charles Riner, “1995 Reformulated 90

Gasoline Market Affected Refiners Differently,” Energy Information

Administration, Petroleum Marketing Monthly, DOE/EIA-0380(96/01)

(January 1996), pp. xiii-xxxi.
138 Energy Information Administration / Petroleum 1996: Issues and Trends

facility investment or any return on RFG investment in the

time since RFG production began through 1996.

Gulf Coast Margins Have Been

Generally Higher Than Those on the

East Coast

The last factor contributing to margin variation is the

regional differences in refineries. This chapter explores only

East Coast and Gulf Coast refineries, leaving the unique

aspects of California refineries for a future discussion.

Table 16 shows the margins calculated for typical refineries

in each area using several crude oils. 

Figure 101 compares the margins for the East Coast refinery

running Brent crude oil and the Gulf Coast refinery running

Brent and WTI. The Gulf Coast refinery margins are

generally higher than the East Coast margins. The extra

conversion equipment contained in the Gulf Coast refinery

allowed the refiner to improve the yields of the lighter,

higher valued products over the East Coast refiner, even

when using lighter crude oils. Yet the interesting point is that

the improvement is fairly small. Very little premium is

available to cover the costs and returns on this extra

conversion equipment. However, the East Coast refinery

used to generate these margins is as cost efficient as the Gulf

Coast refinery for the same processing equipment. In reality,

some East Coast refineries are not very cost efficient, so Gulf

Coast refiners likely experienced larger margin premiums

over East Coast refiners than shown here.

Seasonal variations are slightly different between the Gulf

Coast and the East Coast refineries. The Gulf Coast

refineries exhibit large second quarter margins, which fall

again in the third quarter. Up until 1992, the East Coast

refinery margins were similar. However, beginning in 1992,

a slightly different pattern began emerging. While East Coast

margins rise in the second quarter, they don’t fall back as

much in the third quarter as they do on the Gulf Coast

margins. The reasons for this shift are not clear. 

Since 1990, the margins of Gulf Coast refiners processing

either Brent crude oil or WTI moved together fairly closely,

with East Coast refiners using Brent trailing somewhat

behind. Since 1994, though, the East Coast refiners using

Brent improved their position. Part of this shift may be due

to a shift in relative gasoline spot prices between the East

and Gulf Coasts that occurred during 1994 and 1995. Since

1990, New York Harbor spot gasoline prices frequently

exhibited a stronger premium over Gulf Coast prices during

the second half of the year. But in 1994 and 1995, this

premium was much larger than usual, boosting the margin

for East Coast refiners using lighter crude oils.

Spring 1996 and Future Trends

As was discussed in Chapter 1, gasoline and distillate prices

rose rapidly in April of 1996. Were these price increases

reflected in unusually high margins? As shown in Figure 88

and other margin figures throughout this chapter, the answer

is no. The first and second quarter margins in 1996 were not

unusually high compared to those experienced over the last

decade. 

Two factors contributed to cash margin increases since 1994.

The first was a mild widening of the light-heavy price

differences for both crude and product. While this increase

was not very significant, it reversed the decline in this price

difference. As discussed above, the turnaround in light-heavy

price differences should have a positive effect on margins.

The second factor that caused stronger margin performance

was a tight petroleum supply/demand balance. In 1996, this

latter factor probably had a greater influence on margin

increases.

Recall from earlier discussion in this chapter that from 1992

through 1993 markets weakened:

! petroleum production exceeded petroleum demand

worldwide as well as in the United States;

! worldwide stock builds in the second and third quarters

exceeded stock draws in the high demand fourth and first

winter quarters;

! market prices for crude oil and products weakened;

! seasonal product price spread increases were smaller than

usual; and 

! overall price levels drifted downward, causing lackluster

margin performance. 

The supply/demand balance began to tighten in 1994, but

record low light-heavy price differences kept margins

depressed. In 1995 and 1996, the supply/demand balance

pattern is the reverse of 1992 and 1993:

! product demand outpaced crude supply increases;

! winter stock draw downs exceeded summer stock builds,

causing overall inventory levels to drop;

! this tight balance caused crude prices to increase; and

! in the summer quarters (second and third), U.S. refiners’

margins benefitted from the tight supply/demand balance

reflected in low inventories.

The margins for the second quarter 1996 were similar to

those second quarter 1995, and both second quarter margins

showed stronger seasonal upturns than were experienced in

1992 and 1993. If the light-heavy price differences had also

been high, the overall margin levels would have been higher.
Energy Information Administration / Petroleum 1996: Issues and Trends 139

Table 16. Quarterly MarginsRefinery 85Q1 Q2 Q3 Q4 86Q1 Q2 Q3 Q4 87Q1 Q2 Q3 Q4 88Q1 Q2 Q3 Q4 89Q1 Q2 Q3 Q4BONNY LT -EC 1.33 2.99 1.09 0.53 0.14 0.68 0.33 1.25 1.18 2.26 2.76 4.02 1.45 3.15 2.38 2.24BRENT-EC -0.20 0.48 0.13 0.58 0.66 1.95 2.28 3.71 1.28 3.72 2.06 1.54BRENT-GC 0.33 0.69 0.40 0.43 0.83 2.36 3.20 3.98 2.00 4.53 2.50 2.03WTI-GC 1.13 2.33 1.23 0.65 2.23 2.70 0.61 0.28 0.20 0.25 -0.50 0.21 0.30 1.69 3.17 3.39 1.38 3.19 1.21 1.66ARAB LT-GC -2.34 -0.08 -1.17 -0.48 0.25 3.26 0.84 -0.67 -0.95 0.03 -0.15 -0.12 0.27 1.69 2.90 4.07 2.05 3.83 2.15 2.33Refinery 90Q1 Q2 Q3 Q4 91Q1 Q2 Q3 Q4 92Q1 Q2 Q3 Q4 93Q1 Q2 Q3 Q4 94Q1 Q2 Q3 Q4BONNY LT -EC 1.96 4.56 3.47 -1.41 1.42 3.32 2.66 1.05 0.62 1.69 1.72 1.06 0.62 1.63 1.73 1.40 2.60 2.10 1.97 0.37BRENT-EC 1.91 4.30 2.29 -1.62 1.99 2.81 2.27 0.92 0.25 1.35 1.46 1.10 0.43 1.52 1.60 1.14 2.48 1.44 1.30 1.08BRENT-GC 3.07 6.19 3.26 -0.98 2.88 4.50 3.39 1.72 1.59 3.25 2.29 1.72 1.46 3.08 2.34 2.00 3.05 2.73 2.25 0.72WTI-GC 1.80 5.39 4.40 0.19 2.72 3.53 2.38 1.07 1.13 2.59 1.13 0.91 0.51 2.16 1.57 1.10 2.46 1.54 1.19 -0.07ARAB LT-GC 3.01 5.36 4.29 0.84 3.33 4.46 3.47 1.88 1.58 2.73 1.50 1.17 1.58 2.77 2.16 1.59 2.12 2.02 0.76 -0.58Refinery 95Q1 Q2 Q3 Q4 96Q1 Q2 Q3 Q4BONNY LT -EC 0.05 1.83 2.08 1.23 1.01 1.96 1.17 1.08BRENT-EC 0.75 2.41 2.30 1.47 1.70 2.63 1.17 1.49BRENT-GC 0.80 3.15 2.36 1.13 1.57 3.22 1.83 1.86WTI-GC -0.26 2.56 1.20 0.32 0.56 1.50 0.64 0.97ARAB LT-GC -0.96 1.62 0.58 -0.06 0.38 1.31 0.95 1.31

Note: EC=East Coast Refinery. GC=Gulf Coast Refinery.Sources: Crude Oil, Natural Gas Liquid, and Product Prices: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News, Hart/IRI Fuels Information Services (Arlington, VA). Crude Oil

Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus, Petroleum Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum

and Economic Publications (Nicosia, Cyprus) and Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company sources and

downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various public literature sources. Cost Escalation: Based onNelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell Publishing Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA),

price delivered to industrial customers in Louisiana and Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

-2.00

-1.00

0

1.00

2.00

3.00

4.00

5.00

6.00

7.00

Dollars per Barrel

East Coast (Brent)

Gulf Coast (W TI) Gulf Coast (Brent)

140 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 101. East Versus Gulf Coast Margins Running Brent and WTI

(Based on Spot Product Prices)

Sources: Crude Oil, Natural Gas Liquid, and Product Prices: Standard & Poor’s Platts. Spot MTBE Price: Oxy-Fuel News, Hart/IRI Fuels

Information Services (Arlington, VA). Crude Oil Transportation Costs: Average spot freight rates reported in Weekly Petroleum Argus, Petroleum

Argus Limited (New York, NY), International Crude Oil and Product Prices, Middle East Petroleum and Economic Publications (Nicosia, Cyprus) and

Oil and Energy Trends, Blackwell Publishers (Oxford, UK). Refinery Yields: EIA estimates based on crude assays from company sources and

downstream process unit yields based on proprietary correlations. Operating Costs: EIA estimates based on company data and various public

literature sources. Cost Escalation: Based on Nelson Farrar Index published in first issue of each month of Oil and Gas Journal, Pennwell Publishing

Co. (Tulsa, OK). Purchased Natural Gas Price: Energy Information Administration (EIA), price delivered to industrial customers in Louisiana and

Texas, Natural Gas Annual. Electric Power Cost: EIA, large industrial customer price, Electric Power Annual.

What does the future hold? The turnaround in light-heavy and refrain from overproduction. These changes happen over

price differences indicates increasing margin strength. But many months. The tight supply/demand balance will not

the light-heavy differentials are widening slowly, and by the reverse in time to significantly affect margin performance in

end of 1996, the associated margin changes were small. 1997. However, the balance is expected to begin changing in

Supply/demand balances will again move into a supply 1998. The promises of increased light sweet crude oil

surplus following typical economic cycles, but such production in the North Sea and in Colombia will continue

movements do not happen quickly. The roots of the surplus to keep light-heavy differentials low, dampening margin

lie in increased Iraqi production, increasing non-OPEC growth. Thus, 1997 may not see significant improvement in

production in the North Sea and Latin America, and any refinery margins, even if the supply/demand balance remains

decline in OPEC discipline to maintain production quotas relatively tight all year.
Energy Information Administration / Petroleum 1996: Issues and Trends 141

The profitability of U.S. refining and marketing has been volatile. In the past 10 years or so, the rate of return

to the major petroleum companies’ U.S. refining and marketing assets ranged from the most profitable of their

lines of business to near zero. In the 1990s, the profitability of U.S. refining and marketing was frequently lower

than that of U.S. industry generally. The following chapter reviews the factors underlying the volatility of U.S.

refining and marketing profitability and the sources of depressed rates of return in the 1990s. The chapter

concludes with an examination of refining profits in the context of the rises in gasoline and distillate prices in

the first half of 1996.

8. Financial Performance: Low Profitability in U.S. Refining

and Marketing

An industry’s standing in the capital markets largely depends industrial corporations (excluding energy companies). The

on its profit prospects and the perceived risks associated with petroleum companies include the majors (as represented by

them. Nevertheless, analysis of past profit performance of an the FRS companies), publicly-traded independent oil and gas

industry can yield insights as to fundamental sources of producers, and publicly-traded refiners other than the majors.

profitability and the consequent course of investment. The For most of the past 10 years, petroleum company

profitability of the U.S. refining industry over the past 10 profitability has not kept pace with that of other large

years or so has been volatile and, in the 1990's, frequently industrial corporations. In 1995, independent refiners and oil

lower than U.S. industry generally. In order to understand and gas producers registered very poor financial

this volatility and to assess the prospects for this industry, performances. But the FRS majors registered an uptick in

this chapter reviews the sources of U.S. refining profitability. overall profitability, largely due to an upswing in chemical

The analysis utilizes information reported annually to the U.S. refining and marketing profitability has been below the

Energy Information Administration’s (EIA’s) Financial overall profitability of their other businesses, except for 1988

Reporting System (FRS) by the two dozen or so U.S.-based and 1989 (Figure 103). However, in the first six months of

major energy-producing companies. The FRS contains 1996, all segments of the petroleum industry made 91

financial data and associated measures of energy-related noticeable gains in profitability.

operations by line of business, including U.S. refining/

marketing. Over the past ten years, the FRS companies Income from refining operations primarily depends on the

accounted for 72 percent of U.S. refinery capacity. The FRS spread between refined product prices and raw material input

data are complemented by financial information drawn from prices (termed, the gross refining margin), operating costs,

annual reports for non-major domestic refiners. and volumes processed and sold. The gross refining margin

Margins, Operating Costs, and

Profitability

More often than not, petroleum industry profitability has

been lower than the profitability of overall U.S. industry. In the longer term, though, the relationship between refining

Figure 102 shows the return on equity (net income as a profitability and the gross refining margin attenuates. For

percent of stockholders’ equity), an often-used measure of example, the correlation between the FRS companies’ annual

corporate profitability, for petroleum companies and the U.S. refining/marketing profitability and a somewhat broader

Standard and Poor’s (S&P) group of 400 of the largest U.S. definition of the gross refining margin is not significant by

profits. Also, over the past 10 years, the FRS companies’

is an important determinant of short-term refining

profitability. For example, an examination of the gross

refining margin reveals the sources of increased U.S. refining

profits in the context of the gasoline price runup in the First

Half of 1996 (see the section “Petroleum Price Rises Yield

Profit Gains in First Half of 1996"). 

92

For a detailed description of the FRS and analyses of financial issues 91

and trends among U.S. based major energy companies, see Energy

Information Administration, Performance Profiles of Major Energy

Producers 1995, DOE/EIA-0206 (Washington, DC, January 1997).

Return on investment was measured as contribution to net income/net 92

investment in place. The FRS gross refined product margin consists of refined

product revenues less raw material and product purchases divided by refined

product sales volume.
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

1 0

2 0

3 0

4 0

-10

-20

P ercent R eturn on E quity

S&P Industrials 

Nonenergy

FRS Com panies

Independent Producers

Independent R efiners

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995

0

2

4

6

8

1 0

1 2

1 4

1 6

-2

P e rcent R eturn on Inve s tm e nt

All O ther Businesses

U.S. Refining/M arketing

142 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 102. Annual Return on Equity for Petroleum Companies and U.S. Industry

Return on Investment = Net income divided by net investment in place.

Source: Energy Information Administration (EIA), Form EIA-28.

Figure 103. FRS Companies’ Return on Investment in U.S. Refining/Marketing and All Other Lines of

Business

Return on Equity = Net income as a percent of shareholders equity.

Source: Standard & Poor’s Compustat and fourth quarter press releases.
Energy Information Administration / Petroleum 1996: Issues and Trends 143

the usual statistical conventions. The reason for this weak The FRS companies’ return on U.S. refining and marketing 93

relationship is that the gross margin excludes operating costs investment fell from its post-embargo peak in 1988 to zero

such as refinery energy expense and maintenance of in 1992. Demand for the FRS companies’ refined products

marketing networks. Operating costs may not typically vary fell 7 percent over this period. Unlike the 1980's when gross

much from quarter to quarter, but in a longer term context margins held fairly steady, weak demand squeezed the

they are a key component of profit change. Of particular spread between product prices and the prices of crude oil

importance is the strong relationship between U.S. inputs. Overall operating costs also increased owing to a rise

refining/marketing profitability and the net refining margin in marketing costs. The increase in marketing costs was

based on FRS data (i.e., the gross margin less out-of-pocket widespread, with 16 of 18 FRS refiners reporting higher unit

operating costs) (Figure 104). Thus, examination of the marketing costs between 1988 and 1992. The reasons for 94

components of the net refining margin should provide higher marketing costs are not altogether clear. Advertising

insights as to the level and volatility of U.S. refining outlays were up, reflecting a resurgence of growth in

profitability. Table 17 presents the components of the net gasoline marketing in the wake of the oil price collapse of

refining margin and measures of U.S. demand for the FRS 1986. Also, the added costs of complying with leaking

companies’ refined products, and refinery utilization for the underground storage tank requirements were a contributing

peak and trough years of refining profitability. factor to higher marketing costs.

The profitability story in the 1980's is largely told by the The profitability of the FRS companies’ U.S. refining

dynamics of demand, capacity rationalization, and reductions operations recovered slightly in 1993 and 1994, but remained

in operating costs, as gross margins were fairly stable over low by historical standards (Figure 102). This recovery is

the period. Following full deregulation of petroleum prices remarkable since it occurred while the gross margin fell by

in 1981, refining profitability in the United States reached its nearly $1.30 per barrel. Growth in demand of about 2

lowest point in 1984. The U.S. refining industry was plagued percent helped the bottom line but most of the improvement

by a falloff in demand and massive amounts of excess crude in earnings came from operating cost reductions, mainly

oil distillation capacity. The net margin on the FRS marketing costs. Nearly all of the FRS refiners reported

companies’ U.S. refining and marketing operations was only lower marketing costs between 1992 and 1994, citing

1 penny per barrel in 1984. However, the gross margin restructuring and efficiencies gained through greater retail

changed little from the previous peak profitability year of outlet productivity. Also, the FRS companies reduced their

1979. What did change was demand (down 19 percent), advertising outlays, at least for television. On the refining

capacity utilization (down 9 percentage points), and side, cost cutting by the companies and higher capacity

operating costs (up $1.80 ($1995) per barrel). Moving to the utilization contributed to improved profits.

peak profitability year of 1988, most of the factors that

devastated the bottom line in 1984 turned around: demand In 1995, increases in refined product prices did not match the

was up 17 percent, capacity utilization noticeably improved, rise in crude oil costs. The consequent squeeze on margins

and operating costs declined by more than $2 per barrel. was in part due to the effects of unusually warm winter

Again, the gross margin changed little. weather on first-quarter heating fuel demand and to

complications arising from the introduction of reformulated

gasolines. As a result, the FRS companies reported a 1.0-

percent return on their U.S. refining/marketing investment

base, the third poorest financial performance in nearly two

decades. Despite jumps in distillate and gasoline prices in

1996, U.S. refining operations fared only slightly better in

terms of financial performance than they did in 1995. For

example, major petroleum companies that separately

disclosed quarterly financial results for their U.S. refining

and marketing operations reported that income from these

operations in 1996 was 15 percent above the comparable

total in 1995.95

Examination of the FRS companies’ U.S. refined product

margins is thus seen to reveal the sources of volatility in

The regression of the FRS U.S. refining/marketing return on investment 93

(ROI) on the FRS gross margin (constant dollars) for 1977 to 1995 yielded

the following results:

ROI = -0.068 + 0.737 (FRS Gross Margin) R = 0.059. 2

The t-statistic for the coefficient of the FRS Gross Margin was 1.00, which is

far below the conventional thresholds of statistical significance.

To demonstrate the relationship between refining returns and the net 94

refining margin, a regression was run using FRS U.S. refining/marketing

return on investment (ROI) against the FRS net refined product margin

(constant dollars) for the years 1977 to 1994.

The regression results for 1977-1995 were:

ROI = -1.3 + 6.2 (FRS Net Margin) R = 0.852. 2

The regression produced a t-statistic of 9.90 for the independent variable, Based on fourth quarter 1996 press releases. Data for 1996 to update

indicating that the probability of the above association between ROI and the most of the figures and tables in this chapter were not available at the time

FRS net margin occurring by chance is nearly nil. this report went to press.

95
0 0.5 1 1.5 2 2.5

Return on Investm ent (percent)

0

5

10

15

-5

(1995 Dollars per Barrel)

Net Refined Product Margin

144 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 104. U.S. Refining/Marketing Return on Investment and Refined Product Margins for FRS

Companies, 1977-1995

Source: Energy Information Administration (EIA), Form EIA-28.

Table 17. U.S. Refined Product Margins and Costs per Barrel Sold for FRS Companies,

Selected Years, 1979 - 1995

(1995 Dollars per Barrel)

1979 1984 1988 1992 1994 1995

Gross Margin ............................ a 8.21 8.37 8.52 7.39 6.11 5.53

 less

Marketing Costs ........................... 1.95 2.63 1.96 2.90 1.85 1.75

Energy Costs ............................. 2.04 2.78 1.33 1.21 0.98 0.82

Other Operating Expense ................... 2.57 2.95 3.02 2.88 2.56 2.47

 equals

Net Refined Product Margin ................ b 1.63 0.01 2.22 0.41 0.72 0.49

Refined Product Sales (mbd)` ............... 14,868 12,088 14,114 13,089 13,455 13,641

Refinery Capacity Utilization Rate (percent) . . . . 89 80 86 89 92 92

Refined product revenues less raw material and product purchases divided by refined product sales volumes. a

Calculated from unrounded data. b

Note: Years shown prior to 1994 are successive peak and trough years of U.S. refining/marketing profitability.

Source: Energy Information Administration (EIA), Form EIA-28.
Energy Information Administration / Petroleum 1996: Issues and Trends 145

rates of return to U.S. refining and marketing. The volatility many U.S. refiners invested in specialized plant and

of U.S. refining/marketing profitability over the past decade equipment in order to profit from the expected growth in the

or so reflects a combination of swings both in the spread wedge in prices favoring lower quality crudes. Also, market

between refined product prices and crude oil input prices and adjustments made in the context of the crude oil price

in marketing costs, which, despite the massive restructuring escalations of the 1974-1981 period signaled a shift in the

of marketing networks, have shown a varying pattern over composition of petroleum demand toward gasoline and

time with a tendency toward long-term decline only recently distillates and away from heavier products. Domestic

evident. Further, the low level of refining/marketing refiners, again led by the FRS companies, added light

profitability in the 1990's is largely traceable to lower gross product capacity to accommodate this shift.

margins which were only partly offset by reductions in

operating costs. However, there are other developments that Increased environmental standards further heightened the

have contributed importantly to the longer term course of capital intensity of U.S. refining during this period.

U.S. refining/marketing profitability. These developments Implementation of major Federal environmental quality

are not directly observable in the data on margins, but, legislation in the 1970's confronted refiners with stringent

instead, are best understood in the context of capital standards for airborne emissions and effluents discharged

deployment. into waterways. Compliance resulted in added capital

Investment and Capital Intensity in

U.S. Refining and Marketing

The capital intensity of a process generally refers to the together with the deregulation of U.S. petroleum prices in

amount of capital used to produce a unit of output from the early 1981, made much of U.S. refining capacity

process. Profitability and capital intensity are closely related. uneconomic. While petroleum price regulations were in

Simply put, if a process becomes more capital intensive, then force, U.S. refining operations yielded moderate rates of

unless there is an increase in profit per unit of output, return. However, starting in 1981, profitability declined

profitability will decline. sharply. Narrowing of the price differential between high and

In the 1990's, U.S. refining was hit by lower gross margins eroded rates of return. Investments for upgrading refinery

following the peak years of 1988 and 1989. Also, over the input capabilities were premised on a widening of this

same period, the capital intensity of U.S. refining increased differential. Therefore, a narrowing tended to impair rates of 96

by 50 percent or so after remaining nearly unchanged for return.

several years (Figure 105). Together, these developments

underlie the generally low rates of return to U.S. refining and By 1986, U.S. refiners had shut down or otherwise disposed

marketing in the 1990's. Examination of investment patterns of plant and equipment representing over 3 million barrels a

in U.S. refining proves useful for understanding why capital day of refining capacity. The FRS companies accounted for

intensity rose in some periods and was unchanged in other 75 percent of this reduction. Investment fell off in part

periods. because upgrading projects were completed, in part because

The past 20 years saw several distinct phases of capital the capital markets were repelled by the poor returns to

deployment in U.S. refining. Investment patterns during this refining investments. The winding down of pollution

span had the effect of increasing the capital intensity of these abatement expenditures and redeployment of assets gained

operations. Beginning in the late 1970's and continuing in the mega-mergers among the FRS companies in the 1981

through the early 1980's, the FRS companies led U.S. through 1984 time period also contributed to a falloff in U.S.

refiners in making investments to upgrade their capability to refining investments. All of these developments flattened the

utilize heavier, more sulfurous crude oils. The companies growth in capital intensity.

premised these investments on expectations that the

composition of world supplies would shift toward lower Capital intensity remained level through most of the 1980's.

quality, lower priced crude oils. Led by the FRS companies, During this period, net refining margins improved, as did

expenditures for U.S. refiners (Figure 106). Upgrading and

environmental quality measures led to a surge in capital

expenditures for U.S. refining over the 1978 through 1983

time span with an attendant rise in capital intensity.

Responses by energy consumers to oil price escalations,

low quality crudes during the first half of the 1980's further

refiners massively consolidated capacity, and in part because

petroleum product demand, leading to increased profitability

for U.S. refining and marketing. A widening of the price

spread between crude oil qualities also contributed to higher

earnings (see Figure 91 in Chapter 7).

The capital intensity is represented by the ratio of net property, plant, 96

and equipment (PP&E) to barrels per day of crude oil distillation capacity.

PP&E is the book value of fixed assets carried on company balance sheets.
1974 1977 1980 1983 1986 1989 1992 1995

0

Dollars per Barrel of Daily Capacity

500.00

1,000.00

2,000.00

2,500.00

3,000.00

3,500.00

1,500.00

1974 1977 1980 1983 1986 1989 1992 1995

 0

2.00

4.00

6.00

8.00

Billion Dollars ($1995)

Pollution Abatem ent

To ta l

146 Energy Information Administration / Petroleum 1996: Issues and Trends

Figure 105. Net PP&E per Unit of U.S. Refinery Capacity for FRS Companies

Source: Energy Information Administration (EIA), Form EIA-28.

Figure 106. U.S. Refining Capital Expenditures for FRS Companies

Note: Excludes effects of intra-FRS mergers in 1982 and 1984.

Source: Energy Information Administration (EIA), Form EIA-28. U.S. Department of Commerce, Bureau of the Census, Pollution Abatement Costs

and Expenditures (various issues) (Washington, DC).
Energy Information Administration / Petroleum 1996: Issues and Trends 147

The buoyant rates of return in U.S. refining during the latter 1996 (Q196), major integrated refiners (the “majors”)

half of the 1980's were short lived. In the 1990's, lower reported income from their U.S. refining operations of $223

margins, due in part to the narrowing of the crude oil price- million (Table 18), which was a turnaround from losses in

quality differential, eroded U.S. refining and marketing the first quarter of 1995 (Q195) their worst first-quarter

profits. The adverse effects on profitability were exacerbated performance in the past 10 years (Figure 107). Similarly,

by a renewed rise in capital intensity beginning in 1990. smaller, non-integrated refiners (the “independent refiners”)

Refinery upgrading, in part undertaken to satisfy mandates made a substantial recovery from a very poor first quarter the

for reformulated fuels, was the major source of this most year before. The majors registered a $0.5 billion gain in their

recent upswing in capital intensity. Expenditures for U.S. refining profits in the second quarter of 1996 (Q296)

pollution abatement played a key role as well. while the independent refiners’ net income was up 55

Growth in motor fuel demand, spurred by the low level of more than doubled their earnings compared with the very

petroleum prices following the oil price collapse in 1986, poor results in the first half of 1995.

encouraged investment in light-product capability. The

earlier shift in the price-quality spread favoring the use of

heavier crude oils encouraged investments in processing

capabilities. What differed in the 1990's from the earlier

surge in U.S. refining investment was the role of

environmentally-related capital expenditures. Starting in the

mid-1970's, refiners’ environmentally-related capital

expenditures trended downwards as the requirements of the

Clean Water Act and Clean Air Act were met. By the mid1980's, environmentally-related outlays were less than 10

percent of overall capital expenditures of U.S. refiners.

In 1990, the Clean Air Act Amendments were enacted by

Congress and signed into law. This legislation presented U.S.

refiners with added requirements for motor fuels to be met

by the end of the decade, including the production of

oxygenated gasolines by late 1992, lower sulfur diesel fuels

by late 1993, and reformulated gasoline by January 1, 1995.

To comply with these measures, FRS refiners stepped up

their capital expenditures for the necessary facilities.

Environmentally-related capital expenditures quadrupled,

accounting for nearly 40 percent of U.S. refining capital

expenditures by 1994. The additional capital expenditures

raised the capital intensity of U.S. refining.

Examination of the path of capital intensity thus completes

the story of U.S. refining profitability over the past 20 years

or so (see box, p. 148). For the 1990's in particular, capital

intensity grew but refining margins diminished while growth

in refined product demand was nearly flat. As a result, the

returns to investment in U.S. refining have been low,

compared with the rest of U.S. industry.

Petroleum Price Rises Yield Profit

Gains in First Half of 1996

Higher petroleum prices in the first half of 1996, particularly

gasoline prices, raised concerns about the profits of

petroleum companies. In fact, profits from U.S. refining and

marketing operations were up sharply. In the first quarter of

97

percent. For the first half of 1996, both groups of companies

Distillate Prices Lift Refining Margins

Based on price and demand patterns, gasoline market

developments had a small role in the turnaround in refining

profits between Q195 and Q196. Gasoline prices rises were

important in the surge in second-quarter profits, but increases

in distillate prices contributed more heavily.

The spread between product prices received by refiners and

the cost of raw material inputs for their refineries (termed,

the gross refining margin) is an important determinant of

refining profits, in the short term. For example, there is a

strong positive relationship between second-quarter U.S.

refining/marketing income and the second-quarter gross

refining margin. Although the gross refining margin in 98

Q196 was low in comparison with the general level of

margins in the 1990's, it was well above the first-quarter

Quarterly financial results are available for a consistent group of 13 97

specialized refiner/marketers and 13 major integrated petroleum companies

that separately report data for their U.S. refining/marketing line of business.

Integrated major petroleum companies include Amoco, Atlantic Richfield,

Chevron, Exxon, Mobil, Murphy Oil, Pennzoil, Phillips, Shell Oil, Sun,

Texaco, Unocal, and USX (Marathon). Independent refiners include

Ashland, Clark USA, Crown Central Petroleum, Diamond Shamrock,

Louisiana Land & Exploration, Mapco, Quaker State, Tesoro Petroleum,

Tosco, Total Petroleum, Ultramar, Valero Energy, and Witco. Beginning in

the fourth quarter of 1996, due to a merger, Ultramar-Diamond Shamrock

replaced the two formerly separate companies.

For the majors, the regression of second-quarter U.S. refining/marketing 98

income per company (Y) on the second-quarter gross refining margin (X) and

a dummy variable which is equal to one for 1991-1995 and zero otherwise

(DUM), for the years 1987-1995, yielded

Y = -35.17 - 34.57 DUM + 14.37X with R =0.769 and a t-value of 3.54 2

for the X-coefficient.

For the independent refiners’ second-quarter net income per company (Y),

the regression analysis yielded

Y = -9.38 - 5.41 DUM + 3.73X with R = 0.942 and a t-value of 9.07 for 2

the X-coefficient.
1977 1980 1983 1986 1989 1992 1995

0

5

10

15

20

25

Percent Return on Investment

Nonpetroleum 

Businesses 

(combined)

Refining, 

Marketing, and 

Transport

Oil & Gas 

Production

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1977 1980 1983 1986 1989 1992 1995

0

25

50

75

100

Percent Distribution (Cumulative)

Nonpetroleum

Businesses (combined)

Oil & Gas 

Production

Refining, Marketing, and 

Transport

148 Energy Information Administration / Petroleum 1996: Issues and Trends

Return on Investment by Lines of

Business for FRS Companies

Note: Return on investment = net income contribution

divided by net investment in place.

Source: Energy Information Administration (EIA), Form

EIA-28.

Shares of Allocated Income by Lines of

Business for FRS Companies

Source: Energy Information Administration (EIA), Form EIA-28.

Perspectives on Petroleum Profitability

Over the past 20 years or so, downstream petroleum operations have

rarely been the most profitable of the majors’ lines of business. The

figure to the right shows annual returns on investment for the FRS

companies’ worldwide oil and gas production operations, downstream

petroleum (refining, marketing, and transport) operations, and the

aggregate of their operations outside petroleum and natural gas (the share

of these latter operations accounted for by chemicals, based on value of

assets, ranged from 29 percent in 1984 to 59 percent in 1992). Three

periods are distinguishable from the figure to the right.

The period of high oil prices. From 1974 through early 1981, oil prices

sporadically escalated. Dollar-denominated crude oil prices peaked in the

first quarter of 1981 at close to $40 per barrel, a tenfold rise from 1973's

oil prices. Accordingly, the rate of return to oil and gas investments rose

sharply and was, by far, the majors’ most profitable line of activity as

well as the source of the major share of net income (figure below, right),

even as oil prices gradually declined from 1981 through 1985.

Downstream profitability also rose sharply in the late 1970's, in

significant part reflecting the rising value of petroleum inventories, but

never came close to upstream rates of return. Downstream profits

plunged after peaking in 1980. Thereafter, refiners both in the United

States and abroad shutdown or otherwise divested massive amounts of refining capacity which had become uneconomic. The

declining returns to downstream operations in the early 1980's reflected the financial difficulties of that period.

The 1986 oil price collapse and aftermath. Oil prices collapsed in early 1986, and, by mid-year, fell to levels not seen since

1974. On an inflation-adjusted basis, oil prices for the remainder of the 1980's were generally below the levels of the 1974-1985

period. Upstream profitability plunged in 1986 and remained well below levels realized earlier during the period of high oil

prices. Downstream profitability, by contrast, rose steeply in the late 1980's. Lower oil prices led to increased demand for

petroleum products. Refiners, overall, completed their retrenchments at just about the time that oil prices collapsed. Both

developments favored an upswing in downstream profitability, as did

lower crude oil input prices. Lower feedstock costs, stemming from low

oil prices, also contributed to a surge in chemical profits. The sharp rise

in the profitability of nonpetroleum businesses was largely a reflection

of developments in the majors’ chemical operations.

The 1990's. Crude oil prices rose sharply in the last two quarters of

1990, largely due to the effects of Iraq’s invasion of Kuwait. After the

expulsion of Iraqi troops in early 1991, oil prices have tended to vary in

the same range prevailing in the late 1980's (on an inflation-adjusted

basis). Upstream operations benefitted from the war-induced oil price

spike in 1990 but then declined. Although upstream profitability in the

1990's has not come close to pre-collapse levels, it is clearly higher than

the levels of 1986-1989. Cost-cutting in the 1990's has helped raise the

returns to oil and gas production. Downstream operations have also

been a focus of cost-cutting in the 1990's, but, despite these efforts,

downstream profitability has trended downwards. The increased share

of businesses outside petroleum and natural gas in recent years (see

figure to right) was largely due to a surge in chemical earnings.
1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

200

400

600

800

1000

Million Dollars

1400

-200

Majors' Q 1 US R/M Income

Majors' Q 2 US R/M Income

1200

Energy Information Administration / Petroleum 1996: Issues and Trends 149

Table 18. Quarterly Income in U.S. Refining and Marketing

(Million Dollars)

1995 1996

 Percent

 Change

U.S. Refining/Marketing Income for

the Majors (13 Companies)

First Quarter ................ -100 223 NM

Second Quarter . . . . . . . . . . . . . 765 1,261 64.8

Net Income for Independent Refiners

(13 Companies)

First Quarter . . . . . . . . . . . . . . . . 4 121 3,025.0

Second Quarter . . . . . . . . . . . . . 184 286 55.4

NM = Not meaningful.

Source: Company 1996 reports to shareholders.

Source: Companies’ quarterly reports to shareholders.

Figure 107. Majors’ First and Second Quarter U.S. Refining/Marketing Net Income

margin of the year before (Table 19). In Q195, the refining Demand growth also favored higher refining profits in Q196

margin fell to a 6-year low, squeezed by a combination of a relative to Q195. The quantity of total refined products

slight rise in crude oil input costs and downward pressures on supplied was up 4 percent over this period, mainly reflecting

gasoline and distillate prices. The modest recovery in the the greater demand for space heating fuels. Improved

overall refining margin largely reflected the effects of an economic conditions also contributed to overall petroleum

especially cold winter in 1995-1996, particularly in March. demand, with real GDP growing 2 percent between Q195

Distillate prices were up 17 percent and the price of propane and Q196. The total amount of distillate fuel oil and propane

rose 22 percent between Q195 and Q196. In contrast, supplied was up 5 percent. Residual fuel oil volumes were up

gasoline prices were up 6 percent, just matching the rise in 7 percent, fed by electric utility demand. However, growth

crude oil input prices. in gasoline demand was nearly flat.
150 Energy Information Administration / Petroleum 1996: Issues and Trends

Table 19. Refined Product Resale Prices, Margins, and Products Supplied, First and Second Quarters,

1995 and 1996

Q195 Q196 Q295 Q296

Resale Prices (Dollars per Barrel)

Motor Gasoline .............................. 25.24 26.72 28.92 31.82

Distillate .................................... 21.14 24.83 22.42 27.07

Kerojet and Kerosene ......................... 22.09 25.65 22.43 26.23

Propane .................................... 14.63 17.78 13.82 15.46

Other Products 15.97 18.55 17.48 18.68

Composite Product Price ..................... 22.75 25.16 26.12 29.27

Composite Refiner Acquisition Cost of Crude Oil . . 16.99 18.47 18.24 20.45

Gross Refining Margin .......................... 5.76 6.69 7.88 8.82

Products Supplied (Thousand Barrels per Day)

Motor Gasoline .............................. 7,477 7,511 7,921 7,985

Distillate .................................... 3,463 3,616 3,089 3,231

Jet Fuel .................................... 1,513 1,605 1,425 1,505

Propane and Other Products ................... 5,187 5,560 5,084 5,193

Total Products Supplied ......................... 17,640 18,292 17,519 17,914 

Retailer Margin (Dollars per Barrel)

Motor Gasoline .............................. 5.68 5.09 5.34 6.14

Diesel Fuel .................................. 1.09 1.00 0.98 1.07

Sources: Energy Information Administration (EIA), Petroleum Marketing Monthly, August 1996, DOE/EIA-0380(96/08) (Washington, DC, August

1996) and Petroleum Supply Monthly, August 1996, DOE/EIA-0109(96/08) (Washington, DC, August 1996).

In the second quarter, the rise in gasoline prices outpaced the invasion of Kuwait yielded record refining margins

rise in crude oil prices compared with Q295, $2.91 per barrel (Figure 107). The independent refiners recent second-quarter

vs. $2.21. However, overall distillate product prices financial results also surpassed those of 1990 (Figure 108).

registered a steeper rise of $4.65 per barrel over the same

period. Similarly, while motor gasoline demand rose nearly It is probably worthwhile to note that second-quarter profits

1 percent, distillate demand was up nearly 5 percent, in 1996 exceeded expectations based on the estimated

reflecting strong demand for diesel and replenishment of relationships between profits and the gross refining margin

inventories. noted above. Based on these relationships, the actual value

Second-quarter U.S. Refining Profits

Reach a 10-Year Peak in 1996

Public concerns about U.S. refinery profits were probably

most intensely focused on the second quarter of 1996, since

the rise in gasoline prices began late in the first quarter and

continued into the second quarter. The majors’ secondquarter financial results for their U.S. refining/marketing

operations were at a 10-year peak, surpassing the previous

peak in 1990, when crude oil gluts preceding the Iraqi

of Q296 refining/marketing profits were 1.7 times the

predicted value for the majors and 1.3 times the predicted

value for the independents. One source of higher profits

in this quarter not accounted for by the above relationships

appeared to be a wider spread between wholesale prices paid

and retail prices charged for gasoline by retailers. The

retailer margin in Q296 was up 2 cents a gallon (15

percent) from the previous year (Table 19). Since most of the

refiners that reported second-quarter financial results have

gasoline marketing networks, an increased spread in the

retailer margin would contribute to improved bottom-line

results.
1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

50

100

150

200

250

Million Dollars

Independents' Q1 Net Income

300 Independents' Q2 Net Income

Energy Information Administration / Petroleum 1996: Issues and Trends 151

Source: Companies’ quarterly reports to shareholders.

Figure 108. Independent Refiners’ First and Second Quarter Net Income