DOE/EIA-0206(04) 

Distribution Category UC-950 

Performance Profiles 

 of Major Energy Producers 

 2002

February 2004

Energy Information Administration

Office of Energy Markets and End Use 

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 U.S. Department of Energy. The information contained herein should be attributed to the Energy Information 

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

or any other organization. 
ii Energy Information Administration/ Performance Profiles of Major Energy Producers 2002 

 

 Contacts

This report was prepared in the Office of Energy Markets and End Use of the Energy Information Administration 

(EIA), U.S. Department of Energy, under the general direction of W. Calvin Kilgore. The project was directed by Mark 

E. Rodekohr, Director of the Energy Markets and Contingency Information Division (202) 586-1130, and Mary E. 

Northup, the Team Leader for Financial Analysis (202) 586-1383. Specific technical information concerning this 

report and the associated data survey (Form EIA-28) may be obtained from Greg Filas (202) 586-1347. The following 

authors contributed to this report: Mary Northup, Neal Davis, Jon Rasmussen, Bob Schmitt, and Larry Spancake. In 

addition, Kevin Forbes of SAIC provided essential research into major resource development areas. 

Data File Information

Historical Financial Reporting System (FRS) data are available from the Energy Information Administration's File 

Transfer Protocol (FTP) site. These data cover the years 1977 through 2002, published in the Energy Information 

Administration's annual editions of Performance Profiles of Major Energy Producers. There are two different sets of 

data: aggregate data from the FRS survey form and multi-year tables from Appendix B of Performance Profiles of 

Major Energy Producers.

The Financial Reporting System 1977-2002 data files can be downloaded from the Energy Information 

Administration's FTP site by accessing the following EIA Web site: 

http://www.eia.doe.gov/emeu/finance/page2.html. For further assistance, please contact the National Energy 

Information Center at (202) 586-8800, FAX (202) 586-0727, TTY (202) 586-1181, or by email: infoctr@eia.doe.gov. 

For further information on the Financial Reporting System data, please contact Greg Filas at (202) 586-1347, FAX 

(202) 586-9753, or by email: greg.filas@eia.doe.gov. 

Dedication 

This issue of Performance Profiles is dedicated to the memory of Jon Rasmussen, 

who passed away on December 19, 2003. Jon served as the Senior Economist for 

the Financial Reporting System for 24 years. He was respected as one of the 

foremost analysts in energy economics. His intellectual leadership, his 

dedication, and his professionalism served as a guiding light and inspiration to 

all who worked with him. Jon will be sorely missed by his many friends and 

colleagues at the Energy Information Administration, and by all those in both 

the public and private sectors who came to him for his insights on the energy 

industry. We are truly grateful for the time we had with him. 
Preface 

Performance Profiles of Major Energy Producers presents a comprehensive annual financial review and 

analysis of the domestic and worldwide activities and operations of the major U.S.-based energyproducing companies.1

 (For a list of the companies covered in this report, the Financial Reporting 

System (FRS) companies, see Chapter 1, the box entitled "The FRS Companies in 2002" on page 1.) 

Emerging issues in financial performance are also analyzed. The report primarily examines these 

companies’ (the majors’) operations on a consolidated corporate level, by individual lines of business, 

by major functions within each line-of-business, and by various geographic regions. A companion 

analysis of foreign investment2

 (trends and transactions) in U.S. energy resources, assets, and companies 

was previously included as a separate chapter in the report. However, the annual report, Foreign Direct 

Investment in U.S. Energy is now published separately on the Internet (see 

http://www.eia.doe.gov/emeu/finance/fdi/index.html). 

Performance Profiles annually looks at aggregate changes in the U.S. energy industry resulting from

major energy company current operations, and from strategic corporate decisions relating to profits, 

investments, and new business initiatives. Significant organizational decisions of the majors (such as 

those involving corporate mergers or joint ventures) are highlighted, and new strategic directions (such 

as concentration on core businesses or competencies, movements into new lines of business, or changes 

in global investment patterns) are discussed. Changes in the majors' investment and resource 

development patterns, which may result in new or increased opportunities for independent oil and gas 

producers and fast-growing petroleum refiners in the United States, are also explored. 

This edition of Performance Profiles reviews financial and operating data for the calendar year 2002. 

Although the focus is on 2002 activities and results, important trends prior to that time and emerging 

issues relevant to U.S. energy company operations are also discussed. 

The analysis in this report is based on detailed financial and operating data and information submitted 

each year to the Energy Information Administration (EIA) on Form EIA-28, the Financial Reporting 

System. The analysis and FRS data are also supplemented by additional information from company 

annual reports and press releases, disclosures to the U.S. Securities and Exchange Commission, news 

reports and articles, and various complementary energy industry data sets. 

 

Since the Form EIA-28 data are collected by the EIA on a uniform, segmented basis, the comparability 

of information across energy lines of business is unique to the FRS reporting system. For example, 

petroleum activities of the major U.S. energy companies (and financial returns attributable to these 

activities) can be compared to activities in other lines of energy business (such as coal, and/or 

alternative energy) or nonenergy areas (such as chemicals). Similarly, financial returns and operating 

results from domestic activities can be compared to results from foreign activities and operations. 

The information in Performance Profiles responds to the requirements of the Financial Reporting 

System, set forth in P.L. 95-91, the Department of Energy Organization Act of 1977 (see 

http://www.eia.doe.gov/emeu/finance/page1a.html). Both this report, and similar energy financial 

analyses provided by the EIA (see http://www.eia.doe.gov/emeu/finance/pubs.html ), are intended for 

use by the U.S. Congress, government agencies, industry analysts, and the general public. 

Energy Information Administration/ Performance Profiles of Major Energy Producers 2002 iii
iv Energy Information Administration/ Performance Profiles of Major Energy Producers 2002 

 

 

Additional information about Form EIA-28 can also be found at 

http://www.eia.doe.gov/emeu/finance/page1a.html. Also see Appendix A of this report for information 

concerning the format of Form EIA-28, important financial reporting concepts and accounting 

principles, and other information about the Financial Reporting System. For a glossary of terms and 

definitions used in this report, see http://www.eia.doe.gov/emeu/perfpro/glossary.html. 

Endnotes 

1

 The U.S.-based energy companies that respond to the Financial Reporting System (FRS) Form EIA-28 are considered to be 

U.S. majors by the Energy Information Administration (see P.L. 95-91, Sec. 205 (h)). Per the requirements of that statute, the

Administrator of the Energy Information Administration designates "major energy-producing companies" and selects them as 

respondents to the FRS. Currently, the Administrator uses the following selection criteria: at least 1 percent of U.S. oil (crude 

oil and natural gas liquids) reserves or production, or at least 1 percent of U.S. natural gas reserves or production, or at least 1 

percent of U.S. crude oil distillation capacity, or 1 percent of refined petroleum product sales. 2

The purpose of the foreign direct investment report is to provide an assessment of the degree of foreign ownership of energy 

assets in the United States. Section 657, Subpart 8 of the U.S. Department of Energy Organization Act (Public Law 95-91) 

requires an annual report to Congress which presents: “...a summary of activities in the United States by companies which 

are foreign owned or controlled and which own or control United States energy sources and supplies....” 
Contents 

Preface ...........................................................................................................................................................iii 

Executive Summary ................................................................................................................................................ xi 

1. Market Developments and FRS Companies in 2002...................................................................................... 1 

 Petroleum and Natural Gas Markets in 2002............................................................................................... 1 

Demise of Energy Trading Impacts Financial Results ................................................................................. 3 

Changes in the FRS Group in 2002 .............................................................................................................. 5 

 New Survey Entrant................................................................................................................................. 5 

 Mergers and Acquisitions........................................................................................................................ 5 

The FRS Companies' Importance in the U.S. Economy................................................................................ 5 

2. Financial Developments in 2002 ....................................................................................................................... 9 

 Income and Cash Flow ............................................................................................................................... 10 

 Downstream Petroleum Performance Hit a New Low in 2002.............................................................. 10 

 FRS Companies’ Pipeline Earnings....................................................................................................... 12 

Low Natural Gas Prices Hurt Upstream Profits..................................................................................... 13 

Other Energy Plagued by Energy Trading Collapse .............................................................................. 13 

Chemical Operations Yield Rare Gains in Earnings.............................................................................. 14 

Record Cash Flow in 2001 Followed by Mediocre Cash Flow in 2002 ................................................ 15 

 Targets of Investment.................................................................................................................................. 16 

FRS Companies Increase Focus on OECD Europe, North Sea ............................................................. 16 

 Highlight: Upstream Merger Wave Ebbs .............................................................................................. 20 

Mergers Drive Increase in Refining/Marketing Capital Expenditures................................................... 20 

Other Energy No Longer A Source of Corporate Growth ..................................................................... 26 

 Sources and Uses of Cash........................................................................................................................... 26 

3. Behind the Bottom Line.................................................................................................................................. 31 

 Upstream Income........................................................................................................................................ 31 

 Lifting Costs Little Changed – Production Taxes Decline .................................................................... 33 

U.S. Refining and Marketing ...................................................................................................................... 37 

 Profitability of U.S. Refining/Marketing Operations Lowest in Survey History................................... 37 

Lower Product Prices Reduce Product Sales Revenue .......................................................................... 39 

Lower Product Sales Magnify Downward Pressure on Revenue .......................................................... 39 

 Gross Margin Squeezed as Product Prices Fall ..................................................................................... 42 

Operating Costs Rise Despite Lower Energy and Marketing Costs...................................................... 43 

 Highlight: Environmental Compliance Partially Eclipses Recent Gains in Profitability ..................... 47 

 Foreign Refining and Marketing ................................................................................................................ 52 

 Profitability of Foreign Refining/Marketing Operations At An All-Time Low .................................... 52 

Consolidated Operations Contribute to Net Income ............................................................................. 52 

Asian-Pacific Markets Continue Poor Performance .............................................................................. 53 

European Markets Continue to Bolster Foreign Refining/Marketing Results....................................... 54 

 Other Energy............................................................................................................................................... 55 

Revenue and Income Drop Due to Energy Trading Decline ................................................................. 55 

Nonconventional Energy: Tar Sands and Geothermal Stand Out......................................................... 56 

4. Resource Development Trends....................................................................................................................... 61 

 SPECIAL TOPIC: Finding Costs Increased in Most Regions.................................................................. 61

SPECIAL TOPIC: The Gulf of Mexico – Do Technology and Recent Economics Favor 

 Oil Reserves Over Natural Gas? ....................................................................................................... 68 

SPECIAL TOPIC: Natural Gas Supply – A New Paradigm?................................................................... 71 

SPECIAL TOPIC: Canada’s McKenzie Delta – One Part of Future Natural Gas Supply? ..................... 74 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 v
5. Emerging Issues............................................................................................................................................... 77 

 SPECIAL TOPIC: FRS Company Production from Renewables ............................................................ 77 

 SPECIAL TOPIC: Recent Upstream Mergers: A Tradeoff Between Growth and Profitability?............. 81 

 SPECIAL TOPIC: LNG – A Future for the FRS Companies?................................................................. 83 

Appendices 

A. The Financial Reporting System (FRS)...................................................................................................... 87 

B. Detailed Statistical Tables........................................................................................................................... 89 

Glossary (available on EIA's Web site at http://www.eia.doe.gov/emeu/perfpro/glossary.html) 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 vi
Tables

1. Consolidated Income Statement for FRS Companies and the S&P Industrials, 2001-2002......................... 9 

2. Contributions to Net Income by Line of Business for FRS Companies, 2001-2002.................................. 11 

3. Operating Income in Chemicals and Other Nonenergy Segments for FRS Companies, 2001-2002.......... 15 

4. Line-of-Business Contributions to Pretax Cash Flow for FRS Companies, 2001-2002............................. 16 

5. Additions to Investment in Place by Line of Business for FRS Companies, 2001-2002 ........................... 17 

6. Value of Mergers, Acquisitions, and Related Transactions by FRS Companies, 2002.............................. 24 

7. Sources and Uses of Cash for FRS Companies, 2001-2002 ....................................................................... 26 

8. Income Components and Financial Ratios in Oil and Natural Gas Production for FRS Companies, 

 2001-2002 .............................................................................................................................................. 32 

9. Average Prices, Sales, and Production in Oil and Natural Gas for FRS Companies, 2001-2002............... 33 

10. Lifting Costs by Region for FRS Companies, 2001, 2002 ......................................................................... 35 

11. U.S. and Foreign Refining/Marketing Financial Items for FRS Companies, 2001-2002........................... 39 

12. Sales, Prices, Costs, and Margins in U.S. Refining/Marketing for FRS Companies, 2001-2002............... 40 

13. U.S. Refined Product Margins and Costs per Barrel Sold and Product Sales Volume for FRS 

 Companies, 2001-2002 .......................................................................................................................... 42 

14. U.S. and Foreign Refining Investment and Operating Items for FRS Companies, 2001-2002 .................. 42 

15. Motor Gasoline Distribution and Number of Direct-Supplied Branded Outlets 

for FRS Companies, 2001-2002 ............................................................................................................ 46 

16. Components of the Gross Refining Margin and Average Refined Product Revenues for 

FRS Companies, 1988, 1995, and 2001................................................................................................. 50 

17. Regional Distribution of Foreign Refinery Capacity for FRS Companies, 2001 - 2002 ............................ 53 

18. Income Components for Other Energy for FRS Companies, 2000-2002 ................................................... 57 

19. Finding Costs by Region for FRS Companies, 1999-2001 and 2000-2002................................................ 62 

20. Finding Rates and Expenditures per Well by Region for FRS Companies, 1999-2001 and 2000-2002 .... 63 

21. Average Finding Cost and Return on Investment for FRS Companies, 1997-2002................................... 82 

B1. Selected U.S. Operating Statistics for FRS Companies and U.S. Industry, 1996-2002 ............................. 89 

B2. Selected Financial Items for the FRS Companies and the S&P Industrials, 2001-2002 ............................ 90 

B3. Balance Sheet Items and Financial Ratios for FRS Companies and S&P Industrials, 

 2001-2002 .............................................................................................................................................. 91 

B4. Consolidated Balance Sheet for FRS Companies, 1996-2002.................................................................... 92 

B5. Consolidating Statement of Income for FRS Companies, 2002 ................................................................. 93 

B6. Consolidating Statement of Income for FRS Companies, U.S. and Foreign Petroleum 

 Segments, 2002...................................................................................................................................... 94 

B7. Net Property, Plant, and Equipment (PP&E), Additions to PP&E, Investments and Advances, and 

Depreciation, Depletion, and Amortization (DD&A), 

by Lines of Business for FRS Companies, 2002.................................................................................... 95 

B8. Return on Investment for Lines of Business for FRS Companies Ranked by Total 

 Energy Assets, 2001-2002 ..................................................................................................................... 96 

B9. Research and Development Expenditures for FRS Companies, 1996-2002............................................... 97 

B10. Size Distribution of Net Investment in Place for FRS Companies Ranked by 

 Total Energy Assets, 2002 ..................................................................................................................... 98 

B11. Consolidated Statement of Cash Flows for FRS Companies, 1996-2002 .................................................. 99 

B12. Composition of Income Taxes for FRS Companies, 1996-2002 .............................................................. 100 

B13. U.S. Taxes Other Than Income Taxes for FRS Companies, 1996-2002 .................................................. 101 

B14. Oil and Gas Exploration and Development Expenditures for FRS Companies, 

 United States and Foreign, 1996-2002................................................................................................. 102 

B15. Components of U.S. and Foreign Exploration and Development Expenditures for FRS Companies, 

 2002...................................................................................................................................................... 103 

B16. Exploration and Development Expenditures by Region, for FRS Companies, 1996-2002...................... 104 

B17. Production (Lifting) Costs by Region for FRS Companies, 1996-2002................................................... 105 

B18. Oil and Gas Acreage for FRS Companies, 1996-2002 ............................................................................. 106 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 vii
Tables (continued)

B19. U.S. Net Wells Completed for FRS Companies and U.S. Industry, 1996-2002....................................... 107 

B20. U.S. Net Drilling Footage and Net Producing Wells for FRS Companies and U.S. Industry, 

 1996-2002 ............................................................................................................................................ 108 

B21. Number of Net Wells Completed, In-Progress Wells, and Producing Wells by Foreign 

Regions for FRS Companies, 1996-2002 ............................................................................................ 109 

B22. Number of Net Wells Completed, and Average Depth, Onshore and Offshore, for FRS Companies, 

 2001 and 2002...................................................................................................................................... 111 

B23. Oil and Gas Reserves for FRS Companies and U.S. Industry, 2002 ........................................................ 112 

B24. Oil and Gas Reserve Balances by Region for FRS Companies, 2002 ...................................................... 113 

B25. Oil and Gas Exploration and Development Expenditures, Reserves, and Production by Region

for FRS Companies and Total Industry, 2002 and Percent Change from 2001................................... 115 

B26. U.S. and Foreign Refining/Marketing Sources and Dispositions of Crude Oil and Natural Gas 

Liquids for FRS Companies, 1996-2002 ............................................................................................. 117 

B27. U.S. Purchases and Sales of Oil, Natural Gas, Other Raw Materials, and Refined Products 

for FRS Companies, 1996-2002........................................................................................................... 118 

B28. U.S. and Foreign Petroleum Refining Statistics for FRS Companies, 1996-2002.................................... 119 

B29. U.S. and Foreign Refinery Output and Capacity for FRS Companies, Ranked by 

 Total Energy Assets, and Industry, 2002 ............................................................................................. 120 

B30. U.S. Refining/Marketing Dispositions of Refined Products by Channel of Distribution for 

 FRS Companies, 1996-2002 ................................................................................................................ 121 

B31. Sales of U.S. Refined Products, by Volume and Price, for FRS Companies Ranked by 

 Total Energy Assets, 2001-2002.......................................................................................................... 122 

B32. U.S. Refining/Marketing Revenues and Costs for FRS Companies, 1996-2002...................................... 123 

B33. U.S. Petroleum Refining/Marketing General Operating Expenses for FRS Companies, 

 1996-2002 ............................................................................................................................................ 124 

B34. U.S. Coal Reserves Balance for FRS Companies, 1996-2002.................................................................. 125 

Illustrations

1. Operating Revenues by Line of Business for FRS Companies, 1977-2002 ................................................. 6 

2. Shares of U.S. Energy Production and Refinery Capacity for FRS Companies, 1981-2002........................ 6 

3. Return on Equity for FRS Companies and the S&P Industrials, 1973-2002 .............................................. 10 

4. Operating Return on Investment in Chemicals for FRS Companies, 1975-2002 ....................................... 15 

5. Exploration and Development Expenditures by Region for FRS Companies, 1999-2002......................... 18 

6. Recent Mergers Affecting FRS Oil and Gas Producers.............................................................................. 21 

7. Long-Term Debt/Equity Ratio for FRS Companies and the S&P Industrials, 1974-2002 ......................... 27 

8a. Oil Production for FRS Companies, 1981-2002......................................................................................... 34 

8b. Natural Gas Production for FRS Companies, 1981-2002........................................................................... 34 

9. Direct Oil and Gas Lifting Costs for FRS Companies, 1981-2002............................................................. 36 

10. Production Taxes for FRS Companies, 1974-2002..................................................................................... 36 

11. Return on Investment in U.S. and Foreign Refining/Marketing, and All Other Lines of Business 

for FRS Companies, 1980-2002............................................................................................................. 38 

12. U.S. Refined Product Margins and Costs per Barrel of Petroleum Product Sold for FRS Companies, 

 1980-2002 .............................................................................................................................................. 39 

13. Quarterly U.S. Commercial Petroleum Product Stocks, 1996-2000 Average, 2001, and 2002.................. 41 

14. Quarterly U.S. Motor Gasoline Stocks, 1996-2000 Average, 2001, and 2002........................................... 41 

15. Monthly Gross Refined Product Margin for United States, 1996-2000 Average, 2001, and 2002 ............ 44 

16. Quarterly U.S. Crude Oil Stocks, 1996-2000 Average, 2001, and 2002 .................................................... 44 

17. Real Price Difference Between Light Crude Oil and Heavy Crude Oil, 1978-2002 .................................. 45 

18. Real Resale Price Difference Between Motor Gasoline and Residual Fuel Oil, 1978-2002 ...................... 45 

19. Company-Operated and Dealer Outlets for FRS Companies, 1984-2002 .................................................. 46 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 viii
Illustrations (continued)

20. U.S. Refining/Marketing Return on Investment and Net Refined Product Margin for 

 FRS Companies, 1977-2001 .................................................................................................................. 49 

21. U.S. Refining Capital Expenditures for FRS Companies, 1988-2001........................................................ 50

22. Environmental Capital Expenditures as a Share of U.S. Refining Capital Expenditures 

for FRS Companies, 1988-2001 ............................................................................................................ 51 

23. Operating Return on Investment in U.S. Refining/Marketing for FRS Companies, 1988-2001 ................ 51 

24. Foreign Refining/Marketing Net Income from Consolidated Operations and Unconsolidated Affiliates 

of FRS Companies, 1990-2002.............................................................................................................. 53 

25. Foreign Refining Margins, 2000-2002........................................................................................................ 54 

26. Petroleum Consumption by Region, 1997-2002......................................................................................... 55 

27. Net Investment in Place in Other Energy and All Other Businesses for FRS Companies, 1995-2002 ...... 57 

28. Maximum and Minimum Three-Year Weighted Average Regional Finding Costs for 

FRS Companies, 1990-1992 to 2000-2002............................................................................................ 65 

29. Five-Year Weighted Average Regional Finding Costs for FRS Companies, 1990-1994 to 1998-2002 .... 65 

30. U.S. Onshore, U.S. Offshore, and Foreign Three-Year Weighted Average Finding Costs 

 for FRS Companies, 1979-1981 to 2000-2002 ...................................................................................... 67 

31. Indices of Three-Year Average Domestic Real Prices of Crude Oil and Natural Gas and 

 Worldwide Finding Costs for the FRS Companies, 1979-1981 to 2000-2002 ...................................... 67 

32. Reserve Replacement Ratios for the FRS Companies in the U.S. Offshore, 1993-2002............................ 70 

33. The Domestic Wellhead Price of Natural Gas and the Number of Domestic Gas Well 

Completions by the FRS Companies, 1990-2002.................................................................................. 71 

34. Natural Gas Reserve Additions per Well for FRS Companies in U.S. Onshore, 1990-2002 ..................... 72 

35. The Domestic Natural Gas Reserve Replacement Ratio for the FRS Companies and the 

Domestic Natural Gas Supply Industry as a Whole, 1990-2002 ........................................................... 73 

36. The Ratio of Natural Gas Production to Proved Natural Gas Reserves for the FRS Companies 

and the Domestic Natural Gas Supply Industry, 1990-2002.................................................................. 73 

37. Share of FRS Companies’ Domestic Oil and Natural Gas Reserve Additions Due to Mergers and 

Acquisitions, 1981-2002 ........................................................................................................................ 82 

 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 ix
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 x
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 xi

Executive Summary 

The year 2002 began with the world oil market in a state of excess supply. Reflecting this market 

condition, the earnings of the U.S.-based major energy companies in 2002 declined 45 percent 

compared to their net income in 2001, after having already dropped 29 percent from the year 2000. Key 

developments in 2002 included:

• Global petroleum inventories began the year well above normal levels. 

• In the United States, petroleum stocks (crude oil plus finished petroleum products) at the beginning 

of 2002 were over nine percent higher than at the beginning of 2001. 

• Natural gas in working storage opened the year at its highest level since 1990. 

• The crude oil price (as represented by the U.S. composite refiner acquisition price) climbed over the 

year, beginning the year at $17.38 per barrel and ending the year close to $27 per barrel, as excess 

supplies were reduced. 

• Also as excess supplies were reduced, estimated natural gas prices at the U.S. wellhead rose from 

$2.35 per thousand cubic feet in January to $3.84 in December, an increase of over 63 percent. 

To see how these and other developments have affected energy industry financial and operating 

performance, strategies, and industry structure, the Energy Information Administration (EIA) maintains 

the Financial Reporting System (FRS). 

Through Form EIA-28, major U.S. energy companies annually report to the FRS (see the box entitled 

"The FRS Companies in 2002" in Chapter 1 of this report). Financial and operating information is 

reported by major lines of business, including oil and gas production ("upstream"), petroleum refining 

and marketing ("downstream"), other energy operations, and nonenergy businesses. 

Major Energy Companies’ Profits Decline In 2002 As Income From Both 

Upstream And Downstream Operations Falls 

Net income of the FRS companies totaled $20.6 billion in 2002, a 45-percent decrease from the $37.7-

billion result achieved in 2001. (Excluding the effects of unusual items (such as asset writedowns), the 

decline in 2002 was 36.6 percent.) In addition to the 2002 result being the majors’ second net income 

decline in two years, on a constant-dollar basis, it represented the lowest level of net income achieved 

since 1998 and the eighth-lowest level over the 1974 through 2002 period of FRS data collection. 

Further, 2002 was an unusual year for the FRS companies in that both upstream and downstream 

earnings were negatively affected relative to prior-year levels. Net income from oil and gas operations 

was down by over $4 billion, a 21-percent decrease, largely due to a glut of natural gas in the United 

States in the first half of 2002, which resulted in lower natural gas prices. However, financial results of 

the FRS companies’ refining/marketing operations were significantly worse with overall 

refining/marketing net income declining in 2002 by $16.8 billion, or 111 percent. 
With recession in much of the global economy, the impacts of September 11, 2001, a relatively warm

2001-2002 winter, and world oil supply outpacing demand until mid-2002, domestic refiner margins for 

the U.S. energy industry were squeezed, as petroleum product prices declined while crude oil prices 

increased. Although net income from the foreign refining/marketing operations of the FRS companies 

managed to remain positive, both foreign and domestic operations registered a steep decline, with 

domestic refining/marketing net income falling to a loss of $0.3 billion, an all-time low for U.S. 

refining/marketing profitability over the 1977 to 2002 period of FRS line-of-business data collection. 

Further, these historic losses for domestic refining/marketing are all the more troubling as 2001 was the 

second-most profitable year for U.S refining/marketing, reflecting this industry’s continuing efforts at 

cost-cutting. 

The demise of energy trading activities across the energy industry, driven by the collapse of the Enron 

Corporation in late 2001, also negatively affected many of the overall financial results in 2002 for the 

FRS companies. Although only a small minority of FRS companies were significantly involved in 

energy trading, the drop in cash flow for those FRS companies involved in energy trading exceeded that 

of all other FRS companies combined. Further, net income from the FRS companies’ “other energy” 

line of business (now largely consisting of electric power and energy trading activities) plunged from a 

positive $2.0 billion in 2001 to a loss of $1.5 billion in 2002, a $3.5-billion decline. 

Despite Lower Profits, Capital Expenditures Remain High Due to 

Acquisitions 

Capital expenditures of the FRS companies (as measured by additions to investment in place) totaled 

$98 billion in 2002, 11 percent below the all-time high of $110 billion reached in 2001. Among the 

geographic regions, the U.S. Onshore region continued to be the most popular upstream target of 

investment, even with an exploration and development cutback of 17 percent. Additionally, while most 

FRS companies reduced their spending in the U.S. Offshore region, several projects in the Gulf of 

Mexico moved ahead in 2002, and total U.S. Offshore spending held steady, declining by only one 

percent between 2001 and 2002. The largest cutback was for projects in the Canadian region, which 

were down by 37 percent and were concentrated among those majors having made significant 

acquisitions in recent years. Political turmoil in Venezuela may have affected exploration and 

development spending in South America (in the Other Western Hemisphere region) as it declined a 

relatively steep 43 percent. However, spending for Asian Pacific projects (in the Other Eastern 

Hemisphere region) was up 22 percent in 2002, and spending for European projects (in the OECD 

Europe region, and mostly in the North Sea) increased by $0.9 billion, or 19 percent, over 2001 levels. 

With the exception of the Devon Energy acquisition of Mitchell Energy and the completion of the 

ConocoPhillips merger, the upstream mergers by the FRS companies that were a prominent feature of 

the 1998 to 2001 period fell off. Some of the companies previously involved in significant upstream

merger activity (other than Devon and ConocoPhillips) may have ceased their merger activity in order to 

address debt level or stock value problems on their balance sheets. In contrast, the bulk of capital 

expenditures in 2002 (as in 2001) reported by the FRS companies for U.S. refining and marketing 

operations involved transactions between FRS companies. Excluding the effects of mergers and 

acquisitions, the FRS companies’ capital expenditures increased by only 5 percent between 2001 and 

2002. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 xii
1. Market Developments and FRS Companies in 2002 

The 28 major U.S. energy companies1 reporting to the Energy Information Administration’s (EIA) 

Financial Reporting System (FRS) derive the bulk of their revenues and income from petroleum

operations, including natural gas production. A majority of these companies are multinational, with 39

percent of the majors' net investment located abroad. Worldwide petroleum and natural gas market 

developments are of primary importance to the companies' financial performance. (These companies are 

listed below)

The FRS Companies in 2002 

Amerada Hess Corporation LYONDELL-CITGO Refining, L.P. 

Anadarko Petroleum Corporation Marathon Oil Corporation 

Apache Corporation Motiva Enterprises, L.L.C. 

BP America, Inc.2 Occidental Petroleum Corporation 

Burlington Resources, Inc. Phillips Petroleum Company 

ChevronTexaco Corporation Premcor, Inc. 

CITGO Petroleum Corporation Shell Oil Company 

Conoco, Inc. Sunoco, Inc. 

Devon Energy Corporation Tesoro Petroleum Corporation 

Dominion Resources, Inc. Total Fina Elf Holdings USA, Inc. 

El Paso Energy Corporation Unocal Corporation 

EOG Resources, Inc. Valero Energy Corporation 

Exxon Mobil Corporation The Williams Companies, Inc. 

Kerr-McGee Corporation XTO Energy, Inc. 

Overall, petroleum and natural gas market developments led to deterioration in the majors’ financial 

performance in 2002 compared to results for 2001. Developments in the capital markets in 2002 also 

had particularly adverse consequences for a number of the major energy companies. 

Petroleum and Natural Gas Markets in 2002 

Gauged by financial performance, the year 2002 was unusual for the major energy companies in that 

earnings from both upstream operations (oil and gas exploration, development, and production) and 

downstream petroleum operations (refining, marketing, and transport) were down considerably from 

prior-year levels. As in 1998, these conditions reflected market imbalances in which excess supplies put 

downward pressure on oil and natural gas prices and squeezed refiners’ profit margins. 

The world oil market began 2002 in a state of excess supply. This situation had been building for some

time. World oil supplies had been generally outpacing demand since early 2000 and continued to do so 

until the second quarter of 2002. The imbalance was especially exacerbated in the second half of 2001 

by economic downturns in much of the world, a relatively mild onset of winter weather in the United 

States, and the impacts of the terrorist attacks in the United States on September 11, 2001 (hereafter 

referred to as 9/11). 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 1
These higher-than-normal inventories indicated an excess of supplies in the marketplace. Beginning-ofyear petroleum inventories in 2002 (excluding government stockpiles) among the industrialized nations 

of the Organization for Economic Cooperation and Development (OECD) were near a 5-year maximum. 

In the United States, stocks of motor gasoline, distillate fuel, and crude oil were at the top of their 

ranges. Natural gas in working storage in the United States opened the year at the highest level since 

1990. 

Oil and natural gas prices and refiners’ margins (the difference between product prices received and 

crude oil prices paid by refiners) began the year 2002 at sharply reduced levels compared to 2001. In 

January 2002, the price of crude oil, as measured by the composite U.S. refiner acquisition cost of crude 

oil, was $17 per barrel compared with $25 per barrel in January 2001. The U.S. refiner margin plunged 

from an all-time peak of $18 per barrel in May of 2001 to $7 per barrel in January 2002. Natural gas 

prices at the U.S. wellhead averaged $2.35 per thousand cubic feet (mcf) in January 2002, down from

$6.82 per Mcf in the prior January, a record high. 

The elimination of excess supplies and recovery of prices and margins characterized much of petroleum

and natural gas markets for 2002. 

Turning first to petroleum markets, on the demand side, growth in worldwide petroleum demand, which 

was near zero for 2001, grew steadily in 2002 compared to the prior year. The growth in petroleum

demand mainly reflected the improvements in world economic activity. As measured by real gross 

domestic product (GDP), world economic growth began to recover in 2002 from recession and the 

impacts of 9/11. Year-over-year global real GDP growth steadily improved, from near zero in the fourth 

quarter of 2001 to an annual rate of 2.5 percent in the fourth quarter of 2002. For all of 2002, world oil 

demand was up almost 1 percent over demand in 2001. Growth in petroleum demand came largely from

Asia (apart from Japan) and Russia. Petroleum demand in the United States was up 1 percent. 

Domestically, the modest growth in U.S. petroleum demand was led by a 2.8-percent increase in 

gasoline demand. The increase in gasoline demand in part reflected higher economic growth, but also 

continued reluctance by businesses and consumers to return to pre-9/11 levels of airline travel. This 

latter development was evident in the demand for jet fuel, which dropped 2 percent in 2002 following a 

4-percent drop in 2001. 

On the supply side, the nations of the Organization of Petroleum Exporting Countries (OPEC), including 

Iraq, managed to cut production by 1.9 million barrels per day (mmb/d) in 2002 compared to the prior 

year. Notable increases in oil production by Angola, Brazil, Canada, and Russia were only minor offsets 

to the OPEC cuts. For the year, world oil production was 1.2 mmb/d lower in 2002 than in 2001. 

Adjustments by OPEC and a recovery in petroleum demand eliminated most of the excess of petroleum

supplies by the second half of 2002. In the United States, petroleum stocks (excluding the Strategic 

Petroleum Reserve) at the beginning of 2002 were 6 percent above normal levels. As world oil 

production was cut and petroleum demand recovered, U.S. refiners drew down inventories. By the end 

of 2002, petroleum stocks were below the average level of recent years. 

As oil markets came into balance during 2002, oil prices rose. In December 2001, the refiner acquisition 

cost of imported crude oil was $16 per barrel. By December 2002, it was $27 per barrel. Most 

petroleum product prices in the United States, with the exception of jet fuel, rose slightly faster than 

crude oil input prices, providing a boost to refiners’ margins. However, despite this latter improvement, 

refiners’ margins throughout 2002 were well below the levels of 2001. On an annual basis, the refiners’ 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 2
margin was down to an average $8 per barrel in 2002 from just under $12 per barrel in 2001. The sharp 

drop in the margin had a devastating effect on U.S. refiners’ financial results for 2002. 

In refining operations abroad, margins also tended to rise during 2002 in the key European and Asia 

Pacific regions. For the year as a whole, though, margins tended to be lower in 2002 than in 2001. 

Natural gas market developments had the most severe impacts on upstream financial results in 2002. 

The year 2002 opened with the highest level of natural gas in working storage in the United States since 

1990 (using previous year-end levels to approximate beginning year levels of the current year). The 

buildup of natural gas inventories was in part due to mild winter weather at the outset of 2002 (U.S. 

heating degree days in the fourth quarter of 2001 were 27 percent below the previous fourth quarter) and 

in part due to the falloff in economic activity in the second half of 2001. Mild winter weather continued 

into early 2002, putting further downward pressure on U.S. natural gas prices. The U.S. wellhead price 

in February 2002 was slightly over $2 per mcf, down from over $5 per mcf in the previous February. 

Natural gas suppliers drew down inventories during 2002, aided by higher economic growth and a 

colder-than-normal start to winter weather in the fourth quarter of 2002. As excess gas inventories 

declined, estimated natural gas prices rose. However for the year, estimated U.S. wellhead natural gas 

prices averaged $2.95 per Mcf in 2002, a 27-percent drop from $4.02 per Mcf in 2001. Lower natural 

gas prices were the main cause of reduced U.S. upstream earnings for the majors in 2002 compared to 

2001. 

Outside the United States, the majors were also hit by lower natural gas prices. The FRS companies’ 

reported foreign natural gas prices averaged $2.54 per Mcf in 2002, down from an average of $2.82 per 

Mcf in 2001. 

Demise of Energy Trading Impacts Financial Results 

Many of the overall financial results of the FRS companies were affected by the demise of the energy 

trading business in 2002. 

Late in 2001, the Enron Corporation made revelations of improper financial disclosures going back four 

years. The abuses of financial reporting standards included deliberate inflation of revenues, 

misclassification of liabilities to hide debt financing, and manipulation of reported earnings to meet 

earlier forecasts. Many of the abuses were related to Enron’s energy trading business, Enron being the 

largest energy trader at the time. 

Enron’s energy trading customers withdrew their business on a massive scale, having lost confidence in 

Enron’s ability to guarantee future contracted trades at stated terms. Following the accounting 

revelations that began with its report of third quarter earnings on October 16, 2001, investors lost 

confidence in Enron and its ability to generate future earnings. Consequently, Enron’s share prices 

plunged in value to less than $1 a share on November 28, 2001, from a peak value of $84.87 a share on 

December 28, 2000.3

 The demise of Enron’s trading business, its rapidly declining net worth, and its 

growing debt repayments led the company to file for Chapter 11 bankruptcy in November 2001. 

The loss in investor confidence in energy trading activities rapidly spread beyond Enron to other energy 

companies engaged in these activities. Customers who had utilized energy traders to contract for future 

deliveries of energy commodities and manage the prices of future deliveries also lost confidence. The 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 3
financial impacts of the Enron aftermath were severe for companies that depended on energy trading as 

a core source of revenues and earnings. 

As customers cut back on their use of energy trading services, an important source of revenue shrank, 

reducing the net income of energy trading companies. Prior to the Enron collapse, revenue from energy 

trading was the main source of reported revenue growth for companies with significant trading 

operations. 

Energy traders gained profit by tailoring future deliveries and purchases of energy commodities at

contracted prices to their customers’ particular needs. A key component of these transactions was the 

trader’s assurance to the customer that the stated future conditions would be fulfilled. The energy 

trading customer was essentially purchasing assurances of future deliveries and sales at specified prices 

or within price ranges. 

In order to assure that future transactions could be completed, the energy trader had to take positions in 

contracts (i.e., the buying and selling of multiple contracts, such as in the futures, commodities, and 

other markets), both financial and physical. The energy trader’s position often entailed borrowing funds 

in order to provide ready cash to expeditiously settle contracts. As long as the cash flow from the

trading business was growing, or at least steady and predictable, payback of borrowed funds was done in 

the normal course of business. However, should the trading business go into a rapid decline and 

associated cash flow diminish, the energy trader could be in a situation in which the cash needed to pay 

back prior borrowings exceeds the cash currently coming in from the trading business. In this situation, 

the trader must borrow more or sell assets to pay back its borrowings. 

Following the Enron debacle, energy-trading customers lost confidence in the process, concerned that 

future contracts might not be wholly fulfilled. The loss of business had a double-edged effect. The first 

effect is simply that loss of customers means loss of revenue and lower bottom-line results. The other, 

more adverse effect stemmed from paybacks of borrowed funds and associated interest expense that 

exceeded current cash flow from the trading business. To make paybacks in excess of cash flow, energy 

traders borrowed more, moving the trader into a riskier position. With higher risk comes a higher cost 

of capital for additional funds. Increased borrowing at higher interest rates further eroded the financial 

results of energy trading companies. 

Selling assets is another way of raising cash. Energy-trading companies priced some of their assets for 

quick sale to raise cash, often at prices below the assets’ balance sheet value. In corporate financial 

reporting, when a fixed asset (e.g., a pipeline) is sold for a price below its book value, the loss reduces 

net income, resulting in lower reported profits. Traders sold other assets because they were profitable 

with many ready buyers. In this situation, the energy trader was reducing its profits in order to raise 

cash. Again, the need to raise cash reduced reported profits as well as the company’s stock of 

productive assets. 

Thus, massive defection of trading customers, increased borrowing costs, and negative bottom-line 

impacts of hurried asset sales reduced the net income and cash flow of companies engaged in energy 

trading in 2002. Although only a small minority of FRS companies were significantly involved in 

energy trading, the demise of the energy trading business appeared to have effects on overall financial 

results for 2002. For example, as discussed in the next chapter, the drop in cash flow from company 

operations in 2002 of the handful of energy traders in the FRS group exceeded that of all other FRS 

companies combined. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 4
Changes in the FRS Group in 2002 

New Survey Entrant 

XTO Energy, Inc. (formerly Cross Timbers Oil Company) was added to the FRS respondent group for 

2002 due to its oil and gas reserves and production levels. XTO’s growth over the last few years was 

largely due to asset acquisitions and resulted in its addition to the FRS respondent group. 

Mergers and Acquisitions 

Two FRS companies merged with other FRS companies during 2002. On March 3, 2002, Equilon was 

fully consolidated into Shell Oil Company following Shell’s acquisition of Texaco’s 44-percent 

ownership of Equilon on February 18, 2002, and consolidated retroactively as of January 1, 2002.4

 On 

August 30, 2002, Conoco and Phillips completed their merger, a transaction valued at $15.2 billion 

when originally reported in November 2001. ConocoPhillips Company is the name of the resulting 

company, but both Conoco and ConocoPhillips reported to the FRS survey as stand-alone companies for 

2002. 

Two other companies, Tosco and Ultramar Diamond Shamrock, were stand-alone respondents to the 

FRS for 2001 despite being acquired by other FRS companies (Phillips and Valero, respectively) before 

the end of 2001. These companies have now been fully consolidated into Phillips and Valero and, as of 

2002, are no longer reported to the FRS survey on a stand-alone basis. 

The FRS Companies’ Importance in the U.S. Economy

For the reporting year 2002, 28 major energy companies reported their financial and operating data to 

the EIA on Form EIA-28.5

 These companies (referred to as the FRS companies in this report) occupy a 

significant position in the U.S.6

 economy. In 2002, operating revenues of the FRS companies totaled 

$699 billion, which is equal to 10 percent of the $7.0 trillion in revenues of the Fortune 500 largest U.S. 

corporations.7

The reporting companies engage in a wide range of business activities, but their most important 

activities are in the energy sector. About 88 percent, or $642 billion, of allocated operating revenues8

were derived from energy sales. Nearly all of these revenues were derived from the companies’ core 

petroleum operations (which includes natural gas) (Figure 1). (For the purposes of this report, the 

petroleum line of business includes natural gas.9

) 

In 2002, the FRS companies accounted for 49percent of total U.S. oil, which includes crude oil and 

natural gas liquids (NGL) production,10 45 percent of natural gas production, and 84 percent of U.S. 

refining capacity (Figure 2). The bulk of the FRS companies’ assets and new investments were devoted 

to sustaining various aspects of petroleum production, processing, transportation, and marketing. 

Energy production other than oil and natural gas has been a relatively small, but growing, part of the 

FRS companies’ operations since 1994. During 2002, the combined operating revenues of the coal and 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 5
0

100

200

300

400

500

600

700

800

900

1,000

1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001

Billions of 2002 Dollar

s

Source: Energy Information Administration, FormEIA-28 (Financial Reporting System).

Figure 1. Operating Revenues by Line of Business for FRS Companies, 1977-2002

Petroleum (Oil and Natural Gas)

Non-Petroleum Energy

Nonenergy

0

10

20

30

40

50

60

70

80

90

100

1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

Percent of Total United States .

Refinery Capacity

Crude Oil and NGL

Natural Gas

Coal

Uranium Oxide

Figure 2. Shares of U.S. Energy Production and Refinery Capacity for FRS Companies, 1981-2002

 Note: The FRS companies last produced uranium in 1991.

 Sources: Table B1; Total industry uranium oxide production is from Energy Information Administration,

Uranium Industry Annual 1992, DOE/EIA-0478(92) (Washington, DC, October 1993).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 6
other energy operations of the FRS companies totaled $44 billion, or 6 percent of allocated revenues. 

Increased activity in electricity more than offset the continued decline in coal activity by the FRS 

companies beginning in 1994 and continuing through 2001, but declined in 2002. In particular, the FRS 

companies accounted for 29 percent of U.S. coal production in 1991, 15 percent in 1997, 7 percent in 

1998, and 3 percent in 2002, with these declines largely being due to the relative lack of profitability 

attributable to this line of business. Meanwhile, FRS other energy (exclusive of coal), which is chiefly 

composed of electricity operations, increased from 0.3 percent of allocated revenues in 1994 to 10.2 

percent in 2001, but fell to 6 percent in 2002. 

During the 1980’s, the FRS companies were major producers of domestic uranium. However, no FRS 

company has produced uranium oxide since 1991. Nonenergy businesses, mainly chemicals, accounted 

for slightly more than 6 percent, or $46 billion, of the FRS companies’ allocated revenues in 2002. 

 

Endnotes 

 

1

The U.S.-based energy companies that respond to the Financial Reporting System (FRS) Form EIA-28 are considered to be 

U.S. majors by the Energy Information Administration (see P.L. 95-91, Sec. 205 (h)). Per the requirements of that statute, 

the Administrator of the Energy Information Administration designates “major energy-producing companies” and selects 

them as respondents to the FRS. Currently, the Administrator uses the following selection criteria: at least 1 percent of U.S. 

crude oil or natural gas liquids reserves or production, or at least 1 percent of U.S. natural gas reserves or production, or at 

least 1 percent of U.S. crude oil distillation capacity. The companies that reported to the FRS for the years 1974 through 

2002 are listed in Appendix A, Table A1. Three of the FRS companies are owned by foreign companies: BP America—

owned by BP plc; TotalFinaElf Holdings USA—owned by TotalFinaElf; and Shell Oil—owned by Royal Dutch/Shell. 2

BP America, the U.S. subsidiary of BP plc of the United Kingdom, is the FRS respondent. 3 Houston Chronicle, “History of Enron Corp.” (November 29, 2001). 4

Details of the transaction were largely undisclosed, but the value of the overall transaction was $3.8 billion. The transaction 

had several aspects. Shell acquired Texaco’s 44-percent ownership of Equilon, Shell acquired about 48 percent of Texaco’s

32.8-percent share of Motiva, and Saudi Refining acquired about 52 percent of Texaco’s 32.8-percent share of Motiva. The 

results of the transaction are that Texaco (now ChevronTexaco) has no ownership in Equilon or Motiva, Shell fully owns 

Equilon (and subsequently consolidated it), Shell and Saudi Refining are now 50/50 joint venture partners in Motiva. 5

Aggregate time series data from Form EIA-28 for 1977 through 2001 and previous editions of this report can be obtained

from the EIA (see http://www.eia.doe.gov/emeu/finance/page2.html). 6

For the purposes of this report, the term "United States" typically includes the 50 States, the District of Columbia, Puerto

Rico, and the U.S. Virgin Islands. 7

The Fortune 500 is a list of the 500 largest U.S. corporations, ranked by revenues, published annually by Fortune magazine 

(see http://www.fortune.com/fortune/fortune500). 8

 Note that “allocated operating revenues” exceeds corporate operating revenue because of double –counting that is

eliminated when calculating corporate operating revenues. 9

Generally accepted accounting principles (GAAP) for the United States do not require that energy companies separately 

account for costs of oil production and natural gas production in company financial records. Various exploration and 

development costs cannot easily or separately be assigned to either oil production or natural gas production. 10Note that U.S. totals include royalty production while the FRS production levels do not. Thus, the FRS share of crude oil 

and natural gas liquids production and natural gas production are somewhat understated by these calculations. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 7

2. Financial Developments in 2002 

Net income of the FRS companies10 declined 45 percent, from $37.7 billion in 2001 to $20.6 billion in 

2002 (Table 1). This was the second lowest level of net income in the past eight years and well below 

the FRS companies’ peak earnings of $53.2 billion in 2000. Profitability (at 7 percent, as measured by 

return on equity11), was also at the second lowest level in the past ten years (Figure 3). Profitability of 

other large U.S. industrial corporations, as represented by the Standard and Poor’s (S&P) Industrials,12

rebounded from poor results in 2001 and was well above the profitability of the FRS companies in 2002. 

Income Statement Items 2001 2002

Percent

Change

2001-2002 2001 2002

Percent

Change

2001-2002

Operating Revenues 803.7 698.9 -13.0 4,527.1 4,608.7 1.8

Operating Expenses -735.6 -659.7 -10.3 -4,068.9 -4,124.7 1.4

 Operating Income 68.1 39.2 -42.4 458.1 484.0 5.6

Interest Expense -9.1 -10.7 18.7 -105.6 -94.5 -10.5

Other Revenue (Expense) 6.3 6.7 5.8 -124.3 -147.4 18.6

Income Tax Expense -27.7 -14.6 -47.3 -108.6 -124.7 14.8

 Net Income 37.7 20.6 -45.4 119.7 117.3 -1.9

Net Income Excluding Unusual Items 51.2 32.5 -36.6 NA NA

 Note: Sum of components may not equal total due to independent rounding. Percent changes were calculated from unrounded 

data. 

 NA= not available.

 Sources: FRS Companies: Energy Information Administration, Form EIA-28 (Financial Reporting System); S&P Industrials: 

Compustat PC Plus, a service of Standard and Poor's.

Table 1. Consolidated Income Statement for FRS Companies and the S&P Industrials, 

 2001-2002 

 (Billion Dollars)

FRS Companies S&P Industrials1

 1

Time Warner and Qwest Communications data have been excluded from S&P Industrials data due to anomalies in the data for 

both companies in 2002, which, when included, greatly distorted the numbers for the group as a whole.

The primary explanation for the steep decline in net income was the excess supply of petroleum (crude 

oil and refined products) at the beginning of 2002 that squeezed refining margins (the spread between 

refined product prices and crude oil input prices) for most of 2002. Lower natural gas prices, due to a 

glut of natural gas in the United States in the first half of 2002, also reduced the net income of the FRS 

companies. 

Another development in 2002 that had an adverse impact on income and cash flow was the collapse of 

the energy trading business following the demise of the Enron Corporation in late 2001.13 Although 

only a minority of FRS companies were significantly involved in energy trading, these companies 

appeared to do much worse in terms of financial results than did other FRS companies. For example, 

the companies that were most affected by energy trading activity (El Paso, Williams Companies, and 

ChevronTexaco through its Dynegy subsidiary) registered a drop in net income of 138 percent, 

compared to a 38-percent decline for other FRS companies, and accounted for over one-half of the FRS 

companies’ decline in cash flow from their operations. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 9
0

5

10

15

20

25

1973 1976 1979 1982 1985 1988 1991 1994 1998 2002

Percent

 Note: Time Warner and Qwest Communications data have been excluded from S&P Industrials data in 2001 and 2002 due to

anomalies in the data for both companies in 2002, which, when included, greatly distorted the numbers for the group as a whole.

 Sources: FRS Companies: Energy Information Administration, Form EIA-28 (Financial Reporting System). S&P Industrials: 

Compustat PC Plus, a service of Standard and Poor's.

FRS Companies

S&P Industrials

Figure 3. Return on Equity for FRS Companies and the S&P Industrials, 1973-2002

Unusual items, which are charges against and additions to net income of a non-recurring nature, had a 

sizeable effect in 2002 as they did in 2001. Of the $11.9 billion (net) charges against income in 2002, 

$7.9 billion was for asset writedowns. Most of the writedowns stemmed from lower projected cash 

flows from oil and gas projects, but nearly $3 billion in asset writedowns appeared to be related to 

energy trading activities. Restructuring changes, which usually accompany downsizing and planned 

divestitures, totaled $1.5 billion, and discontinued operations reduced net income by $1.0 billion. 

Excluding the effects of unusual items, net income of the FRS companies was down 37 percent between 

2001 and 2002, from $51.2 billion to $32.5 billion (Table 1). Nearly all lines of business registered 

income declines in 2002. The worst financial performance, by far, was in petroleum refining and 

marketing. 

Income and Cash Flow 

Downstream Petroleum Performance Hit A New Low in 2002 

Net income14 from the FRS companies’ U.S. refining/marketing line of business, excluding unusual 

items, fell from $12.8 billion in 2001 to a loss of $0.3 billion in 2002 (Table 2). The loss in 2002 was an 

all-time low for the FRS companies’ U.S. refining/marketing operations during the 1977 to 2002 period 

of FRS data collection. The profitability of these operations, as measured by return on investment,15 was 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 10
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 11

 Production 17,646 15,030 -14.8 20,635 16,232 -21.3

 Refining/Marketing 11,951 -2,164 -118.1 12,829 -284 -102.2

 Pipelines 3,345 1,694 -49.4 3,754 2,141 -43.0

 Total U.S. Petroleum 32,942 14,560 -55.8 37,218 18,089 -51.4

 Production 14,558 12,918 -11.3 16,101 15,744 -2.2

 Refining/Marketing 3,115 452 -85.5 3,239 526 -83.8

 International Marine 176 -38 -121.6 176 -38 -121.6

 Total Foreign Petroleum 17,849 13,332 -25.3 19,516 16,232 -16.8

Total Petroleum 50,791 27,892 -45.1 56,734 34,321 -39.5

Coal 134 -46 -134.3 136 -350 -357.4

Other Energy 1,993 -1,460 -173.3 2,000 2,118 5.9

Nonenergy -2,726 1,842 -- 320 2,088 552.5

 Total Allocated 50,192 28,228 -43.8 59,190 38,177 -35.5

Nontraceables and Eliminations -12,457 -7,636 -- -7,975 -5,716 --

Consolidated Net Incomeb 37,735 20,592 -45.4 51,215 32,461 -36.6

Table 2. Contributions to Net Income by Line of Business for FRS Companies, 2001-2002 

 (Million Dollars)

 aThe Petroleum line of business includes natural gas operations.

 bThe total amount of unusual items was -$2,286 million and -$13,480 million in 2000 and 2001, respectively.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

2001 2002

 -- = Not meaningful.

Percent 

Change 2001-

2002

Percent 

Change 2001-

2002

Petroleuma

 U.S. Petroleum

 Foreign Petroleuma

Line of Business 2002

Net Income Net Income Excluding Unusual Items

2001

also at an all-time low. Over two-thirds of the $17.1-billion decline in the FRS companies’ total net 

income can be attributed to the plunge in U.S. refining/marketing financial results. 

The dramatic reversal in performance was caused by a confluence of events and market developments 

(discussed in detail in Chapter 1), including: 

• world oil supply that outpaced demand until mid-2002, 

• recession in much of the global economy, 

• the impacts of the attacks of 9/11, 

• a relatively warm 2001-to-2002 winter, and 

• low natural gas prices that encouraged substitution away from petroleum products. 

These developments resulted in glut of crude oil and petroleum products at the beginning of 2002. 

Excess petroleum supplies, which had been building for several months prior to 2002, put downward 

pressure on petroleum prices. Refiners’ margins were squeezed. For example, the average margin for 

U.S. refiners plunged from an all-time peak of $18 per barrel in May of 2001 to $7 per barrel in January 

2002. 

The workings of the market, aided by oil production cutbacks by the Organization of Petroleum 

Exporting Countries (OPEC) averaging nearly 2 million barrels per day, eventually eliminated excess 
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 12

petroleum supplies by the second half of 2002. Refiner margins rose throughout the year, but not by 

enough to offset the earlier damage. On an annual basis, U.S. refiner margins were $8 per barrel in 

2002, down from nearly $12 per barrel in 2001. Also, among the FRS refiners, operating costs (the 

costs of running refineries and refined product supply networks) were up by $2 per barrel between 2001 

and 2002, continuing an upward trend evident since 1999. This trend is, at least in part, the result of the 

recent rapid pace of merger and acquisition activity and the difficulties of integrating acquired 

companies and assets into complex and geographically dispersed manufacturing and distribution 

networks. However, recent data do not indicate that environmental requirements were the prime culprit 

in increased operating costs (see the Highlight entitled “Environmental Compliance Partially Eclipses 

Recent Gains in Profitability” in Chapter 3 for a more detailed description). 

The FRS companies’ downstream petroleum operations outside the United States also registered poor 

financial results in 2002. Net income from the foreign refining/marketing line of business, excluding 

unusual items, fell by 84 percent in 2002 compared to net income in 2001. However, the decline in 

income was not as steep as the 102-percent decline in U.S. refining/marketing net income. Available 

data indicate that refiner margins in the regions of Europe and Asia-Pacific, the main areas of the FRS 

companies’ foreign downstream operations, did not decline as much as U.S. margins (see Chapter 3 for 

additional details). The growing weakness of the U.S. dollar during 2002 contributed to this result. 

FRS Companies’ Pipeline Earnings 

Net income from the FRS companies’ pipeline operations, excluding unusual items, was down 43 

percent between 2001 and 2002. This is an unusual result since pipelines, both interstate and intrastate, 

tend to be subject to economic regulation. A characteristic of economically regulated industries is 

stability of rates of return and earnings. 

The volatility of the FRS companies’ pipeline profits comes from the commingling of regulated and 

unregulated activities in this line of business. Due to limitations in the current design of Form EIA-28, 

companies have to report downstream natural gas operations in the pipeline line of business section of 

the Form. Downstream natural gas includes gas gathering (the collection of gas from field production 

locations) and processing, transmission (the transport of natural gas from producing areas to consuming 

areas), distribution (the local delivery of gas to residences and commercial establishments), marketing, 

and trading. (Note that, beginning with the 2003 reporting year, Form EIA-28 will have a separate 

downstream natural gas line of business.) 

The inclusion in pipeline operations of natural gas trading, which declined sharply in 2002 (as did all 

energy trading), caused the large decline in net income from the pipeline line of business. The impact of 

reduced trading activity can be gauged by the change in non-transport revenues. For companies whose 

pipeline operations were wholly or primarily in natural gas, non-transport revenues fell by $3.5 billion, 

or 92 percent. Net income from pipelines for this group, excluding unusual items, fell from $2.7 billion 

in 2001 to $1.2 billion in 2002. In contrast, the balance of net income, which is primarily from liquids 

pipelines, was $1.1 billion in 2001 and $0.9 billion in 2002, a 15-percent decline (unrounded data). 
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 13

Low Natural Gas Prices Hurt Upstream Profits 

Net income from U.S. oil and gas production, excluding unusual items, was down 21 percent (or by over 

$4 billion) in 2002 from net income in 2001 (Table 2). The decline was largely attributable to lower 

estimated natural gas prices. In January 2002, the price of natural gas was $2.35 per thousand cubic feet 

(Mcf) -- 66 percent below the wellhead price of the prior January.16 The year began with a high level of 

natural gas in storage, a result of mild winter weather and a fall off in demand stemming from reduced 

economic activity in the second half of 2001. Natural gas suppliers drew down inventories throughout 

the year, aided by a recovery in economic growth and a colder-than-normal start to winter in late 2002. 

By December 2002, the wellhead price was $3.84, a 12-percent rise from the price of $3.44 of the 

previous December. On an annual basis, however, the U.S. wellhead natural gas price averaged $2.95 

per Mcf in 2002, a 27-percent drop from $4.02 per Mcf in 2001. 

On an annual basis, U.S. oil prices at the wellhead averaged $22.50 per barrel in 2002, up 3 percent from 

2001. Oil prices were up because of cutbacks in oil production of 1.9 million barrels per day by OPEC 

and a modest recovery in world economic growth and petroleum demand. However, the effect of higher 

oil prices could not fully offset the adverse impact of lower natural gas prices. Also, the FRS 

companies’ U.S. oil production and natural gas production were both 1 percent lower in 2002 compared 

to 2001, which further contributed to lower revenues and income. 

Foreign upstream operations fared somewhat better than U.S. upstream operations. Net income, 

excluding unusual items, was nearly flat, down only 2 percent between 2001 and 2002 (Table 2). 

Foreign upstream production is tilted more toward oil than is U.S. production (58 percent oil abroad vs. 

46 percent in U.S. operations), so that foreign operations benefited more from higher oil prices and were 

hurt less by lower gas prices. Also, natural gas prices abroad realized by the FRS companies (see 

Chapter 3) did not fall as much as U.S. prices. An increase in foreign natural gas production of 12 

percent and an increase in foreign oil production of 1 percent by the FRS companies both mitigated the 

decline in foreign upstream net income. 

 

Other Energy Plagued by Energy Trading Collapse 

Although the “other energy” line of business was originally intended for reporting on nonconventional 

energy (synthetic fuels and renewable energy), it now largely consists of electric power activities and 

energy trading. The shift in composition of the other energy line of business occurred over the past 10 

years and reflects two developments. First, in recent years, several companies that satisfy the FRS 

survey respondent selection criteria have significant electric power operations. These companies have 

acquired natural gas production operations large enough to account for at least one percent of U.S. total 

natural gas production and/or reserves and thereby qualify as FRS respondents. Second, several longtime FRS respondents have become involved in various aspects of electric power, both in the United 

States and abroad, including generation, distribution, marketing, and trading. Due to the limitations of 

Form EIA-28, electric power financial information is reported in the other energy line of business. 

(Note that, beginning with the 2003 reporting year, Form EIA-28 will have a separate electric power line 

of business.) 
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 14

Net income from the other energy line of business plunged from a positive $2.0 billion in 2001 to a loss 

of $1.5 billion in 2002, a $3.5-billion downturn. The decline is attributable to the large amount, $3.6 

billion, in unusual items in 2002. The unusual items were the balance sheet consequences of actions 

taken to repair the damage from the collapse of the energy trading business following the demise of the 

Enron Corporation in late 2001. Since these actions tended to reduce the value of a company’s 

stockholders’ equity, the impacts on required stockholders’ equity are to be included in the income 

statement. 

The energy trading activities of ChevronTexaco and El Paso accounted for most of the unusual items. 

ChevronTexaco reported an after-tax writedown of $1.6 billion due to the decline in the value of its 

ownership of Dynegy. Dynegy is an unconsolidated subsidiary of ChevronTexaco, which (until 2002) 

was one of the largest energy traders in the United States. ChevronTexaco also took an after-tax charge 

of $0.7 billion for its share of Dynegy’s asset writedowns, revaluations, and loss on asset sales.17 El 

Paso reported after-tax charges against income totaling $1.1 billion from its energy trading and related 

businesses. The charges were largely for reductions in the fair market value of energy trading contracts, 

reductions in the value of its investments in energy-trading subsidiaries, litigation directed at its energy 

trading business, and changes in accounting principles related to reporting the value of energy trading 

contracts.18

Excluding unusual items, net income from the other energy line of business was up 6 percent to $2.1 

billion in 2002. This result suggests that the core of ongoing other energy operations -- 

production/generation, transmission, distribution, and marketing of electricity -- continued to yield 

positive returns even while the energy trading business was collapsing. 

Chemical Operations Yield Rare Gains in Earnings 

Net income from the FRS companies’ nonenergy line of business, excluding unusual items, totaled $2.1 

billion in 2002, a nearly seven-fold increase over results for 2001. The increase in income was due to 

increased earnings from chemical manufacturing and decreased losses from the remaining businesses 

beyond energy. 

Operating income from the FRS companies’ chemical businesses19, excluding unusual items, was $1.9 

billion in 2002, more than double the amount in 2001 (Table 3). Increased earnings were widespread 

with all but 2 of the 11 companies with chemical operations reporting an earnings improvement in 2002. 

The improvement reflected increased sales volumes compared to 2001. However, chemical margins, the 

difference in product prices and new material input prices, may not have improved much overall in 

2002. For example, Exxon Mobil noted, “chemicals earnings... were $123 million higher than 

2001...[benefiting] from record...product sales volumes,”20 but elsewhere said, “Earnings for 2002 ... 

were higher than 2001, after excluding special items ... as strong volume growth more than offset lower 

margins.”21 However, despite the sharp upswing in income in 2002, the profitability of the FRS 

companies’ chemical operations remained low in an historical context (Figure 4). 

The balance of the FRS companies’ activities outside energy is reported in the “other nonenergy” line of 

business. Other nonenergy has been a long-running target of retrenchment. As discussed in detail in the 

previous edition of this report,22 the FRS companies’ other nonenergy assets as a share of their total 

assets steadily declined from a peak of 13 percent in 1983 to 1.3 percent in 2001. The share declined 

again in 2002, to 1.0 percent, as Exxon Mobil sold its Chilean copper operations for $1.3 billion.23 Most 
of the FRS companies’ other nonenergy activity in 2002 was in technology development. Real estate, 

financial services, and remnants of telecommunications ventures were also included by some of the 

companies. The other nonenergy line of business, however, contributed positively to bottom-line 

results, as the FRS companies were able to reduce their operating losses in this area in 2002 by more 

than $0.2 billion (Table 3). 

Segment 2001 2002

Percent

Change 

2001-2002

 Chemicals 906 1,921 112.0

 Other Nonenergy -1,176 -907 --

Table 3. Operating Income in Chemicals and Other Nonenergy Segments

 for FRS Companies, 2001-2002

 (Million Dollars)

 Sources: Energy Information Administration, Form EIA-28 (Financial Reporting System), except for 

chemicals segment operating income, which for companies with operations in both segments was compiled 

from company annual reports to shareholders.

Operating Income, Excluding Unusual Items

 -- = not meaningful

0

5

10

15

20

25

30

35

40

45

50

1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001

Return on Investment (Percent)

Operating Return on Investment

 Note: Operating return on investment is operating income as a percent of net property, plant, and equipment.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System), and company annual reports to 

stockholders.

Figure 4. Operating Return on Investment in Chemicals for FRS Companies, 1975-2002

Record Cash Flow in 2001 Followed by Mediocre Cash Flow in 2002 

Cash flow is the cash realized from a company’s ongoing operations. Cash includes currency, demand 

deposits, and interest-bearing assets of less than 30 days maturity. Cash flow from operations is usually 

computed by adding to (subtracting from) net income those cost (revenue) items that did not actually 

involve an outlay (receipt) of cash.24 For energy companies, the largest non-cash item generally is 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 15
depreciation, depletion, and amortization (DD&A), which is an allowance for the decline in value of 

property, plant, and equipment recorded as a charge against income. 

In 2002, the FRS companies’ cash flow from operations was down $15 billion from the record of $90 

billion realized in 2001 (Table 4). Although this was a substantial drop, the FRS companies’ cash flow 

performance in 2002 was still somewhat better than in recent years. Cash flow of $75 billion realized in 

2002 was slightly above the average of $70 billion for the prior five years, from the 1997 to 2001. 

Due to limitations of Form EIA-28, cash flow by lines of business can be computed only on a pretax 

basis. The decline in overall pretax cash flow of $30 billion (Table 4) was in line with the $32-billion 

decline in pretax income (Table B12). Among the lines of business, downstream petroleum operations, 

with a drop in cash flow of $25 billion, were largely responsible for the decline in cash flow in 2002. 

 (Billion Dollars)

Contribution to Pretax Cash Flow a 2001 2002

Percent

Change

2001-2002

Petroleumb

 Oil and Gas Production 85.0 76.2 -10.3

 Refining, Marketing, and Transport 34.8 10.3 -70.3

Coal and Other Energy 3.3 0.4 -88.6

Chemicals 0.9 1.5 61.6

Other Nonenergy 0.2 1.2 649.7

Nontraceable -7.3 -2.9 --

 Total Contribution to Pretax Cash Flowa 116.8 86.7 -25.8

Current Income Taxes -24.0 -14.5 -39.5

Other (Net) -3.2 2.8 --

 Cash Flow from Operations 89.6 75.0 -16.4

Table 4. Line-of-Business Contributions to Pretax Cash Flow for 

 FRS Companies, 2001-2002 

 aDefined as the sum of operating income, depreciation, depletion, and amortization, and dry hole 

expense.

 -- = Not meaningful.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

 Note: Sum of components may not equal total due to independent rounding. Percent changes were 

calculated from unrounded data.

 b

The petroleum line of business includes natural gas operations.

Targets of Investment 

FRS Companies Increase Upstream Focus on OECD Europe, North Sea 

Capital expenditures of the FRS companies (as measured by additions to investment in place25) in 2002, 

at $98 billion, were 11 percent below the 2001 all-time high of $110 billion (Table 5). Oil and gas 

production accounted for nearly two-thirds of the FRS companies’ capital expenditures in 2002. The 

FRS collects oil and gas exploration and development expenditures by region and by function. 

Exploration and development expenditures include exploration expenses as well as capital expenditures. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 16
Reviewing patterns of exploration and development expenditures yields a picture of targets of upstream

investment across regions. 

Regions that were targets of increased exploration and development in 2002 were in the Eastern 

Hemisphere while cutbacks were in the Western Hemisphere. Overall exploration and development 

expenditures for the Eastern Hemisphere were up $3.0 billion, or 20 percent, while exploration and 

development expenditures in total for the Western Hemisphere were down $5.0 billion, or 16 percent. 

 (Billion Dollars)

Lines of Business 2001 2002

Percent

Change

2001-2002

Percent Change

Excluding 

Mergers and

Acquisitions

2001-2002

Petroleum a

 U.S. Petroleum

 Production 33.0 30.1 -8.9 3.9

 Refining/Marketing

 Refining 12.1 15.1 25.1 111.4

 Marketing 5.6 1.9 -66.3 -35.6

 Transport 1.6 1.9 19.5 19.5

 Total Refining/Marketing 19.2 18.9 -1.9 39.7

 Pipelines 3.8 2.7 -28.1 -13.7

 Total U.S. Petroleum 56.0 51.7 -7.8 11.1

Foreign Petroleuma

 Production 35.9 33.7 -6.1 18.1

 Refining/Marketing 4.6 5.0 9.7 -0.8

 International Marine 0.0 0.0 -- --

 Total Foreign Petroleum 40.5 38.7 -4.3 14.8

Total Petroleuma 96.5 90.4 -6.3 12.6

Coal 0.1 0.0 -80.0 -80.0

Other Energy 5.0 3.7 -26.6 19.5

Nonenergy

 Chemicals 3.8 2.3 -38.8 -28.5

 Other Nonenergy 3.4 0.4 -87.9 -86.9

Total Nonenergy 7.2 2.7 -62.1 -58.2

Nontraceables 1.5 1.2 -22.7 -23.0

Additions to Investment in Placeb 110.4 98.0 -11.2 5.0

Additions Due to Mergers and Acquisitions 45.8 30.2 -34.1

Total Additions Excluding Mergers and Acquisitions 64.6 67.8 5.0

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System), except for environmental capital

expenditures, which came from company filings of Securities and Exchange Commission Form 10-K.

Table 5. Additions to Investment in Place by Line of Business for FRS Companies, 

 2001-2002

 b

Additions to investment in place = additions to property, plant, and equipment, plus additions to investments and advances.

 -- = Not meaningful.

 Note: Sum of components may not equal total due to independent rounding. Percent changes were calculated from unrounded 

data.

 aThe Petroleum line of business includes natural gas operations.

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 17
Among the geographic regions, the U.S. onshore continued to be the most popular upstream target 

(Figure 5), though spending for exploration and development was down 17 percent. Cutbacks were 

widespread, with 16 companies reducing exploration and development expenditures. A clear exception 

to this development was Devon. More than 95 percent of Devon’s total oil and natural gas production 

comes from the western United States, the Gulf of Mexico, and western Canada, with about two-thirds 

of the production being natural gas.26 Devon completed its acquisition of Mitchell Energy in early 

2002,27 giving the company total proved oil and natural gas reserves of approximately two billion barrels 

of oil equivalent. 

0

5

10

15

20

25

30

U.S. 

Onshore

U.S.

Offshore

Europe Asia

Pacific

Africa Canada South 

America

FSU Mid East

Billion D

ollars

Proved acreage expenditures

Expenditures excluding proved acreage

Figure 5. Exploration and Development Expenditures by Region for FRS Companies, 1999-2002

 Note: In each quadruple of bars, the first bar depicts 1999, the second 2000, the third 2001, and the fourth 2002. 

Regions are in order of exploration and development expenditures, excluding proved acreage, in 2002. FSU = Former 

Soviet Union and Eastern Bloc countries.

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Offshore spending held steady, declining by only one percent between 2001 and 2002. However, 

companies reducing offshore spending outnumbered other offshore producers by two to one. Two of the 

largest participants in the Gulf of Mexico forged ahead with projects in 2002. Shell’s increased Gulf 

production levels in 2002 were driven by the expansion of production capacity at the Brutus platform.

28 

BP, the largest acreage holder in the deepwater Gulf, announced that it expects to spend at least $15 

billion over the next ten years on exploration, production, and development in the Gulf of Mexico, 

focusing primarily on drilling wells and developing already-discovered fields.29

The largest absolute regional cutback in expenditures excluding proved acreage was for Canadian 

upstream projects, which were down by $2.5 billion, or 37 percent. The cutbacks were concentrated 

among majors making significant acquisitions in recent years. ConocoPhillips announced a shift away 

from short-life, high-decline fields to longer-life, low-decline fields in Canada, with plans to reduce 

operating costs and sell more than $300 million worth of nonstrategic conventional properties.30 Devon 

acquired Anderson Exploration Ltd. in early 2002, which increased the relative importance of its 

Canadian operations: at year-end 2002, 36 percent of Devon’s proved reserves were in Canada.31 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 18
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 19

However, Devon recorded writedowns to its Canadian oil and gas properties in 2002 based on lower oil 

and natural gas prices.32 Anadarko began its operations in Canada in 2000 with the merger of Union 

Pacific Resources Group, Inc. (later named the RME Holding Company), and further expanded in 2001 

with the purchase of Berkley Petroleum Corporation. During 2002, however, Anadarko sold its heavy 

oil assets in eastern Alberta for about $160 million.33 In 2002, Apache made two acquisitions in Alberta, 

one from Burlington Resources for $26 million, and one from Canadian affiliates of ConocoPhillips for 

$60 million.34 However, the company also sold marginal properties for $7 million. To some extent, 

these companies were sorting out the assets that belong in their North American core before undertaking 

significant new projects. 

South America also registered a relatively steep 34-percent decline in exploration and development 

expenditures (excluding proved acreage). The political turmoil in Venezuela in the 2001 to 2002 period 

was probably key to this development. BP, however, was noticeable by its increased spending in South 

America. BP has been operating in Trinidad and Tobago since 1961 and has been spending there to 

expand production.35 For example, the company expects its natural gas production to increase from 1.2 

billion cubic feet (bcf) per day in 2002 to 2.0 bcf per day in 2003 to supply Atlantic LNG’s (in which 

BP has an interest) new liquefied natural gas production train, which was approved in 2003.36 BP has 

also been developing Trinidad’s Kapok Field, which is expected to deliver natural gas by 2003. 

Asian-Pacific projects drew the largest step up in spending in 2002 -- up $1.0 billion, or 22 percent, with 

two-thirds of the companies reporting higher spending (exclusive of purchases of proved acreage). 

Deepwater prospects oriented toward gas appeared to be favored targets. Companies noting projects in 

the region included ConocoPhillips, Exxon Mobil, Unocal, and ChevronTexaco. 

Exploration and development expenditures directed to Europe, almost entirely for the North Sea, were 

up $0.9 billion over the prior year. An increased commitment to North Sea projects may be surprising 

since some FRS companies have announced plans to reduce their North Sea holdings. The rationale 

given is that the North Sea is a mature oil and gas province with few large frontier properties. 

Nevertheless, on an overall basis, the FRS companies increased their spending on European prospects by 

19 percent in 2002. For example, ConocoPhillips (along with its partners) has developed and in 2002 

began natural gas production from the Hawksley field in the North Sea.37 ChevronTexaco, operator of 

the Alba Field in the North Sea, developed and in 2002 began production from the southern region of 

the field.38 Exxon Mobil has continued developing oil and natural gas resources in the North Sea, 

leading to the start of production in February 2003 from the Ringhorne platform, part of a $1.1-billion 

development located in the North Sea’s Norwegian sector.39 Exxon Mobil is the operator and sole 

owner of the project. Exxon Mobil is also developing two other projects in offshore Norway, which will 

produce both oil and natural gas. 

Africa continued to attract investment from the majors in 2002. Exploration and development 

expenditures were up 17 percent, or by $0.7 billion, in 2002. The bulk of the spending is for deepwater 

prospects off the coast of West Africa. Countries accounting for most of the active deepwater projects 

include Angola, Equatorial Guinea, and Nigeria. Notable projects in the region in 2002 include those of 

Exxon Mobil, Marathon, ChevronTexaco, and Amerada Hess. Exploration and development efforts in 

Africa also include projects in North Africa, mainly projects by Anadarko in Algeria and by Apache in 

Egypt. 

Expenditures in the countries of the Former Soviet Union region registered the steepest percentage 

increase, 60 percent, of all the regions shown in Figure 5. Most of the majors’ activity involves 
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 20

prospects in the Caspian Sea area, including those of ChevronTexaco, ConocoPhillips, and Unocal. 

Exxon Mobil has been developing oil reserves in the Sakhalin Island area, which is located north of 

Japan. 

The upstream mergers that were a prominent feature of the 1998 to 2001 period fell off in 2002, with 

two exceptions: in 2002, Devon Energy continued their acquisition spree of recent years by acquiring 

Mitchell Energy; and Phillips Petroleum and Conoco, Inc. (now ConocoPhillips) completed their 

merger, which had been announced in 2001. For a further exposition of the upstream mergers over this 

period, see the Highlight entitled “Upstream Merger Wave Ebbs” and Figure 6.) 

Upstream Merger Wave Ebbs 

Several mergers among the FRS survey respondents and acquisitions by FRS oil and gas producers 

(both non-vertically integrated and vertically integrated ones) occurred over the 1998 to 2002 period 

(see Figure 6 for a diagram of the upstream merger transactions during this period). Devon Energy 

emerged as the apparent leader in this series of mergers based on sheer number of major transactions 

they undertook. The recent wave of upstream mergers and acquisitions, however, may have ended in 

2001, as there were only three merger completions after that – Devon Energy’s acquisition of Mitchell 

Energy in January 200240, the completion of the ConocoPhillips’ merger in August 200241, and Devon 

Energy’s acquisition of Ocean Energy in February 200342. 

Some of the companies previously involved in significant upstream merger activity (other than 

ConocoPhillips and Devon) may have ceased their merger activity in order to address problems on their 

balance sheets. For example, some companies may have not wanted to further increase their level of 

debt or further dilute the value of a single share of their stock, depending on the degree to which they 

had used debt or equity financing in their previous merger transactions. As in other industries, other 

energy companies may merely be waiting for confirmation that economic activity has recovered from 

the events of 9/11, the aftermath, and subsequent economy-wide changes. 

Nonetheless, whatever the reasons, the wave of upstream merger and acquisition activity that 

characterized the FRS oil and gas producers in the late 1990’s appears to have paused in 2002, and 

continued to do so in 2003. 

Mergers Drive Increase in Refining/Marketing Capital Expenditures 

In contrast, in 2002, the bulk of capital expenditures reported by the FRS companies for U.S. refinery 

and marketing operations in 2001 and 2002 were for intra-FRS mergers and acquisitions. In 2001, 

Phillips Petroleum acquired Tosco while Valero acquired Ultramar Diamond Shamrock, two of BP’s 

Rocky Mountain refineries, and El Paso’s Corpus Christi refinery. In 2002, Phillips Petroleum acquired 

Conoco to form ConocoPhillips (Table 6). This acquisition included four refineries (566 million barrels 

per day (mmb/d) of crude distillation capacity) along with some related pipelines, terminals, and retail 

gasoline outlets. 
1/89

Figure 6. Recent Mergers Affecting FRS Oil and Gas Producers

1999 2000 2001 2002 2003

Santa Fe

Occidental

8/02

Conoco

Gulf Canada Resources

Phillips

Conoco

*

*

*

*

*

*

Occidental

5/01

*Indicates company was an FRS respondent in the nearest year; i.e., a star to the left of a company name indicates that 

company was an FRS company in 1998 (in the case of SOHIO, this company was a respondent in 1989 when it was 

acquired by BP). Alternatively, if the star is to the right of the company, then it was an FRS respondent in 2002.

Footnote and source notes are at the bottom of the third page of the genealogy figures.

*

*

ConocoPhillips

*

*

* 4/00

4/99

1/99 Snyder

PennzEnergy

12/98

BP America

BP

Amoco

ARCO

BP America

Seagull

SOHIO

BP America

Devon

Mitchell Energy

6/99

10/01

Devon

1/99

6/00

Devon

Santa Fe Snyder

Devon

Devon

Ocean Energy

Ocean Energy

4/03

Anderson Exploration

1/02

Devon

(ARCO Long Beach and Altura Energya)

1/89

Figure 6. Recent Mergers Affecting FRS Oil and Gas Producers

1999 2000 2001 2002 2003

Santa Fe

Occidental

8/02

Conoco

Gulf Canada Resources

Phillips

Conoco

Occidental

8/02

Conoco

Gulf Canada Resources

Phillips

Conoco

*

*

*

*

*

*

Occidental

5/01

*Indicates company was an FRS respondent in the nearest year; i.e., a star to the left of a company name indicates that 

company was an FRS company in 1998 (in the case of SOHIO, this company was a respondent in 1989 when it was 

acquired by BP). Alternatively, if the star is to the right of the company, then it was an FRS respondent in 2002.

Footnote and source notes are at the bottom of the third page of the genealogy figures.

*

*

ConocoPhillips

*

*

* 4/00

4/99

1/99 Snyder

PennzEnergy

12/98

BP America

BP

Amoco

ARCO

BP America

Seagull

SOHIO

BP America

Devon

Mitchell Energy

6/99

10/01

Devon

1/99

6/00

Devon

Santa Fe Snyder

Devon

Devon

Ocean Energy

Ocean Energy

4/03

Anderson Exploration

1/02

Devon

(ARCO Long Beach and Altura Energya)

4/99

1/99 Snyder

PennzEnergy

12/98

BP America

BP

Amoco

ARCO

BP America

Seagull

SOHIO

BP America

Devon

Mitchell Energy

6/99

10/01

Devon

1/99

6/00

Devon

Santa Fe Snyder

Devon

Devon

Ocean Energy

Ocean Energy

4/03

Anderson Exploration

1/02

Devon

(ARCO Long Beach and Altura Energya)

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 21
Figure 6. Recent Mergers Affecting FRS Oil and Gas Producers (continued)

1999 2000 2001 2002 2003

*

*

*

*Indicates company was an FRS respondent in the nearest year; i.e., a star to the left of a company name indicates that

company was an FRS company in 1998. Alternatively, if the star is to the right of the company, then it was an FRS 

respondent in 2002.

Footnotes and source notes are at the bottom of the third and fourth pages of the genealogy figures.

*

*

*

7/01

Triton Energy

8/01

Kerr-McGee

HS Resources

Kerr-McGee

El Paso

Coastal El Paso

Amerada Hess

Amerada Hess

*

Exxon

Exxon Mobil

*

*

*

*

Mobil

12/98

10/99

*

Texaco

ChevronTexaco

*

* Chevron

10/01

Sonat

El Paso

Williams

Barrett Resources

*

5/01

Williams

1/01

7/01

Velvet Exploration

1999 2000 2001 2002 2003

*

*

*

*Indicates company was an FRS respondent in the nearest year; i.e., a star to the left of a company name indicates that

company was an FRS company in 1998. Alternatively, if the star is to the right of the company, then it was an FRS 

respondent in 2002.

Footnotes and source notes are at the bottom of the third and fourth pages of the genealogy figures.

*

*

*

7/01

Triton Energy

8/01

Kerr-McGee

HS Resources

Kerr-McGee

El Paso

Coastal El Paso

Amerada Hess

Amerada Hess

*

Exxon

Exxon Mobil

*

*

*

*

Mobil

12/98

10/99

*

Texaco

ChevronTexaco

*

* Chevron

10/01

Sonat

El Paso

Williams

Barrett Resources

*

5/01

Williams

1/01

7/01

Velvet Exploration

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 22
Figure 6. Recent Mergers Affecting FRS Oil and Gas Producers (continued)

*Indicates company was an FRS respondent in the nearest year; i.e., a star to the left of a company name

indicates that company was an FRS company in 1998. Alternatively, if the star is to the right of the

company, then it was an FRS respondent in 2002.

aOccidental acquired control of Altura Energy, a limited partnership owned by BP Amoco and Royal

Dutch/Shell (through Shell Oil) at approximately the same time as it acquired ARCO Long Beach. Altura

Energy was the largest oil producer in the state of Texas at the time of the transaction. See Energy

Information Administration, “Aspects of Occidental Petroleum’s Purchase of Altura Energy and ARCO

Long Beach” (April 18, 2000). This is available on the Internet at

http://www.eia.doe.gov/emeu/finance/mergers/oxyindex.html (as of November 28, 2003).

Sources: Company news releases and other public disclosures.

*

*

1999 2000 2001 2002 2003

Dominion

Louis Dreyfus Natural Gas

*

10/01

Dominion

*

Andarko

Union Pacific Resources

Andark

*

o 7/00

Figure 6. Recent Mergers Affecting FRS Oil and Gas Producers (continued)

*Indicates company was an FRS respondent in the nearest year; i.e., a star to the left of a company name

indicates that company was an FRS company in 1998. Alternatively, if the star is to the right of the

company, then it was an FRS respondent in 2002.

aOccidental acquired control of Altura Energy, a limited partnership owned by BP Amoco and Royal

Dutch/Shell (through Shell Oil) at approximately the same time as it acquired ARCO Long Beach. Altura

Energy was the largest oil producer in the state of Texas at the time of the transaction. See Energy

Information Administration, “Aspects of Occidental Petroleum’s Purchase of Altura Energy and ARCO

Long Beach” (April 18, 2000). This is available on the Internet at

http://www.eia.doe.gov/emeu/finance/mergers/oxyindex.html (as of November 28, 2003).

Sources: Company news releases and other public disclosures.

*

*

1999 2000 2001 2002 2003

Dominion

Louis Dreyfus Natural Gas

*

10/01

Dominion

*

Andarko

Union Pacific Resources

Andark

*

o 7/00

The other large intra-FRS deal in 2002 was a consequence of Chevron’s merger with Texaco in 2001, 

which was also an intra-FRS transaction. Among other requirements for approval of the merger, the 

Federal Trade Commission (FTC) required the sale of Texaco’s ownership interest in Equilon 

Enterprises and Motiva Enterprises. Equilon was formed in January 1998 as a 56/44 percent joint 

venture of Shell Oil and Texaco, which combined the companies’ downstream petroleum assets in the 

western United States. Motiva began operation in July 1998 as a joint venture of Shell Oil (35 percent), 

Texaco (32.5 percent), and Saudi Aramco (32.5 percent). This joint venture combined the companies’ 

downstream petroleum assets in the Midwestern and eastern United States. In February 2002, the FTC 

approved Shell Oil’s acquisition of Texaco’s ownership share of Equilon and about 48 percent of 

Texaco’s ownership interest in Motiva with Saudi Aramco acquiring the remainder. Subsequent to these 

transactions, Equilon became a part of Shell Oil’s consolidated operations and no longer exists as a 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 23
separate entity. This means that Equilon’s operations continue to be included in the FRS aggregate data 

but as part of Shell Oil. Motiva continues as a separate enterprise reporting to the FRS. 

The increase in refining/marketing capital expenditures is larger than it would have been had several 

FRS companies not merged. This is because before a merger occurs, assets are carried on a company’s 

books at their purchase prices (less the DD&A reductions that were taken over a number of years). 

However, since mergers involve the selling of assets from an acquired company to the newly merged 

entity, these same assets, after a merger, are carried on the newly merged entity’s books at new purchase 

prices, before the DD&A process begins anew on the books of the newly merged entity. 

Line of Business and 

Acquiring Company Merger or Acquisition

Reported Value

of Acquisition 

ConocoPhillips Merger of Phillips and Conoco 16,000

Shell Oil

Acquisition of remaining 50% interest in Equilon 

 and 13.5% interest in Motiva 3,100

Tesoro Valero’s Golden Eagle Refinery (California) 923

Marathon Interests in Equatorial Guinea from CMS Energy 993

Burlington Resources Canadian assets from ATCO 349

Conoco Remaining 28 percent of Gulf Indonesia 327

Marathon Globex Energy (Equatorial Guinea) 155

Occidental Petroleum Pakistan properties 72

Devon Mitchell Energy & Development 4,816

Unocal Remaining 35% interest in Pure Oil 410

XTO Rocky Mountain properties 354

Anadarko Howell Corporation 311

Apache Lousiana properties from Cartex Energy 259

El Paso Tension leg platform, Gulf of Mexico 190

Burlington Resources Producing properties in Texas 141

Shell Oil Pennzoil Quaker State 2,900

Dominion Resources Cove Point LNG Partnership 225

Other Energy

Dominion Resources Mirant State Line Ventures, Inc. 185

 Sources: Company annual reports to shareholders and press releases.

Table 6. Value of Mergers, Acquisitions, and Related Transactions by FRS Companies, 2002

 (Million Dollars)

Mergers and Acquisitions between FRS Companies

U.S. Oil and Natural Gas Production

Refining, Marketing, and Transport

Foreign Oil and Natural Gas Production

Other Acquisitions by FRS Companies

Although most of the capital expenditures for U.S. refining came from companies involved in mergers 

and acquisitions, other FRS refiners showed an increased commitment to these operations in 2002. This 

latter group of companies increased their capital expenditures for U.S. refining from $2.9 billon in 2001 

to $4.8 billion in 2002. The increased spending was apparently for refinery upgrades and enhancements 

rather than expansion, in that the group’s crude distribution capacity fell one percent from the prior year. 

The FRS asset base in refining increased, part of which was due to an accounting change regarding 

Citgo’s Lemont, Illinois refinery.43 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 24

Projects noted by those FRS refiners not involved in mergers and acquisitions in 2002 include Exxon 

Mobil and ChevronTexaco. Exxon Mobil reported a $2.45-billion (6 percent) increase over 2001 in 
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 25

downstream capital expenditures to meet low-sulfur fuel requirements, in addition to cogeneration 

projects underway at several refineries.44 ChevronTexaco finished upgrades at its El Segundo, 

California refinery to produce gasoline meeting environmental requirements without the use of the 

oxygenated blending component methyl tertiary butyl ether (MTBE), and continued construction on a 

project at the Pascagoula, Louisiana refinery to produce lower-sulfur motor gasoline and diesel.45 

The FRS companies trimmed their capital expenditures for U.S. petroleum marketing operations sharply 

in 2002, from $5.6 billion in 2001 to $1.9 billion. In large part, this decline was due to fewer marketing 

assets in the mergers and acquisitions of 2002 compared to 2001. Even excluding mergers and 

acquisitions, the FRS companies’ capital expenditures for petroleum marketing were down by $1.0 

billion, a decline of over 30 percent. 

The FRS companies’ reduced financial commitment was reflected in their ownership of major gasoline 

outlets as direct-supplied branded motor gasoline outlets fell from 54,085 in 2001 to 46,561 in 2002. 

Nevertheless, some companies reported positive activity in gasoline marketing in 2002. For example, 

Amerada Hess added 25 “Hess Express” convenience stores and Exxon Mobil added 180 new “On the 

Run” convenience stores.46 

Abroad, FRS companies’ interest in downstream petroleum operations appeared to increase in 2002. 

The companies’ consolidated refining capacity outside the United States was 5,642 thousand barrels per 

day (mb/d), up from 5,572 mb/d in 2001 (Table B28). Further, their capital expenditures for foreign 

refining/marketing operations increased by 400 million dollars between 2001 and 2002 (Table 5). 

However, these two developments present an overly positive view of the FRS companies’ commitment 

to downstream petroleum operations abroad. 

The increase in refining capacity was largely the result of a reorganization by BP plc, the British parent 

of the FRS respondent BP America, rather than investment in new capacity. Beginning in 2002, BP 

America’s consolidated operations include Australian refineries in Bulwer Island (69.8 mb/d of 

capacity)47 and Kwinana (158.5 mb/d of capacity)48. Excluding these two refineries, the FRS 

companies’ foreign refinery capacity is 5,414 mb/d. 

The big jump in capital expenditures is attributable to Phillips Petroleum’s acquisition of Conoco in 

2002. This transaction added over $3 billion in foreign downstream petroleum assets to the balance 

sheet of ConocoPhillips, the merged entity. However, the transaction simply shifted assets within the 

FRS group but resulted in no expansion of capacity. The effect on foreign refining/marketing capital 

expenditures reported in Table 5 is less than $3 billion since plant and equipment are just parts of total 

assets but still large. Excluding the effects of mergers and acquisitions, the FRS companies’ capital 

expenditures for foreign refining/marketing operations was down one percent between 2001 and 2002. 

Despite the drop in expenditures, upgrading of foreign downstream capacity was evident in 2002. For 

example, in 2002 Exxon Mobil completed the integration of its refineries in Port Jerome-Gravenchon 

(France) and the integration of its refinery/chemical complexes in Singapore.49 Likewise, 

ChevronTexaco upgraded its refineries in Pembroke (UK) and Nerefco (Netherlands) to produce fuel 

meeting the new sulfur specifications.50 
Other Energy No Longer a Source of Corporate Growth 

Until 2002, the other energy line of business was a source of corporate growth for a minority of the FRS 

companies. However, in 2002, other energy capital expenditures fell 27 percent relative to 2001, 

reaching a level of $3.7 billion (Table 5). Even though the other energy line of business, excluding 

unusual items, still contributed positively to net income, this line of business suffered from the postEnron flight from energy trading in electricity. (For additional details on the post-Enron collapse, see 

the section entitled “The Demise of Energy Trading Impacts Financial Results” in Chapter 1.) 

More specifically, electricity generation projects seemed to be the primary focus of 2002 capital 

expenditures by FRS companies. For example, Exxon Mobil was expanding its generation capacity at 

the Black Point Power Station in Hong Kong.51 Dominion Resources purchased a 515-megawatt plant 

in Indiana and completed construction on three power generation units in Pennsylvania, Ohio, and West 

Virginia.52 BP America is constructing a 570-megawatt cogeneration plant at its Texas City refinery.53 

Sources and Uses of Cash 

In 2002, the FRS companies faced a number of problems in their deployment of capital (Table 7). Cash 

flow generated by company operations was $15 billion lower than the year before, largely stemming 

from poor financial results in downstream petroleum. Energy companies’ balance sheets were being 

scrutinized more intensively by investors due to the collapse in energy trading and revelations of 

accounting irregularities following the demise of the Enron Corporation in late 2001. The general 

responses of the FRS companies were to cut back on outlays and reduce their amount of debt financing. 

 (Billion Dollars)

Sources and Uses of Cash 2001 2002

Percent Change

2001-2002

 Cash Flow from Operations 89.6 75.0 -16.4

 Proceeds from Long-Term Debt 55.0 34.1 -38.0

 Proceeds from Disposals of Assets 7.7 14.3 86.3

 Proceeds from Equity Security Offerings 6.3 4.9 -22.2

 Additions to Investment in Place 110.4 98.0 -11.2

 Reductions in Long-Term Debt 34.3 27.9 -18.7

 Dividends to Shareholders 17.1 17.7 3.6

 Purchase of Treasury Stock 7.5 4.7 -37.4

Other Investment and Financing Activities, Net 11.9 23.1 93.2

Net Change in Cash and Cash Equivalents 1.3 3.0 136.6

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Main Sources of Cash 

Main Uses of Cash 

Table 7. Sources and Uses of Cash for FRS Companies, 2001-2002

 Note: Sources minus uses plus other investment and financing activities (net) may not equal net change in cash and 

cash equivalents due to independent rounding.

 Percent changes were calculated from unrounded data.

The largest outlay is for capital expenditures (measured as additions to investment in place). The FRS 

companies reduced their capital expenditures by $12 billion to $98 billion in 2002. The reduction was 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 26
accomplished through a respite from mergers and acquisitions, which had been at record levels in 2000 

and 2001, and cutbacks in expenditures for projects outside oil and gas production. Total capital 

expenditures in 2002 for lines of business outside oil and gas production, excluding mergers and 

acquisitions, were 27 percent below expenditures in 2001. 

The cutbacks were widespread and reductions in capital expenditures in excess of $1 billion were 

common among companies with recent mergers and acquisitions. Two of the companies involved in 

energy trading, El Paso and Williams Companies, reduced their capital expenditures by nearly 50

percent. The only companies that increased their capital expenditures by more than $1 billion between 

2001 and 2002 were ConocoPhillips, with the purchase of Conoco by Phillips for $16 billion, Shell Oil, 

with its acquisition of Pennzoil Quaker State and interests in Equilon and Motiva, and Exxon Mobil. 

Other outlays subject to cuts were expenditures to reduce long-term debt, down 19 percent between 

2001 and 2002, and purchases of treasury stock, down 37 percent. The only outlay that was not cut was 

cash dividends to shareholders. Dividend payouts typically show modest year-to-year increases. Also, 

the anticipation of favorable tax treatment of dividends made companies reluctant to reduce dividends in 

2002. 

The greater attention by investors to energy company balance sheets discouraged the use of debt 

financing. The FRS companies issued $34 billion in long-term debt in 2002, a 38-percent reduction 

from the $55 billion raised in the prior year. Even if the fallout from energy trading and accounting 

irregularities had not occurred, the FRS companies still would have shown a reduction in debt financing 

due to the reduced level of merger and acquisition activity in 2002. 

Despite the emphasis on reducing the role of debt in companies’ balance sheets, the FRS companies’ 

ratio of long-term debt to stockholders’ equity (a summary measure of the importance of long-term debt 

in a company’s balance sheet) rose in 2002 (Figure 7). The apparent rise in long-term debt was the 

result of several companies reclassifying short-term debt as long-term debt and Shell Oil’s assumption 

of debt in its acquisition of Pennzoil Quaker State and its remaining interests in Equilon. 

Cash raised through the sale of assets by the FRS companies increased from $8 billion in 2001 to $14 

billion in 2002. Asset sales by the companies most involved in energy trading increased from $1 billion 

to $3 billion. However, companies with recent mergers and acquisitions accounted for most of the asset 

sales as they sorted out acquired assets that they determined were not integral to their core businesses. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 27

0

10

20

30

40

50

60

70

80

90

1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

Percent

S&P Industrials

FRS Companies

 Sources: FRS Companies: Energy Information Administration Form EIA-28, (Financial Reporting System). 

S&P Industrials: Compustat PC Plus, a service of Standard and Poor's.

Figure 7. Long-Term Debt/Equity Ratio for FRS Companies and the S&P Industrials, 1974-2002
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 28

 

Endnotes 

10For a list of the FRS companies in 2002, see the box entitled, “The FRS Companies in 2002,” in Chapter 1. 11Return on equity, a frequently used measure of corporate profitability, is measured by the ratio of net income to 

stockholders’ equity. 

12The Standard and Poor's (S&P) Industrials is a well-recognized database that includes nearly 400 of the largest U.S. 

industrial companies. Financial statistics for the S&P Industrials were obtained by accessing Compustat PC Plus, a service of 

Standard & Poor's, Inc. 

13Energy Information Administration, Performance Profiles of Major Energy Producers 2001, DOE/EIA-0206(01) 

(Washington, DC, January 2002), p. 53. 

14Line-of-business profit measures should be distinguished from measures that reflect company-wide results because the 

former reflect only allocated income, expense, and asset items. Two measures of income are presented: operating income 

and contribution to net income. Operating income by line of business is similar in concept to the operating income measure 

for total company operations. It is the net of operating revenues and operating expenses (including depreciation, depletion, 

and amortization) for a line of business. Contribution to net income equals operating income plus income from 

unconsolidated affiliates and gains on disposals of property, plant, and equipment less income taxes imputed to the line of 

business and excludes certain non-allocable items, primarily interest expense. Interest expense is the principal source of 

difference between a company-wide net income figure and line-of-business contributions to net income (see Appendix A for 

further discussion). 

15Return on investment is net income divided by net investment in place, which is net property, plant, and equipment plus 

year-end balance for investments and advances to unconsolidated affiliates. 

16Energy Information Administration, Monthly Energy Review, (DOE/EIA-0035 (2003/11)) (Washington, DC, November 

2003), Table 9-11. 

17ChevronTexaco Corporation 2002 Annual Report, pp. 36-37. 18El Paso Coporation 2002 Securities and Exchange Commission Form 10-K, pp. 61-65. 

19For FRS purposes, separate reporting of income for chemical and other nonenergy segments was discontinued beginning 

with the 1987 reporting year. However, the disclosures of chemical segment revenues and operating income made by the 

FRS companies in their annual reports to shareholders closely track, in the aggregate, comparable disclosures in the Form 

EIA-28 from 1974 through 1986, when income statement items were collected for chemical businesses by the FRS. Thus, 

the public disclosures of chemical segment revenue and operating income were utilized for 1987 through 2002. Revenues 

and operating income for the other nonenergy segment after the 1986 reporting year were obtained by subtracting the 

publicly disclosed chemical segment values from the nonenergy line-of-business values reported on Form EIA-28. 20Exxon Mobil Corporation 2002 Securities and Exchange Commission Form 10-K, p. 29. 

21Exxon Mobil Corporation, 2002 Financial and Operating Review, p. 77. 22Energy Information Administration, Performance Profiles of Major Energy Producers 2001, DOE/EIA-0206(2001) 

(Washington, DC, January 2003), p. 81. 

23Exxon Mobil Corporation, press release (November 13, 2002). 

24The largest of these non-cash items is the cost of depreciation, depletion, and amortization. Also, outlays (receipts) of cash

that were recognized as non-cash items in previous income statements (e.g., provisions for a legal settlement taken as a 

charge against income in a previous year but not actually paid until the current year) are subtracted from (added to) net 

income in computing cash flow. Lastly, changes in working capital (excluding cash) due to operations are subtracted. 

25To the extent possible, capital expenditures are measured by additions to investment in place, which is defined as additions 

to property, plant, and equipment (PP&E) plus additions to investments and advances. In 2002, additions to PP&E accounted 

for 92 percent of capital expenditures so measured. 

26Devon Energy Corporation 2002 Annual Report, p. 14. 27Devon Energy Corporation, press release (January 24, 2002). 

28Royal Dutch/Shell, press release (October 31, 2002). 

29BP, press release (August 2, 2002). 

30ConocoPhillips 2002 Annual Report, pp. 13-15. 31Devon Energy Corporation 2002 Securities and Exchange Commission Form 10-K, p.19. 32Devon Energy Corporation 2002 Securities and Exchange Commission Form 10-K, p.47. 33Anadarko Petroleum Corporation 2002 Securities and Exchange Commission Form 10-K, p.14. 34Apache Corporation 2002 Securities and Exchange Commission Form 10-K, p. 4, F16. 

35BP November 2003 discussion on: Upstream Build Projects.” Web address: http://www.eia.doe.gov/perfpro/ref_pi/fig5.gif. 36 Two other trains that were approved earlier have yet to begin full operations, although one began deliveries in August 

2002. Atlantic LNG, Company Website (at Hhttp://www.atlanticlng.comH) train2_3.php3 (as of 1/14/2004). 
Energy Information Administration/Performance Profiles of Major Energy Producers 2002 29

 37ConocoPhillips, press release (September 23, 2002). 38ChevronTexaco Corporation, press release (October 1, 2002). 

39Exxon Mobil Corporation, press release (February 11, 2003). 

40Devon Energy Corporation, press release (January 24, 2002). 

41ConocoPhillips Company, press release (August 30, 2002). 

42Devon Energy Corporation, press release (April 25, 2003). 

43CITGO Petroleum Corporation 2002 Securities and Exchange Commission Form 10-K, p. 2. 

44Exxon Mobil Corporation, 2002 Financial and Operating Review, pp. 63, 66. 45ChevronTexaco Corporation, 2002 Supplement to the Annual Report, p. 40. 46Exxon Mobil Corporation, 2002 Annual Report, p. 17. 47The Oil and Gas Journal, Volume 100, Number 52 (December 23, 2002), p.72. 48The Oil and Gas Journal, Volume 100, Number 52 (December 23, 2002), p.72. 

49Exxon Mobil Corporation, 2002 Financial and Operating Review, p. 65. 50ChevronTexaco Corporation, 2002 Supplement to the Annual Report, p. 40. 51Exxon Mobil Corporation, 2002 Financial and Operating Review, pp. 31 and 40. 52Dominion Resources, Inc., 2002 Annual Report, pp. 13 and 63. 53BP plc, Annual Report on Form 20-F 2002, p. 43. 

3. Behind the Bottom Line 

Upstream Income 

The oil and gas production operations of the FRS companies in the United States fared worse in 

financial performance in 2002 than did the companies’ foreign operations. Net income from U.S. oil 

and gas production, excluding unusual items, totaled $16.2 billion in 2002, a 21-percent decline from

prior-year results (Table 8). Foreign upstream operations registered a much smaller 2-percent decline. 

The difference in financial results is largely traceable to changes in revenues in 2002. 

Revenues from U.S. upstream operations declined almost $8 billion, largely due to lower natural gas 

revenues (Table 8). The realized natural gas prices of the FRS companies averaged $3.07 per thousand 

cubic feet (Mcf) in 2002, a decline of 90 cents, or 23 percent, from the average price realized in 2001 

(Table 9). This decline was less than the drop in the overall U.S. wellhead price of $1.07 per Mcf. A 

contributing factor may be due to the FRS companies having some success in hedging their natural gas 

prices, or it may be that the FRS companies sold more of their natural gas when prices were higher. 

(EIA’s average U.S. wellhead price excludes the effects of price hedges.) Nevertheless, the lower 

natural gas price more than offset the 10-percent increase in the FRS companies’ U.S. upstream natural 

gas sales volumes. 

Domestic oil revenues declined slightly between 2001 and 2002, as a 2-percent increase in FRS 

companies’ average U.S. wellhead price (domestic production average sales price) was more than offset 

a by a 4-percent drop in sales volumes (Table 9). Foreign oil production was up one percent as 

increased production from Canada, Africa, and South America more that offset lower North Sea and 

Former Soviet Union and Eastern Europe production. 

The decline in domestic natural gas revenues was partially offset by lower operating expenses in 2002 

(Table 8). Operating expenses were lower, in part, because the FRS companies’ U.S. crude oil and 

natural gas production levels were each down 1 percent (Table 9). More important was the nearly $2-

billion decline in depreciation, depletion, and amortization (DD&A) between 2001 and 2002. DD&A 

was unusually high in 2001, up by $7 billion from the prior year, because of writedowns of oil and gas 

assets. As noted in the previous edition of this report (Performance Profiles of Major Energy Producers 

2001, January 2003): 

“In 2001, the FRS companies charged $5.3 billion against pre-tax income for asset writedowns in 

U.S. oil and gas production operations and $2.7 billion in foreign upstream operations. Asset 

writedowns are usually included in depreciation, depletion, and amortization (DD&A). Higher 

expenses for DD&A were the main sources of increased operating costs in the FRS companies’ 

upstream operations between 2000 and 2001.”54

Foreign upstream revenues of the FRS companies were less affected by lower natural gas prices in 2002. 

Natural gas is a smaller share of foreign oil and gas production than domestically, 42 percent vs. 54 

percent, respectively, on an energy-equivalent basis. Accordingly, the impact of lower gas prices on 

foreign upstream revenues is less than on domestic upstream revenues. Also, the fall in domestic natural 

gas prices was much steeper than the fall in foreign prices in 2002 (Table 9). This decline more than 

offset higher oil and gas production and higher crude oil prices. Natural gas production from foreign 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 31
2001 2002 2001 2002 2001 2002

Oil and Natural Gas Revenues

 Oil NA NA 31.6 30.9 NA NA

 Natural Gas NA NA 47.4 40.2 NA NA

 Total Revenues 141.7 132.5 79.0 71.1 62.7 61.4

Expenses

 Depreciation, Depletion, and Amortization 32.2 32.8 20.0 18.3 12.1 14.6

 Lifting Costs 24.7 25.1 12.9 12.5 11.8 12.6

 Exploration Expenses 5.2 4.7 3.0 3.1 2.2 1.5

 General and Administrative Expenses 2.7 2.6 1.9 1.7 0.8 0.9

 Raw Material Purchases 21.9 15.8 16.1 12.5 5.8 3.3

 Other Costs (Revenues) 4.9 10.6 -0.2 3.8 5.1 6.8

Total Operating Expenses 91.2 91.1 53.3 51.4 37.9 39.7

Operating Income 50.5 41.5 25.7 19.7 24.8 21.7

Other Income (Expense)a 4.8 4.8 1.6 1.6 3.2 3.2

Income Tax Expense 23.1 18.3 9.6 6.3 13.4 12.0

Net Income 32.2 27.9 17.6 15.0 14.6 12.9

Less Unusual Items -4.5 -4.0 -3.0 -1.2 -1.5 -2.8

Net Income, Excluding Unusual Items 36.7 32.0 20.6 16.2 16.1 15.7

Unit Values (Dollars Per Barrel of Production COE)b 

Direct Lifting Costs (Excluding Taxes) 3.49 3.58 3.53 3.56 3.45 3.60

 Production Taxes 0.78 0.67 0.85 0.75 0.70 0.59

Ratios (Percent)

 Return on Investmentc 12.2 9.9 13.1 10.5 11.2 9.2

 Effective Tax Rated 41.7 39.9 35.3 29.7 48.0 48.6

Table 8. Income Components and Financial Ratios in Oil and Natural Gas Production 

 for FRS Companies, 2001-2002

 (Billion Dollars)

 Note: Sum of components may not equal total due to independent rounding.

 NA = Not available.

 cNet Income divided by net investment in place (Net investment in place = net property, plant, and equipment plus investments and 

advances). dIncome tax expense divided by pretax income.

 aEarnings of unconsolidated affiliates and gain (loss) on disposition of assets. b

COE = Crude oil equivalent. Dry natural gas was converted at 0.178 barrels of oil per thousand cubic feet.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Components of Income and Financial Ratios Worldwide United States Foreign

fields was up 11 percent between 2001 and 2002 vs. a 1-percent decline in the United States (Figures 8a 

and 8b). 

The bulk of the increased foreign natural gas production was from Canada and Asia-Pacific locales. 

Canadian natural gas production increased 24 percent, with some of the companies that made 

acquisitions of Canadian producers in recent years (Devon Energy and Burlington Resources) 

accounting for most of the increase. The 17-percent increase in the FRS companies’ Asia-Pacific 

natural gas production largely came from Exxon Mobil and, to a lesser extent, from ChevronTexaco. 

Exxon Mobil’s 2002 production in Indonesia rebounded from a low in 2001 that had resulted from a 

shutdown in onshore operations “due to civil unrest,”55 while ChevronTexaco’s production in the 

Philippines grew because 2002 was its first full year of operation there.56 Other regions registering 

notable increases in natural gas production were South America and Africa, as well as companies active 

in deepwater production off the west coast of Africa. South American natural gas production was up 16 

percent, largely due to increased production from BP’s Amherstia field in Trinidad-Tobago in order to 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 32
supply a second liquefied natural gas train there.57 African natural gas production was also up, by 37 

percent, largely due to BP’s increased production from the Temsah field in Egypt,58 and Marathon Oil’s 

initiation of production in Equatorial Guinea.59 

Prices, Sales, and Production 2001 2002

Percent Change

2001-2002

Worldwide Oil and Gas Productiona 

 Crude Oil and NGL (Million Barrels) 3,087 3,093 0.2

 Dry Natural Gas (Billion Cubic Feet) 15,148 15,747 4.0

 Total (Million Barrels COE)b 5,784 5,896 1.9

Domestic Oil and Gas Productiona 

 Crude Oil and NGL (Million Barrels) 1,363 1,346 -1.2

 Dry Natural Gas (Billion Cubic Feet) 8,838 8,713 -1.4

 Total (Million Barrels COE)b 2,936 2,897 -1.3

Domestic Oil and Gas Sales Volumes 

 Crude Oil and NGL (Million Barrels) 1,498 1,433 -4.3

 Dry Natural Gas (Billion Cubic Feet) 11,957 13,109 9.6

 Total (Million Barrels COE)b 3,626 3,766 3.9

Domestic Production Average Sales Prices 

 Crude Oil and NGL (Dollars Per Barrel) 21.11 21.59 2.3

 Dry Natural Gas (Dollars Per Thousand Cubic Feet) 3.96 3.07 -22.6

 Composite (Dollars Per Barrel COE)b 21.79 18.89 -13.3

Foreign Oil and Gas Productiona 

 Crude Oil and NGL (Million Barrels) 1,724 1,747 1.3

 Dry Natural Gas (Billion Cubic Feet) 6,310 7,034 11.5

 Total (Million Barrels COE)b 2,847 2,999 5.3

Foreign Production Average Sales Prices 

 Crude Oil and NGL (Dollars Per Barrel) 22.04 23.05 4.6

 Dry Natural Gas (Dollars Per Thousand Cubic Feet) 2.91 2.54 -12.8

 Canada 3.63 2.68 -26.1

 OECD Europe 3.18 2.93 -8.0

 Other Foreign 2.25 2.33 3.6

 Composite (Dollars Per Barrel COE)b 19.97 19.38 -2.9

 b

COE = Crude oil equivalent. Dry natural gas was converted at 0.178 barrels of crude oil per thousand cubic feet.

 Sources: Energy Information Administration, Form EIA-28 (Financial Reporting System). Foreign production segment per unit sales

values were compiled from information in FRS companies' filings of Securities and Exchange Commission Form 10-K, annual reports

to shareholders, and supplements to annual reports.

Table 9. Average Prices, Sales, and Production in Oil and Natural Gas for FRS Companies,

 2001-2002

 aProduction is on a net ownership basis. Sales are domestic production segment sales. See Appendix A for discussion of FRS

reporting conventions.

Lifting costs decreased $0.4 billion in the United States but increased $0.8 billion abroad (Table 8). The 

decrease in the United States occurred because oil and gas production (Table 9) and production taxes per 

barrel fell, while the increase abroad resulted from increased oil and gas production and increased lifting 

costs per barrel, excluding production taxes. The next section of this chapter reviews lifting costs in 

more detail. 

Lifting Costs Little Changed -- Production Taxes Decline 

Worldwide lifting costs (including taxes) changed little in 2002, with a small decline in the United 

States offsetting a small increase in foreign regions (Table 10). Over the long term, lifting costs 

declined very slightly between 1994 and 2002, after declining faster in the early years of the 1990’s 

(Figure 9). [Lifting costs (also called production costs) are the per barrel costs of producing oil and 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 33
0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

1981 1984 1987 1990 1993 1996 1999 2002

Million Barrels

Source: Energy Information Administration, Form EIA-28, (Financial Reporting System).

 Foreign

Figure 8a. Oil Production for FRS Companies, 1981-2002

Offshore

Onshore

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

1981 1984 1987 1990 1993 1996 1999 2002

Billion Cubic Feet

Source: Energy Information Administration, Form EIA-28, (Financial Reporting System).

 Foreign

Figure 8b. Natural Gas Production for FRS Companies, 1981-2002

Offshore

Onshore

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 34
natural gas (measured on a barrel-of-oil equivalent basis). They include the costs to operate and 

maintain wells and related equipment and facilities after hydrocarbons (both crude oil and natural gas) 

have been found and/or acquired, and developed for production.] These per barrel costs include 

depreciation costs for capital equipment and facilities used in production. Total lifting costs are direct 

lifting costs plus production taxes. 

2001 2002

Percent 

Change 2001 2002

Percent 

Change 2001 2002

Percent 

Change

United States

 Onshore -- -- -- -- -- -- 5.19 5.02 -3

 Offshore -- -- -- -- -- -- 2.93 2.93 0.0

 Total United States 3.53 3.56 0.7 0.85 0.75 -11.5 4.39 4.32 -1.6

Foreign

 Canada 3.92 4.07 3.8 0.22 0.19 -13.8 4.14 4.26 2.9

 OECD Europe 3.51 3.54 1.1 0.66 0.52 -20.3 4.16 4.07 -2.3

 Former Soviet Union and

 Eastern Europe 3.85 3.21 -16.6 0.89 0.00 -100.0 4.74 3.21 -32.3

 Africa 3.58 4.23 18.3 1.20 0.92 -22.9 4.77 5.15 8.0

 Middle East 3.05 3.78 24.1 0.41 0.35 -15.9 3.46 4.12 19.3

 Other Eastern Hemisphere 3.21 3.27 1.8 0.88 0.72 -17.4 4.09 4.00 -2.3

 Other Western Hemisphere 2.75 2.57 -6.7 0.66 1.12 70.7 3.41 3.69 8.2

 Total Foreign 3.45 3.60 4.6 0.70 0.59 -14.8 4.14 4.20 1.3

 Worldwide Total 3.49 3.58 2.6 0.78 0.67 -13.3 4.27 4.26 -0.3

 Source: Energy Information Administration, Form EIA-28, (Financial Reporting System).

Table 10. Lifting Costs by Region for FRS Companies, 2001-2002 

 (Dollars Per Barrel of Crude Oil Equivalent)

 -- = Data not available.

 Note: Sum of components may not add to total due to independent rounding.

Region

Direct Lifting Costs Production Taxes Total

.3

One of the most notable changes in lifting costs in 2002 was the decline in both domestic and foreign 

production taxes (Table 10).60 Production taxes increased only in the Other Western Hemisphere region 

(primarily Latin America), which experienced a fairly large increase.61 In the United States, production 

taxes (also called severance taxes) are largely levied by State governments, largely against production in 

the U.S. Onshore and usually in the form of a percent of the value of the oil and gas produced.62 In the 

first half of the 1980’s, domestic production taxes per barrel-of-oil equivalent (boe) for the FRS 

companies fell sharply from their 1981 high of $10 per boe (in real 2002 dollars), reflecting in large part 

a substantial decline in crude oil prices and, to a lesser extent, natural gas prices over that period (Figure 

10). However, in 2000 and 2001, when crude oil and natural gas prices reached highs not seen since the 

mid-1980’s, domestic production taxes remained below $1 per boe. 

One reason that domestic production taxes for the FRS companies did not respond more dramatically to 

increased prices in 2000 and 2001 is the movement of domestic production from onshore to offshore. In 

1985, 31 percent of the FRS companies’ domestic oil and gas production (on a boe basis) came from the 

Offshore region. By 2002, production from the Offshore reached 51 percent of the domestic total. 

Since production from Federal Offshore areas is not subject to State severance taxes, the share of 

production exposed to severance taxes for the FRS companies has been falling. Inexplicably, production 

taxes paid by the FRS companies on foreign production, which is subject to multiple tax schemes, have 

historically moved in tandem with domestic production taxes (Figure 10).63

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 35
0

1

2

3

4

5

6

7

8

1981 1984 1987 1990 1993 1996 1999 2002

Constant Dollars (2002) per BOE

United States

Foreign

Note: Direct lifting costs are the costs of extracting oil and gas, excluding production taxes.

BOE = Barrels of crude oil equivalent.

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 9. Direct Oil and Gas Lifting Costs for FRS Companies, 1981-2002

0.00

2.00

4.00

6.00

8.00

10.00

1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

Constant Dollars (2002) per BOE

Domestic

Foreign

Note: Foreign production taxes include royalty payments while domestic production taxes do not.

BOE = Barrels of crude oil equivalent.

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 10. Production Taxes for FRS Companies, 1974-2002

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 36
The small decline in worldwide production taxes was offset by an increase in per barrel direct lifting 

costs in 2002 (Table 10). Africa was the largest contributor to the increase in worldwide direct lifting 

costs. This is because production by the FRS companies in Africa increased only 6 percent, while total 

expenditures on production (excluding production taxes) increased 25 percent, which resulted in an 18-

percent increase in direct lifting costs. Worldwide direct lifting costs of the FRS companies also were 

notably influenced by increases in Canada and the Middle East, but because of relatively less production 

there, were not as significant as those of Africa.64 

One cause of higher direct lifting costs can be a decline in oil and gas production, with fixed costs 

spread over less production. Another possible cause of higher lifting costs is related to the launching of 

new projects, such as bringing new production online or initiating enhanced recovery programs, which 

often have higher costs initially. 

With an increase of 15 percent, Canada led all regions for increased production in 2002 (Table B25). 

Production in Africa also increased, by 3 percent, while production in the Middle East declined slightly. 

In contrast, the Other Western Hemisphere was the only region making a substantial contribution to

lower worldwide direct lifting costs; oil and gas production there grew twice as fast as direct production 

spending. 

While 2002 worldwide total lifting costs (i.e., direct lifting costs plus production taxes) were virtually 

unchanged, although the Middle East region and the Former Soviet Union and East Europe region had 

relatively large changes in total lifting costs in 2002. In the Middle East, production taxes declined, and 

an increase in direct lifting costs was the only cause of the increase in total lifting costs. In contrast, the 

Former Soviet Union and East Europe was the only region to exhibit a decline in both direct lifting costs 

and production taxes, which resulted in a large relative decline in total lifting costs for the region. The 

FRS companies have just begun substantial production in the Former Soviet Union and East Europe, 

with production there much less than in any other region. Increased production at established projects 

also may lead to falling lifting costs because fixed costs are spread over more production. 

U.S. Refining and Marketing 

Profitability of U.S. Refining/Marketing Operations Lowest in Survey History 

The results of 2002 established a new record as the most unprofitable year for the FRS companies’ 

refining/marketing operations in the 26-year history of the FRS. These disappointing results came after 

a 6-year period of almost continuously increasing profitability, which had resulted in returns from the 

FRS domestic refining/marketing operations becoming competitive with all other lines of business 

(Figure 11) and was referred to just a year ago as a “sort of ‘golden age’ of U.S. refining and 

marketing.”65 

In addition, perhaps one of the most unsettling aspects of the historical losses reported in 2002 is that 

they came on the heels of the second-most profitable year in the history of the FRS. Thus, in view of the 

apparently tenuous nature of profitability gains in this line of business, it appears that the urgency of the 

ongoing cost-cutting efforts that characterized the domestic refining/marketing operations of the FRS 

companies throughout the 1990’s will continue unabated through this decade. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 37
The change in the profitability of U.S. refining/marketing operations can easily be explored by 

examining the net refined product margin (net margin), which is highly correlated with profitability.66

The net margin is the gross margin (refined product revenues minus purchases of raw materials input to 

refining and refined product purchases) minus out-of-pocket operating costs per barrel of refined 

product sold. The net margin measures before-tax cash earnings from the production and sale of refined 

products.67 The $0.19 per barrel net margin of 2002 was the lowest since 1984 (when the net margin, 

after adjusting for inflation, was $0.01 per barrel) and the second lowest in the history of the FRS 

(Figure 12), barely surpassing the $0.21 per barrel (also adjusted for inflation) achieved in 1987. 

-5

0

5

10

15

20

25

30

1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

Percent

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 11. Return on Investment in U.S. and Foreign Refining/Marketing, and All Other Lines of

 Business for FRS Companies, 1980-2002

U.S. A Refining/Marketing ll Other Lines of Business

Foreign

Refining/Marketing

Lower Product Prices Reduce Product Sales Revenue

The 7-percent decline in petroleum product sales revenues (Table 11) was partially due to lower prices 

received, which fell 4 percent in 2002 compared to 2001 (Table 12). Declines in the average price 

received for motor gasoline (falling 6 percent) and distillate (falling 8 percent) were somewhat offset by 

small gains (6 percent) in the average price for other petroleum products. Revenue from other sources 

(e.g., non-petroleum sales at convenience stores) also fell while operating cost increased slightly. The 

combination was disastrous and resulted in an operating loss of $1.5 billion and a net loss of $2.2 billion 

($1.0 billion excluding unusual items). 

Economic growth (2.4 percent), cooler winter weather (2.2 percent more heating degree-days), and 

warmer summer weather (11 percent more cooling degree-days) in 2002 compared to 200168

ameliorated the downward trend in prices. However, these factors were insufficient to overwhelm the 

dampening effect of unusually high end-of-2001 product stock levels (and continuing through the first 

part of 2002) brought on by events in 2001, including the worldwide economic downturn and the 

impacts of the terrorist attacks of 9/11. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 38
0

2

4

6

8

10

12

14

1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

2002 Dollars per Barrel

 Figure 12. U.S. Refined Product Margins and Costs per Barrel of Petroleum Product Sold

 for FRS Companies, 1980-2002

 Note: The gross margin is refined product revenues less raw material cost and product purchases divided by refined product

sales volume.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Net Margin

Operating Costs

Gross Margin

2001 2002

Percent

Change

2001 - 2002

Domestic Refining/Marketing Operations

 Refined Product Sales Revenue 291,609 272,190 -6.7

 Other Revenuea 19,301 16,600 -14.0

 Operating Expensea, b 294,536 290,282 -1.4

 Operating Incomeb 16,374 -1,492 -109.1

 Net Income, excluding unusual Items 12,829 -1,011 -107.9

 Unusual Items -878 -1,153 --

 Net Income 11,951 -2,164 -118.1

Foreign Refining/Marketing Operations

 Refined Product Sales Revenue 142,949 142,227 -0.5

 Other Revenuea 14,249 6,300 -55.8

 Operating Expensea, b 152,420 147,298 -3.4

 Operating Incomeb 4,778 1,229 -74.3

 Net Income, excluding unusual Items 3,239 564 -82.6

 Unusual Items -124 -112 --

 Net Income 3,115 452 -85.5

Table 11. U.S. and Foreign Refining/Marketing Financial Items for

 FRS Companies, 2001-2002

 (Million Dollars)

 aRaw materials revenues are netted against total operating expense. bExcludes unusual items.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

 -- = Not meaningful.

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 39
2001 2002

Percent

Change

2001-2002

Refined Product Sales (Million Barrels per Day) 23.6 23.0 -2.5

Gasoline Average Price 36.96 34.87 -5.6

Distillate Average Price 32.96 30.49 -7.5

Other Products Average Price 26.30 27.81 5.8

All Refined Products Average Price 33.88 32.43 -4.3

Less: Raw Materials Costs and Product Purchases 26.07 26.16 0.3

Equals: Gross Refining Margin 7.81 6.27 -19.7

Less: Direct Operating Costs 5.09 6.08 19.5

Equals: Net Refining Margina 2.72 0.19 -93.0

Reseller/wholesaler spread (dealer price - wholesale price) 3.05 2.32 -24.1

Retailer spread (company-operated price - dealer price) 3.16 4.27 35.1

Table 12. Sales, Prices, Costs, and Margins in U.S. Refining/Marketing for FRS Companies, 

 2001-2002

(Nominal Dollars per Barrel)

a

See Appendix B, Table B32, for the components to calculate the refined product margin.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Industry-wide petroleum product stocks were 9 percent higher in 2002 than in 2001 over the first 

quarter, falling to 4 percent over the second quarter and 2 percent over the third quarter (Figure 13), 

which exerted substantial (and declining) downward pressure on petroleum product prices compared to a 

year earlier.69 Industry-wide stocks of motor gasoline also were higher during the first part of 2002 

compared to 2001, but were much more similar to the average over the period of 1996 through 2000 

(Figure 14) than was the case for petroleum products in general. The accompanying decline in motor 

gasoline prices received by the FRS companies also was somewhat smaller at 6 percent. 

Lower Product Sales Magnify Downward Pressure on Revenue 

The downward pressure on revenues created by lower product prices was magnified by lower product 

sales in 2002 relative to 2001. Sales fell a relatively slight 0.6 million barrels per day against the 2001 

level of almost 24 million barrels for a 3-percent decline in 2002 relative to 2001 (Table 12), largely due 

to a 12-percent decline in the sales of the amorphous category of “other products” (i.e., petroleum

products other than motor gasoline and distillate) (Table 13). Motor gasoline sales were essentially flat 

while distillate sales fell a slight 2 percent. Thus, sales of the more highly valued products did little to 

offset the effects of the product price declines. 

Meanwhile, refinery capacity reported by the FRS companies fell slightly (less than 1 percent) 70 (Table 

14) as small expansions in the capacity of many refineries largely offset Precor’s closing of its Hartford, 

Illinois refinery in October 200271 and BP’s sale of its Yorktown, Virginia refinery to Giant Industries.72 

A few intra-FRS transactions (all of which occurred during 2002) shifted assets around among the FRS 

companies. For example, Tesoro acquired Valero’s Golden Eagle refinery,

73 Shell purchased Texaco’s 

share of Equilon and subsequently consolidated the Equilon assets,74 and Phillips acquired Conoco via 

merger.

75 Additionally, all of these transactions contributed to the 25-percent increase in net investment 

in place between 2002 and 2001. This is because an asset is carried on a company’s books at its 

purchase price less the depreciation, depletion, and amortization (DD&A) reductions taken over a 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 40
number of years, but then, when sold, this same asset is carried on the new owner’s books at the new 

purchase price, before the DD&A process begins anew with the purchasing company. Further, 

upgrading of refineries continued to occur during 200276 and also contributed to the increase. 

580

600

620

640

660

680

700

720

First Quarter Second Quarter Third Quarter Fourth Quarter

Million of Barrels

1996-2000 Average

2001

2002

0

Figure 13. Quarterly U.S. Commercial Petroleum Product Stocks, 1996-2000 Average, 2001, and 2002

 Source: Energy Information Administration, Petroleum Supply Monthly , DOE/EIA-0109 (Various issues, Washington, DC),

Table 51.

145

150

155

160

165

170

First Quarter Second Quarter Third Quarter Fourth Quarter

Millions of Barrels

0

 1996-2000 Average

 Source: Energy Information Administration, Petroleum Supply Monthly , DOE/EIA-0109 (Various issues, Washington, DC),

Table 51.

Figure 14. Quarterly U.S. Motor Gasoline Stocks, 1996-2000 Average, 2001, and 2002

 2002 

 2001

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 41
2001 2002

Percent

Change

2001 - 2002

Gross Margin 7.81 6.27 -19.7

- Marketing Costs 1.59 1.57 -1.1

- Energy Costs 1.32 1.21 -8.4

- Other Operating Costs 2.19 3.31 51.2

= Net Margin 2.72 0.19 -93.0

Product Sales Volume

Motor Gasoline 12,435 12,469 0.3

Distillate 6,958 6,822 -2.0

Other Products 4,185 3,701 -11.6

Total 23,579 22,991 -2.5

Table 13. U.S. Refined Product Margins and Costs per

 Barrel Sold and Product Sales Volume for 

 FRS Companies, 2001-2002

(Dollars per Barrel)

(Million Barrels)

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting 

System).

2001 2002

Percent

Change 

2001-2002

U.S. Refining Additions to Investment in Place 12.1 15.1 25.1

U.S. Marketing Additions to Investment in Place 7.2 3.8 -47.4

Foreign Refining/Marketing Additions to Investment in Place 4.6 5.0 9.7

U.S. Refining Capacity 14,682 14,557 -0.9

U.S. Refinery Output 14,936 14,676 -1.7

Foreign Refining Capacity 5,572 5,642 1.3

Foreign Refinery Output 4,766 4,873 2.2

U.S. Refinery Utilization Rate1 95.2 91.0 (2)

Foreign Refinery Utilization Rate1 83.9 85.2 (2)

 1Refinery utilization rate is calculated by dividing runs to stills at own refineries by the average of the year beginning and year ending 

crude oil distillation capacity. 2

Not meaningful.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table 14. U.S. and Foreign Refining Investment and Operating Items for FRS

 Companies, 2001-2002

(Billion Dollars)

(Thousand Barrels per Day)

(Percent)

Gross Margin Squeezed As Product Prices Fall

Industry-wide gross refining margins in 2002 were consistently lower than in 2001 for almost the entire 

year and fluctuated around the average level for the 1996 to 2000 period (Figure 15) throughout the 

year. Only over the last quarter of 2002 (when the gross margin collapsed) was the gross refining 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 42
margin similar to 2001. Higher motor gasoline stocks than a year ago (Figure 14) and higher petroleum

product stocks in general (Figure 13) put downward pressure on the industry-wide gross margins. 

Meanwhile, U.S. crude oil stock levels were at historically high levels during the first half of 2002 

before consistently falling over the latter half of the year (Figure 16), resulting in an increase in the price 

of crude oil77 and putting downward pressure on the gross margin. The overall effect of these (and other) 

effects was that the industry-wide gross refining margin of 2002 averaged $8.05 per barrel, a 31–percent 

decline relative to the 2001 average of $11.59 per barrel. 

Meanwhile, the gross refining margin received by the FRS companies fell a lesser 20 percent compared 

to 2001 (Table 13). The average price received for petroleum products declined $1.45 per barrel (4 

percent) while raw materials and purchased product costs rose $0.09 per barrel (less than 1 percent), 

which resulted in a $1.54 per barrel decline in the gross refining margin.78 

Successful efforts to increase the complexity of the FRS refineries over the last several years79 allow the 

FRS companies to refine a wide range of crude oils, which has enabled them to use relatively low-cost 

heavy crude oils and transform them into relatively more higher-priced, light products. However, during 

2002 the price of heavy crude relative to light crude increased (Figure 17), which put less downward 

pressure on the price of crude oil paid by the FRS companies and contributed to the slight increase in the 

raw materials and purchased product costs of the FRS companies. Similarly, the price of light products 

(represented by the price of motor gasoline) fell relative to the price of heavy products (represented by 

the price of residual fuel oil), which tended to increase the downward pressure on the prices of refined 

products of the FRS companies (Figure 18). Thus, the revenue side of the net margin was substantially 

lower in 2002 than in 2001. We will next examine the cost side of the net margin. 

Operating Costs Rise Despite Lower Energy and Marketing Costs

A closer look at the operating costs that distinguish the gross margin from the net margin indicates that 

these costs increased 20 percent, but hardly at a uniform rate across the different types of costs (Table 

13). Efforts over the last few years by the FRS companies to reduce their energy costs appeared to bear 

fruit in 2002 as energy costs fell $0.11 per barrel, an 8-percent reduction from their 2001 level. 

Cogeneration projects are one of the major approaches that these companies have taken to reducing their 

energy costs over the last few years.80 

However, continued retrenchment of marketing operations through both selective investment in outlets 

in profitable areas and sales of marginal outlets and of outlets in marginal areas81 was less successful in 

2002 as marketing costs fell $0.02 per barrel, a 1-percent decline. The decline in marketing costs 

occurred despite extensive cost increases due to several companies re-branding their marketing outlets.82 

However, branded marketing outlets directly-supplied by the FRS companies continued to decline in 

2002 (Figure 19), falling to 46,561 (14 percent less than the 54,085 reported in 2001 (Table 15)) and 

indicative of the FRS companies’ efforts to increase the profitability of this line of business by shifting 

to wholesale and direct sales.83 Company-operated outlets were reduced by slightly more than 14 

percent while dealer outlets were reduced by slightly less than 14 percent. These efforts to eliminate 

marginal outlets resulted in increased productivity as the average monthly volume through all directsupplied FRS branded outlets increased 7 percent between 2001 and 2002, with all of the increase 

achieved through dealer outlets. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 43
0

2

4

6

8

10

12

14

16

18

20

January March May July September November

2002 Dollars per Barrel

 Note: The U.S. gross refined product margin is the difference between the composite wholesale product price and the 

composite refiner acquisition cost of crude oil. 

 Sources: Energy Information Administration, Petroleum Marketing Monthly , DOE/EIA-0380 (April 1996 - March 2003), Table 

1, Table 4, and Table 5; and Energy Information Administration, Monthly Energy Review, DOE/EIA-0380 (February 1996 -

January 2003), Table 3-2b.

Figure 15. Monthly Gross Refined Product Margin for United States, 1996-2000 Average, 2001,

 and 2002

1996-2000 Average

2001 

 2002 

270

280

290

300

310

320

330

First Quarter Second Quarter Third Quarter Fourth Quarter

Millions of Barrels

0

1996-2000 Average

2002

2001

Figure 16. Quarterly U.S. Crude Oil Stocks, 1996-2000 Average, 2001, and 2002

 Source: Energy Information Administration, Petroleum Supply Monthly , DOE/EIA-0109 (Various issues,

 Washington, DC), Table 51.

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 44
0

5

10

15

20

25

30

1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

Dollars per Barrel (2002 Dollars)

 Note: Light crude oil tends to sell for a higher price per barrel than does heavy crude oil. Thus, the vertical distance of the 

line in the figure from the horizontal axis indicates the premium paid for light crude oil relative to heavy crude oil. The more 

expensive light crude oil is defined here as having an API gravity of 40.1 or greater and heavy crude oil is defined as having 

an API gravity of 20 or less.

 Source: Energy Information Administration, Petroleum Marketing Monthly , DOE/EIA-0380, Tables 27 and 28.

Figure 17. Real Price Difference Between Light Crude Oil and Heavy Crude Oil, 1978-2002

0

5

10

15

20

25

30

35

1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002

Dollars per barrel (2002 dollars) Figure 18. Real Resale Price Difference Between Motor Gasoline and Residual Fuel Oil, 1978-2002

 Note: Motor gasoline tends to sell for a higher price per barrel than does residual fuel oil. Thus, the vertical distance of the

line in the figure from the horizontal axis indicates the premium paid for motor gasolinel relative to residual fuel oil.

 Source: Energy Information Administration, Petroleum Marketing Monthly , DOE/EIA-0380, Table 4.

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 45
0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Outlets

Figure 19. Company-Operated and Dealer Outlets for FRS Companies, 1984-2002

 *The addition of 11 companies to the group of U.S. majors in 1998, the largest single-year change in the history of the Financial 

Reporting System, resulting in the vertical displacement of the series in 1998.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

*

Company-Operated Outlets

Dealer Outlets

*

2001 2002

Percent 

Change 

2001-2002

Third-Party Volume

Wholesale 1,955.8 2,032.4 3.9

Retail

Dealer 1,182.1 1,133.4 -4.1

Company-Operated 545.1 464.3 -14.8

Total Retail 1,727.3 1,597.6 -7.5

Direct 777.0 819.8 5.5

Total Third-Party Volume 4,460.1 4,449.8 -0.2

Intersegment Volume 78.8 101.4 28.7

Dealer Outlets 42,705 36,816 -13.8

Company-Operated Outlets 11,380 9,745 -14.4

Total Retail Outlets 54,085 46,561 -13.9

Average Monthly Outlet Volume

 Dealers 96.9 107.7 11.2

 Company-Operated 167.7 166.7 -0.6

 All Direct-Supplied Outlets 111.8 120.1 7.4

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table 15. Motor Gasoline Distribution and Number of Direct-Supplied Branded

 Outlets for FRS Companies, 2001-2002

(Million Barrels)

(Number of Direct-Supplied Branded 

Outlets)

(Thousand Gallons per Month)

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 46
Productivity increases, though, were offset by a substantial increase during 2002 in other operating costs 

related to refining, which rose by $1.12 per barrel (51 percent) relative to 2001. However, the change 

was largely due to data reported by one of the respondents. Removal of that company from this 

particular calculation would eliminate more than half of the apparent FRS change in refining-related 

operating costs between 2001 and 2002. Additionally, the FRS companies involved in recent mergers 

have somewhat elevated the cost structure of the FRS companies as the surviving companies merge their 

operations and corporate cultures. Further, environmental spending to comply with the Clean Air Act 

Amendments of 1990 continues, accounting for some increase in other operating costs. (Although we 

have no estimate of the significance of the environmental spending within 2002 other operating costs, a 

recent study examined these for the 1995 to 2001 period and is summarized in the Highlight entitled, 

“Environmental Compliance Partially Eclipses Recent Gains in Profitability.”)

In summary, despite the profits of recent years, the year 2002 saw the lowest level of profits for 

refiner/marketers in the history of the FRS. The net margin was reduced in 2002 by a falling gross 

margin (and revenues), a circumstance that was worsened by higher operating costs, which played a 

large role in the losses experienced in 2002. Nonetheless, reduced energy and marketing costs in 2002 

relative to 2001 may give hope for the future domestic refining/marketing results of the FRS companies 

because cost-cutting efforts by these companies over the last several years suggest that they have 

reorganized (and continue to fine tune) their operations to better withstand the vicissitudes of their 

industry. 

Environmental Compliance Partially Eclipses Recent Gains in Profitability 

The effect of environmental legislation on profitability over the 1995 to 2001 period is explored through 

two avenues in a recent EIA study (The Impact of Environmental Compliance Costs on U.S. Refining 

Profitability, 1995 – 2001a): operating costs, and capital expenditures and depreciation charges. This 

study updates earlier work that examined the apparent effects of environmental compliance on 

refining/marketing operations’ operating costs and capital expenditures (including depreciation charges) 

over the 1988 to 1995 period.b 

The profitabilityc of the FRS companies’ U.S. refining/marketing operations increased from

approximately zero in 1995 to more than 14 percent in 2001 (Figure 11). An investigation of the 

reasons for increased profitability are complicated by tax and other considerations that affect net income

and the investment base. However, a more straightforward approach for an examination of profitability 

changes is available. 

The net margin is also closely related to refining/marketing profitability. Figure 20 shows that when 

cash earnings per barrel sold (net refined product margin adjusted for price changes) are low, so is 

refining/marketing profitability (return on investment). The correlation between profitability (measured 

by return on net investment in place) and the net margin is 0.93,d which is highly significant by the usual 

statistical conventions. 

The net refining margin (net margin) is refined product revenue minus purchases of raw material inputs 

to refining and refined product purchases (gross margin) less out-of-pocket operating costs per barrel of 

refined products sold. The net margin represents the before-tax cash earnings from production and sale 

of refined products and excludes ancillary activities such as non-fuel sales from convenience stores. The 

net margin is an important determinant of short-term decisions in refining operations. Basically, for a 

given scale and configuration of a refinery, output will tend to be expanded as long as the added output 

contributes to cash earnings. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 47
The increase in the net margin over the 1995 to 2001 period was due to both an increase in the gross 

margin and a reduction in operating costs. The gross margin increased over the 1995 to 2001 period 

(Figure 12) as low product stocks (especially in 2000 and 2001) led to higher product prices and the 

increasing sophistication of the FRS companies’ refineriese allowed the companies to take advantage of 

price differences between light and heavy crude oil (Figure 17), lowering their raw materials costs. 

Meanwhile, operating costs generally declined. The FRS companies routinely noted various cost-cutting 

efforts in their public disclosures for the 1995 to 2001 period (i.e., annual reports and Securities and 

Exchange Commission Form 10-K filings). Although energy costs actually increased over the period, 

reductions in other costs more than offset these increases (Table 16). Among these were environmental 

operating costs, which declined $0.15 per barrel (30 percent) due to increased familiarity with the 

production of reformulated fuels and the increased scale of production. Marketing costs were even more 

significant to the increased net margin as they fell $0.36 per barrel (19 percent) due to the increased use 

of lower-cost motor gasoline distribution channels (i.e., wholesale and direct sales) and the decreased 

use of higher-cost motor gasoline distribution channels (i.e., directly supplied company-operated and 

dealer-operated outlet sales). Lastly, and most important, was the reduction in other refining costs, 

which fell $0.44 per barrel (19 percent) due to cost-cutting efforts such as holding lower stock levels, as 

cited by numerous FRS companies. Thus, one of the reasons for the growth in profitability of U.S. 

refining/marketing was lower environmental operating costs, but it was hardly the major reason as it was 

surpassed by marketing costs and other operating costs in terms of the nominal change.f 

The asset base used to generate the cash earnings discussed above must also be examined. Capital 

expenditures and depreciation charges attributable to environmental requirements are also part of the 

profitability calculation. Capital spending by the FRS companies, which had steadily declined between 

1995 and 1997, surged in 1998 as 11 non-vertically integrated refiners were added to the FRS group. 

Capital spending continued to increase following 1998 largely due to mergers and acquisitions (Figure 

21). (Excluding mergers and acquisitions, FRS capital spending has been essentially flat at $3.6 billion 

annually between 1998 and 2001.) Capital spending for environmental compliance fluctuated through 

the 1990’s and early 2000’s ahead of deadlines established by the Clean Air Act Amendments of 1990

(CAAA90). The amount of capital investment by the FRS companies was considerably less after 1995 

than earlier. The effects of this change were twofold: depreciation for environmentally-related assets 

declined from $745 million (in 2001 dollars) in 1995 to $673 million in 2001; and the share of fixed 

assets accounted for by environmental investments declined (Figure 22) from 38 percent in 1995 (having 

peaked at 47 percent a year earlier) to 9 percent in 2001. Thus, the asset base on which the income was 

earned grew more due to economic reasons and less due to environmental reasons during the 1995 to 

2001 period than had been the case during the 1991 to 1995 period. 

In summary, the financial effects (i.e., operating costs, depreciation charges, and investment) attributable 

to environmental compliance all diminished between 1995 and 2001, but have they returned to preCAAA90 levels? To address this issue, actual profitability was compared with profitability adjusted to 

remove the financial effects attributable to environmental compliance in order to determine the effect of

environmental compliance over the 1996 to 2001 period. The ratio of income (omitting environmentally 

related operating costs and depreciation) to net fixed assets (omitting the part of the investment base 

attributable to environmental requirements) is an accounting measure of profitability that excludes the 

financial effects of environmental requirements.g Operating income is used as the measure of income

for both measures of profitability for simplicity.h The average profitability over the 1996 to 2001 period 

was lower (Figure 23) (by 42 percent) than it would have been in the absence of environmental 

requirements, but it still exceeds the 32-percent reduction in profitability associated with environmental 

compliance over the pre-CAAA90 1988 to 1990 period. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 48
 

 

a

T See Energy Information Administration, The Impact of Environmental Compliance Costs on U.S. Refining Profitability, 

1995 – 2001 (Washington, DC, May 2003). This report can be found on the Internet at 

http://www.eia.doe.gov/emeu/perfpro/ref-pi2/index.html . b

 See Energy Information Administration, The Impact of Environmental Compliance Costs on U.S. Refining Profitability

(October 1997). This report can be found on the Internet at http://www.eia.doe.gov/emeu/perfpro/ref-pi/contents.html . c

 Profitability of lines of business of the FRS companies is computed by dividing the net income contributed by the line of 

business by the net investment in place associated with the line of business. More explicitly, net investment in place is the 

sum of year-end net property, plant, and equipment and year-end investments and advances to unconsolidated affiliates. d

 The results from the regression of the return on net investment in place (ROI) for domestic refining/marketing on the net

margin (in 2001 dollars) for all FRS refiners (i.e., those FRS companies having non-zero values for beginning and/or ending

refining capacity) for the years 1977 through 2001 are as follows: Multiple R = 0.934; R square = 0.872; adjusted R square = 

0.867; standard error of the regression = 1.440; and observations = 25. The estimated equation is: Domestic

refining/marketing ROI = -1.156 [0.651] + 5.514 [0.440] * net margin, where the standard errors of the estimated coefficients

are in brackets. 

e

 See, Energy Information Administration, Update of Tables and Figures from U.S. Petroleum Refining and Gasoline

Marketing Industry (Washington, DC, June 2002), Table 6. This is an Internet-only product and is located at

http://www.eia.doe.gov/emeu/finance/usi&to/downstream/update/index.html. f

 Percentage changes may be misleading because a large percentage can occur due of a large nominal change relative to a 

large base, or because of a small nominal change relative to a small base. Consequently, nominal changes are also presented 

and may take precedence over percentage changes when ascribing significance to factors. g

 However, this measure of profitability does not include any estimates of the impacts on energy market dynamics (including

9/11) that might have occurred in the absence of environmental requirements on the U.S. refining industry. h Were net income, the more traditional measure of income in profitability calculations, used instead of operating income, 

then the effects of environmental compliance on affiliate income, income taxes, and gains/losses from asset sales would all 

have to be estimated. These additional estimates are avoided by using operating income. Further, return on investment

calculated with net income is highly correlated with return on investment calculated with operating income. Consequently, 

the returns on investment that are compared use operating income in the calculation.

-4

-2

0

2

4

6

8

10

12

14

16

0 0.5 1 1.522.5

Return on Investment (Percent)

3

1977-1987

1988-2001

Regression Line

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 20. U.S. Refining/Marketing Return on Investment and Net Refined Product Margin

 for FRS Companies, 1977-2001

Net Refined Product Margin

(2001 dollars per barrel)

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 49
1988 1995 2001

Percent

Change

1995-2001

Average Refined Product Revenues 29.36 27.04 33.88 25.3

Raw material Acquisition Costs and 

Refined Product Purchases 20.05 20.87 26.04 24.8

Gross Margin 9.31 6.17 7.85 27.2

Energy Costs 1.45 0.92 1.37 49.3

Marketing Costs 2.14 1.95 1.59 -18.6

Environmental Operating Costs 0.36 0.49 0.34 -29.8

Other Refining Costs 2.94 2.26 1.82 -19.4

Net Refining Margin 2.43 0.55 2.72 397.0

Average Refined Product Revenues

Motor Gasoline 33.59 30.26 36.96 22.1

Distillate 27.59 24.70 32.96 33.4

Other Products 23.20 23.17 26.30 13.5

All Refined Products 29.36 27.04 33.88 25.3

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table 16. Components of the Gross Refining Margin and Average Refined Product 

 Revenues for FRS Companies, 1988, 1995, and 2001 

 (2001 dollars per barrel of refined product sold)

0

2

4

6

8

10

12

14

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Billions of 2001 Dollars

Total Capital Expenditures for U.S. Refining

Total Capital Expenditures Excluding M&A Related Expenditures*

Environmental Capital Expenditures

 1Reformulated motor gasoline.

 * Note that total capital expenditures excluding merger & acquisition related expenditures only cover the period 1995 

through 2001.

 Sources: U.S. refining capital expenditures - Energy Information Administration, Form EIA-28 (Financial Reporting System)

Environmental capital expenditures - 1990-1996: American Petroleum Institute, Petroleum Industry Environmental

Performance (Washington, DC, May 1997), pp. 47-48. 1997-2001: American Petroleum Institute, U.S. Oil and Natural Gas

Industry’s Environmental Expenditures (Washington, DC, February 2003), p. 9. FRS environmental capital expenditures are 

prorated by share of U.S. crude distillation capacity.

RFG1 Phase II,

Complex

RFG Emissions 1 Phase I,

Complex

Emissions

RFG1 Phase I,

Clean Air Act Simple Emissions

Amendments of

1990

Figure 21. U.S. Refining Capital Expenditures for FRS Companies, 1988-2001

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 50
0

10

20

30

40

50

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Percent

 Sources: U.S.refining capital expenditures - Energy Information Administration, Form EIA-28 (Financial Reporting System)

Environmental capital expenditures - 1988-1989: American Petroleum Institute, Petroleum Industry Environmental Performance 

(Washington, DC, May 1997), pp. 47-48 and U.S. Department of Commerce, Bureau of the Census, Pollution Abatement Costs and 

Expenditures (various issues) (Washington, D.C.). (Estimates of expenditures were made by applying the ratio of the American 

Petroleum Institute series to the corresponding Census series for the 1990-1994 overlap period to the Census values for 1988 and 

1989.) 1990-1996: American Petroleum Institute, Petroleum Industry Environmental Performance (Washington, DC, May 1997), pp.

47-48. 1997-2001: American Petroleum Institute, U.S. Oil and Natural Gas Industry’s Environmental Expenditures (Washington, DC,

February 2003), p. 9. FRS environmental capital expenditures are prorated by share of U.S. crude distillation capacity.

Figure 22. Environmental Capital Expenditures as a Share of U.S. Refining Capital 

 Expenditures for FRS Companies, 1988-2001

0

5

10

15

20

25

30

35

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Percent

Operating ROI excluding Financial Effects of Environmental Requirements

Actual Operating ROI

 Note: Operating Return on Investment (Actual Operating ROI) = operating income as a percent of net property, plant, and 

equipment (PP&E). Operating ROI excluding financial effects of environmental requirements = operating income less

environmental operating costs less environmental depreciation expenses as a percent of net PP&E less environmental net

PP&E.

 Sources: Energy Information Administration, Form EIA-28 (Financial Reporting System); American Petroleum Institute,

Petroleum Industry Environmental Performance (Washington, DC, May 1997); American Petroleum Institute, U.S. Oil and 

Natural Gas Industry’s Environmental Expenditures (Washington, DC, February 2003).

Figure 23. Operating Return on Investment in U.S. Refining/Marketing for FRS Companies, 

 1988-2001

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 51
Foreign Refining and Marketing 

Profitability of Foreign Refining/Marketing Operations At An All-Time Low 

In 2002, foreign refining/marketing return on net investment in place achieved an all-time low in the 26-

year history of the FRS at 1.3 percent, breaking the previous low of 3.3 percent in 1985 (Figure 11). A 

small reduction in refined product revenue relative to 2001 coupled with a 56-percent decline in other 

revenue and a 3-percent decline in operating expense resulted in a 86-percent decline in net income (83-

percent decline in net income exclusive of unusual items). 

The FRS companies’ foreign refining/marketing earnings are derived from two sources: unconsolidated 

affiliates and consolidated operations. The corporate parent of an unconsolidated affiliate owns 50

percent, or less, of the affiliate, and does not directly control the affiliate (a joint venture, for example is 

usually an unconsolidated affiliate from the perspective of at least one of the partners

84). Essentially, the 

unconsolidated affiliate is more of a property or holding of the parent corporation than it is a company 

that the parent actually operates. The effect on financial operations of an unconsolidated affiliate can 

only be seen on the parent corporation’s income statement, where the parent company’s proportional 

share of the affiliate’s net income is reported. Conversely, a fully consolidated affiliate is directly 

controlled by the parent corporation (although it could be owned by several companies, with the parent 

corporation owning more than 50 percent). In addition, all operating financial information about a fully 

consolidated affiliate (such as revenues) is reported in the public financial disclosures of the parent

corporation. 

Consolidated Operations Contribute to Net Income

Historically, the operations of the FRS companies’ unconsolidated foreign refining/marketing affiliates 

have been mainly in the Asia-Pacific region. ChevronTexaco owns much of the FRS Asia-Pacific 

refinery capacity, most of which is unconsolidated. In fact, about 69 percent of FRS unconsolidated 

foreign refinery capacity was in the Asia-Pacific region in both 2001 and 2002 (Table 17). 

Consolidated FRS foreign refinery capacity is mostly located in Europe, falling from 51 percent in 2001 

to 50 percent in 2002. The primary reason for the slight decline was BP’s re-assignment of two 

Australian refineries to its U.S. affiliate (an FRS respondent) in 2002,85 which increased the share of 

consolidated capacity in Asia and diminished it elsewhere, including Europe. 

The contribution to net income from the FRS companies’ unconsolidated foreign refining/marketing 

operations has been small for the last several years (since 1997) (Figure 24). However, in 2002, it 

reached an all-time low with a loss of $331 million (after a loss of $4 million in 2001). Alternatively, 

consolidated operations have consistently contributed more to the FRS companies’ foreign 

refining/marketing earnings than have unconsolidated operations over the last several years, particularly 

since 1996. More to the point, between 1990 and 1996, earnings from unconsolidated operations 

averaged 44 percent of the contribution from consolidated operations, peaking at 102 percent in 1996. 

Since then (over the 1997 to 2002 time period), unconsolidated operations' earnings have averaged 9 

percent of consolidated operations' earnings, reaching a nadir in 2002 by generating a loss, while 

consolidated operations generated income. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 52
The FRS companies gave several reasons for the disappointing performance of foreign 

refining/marketing. These included low margins due to excess refinery capacity and weak demand, 

lower refinery runs in response to low margins and due to refinery outages (which were due to a fire (El 

Paso)86 and an electrical outage (ConocoPhillips)87), and foreign exchange losses. 

2001 2002 2001 2002

Europe 51.0 50.0 18.0 17.9

Asia 25.0 29.0 68.6 68.7

Latin America 11.6 9.2 0.7 0.7

Canada 9.7 9.2 0.0 0.0

Other 2.7 2.6 12.7 12.7

Grand Total 100.0 100.0 100.0 100.0

Table 17. Regional Distribution of Foreign Refinery Capacity for

 FRS Companies, 2001-2002

 (Percent)

Consolidated Operations Unconsolidated Affiliates

 Note: The region denoted as "Other" includes Africa and the Middle East.

 Sources: Company Annual Reports and filings of U.S. Securities and Exchange Commission Form 10-K.

 

-1

0

1

2

3

4

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Billion 2002 Dollars

Figure 24. Foreign Refining/Marketing Net Income from Consolidated Operations and Unconsolidated 

 Affiliates of FRS Companies, 1990-2002

Consolidated Operations

Unconsolidated Affiliates

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Asian-Pacific Markets Continue Poor Performance 

During 2002, the FRS companies’ unconsolidated affiliates generated a loss of $331 million, which was 

a reduction of net income of $327 million relative to a $4-million loss in 2001. The Asian-Pacific 

refining margins of 2002 (represented by the Singapore/Dubai gross refining margin) were much lower 

than those of 2001 over the first half of 2002, but by the end of the year this circumstance had reversed 

with the fourth quarter refining margin of 2002 exceeding that of 2001 (Figure 25) by $3 per barrel. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 53
Nonetheless, despite the late rally, the gross refining margin in the Asian-Pacific region in 2002 

averaged $0.09 per barrel less than in 2001. 

Consumption of petroleum products in the Asia-Pacific region (combining Asian Developing Countries 

with Australasia and Japan) increased 2 percent between 2001 and 2002. However, the increased 

consumption was insufficient to prevent the FRS companies from reporting lower returns from their 

unconsolidated foreign refining/marketing operations, which are located in this region. Excess refining 

capacity and the recent relatively small growth of Asia-Pacific petroleum product consumption88 are 

reasons given in company public disclosures for the losses generated by the Asia-Pacific operations of 

the FRS companies. 

-4.00

-3.00

-2.00

-1.00

0.00

1.00

2.00

3.00

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Dollars per Barrel

Figure 25. Foreign Refining Margins, 2000-2002

 Sources: Energy Intelligence Group, Oil Market Intelligence 2000: January 2001 and July 2000, p. 12; 2001: January 2002 

and July 2001, p. 12; and 2002: January 2003 and July 2002, p. 12.

2000 2001

Annual Average 2000 2001 2002

Rotterdam/Brent -0.38 -1.16 -1.27

Singaport/Dubai 0.02 -0.76 -0.69

Rotterdam/Brent

Singapore/Dubai

 2002

European Markets Continue to Bolster Foreign Refining/Marketing Results 

The FRS companies’ consolidated operations (bottom line net income from foreign refining/marketing 

less income from unconsolidated affiliates) provided $783 million of net income, which was 75-percent 

lower than the $3.12 billion result achieved in 2001. Lower earnings were consistent with the decline in 

Europe’s consumption of petroleum products (Figure 26), which fell 1 percent between 2002 and 2001 

(and increased a scant 0.8 percent between 1997 and 2002). 

European refining margins (represented by the Rotterdam/Brent gross refining margin) were $1 to $2 

dollars per barrel lower during the first half of 2002 than during the first half of 2001 (Figure 25). 

However, they rallied in the second half of the year (much as they did in the Asia-Pacific region) and 

surpassed the 2001 margin in both the third and the fourth quarters of 2002. The ultimate result was that 

the average margin for 2002 was $0.07 per barrel greater than the average margin for 2001. Thus, the 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 54
industry-wide story of lower petroleum product consumption and a negligible increase in the refining 

margin provided a background for an equally dismal story for the FRS companies. Among the reasons 

cited in public disclosures for the FRS companies’ decline in earnings from their European operations 

were an electrical outage (and resulting diminished product sales), lower refining margins, lingering 

effects of the 9/11 events on product demand, and currency (foreign exchange) losses. 

0

5

10

15

20

25

North

America

OECD

Europe

FSU &

Eastern

Europe

Asian

Developing

Countries

Australia,

New Zealand

& Japan

Latin America Middle East Africa

Million Barrels per Day

1997 1998 1999 2000 2001 2002

 Source: BP plc, BP Statistical Review of World Energy (June 2003). p. 9.

 

Figure 26. Petroleum Consumption by Region, 1997-2002

Other Energy

The FRS “other energy” line of business consists of energy operations other than the production of oil, 

natural gas, or coal. This includes nonconventional energy operations such as synfuels and renewables, 

as well as assorted other activities including electric power production and supply, transportation of 

power, energy trading operations, and energy management services. Measured by asset growth, the 

other energy line of business has grown much faster in recent years than all other lines of business of the 

FRS companies (See Figure 27). This is equally true if revenues are used as a measure instead of assets. 

Revenue and Income Drop Due to Energy Trading Decline 

The story for the FRS companies’ other energy line of business since the mid-1990’s has been one of 

tremendous growth, followed by a dramatic reversal of that growth in 2001 and 2002. Much of the 

growth has been due to increased electric power generation and trading in both electricity and natural 

gas by the FRS companies. However, a decline in revenues and actual losses in earnings over the last 

two years has occurred largely due to the downturn in the energy trading business following the Enron 

financial scandal. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 55
From 1995 until 2000, the FRS companies’ revenues in other energy grew at a brisk annual rate (Figure 

27) of 127 percent. In 2001, revenues dropped 1.4 percent, as Enron ceased reporting to the FRS. By 

2002, the energy trading crash had spread across the energy industry, leading to a collapse in other 

energy revenues of 48 percent from the 2001 level (Table 18). The demise of El Paso’s trading 

business89 was the biggest cause of this. 

 

The income story is similar to the revenue story. Other energy income grew at a 74- percent annual rate 

over 1995 through 2000. In 2001, income dropped 27 percent over the 2000 level. In 2002, however, 

income collapsed 173 percent as earnings went negative, with much of the decline due to losses of El 

Paso and ChevronTexaco’s affiliate Dynegy Inc., which had also been active in energy trading.90

Nonconventional Energy: Tar Sands and Geothermal Stand Out 

Originally, the FRS “other energy” line of business was primarily intended to cover nonconventional 

energy, which includes renewable resources (such as wind, solar, and geothermal energy) and 

hydrocarbons from tar sands, oil shale, coal gasification and liquefaction, among other sources. 

Although nonconventional energy was the lion’s share of other energy until the mid-1990’s, the FRS 

companies’ forays into nonconventional energy were generally unprofitable, and most FRS companies 

started to scale back their investments in nonconventional energy during the 1980’s. 

Nonetheless, two nonconventional energy projects stand out: Exxon Mobil’s Canadian tar sands and the 

Unocal Corporation’s geothermal energy in Southeast Asia. Exxon Mobil significantly relies on 

production from tar sands, and has been extracting oil from Canadian tar sands since the 1970's. The 

company reports a year-end 2002 total of 800 million barrels of Canadian tar sand reserves, representing 

6.3 percent of its worldwide crude oil and natural gas liquids reserves.91 Gross synthetic crude oil 

produced from those tar sands was 84 million barrels in 2002, up from 80 million barrels in 2001.92

Unocal has over 35 years experience in geothermal energy. It operates major geothermal fields 

producing steam for electricity at Tiwi and Mak-Ban in the Philippines, and Gunung Salak and Wayang 

Windu in Indonesia. These four projects supply steam for a total of 1,120 megawatts of generating 

capacity.93 Unocal’s total 2002 geothermal energy production averaged 13 million kilowatt-hours, the 

equivalent of 20,000 barrels of oil per day, down from 22,000 barrels per day in 2001. Its net proved 

geothermal reserves at year-end 2002 were the equivalent of 232 million barrels of oil, compared to 162 

million barrels in 2000. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 56
0

100

200

300

400

500

600

700

800

900

1000

1995=100

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 27. Net Investment in Place in Other Energy and All Other Businesses for FRS Companies,

 1995-2002 

1995 1996 1997 1998 1999 2000 2001 2002

Other Energy

Other Lines of Business

 Income Components 2000 2001 2002

Percent Change

2001- 2002

Operating Revenue 84,987 83,811 43,243 -48.4

Operating Expenses 81,948 81,678 43,886 -46.3

 Operating Income 3,039 2,133 -643 -130.1

Equity Income 753 902 -563 -162.4

Net Income 2,741 1,993 -1,460 -173.3

 unusual items 0 8 -133 --

Net Income excluding unusual items 2,741 1,985 -1,327 -166.9

(Million Dollars)

Table 18. Income Components for Other Energy for FRS Companies, 2000-2002

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 57
End Notes 

 

54 Energy Information Administration, Performance Profiles of Major Energy Producers 2001, DOE/EIA-0206(01)

(Washington, DC, January 2003), p. 34. 55 Exxon Mobil, 2002 Financial & Operating Review, p, 55 and 2001 Financial and Operating Review, p, 54. 56 ChevronTexaco, 2002 Supplement to the Annual Report, p. 35 and 2001 Supplement to the Annual Report, p. 24. 57 BP, Report to the Securities and Exchange Commission on Form 20-F, 2002, pp. 27 and 80. 58 BP, Report to the Securities and Exchange Commission on Form 20-F, 2002, pp. 27 and 35. 59 Marathon Oil, Report to the Securities and Exchange Commission on Form 20-F, 2002, p. F-44. 60 The levels of domestic and foreign production taxes are not comparable, because the latter includes royalty expenses while 

the former does not. 61 It is not clear why the Other Western Hemisphere region experienced a large increase in production taxes in 2002. 

However, the fact that this region produces heavy oils that may not bring as high a price as lighter oils may be a contributing

factor, and some South American governments may have increased their production taxes to levels higher than in other 

regions. 62 See Energy Information Administration, State Energy Severance Taxes, 1989-1993, DOE/EIA-TR/0599 (Washington, DC, 

September 1995). 63 While the same causality may be driving both domestic and foreign production tax patterns, none is obvious. 64 Both an individual region’s change in lifting costs and its amount of production have an effect on aggregate lifting costs 

because the cost changes in individual regions are weighted by the production in the region to obtain the aggregates. 65Energy Information Administration, Performance Profiles of Major Energy Producers 2001, DOE-EIA-0206(2001)

(Washington, DC, January 2003), p. 37. This publication is available on the Internet at 

http://tonto.eia.doe.gov/FTPROOT/financial/020601.pdf (as of November 12, 2003). 66As has been mentioned numerous times over the last few years, the net margin is highly correlated with return on

investment. The correlation was re-estimated during the spring of 2003 with additional data (now covering the period 1977

through 2001) and the correlation coefficient was found to be 0.93. See Energy Information Administration, The Impact of

Environmental Compliance Costs on U.S. Refining Profitability, 1995-2001 (May 2003), page 4. This publication is 

available on the Internet at http://www.eia.doe.gov/emeu/perfpro/ref_pi2/index.html (as of November 12, 2003). 67The net margin excludes peripheral activities such as non-petroleum product sales at convenience stores. 68Energy Information Administration, Short-Term Energy Outlook (Washington, DC, November 6, 2003), Table A1. This 

publication is available on the Internet at http://www.eia.doe.gov/pub/forecasting/steo/oldsteos/nov03.pdf (as November 12, 

2003). 69Comparing the stock levels of 2002 with the average for the period of 1996 through 2000 tells a similar story with a slightly 

smaller difference in the first quarter and similar differences in the subsequent quarters. 70Note that the apparent decline in the number of FRS wholly owned U.S. refineries was mostly due to double counting 

among merging companies. The actual decline was two refineries, BP sold its Yorktown, Virginia refinery to Giant 

Industries (a non-FRS company) and Precor shutdown its Hartford, Illinois rather than make upgrading investments. All 

other changes are purely due to double counting. 71See Premcor Inc., “Premcor to Close Hartford, Ill. Refinery in October” (February 28, 2002). 72See BP plc, “Giant Industries, Inc. Announces Acquisition of Yorktown, Virginia Refinery from BP” (February 12, 2002). 73Tesoro Petroleum Corporation, “Tesoro Petroleum Corporation Announces Revised Terms for Golden Eagle Acquisition” 

(May 6, 2002). 74Shell Oil Company, press release (February 12, 2002). 75Houston Chronicle, “Merger finally a done deal, ConocoPhillips now country's largest refiner” (August 31, 2002). 76Several FRS companies mentioned upgrading projects in their public financial disclosures. These included: 

ChevronTexaco (ChevronTexaco, 2002 Supplement to the Annual Report, p. 40), ConocoPhillips (ConocoPhillips Petroleum

Company, 2002 Annual Report, pp. 18 and 19), ExxonMobil (Exxon Mobil Corporation, 2002 Annual Report, p. 15 and 2002

Financial and Operating Review, p. 63), Amerada Hess (Amerada Hess Corporation, 2002 Annual Report, p. 2), LyondellCITGO Refinery LLP (Lyondell Chemical Corporation, 2002 U.S. Securities and Exchange Commission Form 10-K Filing, 

p. 54), Marathon Corporation (Marathon Corporation, 2002 Annual Report, p. 23 and 2002 U.S. Securities and Exchange 

Commission Form 10-K Filing, p. 47), Premcor Inc., (Premcor Inc., 2002 U.S. Securities and Exchange Commission Form

10-K Filing, p. 50), Tesoro Petroleum Corporation (Tesoro Petroleum Corporation, 2002 U.S. Securities and Exchange

Commission Form 10-K Filing, p. 46), and Valero Corporation (Valero Corporation, 2002 U.S. Securities and Exchange

Commission Form 10-K Filing, p. 41). 77Energy Information Administration, Annual Energy Review 2002, DOE/EIA-0384(2002) (Washington, DC, October 24, 

2003), Table 5-19. This publication is available on the Internet at http://www.eia.doe.gov/emeu/aer/petro.html (as of

November 12, 2003).

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 58
 78A $1.50-per-barrel decline seems less significant when compared to a base of almost $34 per barrel than when it is

compared to a base of slightly less than $8 per barrel. 79See Energy Information Administration, “Update of Tables and Figures from U.S. Petroleum Refining and Gasoline 

Marketing Industry,” Table 6. This is an Internet-only product that is available at 

http://www.eia.doe.gov/emeu/finance/usi&to/downstream/update/index.html (as of November 12, 2003). 80See for example, Energy Information Administration, Performance Profiles of Major Energy Producers 2001, DOE/EIA0206(2001) (Washington, DC, January 2003), p.43 (This publication is available on the Internet from a link at 

http://www.eia.doe.gov/emeu/finance/histlib.html (as of November 12, 2003).) and ExxonMobil Corporation, 2002 Financial 

and Operating Review, p. 66. 81Amerada Hess added 25 Hess Express convenience stores during 2002 (Amerada Hess Corporation, 2002 Annual Report, p.

12). ConocoPhillips recorded charges for the impairment of assets associated with retail outlets that will be sold during 2003

(ConocoPhillips, 2002 Annual Report, p. 72). ExxonMobil identified four key areas for its focus: “cost reductions, 

nonpetroleum income growth, selective and disciplined new investments, and high-grading service stations (ExxonMobil

Corporation, 2002 Annual Report, p. 17).” Marathon consolidated Speedway SuperAmerica operations by exiting 

southeastern States in which it has a minimum market presence, refocusing on its Midwest operations. (Marathon Oil 

Company, 2002 Annual Report, p. 23). Valero invested in “top-performing stores” and closed marginal ones (Valero 

Corporation, 2002 Annual Report, p. 15). 82For example, BP is transforming many Amoco outlets into BP outlets, but continuing to offer Amoco-branded motor

gasoline (see BP plc, “BP Unveils Chicago’s Gas Station of the Future” (May 14, 2002) at 

http://www.bpamoco.com/centres/press/p_r_detail_p.asp?id=895 (as of November 12, 2003)). Also, Shell is transforming

many Texaco outlets that were formerly part of Equilon into Shell-branded outlets (see Shell Oil Company, “Shell Brand 

Poised for Major Expansion in U.S.” (February 8, 2002) at 

http://www.piersystem.com/external/final_View.cfm?pressID=5527&CID=69 (as of November 12, 2003)). Additionally, BP 

has installed photovoltaic panels at many of its outlets, which are asserted to supply about “20 percent of the site’s overall 

energy needs” (see BP plc, “Commited to Cleaner Environment, BP Begins Selling Ultra Low Sulfur Diesel in California; 

Converts ARCO Sites to Solar” (June 14, 2002) at http://www.bpamoco.com/centres/press/p_r_detail_p.asp?id=903 (as of 

November 12, 2003)). 83This continues a recent trend discussed elsewhere, particularly two Energy Information Administration publications: 

Performance Profiles of Major Energy Producers 2000, DOE/EIA-0206(2000) (Washington, DC, January 2002), p. 44

(available on the Internet at http://tonto.eia.doe.gov/FTPROOT/financial/020600.pdf (as of November 13, 2003)) and

Restructuring: The Changing Face of Motor Gasoline Marketing (October 2001), an Internet-only product at

http://www.eia.doe.gov/emeu/finance/sptopics/downstrm00/index.html (as of November 13, 2003). 84The Caltex joint venture was an unconsolidated affiliate for both of its parents, Chevron and Texaco. 85The refineries are the 69,800 barrels per day Bulwar Island refinery and the 158,500 barrels per day Kwinana refinery. 86El Paso Corporation, 2002 U.S. Securities and Exchange Commission Form 10-K filing, p. 60. 87ConocoPhillips Company, 2002 Annual Report, p. 43. 88Between 1992 and 1997 Asia-Pacific (computed by combining Asian Developing Countries and Australia, New Zealand, 

and Japan) petroleum product consumption increased 28 percent. However, between 1997 and 2002 Asia-Pacific petroleum

product consumption increased 9 percent. Thus, the growth over the last few years has failed to match the pace over the 

earlier period, which seems to be the major reason that companies speak of excess refinery capacity in this region. 89El Paso Corporation, press release (November 8, 2002). 

90Dynegy Inc., 2002 Securities and Exchange Commission Form 10-K, pp. F-73, F-74. 91Exxon Mobil Corporation, 2002 Financial and Operating Review, p.57. 92Exxon Mobil Corporation, 2001 Financial and Operating Review, p.35. 93Unocal Corporation, 2002 Securities and Exchange Commission Form 10-K, pp. 18-19. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 59

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 61

4. Resource Development Trends 

This chapter of Performance Profiles addresses the costs of finding oil and natural gas and other 

resource development issues. While the costs of adding oil and gas reserves (finding costs) do not 

directly affect the current-year bottom line of the FRS companies (see Chapter 3), they are important in 

guiding the scale and scope of the companies' current and future resource development strategies. 

Accordingly, this chapter also discusses the geographical areas of most importance to the FRS 

companies' current resource development initiatives. Specifically, this chapter presents four analyses 

("Special Topics") that discuss: 

• Variations in regional finding costs 

• Development in the Gulf of Mexico 

• Natural gas production in the United States 

• The Mackenzie pipeline and implications for the U.S. natural gas market 

SPECIAL TOPIC: Finding Costs Increased in Most Regions 

Average finding costs rose worldwide, boosted by increases in six of the nine FRS regions for the 2000 

to 2002 period, with Canada again experiencing the highest costs as it had for the 1999 to 2001 period 

(Table 19). Compared to the second-most-costly region, Canada’s costs increased from $3 per barrel of 

oil equivalent for the 1999 to 2001 to $5.51 for the 2000 to 2002 period and had the largest absolute 

increase for the 2000 to 2002 finding costs for any FRS region. 

Finding costs are the costs of adding oil, including crude oil and natural gas liquids, and dry natural gas 

proven reserves via exploration and development activities.P

a

P

 They are measured for oil and gas on a 

combined basis in units of dollars per barrel of oil equivalent (BOE). Ideally, finding costs would 

include all the costs incurred (no matter when these costs were incurred or actually recognized on a 

company's books) in finding any particular proven reserves (not including the purchases of already 

discovered reserves). In practice, finding costs are actually measured as the ratio of exploration and 

development expenditures (excluding the expenditures on proved acreage) to proven reserve additions 

(excluding net purchases of proven reserves) over a specified period of time.P

b

P

 Finding costs are 

generally measured in Performance Profiles as a weighted average over a period of three years to 

accommodate leads and lags in data reporting, and, if several years of data are presented, they are 

usually reported in constant dollars to facilitate comparisons over time. 

Other prominent changes in regional finding costs for the FRS companies for the 2000 to 2002 period 

include the largest proportional increase in finding costs in OECD Europe and a notable increase in the 

U.S. Onshore (Table 19). The large increase in OECD Europe (predominantly the North Sea) raised that 

region to the second-highest region for finding costs, while the increase in the U.S. Onshore pushed it 

into virtual tie with the U.S. Offshore (predominantly the Gulf of Mexico) for the third highest-cost 

region. The large decrease in finding costs for the FRS companies in the Middle East for the 2000 to 

2002 period is of little significance because, with the unfavorable investment climate in the Middle East, 
this region is usually the one with the smallest amount of reserve additions through the drill bit for the 

FRS companies. 

Region 1999-2001 2000-2002 Percent

Change 

United States

 Onshore 6.01 7.62 26.7

 Offshore 6.99 7.59 8.6

 Total United States 6.39 7.61 19.1

Foreign

 Canada 10.70 14.83 38.6

 OECD Europe 5.51 9.32 69.3

 Former Soviet Union and

 Eastern Europe 3.26 3.10 -4.9

 Africa 3.68 3.68 0.0

 Middle East 7.66 5.94 -22.5

 Other Eastern Hemisphere 4.07 4.63 13.7

 Other Western Hemisphere 6.22 5.14 -17.5

 Total Foreign 5.25 5.92 12.6

Worldwide 5.78 6.70 16.0

 Notes: The above figures are 3-year weighted averages of exploration and 

development expenditures (current dollars), excluding expenditures for proven acreage,

divided by reserve additions, excluding net purchases of reserves. Gas is converted to

barrels of oil equivalent on the basis of 0.178 barrels of oil per thousand cubic feet of

gas.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting 

System).

Table 19. Finding Costs by Region for FRS Companies,

 1999-2001 and 2000-2002

 (Dollars per Barrel of Oil Equivalent)

In order to understand the basis for finding cost increases or decreases, one must look at its two 

components -- finding rates and expenditures per well. Finding rates are the average amount of proved 

reserves added by the drill bit (through extensions and discoveries, improved recovery, and revisions to 

previous reserves estimates) per well drilled. 

Ideally, reserve additions per well are measured as the average of the reserves added by each well during 

its lifetime (no matter the date that the well was completed or the reserves added). In practice, additions 

to reserves per well are actually measured as the ratio of total proven reserve additions (excluding net 

purchases) to the number of wells completed (including dry holes) during a specified period of time, 

with no attempt to link reserve increases to individual wells.c

 

Similarly, expenditures per well are ideally measured as the average of the exploration, development, 

and unproved acreage expenditures associated with each well during its lifetime. In practice, 

expenditures per well are the total expenditures on exploration, development, and unproved acreage 

divided by the number of wells completed during a particular time period, with no attempt to link

expenditures to individual wells. 

These two ratios are generally measured in Performance Profiles as a weighted average over a period of 

three years (in part, to compensate for the imperfect way they are measured), and, if several years of 

data are presented, expenditures are usually reported in constant dollars (to facilitate comparisons over 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 62
time). Finding costs are then the expenditures (to find additional reserves) per well completed divided 

by the finding rate (proven reserve additions per well completed). 

Worldwide finding rates and expenditures per well for the FRS companies both fell for the 2000 to 2002 

period (Table 20). However, the increase in worldwide finding costs, as shown in Table 19, resulted 

from finding rates falling faster than expenditures per well.d

 In other words, the relatively larger decline 

in the worldwide finding rate was the sole reason that finding costs rose. In Canada, the region with the 

largest absolute increase in finding costs for the 2000 to 2002 period, a 13-percent decline in the 

expenditures per well was more than offset by a 37-percent decline in the finding rate. Finding costs in 

OECD Europe rose so much because the finding rate there fell while expenditures per well rose (both of 

which resulted in increased finding costs). For the U.S. Onshore, expenditures per well changed little 

while the finding rate fell. In each of these instances, the fall in finding rates was the more prominent 

contributor to increased finding costs. 

1999-2001 2000-2002 Percent

Change

1999-2001 2000-2002 Percent

Change

United States

 Onshore 354 293 -17.2 2,128 2,232 4.9

 Offshore 2,258 2,293 1.5 15,782 17,391 10.2

 Total United States 522 437 -16.3 3,332 3,322 -0.3

Foreign

 Canada 162 102 -37.4 1,738 1,508 -13.2

 OECD Europe 6,087 4,185 -31.2 33,519 39,024 16.4

 Former Soviet Union and

 Eastern Europe 10,067 13,913 38.2 32,776 43,068 31.4

 Africa 6,715 6,057 -9.8 24,687 22,263 -9.8

 Middle East 438 831 89.7 3,358 4,940 47.1

 Other Eastern Hemisphere 1,728 1,338 -22.6 7,034 6,193 -12.0

 Other Western Hemisphere 2,127 1,721 -19.1 13,240 8,836 -33.3

 Total Foreign 1,084 817 -24.6 5,696 4,836 -15.1

Worldwide 723 582 -19.6 4,180 3,900 -6.7

Expenditures Per Well

(Thousand Dollars per Well)

Table 20. Finding Rates and Expenditures per Well by Region for FRS Companies,

 1999-2001 and 2000-2002

 Notes: The above finding rates are 3-year weighted averages of reserve additions, excluding net purchases of reserves, divided by 

number of wells completed, and the above expenditures per well are 3-year weighted averages of exploration and development

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Region

Finding Rates

(Thousand Barrel of Oil Equivalent

per Well)

Finding Costs for Many Regions Show Consistent Patterns Since Early 1990’s 

Regional finding costs vary substantially across the FRS regions in any particular period and in any 

particular region from period-to-period (Table 19). From the 1990’s until 2002, the highest and lowest 

regional finding costs year have differed from each other by $3.60 per barrel of oil equivalent (boe) to 

$11.90 per boe in constant 2002 dollars (Figure 28). The relatively high variance in regional finding 

costs is indicated by the extent that the range between the maximum and minimum finding costs has 

exceeded the lowest finding cost in every year except one. In addition, the gap between maximum and 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 63
minimum finding costs has been widening in recent years, largely because the maximum finding cost 

has increased much more than the minimum one. 

Nonetheless, when examining regional finding costs over a long period of time, many of the regions 

have had relatively consistent finding cost levels. (In this discussion of regional finding cost trends, 

five-year periods are being used to dampen extreme values and facilitate comparisons.) The regions 

can, somewhat arbitrarily, be separated into groups with high costs, low costs, and varying costs for the 

years 1990 through 2002 (Figure 29). 

The regions that have had high finding costs are Canada, the U.S. Offshore (largely the Gulf of Mexico), 

and OECD Europe (largely the North Sea). Moreover, some of the largest finding cost increases in 

recent years have been incurred in these regions. With one of the lowest expenditures per well of any 

region, Canada might be expected to have low finding costs. However, most of Canada’s oil and gas 

reserves tend to be in smaller pockets somewhat near to the surface, resulting in a majority of the wells 

in Canada being relatively shallow wells that are less costly to drill but also account for smaller reserve 

additions. Therefore, the low reserve additions per well results in Canada having one of the highest 

regional finding costs for the FRS companies. OECD Europe reserves are mostly offshore. Offshore 

exploration and development tends to be relatively more expensive, with larger fields found and lower 

lifting costs. This is part of the reason that the U.S. Offshore and OECD Europe are among the regions 

with the highest expenditures per well. 

The low-cost regions from 1990 through 2002 are Africa, the Other Western Hemisphere, and the Other 

Eastern Hemisphere (Figure 29). All three regions fall in the middle range of the amount of exploration 

and development activity, both in spending and reserves added over the period. These regions differ 

from the other FRS regions because they are not as well developed as the U.S. Onshore and Offshore, 

Canada, and OECD Europe regions and generally have not restricted investment by U.S. companies as 

much as the two regions of the Middle East and the Former Soviet Union and Eastern Europe. The three 

low-cost regions also have had some of the most stable finding cost levels of any of the FRS regions. 

The remaining regions, the U.S. Onshore, the Middle East, and the Former Soviet Union and Eastern 

Europe, exhibit cost patterns that are not as consistent as the other FRS regions (Figure 29). Finding 

costs for the U.S. Onshore had remained rather stable and low, but they have increased substantially in 

both of the last two five-year periods, indicating the possibility that this region may become one of the 

high-cost ones.e

 Finding costs for the FRS companies in the Middle East have followed a “U-shaped” 

pattern, from high to low to high again, with increases in the last four five-year periods (a total 

timeframe of eight years). The cost estimates for this region are probably the most uncertain, because, 

as previously explained, the Middle East has had less exploration and development spending by the FRS 

companies than any other region by a large margin. The region of the Former Soviet Union and Eastern 

Europe had high finding costs in the middle of the period, but has experienced dramatic declines in 

eight-year period comprised by the last four five-year periods, as exploration and development activities 

has ramped up from very low levels in the early and mid-1990’s.f

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 64
0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

1990-1992 1992-1994 1994-1996 1996-1998 1998-2000 2000-2002

Constant Dollars (2002) per BOE

 Note: Finding costs are weighted averages of the annual finding costs for the three years specified. The labels used on the

horizontal axis reflect that the values plotted on the figure are 3-year averages. 

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 28. Maximum and Minimum Three-Year Weighted Average Regional Finding Costs 

 for FRS Companies, 1990-1992 to 2000-2002

0.00

2.00

4.00

6.00

8.00

10.00

12.00

1990-1994

1992-1996

1994-1998

1996-2000

1998-2002

1990-1994

1992-1996

1994-1998

1996-2000

1998-2002

1990-1994

1992-1996

1994-1998

1996-2000

1998-2002

Constant Dollars (2002) per BOE

Figure 29. Five-Year Weighted Average Regional Finding Costs for FRS Companies, 1990-1994 to 1998-2002

 Note: Finding costs are weighted averages of the annual finding costs for the five years specified. The labels used on the horizontal

axis reflect that the values plotted are 5-year averages. Finding costs for the Former Soviet Union and Eastern Europe are not

available before 1992-1996 due to confidentially requirements.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

 Canada

U.S. Offshore

OECD Europe

Other Eastern 

Hemisphere

Other Western 

Hemisphere

Africa

Former Soviet Union &

Eastern Europe

U.S. Onshore

Middle East

High-Cost Regions Low-Cost Regions Mixed-Cost Regions

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 65
Finding Costs Are Rising, But So Are Prices 

Overall, finding costs have been rising above their lows of the mid-1990’s, both domestically and 

abroad (Figure 30). However, U.S. Offshore finding costs, which had surged beginning in the three 

years of 1994 to 1996, have fallen back to meet the rising U.S. Onshore costs, while foreign costs have 

stayed lower than costs in the United States for the two most recent three-year periods. 

However, trends in finding costs must be considered, among other things, in the context of oil and gas 

prices. Finding costs are expected to move in concert with crude oil and natural gas prices.g

 Higher 

crude oil and natural gas prices mean that crude oil and natural gas are worth more than they had been, 

so profit-seeking companies should be spending more to find them. 

The prices of crude oil and natural gas declined through most of the 1980’s, followed by a level period 

for natural gas and a slight decline for crude oil (Figure 31).h

 However, both have been rising in recent 

years. The trend in worldwide finding costs for the FRS companies has exhibited a similar pattern. 

Worldwide finding costs declined in the 1980’s through mid-1990’s, but then began rising. They have 

increased 42 percent since their low in the 1994 to 1996 period; over the same period, domestic crude oil 

prices rose by 39 percent and natural gas prices by 72 percent. 

a

Alternatively, finding costs are the exploration and development costs of replacing reserves removed through production. b

One inherent limitation of measuring finding costs this way is that the expenditures and the reserve additions recognized in a 

particular interval do not usually correspond exactly with each other. Expenditures are usually recognized in the period that

the payment actually occurred. Proven reserves are usually recognized when there is reasonable certainty that they can be 

produced economically. There is no reason that these must occur in the same time period (oil and gas wells are often 

operated over a long time period), so that some expenditures may not be recognized in the same time period that their 

corresponding reserves are recognized. One way to moderate this limitation is to increase the length of the time period over 

which finding costs are measured, allowing reserve additions and exploration and development expenditures to match up

more closely. However, the longer the time period over which finding costs are measured, the more out of date they become, 

because they include older and older expenditures and reserves, and costs and technology are constantly changing. The only 

way to solve the correspondence problem would be to calculate an average finding cost for all of the oil and gas produced by

a well after it is permanently shut in. But then many costs included would be far out of date. c

As with finding costs, measurements of reserve additions per well are limited because the reserves added and the wells 

completed during a particular interval of time do not necessarily correspond exactly with each other. (For further discussion,

see previous note.) d

If finding rates and expenditures either rise or fall by the same percentage, then finding costs will not change. (See Former 

Soviet Union and Eastern Europe Tables 19 and 20.) e

Every year, one year is added and one year is dropped from this calculation. The above result regarding finding costs for the 

U.S. Onshore region means that annual U.S. Onshore finding costs were higher in 2001 that in 1996, and higher in 2002 than 

in 1997. f

Five-year finding costs for the regions of the Former Soviet Union and Eastern Europe before the 1992 to 1996 period

cannot be disclosed because of data confidentiality requirements. g

Technological change is another factor in determining finding costs; it is not considered in this discussion. h

The prices used to construct these indices are domestic prices. While the domestic price of crude oil is similar to the world 

price, the domestic price of natural gas is not. However, worldwide natural gas prices have moved in similar directions since 

the mid-1990’s. See BP Statistical Review of World Energy, (London, United Kingdom, June 2003), p. 29. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 66
4

8

12

16

20

1979 - 1981 1982 - 1984 1985 - 1987 1988 - 1990 1991 - 1993 1994 - 1996 1997 - 1999 2000 - 2002

Constant Dollars (2002) per BOE

Note: Finding costs are weighted averages of the annual finding costs for the three years specified. The labels used on the 

horizontal axis reflect that the values plotted on the figure are 3-year averages. 

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 30. U.S. Onshore, U.S. Offshore, and Foreign Three-Year Weighted Average Finding Costs 

 for FRS Companies, 1979-1981 to 2000-2002

U.S. Offshore

U.S. Onshore

Foreign

20

40

60

80

100

120

140

1979-1981 1982-1984 1985-1987 1988-1990 1991-1993 1994-1996 1997-1999 2000-2002

Index (1979-1981 = 100)

Domestic Natural Gas Price Index

Domestic Crude Oil Price Index

Worldwide Finding Cost Index

Figure 31. Indices of Three-Year Average Domestic Real Prices of Crude Oil and Natural Gas and 

 Worldwide Finding Costs for the FRS Companies, 1979-1981 to 2000-2002

 Notes: Averages are unweighted. Real prices are in constant 2002 dollars. Crude oil price is the crude oil domestic first purchase 

price, and natural gas price is the domestic wellhead natural gas price. The labels used on the horizontal axis reflect that the values

plotted on the figure are 3-year averages.

 Source: Domestic natural gas price index and domestic crude oil price index: Energy Information Administration, Monthly Energy

Review October 2003, DOE/EIA-0035(2003/10) (Washington, DC, October 2003), Tables 9.1 and 9.11. Worldwide finding cost index: 

Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 67
SPECIAL TOPIC: The Gulf of Mexico – Do Technology and Recent 

Economics Favor Oil Reserves Over Natural Gas? 

Exploration and development in the Gulf of Mexico commenced over fifty years ago when the KerrMcGee corporation discovered Ship Shoal 32, about 10 miles off the Louisiana coast in 18 feet of water. 

By the mid-1980’s, almost 1,000 fields had been discovered and many industry analysts were convinced 

that the Gulf was in decline.a

 Some even referred to the Gulf as the “Dead Sea.”b Starting with Shell 

Oil’s discovery of the 220-million-barrel deepwater Auger field in 1987, this view has been replaced 

with the recognition that the Gulf still has tremendous potential. What has been especially striking 

about the deepwater fields are the high productivity rates of the wells. For example, a typical shallowwater oil well flows at just over 100 barrels of oil per day, whereas oil wells at the deepwater Ursa field 

each produce about 30,000 barrels of oil per day.c

 Similarly, a single well at the deepwater Mensa field 

produces about 100 million cubic feet of gas per day, which is about fifty times the flow rate for a 

typical shallow-water gas well.d

 

In the shallow-water portion of the Gulf, i.e. that portion of Gulf where the water depth is less than 200 

meters, the industry over the period of 1993 through 2002 replaced approximately 80 percent of the 

roughly 7.4 billion of crude oil equivalent that was produced over the period.e

 As a result, crude oil 

equivalent reserves in the shallow Gulf were approximately 33 percent lower at the end of 2002 than in 

1993. Fortunately, this has been more than offset by the deepwater where reserve additions over the 

1993 through 2002 period were more than 2.5 times the level of production. 

For the Gulf as a whole, over 12 billion barrels of crude oil equivalent were produced over the period 

1993 through 2002 while reserves at the end of 2002 were approximately 2.5 billion barrels of oil 

equivalent higher than at the beginning of the period.f With respect to remaining undiscovered 

resources, the 2000 resource assessment performed by the U.S. Department of Interior’s Minerals 

Management Service (MMS) indicates that there are approximately 71 billion barrels of oil equivalent 

yet to be added to reserves.g

 Not surprisingly, the vast proportion of the remaining undiscovered 

resources are in the deepwater. MMS estimated that the split between oil versus natural gas resources is 

approximately fifty-fifty.h 

Some of the more notable deepwater discoveries include: 

Thunder Horse. This field (previously known as Crazy Horse) is believed to contain between one and 

three billion barrels of recoverable crude oil equivalent, which makes it the largest field ever discovered 

in the Gulf of Mexico.i

 This field gives new meaning to the notion of a deep field in that it lies over 

25,000 feet below the ocean floor which in turn is 6,000 feet below the surface of the Gulf. The field 

also typifies the long lead-time associated with offshore exploration and development. Lead times can 

be long because production requires pipeline infrastructure that may only be economic when there are a 

number of fields to be brought onstream. 

For example, in the case of Thunder Horse, the field was leased in 1988 but the first discovery well was 

not drilled until 1999. Initial production is expected to commence in 2005, 17 years after the lease was 

acquired.j

 It is expected to be worth the wait given that the field will be produced using a 250,000- 

barrels-of-oil-equivalent-per-day floating production facility. Partners in the field are BP (with a 75-

percent ownership share) and Exxon Mobil (with a 25-percent ownership share). The field also typifies 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 68
the oil-prone nature of the deepwater discoveries to date based on the planned production facilities, 

approximately 87 percent of the production (on an oil equivalent basis) is expected to be accounted for 

by crude oil as compared to natural gas.k 

Mad Dog. Discovered in 1998, the Mad Dog oil field development is planned to have 14 wells tied 

back to a spar. The facility is designed to process 87,000 barrels of oil equivalent per day.l 

Approximately 92 percent of the production is expected to be oil.m The first production of oil is 

expected by early 2005. Partners in the project are BP (with a 60.5-percent ownership share), BHP 

Billiton (with a 23.9-percent ownership share), and Unocal (with a 15.6-percent ownership share). 

Na Kika. This project is located 140 miles southeast of New Orleans. It consists of five distinct fields 

with water depths of 5,800 to 7,000 feet.n

 In part because of a lack of pipeline infrastructure, the fields 

(while discovered in the 1980s) are only now being developed. The fields will be produced using 10 

wells tied back to a centrally located floating production platform. The platform is a semi-submersible 

unit equipped with drilling and production equipment. It is anchored in place or can be dynamically 

positioned using thrusters. The facility is designed to process 190,000 barrels of oil equivalent per day 

with approximately 57 percent of the production being accounted for by oil.o

 Production is expected to 

commence in early 2004. Partners in the project are BP and Shell Oil. The partners have equal 

ownership interests in four of the five fields. BP has a majority stake in the fifth field. 

Atlantis. This field is located 125 miles south of New Orleans in 4,400 to 7,100 feet of water.p

 The 

field will be developed with a moored semi-submersible production facility with a design capacity of

around 180,000 barrels of oil equivalent per day. Less than 20 percent of the output is expected to be 

natural gas. BP is the operator and has a 56-percent ownership interest. BHP Billiton accounts for the 

remaining 44-percent ownership share. 

All of the above projects will make use of the $1-billion Mardi Gras transportation system which upon 

completion will consist of five pipelines stretching more the 450 miles across the Gulf. This system will 

have the capability of transporting over 1 million barrels per day and 1.5 billion cubic feet day of crude 

oil and natural gas, respectively.q

 

Other recent significant discoveries includes Vortex (Kerr-McGee, BHP Billiton, and Ocean Energy), 

Tahiti (ChevronTexaco, PanCanadian Energy, and Enterprise), Deimos (Shell Oil and BP), and Great 

White (Shell Oil, BP, and ChevronTexaco). Only Vortex is known to be prone to natural gas.r 

The oil-prone nature of these recent discoveries does not appear to be consistent with what one would 

expect based on MMS’s fifty-fifty oil to natural gas resource assessment in 2000. It is also not 

consistent with the most recent 2003 MMS resource assessment which (according to The Wall Street 

Journal) significantly raised their estimate of the amount of undiscovered natural gas resources left in 

the Gulf.

s

It may be the oil-prone nature of the projects currently being developed in the Gulf is a legacy of the 

industry’s previous focus on finding and developing oil resources. Alternatively, this outcome could be 

attributed to the fact that many of the undiscovered gas prospects have a vertical drilling depth greater 

than 15,000 feet where the seismic imaging is poor relative to shallower drilling depths. 

In any event, the relatively more oil versus natural gas being developed in the Gulf has major 

implications for domestic crude oil and natural gas supplies. Buoyed by these and other discoveries, the 

FRS companies have replaced over 100 percent of their offshore oil production in eight out of the past 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 69
ten years (Figure 32). For the period as a whole, the companies have replaced 145 percent of their 

offshore crude oil production. In contrast, the natural gas reserve replacement rate has exceeded 100 

percent in only three of the past ten years. For the period as a whole, the natural gas reserve replacement 

rate was a disappointing 87 percent.t

 Additionally, this situation has deteriorated further in recent years. 

Over the 1998 through 2002 period, natural gas reserve additions were only about 70 percent of the 

amount of natural gas that was produced. Fortunately, continued improvement in seismic technology (in 

conjunction with the current price environment) should eventually yield the discovery of additional 

natural gas. 

0.0

0.5

1.0

1.5

2.0

2.5

3.0

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Reserve Replacement Ratio

Oil

Natural Gas

Figure 32. Reserve Replacement Ratios for the FRSCompanies in the U.S. Offshore, 1993-2002

Source: Energy Information Administration, FormEIA-28 (Financial Reporting System).

a

Kallaur, Carolita, “The Deepwater Gulf of Mexico—Lessons Learned,” Institute of Petroleum's International Conference 

on Deepwater Exploration and Production in Association with OGP, February 22, 2001 London, UK. Located on the 

Internet at http://www.gomr.mms.gov/homepg/offshore/deepwatr/lessons_learned.html (as of December 15, 2003). b

Ibid. c

Ibid. d

Ibid. e

Energy Information Administration, “Advanced Summary U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserve

2002 Annual Report,” DOE/EIA-0216(2002) Advance Summary, October 2003. f

Minerals Management Service, “Outer Continental Shelf Petroleum Assessment 2000,” September 2003. Located on the

Internet at http://www.mms.gov/revaldiv/RedNatAssessment.htm (as of December 15, 2003). g

Ibid. h Ibid. i BP plc, “Upstream Build Projects,” January 2003. Located on the Internet at 

http://www.bp.com/liveassets/bp_internet/globalbp/STAGING/global_assets/downloads/U/Upstream_build_projects.pdf (as 

of December 15, 2003). 

j

Ibid. k

Ibid. Based on the reported design capacities and the conversion factor of 0.178 mcf of natural gas per barrel of crude oil. l Ibid. mIbid. Based on the reported design capacities and the conversion factor of 0.178 mcf of natural gas per barrel of crude oil. n Ibid. o

Ibid. Based on the reported design capacities and the conversion factor of 0.178 mcf of natural gas per barrel of crude oil. p Ibid. q

Ibid. r”BHP Billiton Discovers Natural Gas with Vortex-1 Well in Deepwater Gulf of Mexico,” Oil & Gas Journal Online, 

(December 13, 2002). Located on the Internet at 

http://ogj.pennnet.com/articles/web_article_display.cfm?Section=Archives&Article_Category=ExplD&ARTICLE_ID=1637

72&KEYWORD=vortex (as of December 15, 2003) s

Gold, Russell, “ Gulf of Mexico May Hold More Natural-Gas Supply,” The Wall Street Journal (November 19, 2003).

 

t

Energy Information Administration, Form EIA-28 (Financial Reporting System). 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 70
SPECIAL TOPIC: Natural Gas Supply -- A New Paradigm? 

Throughout most of the 1990’s, many natural gas analysts were of the view that technological progress 

would enable the North American natural gas supply industry to meet growing demand at moderate to 

low prices. According to the Energy Information Administration, the natural gas price in 1999a

 was 

$2.19 per thousand cubic feet while the natural gas price for 2003b

 was projected (in December 2003) to 

be $4.97 per thousand cubic feet, a 127-percent increase over the period. However, despite these higher 

prices, natural gas production in 2003 was projected (in December 2003) to be only about 3.6 percent 

higher than in 1999.c

 This seemingly inelastic response of production with respect to price has led some

to question whether technology advances will in fact be robust enough to keep natural gas prices at 

moderate to low levels. In other words, is a new natural gas supply paradigm – one of higher prices 

being needed to meet projected demand – emerging? For instance, the National Petroleum Council 

(NPC) has recently concluded that current North American producing areas and those under 

development will be unable to meet projected demand over the next 20 years.d 

At first glance, the NPC’s concerns appear to be misplaced. Producers such as the FRS companies have 

responded to the increase in the price of natural gas by substantially increasing their level of drilling for 

natural gas (Figure 33). Domestic gas well completions by the FRS companies attained an all-time high 

in 2001. While completions were off in 2002, they were nevertheless almost three times their level in 

1999. 

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Price in Constant Dollars (2002)

 per thousand cubic feet (MCF)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Number of Completions

Completions

Price

Figure 33. The Domestic Wellhead Price of Natural Gas and the Number of Domestic Gas Well 

 Completions by the FRS Companies, 1990-2002

Sources: Energy Information Administration, Form EIA-28 (Financial Reporting System) and Energy Information 

Administration, Natural Gas Monthly , DOE/EIA-0130(2003/10) (Washington, DC, October 2003).

The possibility of a paradigm shift becomes more apparent if one examines the volume of gas added to 

reserves by the average successful gas well. Over the period of 1990 through 2000, the FRS companies 

drilled 23,367 gas wells in the onshore United States. This drilling yielded approximately 54,903 billion 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 71
cubic feet of reserve additions (extensions and discoveries plus reserve additions associated with 

improved recovery plus reserve revisions), which means that the average onshore gas well added 

approximately 2.3 billion cubic feet of natural gas to proved reserves.e

 In sharp contrast, reserve 

additions per well in 2001 and 2002 were about 1 billion cubic feet (Figure 34). A portion of the decline 

can be attributed to a change in the type of wells drilled. Approximately 90 percent of the onshore gas 

wells that the FRS companies drilled over the period of 1990 through 2000 were developmental wells.f

 

Relative to exploratory wells, developmental wells do not add much to reserves but instead extract gas 

out of already proved reserves. In the 2000 through 2001 time period, the share of wells classified as 

developmental was over 95 percent. Whether this shift in the mix of drilling explains the entire decline 

in reserves added per well is the fundamental natural gas supply question.

0.0

0.5

1.0

1.5

2.0

2.5

3.0

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Billion Cubic Feet per Well

Figure 34. Natural Gas Reserve Additions per Well for FRS Companies in U.S. Onshore, 1990-2002

Notes: The numerator of reserves additions per well includes revisions, improved recovery, and extensions and discoveries. The

denominator includes both exploratory and developmental successful gas wells.

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System). 

Nonetheless, the NPC’s concern about the adequacy of the natural gas supply becomes almost 

impossible to dismiss if one examines the reserve replacement rate. This statistic is the ratio of reserve 

additions to production. (A ratio greater than one indicates that exploration and development efforts are 

adding more to reserves than the firms are withdrawing from reserves.g

 A ratio less than one indicates 

that the exploration and development efforts are adding less to reserves than the amounts that the firms 

are producing from reserves.h

 ) The domestic natural gas reserve replacement rate for the FRS 

companies over the period of 1990 through 2002 was less than 1.0 in 9 out of the 13 years (Figure 35). 

For the entire period, the companies replaced only about 90 percent of production. For the industry as a 

whole, the situation is less grim. The domestic natural gas reserve replacement rate for the industry over 

the period of 1990 through 2002 was greater than 1 in 9 out of the previous 13 years.i

 For the period of 

1990 through 2002 as a whole, the industry has replaced 108 percent of production. While this latter 

statistic does provide some grounds for natural gas supply optimism, it should be understood within the 

context of a declining extraction rate. 

The extraction rate, which is the ratio of production to reserves, increased over the early part of the 

1990’s for both the FRS companies and the industry as a whole (Figure 36). Over the past few years, 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 72
however, the ratio has declined for both groups. Indicative of the significance of the decline, the 

domestic natural gas production of the FRS companies in 2002 would have been 616 billion cubic feet 

higher had the production to reserves ratio in 2002 been equal to its 1999 value. For the industry as a 

whole, production would have been 1.8 trillion cubic feet higher. 

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Reserve Replacement Ratio

Industry

FRS Companies

 Sources: Energy Information Administration, Form EIA-28 (Financial Reporting System) and Energy Information Administration,

Advanced Summary U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserve 2002 Annual Report , DOE/EIA-0216(2002) Advance 

Summary (Washington, DC, October 2003).

Figure 35. The Domestic Natural Gas Reserve Replacement Ratio for the FRS Companies and the Domestic 

 Natural Gas Supply Industry as a Whole, 1990-2002

0.080

0.085

0.090

0.095

0.100

0.105

0.110

0.115

0.120

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Ratio of Production to Reserves

Industry

FRS Companies

Figure 36. The Ratio of Natural Gas Production to Proved Natural Gas Reserves for the FRS 

 Companies and the Domestic Natural Gas Supply Industry, 1990-2002.

 Source: Sources: Energy Information Administration, Form EIA-28 (Financial Reporting System) and Energy 

Information Administration, Advanced Summary U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserve 

2002 Annual Report , DOE/EIA-0216(2002) Advance Summary (Washington, DC, October 2003).

 0.0

The recent decline in the production to reserves ratio can be partly attributed to an increase in nonproducing reserves as firms commence drilling in areas where there may be a lack of pipeline 

infrastructure (such as in frontier areas of the Rocky Mountains). Another factor contributing to the 

decline is the increased emphasis on unconventional gas sources such as coalbed methane, tight sands, 

and gas shales.j

 As recently as 1996, less than 40 percent of onshore reserve additions were accounted 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 73
for by unconventional sources; the comparable figure for 2000, the latest year for which reliable data are 

available, is 67 percent.k

 As compared to conventional natural gas wells, unconventional wells typically 

have lower daily production rates, which translate into a smaller amount of production for a given 

reserve base. For example, in 2000, the extraction rate for tight gas was almost 25 lower per unit of 

reserves as compared to conventional gas.l

 Given that unconventional gas is expected to become an 

even larger component of gas supply in the future,m the lower extraction rate that both the FRS 

companies and the industry as whole have experienced over the past few years may become a permanent 

fixture in the gas supply paradigm. 

a

Energy Information Administration, Natural Gas Annual 1999, DOE/EIA-0131(99) (Washington DC, October 2000). bEnergy Information Administration, Short-Term Energy Outlook, December 2003, 

http://www.eia.doe.gov/emeu/steo/pub/contents.html (as of December 16, 2003). c

Ibid. d

The NPC report is available at http://npc.org e

Energy Information Administration, Form EIA-28 (Financial Reporting System). f

Ibid. g

Remaining reserves rise as a result, which enables production to also rise (for a given extraction rate). h

Remaining reserves decline as a result, which allows production to also decline (for a given extraction rate). i

Energy Information Administration, Advanced Summary U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserve 

2002 Annual Report, DOE/EIA-0216(2002) Advance Summary, October 2003. j

For additional information on the production of natural gas as coalbed methane, see Energy Information Administration,

Performance Profiles of Major Energy Producers 2000, DOE/EIA-0206(2000) (January 2002, Washington, DC), pp. 79-83. 

Available on the Internet at http://tonto.eia.doe.gov/FTPROOT/financial/020600.pdf (as of December 16, 2003). k

Special compilation by the Energy Information Administration, Office of Integrated Analysis and Forecasting. l

Ibid. mEnergy Information Administration, Annual Energy Outlook 2004, DOE/EIA-0383(2004) (Washington DC, January 2004). 

SPECIAL TOPIC: Canada’s Mackenzie Delta -- One Part of Future Natural 

Gas Supply? 

Natural gas prices are now over twice what they were in the late 1990’sa. Some, such as Federal Reserve 

Chairman Alan Greenspan, see imported liquefied natural gas (LNG) as the solution to this problem.b

 

While not dismissing the importance of LNG, others point out that North America has a substantial 

quantity of stranded gas reserves -- gas that could be marketed if there were a low-cost mechanism of 

transporting the gas to market. For instance, the Mackenzie Delta in Canada’s Northwest Territories 

contains over 10 trillion cubic (tcf) feet of known recoverable natural gas.c

 This is the volume of gas 

that had been booked as reserves during the 1970’s; however, like the natural gas on Alaska’s North 

Slope, this gas was never produced because of a lack of pipeline infrastructure that could move the gas 

to market. In 1994, the Mackenzie Delta gas reserves were written off the books (by those companies 

owning the gas) when the price of gas in Canada sold for an equivalent of approximately $1.50 (U.S.) 

per thousand cubic feet (Mcf).d A year earlier, over 14 tcf of gas located in Canada’s Artic Islands 

(located northeast of the Mackenzie Delta) was also written off given its remote location.e 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 74
Recently, Imperial Oil (Canada’s largest oil company, 69.6-percent owned by the FRS company Exxon 

Mobil), ConocoPhillips, Exxon Mobil, and Shell Canada (a wholly owned subsidiary of the British 

Royal Dutch Shell) have formed the Mackenzie Gas Producers Group with the aim of developing the 

natural gas fields and constructing a pipeline system along the Mackenzie Valley. This system would 

deliver the gas to Northwestern Alberta where existing pipelines could then move the gas to other parts 

of Canada as well as to the United States.f

 The goal is to have the natural gas moving through the 

pipeline by 2010. The pipeline is planned to have a 1.2-billion-cubic-feet-per-day (bcf/d) initial capacity 

that could be expanded to 1.9 bcf/d by adding additional compression stations. The overall cost of the 

project including the construction costs of the pipeline, the gathering system, and required field 

development is estimated at $4 to 5 billion (in Canadian dollars), which is approximately $3 to 3.8 

billion (in U.S. dollars).

A large portion of the gas for the pipeline is expected to come from three major fields: 

Taglu. This field has estimated recoverable natural gas resources of 3 tcf. Imperial Oil Limited has a 

100-percent interest in the field. Imperial will also have an interest in the gathering lines as well as in 

the pipeline system. 

Parsons Lake. This field has estimated recoverable natural gas resources of 1.8 tcf. Partners in this field 

are the FRS companies ConocoPhillips (with a 75-percent ownership share) and Exxon Mobil (with a 

25-percent ownership share). 

Nglintgak. This field was discovered in 1973 and has estimated recoverable natural gas resources of 

approximately 1 tcf. The field is owned by Shell Canada. Because of the high productivity of the wells 

in terms of output per day, it is believed that the field can be developed using only about 6 to 10 wells. 

In addition to the Producers Group, the Aboriginal Pipeline Group (APG) will also have an interest in 

the pipeline portion of the project. The APG was formed in 2000 to represent the interests of the 

aboriginal people of the Northwest Territories in the project. The APG has signed a “Memorandum of 

Understanding” with the Mackenzie Gas Producers Group that gives APG the right, depending on the 

throughput of the pipeline, to own up to one-third of it. Also, as part of the Memorandum, TransCanada 

(a Canadian pipeline company) will lend approximately $80 million (in Canadian dollars), which is 

approximately $60 million in U.S. dollars to the APG to finance APG’s share of the project planning 

costs. The APG expects to finance the vast proportion of its share of the pipeline construction costs by 

borrowing against its share of future pipeline revenues. However, it is far from clear that these loans 

will be sufficient to fund the entire amount of APG’s commitment. 

Other companies active in the Mackenzie Delta include Devon Energy and Petro-Canada (a major 

Canadian integrated oil and gas company), which together hold leases on more than 1 million acres of

land. Over the last two winters, the two firms drilled three unsuccessful exploratory wells -- Kurk M-15, 

Tuk B-02, and Kugpik L-46. While hydrocarbons were encountered at Tuk B-02, the well was 

subsequently determined to be uneconomic. More recently, the partners have announced that a fourth 

exploratory well, Tuk M-18, has yielded significant gas flows. The well is estimated to have a reserve 

potential of 200 to 300 bcf with a sustained deliverability of 60 to 80 mcf/d.h 

While it is increasingly likely that the Mackenzie Delta project will become a reality, it is far from clear 

how much of the gas will ultimately reach U.S. markets. It may be that much of the gas will be used by 

Canada’s expanding oil sands (synthetic crude) industry. The in situ oil sands projects in Canada use 

natural gas to create steam that enables the bitumen hydrocarbons to flow to the surface. According to 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 75
Canada’s National Energy Board, one of the most promising in situ technologies, Steam Assisted 

Gravity Drainage (SAGD), requires 1 mcf of gas for every barrel of bitumen that is produced.i

 Given 

these gas requirements, it is not surprising that one study has recently concluded that the incremental gas 

demand from the oil sands projects could equal or even exceed the initial planned capacity of the 

MacKenzie Delta pipeline. 

a

Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130(2003/10) (October 2003, Washington, DC). b

“Natural Gas Outlook Worries Greenspan,” New York Times, (June 11, 2003), p. C4. c

Canadian Association of Petroleum Producers, Statistical Handbook for Canada's Upstream Petroleum Industry, 2002,

Table 2-13A. d Ibid..Table 5-06A. e

Ibid. Table 2-13A. f

Canadian Association of Petroleum Producers, “Canadian Natural Gas Overview,” April 2003. 

This document is available in the Internet at 

http://www.capp.ca/Pandell_Docs_File_Streamer/IndependantFileRelayDirectFromDocs.asp?XXX=1&doctype=

NTV&docnumber=56189 ( as of December 15, 2003). g

This information is based on the project’s preliminary information package which is available on the Internet at 

http://www.mackenziegasproject.com/theProject/regulatoryProcess/pipSubmission/Documents/Volume%202%20PIP.pdf ( as

of December 15, 2003). h

“Exploration and Development: Canada,” Oil & Gas Journal Online, January 24, 2003. Available on the Internet at 

http://ogj.pennnet.com/articles/web_article_display.cfm?Section=Archives&Article_Category=ExplD&ARTICL

E_ID=166830&KEYWORD=Tuk%20M%2D18 ( as of December 15, 2003). i

”No Relief from Mackenzie gas: Lehman Brothers report says Delta Gas will likely all go to Oil Sands,” Petroleum News, 

September 14, 2003. 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 76
Energy Information Administration / Performance Profiles of Major Energy Producers 2002 77

5. Emerging Issues 

This chapter of Performance Profiles analyzes new developments and emerging directions of the larger 

energy industry. FRS data are combined with additional information from company annual reports, press 

releases, and other energy company public disclosures so as to expand the scope of energy industry 

financial analyses presented in this report. Specifically, this chapter presents three analyses ("Special 

Topics") that discuss: 

• The level of activity of the U.S. major energy companies in energy production from renewable 

energy sources

• The level of success of mergers and acquisitions by the U.S. majors as a strategy in replacing 

their oil and natural gas reserves 

• The role of the U.S. majors in the developing liquefied natural gas market in the United States 

SPECIAL TOPIC: FRS Company Production From Renewables

Even though renewable energy sources constitute a small part of the U.S. energy mix, some of the large 

U.S. major energy companies reporting to EIA’s Financial Reporting System (FRS) have become 

involved in renewables energy production. Specifically, in referring to the term “renewables,” we are 

confining our discussion to geothermal, solar, and wind energy sources. Biomass is not significant in 

any FRS company’s energy production. In addition, hydroelectric power has more than a hundred-year 

history in the United States and is beyond the scope of what can be addressed here. 

Despite strong governmental and public interest in renewables, of the three renewables being discussed 

here only wind energy production has grown in the 1998 to 2002 period, by 242 percent from 0.031 

quadrillion Btus to 0.106 quadrillion Btus.TP

a

PT Production from geothermal and solar has essentially 

remained steady over that period. Together, these three energy sources comprised just under one-half of 

one percent of total U.S. energy consumption in 2002. 

Geothermal Energy 

Geothermal energy chiefly is electric power that is derived from heat within the earth.TP

 bPT More 

specifically, geothermal energy comes from precipitation that over the eons has seeped deep into the 

ground and has been warmed by the natural heat of the earth. These heated geothermal fluids occur 

where magma has pushed close enough to the surface through fractures in the earth’s crust. These 

heated fluids have been found and developed in reservoirs up to 9,800 feet deep. Wells are drilled to 

recover these fluids to the surface. There the fluids are converted into steam, and if necessary scrubbed 

to remove impurities, with excess fluids being returned to the reservoir. The scrubbed steam is then 

delivered by pipeline to a power plant. The power plant uses the steam to drive turbines to generate 

electric power. 
Geothermal energy’s environmental properties are considered benign: geothermal emissions consist 

mostly of water, and geothermal energy production requires no cooling water from the surrounding area. 

The geological conditions necessary for harnessing geothermal energy have been found mainly in the 

Pacific Rim, particularly in the Philippines and Indonesia. 

The Unocal Corporation is the only FRS company active in geothermal energy. It has been producing 

geothermal energy for over 30 years. Unocal’s geothermal operations are in the Philippines, at Tiwi 

(330 megawatts of generating capacity) and Mak-Ban (426 megawatts of generating capacity),c

 and in 

Indonesia, at Gunung Salak (330 megawatts of generating capacity) and Wayang Windu (110 megawatts 

of generating capacity).d

 The two Philippines plants have been operating over thirty years and provide 

15 percent of the electricity required by Luzon, the Philippines’ largest island. Unocal began 

geothermal operations in Indonesia in 1982. 

Together, these four projects supply steam for almost 1,200 megawatts of generating capacity. Unocal’s 

total 2002 geothermal energy production averaged 13 million kilowatthours, the equivalent of 20,000 

barrels of oil per day, down from 22,000 barrels per day in 2001.e

 Its net proved geothermal reserves at 

year-end 2002 were the equivalent of 232 million barrels of oil, compared to 162 million barrels in 

2001. 

Wind Energy 

Wind energy is the harnessing of the wind to generate power. By turning like a pinwheel in the wind, 

wind turbines convert the energy in the wind into mechanical power. This mechanical power can be 

used directly for such things as grinding grain or pumping water or can be converted into electricity. 

Environmentally, wind energy is considered a very clean source of power. The primary environmental 

concerns with wind are noise from the rotors, the visual aesthetics of wind farms, and potential harm to 

wildlife. Objections have been raised to proposed wind energy installation both inland and offshore. 

Europe has the largest base of installed wind power capacity, at over 20,000 megawatts, particularly in 

Germany, Spain, and Denmark. The United States follows at 4,685 megawatts at year-end 2002. f

Regions in the United States with an average annual wind speed of at least 13 miles per hour, a speed 

considered the threshold for undertaking a wind power project, are found along the East Coast, the 

Appalachian Mountains, the Great Plains, the Pacific Northwest, and California.g

 

A former FRS company, Enron, was active in wind power, but has divested its wind generating assets 

due to Enron’s bankruptcy. Enron was active both in manufacturing wind power equipment and in 

developing wind farms. Both General Electric Co. and American Electric Power have purchased Enron 

wind assets. 

Another FRS company, Shell Oil, has a parent (Royal Dutch/Shell) that has a modest wind energy 

program. Royal Dutch/Shell subsidiary Shell WindEnergy Inc. is building its largest wind farm to date 

near Lubbock, Texas, in a 50/50 percent joint venture with Padoma Wind Power.h

 This 160-megawatt 

project was scheduled be completed by year-end 2003. Shell Wind Energy first entered the U.S. wind 

power market with its purchase of a 50-megawatt facility in Wyoming in 2001. The company also 

develops and operates wind parks in Europe. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 78
One other FRS company, BP America, has a parent company (BP plc of the United Kingdom) with one 

wind project.i

 This is its jointly owned Nerefco oil refinery near Rotterdam, where it has nine wind 

turbines, with the power sold through the national power grid. 

 

Although wind power represents a small part of the U.S. electric power generation mix, this renewable 

energy source has recently been growing faster, beginning in 1999. This is in part due to technological 

innovations improving performance and cost and also to a Federal tax credit of 1.5 cents per 

kilowatthour for electricity generated by wind turbines. This credit expired at year-end 2003. Although 

there had been two retroactive renewals of the tax credit in the past, it was not renewed a third time. 

Despite the recent growth in generation from wind, there is not as yet a big presence by FRS companies 

in this renewable power source. Non-FRS companies are the market leaders in wind power in the 

United States. FPL Energy is the nation’s largest generator of wind power, with 24 wind farms. 

American Electric Power is another big presence in wind power. Also, the Federal government’s 

Bonneville Power Administration has increased its presence as a supplier of electric power from wind 

energy. 

Solar Energy 

Solar energy refers to the harnessing of the power of the sun. Passive solar is a means of reducing 

energy consumption. As for actual energy production, there are primarily two types of solar energy: 

photovoltaic, which uses the sun’s rays to generate electricity, and thermal, in which the sun’s heat is 

concentrated and used directly for such applications as heating water or other liquids. Worldwide, most 

solar energy production is from the use of photovoltaics. 

Solar energy is considered environmentally benign, with essentially no harmful emissions, and it also 

can be used for power generation. There seem to be fewer objections about solar’s visual aesthetics than 

wind’s, perhaps since solar collection facilities tend to be located remotely and not on high ground. 

However, solar power still represents a small part of the U.S. energy mix. 

Two FRS companies, Shell Oil and BP America, have parent companies (Royal Dutch/Shell and BP plc) 

active in the solar energy business. They are primarily active in the solar equipment and facilities

manufacturing end of the business, not in solar power production itself. This may be in part because 

solar has been used mainly in smaller, decentralized applications and much less in central station electric 

power generation. 

Shell Solar is active in the photovoltaic but not the thermal portion of the solar manufacturing business, 

manufacturing solar components as well as complete solar systems. The company reports a total yearly 

manufacturing capacity of 60 megawatts of solar panels, with facilities in the United States and Europe.j

Shell Solar acquired Siemens Solar in 2002k

 and reports a global market share of 13 percent.l 

BP is active in solar equipment manufacturing, with nearly 30 years of experience in the United States 

and elsewhere.m BP reports being the largest user of solar energy in the world, employing solar power at 

BP service stations, plants, and offices.n BP Solar, headquartered in Maryland, does own and operate 

one small solar field in Paulsboro, New Jersey, for supplying electric power to the grid, a 350,000- 

kilowatthour per year field, enough for 50 homes.o

 

ChevronTexaco, with a fledgling solar program, has also begun operating a solar facility outside

Bakersfield, California.

p

 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 79
Conclusion 

Interest in renewable energy resources has increased over time, due to both environmental and energy 

security considerations. Renewables are considered more environmentally benign than other fuels, with 

little to no air emissions or local water use. They are also viewed as enhancing energy security both by 

diversifying the portfolio of energy we use and by relying on resources that are domestically abundant. 

The FRS companies producing renewable energy may be involved in these energy sources in part to 

keep up with potential advances in energy production technologies and perhaps also to enhance their 

environmental image.q However, there is no indication that renewable energy will constitute a 

substantial portion of the energy produced by FRS companies in the near future. 

a

Energy Information Administration, Renewable Energy Annual 2001, DOE/EIA-0603(2001) (Washington, DC, November 

21, 2002), Table 1. Web address:

http://www.eia.doe.gov/cneaf/solar.renewables/page/rea2002.pdf b

Other types of geothermal energy include geothermal heat pump and enhanced geothermal recovery (hot dry rock), which is

a potential technology. c

Unocal Corporation, March 2002 discussion on “Philippine Geothermal.” Web address:

http://www.unocal.com/geopower/pgi.htm d

Unocal Corporation, July 2003 discussion on “Unocal Geothermal Indonesia.” Web address:

http://www.unocal.com/geopower/ugi.htm. e

Unocal Corporation, 2002 Securities and Exchange Commission Form 10-K, p.18. f

United States Department of Energy, discussion on Wind Energy. Web address: 

http://www.eere.energy.gov/windpoweringamerica/pdfs/wpa/wpa_update.pdf g

U.S. Department of Energy, discussion on Wind Energy. Web address: http://www.eere.energy.gov/windpoweringamerica. h

Royal Dutch Shell, press release (July 23, 2003) i

BP plc, discussion on “Renewable Energy.” Web address: http://www.bp.com/environ_social/environment/renewable.asp

j

Royal Dutch Shell, September 2003 discussion on “Shell Renewables.” Web address: 

http://www.shell.com/home/Framework?siteId=shellsolar&FC1=&FC2=%2FLeftHandNav%3FLeftNavState%3D1%2C0&F

C3=%2Fshellsolar%2Fhtml%2Fiwgen%2Fabout_shell%2Ffact_fig_new_01291129.html&FC4=&FC5= k

Royal Dutch Shell, press release (January 23, 2002). l

Royal Dutch Shell, press release (September 11, 2003). mBP plc, September 2003 discussion on “Renewable Energy.” Web address: 

http://www.bp.com/environ_social/environment/renewable.asp n

BP plc, September 2003 discussion on “BP Gas, Power & Renewables.” Web address: 

http://www.bp.com/bp_businesses/transition_page.asp?id=39 o

BP plc, press release (April 22, 2003). p

ChevronTexaco Corporation, press release (June 5, 2003). q

Newsweek Magazine, September 22, 2003, advertisement by Shell Oil after page 10: 

"One of our goals is to make solar energy cheaper ... It's part of our commitment to sustainable development, balancing 

economic progress with environmental care and social responsibility." 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 80
SPECIAL TOPIC: Recent Upstream Mergers: A Tradeoff Between Growth 

and Profitability? 

In order to survive, oil and natural gas companies need to replenish their oil and natural gas resources as 

they are produced, even if demand for those fuels is stable. But with the demand for natural gas and 

petroleum forecast to grow sharply over the coming decade, continuing the trend of recent years, the 

question arises all the more prominently: what strategies do companies employ to obtain the natural gas 

and petroleum they intend to supply? 

To shed light on this question, two choices companies face were examined: to find and develop the 

reserves themselves in areas they have mineral rights to, or to acquire reserves already discovered by 

others through mergers and acquisitions. This was termed the “make-or-buy” choice. Reasonable 

hypotheses were then developed to explain why companies choose one strategy or the other. 

The universe of companies examined to test these hypotheses was the set of companies responding to 

EIA’s FRS that held oil or natural gas reserves in the United States during the 1997 to 2002 period. 

More particularly, these companies are: TotalFinaElf USA, Shell Oil Company, Burlington Resources 

Inc., ConocoPhillips Company, Inc., Marathon Oil, Corp., Exxon Mobil Corporation, Amerada Hess 

Corporation, Anadarko Petroleum, Inc., Unocal Corporation, Apache Corporation, EOG Resources, Inc., 

Devon Energy Corporation, Kerr-McGee Corporation, BP America, Inc., Williams Companies, Inc., 

Occidental Petroleum Corporation, ChevronTexaco Corporation, Dominion Resources, Inc., El Paso 

Corporation, and XTO Energy, Inc. 

The 1997 to 2002 period of study was chosen because, while there were relatively few mergers among 

the FRS companies in the first part of the 1990’s, around 1997 a wave of mergers began, continuing 

through 2002 (Figure 37). 

What goes into a company’s decision on how to obtain the natural gas and petroleum it intends to 

supply? Since it is costly to find oil and natural gas resources that will yield successfully producing 

wells and since the FRS companies are profit seekers, it is natural to examine oil and gas finding costs as 

an explanatory factor. A company’s finding cost is its average cost of finding a unit of reserves. Other 

things being equal, one would expect that companies which faced higher finding costs for oil and gas 

resources would tend to be buyers of reserves, whereas companies with lower finding costs would tend 

to be “makers” of reserves (that is, develop their own reserves in areas where they had mineral rights). 

To test these explanations, the FRS data was examined. 

In fact, the data revealed a tendency for companies with higher finding costs to buy their reserves rather 

than “make” them. As expected, for companies with higher finding costs, buying reserves is the strategy 

that entails relatively lower cost (Table 21). However, the statistical significance of these results was 

below the threshold of significance. Consequently, the data hint at the tendency just described, but are 

not strong enough to warrant a definite conclusion on this score. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 81
0

10

20

30

40

50

60

70

1981 1984 1987 1990 1993 1996 1999 2002

Percent

 Note: Solid line includes U.S. reserves added in BP-Amoco (1998), Exxon-Mobil (1999), BP Amoco-ARCO (2000),

Chevron-Texaco (2001), and El Paso-Coastal (2001) mergers as purchases in addition to all other transactions. These 

mergers were accounted for using the "pooling of interests" method, which does not record reserves acquired in a business

combination as purchased reserves. For mergers initiated after June 30, 2001, the Financial Accounting Standards Board 

(FASB) no longer allows the use of this method of accounting in business combinations. Dashed line excludes the effects

of accounting for "mergers as purchases."

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Figure 37. Share of FRS Companies' Domestic Oil and Natural Gas Reserve Additions due to Mergers and 

 Acquisitions, 1981-2002 

U.S. Finding Cost Return on Investment

(Dollars Per Barrel of Oil Equivalent) (Percent)

Makers 6.83 12.71

Buyers 7.88 10.25

 Source: Energy Information Administration, Form EI-28 (Financial Reporting System).

1997-2002

Company Type

Table 21. Average Finding Cost and Return on Investment for FRS Companies, 

 1997-2002 

 Notes: Included are those 20 companies that were FRS respondents in 2002 and had oil or natural gas reserves

(this, for example, excluded FRS respondents who are only refiner/marketer companies). Return on investment is

net income as a percent of net property, plant, and equipment.

An interesting finding was that companies having a higher “purchase ratio”, that is, the ratio of reserve 

additions that were purchased to reserve additions that were developed by the company, tended to have 

higher growth in reserves. One possible explanation for this might be that these companies adopted a 

strategy of fast growth, and the way for them to achieve that was to buy reserves rather than the slower 

process of developing their own. 

The rate of return on investment was also examined for both the “make” companies and the “buy” 

companies (Table 21). It turns out that “makers” tended to have a higher return on investment than 

“buyers.” Furthermore, unlike the result for finding costs, this result was statistically significant. One 

possible explanation for this outcome is that “makers” may have been focusing on maximizing profits 

while “buyers” were focusing on growing fast. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 82
Another possibility is that the initial endowments of these two types of companies, their starting 

positions, were different. This may have led to different strategies and consequently different outcomes 

in profitability. Specifically, companies tending toward the strategy of “making” their own reserves, 

relative to companies electing to buy reserves, may have been endowed with more lucrative assets: 

namely, a base of reserves tending to be relatively rich and productive. Whether having a relatively 

fortunate initial position stems from good fortune or shrewd decision-making in the past is an open 

question. Thus, although the level of finding costs that an FRS company experiences is one of the 

factors that a company would examine, it evidently does not, by itself, determine the choice of reserve 

acquisition and replacement strategy.

a

Energy Information Administration, Financial Aspects of the U.S. Oil and Gas Industry in the 1980’s, DOE/EIA-0524

(Washington, DC, May 1989). 

SPECIAL TOPIC: LNG -- A Future for the FRS Companies? 

There appears to be steadily increasing interest in LNG as an energy source in the United States, as 

alternative sources are being sought to satisfy the anticipated growth in demand for natural gas. The 

FRS companies play a major role in the United States’ LNG market: they own two of the four LNG 

import facilities and the sole export facility in the United States.a

While FRS company investment in LNG is clearly an important part of supplying U.S. energy needs, the 

discussion below indicates that FRS company activity in LNG was mixed in 2002: some FRS 

companies expanded their LNG activities while others contracted in that area. 

Domestic Facilities: Cove Point, Elba Island, and Alaska’s Kenai Peninsula. 

In September 2002, Dominion Resources bought the Cove Point LNG facility in Lusby, Maryland, for 

$225 million from The Williams Companies (another FRS company).b

 The purchased assets include an 

LNG import facility, an LNG storage facility, and an approximately 85-mile natural gas pipeline feeding 

into an established natural gas market in the mid-Atlantic region. Dominion reports that capacity at the 

Cove Point facility is fully booked.c

 The El Paso Corporation also held rights to capacity at the Cove 

Point LNG regasification facility. However, in the fourth quarter of 2002, El Paso sold that capacity 

(along with its position in the LNG purchase and sale agreement at Cove Point) to Norway’s Statoil for 

$210 million. 

Serving the natural gas market in the southeastern United States is a facility which El Paso still owns, 

the LNG terminal and regasification facility at Elba Island, Georgia. This facility began receiving 

deliveries in December 2001.d

 In August 2002, Marathon acquired capacity rights for 22 years for 

delivering LNG to the Elba Island facility.e

 This would provide a potential outlet for Marathon-owned 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 83
natural gas resources located near the company’s proposed LNG plant in Equatorial Guinea, where the 

natural gas would be liquefied and shipped to Elba Island for regasification and subsequent distribution 

to the U.S. southeastern natural gas market.f

 

There is only one LNG export facility in the United States, located on the Kenai Peninsula in southern 

Alaska. At present, it is entirely devoted to serving the Pacific Rim natural gas market.g

 Phillips built 

this 230-million-cubic-feet-per-day export facility in a joint venture with Marathon.h

 ConocoPhillips, 

the result of the recent merger of Conoco and Phillips, owns a 70-percent share and is the operator of the 

facility, while Marathon owns the other 30 percent. Export began in 1969, under a 15-year contract to 

supply LNG to Tokyo Electric and Tokyo Gas. Shipping to those two utilities has continued 

uninterrupted since then. As with the investment in the Kenai Peninsula LNG export facility, much of 

FRS companies’ investments in LNG projects abroad is intended for the Pacific Rim market, with some

also aimed at portions of the European market. 

Investments in LNG Facilities Abroad: Qatar and Australia 

The Exxon Mobil Corporation has been involved with LNG for more than thirty years, and, through its 

subsidiaries, has had a presence in Qatar since 1935, i

 where Exxon Mobil owns interest in two LNG 

projects:j

- Qatargas, in which Exxon Mobil has a 10-percent interest, with most of the LNG going to Japan 

and Spain. 

- RasGas LNG facilities, in which Exxon Mobil has a 25-percent interest, with most of the LNG 

going to Korea. Exxon Mobil also has a 28.5-percent interest in the two additional RasGas LNG 

trains currently under construction, each with a planned capacity of 4.7 million metric tons per 

year, intending to supply India and Europe. 

The ChevronTexaco Corporation holds a one-sixth interest in the North West Shelf Venture in 

Australia.k

 About 60 percent of the natural gas from this venture is sold in the form of LNG to Japanese 

utilities, with the remaining natural gas being sold in the Australian domestic market.l

 A project to 

increase this LNG capacity by about 50 percent is currently under construction, and a conditional 25-

year agreement was signed with China in October 2002 to supply the proposed Guangdong LNG 

Terminal Project.m 

ConocoPhillips also has ownership in major natural gas production ventures in the Bayu-Undan field in 

the Timor Sea off Australia, and is in development phase of a planned liquefaction facility near Darwin, 

Australia.n

 To market this LNG, in March 2002 ConocoPhillips signed an agreement with the same two 

utilities it has been supplying, Tokyo Electric and Tokyo Gas, for the sale of LNG for 17 years.o

Financial Distress Causes Retrenching in LNG: El Paso 

During 2002, El Paso felt the effects of the downturn of the energy trading and merchant services 

businesses that began with the demise of Enron in 2001.p

 Contributing to its financial pressures, El Paso 

suffered from a $67-million decline in the fair value of its LNG supply contract derivatives in 2002 

compared to a $86-million increase in the fair value of those contracts in 2001.q

 El Paso stated that the 

significant capital and credit requirements associated with the LNG business were in excess of its 

current financial capacity.r

 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 84
El Paso responded to these developments by initiating a series of actions to wind down its involvement 

in non-core businesses including energy trading and petroleum markets, as well as the capital-intensive 

business of LNG operations.s

 In particular, in February 2003 El Paso extricated itself from obligations 

to charter four LNG tankers, in exchange for payments by El Paso totaling $24 million.t

 

What Next?

There are many proposals by FRS and other companies to build LNG facilities, with varying degrees of 

promise. Some proposals may be intended as strategic moves by a company considering investing in a 

particular LNG market, designed to discourage other companies from entering that market. However, 

actual investment in LNG facilities, particularly in liquefaction, requires large commitments of capital. 

Not all companies are currently in a strong enough financial position to risk undertaking such projects. 

Nonetheless, given the ever-increasing demand for natural gas, involvement by the FRS companies in 

the LNG market warrants continued watching. 

a

 The two domestic import LNG facilities in which the FRS companies have no ownership are in Lake Charles, Louisiana and

Everett, Massachusetts. b

Dominion Resources, Inc., 2002 Securities and Exchange Commission Form 10K, p. 3. c

Dominion Resources, Inc., 2002 Annual Report, p. 12. d

El Paso Corporation, 2002 Securities and Exchange Commission Form 10K, p. 5. e

Marathon Oil Corporation, 2002 Securities and Exchange Commission Form 10K, p. 19. f

Marathon Oil Corporation, 2002 Annual Report, p. 3. g

Phillips Petroleum Company, Press Release (September 14, 2000). h

Marathon Oil Corporation, Press Release (February 28, 2002). i

Exxon Mobil Corporation, Press Release (April 4, 2001). j

Exxon Mobil Corporation, 2002 Financial & Operating Review, p.48 k

ChevronTexaco Corporation, 2002 Annual Report, p. 1. l

ChevronTexaco Corporation, 2002 Annual Report, p. 23. mChevronTexaco Corporation, 2002 Annual Report, p. 23. n

ConocoPhillips, 2002 Annual Report, p. 17. o

ConocoPhillips, 2002 Annual Report, p. 14. p

El Paso Corporation, 2002 Securities and Exchange Commission Form 10K, pp. 1-2. q

El Paso Corporation, 2002 Securities and Exchange Commission Form 10K, p. 60. r

El Paso Corporation, 2002 Securities and Exchange Commission Form 10K, p. 22. s

El Paso Corporation, 2002 Securities and Exchange Commission Form 10K, p. 2. t

El Paso Corporation, 2002 Securities and Exchange Commission Form 10K, p. 23. 

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 85

Energy Information Administration / Performance Profiles of Major Energy Producers 2002 87

Appendix A 

The Financial Reporting System (FRS) 

The legislation establishing the Financial Reporting System (FRS) requires the reporting of individual 

company financial and operating data to be on a "uniform and standardized basis" so that the data can be 

aggregated and comparisons can be made across companies and groups of companies. 

The legislation also required the Energy Information Administration (EIA) to consult with the U.S. 

Securities and Exchange Commission in an effort to be consistent with other Federal financial 

accounting practices. 

Accordingly, the FRS reporting form (Form EIA-28) necessarily incorporates a number of specific 

energy financial accounting principles and conventions. Details on these financial accounting concepts 

and principles can be found on the EIA Worldwide Web site at 

http://www.eia.doe.gov/emeu/perfpro/appenda.html. In particular, the interested reader is referenced to 

the following subheadings: 

• Survey Format (see HTUhttp://www.eia.doe.gov/emeu/perfpro/appenda.html#rptfrmtUTH), 

• Petroleum Segment Overview (see HTUhttp://www.eia.doe.gov/emeu/perfpro/appenda.html#petovwUTH), 

• Selection of Reporting Companies (see HTUhttp://www.eia.doe.gov/emeu/perfpro/appenda.html#criteriaUTH), 

• Financial Analysis Guide (see HTUhttp://www.eia.doe.gov/emeu/perfpro/appenda.html#faguideUTH), 

• Accounting Practices (see HTUhttp://www.eia.doe.gov/emeu/perfpro/appenda.html#acctprUTH). 

Appendix B 

Detailed Statistical Tables 

Operating Statistics 1996 1997 1998 1999 2000 2001 2002

Petroleum and Natural Gas 

 Net Production 

 Crude Oil and Natural Gas Liquids (million barrels)

 FRS Companies 1,532.4 1,458.8 1,388.8 1,305.7 1,267.9 1,363.2 1,346.4

 U.S. Industry1 3,023.0 3,002.0 2,824.0 2,848.0 2,801.0 2,805.0 2,759.0

 FRS as a Percent of U.S. Industry 50.7 48.6 49.2 45.8 45.3 48.6 48.8

 Natural Gas (billion cubic feet)

 FRS Companies 8,191.6 8,299.1 8,395.9 7,994.1 8,340.1 8,838.0 8,712.5

 U.S. Industry1 18,861.0 19,211.0 18,720.0 18,928.0 19,219.0 19,779.0 19,353.0

 FRS as a Percent of U.S. Industry 43.4 43.2 44.8 42.2 43.4 44.7 45.0

 Net Imports 

 Crude Oil and Natural Gas Liquids (million barrels)

 FRS Companies 565.7 571.1 634.7 474.9 324.1 716.1 630.5

 U.S. Industry1 2,946.6 3,191.0 3,358.5 3,366.4 3,527.0 3,620.1 3,523.2

 FRS as a Percent of U.S. Industry 19.2 17.9 18.9 14.1 9.2 19.8 17.9

 Refinery Capacity (thousand barrels per day)

 FRS Companies 10,477.0 9,410.0 14,277.0 14,158.0 14,424.0 14,682.0 14,557.0

 U.S. Industry1 16,031.8 16,128.7 16,567.0 16,787.0 17,177.4 17,367.4 17,338.9

 FRS as a Percent of U.S. Industry 65.4 58.3 86.2 84.3 84.0 84.5 84.0

 Refinery Output2

 (thousand barrels per day)

 FRS Companies 10,954.0 10,030.0 14,929.0 14,639.0 14,499.0 15,022.0 14,761.0

 U.S. Industry1 16,800.7 17,234.3 17,499.6 17,493.1 17,763.2 17,688.9 17,654.5

 FRS as a Percent of U.S. Industry 65.2 58.2 85.3 83.7 81.6 84.9 83.6

Coal Production

(million tons)

 FRS Companies 169.4 163.3 73.9 44.0 35.5 33.0 29.3

 U.S. Industry1 1,063.9 1,089.9 1,117.5 1,100.4 1,073.6 1,127.7 1,093.3

 FRS as a Percent of U.S. Industry 15.9 15.0 6.6 4.0 3.3 2.9 2.7

 FRS companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B1. Selected U.S. Operating Statistics for FRS Companies and U.S. Industry, 1996-2002

 Note: The data for total U.S. production of crude oil and natural gas liquids and natural gas (dry) utilized in this report are taken 

from Energy Information Administration, Form EIA-23 (Annual Survey of Domestic Oil and Gas Reserves); see U.S. Crude Oil, 

Natural Gas, and Natural Gas Liquids Reserves 2002 Annual Report November 2003). This source is utilized in order to preserve

consistency between production reported in the context of oil and gas reserves and reserve additions and production reported 

elsewhere in this report. However, the official Energy Information Administration U.S. totals for crude oil and natural gas plant 

production are 2,936 million barrels in 2002 and 2,940 million barrels in 2001. (See Energy Information Administration, Petroleum

Supply Annual 2002, Volume I (June 2003), p. 2.) For dry natural gas production, the official Energy Information Administration

U.S. totals are 19,047 billion cubic feet in 2002 and 19,676 billion cubic feet in 2001. (See Energy Information Administration,

Natural Gas Monthly, September 2003, Table 1.) 

 Sources: Industry data - Petroleum net production: Energy Information Administration, Form EIA-23; see U.S. Crude Oil, Natural 

Gas, and Natural Gas Liquids Reserves, 2002 Annual Report (November 2003). Net imports: data compiled for the International 

Energy Agency by the Petroleum Supply Division, Office of Oil and Gas, Energy Information Administration. Refinery capacity and 

refinery output: Energy Information Administration, Forms EIA-820 (Annual Refinery Report) and EIA-810 (Monthly Refinery

Report); see Petroleum Supply Annual, 2001 and 2002. Coal production: 1996-2000--EIA, Coal Industry Annual , annual reports; 

2001-2002 - EIA, Annual Coal Report, annual reports . 

 1 U.S. area is defined to include the 50 States, District of Columbia, U.S. Virgin Islands, and Puerto Rico.

 2

 For FRS companies, includes refinery output at own refineries for own account and at others' refineries for own account.

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 89
2001 2002 2001 2002

Income Statement

 Operating Revenues 803.7 698.9 4,841.0 4,703.8

 Operating Expenses -735.6 -659.7 -4,380.5 -4,206.2

 Operating Income 68.1 39.2 460.5 497.6

 Interest Expense -9.1 -10.7 -114.0 -98.2

 Other Income1 6.3 6.7 -148.5 -246.1

 Income Taxes -27.7 -14.6 -111.7 -127.1

 Net Income 37.7 20.6 86.4 26.2

Cash Flows from Operations2 

 Net Income 37.7 20.6 86.4 26.2

 Other Items, Net

3 51.9 54.4 502.1 556.3

Net Cash Flow from Operations 89.6 75.0 588.5 582.5

Cash Flows from Investing Activities2 

 Additions to Property, Plant & Equipment -100.3 -90.5 -360.8 -290.3

 Other Investment Activities, Net

4 6.0 36.4 -128.3 -103.7

Net Cash Flow from Investing Activities -94.3 -54.1 -489.2 -394.0

Cash Flows from Financing Activities2

 Proceeds from Long-Term Debt 55.0 34.1 539.7 460.1

 Proceeds from Equity Security Offerings 6.3 4.9 72.5 33.8

 Dividends to Shareholders -17.1 -17.7 -98.7 -95.4

 Reductions in Long-Term Debt -34.3 -27.9 -370.1 -336.4

 Stock Repurchases -7.5 -4.7 -110.9 -108.9

 Other Financing Activities, Net 3.8 -7.1 -60.1 -85.2

Net Cash Flow from Financing Activities 6.2 -18.4 -27.5 -132.0

Effect of Exchange Rate Changes on Cash -0.3 0.6 -2.8 4.9

Increase (Decrease) in Cash and Cash

Equivalents 1.3 3.0 69.0 61.4

FRS companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B2. Selected Financial Items for the FRS Companies and the S&P 

 Industrials, 2001-2002 

 (Billion Dollars)

 1

 "Other Income" includes other revenue and expense (excluding interest expense), discontinued 

operations, extraordinary items, and accounting changes.

 2 Items that add to cash are positive, and items that use cash are shown as negative values.

 3

 "Other Items, Net" includes: Depreciation, Depletion & Amortization, deferred taxes, dry hole expense, 

minority interest, recognized undistributed earnings/(losses) of unconsolidated affiliates, (gain)/loss on

disposition of Property, Plant & Equipment, changes in operating assets and liabilities, and other noncash 

items, excluding net change in short-term debt; other cash items, net.

 4

 "Other Investment Activities, Net" includes additions to investments and advances and proceeds from

disposals of PP&E.

 Sources:

Standard & Poor's (S&P) Industrials data are extracted from the S&P 500 Index, excluding the Financial,

Utilities, and Transportation, sectors - Compustat PC Plus, a service of Standard & Poor's.

FRS Companies S&P Industrials

Selected Financial Items

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 90
2001 2002 2001 2002

Balance Sheet 

 Assets 

 Current Assets 147.5 156.3 1,441.2 1,510.2

 Noncurrent Assets 

 Property, Plant, and Equipment (PP&E) 

 Gross 806.0 826.3 3,222.8 3,178.6

 Accumulated Depreciation, Depletion,

 and Amortization (DD&A) -373.6 -379.6 -1,457.0 -1,479.9

 Net PP&E 432.4 446.6 1,765.8 1,698.7

 Investments and Advances 57.3 53.9 155.3 135.3

 Other Noncurrent Assets 97.9 115.7 2,933.4 2,910.4

 Subtotal Noncurrent Assets 587.5 616.2 3,308.3 3,136.1

Total Assets 735.0 772.5 6,295.6 6,254.5

Liabilities and Stockholders Equity 

 Liabilities 

 Current Liabilities 159.8 156.7 1,098.3 1,087.4

 Long-Term Debt 132.0 154.0 1,397.2 1,493.7

 Other Long-Term Items 144.0 156.1 1,568.7 1,653.1

 Minority Interest 15.5 11.0 82.9 75.5

 Subtotal Liabilities and Other Items 451.3 477.8 4,147.1 4,309.8

 Stockholders' Equity 

 Retained Earnings 209.7 206.1 1,150.9 962.0

 Other Equity 74.0 88.7 997.6 982.7

 Subtotal Stockholders' Equity 283.7 294.7 2,148.5 1,944.7

Total Liabilities and Stockholders' Equity 735.0 772.5 6,295.6 6,254.5

Financial Ratios 

 Net Income/Stockholders' Equity 13.3 7.0 4.0 1.3

 Net Income plus Interest/Total Invested Capital 11.3 7.0 5.7 3.6

 Dividends/Net Cash Flow from Operations 19.1 23.7 16.8 16.4

 Long-term Debt/Stockholders' Equity 46.5 52.3 65.0 76.8

FRS companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

 Sources: 

Standard & Poor's (S&P) Industrials data are extracted from the S&P 500 Index, excluding the Financial, 

Utilities, and Transportation, sectors - Compustat PC Plus, a service of Standard & Poor's.

Table B3. Balance Sheet Items and Financial Ratios for FRS Companies and

 S&P Industrials, 2001-2002

FRS Companies S&P Industrials

 

(billion dollars)

(percent)

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 91
Balance Sheet Items 1996 1997 1998 1999 2000 2001 2002

Assets 

 Current Assets 

 Cash & Marketable Securities 13.4 12.2 8.1 12.2 18.7 18.6 19.5

 Trade Accounts & Notes Receivable 56.2 51.2 47.8 68.1 98.6 71.4 78.7

 Inventories 

 Raw Materials & Products 22.7 21.4 21.6 23.3 25.6 23.4 23.2

 Materials & Supplies 3.8 3.7 3.8 3.9 4.4 7.3 7.6

 Other Current Assets 12.1 12.4 12.9 13.4 49.1 26.7 27.4

 Total Current Assets 108.2 100.9 94.2 121.0 196.5 147.5 156.3

Non-current Assets 

 Property, Plant & Equipment (PP&E)

 Gross PP&E 635.0 636.9 671.0 708.0 757.2 806.0 826.3

 Accumulated Depcreciation,

 Depletion, and Amortization -331.6 -333.3 -334.5 -355.5 -351.6 -373.6 -379.6

 Net PP&E 303.4 303.6 336.5 352.5 405.5 432.4 446.6

 Investments & Advances to Unconsolidated Affiliates 32.3 44.2 53.9 58.2 62.3 57.3 53.9

 Other Non-current Assets 26.8 35.2 35.8 39.6 86.9 97.9 115.7

 Total Non-current Assets 362.4 382.9 426.3 450.3 554.8 587.5 616.2

Total Assets 470.6 483.8 520.4 571.3 751.2 735.0 772.5

Liabilities & Stockholders' Equity 

 Liabilities 

 Current Liabilities 

 Trade Accounts & Notes Payable 61.4 57.7 62.8 79.4 102.4 90.6 91.8

 Other Current Liabilities 48.8 49.2 51.1 51.9 96.4 69.2 64.9

 Long-Term Debt 70.9 73.4 94.6 104.0 120.0 132.0 154.0

 Deferred Income Tax Credits 45.5 46.3 49.0 53.1 68.2 77.0 76.1

 Other Deferred Credits 19.2 18.8 18.4 18.8 34.1 23.3 27.9

 Other Long-Term Items 40.6 41.6 39.7 42.6 41.2 43.7 52.1

 Minority Interest in Consolidated Affiliates 6.6 8.2 10.4 15.2 17.1 15.5 11.0

 Total Liabilities 292.9 295.1 326.0 364.9 479.5 451.3 477.8

Stockholders' Equity 156.3 160.8 165.8 170.6 199.2 209.7 206.1

 Retained Earnings 21.4 27.9 28.7 35.7 72.5 74.0 88.7

 Other Equity 

 Total Stockholders' Equity 177.8 188.7 194.4 206.3 271.8 283.7 294.7

Total Liabilities & Stockholders' Equity 470.6 483.8 520.4 571.3 751.2 735.0 772.5

Cumulative at Year End 1.2 -2.7 -2.3 -2.7 -3.0 -5.1 -2.0

for the Current Year -0.4 -3.9 0.0 -0.3 -2.1 -1.0 3.1

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B4. Consolidated Balance Sheet for FRS Companies, 1996-2002

 (Billion Dollars)

Memo: 

Foreign Currency Translation Adjustment 

Foreign Currency Translation Adjustment 

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 92
Income Statement Items Consolidated

Eliminations &

Nontraceables Petroleum Coal

Other

Energy

Nonenergy

Operating Revenues 698,884 -33,320 642,126 737 43,243 46,098

Operating Expenses

 General Operating Expenses 598,972 -32,595 547,481 572 41,706 41,808

 Depreciation, Depletion, & Allowance 45,529 780 41,561 W 878 2,239

 General & Administrative 15,161 2,202 10,021 W 1,302 1,617

Total Operating Expenses 659,662 -29,613 599,063 662 43,886 45,664

Operating Income 39,222 -3,707 43,063 75 -643 434

Other Revenue & (Expense)

 Earnings of Unconsolidated Affiliates 4,103 -294 4,714 W -563 244

 Other Dividend & Interest Income 2,614 2,614 - - - -

 Gain/Loss on Disposition of

 Property, Plant, & Equipment 1,374 -295 1,024 W W 646

 Interest Expenses & Financial Charges -10,748 -10,748 - - - -

 Minority Interest in Income -1,068 -1,068 - - - -

 Foreign Currency Translation Effects 197 197 - - - -

 Other Revenue & (Expense) 477 477 - - - -

Total Other Revenue & (Expense) -3,051 -9,117 5,738 W -565 890

Pretax Income 36,171 -12,824 48,801 78 -1,208 1,324

Income Tax Expense 14,566 -5,381 20,023 21 15 -112

Discontinued Operations -828 -81 -968 W W W

Extraordinary Items and Cumulative 

Effect of Accounting Changes -185 -112 82 W W W

Net Income 20,592 -7,636 27,892 -46 -1,460 1,842

Table B5. Consolidating Statement of Income for FRS Companies, 2002

 (Million Dollars)

 - = Not available.

 W = Data withheld to avoid disclosure.

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 93
Consolidated Production

Refining/ 

Marketing

PipelinesConsolidated ProductionRefining/

Marketing

Int'l

 Marine

 Operating Revenues

 Raw Material Sales 126,771 71,138 109,067 1,625 87,424 61,405 63,582 0

 Refined Products Sales 267,974 W 272,190 W 141,742 W 142,227 0

 Transportation Revenues 11,115 1,085 2,562 9,561 1,698 376 W 2,643

 Management and Processing Fees 1,491 W 1,257 W 1,968 W W W

 Other 14,161 968 12,781 416 4,598 529 4,051 W

Total Operating Revenues 421,512 73,974 397,857 11,810 237,430 63,932 212,109 2,681

Operating Expenses

 General Operating Expenses 368,645 34,304 390,037 6,433 195,652 26,694 207,559 2,691

 Depreciation, Depletion, & Allowance 24,935 18,268 5,617 1,050 16,626 14,579 2,011 W

 General & Administrative 7,760 1,653 3,695 2,412 2,261 945 1,310 W

Total Operating Expenses 401,340 54,225 399,349 9,895 214,539 42,218 210,880 2,733

Operating Income 20,172 19,749 -1,492 1,915 22,891 21,714 1,229 -52

Other Revenue & (Expense)

 Earnings of Unconsolidated Affiliates 1,944 1,041 613 290 2,770 3,082 -331 W

 Gain(Loss) on Disposition of

 Property, Plant, & Equipment 996 312 367 317 28 -7 37 W

Total Other Revenue & (Expense) 2,940 1,353 980 607 2,798 3,075 -294 17

Pretax Income 23,112 21,102 -512 2,522 25,689 24,789 935 -35

Income Tax Expense 7,481 6,274 346 861 12,542 12,038 501 3

Discontinued Operations -1,139 W W W W W W 0

Extraordinary Items and Cumulative

Effect of Accounting Changes 68 W W W W W W 0

Contribution To Net Income 14,560 15,030 -2,164 1,694 13,332 12,918 452 -38

 W = Data withheld to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B6. Consolidating Statement of Income for FRS Companies, U.S. and Foreign Petroleum

 Segments, 2002

 (Million Dollars)

Income Statement Items

U.S. Petroleum Foreign Petroleum

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 94
Net PP&E

Investments & 

Advances

Additions to

PP&E

Additions to

Investments & 

Advances DD&A

Petroleum 

 United States

 Production 137,933 4,773 29,191 863 18,268

 Refining/Marketing

 Refining 53,109 4,439 14,644 451 3,710

 Marketing 15,124 959 1,452 430 1,171

 Refining/Marketing Transport 

 Pipelines 2,410 774 740 68 250

 Marine 1,265 W 530 W 296

 Other 1,113 W 239 W 190

 Total U.S. Refining/Marketing 73,021 6,545 17,605 1,259 5,617

 Rate Regulated Pipelines

 Refined Products 1,965 632 92 151 45

 Natural Gas 21,767 3,604 2,049 -103 817

 Crude Oil and Liquids 4,335 553 352 195 188

 Total Rate Regulated Pipelines 28,067 4,789 2,493 243 1,050

 Total U.S. Petroleum 239,021 16,107 49,289 2,365 24,935

 Foreign 

 Production 124,225 15,738 30,138 3,554 14,579

 Refining/Marketing 27,998 W 4,055 W 2,011

 International Marine 529 W 10 W 36

 Total Foreign Petroleum 152,752 22,038 34,203 4,527 16,626

Total Petroleum 391,773 38,145 83,492 6,892 41,561

Coal

 Foreign 0 0 W 0

 United States 522 W W 0 71

Total Coal 522 W 23 0 71

Other Energy

 Foreign 2,640 2,858 1,154 304 74

 United States 14,038 1,800 1,759 477 804

Total Other Energy 16,678 4,658 2,913 781 878

 Nonenergy

 Foreign Chemicals 7,057 2,650 544 336 578

 U.S. Chemicals 19,485 4,723 1,608 -166 1,531

 Foreign Other Nonenergy W 2,138 W -393 W

 U.S. Other Nonenergy W 763 W 183

Total Nonenerg

0

W

y 28,799 10,274 2,776 -40 2,239

Nontraceable 8,877 774 1,265 -104 780

Consolidated 446,649 53,873 90,469 7,529 45,529

 W = Data withheld to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B7. Net Property, Plant, and Equipment (PP&E), Additions to PP&E, Investments and 

 Advances, and Depreciation, Depletion, and Amortization (DD&A), by Lines of

 Business for FRS Companies, 2002

 (Million Dollars)

Year End Balance Activity During Year

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 95
2001 2002 2001 2002 2001 2002 2001 2002

 Petroleum 12.2 6.5 12.5 8.0 11.8 6.3 12.2 2.7

 U.S. Petroleum 13.1 5.7 12.7 7.3 12.7 5.7 14.5 2.6

 Oil and Gas Production 13.1 10.5 12.3 12.8 14.0 10.4 13.3 6.1

 Refining/Marketing 14.5 -2.7 16.7 -3.3 10.9 -2.8 15.1 -2.0

 Pipelines 9.7 5.2 8.2 5.7 11.0 3.0 25.7 13.6

 Foreign Petroleum 10.9 7.6 12.3 8.6 9.0 8.0 7.7 2.9

 Oil and Gas Production 11.2 9.2 13.0 11.4 9.3 8.3 7.9 2.9

 Refining/Marketing 9.5 1.3 10.0 1.1 5.7 3.3 5.7 3.2

 International Marine 25.9 -6.2 24.9 -5.6 W 0.0 0.0 0.0

Coal 9.0 -8.5 5.1 -33.6 34.4 W W W

Other Energy 9.0 -6.8 15.2 -31.9 5.7 6.5 2.8 10.5

Nonenergy -6.6 4.7 2.9 4.6 -33.9 0.8 -1.3 13.1

 W = Data withheld to avoid disclosure.

 Note: Return on investment measured as contribution to net income/net investment in place.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B8. Return on Investment for Lines of Business for FRS Companies Ranked by Total

 Energy Assets, 2001-2002

 (Percent)

All FRS Top Four Five through Twelve All Other Line of Business

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 96
1996 1997 1998 1999 2000 2001 2002

 Sources of R&D Funds 

 Federal Government W W W 27 W W W

 Internal Company 2,675 2,841 1,668 1,377 1,316 1,542 1,742

 Other Sources W W W 20 W W W

Total Sources 2,717 2,885 1,707 1,424 1,326 1,570 1,753

Breakdown of R&D Expenditures 

 Oil & Gas Recovery 482 585 606 430 453 592 464

 Other Petroleum 432 380 365 345 327 376 656

 Coal Gasification/Liquefaction W W W W W 0 0

 Other Coal W W W W W 0 W

 Nuclear and Other Energy 51 54 W W W W 59

 Nonenergy 1,617 1,738 616 538 452 526 517

 Unassigned 127 120 85 W W W W

Total Expenditures 2,717 2,885 1,707 1,424 1,326 1,570 1,753

Table B9. Research and Development Expenditures for FRS Companies, 1996-2002

 (Million Dollars)

 W = Data withheld to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 97
Line of Business Top Four

Five through 

Twelve All Other All FRS

Petroleum 51.5 29.4 19.1 100.0

 United States 41.9 36.5 21.6 100.0

 Production 41.8 38.6 19.6 100.0

 Refining/Marketing 34.1 33.8 32.1 100.0

 Refining 28.7 36.1 35.2 100.0

 Marketing 56.0 15.3 28.8 100.0

 Rate Regulated Pipelines 61.1 34.1 4.9 100.0

 Foreign 65.6 19.0 15.4 100.0

 Production 59.9 22.2 17.8 100.0

 Refining/Marketing 88.2 6.2 5.5 100.0

 International Marine 100.0 0.0 0.0 100.0

Coal 53.1 3.9 43.0 100.0

Other Energy 35.0 63.4 1.7 100.0

 Nonenergy 63.2 24.5 12.3 100.0

 Chemicals 60.0 26.6 13.4 100.0

 Other Nonenergy 84.6 10.5 4.9 100.0

Consolidated 52.1 30.2 17.6 100.0

Table B10. Size Distribution of Net Investment in Place for FRS Companies Ranked

 by Total Energy Assets, 2002

 (Percent) 

 Note: Sum of components may not equal total due to independent rounding, eliminations, and nontraceables. 

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 98
Cash Flows 1 1996 1997 1998 1999 2000 2001 2002

 Cash Flows From Operations 

 Net Income 32,029 32,082 12,519 22,866 53,192 37,735 20,592

 Minority Interest in Income 845 896 764 1,161 1,912 2,172 1,068

 Depreciation, Depletion, & Allowance 29,331 29,569 35,445 32,452 37,621 46,377 45,529

 Dry Hole Expense, This Year 1,812 2,069 2,518 1,808 1,328 2,344 1,925

 Deferred Income Taxes 2,863 2,301 -1,123 -25 5,611 3,145 -143

 Recognized Undistributed (Earnings)/Losses 

 of Unconsolidated Affiliates -226 -374 2,987 136 -3,319 -318 1,144

 (Gain)/Loss on Disposition of

 Property, Plant, & Equipment (PP&E) -1,940 -2,716 -2,658 -1,922 -2,065 -1,176 -1,374

 Changes in Operating Assets and Liabilities

 and Other Noncash Items -365 298 -3,792 -2,259 -6,269 2,848 -636

 Other Cash Items, Net -165 1,197 1,502 581 629 -3,490 6,847

Net Cash Flow From Operations 64,184 65,322 48,162 54,798 88,640 89,637 74,952

Cash Flows From Investing Activities 

 Additions to PP&E: 

 Due to Mergers and Acquisitions -2,281 -5,579 -18,868 -5,961 -49,722 -40,971 -33,147

 Other -41,872 -48,666 -51,046 -44,775 -52,470 -59,313 -57,322

 Total Additions to PP&E -44,153 -54,245 -69,914 -50,736 -102,192 -100,284 -90,469

 Additions to Investments and Advances -5,799 -7,685 -5,223 -6,874 -7,156 -10,086 -7,529

 Proceeds From Disposals of PP&E 10,942 9,320 16,243 13,267 26,663 7,683 14,310

 Other Investment Activities, Net 1,608 6,587 4,235 3,523 8,742 8,406 29,572

Cash Flow From Investing Activities -37,402 -46,023 -54,659 -40,820 -73,943 -94,281 -54,116

Cash Flows From Financing Activities 

 Proceeds From Long-Term Debt 10,708 17,901 27,072 29,862 33,292 54,987 34,094

 Proceeds From Equity Security Offerings 1,171 1,507 9,112 3,557 30,606 6,267 4,878

 Reductions in Long-Term Debt -18,883 -19,774 -18,019 -24,988 -29,323 -34,264 -27,863

 Purchase of Treasury Stock -1,299 -7,910 -5,776 -424 -5,362 -7,474 -4,680

 Dividends to Shareholders -15,585 -16,941 -17,169 -16,081 -18,981 -17,132 -17,744

 Other Financing Activities, Including Net Change

 in Short-Term Debt -578 5,537 6,859 -3,377 -17,205 3,848 -7,063

Cash Flow From Financing Activities -24,466 -19,680 2,079 -11,451 -6,973 6,232 -18,378

Effect of Exchange Rate on Cash 3 -255 -13 -24 -119 -308 571

Net Increase/(Decrease) in Cash

and Cash Equivalents 2,319 -636 -4,431 2,503 7,605 1,280 3,029

Table B11. Consolidated Statement of Cash Flows for FRS Companies, 1996-2002

 (Million Dollars)

 1

 Items that add to cash are positive, and items that use cash are shown as negative values. 

 Noncash Items: 

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 99
1996 1997 1998 1999 2000 2001 2002

Income Taxes (as per Financial Statements) 

 Current Paid or Accrued: 

 U.S. Federal, before Investment Tax Credit &

 Alternative Minimum Tax 6,141 5,656 603 1,375 11,705 8,812 390

 U.S. Federal Investment Tax Credit -146 -93 -85 -90 -129 -246 -245

 Effect of Alternative Minimum Tax -325 -400 -16 445 -1,222 -632 69

 U.S. State & Local Income Taxes 745 794 443 371 1,338 1,067 478

 Foreign Income Taxes 

 Canada 745 932 456 597 1,765 1,139 1,236

 Europe and Former Soviet Union 1 3,862 2,927 1,798 3,110 7,002 6,515 5,619

 Africa 1,956 1,926 449 1,607 3,617 3,057 2,884

 Middle East 1,326 802 745 1,286 2,380 1,937 1,753

 Other Eastern Hemisphere 2,195 1,901 992 1,679 2,214 1,676 1,674

 Other Western Hemisphere 729 1,739 428 346 900 695 669

 Total Foreign 10,813 10,227 4,868 8,625 17,878 15,019 13,835

Total Current 17,228 16,184 5,813 10,726 29,570 24,020 14,527

Deferred 

 U.S. Federal, before Investment Tax Credit 1,410 1,477 -373 1,480 3,168 2,403 241

 U.S. Federal Investment Tax Credit 69 -2 -28 -14 -78 -10 -18

 Effect of Alternative Minimum Tax 312 400 -16 -415 1,233 650 -69

 U.S. State & Local Income Taxes 56 54 104 136 221 26 76

 Foreign 930 519 -791 -1,075 910 567 -191

Total Deferred 2,777 2,448 -1,104 112 5,454 3,636 39

Total Income Tax Expense 20,005 18,632 4,709 10,838 35,024 27,656 14,566

Reconciliation of Accrued U.S. Federal 

Income Tax Expense To Statutory Rate

 Consolidated Pretax Income/(Loss) 52,808 51,453 16,017 33,837 86,702 68,246 36,171

 Less: Foreign Source Income not Subject to U.S. 6,230 5,827 251 2,160 13,355 8,918 8,816

 Equals: Income Subject to U.S. Tax 46,578 45,626 15,766 31,677 73,347 59,328 27,355

 Less: U.S. State & Local Income Taxes 782 785 570 486 1,497 895 345

 Less: Applicable Foreign Income Taxes Deducted 554 312 32 107 353 82 252

 Equals: Pretax Income Subject to U.S. Tax 45,242 44,529 15,164 31,084 71,497 58,351 26,758

 Tax Provision Based on Previous Line 15,834 15,621 5,332 10,902 25,032 20,438 9,363

 Foreign Tax Credits Recognized -6,926 -6,982 -3,563 -5,963 -9,787 -8,513 -7,283

 U.S. Federal Investment Tax Credit Recognized -123 -137 -124 -98 -129 -486 -245

 Statutory Depletion -54 -63 -30 -8 -3 -1 -3

 Effect of Alternative Minimum Tax 1 0 -16 23 11 16 0

 Other -1,273 -1,399 -1,485 -2,068 -447 -582 -1,462

Actual U.S. Federal Tax Provision (Refund) 7,459 7,040 114 2,788 14,677 10,872 370

Table B12. Composition of Income Taxes for FRS Companies, 1996-2002

 (Million Dollars)

 1 OECD Europe combined with the former Soviet Union and Eastern Europe to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

 Increase/(Decrease) in Taxes Due To:

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 100
1996 1997 1998 1999 2000 2001 2002

Production Taxes

 Oil and Gas Production 2,098 1,965 1,176 1,674 2,604 2,506 2,187

 Coal 139 172 47 43 30 35 3

 Other 1 1 1 0 0 25 1

Total Production Taxes 2,238 2,138 1,223 1,717 2,659 2,542 2,222

Superfund 14 WWW WWW

Import Duties 260 WWW WWW

Sales, Use, and Property 2,516 2,407 2,648 2,268 2,356 2,373 2,360

Payroll 1,531 1,406 1,357 1,289 1,259 1,193 1,121

Other Taxes 514 559 360 467 789 546 378

Total Taxes Paid (Other Than

Income Taxes) 7,073 6,601 5,660 5,825 7,186 6,740 6,156

Excise Taxes Collected 32,426 30,984 39,918 46,293 47,084 44,310 43,464

Table B13. U.S. Taxes Other Than Income Taxes for FRS Companies, 

 1996-2002

 (Million Dollars)

 1 Nuclear, Other Energy, and Nonenergy.

 W = Data withheld to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

3

2

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 101
1996 1997 1998 1999 2000 2001 2002

United States

 Exploration 

 Acquisition of Unproved Acreage 997 2,653 3,912 633 4,010 3,527 2,281

 Geological and Geophysical 625 750 916 621 849 758 821

 Drilling and Equipping 1 2,338 2,905 2,964 1,921 2,550 3,276 2,555

 Other 693 690 954 659 610 770 832

 Total Exploration 4,653 6,998 8,746 3,834 8,019 8,331 6,489

Development 

 Acquisition of Proved Acreage 922 2,928 3,568 1,144 27,939 7,383 7,572

 Lease Equipment 1,613 1,823 2,688 2,431 1,907 3,818 3,325

 Drilling and Equipping 1 6,154 8,540 7,769 5,022 8,788 11,671 10,711

 Other 2 1,290 1,557 1,657 1,056 1,391 2,655 3,715

 Total Development 9,979 14,848 15,682 9,653 40,025 25,527 25,323

Total U.S. Exploration and 

Development 14,632 21,846 24,428 13,487 48,044 33,858 31,812

Foreign

 Exploration 

 Acquisition of Unproved Acreage 745 565 2,159 2,252 4,105 4,696 2,588

 Geological and Geophysical 869 897 1,065 885 875 1,028 939

 Drilling and Equipping 1 2,277 2,684 2,650 1,579 1,824 2,677 2,108

 Other 919 1,128 1,299 903 1,087 1,146 864

 Total Exploration 4,810 5,274 7,173 5,619 7,891 9,547 6,499

Development 

 Acquisition of Proved Acreage 1,932 1,641 7,121 2,083 11,644 12,186 8,600

 Lease Equipment 2,064 2,207 2,505 2,142 1,842 3,186 2,538

 Drilling and Equipping 1 5,278 6,426 6,206 5,143 5,057 7,060 8,040

 Other 2 2,534 2,383 3,388 2,531 2,364 3,965 5,695

 Total Development 11,808 12,657 19,220 11,899 20,907 26,397 24,873

Total Foreign Exploration and 

Development 16,618 17,931 26,393 17,518 28,798 35,944 31,372

Table B14. Oil and Gas Exploration and Development Expenditures for FRS Companies,

 United States and Foreign, 1996-2002

 (Million Dollars)

 1 Expenditure incurred in a given year not cumulative (includes work-in-progress adjustment).

 2 Includes support equipment.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 102
Total Onshore Offshore

 Exploration and Development Expenditures

 Exploration Expenditures

 Unproved Acreage 4,869 2,281 1,483 798 2,588

 Drilling and Equipping:

 Completed Well Costs - 2,065 609 1,456 -

 Work-in-progress Adjustment - 490 165 -

 Total Drilling and Equipping 4,663 2,555 774 1,781 2,108

 Geological and Geophysical 1,760 821 355 466 939

 Other, Including Direct Overhead 1,696 832 411 421 864

 Total Exploration Expenditures 12,988 6,489 3,023 3,466 6,499

 Development Expenditures

 Proved Acreage (Including Mergers and Acquisitions) 16,172 7,572 6,951 621 8,600

 Drilling and Equipping: 

 Completed Well Costs - 8,665 5,929 2,736 -

 Work-in-progress Adjustment - 2,046 882 1,164 -

 Total Drilling and Equipping 18,751 10,711 6,811 3,900 8,040

 Lease Equipment 5,863 3,325 2,276 1,049 2,538

 Other Development 

 Support Equipment 1,561 1,366 1,340 26 195

 Other, Including Direct Overhead 7,849 2,349 1,929 420 5,500

 Total Development Expenditures 50,196 25,323 19,307 6,016 24,873

Total Exploration and Development Expenditures 63,184 31,812 22,330 9,482 31,372

 - = Not available.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B15. Components of U.S. and Foreign Exploration and Development Expenditures for 

 FRS Companies, 2002

 (Million Dollars)

United States 

Worldwide Foreign

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 103
1996 1997 1998 1999 2000 2001 2002

Exploration Expenditures

 U.S. Onshore 1,826 3,396 3,941 1,174 4,136 4,779 3,023

 U.S. Offshore 2,827 3,602 4,805 2,660 3,883 3,552 3,466

 Total United States 4,653 6,998 8,746 3,834 8,019 8,331 6,489

 Canada 355 310 638 420 1,184 3,899 1,694

 OECD Europe 1,345 1,684 1,916 767 869 756 1,223

 Former Soviet Union and E. Europe 194 285 630 354 317 374 470

 Africa 779 807 1,092 1,268 910 1,579 1,292

 Middle East 45 53 141 96 56 197 121

 Other Eastern Hemisphere 1,462 1,341 1,563 1,192 1,675 1,478 1,121

 Other Western Hemisphere 630 794 1,193 1,522 2,880 1,264 578

 Total Foreign 4,810 5,274 7,173 5,619 7,891 9,547 6,499

Worldwide Exploration Expenditures 9,463 12,272 15,919 9,453 15,910 17,878 12,988

Development Expenditures 

 U.S. Onshore 6,087 9,624 9,519 5,396 22,953 19,465 19,307

 U.S. Offshore 3,892 5,224 6,163 4,257 17,072 6,062 6,016

 Total United States 9,979 14,848 15,682 9,653 40,025 25,527 25,323

 Canada 1,210 1,688 4,168 1,636 3,697 11,425 4,993

 OECD Europe 4,222 5,368 6,670 3,370 6,651 4,617 8,571

 Former Soviet Union and E. Europe 267 343 637 252 576 507 803

 Africa 2,014 2,171 2,042 1,826 1,809 3,968 3,799

 Middle East 418 590 801 297 494 542 653

 Other Eastern Hemisphere 2,670 1,643 2,386 2,250 5,112 3,513 5,074

 Other Western Hemisphere 1,007 854 2,516 2,268 2,568 1,826 980

 Total Foreign 11,808 12,657 19,220 11,899 20,907 26,397 24,873

Worldwide Development Expenditures 21,787 27,505 34,902 21,552 60,932 51,924 50,196

Total Exploration and Development 

Expenditures 

 U.S. Onshore 7,913 13,020 13,460 6,570 27,089 24,244 22,330

 U.S. Offshore 6,719 8,826 10,968 6,917 20,955 9,614 9,482

 Total United States 14,632 21,846 24,428 13,487 48,044 33,858 31,812

 Canada 1,565 1,998 4,806 2,056 4,881 15,324 6,687

 OECD Europe 5,567 7,052 8,586 4,137 7,520 5,373 9,794

 Former Soviet Union and E. Europe 461 628 1,267 606 893 881 1,273

 Africa 2,793 2,978 3,134 3,094 2,719 5,547 5,091

 Middle East 463 643 942 393 550 739 774

 Other Eastern Hemisphere 4,132 2,984 3,949 3,442 6,787 4,991 6,195

 Other Western Hemisphere 1,637 1,648 3,709 3,790 5,448 3,090 1,558

 Total Foreign 16,618 17,931 26,393 17,518 28,798 35,944 31,372

Worldwide Exploration and 

Development Expenditures 31,250 39,777 50,821 31,005 76,842 69,802 63,184

Table B16. Exploration and Development Expenditures by Region, for FRS Companies, 

 1996-2002

 (Million Dollars)

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 104
1996 1997 1998 1999 2000 2001 2002

United States

 Taxes Other Than Income Taxes 2,098 1,965 1,176 1,674 2,604 2,506 2,187

 Other Costs 10,221 10,147 9,787 9,494 8,417 10,377 10,315

 Total Production Costs 12,319 12,112 10,963 11,168 11,021 12,883 12,502

 U.S. Onshore 9,855 9,604 8,198 8,039 8,254 9,838 9,650

 U.S. Offshore 2,464 2,508 2,765 3,129 2,767 3,045 2,852

Canada

 Royalty Expenses W W W W W 0

 Taxes Other Than Income Taxes W W W W W 105

 Other Costs 993 961 1,037 1,120 1,379 1,842 2,303

 Total Production Costs 1,082 1,049 1,129 1,252 1,496 1,947 2,412

OECD Europe

 Royalty Expenses 251 217 251 62 W W 49

 Taxes Other Than Income Taxes 400 360 269 330 W W 456

 Other Costs 3,996 3,950 3,980 3,666 3,485 3,496 3,416

 Total Production Costs 4,647 4,527 4,500 4,058 4,025 4,151 3,921

Former Soviet Union and E. Europe

 Royalty Expenses W W W W W W

 Taxes Other Than Income Taxes W W W W W W

 Other Costs 133 188 207 111 179 155 111

 Total Production Costs 134 192 208 148 196 191 111

Africa

 Royalty Expenses W W W W W W

 Taxes Other Than Income Taxes W W W W W W

 Other Costs 812 861 1,194 1,153 1,208 1,384 1,730

 Total Production Costs 1,259 1,310 1,490 1,268 1,784 1,847 2,107

Middle East

 Royalty Expenses W W W W 137 0

 Taxes Other Than Income Taxes W W W W 75 55 46

 Other Costs 296 280 250 235 175 407 502

 Total Production Costs 483 491 429 424 387 462 548

Other Eastern Hemisphere

 Royalty Expenses and 

 Taxes Other Than Income Taxes 542 456 240 507 618 527 468

 Other Costs 1,161 1,144 1,074 1,097 1,392 1,931 2,114

 Total Production Costs 1,703 1,600 1,314 1,604 2,010 2,458 2,582

Other Western Hemisphere

 Royalty Expenses and

 Taxes Other Than Income Taxes 180 156 87 184 304 143 276

 Other Costs 389 470 552 443 533 600 633

 Total Production Costs 569 626 639 627 837 743 909

Total Foreign

 Royalty Expenses 901 891 740 384 437 153 150

 Taxes Other Than Income Taxes 1,196 1,050 675 1,172 1,947 1,831 1,631

 Other Costs 7,780 7,854 8,294 7,825 8,351 9,815 10,809

 Total Production Costs 9,877 9,795 9,709 9,381 10,735 11,799 12,590

Table B17. Production (Lifting) Costs by Region for FRS Companies, 1996-2002

 (Million Dollars)

 W = Data withheld to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

0

109

0

0

0

377

0

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 105
1996 1997 1998 1999 2000 2001 2002

 Net Acreage 

 U.S. Onshore 

 Developed 26,733 25,474 26,396 25,895 31,760 34,332 37,103

 Undeveloped 31,659 31,154 30,598 25,880 37,657 43,293 40,280

 U.S. Offshore 

 Developed 5,470 5,343 4,634 4,988 5,383 5,881 5,281

 Undeveloped 16,880 22,983 23,168 24,940 21,483 20,933 21,929

 Foreign

 Developed 22,574 21,984 24,887 26,337 32,535 32,903 37,603

 Undeveloped 445,176 472,106 514,511 416,209 416,941 424,465 429,394

Gross Acreage 

 U.S. Onshore 

 Developed 46,887 45,249 49,097 45,978 57,626 63,721 69,641

 Undeveloped 53,775 55,530 51,364 42,325 59,295 69,790 64,841

 U.S. Offshore 

 Developed 9,668 10,665 8,861 9,534 10,588 11,317 9,802

 Undeveloped 21,786 30,845 32,439 35,689 31,609 30,523 32,384

 Foreign

 Developed 59,926 58,198 64,358 59,247 71,330 70,112 81,171

 Undeveloped 857,130 924,839 1,083,355 835,615 882,761 834,500 799,007

Table B18. Oil and Gas Acreage for FRS Companies, 1996-2002

 (Thousand Acres)

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 106
1996 1997 1998 1999 2000 2001 2002

Number of Net Wells Completed During Year for

FRS Companies

 Onshore 

 Net Exploratory Wells 

 Dry Holes 274 163 159 93 86 122 119

 Oil Wells 91 90 55 26 19 59 21

 Gas Wells 207 170 142 105 217 351 164

 Total Exploratory Wells 572 424 356 225 321 533 304

 Net Development Wells 

 Dry Holes 319 301 256 162 229 266 220

 Oil Wells 2,095 3,016 2,510 1,130 1,775 1,815 1,187

 Gas Wells 2,049 2,261 2,074 1,519 2,927 5,226 4,982

 Total Development Wells 4,463 5,577 4,841 2,812 4,930 7,307 6,389

 Offshore 

 Net Exploratory Wells 

 Dry Holes 84 98 91 59 73 63 52

 Oil Wells 36 31 22 28 28 39 35

 Gas Wells 87 73 63 61 59 63 53

 Total Exploratory Wells 206 202 176 148 159 165 140

 Net Development Wells 

 Dry Holes 23 46 32 26 29 38 38

 Oil Wells 158 181 115 145 128 240 135

 Gas Wells 153 168 133 153 157 170 134

 Total Development Wells 334 396 280 324 315 448 307

Total United States

 Net Exploratory Wells 

 Dry Holes 358 261 249 153 158 185 171

 Oil Wells 127 121 77 54 47 98 56

 Gas Wells 293 243 205 166 275 415 217

 Total Exploratory Wells 778 626 531 372 480 698 443

 Net Development Wells 

 Dry Holes 342 347 288 188 258 305 259

 Oil Wells 2,253 3,197 2,625 1,275 1,903 2,054 1,321

 Gas Wells 2,202 2,429 2,208 1,672 3,084 5,396 5,116

 Total Development Wells 4,797 5,973 5,121 3,136 5,245 7,755 6,696

Number of Net Wells Completed During Year for

Total U.S. Industry

 Net Exploratory Wells 

 Dry Holes 2,154 2,145 1,843 1,157 1,331 1,576 1,130

 Oil Wells 484 434 306 153 267 327 223

 Gas Wells 575 542 589 520 613 963 666

 Total Exploratory Wells 3,213 3,121 2,739 1,830 2,210 2,866 2,018

 Net Development Wells 

 Dry Holes 3,184 3,659 3,138 2,273 2,636 2,742 2,394

 Oil Wells 7,911 9,889 6,566 4,119 7,240 7,876 5,934

 Gas Wells 8,729 10,592 11,494 10,530 15,852 20,740 16,097

 Total Development Wells 19,824 24,140 21,198 16,921 25,728 31,358 24,424

Number of Net In-Progress Wells At Year End 

for FRS Companies

 Onshore 

 Exploratory Wells 133 135 51 40 70 85 66

 Development Wells 675 929 392 464 716 1,052 1,315

 Total In-Progress Wells 808 1,064 444 504 786 1,138 1,381

 Offshore 

 Exploratory Wells 45 92 52 68 50 56 55

 Development Wells 93 128 73 87 110 63 47

 Total In-Progress Wells 138 220 124 155 160 118 102

 Total United States 

 Exploratory Wells 178 226 103 108 120 141 120

 Development Wells 768 1,058 465 551 826 1,115 1,362

 Total In-Progress Wells 946 1,284 568 659 946 1,256 1,482

FRS companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System). 

Table B19. U.S. Net Wells Completed for FRS Companies and U.S. Industry, 1996-2002

 Note: Sum of components may not equal total due to independent rounding. 

 Sources: Industry data - Special compilation provided by the Office of Oil and Gas, Energy Information Adminstration. Totals

are based on data which appeared in the Energy Information Administration's Monthly Energy Review, October 2003, p. 84.

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 107
1996 1997 1998 1999 2000 2001 2002

FRS Companies

 Onshore

 Exploratory Well Footage 

 Dry Hole Footage 2,052 1,700 1,714 921 955 1,085 1,000

 Oil Well Footage 732 1,027 406 312 199 397 141

 Gas Well Footage 1,860 1,521 1,548 1,150 1,399 2,016 1,284

 Total Exploratory Footage 4,644 4,248 3,668 2,383 2,553 3,498 2,425

 Development Well Footage 

 Dry Hole Footage 2,224 1,926 1,939 1,252 1,597 2,029 1,716

 Oil Well Footage 10,956 14,534 12,513 4,449 9,374 9,435 6,928

 Gas Well Footage 14,304 16,751 16,521 12,291 20,516 26,653 32,078

 Total Development Footage 27,484 33,211 30,973 17,992 31,487 38,117 40,722

 Offshore 

 Exploratory Well Footage 

 Dry Hole Footage 1,091 1,362 1,345 848 1,151 1,004 652

 Oil Well Footage 408 397 443 434 364 551 589

 Gas Well Footage 1,824 981 1,285 1,002 1,141 759 697

 Total Exploratory Footage 3,323 2,740 3,073 2,284 2,656 2,314 1,938

 Development Well Footage 

 Dry Hole Footage 244 459 344 199 411 353 369

 Oil Well Footage 1,704 1,736 1,428 1,280 1,505 2,260 1,362

 Gas Well Footage 1,538 1,584 1,398 1,295 1,899 1,917 1,370

 Total Development Footage 3,486 3,779 3,170 2,774 3,815 4,530 3,101

Total United States

 Exploratory Well Footage 

 Dry Hole Footage 3,143 3,062 3,059 1,769 2,107 2,089 1,652

 Oil Well Footage 1,140 1,424 849 746 563 948 730

 Gas Well Footage 3,684 2,502 2,833 2,152 2,540 2,775 1,981

 Total Exploratory Footage 7,967 6,988 6,741 4,667 5,209 5,812 4,363

 Development Well Footage

 Dry Hole Footage 2,468 2,385 2,283 1,451 2,008 2,382 2,085

 Oil Well Footage 12,660 16,270 13,941 5,729 10,879 11,695 8,290

 Gas Well Footage 15,842 18,335 17,919 13,586 22,415 28,570 33,448

 Total Development Footage 30,970 36,990 34,143 20,766 35,303 42,647 43,823

Total United States Industry

 Exploratory Well Footage 

 Dry Hole Footage 13,199 13,861 12,398 7,646 8,863 10,100 7,479

 Oil Well Footage 3,504 3,432 2,505 1,045 1,918 2,433 1,548

 Gas Well Footage 3,782 3,955 4,196 3,315 4,538 6,938 5,016

 Total Exploratory Footage 20,485 21,248 19,098 12,006 15,319 19,472 14,044

 Development Well Footage 

 Dry Hole Footage 16,656 19,666 18,005 12,508 13,981 14,573 12,688

 Oil Well Footage 36,988 47,773 32,125 17,705 31,782 36,470 26,589

 Gas Well Footage 54,376 65,860 70,746 52,204 76,309 103,547 88,903

 Total Development Footage 108,020 133,298 120,875 82,417 122,073 154,590 128,179

Number of Net Producing Wells for

FRS Companies

 Onshore 

 Oil Wells 87,461 75,493 69,401 58,987 68,274 66,667 69,021

 Gas Wells 48,779 48,779 49,429 44,880 64,696 82,083 89,102

 Total Producing Wells 136,240 124,272 118,830 103,867 132,970 148,750 158,123

 Offshore 

 Oil Wells 3,552 3,760 3,421 2,855 3,536 4,738 4,384

 Gas Wells 2,556 2,898 2,737 2,707 3,111 3,606 3,011

 Total Producing Wells 6,108 6,658 6,158 5,562 6,647 8,344 7,395

 Total United States

 Oil Wells 91,013 79,253 72,822 61,842 71,810 71,405 73,405

 Gas Wells 51,335 51,677 52,166 47,587 67,807 85,689 92,113

 Total Producing Wells 142,348 130,930 124,987 109,429 139,617 157,094 165,518

Table B20. U.S. Net Drilling Footage and Net Producing Wells For FRS Companies and 

 U.S. Industry, 1996-2002

 Sources: Well footage, U.S. - special compilation provided by the Office of Oil and Gas, Energy Information Administration. Totals are based on data

which appeared in the Energy Information Administration's Monthly Energy Review , October 2003, p. 84. 

FRS companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

(number of wells)

(thousand feet)

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 108
1996 1997 1998 1999 2000 2001 2002

 Canada

 Net Wells Completed During Year

 Exploratory Wells

 Dry Holes 86.2 22.8 54.8 36.4 126.3 106.4 156.6

 Oil Wells 46.0 10.7 10.0 25.8 23.3 63.1 74.0

 Gas Wells 96.1 49.2 66.3 127.5 194.2 165.9 329.4

 Total Exploratory Wells 228.3 82.7 131.1 189.7 343.8 335.4 560.0

 Development Wells

 Dry Holes 48.1 59.6 58.8 58.3 138.2 228.8 151.2

 Oil Wells 559.4 778.6 198.9 352.1 373.3 818.1 794.1

 Gas Wells 233.7 275.1 422.4 758.7 891.5 2,025.1 2,381.1

 Total Development Wells 841.2 1,113.3 680.1 1,169.1 1,403.0 3,072.1 3,326.4

 Net In-Progress Wells at Year End 17.2 30.6 24.3 76.3 116.8 307.2 190.0

 Net Producing Wells

 Oil Wells 8,719.5 9,364.7 10,532.3 10,155.9 12,094.8 17,640.5 14,203.0

 Gas Wells 5,784.8 6,199.5 8,872.7 10,038.7 15,242.7 25,230.5 26,434.9

 Total Producing Wells 14,504.3 15,564.2 19,405.0 20,194.6 27,337.5 42,870.9 40,637.9

Europe and Former Soviet Union 1

 Net Wells Completed During Year

 Exploratory Wells

 Dry Holes 49.4 56.6 36.3 15.4 15.7 15.6 11.2

 Oil Wells 14.5 19.2 11.8 9.2 5.2 25.9 5.3

 Gas Wells 11.4 8.9 12.0 4.0 6.4 8.6 3.1

 Total Exploratory Wells 75.3 84.7 60.1 28.6 27.3 50.1 19.6

 Development Wells

 Dry Holes 5.3 3.2 7.8 2.6 10.3 5.4 4.6

 Oil Wells 77.6 80.7 118.5 75.4 67.7 91.8 63.0

 Gas Wells 31.0 25.1 60.5 30.4 30.4 31.8 41.2

 Total Development Wells 113.9 109.0 186.8 108.4 108.4 129.0 108.8

 Net In-Progress Wells at Year End 68.7 62.7 54.5 31.6 63.7 69.3 38.7

 Net Producing Wells

 Oil Wells 1,445.5 1,328.0 1,294.4 1,218.8 1,431.3 1,478.2 1,225.7

 Gas Wells 765.2 766.8 805.3 626.6 737.7 717.2 788.7

 Total Producing Wells 2,210.7 2,094.8 2,099.7 1,845.4 2,169.0 2,195.4 2,014.4

Africa and Middle East

 Net Wells Completed During Year

 Exploratory Wells

 Dry Holes 19.8 25.3 33.1 14.9 37.2 21.9 26.8

 Oil Wells W W W 9.9 W W

 Gas Wells W W W 10.0 W W

 Total Exploratory Wells 44.0 46.1 65.0 34.8 50.7 50.9 67.5

 Development Wells

 Dry Holes W W W 5.8 W W 1

 Oil Wells 133.0 151.6 218.4 206.3 239.3 159.8 209.4

 Gas Wells W W W 8.6 W W 1

 Total Development Wells 144.0 157.8 225.6 220.7 252.0 186.9 234.2

 Net In-Progress Wells at Year End 36.9 29.0 18.0 36.8 35.2 35.4 57.0

 Net Producing Wells

 Oil Wells 1,688.9 1,644.6 1,924.2 1,969.8 1,954.1 2,063.8 2,209.2

 Gas Wells 49.9 59.5 62.7 83.2 79.0 121.2 140.2

 Total Producing Wells 1,738.8 1,704.1 1,986.9 2,053.0 2,033.1 2,185.0 2,349.4

Table B21. Number of Net Wells Completed, In-Progress Wells, and Producing Wells by

 Foreign Regions for FRS Companies, 1996-2002

 See footnotes at end of table.

W

W

1.3

3.5

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 109
1996 1997 1998 1999 2000 2001 2002

Other Eastern Hemisphere

 Net Wells Completed During Year

 Exploratory Wells

 Dry Holes 42.6 39.8 47.1 35.4 40.7 39.1 36.8

 Oil Wells 21.6 16.1 36.6 41.6 31.3 19.9 11.0

 Gas Wells 46.3 15.8 13.8 16.0 20.7 42.3 26.6

 Total Exploratory Wells 110.5 71.7 97.5 93.0 92.7 101.3 74.4

 Development Wells

 Dry Holes 3.7 4.7 11.5 1.9 4.4 7.1 3.0

 Oil Wells 103.1 162.6 149.5 82.4 140.6 595.3 554.8

 Gas Wells 91.7 116.5 101.2 104.5 113.5 117.0 201.7

 Total Development Wells 198.5 283.8 262.2 188.8 258.5 719.4 759.5

 Net In-Progress Wells at Year End 72.4 61.4 64.5 56.2 80.5 67.1 30.9

 Net Producing Wells

 Oil Wells 1,622.0 1,767.0 1,707.2 1,654.2 1,950.2 7,852.9 7,458.6

 Gas Wells 561.2 633.8 862.2 882.2 927.4 1,090.3 1,288.8

 Total Producing Wells 2,183.2 2,400.8 2,569.4 2,536.4 2,877.6 8,943.2 8,747.4

Other Western Hemisphere

 Net Wells Completed During Year

 Exploratory Wells

 Dry Holes 12.4 5.7 14.6 7.9 14.5 31.9 13.2

 Oil Wells 9.0 4.7 10.4 3.2 W W W

 Gas Wells 2.0 0.0 4.5 3.8 W W W

 Total Exploratory Wells 23.4 10.4 29.5 14.9 23.4 40.0 21.3

 Development Wells

 Dry Holes W W W W W W

 Oil Wells 123.3 141.4 212.8 81.4 205.8 240.5 217.0

 Gas Wells W W W W W W

 Total Development Wells 129.8 148.3 224.5 91.7 245.0 262.9 245.1

 Net In-Progress Wells at Year End 16.1 24.4 28.9 27.2 31.3 47.4 31.6

 Net Producing Wells

 Oil Wells 2,478.9 605.0 2,045.6 2,426.5 2,597.2 2,580.2 2,439.6

 Gas Wells 77.3 72.2 190.9 161.4 253.1 262.7 274.0

 Total Producing Wells 2,556.2 677.2 2,236.5 2,587.9 2,850.3 2,842.9 2,713.6

Total Foreign

 Net Wells Completed During Yea

W

W

r

 Exploratory Wells

 Dry Holes 210.4 150.2 185.9 110.0 234.4 214.9 244.6

 Oil Wells 110.9 71.0 97.6 89.7 74.1 136.0 134.3

 Gas Wells 160.2 74.4 99.7 161.3 229.4 226.8 363.9

 Total Exploratory Wells 481.5 295.6 383.2 361.0 537.9 577.7 742.8

 Development Wells

 Dry Holes 67.9 75.5 83.7 70.1 156.7 252.5 171.2

 Oil Wells 996.4 1,314.9 898.1 797.6 1,026.7 1,905.5 1,838.3

 Gas Wells 363.1 421.8 597.4 911.0 1,083.5 2,212.2 2,664.5

 Total Development Wells 1,427.4 1,812.2 1,579.2 1,778.7 2,266.9 4,370.3 4,674.0

 Net In-Progress Wells at Year End 211.3 208.1 190.2 228.1 327.5 526.4 348.2

 Net Producing Wells

 Oil Wells 15,954.8 14,709.3 17,503.7 17,425.2 20,027.6 31,615.6 27,536.1

 Gas Wells 7,238.4 7,731.8 10,793.8 11,792.1 17,239.9 27,421.9 28,926.6

 Total Producing Wells 23,193.2 22,441.1 28,297.5 29,217.3 37,267.5 59,037.4 56,462.7

Table B21. Number of Net Wells Completed, In-Progress Wells, and Producing Wells by

 Foreign Regions for FRS Companies, 1996-2002 (Continued)

 1OECD Europe combined with the former Soviet Union and Eastern Europe to avoid disclosure.

 W = data withheld to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 110
Drilling and Equipping Measures 2001 2002

Percent 

Change 2001 2002

Percent

Change 2001 2002

Percent

Change

Exploration

Oil Wells

 Wells Completed 97.9 55.5 -43.3 58.8 21.0 -64.3 39.1 34.5 -11.8

 Average Depth (thousand feet) 9.7 13.2 35.8 6.8 6.7 -0.6 14.1 17.1 21.1

Gas Wells

 Wells Completed 414.7 216.7 -47.7 351.4 164.0 -53.3 63.3 52.7 -16.7

 Average Depth (thousand feet) 6.7 9.1 36.6 5.7 7.8 36.5 12.0 13.2 10.3

Dry Holes

 Wells Completed 185.2 171.2 -7.5 122.4 118.8 -2.9 62.8 52.4 -16.5

 Average Depth (thousand feet) 11.3 9.6 -14.5 8.9 8.4 -5.0 16.0 12.4 -22.2

Development

Oil Wells

 Wells Completed 2,054.3 1,321.3 -35.7 1,814.6 1,186.6 -34.6 239.7 134.7 -43.8

 Average Depth (thousand feet) 5.7 6.3 10.2 5.2 5.8 12.3 9.4 10.1 7.3

Gas Wells

 Wells Completed 5,396.3 5,115.7 -5.2 5,226.1 4,982.0 -4.7 170.2 133.7 -21.4

 Average Depth (thousand feet) 5.3 6.5 23.5 5.1 6.4 26.3 11.3 10.2 -9.0

Dry Holes

 Wells Completed 304.7 258.7 -15.1 266.3 220.4 -17.2 38.4 38.3 -0.3

 Average Depth (thousand feet) 7.8 8.1 3.1 7.6 7.8 2.2 9.2 9.6 4.8

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

U.S. Offshore

Table B22. Number of Net Wells Completed, and Average Depth, Onshore and Offshore, 

 for FRS Companies, 2001 and 2002

Total United States U.S. Onshore

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 111
Beginning 

Reserves

Plus

Reserve

Additions 1 

Plus

Net 

Purchases

Less 

Production

Equals

Ending

Reserves

Replacement

Rate

 (percent)

Crude Oil and Natural Gas Liquids 

 U.S. Onshore

 Total U.S. Industry 24,242.0 2,149.0 0.0 2,048.0 24,342.0 104.9

 FRS Companies 11,652.2 585.4 14.6 868.9 11,383.4 67.4

 All Other 12,589.8 1,563.6 -14.6 1,179.1 12,958.6 132.6

 U.S. Offshore

 Total U.S. Industry 6,197.0 842.0 0.0 711.0 6,329.0 118.4

 FRS Companies 4,479.7 459.9 4.3 477.5 4,466.4 96.3

 All Other 1,717.3 382.1 -4.3 233.5 1,862.6 163.6

 U.S. Total

 Total U.S. Industry 30,439.0 2,991.0 0.0 2,759.0 30,671.0 108.4

 FRS Companies 16,131.9 1,045.3 19.0 1,346.4 15,849.8 77.6

 All Other 14,307.1 1,945.7 -19.0 1,412.6 14,821.2 137.7

FRS Companies'

Foreign Oil Reserves

 Canada 2,583.5 228.8 -389.2 234.7 2,188.4 97.5

 Europe 4,448.6 -28.9 -34.1 559.7 3,825.8 -5.2

 FSU and Eastern Europe 948.9 393.2 -5.0 28.9 1,308.2 1,360.2

 Africa 5,257.8 999.3 104.1 370.9 5,990.3 269.4

 Middle East 857.4 38.7 6.8 116.8 786.1 33.2

 Other Eastern Hemisphere 3,048.5 14.3 -81.1 316.7 2,664.9 4.5

 Other Western Hemisphere 1,599.7 14.5 -38.3 119.2 1,456.7 12.1

Total Foreign 18,744.4 1,659.9 -436.9 1,746.9 18,220.5 95.0

Worldwide Total for FRS Companies 34,876.3 2,705.2 -417.9 3,093.3 34,070.3 87.5

Dry Natural Gas 

 U.S. Onshore

 Total U.S. Industry 155,127.0 20,283.0 0.0 14,688.0 160,722.0 138.1

 FRS Companies 68,514.6 4,930.9 610.5 5,920.7 68,135.3 83.3

 All Other 86,612.4 15,352.1 -610.5 8,767.3 92,586.7 175.1

 U.S. Offshore

 Total U.S. Industry 28,333.0 2,556.0 0.0 4,665.0 26,224.0 54.8

 FRS Companies 19,485.1 1,048.2 -26.5 2,791.8 17,715.1 37.5

 All Other 8,847.9 1,507.8 26.5 1,873.2 8,508.9 80.5

 U.S. Total

 Total U.S. Industry 183,460.0 22,839.0 0.0 19,353.0 186,946.0 118.0

 FRS Companies 87,999.7 5,979.2 583.9 8,712.5 85,850.3 68.6

 All Other 95,460.3 16,859.8 -583.9 10,640.5 101,095.7 158.4

FRS Companies'

Foreign Gas Reserves 

 Canada 15,937.3 970.2 76.8 1,863.3 15,121.0 52.1

 Europe 21,348.4 639.8 -213.5 2,270.4 19,504.3 28.2

 FSU and Eastern Europe 1,020.2 373.7 0.0 31.7 1,362.2 1,177.7

 Africa 5,267.6 1,031.4 563.9 214.3 6,648.6 481.4

 Middle East 610.9 115.2 52.6 90.4 688.3 127.5

 Other Eastern Hemisphere 24,186.2 2,322.0 -696.1 1,849.1 23,963.0 125.6

 Other Western Hemisphere 16,336.5 4,294.8 -262.1 715.1 19,654.1 138.6

Total Foreign 84,707.1 9,747.1 -478.4 7,034.3 86,941.5 138.6

Worldwide Total for FRS Companies 172,706.8 15,726.3 105.5 15,746.8 172,791.9 99.9

FRS companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B23. Oil and Gas Reserves for FRS Companies and U.S. Industry, 2002

 1

 Excludes net purchases of minerals in place; includes crude oil and natural gas liquids (measured in millions of barrels) and natural gas (measured in millions

of barrels of crude oil equivalent). The conversion factor for natural gas is 0.178 barrels of crude / 1000 cubic feet. Reserve additions include the net of 

corrections and adjustments.

 Note: "Net Ownership Interest" is defined as net working interest plus own royalty interest.

 Sources: Industry data - Energy Information Administration Form EIA-23 (Annual Survey of Domestic Oil and Gas Reserves); see U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves Annual Report , 2001 and 2002 (November 2002 and November 2003).

(million barrels)

(billion cubic feet)

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 112
Total Onshore Offshore

Crude Oil and Natural Gas Liquids

 Beginning of Period 34,876 16,132 11,652 4,480 18,744

 Revisions of Previous Estimates 29 105 109 -4 -76

 Improved Recovery 685 346 247 99 338

 Purchases of Minerals-in-Place 1,497 473 430 44 1,024

 Extensions & Discoveries 1,991 594 229 365 1,397

 Production -3,093 -1,346 -869 -477 -1,747

 Sales of Minerals-in-Place -1,915 -454 -415 -40 -1,461

 End of period 34,070 15,850 11,383 4,466 18,221

Proportionate Interest in Investee 

Reserves and Foreign Access Reserves -- -- -- -- 7,383

Natural Gas Reserves 

 Beginning of Period 172,707 88,000 68,515 19,485 84,707

 Revisions of Previous Estimates 694 -1,111 -558 -553 1,805

 Improved Recovery 2,327 821 780 41 1,506

 Purchases of Minerals-in-Place 12,649 5,562 5,297 265 7,087

 Extensions & Discoveries 12,705 6,269 4,709 1,560 6,436

 Production -15,747 -8,713 -5,921 -2,792 -7,034

 Sales of Minerals-in-Place -12,544 -4,978 -4,687 -292 -7,566

 End of Period 172,792 85,850 68,135 17,715 86,942

Proportionate Interest in Investee 

Reserves and Foreign Access Reserves -- -- -- -- 29,512

 See footnotes at end of table.

Table B24. Oil and Gas Reserve Balances by Region for FRS Companies, 

 2002

United States Total

Reserves Statistics Foreign

Worldwide

Total

(million barrels)

(billion cubic feet)

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 113
Total Canada

Europe and

Former

Soviet Union 1 

Africa

and

Middle East

Other

Eastern

Hemisphere

Other

Western

Hemisphere

Crude Oil and 

Natural Gas Liquids

 Beginning of Period 18,744 2,584 5,397 6,115 3,049 1,600

 Revisions of Previous Estimates -76 78 -116 182 -113 -106

 Improved Recovery 338 9 22 237 W W

 Purchases of Minerals-in-Place 1,024 150 475 196 W W

 Extensions & Discoveries 1,397 141 458 619 100 79

 Production -1,747 -235 -589 -488 -317 -119

 Sales of Minerals-in-Place -1,461 -540 -515 -85 -234 -87

 End of period 18,221 2,188 5,134 6,776 2,665 1,457

Proportionate Interest in Investee

Reserves and Foreign Access Reserves 7,383 W 3,235 W W 2,709

 Natural Gas Reserves

 Beginning of Period 84,707 15,937 22,369 5,878 24,186 16,337

 Revisions of Previous Estimates 1,805 -508 354 272 1,554 133

 Improved Recovery 1,506 11 W W 51 W

 Purchases of Minerals-in-Place 7,087 1,711 2,798 668 1,909 0

 Extensions & Discoveries 6,436 1,467 622 726 717 2,905

 Production -7,034 -1,863 -2,302 -305 -1,849 -715

 Sales of Minerals-in-Place -7,566 -1,634 W W -2,605 W

 End of Period 86,942 15,121 20,866 7,337 23,963 19,654

Proportionate Interest in Investee

Reserves and Foreign Access Reserves 29,512 42 19,980 W W 2,368

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Foreign 

Reserves Statistics

Table B24. Oil and Gas Reserve Balances by Region for FRS Companies, 2002 (Continued)

 1

 OECD Europe combined with the former Soviet Union and Eastern Europe to avoid disclosure. Prior to 1993, only OECD Europe is included in this region.

 -- = Not applicable.

 W = Data withheld to avoid disclosure.

(million barrels)

(billion cubic feet)

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 114
Total Onshore Offshore

Exploration and Development 

Expenditures (million dollars)

 FRS Companies 31,812.0 22,330.0 9,482.0 31,372.0

 Percent Change -6.0 -7.9 -1.4 -12.7

Wells Completed

 FRS Companies 7,139.1 6,692.8 446.3 5,416.8

 Percent Change -15.5 -14.6 -27.2 9.5

 Industry

1 26,442.0 25,927.0 515.0 21,493.0

 Percent Change -25.9 -27.0 208.4 -16.3

Success Rate2

 FRS Companies 94.0 94.9 79.7 92.3

 Industry

1 86.7 87.2 58.3 93.2

Crude Oil and NGL Production3 

(million barrels)

 FRS Companies 1,346.4 868.9 477.5 1,778.3

 Percent Change -1.2 -0.9 -1.8 1.2

 Industry 1 2,759.0 2,048.0 711.0 22,765.3

 Percent Change -1.6 -1.3 -2.6 -1.7

Crude Oil and NGL Reserve 

Interests4

 (million barrels) 

 FRS Companies 15,849.8 11,383.4 4,466.4 25,603.8

 Percent Change -1.3 -2.6 2.2 3.2

Natural Gas Production 

(billion cubic feet)

 FRS Companies 8,712.5 5,920.7 2,791.8 7,034.3

 Percent Change -1.4 3.5 -10.4 11.5

 Industry

1 19,353.0 14,688.0 4,665.0 68,347.9

 Percent Change -2.2 0.7 -10.1 3.1

Natural Gas Reserve Interests

(billion cubic feet)

 FRS Companies 85,850.3 68,135.3 17,715.1 116,454.0

 Percent Change 0.1 2.2 -7.1 4.0

Table B25. Oil and Gas Exploration and Development Expenditures, Reserves, 

 and Production by Region for FRS Companies and Total Industry,

 2002 and Percent Change from 2001

 See footnotes at end of table.

United States Foreign Total

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 115
Total Canada

Europe & 

Former 

Soviet Union 5 Africa

Middle

East

Other

Eastern

Hemisphere

Other

Western

Hemisphere

Exploration and Development 

Expenditures (million dollars)

 FRS Companies 31,372.0 6,687.0 11,067.0 5,091.0 774.0 6,195.0 1,558.0

 Percent Change -12.7 -56.4 77.0 -8.2 4.7 24.1 -49.6

Wells Completed 

 FRS Companies 5,416.8 3,886.4 128.4 201.7 100.0 833.9 266.4

 Percent Change 9.5 14.1 -28.3 35.0 13.3 1.6 -12.1

 Foreign Industry

1 21,493.0 14,237.0 687.0 854.0 1,050.0 1,649.0 3,016.0

 Percent Change -16.3 -19.6 -11.4 33.0 38.5 -20.1 -19.3

Success Rate2

 (percent)

 FRS Companies 92.3 92.1 87.7 83.3 95.5 95.2 94.6

 Foreign Industry

1 93.2 94.0 100.9 85.7 97.2 88.9 92.9

Crude Oil and NGL Production3 

(million barrels)

 FRS Companies 1,778.3 234.7 588.6 370.9 148.2 316.7 119.2

 Percent Change 1.2 15.1 -4.1 3.2 -2.2 -1.1 9.7

 Foreign Industry

1 22,765.3 1,051.2 5,745.9 2,897.0 7,655.0 1,679.0 3,737.2

 Percent Change -1.7 4.2 1.8 1.6 -5.7 -0.8 -3.1

Crude Oil and NGL Reserve

Interests4

 (million barrels)

 FRS Companies 25,603.8 2,262.0 8,369.2 5,990.3 2,119.0 2,697.2 4,166.0

 Percent Change 3.2 -13.7 5.7 13.9 -3.6 -12.8 12.2

Natural Gas Production

(billion cubic feet)

 FRS Companies 7,034.3 1,863.3 2,302.1 214.3 90.4 1,849.1 715.1

 Percent Change 11.5 24.5 -3.2 37.1 1.9 17.3 16.4

 Foreign Industry

1 68,347.9 6,477.6 34,408.1 4,702.0 8,316.7 9,499.2 4,864.3

 Percent Change 3.1 6.7 0.5 7.4 3.3 7.8 2.2

Natural Gas Reserve Interests 

(billion cubic feet)

 FRS Companies 116,454.0 15,162.6 40,846.3 6,648.6 6,380.1 25,394.6 22,021.8

 Percent Change 4.0 -5.0 -0.9 26.2 31.6 -1.0 15.7

Table B25. Oil and Gas Exploration and Development Expenditures, Reserves, 

 and Production by Region for FRS Companies and Total Industry, 

 2002 and Percent Change from 2001 (Continued)

 1Foreign industry levels defined as total activity outside of the United States except the People's Republic of China.

 2

Success Rate defined as the total number of successful well completions during the period divided by the total number of wells drilled.

 3

Crude oil plus natural gas liquids. Foreign includes ownership interest production and foreign access production.

 4

Foreign includes net ownership interest reserves (71.2 percent of total foreign) and "Other Access" reserves (28.8 percent of total foreign). "Other Access"

reserves include proportional interest in investee reserves and foreign access reserves. 5OECD Europe combined with the former Soviet Union and Eastern Europe to avoid disclosure.

FRS companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

 Sources: Reserve additions, U.S. - Energy Information Administration Form EIA-23 (Annual Survey of Domestic Oil and Gas Reserves); see U.S. Crude Oil,

Natural Gas, and Natural Gas Liquids Reserves , 2001, and 2002 Annual Reports. Wells completed, U.S. - special compilation provided by the Energy

Information Administration's Office of Oil and Gas. Totals are based on data which appeared in the Energy Information Administration's Monthly Energy Review , 

October 2003, p. 84. Reserve Additions, Foreign - British Petroleum Statistical Review of World Energy 2002 and 2003. Wells Completed, Foreign - World Oil , 

August 2002 and 2003.

Foreign

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 116
1996 1997 1998 1999 2000 2001 2002

 U.S. Refining/Marketing 

Sources 

 Acquisitions from U.S. Production Segment 1,599 1,542 1,484 1,516 1,238 1,358 1,368

 Purchases from Other U.S. Segments and

 Unconsolidated Affiliates 459 468 1,935 2,181 2,149 2,629 1,709

 Purchases from Third Parties 4,488 4,444 4,968 5,205 5,340 3,679 4,219

 Net Transfers from Foreign Refining/Marketing

 Segment 566 571 635 475 324 716 631

Total Sources 7,112 7,025 9,021 9,377 9,050 8,383 7,926

Dispositions 

 Net Change in Inventories 21 14 31 -1 -4 -1 -28

 Input to Refineries 3,563 3,259 4,883 4,872 4,690 4,668 4,711

 Sales to: 

 Unaffiliated Third Parties 3,291 3,424 3,730 4,147 4,281 3,391 3,060

 Other Segments Excluding Foreign 

 Refining/Marketing 237 328 377 359 84 325 183

Total Dispositions 7,112 7,025 9,021 9,377 9,050 8,383 7,926

Foreign Refining/Marketing 

Sources 

 Acquisitions from Foreign Production Segment 1,371 1,391 1,380 1,462 1,585 1,661 1,590

 Purchases 

 Other Foreign Segments 88 WWWWW

 Unconsolidated Affiliates 89 WWWWW

 Unaffiliated Third Parties 

 Foreign Access 145 228 209 W W W W

 Foreign Governments (Open Market) 844 851 679 W W W W

 Other Unaffiliated Third Parties 1,819 1,785 2,000 2,244 2,165 2,459 1,626

 Net Transfers to U.S. Refining/Marketing -566 -571 -635 -475 -324 -716 -631

Total Sources 3,790 3,699 4,021 4,307 4,067 4,200 3,287

Dispositions 

 Net Change in Inventories 38 18 155 -19 10 -2 0

 Input to Refineries 1,605 1,435 1,419 1,641 1,673 1,682 1,639

 Sales 2,147 2,246 2,446 2,685 2,384 2,520 1,647

Total Dispositions 3,790 3,699 4,021 4,307 4,067 4,200 3,287

Table B26. U.S. and Foreign Refining/Marketing Sources and Dispositions of Crude

 Oil and Natural Gas Liquids for FRS Companies,1996-2002

 (million barrels)

 W = Data withheld to avoid disclosure.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

W

W

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 117
1996 1997 1998 1999 2000 2001 2002

 Purcha se s 

 U.S. Refining/M arketing Segm ent 

 Raw M aterials 

 Crude Oil and NGL 138,397 126,535 106,128 152,880 253,092 192,228 186,084

 Natural Gas 15,651 18,657 15,177 20,387 58,679 38,947 33,744

 Other Raw M aterials 2,697 3,159 5,348 5,705 8,395 7,852 7,950

 Total Raw M aterials 156,745 148,351 126,653 178,972 320,166 239,027 227,778

 Refined Produc ts 

 M otor Gasoline 18,078 18,613 24,249 36,095 65,488 64,609 59,357

 Dis tillate Fuels 9,634 9,565 10,574 17,433 35,116 31,323 27,031

 Other Refined Produc ts 10,246 9,141 8,786 9,963 17,036 18,895 16,868

 Total Refined Produc ts 37,958 37,319 43,609 63,491 117,640 114,827 103,256

 U.S. Produc tion Segm ent 

 Crude Oil and NGL 5,163 5,399 4,694 5,695 4,794 1,979 721

 Natural Gas 10,715 11,220 8,922 8,608 12,208 14,113 11,785

 Total Raw M aterials 15,878 16,619 13,616 14,303 17,002 16,092 12,506

Sa le s 

 U.S. Refining/M arketing Segm ent 

 Raw M aterials 

 Crude Oil and NGL 69,485 70,437 50,702 72,955 121,118 86,675 75,241

 Natural Gas 15,790 18,252 15,270 20,023 56,482 37,648 32,882

 Other Raw M aterials 1,276 1,499 2,172 1,576 2,403 2,203 944

 Total Raw M aterials 86,551 90,188 68,144 94,554 180,003 126,526 109,067

 Refined Produc ts 

 M otor Gasoline 75,330 71,185 84,968 109,301 176,394 167,735 158,691

 Dis tillate Fuels 41,618 36,962 39,513 51,810 91,998 83,702 75,929

 Other Refined Produc ts 24,577 20,964 23,283 28,506 42,269 40,172 37,570

 Total Refined Produc ts 141,525 129,111 147,764 189,617 310,661 291,609 272,190

 U.S. Produc tion Segm ent 

 Crude Oil and NGL 32,948 30,604 19,688 25,186 38,314 31,613 30,930

 Natural Gas 26,840 29,459 23,649 23,178 40,719 47,390 40,208

 Total Raw M aterials 59,788 60,063 43,337 48,364 79,033 79,003 71,138

 

Table B 27. U .S. Purchases and Sales of Oil, N atural Gas, Other R aw Materials, and R efined

 Products for FR S C ompanies, 1996-2002

Values (m illion dollars )

 Purcha se s 

 U.S. Refining/M arketing Segm ent 

 Raw M aterials 

 Crude Oil and NGL (m illion barrels ) 7,112 7,025 9,021 9,377 9,050 8,383 7,926

 Natural Gas (billion cubic feet) 7,506 7,573 7,425 9,285 13,323 9,147 10,458

 Refined Produc ts (m illion barrels ) 

 M otor Gasoline 677 689 1,272 1,533 1,708 1,892 1,840

 Dis tillate Fuels 380 397 625 837 943 987 944

 Other Refined Produc ts 363 329 464 446 535 625 633

 Total Refined Produc ts 1,420 1,415 2,361 2,815 3,186 3,504 3,417

 U.S. Produc tion Segm ent 

 Crude Oil and NGL (m illion barrels ) 300 308 394 367 200 88 37

 Natural Gas (billion cubic feet) 4,723 4,551 4,295 3,835 3,276 3,461 3,956

Sa le s 

 U.S. Refining/M arketing Segm ent 

 Raw M aterials 

 Crude Oil and NGL (m illion barrels ) 3,528 3,752 4,107 4,506 4,365 3,716 3,243

 Natural Gas (billion cubic feet) 7,195 7,242 6,764 8,834 13,001 8,460 9,783

 Refined Produc ts (m illion barrels ) 

 M otor Gasoline 2,488 2,371 3,789 4,070 4,286 4,539 4,551

 Dis tillate Fuels 1,562 1,473 2,146 2,344 2,444 2,540 2,490

 Other Refined Produc ts 1,069 1,008 1,342 1,407 1,405 1,528 1,351

 Total Refined Produc ts 5,119 4,852 7,277 7,820 8,135 8,606 8,392

 U.S. Produc tion Segm ent 

 Crude Oil and NGL (m illion barrels ) 1,933 1,860 1,805 1,667 1,484 1,498 1,433

 Natural Gas (billion cubic feet) 12,281 12,421 11,765 10,952 11,348 11,957 13,109

 Volum es

 Source: Energy Inform ation Adm inis tration, Form EIA-28 (Financ ial Reporting Sy s tem ).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 118
1996 1997 1998 1999 2000 2001 2002

 U.S. Refining

 Runs to Stills 

 At Own Refineries 9,777 9,060 13,699 13,476 13,361 13,875 13,307

 By Refineries of Others 5 5 0 82 86 105 80

 Total Runs to Stills 9,782 9,065 13,699 13,558 13,447 13,980 13,387

Refinery Output at Own Refineries and 

 Refineries of Others

 Reformulated Motor Gasoline 1,302 768 1,552 1,792 2,129 2,061 1,991

 Oxygenated Motor Gasoline 165 749 1,018 609 412 588 552

 Other Motor Gasoline 3,410 2,980 4,665 4,588 4,207 4,373 4,456

 Total Motor Gasoline 4,877 4,497 7,235 6,989 6,748 7,022 6,999

 Distillate Fuels 3,323 2,921 4,278 4,167 4,376 4,331 4,167

 Other Refined Products 2,754 2,612 3,416 3,483 3,375 3,669 3,595

 Total Refinery Output 10,954 10,030 14,929 14,639 14,499 15,022 14,761

 Refinery Capacity at End of Year 10,477 9,410 14,277 14,158 14,424 14,682 14,557

 

 Number of Wholly-Owned Refineries 69 60 95 94 90 99 84

 

Foreign Refining

 Runs to Stills

 At Own Refineries 3,936 3,961 4,043 4,407 4,513 4,620 4,778

 By Refineries of Others 506 340 292 397 403 339 325

 Total Runs to Stills 4,442 4,301 4,335 4,804 4,916 4,959 5,103

 Refinery Output at Own Refineries

 Motor Gasoline 1,172 1,041 1,135 1,247 1,295 1,293 1,427

 Distillate Fuels 1,690 1,648 1,787 1,901 1,738 1,744 2,041

 Other Refined Products 1,280 1,283 1,213 1,315 1,717 1,729 1,405

 Total Refinery Output at Own Refineries 4,142 3,972 4,135 4,463 4,750 4,766 4,873

 Refinery Output at Refineries of Others

 Motor Gasoline 107 75 83 122 123 120 117

 Distillate Fuels 234 154 121 135 171 155 175

 Other Refined Products 165 110 87 146 80 84 70

 Total Refinery Output at Refineries of 506 339 291 403 374 359 362

Total Refinery Output 4,648 4,311 4,426 4,866 5,124 5,125 5,235

Refinery Capacity at End of Year 4,346 4,270 4,508 4,930 5,134 5,572 5,642

 

 Number of Wholly-Owned Refineries 20 20 20 19 18 23 22

 Number of Partially-Owned Refineries 12 15 15 18 18 18 19

Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

 (number of refineries)

 (number of refineries)

Table B28. U.S. and Foreign Petroleum Refining Statistics for FRS Companies, 1996-2002

 (thousand barrels per calendar day)

 (thousand barrels per calendar day)

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 119
All FRS Top Four

Five through 

Twelve2 All Other

2

United States

 Refinery Output Volume3 14,761 5,089 4,354 5,318 17,655 83.6

 Percent Gasoline

 Reformulated/Oxygenated 17.2 17.0 16.9 17.7 17.2 83.8

 Other 30.2 28.7 30.7 31.2 30.1 84.0

 Percent Distillate 28.2 28.3 27.5 28.8 30.0 78.6

 Percent Other 24.4 26.0 24.9 22.3 22.7 89.6

 Refinery Capacity

 Years Change (Net) -125 -51 553 -627 -29 (5)

 At Year End 14,557 4,544 4,542 5,471 17,339 84.0

 Utilization Rate4 91.0 96.8 92.0 85.8 88.4 (5)

Foreign 

 Refinery Output Volume3 5,235 4,583 0 652 - (5)

 Percent Gasoline 29.5 29.1 0.0 32.4 - (5)

 Percent Distillate 42.3 42.0 0.0 44.9 - (5)

 Percent Other 28.2 29.0 0.0 22.7 - (5)

 Refinery Capacity

 Years Change (Net) 70 197 0 -127 0 (5)

 At Year End 5,642 5,121 0 521 0 0.0

 Utilization Rate3 85.2 82.3 0.0 110.4 0.0 (5)

FRS companies data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

 Note: Sum of components may not equal total due to independent rounding.

 Sources: Industry data, U.S. - Refinery output and refinery capacity: Energy Information Administration, Forms EIA-820 (Annual Refinery

Report) and EIA-810 (Monthly Refinery Report); see Petroleum Supply Annual, 2001 and 2002. Industry data, Foreign - Refinery Capacity: 

British Petroleum Statistical Review of World Energy , 2002 and 2003. 

Refined Product Statistics 1 

 1U.S. FRS and U.S. industry data include operations in Puerto Rico and the U.S. Virgin Islands. Foreign FRS and foreign industry data

exclude operations in Puerto Rico and the U.S. Virgin Islands, as well as China.

 2

For foreign FRS, the "Five through Twelve" and "All Other" groups are combined to avoid disclosure.

 3

For FRS companies, includes refinery output at own refineries for own account and at others' refineries for own account.

 4

Defined as average daily crude runs at own refineries, for own account, and for account of others, divided by average daily crude 

distillation capacity.

 5

Not meaningful.

 FRS Companies

Table B29. U.S. and Foreign Refinery Output and Capacity for FRS Companies, Ranked by

 Total Energy Assets, and Industry, 2002

 (Thousand Barrels per Day)

Total Industry

FRS Percent of

Industry

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 120
U.S. Dispositions 1996 1997 1998 1999 2000 2001 2002

Motor Gasoline 

 Intersegment Sales 400 581 966 1,521 1,802 2,521 3,500

 U.S. Third-Party Sales

 Wholesale-Resellers 32,500 31,895 38,659 51,908 83,203 69,799 68,311

 Company Operated Automotive Outlets 11,293 11,855 15,497 17,334 24,870 22,843 18,662

 Company Lessee and Open Automotive Outlets 21,725 20,517 23,966 29,434 48,693 45,798 40,720

 Other (Industrial, Commercial and Other Retail) 9,412 6,337 5,880 9,104 17,826 26,774 27,498

 Total Third-Party Sales 74,930 70,604 84,002 107,780 174,592 165,214 155,191

Total Motor Gasoline Sales 75,330 71,185 84,968 109,301 176,394 167,735 158,691

Distillate Fuels 

 Intersegment Sales 291 191 682 708 444 535 2,387

 Third-Party Sales 41,327 36,771 38,831 51,102 91,554 83,167 73,542

Total Distillate Fuels Sales 41,618 36,962 39,513 51,810 91,998 83,702 75,929

Other Refined Products

 Intersegment Sales 4,124 3,322 2,059 2,779 6,078 7,386 4,474

 Third-Party Sales 20,453 17,642 21,224 25,727 36,191 32,786 33,096

Total Other Refined Products Sales 24,577 20,964 23,283 28,506 42,269 40,172 37,570

Total U.S. Refined Products 

 Intersegment Sales 4,815 4,094 3,707 5,008 8,324 10,442 10,361

 Third-Party Sales 136,710 125,017 144,057 184,609 302,337 281,167 261,829

Total U.S. Refined Products Sales 141,525 129,111 147,764 189,617 310,661 291,609 272,190

Motor Gasoline 

 Intersegment Sales 12 18 50 66 47 79 101

 U.S. Third-Party Sales

 Wholesale-Resellers 1,154 1,150 1,901 2,059 2,126 1,956 2,032

 Company Operated Automotive Outlets 319 335 558 540 543 545 464

 Company Lessee and Open Automotive Outlets 653 615 965 1,006 1,105 1,182 1,133

 Other (Industrial, Commercial and Other Retail) 350 253 316 399 465 777 820

 Total Third-Party Sales 2,476 2,353 3,739 4,004 4,239 4,460 4,450

Total Motor Gasoline Sales 2,488 2,371 3,789 4,070 4,286 4,539 4,551

Distillate Fuels

 Intersegment Sales 12 8 38 33 13 17 8

 Third-Party Sales 1,550 1,464 2,109 2,310 2,430 2,522 2,405

Total Distillate Fuels Sales 1,562 1,473 2,146 2,344 2,444 2,540 2,490

Other Refined Products

 Intersegment Sales 209 254 141 153 213 258 162

 Third-Party Sales 860 755 1,201 1,254 1,191 1,269 1,188

Total Other Refined Products Sales 1,069 1,008 1,342 1,407 1,405 1,528 1,351

Total U.S. Refined Products

 Intersegment Sales 232 280 229 252 274 354 348

 Third-Party Sales 4,886 4,572 7,048 7,568 7,861 8,252 8,043

Total U.S. Refined Products Sales 5,119 4,852 7,277 7,820 8,135 8,606 8,392

Number of Active Automotive Outlets at Year 

End

 Company Operated 8,927 8,942 13,645 12,018 12,583 11,380 9,745

 Lessee Dealers 15,247 12,852 16,396 17,847 16,953 11,474 9,371

 Open Dealers 14,151 11,959 28,859 26,805 25,707 31,231 26,277

Total Outlets 38,325 33,753 58,900 56,670 55,243 54,085 45,393

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Table B30. U.S. Refining/Marketing Dispositions of Refined Products by Channel of 

 Distribution for FRS Companies, 1996-2002

Values (million dollars)

 Volumes (million barrels)

Number of Automotive Outlets

5

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 121
Volume Price Volume Price Volume Price Volume Price

Gasoline

 Intra-Company Sales

2002 101.4 34.51 101.4 34.51 W W 0.0 0.00

2001 78.8 31.99 77.8 31.95 W W 0.0 0.00

 Percent Change 28.7 7.9 30.3 8.0 W W 0.0 0.0

 Wholesale/Resellers

2002 2,032.4 33.61 695.3 34.60 371.3 34.95 965.8 32.38

2001 1,955.8 35.69 676.6 36.06 324.4 36.80 954.9 35.05

 Percent Change 3.9 -5.8 2.8 -4.0 14.5 -5.0 1.1 -7.6

 Dealer-Operated Outlets

2002 1,133.4 35.93 653.4 36.23 148.8 36.68 331.2 34.99

2001 1,182.1 38.74 634.5 38.22 76.7 37.59 471.0 39.63

 Percent Change -4.1 -7.3 3.0 -5.2 94.0 -2.4 -29.7 -11.7

 Company-Operated Outlets

2002 464.3 40.20 189.0 37.56 135.2 40.50 140.1 43.46

2001 545.1 41.90 149.4 40.35 118.7 43.65 277.0 41.99

 Percent Change -14.8 -4.1 26.5 -6.9 13.8 -7.2 -49.4 3.5

 Other 1

2002 819.8 33.54 211.7 33.69 504.6 33.65 103.6 32.71

2001 777.0 34.46 257.4 35.72 198.3 32.90 321.2 34.41

 Percent Change 5.5 -2.7 -17.8 -5.7 154.4 2.3 -67.8 -5.0

Total Gasoline 

2002 4,551.2 34.87 1,850.7 35.37 1,159.8 35.25 1,540.8 33.97

2001 4,538.9 36.96 1,795.7 36.95 719.1 36.94 2,024.1 36.96

 Percent Change 0.3 -5.6 3.1 -4.3 61.3 -4.6 -23.9 -8.1

Distillate

2002 2,489.9 30.49 1,008.4 31.27 658.1 30.09 823.3 29.87

2001 2,539.8 32.96 988.6 33.55 415.6 33.55 1,135.6 32.22

 Percent Change -2.0 -7.5 2.0 -6.8 58.4 -10.3 -27.5 -7.3

All Other Products

2002 1,350.7 27.81 535.5 28.15 345.1 29.67 470.2 26.07

2001 1,527.6 26.30 641.4 26.66 286.0 25.03 600.2 26.51

 Percent Change -11.6 5.8 -16.5 5.6 20.7 18.5 -21.7 -1.6

Total Refined Products

2002 8,391.9 32.43 3,394.6 33.01 2,163.0 32.79 2,834.3 31.47

2001 8,606.3 33.88 3,425.7 34.04 1,420.7 33.55 3,759.9 33.86

 Percent Change -2.5 -4.3 -0.9 -3.0 52.3 -2.3 -24.6 -7.1 1Includes direct sales to industrial and commercial customers and sales to unconsolidated affiliates.

 Note: Sum of components may not equal total due to independent rounding.

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

 W = Data withheld to avoid disclosure.

Table B31. Sales of U.S. Refined Products, by Volume and Price, for FRS Companies 

 Ranked by Total Energy Assets, 2001-2002

 (Million Barrels and Dollars per Barrel)

Product Distribution 

Channel

All FRS Top Four Five through Twelve All Other

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 122
 Revenues and Costs 1996 1997 1998 1999 2000 2001 2002

Refined Product Revenues 141,525 129,111 147,764 189,617 310,661 291,609 272,190

Refined Product Costs

 Raw Materials Processed 1 70,339 58,888 60,094 83,348 135,624 109,565 116,277

 Refinery Energy Expense 5,480 5,005 5,349 6,427 10,838 11,321 10,114

 Other Refinery Expense 9,882 8,436 12,219 11,734 10,635 12,274 15,202

 Product Purchases 37,958 37,319 43,609 63,491 117,640 114,827 103,256

 Other Product Supply Expense 4,072 3,777 5,160 4,915 6,655 6,552 12,562

 Marketing Expense 2 9,318 8,538 10,308 11,100 11,128 13,672 13,186

Total Refined Product Costs 137,049 121,963 136,739 181,015 292,520 268,211 270,597

Refined Product Margin 4,476 7,148 11,025 8,602 18,141 23,398 1,593

Refined Products Sold (million barrels) 5,118.6 4,852.2 7,276.9 7,820.2 8,134.7 8,606.3 8,391.9

Dollars per Barrel Margin 3 0.87 1.47 1.52 1.10 2.23 2.72 0.19

Other Refining/Marketing Revenues 4 10,731 9,693 15,997 14,282 14,196 16,918 15,343

Other Refining/Marketing Expenses

 Depreciation, Depletion, & Allowance 3,847 3,674 4,700 5,273 4,712 5,259 5,617

 Other 5 7,873 8,419 15,547 12,546 16,865 18,683 12,811

Total Other Expenses 11,720 12,093 20,247 17,819 21,577 23,942 18,428

Refining/Marketing Operating Income 3,487 4,748 6,775 5,065 10,760 16,374 -1,492

Miscellaneous Revenue & Expense 6 -101 204 1,315 1,367 1,265 1,866 1,002

Less Income Taxes 1,135 1,876 2,142 1,714 4,360 6,271 346

Refining/Marketing Net Income 2,251 3,106 5,932 4,883 7,659 11,951 -2,164

Table B32. U.S. Refining/Marketing Revenues and Costs for FRS Companies, 

 1996-2002

 (Million Dollars)

 1

Represents reported cost of raw materials processed at refineries, less any profit from raw material trades or

exchanges by refining/marketing.

 2

Excludes costs of nonfuel goods and services and tires, batteries, and accessories (TBA).

 3

Dollars per barrel of refined product sold.

 4

Includes revenues from transportation services supplied (non-federally regulated), TBA sales, and miscellaneous.

 5

Includes general and administrative expenses, research and development costs, costs of transportation services 

supplied to others, and expenses for TBA.

 6

Includes other revenue and expense items, extraordinary items, and cumulative effect of accounting changes. 

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 123
General Operating Expenses 1996 1997 1998 1999 2000 2001 2002

 Raw Material Supply

 Raw Material Purchases 156,745 148,351 126,653 178,972 320,166 239,027 227,778

 Other Raw Material Supply Expense 4,067 4,523 5,183 3,184 2,371 4,196 4,520

 Total Raw Material Supply Expense 160,812 152,874 131,836 182,156 322,537 243,223 232,298

 Less: Cost of Raw Materials Input To Refining 75,892 64,132 62,955 85,270 139,931 114,400 121,192

Net Raw Material Supply 84,920 88,742 68,881 96,886 182,606 128,823 111,106

Refining

 Raw Materials Input to Refining 75,892 64,132 62,955 85,270 139,931 114,400 121,192

 Less: Raw Material Used as Refinery Fuel 3,922 3,798 3,598 4,254 6,910 7,132 6,954

 Refinery Process Energy Expense 5,480 5,005 5,349 6,427 10,838 11,321 10,114

 Other Refining Operating Expenses 10,631 9,173 12,984 12,928 13,675 14,657 16,459

 Refined Product Purchases 37,958 37,319 43,609 63,491 117,640 114,827 103,256

 Other Refined Product Supply Expenses 4,072 3,777 5,160 4,915 6,655 6,552 12,562

Total Refining 130,111 115,608 126,459 168,777 281,829 254,625 256,629

Marketing

 Cost of Other Products Sold 5,449 6,255 6,844 5,305 7,342 9,797 8,677

 Other Marketing Expenses 9,318 8,538 10,308 11,100 11,128 13,672 13,186

 Subtotal 14,767 14,793 17,152 16,405 18,470 23,469 21,863

 Expense of Transport Services for Others 507 376 4,297 4,191 3,691 4,002 439

Total Marketing 15,274 15,169 21,449 20,596 22,161 27,471 22,302

Total U.S. Refining/Marketing Segment 

General Operating Expenses 230,305 219,519 216,789 286,259 486,596 410,919 390,037

Table B33. U.S. Petroleum Refining/Marketing General Operating Expenses for FRS Companies, 

 1996-2002

 (Million Dollars)

 Source: Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 124
Reserves and Production Statistics 1996 1997 1998 1999 2000 2001 2002

Changes to U.S. Coal Reserves

 Beginning of Period 10,493 9,410 7,502 5,334 4,410 2,530 1,320

 Changes due to: 

 Leases/Purchases of Minerals-in-Place WWWWWWW

 Corporate Mergers and Acquisitions WWWWWWW

 Other Reserve Changes 8 -127 -17 -25 -58 -354 27

 Production -169 -163 -74 -44 -36 -33 -29

 Dispositions of Minerals-in-Place -1,150 -774 -2,113 -802 -1,799 W W

 End of Period Reserves 9,542 8,498 5,334 4,507 2,530 1,320 856

Weighted Average Annual Production

Capacity 192 215 65 55 51 40 40

Reserves and Production:

 Total United States

 FRS Companies' Reserves 9,542 8,498 5,334 4,507 2,530 1,320 856

 FRS Companies' Production 169 163 74 44 36 33 29

 U.S. Industry Production 1,064 1,090 1,118 1,100 1,074 1,128 1,093

 Region

 East

 FRS Companies' Reserves 2,675 2,477 1,774 1,676 1,034 557 227

 FRS Companies' Production 44 43 24 21 20 16 14

 U.S. Industry Production 452 468 460 426 420 433 399

 Midwest

 FRS Companies' Reserves 2,467 2,080 1,372 1,055 1,051 394 W

 FRS Companies' Production 18 17 12 WWWW

 U.S. Industry Production 112 112 110 104 87 95 93

 West

 FRS Companies' Reserves 4,400 3,940 2,188 1,776 446 370 W

 FRS Companies' Production 107 104 38 WWWW

 U.S. Industry Production 500 511 548 571 566 597 601

Mining Method

 Underground

 FRS Companies' Reserves 4,571 3,880 2,352 1,853 1,752 886 620

 FRS Companies' Production 59 51 28 21 21 18 16

 U.S. Industry Production 410 421 418 392 374 381 357

 Surface

 FRS Companies' Reserves 4,970 4,618 2,982 2,654 779 434 236

 FRS Companies' Production 110 112 46 23 15 15 13

 U.S. Industry Production 654 669 700 709 700 747 736

Table B34. U.S. Coal Reserves Balance for FRS Companies, 1996-2002

 (Million Tons)

 W = Data withheld to avoid disclosure.

 Sources: Coal production: 1996-2000--Energy Information Administration, Coal Industry Annual , annual reports; 2001-2002 - EIA,

Annual Coal Report, annual reports.

FRS Companies' data - Energy Information Administration, Form EIA-28 (Financial Reporting System).

Energy Information Administration/Performance Profiles of Major Energy Producers 2002 125