Form 10-K
Table of Contents

2002


UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549


FORM 10-K

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

OR

¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

 

NEW JERSEY

(State or other jurisdiction of
incorporation or organization)

 

13-5409005

(I.R.S. Employer
Identification Number)

 

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant’s telephone number, including area code)


Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class


  

Name of Each Exchange
on Which Registered


Common Stock, without par value (6,689,882,215 shares
outstanding at February 28, 2003)

  

New York Stock Exchange

Registered securities guaranteed by Registrant:

    

SeaRiver Maritime Financial Holdings, Inc.

    

Twenty-Five Year Debt Securities due October 1, 2011

  

New York Stock Exchange

Exxon Capital Corporation

    

Twelve Year 6% Notes due July 1, 2005

  

New York Stock Exchange

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes   ü    No        

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ü   

 

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Act).  Yes   ü    No        

 

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 28, 2002, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $40.92 on the New York Stock Exchange composite tape, was in excess of $276 billion.

 

Documents Incorporated by Reference:

Proxy Statement for the 2003 Annual Meeting of Shareholders (Part III)



Table of Contents

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

 

TABLE OF CONTENTS

 

    

Page
Number


PART I

Item 1.

  

Business

  

1-2

Item 2.

  

Properties

  

2-17

Item 3.

  

Legal Proceedings

  

17-18

Item 4.

  

Submission of Matters to a Vote of Security Holders

  

18

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K,     Item 401(b)]

  

19

PART II

Item 5.

  

Market for Registrant’s Common Stock and Related Shareholder Matters

  

20

Item 6.

  

Selected Financial Data

  

20

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

20

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

  

21

Item 8.

  

Financial Statements and Supplementary Data

  

21

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  

21

PART III

Item 10.

  

Directors and Executive Officers of the Registrant

  

21

Item 11.

  

Executive Compensation

  

21

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

  

21

Item 13.

  

Certain Relationships and Related Transactions

  

21

Item 14.

  

Controls and Procedures

  

21

PART IV

Item 15.

  

Exhibits, Financial Statement Schedules and Reports on Form 8-K

  

22

Financial Section

  

23-67

Signatures

  

68-69

Certifications

  

70-72

Index to Exhibits

  

73

Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges

    


Table of Contents

PART I

 

Item 1.     Business.

 

Exxon Mobil Corporation (“ExxonMobil”), formerly named Exxon Corporation, was incorporated in the State of New Jersey in 1882. On November 30, 1999, Mobil Corporation (“Mobil”) became a wholly-owned subsidiary of Exxon Corporation (“Exxon”) and Exxon changed its name to Exxon Mobil Corporation.

 

Divisions and affiliated companies of ExxonMobil operate or market products in the United States and about 200 other countries and territories. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of basic petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil also has interests in electric power generation facilities. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.

 

Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso or Mobil. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso and Mobil, as well as terms like corporation, company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.

 

ExxonMobil’s worldwide environmental costs in 2002 totaled $2,343 million of which $1,054 million were capital expenditures and $1,289 million were operating costs (including $400 million of site restoration and environmental provisions). These costs were mostly associated with air and water conservation. Total costs for such activities are expected to increase to about $2.5 billion in both 2003 and 2004 (with capital expenditures representing about 50 percent of the total). The projected increase is primarily for capital projects to implement refining technology to manufacture low-sulfur motor fuels in many parts of the world.

 

Operating data and industry segment information for the corporation are contained on pages 58, 59, 61 and 67; information on oil and gas reserves is contained on pages 64 and 65 and information on company-sponsored research and development activities is contained on page 45 of the Financial Section of this report. The number of regular employees was 92.5 thousand, 97.9 thousand and 99.6 thousand at years ended 2002, 2001 and 2000, respectively.

 

ExxonMobil maintains a website at www.exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Information on our website is not incorporated into this report.

 

Factors Affecting Future Results

 

Competitive Factors:    The energy and petrochemical industries are highly competitive. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of industry and individual consumers. The corporation competes with other firms in the sale or purchase of various goods or services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes. A key component of the corporation’s competitive position, particularly given the commodity-based nature of many of its products, is its ability to manage operating expenses successfully, which requires continuous management focus on reducing unit costs and improving efficiency.

 

Political Factors:    The operations and earnings of the corporation and its affiliates throughout the world have been, and may in the future be, affected from time to time in varying degree by

 

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political instability and by other political developments and laws and regulations, such as forced divestiture of assets; restrictions on production, imports and exports; war or other international conflicts; civil unrest and local security concerns that threaten the safe operation of company facilities; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of contract rights; and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the corporation vary greatly from country to country and are not predictable.

 

Industry and Economic Factors:    The operations and earnings of the corporation and its affiliates throughout the world are affected by local, regional and global events or conditions that affect supply and demand for oil, natural gas, petroleum products, petrochemicals and other ExxonMobil products. These events or conditions are generally not predictable and include, among other things, general economic growth rates and the occurrence of economic recessions; the development of new supply sources; adherence by countries to OPEC quotas; supply disruptions; weather, including seasonal patterns that affect energy demand and severe weather events that can disrupt operations; technological advances, including advances in exploration, production, refining, and petrochemical manufacturing technology and advances in technology relating to energy usage; changes in demographics, including population growth rates and consumer preferences; and the competitiveness of alternative hydrocarbon or other energy sources or product substitutes.

 

Project Factors:    In addition to the factors cited above, the advancement, cost and results of particular ExxonMobil projects depend on the outcome of negotiations with partners, governments, suppliers, customers or others; changes in operating conditions or costs; and the occurrence of unforeseen technical difficulties.

 

Market Risk Factors:    See pages 33 and 34 of the Financial Section of this report for discussion of the impact of market risks, inflation and other uncertainties.

 

Projections, estimates and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 2, 7 and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report.

 

Item 2.    Properties.

 

Part of the information in response to this item and to the Securities Exchange Act Industry Guide 2 is contained in the Financial Section of this report in Note 10, which note appears on page 47, and on pages 62 through 67.

 

Information with regard to oil and gas producing activities follows:

 

1.

  

Net Reserves of Crude Oil and Natural Gas Liquids (millions of barrels) and Natural Gas (billions of cubic feet) at Year-End 2002

 

Estimated proved reserves are shown on pages 64 and 65 of the Financial Section of this report. No major discovery or other favorable or adverse event has occurred since December 31, 2002, that would cause a significant change in the estimated proved reserves as of that date. For information on the standardized measure of discounted future net cash flows relating to proved oil and gas reserves, see page 66 of the Financial Section of this report.

 

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The estimation of proved reserves is an ongoing process based on rigorous technical evaluations and extrapolations of well information such as flow rates and reservoir pressure declines. In certain deepwater fields, proved reserves are occasionally recorded before flow tests are conducted because of the safety and cost implications of conducting the tests. In those situations, other industry accepted analyses are used such as information from well logs, a thorough pressure and fluid sampling program, conventional core data obtained across the entire reservoir interval and nearby analog data. Historically, proved reserves recorded using these methods have been immaterial when compared to the corporation’s total proved reserves and have also been validated by subsequent flow tests or actual production levels. In addition, the corporation records proved reserves in conjunction with significant funding commitments made towards development of the reserves.

 

2.    Estimates of Total Net Proved Oil and Gas Reserves Filed with Other Federal Agencies

 

During 2002, ExxonMobil filed proved reserves estimates with the U.S. Department of Energy on Forms EIA-23 and EIA-28. The information on Form EIA-28 is presented on the same basis as the registrant’s Annual Report on Form 10-K for 2001, which shows ExxonMobil’s net interests in all liquids and gas reserve volumes and changes thereto from both ExxonMobil-operated properties and properties operated by others. The data on Form EIA-23, although consistent with the data on Form EIA-28, is presented on a different basis, and includes 100 percent of the oil and gas volumes from ExxonMobil-operated properties only, regardless of the company’s net interest. In addition, Form EIA-23 information does not include gas plant liquids. The difference between the oil and gas reserves reported on EIA-23 and those reported in the registrant’s Annual Report on Form 10-K for 2001 exceeds five percent.

 

3.    Average Sales Prices and Production Costs per Unit of Production

 

Reference is made to page 62 of the Financial Section of this report. Average sales prices have been calculated by using sales quantities from our own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the reserves table on page 64 of the Financial Section of this report. The net production volumes of natural gas available for sale used in this calculation are shown on page 67 of the Financial Section of this report. The volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.

 

4.    Gross and Net Productive Wells

 

    

Year-End 2002


    

Year-End 2001


 
    

Oil


    

Gas


    

Oil


    

Gas


 
    

Gross


    

Net


    

Gross


    

Net


    

Gross


    

Net


    

Gross


    

Net


 

United States

  

34,737

 

  

13,509

 

  

  9,564

 

  

  5,614

 

  

35,610

 

  

14,020

 

  

9,905

 

  

  5,872

 

Canada

  

6,719

 

  

5,421

 

  

5,268

 

  

2,623

 

  

6,551

 

  

5,266

 

  

5,096

 

  

2,548

 

Europe

  

1,839

 

  

593

 

  

1,398

 

  

531

 

  

1,710

 

  

548

 

  

1,356

 

  

479

 

Asia-Pacific

  

1,463

 

  

557

 

  

815

 

  

288

 

  

1,401

 

  

527

 

  

760

 

  

266

 

Africa

  

373

 

  

160

 

  

3

 

  

1

 

  

325

 

  

139

 

  

1

 

  

1

 

Other

  

1,181

 

  

221

 

  

103

 

  

32

 

  

1,086

 

  

202

 

  

123

 

  

39

 

    

  

  

  

  

  

  

  

Total

  

46,312

 

  

20,461

 

  

17,151

 

  

9,089

 

  

46,683

 

  

20,702

 

  

17,241

 

  

9,205

 

    

  

  

  

  

  

  

  

 

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5.    Gross and Net Developed Acreage

 

    

Year-End 2002


    

Year-End 2001


 
    

Gross


    

Net


    

Gross


    

Net


 
    

(Thousands of acres)

 

United States

  

    9,451

 

  

    5,695

 

  

      9,528

 

  

      5,714

 

Canada

  

4,720

 

  

2,356

 

  

4,538

 

  

2,414

 

Europe

  

11,842

 

  

4,874

 

  

11,206

 

  

4,819

 

Asia-Pacific

  

5,393

 

  

1,692

 

  

5,203

 

  

1,640

 

Africa

  

2,251

 

  

685

 

  

2,108

 

  

630

 

Other

  

9,223

 

  

1,845

 

  

  9,223

 

  

  1,846

 

    

  

  

  

Total

  

42,880

 

  

17,147

 

  

41,806

 

  

17,063

 

    

  

  

  

 

Note: Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.

 

6.    Gross and Net Undeveloped Acreage

 

    

Year-End 2002


    

Year-End 2001


 
    

Gross


    

Net


    

Gross


    

Net


 
    

(Thousands of acres)

 

United States

  

11,396

 

  

  7,309

 

  

  11,801

 

  

    7,669

 

Canada

  

18,704

 

  

8,701

 

  

21,151

 

  

9,552

 

Europe

  

9,305

 

  

2,687

 

  

13,218

 

  

4,624

 

Asia-Pacific

  

24,127

 

  

12,163

 

  

28,295

 

  

14,161

 

Africa

  

29,488

 

  

12,205

 

  

43,660

 

  

15,736

 

Other

  

26,492

 

  

18,012

 

  

33,190

 

  

20,456

 

    

  

  

  

Total

  

119,512

 

  

61,077

 

  

151,315

 

  

72,198

 

    

  

  

  

 

7.    Summary of Acreage Terms in Key Areas

 

UNITED STATES

 

Oil and gas leases have an exploration period ranging from one to ten years, and a production period that normally remains in effect until production ceases. In some instances, a “fee interest” is acquired where both the surface and the underlying mineral interests are owned outright.

 

CANADA

 

Exploration permits are granted for varying periods of time with renewals possible. Production leases are held as long as there is production on the lease. The majority of Cold Lake leases were taken for an initial 21-year term in 1968-1969 and renewed for a second 21-year term in 1989-1990. The exploration acreage in Eastern Canada is currently held by work commitments of various amounts.

 

EUROPE

 

France

 

Exploration permits are granted for periods of three to five years, and are renewable up to two times accompanied by substantial acreage relinquishments: 50 percent of the acreage at first renewal; 25 percent of the remaining acreage at second renewal. A 1994 law requires a bidding process prior to granting of an exploration permit. Upon discovery of commercial hydrocarbons, a production concession is granted for up to 50 years, renewable in periods of 25 years each.

 

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Germany

 

Exploration concessions are granted for an initial maximum period of five years with possible extensions of up to three years for an indefinite period. Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple possible extensions as long as there is production on the license.

 

Italy

 

Exploration permits are awarded for a period of six years, subject to specific, minimum work commitments (an exploration well is usually included). If permit obligations have been fulfilled, the titleholder of the permit is entitled to two subsequent extensions of three years each. The program of both the first and second extension period must include the drilling of a further well. Production licenses are awarded for a period of 20 years upon discovery of commercial hydrocarbons. After 15 years, the license holder can apply for an extension of ten years. After seven years of the first extension period, the license holder can apply for a further extension of five years.

 

Netherlands

 

Under the new Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the Mining Law.

 

Exploration and production rights granted prior to January 1, 2003 remain subject to their existing terms, and differ slightly for onshore and offshore areas.

 

Onshore:  Exploration licenses were issued for a period of time necessary to perform the activities for which the license was issued. Production concessions are granted after discoveries have been made, under conditions that are negotiated with the government. Normally, they are field-life concessions covering an area defined by hydrocarbon occurrences.

 

Offshore: Exploration licenses issued between 1976 and 1996 were for a ten-year period, with relinquishment of about 50 percent of the original area required at the end of six years. Exploration licenses granted after that time were for a period of time necessary to perform the activities for which the permit was issued. Production licenses are normally issued for a 40-year period.

 

Norway

 

Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for an initial period of up to ten years and an extension period of up to 30 years, with relinquishment of at least one-half of the original area required at the end of the sixth year. Licenses issued after July 1, 1997 have an initial period of four to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half of the original area required at the end of the initial period.

 

United Kingdom

 

Acreage terms are fixed by the government and are periodically changed. For example, the regulations governing licenses issued between 1996 and 1998 provided for an initial term of three years with possible extensions of six, 15 and 24 years for a license period of 45 more years. After the second extension, the license must be surrendered in part. Licenses issued in 2002 as part of the 20th licensing round have an initial term of four years with a second term extension of four years. There is a mandatory relinquishment of all acreage that is not covered by a development plan at the end of the second term.

 

 

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ASIA-PACIFIC

 

Australia

 

Onshore:  Acreage terms are fixed by the individual state and territory governments. These terms and conditions vary significantly between the states and territories. Exploration permits are normally granted for two to six years (in some states the responsible Minister fixes the term) with possible renewals and relinquishment. Production licenses in South Australia are granted for an unlimited term, subject to meeting stipulated conditions in the license, including production and expenditure requirements. Production licenses in Queensland are granted for varying periods consistent with expected field lives, with renewals on a similar basis.

 

Offshore:  Exploration and production activities beyond the three nautical mile limit are governed by Federal legislation applicable to all ExxonMobil’s offshore acreage. Exploration permits granted before January 1, 2003 were issued for six years with three possible five-year renewal periods. Exploration permits granted after that date are issued for six years with two possible five-year renewal periods. A 50 percent relinquishment of remaining area is mandatory at the end of each renewal period. Retention leases may be granted for resources that are not commercially viable at the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to September 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter renewals at the discretion of the Joint Authority, comprising Federal and State Ministers. Effective from September 1998, new production licenses are granted “indefinitely”, i.e., for the life of the field (if no operations for the recovery of petroleum have been carried on for five years, the license may be terminated).

 

Indonesia

 

Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract, negotiated with the national oil company. Pursuant to the 2001 Oil and Gas Law, the national oil company’s role as manager of upstream activities under existing and future contracts was transferred, effective July 16, 2002, to an upstream supervisory body (legally referred to as the Badan Pelaksana, commonly known as “BPMIGAS”). Existing cooperation contracts are in the process of being amended to reflect the transfer of authority to BPMIGAS; however, the terms and conditions of the existing contracts are not being changed.

 

Japan

 

The Mining Law provides for the granting of concessions that convey exploration and production rights. Exploration rights are granted for an initial two-year period, and may be extended for two two-year periods for gas and three two-year periods for oil. Production rights have no fixed term and continue until abandonment so long as the rights holder is fulfilling its obligations.

 

Malaysia

 

Exploration and production activities are governed by production sharing contracts negotiated with the national oil company. The more recent contracts have an overall term of 24 to 38 years with possible extensions to the exploration or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries must be relinquished. The development period is from four to six years from commercial discovery, with the possibility of extensions under special circumstances. Areas from which commercial production has not started by the end of the development period must be relinquished if no extension is granted. The total production period is 15 to 25 years from first commercial lifting, not to exceed the overall term of the contract.

 

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Papua New Guinea

 

Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years with a five-year extension possible. Generally, a 50 percent relinquishment of the license area is required at the end of the initial six year-term, if extended. Petroleum Development licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Minister’s discretion. Petroleum Retention licenses may be granted for gas resources that are not commercially viable at the time of application, but may become commercially viable. Petroleum Retention licenses are granted for five-year terms, and may be extended twice for a maximum retention time of 15 years.

 

Russia

 

Acreage terms are fixed by the production sharing agreement (PSA) executed in 1996 between the Russian government and the Sakhalin I consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, or until 2021. The term may be extended thereafter in 10-year increments as specified in the PSA.

 

Thailand

 

The Petroleum Act of 1971 allows production under ExxonMobil’s concession for 30 years (through 2021) with a possible ten-year extension at terms generally prevalent at the time.

 

AFRICA

 

Angola

 

Exploration and production activities are governed by production sharing agreements with an initial exploration term of four years and an optional second phase of two to three years. The production period is for 25 years and agreements generally provide for a negotiated extension.

 

Cameroon

 

Exploration and production activities are governed by various agreements negotiated with the national oil company and the government of Cameroon. Exploration permits are granted for terms from four to 16 years and are generally renewable for multiple periods up to four years each. Upon commercial discovery, mining concessions are issued for a period of 25 years with one 25-year extension.

 

Chad

 

Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The production term is for 30 years.

 

Equatorial Guinea

 

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years while the production period for gas is 50 years.

 

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Nigeria

 

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company. The national oil company holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase plus one or two optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the ten-year exploration period, and OMLs have a 20-year production period that may be extended.

 

Some exploration activities are carried out in deepwater by joint ventures with indigenous companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-renewable, while in all other areas the licenses are for five years and also are non-renewable. Demonstrating a commercial discovery is the basis for conversion of an OPL to an OML.

 

OMLs granted prior to the 1969 Petroleum Act (i.e., under the Minerals Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40 years in offshore areas and are renewable upon 12 months’ written notice, for further periods of 30 and 40 years, respectively.

 

OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for onshore or offshore location and are renewable, upon 12 months’ written notice, for another period of 20 years. OMLs not held by the national oil company are also subject to a mandatory 50 percent relinquishment after the first ten years of their duration.

 

The Memorandum of Understanding (MOU) defining commercial terms applicable to existing oil production was renegotiated and executed in 2000. The MOU is effective for a minimum of three years with possible extensions on mutual agreement and is terminable on one calendar year’s notice.

 

OTHER COUNTRIES

 

United Arab Emirates

 

Exploration and production activities in the Emirate of Abu Dhabi are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi.

 

Argentina

 

The onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration period and up to two years for the third exploration period. A 50 percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been developed.

 

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Azerbaijan

 

The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field (commonly known as the Megastructure) is established for an initial period of 30 years starting from the PSA execution date in 1994.

 

Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The exploration period consists of three or four years with the possibility of a one to three-year extension. The production period, which includes development, is for 25 years or 35 years with the possibility of one or two five-year extensions.

 

Kazakhstan

 

Onshore: Exploration and production activities are governed by the production license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.

 

Offshore: Exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years with the possibility of a two-year extension. The production period, which includes development, is for 20 years with the possibility of two ten-year extensions.

 

Qatar

 

The State of Qatar grants gas production development projects rights to develop and supply gas from the offshore North Field to permit the economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects.

 

Republic of Yemen

 

Production sharing agreements (PSAs) negotiated with the government entitle the company to participate in exploration operations within a designated area during the exploration period. In the event of a commercial oil discovery, the company is entitled to proceed with development and production operations during the development period. The length of these periods and other specific terms are negotiated prior to executing the PSA. Existing production operations have a development period extending 20 years from first commercial declaration made in November 1985 for the Marib PSA and June 1995 for the Jannah PSA.

 

Venezuela

 

Exploration and production activities are governed by contracts negotiated with the national oil company. Exploration activity is covered by risk/profit sharing contracts where exploration blocks are awarded for 35 years. Production licenses are awarded for 20 years under production service agreements.

 

Strategic association agreements (such as the Cerro Negro project) are typically limited to those projects that require vertical integration for extra heavy crude oil. Contracts are awarded for 35 years. Significant amendments to the contract terms require Venezuelan congressional approval.

 

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8.    Number of Net Productive and Dry Wells Drilled

 

    

2002


    

2001


    

2000


 

A. Net Productive Exploratory Wells Drilled

                    

United States

  

12

 

  

4

 

  

2

 

Canada

  

20

 

  

30

 

  

49

 

Europe

  

2

 

  

3

 

  

3

 

Asia-Pacific

  

2

 

  

7

 

  

5

 

Africa

  

10

 

  

4

 

  

2

 

Other

  

 

  

3

 

  

1

 

    

  

  

Total

  

46

 

  

51

 

  

62

 

    

  

  

B. Net Dry Exploratory Wells Drilled

                    

United States

  

5

 

  

4

 

  

2

 

Canada

  

4

 

  

22

 

  

12

 

Europe

  

4

 

  

3

 

  

3

 

Asia-Pacific

  

1

 

  

2

 

  

3

 

Africa

  

5

 

  

4

 

  

4

 

Other

  

4

 

  

6

 

  

2

 

    

  

  

Total

  

23

 

  

41

 

  

26

 

    

  

  

C. Net Productive Development Wells Drilled

                    

United States

  

709

 

  

733

 

  

604

 

Canada

  

430

 

  

451

 

  

213

 

Europe

  

36

 

  

32

 

  

40

 

Asia-Pacific

  

67

 

  

44

 

  

30

 

Africa

  

27

 

  

23

 

  

16

 

Other

  

18

 

  

30

 

  

31

 

    

  

  

Total

  

1,287

 

  

1,313

 

  

934

 

    

  

  

D. Net Dry Development Wells Drilled

                    

United States

  

18

 

  

14

 

  

7

 

Canada

  

8

 

  

6

 

  

 

Europe

  

2

 

  

3

 

  

5

 

Asia-Pacific

  

1

 

  

1

 

  

1

 

Africa

  

 

  

 

  

 

Other

  

 

  

 

  

 

    

  

  

Total

  

29

 

  

24

 

  

13

 

    

  

  

Total number of net wells drilled

  

1,385

 

  

1,429

 

  

1,035

 

    

  

  

 

9.    Present Activities

 

A. Wells Drilling

 

    

Year-End 2002


      

Year-End 2001


 
    

Gross


    

Net


      

Gross


    

Net


 

United States

  

157

 

  

75

 

    

138

 

  

83

 

Canada

  

51

 

  

37

 

    

33

 

  

19

 

Europe

  

45

 

  

17

 

    

7

 

  

2

 

Asia-Pacific

  

10

 

  

6

 

    

26

 

  

14

 

Africa

  

78

 

  

31

 

    

13

 

  

4

 

Other

  

33

 

  

5

 

    

10

 

  

3

 

    

  

    

  

Total

  

374

 

  

171

 

    

227

 

  

125

 

    

  

    

  

 

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B.    Review of Principal Ongoing Activities in Key Areas

 

During 2002, ExxonMobil’s activities were conducted, either directly or through affiliated companies, by ExxonMobil Exploration Company (for exploration), by ExxonMobil Development Company (for large development activities), by ExxonMobil Production Company (for producing and smaller development actives) and by ExxonMobil Gas & Power Marketing Company (for gas marketing). During this same period, some of ExxonMobil’s exploration, development, production and gas marketing activities were also conducted in California by Aera Energy, LLC, a 48.2 percent owned ExxonMobil joint venture with Shell Oil Company, and in Canada by the Resources Division of Imperial Oil Limited, which is 69.6 percent owned by ExxonMobil.

 

Some of the more significant ongoing activities are set forth below:

 

UNITED STATES

 

Exploration and delineation of additional hydrocarbon resources continued in 2002. At year-end 2002, ExxonMobil’s acreage totaled 13.0 million net acres, of which 3.4 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. A total of 16.6 net exploration and delineation wells were completed during 2002.

 

During 2002, 663.7 net development wells were completed within and around mature fields in the inland lower 48 states. Participation in Alaska production and development continued and a total of 29.5 net development wells were drilled. On Alaska’s North Slope, the permitting process has begun on the gas-cycling project at Point Thomson.

 

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2002 was 3.3 million acres. A total of 25.4 net development wells were completed during the year and development continued on several Gulf of Mexico projects.

 

  ·   In February 2002, production began from the Madison development well located in 4,850 feet of water, tied back to the Hoover-Diana host platform.

 

  ·   In October 2002, the second phase of the Mica development, located in 4,500 feet of water, was brought on production, tied back to the Pompano host platform.

 

  ·   At the Thunder Horse development, appraisal and development drilling continued and facility fabrication is underway. A floating semi-submersible platform has been selected as the design concept for the field.

 

CANADA

 

ExxonMobil’s year-end acreage holdings totaled 11.1 million net acres, of which 5.8 million net acres were offshore. A total of 462.6 net exploration and development wells were completed during the year.

 

Gross production from Cold Lake averaged 112 thousand barrels per day during 2002. The next three phases of expansion, Cold Lake 11-13, started up in 2002. In Eastern Canada, the Terra Nova oil development project came on stream in early 2002. Development of the Sable Offshore Energy Project continues, with the Alma field project underway.

 

EUROPE

 

France

 

ExxonMobil’s acreage at year-end 2002 was 0.1 million net onshore acres, with 1.0 net development wells completed during the year.

 

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Germany

 

A total of 2.5 million net onshore acres were held by ExxonMobil at year-end 2002, with 2.4 net development wells drilled during the year.

 

Italy

 

ExxonMobil’s acreage was 30 thousand net onshore acres at year-end 2002, with 1.3 net development wells completed during the year.

 

Netherlands

 

ExxonMobil’s interest in licenses totaled 2.1 million net acres at year-end 2002, 1.5 million acres onshore and 0.6 million acres offshore. During 2002, 5.1 net exploration and development wells were drilled. Offshore, the K/15-FK platform was set.

 

Norway

 

ExxonMobil’s net interest in licenses at year-end 2002 totaled approximately 0.8 million acres, all offshore. ExxonMobil participated in 8.1 net exploration and development well completions in 2002. Production was initiated on Sigyn in December 2002 and at Ringhorne in early 2003. Field development projects at Grane, Fram West, Mikkel and Vigdis Extension are in progress.

 

United Kingdom

 

ExxonMobil’s net interest in licenses at year-end 2002 totaled approximately 2.0 million acres, all offshore. A total of 25.5 net exploration and development wells were completed during the year. Several projects started up in 2002, including Maclure, Otter, Madoes and Mirren, while Penguins started up in early 2003. Several projects are underway including Goldeneye, Scoter and Carrack.

 

ASIA-PACIFIC

 

Australia

 

ExxonMobil’s net year-end 2002 acreage holdings totaled 4.8 million acres, 2.4 million acres offshore and 2.4 million acres onshore. ExxonMobil drilled a total of 18.7 net exploration and development wells in 2002, both offshore and onshore. A gas pipeline in the offshore Gippsland Basin from the Bream A platform to shore was commissioned in 2002.

 

Indonesia

 

ExxonMobil had 7.3 million net acres at year-end 2002, 6.2 million acres offshore and 1.1 million acres onshore. A total of 5.0 net development wells were drilled during the year.

 

Japan

 

ExxonMobil’s net offshore acreage was 37 thousand acres at year-end 2002.

 

Malaysia

 

ExxonMobil had interests in production sharing contracts covering 0.9 million net acres offshore Malaysia at year-end 2002. During the year, a total of 46.0 net development wells were completed. Development and infill drilling were successfully completed at six platforms, Irong Barat-A, Palas-A, Seligi-C, Seligi-H, Dulang-A and Dulang-B. First oil was produced from the Angsi-B platform and the Larut, Lawang/Langat and Serudon fields in 2002. Development projects are currently in progress at Bintang, Irong Barat-B&C, Tapis-F, Guntong-E, F&G, Raya-B and Angsi-C&E.

 

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Papua New Guinea

 

A total of 0.6 million net onshore acres were held by ExxonMobil at year-end 2002, with 1.5 net exploration and development wells completed during the year. The Moran field development project was completed and gas injection initiated in 2002.

 

Russia

 

ExxonMobil’s net acreage holdings at year-end 2002 were 0.1 million acres, all offshore. Construction has commenced on Phase 1 of Sakhalin I, which is developing a portion of the oil zones. Phase 1 facilities will include an offshore platform, onshore drill sites for extended reach drilling to offshore oil zones, two onshore processing plants, an oil pipeline from Sakhalin Island to the Russian mainland and a mainland terminal for shipment of oil by tanker.

 

Thailand

 

ExxonMobil’s net acreage in the onshore Khorat concession totaled 15 thousand net acres at year-end 2002.

 

AFRICA

 

Angola

 

ExxonMobil’s year-end 2002 acreage holdings totaled 2.7 million net offshore acres and 3.9 net exploration and development wells were completed during the year. Construction is underway on ExxonMobil-operated Xikomba and Kizomba A, both on Block 15. These are the first of several projects planned on this block. In addition, engineering and design work is proceeding on Dalia, a non-operated Block 17 discovery.

 

Cameroon

 

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2002, with 0.9 net exploration and development wells completed during the year. The D1b project started production in January 2002.

 

Chad

 

ExxonMobil’s net year-end 2002 acreage holdings consisted of 4.1 million onshore acres, with 10.8 net exploration and development wells completed during the year. Construction is progressing on the Chad-Cameroon oil development and pipeline project, which will develop discovered oil fields in landlocked southern Chad and transport produced oil to the coast of Cameroon.

 

Equatorial Guinea

 

ExxonMobil’s acreage totaled 0.6 million net offshore acres at year-end 2002, with 7.3 net exploration and development wells completed during the year. Construction is progressing on the Southern Expansion Area of the Zafiro field.

 

Nigeria

 

ExxonMobil’s net acreage totaled 1.4 million offshore acres at year-end 2002, with 18.7 net exploration and development wells completed during the year. ExxonMobil-operated Yoho field (OML 104) commenced production during December 2002. Development is progressing on the Amenam-Kpono joint development project and at the Bonga field (OML 118). Development planning continues for the ExxonMobil-operated Erha (OPL 209) discovery.

 

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OTHER COUNTRIES

 

United Arab Emirates

 

ExxonMobil’s net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2002. During the year, 5.9 net development wells were completed.

 

Argentina

 

ExxonMobil’s net acreage totaled 0.3 million onshore acres at year-end 2002.

 

Azerbaijan

 

At year-end 2002, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 0.2 million acres. During the year, 0.7 net exploration and development wells were completed.

 

At the Azeri-Chirag-Gunashli (ACG) Early Oil project (the Megastructure), water injection to continue support of reservoir pressure is ongoing. Engineering and construction efforts are underway on the first phase of full field development at ACG. Phase two of the full field development was approved in 2002.

 

Kazakhstan

 

ExxonMobil’s net acreage totaled 0.3 million acres onshore and 0.2 million acres offshore at year-end 2002, with 3.2 net development wells completed during 2002.

 

At Tengiz, front-end engineering and design has been completed on the next phase of project expansion. Construction and commissioning of the Caspian Pipeline Consortium (CPC) pipeline was completed in 2002, with virtually all of Tengiz production now being exported through CPC to the port of Novorossiysk in the Black Sea.

 

Appraisal and initial development planning continue for the offshore Kashagan discovery.

 

Qatar

 

Production and development activities continued on two major Liquefied Natural Gas (LNG) projects in Qatar.

 

Production at the Qatargas project (Qatar Liquefied Gas Company Limited) is currently from three LNG trains. In June 2002, ExxonMobil signed a Heads of Agreements with Qatar Petroleum to construct two new LNG trains at Qatargas to produce additional gas reserves from Qatar’s North Field. The RasGas project (Ras Laffan Liquefied Natural Gas Company Limited, Ras Laffan Liquefied Natural Gas Company Limited (II), both operated by RasGas Company Limited) currently produces from two LNG trains, with a total combined production capacity of 6.6 million metric tons per year (MTA). Expansion projects are underway for two additional LNG trains, each with 4.7 MTA capacity.

 

Republic of Yemen

 

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 0.9 million acres onshore at year-end. During the year, 8.5 net development wells were drilled and completed.

 

Venezuela

 

ExxonMobil’s net acreage totaled 0.3 million onshore acres at year-end with 0.3 net development wells completed during the year.

 

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Table of Contents

 

WORLDWIDE EXPLORATION

 

At year-end 2002, exploration activities were underway in several areas in which ExxonMobil has no established production operations. A total of 21 million net acres were held at year-end 2002, and 4.2 net exploration wells were completed during the year.

 

Information with regard to mining activities follows:

 

Syncrude Operations

 

Syncrude is a joint-venture established to recover shallow deposits of tar sands using open-pit mining methods, to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, Canada, exploits a portion of the Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. Since start-up in 1978, Syncrude has produced about 1.4 billion barrels of synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint-venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited.

 

Operating License and Leases

 

Syncrude has an operating license issued by the Province of Alberta which is effective until 2035. This license permits Syncrude to mine tar sands and produce synthetic crude oil from approved development areas on tar sands leases. Syncrude holds eight tar sands leases covering approximately 252,000 acres in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta, the leases are automatically renewable as long as tar sands operations are ongoing or the leases are part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within a development plan approved by the Province of Alberta’s Department of Resource Development. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.

 

Operations, Plant and Equipment

 

Operations at Syncrude involve three main processes: open pit mining, extraction of crude bitumen and upgrading of crude bitumen into synthetic crude oil. In the Base mine (lease 17), the mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. In the North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. Production from the Aurora mine commenced in 2000. The extraction facilities, which separates crude bitumen from sand, are capable of processing approximately 545,000 tons of tar sands a day, producing 110 million barrels of crude bitumen a year. This represents recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands.

 

Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two large, high-temperature, fluid-coking vessels and by hydrogen addition in high-temperature, high-pressure, hydrocracking vessels. These processes remove carbon and sulfur and reformulate the crude into a low viscosity, low sulfur, high-quality synthetic crude oil product. In 2002, this upgrading process yielded 0.863 barrels of synthetic crude oil per barrel of crude bitumen. In 2002 about 60 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 40 percent was pipelined to refineries in eastern Canada and the mid-western United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and an 80 megawatt electricity generating plant, both located at Syncrude. The generating plants

 

15


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are owned by the Syncrude participants. Imperial Oil Limited’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities was about $1.0 billion at year end 2002.

 

Synthetic Crude Oil Reserves

 

The crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 50 to 150 feet of overburden, have bitumen grades ranging from 4 to 14 weight percent and ore thickness of 115 to 160 feet. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the approved mining plan, there are an estimated 3,295 million tons of extractable tar sands in the Base and North mines, with an average bitumen grade of 10.4 weight percent. In addition, at the Aurora mine, there are an estimated 4,050 million tons of extractable tar sands at an average bitumen grade of 11.3 weight percent. After deducting royalties payable to the Province of Alberta, Imperial Oil Limited estimates that its 25 percent net share of proven reserves at year end 2002 was equivalent to 800 million barrels of synthetic crude oil.

 

In 2001, the Syncrude owners endorsed a further development of the Syncrude resource in the area and expansion of the upgrading facilities. The Syncrude Aurora 2 and Upgrader Expansion 1 project adds a remote mining train and expands the central processing and upgrading plant. This expansion will lead to total production of about 370 thousand barrels of synthetic crude oil per day (gross) when completed.

 

ExxonMobil Share of Net Proven Syncrude Reserves(1)

 

      

Synthetic Crude Oil


 
      

Base Mine and
North Mine


      

Aurora Mine


    

Total


 
      

(millions of barrels)

 

January 1, 2002

    

358

 

    

463

 

  

821

 

Revision of previous estimate

    

 

    

 

  

 

Production

    

(14

)

    

(7

)

  

(21

)

      

    

  

December 31, 2002

    

344

 

    

456

 

  

800

 

      

    

  


(1)   Net reserves are the company’s share of reserves after deducting royalties payable to the Province of Alberta.

 

16


Table of Contents

 

Syncrude Operating Statistics (total operation)

 

    

2002


    

2001


    

2000


    

1999


    

1998


 

Operating Statistics

                                  

Total mined volume (millions of cubic yards)(1)

  

102.0

 

  

118.3

 

  

85.1

 

  

100.1

 

  

98.4

 

Mined volume to tar sands ratio(1)

  

1.05

 

  

1.15

 

  

0.96

 

  

0.99

 

  

1.05

 

Tar sands mined (million of tons)

  

172.1

 

  

181.2

 

  

156.4

 

  

178.7

 

  

165.9

 

Average bitumen grade (weight percent)

  

11.2

 

  

11.0

 

  

11.0

 

  

10.8

 

  

10.7

 

    

  

  

  

  

Crude bitumen in mined tar sands (millions of tons)

  

19.2

 

  

19.9

 

  

17.2

 

  

19.3

 

  

17.8

 

Average extraction recovery (percent)

  

89.9

 

  

87.0

 

  

89.7

 

  

91.4

 

  

91.6

 

    

  

  

  

  

Crude bitumen production (millions of barrels)(2)

  

97.8

 

  

97.6

 

  

86.8

 

  

99.6

 

  

92.1

 

Average upgrading yield (percent)

  

86.3

 

  

84.5

 

  

84.3

 

  

83.9

 

  

84.6

 

    

  

  

  

  

Gross synthetic crude oil produced (millions of barrels)

  

84.8

 

  

82.4

 

  

73.2

 

  

83.6

 

  

77.9

 

ExxonMobil net share (millions of barrels)(3)

  

21

 

  

19

 

  

15

 

  

20

 

  

19

 


(1)   Includes pre-stripping of mine areas and reclamation volumes.
(2)   Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.
(3)   Reflects ExxonMobil’s 25 percent interest in production less applicable royalties payable to the Province of Alberta.

 

Item 3.    Legal Proceedings.

 

ExxonMobil Oil Corporation (“EMOC”) has settled a previously-reported matter relating to claims arising from a 1991 oil spill from an EMOC pipeline into the Santa Clara River in California. The Consent Decree in this matter was approved by the U.S. District Court, Central District of California, on October 28, 2002, in the case captioned United States of America and People of the State of California v. ExxonMobil Oil Corporation (filed on September 20, 2002, along with the Consent Decree as signed by all the parties). On December 30, 2002, EMOC discharged all its obligations under the Consent Decree by paying a total of $4,721,831 to various federal and state agencies. Of this amount, $850,000 was payment of civil penalties to the U.S. Department of Justice and the California Department of Fish and Game, and the other amounts covered natural resource damage compensation, expense reimbursement and supplemental environmental projects.

 

In another previously-reported matter, EMOC prevailed in an arbitration proceeding relating to Notices of Violation (“NOVs”) issued by the Environmental Protection Agency regarding the former Mobil refinery in Paulsboro, New Jersey. In August 2002, the arbitrators held that the company that purchased the refinery from EMOC was contractually obligated under the purchase agreement to indemnify EMOC for any penalties arising out of the NOVs. While the NOVs remain pending, the purchaser will assume the defense of the matter and will be responsible for any resulting penalties. The NOVs allege that projects undertaken during 1998 and 1992 triggered New Source Review pre-construction permitting and pollution control requirements.

 

The Louisiana Department of Environmental Quality (LDEQ) issued an Air Compliance Order and Notice of Potential Penalty, received on December 5, 2002, with respect to the corporation’s Baton Rouge chemical plant. The LDEQ initiated this enforcement action in response to the finding that certain offsite piping components were not contained in the plant’s fugitive emissions monitoring program, as required under federal and state clean air laws. The corporation initially identified the issue, met with the LDEQ, and completed a mutually agreeable compliance plan prior to the initiation of this action. No specific demand for penalties has been made.

 

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Table of Contents

 

The New York State Department of Environmental Conservation (“NYSDEC”) issued 22 substantially similar Proposed Orders on Consent for 12 service stations in New York, with issue dates ranging from November 4, 2002 to November 13, 2002. The NYSDEC alleges that EMOC failed to conduct tank tightness tests in accordance with the applicable petroleum bulk storage law (under the Environmental Conservation Law of New York). The NYSDEC seeks penalties for all stations in an aggregate amount of $347,000, but settlement discussions are underway.

 

Refer to the relevant portions of Note 17 on page 56 of the Financial Section of this report for additional information on legal proceedings.

 

Item 4.    Submission of Matters to a Vote of Security Holders.

 

None.

 


 

18


Table of Contents

 

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].

 

Name


  

Age as of March 31, 2003


 

Title (Held Office Since)


L. R. Raymond

  

64

 

Chairman of the Board (1993)

H. J. Longwell

  

61

 

Executive Vice President (2001)

E. G. Galante

  

52

 

Senior Vice President (2001)

R. W. Tillerson

  

51

 

Senior Vice President (2001)

H. R. Cramer

  

52

 

Vice President (1999)

M. E. Foster

  

60

 

President, ExxonMobil Development Company (1999)            

D. D. Humphreys

  

55

 

Vice President and Controller (1997)

G. L. Kohlenberger

  

50

 

Vice President (2002)

K. T. Koonce

  

64

 

Vice President (1999)

C. W. Matthews

  

58

 

Vice President and General Counsel (1995)

S. R. McGill

  

60

 

Vice President (1998)

P. T. Mulva

  

51

 

Vice President — Investor Relations and Secretary (2002)

F. A. Risch

  

60

 

Vice President and Treasurer (1999)

D. S. Sanders

  

63

 

Vice President (1999)

J. S. Simon

  

59

 

Vice President (1999)

P. E. Sullivan

  

59

 

Vice President and General Tax Counsel (1995)

J. L. Thompson

  

63

 

Vice President (1991)

 

For at least the past five years, Messrs. Humphreys, Longwell, Matthews, Raymond, Risch, Sullivan and Thompson have been employed as executives of the registrant. Mr. Raymond also holds the title of President.

 

The following executive officers of the registrant have also served as executives of the subsidiaries, affiliates or divisions of the registrant shown opposite their names during the five years preceding December 31, 2002.

 

Esso (Thailand) Public Company Limited

  

Galante

Exxon Company, International

  

McGill and Simon

Exxon Company, U.S.A.

  

Foster

Exxon Upstream Development Company

  

Foster

Exxon Ventures (CIS) Inc. 

  

Koonce and Tillerson

ExxonMobil Chemical Company

  

Sanders and Galante

ExxonMobil Development Company

  

Tillerson

ExxonMobil Fuels Marketing Company

  

Cramer

ExxonMobil Gas & Power Marketing Company

  

McGill

ExxonMobil Global Services Company

  

Kohlenberger

ExxonMobil Lubricants & Petroleum Specialties Company

  

Kohlenberger

ExxonMobil Production Company

  

Koonce

ExxonMobil Refining & Supply Company

  

Simon

Imperial Oil Limited

  

Mulva

Mobil Business Resources Corporation

  

Kohlenberger

Mobil Corporation

  

Cramer

Mobil Europe and Central Asia Limited

  

Cramer

 

Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.

 

19


Table of Contents

PART II

 

Item 5.    Market for Registrant’s Common Stock and Related Shareholder Matters.

 

Reference is made to the quarterly information which appears on page 61 of the Financial Section of this report.

 

In accordance with the registrant’s 1997 Nonemployee Director Restricted Stock Plan, as amended, each incumbent nonemployee director (11 persons) was granted 2,400 shares of restricted stock on January 1, 2003. These grants are exempt from registration under bonus stock interpretations such as the “no-action” letter to Pacific Telesis Group (June 30, 1992).

 

Item 6.    Selected Financial Data.

 

   

Years Ended December 31,


 
   

  2002  


 

2001


 

2000


 

1999


 

1998


 
   

(millions of dollars, except per share amounts)

 

Sales and other operating revenue, including excise taxes

 

$

200,949

 

$

208,715

 

$

227,596

 

$

181,759

 

$

164,883

 

Net income

                               

Income from continuing operations

 

$

11,011

 

$

15,003

 

$

15,806

 

$

7,845

 

$

8,131

 

Discontinued operations, net of income tax

 

$

449

 

$

102

 

$

184

 

$

65

 

$

13

 

Extraordinary gain, net of income tax

 

$

 

$

215

 

$

1,730

 

$

 

$

 

Cumulative effect of accounting change

 

$

 

$

 

$

 

$

 

$

(70

)

   

 

 

 

 


Net income

 

$

11,460

 

$

15,320

 

$

17,720

 

$

7,910

 

$

8,074

 

Net income per common share

                               

Income from continuing operations

 

$

1.62

 

$

2.19

 

$

2.27

 

$

1.13

 

$

1.16

 

Discontinued operations, net of income tax

 

$

0.07

 

$

0.01

 

$

0.03

 

$

0.01

 

$

 

Extraordinary gain, net of income tax

 

$

 

$

0.03

 

$

0.25

 

$

 

$

 

Cumulative effect of accounting change

 

$

 

$

 

$

 

$

 

$

(0.01

)

   

 

 

 

 


Net income

 

$

1.69

 

$

2.23

 

$

2.55

 

$

1.14

 

$

1.15

 

Net income per common share - assuming dilution

                               

Income from continuing operations

 

$

1.61

 

$

2.17

 

$

2.24

 

$

1.11

 

$

1.15

 

Discontinued operations, net of income tax

 

$

0.07

 

$

0.01

 

$

0.03

 

$

0.01

 

$

 

Extraordinary gain, net of income tax

 

$

 

$

0.03

 

$

0.25

 

$

 

$

 

Cumulative effect of accounting change

 

$

 

$

 

$

 

$

 

$

(0.01

)

   

 

 

 

 


Net income

 

$

1.68

 

$

2.21

 

$

2.52

 

$

1.12

 

$

1.14

 

Cash dividends per common share

 

$

0.920

 

$

0.910

 

$

0.880

 

$

0.844

 

$

0.833

 

Total assets

 

$

152,644

 

$

143,174

 

$

149,000

 

$

144,521

 

$

139,335

 

Long-term debt

 

$

6,655

 

$

7,099

 

$

7,280

 

$

8,402

 

$

8,532

 

 

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 28 of the Financial Section of this report.

 

20


Table of Contents

 

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk.

 

Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties” beginning on page 33, excluding the part entitled “Inflation and Other Uncertainties,” of the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.

 

Item 8.    Financial Statements and Supplementary Data.

 

Reference is made to the consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 26, 2003, beginning on page 38 with the section entitled “Report of Independent Accountants” and continuing to page 60; the Quarterly Information appearing on page 61 and the Supplemental Information on Oil and Gas Exploration and Production Activities appearing on pages 62 to 66 of the Financial Section of this report. Consolidated Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

 

Item  9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.                      

 

None.

 

PART III

 

Item 10.    Directors and Executive Officers of the Registrant.

 

Incorporated by reference to the sections entitled “Election of Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” of the registrant’s definitive proxy statement for the 2003 annual meeting of shareholders (the “2003 Proxy Statement”).

 

Item 11.    Executive Compensation.

 

Incorporated by reference to the section entitled “Director Compensation” and the section entitled “Executive Compensation Tables” of the registrant’s 2003 Proxy Statement.

 

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

 

Incorporated by reference to the section entitled “Director and Executive Officer Stock Ownership” and the section entitled “Equity Compensation Plan Information” of the registrant’s 2003 Proxy Statement.

 

Item 13.    Certain Relationships and Related Transactions.

 

Incorporated by reference to the section entitled “Director Relationships” of the registrant’s 2003 Proxy Statement.

 

Item 14.    Controls and Procedures.

 

As indicated in the certifications on pages 70 through 72 of this report, the corporation’s principal executive officer, principal accounting officer and principal financial officer have evaluated the corporation’s disclosure controls and procedures as of December 31, 2002. Based on that evaluation, these officers have concluded that the corporation’s disclosure controls and procedures are effective for the purpose of ensuring that material information required to be in this annual report is made known to them by others on a timely basis. There have not been changes in the corporation’s internal controls or in other factors that could significantly affect these controls subsequent to the date of this evaluation.

 

21


Table of Contents

 

PART IV

 

Item 15.    Exhibits, Financial Statement Schedules and Reports on Form 8-K.

 

  (a) (1) and (2) Financial Statements:

See Table of Contents on page 23 of the Financial Section of this report.

 

  (a) (3) Exhibits:

See Index to Exhibits on page 73 of this report.

 

  (b) Reports on Form 8-K.

 

On November 12, 2002, the registrant filed a Current Report on Form 8-K furnishing information under Item 9 about the certifications filed with the Securities and Exchange Commission by the principal executive officer, principal financial officer and principal accounting officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

On November 13, 2002, the registrant filed a Current Report on Form 8-K about the completion of the sale of Compania Minera Disputada De Las Condes.

 

On December 10, 2002, the registrant filed a Current Report on Form 8-K about a court ruling related to the 1989 Exxon Valdez accident.

 

On December 20, 2002, the registrant filed a Current Report on Form 8-K furnishing information under Item 9 about a change in the presentation of certain segment information in future financial reports and furnishing resegmented historical functional earnings and capital and exploration expenditures.

 

Reports listed above as “furnished” under Item 9 are not deemed “filed” with the SEC and are not incorporated by reference herein or any other SEC filings.

 

22


Table of Contents

 

FINANCIAL SECTION

 

TABLE OF CONTENTS

 

Business Profile

  

24

Financial Summary

  

25

Frequently Used Terms

  

26-27

Management’s Discussion and Analysis of Financial Condition and Results of Operations

    

Functional Earnings

  

28

Overview

  

29

Review of 2002 and 2001 Results

  

29

Liquidity and Capital Resources

  

30

Capital and Exploration Expenditures

  

32

Merger of Exxon Corporation and Mobil Corporation

  

33

Merger Expenses and Reorganization Reserves

  

33

Site Restoration and Other Environmental Costs

  

33

Taxes

  

33

Market Risks, Inflation and Other Uncertainties

  

33

Recently Issued Financial Accounting Standards

  

34

Critical Accounting Policies

  

35

Forward-Looking Statements

  

37

Management’s Discussion of Internal Controls for Financial Reporting

  

38

Report of Independent Accountants

  

38

Consolidated Financial Statements

    

Statement of Income

  

39

Balance Sheet

  

40

Statement of Shareholders’ Equity

  

41

Statement of Cash Flows

  

42

Notes to Consolidated Financial Statements

    

  1. Summary of Accounting Policies

  

43

  2. Extraordinary Item

  

44

  3. Discontinued Operations

  

45

  4. Merger Expenses and Reorganization Reserves

  

45

  5. Miscellaneous Financial Information

  

45

  6. Cash Flow Information

  

45

  7. Additional Working Capital Data

  

45

  8. Equity Company Information

  

46

  9. Investments and Advances

  

47

10. Investment in Property, Plant and Equipment

  

47

11. Leased Facilities

  

47

12. Employee Stock Ownership Plans

  

47

13. Capital

  

48

14. Financial Instruments and Derivatives

  

49

15. Long-Term Debt

  

49

16. Incentive Program

  

55

17. Litigation and Other Contingencies

  

56

18. Annuity Benefits and Other Postretirement Benefits

  

57

19. Disclosures about Segments and Related Information

  

58

20. Income, Excise and Other Taxes

  

60

Quarterly Information

  

61

Supplemental Information on Oil and Gas Exploration and Production Activities

  

62-66

Operating Summary

  

67

 

23


Table of Contents

 

BUSINESS PROFILE

 

    

Earnings After

Income Taxes


   

Average Capital Employed


   

Return on Average Capital Employed


   

Capital and

Exploration Expenditures


 
    

2002


    

2001


   

2002


   

2001


   

2002


   

2001


   

2002


   

2001


 
    

(millions of dollars)

   

(percent)

   

(millions of dollars)

 

Financial

                                                             

Upstream

                                                             

United States

  

$

2,524

 

  

$

3,933

 

 

$

13,264

 

 

$

12,952

 

 

19.0

 

 

30.4

 

 

$

2,357

 

 

$

2,423

 

Non-U.S.

  

 

7,074

 

  

 

6,803

 

 

 

29,800

 

 

 

27,077

 

 

23.7

 

 

25.1

 

 

 

8,037

 

 

 

6,393

 

    


  


 


 


             


 


Total

  

$

9,598

 

  

$

10,736

 

 

$

43,064

 

 

$

40,029

 

 

22.3

 

 

26.8

 

 

$

10,394

 

 

$

8,816

 

    


  


 


 


             


 


Downstream

                                                             

United States

  

$

693

 

  

$

1,924

 

 

$

8,060

 

 

$

7,711

 

 

8.6

 

 

25.0

 

 

$

980

 

 

$

961

 

Non-U.S.

  

 

607

 

  

 

2,303

 

 

 

17,985

 

 

 

18,610

 

 

3.4

 

 

12.4

 

 

 

1,470

 

 

 

1,361

 

    


  


 


 


             


 


Total

  

$

1,300

 

  

$

4,227

 

 

$

26,045

 

 

$

26,321

 

 

5.0

 

 

16.1

 

 

$

2,450

 

 

$

2,322

 

    


  


 


 


             


 


Chemicals

                                                             

United States

  

$

384

 

  

$

398

 

 

$

5,235

 

 

$

5,506

 

 

7.3

 

 

7.2

 

 

$

575

 

 

$

432

 

Non-U.S.

  

 

446

 

  

 

484

 

 

 

8,410

 

 

 

8,333

 

 

5.3

 

 

5.8

 

 

 

379

 

 

 

440

 

    


  


 


 


             


 


Total

  

$

830

 

  

$

882

 

 

$

13,645

 

 

$

13,839

 

 

6.1

 

 

6.4

 

 

$

954

 

 

$

872

 

Corporate and financing

  

 

(442

)

  

 

(142

)

 

 

4,878

 

 

 

6,399

 

 

—  

 

 

—  

 

 

 

77

 

 

 

158

 

Merger expenses

  

 

(275

)

  

 

(525

)

 

 

—  

 

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

 

 

 

—  

 

Gain from required asset divestitures

  

 

—  

 

  

 

40

 

 

 

—  

 

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

 

 

 

—  

 

Discontinued operations

  

 

449

 

  

 

102

 

 

 

710

 

 

 

1,412

 

 

63.2

 

 

7.2

 

 

 

80

 

 

 

143

 

    


  


 


 


             


 


ExxonMobil Total

  

$

11,460

 

  

$

15,320

 

 

$

88,342

 

 

$

88,000

 

 

13.5

 

 

17.8

 

 

$

13,955

 

 

$

12,311

 

    


  


 


 


             


 


See Frequently Used Terms on page 27 for a definition and calculation of capital employed and return on average capital employed.

    

2002


    

2001


                                     
    

(thousands of barrels daily)

                                     

Operating

                                                             

Net liquids production

                                                             

United States

  

 

681

 

  

 

712

 

                                           

Non-U.S.

  

 

1,815

 

  

 

1,830

 

                                           
    


  


                                           

Total

  

 

2,496

 

  

 

2,542

 

                                           
    

(millions of cubic feet daily)

                                     

Natural gas production available for sale

                                                             

United States

  

 

2,375

 

  

 

2,598

 

                                           

Non-U.S.

  

 

8,077

 

  

 

7,681

 

                                           
    


  


                                           

Total

  

 

10,452

 

  

 

10,279

 

                                           
    

(thousands of oil-

equivalent barrels daily)

                                     

Oil-equivalent production*

  

 

4,238

 

  

 

4,255

 

                                           
    

(thousands of barrels daily)

                                     

Petroleum product sales

                                                             

United States

  

 

2,731

 

  

 

2,751

 

                                           

Non-U.S.

  

 

5,026

 

  

 

5,220

 

                                           
    


  


                                           

Total

  

 

7,757

 

  

 

7,971

 

                                           
    

(thousands of barrels daily)

                                     

Refinery throughput

                                                             

United States

  

 

1,871

 

  

 

1,840

 

                                           

Non-U.S.

  

 

3,610

 

  

 

3,731

 

                                           
    


  


                                           

Total

  

 

5,481

 

  

 

5,571

 

                                           
    

(thousands of metric tons)

                                     

Chemical prime product sales

  

 

26,925

 

  

 

25,780

 

                                           

 

* Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.

 

24


Table of Contents

 

FINANCIAL SUMMARY

 

    

2002


    

2001


    

2000


    

1999


    

1998


 
    

(millions of dollars, except per share amounts)

 

Sales and other operating revenue

                                            

Upstream

  

$

16,484

 

  

$

18,567

 

  

$

21,509

 

  

$

14,565

 

  

$

13,601

 

Downstream

  

 

168,032

 

  

 

174,185

 

  

 

188,563

 

  

 

153,345

 

  

 

137,599

 

Chemicals

  

 

16,408

 

  

 

15,943

 

  

 

17,501

 

  

 

13,777

 

  

 

13,589

 

Other

  

 

25

 

  

 

20

 

  

 

23

 

  

 

72

 

  

 

94

 

    


  


  


  


  


Sales and other operating revenue, including excise taxes

  

$

200,949

 

  

$

208,715

 

  

$

227,596

 

  

$

181,759

 

  

$

164,883

 

Earnings from equity interests and other revenue

  

 

3,557

 

  

 

4,070

 

  

 

4,250

 

  

 

2,994

 

  

 

4,013

 

    


  


  


  


  


Total revenue

  

$

204,506

 

  

$

212,785

 

  

$

231,846

 

  

$

184,753

 

  

$

168,896

 

    


  


  


  


  


Earnings

                                            

Upstream

  

$

9,598

 

  

$

10,736

 

  

$

12,685

 

  

$

6,244

 

  

$

3,706

 

Downstream

  

 

1,300

 

  

 

4,227

 

  

 

3,418

 

  

 

1,227

 

  

 

3,474

 

Chemicals

  

 

830

 

  

 

882

 

  

 

1,161

 

  

 

1,354

 

  

 

1,394

 

Corporate and financing

  

 

(442

)

  

 

(142

)

  

 

(538

)

  

 

(511

)

  

 

(443

)

Merger expenses

  

 

(275

)

  

 

(525

)

  

 

(920

)

  

 

(469

)

  

 

—  

 

Gain from required asset divestitures

  

 

—  

 

  

 

40

 

  

 

1,730

 

  

 

—  

 

  

 

—  

 

Discontinued operations

  

 

449

 

  

 

102

 

  

 

184

 

  

 

65

 

  

 

13

 

Accounting change

  

 

—  

 

  

 

—  

 

  

 

—  

 

  

 

—  

 

  

 

(70

)

    


  


  


  


  


Net income

  

$

11,460

 

  

$

15,320

 

  

$

17,720

 

  

$

7,910

 

  

$

8,074

 

    


  


  


  


  


Net income per common share

  

$

1.69

 

  

$

2.23

 

  

$

2.55

 

  

$

1.14

 

  

$

1.15

 

Net income per common share – assuming dilution

  

$

1.68

 

  

$

2.21

 

  

$

2.52

 

  

$

1.12

 

  

$

1.14

 

Cash dividends per common share

  

$

0.920

 

  

$

0.910

 

  

$

0.880

 

  

$

0.844

 

  

$

0.833

 

Net income to average shareholders’ equity (percent)

  

 

15.5

 

  

 

21.3

 

  

 

26.4

 

  

 

12.6

 

  

 

12.9

 

Net income to total revenue (percent)

  

 

5.6

 

  

 

7.2

 

  

 

7.6

 

  

 

4.3

 

  

 

4.8

 

Working capital

  

$

5,116

 

  

$

5,567

 

  

$

2,208

 

  

$

(7,592

)

  

$

(5,187

)

Ratio of current assets to current liabilities

  

 

1.15

 

  

 

1.18

 

  

 

1.06

 

  

 

0.80

 

  

 

0.85

 

Total additions to property, plant and equipment

  

$

11,437

 

  

$

9,989

 

  

$

8,446

 

  

$

10,849

 

  

$

12,730

 

Property, plant and equipment, less allowances

  

$

94,940

 

  

$

89,602

 

  

$

89,829

 

  

$

94,043

 

  

$

92,583

 

Total assets

  

$

152,644

 

  

$

143,174

 

  

$

149,000

 

  

$

144,521

 

  

$

139,335

 

Exploration expenses, including dry holes

  

$

920

 

  

$

1,175

 

  

$

936

 

  

$

1,246

 

  

$

1,506

 

Research and development costs

  

$

631

 

  

$

603

 

  

$

564

 

  

$

630

 

  

$

753

 

Long-term debt

  

$

6,655

 

  

$

7,099

 

  

$

7,280

 

  

$

8,402

 

  

$

8,532

 

Total debt

  

$

10,748

 

  

$

10,802

 

  

$

13,441

 

  

$

18,972

 

  

$

17,016

 

Fixed charge coverage ratio (times)

  

 

13.8

 

  

 

17.7

 

  

 

15.6

 

  

 

6.6

 

  

 

6.9

 

Debt to capital (percent)

  

 

12.2

 

  

 

12.4

 

  

 

15.4

 

  

 

22.0

 

  

 

20.6

 

Net debt to capital (percent)

  

 

4.4

 

  

 

5.3

 

  

 

7.9

 

  

 

20.4

 

  

 

18.2

 

Shareholders’ equity at year-end

  

$

74,597

 

  

$

73,161

 

  

$

70,757

 

  

$

63,466

 

  

$

62,120

 

Shareholders’ equity per common share

  

$

11.13

 

  

$

10.74

 

  

$

10.21

 

  

$

9.13

 

  

$

8.98

 

Average number of common shares outstanding (millions)

  

 

6,753

 

  

 

6,868

 

  

 

6,953

 

  

 

6,906

 

  

 

6,937

 

Number of regular employees at year-end (thousands)

  

 

92.5

 

  

 

97.9

 

  

 

99.6

 

  

 

106.9

 

  

 

111.6

 

 

25


Table of Contents

 

FREQUENTLY USED TERMS

 

Listed below are definitions of several of ExxonMobil’s frequently used financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation.

 

EARNINGS EXCLUDING MERGER EXPENSES, DISCONTINUED OPERATIONS AND OTHER SPECIAL ITEMS

 

In addition to reporting U.S. Generally Accepted Accounting Principles (GAAP) defined net income, ExxonMobil also presents a measure of earnings that excludes merger effects, earnings from discontinued operations and other quantified special items. Earnings excluding the aforementioned items is a non-GAAP financial measure and is included to facilitate comparisons of base business performance across periods. A reconciliation of net income versus earnings excluding merger effects, discontinued operations and other special items is provided in Management’s Discussion and Analysis of Financial Condition and Results of Operations on page 28.

 

Earnings per share amounts use the same average common shares outstanding as used for the calculation of net income per common share and net income per common share – assuming dilution.

 

OPERATING COSTS

 

Operating costs are the combined total of operating, selling, general, administrative, exploration, depreciation and depletion expenses from the consolidated statement of income and ExxonMobil’s share of similar costs for equity companies. Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing, maintenance, and other costs to explore for and produce oil and gas and operate refining and chemical plants. Distribution and marketing expenses are also included. Operating costs exclude the cost of raw materials and separately reported merger-related expenses. These expenses are on a before-tax basis. While ExxonMobil’s management is responsible for all revenue and expense elements of net income, particular focus is placed on managing the controllable aspects of this group of expenses.

 

Operating costs excluding merger expenses


  

2002


  

2001


  

2000


    

(millions of dollars)

From ExxonMobil’s Consolidated Statement of Income:

                    

Operating expenses

  

$

17,831

  

$

17,743

  

$

17,600

Selling, general and administrative expenses

  

 

12,356

  

 

12,898

  

 

12,044

Depreciation and depletion

  

 

8,310

  

 

7,848

  

 

8,001

Exploration expenses, including dry holes

  

 

920

  

 

1,175

  

 

936

    

  

  

Subtotal

  

 

39,417

  

 

39,664

  

 

38,581

ExxonMobil’s share of equity company expenses

  

 

3,800

  

 

3,832

  

 

4,355

    

  

  

Total operating costs

  

$

43,217

  

$

43,496

  

$

42,936

    

  

  

 

CASH FLOW FROM OPERATIONS AND ASSET SALES

 

Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from sales of subsidiaries, investments and property, plant and equipment from the Consolidated Statement of Cash Flows. This cash flow is the total sources of cash from both operating the company’s assets and the cash from divesting of assets. The corporation employs a long-standing disciplined regular review process to ensure that all assets are contributing to the company’s strategic and financial objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others.

 

Cash flow from operations and asset sales


  

2002


  

2001


  

2000


    

(millions of dollars)

Net cash provided by operating activities

  

$

21,268

  

$

22,889

  

$

22,937

Sales of subsidiaries, investments and property, plant and equipment

  

 

2,793

  

 

1,078

  

 

5,770

    

  

  

Cash flow from operations and asset sales

  

$

24,061

  

$

23,967

  

$

28,707

    

  

  

 

26


Table of Contents

 

CAPITAL EMPLOYED

 

Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed for the total corporation, it includes ExxonMobil’s share of total debt and shareholders’ equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which we believe should be included to provide a more comprehensive measure of capital employed.

 

Capital employed


  

2002


    

2001


    

2000


 
    

(millions of dollars)

 

Business uses: asset and liability perspective

                          

Total assets

  

$

152,644

 

  

$

143,174

 

  

$

149,000

 

Less liabilities and minority share of assets and liabilities

                          

Total current liabilities excluding notes and loans payable

  

 

(29,082

)

  

 

(26,411

)

  

 

(32,030

)

Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies

  

 

(35,449

)

  

 

(29,975

)

  

 

(29,542

)

Minority share of assets and liabilities

  

 

(4,210

)

  

 

(3,985

)

  

 

(4,601

)

Add ExxonMobil share of debt-financed equity company net assets

  

 

4,795

 

  

 

5,182

 

  

 

5,187

 

    


  


  


Total capital employed

  

$

88,698

 

  

$

87,985

 

  

$

88,014

 

    


  


  


Total corporate sources: debt and equity perspective

                          

Notes and loans payable

  

$

4,093

 

  

$

3,703

 

  

$

6,161

 

Long-term debt

  

 

6,655

 

  

 

7,099

 

  

 

7,280

 

Shareholders’ equity

  

 

74,597

 

  

 

73,161

 

  

 

70,757

 

Less minority share of total debt

  

 

(1,442

)

  

 

(1,160

)

  

 

(1,371

)

Add ExxonMobil share of equity company debt

  

 

4,795

 

  

 

5,182

 

  

 

5,187

 

    


  


  


Total capital employed

  

$

88,698

 

  

$

87,985

 

  

$

88,014

 

    


  


  


 

RETURN ON AVERAGE CAPITAL EMPLOYED

 

Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end of year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The corporation’s total ROCE is net income excluding the after-tax cost of financing, divided by total corporate average capital employed. The corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity to both evaluate management’s performance and to demonstrate to our shareholders that their capital has been used wisely over the long term. Additional measures, which tend to be more cash flow based, are used for future investment decisions.

 

Return on average capital employed


  

2002


    

2001


    

2000


 
    

(millions of dollars)

 

Net income

  

$

11,460

 

  

$

15,320

 

  

$

17,720

 

Financing costs (after tax)

                          

Third-party debt

  

 

(81

)

  

 

(96

)

  

 

(252

)

ExxonMobil share of equity companies

  

 

(227

)

  

 

(229

)

  

 

(298

)

All other financing costs – net

  

 

(127

)

  

 

(25

)

  

 

238

 

    


  


  


Total financing costs

  

 

(435

)

  

 

(350

)

  

 

(312

)

    


  


  


Earnings excluding financing costs

  

$

11,895

 

  

$

15,670

 

  

$

18,032

 

    


  


  


Average capital employed

  

$

88,342

 

  

$

88,000

 

  

$

87,463

 

Return on average capital employed – corporate total

  

 

13.5

%

  

 

17.8

%

  

 

20.6

%

 

27


Table of Contents

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

FUNCTIONAL EARNINGS


  

2002


    

2001


    

2000


 
    

(millions of dollars,

except per share amounts)

 

Net Income (U.S. GAAP)

                          

Upstream

                          

United States

  

$

2,524

 

  

$

3,933

 

  

$

4,542

 

Non-U.S.

  

 

7,074

 

  

 

6,803

 

  

 

8,143

 

Downstream

                          

United States

  

 

693

 

  

 

1,924

 

  

 

1,561

 

Non-U.S.

  

 

607

 

  

 

2,303

 

  

 

1,857

 

Chemicals

                          

United States

  

 

384

 

  

 

398

 

  

 

644

 

Non-U.S.

  

 

446

 

  

 

484

 

  

 

517

 

Corporate and financing

  

 

(442

)

  

 

(142

)

  

 

(538

)

Merger expenses

  

 

(275

)

  

 

(525

)

  

 

(920

)

Gain from required asset divestitures

  

 

 

  

 

40

 

  

 

1,730

 

Discontinued operations

  

 

449

 

  

 

102

 

  

 

184

 

    


  


  


Net income (U.S. GAAP)

  

$

11,460

 

  

$

15,320

 

  

$

17,720

 

    


  


  


Net income per common share (U.S. GAAP)

  

$

1.69

 

  

$

2.23

 

  

$

2.55

 

Net income per common share – assuming dilution (U.S. GAAP)

  

$

1.68

 

  

$

2.21

 

  

$

2.52

 

Merger Effects, Discontinued Operations and Other Special Items

                          

Upstream

                          

United States

  

$

—  

 

  

$

—  

 

  

$

—  

 

Non-U.S.

  

 

(215

)

  

 

—  

 

  

 

—  

 

Downstream

                          

United States

  

 

—  

 

  

 

—  

 

  

 

—  

 

Non-U.S.

  

 

—  

 

  

 

—  

 

  

 

—  

 

Chemicals

                          

United States (extraordinary item)

  

 

—  

 

  

 

100

 

  

 

—  

 

Non-U.S. (extraordinary item)

  

 

—  

 

  

 

75

 

  

 

—  

 

Merger expenses

  

 

(275

)

  

 

(525

)

  

 

(920

)

Gain from required asset divestitures (extraordinary item)

  

 

—  

 

  

 

40

 

  

 

1,730

 

Discontinued operations

  

 

449

 

  

 

102

 

  

 

184

 

    


  


  


Corporate total

  

$

(41

)

  

$

(208

)

  

$

994

 

    


  


  


Earnings Excluding Merger Effects, Discontinued Operations and Other Special Items

                          

Upstream

                          

United States

  

$

2,524

 

  

$

3,933

 

  

$

4,542

 

Non-U.S.

  

 

7,289

 

  

 

6,803

 

  

 

8,143

 

Downstream

                          

United States

  

 

693

 

  

 

1,924

 

  

 

1,561

 

Non-U.S.

  

 

607

 

  

 

2,303

 

  

 

1,857

 

Chemicals

                          

United States

  

 

384

 

  

 

298

 

  

 

644

 

Non-U.S.

  

 

446

 

  

 

409

 

  

 

517

 

Corporate and financing

  

 

(442

)

  

 

(142

)

  

 

(538

)

    


  


  


Corporate total

  

$

11,501

 

  

$

15,528

 

  

$

16,726

 

    


  


  


Earnings per common share

  

$

1.70

 

  

$

2.27

 

  

$

2.40

 

Earnings per common share – assuming dilution

  

$

1.69

 

  

$

2.25

 

  

$

2.37

 

 

Note: Prior periods amounts include reclassifications to reflect previously announced change in segment reporting. Earnings of divested coal and copper mining businesses are reported as discontinued operations.

 

28


Table of Contents

 

OVERVIEW

 

The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The corporation’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.

 

This straightforward approach extends to the financing of the business. In evaluating business or investment opportunities, the corporation views as economically equivalent any debt obligation, whether disclosed on the face of the consolidated balance sheet, or disclosed as other debt-like obligations in notes to the financial statements, such as those summarized in the table on page 31. This consistent, conservative approach to financing the capital-intensive needs of the corporation has helped ExxonMobil to sustain the “triple-A” status of its long-term debt securities for 84 years.

 

REVIEW OF 2002 RESULTS

 

Net income was $11,460 million, a decrease of $3,860 million from 2001. Earnings excluding merger effects, discontinued operations and other special items were $11,501 million, a decrease of $4,027 million from 2001. Upstream (Exploration, Production and Power) earnings in 2002 decreased primarily due to lower natural gas realizations. Upstream volumes in 2002, on an oil-equivalent basis, were up 1 percent excluding the impact of OPEC quota restrictions. Downstream (Refining and Marketing) earnings decreased substantially from 2001 reflecting significantly lower worldwide refining and marketing margins. Chemicals earnings, excluding the $175 million of extraordinary gains associated with asset management activities recorded in 2001, were $123 million higher reflecting increased prime product sales across all regions. Merger implementation activities in 2002 reduced earnings by $275 million. Earnings of $449 million associated with the Chilean copper business and the Colombian coal operations, which were sold in 2002, are reported as discontinued operations. These earnings include a gain on sale of $400 million. Revenue for 2002 totaled $205 billion, down 4 percent from 2001.

 

Excluding merger expenses and discontinued operations, the combined total of operating costs (including operating, selling, general, administrative, exploration, depreciation and depletion expenses from the consolidated statement of income and ExxonMobil’s share of similar costs for equity companies) in 2002 was $43.2 billion, down approximately $300 million from 2001. Cost increases associated with new operations and higher pension-related expenses were more than offset by lower energy prices and additional efficiency initiatives captured in all business lines. The impact of these initiatives, including the capture of merger efficiencies, reduced operating costs by $1.1 billion in 2002, and cumulatively by $5 billion since 1998. Interest expense in 2002 was $398 million compared to $293 million in 2001 primarily reflecting non-debt items.

 

Upstream

 

Upstream earnings totaled $9,598 million including a special charge of $215 million relating to the impact on deferred taxes from the United Kingdom supplementary tax enacted in 2002. Absent this, upstream earnings of $9,813 million decreased $923 million primarily due to lower natural gas realizations, particularly in North America, where prices reached historical highs at the beginning of 2001. Higher crude oil realizations partly offset declines in natural gas prices. Oil-equivalent production was up 1 percent versus 2001 excluding the impact of OPEC quota restrictions. Total actual oil-equivalent production was flat as the resumption of full production at Arun and contributions from new projects and work programs offset natural field declines and OPEC quota restrictions. Liquids production of 2,496 kbd (thousands of barrels daily) decreased 46 kbd from 2001. Production increases from new projects in Angola, Canada, Malaysia and Venezuela offset natural field declines in mature areas. OPEC quota restrictions increased in 2002. Excluding the effect of these restrictions, liquids production was flat with 2001. Worldwide natural gas production of 10,452 mcfd (millions of cubic feet daily) in 2002 compared with 10,279 mcfd in 2001. Improvements in Asia-Pacific volumes, mainly from the return to full production levels at the Arun field in Indonesia following last year’s curtailments due to security concerns, more than offset lower weather-related demand in Europe and natural field decline in the U.S. Weather-related demand in Europe reduced total gas volumes by about 1 percent. Earnings from U.S. upstream operations for 2002 were $2,524 million, a decrease of $1,409 million. Excluding the $215 million special charge relating to the U.K. tax rate change reported in 2002, earnings outside the U.S. were $7,289 million, $486 million higher than last year.

 

Downstream

 

Downstream earnings of $1,300 million decreased by $2,927 million from a record 2001, reflecting significantly lower refining margins in most geographical areas, and further weakness in marketing margins. Improved refining operations and lower operating expenses provided a partial offset to the margin decline. Earnings also benefited from a planned reduction in inventories as a result of optimizing operations around the world. Petroleum product sales of 7,757 kbd decreased 214 kbd from 2001, largely related to reduced refinery runs due to weak margins and lower demand for distillates and aviation fuels. Refinery throughput was 5,481 kbd compared with 5,571 kbd in 2001. U.S. downstream earnings were $693 million, down $1,231 million due to weaker refining margins. Earnings outside the U.S. of $607 million were $1,696 million lower than 2001 due to lower refining and marketing margins.

 

Chemicals

 

Excluding extraordinary gains of $175 million recorded in 2001, chemicals earnings of $830 million for 2002 were $123 million higher than 2001. Earnings benefited from record prime product sales volumes of 26,925 kt (thousands of metric tons) which were 4 percent above 2001 reflecting capacity additions in Singapore and Saudi Arabia. Worldwide chemicals margins remained weak during 2002.

 

Corporate and Financing

 

Corporate and financing expenses increased $300 million to $442 million, reflecting higher pension expense and lower interest income.

 

Discontinued Operations

 

Earnings from discontinued operations totaled $449 million, an increase of $347 million, primarily reflecting the gain on the sale of assets during the period.

 

29


Table of Contents

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

REVIEW OF 2001 RESULTS

 

Net income in 2001 was $15,320 million, including $215 million of extraordinary gains, $525 million of merger costs and $102 million of earnings from discontinued operations. Net income in 2001 decreased $2,400 million from 2000, which benefited from $810 million in net favorable merger effects including gains from divestments required as a condition of regulatory approval of the merger and $184 million from discontinued operations. Earnings excluding merger effects, discontinued operations and other special items were $15,528 million, a decrease of $1,198 million from 2000. Upstream (Exploration, Production and Power) earnings in 2001 declined, following lower crude oil realizations, which on average were down 18 percent versus 2000. Upstream volumes in 2001, on an oil-equivalent basis, were up 1 percent excluding the effect of reduced natural gas production operations in Indonesia due to security concerns. Downstream (Refining and Marketing) earnings improved from 2000, reflecting stronger U.S. refining margins and improved marketing results outside of the U.S. Chemicals earnings declined versus 2000, as lower product realizations and weakening demand conditions put significant pressure on commodity margins and more than offset the $175 million of extraordinary gains associated with asset management activities. Prime product sales volumes were 1 percent higher than 2000, reflecting capacity additions in Singapore and Saudi Arabia. Merger implementation activities in 2001 reduced earnings by a net $485 million. Gains from asset divestitures that were a condition of regulatory approval of the merger added $40 million to earnings, partly offsetting merger implementation expenses of $525 million. Revenue for 2001 totaled $213 billion, down 8 percent from 2000.

 

Excluding merger expenses and discontinued operations, the combined total of operating costs (including operating, selling, general, administrative, exploration, depreciation and depletion expenses from the consolidated statement of income and ExxonMobil’s share of similar costs for equity companies) in 2001 was $43.5 billion, up $600 million from 2000. Cost increases associated with new operations, higher energy costs and higher pension-related expenses were substantially offset by the favorable impact of continuing efficiency initiatives carried out in all business lines. The impact of these initiatives, including the capture of merger efficiencies, reduced operating costs by $1.2 billion in 2001, and cumulatively by $4 billion since 1998. Interest expense in 2001 was $293 million compared to $589 million in 2000 reflecting lower debt levels and interest rates.

 

Upstream

 

Upstream earnings of $10,736 million decreased $1,949 million, or 15 percent from 2000’s record level, primarily due to lower crude oil prices. The impacts of lower crude realizations and higher exploration expenses in future growth areas were partly offset by higher average natural gas realizations, principally in North America and Europe. U.S. and Canadian natural gas prices reached historical highs early in 2001 but dropped through the remainder of the year. Liquids production in 2001 of 2,542 kbd was down slightly from 2000, as natural field declines in mature areas were largely offset by new volumes from work programs and new developments in the North Sea, U.S., Equatorial Guinea and Kazakhstan, some of which have not yet reached full capacity. Absent the effect of reduced Arun operations in Indonesia due to security concerns, worldwide gas production was up about 2 percent, with increases in Europe, Australia, Canada and Qatar. Including the impact of lower Indonesia volumes, full-year 2001 worldwide natural gas production of 10,279 mcfd compared with 10,343 mcfd in 2000. Combined liquids and gas volumes, on an oil-equivalent basis, were up 1 percent excluding the effect of reduced natural gas production operations in Indonesia. Earnings from U.S. upstream operations were $3,933 million, a decrease of $609 million. Earnings outside the U.S. were $6,803 million, $1,340 million lower than 2000.

 

Downstream

 

Downstream earnings of $4,227 million were a record and improved 24 percent over 2000. Results benefited from higher refining margins early in the year, particularly in the U.S., improved worldwide refining operations and higher marketing margins outside the U.S. Refining margins in most areas peaked in the second quarter and declined during the second half of 2001. Earnings also benefited from a planned reduction in inventories as a result of optimizing operations around the world. Petroleum product sales of 7,971 kbd compared with 7,993 kbd in the prior year. Excluding the effect of the required merger-related divestments in 2000, volumes were up slightly. Refinery throughput was 5,571 kbd compared with 5,642 kbd in 2000. U.S. downstream earnings were $1,924 million, up $363 million, reflecting stronger refining margins and improved operations. Earnings outside the U.S. of $2,303 million were $446 million higher than 2000. The improvement was driven by stronger marketing margins, partly offset by weaker European refining margins.

 

Chemicals

 

Chemicals earnings totaled $882 million, including $175 million of net gains on asset management activities. Absent this special item, chemicals earnings were $707 million, a decrease of $454 million from 2000. Most of the reduction occurred in the U.S. as lower product realizations and weakening demand conditions put significant pressure on commodity margins. Prime product sales volumes of 25,780 kt were 1 percent above the prior year’s record level as higher sales outside the U.S., reflecting capacity additions in Singapore and Saudi Arabia, were partly offset by lower sales in the U.S. reflecting weaker industrial demand.

 

Corporate and Financing

 

Corporate and financing expenses decreased $396 million to $142 million, reflecting lower net interest costs due to lower debt levels and higher cash balances, along with favorable foreign exchange and tax effects.

 

Discontinued Operations

 

Earnings from discontinued operations totaled $102 million, a decrease of $82 million from 2000, reflecting lower copper prices.

 

LIQUIDITY AND CAPITAL RESOURCES

 

2002

 

Cash provided by operating activities totaled $21.3 billion, down $1.6 billion from 2001. Major sources of funds were net income of $11.5 billion and non-cash provisions of $8.3 billion for depreciation and depletion. The “All other items – net” line in cash flow from operations included $1.5 billion in funds received from BEB Erdgas und Erdoel GmbH (“BEB”), a German exploration and production company indirectly owned 50 percent and accounted for under the equity method of accounting. The funds were loaned in connection with a restructuring that will enable BEB to transfer its holdings in Ruhrgas

 

30


Table of Contents

 

AG, a German gas transmission company. It is anticipated that net income will be recognized in 2003 upon finalization of regulatory reviews and completion of the transfer of the Ruhrgas shares.

 

Cash used in investing activities totaled $9.8 billion, $1.6 billion higher than 2001 and included increased spending for property, plant and equipment and other investments and advances. Proceeds from the sales of subsidiaries, investments and property, plant and equipment were $2.8 billion, including the divestment of Colombian coal operations and the company’s copper business in Chile in 2002.

 

Cash used in financing activities was $11.4 billion, down $3.7 billion reflecting lower debt reductions. Dividend payments on common shares increased to $0.92 per share from $0.91 per share and totaled $6.2 billion, a payout of 54 percent. Total consolidated short-term and long-term debt was comparable at $10.7 billion. Shareholders’ equity increased by $1.4 billion to $74.6 billion.

 

During 2002, Exxon Mobil Corporation purchased 127 million shares of its common stock for the treasury at a gross cost of $4.8 billion. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,809 million at the end of 2001 to 6,700 million at the end of 2002. Purchases were made in both the open market and through negotiated transactions, and may be discontinued at any time.

 

Although the corporation issues long-term debt from time to time and maintains a revolving commercial paper program, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the corporation’s immediate needs is carefully controlled, both to optimize returns on cash balances, and to ensure its secure, ready availability to meet the corporation’s cash requirements as they arise.

 

2001

 

Cash provided by operating activities totaled $22.9 billion, the same level as 2000. Major sources of funds were net income of $15.3 billion and non-cash provisions of $7.8 billion for depreciation and depletion.

 

Cash used in investing activities totaled $8.2 billion, up $4.9 billion from 2000 due to lower proceeds from sales of subsidiaries, investments and property, plant and equipment resulting from the absence of the asset divestitures in 2000 that were required as a condition of the regulatory approval of the merger, and due to higher additions to property, plant and equipment.

 

Cash used in financing activities was $15.0 billion, up $0.9 billion, driven by higher purchases of common shares, offset by lower debt reductions. Dividend payments on common shares increased from $0.88 per share to $0.91 per share and totaled $6.3 billion, a payout of 41 percent. Total consolidated short-term and long-term debt declined by $2.6 billion to $10.8 billion. Shareholders’ equity increased by $2.4 billion to $73.2 billion.

 

During 2001, Exxon Mobil Corporation purchased 139 million shares of its common stock for the treasury at a gross cost of $5.7 billion. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,930 million at the end of 2000 to 6,809 million at the end of 2001. Purchases were made in both the open market and through negotiated transactions, and may be discontinued at any time.

 

Long-Term Contractual Obligations and Other Commercial Commitments

 

Set forth below is information about the corporation’s long-term contractual obligations and other commercial commitments outstanding at December 31, 2002. It brings together data for easy reference from the consolidated balance sheet and from individual notes to consolidated financial statements. This information is important in understanding the financial position of the corporation. In considering the economic viability of investment opportunities, the corporation views any source of financing, whether it be operating leases, third-party guarantees or equity company debt, as being economically equivalent to consolidated debt of the corporation.

 

           

Payments Due by Period


             

Long-Term Contractual Obligations


    

Note Reference Number


  

2003


  

2004 - 2007


    

2008 and Beyond


    

2002 Total Amount


    

2001 Total Amount


      

(millions of dollars)

Long-term debt (1)

    

15

  

$

—  

  

$

3,065

    

$

3,590

    

$

6,655

    

$

7,099

—  Due in one year (2)

         

 

884

  

 

—  

    

 

—  

    

 

884

    

 

339

ExxonMobil share of equity company long-term debt (3)

    

 8

  

 

—  

  

 

1,973

    

 

1,379

    

 

3,352

    

 

3,950

—  Due in one year (2)

         

 

707

  

 

—  

    

 

—  

    

 

707

    

 

590

Operating leases (4)

    

11

  

 

1,352

  

 

3,160

    

 

2,433

    

 

6,945

    

 

6,924

Unconditional purchase obligations (5)

    

17

  

 

337

  

 

1,140

    

 

2,172

    

 

3,649

    

 

2,029

Firm capital commitments (6)

         

 

4,350

  

 

2,986

    

 

1,113

    

 

8,449

    

 

3,885

           

  

    

    

    

Total

         

$

7,630

  

$

12,324

    

$

10,687

    

$

30,641

    

$

24,816

           

  

    

    

    

 

Notes:

(1) Includes capitalized lease obligations of $294 million.

(2) The amounts due in one year are included in notes and loans payable of $4,093 million (note 7 on page 45) for consolidated companies and in short-term debt of $1,443 million (note 8 on page 46) for equity companies.

(3) The corporation includes its share of equity company debt in its calculation of return on average capital employed.

(4) Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties.

(5) Unconditional purchase obligations, shown on an undiscounted basis, mainly pertain to pipeline throughput agreements. The present value of these commitments, excluding imputed interest of $1,186 million, totaled $2,463 million.

(6) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $8.4 billion at the end of 2002, compared with $3.9 billion at year-end 2001. These commitments were predominantly associated with upstream projects outside the U.S., of which the largest single commitment outstanding at year-end 2002 was $1.8 billion associated with the development of crude oil and natural gas resources in Malaysia. The corporation expects to fund the majority of these commitments through internal cash flow.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Other Commercial Commitments

 

The corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2002, for $3,038 million, primarily relating to guarantees for notes, loans and performance under contracts (note 17). This included $986 million representing guarantees of non-U.S. excise taxes and customs duties of other companies, entered into as a normal business practice, under reciprocal arrangements. Also included in this amount were guarantees by consolidated affiliates of $1,621 million, representing ExxonMobil’s share of obligations of certain equity companies. The above-mentioned guarantees are not reasonably likely to have a material current or future effect on the corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

 

On December 31, 2002, unused credit lines for short-term financing totaled approximately $4.2 billion (note 7).

 

The table below shows the corporation’s fixed charge coverage and consolidated debt to capital ratios. The data demonstrate the corporation’s creditworthiness. Throughout this period, the corporation’s long-term debt securities maintained the top credit rating from both Standard and Poor’s (AAA) and Moody’s (Aaa), a rating it has sustained for 84 years.

 

    

2002


  

2001


  

2000


Fixed charge coverage ratio (times)

  

13.8

  

17.7

  

15.6

Debt to capital (percent)

  

12.2

  

12.4

  

15.4

Net debt to capital (percent) (1)

  

  4.4

  

  5.3

  

  7.9

Credit rating

  

AAA/Aaa

  

AAA/Aaa

  

AAA/Aaa

 

(1) Debt net of all cash

 

Management views the corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The corporation’s sound financial position gives it the opportunity to access the world’s capital markets in the full range of market conditions, and enables the corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

 

In addition to the above commitments, the corporation makes limited use of derivative instruments, which are discussed in Risk Management on page 34 and note 14 on page 49.

 

Litigation and Other Contingencies

 

As discussed in note 17 to the consolidated financial statements, a number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. The vast majority of the claims have been resolved leaving a few compensatory damages cases to be resolved. All of the punitive damage claims were consolidated in the civil trial that began in May 1994.

 

In that trial, on September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5 billion in punitive damages to a class composed of all persons and entities who asserted claims for punitive damages from the corporation as a result of the Exxon Valdez grounding. ExxonMobil appealed the judgment. On November 7, 2001, the United States Court of Appeals for the Ninth Circuit vacated the punitive damage award as being excessive under the Constitution and remanded the case to the District Court for it to determine the amount of the punitive damage award consistent with the Ninth Circuit’s holding. On December 6, 2002, the District Court reduced the punitive damages award from $5 billion to $4 billion. This case will return to the Ninth Circuit for its determination. The corporation has posted a $4.8 billion letter of credit. The ultimate cost to the corporation from the lawsuits arising from the Exxon Valdez grounding is not possible to predict and may not be resolved for a number of years.

 

On December 19, 2000, a jury in Montgomery County, Alabama, returned a verdict against the corporation in a contract dispute over royalties in the amount of $87.69 million in compensatory damages and $3.42 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court on May 4, 2001. On December 20, 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The decision sends the case back to a lower court for a new trial. The ultimate outcome is not expected to have a materially adverse effect upon the corporation’s operations or financial condition.

 

On May 22, 2001, a state court jury in New Orleans, Louisiana, returned a verdict against the corporation and three other entities in a case brought by a landowner claiming damage to his property. The property had been leased by the landowner to a company that performed pipe cleaning and storage services for customers, including the corporation. The jury awarded the plaintiff $56 million in compensatory damages (90 percent to be paid by the corporation) and $1 billion in punitive damages (all to be paid by the corporation). The damage related to the presence of naturally occurring radioactive material (NORM) on the site resulting from pipe cleaning operations. The award has been upheld at the trial court. ExxonMobil has appealed the judgment to the Louisiana Fourth Circuit Court of Appeals and believes that the judgment should be set aside or substantially reduced on factual and constitutional grounds. The ultimate outcome is not expected to have a materially adverse effect upon the corporation’s operations or financial condition.

 

The U.S. Tax Court has decided the issue with respect to the pricing of crude oil purchased from Saudi Arabia for the years 1979-1981 in favor of the corporation. This decision is subject to appeal. Certain other issues for the years 1979-1993 remain pending before the Tax Court. The ultimate resolution of these issues and several other tax and legal issues, including resolution of tax issues related to the gas lifting imbalance along the German/Dutch border, is not expected to have a materially adverse effect upon the corporation’s operations or financial condition.

 

There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

 

CAPITAL AND EXPLORATION EXPENDITURES

 

Capital and exploration expenditures in 2002 were $14.0 billion, up from $12.3 billion in 2001, reflecting the corporation’s active investment program.

 

Upstream spending was up 18 percent to $10.4 billion in 2002, from $8.8 billion in 2001, as a result of higher spending on major projects in Africa, Canada and Azerbaijan, and increased drilling activity. Capital investments in the downstream totaled $2.4 billion in 2002, up $0.1 billion from 2001, primarily reflecting increased investments required for

 

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low-sulfur motor fuels partially offset by lower spending on base activities. Chemicals capital expenditures were $1.0 billion in 2002, up from $0.9 billion in 2001, due to the acquisition of our joint venture partner’s interest in Advanced Elastomers Systems.

 

Capital and exploration expenditures in the U.S. totaled $4.0 billion in 2002, an increase of $0.1 billion from 2001, reflecting higher spending in chemicals, partly offset by lower spending in the upstream. Spending outside the U.S. of $10.0 billion in 2002 was up $1.6 billion from 2001, reflecting higher expenditures in the upstream and downstream, partly offset by lower expenditures in chemicals.

 

MERGER OF EXXON CORPORATION AND MOBIL CORPORATION

 

On November 30, 1999, a wholly-owned subsidiary of Exxon Corporation (Exxon) merged with Mobil Corporation (Mobil) so that Mobil became a wholly-owned subsidiary of Exxon (the “Merger”). At the same time, Exxon changed its name to Exxon Mobil Corporation (ExxonMobil).

 

As a condition of the approval of the Merger, the U.S. Federal Trade Commission and the European Commission required that certain property — primarily downstream, pipeline and natural gas distribution assets — be divested. The carrying value of these assets was approximately $3 billion and before-tax proceeds were approximately $5 billion. Net after-tax gains of $40 million and $1,730 million were reported in 2001 and 2000, respectively, as extraordinary items consistent with pooling of interests accounting requirements. The divested properties historically earned approximately $200 million per year. The Merger was accounted for as a pooling of interests.

 

MERGER EXPENSES AND REORGANIZATION RESERVES

 

In association with the Merger between Exxon and Mobil, $410 million pre-tax ($275 million after-tax), $748 million pre-tax ($525 million after-tax) and $1,406 million pre-tax ($920 million after-tax) of costs were recorded as merger-related expenses in 2002, 2001 and 2000, respectively. Charges included separation expenses related to workforce reductions (approximately 8,200 employees at year-end 2002), plus implementation and merger closing costs. The separation reserve balance at year-end 2002 of approximately $101 million is expected to be expended in 2003. Merger-related expenses for the period 1999 to 2002 cumulatively total approximately $3.2 billion pre-tax. Pre-tax operating synergies associated with the Merger, including cost savings, efficiency gains, and revenue enhancements, have cumulatively reached over $7 billion by 2002. Reflecting the completion of merger-related activities, merger expenses will not be reported in 2003.

 

The following table summarizes the activity in the reorganization reserves. The 2000 opening balance represents accruals for provisions taken in prior years.

 

    

Opening

Balance


  

Additions


    

Deductions


  

Balance at

Year End


    

(millions of dollars)

2000

  

$381

  

$738

    

$780

  

$339

2001

  

339

  

187

    

329

  

197

2002

  

197

  

93

    

189

  

101

 

SITE RESTORATION AND OTHER ENVIRONMENTAL COSTS

 

Over the years the corporation has accrued provisions for estimated site restoration costs to be incurred at the end of the operating life of certain of its facilities and properties. In addition, the corporation accrues provisions for environmental liabilities in the many countries in which it does business when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed.

 

The corporation has accrued provisions for probable environmental remediation obligations at various sites, including multi-party sites where ExxonMobil has been identified as one of the potentially responsible parties by the U.S. Environmental Protection Agency. The involvement of other financially responsible companies at these multi-party sites mitigates ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations, financial condition or liquidity.

 

Charges made against income for site restoration and environmental liabilities were $400 million in 2002, $371 million in 2001 and $311 million in 2000. At the end of 2002, accumulated site restoration and environmental provisions, after reduction for amounts paid, amounted to $3.9 billion. ExxonMobil believes that any cost in excess of the amounts already provided for in the financial statements would not have a materially adverse effect upon the corporation’s operations, financial condition or liquidity. The methodology for accounting for site restoration reserves will be modified as of January 1, 2003 (see pages 34-35).

 

ExxonMobil’s worldwide environmental costs in 2002 totaled $2,343 million of which $1,054 million were capital expenditures and $1,289 million were operating costs (including the $400 million of site restoration and environmental provisions noted above). These costs were mostly associated with air and water conservation. Total costs for such activities are expected to increase to about $2.5 billion in both 2003 and 2004 (with capital expenditures representing about 50 percent of the total). The projected increase is primarily for capital projects to implement refining technology to manufacture low-sulfur motor fuels in many parts of the world.

 

TAXES

 

2002

 

Income, excise and all other taxes and duties totaled $64.3 billion in 2002, a decrease of $2.2 billion or 3 percent from 2001. Income tax expense, both current and deferred, was $6.5 billion compared to $9.0 billion in 2001, reflecting lower pre-tax income in 2002. The effective tax rate of 39.8 percent in 2002 compared to 39.3 percent in 2001. During 2002, the company continued to benefit from favorable resolution of tax-related issues. Excise and all other taxes and duties were $57.8 billion.

 

2001

 

Income, excise and all other taxes and duties totaled $66.5 billion in 2001, a decrease of $1.9 billion or 3 percent from 2000. Income tax expense, both current and deferred, was $9.0 billion compared to $11.1 billion in 2000, reflecting lower pre-tax income in 2001. The effective tax rate of 39.3 percent in 2001 compared to 42.6 percent in 2000, benefiting from a higher level of favorably resolved tax-related issues. Excise and all other taxes and duties were $57.6 billion.

 

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

In the past, crude, natural gas, petroleum product and chemical prices have fluctuated widely in response to changing market forces. The impacts of these price fluctuations on earnings from upstream operations, downstream operations and chemicals operations have been var-

 

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ied, tending at times to be offsetting. Nonetheless, the global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the corporation’s financial strength, including the AAA and Aaa ratings of its long-term debt securities by Standard and Poor’s and Moody’s, as a competitive advantage.

 

Although price levels of crude oil and natural gas may rise or fall significantly over the short- to medium term due to political events, OPEC actions and other factors, industry prices over the long term will continue to be driven by market supply and demand fundamentals. Accordingly, the corporation tests the viability of all of its assets based on long-term price projections. The corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs. Investment opportunities are tested against a variety of market conditions, including low price scenarios. As a result, investments that would succeed only in highly favorable price environments are screened out of the investment plan.

 

The corporation has had an active asset management program in which under-performing assets are either improved to acceptable levels or considered for divestment. The asset management program involves a disciplined, regular review to ensure that all assets are contributing to the corporation’s strategic and financial objectives. The result has been the creation of a very efficient capital base and has meant that the corporation has seldom been required to write-down the carrying value of assets, even during periods of low commodity prices.

 

Risk Management

 

The corporation’s size, geographic diversity and the complementary nature of the upstream, downstream and chemicals businesses mitigate the corporation’s risk from changes in interest rates, currency rates and commodity prices. The corporation relies on these operating attributes and strengths to reduce enterprise-wide risk. As a result, the corporation makes limited use of derivatives to offset exposures arising from existing transactions.

 

The corporation does not trade in derivatives nor does it use derivatives with leverage features. The corporation maintains a system of controls that includes a policy covering the authorization, reporting, and monitoring of derivative activity. The corporation’s derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. Interest rate, foreign exchange rate and commodity price exposures arising from derivative contracts undertaken in accordance with the corporation’s policies have not been significant.

 

The fair value of derivatives outstanding and recorded on the balance sheet was a net receivable of $20 million before-tax and a net payable of $50 million before-tax at year-end 2002 and 2001, respectively. This is the amount that the corporation would have received or paid to third parties if these derivatives had been settled. These derivative fair values were substantially offset by the fair values of the underlying exposures being hedged. The corporation recognized a before-tax loss of $35 million and a before-tax gain of $23 million related to derivative activity during 2002 and 2001, respectively. The losses/gains included the offsetting amounts from the changes in fair value of the items being hedged by the derivatives. The fair value of derivatives outstanding at year-end 2002 and losses recognized during the year are immaterial in relation to the corporation’s year-end cash balance of $7.2 billion, total assets of $152.6 billion, or net income for the year of $11.5 billion.

 

Debt-Related Instruments

 

The corporation is exposed to changes in interest rates, primarily as a result of its short-term debt and long-term debt carrying floating interest rates. The corporation makes limited use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio. The impact of a 100 basis point change in interest rates affecting the corporation’s debt would not be material to earnings, cash flow or fair value.

 

Foreign Currency Exchange Rate Instruments

 

The corporation conducts business in many foreign currencies and is subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in foreign currency exchange rates on ExxonMobil’s geographically diverse operations are varied and often offsetting in amount. The corporation makes limited use of currency exchange contracts to reduce the risk of adverse foreign currency movements related to certain foreign currency debt obligations. Exposure from market rate fluctuations related to these contracts is not material. Aggregate foreign exchange transaction gains and losses included in net income are discussed in note 5 on page 45.

 

Commodity Instruments

 

The corporation makes limited use of commodity forwards, swaps and futures contracts of short duration to mitigate the risk of unfavorable price movements on certain crude, natural gas and petroleum product purchases and sales. Commodity price exposure related to these contracts is not material.

 

Inflation and Other Uncertainties

 

The general rate of inflation in most major countries of operation has been relatively low in recent years, and the associated impact on operating costs has been countered by cost reductions from efficiency and productivity improvements.

 

The operations and earnings of the corporation and its affiliates throughout the world have been, and may in the future be, affected from time to time in varying degree by political developments and laws and regulations, such as forced divestiture of assets; restrictions on production, imports and exports; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of contract rights and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the corporation vary greatly from country to country and are not predictable.

 

RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

 

In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143 (FAS 143), “Accounting for Asset Retirement Obligations.” FAS 143 is required to be adopted by the corporation no later than January 1, 2003, and its primary impact will be to change the method of accruing for upstream site restoration costs. These costs are currently accrued ratably over the productive lives of the assets in accordance with Statement of Financial Accounting Standards No. 19 (FAS 19), “Financial Accounting and Reporting by Oil and Gas Producing Companies.” At the end of 2002, the cumulative amount accrued under this policy was approximately

 

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Table of Contents

 

$3.5 billion. Under FAS 143, the fair value of asset retirement obligations will be recorded as liabilities on a discounted basis when they are incurred, which are typically at the time the assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations. Over time the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets.

 

The cumulative adjustment for the change in accounting principle will result in after-tax income of approximately $600 million as of January 1, 2003. This adjustment is due to the difference in the method of accruing site restoration costs under FAS 143 compared with the method required by FAS 19, the accounting standard that the corporation has been required to follow since 1978. Under FAS 19, site restoration costs are accrued on a unit-of-production basis of accounting as the oil and gas is produced. The FAS 19 method matches the accruals with the revenues generated from production and results in most of the costs being accrued early in field life, when production is at the highest level. Because FAS 143 requires accretion of the liability as a result of the passage of time using an interest method of allocation, the majority of the costs will be accrued towards the end of field life, when production is at the lowest level. The cumulative income adjustment described above results from reversing the higher liability accumulated under FAS 19 in order to adjust it to the lower present value amount resulting from transition to FAS 143. This amount being reversed in transition, which was previously charged to operating earnings under FAS 19, will again be charged to those earnings under FAS 143 in future years. Because of the long periods over which these costs will be charged, the impact on future annual net income of these increased charges will be immaterial.

 

In November 2002, the Financial Accounting Standards Board issued FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” This interpretation is effective for guarantees issued or modified after December 31, 2002 and requires that a liability be recognized at fair value upon issuance of the guarantees. The impact of FIN 45 on the corporation’s financial statements will not be material.

 

In January 2003, the Financial Accounting Standards Board issued FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.” A discussion of FIN 46 and related financial statement implications for the corporation is included in note 8 on page 46.

 

CRITICAL ACCOUNTING POLICIES

 

The corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The following summary provides further information about the critical accounting policies and the judgments that are made by the corporation in the application of those policies.

 

Oil and Gas Reserves

 

Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed or enhanced recovery methods should be undertaken. Oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation and evaluating for impairment. Oil and gas reserves are divided between proved and unproved reserves. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Unproved reserves are those with less than reasonable certainty of recoverability and are classified as either probable or possible. Probable reserves are reserves that are more likely to be recovered than not and possible reserves are less likely to be recovered than not.

 

The estimation of proved reserves is an ongoing process based on rigorous technical evaluations and extrapolations of well information such as flow rates and reservoir pressure declines. In certain deepwater fields, proved reserves are occasionally recorded before flow tests are conducted because of the safety and cost implications of conducting the tests. In those situations, other industry accepted analyses are used such as information from well logs, a thorough pressure and fluid sampling program, conventional core data obtained across the entire reservoir interval and nearby analog data. Historically, proved reserves recorded using these methods have been immaterial when compared to the corporation’s total proved reserves and have also been validated by subsequent flow tests or actual production levels. In addition, the corporation records proved reserves in conjunction with significant funding commitments made towards the development of the reserves.

 

At year-end 2002, proved oil and gas reserves were 21.1 billion oil-equivalent barrels. The corporation added 1.9 billion oil-equivalent barrels to proved reserves in 2002, while producing 1.6 billion oil-equivalent barrels, replacing 120 percent of reserves produced, excluding sales. With sales included, the corporation replaced 119 percent of reserves produced. Both reserve replacement percentages exclude tar sands. This is the ninth consecutive year that the corporation’s reserves replacement has exceeded 100 percent.

 

The corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to ensure that commercial quantities of reserves have been found or that additional exploration work is under way or planned. Exploratory well costs not meeting either of these tests are charged to expense. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The corporation uses this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of the corporation’s exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.

 

Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those

 

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proved reserves recoverable through existing wells with existing equipment and operating methods) applied to the (3) asset cost. The volumes produced and asset cost are known and while proved developed reserves have a high probability of recoverability they are based on estimates that are subject to some variability. This variability has generally resulted in net upward revisions of proved reserves in existing fields, as more information becomes available through research and production. Revisions have averaged 670 million oil-equivalent barrels per year over the last five years, and have resulted from effective reservoir management and the application of new technology. While the upward revisions the corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.

 

Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Oil and gas producing properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves, except in circumstances where it is probable that additional non-proved reserves will be developed and contribute to cash flows in the future.

 

The corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the corporation in reviewing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices.

 

In general, the corporation does not view temporarily low oil prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, industry prices over the long term will continue to be driven by market supply and demand fundamentals. Accordingly, any impairment tests that the corporation performs make use of the corporation’s long-term price assumptions for the crude oil and natural gas markets. These are the same price assumptions that are used in the corporation’s planning and budgeting processes and its capital investment decisions. Supplemental information regarding oil and gas results of operations, capitalized costs and reserves can be found on pages 62 to 66.

 

Consolidations

 

The consolidated financial statements include the accounts of those significant subsidiaries that the corporation controls. They also include the corporation’s undivided interests in upstream assets and liabilities. Amounts representing the corporation’s percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in “Investments and advances”; the corporation’s share of the net income of these companies is included in the consolidated statement of income caption “Earnings from equity interests and other revenue.” The accounting for these non-consolidated companies is referred to as the equity method of accounting.

 

Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 8 on page 46. The corporation believes this to be important information necessary to a full understanding of the corporation’s financial statements.

 

Investments in companies that are partially owned by the corporation are integral to the corporation’s operations. In some cases they serve to balance worldwide risks and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their percentage ownership. The corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its percentage share of all assets and liabilities in these partially owned companies rather than only the percentage in the net equity. This method of accounting for investments in partially owned companies is not permitted by GAAP except where the investments are in the direct ownership of a share in the upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by GAAP standards, the corporation includes its share of debt of these partially owned companies in the determination of average capital employed.

 

Annuity Plans

 

The corporation and its affiliates sponsor over 100 defined benefit (pension) plans in more than 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the company operates. Note 18, pages 57-58, provides details on pension obligations, fund assets and pension expense.

 

Some of these plans (primarily non-U.S.) provide pension benefits which are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans, because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets. The corporation uses the fair value of plan assets at year-end to determine its annual pension expense and does not use a moving average value allowed by GAAP to reduce the volatility of pension expense.

 

For funded plans, including many in the U.S., pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities, and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions which differ from those used for accounting purposes. Contributions to funded plans totaled $969 million in 2002 (U.S. $460 million, non-U.S. $509 million).

 

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The corporation will continue to make contributions to these funded plans as necessary. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the corporation or the respective sponsoring affiliate.

 

Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations, and the long-term rate for future salary increases. All the pension assumptions are reviewed annually by outside actuaries and senior financial management. These assumptions are adjusted only as appropriate to reflect changes in market rates and outlook. For example, the long-term expected earnings rate on U.S. pension plan assets has been evaluated annually, but was changed only twice in the past 15 years, in both cases downward. The expected earnings rate of 9.5 percent used in 2002 compares to actual returns of 10 percent and 11 percent actually achieved over the last 10- and 20-year periods ending December 31, 2002. Based on the most recent forward-looking analysis, an expected earnings rate of 9.0 percent will be used for the U.S. plans in 2003. A worldwide reduction of 0.5 percent in the pension fund earnings rate would increase pension expense by approximately $60 million before-tax.

 

Due to the general decline in the market value of pension assets and in interest rates, pension expense grew from $451 million in 2001 (U.S. $145 million, non-U.S. $306 million) to $995 million in 2002 (U.S. $470 million, non-U.S. $525 million), and is expected to further increase in 2003. Under U.S. GAAP, differences between actual returns on fund assets versus the long-term expected return are amortized in pension expense, along with other actuarial gains and losses, over the expected remaining service life of employees.

 

Litigation and Other Contingencies

 

Claims for substantial amounts have been made against ExxonMobil and certain of its consolidated subsidiaries in pending lawsuits and tax disputes. These are summarized on page 32, with a more extensive discussion included in note 17 on page 56.

 

The general guidance provided by GAAP requires that liabilities for contingencies should be recorded when it is probable that a liability has been incurred before the date of the balance sheet and that the amount can be reasonably estimated. Significant management judgment is required to comply with this guidance, and it includes management reviews with the corporation’s attorneys, taking into consideration all of the relevant facts and circumstances.

 

Foreign Currency Translation

 

The method of translating the foreign currency financial statements of the corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment. Downstream and chemicals operations normally use the local currency, except in highly inflationary countries, primarily Latin America, as well as in Singapore, which uses the U.S. dollar, because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas production is predominantly sold in the export market in U.S. dollars. These operations, which use the U.S. dollar as their functional currency, are in Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea and the Middle East countries.

 

FORWARD-LOOKING STATEMENTS

 

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including production growth; financing sources; the resolution of contingencies; the effect of changes in prices; interest rates and other market conditions; and environmental and capital expenditures could differ materially depending on a number of factors, such as the outcome of commercial negotiations; changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; and other factors discussed above and under the caption “Factors Affecting Future Results” in Item 1 of ExxonMobil’s 2002 Form 10-K.

 

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MANAGEMENT’S DISCUSSION OF INTERNAL CONTROLS FOR FINANCIAL REPORTING

 

Management is responsible for establishing and maintaining adequate internal controls and procedures for the preparation of financial reports. Accordingly, comprehensive procedures and practices are in place. These procedures and practices are designed to provide reasonable assurance that the corporation’s transactions are properly authorized; the corporation’s assets are safeguarded against unauthorized or improper use; and the corporation’s transactions are properly recorded and reported to permit the preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles.

 

Internal controls and procedures for financial reporting are regularly reviewed by management and by the ExxonMobil internal audit function and findings are shared with the Board Audit Committee. In addition, PricewaterhouseCoopers, the corporation’s independent accountant, who reports to the Board Audit Committee, considers and selectively tests internal controls in planning and performing their audits. Management’s review of the design and operation of these controls and procedures in 2002, including review as of year-end, did not identify any significant deficiencies or material weaknesses, including any deficiencies which could adversely affect the corporation’s ability to record, process, summarize and report financial data.

 

/s/    Lee R. Raymond        


 

/s/    Donald D. Humphreys        


 

/s/    Frank A. Risch        


Lee R. Raymond

 

Donald D. Humphreys

 

Frank A. Risch

Chief Executive Officer

 

Vice President and Controller (Principal Accounting Officer)

 

Vice President and Treasurer (Principal Financial Officer)

 

REPORT OF INDEPENDENT ACCOUNTANTS

 

[LOGO OF PRICEWATERHOUSECOOPERS]

 

To the Shareholders of Exxon Mobil Corporation

 

In our opinion, the consolidated financial statements appearing on pages 39 through 60 present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiary companies at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the corporation’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

/s/    PricewaterhouseCoopers LLP

 

Dallas, Texas

February 26, 2003

 

 

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CONSOLIDATED STATEMENT OF INCOME

 

    

2002


  

2001


  

2000


    

(millions of dollars)

Revenue

                    

Sales and other operating revenue, including excise taxes

  

$

200,949

  

$

208,715

  

$

227,596

Earnings from equity interests and other revenue

  

 

3,557

  

 

4,070

  

 

4,250

    

  

  

Total revenue

  

$

204,506

  

$

212,785

  

$

231,846

    

  

  

Costs and other deductions

                    

Crude oil and product purchases

  

$

90,950

  

$

92,257

  

$

108,913

Operating expenses

  

 

17,831

  

 

17,743

  

 

17,600

Selling, general and administrative expenses

  

 

12,356

  

 

12,898

  

 

12,044

Depreciation and depletion

  

 

8,310

  

 

7,848

  

 

8,001

Exploration expenses, including dry holes

  

 

920

  

 

1,175

  

 

936

Merger related expenses

  

 

410

  

 

748

  

 

1,406

Interest expense

  

 

398

  

 

293

  

 

589

Excise taxes

  

 

22,040

  

 

21,907

  

 

22,356

Other taxes and duties

  

 

33,572

  

 

33,377

  

 

32,708

Income applicable to minority and preferred interests

  

 

209

  

 

569

  

 

412

    

  

  

Total costs and other deductions

  

$

186,996

  

$

188,815

  

$

204,965

    

  

  

Income before income taxes

  

$

17,510

  

$

23,970

  

$

26,881

Income taxes

  

 

6,499

  

 

8,967

  

 

11,075

    

  

  

Income from continuing operations

  

$

11,011

  

$

15,003

  

$

15,806

Discontinued operations, net of income tax

  

 

449

  

 

102

  

 

184

Extraordinary gain, net of income tax

  

 

—  

  

 

215

  

 

1,730

    

  

  

Net income

  

$

11,460

  

$

15,320

  

$

17,720

    

  

  

Net income per common share (dollars)

                    

Income from continuing operations

  

$

1.62

  

$

2.19

  

$

2.27

Discontinued operations, net of income tax

  

 

0.07

  

 

0.01

  

 

0.03

Extraordinary gain, net of income tax

  

 

—