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

  

 

—  

  

 

0.03

  

 

0.25

    

  

  

Net income

  

$

1.69

  

$

2.23

  

$

2.55

    

  

  

Net income per common share – assuming dilution (dollars)

                    

Income from continuing operations

  

$

1.61

  

$

2.17

  

$

2.24

Discontinued operations, net of income tax

  

 

0.07

  

 

0.01

  

 

0.03

Extraordinary gain, net of income tax

  

 

—  

  

 

0.03

  

 

0.25

    

  

  

Net income

  

$

1.68

  

$

2.21

  

$

2.52

    

  

  

 

The information on pages 43 through 60 is an integral part of these statements.

 

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CONSOLIDATED BALANCE SHEET

 

    

Dec. 31

2002


    

Dec. 31

2001


 
    

(millions of dollars)

 

Assets

                 

Current assets

                 

Cash and cash equivalents

  

$

7,229

 

  

$

6,547

 

Notes and accounts receivable, less estimated doubtful amounts

  

 

21,163

 

  

 

19,549

 

Inventories

                 

Crude oil, products and merchandise

  

 

6,827

 

  

 

6,743

 

Materials and supplies

  

 

1,241

 

  

 

1,161

 

Prepaid taxes and expenses

  

 

1,831

 

  

 

1,681

 

    


  


Total current assets

  

$

38,291

 

  

$

35,681

 

Investments and advances

  

 

12,111

 

  

 

10,768

 

Property, plant and equipment, at cost, less accumulated depreciation and depletion

  

 

94,940

 

  

 

89,602

 

Other assets, including intangibles, net

  

 

7,302

 

  

 

7,123

 

    


  


Total assets

  

$

152,644

 

  

$

143,174

 

    


  


Liabilities

                 

Current liabilities

                 

Notes and loans payable

  

$

4,093

 

  

$

3,703

 

Accounts payable and accrued liabilities

  

 

25,186

 

  

 

22,862

 

Income taxes payable

  

 

3,896

 

  

 

3,549

 

    


  


Total current liabilities

  

$

33,175

 

  

$

30,114

 

Long-term debt

  

 

6,655

 

  

 

7,099

 

Annuity reserves and accrued liabilities

  

 

16,454

 

  

 

12,475

 

Deferred income tax liabilities

  

 

16,484

 

  

 

16,359

 

Deferred credits and other long-term obligations

  

 

2,511

 

  

 

1,141

 

Equity of minority and preferred shareholders in affiliated companies

  

 

2,768

 

  

 

2,825

 

    


  


Total liabilities

  

$

78,047

 

  

$

70,013

 

    


  


Shareholders’ equity

                 

Benefit plan related balances

  

$

(450

)

  

$

(159

)

Common stock without par value (9,000 million shares authorized)

  

 

4,217

 

  

 

3,789

 

Earnings reinvested

  

 

100,961

 

  

 

95,718

 

Accumulated other nonowner changes in equity

                 

Cumulative foreign exchange translation adjustment

  

 

(3,015

)

  

 

(5,947

)

Minimum pension liability adjustment

  

 

(2,960

)

  

 

(535

)

Unrealized gains/(losses) on stock investments

  

 

(79

)

  

 

(108

)

Common stock held in treasury (1,319 million shares in 2002 and 1,210 million shares in 2001)

  

 

(24,077

)

  

 

(19,597

)

    


  


Total shareholders’ equity

  

$

74,597

 

  

$

73,161

 

    


  


Total liabilities and shareholders’ equity

  

$

152,644

 

  

$

143,174

 

    


  


 

The information on pages 43 through 60 is an integral part of these statements.

 

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CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

 

    

2002


    

2001


    

2000


 
    

Shareholders’ Equity


    

Nonowner Changes in Equity


    

Shareholders’ Equity


    

Nonowner Changes in Equity


    

Shareholders’ Equity


    

Nonowner Changes in Equity


 
    

(millions of dollars)

 

Benefit plan related balances

                                                     

At beginning of year

  

$

(159

)

           

$

(235

)

           

$

(298

)

        

Restricted stock award

  

 

(361

)

           

 

—  

 

           

 

—  

 

        

Amortization

  

 

11

 

           

 

—  

 

           

 

—  

 

        

Other

  

 

59

 

           

 

76

 

           

 

63

 

        
    


           


           


        

At end of year

  

$

(450

)

           

$

(159

)

           

$

(235

)

        
    


           


           


        

Common stock (see note 13)

                                                     

At beginning of year

  

 

3,789

 

           

 

3,661

 

           

 

3,403

 

        

Issued

  

 

—  

 

           

 

—  

 

           

 

—  

 

        

Other

  

 

428

 

           

 

128

 

           

 

258

 

        
    


           


           


        

At end of year

  

$

4,217

 

           

$

3,789

 

           

$

3,661

 

        
    


           


           


        

Earnings reinvested

                                                     

At beginning of year

  

 

95,718

 

           

 

86,652

 

           

 

75,055

 

        

Net income for the year

  

 

11,460

 

  

$

11,460

 

  

 

15,320

 

  

$

15,320

 

  

 

17,720

 

  

$

17,720

 

Dividends – common shares

  

 

(6,217

)

           

 

(6,254

)

           

 

(6,123

)

        
    


           


           


        

At end of year

  

$

100,961

 

           

$

95,718

 

           

$

86,652

 

        
    


           


           


        

Accumulated other nonowner changes in equity

                                                     

At beginning of year

  

 

(6,590

)

           

 

(5,189

)

           

 

(2,568

)

        

Foreign exchange translation adjustment

  

 

2,932

 

  

 

2,932

 

  

 

(1,085

)

  

 

(1,085

)

  

 

(2,562

)

  

 

(2,562

)

Minimum pension liability adjustment

  

 

(2,425

)

  

 

(2,425

)

  

 

(225

)

  

 

(225

)

  

 

(11

)

  

 

(11

)

Unrealized gains/(losses) on stock investments

  

 

29

 

  

 

29

 

  

 

(91

)

  

 

(91

)

  

 

(48

)

  

 

(48

)

    


           


           


        

At end of year

  

$

(6,054

)

           

$

(6,590

)

           

$

(5,189

)

        
    


  


  


  


  


  


Total

           

$

11,996

 

           

$

13,919

 

           

$

15,099

 

             


           


           


Common stock held in treasury

                                                     

At beginning of year

  

 

(19,597

)

           

 

(14,132

)

           

 

(12,126

)

        

Acquisitions, at cost

  

 

(4,798

)

           

 

(5,721

)

           

 

(2,352

)

        

Dispositions

  

 

318

 

           

 

256

 

           

 

346

 

        
    


           


           


        

At end of year

  

$

(24,077

)

           

$

(19,597

)

           

$

(14,132

)

        
    


           


           


        

Shareholders’ equity at end of year

  

$

74,597

 

           

$

73,161

 

           

$

70,757

 

        
    


           


           


        
    

Share Activity


        
    

2002


           

2001


           

2000


        
    

(millions of shares)

        

Common stock

                                                     

Issued (see note 13)

                                                     

At beginning of year

  

 

8,019

 

           

 

8,019

 

           

 

8,019

 

        

Issued

  

 

—  

 

           

 

—  

 

           

 

—  

 

        
    


           


           


        

At end of year

  

 

8,019

 

           

 

8,019

 

           

 

8,019

 

        
    


           


           


        

Held in treasury (see note 13)

                                                     

At beginning of year

  

 

(1,210

)

           

 

(1,089

)

           

 

(1,064

)

        

Acquisitions

  

 

(127

)

           

 

(139

)

           

 

(54

)

        

Dispositions

  

 

18

 

           

 

18

 

           

 

29

 

        
    


           


           


        

At end of year

  

 

(1,319

)

           

 

(1,210

)

           

 

(1,089

)

        
    


           


           


        

Common shares outstanding at end of year

  

 

6,700

 

           

 

6,809

 

           

 

6,930

 

        
    


           


           


        

 

The information on pages 43 through 60 is an integral part of these statements.

 

 

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CONSOLIDATED STATEMENT OF CASH FLOWS

 

   

2002


   

2001


    

2000


 
   

(millions of dollars)

 

Cash flows from operating activities

                        

Net income

                        

Accruing to ExxonMobil shareholders

 

$

11,460

 

 

$

15,320

 

  

$

17,720

 

Accruing to minority and preferred interests

 

 

209

 

 

 

569

 

  

 

412

 

Adjustments for non-cash transactions

                        

Depreciation and depletion

 

 

8,310

 

 

 

7,848

 

  

 

8,001

 

Deferred income tax charges/(credits)

 

 

297

 

 

 

650

 

  

 

10

 

Annuity and accrued liability provisions

 

 

(590

)

 

 

498

 

  

 

(662

)

Dividends received greater than/(less than) equity in current earnings of equity companies

 

 

(170

)

 

 

78

 

  

 

(387

)

Extraordinary gain, before income tax

 

 

—  

 

 

 

(194

)

  

 

(2,038

)

Changes in operational working capital, excluding cash and debt

                        

Reduction/(increase) – Notes and accounts receivable

 

 

(305

)

 

 

3,062

 

  

 

(4,832

)

– Inventories

 

 

353

 

 

 

154

 

  

 

(297

)

– Prepaid taxes and expenses

 

 

32

 

 

 

118

 

  

 

(204

)

Increase/(reduction) – Accounts and other payables

 

 

365

 

 

 

(5,103

)

  

 

5,411

 

All other items – net

 

 

1,307

 

 

 

(111

)

  

 

(197

)

   


 


  


Net cash provided by operating activities

 

$

21,268

 

 

$

22,889

 

  

$

22,937

 

   


 


  


Cash flows from investing activities

                        

Additions to property, plant and equipment

 

$

(11,437

)

 

$

(9,989

)

  

$

(8,446

)

Sales of subsidiaries, investments and property, plant and equipment

 

 

2,793

 

 

 

1,078

 

  

 

5,770

 

Additional investments and advances

 

 

(2,012

)

 

 

(1,035

)

  

 

(1,648

)

Collection of advances

 

 

898

 

 

 

1,735

 

  

 

985

 

Additions to other marketable securities

 

 

—  

 

 

 

—  

 

  

 

(41

)

Sales of other marketable securities

 

 

—  

 

 

 

—  

 

  

 

82

 

   


 


  


Net cash used in investing activities

 

$

(9,758

)

 

$

(8,211

)

  

$

(3,298

)

   


 


  


Net cash generation before financing activities

 

$

11,510

 

 

$

14,678

 

  

$

19,639

 

   


 


  


Cash flows from financing activities

                        

Additions to long-term debt

 

$

396

 

 

$

547

 

  

$

238

 

Reductions in long-term debt

 

 

(246

)

 

 

(506

)

  

 

(901

)

Additions to short-term debt

 

 

751

 

 

 

705

 

  

 

500

 

Reductions in short-term debt

 

 

(927

)

 

 

(1,212

)

  

 

(2,413

)

Additions/(reductions) in debt with less than 90 day maturity

 

 

(281

)

 

 

(2,306

)

  

 

(3,129

)

Cash dividends to ExxonMobil shareholders

 

 

(6,217

)

 

 

(6,254

)

  

 

(6,123

)

Cash dividends to minority interests

 

 

(169

)

 

 

(194

)

  

 

(251

)

Changes in minority interests and sales/(purchases) of affiliate stock

 

 

(161

)

 

 

(401

)

  

 

(227

)

Common stock acquired

 

 

(4,798

)

 

 

(5,721

)

  

 

(2,352

)

Common stock sold

 

 

299

 

 

 

301

 

  

 

493

 

   


 


  


Net cash used in financing activities

 

$

(11,353

)

 

$

(15,041

)

  

$

(14,165

)

   


 


  


Effects of exchange rate changes on cash

 

$

525

 

 

$

(170

)

  

$

(82

)

   


 


  


Increase/(decrease) in cash and cash equivalents

 

$

682

 

 

$

(533

)

  

$

5,392

 

Cash and cash equivalents at beginning of year

 

 

6,547

 

 

 

7,080

 

  

 

1,688

 

   


 


  


Cash and cash equivalents at end of year

 

$

7,229

 

 

$

6,547

 

  

$

7,080

 

   


 


  


 

The information on pages 43 through 60 is an integral part of these statements.

 

 

42


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.

 

The corporation’s principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (upstream) and the manufacture, transportation and sale of petroleum products (downstream). The corporation is also a major worldwide manufacturer and marketer of petrochemicals (chemicals), and participates in electric power generation (upstream).

 

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

 

1. Summary of Accounting Policies

 

Principles of Consolidation. The consolidated financial statements include the accounts of those significant subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the corporation, and for which other shareholders do not possess the right to participate in significant management decisions. They also include the corporation’s share of the undivided interest in upstream assets and liabilities. Amounts representing the corporation’s percentage interest in the underlying net assets of other significant subsidiaries and less than majority owned companies in which a significant equity ownership interest is held, 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.”

 

Investments in other companies, none of which is significant, are generally included in “Investments and advances” at cost or less. Dividends from these companies are included in income as received.

 

Revenue Recognition. Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and all other items are recorded when title passes to the customer.

 

Revenues from the production of natural gas properties in which the corporation has an interest with the other producers are recognized on the basis of the company’s net working interest. Differences between actual production and net working interest volumes are not significant.

 

Derivative Instruments. The corporation makes limited use of derivatives. Derivative instruments are not held for trading purposes nor do they have leverage features. When the corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices. The gains and losses resulting from the changes in fair value of these instruments are recorded in income, except when the instruments are designated as hedging the currency exposure of net investments in foreign subsidiaries, in which case they are recorded in the cumulative foreign exchange translation account, as part of shareholders’ equity.

 

The gains and losses on derivative instruments that are designated as fair value hedges (i.e., those hedging the exposure to changes in the fair value of an asset or a liability or the changes in the fair value of a firm commitment), are offset by the gains and losses from the changes in fair value of the hedged items, which are also recognized in income. Most of these designated hedges are entered into at the same time that the hedged items are transacted, they are fully effective and in combination with the offsetting hedged items, they result in no net impact on income. In some situations, the corporation has chosen not to designate certain immaterial derivatives used for hedging economic exposure as hedges for accounting purposes due to the excessive administrative effort that would be required to account for these items as hedging transactions. These derivatives are recorded on the balance sheet at fair value and the gains and losses arising from changes in fair value are recognized in income. All derivatives activity is immaterial.

 

Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Costs include applicable purchase costs and operating expenses but not general and administrative expenses or research and development costs. Inventories of materials and supplies are valued at cost or less.

 

Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method. Unit-of-production rates are based on oil, gas and other mineral reserves estimated to be recoverable from existing facilities. The straight-line method of depreciation is based on estimated asset service life taking obsolescence into consideration.

 

Maintenance and repairs are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

 

The corporation’s upstream activities are accounted for under the “successful efforts” method. Under this method, costs of productive wells and development dry holes, both tangible and intangible, as well as productive acreage are capitalized and amortized on the unit-of-production method. Costs of that portion of undeveloped acreage likely to be unproductive, based largely on historical experience, are amortized over the period of exploration. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are 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 assure 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.

 

Oil, gas and other properties held and used by the corporation 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.

 

Site Restoration and Environmental Conservation Costs. Site restoration costs that may be incurred by the corporation at the end of the operating life of certain of its facilities and properties are reserved ratably over the asset’s productive life.

 

 

43


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Liabilities for environmental conservation are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties, and projected cash expenditures are not discounted.

 

Foreign Currency Translation. The “functional currency” for translating the accounts of the majority of downstream and chemical operations outside the U.S. is the local currency. Local currency is also used for upstream operations that are relatively self-contained and integrated within a particular country, such as in Canada, the United Kingdom, Norway and Continental Europe. The U.S. dollar is used for operations in highly inflationary economies, in Singapore which is predominantly export oriented and for some upstream operations, primarily in Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea and the Middle East countries. For all operations, gains or losses on remeasuring foreign currency transactions into functional currency are included in income.

 

Stock Option Accounting. Effective January 1, 2003, the corporation will adopt for all employee stock-based awards granted after that date, the recognition provisions of Statement of Financial Accounting Standards No. 123 (FAS 123), “Accounting for Stock-Based Compensation.” In accordance with FAS 123, compensation expense for future awards will be measured by the fair value of the award at the date of grant and recognized over the vesting period. The fair value of awards in the form of restricted stock is the market price of the stock. The fair value of awards in the form of stock options is estimated using an option-pricing model.

 

As permitted by FAS 123, the corporation has retained its prior method of accounting for stock-based awards granted before January 1, 2003. Under this method, compensation expense for awards granted in the form of stock options is measured at the intrinsic value of the options (the difference between the market price of stock and the exercise price of the options) on the date of grant. Since these two prices are the same on the date of grant, no compensation expense was recognized in income for these awards. Additionally, compensation expense for awards granted in the form of restricted stock is based on the price of the stock when it is granted and is recognized over the vesting period, which is the same method of accounting as under FAS 123.

 

If the provisions of FAS 123 had been adopted for all prior years, the impact on compensation expense, net income, and net income per share would have been as follows:

 

    

2002


    

2001


    

2000


 
    

(millions of dollars)

 

Net income, as reported

  

$

11,460

 

  

$

15,320

 

  

$

17,720

 

Add: Stock-based compensation, net of tax included in reported net income

  

 

19

 

  

 

8

 

  

 

(2

)

Deduct: Stock-based compensation, net of tax determined under fair value based method

  

 

(180

)

  

 

(293

)

  

 

(294

)

    


  


  


Pro forma net income

  

$

11,299

 

  

$

15,035

 

  

$

17,424

 

    

(dollars per share)

 

Net income per share:

                          

Basic – as reported

  

$

1.69

 

  

$

2.23

 

  

$

2.55

 

Basic – pro forma

  

 

1.67

 

  

 

2.19

 

  

 

2.51

 

Diluted – as reported

  

 

1.68

 

  

 

2.21

 

  

 

2.52

 

Diluted – pro forma

  

 

1.66

 

  

 

2.17

 

  

 

2.48

 

 

The pro forma amounts that would have been reported if FAS 123 had been in effect for all years are based on the fair value of stock-based awards granted for each of those years and recognized over the vesting period. In 2002, the stock-based awards were in the form of restricted common stock and restricted stock units, and the fair value is based on the price of the stock at the date of grant, which was $34.64. No stock option awards were made in 2002. In 2001 and 2000, the stock-based awards were primarily stock options and the fair values were estimated using an option-pricing model. The average fair value for each stock option granted during 2001 and 2000 was $6.89 and $10.18, respectively. The weighted average assumptions used to determine these amounts for 2001 and 2000, respectively, were: risk-free interest rates of 4.6 percent and 5.5 percent; expected life of 6 years and volatility of 16 percent for both years; and a dividend yield of 2.5 percent and 2.0 percent.

 

2. Extraordinary Item

 

Net income for 2001 included net after-tax gains from asset management activities in the chemicals segment and regulatory required asset divestitures in the amount of $215 million (including an income tax credit of $21 million), or $0.03 per common share. Net income for 2000 included net after-tax gains from regulatory required asset divestitures in the amount of $1,730 million (net of $308 million of income taxes), or $0.25 per common share. These net after-tax gains were reported as extraordinary items according to accounting requirements for business combinations accounted for as pooling of interests.

 

 

44


Table of Contents

 

3. Discontinued Operations

 

In 2002, the copper business in Chile and the coal operations in Colombia were sold. Earnings of these businesses are reported as discontinued operations for all years presented in the consolidated statement of income. Income taxes related to discontinued operations were: 2002 – $41 million, 2001 – $47 million and 2000 – $16 million. Included in discontinued operations for 2002 are gains on the dispositions of $400 million, net of tax. The assets that were sold were primarily property, plant and equipment in the amount of $1.3 billion. Revenues of these operations were not material. These businesses were historically reported in the “All Other” column in the segment disclosures located in note 19 on pages 58 and 59.

 

4. Merger Expenses and Reorganization Reserves

 

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 net after-tax gains of $40 million and $1,730 million were reported as extraordinary items in 2001 and 2000, respectively. The divested properties historically earned approximately $200 million per year.

 

In association with the Merger, $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. Cumulative charges for the period 1999 to 2002 of $3,189 million included separation expenses of approximately $1,460 million related to workforce reductions (approximately 8,200 employees at year-end 2002), plus implementation costs and merger closing costs. Reflecting the completion of merger-related activities, merger expenses will not be reported in 2003.

 

The separation reserve balance at year-end 2002 of approximately $101 million is expected to be expended 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

 

5. Miscellaneous Financial Information

 

Research and development costs totaled $631 million in 2002, $603 million in 2001 and $564 million in 2000.

 

Net income included aggregate foreign exchange transaction losses of $106 million in 2002, $142 million in 2001 and $236 million in 2000.

 

In 2002, 2001 and 2000, net income included gains of $159 million, $238 million and $175 million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $6.8 billion and $4.2 billion at December 31, 2002 and 2001, respectively.

 

6. Cash Flow Information

 

The consolidated statement of cash flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.

 

In 2002, 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 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 payments for interest were: 2002 – $437 million, 2001 – $562 million and 2000 – $729 million. Cash payments for income taxes were: 2002 – $6,106 million, 2001 – $9,855 million and 2000 – $8,671 million.

 

7. Additional Working Capital Data

 

    

Dec. 31

2002


  

Dec. 31 2001


    

(millions of dollars)

Notes and accounts receivable

             

Trade, less reserves of $314 million and $279 million

  

$

15,317

  

$

13,597

Other, less reserves of $39 million and $62 million

  

 

5,846

  

 

5,952

    

  

    

$

21,163

  

$

19,549

    

  

Notes and loans payable

             

Bank loans

  

$

987

  

$

1,063

Commercial paper

  

 

1,870

  

 

1,804

Long-term debt due within one year

  

 

884

  

 

339

Other

  

 

352

  

 

497

    

  

    

$

4,093

  

$

3,703

    

  

Accounts payable and accrued liabilities

             

Trade payables

  

$

13,792

  

$

12,696

Obligations to equity companies

  

 

1,192

  

 

632

Accrued taxes other than income taxes

  

 

4,628

  

 

4,768

Other

  

 

5,574

  

 

4,766

    

  

    

$

25,186

  

$

22,862

    

  

 

On December 31, 2002, unused credit lines for short-term financing totaled approximately $4.2 billion. Of this total, $1.7 billion support commercial paper programs under terms negotiated when drawn. The weighted average interest rate on short-term borrowings outstanding at December 31, 2002 and 2001 was 2.8 percent and 3.8 percent, respectively.

 

 

45


Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

8. Equity Company Information

 

The summarized financial information below includes amounts related to certain less than majority owned companies and majority owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see note 1). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution, and downstream operations in Europe and crude production in Kazakhstan and the Middle East. Also included are several power generation, petrochemical/lubes manufacturing and chemical ventures. The share of total revenues in the table below representing sales to ExxonMobil consolidated companies was 19 percent, 19 percent and 18 percent, respectively, in the years 2002, 2001 and 2000.

 

    

2002


    

2001


    

2000


 

Equity Company Financial Summary


  

Total


    

ExxonMobil Share


    

Total


    

ExxonMobil Share


    

Total


    

ExxonMobil Share


 
    

(millions of dollars)

 

Total revenues (a)

  

$

47,204

 

  

$

17,230

 

  

$

47,072

 

  

$

17,520

 

  

$

48,550

 

  

$

19,323

 

    


  


  


  


  


  


Income before income taxes

  

$

6,028

 

  

$

2,844

 

  

$

6,952

 

  

$

2,922

 

  

$

7,632

 

  

$

3,092

 

Less: Related income taxes

  

 

(1,461

)

  

 

(778

)

  

 

(1,562

)

  

 

(748

)

  

 

(1,382

)

  

 

(658

)

    


  


  


  


  


  


Net income

  

$

4,567

 

  

$

2,066

 

  

$

5,390

 

  

$

2,174

 

  

$

6,250

 

  

$

2,434

 

    


  


  


  


  


  


Current assets

  

$

20,162

 

  

$

7,658

 

  

$

18,992

 

  

$

7,369

 

  

$

28,784

 

  

$

11,479

 

Property, plant and equipment, less accumulated depreciation

  

 

39,351

 

  

 

14,254

 

  

 

36,565

 

  

 

13,135

 

  

 

36,553

 

  

 

13,733

 

Other long-term assets

  

 

5,524

 

  

 

2,614

 

  

 

5,127

 

  

 

2,284

 

  

 

6,656

 

  

 

2,979

 

    


  


  


  


  


  


Total assets

  

$

65,037

 

  

$

24,526

 

  

$

60,684

 

  

$

22,788

 

  

$

71,993

 

  

$

28,191

 

    


  


  


  


  


  


Short-term debt

  

$

3,561

 

  

$

1,443

 

  

$

3,142

 

  

$

1,232

 

  

$

2,636

 

  

$

1,093

 

Other current liabilities

  

 

15,529

 

  

 

5,991

 

  

 

16,218

 

  

 

6,349

 

  

 

25,377

 

  

 

10,357

 

Long-term debt

  

 

9,236

 

  

 

3,352

 

  

 

10,496

 

  

 

3,950

 

  

 

11,116

 

  

 

4,094

 

Other long-term liabilities

  

 

8,248

 

  

 

3,881

 

  

 

6,253

 

  

 

2,862

 

  

 

7,054

 

  

 

3,273

 

Advances from shareholders

  

 

10,721

 

  

 

2,927

 

  

 

8,443

 

  

 

2,179

 

  

 

8,485

 

  

 

2,510

 

    


  


  


  


  


  


Net assets

  

$

17,742

 

  

$

6,932

 

  

$

16,132

 

  

$

6,216

 

  

$

17,325

 

  

$

6,864

 

    


  


  


  


  


  


 

(a) Equity company revenues for prior years have been adjusted on a comparable basis to conform to the Financial Accounting Standards Board Emerging Issues Task Force consensus in Issue No. 02-3 regarding the reporting of revenues on certain energy contracts. This change in accounting does not affect net income.

 

In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities,” which provides guidance on when certain entities should be consolidated or the interests in those entities should be disclosed by enterprises that do not control them through majority voting interest. Under FIN 46, entities are required to be consolidated by enterprises that lack majority voting interest when equity investors of those entities have insignificant capital at risk or they lack voting rights, the obligation to absorb expected losses, or the right to receive expected returns. Entities identified with these characteristics are called variable interest entities and the interests that enterprises have in these entities are called variable interests. These interests can derive from certain guarantees, leases, loans, or other arrangements that result in risks and rewards that are disproportionate to the voting interests in the entities.

 

The provisions of FIN 46 must be immediately applied for variable interest entities created after January 31, 2003. For variable interest entities created before February 1, 2003, FIN 46 must be adopted in the first reporting period beginning after June 15, 2003.

 

In order to comply with the provisions of FIN 46, the corporation is reviewing its financial arrangements to identify any that might qualify as variable interest entities. There is a reasonable possibility that certain joint ventures in which the corporation has an interest might be variable interest entities. Summarized financial data for these entities are a part of the data in the above tables. These joint ventures are operating entities and the other equity investors are third parties independent from the corporation. The corporation’s share of net income of these entities is included in the consolidated statement of income. The variable interests arise primarily because of certain guarantees extended by the corporation to the joint ventures, which are included in the disclosure of guarantees included in note 17 on page 56.

 

The corporation does not expect any impact on net income if it is required to consolidate any of these possible variable interest entities because it already is recording its share of net income of these entities. The impact to the balance sheet would be an increase in assets and liabilities estimated to be less than 1 percent of total assets. However, there would be no change to the calculation of return on average capital employed because the corporation already includes its share of joint venture debt in the determination of average capital employed.

 

46


Table of Contents

 

9. Investments and Advances

 

    

Dec. 31

2002


  

Dec. 31

2001


    

(millions of dollars)

Companies carried at equity in underlying assets

             

Investments

  

$

6,932

  

$

6,216

Advances

  

 

2,927

  

 

2,179

    

  

    

$

9,859

  

$

8,395

Companies carried at cost or less and stock investments carried at fair value

  

 

1,088

  

 

1,060

    

  

    

$

10,947

  

$

9,455

Long-term receivables and miscellaneous investments at cost or less

  

 

1,164

  

 

1,313

    

  

Total

  

$

12,111

  

$

10,768

    

  

 

10. Investment in Property, Plant and Equipment

 

    

Dec. 31, 2002


  

Dec. 31, 2001


    

Cost


  

Net


  

Cost


  

Net


    

(millions of dollars)

Upstream

  

$

122,210

  

$

51,696

  

$

109,786

  

$

46,677

Downstream

  

 

54,032

  

 

26,920

  

 

50,691

  

 

25,560

Chemicals

  

 

19,138

  

 

9,909

  

 

17,973

  

 

9,690

Other

  

 

9,580

  

 

6,415

  

 

12,053

  

 

7,675

    

  

  

  

Total

  

$

204,960

  

$

94,940

  

$

190,503

  

$

89,602

    

  

  

  

 

Accumulated depreciation and depletion totaled $110,020 million at the end of 2002 and $100,901 million at the end of 2001. Interest capitalized in 2002, 2001 and 2000 was $426 million, $518 million and $641 million, respectively.

 

11. Leased Facilities

 

At December 31, 2002, the corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum lease commitments as indicated in the table.

 

Net rental expenditures for 2002, 2001 and 2000 totaled $2,322 million, $2,454 million and $1,935 million, respectively, after being reduced by related rental income of $140 million, $199 million and $195 million, respectively. Minimum rental expenditures totaled $2,378 million in 2002, $2,562 million in 2001 and $1,992 million in 2000.

 

    

Minimum Commitment


    

Related Rental Income


    

(millions of dollars)

2003

  

$1,352

    

$66

2004

  

1,066

    

56

2005

  

836

    

50

2006

  

683

    

45

2007

  

575

    

37

2008 and beyond

  

2,433

    

144

    
    

Total

  

$6,945

    

$398

    
    

 

12. Employee Stock Ownership Plans

 

In 1989, the Exxon and Mobil employee stock ownership plan trusts borrowed $1,000 million and $800 million respectively to finance the purchase of shares of Exxon and Mobil stock. The trusts were merged in late 1999 to create the ExxonMobil leveraged employee stock ownership trust (ExxonMobil LESOP). The ExxonMobil LESOP is a constituent part of the ExxonMobil Savings Plan, which, effective February 8, 2002, is an employee stock ownership plan in its entirety.

 

Employees eligible to participate in the ExxonMobil Savings Plan may elect to participate in the ExxonMobil LESOP. Corporate contributions to the plan and dividends are used to make principal and interest payments on the remaining ExxonMobil LESOP notes ($65 million outstanding as of December 31, 2002, which will be fully repaid in 2003). As corporate contributions and dividends are credited, common shares are allocated to participants’ plan accounts. The corporation’s contribution to the ExxonMobil LESOP, representing the amount by which debt service exceeded dividends on shares held by the ExxonMobil LESOP, was $86 million, $58 million and $15 million in 2002, 2001 and 2000, respectively.

 

Accounting for the plans has followed the principles that were in effect for the respective plans when they were established. The amount of compensation expense related to the plans and recorded by the corporation during the periods was $122 million in 2002, $83 million in 2001 and $13 million in 2000. The ExxonMobil LESOP trust held 98 million shares of ExxonMobil common stock at the end of 2002 and 104.2 million shares at the end of 2001.

 

 

47


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

13. Capital

 

On May 30, 2001, the company’s Board of Directors approved a two-for-one stock split of common stock for shareholders of record on June 20, 2001. The authorized common stock was increased from 4.5 billion shares without par value to 9 billion shares without par value, and the issued shares were split on a two-for-one basis on June 20, 2001.

 

In 1989, $1,800 million of benefit related balances were recorded as debt and as a reduction to shareholders’ equity, representing Exxon and Mobil guaranteed borrowings by the Exxon LESOP to purchase Exxon Class A Preferred Stock and the Mobil LESOP to purchase Mobil Class B Preferred Stock. All preferred shares were converted to ExxonMobil common stock by year-end 1999. As common shares are earned by employees and the debt is repaid, the benefit plan related balances are being reduced.

 

The table below summarizes the earnings per share calculations.

 

    

2002


  

2001


    

2000


 

Net income per common share

                        

Income from continuing operations (millions of dollars)

  

$

11,011

  

$

15,003

 

  

$

15,806

 

Weighted average number of common shares outstanding (millions of shares)

  

 

6,753

  

 

6,868

 

  

 

6,953

 

Net income per common share

                        

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

  

 

—  

  

 

0.03

 

  

 

0.25

 

    

  


  


Net income

  

$

1.69

  

$

2.23

 

  

$

2.55

 

    

  


  


Net income per common share – assuming dilution

                        

Income from continuing operations (millions of dollars)

  

$

11,011

  

$

15,003

 

  

$

15,806

 

Adjustment for assumed dilution

  

 

—  

  

 

(4

)

  

 

(8

)

    

  


  


Income available to common shares

  

$

11,011

  

$

14,999

 

  

$

15,798

 

    

  


  


Weighted average number of common shares outstanding (millions of shares)

  

 

6,753

  

 

6,868

 

  

 

6,953

 

Effect of employee stock-based awards

  

 

50

  

 

73

 

  

 

80

 

    

  


  


Weighted average number of common shares outstanding – assuming dilution

  

 

6,803

  

 

6,941

 

  

 

7,033

 

    

  


  


Net income per common share

                        

Income from continuing operations

  

$

1.61

  

$

2.17

 

  

$

2.24

 

Discontinued operations, net of income tax

  

 

0.07

  

 

0.01

 

  

 

0.03

 

Extraordinary gain, net of income tax

  

 

—  

  

 

0.03

 

  

 

0.25

 

    

  


  


Net income

  

$

1.68

  

$

2.21

 

  

$

2.52

 

    

  


  


Dividends paid per common share

  

$

0.92

  

$

0.91

 

  

$

0.88

 

 

 

48


Table of Contents

 

14. Financial Instruments and Derivatives

 

The fair value of financial instruments is determined by reference to various market data and other valuation techniques as appropriate. Long-term debt is the only category of financial instruments whose fair value differs materially from the recorded book value. The estimated fair value of total long-term debt, including capitalized lease obligations, at December 31, 2002 and 2001, was $7.8 billion and $7.9 billion, respectively, as compared to recorded book values of $6.7 billion and $7.1 billion.

 

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 leveraged 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 and a net payable of $50 million 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 loss of $35 million and a 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.

 

15. Long-Term Debt

 

At December 31, 2002, long-term debt consisted of $5,985 million due in U.S. dollars and $670 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $884 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, together with sinking fund payments required, in each of the four years after December 31, 2003, in millions of dollars, are: 2004 – $2,499, 2005 – $345, 2006 – $132 and 2007 –$89. Certain of the borrowings described may from time to time be assigned to other ExxonMobil affiliates. At December 31, 2002, the corporation’s unused long-term credit lines were not material.

 

The total outstanding balance of defeased debt at year-end 2002 was $196 million. Summarized long-term borrowings at year-end 2002 and 2001 were as shown in the adjacent table:

 

    

2002


  

2001


    

(millions of dollars)

Exxon Mobil Corporation

             

Guaranteed zero coupon notes due 2004

             

– Face value ($1,146) net of unamortized discount

  

$

933

  

$

836

Exxon Capital Corporation (1)

             

6.0% Guaranteed notes due 2005

  

 

106

  

 

106

6.125% Guaranteed notes due 2008

  

 

160

  

 

160

SeaRiver Maritime Financial Holdings, Inc. (1)

             

Guaranteed debt securities due 2004-2011 (2)

  

 

95

  

 

105

Guaranteed deferred interest debentures due 2012

             

– Face value ($771) net of unamortized discount plus accrued interest

  

 

1,006

  

 

903

Imperial Oil Limited

             

Variable rate notes due 2004 (3)

  

 

600

  

 

600

Variable rate Canadian dollar notes due 2004 (4)

  

 

317

  

 

—  

ExxonMobil Canada Ltd.

             

3.0% Swiss franc debentures

  

 

—  

  

 

328

5.0% U.S. dollar Eurobonds due 2004 (5)

  

 

255

  

 

262

Mobil Producing Nigeria Unlimited

             

8.625% notes due 2004-2006

  

 

104

  

 

146

Mobil Corporation

             

8.625% debentures due 2021

  

 

248

  

 

247

7.625% debentures due 2033

  

 

204

  

 

204

Industrial revenue bonds due 2007-2033 (6)

  

 

1,530

  

 

1,535

ESOP Trust notes

  

 

—  

  

 

65

Other U.S. dollar obligations (7)

  

 

507

  

 

751

Other foreign currency obligations

  

 

296

  

 

585

Capitalized lease obligations (8)

  

 

294

  

 

266

    

  

Total long-term debt

  

$

6,655

  

$

7,099

    

  

 

(1)   Additional information is provided for these subsidiaries on pages 50-54.
(2)   Average effective interest rate of 1.8% in 2002 and 4.1% in 2001.
(3)   Average effective interest rate of 1.9% in 2002 and 4.2% in 2001.
(4)   Average effective interest rate of 2.8% in 2002.
(5)   Swapped into floating rate debt.
(6)   Average effective interest rate of 1.8% in 2002 and 3.0% in 2001.
(7)   Average effective interest rate of 5.7% in 2002 and 8.0% in 2001.
(8)   Average imputed interest rate of 6.4% in 2002 and 6.4% in 2001.

 

49


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

 

Exxon Mobil Corporation has fully and unconditionally guaranteed the 6.0% notes due 2005 ($106 million of long-term debt at year-end 2002) and the 6.125% notes due 2008 ($160 million) of Exxon Capital Corporation and the deferred interest debentures due 2012 ($1,006 million) and the debt securities due 2004-2011 ($95 million long-term and $10 million short-term) of SeaRiver Maritime Financial Holdings, Inc. Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc. are 100 percent owned subsidiaries of Exxon Mobil Corporation.

 

The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc., as issuers, as an alternative to providing separate financial statements for the issuers. The accounts of Exxon Mobil Corporation, Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the equity method of accounting for investments in subsidiaries.

 

    

Exxon Mobil Corporation Parent Guarantor


  

Exxon Capital Corporation


 

SeaRiver Maritime Financial Holdings, Inc.


   

All Other Subsidiaries


  

Consolidating and Eliminating Adjustments


   

Consolidated


    

(millions of dollars)

Condensed consolidated statement of income for twelve months ended December 31, 2002

Revenue

                                          

Sales and other operating revenue, including excise taxes  

  

$

8,711

  

$

 

$

—  

 

 

$

192,238

  

$

—  

 

 

$

200,949

Earnings from equity interests and other revenue

  

 

10,757

  

 

5

 

 

(16

)

 

 

2,954

  

 

(10,143

)

 

 

3,557

Intercompany revenue

  

 

15,711

  

 

41

 

 

27

 

 

 

120,836

  

 

(136,615

)

 

 

    

  

 


 

  


 

Total revenue

  

 

35,179

  

 

46

 

 

11

 

 

 

316,028

  

 

(146,758

)

 

 

204,506

    

  

 


 

  


 

Costs and other deductions

                                          

Crude oil and product purchases

  

 

14,687

  

 

 

 

 

 

 

207,709

  

 

(131,446

)

 

 

90,950

Operating expenses

  

 

5,312

  

 

2

 

 

1

 

 

 

16,839

  

 

(4,323

)

 

 

17,831

Selling, general and administrative expenses

  

 

1,592

  

 

2

 

 

 

 

 

10,898

  

 

(136

)

 

 

12,356

Depreciation and depletion

  

 

1,572

  

 

5

 

 

3

 

 

 

6,730

  

 

 

 

 

8,310

Exploration expenses, including dry holes

  

 

147

  

 

 

 

 

 

 

773

  

 

 

 

 

920

Merger related expenses

  

 

70

  

 

 

 

 

 

 

356

  

 

(16

)

 

 

410

Interest expense

  

 

655

  

 

22

 

 

112

 

 

 

4,634

  

 

(5,025

)

 

 

398

Excise taxes

  

 

  

 

 

 

 

 

 

22,040

  

 

 

 

 

22,040

Other taxes and duties

  

 

12

  

 

 

 

 

 

 

33,560

  

 

 

 

 

33,572

Income applicable to minority and preferred interests

  

 

  

 

 

 

 

 

 

209

  

 

 

 

 

209

    

  

 


 

  


 

Total costs and other deductions

  

 

24,047

  

 

31

 

 

116

 

 

 

303,748

  

 

(140,946

)

 

 

186,996

    

  

 


 

  


 

Income before income taxes

  

 

11,132

  

 

15

 

 

(105

)

 

 

12,280

  

 

(5,812

)

 

 

17,510

Income taxes

  

 

121

  

 

6

 

 

(31

)

 

 

6,403

  

 

 

 

 

6,499

    

  

 


 

  


 

Income from continuing operations

  

 

11,011

  

 

9

 

 

(74

)

 

 

5,877

  

 

(5,812

)

 

 

11,011

Discontinued operations, net of income tax

  

 

449

  

 

 

 

 

 

 

456

  

 

(456

)

 

 

449

Extraordinary gain, net of income tax

  

 

  

 

 

 

 

 

 

  

 

 

 

 

    

  

 


 

  


 

Net income

  

$

11,460

  

$

9

 

$

(74

)

 

$

6,333

  

$

(6,268

)

 

$

11,460

    

  

 


 

  


 

 

50


Table of Contents

 

    

Exxon Mobil Corporation Parent Guarantor


  

Exxon Capital Corporation


    

SeaRiver Maritime Financial Holdings, Inc.


    

All Other

Subsidiaries


  

Consolidating and Eliminating Adjustments


    

Consolidated


    

(millions of dollars)

Condensed consolidated statement of income for twelve months ended December 31, 2001

Revenue

                                               

Sales and other operating revenue, including excise taxes

  

$

28,800

  

  $

—  

    

$

—  

 

  

$

179,915

  

$

—    

 

  

$

208,715

Earnings from equity interests and other revenue

  

 

13,427

  

 

—  

    

 

32

 

  

 

3,708

  

 

(13,097

)

  

 

4,070

Intercompany revenue

  

 

6,252

  

 

584

    

 

62

 

  

 

106,498

  

 

(113,396

)

  

 

    

  

    


  

  


  

Total revenue

  

 

48,479

  

 

584

    

 

94

 

  

 

290,121

  

 

(126,493

)

  

 

212,785

    

  

    


  

  


  

Costs and other deductions

                                               

Crude oil and product purchases

  

 

19,483

  

 

—  

    

 

—  

 

  

 

174,455

  

 

(101,681

)

  

 

92,257

Operating expenses

  

 

5,696

  

 

3

    

 

1

 

  

 

17,192

  

 

(5,149

)

  

 

17,743

Selling, general and administrative expenses

  

 

2,158

  

 

2

    

 

—  

 

  

 

10,800

  

 

(62

)

  

 

12,898

Depreciation and depletion

  

 

1,584

  

 

5

    

 

3

 

  

 

6,256

  

 

   —  

 

  

 

7,848

Exploration expenses, including dry holes

  

 

125

  

 

—  

    

 

—  

 

  

 

1,050

  

 

—  

 

  

 

1,175

Merger related expenses

  

 

89

  

 

—  

    

 

—  

 

  

 

771

  

 

(112

)

  

 

748

Interest expense

  

 

1,043

  

 

531

    

 

114

 

  

 

4,924

  

 

(6,319

)

  

 

293

Excise taxes

  

 

1,957

  

 

—  

    

 

—  

 

  

 

19,950

  

 

—  

 

  

 

21,907

Other taxes and duties

  

 

14

  

 

—  

    

 

—  

 

  

 

33,363

  

 

—  

 

  

 

33,377

Income applicable to minority and preferred interests

  

 

—  

  

 

—  

    

 

—  

 

  

 

569

  

 

—  

 

  

 

569

    

  

    


  

  


  

Total costs and other deductions

  

 

32,149

  

 

541

    

 

118

 

  

 

269,330

  

 

(113,323

)

  

 

188,815

    

  

    


  

  


  

Income before income taxes

  

 

16,330

  

 

43

    

 

(24

)

  

 

20,791

  

 

(13,170

)

  

 

23,970

Income taxes

  

 

1,327

  

 

15

    

 

(20

)

  

 

7,645

  

 

  —  

 

  

 

8,967

    

  

    


  

  


  

Income from continuing operations

  

 

15,003

  

 

28

    

 

(4

)

  

 

13,146

  

 

(13,170

)

  

 

15,003

Discontinued operations, net of income tax

  

 

102

  

 

—  

    

 

—  

 

  

 

108

  

 

(108

)

  

 

102

Extraordinary gain, net of income tax

  

 

215

  

 

—  

    

 

—  

 

  

 

—  

  

 

—  

 

  

 

215

    

  

    


  

  


  

Net income

  

$

15,320

  

$

28

    

$

(4

)

  

$

13,254

  

$

(13,278

)

  

$

15,320

    

  

    


  

  


  

 

Condensed consolidated statement of income for twelve months ended December 31, 2000

Revenue

                                       

Sales and other operating revenue, including excise taxes

 

$

36,211

 

$

—  

 

$

—  

 

 

$

191,385

 

$

—  

 

 

$

227,596

Earnings from equity interests and other revenue

 

 

14,209

 

 

—  

 

 

35

 

 

 

3,518

 

 

(13,512

)

 

 

4,250

Intercompany revenue

 

 

4,148

 

 

997

 

 

90

 

 

 

92,832

 

 

(98,067

)

 

 

—  

   

 

 


 

 


 

Total revenue

 

 

54,568

 

 

997

 

 

125

 

 

 

287,735

 

 

(111,579

)

 

 

231,846

   

 

 


 

 


 

Costs and other deductions

                                       

Crude oil and product purchases

 

 

22,790

 

 

—  

 

 

—  

 

 

 

172,974

 

 

(86,851

)

 

 

108,913

Operating expenses

 

 

5,781

 

 

3

 

 

1

 

 

 

16,522

 

 

(4,707

)

 

 

17,600

Selling, general and administrative expenses

 

 

1,978

 

 

—  

 

 

—  

 

 

 

10,203

 

 

(137

)

 

 

12,044

Depreciation and depletion

 

 

1,510

 

 

5

 

 

3

 

 

 

6,483

 

 

—  

 

 

 

8,001

Exploration expenses, including dry holes

 

 

115

 

 

—  

 

 

—  

 

 

 

821

 

 

—  

 

 

 

936

Merger related expenses

 

 

402

 

 

—  

 

 

—  

 

 

 

1,171

 

 

(167

)

 

 

1,406

Interest expense

 

 

1,449

 

 

916

 

 

116

 

 

 

4,313

 

 

(6,205

)

 

 

589

Excise taxes

 

 

2,614

 

 

—  

 

 

—  

 

 

 

19,742

 

 

—  

 

 

 

22,356

Other taxes and duties

 

 

15

 

 

—  

 

 

—  

 

 

 

32,693

 

 

—  

 

 

 

32,708

Income applicable to minority and preferred interests

 

 

—  

 

 

—  

 

 

—  

 

 

 

412

 

 

—  

 

 

 

412

   

 

 


 

 


 

Total costs and other deductions

 

 

36,654

 

 

924

 

 

120

 

 

 

265,334

 

 

(98,067

)

 

 

204,965

   

 

 


 

 


 

Income before income taxes

 

 

17,914

 

 

73

 

 

5

 

 

 

22,401

 

 

(13,512

)

 

 

26,881

Income taxes

 

 

2,108

 

 

20

 

 

(10

)

 

 

8,957

 

 

—  

 

 

 

11,075

   

 

 


 

 


 

Income from continuing operations

 

 

15,806

 

 

53

 

 

15

 

 

 

13,444

 

 

(13,512

)

 

 

15,806

Discontinued operations, net of income tax

 

 

184

 

 

—  

 

 

—  

 

 

 

190

 

 

(190

)

 

 

184

Extraordinary gain, net of income tax

 

 

1,730

 

 

—  

 

 

—  

 

 

 

962

 

 

(962

)

 

 

1,730

   

 

 


 

 


 

Net income

 

$

17,720

 

  $

53

 

$

15

 

 

$

14,596

 

$

(14,664

)

 

$

17,720

   

 

 


 

 


 

 

51


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

 

    

Exxon Mobil

Corporation

Parent

Guarantor


      

Exxon

Capital

Corporation


    

SeaRiver

Maritime

Financial

Holdings, Inc.


    

All Other

Subsidiaries


  

Consolidating

and

Eliminating

Adjustments


    

Consolidated


 
    

(millions of dollars)

 

Condensed consolidated balance sheet for year ended December 31, 2002

                                   

Cash and cash equivalents

  

$

710

 

    

$

—  

    

$

—  

 

  

$

6,519

  

$

—  

 

  

$

7,229

 

Notes and accounts receivable – net

  

 

3,827

 

    

 

—  

    

 

—  

 

  

 

17,336

  

 

—  

 

  

 

21,163

 

Inventories

  

 

964

 

    

 

—  

    

 

—  

 

  

 

7,104

  

 

—  

 

  

 

8,068

 

Prepaid taxes and expenses

  

 

65

 

    

 

—  

    

 

—  

 

  

 

1,766

  

 

—  

 

  

 

1,831

 

    


    

    


  

  


  


Total current assets

  

 

5,566

 

    

 

—  

    

 

—  

 

  

 

32,725

  

 

—  

 

  

 

38,291

 

Investments and advances

  

 

101,694

 

    

 

—  

    

 

400

 

  

 

336,061

  

 

(426,044

)

  

 

12,111

 

Property, plant and equipment – net

  

 

16,922

 

    

 

104

    

 

3

 

  

 

77,911

  

 

—  

 

  

 

94,940

 

Other long-term assets

  

 

2,421

 

    

 

—  

    

 

121

 

  

 

4,760

  

 

—  

 

  

 

7,302

 

Intercompany receivables

  

 

16,234

 

    

 

1,395

    

 

1,490

 

  

 

295,909

  

 

(315,028

)

  

 

—  

 

    


    

    


  

  


  


Total assets

  

$

142,837

 

    

$

1,499

    

$

2,014

 

  

$

747,366

  

$

(741,072

)

  

$

152,644

 

    


    

    


  

  


  


Notes and loans payable

  

$

—  

 

    

$

6

    

$

10

 

  

$

4,077

  

$

—  

 

  

$

4,093

 

Accounts payable and accrued liabilities

  

 

2,844

 

    

 

6

    

 

—  

 

  

 

22,336

  

 

—  

 

  

 

25,186

 

Income taxes payable

  

 

916

 

    

 

1

    

 

—  

 

  

 

2,979

  

 

—  

 

  

 

3,896

 

    


    

    


  

  


  


Total current liabilities

  

 

3,760

 

    

 

13

    

 

10

 

  

 

29,392

  

 

—  

 

  

 

33,175

 

Long-term debt

  

 

1,311

 

    

 

266

    

 

1,101

 

  

 

3,977

  

 

—  

 

  

 

6,655

 

Deferred income tax liabilities

  

 

3,163

 

    

 

31

    

 

301

 

  

 

12,989

  

 

—  

 

  

 

16,484

 

Other long-term liabilities

  

 

5,820

 

    

 

—  

    

 

—  

 

  

 

15,913

  

 

—  

 

  

 

21,733

 

Intercompany payables

  

 

54,186

 

    

 

290

    

 

382

 

  

 

260,170

  

 

(315,028

)

  

 

—  

 

    


    

    


  

  


  


Total liabilities

  

 

68,240

 

    

 

600

    

 

1,794

 

  

 

322,441

  

 

(315,028

)

  

 

78,047

 

Earnings reinvested

  

 

100,961

 

    

 

93

    

 

(174

)

  

 

54,547

  

 

(54,466

)

  

 

100,961

 

Other shareholders’ equity

  

 

(26,364

)

    

 

806

    

 

394

 

  

 

370,378

  

 

(371,578

)

  

 

(26,364

)

    


    

    


  

  


  


Total shareholders’ equity

  

 

74,597

 

    

 

899

    

 

220

 

  

 

424,925

  

 

(426,044

)

  

 

74,597

 

    


    

    


  

  


  


Total liabilities and shareholders’ equity

  

$

142,837

 

    

$

1,499

    

$

2,014

 

  

$

747,366

  

$

(741,072

)

  

$

152,644

 

    


    

    


  

  


  


Condensed consolidated balance sheet for year ended December 31, 2001

                                   

Cash and cash equivalents

  

$

1,375

 

    

$

—  

    

$

—  

 

  

$

5,172

  

$

—  

 

  

$

6,547

 

Notes and accounts receivable – net

  

 

2,458

 

    

 

—  

    

 

—  

 

  

 

17,091

  

 

—  

 

  

 

19,549

 

Inventories

  

 

996

 

    

 

—  

    

 

—  

 

  

 

6,908

  

 

—  

 

  

 

7,904

 

Prepaid taxes and expenses

  

 

155

 

    

 

5

    

 

8

 

  

 

1,513

  

 

—  

 

  

 

1,681

 

    


    

    


  

  


  


Total current assets

  

 

4,984

 

    

 

5

    

 

8

 

  

 

30,684

  

 

—  

 

  

 

35,681

 

Investments and advances

  

 

92,091

 

    

 

—  

    

 

415

 

  

 

317,456

  

 

(399,194

)

  

 

10,768

 

Property, plant and equipment – net

  

 

16,843

 

    

 

108

    

 

6

 

  

 

72,645

  

 

—  

 

  

 

89,602

 

Other long-term assets

  

 

753

 

    

 

—  

    

 

137

 

  

 

6,233

  

 

—  

 

  

 

7,123

 

Intercompany receivables

  

 

8,466

 

    

 

1,365

    

 

1,431

 

  

 

266,527

  

 

(277,789

)

  

 

—  

 

    


    

    


  

  


  


Total assets

  

$

123,137

 

    

$

1,478

    

$

1,997

 

  

$

693,545

  

$

(676,983

)

  

$

143,174

 

    


    

    


  

  


  


Notes and loans payable

  

$

—  

 

    

$

35

    

$

10

 

  

$

3,658

  

$

—  

 

  

$

3,703

 

Accounts payable and accrued liabilities

  

 

2,735

 

    

 

6

    

 

1

 

  

 

20,120

  

 

—  

 

  

 

22,862

 

Income taxes payable

  

 

767

 

    

 

—  

    

 

—  

 

  

 

2,782

  

 

—  

 

  

 

3,549

 

    


    

    


  

  


  


Total current liabilities

  

 

3,502

 

    

 

41

    

 

11

 

  

 

26,560

  

 

—  

 

  

 

30,114

 

Long-term debt

  

 

1,258

 

    

 

266

    

 

1,008

 

  

 

4,567

  

 

—  

 

  

 

7,099

 

Deferred income tax liabilities

  

 

2,989

 

    

 

33

    

 

302

 

  

 

13,035

  

 

—  

 

  

 

16,359

 

Other long-term liabilities

  

 

4,373

 

    

 

—  

    

 

—  

 

  

 

12,068

  

 

—  

 

  

 

16,441

 

Intercompany payables

  

 

37,854

 

    

 

248

    

 

382

 

  

 

239,305

  

 

(277,789

)

  

 

—  

 

    


    

    


  

  


  


Total liabilities

  

 

49,976

 

    

 

588

    

 

1,703

 

  

 

295,535

  

 

(277,789

)

  

 

70,013

 

Earnings reinvested

  

 

95,718

 

    

 

84

    

 

(100

)

  

 

48,907

  

 

(48,891

)

  

 

95,718

 

Other shareholders’ equity

  

 

(22,557

)

    

 

806

    

 

394

 

  

 

349,103

  

 

(350,303

)

  

 

(22,557

)

    


    

    


  

  


  


Total shareholders’ equity

  

 

73,161

 

    

 

890

    

 

294

 

  

 

398,010

  

 

(399,194

)

  

 

73,161

 

    


    

    


  

  


  


Total liabilities and shareholders’ equity

  

$

123,137

 

    

$

1,478

    

$

1,997

 

  

$

693,545

  

$

(676,983

)

  

$

143,174

 

    


    

    


  

  


  


 

52


Table of Contents

 

    

Exxon Mobil Corporation Parent Guarantor


   

Exxon

Capital

Corporation


    

SeaRiver Maritime Financial Holdings, Inc.


   

All Other Subsidiaries


    

Consolidating and Eliminating Adjustments


    

Consolidated


 
    

(millions of dollars)

        

Condensed consolidated statement of cash flows for twelve months ended December 31, 2002

Cash provided by/(used in) operating activities

  

$

1,970

 

 

$

17

 

  

$

69

 

 

$

19,905

 

  

$

(693

)

  

$

21,268

 

    


 


  


 


  


  


Cash flows from investing activities

                                                   

Additions to property, plant and equipment

  

 

(1,727

)

 

 

—  

 

  

 

—  

 

 

 

(9,710

)

  

 

—  

 

  

 

(11,437

)

Sales of long-term assets

  

 

168

 

 

 

—  

 

  

 

—  

 

 

 

2,625

 

  

 

—  

 

  

 

2,793

 

Net intercompany investing

  

 

9,640

 

 

 

(30

)

  

 

(59

)

 

 

(9,646

)

  

 

95

 

  

 

—  

 

All other investing, net

  

 

—  

 

 

 

—  

 

  

 

—  

 

 

 

(1,114

)

  

 

—  

 

  

 

(1,114

)

    


 


  


 


  


  


Net cash provided by/(used in) investing activities

  

 

8,081

 

 

 

(30

)

  

 

(59

)

 

 

(17,845

)

  

 

95

 

  

 

(9,758

)

    


 


  


 


  


  


Cash flows from financing activities

                                                   

Additions to short- and long-term debt

  

 

—  

 

 

 

—  

 

  

 

—  

 

 

 

1,147

 

  

 

—  

 

  

 

1,147

 

Reductions in short- and long-term debt

  

 

—  

 

 

 

—  

 

  

 

(10

)

 

 

(1,163

)

  

 

—  

 

  

 

(1,173

)

Additions/(reductions) in debt with less than 90 day maturity

  

 

—  

 

 

 

(29

)

  

 

—  

 

 

 

(252

)

  

 

—  

 

  

 

(281

)

Cash dividends

  

 

(6,217

)

 

 

—  

 

  

 

—  

 

 

 

(693

)

  

 

693

 

  

 

(6,217

)

Common stock acquired

  

 

(4,798

)

 

 

—  

 

  

 

—  

 

 

 

—  

 

  

 

—  

 

  

 

(4,798

)

Net intercompany financing activity

  

 

—  

 

 

 

42

 

  

 

—  

 

 

 

53

 

  

 

(95

)

  

 

—  

 

All other financing, net

  

 

299

 

 

 

—  

 

  

 

—  

 

 

 

(330

)

  

 

—  

 

  

 

(31

)

    


 


  


 


  


  


Net cash provided by/(used in) financing activities

  

 

(10,716

)

 

 

13

 

  

 

(10

)

 

 

(1,238

)

  

 

598

 

  

 

(11,353

)

    


 


  


 


  


  


Effects of exchange rate changes on cash

  

 

—  

 

 

 

—  

 

  

 

—  

 

 

 

525

 

  

 

—  

 

  

 

525

 

    


 


  


 


  


  


Increase/(decrease) in cash and cash equivalents

  

$

(665

)

 

$

—  

 

  

$

—  

 

 

$

1,347

 

  

$

—  

 

  

$

682

 

    


 


  


 


  


  


Condensed consolidated statement of cash flows for twelve months ended December 31, 2001

Cash provided by/(used in) operating activities

  

$

7,277

 

 

$

12

 

  

$

113

 

 

$

16,239

 

  

$

(752

)

  

$

22,889

 

    


 


  


 


  


  


Cash flows from investing activities

                                                   

Additions to property, plant and equipment

  

 

(2,058

)

 

 

—  

 

  

 

—  

 

 

 

(7,931

)

  

 

—  

 

  

 

(9,989

)

Sales of long-term assets

  

 

536

 

 

 

—  

 

  

 

—  

 

 

 

542

 

  

 

—  

 

  

 

1,078

 

Net intercompany investing

  

 

3,152

 

 

 

17,759

 

  

 

(76

)

 

 

(1,345

)

  

 

(19,490

)

  

 

—  

 

All other investing, net

  

 

(31

)

 

 

 

  

 

—  

 

 

 

731

 

  

 

—  

 

  

 

700

 

    


 


  


 


  


  


Net cash provided by/(used in) investing activities

  

 

1,599

 

 

 

17,759

 

  

 

(76

)

 

 

(8,003

)

  

 

(19,490

)

  

 

(8,211

)

    


 


  


 


  


  


Cash flows from financing activities

                                                   

Additions to short-  and long-term debt

  

 

 

 

 

—  

 

  

 

—  

 

 

 

1,252

 

  

 

—  

 

  

 

1,252

 

Reductions in short-  and long-term debt

  

 

(62

)

 

 

(15

)

  

 

(7

)

 

 

(1,634

)

  

 

—  

 

  

 

(1,718

)

Additions/(reductions) in debt with less than 90 day maturity

  

 

 

 

 

(39

)

  

 

—  

 

 

 

(2,267

)

  

 

—  

 

  

 

(2,306

)

Cash dividends

  

 

(6,254

)

 

 

—  

 

  

 

—  

 

 

 

(752

)

  

 

752

 

  

 

(6,254

)

Common stock acquired

  

 

(5,721

)

 

 

—  

 

  

 

—  

 

 

 

 

  

 

—  

 

  

 

(5,721

)

Net intercompany financing activity

  

 

—  

 

 

 

(17,717

)

  

 

(30

)

 

 

(1,743

)

  

 

19,490

 

  

 

—  

 

All other financing, net

  

 

301

 

 

 

—  

 

  

 

—  

 

 

 

(595

)

  

 

—  

 

  

 

(294

)

    


 


  


 


  


  


Net cash provided by/(used in) financing activities

  

 

(11,736

)

 

 

(17,771

)

  

 

(37

)

 

 

(5,739

)

  

 

20,242

 

  

 

(15,041

)

    


 


  


 


  


  


Effects of exchange rate changes on cash

  

 

—  

 

 

 

—  

 

  

$

—  

 

 

 

(170

)

  

 

—  

 

  

 

(170

)

    


 


  


 


  


  


Increase/(decrease) in cash and cash equivalents

  

$

(2,860

)

 

$

—  

 

  

$

—  

 

 

$

2,327

 

  

$

—  

 

  

$

(533

)

    


 


  


 


  


  


 

53


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

 

    

Exxon Mobil Corporation Parent Guarantor


    

Exxon Capital Corporation


    

SeaRiver Maritime Financial Holdings, Inc.


    

All Other Subsidiaries


    

Consolidating and Eliminating Adjustments


    

Consolidated


 
    

(millions of dollars)

 

Condensed consolidated statement of cash flows for twelve months ended December 31, 2000

Cash provided by/(used in) operating activities

  

$

7,704

 

  

$

61

 

  

$

94

 

  

$

16,063

 

  

$

(985

)

  

$

22,937

 

    


  


  


  


  


  


Cash flows from investing activities

                                                     

Additions to property, plant and equipment

  

 

(1,832

)

  

 

—  

 

  

 

—  

 

  

 

(6,614

)

  

 

—  

 

  

 

(8,446

)

Sales of long-term assets

  

 

1,088

 

  

 

—  

 

  

 

—  

 

  

 

4,682

 

  

 

—  

 

  

 

5,770

 

Net intercompany investing

  

 

6,386

 

  

 

(7,143

)

  

 

(114

)

  

 

(6,285

)

  

 

7,156

 

  

 

—  

 

All other investing, net

  

 

(26

)

  

 

—  

 

  

 

—  

 

  

 

(596

)

  

 

—  

 

  

 

(622

)

    


  


  


  


  


  


Net cash provided by/(used in) investing activities

  

 

5,616

 

  

 

(7,143

)

  

 

(114

)

  

 

(8,813

)

  

 

7,156

 

  

 

(3,298

)

    


  


  


  


  


  


Cash flows from financing activities

                                                     

Additions to short-  and long-term debt

  

 

23

 

  

 

—  

 

  

 

—  

 

  

 

715

 

  

 

—  

 

  

 

738

 

Reductions in short-  and long-term debt

  

 

(247

)

  

 

(214

)

  

 

(7

)

  

 

(2,846

)

  

 

—  

 

  

 

(3,314

)

Additions/(reductions) in debt with less than 90 day maturity

  

 

(990

)

  

 

16

 

  

 

—  

 

  

 

(2,155

)

  

 

—  

 

  

 

(3,129

)

Cash dividends

  

 

(6,123

)

  

 

—  

 

  

 

—  

 

  

 

(985

)

  

 

985

 

  

 

(6,123

)

Common stock acquired

  

 

(2,352

)

  

 

—  

 

  

 

—  

 

  

 

 

  

 

—  

 

  

 

(2,352

)

Net intercompany financing activity

  

 

—  

 

  

 

7,280

 

  

 

27

 

  

 

(151

)

  

 

(7,156

)

  

 

—  

 

All other financing, net

  

 

493

 

  

 

—  

 

  

 

—  

 

  

 

(478

)

  

 

—  

 

  

 

15

 

    


  


  


  


  


  


Net cash provided by/(used in) financing activities

  

 

(9,196

)

  

 

7,082

 

  

 

20

 

  

 

(5,900

)

  

 

(6,171

)

  

 

(14,165

)

    


  


  


  


  


  


Effects of exchange rate changes on cash

  

 

—  

 

  

 

—  

 

  

 

—  

 

  

 

(82

)

  

 

—  

 

  

 

(82

)

    


  


  


  


  


  


Increase/(decrease) in cash and cash equivalents

  

$

4,124

 

  

$

—  

 

  

$

—  

 

  

$

1,268

 

  

$

—  

 

  

$

5,392

 

    


  


  


  


  


  


 

54


Table of Contents

16. Incentive Program

 

The 1993 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted over a 10-year period that expires in April 2003 to eligible employees of the corporation and those affiliates at least 50 percent owned. The number of shares of stock which may be awarded each year under the 1993 Incentive Program may not exceed seven tenths of one percent (0.7%) of the total number of shares of common stock of the corporation outstanding (excluding shares held by the corporation) on December 31 of the preceding year. If the total number of shares effectively granted in any year is less than the maximum number of shares allowable, the balance may be carried over thereafter. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Shares available for granting under the 1993 Incentive Program were 146,328 thousand at the beginning of 2002 and 135,737 thousand at the end of 2002. The Board of Directors of the corporation subsequently reduced the number of shares available for grant during the remaining term of the 1993 Incentive Program to 2 million shares and no shares were granted in 2003 prior to this reduction.

 

Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. Most of the options and SARs normally first become exercisable one year following the date of grant.

 

In 2002, there were no stock options or SARs granted. Instead, long-term incentive awards totaling 11,072 thousand shares of restricted common stock and restricted common stock units were granted in November 2002. These shares with a value of $361 million at the grant date will be issued to employees from treasury stock in 2003 and subsequent years. The price of the stock on the date of grant was $34.64 and the total compensation expense of $384 million (including units with a value of $23 million that will be settled in cash) will be recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. A small number of awards granted to certain employees have longer vesting periods. At December 31, 2002, 2,382 thousand shares of restricted common stock were outstanding from grants made in prior years.

 

The following table summarizes information about restricted stock and restricted stock units, including those shares from former Mobil plans (shares in thousands):

 

Restricted Stock and Units


  

2002


    

2001


    

2000


 

Restricted stock and units granted

  

11,072

 

  

348

 

  

397

 

Restricted stock issued and outstanding at end of year

  

2,382

 

  

2,559

 

  

2,438

 

 

Changes that occurred in stock options in 2002, 2001 and 2000, including the former Mobil plans, are summarized below (shares in thousands):

 

   

2002


   

2001


   

2000


 

Stock Options


 

Shares


   

Avg.

Exercise Price


   

Shares


   

Avg.

Exercise Price


   

Shares


   

Avg.

Exercise Price


 

Outstanding at beginning of year

 

265,695

 

 

$

30.54

 

 

248,680

 

 

$

28.70

 

 

242,232

 

 

$

24.81

 

Granted

 

 

 

 

 

 

34,717

 

 

 

37.12

 

 

36,224

 

 

 

45.19

 

Exercised

 

(18,334

)

 

 

16.18

 

 

(16,949

)

 

 

16.63

 

 

(28,714

)

 

 

16.35

 

Expired/Canceled

 

(366

)

 

 

40.47

 

 

(753

)

 

 

39.44

 

 

(1,062

)

 

 

37.13

 

   

         

         

       

Outstanding at end of year

 

246,995

 

 

 

31.59

 

 

265,695

 

 

 

30.54

 

 

248,680

 

 

 

28.70

 

Exercisable at end of year

 

243,548

 

 

 

31.46

 

 

221,405

 

 

 

29.29

 

 

195,144

 

 

 

25.95

 

 

The following table summarizes information about stock options outstanding, including those from former Mobil plans, at December 31, 2002 (shares in thousands):

 

Options Outstanding


 

Options Exercisable


Exercise Price Range


 

Shares


  

Avg. Remaining

Contractual Life


    

Avg. Exercise Price


 

Shares


    

Avg. Exercise Price


$11.97-16.54

 

34,254

  

1.9 years

    

$15.46

 

34,254

    

$15.46

  19.06-27.71

 

60,085

  

4.2 years

    

22.98

 

60,085

    

22.98

  29.18-45.22

 

152,656

  

7.2 years

    

38.60

 

149,209

    

38.54

                            

Total

 

246,995

  

5.7 years

    

31.59

 

243,548

    

31.46

 

 

55


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

17. Litigation and Other Contingencies

 

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.

 

On January 29, 1997, a settlement agreement was concluded resolving all remaining matters between the corporation and various insurers arising from the Valdez accident. Under terms of this settlement, ExxonMobil received $480 million. Final income statement recognition of this settlement continues to be deferred in view of uncertainty regarding the ultimate cost to the corporation of the Valdez accident.

 

The ultimate cost to ExxonMobil from the lawsuits arising from the Exxon Valdez grounding is not possible to predict and may not be resolved for a number of years.

 

A dispute with a Dutch affiliate concerning an overlift of natural gas by a German affiliate was resolved by payments by the German affiliate pursuant to an arbitration award. The German affiliate had paid royalties on the excess gas and recovered the royalties in 2001. The only substantive issue remaining is the taxes payable on the final compensation for the overlift. Resolution of this issue will not have a materially adverse effect upon the corporation’s operations or financial condition.

 

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 is not expected to have a materially adverse effect upon the corporation’s operations or financial condition.

 

Claims for substantial amounts have been made against ExxonMobil and certain of its consolidated subsidiaries in other pending lawsuits, the outcome of which is not expected to have a materially adverse effect upon the corporation’s operations or financial condition.

 

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. 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.

 

        Additionally, the corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the corporation’s operations or financial condition. The present value of unconditional purchase obligations was $2,463 million at December 31, 2002. On an undiscounted basis, including imputed interest of $1,186 million, these commitments totaled $3,649 million. Unconditional purchase obligations as defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.

 

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.

 

56


Table of Contents

 

18. Annuity Benefits and Other Postretirement Benefits

 

   

Annuity Benefits


   

Other

Postretirement

Benefits


 
   

U.S.


   

Non-U.S.


   
   

2002


   

2001


   

2000


   

2002


   

2001


   

2000


   

  2002  


   

  2001  


   

  2000  


 
   

(millions of dollars)

 

Components of net benefit cost

                                                               

Service cost

 

$

224

 

 

$

200

 

 

$

214

 

 

$

257

 

 

$

232

 

 

$

245

 

 

$

30

 

 

$

27

 

 

$

24

 

Interest cost

 

 

577

 

 

 

579

 

 

 

592

 

 

 

621

 

 

 

598

 

 

 

603

 

 

 

220

 

 

 

205

 

 

 

201

 

Expected return on plan assets

 

 

(501

)

 

 

(623

)

 

 

(726

)

 

 

(561

)

 

 

(629

)

 

 

(641

)

 

 

(38

)

 

 

(43

)

 

 

(51

)

Amortization of actuarial loss/(gain) and prior service cost

 

 

121

 

 

 

(25

)

 

 

(168

)

 

 

190

 

 

 

78

 

 

 

55

 

 

 

57

 

 

 

4

 

 

 

—  

 

Net pension enhancement and curtailment/settlement expense

 

 

49

 

 

 

14

 

 

 

(175

)

 

 

18

 

 

 

27

 

 

 

77

 

 

 

—  

 

 

 

—  

 

 

 

(5

)

   


 


 


 


 


 


 


 


 


Net benefit cost

 

$

470

 

 

$

145

 

 

$

(263

)

 

$

525

 

 

$

306

 

 

$

339

 

 

$

269

 

 

$

193

 

 

$

169

 

   


 


 


 


 


 


 


 


 


 

Costs for defined contribution plans were $191 million, $132 million and $67 million in 2002, 2001 and 2000, respectively.

 

   

Annuity Benefits


   

Other

Postretirement

Benefits


 
   

U.S.


   

Non-U.S.


   
   

2002


   

2001


   

2002


   

2001


   

2002


   

2001


 
   

(millions of dollars)

 

Change in benefit obligation (1)

                                               

Benefit obligation at January 1

 

$

8,213

 

 

$

7,651

 

 

$

11,206

 

 

$

11,063

 

 

$

3,131

 

 

$

2,942

 

Service cost

 

 

224

 

 

 

200

 

 

 

257

 

 

 

232

 

 

 

30

 

 

 

27

 

Interest cost

 

 

577

 

 

 

579

 

 

 

621

 

 

 

598

 

 

 

220

 

 

 

205

 

Actuarial loss/(gain)

 

 

990

 

 

 

638

 

 

 

860

 

 

 

540

 

 

 

207

 

 

 

7

 

Benefits paid

 

 

(876

)

 

 

(868

)

 

 

(747

)

 

 

(710

)

 

 

(302

)

 

 

(258

)

Foreign exchange rate changes

 

 

—  

 

 

 

—  

 

 

 

1,244

 

 

 

(678

)

 

 

2

 

 

 

(12

)

Other

 

 

11

 

 

 

13

 

 

 

102

 

 

 

161

 

 

 

208

 

 

 

220

 

   


 


 


 


 


 


Benefit obligation at December 31

 

$

9,139

 

 

$

8,213

 

 

$

13,543

 

 

$

11,206

 

 

$

3,496

 

 

$

3,131

 

   


 


 


 


 


 


Change in plan assets

                                               

Fair value at January 1

 

$

5,415

 

 

$

6,795

 

 

$

6,755

 

 

$

7,780

 

 

$

395

 

 

$

446

 

Actual return on plan assets

 

 

(570

)

 

 

(647

)

 

 

(827

)

 

 

(424

)

 

 

(31

)

 

 

(34

)

Foreign exchange rate changes

 

 

—  

 

 

 

—  

 

 

 

647

 

 

 

(422

)

 

 

—  

 

 

 

—  

 

Payments directly to participants

 

 

163

 

 

 

135

 

 

 

259

 

 

 

225

 

 

 

203

 

 

 

187

 

Company contribution

 

 

460

 

 

 

—  

 

 

 

509

 

 

 

299

 

 

 

33

 

 

 

32

 

Benefits paid

 

 

(876

)

 

 

(868

)

 

 

(747

)

 

 

(710

)

 

 

(302

)

 

 

(258

)

Other

 

 

24

 

 

 

—  

 

 

 

139

 

 

 

7

 

 

 

47

 

 

 

22

 

   


 


 


 


 


 


Fair value at December 31

 

$

4,616

 

 

$

5,415

 

 

$

6,735

 

 

$

6,755

 

 

$

345

 

 

$

395

 

   


 


 


 


 


 


Assets in excess of / (less than) benefit obligation

                                               

Balance at December 31

 

$

(4,523

)

 

$

(2,798

)

 

$

(6,808

)

 

$

(4,451

)

 

$

(3,151

)

 

$

(2,736

)

Unrecognized net transition liability/(asset)

 

 

—  

 

 

 

(2

)

 

 

30

 

 

 

34

 

 

 

—  

 

 

 

—  

 

Unrecognized net actuarial loss/(gain)

 

 

3,064

 

 

 

1,142

 

 

 

4,340

 

 

 

2,002

 

 

 

377

 

 

 

108

 

Unrecognized prior service cost

 

 

231

 

 

 

248

 

 

 

323

 

 

 

308

 

 

 

490

 

 

 

381

 

Intangible asset

 

 

(322

)

 

 

(226

)

 

 

(317

)

 

 

(135

)

 

 

—  

 

 

 

—  

 

Equity of minority shareholders

 

 

—  

 

 

 

—  

 

 

 

(211

)

 

 

(82

)

 

 

—  

 

 

 

—  

 

Minimum pension liability adjustment

 

 

(1,790

)

 

 

(144

)

 

 

(2,957

)

 

 

(805

)

 

 

—  

 

 

 

—  

 

   


 


 


 


 


 


Prepaid/(accrued) benefit cost

 

$

(3,340

)

 

$

(1,780

)

 

$

(5,600

)

 

$

(3,129

)

 

$

(2,284

)

 

$

(2,247

)

   


 


 


 


 


 


Assumptions as of December 31 (percent)

                                               

Discount rate

 

 

6.75

 

 

 

7.25

 

 

 

2.1-6.5

 

 

 

2.6-6.8

 

 

 

6.75

 

 

 

7.25

 

Long-term rate of compensation increase

 

 

3.50

 

 

 

3.50

 

 

 

2.4-4.2

 

 

 

2.8-4.3

 

 

 

3.50

 

 

 

3.50

 

Long-term rate of return on funded assets

 

 

9.50

 

 

 

9.50

 

 

 

6.5-8.8

 

 

 

6.5-10.0

 

 

 

9.50

 

 

 

9.50

 

 

(1) The term benefit obligation means “projected benefit obligation” as defined by Statement of Financial Accounting Standards No. 87 (FAS 87) “Employers’ Accounting for Pensions” for annuity benefits and “accumulated postretirement benefit obligation” as defined by FAS 106 “Employers’ Accounting for Postretirement Benefits Other than Pensions” for other postretirement benefits.

 

 

57


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

    

Annuity Benefits


    

U.S.


  

Non-U.S.


    

2002


  

2001


  

2002


  

2001


    

(millions of dollars)

For funded pension plans with accumulated benefit obligations in excess of plan assets:

                           

Projected benefit obligation

  

$

7,948

  

$

7,140

  

$

8,719

  

$

4,142

Accumulated benefit obligation

  

 

6,907

  

 

6,226

  

 

8,100

  

 

3,828

Fair value of plan assets

  

 

4,476

  

 

5,247

  

 

5,158

  

 

2,855

For unfunded plans covered by book reserves:

                           

Projected benefit obligation

  

$

1,082

  

$

963

  

$

3,446

  

$

3,197

Accumulated benefit obligation

  

 

970

  

 

859

  

 

3,042

  

 

2,854

 

As a result of losses on plan assets driven by the downturn in worldwide equity markets and decreases in the discount rate used to value the pension liability, increases to the additional minimum pension liability adjustment resulted in after-tax charges of $2,425 million and $225 million to the “accumulated other nonowner changes in equity” account included in “Shareholders’ equity” on the consolidated balance sheet in 2002 and 2001, respectively. This adjustment is required so that the pension liability recorded on the corporation’s books is at least equal to the unfunded accumulated benefit obligation for each pension plan.

 

The data on the preceding page conform with current accounting standards that specify use of a discount rate at which postretirement liabilities could be effectively settled. The discount rate for calculating year-end postretirement liabilities is based on the year-end rate of interest on high quality bonds. The return on the annuity fund’s actual portfolio of assets has historically been higher than bonds as the majority of pension assets are invested in equities. The expected U.S. earnings rate of 9.5 per cent used in 2002 compares to an actual rate earned in the U.S. over the past decade of 10 percent. 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.

 

All funded U.S. plans are fully funded in 2002 under the standards set by the Department of Labor and the Internal Revenue Service. The corporation will continue to make contributions as necessary to maintain the fully funded status of these plans according to those standards. Contributions to U.S. plans totaled $460 million in 2002 and contributions to non-U.S. plans totaled $509 million. Certain smaller U.S. plans and a number of non-U.S. plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. Book reserves have been established for these plans to provide for future benefit payments. 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.

 

19. Disclosures about Segments and Related Information

 

The functional segmentation of operations reflected on page 59 is consistent with ExxonMobil’s internal reporting. Earnings include special items and transfers are at estimated market prices. Consistent with a change in internal organization in 2002, earnings from the electric power business, previously reported in the other segment, are now shown within non-U.S. upstream. Earnings from the divested coal and minerals businesses are shown as discontinued operations and are included within the other segment. Corresponding items of segment information have been revised for all earlier periods shown on page 59. In addition to discontinued operations, the other segment includes corporate and financing activities, merger expenses and extraordinary gains from required asset divestitures. The interest revenue amount relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt related interest expense of $207 million, $105 million and $142 million in 2002, 2001 and 2000, respectively. Non-U.S. upstream after-tax earnings in 2002 include a special charge of $215 million reflecting the impact on deferred taxes from the 10 percent supplementary tax enacted in the United Kingdom in July 2002.

 

58


Table of Contents

 

   

Upstream


 

Downstream


  

Chemicals


 

All Other


   

Corporate Total


   

U.S.


 

Non-U.S.


 

U.S.


   

Non-U.S.


  

U.S.


 

Non-U.S.


   
   

(millions of dollars)

As of December 31, 2002

                                                    

Earnings after income tax

 

$

2,524

 

$

7,074

 

$

693

 

 

$

607

  

$

384

 

$

446

 

$

(268

)

 

$

11,460

Earnings of equity companies included above

 

 

391

 

 

1,761

 

 

(40

)

 

 

27

  

 

24

 

 

175

 

 

(272

)

 

 

2,066

Sales and other operating revenue

 

 

3,896

 

 

12,588

 

 

48,865

 

 

 

119,167

  

 

6,891

 

 

9,517

 

 

25

 

 

 

200,949

Intersegment revenue

 

 

5,020

 

 

12,144

 

 

4,540

 

 

 

15,157

  

 

2,666

 

 

2,486

 

 

269

 

 

 

—  

Depreciation and depletion expense

 

 

1,597

 

 

3,551

 

 

583

 

 

 

1,399

  

 

414

 

 

348

 

 

418

 

 

 

8,310

Interest revenue

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

  

 

—  

 

 

—  

 

 

297

 

 

 

297

Interest expense

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

  

 

—  

 

 

—  

 

 

398

 

 

 

398

Income taxes

 

 

1,321

 

 

5,162

 

 

359

 

 

 

44

  

 

165

 

 

189

 

 

(741

)

 

 

6,499

Additions to property, plant and equipment

 

 

1,902

 

 

6,122

 

 

884

 

 

 

1,357

  

 

448

 

 

181

 

 

543

 

 

 

11,437

Investments in equity companies

 

 

1,360

 

 

2,867

 

 

246

 

 

 

795

  

 

265

 

 

1,399

 

 

—  

 

 

 

6,932

Total assets

 

 

19,385

 

 

47,040

 

 

13,562

 

 

 

41,530

  

 

7,543

 

 

10,581

 

 

13,003

 

 

 

152,644

   

 

 


 

  

 

 


 

As of December 31, 2001

                                                    

Earnings after income tax

 

$

3,933

 

$

6,803

 

$

1,924

 

 

$

2,303

  

$

398

 

$

484

 

$

(525

)

 

$

15,320

Earnings of equity companies included above

 

 

482

 

 

1,797

 

 

89

 

 

 

12

  

 

19

 

 

118

 

 

(343

)

 

 

2,174

Sales and other operating revenue

 

 

5,678

 

 

12,889

 

 

50,988

 

 

 

123,197

  

 

6,918

 

 

9,025

 

 

20

 

 

 

208,715

Intersegment revenue

 

 

5,408

 

 

12,322

 

 

4,115

 

 

 

16,880

  

 

2,186

 

 

2,284

 

 

178

 

 

 

—  

Depreciation and depletion expense

 

 

1,447

 

 

3,221

 

 

598

 

 

 

1,476

  

 

408

 

 

289

 

 

409

 

 

 

7,848

Interest revenue

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

  

 

—  

 

 

—  

 

 

380

 

 

 

380

Interest expense

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

  

 

—  

 

 

—  

 

 

293

 

 

 

293

Income taxes

 

 

2,089

 

 

5,546

 

 

1,075

 

 

 

744

  

 

82

 

 

149

 

 

(718

)

 

 

8,967

Additions to property, plant and equipment

 

 

1,985

 

 

4,520

 

 

827

 

 

 

1,239

  

 

390

 

 

243

 

 

785

 

 

 

9,989

Investments in equity companies

 

 

1,371

 

 

2,061

 

 

329

 

 

 

831

  

 

333

 

 

1,291

 

 

—  

 

 

 

6,216

Total assets

 

 

18,896

 

 

40,901

 

 

12,850

 

 

 

37,617

  

 

7,495

 

 

9,524

 

 

15,891

 

 

 

143,174

   

 

 


 

  

 

 


 

As of December 31, 2000

                                                    

Earnings after income tax

 

$

4,542

 

$

8,143

 

$

1,561

 

 

$

1,857

  

$

644

 

$

517

 

$

456

 

 

$

17,720

Earnings of equity companies included above

 

 

753

 

 

1,731

 

 

71

 

 

 

74

  

 

35

 

 

139

 

 

(369

)

 

 

2,434

Sales and other operating revenue

 

 

5,735

 

 

15,774

 

 

56,080

 

 

 

132,483

  

 

8,198

 

 

9,303

 

 

23

 

 

 

227,596

Intersegment revenue

 

 

6,557

 

 

15,654

 

 

8,631

 

 

 

11,684

  

 

2,905

 

 

2,398

 

 

181

 

 

 

—  

Depreciation and depletion expense

 

 

1,426

 

 

3,469

 

 

594

 

 

 

1,489

  

 

397

 

 

281

 

 

345

 

 

 

8,001

Interest revenue

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

  

 

—  

 

 

—  

 

 

258

 

 

 

258

Interest expense

 

 

—  

 

 

—  

 

 

—  

 

 

 

—  

  

 

—  

 

 

—  

 

 

589

 

 

 

589

Income taxes

 

 

2,482

 

 

7,136

 

 

889

 

 

 

850

  

 

344

 

 

210

 

 

(836

)

 

 

11,075

Additions to property, plant and equipment

 

 

1,518

 

 

3,501

 

 

966

 

 

 

926

  

 

288

 

 

458

 

 

789

 

 

 

8,446

Investments in equity companies

 

 

1,261

 

 

1,984

 

 

264

 

 

 

1,456

  

 

492

 

 

1,395

 

 

12

 

 

 

6,864

Total assets

 

 

18,925

 

 

40,447

 

 

13,516

 

 

 

42,422

  

 

8,047

 

 

10,234

 

 

15,409

 

 

 

149,000

   

 

 


 

  

 

 


 

 

Geographic sales and other operating revenue


  

2002


  

2001


  

2000


    

(millions of dollars)

United States

  

$

59,675

  

$

63,603

  

$

70,036

Non-U.S.

  

 

141,274

  

 

145,112

  

 

157,560

    

  

  

Total

  

$

200,949

  

$

208,715

  

$

227,596

Significant non-U.S. revenue sources include:

                    

Japan

  

$

19,300

  

$

21,788

  

$

24,520

United Kingdom

  

 

17,701

  

 

18,628

  

 

19,904

Canada

  

 

14,087

  

 

14,912

  

 

16,059

Geographic long-lived assets


  

2002


  

2001


  

2000


    

(millions of dollars)

United States

  

$

34,138

  

$

33,637

  

$

33,087

Non-U.S.

  

 

60,802

  

 

55,965

  

 

56,742

    

  

  

Total

  

$

94,940

  

$

89,602

  

$

89,829

Significant non-U.S. long-lived assets include:

                    

United Kingdom

  

$

9,030

  

$

8,390

  

$

9,024

Canada

  

 

8,469

  

 

7,862

  

 

7,922

Norway

  

 

6,449

  

 

4,627

  

 

4,383

 

59


Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

20. Income, Excise and Other Taxes

 

   

2002


 

2001


 

2000


   

United States


 

Non-U.S.


   

Total


 

United States


 

Non-U.S.


 

Total


 

United States


 

Non-U.S.


   

Total


   

(millions of dollars)

     

Income taxes

                                                         

Federal or non-U.S.

                                                         

Current

 

$

351

 

$

5,618

 

 

$

5,969

 

$

1,729

 

$

6,084

 

$

7,813

 

$

2,635

 

$

7,972

 

 

$

10,607

Deferred – net

 

 

635

 

 

(288

)

 

 

347

 

 

712

 

 

122

 

 

834

 

 

433

 

 

(338

)

 

 

95

U.S. tax on non-U.S. operations

 

 

62

 

 

 

 

 

62

 

 

91

 

 

 

 

91

 

 

64

 

 

 

 

 

64

   

 


 

 

 

 

 

 


 

   

$

1,048

 

$

5,330

 

 

$

6,378

 

$

2,532

 

$

6,206

 

$

8,738

 

$

3,132

 

$

7,634

 

 

$

10,766

State

 

 

121

 

 

 

 

 

121

 

 

229

 

 

 

 

229

 

 

309

 

 

 

 

 

309

   

 


 

 

 

 

 

 


 

Total income taxes

 

$

1,169

 

$

5,330

 

 

$

6,499

 

$

2,761

 

$

6,206

 

$

8,967

 

$

3,441

 

$

7,634

 

 

$

11,075

Excise taxes

 

 

7,174

 

 

14,866

 

 

 

22,040

 

 

7,030

 

 

14,877

 

 

21,907

 

 

6,997

 

 

15,359

 

 

 

22,356

All other taxes and duties

 

 

1,120

 

 

34,626

 

 

 

35,746

 

 

1,177

 

 

34,476

 

 

35,653

 

 

1,253

 

 

33,674

 

 

 

34,927

   

 


 

 

 

 

 

 


 

Total

 

$

9,463

 

$

54,822

 

 

$

64,285

 

$

10,968

 

$

55,559

 

$

66,527

 

$

11,691

 

$

56,667

 

 

$

68,358

   

 


 

 

 

 

 

 


 

 

All other taxes and duties include taxes reported in operating and selling, general and administrative expenses. The above provisions for deferred income taxes include net (charges)/credits for the effect of changes in tax laws and rates of $(194) million in 2002, $31 million in 2001 and $84 million in 2000. Income taxes (charged)/credited directly to shareholders’ equity were:

 

    

2002


    

2001


  

2000


    

(millions of dollars)

Cumulative foreign exchange translation adjustment

  

$

(331

)

  

$

102

  

$

221

Minimum pension liability adjustment

  

 

1,373

 

  

 

139

  

 

27

Unrealized gains and losses on stock investments

  

 

(8

)

  

 

40

  

 

57

Other components of shareholders’ equity

  

 

86

 

  

 

83

  

 

111

 

The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2002, 2001 and 2000, is as follows:

 

    

2002


    

2001


    

2000


 
    

(millions of dollars)

 

Earnings before Federal and non-U.S. income taxes

                          

United States

  

$

4,340

 

  

$

8,315

 

  

$

9,021

 

Non-U.S.

  

 

13,049

 

  

 

15,426

 

  

 

17,551

 

    


  


  


Total

  

$

17,389

 

  

$

23,741

 

  

$

26,572

 

    


  


  


Theoretical tax

  

$

6,086

 

  

$

8,309

 

  

$

9,300

 

Effect of equity method accounting

  

 

(723

)

  

 

(761

)

  

 

(852

)

Non-U.S. taxes in excess of theoretical U.S. tax

  

 

1,355

 

  

 

1,361

 

  

 

2,042

 

U.S. tax on non-U.S. operations

  

 

62

 

  

 

91

 

  

 

64

 

Other U.S.

  

 

(402

)

  

 

(262

)

  

 

212

 

    


  


  


Federal and non-U.S. income tax expense

  

$

6,378

 

  

$

8,738

 

  

$

10,766

 

    


  


  


Total effective tax rate

  

 

39.8

%

  

 

39.3

%

  

 

42.6

%

 

The effective income tax rate includes state income taxes and the corporation’s share of income taxes of equity companies. Equity company taxes totaled $778 million in 2002, $748 million in 2001 and $658 million in 2000, primarily all outside the U.S.

 

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

 

Deferred tax liabilities/(assets) are comprised of the following at December 31:

 

Tax effects of temporary differences for:


  

2002


    

2001


 
    

(millions of dollars)

 

Depreciation

  

$

14,254

 

  

$

12,738

 

Intangible development costs

  

 

3,664

 

  

 

3,445

 

Capitalized interest

  

 

2,040

 

  

 

1,989

 

Other liabilities

  

 

3,188

 

  

 

3,165

 

    


  


Total deferred tax liabilities

  

$

23,146

 

  

$

21,337

 

    


  


Pension and other postretirement benefits

  

$

(3,225

)

  

$

(1,911

)

Tax loss carryforwards

  

 

(2,350

)

  

 

(2,057

)

Other assets

  

 

(3,047

)

  

 

(2,803

)

    


  


Total deferred tax assets

  

$

(8,622

)

  

$

(6,771

)

    


  


Asset valuation allowances

  

 

582

 

  

 

209

 

    


  


Net deferred tax liabilities

  

$

15,106

 

  

$

14,775

 

    


  


 

The corporation had $17 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.

 

60


Table of Contents

 

QUARTERLY INFORMATION

 

   

2002


  

2001


   

First Quarter


 

Second Quarter


  

Third Quarter


  

Fourth Quarter


  

Year


  

First Quarter


 

Second Quarter


 

Third Quarter


 

Fourth Quarter


  

Year


Volumes    
   

(thousands of barrels daily)

Production of crude oil and natural gas liquids

 

 

2,541

 

2,495

  

2,453

  

2,497

  

2,496

  

 

2,620

 

2,539

 

2,484

 

2,527

  

2,542

Refinery throughput

 

 

5,447

 

5,372

  

5,518

  

5,585

  

5,481

  

 

5,687

 

5,406

 

5,605

 

5,587

  

5,571

Petroleum product sales

 

 

7,675

 

7,569

  

7,763

  

8,017

  

7,757

  

 

7,985

 

7,933

 

7,951

 

8,016

  

7,971

   

(millions of cubic feet daily)

Natural gas production available for sale

 

 

11,740

 

9,192

  

9,222

  

11,667

  

10,452

  

 

12,119

 

9,090

 

8,561

 

11,373

  

10,279

   

(thousands of oil-equivalent barrels daily)

Oil-equivalent production*

 

 

4,498

 

4,027

  

3,990

  

4,442

  

4,238

  

 

4,640

 

4,054

 

3,911

 

4,423

  

4,255

   

(thousands of metric tons)

Chemical prime product sales

 

 

6,720

 

6,785

  

6,711

  

6,709

  

26,925

  

 

6,533

 

6,418

 

6,457

 

6,372

  

25,780

Summarized financial data

                                                
   

(millions of dollars)

Sales and other operating revenue

 

$

42,592

 

49,972

  

53,194

  

55,191

  

200,949

  

$

55,878

 

54,931

 

50,947

 

46,959

  

208,715

Gross profit**

 

$

18,804

 

21,138

  

20,996

  

22,920

  

83,858

  

$

24,192

 

22,825

 

21,812

 

22,038

  

90,867

Income from continuing operations

 

$

2,063

 

2,629

  

2,629

  

3,690

  

11,011

  

$

4,932

 

4,251

 

3,151

 

2,669

  

15,003

Discontinued operations, net of income tax

 

$

27

 

11

  

11

  

400

  

449

  

$

28

 

34

 

29

 

11

  

102

                                                  

Extraordinary gain, net of income tax

 

 

—  

 

—  

  

—  

  

—  

  

—  

  

$

40

 

175

 

—  

 

—  

  

215

Net income

 

$

2,090

 

2,640

  

2,640

  

4,090

  

11,460

  

$

5,000

 

4,460

 

3,180

 

2,680

  

15,320

Per share data

                                                
   

(dollars per share)

Income from continuing operations

 

$

0.30

 

0.39

  

0.39

  

0.54

  

1.62

  

$

0.71

 

0.63

 

0.46

 

0.39

  

2.19

Discontinued operations, net of income tax

 

$

0.00

 

0.01

  

0.00

  

0.06

  

0.07

  

$

0.00

 

0.01

 

0.00

 

0.00

  

0.01

Extraordinary gain, net of income tax

 

$

0.00

 

0.00

  

0.00

  

0.00

  

0.00

  

$

0.01

 

0.02

 

0.00

 

0.00

  

0.03

Net income per common share

 

$

0.30

 

0.40

  

0.39

  

0.60

  

1.69

  

$

0.72

 

0.66

 

0.46

 

0.39

  

2.23

Net income per common share – assuming dilution

 

$

0.30

 

0.39

  

0.39

  

0.60

  

1.68

  

$

0.71

 

0.65

 

0.46

 

0.39

  

2.21

Dividends per common share

 

$

0.23

 

0.23

  

0.23

  

0.23

  

0.92

  

$

0.22

 

0.23

 

0.23

 

0.23

  

0.91

Common stock prices

                                                

High

 

$

44.290

 

44.579

  

41.100

  

36.500

  

44.579

  

$

44.875

 

45.835

 

44.400

 

42.700

  

45.835

Low

 

$

37.600

 

38.500

  

29.750

  

32.030

  

29.750

  

$

37.600

 

38.500

 

35.010

 

36.410

  

35.010

 

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

 

** Gross profit equals sales and other operating revenue less estimated costs associated with products sold.

 

The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.

 

There were 677,738 registered shareholders of ExxonMobil common stock at December 31, 2002. At January 31, 2003, the registered shareholders of ExxonMobil common stock numbered 679,211.

 

On January 29, 2003, the corporation declared a $0.23 dividend per common share, payable March 10, 2003.

 

 

61


Table of Contents

 

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

 

   

Consolidated Subsidiaries


  

Non-

Consolidated

Interests


  

Total

Worldwide


Results of Operations


 

United

States


 

Canada


   

Europe


  

Asia-Pacific


   

Africa


 

Other


   

Total


     
   

(millions of dollars)

2002 – Revenue

                                                              

Sales to third parties

 

$

2,499

 

$

1,441

 

 

$

4,856

  

$

1,994

 

 

$

18

 

$

343

 

 

$

11,151

  

$

3,426

  

$

14,577

Transfers

 

 

4,176

 

 

1,617

 

 

 

3,334

  

 

2,022

 

 

 

3,046

 

 

273

 

 

 

14,468

  

 

1,296

  

 

15,764

   

 


 

  


 

 


 

  

  

   

$

6,675

 

$

3,058

 

 

$

8,190

  

$

4,016

 

 

$

3,064

 

$

616

 

 

$

25,619

  

$

4,722

  

$

30,341

Production costs excluding taxes

 

 

1,405

 

 

766

 

 

 

1,493

  

 

592

 

 

 

455

 

 

192

 

 

 

4,903

  

 

561

  

 

5,464

Exploration expenses

 

 

222

 

 

66

 

 

 

109

  

 

88

 

 

 

177

 

 

257

 

 

 

919

  

 

38

  

 

957

Depreciation and depletion

 

 

1,512

 

 

681

 

 

 

1,737

  

 

651

 

 

 

354

 

 

150

 

 

 

5,085

  

 

349

  

 

5,434

Taxes other than income

 

 

459

 

 

31

 

 

 

360

  

 

403

 

 

 

345

 

 

4

 

 

 

1,602

  

 

1,179

  

 

2,781

Related income tax

 

 

1,153

 

 

486

 

 

 

2,399

  

 

939

 

 

 

972

 

 

(122

)

 

 

5,827

  

 

918

  

 

6,745

   

 


 

  


 

 


 

  

  

Results of producing activities

 

$

1,924

 

$

1,028

 

 

$

2,092

  

$

1,343

 

 

$

761

 

$

135

 

 

$

7,283

  

$

1,677

  

$

8,960

Other earnings*

 

 

207

 

 

(31

)

 

 

151

  

 

(47

)

 

 

81

 

 

(69

)

 

 

292

  

 

346

  

 

638

   

 


 

  


 

 


 

  

  

Total earnings

 

$

2,131

 

$

997

 

 

$

2,243

  

$

1,296

 

 

$

842

 

$

66

 

 

$

7,575

  

$

2,023

  

$

9,598

   

 


 

  


 

 


 

  

  

2001 – Revenue

                                                              

Sales to third parties

 

$

4,045

 

$

1,784

 

 

$

5,017

  

$

1,269

 

 

$

17

 

$

342

 

 

$

12,474

  

$

3,326

  

$

15,800

Transfers

 

 

4,547

 

 

1,203

 

 

 

3,927

  

 

1,917

 

 

 

2,894

 

 

250

 

 

 

14,738

  

 

1,306

  

 

16,044

   

 


 

  


 

 


 

  

  

   

$

8,592

 

$

2,987

 

 

$

8,944

  

$

3,186

 

 

$

2,911

 

$

592

 

 

$

27,212

  

$

4,632

  

$

31,844

Production costs excluding taxes

 

 

1,389

 

 

633

 

 

 

1,425

  

 

549

 

 

 

414

 

 

210

 

 

 

4,620

  

 

580

  

 

5,200

Exploration expenses

 

 

215

 

 

109

 

 

 

117

  

 

103

 

 

 

217

 

 

412

 

 

 

1,173

  

 

18

  

 

1,191

Depreciation and depletion

 

 

1,392

 

 

570

 

 

 

1,644

  

 

557

 

 

 

318

 

 

148

 

 

 

4,629

  

 

354

  

 

4,983

Taxes other than income

 

 

545

 

 

54

 

 

 

484

  

 

410

 

 

 

375

 

 

5

 

 

 

1,873

  

 

1,160

  

 

3,033

Related income tax

 

 

1,957

 

 

543

 

 

 

2,567

  

 

622

 

 

 

1,023

 

 

(98

)

 

 

6,614

  

 

1,037

  

 

7,651

   

 


 

  


 

 


 

  

  

Results of producing activities

 

$

3,094

 

$

1,078

 

 

$

2,707

  

$

945

 

 

$

564

 

$

(85

)

 

$

8,303

  

$

1,483

  

$

9,786

Other earnings*

 

 

355

 

 

(37

)

 

 

132

  

 

(42

)

 

 

33

 

 

(66

)

 

 

375

  

 

575

  

 

950

   

 


 

  


 

 


 

  

  

Total earnings

 

$

3,449

 

$

1,041

 

 

$

2,839

  

$

903

 

 

$

597

 

$

(151

)

 

$

8,678

  

$

2,058

  

$

10,736

   

 


 

  


 

 


 

  

  

2000 – Revenue

                                                              

Sales to third parties

 

$

4,060

 

$

2,423

 

 

$

4,387

  

$

2,167

 

 

$

20

 

$

366

 

 

$

13,423

  

$

3,055

  

$

16,478

Transfers

 

 

5,420

 

 

771

 

 

 

5,491

  

 

2,130

 

 

 

3,212

 

 

324

 

 

 

17,348

  

 

1,532

  

 

18,880

   

 


 

  


 

 


 

  

  

   

$

9,480

 

$

3,194

 

 

$

9,878

  

$

4,297

 

 

$

3,232

 

$

690

 

 

$

30,771

  

$

4,587

  

$

35,358

Production costs excluding taxes

 

 

1,231

 

 

595

 

 

 

1,627

  

 

543

 

 

 

400

 

 

181

 

 

 

4,577

  

 

621

  

 

5,198

Exploration expenses

 

 

145

 

 

81

 

 

 

135

  

 

164

 

 

 

196

 

 

211

 

 

 

932

  

 

22

  

 

954

Depreciation and depletion

 

 

1,373

 

 

586

 

 

 

1,906

  

 

556

 

 

 

340

 

 

141

 

 

 

4,902

  

 

399

  

 

5,301

Taxes other than income

 

 

637

 

 

33

 

 

 

358

  

 

506

 

 

 

446

 

 

4

 

 

 

1,984

  

 

997

  

 

2,981

Related income tax

 

 

2,419

 

 

736

 

 

 

3,274

  

 

1,005

 

 

 

1,093

 

 

97

 

 

 

8,624

  

 

975

  

 

9,599

   

 


 

  


 

 


 

  

  

Results of producing activities

 

$

3,675

 

$

1,163

 

 

$

2,578

  

$

1,523

 

 

$

757

 

$

56

 

 

$

9,752

  

$

1,573

  

$

11,325

Other earnings*

 

 

114

 

 

(36

)

 

 

521

  

 

137

 

 

 

31

 

 

(35

)

 

 

732

  

 

628

  

 

1,360

   

 


 

  


 

 


 

  

  

Total earnings

 

$

3,789

 

$

1,127

 

 

$

3,099

  

$

1,660

 

 

$

788

 

$

21

 

 

$

10,484

  

$

2,201

  

$

12,685

   

 


 

  


 

 


 

  

  

Average sales prices and production costs per unit of production

During 2002

                                                              

Average sales prices

                                                              

Crude oil and NGL, per barrel

 

$

20.80

 

$

20.73

 

 

$

22.95

  

$

24.26

 

 

$

24.19

 

$

19.43

 

 

$

22.30

  

$

21.88

  

$

22.25

Natural gas, per thousand cubic feet

 

 

2.67

 

 

2.34

 

 

 

3.08

  

 

2.26

 

 

 

—  

 

 

0.48

 

 

 

2.65

  

 

3.23

  

 

2.77

Average production costs, per barrel**

 

 

3.97

 

 

4.53

 

 

 

3.82

  

 

2.72

 

 

 

3.57

 

 

5.03

 

 

 

3.78

  

 

2.44

  

 

3.58

During 2001

                                                              

Average sales prices

                                                              

Crude oil and NGL, per barrel

 

$

19.92

 

$

15.95

 

 

$

22.79

  

$

24.36

 

 

$

23.34

 

$

20.21

 

 

$

21.30

  

$

19.64

  

$

21.10

Natural gas, per thousand cubic feet

 

 

4.36

 

 

3.71

 

 

 

3.28

  

 

1.80

 

 

 

—  

 

 

1.44

 

 

 

3.37

  

 

3.48

  

 

3.39

Average production costs, per barrel**

 

 

3.68

 

 

3.88

 

 

 

3.40

  

 

2.98

 

 

 

3.32

 

 

5.85

 

 

 

3.54

  

 

2.53

  

 

3.39

During 2000

                                                              

Average sales prices

                                                              

Crude oil and NGL, per barrel

 

$

23.94

 

$

21.60

 

 

$

26.96

  

$

28.74

 

 

$

28.17

 

$

24.57

 

 

$

25.77

  

$

24.17

  

$

25.59

Natural gas, per thousand cubic feet

 

 

3.85

 

 

3.58

 

 

 

2.69

  

 

2.59

 

 

 

 

 

1.29

 

 

 

3.12

  

 

3.11

  

 

3.12

Average production costs, per barrel**

 

 

3.08

 

 

4.04

 

 

 

3.72

  

 

2.72

 

 

 

3.39

 

 

5.50

 

 

 

3.43

  

 

2.90

  

 

3.35

 

 

*   Includes earnings from transportation operations, tar sands operations, LNG operations, coal and power operations, technical services agreements, other non-operating activities and adjustments for minority interests. “Other earnings” for prior years have been revised to include coal and power operations.
**   Production costs exclude depreciation and depletion and all taxes. Natural gas included by conversion to crude oil equivalent.

 

62


Table of Contents

 

Oil and Gas Exploration and Production Costs

 

The amounts shown for net capitalized costs of consolidated subsidiaries are $5,969 million less at year-end 2002 and $5,292 million less at year-end 2001 than the amounts reported as investments in property, plant and equipment for the upstream in note 10. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to the tar sands and LNG operations, and to the inclusion of accumulated provisions for site restoration costs, all as required in Statement of Financial Accounting Standards No. 19.

 

The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Total worldwide costs incurred in 2002 were $9,155 million, up $1,352 million from 2001, due primarily to higher development costs. 2001 costs were $7,803 million, up $1,740 million from 2000, due primarily to higher development costs.

 

   

Consolidated Subsidiaries


        

Capitalized costs


 

United

States


 

Canada


 

Europe


  

Asia-Pacific


   

Africa


 

Other


 

Total


  

Non-

Consolidated Interests


 

Total

Worldwide


   

(millions of dollars)

As of December 31, 2002

                                                         

Property (acreage) costs – Proved

 

$

4,433

 

$

2,604

 

$

202

  

$

745

 

 

$

106

 

$

1,018

 

$

9,108

  

$

56

 

$

9,164

                – Unproved

 

 

657

 

 

205

 

 

35

  

 

900

 

 

 

610

 

 

568

 

 

2,975

  

 

1

 

 

2,976

   

 

 

  


 

 

 

  

 

Total property costs

 

$

5,090

 

$

2,809

 

$

237

  

$

1,645

 

 

$

716

 

$

1,586

 

$

12,083

  

$

57

 

$

12,140

Producing assets

 

 

34,850

 

 

7,404

 

 

33,385

  

 

12,789

 

 

 

4,701

 

 

1,983

 

 

95,112

  

 

7,251

 

 

102,363

Support facilities

 

 

533

 

 

93

 

 

489

  

 

953

 

 

 

212

 

 

85

 

 

2,365

  

 

335

 

 

2,700

Incomplete construction

 

 

910

 

 

310

 

 

2,210

  

 

940

 

 

 

2,818

 

 

514

 

 

7,702

  

 

720

 

 

8,422

   

 

 

  


 

 

 

  

 

Total capitalized costs

 

$

41,383

 

$

10,616

 

$

36,321

  

$

16,327

 

 

$

8,447

 

$

4,168

 

$

117,262

  

$

8,363

 

$

125,625

Accumulated depreciation and depletion

 

 

26,729

 

 

5,497

 

 

24,111

  

 

10,625

 

 

 

2,692

 

 

1,881

 

 

71,535

  

 

4,326

 

 

75,861

   

 

 

  


 

 

 

  

 

Net capitalized costs

 

$

14,654

 

$

5,119

 

$

12,210

  

$

5,702

 

 

$

5,755

 

$

2,287

 

$

45,727

  

$

4,037

 

$

49,764

   

 

 

  


 

 

 

  

 

As of December 31, 2001

                                                         

Property (acreage) costs – Proved

 

$

4,543

 

$

2,656

 

$

178

  

$

689

 

 

$

107

 

$

957

 

$

9,130

  

$

11

 

$

9,141

                – Unproved

 

 

674

 

 

196

 

 

49

  

 

850

 

 

 

630

 

 

530

 

 

2,929

  

 

2

 

 

2,931

   

 

 

  


 

 

 

  

 

Total property costs

 

$

5,217

 

$

2,852

 

$

227

  

$

1,539

 

 

$

737

 

$

1,487

 

$

12,059

  

$

13

 

$

12,072

Producing assets

 

 

33,379

 

 

6,662

 

 

27,628

  

 

11,764

 

 

 

4,300

 

 

1,992

 

 

85,725

  

 

5,710

 

 

91,435

Support facilities

 

 

488

 

 

83

 

 

449

  

 

925

 

 

 

208

 

 

159

 

 

2,312

  

 

257

 

 

2,569

Incomplete construction

 

 

1,050

 

 

334

 

 

1,306

  

 

684

 

 

 

1,433

 

 

346

 

 

5,153

  

 

495

 

 

5,648

   

 

 

  


 

 

 

  

 

Total capitalized costs

 

$

40,134

 

$

9,931

 

$

29,610

  

$

14,912

 

 

$

6,678

 

$

3,984

 

$

105,249

  

$

6,475

 

$

111,724

Accumulated depreciation and depletion

 

 

25,754

 

 

4,888

 

 

19,398

  

 

9,705

 

 

 

2,323

 

 

1,796

 

 

63,864

  

 

3,127

 

 

66,991

   

 

 

  


 

 

 

  

 

Net capitalized costs

 

$

14,380

 

$

5,043

 

$

10,212

  

$

5,207

 

 

$

4,355

 

$

2,188

 

$

41,385

  

$

3,348

 

$

44,733

   

 

 

  


 

 

 

  

 

Costs incurred in property acquisitions, exploration and development activities

During 2002

                                                         

Property acquisition costs – Proved

 

$

18

 

$

8

 

$

  

$

 

 

$

 

$

 

$

26

  

$

1

 

$

27

                   – Unproved

 

 

13

 

 

12

 

 

  

 

 

 

 

10

 

 

125

 

 

160

  

 

 

 

160

Exploration costs

 

 

276

 

 

109

 

 

127

  

 

82

 

 

 

301

 

 

216

 

 

1,111

  

 

52

 

 

1,163

Development costs

 

 

1,676

 

 

653

 

 

1,785

  

 

936

 

 

 

1,708

 

 

360

 

 

7,118

  

 

687

 

 

7,805

   

 

 

  


 

 

 

  

 

Total

 

$

1,983

 

$

782

 

$

1,912

  

$

1,018

 

 

$

2,019

 

$

701

 

$

8,415

  

$

740

 

$

9,155

   

 

 

  


 

 

 

  

 

During 2001

                                                         

Property acquisition costs – Proved

 

$

 

$

 

$

  

$

 

 

$

2

 

$

 

$

2

  

$

 

$

2

                   – Unproved

 

 

95

 

 

17

 

 

1

  

 

(1

)

 

 

 

 

10

 

 

122

  

 

 

 

122

Exploration costs

 

 

352

 

 

141

 

 

144

  

 

148

 

 

 

281

 

 

459

 

 

1,525

  

 

35

 

 

1,560

Development costs

 

 

1,648

 

 

664

 

 

1,498

  

 

666

 

 

 

995

 

 

219

 

 

5,690

  

 

429

 

 

6,119

   

 

 

  


 

 

 

  

 

Total

 

$

2,095

 

$

822

 

$

1,643

  

$

813

 

 

$

1,278

 

$

688

 

$

7,339

  

$

464

 

$

7,803

   

 

 

  


 

 

 

  

 

During 2000

                                                         

Property acquisition costs – Proved

 

$

1

 

$

1

 

$

  

$

1

 

 

$

 

$

 

$

3

  

$

 

$

3

                   – Unproved

 

 

72

 

 

15

 

 

4

  

 

96

 

 

 

2

 

 

49

 

 

238

  

 

 

 

238

Exploration costs

 

 

219

 

 

145

 

 

187

  

 

145

 

 

 

272

 

 

297

 

 

1,265

  

 

23

 

 

1,288

Development costs

 

 

1,236

 

 

525

 

 

1,262

  

 

502

 

 

 

402

 

 

224

 

 

4,151

  

 

383

 

 

4,534

   

 

 

  


 

 

 

  

 

Total

 

$

1,528

 

$

686

 

$

1,453

  

$

744

 

 

$

676

 

$

570

 

$

5,657

  

$

406

 

$

6,063

   

 

 

  


 

 

 

  

 

 

63


Table of Contents

 

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

 

Oil and Gas Reserves

 

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2000, 2001 and 2002.

 

The definitions used are in accordance with applicable Securities and Exchange Commission regulations.

 

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which 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. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. 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. 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.

 

Proved reserves include 100 percent of each majority owned affiliate’s participation in proved reserves and ExxonMobil’s ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.

 

   

Consolidated Subsidiaries


               

Crude Oil and Natural Gas Liquids


 

United States


   

Canada


   

Europe


    

Asia-Pacific


   

Africa


   

Other


   

Total


    

Non-  

Consolidated Interests


    

Total

Worldwide


 
   

(millions of barrels)

 

Net proved developed and undeveloped reserves

                                                  

January 1, 2000

 

2,749

 

 

1,355

 

 

1,761

 

  

715

 

 

2,024

 

 

700

 

 

9,304

 

  

1,956

 

  

11,260

 

Revisions

 

410

 

 

9

 

 

25

 

  

29

 

 

50

 

 

24

 

 

547

 

  

33

 

  

580

 

Purchases

 

—  

 

 

—  

 

 

—  

 

  

—  

 

 

—  

 

 

—  

 

 

—  

 

  

—  

 

  

—  

 

Sales

 

(1

)

 

(5

)

 

—  

 

  

—  

 

 

—  

 

 

—  

 

 

(6

)

  

—  

 

  

(6

)

Improved recovery

 

40

 

 

34

 

 

20

 

  

—  

 

 

3

 

 

—  

 

 

97

 

  

26

 

  

123

 

Extensions and discoveries

 

8

 

 

33

 

 

5

 

  

39

 

 

425

 

 

4

 

 

514

 

  

3

 

  

517

 

Production

 

(220

)

 

(96

)

 

(253

)

  

(93

)

 

(118

)

 

(26

)

 

(806

)

  

(107

)

  

(913

)

   

 

 

  

 

 

 

  

  

December 31, 2000

 

2,986

 

 

1,330

 

 

1,558

 

  

690

 

 

2,384

 

 

702

 

 

9,650

 

  

1,911

 

  

11,561

 

Revisions

 

89

 

 

(9

)

 

68

 

  

(1

)

 

94

 

 

15

 

 

256

 

  

8

 

  

264

 

Purchases

 

—  

 

 

—  

 

 

—  

 

  

—  

 

 

—  

 

 

—  

 

 

—  

 

  

—  

 

  

—  

 

Sales

 

(6

)

 

—  

 

 

—  

 

  

—  

 

 

—  

 

 

—  

 

 

(6

)

  

(3

)

  

(9

)

Improved recovery

 

57

 

 

5

 

 

5

 

  

—  

 

 

34

 

 

—  

 

 

101

 

  

20

 

  

121

 

Extensions and discoveries

 

112

 

 

53

 

 

79

 

  

23

 

 

74

 

 

—  

 

 

341

 

  

112

 

  

453

 

Production

 

(210

)

 

(102

)

 

(234

)

  

(90

)

 

(125

)

 

(29

)

 

(790

)

  

(109

)

  

(899

)

   

 

 

  

 

 

 

  

  

December 31, 2001

 

3,028

 

 

1,277

 

 

1,476

 

  

622

 

 

2,461

 

 

688

 

 

9,552

 

  

1,939

 

  

11,491

 

Revisions

 

31

 

 

74

 

 

59

 

  

40

 

 

73

 

 

26

 

 

303

 

  

52

 

  

355

 

Purchases

 

—  

 

 

—  

 

 

—    

 

  

—  

 

 

—  

 

 

—  

 

 

—  

 

  

—  

 

  

—  

 

Sales

 

(13

)

 

—  

 

 

—    

 

  

—  

 

 

—  

 

 

—  

 

 

(13

)

  

—  

 

  

(13

)

Improved recovery

 

3

 

 

—  

 

 

—    

 

  

—  

 

 

75

 

 

—  

 

 

78

 

  

16

 

  

94

 

Extensions and discoveries

 

60

 

 

40

 

 

11

 

  

124

 

 

145

 

 

100

 

 

480

 

  

297

 

  

777

 

Production

 

(200

)

 

(106

)

 

(213

)

  

(95

)

 

(128

)

 

(33

)

 

(775

)

  

(106

)

  

(881

)

   

 

 

  

 

 

 

  

  

December 31, 2002

 

2,909

 

 

1,285

 

 

1,333

 

  

691

 

 

2,626

 

 

781

 

 

9,625

 

  

2,198

 

  

11,823

 

Developed reserves, included above

                                                        

At December 31, 2000

 

2,661

 

 

630

 

 

978

 

  

504

 

 

989

 

 

245

 

 

6,007

 

  

1,331

 

  

7,338

 

At December 31, 2001

 

2,567

 

 

593

 

 

881

 

  

477

 

 

1,022

 

 

232

 

 

5,772

 

  

1,440

 

  

7,212

 

At December 31, 2002

 

2,461

 

 

685

 

 

797

 

  

487

 

 

1,057

 

 

208

 

 

5,695

 

  

1,505

 

  

7,200

 

 

64


Table of Contents

 

Net proved developed reserves are those volumes which are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those volumes which are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells.

 

Reserves attributable to certain oil and gas discoveries were not considered proved as of year-end 2002 due to geological, technological or economic uncertainties and therefore are not included in the tabulation.

 

Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported on page 67 due to volumes consumed or flared and inventory changes. Such quantities amounted to approximately 392 billion cubic feet in 2000, 406 billion cubic feet in 2001 and 420 billion cubic feet in 2002.

 

   

Consolidated Subsidiaries


               

Natural Gas


 

United States


   

Canada


   

Europe


    

Asia-Pacific


   

Africa


   

Other


   

Total


    

Non-  

Consolidated Interests


    

Total Worldwide


 
   

(billions of cubic feet)

 

Net proved developed and undeveloped reserves

                                                  

January 1, 2000

 

13,001

 

 

3,387

 

 

11,228

 

  

9,358

 

 

171

 

 

608

 

 

37,753

 

  

19,043

 

  

56,796

 

Revisions

 

987

 

 

69

 

 

970

 

  

(113

)

 

147

 

 

62

 

 

2,122

 

  

85

 

  

2,207

 

Purchases

 

 

 

10

 

 

 

  

 

 

 

 

 

 

10

 

  

 

  

10

 

Sales

 

(3

)

 

(5

)

 

 

  

 

 

 

 

 

 

(8

)

  

 

  

(8

)

Improved recovery

 

22

 

 

24

 

 

46

 

  

 

 

 

 

24

 

 

116

 

  

50

 

  

166

 

Extensions and discoveries

 

195

 

 

430

 

 

96

 

  

11

 

 

70

 

 

26

 

 

828

 

  

45

 

  

873

 

Production

 

(1,157

)

 

(399

)

 

(1,170

)

  

(710

)

 

(13

)

 

(53

)

 

(3,502

)

  

(676

)

  

(4,178

)

   

 

 

  

 

 

 

  

  

December 31, 2000

 

13,045

 

 

3,516

 

 

11,170

 

  

8,546

 

 

375

 

 

667

 

 

37,319

 

  

18,547

 

  

55,866

 

Revisions

 

612

 

 

(51

)

 

564

 

  

(198

)

 

8

 

 

(5

)

 

930

 

  

(94

)

  

836

 

Purchases

 

 

 

1

 

 

 

  

 

 

 

 

 

 

1

 

  

 

  

1

 

Sales

 

(57

)

 

 

 

(2

)

  

(8

)

 

 

 

 

 

(67

)

  

(2

)

  

(69

)

Improved recovery

 

4

 

 

15

 

 

11

 

  

 

 

2

 

 

 

 

32

 

  

7

 

  

39

 

Extensions and discoveries

 

242

 

 

120

 

 

360

 

  

590

 

 

8

 

 

120

 

 

1,440

 

  

1,991

 

  

3,431

 

Production

 

(1,114

)

 

(418

)

 

(1,172

)

  

(629

)

 

(14

)

 

(54

)

 

(3,401

)

  

(757

)

  

(4,158

)

   

 

 

  

 

 

 

  

  

December 31, 2001

 

12,732

 

 

3,183

 

 

10,931

 

  

8,301

 

 

379

 

 

728

 

 

36,254

 

  

19,692

 

  

55,946

 

Revisions

 

206

 

 

30

 

 

600

 

  

258

 

 

17

 

 

42

 

 

1,153

 

  

294

 

  

1,447

 

Purchases

 

 

 

2

 

 

 

  

 

 

 

 

 

 

2

 

  

 

  

2

 

Sales

 

(43

)

 

 

 

 

  

 

 

 

 

 

 

(43

)

  

 

  

(43

)

Improved recovery

 

1

 

 

3

 

 

 

  

 

 

 

 

 

 

4

 

  

 

  

4

 

Extensions and discoveries

 

209

 

 

83

 

 

115

 

  

212

 

 

52

 

 

9

 

 

680

 

  

1,917

 

  

2,597

 

Production

 

(1,043

)

 

(419

)

 

(1,138

)

  

(813

)

 

(12

)

 

(44

)

 

(3,469

)

  

(766

)

  

(4,235

)

   

 

 

  

 

 

 

  

  

December 31, 2002

 

12,062

 

 

2,882

 

 

10,508

 

  

7,958

 

 

436

 

 

735

 

 

34,581

 

  

21,137

 

  

55,718

 

Developed reserves, included above

                                                        

At December 31, 2000

 

10,956

 

 

2,850

 

 

8,222

 

  

6,300

 

 

125

 

 

477

 

 

28,930

 

  

9,087

 

  

38,017

 

At December 31, 2001

 

10,366

 

 

2,517

 

 

7,824

 

  

6,005

 

 

122

 

 

404

 

 

27,238

 

  

8,784

 

  

36,022

 

At December 31, 2002

 

9,991

 

 

2,294

 

 

7,326

 

  

5,887

 

 

112

 

 

402

 

 

26,012

 

  

8,731

 

  

34,743

 

 


 

INFORMATION ON CANADIAN TAR SANDS PROVEN RESERVES NOT INCLUDED ABOVE

 

In addition to conventional liquids and natural gas proved reserves, ExxonMobil has significant interests in proven tar sands reserves in Canada associated with the Syncrude project. For internal management purposes, ExxonMobil views these reserves and their development as an integral part of total upstream operations. However, U.S. Securities and Exchange Commission regulations define these reserves as mining related and not a part of conventional oil and gas reserves.

 

The tar sands reserves are not considered in the standardized measure of discounted future cash flows for conventional oil and gas reserves, which is found on page 66.

 

Tar Sands Reserves


    

Canada


      

(millions of barrels)

At December 31, 2000

    

610

At December 31, 2001

    

821

At December 31, 2002

    

800

 

65


Table of Contents

 

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

 

Standardized Measure of Discounted Future Cash Flows

 

As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year-end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The corporation believes the standardized measure is not meaningful and may be misleading, due to a number of factors, including significant variability in cash flows due to changes in year-end prices.

 

    

Consolidated Subsidiaries


         
    

United States


  

Canada


  

Europe


  

Asia-

Pacific


  

Africa


  

Other


  

Total


  

Non-

Consolidated

Interests


  

Total

Worldwide


    

(millions of dollars)

As of December 31, 2000

                                                              

Future cash inflows from sales of oil and gas

  

$

177,178

  

$

41,275

  

$

70,208

  

$

34,658

  

$

52,651

  

$

10,317

  

$

386,287

  

$

93,597

  

$

479,884

Future production costs

  

 

26,417

  

 

7,857

  

 

15,979

  

 

9,977

  

 

10,953

  

 

3,467

  

 

74,650

  

 

38,011

  

 

112,661

Future development costs

  

 

3,977

  

 

2,806

  

 

5,552

  

 

3,405

  

 

7,516

  

 

798

  

 

24,054

  

 

3,901

  

 

27,955

Future income tax expenses

  

 

55,192

  

 

12,731

  

 

26,078

  

 

7,382

  

 

18,949

  

 

1,830

  

 

122,162

  

 

21,333

  

 

143,495

    

  

  

  

  

  

  

  

  

Future net cash flows

  

$

91,592

  

$

17,881

  

$

22,599

  

$

13,894

  

$

15,233

  

$

4,222

  

$

165,421

  

$

30,352

  

$

195,773

Effect of discounting net cash flows at 10%

  

 

48,876

  

 

6,795

  

 

7,779

  

 

5,638

  

 

8,158

  

 

2,450

  

 

79,696

  

 

18,825

  

 

98,521

    

  

  

  

  

  

  

  

  

Discounted future net cash flows

  

$

42,716

  

$

11,086

  

$

14,820

  

$

8,256

  

$

7,075

  

$

1,772

  

$

85,725

  

$

11,527

  

$

97,252

    

  

  

  

  

  

  

  

  

As of December 31, 2001

                                                              

Future cash inflows from sales of oil and gas

  

$

68,713

  

$

19,573

  

$

58,394

  

$

24,452

  

$

42,806

  

$

10,370

  

$

224,308

  

$

87,828

  

$

312,136

Future production costs

  

 

20,008

  

 

6,711

  

 

15,807

  

 

7,801

  

 

10,341

  

 

3,217

  

 

63,885

  

 

31,839

  

 

95,724

Future development costs

  

 

4,613

  

 

2,695

  

 

5,252

  

 

3,262

  

 

7,839

  

 

831

  

 

24,492

  

 

3,043

  

 

27,535

Future income tax expenses

  

 

16,620

  

 

3,908

  

 

17,416

  

 

4,325

  

 

13,485

  

 

2,091

  

 

57,845

  

 

22,046

  

 

79,891

    

  

  

  

  

  

  

  

  

Future net cash flows

  

$

27,472

  

$

6,259

  

$

19,919

  

$

9,064

  

$

11,141

  

$

4,231

  

$

78,086

  

$

30,900

  

$

108,986

Effect of discounting net cash flows at 10%

  

 

15,065

  

 

2,377

  

 

7,338

  

 

3,552

  

 

6,087

  

 

2,553

  

 

36,972

  

 

18,766

  

 

55,738

    

  

  

  

  

  

  

  

  

Discounted future net cash flows

  

$

12,407

  

$

3,882

  

$

12,581

  

$

5,512

  

$

5,054

  

$

1,678

  

$

41,114

  

$

12,134

  

$

53,248

    

  

  

  

  

  

  

  

  

As of December 31, 2002

                                                              

Future cash inflows from sales of oil and gas

  

$

118,905

  

$

38,528

  

$

68,111

  

$

36,917

  

$

76,407

  

$

18,321

  

$

357,189

  

$

127,089

  

$

484,278

Future production costs

  

 

26,601

  

 

7,910

  

 

14,781

  

 

9,889

  

 

13,673

  

 

3,438

  

 

76,292

  

 

41,463

  

 

117,755

Future development costs

  

 

5,545

  

 

3,157

  

 

5,983

  

 

3,433

  

 

10,454

  

 

1,789

  

 

30,361

  

 

5,583

  

 

35,944

Future income tax expenses

  

 

34,289

  

 

10,261

  

 

23,580

  

 

8,254

  

 

28,190

  

 

3,921

  

 

108,495

  

 

27,633

  

 

136,128

    

  

  

  

  

  

  

  

  

Future net cash flows

  

$

52,470

  

$

17,200

  

$

23,767

  

$

15,341

  

$

24,090

  

$

9,173

  

$

142,041

  

$

52,410

  

$

194,451

Effect of discounting net cash flows at 10%

  

 

28,930

  

 

6,792

  

 

7,788

  

 

5,857

  

 

11,658

  

 

5,634

  

 

66,659

  

 

31,233

  

 

97,892

    

  

  

  

  

  

  

  

  

Discounted future net cash flows

  

$

23,540

  

$

10,408

  

$

15,979

  

$

9,484

  

$

12,432

  

$

3,539

  

$

75,382

  

$

21,177

  

$

96,559

    

  

  

  

  

  

  

  

  

 

Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

 

Consolidated Subsidiaries


  

2002


    

2001


    

2000


 
    

(millions of dollars)

 

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs

  

$

5,481

 

  

$

2,660

 

  

$

6,029

 

Changes in value of previous-year reserves due to:

                          

Sales and transfers of oil and gas produced during the year, net of production (lifting) costs

  

 

(19,242

)

  

 

(20,748

)

  

 

(24,498

)

Development costs incurred during the year

  

 

6,994

 

  

 

5,577

 

  

 

4,194

 

Net change in prices, lifting and development costs

  

 

57,506

 

  

 

(79,693

)

  

 

44,702

 

Revisions of previous reserves estimates

  

 

4,665

 

  

 

2,520

 

  

 

12,537

 

Accretion of discount

  

 

5,837

 

  

 

12,293

 

  

 

7,694

 

Net change in income taxes

  

 

(26,973

)

  

 

32,780

 

  

 

(20,889

)

    


  


  


Total change in the standardized measure during the year

  

$

34,268

 

  

$

(44,611

)

  

$

29,769

 

    


  


  


 

66


Table of Contents

 

OPERATING SUMMARY

 

    

2002


    

2001


    

2000


    

1999


    

1998


 
    

(thousands of barrels daily)

 

Production of crude oil and natural gas liquids

                                  

Net production

                                  

United States

  

681

 

  

712

 

  

733

 

  

729

 

  

745

 

Canada

  

349

 

  

331

 

  

304

 

  

315

 

  

322

 

Europe

  

592

 

  

653

 

  

704

 

  

650

 

  

635

 

Asia-Pacific

  

260

 

  

247

 

  

253

 

  

307

 

  

322

 

Africa

  

349

 

  

342

 

  

323

 

  

326

 

  

301

 

Other Non-U.S.

  

265

 

  

257

 

  

236

 

  

190

 

  

177

 

    

  

  

  

  

Worldwide

  

2,496

 

  

2,542

 

  

2,553

 

  

2,517

 

  

2,502

 

    

  

  

  

  

        
    

(millions of cubic feet daily)

 

Natural gas production available for sale

                                  

Net production

                                  

United States

  

2,375

 

  

2,598

 

  

2,856

 

  

2,871

 

  

3,140

 

Canada

  

1,024

 

  

1,006

 

  

844

 

  

683

 

  

667

 

Europe

  

4,463

 

  

4,595

 

  

4,463

 

  

4,438

 

  

4,245

 

Asia-Pacific

  

2,019

 

  

1,547

 

  

1,755

 

  

2,027

 

  

2,352

 

Other Non-U.S.

  

571

 

  

533

 

  

425

 

  

289

 

  

213

 

    

  

  

  

  

Worldwide

  

10,452

 

  

10,279

 

  

10,343

 

  

10,308

 

  

10,617

 

    

  

  

  

  

        
    

(thousands of oil-equivalent barrels daily)

 

Oil-equivalent production*

  

4,238

 

  

4,255

 

  

4,277

 

  

4,235

 

  

4,272

 

    

  

  

  

  

        
    

(thousands of barrels daily)

 

Refinery throughput

                                  

United States

  

1,871

 

  

1,840

 

  

1,862

 

  

1,930

 

  

1,919

 

Canada

  

447

 

  

449

 

  

451

 

  

441

 

  

445

 

Europe

  

1,539

 

  

1,563

 

  

1,578

 

  

1,782

 

  

1,888

 

Asia-Pacific

  

1,379

 

  

1,436

 

  

1,462

 

  

1,537

 

  

1,554

 

Other Non-U.S.

  

245

 

  

283

 

  

289

 

  

287

 

  

287

 

    

  

  

  

  

Worldwide

  

5,481

 

  

5,571

 

  

5,642

 

  

5,977

 

  

6,093

 

    

  

  

  

  

Petroleum product sales

                                  

United States

  

2,731

 

  

2,751

 

  

2,669

 

  

2,918

 

  

2,804

 

Canada

  

593

 

  

585

 

  

577

 

  

587

 

  

579

 

Europe

  

2,042

 

  

2,079

 

  

2,129

 

  

2,597

 

  

2,646

 

Asia-Pacific and other Eastern Hemisphere

  

1,889

 

  

2,024

 

  

2,090

 

  

2,223

 

  

2,266

 

Latin America

  

502

 

  

532

 

  

528

 

  

562

 

  

578

 

    

  

  

  

  

Worldwide

  

7,757

 

  

7,971

 

  

7,993

 

  

8,887

 

  

8,873

 

    

  

  

  

  

Gasoline, naphthas

  

3,176

 

  

3,165

 

  

3,122

 

  

3,428

 

  

3,417

 

Heating oils, kerosene, diesel oils

  

2,292

 

  

2,389

 

  

2,373

 

  

2,658

 

  

2,689

 

Aviation fuels

  

691

 

  

721

 

  

749

 

  

813

 

  

774

 

Heavy fuels

  

604

 

  

668

 

  

694

 

  

706

 

  

765

 

Specialty petroleum products

  

994

 

  

1,028

 

  

1,055

 

  

1,282

 

  

1,228

 

    

  

  

  

  

Worldwide

  

7,757

 

  

7,971

 

  

7,993

 

  

8,887

 

  

8,873

 

    

  

  

  

  

        
    

(thousands of metric tons)

 

Chemical prime product sales

  

26,925

 

  

25,780

 

  

25,637

 

  

25,283

 

  

23,628

 

    

  

  

  

  

 

Operating statistics include 100 percent of operations of majority owned subsidiaries; for other companies, crude production, gas, petroleum product and chemical prime product sales include ExxonMobil’s ownership percentage, and refining throughput includes quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is made in kind or cash.

 

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

 

67


Table of Contents

SIGNATURES

 

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

EXXON MOBIL CORPORATION

By:

 

/s/    LEE R. RAYMOND


   

(Lee R. Raymond,

Chairman of the Board)

 

Dated March 26, 2003

 


 

POWER OF ATTORNEY

 

Each person whose signature appears below constitutes and appoints Richard E. Gutman, Robert E. Harayda and Brian A. Maher, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

 


 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

/s/    LEE R. RAYMOND        


(Lee R. Raymond)

  

Chairman of the Board

(Principal Executive Officer)

 

March 26, 2003

/s/    MICHAEL J. BOSKIN        


(Michael J. Boskin)

  

Director

 

March 26, 2003

/s/    WILLIAM T. ESREY        

                                                                                        

(William T. Esrey)

  

Director

 

March 26, 2003

/s/    DONALD V. FITES        

                                                                                        

(Donald V. Fites)

  

Director

 

March 26, 2003

 

 

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/s/    JAMES R. HOUGHTON        


(James R. Houghton)

  

Director

 

March 26, 2003

/s/    WILLIAM R. HOWELL        


(William R. Howell)

  

Director

 

March 26, 2003

/s/    HELENE L. KAPLAN        


(Helene L. Kaplan)

  

Director

 

March 26, 2003

/s/    REATHA CLARK KING        


(Reatha Clark King)

  

Director

 

March 26, 2003

/s/    PHILIP E. LIPPINCOTT        


(Philip E. Lippincott)

  

Director

 

March 26, 2003

/s/    HARRY J. LONGWELL        


(Harry J. Longwell)

  

Director

 

March 26, 2003

/s/    HENRY A. MCKINNELL, JR.    


(Henry A. McKinnell, Jr.)

  

Director

 

March 26, 2003

  /s/    MARILYN CARLSON NELSON


(Marilyn Carlson Nelson)

  

Director

 

March 26, 2003

/s/    WALTER V. SHIPLEY        


(Walter V. Shipley)

  

Director

 

March 26, 2003

/s/    DONALD D. HUMPHREYS        


(Donald D. Humphreys)

  

Controller
(Principal Accounting Officer)

 

March 26, 2003

/s/    FRANK A. RISCH        


(Frank A. Risch)

  

Treasurer
(Principal Financial Officer)

 

March 26, 2003

 

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CERTIFICATIONS

 

Certification by Lee R. Raymond

Pursuant to Securities Exchange Act Rule 13a-14

 

I, Lee R. Raymond , certify that:

 

1.    I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;

 

2.    Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

 

3.    Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

 

4.    The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

 

a)    designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

 

b)    evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c)    presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.    The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

 

a)    all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6.    The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:    March 26, 2003

/s/    LEE R. RAYMOND         


Lee R. Raymond

Chief Executive Officer

 

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Certification by Donald D. Humphreys

Pursuant to Securities Exchange Act Rule 13a-14

 

I, Donald D. Humphreys , certify that:

 

1.    I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;

 

2.    Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

 

3.    Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

 

4.    The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

 

a)    designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

 

b)    evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c)    presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.    The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

 

a)    all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6.    The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:    March 26, 2003

/s/    DONALD D. HUMPHREYS         


Donald D. Humphreys

Vice President and Controller

(Principal Accounting Officer)

 

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Certification by Frank A. Risch

Pursuant to Securities Exchange Act Rule 13a-14

 

I, Frank A. Risch, certify that:

 

1.    I have reviewed this annual report on Form 10-K of Exxon Mobil Corporation;

 

2.    Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

 

3.    Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

 

4.    The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

 

a)    designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

 

b)    evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

 

c)    presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.    The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

 

a)    all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

 

b)    any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6.    The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

Date:    March 26, 2003

/s/    FRANK A. RISCH        


Frank A. Risch

Vice President and Treasurer

(Principal Financial Officer)

 

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INDEX TO EXHIBITS

 

3(i).

  

Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).

    

3(ii).

  

By-Laws, as revised to July 31, 2002 (incorporated by reference to Exhibit 3(ii) to the registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002).

    

10(iii)(a).

  

1993 Incentive Program, as amended.*

    

10(iii)(b).

  

2001 Nonemployee Directors’ Deferred Compensation Plan (incorporated by reference to Exhibit 10(iii)(b) to the registrant’s Annual Report on Form 10-K for 2000).*

    

10(iii)(c).

  

Restricted Stock Plan for Nonemployee Directors, as amended (incorporated by reference to Exhibit 10(iii)(c) to the registrant’s Annual Report on Form 10-K for 2001).*

    

10(iii)(d).

  

ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the registrant’s Annual Report on Form 10-K for 1999).*

    

10(iii)(e).

  

Short Term Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(e) to the registrant’s Annual Report on Form 10-K for 1999).*

    

10(iii)(f).

  

1997 Nonemployee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f) to the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000).*

    

10(iii)(g).

  

1995 Mobil Incentive Compensation and Stock Ownership Plan (incorporated by reference to Exhibit 10(iii)(g) to the registrant’s Annual Report on Form 10-K for 2000).*

    

10(iii)(i).

  

Supplemental Employees Savings Plan of Mobil Oil Corporation (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K of Mobil Corporation filed March 31, 1999).*

    

10(iii)(j).

  

Form of terms for restricted stock agreements with executive officers.*

    

10(iii)(k).

  

Form of terms for annuitant cash unit agreements.*

    

12.

  

Computation of ratio of earnings to fixed charges.

    

21.

  

Subsidiaries of the registrant.

    

23.

  

Consent of PricewaterhouseCoopers LLP, Independent Accountants.

    

99.1

  

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.

    

99.2

  

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.

    

99.3

  

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Financial Officer.

    

*   Compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K.

 

The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request.

 

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