Exxon Mobil - 10-K annual report

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)

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:

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)

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EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

TABLE OF CONTENTS

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:

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

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5.    Gross and Net Developed Acreage

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

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

9.    Present Activities

A. Wells Drilling

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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.

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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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

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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)

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Syncrude Operating Statistics (total operation)

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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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.

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

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.

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.

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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.

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.

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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.

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PART IV

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

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

See Index to Exhibits on page 73 of this report.

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.

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FINANCIAL SECTION

TABLE OF CONTENTS

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BUSINESS PROFILE

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

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FINANCIAL SUMMARY