Form 10-K

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.

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.

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

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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 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

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.

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 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.

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.

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.

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 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.

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.

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.

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”).

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.

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

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.

Item 15. Exhibits, Financial Statement Schedules and 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.

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 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.

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.

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.

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.

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

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.

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.

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 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 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.

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

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

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

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 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 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 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 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.

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

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

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.

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.

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.

(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.

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

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.

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.

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 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

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.

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.

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.

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.

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.

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.

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-

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

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.

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.

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.

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.

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.

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.

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

$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.

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.

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.

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

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

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.

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.

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).

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.

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.

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.

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.

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.

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.

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

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

		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

	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

	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

	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

	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

	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

	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

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

	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

	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

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	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

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	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	%

	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

	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

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

		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

/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)