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Form 10-K

2002

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

NEW JERSEY

(State or other jurisdiction of
incorporation or organization)

13-5409005

(I.R.S. Employer
Identification Number)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant’s telephone number, including area code)

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

Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, without par value (6,689,882,215 shares outstanding at February 28, 2003)		New York Stock Exchange
Registered securities guaranteed by Registrant:
SeaRiver Maritime Financial Holdings, Inc.
Twenty-Five Year Debt Securities due October 1, 2011		New York Stock Exchange
Exxon Capital Corporation
Twelve Year 6% Notes due July 1, 2005		New York Stock Exchange

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

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

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

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

Documents Incorporated by Reference:

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

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

TABLE OF CONTENTS

		Page Number
PART I

Item 1.	Business	1-2

Item 2.	Properties	2-17

Item 3.	Legal Proceedings	17-18

Item 4.	Submission of Matters to a Vote of Security Holders	18

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]		19

PART II

Item 5.	Market for Registrant’s Common Stock and Related Shareholder Matters	20

Item 6.	Selected Financial Data	20

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	21

Item 8.	Financial Statements and Supplementary Data	21

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	21

PART III

Item 10.	Directors and Executive Officers of the Registrant	21

Item 11.	Executive Compensation	21

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	21

Item 13.	Certain Relationships and Related Transactions	21

Item 14.	Controls and Procedures	21

PART IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	22

Financial Section		23-67

Signatures		68-69

Certifications		70-72

Index to Exhibits		73

Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges

PART I

Item 1. Business.

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

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

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

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

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

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

Factors Affecting Future Results

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

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

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

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

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

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

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

Item 2. Properties.

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

Information with regard to oil and gas producing activities follows:

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

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

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

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

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

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

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

4. Gross and Net Productive Wells

	Year-End 2002				Year-End 2001
	Oil		Gas		Oil		Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
United States	34,737	13,509	9,564	5,614	35,610	14,020	9,905	5,872
Canada	6,719	5,421	5,268	2,623	6,551	5,266	5,096	2,548
Europe	1,839	593	1,398	531	1,710	548	1,356	479
Asia-Pacific	1,463	557	815	288	1,401	527	760	266
Africa	373	160	3	1	325	139	1	1
Other	1,181	221	103	32	1,086	202	123	39

Total	46,312	20,461	17,151	9,089	46,683	20,702	17,241	9,205

5. Gross and Net Developed Acreage

	Year-End 2002		Year-End 2001
	Gross	Net	Gross	Net
	(Thousands of acres)
United States	9,451	5,695	9,528	5,714
Canada	4,720	2,356	4,538	2,414
Europe	11,842	4,874	11,206	4,819
Asia-Pacific	5,393	1,692	5,203	1,640
Africa	2,251	685	2,108	630
Other	9,223	1,845	9,223	1,846

Total	42,880	17,147	41,806	17,063

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

6. Gross and Net Undeveloped Acreage

	Year-End 2002		Year-End 2001
	Gross	Net	Gross	Net
	(Thousands of acres)
United States	11,396	7,309	11,801	7,669
Canada	18,704	8,701	21,151	9,552
Europe	9,305	2,687	13,218	4,624
Asia-Pacific	24,127	12,163	28,295	14,161
Africa	29,488	12,205	43,660	15,736
Other	26,492	18,012	33,190	20,456

Total	119,512	61,077	151,315	72,198

7. Summary of Acreage Terms in Key Areas

UNITED STATES

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

CANADA

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

EUROPE

France

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

Germany

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

Italy

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

Netherlands

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

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

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

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

Norway

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

United Kingdom

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

ASIA-PACIFIC

Australia

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

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

Indonesia

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

Japan

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

Malaysia

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

Papua New Guinea

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

Russia

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

Thailand

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

AFRICA

Angola

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

Cameroon

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

Chad

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

Equatorial Guinea

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

Nigeria

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

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

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

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

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

OTHER COUNTRIES

United Arab Emirates

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

Argentina

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

Azerbaijan

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

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

Kazakhstan

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

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

Qatar

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

Republic of Yemen

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

Venezuela

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

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

8. Number of Net Productive and Dry Wells Drilled

	2002	2001	2000
A. Net Productive Exploratory Wells Drilled
United States	12	4	2
Canada	20	30	49
Europe	2	3	3
Asia-Pacific	2	7	5
Africa	10	4	2
Other	—	3	1

Total	46	51	62

B. Net Dry Exploratory Wells Drilled
United States	5	4	2
Canada	4	22	12
Europe	4	3	3
Asia-Pacific	1	2	3
Africa	5	4	4
Other	4	6	2

Total	23	41	26

C. Net Productive Development Wells Drilled
United States	709	733	604
Canada	430	451	213
Europe	36	32	40
Asia-Pacific	67	44	30
Africa	27	23	16
Other	18	30	31

Total	1,287	1,313	934

D. Net Dry Development Wells Drilled
United States	18	14	7
Canada	8	6	—
Europe	2	3	5
Asia-Pacific	1	1	1
Africa	—	—	—
Other	—	—	—

Total	29	24	13


Total number of net wells drilled	1,385	1,429	1,035

9. Present Activities

A. Wells Drilling

	Year-End 2002		Year-End 2001
	Gross	Net	Gross	Net
United States	157	75	138	83
Canada	51	37	33	19
Europe	45	17	7	2
Asia-Pacific	10	6	26	14
Africa	78	31	13	4
Other	33	5	10	3

Total	374	171	227	125

B. Review of Principal Ongoing Activities in Key Areas

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

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

UNITED STATES

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

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

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

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

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

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

CANADA

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

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

EUROPE

France

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

Germany

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

Italy

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

Netherlands

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

Norway

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

United Kingdom

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

ASIA-PACIFIC

Australia

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

Indonesia

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

Japan

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

Malaysia

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

Papua New Guinea

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

Russia

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

Thailand

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

AFRICA

Angola

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

Cameroon

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

Chad

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

Equatorial Guinea

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

Nigeria

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

OTHER COUNTRIES

United Arab Emirates

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

Argentina

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

Azerbaijan

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

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

Kazakhstan

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

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

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

Qatar

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

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

Republic of Yemen

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

Venezuela

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

WORLDWIDE EXPLORATION

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

Information with regard to mining activities follows:

Syncrude Operations

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

Operating License and Leases

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

Operations, Plant and Equipment

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

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

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

Synthetic Crude Oil Reserves

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

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

ExxonMobil Share of Net Proven Syncrude Reserves(1)

	Synthetic Crude Oil
	Base Mine and North Mine		Aurora Mine		Total
	(millions of barrels)
January 1, 2002	358		463		821
Revision of previous estimate	—		—		—
Production	(14	)	(7	)	(21	)

December 31, 2002	344		456		800

(1)

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

Syncrude Operating Statistics (total operation)

	2002	2001	2000	1999	1998
Operating Statistics
Total mined volume (millions of cubic yards)(1)	102.0	118.3	85.1	100.1	98.4
Mined volume to tar sands ratio(1)	1.05	1.15	0.96	0.99	1.05

Tar sands mined (million of tons)	172.1	181.2	156.4	178.7	165.9
Average bitumen grade (weight percent)	11.2	11.0	11.0	10.8	10.7

Crude bitumen in mined tar sands (millions of tons)	19.2	19.9	17.2	19.3	17.8
Average extraction recovery (percent)	89.9	87.0	89.7	91.4	91.6

Crude bitumen production (millions of barrels)(2)	97.8	97.6	86.8	99.6	92.1
Average upgrading yield (percent)	86.3	84.5	84.3	83.9	84.6

Gross synthetic crude oil produced (millions of barrels)	84.8	82.4	73.2	83.6	77.9

ExxonMobil net share (millions of barrels)(3)	21	19	15	20	19

(1)

Includes pre-stripping of mine areas and reclamation volumes.

(2)

Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.

(3)

Reflects ExxonMobil’s 25 percent interest in production less applicable royalties payable to the Province of Alberta.

Item 3. Legal Proceedings.

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

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

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

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

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

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

None.

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.

PART II

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

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

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

Item 6. Selected Financial Data.

	Years Ended December 31,
	2002		2001		2000		1999		1998
	(millions of dollars, except per share amounts)
Sales and other operating revenue, including excise taxes	$	200,949	$	208,715	$	227,596	$	181,759	$	164,883

Net income
Income from continuing operations	$	11,011	$	15,003	$	15,806	$	7,845	$	8,131
Discontinued operations, net of income tax	$	449	$	102	$	184	$	65	$	13
Extraordinary gain, net of income tax	$	—	$	215	$	1,730	$	—	$	—
Cumulative effect of accounting change	$	—	$	—	$	—	$	—	$	(70	)

Net income	$	11,460	$	15,320	$	17,720	$	7,910	$	8,074

Net income per common share
Income from continuing operations	$	1.62	$	2.19	$	2.27	$	1.13	$	1.16
Discontinued operations, net of income tax	$	0.07	$	0.01	$	0.03	$	0.01	$	—
Extraordinary gain, net of income tax	$	—	$	0.03	$	0.25	$	—	$	—
Cumulative effect of accounting change	$	—	$	—	$	—	$	—	$	(0.01	)

Net income	$	1.69	$	2.23	$	2.55	$	1.14	$	1.15

Net income per common share - assuming dilution
Income from continuing operations	$	1.61	$	2.17	$	2.24	$	1.11	$	1.15
Discontinued operations, net of income tax	$	0.07	$	0.01	$	0.03	$	0.01	$	—
Extraordinary gain, net of income tax	$	—	$	0.03	$	0.25	$	—	$	—
Cumulative effect of accounting change	$	—	$	—	$	—	$	—	$	(0.01	)

Net income	$	1.68	$	2.21	$	2.52	$	1.12	$	1.14

Cash dividends per common share	$	0.920	$	0.910	$	0.880	$	0.844	$	0.833

Total assets	$	152,644	$	143,174	$	149,000	$	144,521	$	139,335

Long-term debt	$	6,655	$	7,099	$	7,280	$	8,402	$	8,532

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

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

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

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

Item 8. Financial Statements and Supplementary Data.

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

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

None.

PART III

Item 10. Directors and Executive Officers of the Registrant.

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

Item 11. Executive Compensation.

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

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

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

Item 13. Certain Relationships and Related Transactions.

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

Item 14. Controls and Procedures.

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

PART IV

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

(a)

(1) and (2) Financial Statements:

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

(a)

(3) Exhibits:

See Index to Exhibits on page 73 of this report.

(b)

Reports on Form 8-K.

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

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

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

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

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

FINANCIAL SECTION

TABLE OF CONTENTS

Business Profile		24
Financial Summary		25
Frequently Used Terms		26-27
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Functional Earnings		28
Overview		29
Review of 2002 and 2001 Results		29
Liquidity and Capital Resources		30
Capital and Exploration Expenditures		32
Merger of Exxon Corporation and Mobil Corporation		33
Merger Expenses and Reorganization Reserves		33
Site Restoration and Other Environmental Costs		33
Taxes		33
Market Risks, Inflation and Other Uncertainties		33
Recently Issued Financial Accounting Standards		34
Critical Accounting Policies		35
Forward-Looking Statements		37
Management’s Discussion of Internal Controls for Financial Reporting		38
Report of Independent Accountants		38
Consolidated Financial Statements
Statement of Income		39
Balance Sheet		40
Statement of Shareholders’ Equity		41
Statement of Cash Flows		42
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies		43
2. Extraordinary Item		44
3. Discontinued Operations		45
4. Merger Expenses and Reorganization Reserves		45
5. Miscellaneous Financial Information		45
6. Cash Flow Information		45
7. Additional Working Capital Data		45
8. Equity Company Information		46
9. Investments and Advances		47
10. Investment in Property, Plant and Equipment		47
11. Leased Facilities		47
12. Employee Stock Ownership Plans		47
13. Capital		48
14. Financial Instruments and Derivatives		49
15. Long-Term Debt		49
16. Incentive Program		55
17. Litigation and Other Contingencies		56
18. Annuity Benefits and Other Postretirement Benefits		57
19. Disclosures about Segments and Related Information		58
20. Income, Excise and Other Taxes		60
Quarterly Information		61
Supplemental Information on Oil and Gas Exploration and Production Activities		62-66
Operating Summary		67

BUSINESS PROFILE

	Earnings After Income Taxes						Average Capital Employed				Return on Average Capital Employed		Capital and Exploration Expenditures
	2002			2001			2002		2001		2002	2001	2002		2001
	(millions of dollars)										(percent)		(millions of dollars)
Financial
Upstream
United States	$	2,524		$	3,933		$	13,264	$	12,952	19.0	30.4	$	2,357	$	2,423
Non-U.S.		7,074			6,803			29,800		27,077	23.7	25.1		8,037		6,393

Total	$	9,598		$	10,736		$	43,064	$	40,029	22.3	26.8	$	10,394	$	8,816

Downstream
United States	$	693		$	1,924		$	8,060	$	7,711	8.6	25.0	$	980	$	961
Non-U.S.		607			2,303			17,985		18,610	3.4	12.4		1,470		1,361

Total	$	1,300		$	4,227		$	26,045	$	26,321	5.0	16.1	$	2,450	$	2,322

Chemicals
United States	$	384		$	398		$	5,235	$	5,506	7.3	7.2	$	575	$	432
Non-U.S.		446			484			8,410		8,333	5.3	5.8		379		440

Total	$	830		$	882		$	13,645	$	13,839	6.1	6.4	$	954	$	872
Corporate and financing		(442	)		(142	)		4,878		6,399	—	—		77		158
Merger expenses		(275	)		(525	)		—		—	—	—		—		—
Gain from required asset divestitures		—			40			—		—	—	—		—		—
Discontinued operations		449			102			710		1,412	63.2	7.2		80		143

ExxonMobil Total	$	11,460		$	15,320		$	88,342	$	88,000	13.5	17.8	$	13,955	$	12,311


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

	2002			2001
	(thousands of barrels daily)
Operating
Net liquids production
United States		681			712
Non-U.S.		1,815			1,830

Total		2,496			2,542

	(millions of cubic feet daily)
Natural gas production available for sale
United States		2,375			2,598
Non-U.S.		8,077			7,681

Total		10,452			10,279

	(thousands of oil- equivalent barrels daily)
Oil-equivalent production*		4,238			4,255

	(thousands of barrels daily)
Petroleum product sales
United States		2,731			2,751
Non-U.S.		5,026			5,220

Total		7,757			7,971

	(thousands of barrels daily)
Refinery throughput
United States		1,871			1,840
Non-U.S.		3,610			3,731

Total		5,481			5,571

	(thousands of metric tons)
Chemical prime product sales		26,925			25,780

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

FINANCIAL SUMMARY

	2002			2001			2000			1999			1998
	(millions of dollars, except per share amounts)
Sales and other operating revenue
Upstream	$	16,484		$	18,567		$	21,509		$	14,565		$	13,601
Downstream		168,032			174,185			188,563			153,345			137,599
Chemicals		16,408			15,943			17,501			13,777			13,589
Other		25			20			23			72			94

Sales and other operating revenue, including excise taxes	$	200,949		$	208,715		$	227,596		$	181,759		$	164,883
Earnings from equity interests and other revenue		3,557			4,070			4,250			2,994			4,013

Total revenue	$	204,506		$	212,785		$	231,846		$	184,753		$	168,896

Earnings
Upstream	$	9,598		$	10,736		$	12,685		$	6,244		$	3,706
Downstream		1,300			4,227			3,418			1,227			3,474
Chemicals		830			882			1,161			1,354			1,394
Corporate and financing		(442	)		(142	)		(538	)		(511	)		(443	)
Merger expenses		(275	)		(525	)		(920	)		(469	)		—
Gain from required asset divestitures		—			40			1,730			—			—
Discontinued operations		449			102			184			65			13
Accounting change		—			—			—			—			(70	)

Net income	$	11,460		$	15,320		$	17,720		$	7,910		$	8,074


Net income per common share	$	1.69		$	2.23		$	2.55		$	1.14		$	1.15
Net income per common share – assuming dilution	$	1.68		$	2.21		$	2.52		$	1.12		$	1.14

Cash dividends per common share	$	0.920		$	0.910		$	0.880		$	0.844		$	0.833

Net income to average shareholders’ equity (percent)		15.5			21.3			26.4			12.6			12.9
Net income to total revenue (percent)		5.6			7.2			7.6			4.3			4.8

Working capital	$	5,116		$	5,567		$	2,208		$	(7,592	)	$	(5,187	)
Ratio of current assets to current liabilities		1.15			1.18			1.06			0.80			0.85

Total additions to property, plant and equipment	$	11,437		$	9,989		$	8,446		$	10,849		$	12,730
Property, plant and equipment, less allowances	$	94,940		$	89,602		$	89,829		$	94,043		$	92,583
Total assets	$	152,644		$	143,174		$	149,000		$	144,521		$	139,335

Exploration expenses, including dry holes	$	920		$	1,175		$	936		$	1,246		$	1,506
Research and development costs	$	631		$	603		$	564		$	630		$	753

Long-term debt	$	6,655		$	7,099		$	7,280		$	8,402		$	8,532
Total debt	$	10,748		$	10,802		$	13,441		$	18,972		$	17,016
Fixed charge coverage ratio (times)		13.8			17.7			15.6			6.6			6.9
Debt to capital (percent)		12.2			12.4			15.4			22.0			20.6
Net debt to capital (percent)		4.4			5.3			7.9			20.4			18.2

Shareholders’ equity at year-end	$	74,597		$	73,161		$	70,757		$	63,466		$	62,120
Shareholders’ equity per common share	$	11.13		$	10.74		$	10.21		$	9.13		$	8.98
Average number of common shares outstanding (millions)		6,753			6,868			6,953			6,906			6,937

Number of regular employees at year-end (thousands)		92.5			97.9			99.6			106.9			111.6

FREQUENTLY USED TERMS

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

EARNINGS EXCLUDING MERGER EXPENSES, DISCONTINUED OPERATIONS AND OTHER SPECIAL ITEMS

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

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

OPERATING COSTS

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

Operating costs excluding merger expenses	2002		2001		2000
	(millions of dollars)
From ExxonMobil’s Consolidated Statement of Income:
Operating expenses	$	17,831	$	17,743	$	17,600
Selling, general and administrative expenses		12,356		12,898		12,044
Depreciation and depletion		8,310		7,848		8,001
Exploration expenses, including dry holes		920		1,175		936

Subtotal		39,417		39,664		38,581
ExxonMobil’s share of equity company expenses		3,800		3,832		4,355

Total operating costs	$	43,217	$	43,496	$	42,936

CASH FLOW FROM OPERATIONS AND ASSET SALES

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

Cash flow from operations and asset sales	2002		2001		2000
	(millions of dollars)
Net cash provided by operating activities	$	21,268	$	22,889	$	22,937
Sales of subsidiaries, investments and property, plant and equipment		2,793		1,078		5,770

Cash flow from operations and asset sales	$	24,061	$	23,967	$	28,707

CAPITAL EMPLOYED

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

Capital employed	2002			2001			2000
	(millions of dollars)
Business uses: asset and liability perspective
Total assets	$	152,644		$	143,174		$	149,000
Less liabilities and minority share of assets and liabilities
Total current liabilities excluding notes and loans payable		(29,082	)		(26,411	)		(32,030	)
Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies		(35,449	)		(29,975	)		(29,542	)
Minority share of assets and liabilities		(4,210	)		(3,985	)		(4,601	)
Add ExxonMobil share of debt-financed equity company net assets		4,795			5,182			5,187

Total capital employed	$	88,698		$	87,985		$	88,014

Total corporate sources: debt and equity perspective
Notes and loans payable	$	4,093		$	3,703		$	6,161
Long-term debt		6,655			7,099			7,280
Shareholders’ equity		74,597			73,161			70,757
Less minority share of total debt		(1,442	)		(1,160	)		(1,371	)
Add ExxonMobil share of equity company debt		4,795			5,182			5,187

Total capital employed	$	88,698		$	87,985		$	88,014

RETURN ON AVERAGE CAPITAL EMPLOYED

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

Return on average capital employed	2002			2001			2000
	(millions of dollars)
Net income	$	11,460		$	15,320		$	17,720
Financing costs (after tax)
Third-party debt		(81	)		(96	)		(252	)
ExxonMobil share of equity companies		(227	)		(229	)		(298	)
All other financing costs – net		(127	)		(25	)		238

Total financing costs		(435	)		(350	)		(312	)

Earnings excluding financing costs	$	11,895		$	15,670		$	18,032

Average capital employed	$	88,342		$	88,000		$	87,463

Return on average capital employed – corporate total		13.5	%		17.8	%		20.6	%

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

FUNCTIONAL EARNINGS	2002			2001			2000
	(millions of dollars, except per share amounts)
Net Income (U.S. GAAP)
Upstream
United States	$	2,524		$	3,933		$	4,542
Non-U.S.		7,074			6,803			8,143
Downstream
United States		693			1,924			1,561
Non-U.S.		607			2,303			1,857
Chemicals
United States		384			398			644
Non-U.S.		446			484			517
Corporate and financing		(442	)		(142	)		(538	)
Merger expenses		(275	)		(525	)		(920	)
Gain from required asset divestitures		—			40			1,730
Discontinued operations		449			102			184

Net income (U.S. GAAP)	$	11,460		$	15,320		$	17,720

Net income per common share (U.S. GAAP)	$	1.69		$	2.23		$	2.55
Net income per common share – assuming dilution (U.S. GAAP)	$	1.68		$	2.21		$	2.52

Merger Effects, Discontinued Operations and Other Special Items
Upstream
United States	$	—		$	—		$	—
Non-U.S.		(215	)		—			—
Downstream
United States		—			—			—
Non-U.S.		—			—			—
Chemicals
United States (extraordinary item)		—			100			—
Non-U.S. (extraordinary item)		—			75			—
Merger expenses		(275	)		(525	)		(920	)
Gain from required asset divestitures (extraordinary item)		—			40			1,730
Discontinued operations		449			102			184

Corporate total	$	(41	)	$	(208	)	$	994


Earnings Excluding Merger Effects, Discontinued Operations and Other Special Items
Upstream
United States	$	2,524		$	3,933		$	4,542
Non-U.S.		7,289			6,803			8,143
Downstream
United States		693			1,924			1,561
Non-U.S.		607			2,303			1,857
Chemicals
United States		384			298			644
Non-U.S.		446			409			517
Corporate and financing		(442	)		(142	)		(538	)

Corporate total	$	11,501		$	15,528		$	16,726

Earnings per common share	$	1.70		$	2.27		$	2.40
Earnings per common share – assuming dilution	$	1.69		$	2.25		$	2.37

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

OVERVIEW

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

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

REVIEW OF 2002 RESULTS

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

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

Upstream

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

Downstream

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

Chemicals

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

Corporate and Financing

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

Discontinued Operations

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

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

REVIEW OF 2001 RESULTS

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

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

Upstream

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

Downstream

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

Chemicals

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

Corporate and Financing

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

Discontinued Operations

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

LIQUIDITY AND CAPITAL RESOURCES

2002

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

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

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

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

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

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

2001

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

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

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

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

Long-Term Contractual Obligations and Other Commercial Commitments

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

		Payments Due by Period
Long-Term Contractual Obligations	Note Reference Number	2003		2004 - 2007		2008 and Beyond		2002 Total Amount		2001 Total Amount
	(millions of dollars)
Long-term debt (1)	15	$	—	$	3,065	$	3,590	$	6,655	$	7,099
— Due in one year (2)			884		—		—		884		339
ExxonMobil share of equity company long-term debt (3)	8		—		1,973		1,379		3,352		3,950
— Due in one year (2)			707		—		—		707		590
Operating leases (4)	11		1,352		3,160		2,433		6,945		6,924
Unconditional purchase obligations (5)	17		337		1,140		2,172		3,649		2,029
Firm capital commitments (6)			4,350		2,986		1,113		8,449		3,885

Total		$	7,630	$	12,324	$	10,687	$	30,641	$	24,816

Notes:

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

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

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

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

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

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

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

Other Commercial Commitments

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

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

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

	2002	2001	2000
Fixed charge coverage ratio (times)	13.8	17.7	15.6
Debt to capital (percent)	12.2	12.4	15.4
Net debt to capital (percent) (1)	4.4	5.3	7.9
Credit rating	AAA/Aaa	AAA/Aaa	AAA/Aaa

(1) Debt net of all cash

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

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

Litigation and Other Contingencies

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

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

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

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

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

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

CAPITAL AND EXPLORATION EXPENDITURES

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

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

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

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

MERGER OF EXXON CORPORATION AND MOBIL CORPORATION

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

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

MERGER EXPENSES AND REORGANIZATION RESERVES

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

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

	Opening Balance	Additions	Deductions	Balance at Year End
	(millions of dollars)
2000	$381	$738	$780	$339
2001	339	187	329	197
2002	197	93	189	101

SITE RESTORATION AND OTHER ENVIRONMENTAL COSTS

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

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

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

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

TAXES

2002

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

2001

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

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

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

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.

Risk Management

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

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

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

Debt-Related Instruments

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

Foreign Currency Exchange Rate Instruments

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

Commodity Instruments

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

Inflation and Other Uncertainties

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

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

RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

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

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

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

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

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

CRITICAL ACCOUNTING POLICIES

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

Oil and Gas Reserves

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

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.

Consolidations

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

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

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

Annuity Plans

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

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

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

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

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

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

Litigation and Other Contingencies

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

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

Foreign Currency Translation

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

FORWARD-LOOKING STATEMENTS

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

MANAGEMENT’S DISCUSSION OF INTERNAL CONTROLS FOR FINANCIAL REPORTING

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

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

/s/ Lee R. Raymond	/s/ Donald D. Humphreys	/s/ Frank A. Risch
Lee R. Raymond	Donald D. Humphreys	Frank A. Risch
Chief Executive Officer	Vice President and Controller (Principal Accounting Officer)	Vice President and Treasurer (Principal Financial Officer)

REPORT OF INDEPENDENT ACCOUNTANTS

[LOGO OF PRICEWATERHOUSECOOPERS]

To the Shareholders of Exxon Mobil Corporation

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

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 26, 2003

CONSOLIDATED STATEMENT OF INCOME

	2002		2001		2000
	(millions of dollars)
Revenue
Sales and other operating revenue, including excise taxes	$	200,949	$	208,715	$	227,596
Earnings from equity interests and other revenue		3,557		4,070		4,250

Total revenue	$	204,506	$	212,785	$	231,846

Costs and other deductions
Crude oil and product purchases	$	90,950	$	92,257	$	108,913
Operating expenses		17,831		17,743		17,600
Selling, general and administrative expenses		12,356		12,898		12,044
Depreciation and depletion		8,310		7,848		8,001
Exploration expenses, including dry holes		920		1,175		936
Merger related expenses		410		748		1,406
Interest expense		398		293		589
Excise taxes		22,040		21,907		22,356
Other taxes and duties		33,572		33,377		32,708
Income applicable to minority and preferred interests		209		569		412

Total costs and other deductions	$	186,996	$	188,815	$	204,965

Income before income taxes	$	17,510	$	23,970	$	26,881
Income taxes		6,499		8,967		11,075

Income from continuing operations	$	11,011	$	15,003	$	15,806
Discontinued operations, net of income tax		449		102		184
Extraordinary gain, net of income tax		—		215		1,730

Net income	$	11,460	$	15,320	$	17,720

Net income per common share (dollars)
Income from continuing operations	$	1.62	$	2.19	$	2.27
Discontinued operations, net of income tax		0.07		0.01		0.03
Extraordinary gain, net of income tax		—		0.03		0.25

Net income	$	1.69	$	2.23	$	2.55

Net income per common share – assuming dilution (dollars)
Income from continuing operations	$	1.61	$	2.17	$	2.24
Discontinued operations, net of income tax		0.07		0.01		0.03
Extraordinary gain, net of income tax		—		0.03		0.25

Net income	$	1.68	$	2.21	$	2.52

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

CONSOLIDATED BALANCE SHEET

	Dec. 31 2002			Dec. 31 2001
	(millions of dollars)
Assets
Current assets
Cash and cash equivalents	$	7,229		$	6,547
Notes and accounts receivable, less estimated doubtful amounts		21,163			19,549
Inventories
Crude oil, products and merchandise		6,827			6,743
Materials and supplies		1,241			1,161
Prepaid taxes and expenses		1,831			1,681

Total current assets	$	38,291		$	35,681
Investments and advances		12,111			10,768
Property, plant and equipment, at cost, less accumulated depreciation and depletion		94,940			89,602
Other assets, including intangibles, net		7,302			7,123

Total assets	$	152,644		$	143,174

Liabilities
Current liabilities
Notes and loans payable	$	4,093		$	3,703
Accounts payable and accrued liabilities		25,186			22,862
Income taxes payable		3,896			3,549

Total current liabilities	$	33,175		$	30,114
Long-term debt		6,655			7,099
Annuity reserves and accrued liabilities		16,454			12,475
Deferred income tax liabilities		16,484			16,359
Deferred credits and other long-term obligations		2,511			1,141
Equity of minority and preferred shareholders in affiliated companies		2,768			2,825

Total liabilities	$	78,047		$	70,013

Shareholders’ equity
Benefit plan related balances	$	(450	)	$	(159	)
Common stock without par value (9,000 million shares authorized)		4,217			3,789
Earnings reinvested		100,961			95,718
Accumulated other nonowner changes in equity
Cumulative foreign exchange translation adjustment		(3,015	)		(5,947	)
Minimum pension liability adjustment		(2,960	)		(535	)
Unrealized gains/(losses) on stock investments		(79	)		(108	)
Common stock held in treasury (1,319 million shares in 2002 and 1,210 million shares in 2001)		(24,077	)		(19,597	)

Total shareholders’ equity	$	74,597		$	73,161

Total liabilities and shareholders’ equity	$	152,644		$	143,174

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

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

	2002						2001						2000
	Shareholders’ Equity			Nonowner Changes in Equity			Shareholders’ Equity			Nonowner Changes in Equity			Shareholders’ Equity			Nonowner Changes in Equity
	(millions of dollars)
Benefit plan related balances
At beginning of year	$	(159	)				$	(235	)				$	(298	)
Restricted stock award		(361	)					—						—
Amortization		11						—						—
Other		59						76						63

At end of year	$	(450	)				$	(159	)				$	(235	)

Common stock (see note 13)
At beginning of year		3,789						3,661						3,403
Issued		—						—						—
Other		428						128						258

At end of year	$	4,217					$	3,789					$	3,661

Earnings reinvested
At beginning of year		95,718						86,652						75,055
Net income for the year		11,460		$	11,460			15,320		$	15,320			17,720		$	17,720
Dividends – common shares		(6,217	)					(6,254	)					(6,123	)

At end of year	$	100,961					$	95,718					$	86,652

Accumulated other nonowner changes in equity
At beginning of year		(6,590	)					(5,189	)					(2,568	)
Foreign exchange translation adjustment		2,932			2,932			(1,085	)		(1,085	)		(2,562	)		(2,562	)
Minimum pension liability adjustment		(2,425	)		(2,425	)		(225	)		(225	)		(11	)		(11	)
Unrealized gains/(losses) on stock investments		29			29			(91	)		(91	)		(48	)		(48	)

At end of year	$	(6,054	)				$	(6,590	)				$	(5,189	)

Total				$	11,996					$	13,919					$	15,099

Common stock held in treasury
At beginning of year		(19,597	)					(14,132	)					(12,126	)
Acquisitions, at cost		(4,798	)					(5,721	)					(2,352	)
Dispositions		318						256						346

At end of year	$	(24,077	)				$	(19,597	)				$	(14,132	)

Shareholders’ equity at end of year	$	74,597					$	73,161					$	70,757


	Share Activity
	2002						2001						2000
	(millions of shares)
Common stock
Issued (see note 13)
At beginning of year		8,019						8,019						8,019
Issued		—						—						—

At end of year		8,019						8,019						8,019

Held in treasury (see note 13)
At beginning of year		(1,210	)					(1,089	)					(1,064	)
Acquisitions		(127	)					(139	)					(54	)
Dispositions		18						18						29

At end of year		(1,319	)					(1,210	)					(1,089	)

Common shares outstanding at end of year		6,700						6,809						6,930

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

CONSOLIDATED STATEMENT OF CASH FLOWS

	2002			2001			2000
	(millions of dollars)
Cash flows from operating activities
Net income
Accruing to ExxonMobil shareholders	$	11,460		$	15,320		$	17,720
Accruing to minority and preferred interests		209			569			412
Adjustments for non-cash transactions
Depreciation and depletion		8,310			7,848			8,001
Deferred income tax charges/(credits)		297			650			10
Annuity and accrued liability provisions		(590	)		498			(662	)
Dividends received greater than/(less than) equity in current earnings of equity companies		(170	)		78			(387	)
Extraordinary gain, before income tax		—			(194	)		(2,038	)
Changes in operational working capital, excluding cash and debt
Reduction/(increase) – Notes and accounts receivable		(305	)		3,062			(4,832	)
– Inventories		353			154			(297	)
– Prepaid taxes and expenses		32			118			(204	)
Increase/(reduction) – Accounts and other payables		365			(5,103	)		5,411
All other items – net		1,307			(111	)		(197	)

Net cash provided by operating activities	$	21,268		$	22,889		$	22,937

Cash flows from investing activities
Additions to property, plant and equipment	$	(11,437	)	$	(9,989	)	$	(8,446	)
Sales of subsidiaries, investments and property, plant and equipment		2,793			1,078			5,770
Additional investments and advances		(2,012	)		(1,035	)		(1,648	)
Collection of advances		898			1,735			985
Additions to other marketable securities		—			—			(41	)
Sales of other marketable securities		—			—			82

Net cash used in investing activities	$	(9,758	)	$	(8,211	)	$	(3,298	)

Net cash generation before financing activities	$	11,510		$	14,678		$	19,639

Cash flows from financing activities
Additions to long-term debt	$	396		$	547		$	238
Reductions in long-term debt		(246	)		(506	)		(901	)
Additions to short-term debt		751			705			500
Reductions in short-term debt		(927	)		(1,212	)		(2,413	)
Additions/(reductions) in debt with less than 90 day maturity		(281	)		(2,306	)		(3,129	)
Cash dividends to ExxonMobil shareholders		(6,217	)		(6,254	)		(6,123	)
Cash dividends to minority interests		(169	)		(194	)		(251	)
Changes in minority interests and sales/(purchases) of affiliate stock		(161	)		(401	)		(227	)
Common stock acquired		(4,798	)		(5,721	)		(2,352	)
Common stock sold		299			301			493

Net cash used in financing activities	$	(11,353	)	$	(15,041	)	$	(14,165	)

Effects of exchange rate changes on cash	$	525		$	(170	)	$	(82	)

Increase/(decrease) in cash and cash equivalents	$	682		$	(533	)	$	5,392
Cash and cash equivalents at beginning of year		6,547			7,080			1,688

Cash and cash equivalents at end of year	$	7,229		$	6,547		$	7,080

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

1. Summary of Accounting Policies

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

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

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

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

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

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

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

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

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

The corporation’s upstream activities are accounted for under the “successful efforts” method. Under this method, costs of productive wells and development dry holes, both tangible and intangible, as well as productive acreage are capitalized and amortized on the unit-of-production method. Costs of that portion of undeveloped acreage likely to be unproductive, based largely on historical experience, are amortized over the period of exploration. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred. Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to assure that commercial quantities of reserves have been found or that additional exploration work is under way or planned. Exploratory well costs not meeting either of these tests are charged to expense.

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

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

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

	2002			2001			2000
	(millions of dollars)
Net income, as reported	$	11,460		$	15,320		$	17,720
Add: Stock-based compensation, net of tax included in reported net income		19			8			(2	)
Deduct: Stock-based compensation, net of tax determined under fair value based method		(180	)		(293	)		(294	)

Pro forma net income	$	11,299		$	15,035		$	17,424

	(dollars per share)
Net income per share:
Basic – as reported	$	1.69		$	2.23		$	2.55
Basic – pro forma		1.67			2.19			2.51
Diluted – as reported		1.68			2.21			2.52
Diluted – pro forma		1.66			2.17			2.48

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

2. Extraordinary Item

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

3. Discontinued Operations

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

4. Merger Expenses and Reorganization Reserves

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

In association with the Merger, $410 million pre-tax ($275 million after-tax), $748 million pre-tax ($525 million after-tax) and $1,406 million pre-tax ($920 million after-tax) of costs were recorded as merger-related expenses in 2002, 2001 and 2000, respectively. Cumulative charges for the period 1999 to 2002 of $3,189 million included separation expenses of approximately $1,460 million related to workforce reductions (approximately 8,200 employees at year-end 2002), plus implementation costs and merger closing costs. Reflecting the completion of merger-related activities, merger expenses will not be reported in 2003.

The separation reserve balance at year-end 2002 of approximately $101 million is expected to be expended in 2003.

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

	Opening Balance		Additions		Deductions		Balance at Year End
	(millions of dollars)
2000	$	381	$	738	$	780	$	339
2001		339		187		329		197
2002		197		93		189		101

5. Miscellaneous Financial Information

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

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

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

6. Cash Flow Information

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

In 2002, the “All other items – net” line in cash flow from operations included $1.5 billion in funds received from BEB Erdgas und Erdoel GmbH (“BEB”), a German exploration and production company indirectly owned 50 percent and accounted for under the equity method of accounting. The funds were loaned in connection with a restructuring that will enable BEB to transfer its holdings in Ruhrgas AG, a German gas transmission company. It is anticipated that net income will be recognized in 2003 upon finalization of regulatory reviews and completion of the transfer of the Ruhrgas shares.

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

7. Additional Working Capital Data

	Dec. 31 2002		Dec. 31 2001
	(millions of dollars)
Notes and accounts receivable
Trade, less reserves of $314 million and $279 million	$	15,317	$	13,597
Other, less reserves of $39 million and $62 million		5,846		5,952

	$	21,163	$	19,549

Notes and loans payable
Bank loans	$	987	$	1,063
Commercial paper		1,870		1,804
Long-term debt due within one year		884		339
Other		352		497

	$	4,093	$	3,703

Accounts payable and accrued liabilities
Trade payables	$	13,792	$	12,696
Obligations to equity companies		1,192		632
Accrued taxes other than income taxes		4,628		4,768
Other		5,574		4,766

	$	25,186	$	22,862

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. Equity Company Information

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

	2002						2001						2000
Equity Company Financial Summary	Total			ExxonMobil Share			Total			ExxonMobil Share			Total			ExxonMobil Share
	(millions of dollars)
Total revenues (a)	$	47,204		$	17,230		$	47,072		$	17,520		$	48,550		$	19,323

Income before income taxes	$	6,028		$	2,844		$	6,952		$	2,922		$	7,632		$	3,092
Less: Related income taxes		(1,461	)		(778	)		(1,562	)		(748	)		(1,382	)		(658	)

Net income	$	4,567		$	2,066		$	5,390		$	2,174		$	6,250		$	2,434


Current assets	$	20,162		$	7,658		$	18,992		$	7,369		$	28,784		$	11,479
Property, plant and equipment, less accumulated depreciation		39,351			14,254			36,565			13,135			36,553			13,733
Other long-term assets		5,524			2,614			5,127			2,284			6,656			2,979

Total assets	$	65,037		$	24,526		$	60,684		$	22,788		$	71,993		$	28,191

Short-term debt	$	3,561		$	1,443		$	3,142		$	1,232		$	2,636		$	1,093
Other current liabilities		15,529			5,991			16,218			6,349			25,377			10,357
Long-term debt		9,236			3,352			10,496			3,950			11,116			4,094
Other long-term liabilities		8,248			3,881			6,253			2,862			7,054			3,273
Advances from shareholders		10,721			2,927			8,443			2,179			8,485			2,510

Net assets	$	17,742		$	6,932		$	16,132		$	6,216		$	17,325		$	6,864

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

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

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

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

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

9. Investments and Advances

	Dec. 31 2002		Dec. 31 2001
	(millions of dollars)
Companies carried at equity in underlying assets
Investments	$	6,932	$	6,216
Advances		2,927		2,179

	$	9,859	$	8,395
Companies carried at cost or less and stock investments carried at fair value		1,088		1,060

	$	10,947	$	9,455
Long-term receivables and miscellaneous investments at cost or less		1,164		1,313

Total	$	12,111	$	10,768

10. Investment in Property, Plant and Equipment

	Dec. 31, 2002				Dec. 31, 2001
	Cost		Net		Cost		Net
	(millions of dollars)
Upstream	$	122,210	$	51,696	$	109,786	$	46,677
Downstream		54,032		26,920		50,691		25,560
Chemicals		19,138		9,909		17,973		9,690
Other		9,580		6,415		12,053		7,675

Total	$	204,960	$	94,940	$	190,503	$	89,602

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

11. Leased Facilities

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

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

	Minimum Commitment	Related Rental Income
	(millions of dollars)
2003	$1,352	$66
2004	1,066	56
2005	836	50
2006	683	45
2007	575	37
2008 and beyond	2,433	144

Total	$6,945	$398

12. Employee Stock Ownership Plans

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. Capital

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

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

The table below summarizes the earnings per share calculations.

	2002		2001			2000
Net income per common share
Income from continuing operations (millions of dollars)	$	11,011	$	15,003		$	15,806

Weighted average number of common shares outstanding (millions of shares)		6,753		6,868			6,953

Net income per common share
Income from continuing operations	$	1.62	$	2.19		$	2.27
Discontinued operations, net of income tax		0.07		0.01			0.03
Extraordinary gain, net of income tax		—		0.03			0.25

Net income	$	1.69	$	2.23		$	2.55


Net income per common share – assuming dilution
Income from continuing operations (millions of dollars)	$	11,011	$	15,003		$	15,806
Adjustment for assumed dilution		—		(4	)		(8	)

Income available to common shares	$	11,011	$	14,999		$	15,798


Weighted average number of common shares outstanding (millions of shares)		6,753		6,868			6,953
Effect of employee stock-based awards		50		73			80

Weighted average number of common shares outstanding – assuming dilution		6,803		6,941			7,033

Net income per common share
Income from continuing operations	$	1.61	$	2.17		$	2.24
Discontinued operations, net of income tax		0.07		0.01			0.03
Extraordinary gain, net of income tax		—		0.03			0.25

Net income	$	1.68	$	2.21		$	2.52


Dividends paid per common share	$	0.92	$	0.91		$	0.88

14. Financial Instruments and Derivatives

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

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

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

15. Long-Term Debt

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

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

	2002		2001
	(millions of dollars)
Exxon Mobil Corporation
Guaranteed zero coupon notes due 2004
– Face value ($1,146) net of unamortized discount	$	933	$	836

Exxon Capital Corporation (1)
6.0% Guaranteed notes due 2005		106		106
6.125% Guaranteed notes due 2008		160		160

SeaRiver Maritime Financial Holdings, Inc. (1)
Guaranteed debt securities due 2004-2011 (2)		95		105
Guaranteed deferred interest debentures due 2012
– Face value ($771) net of unamortized discount plus accrued interest		1,006		903

Imperial Oil Limited
Variable rate notes due 2004 (3)		600		600
Variable rate Canadian dollar notes due 2004 (4)		317		—

ExxonMobil Canada Ltd.
3.0% Swiss franc debentures		—		328
5.0% U.S. dollar Eurobonds due 2004 (5)		255		262

Mobil Producing Nigeria Unlimited
8.625% notes due 2004-2006		104		146

Mobil Corporation
8.625% debentures due 2021		248		247
7.625% debentures due 2033		204		204

Industrial revenue bonds due 2007-2033 (6)		1,530		1,535
ESOP Trust notes		—		65
Other U.S. dollar obligations (7)		507		751
Other foreign currency obligations		296		585
Capitalized lease obligations (8)		294		266

Total long-term debt	$	6,655	$	7,099

(1)

Additional information is provided for these subsidiaries on pages 50-54.

(2)

Average effective interest rate of 1.8% in 2002 and 4.1% in 2001.

(3)

Average effective interest rate of 1.9% in 2002 and 4.2% in 2001.

(4)

Average effective interest rate of 2.8% in 2002.

(5)

Swapped into floating rate debt.

(6)

Average effective interest rate of 1.8% in 2002 and 3.0% in 2001.

(7)

Average effective interest rate of 5.7% in 2002 and 8.0% in 2001.

(8)

Average imputed interest rate of 6.4% in 2002 and 6.4% in 2001.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

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

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

	Exxon Mobil Corporation Parent Guarantor		Exxon Capital Corporation		SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated statement of income for twelve months ended December 31, 2002
Revenue
Sales and other operating revenue, including excise taxes	$	8,711	$	—	$	—		$	192,238	$	—		$	200,949
Earnings from equity interests and other revenue		10,757		5		(16	)		2,954		(10,143	)		3,557
Intercompany revenue		15,711		41		27			120,836		(136,615	)		—

Total revenue		35,179		46		11			316,028		(146,758	)		204,506

Costs and other deductions
Crude oil and product purchases		14,687		—		—			207,709		(131,446	)		90,950
Operating expenses		5,312		2		1			16,839		(4,323	)		17,831
Selling, general and administrative expenses		1,592		2		—			10,898		(136	)		12,356
Depreciation and depletion		1,572		5		3			6,730		—			8,310
Exploration expenses, including dry holes		147		—		—			773		—			920
Merger related expenses		70		—		—			356		(16	)		410
Interest expense		655		22		112			4,634		(5,025	)		398
Excise taxes		—		—		—			22,040		—			22,040
Other taxes and duties		12		—		—			33,560		—			33,572
Income applicable to minority and preferred interests		—		—		—			209		—			209

Total costs and other deductions		24,047		31		116			303,748		(140,946	)		186,996

Income before income taxes		11,132		15		(105	)		12,280		(5,812	)		17,510
Income taxes		121		6		(31	)		6,403		—			6,499

Income from continuing operations		11,011		9		(74	)		5,877		(5,812	)		11,011
Discontinued operations, net of income tax		449		—		—			456		(456	)		449
Extraordinary gain, net of income tax		—		—		—			—		—			—

Net income	$	11,460	$	9	$	(74	)	$	6,333	$	(6,268	)	$	11,460

	Exxon Mobil Corporation Parent Guarantor		Exxon Capital Corporation		SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated statement of income for twelve months ended December 31, 2001
Revenue
Sales and other operating revenue, including excise taxes	$	28,800	$	—	$	—		$	179,915	$	—		$	208,715
Earnings from equity interests and other revenue		13,427		—		32			3,708		(13,097	)		4,070
Intercompany revenue		6,252		584		62			106,498		(113,396	)		—

Total revenue		48,479		584		94			290,121		(126,493	)		212,785

Costs and other deductions
Crude oil and product purchases		19,483		—		—			174,455		(101,681	)		92,257
Operating expenses		5,696		3		1			17,192		(5,149	)		17,743
Selling, general and administrative expenses		2,158		2		—			10,800		(62	)		12,898
Depreciation and depletion		1,584		5		3			6,256		—			7,848
Exploration expenses, including dry holes		125		—		—			1,050		—			1,175
Merger related expenses		89		—		—			771		(112	)		748
Interest expense		1,043		531		114			4,924		(6,319	)		293
Excise taxes		1,957		—		—			19,950		—			21,907
Other taxes and duties		14		—		—			33,363		—			33,377
Income applicable to minority and preferred interests		—		—		—			569		—			569

Total costs and other deductions		32,149		541		118			269,330		(113,323	)		188,815

Income before income taxes		16,330		43		(24	)		20,791		(13,170	)		23,970
Income taxes		1,327		15		(20	)		7,645		—			8,967

Income from continuing operations		15,003		28		(4	)		13,146		(13,170	)		15,003
Discontinued operations, net of income tax		102		—		—			108		(108	)		102
Extraordinary gain, net of income tax		215		—		—			—		—			215

Net income	$	15,320	$	28	$	(4	)	$	13,254	$	(13,278	)	$	15,320

Condensed consolidated statement of income for twelve months ended December 31, 2000
Revenue
Sales and other operating revenue, including excise taxes	$	36,211	$	—	$	—		$	191,385	$	—		$	227,596
Earnings from equity interests and other revenue		14,209		—		35			3,518		(13,512	)		4,250
Intercompany revenue		4,148		997		90			92,832		(98,067	)		—

Total revenue		54,568		997		125			287,735		(111,579	)		231,846

Costs and other deductions
Crude oil and product purchases		22,790		—		—			172,974		(86,851	)		108,913
Operating expenses		5,781		3		1			16,522		(4,707	)		17,600
Selling, general and administrative expenses		1,978		—		—			10,203		(137	)		12,044
Depreciation and depletion		1,510		5		3			6,483		—			8,001
Exploration expenses, including dry holes		115		—		—			821		—			936
Merger related expenses		402		—		—			1,171		(167	)		1,406
Interest expense		1,449		916		116			4,313		(6,205	)		589
Excise taxes		2,614		—		—			19,742		—			22,356
Other taxes and duties		15		—		—			32,693		—			32,708
Income applicable to minority and preferred interests		—		—		—			412		—			412

Total costs and other deductions		36,654		924		120			265,334		(98,067	)		204,965

Income before income taxes		17,914		73		5			22,401		(13,512	)		26,881
Income taxes		2,108		20		(10	)		8,957		—			11,075

Income from continuing operations		15,806		53		15			13,444		(13,512	)		15,806
Discontinued operations, net of income tax		184		—		—			190		(190	)		184
Extraordinary gain, net of income tax		1,730		—		—			962		(962	)		1,730

Net income	$	17,720	$	53	$	15		$	14,596	$	(14,664	)	$	17,720

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

	Exxon Mobil Corporation Parent Guarantor			Exxon Capital Corporation		SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated balance sheet for year ended December 31, 2002
Cash and cash equivalents	$	710		$	—	$	—		$	6,519	$	—		$	7,229
Notes and accounts receivable – net		3,827			—		—			17,336		—			21,163
Inventories		964			—		—			7,104		—			8,068
Prepaid taxes and expenses		65			—		—			1,766		—			1,831

Total current assets		5,566			—		—			32,725		—			38,291
Investments and advances		101,694			—		400			336,061		(426,044	)		12,111
Property, plant and equipment – net		16,922			104		3			77,911		—			94,940
Other long-term assets		2,421			—		121			4,760		—			7,302
Intercompany receivables		16,234			1,395		1,490			295,909		(315,028	)		—

Total assets	$	142,837		$	1,499	$	2,014		$	747,366	$	(741,072	)	$	152,644

Notes and loans payable	$	—		$	6	$	10		$	4,077	$	—		$	4,093
Accounts payable and accrued liabilities		2,844			6		—			22,336		—			25,186
Income taxes payable		916			1		—			2,979		—			3,896

Total current liabilities		3,760			13		10			29,392		—			33,175
Long-term debt		1,311			266		1,101			3,977		—			6,655
Deferred income tax liabilities		3,163			31		301			12,989		—			16,484
Other long-term liabilities		5,820			—		—			15,913		—			21,733
Intercompany payables		54,186			290		382			260,170		(315,028	)		—

Total liabilities		68,240			600		1,794			322,441		(315,028	)		78,047
Earnings reinvested		100,961			93		(174	)		54,547		(54,466	)		100,961
Other shareholders’ equity		(26,364	)		806		394			370,378		(371,578	)		(26,364	)

Total shareholders’ equity		74,597			899		220			424,925		(426,044	)		74,597

Total liabilities and shareholders’ equity	$	142,837		$	1,499	$	2,014		$	747,366	$	(741,072	)	$	152,644

Condensed consolidated balance sheet for year ended December 31, 2001
Cash and cash equivalents	$	1,375		$	—	$	—		$	5,172	$	—		$	6,547
Notes and accounts receivable – net		2,458			—		—			17,091		—			19,549
Inventories		996			—		—			6,908		—			7,904
Prepaid taxes and expenses		155			5		8			1,513		—			1,681

Total current assets		4,984			5		8			30,684		—			35,681
Investments and advances		92,091			—		415			317,456		(399,194	)		10,768
Property, plant and equipment – net		16,843			108		6			72,645		—			89,602
Other long-term assets		753			—		137			6,233		—			7,123
Intercompany receivables		8,466			1,365		1,431			266,527		(277,789	)		—

Total assets	$	123,137		$	1,478	$	1,997		$	693,545	$	(676,983	)	$	143,174

Notes and loans payable	$	—		$	35	$	10		$	3,658	$	—		$	3,703
Accounts payable and accrued liabilities		2,735			6		1			20,120		—			22,862
Income taxes payable		767			—		—			2,782		—			3,549

Total current liabilities		3,502			41		11			26,560		—			30,114
Long-term debt		1,258			266		1,008			4,567		—			7,099
Deferred income tax liabilities		2,989			33		302			13,035		—			16,359
Other long-term liabilities		4,373			—		—			12,068		—			16,441
Intercompany payables		37,854			248		382			239,305		(277,789	)		—

Total liabilities		49,976			588		1,703			295,535		(277,789	)		70,013
Earnings reinvested		95,718			84		(100	)		48,907		(48,891	)		95,718
Other shareholders’ equity		(22,557	)		806		394			349,103		(350,303	)		(22,557	)

Total shareholders’ equity		73,161			890		294			398,010		(399,194	)		73,161

Total liabilities and shareholders’ equity	$	123,137		$	1,478	$	1,997		$	693,545	$	(676,983	)	$	143,174

	Exxon Mobil Corporation Parent Guarantor			Exxon Capital Corporation			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries			Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)

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

Cash provided by/(used in) operating activities	$	1,970		$	17		$	69		$	19,905		$	(693	)	$	21,268

Cash flows from investing activities
Additions to property, plant and equipment		(1,727	)		—			—			(9,710	)		—			(11,437	)
Sales of long-term assets		168			—			—			2,625			—			2,793
Net intercompany investing		9,640			(30	)		(59	)		(9,646	)		95			—
All other investing, net		—			—			—			(1,114	)		—			(1,114	)

Net cash provided by/(used in) investing activities		8,081			(30	)		(59	)		(17,845	)		95			(9,758	)

Cash flows from financing activities
Additions to short- and long-term debt		—			—			—			1,147			—			1,147
Reductions in short- and long-term debt		—			—			(10	)		(1,163	)		—			(1,173	)
Additions/(reductions) in debt with less than 90 day maturity		—			(29	)		—			(252	)		—			(281	)
Cash dividends		(6,217	)		—			—			(693	)		693			(6,217	)
Common stock acquired		(4,798	)		—			—			—			—			(4,798	)
Net intercompany financing activity		—			42			—			53			(95	)		—
All other financing, net		299			—			—			(330	)		—			(31	)

Net cash provided by/(used in) financing activities		(10,716	)		13			(10	)		(1,238	)		598			(11,353	)

Effects of exchange rate changes on cash		—			—			—			525			—			525

Increase/(decrease) in cash and cash equivalents	$	(665	)	$	—		$	—		$	1,347		$	—		$	682


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

Cash provided by/(used in) operating activities	$	7,277		$	12		$	113		$	16,239		$	(752	)	$	22,889

Cash flows from investing activities
Additions to property, plant and equipment		(2,058	)		—			—			(7,931	)		—			(9,989	)
Sales of long-term assets		536			—			—			542			—			1,078
Net intercompany investing		3,152			17,759			(76	)		(1,345	)		(19,490	)		—
All other investing, net		(31	)		—			—			731			—			700

Net cash provided by/(used in) investing activities		1,599			17,759			(76	)		(8,003	)		(19,490	)		(8,211	)

Cash flows from financing activities
Additions to short- and long-term debt		—			—			—			1,252			—			1,252
Reductions in short- and long-term debt		(62	)		(15	)		(7	)		(1,634	)		—			(1,718	)
Additions/(reductions) in debt with less than 90 day maturity		—			(39	)		—			(2,267	)		—			(2,306	)
Cash dividends		(6,254	)		—			—			(752	)		752			(6,254	)
Common stock acquired		(5,721	)		—			—			—			—			(5,721	)
Net intercompany financing activity		—			(17,717	)		(30	)		(1,743	)		19,490			—
All other financing, net		301			—			—			(595	)		—			(294	)

Net cash provided by/(used in) financing activities		(11,736	)		(17,771	)		(37	)		(5,739	)		20,242			(15,041	)

Effects of exchange rate changes on cash		—			—		$	—			(170	)		—			(170	)

Increase/(decrease) in cash and cash equivalents	$	(2,860	)	$	—		$	—		$	2,327		$	—		$	(533	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

	Exxon Mobil Corporation Parent Guarantor			Exxon Capital Corporation			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries			Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)

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

Cash provided by/(used in) operating activities	$	7,704		$	61		$	94		$	16,063		$	(985	)	$	22,937

Cash flows from investing activities
Additions to property, plant and equipment		(1,832	)		—			—			(6,614	)		—			(8,446	)
Sales of long-term assets		1,088			—			—			4,682			—			5,770
Net intercompany investing		6,386			(7,143	)		(114	)		(6,285	)		7,156			—
All other investing, net		(26	)		—			—			(596	)		—			(622	)

Net cash provided by/(used in) investing activities		5,616			(7,143	)		(114	)		(8,813	)		7,156			(3,298	)

Cash flows from financing activities
Additions to short- and long-term debt		23			—			—			715			—			738
Reductions in short- and long-term debt		(247	)		(214	)		(7	)		(2,846	)		—			(3,314	)
Additions/(reductions) in debt with less than 90 day maturity		(990	)		16			—			(2,155	)		—			(3,129	)
Cash dividends		(6,123	)		—			—			(985	)		985			(6,123	)
Common stock acquired		(2,352	)		—			—			—			—			(2,352	)
Net intercompany financing activity		—			7,280			27			(151	)		(7,156	)		—
All other financing, net		493			—			—			(478	)		—			15

Net cash provided by/(used in) financing activities		(9,196	)		7,082			20			(5,900	)		(6,171	)		(14,165	)

Effects of exchange rate changes on cash		—			—			—			(82	)		—			(82	)

Increase/(decrease) in cash and cash equivalents	$	4,124		$	—		$	—		$	1,268		$	—		$	5,392

16. Incentive Program

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

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

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

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

Restricted Stock and Units	2002	2001	2000
Restricted stock and units granted	11,072	348	397
Restricted stock issued and outstanding at end of year	2,382	2,559	2,438

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

	2002				2001				2000
Stock Options	Shares		Avg. Exercise Price		Shares		Avg. Exercise Price		Shares		Avg. Exercise Price
Outstanding at beginning of year	265,695		$	30.54	248,680		$	28.70	242,232		$	24.81
Granted	—			—	34,717			37.12	36,224			45.19
Exercised	(18,334	)		16.18	(16,949	)		16.63	(28,714	)		16.35
Expired/Canceled	(366	)		40.47	(753	)		39.44	(1,062	)		37.13

Outstanding at end of year	246,995			31.59	265,695			30.54	248,680			28.70

Exercisable at end of year	243,548			31.46	221,405			29.29	195,144			25.95

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

Options Outstanding				Options Exercisable
Exercise Price Range	Shares	Avg. Remaining Contractual Life	Avg. Exercise Price	Shares	Avg. Exercise Price
$11.97-16.54	34,254	1.9 years	$15.46	34,254	$15.46
19.06-27.71	60,085	4.2 years	22.98	60,085	22.98
29.18-45.22	152,656	7.2 years	38.60	149,209	38.54

Total	246,995	5.7 years	31.59	243,548	31.46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. Litigation and Other Contingencies

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

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

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

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

The U.S. Tax Court has decided the issue with respect to the pricing of crude oil purchased from Saudi Arabia for the years 1979-1981 in favor of the corporation. This decision is subject to appeal. Certain other issues for the years 1979-1993 remain pending before the Tax Court. The ultimate resolution of these issues is not expected to have a materially adverse effect upon the corporation’s operations or financial condition.

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

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

18. Annuity Benefits and Other Postretirement Benefits

	Annuity Benefits																		Other Postretirement Benefits
	U.S.									Non-U.S.									Other Postretirement Benefits
	2002			2001			2000			2002			2001			2000			2002			2001			2000
	(millions of dollars)
Components of net benefit cost
Service cost	$	224		$	200		$	214		$	257		$	232		$	245		$	30		$	27		$	24
Interest cost		577			579			592			621			598			603			220			205			201
Expected return on plan assets		(501	)		(623	)		(726	)		(561	)		(629	)		(641	)		(38	)		(43	)		(51	)
Amortization of actuarial loss/(gain) and prior service cost		121			(25	)		(168	)		190			78			55			57			4			—
Net pension enhancement and curtailment/settlement expense		49			14			(175	)		18			27			77			—			—			(5	)

Net benefit cost	$	470		$	145		$	(263	)	$	525		$	306		$	339		$	269		$	193		$	169

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

	Annuity Benefits												Other Postretirement Benefits
	U.S.						Non-U.S.						Other Postretirement Benefits
	2002			2001			2002			2001			2002			2001
	(millions of dollars)
Change in benefit obligation (1)
Benefit obligation at January 1	$	8,213		$	7,651		$	11,206		$	11,063		$	3,131		$	2,942
Service cost		224			200			257			232			30			27
Interest cost		577			579			621			598			220			205
Actuarial loss/(gain)		990			638			860			540			207			7
Benefits paid		(876	)		(868	)		(747	)		(710	)		(302	)		(258	)
Foreign exchange rate changes		—			—			1,244			(678	)		2			(12	)
Other		11			13			102			161			208			220

Benefit obligation at December 31	$	9,139		$	8,213		$	13,543		$	11,206		$	3,496		$	3,131

Change in plan assets
Fair value at January 1	$	5,415		$	6,795		$	6,755		$	7,780		$	395		$	446
Actual return on plan assets		(570	)		(647	)		(827	)		(424	)		(31	)		(34	)
Foreign exchange rate changes		—			—			647			(422	)		—			—
Payments directly to participants		163			135			259			225			203			187
Company contribution		460			—			509			299			33			32
Benefits paid		(876	)		(868	)		(747	)		(710	)		(302	)		(258	)
Other		24			—			139			7			47			22

Fair value at December 31	$	4,616		$	5,415		$	6,735		$	6,755		$	345		$	395

Assets in excess of / (less than) benefit obligation
Balance at December 31	$	(4,523	)	$	(2,798	)	$	(6,808	)	$	(4,451	)	$	(3,151	)	$	(2,736	)
Unrecognized net transition liability/(asset)		—			(2	)		30			34			—			—
Unrecognized net actuarial loss/(gain)		3,064			1,142			4,340			2,002			377			108
Unrecognized prior service cost		231			248			323			308			490			381
Intangible asset		(322	)		(226	)		(317	)		(135	)		—			—
Equity of minority shareholders		—			—			(211	)		(82	)		—			—
Minimum pension liability adjustment		(1,790	)		(144	)		(2,957	)		(805	)		—			—

Prepaid/(accrued) benefit cost	$	(3,340	)	$	(1,780	)	$	(5,600	)	$	(3,129	)	$	(2,284	)	$	(2,247	)

Assumptions as of December 31 (percent)
Discount rate		6.75			7.25			2.1-6.5			2.6-6.8			6.75			7.25
Long-term rate of compensation increase		3.50			3.50			2.4-4.2			2.8-4.3			3.50			3.50
Long-term rate of return on funded assets		9.50			9.50			6.5-8.8			6.5-10.0			9.50			9.50

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Annuity Benefits
	U.S.				Non-U.S.
	2002		2001		2002		2001
	(millions of dollars)
For funded pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation	$	7,948	$	7,140	$	8,719	$	4,142
Accumulated benefit obligation		6,907		6,226		8,100		3,828
Fair value of plan assets		4,476		5,247		5,158		2,855
For unfunded plans covered by book reserves:
Projected benefit obligation	$	1,082	$	963	$	3,446	$	3,197
Accumulated benefit obligation		970		859		3,042		2,854

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

The data on the preceding page conform with current accounting standards that specify use of a discount rate at which postretirement liabilities could be effectively settled. The discount rate for calculating year-end postretirement liabilities is based on the year-end rate of interest on high quality bonds. The return on the annuity fund’s actual portfolio of assets has historically been higher than bonds as the majority of pension assets are invested in equities. The expected U.S. earnings rate of 9.5 per cent used in 2002 compares to an actual rate earned in the U.S. over the past decade of 10 percent. Based on the most recent forward-looking analysis, an expected earnings rate of 9.0 percent will be used for the U.S. plans in 2003.

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

19. Disclosures about Segments and Related Information

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

	Upstream				Downstream					Chemicals				All Other			Corporate Total
	U.S.		Non-U.S.		U.S.			Non-U.S.		U.S.		Non-U.S.		All Other			Corporate Total
	(millions of dollars)
As of December 31, 2002
Earnings after income tax	$	2,524	$	7,074	$	693		$	607	$	384	$	446	$	(268	)	$	11,460
Earnings of equity companies included above		391		1,761		(40	)		27		24		175		(272	)		2,066
Sales and other operating revenue		3,896		12,588		48,865			119,167		6,891		9,517		25			200,949
Intersegment revenue		5,020		12,144		4,540			15,157		2,666		2,486		269			—
Depreciation and depletion expense		1,597		3,551		583			1,399		414		348		418			8,310
Interest revenue		—		—		—			—		—		—		297			297
Interest expense		—		—		—			—		—		—		398			398
Income taxes		1,321		5,162		359			44		165		189		(741	)		6,499
Additions to property, plant and equipment		1,902		6,122		884			1,357		448		181		543			11,437
Investments in equity companies		1,360		2,867		246			795		265		1,399		—			6,932
Total assets		19,385		47,040		13,562			41,530		7,543		10,581		13,003			152,644

As of December 31, 2001
Earnings after income tax	$	3,933	$	6,803	$	1,924		$	2,303	$	398	$	484	$	(525	)	$	15,320
Earnings of equity companies included above		482		1,797		89			12		19		118		(343	)		2,174
Sales and other operating revenue		5,678		12,889		50,988			123,197		6,918		9,025		20			208,715
Intersegment revenue		5,408		12,322		4,115			16,880		2,186		2,284		178			—
Depreciation and depletion expense		1,447		3,221		598			1,476		408		289		409			7,848
Interest revenue		—		—		—			—		—		—		380			380
Interest expense		—		—		—			—		—		—		293			293
Income taxes		2,089		5,546		1,075			744		82		149		(718	)		8,967
Additions to property, plant and equipment		1,985		4,520		827			1,239		390		243		785			9,989
Investments in equity companies		1,371		2,061		329			831		333		1,291		—			6,216
Total assets		18,896		40,901		12,850			37,617		7,495		9,524		15,891			143,174

As of December 31, 2000
Earnings after income tax	$	4,542	$	8,143	$	1,561		$	1,857	$	644	$	517	$	456		$	17,720
Earnings of equity companies included above		753		1,731		71			74		35		139		(369	)		2,434
Sales and other operating revenue		5,735		15,774		56,080			132,483		8,198		9,303		23			227,596
Intersegment revenue		6,557		15,654		8,631			11,684		2,905		2,398		181			—
Depreciation and depletion expense		1,426		3,469		594			1,489		397		281		345			8,001
Interest revenue		—		—		—			—		—		—		258			258
Interest expense		—		—		—			—		—		—		589			589
Income taxes		2,482		7,136		889			850		344		210		(836	)		11,075
Additions to property, plant and equipment		1,518		3,501		966			926		288		458		789			8,446
Investments in equity companies		1,261		1,984		264			1,456		492		1,395		12			6,864
Total assets		18,925		40,447		13,516			42,422		8,047		10,234		15,409			149,000

Geographic sales and other operating revenue	2002		2001		2000
	(millions of dollars)
United States	$	59,675	$	63,603	$	70,036
Non-U.S.		141,274		145,112		157,560

Total	$	200,949	$	208,715	$	227,596

Significant non-U.S. revenue sources include:
Japan	$	19,300	$	21,788	$	24,520
United Kingdom		17,701		18,628		19,904
Canada		14,087		14,912		16,059

Geographic long-lived assets	2002		2001		2000
	(millions of dollars)
United States	$	34,138	$	33,637	$	33,087
Non-U.S.		60,802		55,965		56,742

Total	$	94,940	$	89,602	$	89,829

Significant non-U.S. long-lived assets include:
United Kingdom	$	9,030	$	8,390	$	9,024
Canada		8,469		7,862		7,922
Norway		6,449		4,627		4,383

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

20. Income, Excise and Other Taxes

	2002							2001						2000
	United States		Non-U.S.			Total		United States		Non-U.S.		Total		United States		Non-U.S.			Total
	(millions of dollars)
Income taxes
Federal or non-U.S.
Current	$	351	$	5,618		$	5,969	$	1,729	$	6,084	$	7,813	$	2,635	$	7,972		$	10,607
Deferred – net		635		(288	)		347		712		122		834		433		(338	)		95
U.S. tax on non-U.S. operations		62		—			62		91		—		91		64		—			64

	$	1,048	$	5,330		$	6,378	$	2,532	$	6,206	$	8,738	$	3,132	$	7,634		$	10,766
State		121		—			121		229		—		229		309		—			309

Total income taxes	$	1,169	$	5,330		$	6,499	$	2,761	$	6,206	$	8,967	$	3,441	$	7,634		$	11,075
Excise taxes		7,174		14,866			22,040		7,030		14,877		21,907		6,997		15,359			22,356
All other taxes and duties		1,120		34,626			35,746		1,177		34,476		35,653		1,253		33,674			34,927

Total	$	9,463	$	54,822		$	64,285	$	10,968	$	55,559	$	66,527	$	11,691	$	56,667		$	68,358

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

	2002			2001		2000
	(millions of dollars)
Cumulative foreign exchange translation adjustment	$	(331	)	$	102	$	221
Minimum pension liability adjustment		1,373			139		27
Unrealized gains and losses on stock investments		(8	)		40		57
Other components of shareholders’ equity		86			83		111

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

	2002			2001			2000
	(millions of dollars)
Earnings before Federal and non-U.S. income taxes
United States	$	4,340		$	8,315		$	9,021
Non-U.S.		13,049			15,426			17,551

Total	$	17,389		$	23,741		$	26,572

Theoretical tax	$	6,086		$	8,309		$	9,300
Effect of equity method accounting		(723	)		(761	)		(852	)
Non-U.S. taxes in excess of theoretical U.S. tax		1,355			1,361			2,042
U.S. tax on non-U.S. operations		62			91			64
Other U.S.		(402	)		(262	)		212

Federal and non-U.S. income tax expense	$	6,378		$	8,738		$	10,766

Total effective tax rate		39.8	%		39.3	%		42.6	%

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

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

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

Tax effects of temporary differences for:	2002			2001
	(millions of dollars)
Depreciation	$	14,254		$	12,738
Intangible development costs		3,664			3,445
Capitalized interest		2,040			1,989
Other liabilities		3,188			3,165


Total deferred tax liabilities	$	23,146		$	21,337

Pension and other postretirement benefits	$	(3,225	)	$	(1,911	)
Tax loss carryforwards		(2,350	)		(2,057	)
Other assets		(3,047	)		(2,803	)

Total deferred tax assets	$	(8,622	)	$	(6,771	)

Asset valuation allowances		582			209

Net deferred tax liabilities	$	15,106		$	14,775

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

QUARTERLY INFORMATION

	2002						2001
	First Quarter		Second Quarter	Third Quarter	Fourth Quarter	Year	First Quarter		Second Quarter	Third Quarter	Fourth Quarter	Year
Volumes
	(thousands of barrels daily)
Production of crude oil and natural gas liquids		2,541	2,495	2,453	2,497	2,496		2,620	2,539	2,484	2,527	2,542
Refinery throughput		5,447	5,372	5,518	5,585	5,481		5,687	5,406	5,605	5,587	5,571
Petroleum product sales		7,675	7,569	7,763	8,017	7,757		7,985	7,933	7,951	8,016	7,971

	(millions of cubic feet daily)
Natural gas production available for sale		11,740	9,192	9,222	11,667	10,452		12,119	9,090	8,561	11,373	10,279

	(thousands of oil-equivalent barrels daily)
Oil-equivalent production*		4,498	4,027	3,990	4,442	4,238		4,640	4,054	3,911	4,423	4,255

	(thousands of metric tons)
Chemical prime product sales		6,720	6,785	6,711	6,709	26,925		6,533	6,418	6,457	6,372	25,780

Summarized financial data

	(millions of dollars)
Sales and other operating revenue	$	42,592	49,972	53,194	55,191	200,949	$	55,878	54,931	50,947	46,959	208,715
Gross profit**	$	18,804	21,138	20,996	22,920	83,858	$	24,192	22,825	21,812	22,038	90,867
Income from continuing operations	$	2,063	2,629	2,629	3,690	11,011	$	4,932	4,251	3,151	2,669	15,003
Discontinued operations, net of income tax	$	27	11	11	400	449	$	28	34	29	11	102

Extraordinary gain, net of income tax		—	—	—	—	—	$	40	175	—	—	215
Net income	$	2,090	2,640	2,640	4,090	11,460	$	5,000	4,460	3,180	2,680	15,320

Per share data

	(dollars per share)
Income from continuing operations	$	0.30	0.39	0.39	0.54	1.62	$	0.71	0.63	0.46	0.39	2.19
Discontinued operations, net of income tax	$	0.00	0.01	0.00	0.06	0.07	$	0.00	0.01	0.00	0.00	0.01
Extraordinary gain, net of income tax	$	0.00	0.00	0.00	0.00	0.00	$	0.01	0.02	0.00	0.00	0.03
Net income per common share	$	0.30	0.40	0.39	0.60	1.69	$	0.72	0.66	0.46	0.39	2.23
Net income per common share – assuming dilution	$	0.30	0.39	0.39	0.60	1.68	$	0.71	0.65	0.46	0.39	2.21
Dividends per common share	$	0.23	0.23	0.23	0.23	0.92	$	0.22	0.23	0.23	0.23	0.91

Common stock prices
High	$	44.290	44.579	41.100	36.500	44.579	$	44.875	45.835	44.400	42.700	45.835
Low	$	37.600	38.500	29.750	32.030	29.750	$	37.600	38.500	35.010	36.410	35.010

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

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

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

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

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

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

	Consolidated Subsidiaries																	Non- Consolidated Interests		Total Worldwide
Results of Operations	United States		Canada			Europe		Asia-Pacific			Africa		Other			Total		Non- Consolidated Interests		Total Worldwide
	(millions of dollars)
2002 – Revenue
Sales to third parties	$	2,499	$	1,441		$	4,856	$	1,994		$	18	$	343		$	11,151	$	3,426	$	14,577
Transfers		4,176		1,617			3,334		2,022			3,046		273			14,468		1,296		15,764

	$	6,675	$	3,058		$	8,190	$	4,016		$	3,064	$	616		$	25,619	$	4,722	$	30,341
Production costs excluding taxes		1,405		766			1,493		592			455		192			4,903		561		5,464
Exploration expenses		222		66			109		88			177		257			919		38		957
Depreciation and depletion		1,512		681			1,737		651			354		150			5,085		349		5,434
Taxes other than income		459		31			360		403			345		4			1,602		1,179		2,781
Related income tax		1,153		486			2,399		939			972		(122	)		5,827		918		6,745

Results of producing activities	$	1,924	$	1,028		$	2,092	$	1,343		$	761	$	135		$	7,283	$	1,677	$	8,960
Other earnings*		207		(31	)		151		(47	)		81		(69	)		292		346		638

Total earnings	$	2,131	$	997		$	2,243	$	1,296		$	842	$	66		$	7,575	$	2,023	$	9,598

2001 – Revenue
Sales to third parties	$	4,045	$	1,784		$	5,017	$	1,269		$	17	$	342		$	12,474	$	3,326	$	15,800
Transfers		4,547		1,203			3,927		1,917			2,894		250			14,738		1,306		16,044

	$	8,592	$	2,987		$	8,944	$	3,186		$	2,911	$	592		$	27,212	$	4,632	$	31,844
Production costs excluding taxes		1,389		633			1,425		549			414		210			4,620		580		5,200
Exploration expenses		215		109			117		103			217		412			1,173		18		1,191
Depreciation and depletion		1,392		570			1,644		557			318		148			4,629		354		4,983
Taxes other than income		545		54			484		410			375		5			1,873		1,160		3,033
Related income tax		1,957		543			2,567		622			1,023		(98	)		6,614		1,037		7,651

Results of producing activities	$	3,094	$	1,078		$	2,707	$	945		$	564	$	(85	)	$	8,303	$	1,483	$	9,786
Other earnings*		355		(37	)		132		(42	)		33		(66	)		375		575		950

Total earnings	$	3,449	$	1,041		$	2,839	$	903		$	597	$	(151	)	$	8,678	$	2,058	$	10,736

2000 – Revenue
Sales to third parties	$	4,060	$	2,423		$	4,387	$	2,167		$	20	$	366		$	13,423	$	3,055	$	16,478
Transfers		5,420		771			5,491		2,130			3,212		324			17,348		1,532		18,880

	$	9,480	$	3,194		$	9,878	$	4,297		$	3,232	$	690		$	30,771	$	4,587	$	35,358
Production costs excluding taxes		1,231		595			1,627		543			400		181			4,577		621		5,198
Exploration expenses		145		81			135		164			196		211			932		22		954
Depreciation and depletion		1,373		586			1,906		556			340		141			4,902		399		5,301
Taxes other than income		637		33			358		506			446		4			1,984		997		2,981
Related income tax		2,419		736			3,274		1,005			1,093		97			8,624		975		9,599

Results of producing activities	$	3,675	$	1,163		$	2,578	$	1,523		$	757	$	56		$	9,752	$	1,573	$	11,325
Other earnings*		114		(36	)		521		137			31		(35	)		732		628		1,360

Total earnings	$	3,789	$	1,127		$	3,099	$	1,660		$	788	$	21		$	10,484	$	2,201	$	12,685


Average sales prices and production costs per unit of production
During 2002
Average sales prices
Crude oil and NGL, per barrel	$	20.80	$	20.73		$	22.95	$	24.26		$	24.19	$	19.43		$	22.30	$	21.88	$	22.25
Natural gas, per thousand cubic feet		2.67		2.34			3.08		2.26			—		0.48			2.65		3.23		2.77
Average production costs, per barrel**		3.97		4.53			3.82		2.72			3.57		5.03			3.78		2.44		3.58
During 2001
Average sales prices
Crude oil and NGL, per barrel	$	19.92	$	15.95		$	22.79	$	24.36		$	23.34	$	20.21		$	21.30	$	19.64	$	21.10
Natural gas, per thousand cubic feet		4.36		3.71			3.28		1.80			—		1.44			3.37		3.48		3.39
Average production costs, per barrel**		3.68		3.88			3.40		2.98			3.32		5.85			3.54		2.53		3.39
During 2000
Average sales prices
Crude oil and NGL, per barrel	$	23.94	$	21.60		$	26.96	$	28.74		$	28.17	$	24.57		$	25.77	$	24.17	$	25.59
Natural gas, per thousand cubic feet		3.85		3.58			2.69		2.59			—		1.29			3.12		3.11		3.12
Average production costs, per barrel**		3.08		4.04			3.72		2.72			3.39		5.50			3.43		2.90		3.35

Includes earnings from transportation operations, tar sands operations, LNG operations, coal and power operations, technical services agreements, other non-operating activities and adjustments for minority interests. “Other earnings” for prior years have been revised to include coal and power operations.

Production costs exclude depreciation and depletion and all taxes. Natural gas included by conversion to crude oil equivalent.

Oil and Gas Exploration and Production Costs

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

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

	Consolidated Subsidiaries
Capitalized costs	United States		Canada		Europe		Asia-Pacific			Africa		Other		Total		Non- Consolidated Interests		Total Worldwide
	(millions of dollars)
As of December 31, 2002
Property (acreage) costs – Proved	$	4,433	$	2,604	$	202	$	745		$	106	$	1,018	$	9,108	$	56	$	9,164
– Unproved		657		205		35		900			610		568		2,975		1		2,976

Total property costs	$	5,090	$	2,809	$	237	$	1,645		$	716	$	1,586	$	12,083	$	57	$	12,140
Producing assets		34,850		7,404		33,385		12,789			4,701		1,983		95,112		7,251		102,363
Support facilities		533		93		489		953			212		85		2,365		335		2,700
Incomplete construction		910		310		2,210		940			2,818		514		7,702		720		8,422

Total capitalized costs	$	41,383	$	10,616	$	36,321	$	16,327		$	8,447	$	4,168	$	117,262	$	8,363	$	125,625
Accumulated depreciation and depletion		26,729		5,497		24,111		10,625			2,692		1,881		71,535		4,326		75,861

Net capitalized costs	$	14,654	$	5,119	$	12,210	$	5,702		$	5,755	$	2,287	$	45,727	$	4,037	$	49,764

As of December 31, 2001
Property (acreage) costs – Proved	$	4,543	$	2,656	$	178	$	689		$	107	$	957	$	9,130	$	11	$	9,141
– Unproved		674		196		49		850			630		530		2,929		2		2,931

Total property costs	$	5,217	$	2,852	$	227	$	1,539		$	737	$	1,487	$	12,059	$	13	$	12,072
Producing assets		33,379		6,662		27,628		11,764			4,300		1,992		85,725		5,710		91,435
Support facilities		488		83		449		925			208		159		2,312		257		2,569
Incomplete construction		1,050		334		1,306		684			1,433		346		5,153		495		5,648

Total capitalized costs	$	40,134	$	9,931	$	29,610	$	14,912		$	6,678	$	3,984	$	105,249	$	6,475	$	111,724
Accumulated depreciation and depletion		25,754		4,888		19,398		9,705			2,323		1,796		63,864		3,127		66,991

Net capitalized costs	$	14,380	$	5,043	$	10,212	$	5,207		$	4,355	$	2,188	$	41,385	$	3,348	$	44,733


Costs incurred in property acquisitions, exploration and development activities
During 2002
Property acquisition costs – Proved	$	18	$	8	$	—	$	—		$	—	$	—	$	26	$	1	$	27
– Unproved		13		12		—		—			10		125		160		—		160
Exploration costs		276		109		127		82			301		216		1,111		52		1,163
Development costs		1,676		653		1,785		936			1,708		360		7,118		687		7,805

Total	$	1,983	$	782	$	1,912	$	1,018		$	2,019	$	701	$	8,415	$	740	$	9,155

During 2001
Property acquisition costs – Proved	$	—	$	—	$	—	$	—		$	2	$	—	$	2	$	—	$	2
– Unproved		95		17		1		(1	)		—		10		122		—		122
Exploration costs		352		141		144		148			281		459		1,525		35		1,560
Development costs		1,648		664		1,498		666			995		219		5,690		429		6,119

Total	$	2,095	$	822	$	1,643	$	813		$	1,278	$	688	$	7,339	$	464	$	7,803

During 2000
Property acquisition costs – Proved	$	1	$	1	$	—	$	1		$	—	$	—	$	3	$	—	$	3
– Unproved		72		15		4		96			2		49		238		—		238
Exploration costs		219		145		187		145			272		297		1,265		23		1,288
Development costs		1,236		525		1,262		502			402		224		4,151		383		4,534

Total	$	1,528	$	686	$	1,453	$	744		$	676	$	570	$	5,657	$	406	$	6,063

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

Oil and Gas Reserves

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

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

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. In certain deepwater fields, proved reserves are occasionally recorded before flow tests are conducted because of the safety and cost implications of conducting the tests. In those situations, other industry accepted analyses are used. Historically, proved reserves recorded using these methods have been immaterial when compared to the corporation’s total proved reserves and have also been validated by subsequent flow tests or actual production levels.

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

	Consolidated Subsidiaries
Crude Oil and Natural Gas Liquids	United States		Canada		Europe		Asia-Pacific		Africa		Other		Total		Non- Consolidated Interests		Total Worldwide
	(millions of barrels)
Net proved developed and undeveloped reserves
January 1, 2000	2,749		1,355		1,761		715		2,024		700		9,304		1,956		11,260
Revisions	410		9		25		29		50		24		547		33		580
Purchases	—		—		—		—		—		—		—		—		—
Sales	(1	)	(5	)	—		—		—		—		(6	)	—		(6	)
Improved recovery	40		34		20		—		3		—		97		26		123
Extensions and discoveries	8		33		5		39		425		4		514		3		517
Production	(220	)	(96	)	(253	)	(93	)	(118	)	(26	)	(806	)	(107	)	(913	)

December 31, 2000	2,986		1,330		1,558		690		2,384		702		9,650		1,911		11,561
Revisions	89		(9	)	68		(1	)	94		15		256		8		264
Purchases	—		—		—		—		—		—		—		—		—
Sales	(6	)	—		—		—		—		—		(6	)	(3	)	(9	)
Improved recovery	57		5		5		—		34		—		101		20		121
Extensions and discoveries	112		53		79		23		74		—		341		112		453
Production	(210	)	(102	)	(234	)	(90	)	(125	)	(29	)	(790	)	(109	)	(899	)

December 31, 2001	3,028		1,277		1,476		622		2,461		688		9,552		1,939		11,491
Revisions	31		74		59		40		73		26		303		52		355
Purchases	—		—		—		—		—		—		—		—		—
Sales	(13	)	—		—		—		—		—		(13	)	—		(13	)
Improved recovery	3		—		—		—		75		—		78		16		94
Extensions and discoveries	60		40		11		124		145		100		480		297		777
Production	(200	)	(106	)	(213	)	(95	)	(128	)	(33	)	(775	)	(106	)	(881	)

December 31, 2002	2,909		1,285		1,333		691		2,626		781		9,625		2,198		11,823

Developed reserves, included above
At December 31, 2000	2,661		630		978		504		989		245		6,007		1,331		7,338
At December 31, 2001	2,567		593		881		477		1,022		232		5,772		1,440		7,212
At December 31, 2002	2,461		685		797		487		1,057		208		5,695		1,505		7,200

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

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

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

	Consolidated Subsidiaries
Natural Gas	United States		Canada		Europe		Asia-Pacific		Africa		Other		Total		Non- Consolidated Interests		Total Worldwide
	(billions of cubic feet)
Net proved developed and undeveloped reserves
January 1, 2000	13,001		3,387		11,228		9,358		171		608		37,753		19,043		56,796
Revisions	987		69		970		(113	)	147		62		2,122		85		2,207
Purchases	—		10		—		—		—		—		10		—		10
Sales	(3	)	(5	)	—		—		—		—		(8	)	—		(8	)
Improved recovery	22		24		46		—		—		24		116		50		166
Extensions and discoveries	195		430		96		11		70		26		828		45		873
Production	(1,157	)	(399	)	(1,170	)	(710	)	(13	)	(53	)	(3,502	)	(676	)	(4,178	)

December 31, 2000	13,045		3,516		11,170		8,546		375		667		37,319		18,547		55,866
Revisions	612		(51	)	564		(198	)	8		(5	)	930		(94	)	836
Purchases	—		1		—		—		—		—		1		—		1
Sales	(57	)	—		(2	)	(8	)	—		—		(67	)	(2	)	(69	)
Improved recovery	4		15		11		—		2		—		32		7		39
Extensions and discoveries	242		120		360		590		8		120		1,440		1,991		3,431
Production	(1,114	)	(418	)	(1,172	)	(629	)	(14	)	(54	)	(3,401	)	(757	)	(4,158	)

December 31, 2001	12,732		3,183		10,931		8,301		379		728		36,254		19,692		55,946
Revisions	206		30		600		258		17		42		1,153		294		1,447
Purchases	—		2		—		—		—		—		2		—		2
Sales	(43	)	—		—		—		—		—		(43	)	—		(43	)
Improved recovery	1		3		—		—		—		—		4		—		4
Extensions and discoveries	209		83		115		212		52		9		680		1,917		2,597
Production	(1,043	)	(419	)	(1,138	)	(813	)	(12	)	(44	)	(3,469	)	(766	)	(4,235	)

December 31, 2002	12,062		2,882		10,508		7,958		436		735		34,581		21,137		55,718

Developed reserves, included above
At December 31, 2000	10,956		2,850		8,222		6,300		125		477		28,930		9,087		38,017
At December 31, 2001	10,366		2,517		7,824		6,005		122		404		27,238		8,784		36,022
At December 31, 2002	9,991		2,294		7,326		5,887		112		402		26,012		8,731		34,743

INFORMATION ON CANADIAN TAR SANDS PROVEN RESERVES NOT INCLUDED ABOVE

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

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

Tar Sands Reserves		Canada
		(millions of barrels)
At December 31, 2000		610
At December 31, 2001		821
At December 31, 2002		800

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES

Standardized Measure of Discounted Future Cash Flows

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

	Consolidated Subsidiaries
	United States		Canada		Europe		Asia- Pacific		Africa		Other		Total		Non- Consolidated Interests		Total Worldwide
	(millions of dollars)
As of December 31, 2000
Future cash inflows from sales of oil and gas	$	177,178	$	41,275	$	70,208	$	34,658	$	52,651	$	10,317	$	386,287	$	93,597	$	479,884
Future production costs		26,417		7,857		15,979		9,977		10,953		3,467		74,650		38,011		112,661
Future development costs		3,977		2,806		5,552		3,405		7,516		798		24,054		3,901		27,955
Future income tax expenses		55,192		12,731		26,078		7,382		18,949		1,830		122,162		21,333		143,495

Future net cash flows	$	91,592	$	17,881	$	22,599	$	13,894	$	15,233	$	4,222	$	165,421	$	30,352	$	195,773
Effect of discounting net cash flows at 10%		48,876		6,795		7,779		5,638		8,158		2,450		79,696		18,825		98,521

Discounted future net cash flows	$	42,716	$	11,086	$	14,820	$	8,256	$	7,075	$	1,772	$	85,725	$	11,527	$	97,252

As of December 31, 2001
Future cash inflows from sales of oil and gas	$	68,713	$	19,573	$	58,394	$	24,452	$	42,806	$	10,370	$	224,308	$	87,828	$	312,136
Future production costs		20,008		6,711		15,807		7,801		10,341		3,217		63,885		31,839		95,724
Future development costs		4,613		2,695		5,252		3,262		7,839		831		24,492		3,043		27,535
Future income tax expenses		16,620		3,908		17,416		4,325		13,485		2,091		57,845		22,046		79,891

Future net cash flows	$	27,472	$	6,259	$	19,919	$	9,064	$	11,141	$	4,231	$	78,086	$	30,900	$	108,986
Effect of discounting net cash flows at 10%		15,065		2,377		7,338		3,552		6,087		2,553		36,972		18,766		55,738

Discounted future net cash flows	$	12,407	$	3,882	$	12,581	$	5,512	$	5,054	$	1,678	$	41,114	$	12,134	$	53,248

As of December 31, 2002
Future cash inflows from sales of oil and gas	$	118,905	$	38,528	$	68,111	$	36,917	$	76,407	$	18,321	$	357,189	$	127,089	$	484,278
Future production costs		26,601		7,910		14,781		9,889		13,673		3,438		76,292		41,463		117,755
Future development costs		5,545		3,157		5,983		3,433		10,454		1,789		30,361		5,583		35,944
Future income tax expenses		34,289		10,261		23,580		8,254		28,190		3,921		108,495		27,633		136,128

Future net cash flows	$	52,470	$	17,200	$	23,767	$	15,341	$	24,090	$	9,173	$	142,041	$	52,410	$	194,451
Effect of discounting net cash flows at 10%		28,930		6,792		7,788		5,857		11,658		5,634		66,659		31,233		97,892

Discounted future net cash flows	$	23,540	$	10,408	$	15,979	$	9,484	$	12,432	$	3,539	$	75,382	$	21,177	$	96,559

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

Consolidated Subsidiaries	2002			2001			2000
	(millions of dollars)
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs	$	5,481		$	2,660		$	6,029
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs		(19,242	)		(20,748	)		(24,498	)
Development costs incurred during the year		6,994			5,577			4,194
Net change in prices, lifting and development costs		57,506			(79,693	)		44,702
Revisions of previous reserves estimates		4,665			2,520			12,537
Accretion of discount		5,837			12,293			7,694
Net change in income taxes		(26,973	)		32,780			(20,889	)

Total change in the standardized measure during the year	$	34,268		$	(44,611	)	$	29,769

OPERATING SUMMARY

	2002	2001	2000	1999	1998
	(thousands of barrels daily)
Production of crude oil and natural gas liquids
Net production
United States	681	712	733	729	745
Canada	349	331	304	315	322
Europe	592	653	704	650	635
Asia-Pacific	260	247	253	307	322
Africa	349	342	323	326	301
Other Non-U.S.	265	257	236	190	177

Worldwide	2,496	2,542	2,553	2,517	2,502


	(millions of cubic feet daily)
Natural gas production available for sale
Net production
United States	2,375	2,598	2,856	2,871	3,140
Canada	1,024	1,006	844	683	667
Europe	4,463	4,595	4,463	4,438	4,245
Asia-Pacific	2,019	1,547	1,755	2,027	2,352
Other Non-U.S.	571	533	425	289	213

Worldwide	10,452	10,279	10,343	10,308	10,617


	(thousands of oil-equivalent barrels daily)
Oil-equivalent production*	4,238	4,255	4,277	4,235	4,272


	(thousands of barrels daily)
Refinery throughput
United States	1,871	1,840	1,862	1,930	1,919
Canada	447	449	451	441	445
Europe	1,539	1,563	1,578	1,782	1,888
Asia-Pacific	1,379	1,436	1,462	1,537	1,554
Other Non-U.S.	245	283	289	287	287

Worldwide	5,481	5,571	5,642	5,977	6,093

Petroleum product sales
United States	2,731	2,751	2,669	2,918	2,804
Canada	593	585	577	587	579
Europe	2,042	2,079	2,129	2,597	2,646
Asia-Pacific and other Eastern Hemisphere	1,889	2,024	2,090	2,223	2,266
Latin America	502	532	528	562	578

Worldwide	7,757	7,971	7,993	8,887	8,873

Gasoline, naphthas	3,176	3,165	3,122	3,428	3,417
Heating oils, kerosene, diesel oils	2,292	2,389	2,373	2,658	2,689
Aviation fuels	691	721	749	813	774
Heavy fuels	604	668	694	706	765
Specialty petroleum products	994	1,028	1,055	1,282	1,228

Worldwide	7,757	7,971	7,993	8,887	8,873


	(thousands of metric tons)
Chemical prime product sales	26,925	25,780	25,637	25,283	23,628

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

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

SIGNATURES

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

EXXON MOBIL CORPORATION

By:		/s/ LEE R. RAYMOND
		(Lee R. Raymond, Chairman of the Board)

Dated March 26, 2003

POWER OF ATTORNEY

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

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


/s/ LEE R. RAYMOND (Lee R. Raymond)	Chairman of the Board (Principal Executive Officer)	March 26, 2003

/s/ MICHAEL J. BOSKIN (Michael J. Boskin)	Director	March 26, 2003

/s/ WILLIAM T. ESREY (William T. Esrey)	Director	March 26, 2003

/s/ DONALD V. FITES (Donald V. Fites)	Director	March 26, 2003


/s/ JAMES R. HOUGHTON (James R. Houghton)	Director	March 26, 2003

/s/ WILLIAM R. HOWELL (William R. Howell)	Director	March 26, 2003

/s/ HELENE L. KAPLAN (Helene L. Kaplan)	Director	March 26, 2003

/s/ REATHA CLARK KING (Reatha Clark King)	Director	March 26, 2003

/s/ PHILIP E. LIPPINCOTT (Philip E. Lippincott)	Director	March 26, 2003

/s/ HARRY J. LONGWELL (Harry J. Longwell)	Director	March 26, 2003

/s/ HENRY A. MCKINNELL, JR. (Henry A. McKinnell, Jr.)	Director	March 26, 2003

/s/ MARILYN CARLSON NELSON (Marilyn Carlson Nelson)	Director	March 26, 2003

/s/ WALTER V. SHIPLEY (Walter V. Shipley)	Director	March 26, 2003

/s/ DONALD D. HUMPHREYS (Donald D. Humphreys)	Controller (Principal Accounting Officer)	March 26, 2003

/s/ FRANK A. RISCH (Frank A. Risch)	Treasurer (Principal Financial Officer)	March 26, 2003

CERTIFICATIONS

Certification by Lee R. Raymond

Pursuant to Securities Exchange Act Rule 13a-14

I, Lee R. Raymond , certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: March 26, 2003

/s/ LEE R. RAYMOND

Lee R. Raymond

Chief Executive Officer

Certification by Donald D. Humphreys

Pursuant to Securities Exchange Act Rule 13a-14

I, Donald D. Humphreys , certify that:

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

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

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

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

Date: March 26, 2003

/s/ DONALD D. HUMPHREYS

Donald D. Humphreys

Vice President and Controller

(Principal Accounting Officer)

Certification by Frank A. Risch

Pursuant to Securities Exchange Act Rule 13a-14

I, Frank A. Risch, certify that:

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

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

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

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

Date: March 26, 2003

/s/ FRANK A. RISCH

Frank A. Risch

Vice President and Treasurer

(Principal Financial Officer)

INDEX TO EXHIBITS


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

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

10(iii)(a).		1993 Incentive Program, as amended.*

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

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

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

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

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

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

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

10(iii)(j).		Form of terms for restricted stock agreements with executive officers.*

10(iii)(k).		Form of terms for annuitant cash unit agreements.*

12.		Computation of ratio of earnings to fixed charges.

21.		Subsidiaries of the registrant.

23.		Consent of PricewaterhouseCoopers LLP, Independent Accountants.

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

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

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

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

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

1993 Incentive Program,as amended

EXHIBIT 10(iii)(a)

EXXON CORPORATION

1993 INCENTIVE PROGRAM

Adopted by shareholders April 28, 1993

(as last amended February 26, 2003)

GENERAL PROVISIONS

I. Purpose.

The 1993 Incentive Program is intended to help maintain and develop strong management through ownership of shares of the Corporation by key employees of the Corporation and certain of its affiliates and through incentive awards for recognition of efforts and accomplishments which contribute materially to the success of the Corporation’s business interests.

II. Definitions.

In this Program, except where the context otherwise indicates, the following definitions apply:

(1) ‘Administrative authority’ means one of the following, as appropriate in accordance with Section III: the Board; any committee to which the Board delegates authority to administer this Program; or, in individual cases, the Chairman of the Board or persons acting under his direction.

(2) ‘Affiliate’ means (a) any subsidiary and (b) any other corporation, partnership, joint venture, or other entity in which the Corporation, directly or indirectly, owns an equity interest and which the administrative authority deems to be an affiliate for purposes of this Program (including, without limitation, for purposes of determining whether a change of employment constitutes a termination).

(3) ‘Award’ means a stock option, stock appreciation right (‘SAR’), restricted stock, performance award, incentive share, dividend equivalent right (‘DER’), or other award under this Program.

(4) ‘Board’ means the Board of Directors of the Corporation.

(5) ‘Board Compensation Committee,’ hereinafter sometimes called the ‘BCC,’ means the committee of the Board so designated in accordance with Section IV.

(6) ‘By the grant’ means by the action of the granting authority at the time of the grant of an award hereunder, or at the time of an amendment of the grant, as the case may be.

(7) ‘Code’ means the Internal Revenue Code, as in effect from time to time.

(8) ‘Corporation’ means Exxon Corporation, a New Jersey corporation.

(9) ‘Designated beneficiary’ means the person designated by the grantee of an award hereunder to be entitled, on the death of the grantee, to any remaining rights arising out of such award. Such designation must be made in writing and in accordance with such regulations as the administrative authority may establish.

(10) ‘Detrimental activity’ means activity that is determined in individual cases by the administrative authority to be detrimental to the interests of the Corporation or any affiliate.

(11) ‘Dividend equivalent right,’ herein sometimes called a ‘DER,’ means the right of the holder thereof to receive, pursuant to the terms of the DER, credits based on the cash dividends that would be paid on the shares specified in the DER if such shares were held by the grantee, as more particularly set forth in Section XIV(1).

(12) ‘Effectively granted’ means, for purposes of determining the number of shares subject to an outstanding award under this Program, the number of shares subject to such award or the number of shares with respect to which the value of such award is measured, as applicable. An option that includes an SAR shall be considered a single award for this purpose.

(13) ‘Effectively issued’ means the gross number of shares purchased, issued, delivered, or paid free of restrictions upon the exercise, settlement, or payment of an award, or lapse of restrictions thereon, as the case may be.

(14) ‘Eligible employee’ means an employee of the Corporation or a subsidiary who is a director or officer, or in a managerial, professional, or other key position as determined by the granting authority.

(15) ‘Employee’ means an employee of the Corporation or an affiliate.

(16) ‘Exchange Act’ means the Securities Exchange Act of 1934, as amended from time to time.

(17) ‘Fair market value’ in relation to a share as of any specific time shall mean such value as reported for stock exchange transactions determined in accordance with any applicable regulations of the administrative authority in effect at the relevant time.

(18) ‘Grantee’ means a recipient of an award under this Program.

(19) ‘Granting authority’ means the Board or any appropriate committee authorized to grant and amend awards under this Program in accordance with Section V and to exercise other powers of the granting authority hereunder.

(20) ‘Incentive shares’ means an award of shares granted pursuant to Section XIII.

(21) ‘Incentive Stock Option,’ herein sometimes called an ‘ISO,’ means a stock option meeting the requirements of Section 422 of the Code or any successor provision.

(22) ‘Performance award’ means an award of shares, or of units or rights based on, payable in, or otherwise related to shares, granted pursuant to Section XII.

(23) ‘Performance period’ means any period specified by the grant of a performance award during which specified performance criteria are to be measured.

(24) ‘Reporting person’ means a person subject to the reporting requirements of Section 16(a) of the Exchange Act with respect to equity securities of the Corporation.

(25) ‘Restricted stock’ means any share issued with the restriction that the holder may not sell, transfer, pledge, or assign such share and such other restrictions (which may include, but are not limited to, restrictions on the right to vote or receive dividends) which may expire separately or in combination, at one time or in installments, all as specified by the grant.

(26) ‘Rule 16b-3’ means Rule 16b-3 (or any successor thereto) under the Exchange Act that exempts transactions under employee benefit plans, as in effect from time to time.

(27) ‘Share’ means a share of Common Stock of the Corporation issued and reacquired by the Corporation or previously authorized but unissued.

(28) ‘Shareholder-approved plan’ means any of the plans constituting parts of any of the Incentive Programs previously approved by shareholders of the Corporation.

(29) ‘Stock appreciation right,’ herein sometimes called an ‘SAR,’ means the right of the holder thereof to receive, pursuant to the terms of the SAR, a number of shares or cash or a combination of shares and cash, based on the increase in the value of the number of shares specified in the SAR, as more particularly set forth in Section X.

(30) ‘Subsidiary’ means a corporation, partnership, joint venture, or other entity in which the Corporation, directly or indirectly, owns a 50% or greater equity interest.

(31) ‘Terminate’ means cease to be an employee for any reason, except by death, but a change of employment from the Corporation or one affiliate to another affiliate or to the Corporation shall not be considered a termination. For purposes of this Program, the administrative authority may determine that the time or date of termination is the day an employee resigns, accepts employment with another employer or otherwise indicates an intent to resign, which time or date need not necessarily be the last day on the payroll.

(32) ‘Terminate normally’ for purposes of this Program means terminate

(a) at normal retirement time for that employee, or

(b) with written approval of the administrative authority given in the context of recognition that all or a specified portion of the outstanding awards to that employee will not expire or be forfeited or annulled because of such termination.

(33) ‘Year’ means calendar year.

III. Administration.

(1) The Board is the ultimate administrative authority for this Program, with the power to conclusively interpret its provisions and decide all questions of fact arising in its application. The Board may delegate its authority pursuant to any provision of this Program to a committee which, except in the case of the BCC, need not be a committee of the Board. Subject to the authority of the Board or an authorized committee and excluding cases involving the Chairman as grantee, the Chairman of the Board and persons acting under his direction may serve as the administrative authority under this Program for purposes of making determinations and interpretations in individual cases.

(2) The Board and any committee acting as the administrative authority under this Program can act by regulation, by making individual determinations, or by both. The Chairman of the Board and persons designated by him can act as the administrative authority under this Program only by making individual determinations.

(3) All determinations and interpretations pursuant to the provisions of this Program shall be binding and conclusive upon the individuals involved and all persons claiming under them.

(4) With respect to reporting persons, transactions under this Program are intended to comply with all applicable conditions of Rule 16b-3. To the extent any provision of this Program or any action by an authority under this Program fails to so comply, such provision or action shall, without further action by any person, be deemed to be automatically amended to the extent necessary to effect compliance with Rule 16b-3, provided that if such provision or action cannot be amended to effect such compliance, such provision or action shall be deemed null and void, to the extent permitted by law and deemed advisable by the appropriate authority. Each award to a reporting person under this Program shall be deemed issued subject to the foregoing qualification.

(5) An award under this Program is not transferable except, as provided in the award, by will or the laws of descent and distribution, and is not subject to attachment, execution, or levy of any kind. The designation by a grantee of a designated beneficiary shall not constitute a transfer.

(6) Any rights with respect to an award granted under this Program existing after the grantee dies are exercisable by the grantee’s designated beneficiary or, if there is no designated beneficiary, by the grantee’s personal representative.

(7) Except as otherwise provided herein, a particular form of award may be granted to an eligible employee either alone or in addition to other awards hereunder. The provisions of particular forms of award need not be the same with respect to each recipient.

(8) If the administrative authority believes that a grantee (a) may have engaged in detrimental activity or (b) may have accepted employment with another employer or otherwise indicated an intent to resign, the authority may suspend the exercise, vesting or settlement of all or any specified portion of such grantee’s outstanding awards pending an investigation of the matter.

(9) This Program and all action taken under it shall be governed by the laws of the State of New York.

(10) Any award which was granted under a shareholder-approved plan and is still outstanding shall be interpreted and administered in accordance with the definitions and administrative provisions of this Program, including, without limitation, Sections II through V hereof.

IV. Board Compensation Committee (BCC).

The Board shall appoint a BCC. The BCC shall consist of two or more members of the Board, each of whom is a ‘nonemployee director’ within the meaning of Rule 16b-3. No award may be granted to a member of the BCC.

V. Right to Grant Awards; Reserved Powers.

The Board is the ultimate granting authority for this Program, with the power to select eligible employees for participation in this Program and to make all decisions concerning the grant or amendment of awards. The Board may delegate such authority in whole or in part (1) in the case of reporting persons, to the BCC and (2) in the case of eligible employees who are not reporting persons, to any committee.

VI. Term.

The term of this Program begins on the date shareholder approval of this Program is obtained and ends on the tenth anniversary of that date.

VII. Awards Grantable.

(1) With effect from year end 2002 through the expiration of this Program on April 28, 2003, no more than two million shares may be effectively granted as new awards.

(2) [reserved]

(3) [reserved]

(4) [reserved]

(5) Notwithstanding the foregoing provisions of this Section VII, the total number of shares that may be effectively granted under stock options or stock appreciation rights to any one grantee in any one calendar year may not exceed two tenths of one percent (0.2%) of the total number of shares of Common Stock of the Corporation outstanding (excluding shares held by the Corporation) on December 31, 1996.¹

VIII. Adjustments.

Whenever a stock split, stock dividend, or other relevant change in capitalization which the administrative authority determines to be dilutive to outstanding awards occurs,

(1) the number of shares that can thereafter be obtained under outstanding awards and the purchase price per share, if any, under such awards, and

(2) every number of shares used in determining whether a particular award is grantable thereafter,

shall be appropriately adjusted.

¹ In accordance with Section VIII, such number of shares is doubled to reflect a two-for-one split of the shares on March 14, 1997, and doubled again to reflect a two-for-one split of the shares on June 20, 2001.

IX. Stock Options.

One or more grantable stock options can be granted to any eligible employee. Each stock option so granted shall be subject to such terms and conditions as the granting authority shall impose, which shall include the following:

(1) The exercise price per share shall be specified by the grant, but shall in no instance be less than 100 percent of fair market value at the time of grant. Payment of the exercise price shall be made in cash, shares, or other consideration in accordance with the terms of this Program and any applicable regulations of the administrative authority in effect at the time and valued at fair market value on the date of exercise of the stock option.

(2) A stock option shall become exercisable, if at all, at the time or times specified by the grant. If the grantee terminates other than normally before a stock option or portion thereof becomes exercisable, that stock option or portion thereof shall be forfeited and shall never become exercisable. Except as otherwise specified by the grant, a stock option shall become immediately exercisable in full upon the death of the grantee.

(3) Any stock option or portion thereof that is exercisable is exercisable for the full amount or for any part thereof, except as otherwise provided by the grant.

(4) Each stock option ceases to be exercisable, as to any share, when the stock option is exercised to purchase that share, or when a related SAR is exercised either by the holder or automatically in accordance with its terms, or when the stock option expires. To the extent an SAR included in a stock option is exercised, such stock option shall be deemed to have been exercised and shall not be deemed to have expired.

(5) A stock option or portion thereof that is exercisable shall expire in the following situations:

(a) unless clauses (b), (c) or (d) below apply, it shall expire at the earlier of:

(i) ten years after it is granted, or

(ii) any earlier time specified by the grant;

(b) if the grantee terminates, but does not terminate normally, it shall expire at the time of termination;

(c) if the grantee is determined to have engaged in detrimental activity, it shall expire as of the date of such determination; or

(d) if the grantee dies, it shall expire at the earlier of:

(i) five years after the grantee’s death, or

(ii) any earlier time specified by the grant;

but, in any case, no later than ten years after it is granted.

(6) If a grantee terminates other than normally, (a) the administrative authority may refuse to deliver shares in settlement of any pending stock option exercise and (b) the granting authority may require the grantee to repay to the Corporation an amount equal to the spread on any stock option exercised by the grantee during the six-month period immediately preceding such termination. For purposes of the foregoing subsection (6)(b), ‘spread’ means the difference between the aggregate stock option exercise price and the fair market value of the underlying shares on the date such option is exercised.

(7) All stock options granted hereunder are hereby designated as ISOs except to the extent otherwise specified by the grant and except to the extent otherwise specified in this Section IX(7). To the extent that the aggregate fair market value of shares with respect to which stock options designated as ISOs are exercisable for the first time by any grantee during any year (under all plans of the Corporation and any affiliate thereof) exceeds $100,000, such stock options shall be treated as not being ISOs. The foregoing shall be applied by taking stock options into account in the order in which they were granted. For the purposes of the foregoing, the fair market value of any share shall be determined as of the time the stock option with respect to such share is granted. In the event the foregoing results in a portion of a stock option designated as an ISO exceeding the above $100,000 limitation, only such excess shall be treated as not being an ISO.

For each year in which this Program is in effect, the number of shares that may be effectively granted as ISOs may not exceed seven tenths of one percent (0.7%) of the total number of shares of Common Stock of the Corporation outstanding (excluding shares held by the Corporation) on the December 31 preceding the date on which shareholder approval of this Program is obtained.² If the number of shares effectively granted as ISOs in any year is less than the number of shares that could have been so granted pursuant to this paragraph, the balance of such unused shares may be added to the maximum number of shares that may be effectively granted as ISOs the following year.

A stock option designated as an ISO, or portion thereof, that fails or ceases to qualify as such under the Code shall otherwise remain valid according to its terms as a non-ISO under this Program.

² In accordance with Section VIII, such number of shares is doubled to reflect a two-for-one split of the shares on March 14, 1997, and doubled again to reflect a two-for-one split of the shares on June 20, 2001

X. Stock Appreciation Rights.

(1) An SAR may be granted to an eligible employee as a separate award hereunder. Any such SAR shall be subject to such terms and conditions as the granting authority shall impose, which shall include provisions that (a) such SAR shall entitle the holder thereof, upon exercise thereof in accordance with such SAR and the regulations of the administrative authority, to receive from the Corporation that number of shares having an aggregate value equal to the excess of the fair market value, at the time of exercise of such SAR, of one share over the exercise price per share specified by the grant of such SAR (which shall in no instance be less than 100 percent of fair market value at the time of grant) times the number of shares specified in such SAR, or portion thereof, which is so exercised; and (b) such SAR shall be exercisable, or be forfeited or expire, upon the same conditions set forth for freestanding options in Section IX, paragraphs (2), (3), (4), (5), and (6).

(2) Any stock option granted under this Program may include an SAR, either at the time of grant or by amendment. An SAR included in a stock option shall be subject to such terms and conditions as the granting authority shall impose, which shall include provisions that (a) such SAR shall be exercisable to the extent, and only to the extent, the stock option is exercisable; and (b) such SAR shall entitle the optionee to surrender to the Corporation unexercised the stock option in which the SAR is included, or any portion thereof, and to receive from the Corporation in exchange therefor that number of shares having an aggregate value equal to the excess of the fair market value, at the time of exercise of such SAR, of one share over the exercise price specified in such stock option times the number of shares specified in such stock option, or portion thereof, which is so surrendered.

(3) In lieu of the right to receive all or any specified portion of such shares, an SAR may entitle the holder thereof to receive the cash equivalent thereof as specified by the grant.

(4) An SAR may provide that such SAR shall be deemed to have been exercised at the close of business on the business day preceding the expiration of such SAR or the related stock option, if any, if at such time such SAR has positive value and would have expired in accordance with the conditions set forth in Section IX(5)(a).

Xl. Restricted Stock.

(1) An award of restricted stock may be granted hereunder to an eligible employee, for no cash consideration, for such minimum consideration as may be required by applicable law, or for such other consideration as may be specified by the grant. The terms and conditions of restricted stock shall be specified by the grant.

(2) Any restricted stock issued hereunder may be evidenced in such manner as the administrative authority in its sole discretion shall deem appropriate, including, without limitation, book-entry registration or issuance of a stock certificate or certificates. In the event any stock certificate is issued in respect of shares of restricted stock awarded hereunder, such certificate shall bear an appropriate legend with respect to the restrictions applicable to such award.

(3) Except as otherwise specified by the grant, if a holder of record of restricted stock terminates, but does not terminate normally, all shares of restricted stock (whether or not stock certificates have been issued) then held by such holder and then subject to restriction shall be forfeited by such holder and reacquired by the Corporation. Except as otherwise specified by the grant, if a holder of record of restricted stock terminates normally or dies, any and all remaining restrictions with respect to such restricted stock shall expire. Notwithstanding the foregoing, if a holder of record of restricted stock is determined to have engaged in detrimental activity, all shares of restricted stock (whether or not stock certificates have been issued) then held by such holder and then subject to restriction shall be forfeited by such holder as of the date of such determination and shall be reacquired by the Corporation.

XII. Performance Awards.

(1) Performance awards may be granted hereunder to an eligible employee, for no cash consideration, for such minimum consideration as may be required by applicable law, or for such other consideration as may be specified by the grant. The terms and conditions of performance awards, which may include provisions establishing performance periods, performance criteria to be achieved during a performance period, and maximum or minimum settlement values, shall be specified by the grant.

(2) Performance awards may be valued by reference to the value of Common Stock of the Corporation or according to any other formula or method. Performance awards may be paid in cash, shares, or other consideration, or any combination thereof. The extent to which any applicable performance criteria have been achieved shall be conclusively determined by the administrative authority. Performance awards may be payable in a single payment or in installments and may be payable at a specified date or dates or upon attaining performance criteria.

(3) Except as otherwise specified by the grant, if the grantee terminates, but does not terminate normally, any performance award or installment thereof not payable prior to the grantee’s termination shall be annulled as of the date of termination. If the grantee is determined to have engaged in detrimental activity, any performance award or installment thereof not payable prior to the date of such determination shall be annulled as of such date.

XIII. Incentive Shares.

(1) An incentive award may be granted hereunder in the form of shares. Incentive shares may be granted to an eligible employee for no cash consideration, for such minimum consideration as may be required by applicable law, or for such other consideration as may be specified by the grant. The terms and conditions of incentive shares shall be specified by the grant.

(2) Incentive shares may be paid to the grantee in a single installment or in installments and may be paid at the time of grant or deferred to a later date or dates. Each grant shall specify the time and method of payment as determined by the granting authority, provided that no such determination shall authorize delivery of shares to be made later than the tenth anniversary of the

grantee’s date of termination. The granting authority, by amendment of the grant prior to delivery, can modify the method of payment for any incentive shares, provided that the delivery of any incentive shares shall be completed not later than the tenth anniversary of the grantee’s date of termination.

(3) If any incentive shares are payable after the grantee dies, such shares shall be payable (a) to the grantee’s designated beneficiary or, if there is no designated beneficiary, to the grantee’s personal representative, and (b) either in the form specified by the grant or otherwise, as may be determined by the administrative authority.

(4) Any grant of incentive shares is provisional, as to any share, until delivery of the certificate representing such share. If, while the grant is provisional,

(a) the grantee terminates, but does not terminate normally, or

(b) the grantee is determined to have engaged in detrimental activity,

the grant shall be annulled as of the date of termination, or the date of such determination, as the case may be.

XIV. Dividend Equivalent Rights; Interest Equivalents.

(1) A DER may be granted hereunder to an eligible employee, as a component of another award or as a separate award. The terms and conditions of DERs shall be specified by the grant. Dividend equivalents credited to the holder of a DER may be paid currently or may be deemed to be reinvested in additional shares (which may thereafter accrue additional dividend equivalents). Any such reinvestment shall be at fair market value at the time thereof. DERs may be settled in cash or shares or a combination thereof, in a single installment or installments. A DER granted as a component of another award may provide that such DER shall be settled upon exercise, settlement, or payment of, or lapse of restrictions on, such other award, and that such DER shall expire or be forfeited or annulled under the same conditions as such other award. A DER granted as a component of another award may also contain terms and conditions different from such other award.

(2) Any award under this Program that is settled in whole or in part in cash on a deferred basis may provide by the grant for interest equivalents to be credited with respect to such cash payment. Interest equivalents may be compounded and shall be paid upon such terms and conditions as may be specified by the grant.

XV. Other Awards.

Other forms of award based on, payable in or otherwise related in whole or in part to shares may be granted to an eligible employee under this Program if the granting authority determines that such awards are consistent with the purposes and restrictions of this Program. The terms and conditions of such awards shall be specified by the grant. Such awards shall be granted for no cash

consideration, for such minimum consideration as may be required by applicable law, or for such other consideration as may be specified by the grant.

XVI. Amendments to This Program.

The Board can from time to time amend or terminate this Program, or any provision hereof, except that approval of the shareholders of the Corporation shall be required for any amendment (1) to increase the maximum number of shares that may be effectively granted as awards hereunder; (2) to decrease the minimum exercise price per share of a stock option or SAR; or (3) for which such approval is otherwise necessary to comply with any applicable law, regulation, or listing requirement, or to qualify for an exemption or characterization that is deemed desirable by the Board. An amendment of this Program shall, unless the amendment provides otherwise, be effective for all outstanding awards.

XVII. Amendments to Individual Awards.

Without amending this Program, but subject to any requirements of applicable law or regulation, the granting authority may amend any one or more outstanding awards under this Program or any other shareholder-approved plan to incorporate in those awards any terms that could then be incorporated in a new award under this Program.

XVIII. Withholding Taxes.

The Corporation shall have the right to deduct from any cash payment made under this Program any federal, state or local income or other taxes required by law to be withheld with respect to such payment. It shall be a condition to the obligation of the Corporation to deliver shares or securities of the Corporation upon exercise of a stock option or SAR, upon settlement of a performance award or DER, upon delivery of restricted stock or incentive shares, or upon exercise, settlement, or payment of any other award under this Program, that the grantee of such award pay to the Corporation such amount as may be requested by the Corporation for the purpose of satisfying any liability for such withholding taxes. Any award under this Program may provide by the grant that the grantee of such award may elect, in accordance with any applicable regulations of the administrative authority, to pay a portion or all of the amount of such minimum required or additional permitted withholding taxes in shares. The grantee shall authorize the Corporation to withhold, or shall agree to surrender back to the Corporation, on or about the date such withholding tax liability is determinable, shares previously owned by such grantee or a portion of the shares that were or otherwise would be distributed to such grantee pursuant to such award having a fair market value equal to the amount of such required or permitted withholding taxes to be paid in shares.

XIX. Grant of Awards to Employees Who are Foreign Nationals.

Without amending this Program, but subject to the limitations specified in Sections III(4) and XVI, the granting authority can grant or amend, and the administrative authority can administer, annul, or terminate, awards to eligible employees who are foreign nationals on such terms and conditions different from those specified in this Program as may in its judgment be necessary or desirable to foster and promote achievement of the purposes of this Program.

Form of terms for restricted stock agreements with executive officers.

EXHIBIT 10(iii)(j)

Exxon Mobil Corporation

Extended Provisions for Restricted Stock Agreements

November 27, 2002

1. Effective Date and Issuance of Restricted Stock. If Grantee completes, signs, and returns the signature page of this Agreement to the Corporation in Dallas County, Texas, U.S.A. on or before March 14, 2003, this Agreement will become effective the date the Corporation receives and accepts this Agreement in Dallas County, Texas, U.S.A. After this Agreement becomes effective, the Corporation will, subject to paragraph 5, issue to Grantee, on a restricted basis as explained below, the number of shares of the Corporation’s common stock specified on the signature page of this Agreement.

2. Conditions. If issued, the shares of restricted stock will be subject to the provisions of this Agreement and the Program, and to such regulations and requirements as the administrative authority may establish from time to time. The shares will only be issued on the condition that Grantee accepts such provisions, regulations, and requirements.

3. Restrictions and Risk of Forfeiture. During the applicable restricted periods specified in paragraph 4 of this Agreement,

(a) the shares under restriction may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered, and any attempt to do so will be null and void; and

(b) the shares under restriction may be forfeited as provided in paragraph 6.

4. Restricted Periods. The restricted periods will commence at issuance and, unless the shares have been forfeited earlier under paragraph 6, will expire as follows, whether Grantee is still an employee or has terminated normally within the meaning of the Program:

(a) with respect to 50% of the shares, on November 27, 2007; and

(b) with respect to the remaining shares, on the later to occur of

(i) November 27, 2012, or

(ii) the first day of the calendar year immediately following the year in which Grantee terminates normally within the meaning of the Program;

except that

5. No Obligation to Issue Restricted Stock. The Corporation will have no obligation to issue the restricted stock and will have no other obligation to Grantee with respect to the subject matter of this Agreement if Grantee fails to complete, sign, and return this Agreement on or before March 14, 2003. In addition, whether or not Grantee has completed, signed, and returned the signature page of this Agreement, the Corporation will have no obligation to issue the restricted stock and will have no other obligation to Grantee with respect to the subject matter of this Agreement if, before the shares are actually issued:

(a) Grantee has terminated other than normally within the meaning of the Program; or

(b) Grantee is determined to have engaged in detrimental activity within the meaning of the Program; or

(c) Grantee has failed to provide the Corporation with cash for any required taxes due at issuance of the shares, if Grantee is required to do so under paragraph 7.

6. Forfeiture of Shares After Issuance. Until the applicable restricted period specified in paragraph 4 has expired, the shares under restriction will be forfeited or subject to forfeiture in the following circumstances:

(a) Termination. If Grantee terminates other than normally within the meaning of the Program, all shares for which the applicable restricted periods have not expired will be automatically forfeited and reacquired by the Corporation as of the date of termination.

(b) Detrimental activity. If Grantee is determined to have engaged in detrimental activity within the meaning of the Program, either before or after termination, all shares for which the applicable restricted periods have not expired will be automatically forfeited and reacquired by the Corporation as of the date of such determination.

(c) Attempted transfer. The shares are subject to forfeiture in the discretion of the administrative authority if Grantee attempts to sell, assign, transfer, pledge, or otherwise dispose of or encumber them during the applicable restricted periods.

7. Taxes. Notwithstanding the restrictions on transfer that otherwise apply, the Corporation in its sole discretion may withhold shares, either at the time of issuance, at the time the applicable restricted periods expire, or at any other time in order to satisfy any required withholding, social security, and similar taxes and contributions (collectively, “required taxes”). Withheld shares may be retained by the Corporation or sold on behalf of Grantee. If the Corporation does not withhold shares to satisfy required taxes, in the alternative the Corporation may require Grantee and Grantee will deposit with the Corporation cash in an amount determined by the Corporation to be necessary to satisfy required taxes. Notwithstanding any other provision of this Agreement, the Corporation will be under no obligation to issue or deliver shares to Grantee if Grantee fails timely to deposit such amount with the Corporation. The Corporation in its sole discretion may also withhold any required taxes from dividends paid on the restricted stock.

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8. Form of Shares. The shares will, upon issuance, be registered in the name of Grantee. During the applicable restricted periods, however, the shares will be held by or on behalf of the Corporation. Shares under restriction may be held in certificated or book-entry form as the administrative authority determines. Grantee agrees that the Corporation may give stop transfer instructions to its transfer agent with respect to shares subject to restriction and that, during the applicable restricted period, any restricted shares issued in certificated form may bear an appropriate legend noting the restrictions, risk of forfeiture, and requirements regarding withholding taxes. If and when the applicable restricted period expires with respect to any issued shares, subject to paragraph 7 the Corporation will deliver those shares promptly after such expiration to or for the account of Grantee free of restriction, either in certificated form or by book-entry transfer in accordance with the procedures of the administrative authority in effect at the time.

9. Shareholder Status. During the applicable restricted periods, Grantee will have customary rights of a shareholder with respect to the shares registered in Grantee’s name, including the rights to vote and to receive dividends on the shares, subject to the restrictions on transfer and the possible events of forfeiture provided in this Agreement. However, before the shares are registered in Grantee’s name Grantee will not be a shareholder of the Corporation and will not be entitled to dividends with respect to those shares.

10. Change in Capitalization. If a stock split, stock dividend, or other relevant change in capitalization of the Corporation occurs, any resulting new shares or securities issued with respect to previously issued shares that are still restricted under this Agreement will be delivered to and held by or on behalf of the Corporation and will be subject to the same provisions, restrictions, and requirements as those previously issued shares.

11. Limits on the Corporation’s Obligations. Notwithstanding anything else contained in this Agreement, under no circumstances will the Corporation be required to issue or deliver any shares if doing so would violate any law or listing requirement that the administrative authority determines to be applicable, or if Grantee has failed to provide for required taxes pursuant to paragraph 7.

12. Receipt or Access to Program. Grantee acknowledges receipt of or access to the full text of the Program.

13. Appointment of Agent for Dividends. Grantee appoints the Corporation to be Grantee’s agent to receive for Grantee dividends on shares while they are subject to restriction under this Agreement. The Corporation will transmit such dividends, net of required taxes pursuant to paragraph 7, to or for the account of Grantee in such manner as the administrative authority determines.

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14. Electronic Delivery of Shareholder Communications. The Corporation’s proxy statement, annual report, and other shareholder materials deliverable to Grantee with respect to shares issued under this Agreement may be delivered to Grantee electronically, unless Grantee specifically requests delivery in paper format. Such electronic delivery may be accomplished by email transmission of the materials, or by email notification to Grantee that the materials are available at a specified website to which Grantee has access.

15. Addresses for Communications. To facilitate communications regarding this Agreement and electronic delivery of shareholder communications as provided in paragraph 14, Grantee will provide Grantee’s current mailing and email addresses on the signature page of this Agreement and agrees to notify the Corporation promptly of changes in such information in the future. Communications to the Corporation in connection with this Agreement should be directed to the Incentive Processing Office at the address given on the signature page of this Agreement, or to such other address as the Corporation may designate by further notice to Grantee.

16. No Employment Contract or Entitlement to Future Awards. This Agreement is not and does not imply a contract or assurance of employment and does not in any way limit or restrict the ability of Grantee’s employer to terminate Grantee’s employment. This Agreement does not entitle Grantee to any other or future awards.

17. Governing Law and Consent to Jurisdiction. This Agreement and the Program are governed by the laws of the State of New York without regard to any conflict of law rules. Any dispute arising out of or relating to the Agreement or the Program may be resolved in any state or federal court located within Dallas County, Texas, U.S.A. Grantee accepts that venue and submits to the personal jurisdiction of any such court. Similarly, the Corporation accepts such venue and submits to such jurisdiction.

18. Entire Agreement. This Agreement and the Program constitute the entire understanding between Grantee and the Corporation with respect to the subject matter of this Agreement.

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Form of terms for annuitant cash unit agreements.

EXHIBIT 10(iii)(k)

Exxon Mobil Corporation

Provisions for Annuitant Cash Unit Agreements

November 27, 2002

1. Effective Date and Credit of Units. If Grantee completes, signs, and returns the signature page of this Agreement to Exxon Mobil Corporation (the “Corporation”) in Dallas County, Texas, U.S.A. on or before March 14, 2003, this Agreement will become effective the date the Corporation receives and accepts this Agreement in Dallas County, Texas, U.S.A. After this Agreement becomes effective, the Corporation will credit to Grantee the number of units specified on the signature page of this Agreement. Subject to the terms and conditions of this Agreement, each unit will entitle Grantee to receive in settlement of the unit an amount in cash equal to the fair market value of one share of the Corporation’s common stock as described in paragraph 9.

2. Conditions. The units will be subject to the provisions of this Agreement and to such regulations and requirements as the Corporation may establish from time to time. The units will only be credited to Grantee on the condition that Grantee accepts such provisions, regulations, and requirements.

3. Restrictions and Risk of Forfeiture. During the applicable restricted periods specified in paragraph 4 of this Agreement,

(a) the units under restriction may not be sold, assigned, transferred, pledged, or otherwise disposed of or encumbered, and any attempt to do so will be null and void; and

(b) the units under restriction may be forfeited as provided in paragraph 6.

4. Restricted Periods. The restricted periods will commence when the units are credited to Grantee and, unless the units have been forfeited earlier under paragraph 6, will expire as follows:

(a) with respect to 50% of the units, on November 27, 2007; and

(b) with respect to the remaining units, on November 27, 2012;

except that

5. No Obligation to Credit Units. The Corporation will have no obligation to credit any units and will have no other obligation to Grantee with respect to the subject matter of this Agreement if Grantee fails to complete, sign, and return this Agreement on or before March 14, 2003. In addition, whether or not Grantee has completed, signed, and returned this Agreement, the Corporation will have no obligation to credit any units and will have no other obligation to Grantee with respect to the subject matter of this Agreement if, before the units are credited Grantee is determined to have engaged in detrimental activity. In this Agreement, “detrimental activity” means activity that is determined in individual cases by the Board Compensation Committee or the Chairman of the Board of the Corporation to be detrimental to the interests of the Corporation or any affiliate.

6. Forfeiture of Units After Crediting. Until the applicable restricted period specified in paragraph 4 has expired, the units subject to restriction will be forfeited or subject to forfeiture in the following circumstances:

(a) Detrimental activity. If Grantee is determined to have engaged in detrimental activity, all units for which the applicable restricted periods have not expired will be automatically forfeited as of the date of such determination.

(b) Attempted transfer. The units are subject to forfeiture in the discretion of the Corporation if Grantee attempts to sell, assign, transfer, pledge, or otherwise dispose of or encumber them during the applicable restricted periods.

7. Taxes. Notwithstanding the restrictions on transfer that otherwise apply, the Corporation in its sole discretion may withhold units, or cash otherwise payable in settlement of units, either at the time of crediting, at the time of settlement, or at any other time in order to satisfy any required withholding, social security, and similar taxes and contributions (collectively, “required taxes”). If the Corporation does not withhold units or cash to satisfy required taxes, in the alternative the Corporation may require Grantee and Grantee will deposit with the Corporation cash in an amount determined by the Corporation to be necessary to satisfy required taxes. Notwithstanding any other provision of this Agreement, the Corporation will be under no obligation to credit units or to pay cash to Grantee in settlement of any units if Grantee fails timely to deposit such amount with the Corporation. The Corporation in its sole discretion may also withhold any required taxes from dividend equivalents payable on the units.

8. Form of Units; No Shareholder Status. The units will be represented by book-entry credits in records maintained by or on behalf of the Corporation. Units will be unfunded, unsecured promises by the Corporation to pay cash in the future upon the terms and subject to the conditions of this Agreement. Grantee will not be a shareholder of the Corporation with respect to units.

-2-

9. Settlement of Units. If and when the applicable restricted period expires with respect to any units, the Corporation will pay to or for the account of Grantee promptly after such expiration an amount in cash equal to the fair market value of one share of the Corporation’s common stock on the expiration date, net of required taxes in accordance with paragraph 7. Fair market value of shares will be determined and payments will be made in accordance with the procedures of the Corporation in effect at the time. Units will only be settled in cash.

10. Dividend Equivalents. During the applicable restricted periods, the Corporation will pay to Grantee cash with respect to each credited unit corresponding in amount, currency, and timing to cash dividends that would be payable with respect to an outstanding share of the Corporation’s common stock.

11. Change in Capitalization. If during the applicable restricted periods a stock split, stock dividend, or other relevant change in capitalization of the Corporation occurs, the Corporation will make such adjustments in the number of units credited to Grantee, or in the number and type of securities used in determining the cash settlement value of units or dividend equivalent amounts, as the Corporation may determine to be appropriate.

12. Limits on the Corporation’s Obligations. Notwithstanding anything else contained in this Agreement, under no circumstances will the Corporation be required to credit any units or make any payments in settlement of units if doing so would violate any law or listing requirement that the Corporation determines to be applicable.

13. Addresses for Communications. To facilitate communications regarding this Agreement, Grantee will provide Grantee’s current mailing and email addresses on the signature page of this Agreement and agrees to notify the Corporation promptly of changes in such information in the future. Communications to the Corporation in connection with this Agreement should be directed to the Incentive Processing Office at the address given on the signature page of this Agreement, or to such other address as the Corporation may designate by further notice to Grantee.

14. Governing Law and Consent to Jurisdiction. This Agreement is governed by the laws of the State of New York without regard to any conflict of law rules. Any dispute arising out of or relating to the Agreement may be resolved in any state or federal court located within Dallas County, Texas, U.S.A. Grantee accepts that venue and submits to the personal jurisdiction of any such court. Similarly, the Corporation accepts such venue and submits to such jurisdiction.

15. Entire Agreement. This Agreement constitutes the entire understanding between Grantee and the Corporation with respect to the subject matter of this Agreement. This Agreement is not governed by or subject to the provisions of the Corporation’s 1993 Incentive Program or Short Term Incentive Program.

-3-

Computation of ratio earnings to fixed charges.

EXHIBIT 12

EXXON MOBIL CORPORATION

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Years Ended December 31,
	2002			2001			2000			1999			1998
	(millions of dollars)
Income from continuing operations	$	11,011		$	15,003		$	15,806		$	7,845		$	8,131
Excess/(shortfall) of dividends over earnings of affiliates owned less than 50 percent accounted for by the equity method		(140	)		(108	)		(354	)		300			164
Provision for income taxes(1)		7,073			9,599			11,614			3,617			4,385
Capitalized interest		(143	)		(255	)		(409	)		(423	)		(400	)
Minority interests in earnings of consolidated subsidiaries		206			556			346			139			261

		18,007			24,795			27,003			11,478			12,541

Fixed Charges:(1)
Interest expense—borrowings		368			328			637			826			769
Capitalized interest		442			529			653			606			564
Rental expense representative of interest factor		587			621			551			617			795
Dividends on preferred stock		5			8			12			8			6

		1,402			1,486			1,853			2,057			2,134

Total adjusted earnings available for payment of fixed charges	$	19,409		$	26,281		$	28,856		$	13,535		$	14,675

Number of times fixed charges are earned		13.8			17.7			15.6			6.6			6.9

Note:

(1)

The provision for income taxes and the fixed charges include Exxon Mobil Corporation’s share of 50 percent owned companies and majority owned subsidiaries that are not consolidated.

Subsidiaries of the registrant.

EXHIBIT 21

Subsidiaries of the Registrant (1), (2) and (3)

AT DECEMBER 31, 2002

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
Aera Energy LLC (5)	48.2	California
Al-Jubail Petrochemical Company (4) (5)	50	Saudi Arabia
Ampolex (CEPU) Pte Ltd	100	Singapore
Ancon Insurance Company, Inc.	100	Vermont
BEB Erdgas und Erdoel GmbH (4) (5)	50	Germany
Cameroon Oil Transportation Company S.A. (5)	49.46	Cameroon
Caspian Pipeline Consortium (5)	7.5	Russia/Kazakhstan
Castle Peak Power Company Limited (5)	60	Hong Kong
Chalmette Refining, LLC (4) (5)	50	Delaware
CMD Partnership, L.P.	100	Delaware
Delhi Petroleum Pty. Ltd.	100	Australia
Esso Australia Resources Pty Ltd	100	Australia
Esso Austria GmbH	100	Austria
Esso Brasileira de Petroleo Limitada	100	Brazil
Esso Capital B.V.	100	Netherlands
Esso Chile Petrolera Limitada	100	Chile
ESSO Deutschland GmbH	100	Germany
Esso Espanola, S. L.	100	Spain
Esso Exploration and Production Angola (Block 33) Limited	100	Bahamas
Esso Exploration and Production Chad Inc.	100	Delaware
Esso Exploration and Production Nigeria (Deepwater) Limited	100	Nigeria
Esso Exploration and Production Nigeria Limited	100	Nigeria
Esso Exploration and Production Norway AS	100	Norway
Esso Exploration and Production UK Limited	100	England
Esso Exploration Angola (Block 15) Limited	100	Bahamas
Esso Exploration Angola (Block 17) Limited	100	Bahamas
Esso Holding Company Singapore Limited	100	Bahamas
Esso Ireland Limited	100	Ireland
Esso Italiana S.r.l.	100	Italy
Esso Malaysia Berhad	65	Malaysia
Esso Natuna Ltd.	100	Bahamas
Esso Nederland B.V.	100	Netherlands
Esso Norge AS	100	Norway
Esso Petrolera Argentina Sociedad de Responsabilidad Limitada	100	Argentina
Esso Petroleum Company, Limited	100	England
Esso Pipeline Investments Limited	100	Bahamas
Esso Schweiz GmbH	100	Switzerland
Esso Societe Anonyme Francaise	81.548	France
Esso Standard Oil Company (Puerto Rico)	100	Puerto Rico
Esso (Thailand) Public Company Limited	87.5	Thailand
Esso Trading Company of Abu Dhabi	100	Delaware
Exxon Azerbaijan Limited	100	Bahamas
Exxon Capital Corporation	100	New Jersey
Exxon Chemical Arabia Inc.	100	Delaware
Exxon Chemical Asset Management Partnership	87.75	Delaware

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
Exxon Luxembourg Holdings LLC	100	Delaware
Exxon Mobile Bay Limited Partnership	88.69	Delaware
Exxon Neftegas Limited	100	Bahamas
Exxon Overseas Corporation	100	Delaware
Exxon Overseas Investment Corporation	100	Delaware
Exxon Yemen Inc.	100	Delaware
ExxonMobil Alaska Production Inc.	100	Delaware
ExxonMobil Asia Pacific Pte. Ltd.	100	Singapore
ExxonMobil Aviation International Limited	100	England
ExxonMobil Canada Ltd.	100	Canada
ExxonMobil Central Europe Holding GmbH	100	Germany
ExxonMobil Chemical Films Europe, Inc.	100	Delaware
ExxonMobil Chemical France S.A.R.L.	99.77	France
ExxonMobil Chemical Holland B.V.	100	Netherlands
ExxonMobil Chemical Holland LLC	100	Delaware
ExxonMobil Chemical Limited	100	England
ExxonMobil Chemical Olefins Inc.	100	Delaware
ExxonMobil Chemical Operations Private Limited	100	Singapore
ExxonMobil Chemical Polymeres SNC	99.77	France
ExxonMobil de Colombia S.A.	99.03	Colombia
ExxonMobil Egypt (S.A.E.)	100	Egypt
ExxonMobil Energy Limited	100	Hong Kong
ExxonMobil Exploration and Production Malaysia Inc.	100	Delaware
ExxonMobil Far East Holdings Ltd.	100	Bahamas
ExxonMobil Finance B.V.	100	Netherlands
ExxonMobil Gas Marketing Europe Limited	100	England
ExxonMobil Global Services Company	100	Delaware
ExxonMobil Holding Company Holland LLC	100	Delaware
ExxonMobil Hong Kong Limited	100	Hong Kong
ExxonMobil International Holdings Inc.	100	Delaware
ExxonMobil International Services, SARL	100	Luxembourg
ExxonMobil Kazakhstan Inc.	100	Bahamas
ExxonMobil Kazakhstan Ventures Inc.	100	Delaware
ExxonMobil Luxembourg UK, SARL	100	Luxembourg
ExxonMobil Malaysia Sdn Bhd	100	Malaysia
ExxonMobil Marine Limited	100	England
ExxonMobil Mediterranea S.R.L.	100	Italy
ExxonMobil Oil Corporation	100	New York
ExxonMobil Oil Indonesia Inc.	100	Delaware
ExxonMobil Petroleum & Chemical	100	Belgium
ExxonMobil Pipeline Company	100	Delaware
ExxonMobil Qatargas Inc.	100	Delaware
ExxonMobil Rasgas Inc.	100	Delaware
ExxonMobil Sales and Supply Corporation	100	Delaware
ExxonMobil Yugen Kaisha	100	Japan

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
Fina Antwerp Olefins N.V. (5)	35	Belgium
Imperial Oil Limited	69.6	Canada
Infineum USA L.P. (4) (5)	50	Delaware
Kyokuto Sekiyu Kogyo Kabushiki Kaisha (4) (5)	50	Japan
Mineraloelraffinerie Oberrhein GmbH & Co. KG (5)	25	Germany
Mobil Argentina S.A.	100	Argentina
Mobil Australia Resources Company Pty Limited	100	Australia
Mobil California Exploration & Producing Asset Company	100	Delaware
Mobil Caspian Pipeline Company	100	Delaware
Mobil Cerro Negro, Ltd.	100	Bahamas
Mobil Corporation	100	Delaware
Mobil Equatorial Guinea Inc.	100	Delaware
Mobil Erdgas-Erdoel GmbH	99.999	Germany
Mobil Exploration and Development Argentina Inc.	100	Delaware
Mobil Exploration & Producing Australia Pty Ltd	100	Australia
Mobil Exploration and Producing North America Inc.	100	Nevada
Mobil Exploration Indonesia Inc.	100	Delaware
Mobil Exploration Norway Inc.	100	Delaware
Mobil Fairfax Inc.	100	Delaware
Mobil International Finance Corporation	100	Delaware
Mobil North Sea Limited	100	Delaware
Mobil Oil Australia Pty Ltd	100	Australia
Mobil Oil Exploration & Producing Southeast Inc.	100	Delaware
Mobil Oil Francaise	99.986	France
Mobil Oil New Zealand Limited	100	New Zealand
Mobil Oil Nigeria Public Limited Company	60	Nigeria
Mobil Pase Inc.	100	Delaware
Mobil Producing Nigeria Unlimited	100	Nigeria
Mobil Producing Texas & New Mexico Inc.	100	Delaware
Mobil Refining Australia Pty Ltd	100	Australia
Mobil Yanbu Petrochemical Company Inc.	100	Delaware
Mobil Yanbu Refining Company Inc.	100	Delaware
Nansei Sekiyu Kabushiki Kaisha (5)	43.77	Japan
Nederlandse Aardolie Maatschappij B.V. (4) (5)	50	Netherlands
oy Esso ab	100	Finland
Paxon Polymer Company, L.P. II	92.84	Delaware
Qatar Liquefied Gas Company Limited (5)	10	Qatar
Ras Laffan Liquefied Natural Gas Company Limited (5)	26.5	Qatar
Ras Laffan Liquefied Natural Gas Company Limited (II) (5)	29.999	Qatar
Saudi Aramco Mobil Refinery Company Ltd. (4) (5)	50	Saudi Arabia
Saudi Yanbu Petrochemical Co. (4) (5)	50	Saudi Arabia
Schubert Beteiligungs-GmbH	72.999	Germany
SeaRiver Maritime Financial Holdings, Inc.	100	Delaware
SeaRiver Maritime, Inc.	100	Delaware
Societa per Azioni Raffineria Padana Olii Minerali-SARPOM	74.21	Italy
Standard Marine Tonsberg AS	100	Norway

	Percentage of Voting Securities Owned Directly or Indirectly by Registrant	State or Country of Organization
Superior Oil (U.K.) Limited	100	England
Tengizchevroil (5)	25	Kazakhstan
TonenGeneral Sekiyu K.K.	50.021	Japan
Tonen Kagaku K.K.	50.021	Japan

NOTES:

(1)

For the purposes of this list, if the registrant owns directly or indirectly approximately 50 percent of the voting securities of any person and approximately 50 percent of the voting securities of such person is owned directly or indirectly by another interest, or if the registrant includes its share of net income of any other unconsolidated person in consolidated net income, such person is deemed to be a subsidiary.

(2)

With respect to certain companies, shares in names of nominees and qualifying shares in names of directors are included in the above percentages.

(3)

The names of other subsidiaries have been omitted from the above list since considered in the aggregate, they would not constitute a significant subsidiary under Securities and Exchange Commission Regulation S-X, Rule 1-02(w).

(4)

The registrant owns directly or indirectly approximately 50 percent of the securities of this person and approximately 50 percent of the voting securities of this person is owned directly or indirectly by another single interest.

(5)

The investment in this unconsolidated person is represented by the registrant’s percentage interest in the underlying net assets of such person. The accounting for these unconsolidated persons is referred to as the equity method of accounting.

Consent of PricewaterhouseCoopers LLP, Independent Accountants.

EXHIBIT 23

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the following Prospectuses constituting part of the Registration Statements on:

Form S-3 (Nos. 333-85016 and 333-27489)		—Exxon Mobil Corporation Shareholder Investment Program;
Form S-3 (No. 33-48919)		—Guaranteed Debt Securities and Warrants to Purchase Guaranteed Debt Securities of Exxon Capital Corporation;
Form S-3 (No. 33-8922)		—Guaranteed Debt Securities of SeaRiver Maritime Financial Holdings, Inc. (formerly Exxon Shipping Company)

and we hereby consent to the incorporation by reference in the Registration Statements on:

Form S-8 (Nos. 333-101175, 333-38917 and 33-51107)		—1993 Incentive Program of Exxon Mobil Corporation (together with 1988 Long Term Incentive Plan of Exxon Mobil Corporation);
Form S-8 (No. 333-69378)		—ExxonMobil Fuels Marketing Savings Plan;
Form S-8 (No. 333-72955)		—ExxonMobil Savings Plan;
Form S-8 (No. 333-75659)		—Post-Effective Amendment No. 2 on Form S-8 to Form S-4 which pertains to the 1993 Incentive Program of Exxon Mobil Corporation

of our report dated February 26, 2003 relating to the financial statements which appear in this Form 10-K.

/S/ PRICEWATERHOUSECOOPERS LLP

Dallas, Texas

March 26, 2003

Certification of Periodic Financial Report

EXHIBIT 99.1

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Lee R. Raymond, the chief executive officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge:

(i) the Annual Report on Form 10-K of the Company for the year ended December 31, 2002, as filed with the Securities and Exchange Commission on the date hereof (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 26, 2003

/s/ LEE R. RAYMOND

Lee R. Raymond

Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to Exxon Mobil Corporation and will be retained by Exxon Mobil Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

Certification of Periodic Financial Report

EXHIBIT 99.2

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Donald D. Humphreys, the principal accounting officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge:

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 26, 2003

/s/ DONALD D. HUMPHREYS

Donald D. Humphreys

Vice President and Controller

(Principal Accounting Officer)

Certification of Periodic Financial Report

EXHIBIT 99.3

Certification of Periodic Financial Report

Pursuant to 18 U.S.C. Section 1350

For purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned, Frank A. Risch, the principal financial officer of Exxon Mobil Corporation (the “Company”), hereby certifies that, to his knowledge:

(ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 26, 2003

/s/ FRANK A. RISCH

Frank A. Risch

Vice President and Treasurer

(Principal Financial Officer)