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Index to Financial Statements

2005

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, 2005

or

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant’s telephone number, including area code)

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes   ü    No        

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes         No   ü    

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

            Large accelerated filer    ü           Accelerated filer                 Non-accelerated filer         

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act).  Yes         No   ü    

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2005, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $57.47 on the New York Stock Exchange composite tape, was in excess of $362 billion.

Documents Incorporated by Reference:

    Proxy Statement for the 2006 Annual Meeting of Shareholders (Part III)

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EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

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Index to Financial Statements

PART I

Item 1.     Business.

Exxon Mobil Corporation, formerly named Exxon Corporation, was incorporated in the State of New Jersey in 1882. On November 30, 1999, Mobil Corporation became a wholly-owned subsidiary of Exxon Corporation, 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 commodity 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.

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on the air, water and ground. This includes a significant investment in refining technology to manufacture low-sulfur motor fuels as well as projects to reduce nitrogen oxide and sulfur oxide emissions. ExxonMobil’s 2005 worldwide environmental costs for all such preventative and remediation steps were about $3.3 billion, of which $1.2 billion were capital expenditures and $2.1 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2006 and 2007 (with capital expenditures approximately 35 percent of the total).

Operating data and industry segment information for the Corporation are contained on pages 30, 73, 74 and 86; information on oil and gas reserves is contained on pages 80 through 83 and information on Company-sponsored research and development activities is contained on page 58 of the Financial Section of this report.

The number of regular employees was 83.7 thousand, 85.9 thousand and 88.3 thousand at years ended 2005, 2004 and 2003, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 22.4 thousand, 19.3 thousand and 17.4 thousand at years ended 2005, 2004 and 2003, 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. Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit, compensation and nominating committees of the Board of Directors. All of these documents are available in print without charge to shareholders who request them. Information on our website is not incorporated into this report.

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ExxonMobil’s financial and operating results are subject to a number of factors, many of which are not within the company’s control. These factors include the following:

Industry and Economic Factors:    The oil and gas business is fundamentally a commodity business. This means the operations and earnings of the Corporation and its affiliates throughout the world may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on gasoline and other refined products. Oil, gas, petrochemical and product prices and margins in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity. These events or conditions are generally not predictable and include, among other things:

Under certain market conditions, factors that have a positive impact on one segment of our business may have a negative impact on another segment and vice versa.

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 both industrial and individual consumers. The Corporation competes with other firms in the sale or purchase of needed goods and 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 businesses, is ExxonMobil’s ability to manage expenses successfully. This requires continuous management focus on reducing unit costs and improving efficiency including through technology improvements, cost control, productivity enhancements and regular reappraisal of our asset portfolio as described elsewhere in this report.

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 factors including:

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Both the likelihood of these occurrences and their overall effect upon the Corporation vary greatly from country to country and are not predictable. A key component of the Corporation’s strategy for managing political risk is geographic diversification of the Corporation’s assets and operations.

Project Factors:    In addition to some of the factors cited above, ExxonMobil’s results depend upon the Corporation’s ability to develop and operate major projects and facilities as planned. The Corporation’s results will therefore be affected by events or conditions that impact the advancement, operation, cost or results of such projects or facilities, including:

See section 1 of Item 2 of this report for a discussion of additional factors affecting future capacity growth and the timing and ultimate recovery of reserves.

Market Risk Factors:    See pages 40 and 41 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.

None.

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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 8, which note appears on page 60, and on pages 76 through 85.

Information with regard to oil and gas producing activities follows:

Estimated proved reserves are shown on pages 80 through 83 of the Financial Section of this report. No major discovery or other favorable or adverse event has occurred since December 31, 2005, 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 pages 84 and 85 of the Financial Section of this report.

The table below summarizes the oil-equivalent proved reserves in each geographic area for consolidated subsidiaries as detailed on pages 80 through 83 of the Financial Section of this report for the year ended December 31, 2005. The Corporation has reported 2004 and 2005 proved reserves on the basis of December 31 prices and costs. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

Additional detail on developed and undeveloped oil-equivalent proved reserves is shown in the table below.

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In the preceding reserves information, and in the reserves tables on pages 80 through 83 of the Financial Section of this report, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same views of equity company reserves as it has for reserves from consolidated subsidiaries.

The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the period 2006-2010. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, severe weather events, price effects on production sharing contracts and other factors as described in Item 1A—Risk Factors of this report.

The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long term oil and gas price levels.

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

During 2005, 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 2004, 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 reserves and gas reserves reported on EIA-23 and those reported in the registrant’s Annual Report on Form 10-K for 2004 exceeds five percent.

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

Reference is made to pages 76 and 77 of the Financial Section of this report. Average sales prices have been calculated by using sales quantities from the Corporation’s 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 81 of the Financial Section of this report. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and thus are different from those shown in the reserves table on page 82 of the Financial Section of this report due to volumes consumed or flared. The volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.

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4.    Gross and Net Productive Wells

The numbers of wells operated at year-end 2005 were 17,351 gross wells and 14,028 net wells. At year-end 2004, the numbers of operated wells were 18,427 gross wells and 15,216 net wells.

5.    Gross and Net Developed Acreage

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

6.    Gross and Net Undeveloped Acreage

        ExxonMobil’s investment in developed and undeveloped acreage is comprised of numerous concessions, blocks and leases. The terms and conditions under which the Corporation maintains exploration and/or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Corporation may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Corporation has generally been successful in obtaining extensions.

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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.

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

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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 six years (with extension of the initial period of one year at a time up to ten years after 1985), 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 initial period. Licenses issued after July 1, 1997 have an initial period of up 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, many of the early licenses issued under the first four licensing rounds, provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. ExxonMobil’s licenses issued in 2005 as part of the 23rd licensing round have an initial term of four years with a second term extension of four years and final term of 18 years. There is a mandatory relinquishment of 50-percent of acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.

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 terms and conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended at the discretion of the government.

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 Nigerian National Petroleum Corporation (NNPC). NNPC 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.

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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 local 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 Mineral 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. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC.

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 NNPC 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 joint venture 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.

ASIA PACIFIC / MIDDLE EAST

Australia

Exploration and production activities are conducted offshore and are governed by Federal legislation. 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 BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. Formerly this activity was carried out by Pertamina, the government owned oil company, which is now a competing limited liability company.

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.

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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, depending on whether deep water areas or otherwise, with possible extensions to the exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed 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 will be deemed relinquished if no extension is granted. All extensions are subject to the national oil company’s prior written approval. 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 (an additional extension of three years is possible in certain circumstances). 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.

Qatar

The State of Qatar grants gas production development project 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. The Government of Yemen awarded a five-year extension of the Marib PSA, but later repudiated the extension and expelled the concession holders. The parties are now in arbitration over the validity of the extension.

Thailand

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

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.

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RUSSIA/CASPIAN

Azerbaijan

The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field 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, exploration 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 possible extensions. The production period, which includes development, is for 20 years with the possibility of two ten-year extensions.

Russia

Terms for ExxonMobil’s acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, which would be 2021. The term may be extended thereafter in 10-year increments as specified in the PSA.

SOUTH AMERICA

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.

Venezuela

Exploration and production activities are governed by Association Agreements containing risk/profit provisions negotiated with the national oil company or its affiliates. Association Agreements are awarded for a term not to exceed 39 years. These agreements have an exploration and a production phase. The term of production begins after the exploration phase and runs for 20 years with the possibility of an extension, so long as the total contract term does not exceed 39 years.

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

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8.    Number of Net Productive and Dry Wells Drilled

9.    Present Activities

A. Wells Drilling

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B. Review of Principal Ongoing Activities in Key Areas

During 2005, 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 activities) 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 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 2005. At year-end 2005, ExxonMobil’s acreage totaled 11.7 million net acres, of which 3.0 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During 2005, 514.3 net exploration and development wells were completed in the inland lower 48 states and 9.0 net development wells were completed offshore in the Pacific. An acid gas injection project was started up to increase existing plant capacity at the Shute Creek treating facility in La Barge, Wyoming, and tight gas development continues in the Piceance Basin of Colorado. Participation in Alaska production and development continued and a total of 23.7 net exploration and development wells were drilled. On Alaska’s North Slope, activity continued on the Western Region Development Project (primarily the Orion field) with development drilling and engineering design for facility expansions.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2005 was 2.8 million acres. A total of 16.2 net exploration and development wells were completed during the year. Installation of the semi-submersible production and drilling vessel, along with infrastructure to transport future oil and gas production onshore, continued for the Thunder Horse development in 2005. Startup, delayed due to a listing incident, is anticipated to occur in 2006.

CANADA

ExxonMobil’s year-end 2005 acreage holdings totaled 7.1 million net acres, of which 3.1 million net acres were offshore. A total of 266.7 net exploration and development wells were completed during the year. In eastern Canada, work continued on the Sable Compression project.

EUROPE

France

ExxonMobil’s acreage at year-end 2005 was 0.1 million net onshore acres.

Germany

A total of 2.3 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2005, with 7.6 net exploration and development wells drilled during the year.

Netherlands

ExxonMobil’s interest in licenses totaled 1.9 million net acres at year-end 2005, 1.5 million acres onshore and 0.4 million acres offshore. During 2005, 1.8 net exploration and development wells were

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drilled. Offshore, the first unmanned minimum facility monotower platform was successfully located on the K17-FA field. Onshore, a multi-year project is underway to renovate production clusters and install new compression to maintain capacity and extend field life.

Norway

ExxonMobil’s net interest in licenses at year-end 2005 totaled approximately 1.0 million acres, all offshore. ExxonMobil participated in 7.7 net exploration and development well completions in 2005. Production was initiated at the Oseberg J field in June, the Aasgard Q field in August and the Kristin field in November 2005. The Sleipner A low pressure project and Ringhorne East, Oseberg Vestflanken, Fram East and Ormen Lange field developments are in progress.

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2005 totaled approximately 2.1 million acres, all offshore. A total of 9.4 net exploration and development wells were completed during the year. The Arthur project commenced production in early 2005. Other projects progressed in 2005 include Caravel, Cutter, Merganser and Starling.

AFRICA

Angola

ExxonMobil’s year-end 2005 acreage holdings totaled 0.7 million net offshore acres and 12.0 net exploration and development wells were completed during the year. On Block 15, production began in July from the Kizomba B development and design work is complete on the Marimba development, which will tie-back to the Kizomba A Floating, Production, Storage and Offloading (FPSO) vessel. Planning for the Kizomba C development is ongoing. A block-wide 4D seismic acquisition program started late in the year. On Block 17, construction is underway on the Dalia and Rosa developments.

Cameroon

ExxonMobil’s acreage totaled 0.3 million net offshore acres at year-end 2005.

Chad

ExxonMobil’s net year-end 2005 acreage holdings consisted of 3.3 million onshore acres, with 35.6 net exploration and development wells completed during the year. Development of the Moundouli field is in progress.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.4 million net offshore acres at year-end 2005, with 4.5 net development wells completed during the year.

Nigeria

ExxonMobil’s net acreage totaled 1.6 million offshore acres at year-end 2005, with 17.3 net exploration and development wells completed during the year. The ExxonMobil-operated Yoho field (OML 104) early production system was expanded, and the full field production platform was installed. The ExxonMobil-operated East Area Additional Oil Recovery platform was also installed, and detailed design and construction began on the ExxonMobil-operated East Area NGL II project. Production began in 2005 at the deepwater Bonga field (OML 118). Drilling continued at the ExxonMobil-operated deepwater Erha field (OPL 209), and the Erha FPSO vessel arrived. Construction continued on the

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Amenam-Kpono Phase 2 Gas project and Front End Engineering and Design (FEED) work was initiated on the deepwater Usan field (OPL 222).

ASIA PACIFIC / MIDDLE EAST

Australia

ExxonMobil’s net year-end 2005 acreage holdings totaled 1.2 million acres, all offshore. ExxonMobil drilled a total of 11.4 net exploration and development wells in 2005.

Indonesia

ExxonMobil had acreage of 2.5 million net acres at year-end 2005, 1.7 million acres offshore and 0.8 million acres onshore.

The production sharing contract for the Cepu Contract Area was signed in September 2005 by PT Pertamina (Persero) and ExxonMobil and approved by the Government of Indonesia. The term of the contract is 30 years. PT Pertamina (Persero) and ExxonMobil are currently working on the Joint Operation Agreement (JOA).

Japan

ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2005.

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2005. During the year, a total of 25.6 net development wells were completed. Development and infill drilling wells were successfully completed at six platforms: Guntong-F, Irong Barat-C, Tapis-C, Semangkok-B, Angsi-A and Tiong-A. First oil was produced from the Guntong-F and Irong Barat-C platforms in 2005. Drilling activities are currently ongoing at Jerneh-A.

Papua New Guinea

A total of 0.5 million net onshore acres were held by ExxonMobil at year-end 2005, with 0.6 net development wells completed during the year.

Qatar

Production and development activities continued on natural gas projects in Qatar. Liquefied natural gas (LNG) operating companies include:

Qatar Liquefied Gas Company Limited — (QG I)

Qatar Liquefied Gas Company Limited (II) — (QG II)

Ras Laffan Liquefied Natural Gas Company Limited — (RL I)

Ras Laffan Liquefied Natural Gas Company Limited (II) — (RL II)

Ras Laffan Liquefied Natural Gas Company Limited (3) — (RL 3)

In addition, production commenced in 2005 for ExxonMobil’s Al Khaleej Gas (AKG) project which supplies pipeline gas to domestic industrial customers. The AKG project will have a target peak production rate of 675 million of cubic feet per day (gross) and produce associated condensate, and commencing in early 2006 will produce LPG (Liquefied Petroleum Gas).

At the end of 2005, 54 (gross) wells supplied natural gas to currently producing LNG and pipeline gas sales facilities and drilling is underway to complete wells that will supply the new QG II, RL II and RL 3 projects. A total of 9.1 net exploration and development wells were completed in 2005.

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Qatar LNG capacity volumes at year-end included 9.7 MTA (millions of metric tons per annum) in QG I Trains 1-3 and a combined 16.0 MTA in RL I Trains 1-2 and RL II Trains 3-4. During 2005, production commenced at RL II Train 4, and an expansion project was completed to increase the capacity of QG I Trains 1-3 to 9.7 MTA. Construction of QG II Trains 4-5 will add planned capacity of 15.6 MTA when complete. In addition, construction of RL II Train 5 and RL 3 Trains 6-7 will add planned capacity of 4.7 MTA and 15.6 MTA, respectively, when complete.

The conversion factor to translate Qatar LNG volumes (millions of metric tons - MT) into gas volumes (billions of cubic feet - BCF) is dependent on the gas quality and the quality of the LNG produced. The conversion factors are approximately 46 BCF/MT for QG I Trains 1-3, RL I Trains 1-2, RL II Trains 3 and 5, and approximately 49 BCF/MT for QG II Trains 4-5, RL II Train 4, and RL 3 Trains 6-7.

Republic of Yemen

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 9.5 thousand acres onshore at year-end. During the year, 1.1 net development wells were drilled and completed.

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2005.

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi oil concession was 0.5 million acres at year-end 2005, 0.4 million acres onshore and 0.1 million acres offshore. During the year, 6.7 net development wells were completed. The Bab Facility expansion project was completed and commissioning activities were begun for the Northeast Bab Phase I development project.

RUSSIA/CASPIAN

Azerbaijan

At year-end 2005, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 0.1 million acres. During the year, 0.7 net development wells were completed. At the Azeri-Chirag-Gunashli (ACG) development, the first phase of full-field development at Central Azeri came online in March 2005 and full-field oil production increased to 400 thousand barrels of oil per day (gross) by year-end. Commissioning of the second phase at West Azeri was in-progress at year-end, and construction is under way on the third phase at Deep Water Gunashli.

Kazakhstan

ExxonMobil’s net acreage totaled 0.3 million acres onshore and 0.2 million acres offshore at year-end 2005, with 3.2 net exploration and development wells completed during 2005. At Tengiz, construction of the 300 thousand barrels of oil per day (gross) expansion project continued through 2005. Engineering and construction of the initial phase of the Kashagan field continued during 2005.

Russia

ExxonMobil’s net acreage holdings at year-end 2005 were 85 thousand acres, all offshore. A total of 3.6 net development wells were completed in the Chayvo field during the year. Production from the

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field began in October 2005 through an early production system for domestic Russian oil and gas sales. Construction and drilling activities are progressing on Phase 1 full-field production and export systems. Phase 1 facilities include an offshore platform, onshore drill site for extended-reach drilling to offshore oil zones, an onshore processing plant, an oil pipeline from Sakhalin Island to the Russian mainland and a mainland terminal for shipment of oil by tanker.

SOUTH AMERICA

Argentina

ExxonMobil’s net acreage totaled 0.2 million onshore acres at year-end 2005, and there were 1.5 net development wells completed during the year.

Venezuela

ExxonMobil’s net year-end 2005 acreage holdings totaled 0.1 million onshore acres, with 7.1 net development wells completed during the year.

WORLDWIDE EXPLORATION

At year-end 2005, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 42.8 net million acres were held at year-end 2005, and 0.8 net exploration wells were completed during the year in these countries.

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 1.6 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 which were 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. 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

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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 separate 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 2005, this upgrading process yielded 0.853 barrels of synthetic crude oil per barrel of crude bitumen. In 2005 about 49 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 51 percent was pipelined to refineries in eastern Canada and exported, primarily to the 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 $2.8 billion at year end 2005.

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 1,890 million tons of extractable tar sands in the Base and North mines, with an average bitumen grade of 10.6 weight percent. In addition, at the Aurora mine, there are an estimated 4,485 million tons of extractable tar sands at an average bitumen grade of 11.2 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 2005 was equivalent to 738 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. The Aurora 2 mining and extraction development became fully operational in 2004. The Upgrader Expansion will be completed in 2006. When completed, this project will increase production capacity to 350 thousand barrels of synthetic crude oil per day (gross).

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ExxonMobil Share of Net Proven Syncrude Reserves(1)

Syncrude Operating Statistics (total operation)

Item 3.    Legal Proceedings.

Regarding a previously reported matter, the Corporation and the Texas Commission on Environmental Quality (“TCEQ”) have agreed to settle a Notice of Enforcement issued on August 29, 2003, alleging leak detection and repair violations and inadequate notifications of several emissions events as required by air quality regulations at ExxonMobil Oil Corporation’s (“EMOC”) Beaumont, Texas refinery. Under the terms of the settlement, EMOC has agreed to pay a civil penalty totaling $80,444, half of which will be paid through a supplemental environmental project involving county vehicle retrofits. The parties expect to execute an Agreed Order by the end of March 2006.

Regarding a previously reported matter, the Corporation signed an Administrative Consent Agreement in December 2005 setting forth the terms of settlement of an Administrative Consent Agreement and Enforcement Order regarding underground oil storage tank and air activities received from the Maine Department of Environmental Protection (“MDEP”) in March 2005. The MDEP alleged violations at 12 service stations of regulations under the state’s Stage II vapor

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recovery program and underground storage tank program, including those relating to record-keeping, monitoring, equipment, clean-up and testing. The Corporation paid a civil penalty of $269,400 for settlement of the alleged violations. The Agreement is awaiting final execution by the State of Maine.

In another previously reported matter, the Corporation and the Environmental Protection Agency (EPA) filed a Consent Agreement and Final Order with the Administrative Law Judge on January 9, 2006, reflecting the parties’ agreement to settle an Administrative Complaint captioned “In the Matter of ExxonMobil Production Company”. The EPA had alleged violations of the Clean Water Act at the Hawkins Field (in Wood County, Texas) related to 13 spills of produced water into potential waters of the United States occurring from June 2000 to August 2004. The Corporation has agreed to pay a $31,000 civil penalty and to perform a supplemental environmental project valued at $91,000 relating to enhanced detection of upset conditions at the Hawkins Field.

Refer to the relevant portions of note 14 beginning on page 68 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)].

For at least the past five years, Messrs. Cramer, Humphreys, Matthews, McGill, Simon and Sullivan have been employed as executives of the registrant. Mr. Tillerson was a Senior Vice President and then President, a title he continues to hold, before becoming Chairman of the Board. Mr. Humphreys was Vice President and Controller and then Vice President and Treasurer before becoming Senior Vice President and Treasurer. Mr. McGill was President of ExxonMobil Production Company before becoming Senior Vice President. Mr. Simon was President of ExxonMobil Refining & Supply Company before becoming Senior Vice President. Mr. Mulva was Vice President—Investor Relations and Secretary before becoming Vice President and Controller.

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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, 2005.

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 Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Reference is made to the quarterly information which appears on page 30 of the Financial Section of this report.

Note 1—On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

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Item 6.    Selected Financial Data.

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

Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 31 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 40, 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.

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Item 8.    Financial Statements and Supplementary Data.

Reference is made to the following in the Financial Section of this report:

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.

Item  9A.    Controls and Procedures.

Management’s Evaluation of Disclosure Controls and Procedures

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2005. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that material information required to be in this annual report is made known to them on a timely basis.

Management’s Report on Internal Control over Financial Reporting

Management, including the Corporation’s chief executive officer, principal financial officer and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report beginning on page 46 of the Financial Section of this report.

Changes in Internal Control over Financial Reporting

There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect the Corporation’s internal control over financial reporting.

Item  9B.    Other Information.

None.

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PART III

Item 10.    Directors and Executive Officers of the Registrant.

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2006 annual meeting of shareholders (the “2006 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 2006 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 portion entitled “Equity Compensation Plan Information” of the section entitled “Executive Compensation Tables” of the registrant’s 2006 Proxy Statement.

Item 13.    Certain Relationships and Related Transactions.

The Registrant has concluded that it has no disclosable matters under this item. Additional information regarding this determination is incorporated by reference to the portion entitled “Director and Officer Relationships” of the section entitled “Election of Directors” in the registrant’s 2006 Proxy Statement.

Item 14.    Principal Accounting Fees and Services.

Incorporated by reference to the section entitled “Ratification of Independent Auditors” of the registrant’s 2006 Proxy Statement.

PART IV

Item 15.    Exhibits, Financial Statement Schedules.

See Table of Contents on page 25 of the Financial Section of this report.

See Index to Exhibits beginning on page 89 of this report.

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FINANCIAL SECTION

TABLE OF CONTENTS

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BUSINESS PROFILE