The Quarterly
XOM 2010 10-K

Exxon Mobil Corp (XOM) SEC Annual Report (10-K) for 2010

XOM 2011 10-K
XOM 2010 10-K XOM 2011 10-K
Table of Contents Index to Financial Statements

2010

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, 2010

or

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

NEW JERSEY

(State or other jurisdiction of
incorporation or organization)

13-5409005

(I.R.S. Employer
Identification Number)

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant's telephone number, including area code)

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

Title of Each Class

Name of Each Exchange
on Which Registered

Common Stock, without par value (4,958,598,361 shares
outstanding at January 31, 2011)

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

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  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, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer   ü          Accelerated filer

Non-accelerated filer           Smaller reporting company  

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, 2010, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of $57.07 on the New York Stock Exchange composite tape, was in excess of $290 billion.

Documents Incorporated by Reference:

    Proxy Statement for the 2011 Annual Meeting of Shareholders (Part III)

Table of Contents Index to Financial Statements

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

TABLE OF CONTENTS

Page
Number
PART I
Item 1.

Business

1
Item 1A.

Risk Factors

2
Item 1B.

Unresolved Staff Comments

5
Item 2.

Properties

6
Item 3.

Legal Proceedings

31
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)] 32
PART II
Item 5.

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

36
Item 6.

Selected Financial Data

36
Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

37
Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

37
Item 8.

Financial Statements and Supplementary Data

37
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 37
Item 9A. Controls and Procedures 38
Item 9B. Other Information 38
PART III
Item 10.

Directors, Executive Officers and Corporate Governance

38
Item 11.

Executive Compensation

39
Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

39
Item 13.

Certain Relationships and Related Transactions, and Director Independence

40
Item 14.

Principal Accounting Fees and Services

40
PART IV
Item 15.

Exhibits, Financial Statement Schedules

40

Financial Section

41
Signatures 119
Index to Exhibits 121
Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges
Exhibits 31 and 32 - Certifications
Table of Contents Index to Financial Statements

PART I

Item 1.     Business.

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. 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.

On June 25, 2010, ExxonMobil acquired XTO Energy Inc. ("XTO") by merging a wholly-owned subsidiary of ExxonMobil with and into XTO (the "merger"), with XTO continuing as the surviving corporation and a wholly-owned subsidiary of ExxonMobil. Each share of XTO common stock was converted into the right to receive 0.7098 shares of common stock of ExxonMobil plus cash in lieu of fractional shares. The merger combines XTO's high-quality unconventional gas and oil shale reserve base and technical expertise in unconventional development with ExxonMobil's research and development expertise, project management and operational skill, global scale, and financial capacity. Details of the merger transactions are contained in the Financial Section of this report under the following: "Note 19: Acquisition of XTO Energy Inc."

Throughout ExxonMobil's businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to monitor and reduce nitrogen oxide, sulfur oxide, and greenhouse gas emissions and expenditures for asset retirement obligations. ExxonMobil's 2010 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil's share of equity company expenditures, were about $4.5 billion, of which $1.9 billion were capital expenditures and $2.6 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2011 and 2012 (with capital expenditures approximately 40 percent of the total).

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.

Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: "Quarterly Information", "Note 17: Disclosures about Segments and Related Information" and "Operating Summary". Information on oil and gas reserves is contained in the "Oil and Gas Reserves" part of the "Supplemental Information on Oil and Gas Exploration and Production Activities" portion of the Financial Section of this report.

ExxonMobil has a long-standing commitment to the development of proprietary technology. We have a wide array of research programs designed to meet the needs identified in each of our business

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segments. Information on Company-sponsored research and development spending is contained in "Note 3: Miscellaneous Financial Information" of the Financial Section of this report. ExxonMobil held approximately 11 thousand active patents worldwide at the end of 2010. For technology licensed to third parties, revenues totaled approximately $125 million in 2010. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.

The number of regular employees was 83.6 thousand, 80.7 thousand and 79.9 thousand at years ended 2010, 2009 and 2008, 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 20.1 thousand, 22.0 thousand and 24.8 thousand at years ended 2010, 2009 and 2008, respectively.

Information concerning the source and availability of raw materials used in the Corporation's business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to foreign operations may be found in "Item 1A–Risk Factors" and "Item 2–Properties" in this report.

ExxonMobil maintains a website at 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. Information on our website is not incorporated into this report.

Item 1A.     Risk Factors .

ExxonMobil's financial and operating results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of these risk factors are not within the Company's control and could adversely affect our business, our financial and operating results or our financial condition. These risk factors include:

Supply and Demand.

The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil's operations and earnings may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on 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.

Economic conditions.     The demand for energy and petrochemicals correlates closely with general economic growth rates. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates or periods of civil unrest, also impact the demand for energy and petrochemicals. Economic conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our financial assets and to the ability of our partners and customers to fulfill their commitments to ExxonMobil.

2

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Other demand-related factors.     Other factors that may affect the demand for oil, gas and petrochemicals, and therefore impact our results, include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy sources that have so far generally not been competitive with oil and gas without the benefit of government subsidies or mandates; and changes in technology or consumer preferences that alter fuel choices, such as toward alternative fueled vehicles.

Other supply-related factors.     Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity tend to reduce margins on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries to OPEC production quotas and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors' operations, or unexpected unavailability of distribution channels that may disrupt supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.

Other market factors.     ExxonMobil's business results are also exposed to potential negative impacts due to changes in currency exchange rates, interest rates, inflation, and other local or regional market conditions. We generally do not use financial instruments to hedge market exposures.

Government and Political Factors.

ExxonMobil's results can be adversely affected by political or regulatory developments affecting our operations.

Access limitations.     A number of countries limit access to their oil and gas resources, or may place resources off-limits from development altogether. Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national governments may have less need of outside sources of private capital. Many countries also restrict the import or export of certain products based on point of origin.

Restrictions on doing business.     As a U.S. company, ExxonMobil is subject to laws prohibiting U.S. companies from doing business in certain countries, or restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to our non-U.S. competitors unless their own home countries impose comparable restrictions.

Lack of legal certainty.     Some countries in which we do business lack well-developed legal systems, or have not yet adopted clear regulatory frameworks for oil and gas development. Lack of legal certainty exposes our operations to increased risk of adverse or unpredictable actions by government officials, and also makes it more difficult for us to enforce our contracts. In some cases these risks can be partially offset by agreements to arbitrate disputes in an international forum, but the adequacy of this remedy may still depend on the local legal system to enforce an award.

Regulatory and litigation risks.     Even in countries with well-developed legal systems where ExxonMobil does business, we remain exposed to changes in law (including changes that result from international treaties and accords) that could adversely affect our results, such as increases in taxes or government royalty rates (including retroactive claims); price controls; changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business opportunities (including changes in laws related to offshore drilling operations, water use, or hydraulic

3

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fracturing); adoption of regulations mandating the use of alternative fuels or uncompetitive fuel components; government actions to cancel contracts or renegotiate terms unilaterally; and expropriation. Legal remedies available to compensate us for expropriation or other takings may be inadequate. We also may be adversely affected by the outcome of litigation or other legal proceedings, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur.

Security concerns.     Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, and other local security concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time.

Climate change and greenhouse gas restrictions.     Due to concern over the risk of climate change, a number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shifting hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current and pending greenhouse gas regulations may also increase our compliance costs, such as for monitoring or sequestering emissions.

Government sponsorship of alternative energy.     Many governments are providing tax advantages and other subsidies and mandates to make alternative energy sources more competitive against oil and gas. Governments are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research efforts into alternative energy, such as through sponsorship of the Global Climate and Energy Project at Stanford University and research into hydrogen fuel cells and fuel-producing algae. Our future results may depend in part on the success of our research efforts and on our ability to adapt and apply the strengths of our current business model to providing the competitive energy products of the future. See "Management Effectiveness" below.

Management Effectiveness.

In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that are at least in part within our control. The extent to which we manage these factors will impact our performance relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more coventurers whom we do not control.

Exploration and development program.     Our ability to maintain and grow our oil and gas production depends on the success of our exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our project management expertise to bring discovered resources on line on schedule.

Project management.     The success of ExxonMobil's Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled

4

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project downtime; and influence the performance of project operators where ExxonMobil does not perform that role.

Operational efficiency.     An important component of ExxonMobil's competitive performance, especially given the commodity-based nature of many of our businesses, is our ability to operate efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements and regular reappraisal of our asset portfolio.

Research and development.     To maintain our competitive position, especially in light of the technological nature of our businesses and the need for continuous efficiency improvement, ExxonMobil's research and development organizations must be successful and able to adapt to a changing market and policy environment.

Safety, business controls, and environmental risk management.     Our results depend on management's ability to minimize the inherent risks of oil, gas, and petrochemical operations and to control effectively our business activities. We apply rigorous management systems and continuous focus to workplace safety and to avoiding spills or other adverse environmental events. For example, we work to minimize spills through a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. Similarly, we are implementing cost-effective new technologies and adopting new operating practices to reduce air emissions, not only in response to government requirements but also to address community priorities. We also maintain a disciplined framework of internal controls and apply a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if our management systems and controls do not function as intended. The ability to insure against such risks is limited by the capacity of the applicable insurance markets, which may not be sufficient.

Preparedness.     Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our rigorous disaster preparedness and response planning, as well as business continuity planning.

Projections, estimates and descriptions of ExxonMobil's plans and objectives included or incorporated in Items 1, 1A, 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 1B.     Unresolved Staff Comments.

None.

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Item 2.     Properties.

Information with regard to oil and gas producing activities follows:

1.     Disclosure of Reserves

A. Summary of Oil and Gas Reserves at Year-End 2010

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favorable or adverse event has occurred since December 31, 2010, that would cause a significant change in the estimated proved reserves as of that date.

Liquids (1) Bitumen Synthetic
Oil
Natural
Gas
Oil-Equivalent
Basis
(million bbls) (million bbls) (million bbls) (billion cubic ft) (million bbls)

Proved Reserves

Developed

Consolidated Subsidiaries

United States

1,478 -   -   15,344 4,035

Canada/South America (2)

133 519 681 1,077 1,512

Europe

361 -   -   3,516 947

Africa

1,055 -   -   711 1,174

Asia

1,306 -   -   6,593 2,405

Australia/Oceania

139 -   -   1,174 335

Total Consolidated

4,472 519 681 28,415 10,408

Equity Companies

United States

271 -   -   97 287

Europe

21 -   -   8,167 1,382

Asia

1,623 -   -   20,494 5,039

Total Equity Company

1,915 -   -   28,758 6,708

Total Developed

6,387 519 681 57,173 17,116

Undeveloped

Consolidated Subsidiaries

United States

474 -   -   10,650 2,249

Canada/South America (2)

30 1,583 -   181 1,643

Europe

62 -   -   526 150

Africa

744 -   -   197 777

Asia

717 -   -   667 828

Australia/Oceania

136 -   -   6,177 1,165

Total Consolidated

2,163 1,583 -   18,398 6,812

Equity Companies

United States

80 -   -   20 83

Europe

10 -   -   2,579 440

Asia

250 -   -   645 358

Total Equity Company

340 -   -   3,244 881

Total Undeveloped

2,503 1,583 -   21,642 7,693

Total Proved Reserves

8,890 2,102 681 78,815 24,809

(1) Liquids includes crude, condensate and natural gas liquids.
(2) South America includes developed proved reserves of 0.6 million barrels of liquids and 97 billion cubic feet of natural gas and undeveloped proved reserves of 0.6 million barrels of liquids and 66 billion cubic feet of natural gas.

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In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view 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 2011-2015. 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, 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 amount recovered 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.

B. Technologies Used in Establishing Proved Reserves Additions in 2010

Additions to ExxonMobil's proved reserves in 2010 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 2-D and 3-D seismic data, calibrated with available well control information. Where applicable, surface geological information was also utilized. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software and commercially available data analysis packages.

In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves

ExxonMobil has a dedicated Reserves Technical Oversight group that is separate from the operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of ExxonMobil's proved reserves. This group also maintains the official company reserves estimates for ExxonMobil's proved reserves of crude and natural gas liquids, bitumen, synthetic oil and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The group is managed by and staffed with individuals that have an average of more than 20 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under the SEC guidelines. This group includes several individuals who hold advanced degrees in either Engineering or Geology, as well as individuals who hold Bachelor's degrees in various technical disciplines. Several members of the group hold professional registrations in their field of expertise and several have served on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers.

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The Reserves Technical Oversight group maintains a central computerized database containing the official company global reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central computerized database. An annual review of the system's controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to the reserves estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized personnel within the operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and approval of the appropriate level of management within the operating organization before the changes may be made in the central database. Endorsement by the Reserves Technical Oversight group for all proved reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.

2.    Proved Undeveloped Reserves

At year-end 2010, approximately 7.7 billion oil-equivalent barrels (GOEB) of ExxonMobil's proved reserves were classified as proved undeveloped. This represents 31 percent of the 24.8 GOEB reported in proved reserves and includes approximately 1.0 GOEB of new proved undeveloped reserves related to the acquisition of XTO. This compares to the 7.5 GOEB proved undeveloped or 33 percent of the proved reserves reported at the end of 2009. The net reduction in the percentage of proved undeveloped reserves from 2009 is reflective of our active development programs on many projects worldwide which made significant progress in converting proved undeveloped reserves into proved developed reserves in 2010. During the year, ExxonMobil completed development work in over 80 fields and participated in major project start-ups that resulted in the transfer of approximately 1.4 GOEB from proved undeveloped to proved developed reserves by year-end. This represented the movement of 18 percent of the proved undeveloped reserves into the proved developed category or an average turnover time of about five years. The largest individual transfer was associated with the completion and startup of the Ras Laffan (3) Train 7 liquefied natural gas (LNG) train in Qatar.

One of ExxonMobil's requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. Development projects typically take two to four years from the time of first recording of proved reserves to the start of production of these reserves. However, the development time for large and complex projects can exceed five years. During 2010, new approved projects added approximately 0.2 GOEB of proved undeveloped reserves. The largest of these was the Sakhalin 1 Arkutun Dagi development in Russia. Overall, investments of $19.4 billion were made by the Corporation during 2010 to progress the development of reported proved undeveloped reserves, including $16.8 billion for oil and gas producing activities and an additional $2.6 billion for other non-oil and gas producing activities such as the construction of LNG trains, tankers and regasification facilities that were undertaken to progress the development of proved undeveloped reserves. These investments represented 71 percent of the $27.3 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in Kazakhstan, Netherlands, United States, Nigeria, and Canada have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure and the pace of co-venture/government funding, as well as the time required to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance and regulatory approvals.

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Approximately one third of the proved undeveloped reserves that have been reported for five or more years are in Kazakhstan and are related to two separate developments. The first is the initial development of the giant offshore Kashagan field which is included in the North Caspian Production Sharing Agreement in which ExxonMobil participates. The second is the Tengizchevroil joint venture which includes a production license in the Tengiz field and the nearby Korolev field. The joint venture is producing and proved undeveloped reserves will continue to move to proved developed as approved development phases progress.

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3.    Oil and Gas Production, Production Prices and Production Costs

A. Oil and Gas Production

The table below summarizes production by final product sold and by geographic area for the last three years.

2010 2009 2008
(thousands of barrels daily)

Crude oil and natural gas liquids production

Consolidated Subsidiaries

United States

339 311 289

Canada/South America (1)

81 82 106

Europe

330 374 423

Africa

628 685 652

Asia

326 287 319

Australia/Oceania

58 65 67

Total Consolidated Subsidiaries

1,762 1,804 1,856

Equity Companies

United States

69 73 78

Europe

5 5 5

Asia

404 320 280

Total Equity Companies

478 398 363

Total crude oil and natural gas liquids production

2,240 2,202 2,219

Bitumen production

Consolidated Subsidiaries

Canada/South America

115 120 124

Synthetic oil production

Consolidated Subsidiaries

Canada/South America

67 65 62

Total liquids production

2,422 2,387 2,405

(millions of cubic feet daily)

Natural gas production available for sale

Consolidated Subsidiaries

United States

2,595 1,274 1,245

Canada/South America (1)

569 643 640

Europe

1,859 2,071 2,253

Africa

14 19 32

Asia

1,847 1,414 1,437

Australia/Oceania

332 315 358

Total Consolidated Subsidiaries

7,216 5,736 5,965

Equity Companies

United States

1 1 1

Europe

1,977 1,618 1,696

Asia

2,954 1,918 1,433

Total Equity Companies

4,932 3,537 3,130

Total natural gas production available for sale

12,148 9,273 9,095

(thousands of oil-equivalent
barrels daily)

Oil-equivalent production

4,447 3,932 3,921
(1) South America includes liquids production for 2010, 2009 and 2008 of one thousand barrels daily for each year respectively and natural gas production available for sale for 2010, 2009 and 2008 of 52 million, 58 million, and 63 million cubic feet daily for each year respectively.

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B. Production Prices and Production Costs

The table below summarizes average production prices and average production costs by geographic area and by product type for the last three years.

During 2010 United
States
Canada/
S. America
Europe Africa Asia Australia/
Oceania
Total

Consolidated Subsidiaries

Average production prices

Crude oil and NGL, per barrel

$ 70.22 $ 69.92 $ 73.37 $ 78.08 $ 72.96 $ 68.91 $ 74.04

Natural gas, per thousand cubic feet

3.92 3.41 6.44 2.15 3.19 3.31 4.31

Bitumen, per barrel

- 56.61 - - - - 56.61

Synthetic oil, per barrel

- 78.42 - - - - 78.42

Average production costs, per oil-equivalent barrel - total

9.92 20.07 11.62 9.63 5.65 11.20 10.54

Average production costs, per barrel - bitumen

- 17.81 - - - - 17.81

Average production costs, per barrel - synthetic oil

- 42.79 - - - - 42.79

Equity Companies

Average production prices

Crude oil and NGL, per barrel

74.70 - 74.14 - 72.67 - 72.98

Natural gas, per thousand cubic feet

8.30 - 6.91 - 5.42 - 6.02

Average production costs, per oil-equivalent barrel - total

19.11 - 2.41 - 0.98 - 2.31

Total

Average production prices

Crude oil and NGL, per barrel

70.98 69.92 73.38 78.08 72.80 68.91 73.81

Natural gas, per thousand cubic feet

3.92 3.41 6.68 2.15 4.56 3.31 5.00

Bitumen, per barrel

- 56.61 - - - - 56.61

Synthetic oil, per barrel

- 78.42 - - - - 78.42

Average production costs, per oil-equivalent barrel - total

10.67 20.07 8.46 9.63 2.91 11.20 8.14

Average production costs, per barrel - bitumen

- 17.81 - - - - 17.81

Average production costs, per barrel - synthetic oil

- 42.79 - - - - 42.79

During 2009

Consolidated Subsidiaries

Average production prices

Crude oil and NGL, per barrel

$ 53.43 $ 54.07 $ 56.88 $ 60.10 $ 60.38 $ 54.84 $ 57.86

Natural gas, per thousand cubic feet

3.10 3.19 5.61 1.70 3.07 2.97 4.00

Bitumen, per barrel

- 45.22 - - - - 45.22

Synthetic oil, per barrel

- 61.26 - - - - 61.26

Average production costs, per oil-equivalent barrel - total

11.80 17.75 10.19 8.07 6.55 8.98 10.25

Average production costs, per barrel - bitumen

- 14.77 - - - - 14.77

Average production costs, per barrel - synthetic oil

- 37.47 - - - - 37.47

Equity Companies

Average production prices

Crude oil and NGL, per barrel

56.54 - 58.20 - 56.12 - 56.22

Natural gas, per thousand cubic feet

5.75 - 8.20 - 3.79 - 5.81

Average production costs, per oil-equivalent barrel - total

18.07 - 2.48 - 1.07 - 2.72

Total

Average production prices

Crude oil and NGL, per barrel

54.02 54.07 56.89 60.10 58.18 54.84 57.56

Natural gas, per thousand cubic feet

3.10 3.19 6.74 1.70 3.48 2.97 4.69

Bitumen, per barrel

- 45.22 - - - - 45.22

Synthetic oil, per barrel

- 61.26 - - - - 61.26

Average production costs, per oil-equivalent barrel - total

12.57 17.75 8.06 8.07 3.53 8.98 8.36

Average production costs, per barrel - bitumen

- 14.77 - - - - 14.77

Average production costs, per barrel - synthetic oil

- 37.47 - - - - 37.47

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During 2008 United
States
Canada/
S. America
Europe Africa Asia Australia/
Oceania
Total

Consolidated Subsidiaries

Average production prices

Crude oil and NGL, per barrel

$ 87.41 $ 89.46 $ 89.65 $ 92.69 $ 94.04 $ 86.08 $ 90.96

Natural gas, per thousand cubic feet

7.22 7.82 10.12 3.33 4.88 2.97 7.54

Bitumen, per barrel

- 65.45 - - - - 65.45

Synthetic oil, per barrel

- 100.35 - - - - 100.35

Average production costs, per oil-equivalent barrel - total

11.80 18.03 8.97 6.66 5.37 7.18 9.38

Average production costs, per barrel - bitumen

- 19.55 - - - - 19.55

Average production costs, per barrel - synthetic oil

- 41.47 - - - - 41.47

Equity Companies

Average production prices

Crude oil and NGL, per barrel

89.94 - 85.08 - 91.16 - 90.80

Natural gas, per thousand cubic feet

13.97 - 11.09 - 8.46 - 9.89

Average production costs, per oil-equivalent barrel - total

18.55 - 4.06 - 1.54 - 3.86

Total

Average production prices

Crude oil and NGL, per barrel

87.95 89.46 89.59 92.69 92.72 86.08 90.93

Natural gas, per thousand cubic feet

7.23 7.82 10.54 3.33 6.67 2.97 8.35

Bitumen, per barrel

- 65.45 - - - - 65.45

Synthetic oil, per barrel

- 100.35 - - - - 100.35

Average production costs, per oil-equivalent barrel - total

12.72 18.03 7.67 6.66 3.53 7.18 8.14

Average production costs, per barrel - bitumen

- 19.55 - - - - 19.55

Average production costs, per barrel - synthetic oil

- 41.47 - - - - 41.47

Average production 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 oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the "Oil and Gas Reserves" part of the "Supplemental Information on Oil and Gas Exploration and Production Activities" portion of the Financial Section of this report due to volumes consumed or flared. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

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4.    Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled

2010 2009 2008

Net Productive Exploratory Wells Drilled

Consolidated Subsidiaries

United States

17 10 10

Canada/South America

12 4 -

Europe

3 2 3

Africa

1 2 3

Asia

- - 2

Australia/Oceania

2 1 -

Total Consolidated Subsidiaries

35 19 18

Equity Companies

United States

- - -

Europe

2 1 1

Asia

- - -

Total Equity Companies

2 1 1

Total productive exploratory wells drilled

37 20 19

Net Dry Exploratory Wells Drilled

Consolidated Subsidiaries

United States

2 1 3

Canada/South America

1 - -

Europe

- 4 2

Africa

1 3 2

Asia

2 1 -

Australia/Oceania

1 - 1

Total Consolidated Subsidiaries

7 9 8

Equity Companies

United States

- - -

Europe

- - -

Asia

- - 1

Total Equity Companies

- - 1

Total dry exploratory wells drilled

7 9 9

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2010 2009 2008

Net Productive Development Wells Drilled

Consolidated Subsidiaries

United States

604 165 105

Canada/South America

229 291 223

Europe

11 10 8

Africa

60 45 39

Asia

7 9 16

Australia/Oceania

2 7 3

Total Consolidated Subsidiaries

913 527 394

Equity Companies

United States

282 287 321

Europe

1 1 2

Asia

4 14 14

Total Equity Companies

287 302 337

Total productive development wells drilled

1,200 829 731

Net Dry Development Wells Drilled

Consolidated Subsidiaries

United States

2 3 3

Canada/South America

- - 1

Europe

- 1 -

Africa

2 - -

Asia

- - -

Australia/Oceania

1 1 -

Total Consolidated Subsidiaries

5 5 4

Equity Companies

United States

- - -

Europe

- - -

Asia

- - -

Total Equity Companies

- - -

Total dry development wells drilled

5 5 4

Total number of net wells drilled

1,249 863 763

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Table of Contents Index to Financial Statements

B. Exploratory and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies

Syncrude Operations

Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, 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. In 2010, the company's share of net production of synthetic crude oil was about 67,000 barrels per day. The Syncrude leases cover about 63 thousand acres in the Athabasca oil sands deposit.

Kearl Project

The Kearl project is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 48 thousand acres in the Athabasca oil sands deposit.

The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada. Kearl is expected to be developed in two phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a blend of bitumen and diluent, is planned to be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline. At year-end 2010, the initial development of the Kearl project was more than 50 percent complete with expected startup in 2012.

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5.    Present Activities

A. Wells Drilling

Year-end
2010
Year-end
2009
Gross Net Gross Net

Wells Drilling

Consolidated Subsidiaries

United States

1,088 491 185 146

Canada/South America

92 30 83 57

Europe

27 8 20 4

Africa

54 19 24 8

Asia

98 66 20 4

Australia/Oceania

1 - 4 2

Total Consolidated Subsidiaries

1,360 614 336 221

Equity Companies

United States

1 1 10 5

Europe

34 10 16 5

Asia

7 1 5 -

Total Equity Companies

42 12 31 10

Total gross and net wells drilling

1,402 626 367 231

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil's year-end 2010 acreage holdings totaled 14.8 million net acres, of which 2.2 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. The acquisition of XTO Energy Inc. (XTO) was completed in 2010.

During 2010, 879.5 net exploration and development wells were completed in the inland lower 48 states, including development activities in the Barnett Shale of North Texas, the Freestone Trend of East Texas, the Haynesville Shale of Texas and Louisiana, the Fayetteville Shale of Arkansas, the Woodford Shale of Oklahoma, the Bakken oil play in North Dakota and Montana, the Marcellus Shale of Pennsylvania and West Virginia, the Eagle Ford Shale of South Texas, and the Piceance Basin of Colorado. Participation in Alaska production and development continued and a total of 22.2 net exploration and development wells were completed.

ExxonMobil's net acreage in the Gulf of Mexico at year-end 2010 was 2.1 million net acres. A total of 3.7 net exploration and development wells were completed during the year. The non-operated St. Malo project in the Gulf of Mexico was approved in 2010. Offshore California 1.0 net development well was completed.

The Golden Pass LNG regasification terminal in Texas commenced operations in 2010. The terminal will have the capacity to deliver up to two billion cubic feet of gas per day.

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CANADA / SOUTH AMERICA

Canada

Oil and Gas Operations

ExxonMobil's year-end 2010 acreage holdings totaled 6.0 million net acres, of which 2.3 million net acres were offshore. A total of 129.0 net exploration and development wells were completed during the year. The Hibernia Southern Extension project development plan was approved in 2010.

In Situ Bitumen Operations

ExxonMobil's year-end 2010 in situ bitumen acreage holdings totaled 0.5 million net onshore acres. A total of 110.0 net development wells were completed during the year.

Argentina

ExxonMobil's net acreage totaled 0.3 million onshore acres at year-end 2010, and there were 2.0 net development wells completed during the year.

Venezuela

ExxonMobil's acreage holdings and assets were expropriated in 2007. Refer to the relevant portion of "Note 15: Litigation and Other Contingencies" of the Financial Section of this report for additional information.

EUROPE

Germany

A total of 4.8 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2010, with 7.3 net exploration and development wells completed during the year.

Netherlands

ExxonMobil's net interest in licenses totaled approximately 1.6 million acres at year-end 2010, of which 1.2 million acres are onshore. A total of 3.0 net exploration and development wells were completed during the year. The non-operated project to redevelop the Schoonebeek oil field was progressed.

Norway

ExxonMobil's net interest in licenses at year-end 2010 totaled approximately 0.6 million acres, all offshore. ExxonMobil participated in 3.5 net exploration and development well completions in 2010.

United Kingdom

ExxonMobil's net interest in licenses at year-end 2010 totaled approximately 0.4 million acres, all offshore. A total of 2.9 net development wells were completed during the year. The South Hook liquefied natural gas (LNG) terminal reached full capacity of two billion cubic feet per day in 2010.

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Table of Contents Index to Financial Statements

AFRICA

Angola

ExxonMobil's year-end 2010 acreage holdings totaled 0.6 million net offshore acres, and 2.2 net exploration and development wells were completed during the year. The Angola Gas Gathering Project started up on-block gas handling in 2010, and project work continued on Kizomba Satellites Phase 1. On the non-operated Block 17, the Cravo-Lirio-Orquidea-Violeta project was funded in 2010, while project execution continued at Pazflor. On the non-operated Block 31, project work continued on the Plutao-Saturno-Venus-Marte project.

Chad

ExxonMobil's net year-end 2010 acreage holdings consisted of 63 thousand onshore acres with 46.0 net exploration and development wells completed during the year.

Equatorial Guinea

ExxonMobil's acreage totaled 0.1 million net offshore acres at year-end 2010, with 5.3 net development wells completed during the year.

Nigeria

ExxonMobil's net acreage totaled 1.0 million offshore acres at year-end 2010, with 9.4 net exploration and development wells completed during the year. Work continued on the deepwater Usan project in 2010. A 3-D seismic acquisition program was completed on the Nigerian Shelf joint venture acreage.

ASIA

Azerbaijan

At year-end 2010, ExxonMobil's net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 60 thousand acres. At the Azeri-Chirag-Gunashli field, 0.6 net development wells were completed. The Chirag Oil Project was funded in 2010, and project activities are under way.

Indonesia

At year-end 2010, ExxonMobil had 4.4 million net acres, 3.3 million net acres offshore and 1.1 million net acres onshore. A total of 0.8 net exploration wells were completed during the year.

Iraq

At year-end 2010, ExxonMobil's onshore acreage was 87 thousand net acres. During 2010, a contract was signed with South Oil Company of the Iraqi Ministry of Oil to redevelop and expand the West Qurna (Phase 1) oil field. The term of the contract is 20 years with the right to extend for five years. In 2010 initial field rehabilitation activities commenced. Field rehabilitation activities across the life of this project will include drilling of new wells, working over of existing wells, optimization and debottlenecking of existing facilities, and the establishment of field offices and camps.

Kazakhstan

ExxonMobil's net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2010, with 0.2 net development wells completed during 2010. Working with our partners, construction of the initial phase of the Kashagan field continued during 2010.

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Table of Contents Index to Financial Statements

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2010. During the year, a total of 5.1 net exploration and development wells were completed.

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil's net acreage totaled 60 thousand acres offshore at year-end 2010. Following the startup of RasGas Train 7 during 2010, ExxonMobil participated in 61.8 million tonnes per year gross liquefied natural gas (LNG) capacity at year end.

Republic of Yemen

ExxonMobil's net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2010.

Russia

ExxonMobil's net acreage holdings at year-end 2010 were 85 thousand acres, all offshore. A total of 1.5 net development wells were completed at the Sakhalin-1 Odoptu field during the year which started production in 2010. The Sakhalin-1 Chayvo Expansion and Arkutun-Dagi projects were both funded in 2010, and project activities are under way.

Thailand

ExxonMobil's net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2010.

United Arab Emirates

ExxonMobil's net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year end 2010. During the year, 0.6 net development wells were completed, as rig activity focused mainly on workovers and injection wells.

ExxonMobil's net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2010, of which 0.4 million acres are onshore. During the year, a total of 4.3 net development wells were completed.

AUSTRALIA/OCEANIA

Australia

ExxonMobil's net year-end 2010 offshore acreage holdings totaled 1.7 million acres. During 2010, a total of 5.3 net exploration and development wells were drilled. Offshore installation commenced for the Kipper Tuna Turrum project.

Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2010. The project consists of a subsea infrastructure for offshore production and transportation of the gas, and a 15 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.

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Papua New Guinea

A total of 0.4 million net onshore acres were held by ExxonMobil at year-end 2010, with 0.4 net development wells completed during the year. In 2010, the Papua New Guinea liquefied natural gas project commenced construction activities. The project consists of conditioning facilities in the southern PNG Highlands, a 6.6 million tonnes per year LNG facility near Port Moresby and approximately 450 miles of onshore and offshore pipelines.

WORLDWIDE EXPLORATION

At year-end 2010, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 40.6 million net acres were held at year-end 2010, and 2.6 net exploration wells were completed during the year in these countries.

6.     Delivery Commitments

ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 17 million barrels of crude oil and 3,900 billion cubic feet of natural gas for the period from 2011 through 2013. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and spot market purchases as necessary.

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7.    Oil and Gas Properties, Wells, Operations and Acreage

A. Gross and Net Productive Wells

Year-end 2010 Year-end 2009
Oil Gas Oil Gas
Gross Net Gross Net Gross Net Gross Net

Gross and Net Productive Wells

Consolidated Subsidiaries

United States

23,789 8,076 36,189 21,429 15,606 4,821 9,261 5,645

Canada/South America

5,609 5,092 6,650 3,361 5,357 4,828 6,728 3,408

Europe

1,438 395 672 291 1,395 389 649 292

Africa

1,126 454 14 6 1,081 432 13 5

Asia

845 411 207 173 751 352 197 162

Australia/Oceania

687 163 27 13 722 170 41 21

Total Consolidated Subsidiaries

33,494 14,591 43,759 25,273 24,912 10,992 16,889 9,533

Equity Companies

United States

11,270 5,295 7 3 11,592 5,452 8 4

Europe

28 14 594 194 27 14 576 187

Asia

883 99 121 30 873 98 126 36

Total Equity Companies

12,181 5,408 722 227 12,492 5,564 710 227

Total gross and net productive wells

45,675 19,999 44,481 25,500 37,404 16,556 17,599 9,760

There were 35,691 gross and 30,494 net operated wells at year-end 2010 and 16,587 gross and 13,737 net operated wells at year-end 2009. The number of wells with multiple completions was 1,725 gross in 2010 and 1,039 gross in 2009.

B. Gross and Net Developed Acreage

Year-end 2010 Year-end 2009
Gross Net Gross Net
(thousands of acres)

Gross and Net Developed Acreage

Consolidated Subsidiaries

United States

16,621 9,861 9,866 5,061

Canada/South America (1)

5,450 2,439 5,570 2,460

Europe

3,956 1,630 5,359 2,454

Africa

1,772 684 1,958 758

Asia

1,411 623 1,226 512

Australia/Oceania

1,955 719 1,956 719

Total Consolidated Subsidiaries

31,165 15,956 25,935 11,964

Equity Companies

United States

137 58 165 59

Europe

4,363 1,356 4,325 1,352

Asia

5,818 648 5,817 648

Total Equity Companies

10,318 2,062 10,307 2,059

Total gross and net developed acreage

41,483 18,018 36,242 14,023
(1) Includes gross and net developed acreage in South America of 618 gross and 202 net thousands of acres for 2010 and 618 gross and 202 net thousands of acres for 2009.

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

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C. Gross and Net Undeveloped Acreage

Year-end 2010 Year-end 2009
Gross Net Gross Net
(thousands of acres)

Gross and Net Undeveloped Acreage

Consolidated Subsidiaries

United States

8,393 4,845 7,650 5,034

Canada/South America (1)

20,612 11,977 26,074 17,107

Europe

34,787 16,118 25,420 13,462

Africa

14,733 8,612 15,768 10,555

Asia

24,203 19,086 25,568 20,400

Australia/Oceania

4,966 1,352 9,780 5,216

Total Consolidated Subsidiaries

107,694 61,990 110,260 71,774

Equity Companies

United States

188 69 208 77

Europe

- - 53 8

Asia

- - 228 57

Total Equity Companies

188 69 489 142

Total gross and net undeveloped acreage

107,882 62,059 110,749 71,916

(1) Includes gross and net undeveloped acreage in South America of 10,111 gross and 7,442 net thousands of acres for 2010 and 12,005 gross and 11,800 net thousands of acres for 2009.

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. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Corporation.

D. Summary of Acreage Terms

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. Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances, a "fee interest" is acquired where both the surface and the underlying mineral interests are owned outright.

CANADA / SOUTH AMERICA

Canada

Exploration permits are granted for varying periods of time with renewals possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to obtain leases upon

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Table of Contents Index to Financial Statements

completing specified work. In general, production leases are held as long as there is production on the lease. The majority of Cold Lake leases are held in this manner. The exploration acreage in eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.

Argentina

The federal 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. Argentine provinces are entitled to modify the concession terms granted within their territories. The exploration permit granted by Neuquen Province to an ExxonMobil affiliate in 2010 fixed the initial exploration period at three years, the second at two years and the third at one year, and one of these periods can be extended for an additional year.

EUROPE

Germany

Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three years each. 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. In 2007, ExxonMobil affiliates acquired four exploration licenses in the state of Lower Saxony. The exploration licenses are for a period of five years during which exploration work programs will be carried out. In 2009, ExxonMobil affiliates acquired two exploration licenses in the state of North Rhine Westphalia for an initial period of five years and an extension to one of the Lower Saxony licenses.

Netherlands

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

Production rights granted prior to January 1, 2003, remain subject to their existing terms, and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.

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 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

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Table of Contents Index to Financial Statements

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. At the end of any such 40-year term, licenses may continue in producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a case-by-case basis until they become producing areas; or licenses terminate in all other areas. The licensing regime was last updated in 2002, and the majority of licenses issued have an initial term of four years with a second term extension of four years and a final term of 18 years with a mandatory relinquishment of 50 percent of the 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.

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, Industry 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. A new Hydrocarbons Law was enacted in November 2006. Under the new law, the exploration terms for new production sharing contracts are four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.

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. 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.

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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 have been renewed, effective December 1, 2008, for a further period of 20 years, with a further renewal option of 20 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. In 2000, a Memorandum of Understanding (MOU) was executed defining commercial terms applicable to existing joint venture oil production. The MOU may be terminated on one calendar year's notice.

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.

ASIA

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.

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.

Iraq

Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraq Ministry of Oil. An ExxonMobil affiliate entered into a contract with South Oil Company of the Ministry of Iraq for the rights to participate in the development and production activities of the West Qurna (Phase I) oil and gas field effective March 1, 2010. The term of the contract is 20 years with the right to extend for 5 years.

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 followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.

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Malaysia

Exploration and production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The more recent PSCs governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, 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.

In 2008, the Company reached agreement with the national oil company for a new PSC, which was subsequently signed in 2009. Under the new PSC, from 2008 until March 31, 2012, the Company is entitled to undertake new development and production activities in oil fields under an existing PSC, subject to new minimum work and spending commitments, including an enhanced oil recovery project in one of the oil fields. When the existing PSC expires on March 31, 2012, the producing fields covered by the existing PSC will automatically become part of the new PSC, which has a 25-year duration from April 2008.

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

The Jannah production sharing agreement has a development period extending 20 years from first commercial declaration, which was made in June 1995.

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.

Thailand

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

United Arab Emirates

Exploration and production activities for the major onshore oil fields 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. An interest in the Upper Zakum field, a major offshore field, was acquired effective as of January 2006, for a term expiring March 2026.

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AUSTRALIA/OCEANIA

Australia

Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. 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 July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter "indefinitely", i.e., for the life of the field. Effective from July 1998, new production licenses are granted "indefinitely". In each case, a production license may be terminated if no production operations have been carried on for five years.

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 within the maximum possible retention time of 15 years. Petroleum Retention licenses are granted for five-year terms, and may be extended, at the Minister's discretion, twice for the maximum retention time of 15 years. Extensions of Petroleum Retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources could become commercially viable in less than five years.

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Information with regard to the Downstream segment follows :

ExxonMobil's Downstream segment manufactures and sells petroleum products. The refining and supply operations encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants and other products and feedstocks to our customers around the world.

Refining Capacity At Year-End 2010 (1)

ExxonMobil
Share KBD  (2)
ExxonMobil
Interest  %

United States

Torrance

California

150 100

Joliet

Illinois

238 100

Baton Rouge

Louisiana

504 100

Baytown

Texas

561 100

Beaumont

Texas

345 100

Other (2 refineries)

155

Total United States

1,953

Canada

Strathcona

Alberta

189 69.6

Dartmouth

Nova Scotia

83 69.6

Nanticoke

Ontario

113 69.6

Sarnia

Ontario

121 69.6

Total Canada

506

Europe

Antwerp

Belgium

307 100

Fos-sur-Mer

France

119 82.9

Port-Jerome-Gravenchon

France

233 82.9

Karlsruhe

Germany

78 25

Augusta

Italy

198 100

Trecate

Italy

174 74.1

Rotterdam

Netherlands

191 100

Slagen

Norway

116 100

Fawley

United Kingdom

329 100

Total Europe

1,745

Asia Pacific

Kawasaki

Japan

296 50.1

Sakai

Japan

139 50.1

Wakayama

Japan

160 50.1

Jurong/PAC

Singapore

605 100

Sriracha

Thailand

174 66

Other (5 refineries)

337

Total Asia Pacific

1,711

Other Non-U.S.

Yanbu

Saudi Arabia

200 50

Laffan

Qatar

14 10

Other (4 refineries)

131

Total Other Non-U.S.

345

Total Worldwide

6,260

(1) Capacity data is based on 100 percent of rated refinery process unit stream-day capacities under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time.
(2) Thousands of barrels per day (KBD). ExxonMobil share reflects 100 percent of atmospheric distillation capacity in operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, ExxonMobil share is the greater of ExxonMobil's equity interest or that portion of distillation capacity normally available to ExxonMobil.

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The marketing operations sell products and services throughout the world. Our Exxon, Esso and Mobil brands serve customers at over 26,000 retail service stations.

Retail Sites Year-End 2010

United States

Owned/leased

1,243

Distributors/resellers

8,520

Total United States

9,763

Canada

Owned/leased

500

Distributors/resellers

1,349

Total Canada

1,849

Europe

Owned/leased

3,965

Distributors/resellers

2,584

Total Europe

6,549

Asia Pacific

Owned/leased

1,963

Distributors/resellers

3,631

Total Asia Pacific

5,594

Latin America

Owned/leased

567

Distributors/resellers

1,329

Total Latin America

1,896

Middle East/Africa

Owned/leased

472

Distributors/resellers

155

Total Middle East/Africa

627

Worldwide

Owned/leased

8,710

Distributors/resellers

17,568

Total worldwide

26,278

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Information with regard to the Chemical segment follows :

ExxonMobil's Chemical segment manufactures and sells petrochemicals. The Chemical business supplies olefins, polyolefins, aromatics, and a wide variety of other petrochemicals.

Chemical Complex Capacity at Year-End 2010 (1) (2)

Ethylene Polyethylene Polypropylene Paraxylene ExxonMobil
Interest %

North America

Baton Rouge

Louisiana

1.0 1.3 0.4 - 100

Baytown

Texas

2.2 - 0.8 0.6 100

Beaumont

Texas

0.8 1.0 - 0.3 100

Mont Belvieu

Texas

- 1.0 - - 100

Sarnia

Ontario

0.3 0.5 - - 69.6

Total North America

4.3 3.8 1.2 0.9

Europe

Antwerp

Belgium

0.5 0.4 - - 35 (3)

Fife

United Kingdom

0.4 - - - 50

Meerhout

Belgium

- 0.5 - - 100

Notre-Dame-de-
Gravenchon

France

0.4 0.4 0.3 - 100

Rotterdam

Netherlands

- - - 0.7 100

Total Europe

1.3 1.3 0.3 0.7

Middle East

Al Jubail

Saudi Arabia

0.6 0.6 - - 50

Yanbu

Saudi Arabia

1.0 0.7 0.2 - 50

Total Middle East

1.6 1.3 0.2 -

Asia Pacific

Fujian

China

0.2 0.2 0.1 0.2 25

Kawasaki

Japan

0.5 0.1 - - 50

Singapore

Singapore

0.9 0.6 0.4 0.9 100

Sriracha

Thailand

- - - 0.5 66

Total Asia Pacific

1.6 0.9 0.5 1.6

All Other

- - - 0.6

Total Worldwide

8.8 7.3 2.2 3.8

(1) Capacity for ethylene, polyethylene, polypropylene and paraxylene in millions of metric tons per year.
(2) Capacity reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, capacity is ExxonMobil's interest.
(3) Net ExxonMobil ethylene capacity is 35%. Net ExxonMobil polyethylene capacity is 100%.

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Item 3.     Legal Proceedings.

Regarding a matter previously reported in the Corporation's Form 10-Q for the second quarter of 2010, ExxonMobil Oil Corporation's Beaumont, Texas refinery entered into an Agreed Order with the Texas Commission on Environmental Quality on November 15, 2010 and paid a civil penalty of $106 thousand to resolve Notices of Violation issued in January and February 2010 relating to six alleged violations of air emission regulations.

With regard to the matter most recently reported in the Corporation's Form 10-Q for the second quarter of 2007, the New York State Attorney General, Exxon Mobil Corporation and ExxonMobil Oil Corporation have agreed to enter into a Consent Decree to resolve issues relating to alleged contamination at ExxonMobil's former Brooklyn, New York terminal and refinery. The Consent Decree was lodged in the U.S. District Court for the Eastern District of New York on November 17, 2010 and was subject to public comment until January 25, 2011. On January 24, 2011, the United States Department of Justice filed the only comments, which sought clarification of some elements of the Consent Decree. Those comments have been incorporated into the Consent Decree, which is subject to review and approval by the Court. If approved, the Consent Decree would require ExxonMobil to undertake actions to investigate and remediate certain environmental conditions at the Brooklyn terminal and refinery, pay $19.5 million to fund Environmental Benefit Projects to benefit the Greenpoint Community; pay a civil penalty of $250 thousand; pay $250 thousand for Natural Resources Damages Restoration Projects; pay past costs of the State for oversight of, investigation and remedial activities in the amount of $1.5 million and pay future State oversight costs, up to $3.5 million.

On November 29, 2010, XTO Energy Inc. received a Notice of Violation (NOV) from the Pennsylvania Department of Environmental Protection (PaDEP) alleging that an unpermitted discharge of brine or produced fluid occurred from a tank located at the Marquardt Well Site in Penn Township, Pennsylvania, which discharge reached a water of the State and that XTO failed to notify the PaDEP of the incident, had litter on the site, and failed to post well permit numbers and operator information at the well site. The NOV does not contain a specific penalty demand, but XTO believes that PaDEP may seek a penalty in excess of $100 thousand. XTO responded to the NOV on December 9, 2010 and, while not admitting to a violation for the alleged release, agreed to cooperate with PaDEP in responding to and remediating it.

As reported in the Corporation's 2009 Form 10-K, in October 2009, a purported shareholder complaint captioned Resnik v. Boskin et al. , alleging direct and derivative claims, was filed in the United States District Court for the District of New Jersey, naming the directors serving at the time, the "named executive officers" listed in the Corporation's 2009 Proxy Statement (as defined in Securities and Exchange Commission regulations) and ExxonMobil as defendants. The complaint was amended in December 2009, alleging that the defendants made materially false or misleading proxy solicitations in connection with the 2008 and 2009 shareholder votes regarding the election of directors and failed to seek stockholder reapproval of the Exxon Mobil Corporation 2003 Incentive Program to qualify certain incentive compensation paid to the named executive officers as properly deductible expenditures. The amended complaint seeks various injunctive remedies, including corrective disclosure, new election of directors after corrective disclosure, enjoining candidates from serving on the Board until a new election occurs, stockholder reapproval of the program, enjoining payments under the program and short term incentive program to the named executive officers, damages (the amount of which is not specified) from the individual defendants in favor of ExxonMobil, and costs and expenses of the action. The defendants moved to dismiss the lawsuit on several grounds, including that the plaintiff's allegations concerning the Corporation's proxy solicitations do not state claims under the federal securities laws and that the plaintiff's derivative claims cannot stand since the plaintiff failed to make a demand on the Corporation or allege facts that would excuse a demand. The motion was argued to the district court in August 2010. On February 17, 2011, the court granted defendants' motion to dismiss, finding fatal flaws in the plaintiff's three causes of action. Notably, the court determined that

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the Internal Revenue Code and Treasury Regulations did not require the Corporation to seek stockholder reapproval of its incentive programs at the time it distributed the 2008 and 2009 proxy statements. Notwithstanding the plaintiff's dismissal, the court granted the plaintiff 21 days to amend the three causes of action. If the plaintiff does not timely amend, plaintiff will have 30 days thereafter to file a notice of appeal.

Refer to the relevant portions of "Note 15: Litigation and Other Contingencies" of the Financial Section of this report for additional information on legal proceedings.

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

(ages as of March 1, 2011).

Rex W. Tillerson

Chairman of the Board

Held current title since:

January 1, 2006 Age: 58

Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004. He became Chairman of the Board and Chief Executive Officer on January 1, 2006. He still holds these positions as of this filing date.

Mark W. Albers

Senior Vice President

Held current title since:

April 1, 2007 Age: 54

Mr. Mark W. Albers was President of ExxonMobil Development Company October 1, 2004 – April 13, 2007. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2007, a position he still holds as of this filing date.

Michael J. Dolan

Senior Vice President

Held current title since:

April 1, 2008 Age: 57

Mr. Michael J. Dolan was President of ExxonMobil Chemical Company September 1, 2004 – March 31, 2008. He was Vice President of Exxon Mobil Corporation September 1, 2004 – March 31, 2008. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2008, a position he still holds as of this filing date.

Donald D. Humphreys

Senior Vice President and Treasurer

Held current title since:

January 25, 2006 (Senior Vice President)

July 1, 2004 (Treasurer)

Age: 63

Mr. Donald D. Humphreys was Vice President and Controller of Exxon Mobil Corporation (formerly Exxon Corporation) July 1, 1997 – June 30, 2004. He was the Vice President and Treasurer of Exxon Mobil Corporation July 1, 2004 – January 24, 2006. He became Senior Vice President and Treasurer of Exxon Mobil Corporation on January 25, 2006, positions he still holds as of this filing date.

Andrew P. Swiger

Senior Vice President

Held current title since:

April 1, 2009 Age: 54

Mr. Andrew P. Swiger was Executive Vice President of ExxonMobil Production Company May 1, 2004 – September 30, 2006. He was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation October 1, 2006 – March 31, 2009. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds as of this filing date.

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S. Jack Balagia

Vice President and General Counsel

Held current title since:

March 1, 2010 Age: 59

Mr. S. Jack Balagia was Assistant General Counsel of Exxon Mobil Corporation April 1, 2004 to March 1, 2010. He became Vice President and General Counsel of Exxon Mobil Corporation on March 1, 2010, a position he still holds as of this filing date.

William M. Colton

Vice President - Strategic Planning

Held current title since:

February 1, 2009 Age: 57

Mr. William M. Colton was Assistant Treasurer of Exxon Mobil Corporation January 25, 2006 to January 31, 2009. He became Vice President-Strategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.

Harold R. Cramer

Vice President

Held current title since:

November 30, 1999 Age: 60

Mr. Harold R. Cramer became President of ExxonMobil Fuels Marketing Company and Vice President of Exxon Mobil Corporation on November 30, 1999, positions he still holds as of this filing date.

Neil W. Duffin

President, ExxonMobil Development Company

Held current title since:

April 13, 2007 Age: 54

Mr. Neil W. Duffin was Vice President of ExxonMobil Production Company July 1, 2004 – August 31, 2006. He was Executive Vice President of ExxonMobil Development Company September 1, 2006 – April 13, 2007, becoming President on April 13, 2007, a position he still holds as of this filing date.

Robert S. Franklin

Vice President

Held current title since:

May 1, 2009 Age: 53

Mr. Robert S. Franklin was Vice President, New Business Development of ExxonMobil Gas & Power Marketing Company July 1, 2001 – April 15, 2007. He was Executive Assistant to the Chairman, Exxon Mobil Corporation April 16, 2007 – March 31, 2008. He was Vice President, Europe/Russia/Caspian of ExxonMobil Production Company April 1, 2008 – May 1, 2009. He became Vice President of Exxon Mobil Corporation and President, ExxonMobil Upstream Ventures on May 1, 2009, positions he still holds as of this filing date.

Sherman J. Glass, Jr.

Vice President

Held current title since:

April 1, 2008 Age: 63

Mr. Sherman J. Glass, Jr. was Senior Vice President of ExxonMobil Chemical Company September 1, 2005 – March 31, 2008. He became President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on April 1, 2008. He still holds these positions as of this filing date.

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Stephen M. Greenlee

Vice President

Held current title since:

September 1, 2010 Age: 53

Mr. Stephen M. Greenlee was Vice President of ExxonMobil Exploration Company June 1, 2004 – June 1, 2009. He was President of ExxonMobil Upstream Research Company June 1, 2009 – August 31, 2010. He became President of ExxonMobil Exploration Company and Vice President of Exxon Mobil Corporation on September 1, 2010, positions he still holds as of this filing date.

Alan J. Kelly

Vice President

Held current title since:

December 1, 2007 Age: 53

Mr. Alan J. Kelly was Manager, Global Logistics of ExxonMobil Refining & Supply Company February 1, 2005 – February 28, 2006. He was on Special Assignment for the National Petroleum Council March 1, 2006 – November 30, 2007. He became President of ExxonMobil Lubricants & Petroleum Specialties Company and Vice President of Exxon Mobil Corporation on December 1, 2007. He still holds these positions as of this filing date.

Richard M. Kruger

Vice President

Held current title since:

April 1, 2008 Age: 51

Mr. Richard M. Kruger was Vice President of ExxonMobil Production Company January 1, 2003 – September 30, 2006, and then Executive Vice President October 1, 2006 – March 31, 2008. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on April 1, 2008. He still holds these positions as of this filing date.

Patrick T. Mulva

Vice President and Controller

Held current title since:

February 1, 2002 (Vice President)

July 1, 2004 (Controller)

Age: 59

Mr. Patrick T. Mulva was Vice President-Investor Relations and Secretary of Exxon Mobil Corporation February 1, 2002 – July 1, 2004. On July 1, 2004, he became Vice President and Controller, positions he still holds as of this filing date.

Stephen D. Pryor

Vice President

Held current title since:

December 1, 2004 Age: 61

Mr. Stephen D. Pryor was President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation December 1, 2004 – March 31, 2008. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.

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David S. Rosenthal

Vice President - Investor Relations and Secretary

Held current title since:

October 1, 2008 Age: 54

Mr. David S. Rosenthal was Controller of ExxonMobil Production Company April 1, 2002 – May 31, 2006. He was Assistant Controller of Exxon Mobil Corporation on June 1, 2006 – September 30, 2008. He became Vice President-Investor Relations and Secretary of Exxon Mobil Corporation on October 1, 2008, positions he still holds as of this filing date.

James M. Spellings, Jr.

Vice President and General Tax Counsel

Held current title since:

March 1, 2010 Age: 49

Mr. James M. Spellings, Jr. was General Manager-Corporate Planning of Exxon Mobil Corporation February 1, 2005 – March 31, 2007, and then Associate General Tax Counsel April 1, 2007 – March 1, 2010. He became Vice President and General Tax Counsel on March 1, 2010, positions he still holds as of this filing date.

Thomas R. Walters

Vice President

Held current title since:

April 1, 2009 Age: 56

Mr. Thomas R. Walters was President of Global Services Company from September 1, 2005 – April 4, 2007. He was Executive Vice President of ExxonMobil Development Company April 13, 2007 – April 1, 2009. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on April 1, 2009, positions he still holds as of this filing date.

Jack P. Williams, Jr.

President, XTO Energy Inc.

Held current title since:

June 25, 2010 Age: 47

Mr. Jack P. Williams, Jr. was Upstream Advisor, Exxon Mobil Corporation July 1, 2005 – May 1, 2007. He was Vice President, Engineering, ExxonMobil Production Company May 1, 2007 – April 30, 2009. He was Vice President of ExxonMobil Development Company May 1, 2009 – July 1, 2010. He became President of XTO Energy Inc. on June 25, 2010, a position he still holds as of this filing date.

Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Reference is made to the "Quarterly Information" portion of the Financial Section of this report.

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2010

Period

Total Number of
Shares
Purchased
Average Price
Paid per
Share
Total Number of
Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs
Maximum Number
of Shares that
May Yet Be
Purchased Under
the Plans or
Programs

October, 2010

27,460,538 65.07 27,460,538

November, 2010

26,123,594 69.57 26,123,594

December, 2010

29,589,368 72.82 29,589,368

Total

83,173,500 69.24 83,173,500 (See note 1

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. Repurchases were temporarily suspended due to regulatory requirements in connection with the XTO transaction. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated January 31, 2011, the Corporation stated that first quarter 2011 share purchases are continuing at a pace consistent with fourth quarter 2010 share reduction spending of $5 billion. 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.

Item 6.     Selected Financial Data.

Years Ended December 31,
    2010   (1) 2009 2008 2007 2006
(millions of dollars, except per share amounts)
Sales and other operating revenue (2) $ 370,125 $ 301,500 $ 459,579 $ 390,328 $ 365,467

(2) Sales-based taxes included.

$ 28,547 $ 25,936 $ 34,508 $ 31,728 $ 30,381
Net income attributable to ExxonMobil $ 30,460 $ 19,280 $ 45,220 $ 40,610 $ 39,500
Earnings per common share $ 6.24 $ 3.99 $ 8.70 $ 7.31 $ 6.64
Earnings per common share - assuming dilution $ 6.22 $ 3.98 $ 8.66 $ 7.26 $ 6.60
Cash dividends per common share $ 1.74 $ 1.66 $ 1.55 $ 1.37 $ 1.28
Total assets $ 302,510 $ 233,323 $ 228,052 $ 242,082 $ 219,015
Long-term debt $ 12,227 $ 7,129 $ 7,025 $ 7,183 $ 6,645

(1) See Note 19: Acquisition of XTO Energy Inc. contained in the Financial Section of this report.

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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" in 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", excluding the part entitled "Inflation and Other Uncertainties," in 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 following in the Financial Section of this report:

Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 25, 2011, beginning with the section entitled "Report of Independent Registered Public Accounting Firm" and continuing through "Note 19: Acquisition of XTO Energy Inc.";

"Quarterly Information" (unaudited);

"Supplemental Information on Oil and Gas Exploration and Production Activities" (unaudited); and

"Frequently Used Terms" (unaudited).

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.

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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, 2010. Based on that evaluation, these officers have concluded that the Corporation's disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

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 criteria established in 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, 2010.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation's internal control over financial reporting as of December 31, 2010, as stated in their report included in 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 .

Effective April 1, 2011, the annual salary for Michael J. Dolan will increase to $1,010,000. Like all other ExxonMobil executive officers, Mr. Dolan is an "at will" employee of the Corporation and does not have an employment contract.

PART III

Item 10.     Directors, Executive Officers and Corporate Governance.

Incorporated by reference to the following from the registrant's definitive proxy statement for the 2011 annual meeting of shareholders (the "2011 Proxy Statement"):

The section entitled "Election of Directors";

The portion entitled "Section 16(a) Beneficial Ownership Reporting Compliance" of the section entitled "Director and Executive Officer Stock Ownership";

The portions entitled "Director Qualifications" and "Code of Ethics and Business Conduct" of the section entitled "Corporate Governance"; and

The "Audit Committee" portion and the membership table of the portion entitled "Board Meetings and Committees; Annual Meeting Attendance" of the section entitled "Corporate Governance".

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Item 11.     Executive Compensation.

Incorporated by reference to the sections entitled "Director Compensation," "Compensation Committee Report," "Compensation Discussion and Analysis" and "Executive Compensation Tables" of the registrant's 2011 Proxy Statement.

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

The information required under Item 403 of Regulation S-K is incorporated by reference to the sections "Director and Executive Officer Stock Ownership" and "Certain Beneficial Owners" of the registrant's 2011 Proxy Statement.

Equity Compensation Plan Information

(a) (b) (c)

Plan Category

Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
Weighted-
Average
Exercise Price of
Outstanding
Options,
Warrants and
Rights (1)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation
Plans [Excluding
Securities Reflected in
Column (a)]

Equity compensation plans approved by security holders

29,111,877 (2)(3) $ 37.12 142,681,756 (3)(4)(5)

Equity compensation plans not approved by security holders

0 0 0

Total

29,111,877 $ 37.12 142,681,756

(1) The exercise price of each option reflected in this table is equal to the fair market value of the Company's common stock on the date the option was granted. The weighted-average price reflects one prior option grant that is still outstanding.

(2) Includes 19,578,656 options granted under the 1993 Incentive Program and 9,533,221 restricted stock units to be settled in shares.

(3) Does not include options that ExxonMobil assumed in the 2010 merger with XTO Energy Inc. At year-end 2010, the number of securities to be issued upon exercise of outstanding options under XTO Energy Inc. plans was 9,929,860, and the weighted-average exercise price of such options was $59.51. No additional awards may be made under those plans.

(4) Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 141,939,056 shares available for award under the 2003 Incentive Program and 742,700 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

(5) Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 2,500 restricted shares each following year. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board early.

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Item 13.     Certain Relationships and Related Transactions, and Director Independence.

Information provided in response to this Item 13 is incorporated by reference to the portions entitled "Related Person Transactions and Procedures" and "Director Independence" of the section entitled "Corporate Governance" of the registrant's 2011 Proxy Statement.

Item 14.     Principal Accounting Fees and Services .

Incorporated by reference to the portion entitled "Audit Committee" of the section entitled "Corporate Governance" and the section entitled "Ratification of Independent Auditors" of the registrant's 2011 Proxy Statement.

PART IV

Item 15.     Exhibits, Financial Statement Schedules.

(a) (1) and (2) Financial Statements:

See Table of Contents of the Financial Section of this report.

(a) (3) Exhibits:

See Index to Exhibits of this report.

40

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FINANCIAL SECTION

TABLE OF CONTENTS

Business Profile

42

Financial Summary

43

Frequently Used Terms

44

Quarterly Information

46

Management's Discussion and Analysis of Financial Condition and Results of Operations

Functional Earnings

47

Forward-Looking Statements

48

Overview

48

Business Environment and Risk Assessment

48

Review of 2010 and 2009 Results

51

Liquidity and Capital Resources

52

Capital and Exploration Expenditures

56

Taxes

56

Environmental Matters

56

Market Risks, Inflation and Other Uncertainties

57

Critical Accounting Policies

58

Management's Report on Internal Control Over Financial Reporting

62

Report of Independent Registered Public Accounting Firm

62

Consolidated Financial Statements

Statement of Income

64

Balance Sheet

65

Statement of Cash Flows

66

Statement of Changes in Equity

67

Statement of Comprehensive Income

68

Notes to Consolidated Financial Statements

1. Summary of Accounting Policies

69

2. Accounting Changes

71

3. Miscellaneous Financial Information

72

4. Cash Flow Information

72

5. Additional Working Capital Information

72

6. Equity Company Information

73

7. Investments, Advances and Long-Term Receivables

74

8. Property, Plant and Equipment and Asset Retirement Obligations

74

9. Accounting for Suspended Exploratory Well Costs

75

10. Leased Facilities

77

11. Earnings Per Share

77

12. Financial Instruments and Derivatives

78

13. Long-Term Debt

79

14. Incentive Program

84

15. Litigation and Other Contingencies

87

16. Pension and Other Postretirement Benefits

89

17. Disclosures about Segments and Related Information

97

18. Income, Sales-Based and Other Taxes

99

19. Acquisition of XTO Energy Inc.

101

Supplemental Information on Oil and Gas Exploration and Production Activities

103

Operating Summary

118

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Table of Contents Index to Financial Statements

BUSINESS PROFILE

Earnings After
Income Taxes
Average Capital
Employed
Return on
Average Capital
Employed
Capital and
Exploration
Expenditures

Financial

2010 2009 2010 2009 2010 2009 2010 2009

(millions of dollars)

(percent) (millions of dollars)

Upstream

United States

$ 4,272 $ 2,893 $ 34,969 $ 15,865 12.2 18.2 $ 6,349 $ 3,585

Non-U.S.

19,825 14,214 68,318 57,336 29.0 24.8 20,970 17,119

Total

$ 24,097 $ 17,107 $ 103,287 $ 73,201 23.3 23.4 $ 27,319 $ 20,704

Downstream

United States

$ 770 $ (153 $ 6,154 $ 7,306 12.5 (2.1 $ 982 $ 1,511

Non-U.S.

2,797 1,934 17,976 17,793 15.6 10.9 1,523 1,685

Total

$ 3,567 $ 1,781 $ 24,130 $ 25,099 14.8 7.1 $ 2,505 $ 3,196

Chemical

United States

$ 2,422 $ 769 $ 4,566 $ 4,370 53.0 17.6 $ 279 $ 319

Non-U.S.

2,491 1,540 14,114 12,190 17.6 12.6 1,936 2,829

Total

$ 4,913 $ 2,309 $ 18,680 $ 16,560 26.3 13.9 $ 2,215 $ 3,148

Corporate and financing

(2,117 (1,917 (880 10,190 -   -   187 44

Total

$ 30,460 $ 19,280 $ 145,217 $ 125,050 21.7 16.3 $ 32,226 $ 27,092

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

Operating

2010 2009 2010 2009
(thousands of barrels daily) (thousands of barrels daily)

Net liquids production

Refinery throughput

United States

408 384

United States

1,753 1,767

Non-U.S.

2,014 2,003

Non-U.S.

3,500 3,583

Total

2,422 2,387

Total

5,253 5,350
(millions of cubic feet daily) (thousands of barrels daily)

Natural gas production available for sale

Petroleum product sales

United States

2,596 1,275

United States

2,511 2,523

Non-U.S.

9,552 7,998

Non-U.S.

3,903 3,905

Total

12,148 9,273

Total

6,414 6,428
(thousands of oil-equivalent barrels daily) (thousands of metric tons)

Oil-equivalent production  (1)

4,447 3,932

Chemical prime product sales

United States

9,815 9,649

Non-U.S.

16,076 15,176

Total

25,891 24,825

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

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Table of Contents Index to Financial Statements

FINANCIAL SUMMARY

2010 (1) 2009 2008 2007 2006
(millions of dollars, except per share amounts)

Sales and other operating revenue (2)

$ 370,125 $ 301,500 $ 459,579 $ 390,328 $ 365,467

Earnings

Upstream

$ 24,097 $ 17,107 $ 35,402 $ 26,497 $ 26,230

Downstream

3,567 1,781 8,151 9,573 8,454

Chemical

4,913 2,309 2,957 4,563 4,382

Corporate and financing

(2,117 (1,917 (1,290 (23 434

Net income attributable to ExxonMobil

$ 30,460 $ 19,280 $ 45,220 $ 40,610 $ 39,500

Earnings per common share

$ 6.24 $ 3.99 $ 8.70 $ 7.31 $ 6.64

Earnings per common share – assuming dilution

$ 6.22 $ 3.98 $ 8.66 $ 7.26 $ 6.60

Cash dividends per common share

$ 1.74 $ 1.66 $ 1.55 $ 1.37 $ 1.28

Earnings to average ExxonMobil share of equity (percent)

23.7 17.3 38.5 34.5 35.1

Working capital

$ (3,649 $ 3,174 $ 23,166 $ 27,651 $ 26,960

Ratio of current assets to current liabilities (times)

0.94 1.06 1.47 1.47 1.55

Additions to property, plant and equipment

$ 74,156 $ 22,491 $ 19,318 $ 15,387 $ 15,462

Property, plant and equipment, less allowances

$ 199,548 $ 139,116 $ 121,346 $ 120,869 $ 113,687

Total assets

$ 302,510 $ 233,323 $ 228,052 $ 242,082 $ 219,015

Exploration expenses, including dry holes

$ 2,144 $ 2,021 $ 1,451 $ 1,469 $ 1,181

Research and development costs

$ 1,012 $ 1,050 $ 847 $ 814 $ 733

Long-term debt

$ 12,227 $ 7,129 $ 7,025 $ 7,183 $ 6,645

Total debt

$ 15,014 $ 9,605 $ 9,425 $ 9,566 $ 8,347

Fixed-charge coverage ratio (times)

42.2 25.8 54.6 51.6 47.8

Debt to capital (percent)

9.0 7.7 7.4 7.1 6.6

Net debt to capital (percent) (3)

4.5 (1.0 (23.0 (24.0 (20.4

ExxonMobil share of equity at year end

$ 146,839 $ 110,569 $ 112,965 $ 121,762 $ 113,844

ExxonMobil share of equity per common share

$ 29.48 $ 23.39 $ 22.70 $ 22.62 $ 19.87

Weighted average number of common shares outstanding (millions)

4,885 4,832 5,194 5,557 5,948

Number of regular employees at year end (thousands) (4)

83.6 80.7 79.9 80.8 82.1

CORS employees not included above (thousands) (5)

20.1 22.0 24.8 26.3 24.3

(1) See Note 19: Acquisition of XTO Energy Inc.
(2) Sales and other operating revenue includes sales-based taxes of $28,547 million for 2010, $25,936 million for 2009, $34,508 million for 2008, $31,728 million for 2007 and $30,381 million for 2006.
(3) Debt net of cash, excluding restricted cash.
(4) 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.
(5) CORS employees are employees of company-operated retail sites.

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FREQUENTLY USED TERMS

Listed below are definitions of several of ExxonMobil's key business and financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation.

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 reflects the total sources of cash from both operating the Corporation's assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the Corporation's strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.

Cash flow from operations and asset sales

2010 2009 2008

(millions of dollars)

Net cash provided by operating activities

$ 48,413 $ 28,438 $ 59,725

Sales of subsidiaries, investments and property, plant and equipment

3,261 1,545 5,985

Cash flow from operations and asset sales

$ 51,674 $ 29,983 $ 65,710

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 in total for the Corporation, it includes ExxonMobil's share of total debt and equity. Both of these views include ExxonMobil's share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.

Capital employed

2010 2009 2008
(millions of dollars)

Business uses: asset and liability perspective

Total assets

$ 302,510 $ 233,323 $ 228,052

Less liabilities and noncontrolling interests share of assets and liabilities

Total current liabilities excluding notes and loans payable

(59,846 (49,585 (46,700

Total long-term liabilities excluding long-term debt

(74,971 (58,741 (54,404

Noncontrolling interests share of assets and liabilities

(6,532 (5,642 (6,044

Add ExxonMobil share of debt-financed equity company net assets

4,875 5,043 4,798

Total capital employed

$ 166,036 $ 124,398 $ 125,702

Total corporate sources: debt and equity perspective

Notes and loans payable

$ 2,787 $ 2,476 $ 2,400

Long-term debt

12,227 7,129 7,025

ExxonMobil share of equity

146,839 110,569 112,965

Less noncontrolling interests share of total debt

(692 (819 (1,486

Add ExxonMobil share of equity company debt

4,875 5,043 4,798

Total capital employed

$ 166,036 $ 124,398 $ 125,702

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Table of Contents Index to Financial Statements

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 attributable to ExxonMobil 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 in our capital-intensive, long-term industry, both to evaluate management's performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow-based, are used to make investment decisions.

Return on average capital employed

2010 2009 2008
(millions of dollars)

Net income attributable to ExxonMobil

$ 30,460 $ 19,280 $ 45,220

Financing costs (after tax)

Gross third-party debt

(803 (303 (343

ExxonMobil share of equity companies

(333 (285 (325

All other financing costs – net

35 (483 1,485

Total financing costs

(1,101 (1,071 817

Earnings excluding financing costs

$ 31,561 $ 20,351 $ 44,403

Average capital employed

$ 145,217 $ 125,050 $ 129,683

Return on average capital employed – corporate total

21.7% 16.3% 34.2%

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Table of Contents Index to Financial Statements

QUARTERLY INFORMATION

2010 2009
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Year First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Year

(thousands of barrels daily)

Volumes

Production of crude oil and natural gas liquids, synthetic oil and bitumen

2,414 2,325 2,421 2,526 2,422 2,476 2,346 2,335 2,393 2,387

Refinery throughput

5,156 5,192 5,364 5,298 5,253 5,381 5,290 5,352 5,379 5,350

Petroleum product sales

6,195 6,304 6,595 6,555 6,414 6,434 6,487 6,301 6,489 6,428
(millions of cubic feet daily)

Natural gas production available for sale

11,689 10,025 12,192 14,652 12,148 10,187 8,041 8,155 10,717 9,273
(thousands of oil-equivalent barrels daily)

Oil-equivalent production (1)

4,362 3,996 4,453 4,968 4,447 4,174 3,686 3,694 4,179 3,932
(thousands of metric tons)

Chemical prime product sales

6,488 6,496 6,558 6,349 25,891 5,527 6,267 6,356 6,675 24,825
(millions of dollars)

Summarized financial data

Sales and other operating revenue (2)

$ 87,037 89,693 92,353 101,042 370,125 $ 62,128 72,167 80,090 87,115 301,500

Gross profit (3)

$ 28,537 29,482 30,652 32,943 121,614 $ 23,562 24,231 27,377 28,580 103,750

Net income attributable to ExxonMobil

$ 6,300 7,560 7,350 9,250 30,460 $ 4,550 3,950 4,730 6,050 19,280
(dollars per share)

Per share data

Earnings per common share (4)

$ 1.33 1.61 1.44 1.86 6.24 $ 0.92 0.82 0.98 1.27 3.99

Earnings per common share – assuming dilution (4)

$ 1.33 1.60 1.44 1.85 6.22 $ 0.92 0.81 0.98 1.27 3.98

Dividends per common share

$ 0.42 0.44 0.44 0.44 1.74 $ 0.40 0.42 0.42 0.42 1.66

Common stock prices

High

$ 70.60 70.00 62.99 73.69 73.69 $ 82.73 74.83 72.79 76.54 82.73

Low

$ 63.56 56.92 55.94 61.80 55.94 $ 61.86 64.50 64.46 66.11 61.86

(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Includes amounts for sales-based taxes.
(3) Gross profit equals sales and other operating revenue less estimated costs associated with products sold.
(4) Computed using the average number of shares outstanding during each period. The sum of the four quarters may not add to the full year.

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 507,028 registered shareholders of ExxonMobil common stock at December 31, 2010. At January 31, 2011, the registered shareholders of ExxonMobil common stock numbered 505,330.

On January 26, 2011, the Corporation declared a $0.44 dividend per common share, payable March 10, 2011.

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Table of Contents Index to Financial Statements

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

FUNCTIONAL EARNINGS

2010 2009 2008
(millions of dollars, except per
share amounts)

Earnings (U.S. GAAP)

Upstream

United States

$ 4,272 $ 2,893 $ 6,243

Non-U.S.

19,825 14,214 29,159

Downstream

United States

770 (153 1,649

Non-U.S.

2,797 1,934 6,502

Chemical

United States

2,422 769 724

Non-U.S.

2,491 1,540 2,233

Corporate and financing

(2,117 (1,917 (1,290

Net income attributable to ExxonMobil

$ 30,460 $ 19,280 $ 45,220

Earnings per common share

$ 6.24 $ 3.99 $ 8.70

Earnings per common share – assuming dilution

$ 6.22 $ 3.98 $ 8.66

Special items included in earnings

Non-U.S. Upstream

Gain on German natural gas transportation business sale

$ -   $ -   $ 1,620

Corporate and financing

Valdez litigation

$ -   $ (140 $ (460

References in this discussion to total corporate earnings mean net income attributable to ExxonMobil (U.S. GAAP) from the consolidated income statement. Unless otherwise indicated, references to earnings, special items, Upstream, Downstream, Chemical and Corporate and Financing segment earnings, and earnings per share are ExxonMobil's share after excluding amounts attributable to noncontrolling interests.

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Table of Contents Index to Financial Statements

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

FORWARD-LOOKING STATEMENTS

Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including demand growth and energy source mix; capacity increases; production growth and mix; rates of field decline; financing sources; the resolution of contingencies and uncertain tax positions; environmental and capital expenditures; could differ materially depending on a number of factors, such as changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; the outcome of commercial negotiations; political or regulatory events, and other factors discussed herein and in Item 1A of ExxonMobil's 2010 Form 10-K.

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, manufacturing 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.

ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new energy supplies. While commodity prices are volatile on a short-term basis and depend on supply and demand, ExxonMobil's investment decisions are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Prices for crude oil, natural gas and refined products are based on corporate plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

By 2030, the world's population is projected to grow to approximately 8 billion people, or about 1.5 billion more than in 2005. Coincident with this population increase, the Corporation expects worldwide economic growth to average 2.8 percent per year. This combination of population and economic growth is expected to lead to an increase in primary energy demand of about 35 percent by 2030 versus 2005, even with substantial efficiency gains around the world. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development).

As economic progress drives demand higher, increasing penetration of energy-efficient and lower-emission fuels, technologies and practices are expected to contribute to significantly lower levels of energy consumption and emissions per unit of economic output over time. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the introduction of new technologies, as well as many other improvements that span the residential, commercial and industrial sectors.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by nearly 40 percent from 2005 to 2030. The global growth in transportation demand is likely to account for approximately 80 percent of the growth in oil demand over this period. Nearly all the world's transportation fleets will continue to run on liquid fuels because they provide a large quantity of energy in small volumes, making them easy to transport and widely available.

Demand for electricity around the world will grow significantly through 2030. Consistent with this projection, power generation will remain the largest and fastest-growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Natural gas demand will grow most significantly and gain the most market share, although coal demand will also grow and retain the largest share through 2030 despite also losing share to nuclear and wind.

Liquid fuels provide the largest share of energy supply today due to their availability, affordability and ease of transport. By 2030, global demand for liquids is expected to grow to approximately 103 million barrels of oil-equivalent per day, an increase of more than 20 percent from 2005. Global demand for liquid fuels will be met by a wide variety of sources. Conventional non-OPEC crude and condensate production is expected to remain relatively flat through 2030. However, growth is expected from a number of supply sources, including biofuels, oil sands and natural gas liquids, as well as crude oil from OPEC countries. While the world's resource base is sufficient to meet projected demand, access to resources and timely investments will remain critical to meeting global needs with reliable, affordable supplies.

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Increases in natural gas demand in North America, Europe and Asia Pacific will require new sources of supply. Helping meet these needs will be additional local supplies of unconventional natural gas – the result of recent improvements in technologies used to tap these hard-to-produce resources – as well as imports. The growing need for natural gas imports will have a dramatic impact on the worldwide liquefied natural gas (LNG) market, which is expected to approximately triple in volume from 2005 to 2030.

The world's energy mix is highly diverse and will remain so through 2030. Oil is expected to remain the largest source of energy supply at close to 32 percent. From 2005 to 2030, natural gas is expected to grow the fastest of the major energy types and overtake coal as the second-largest energy source. Nuclear power is projected to grow significantly, on par with coal in terms of absolute growth and surpassing biomass as the fourth-largest source of energy. Hydro and geothermal will also grow, though remain limited by the availability of natural sites. Wind, solar and biofuels are expected to grow at close to 10 percent per year on average, the highest growth rate of all fuels, and are projected to reach approximately 2.5 percent of world energy by 2030.

The Corporation anticipates that the world's available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide over the period 2010-2035 will be approximately $15 trillion (measured in 2009 dollars) or close to $580 billion per year on average.

International accords and underlying regional and national regulations for greenhouse gas reduction are evolving with uncertain timing and outcome, making it difficult to predict their business impact. ExxonMobil includes estimates of potential costs related to possible public policies covering energy-related greenhouse gas emissions in its long-term Energy Outlook, which is used for assessing the business environment and in its investment evaluations.

The information provided in the Long-Term Business Outlook includes ExxonMobil's internal estimates and forecasts based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency.

Upstream

ExxonMobil continues to maintain a large portfolio of exploration and development opportunities, which enables the Corporation to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil's fundamental Upstream business strategies guide our global exploration, development, production, and gas and power marketing activities. These strategies include identifying and selectively pursuing the highest quality exploration opportunities, investing in projects that deliver superior returns, maximizing profitability of existing oil and gas production, and capitalizing on growing natural gas and power markets. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees and investment in the communities in which we operate.

As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2015. Oil and natural gas output from North America is expected to increase over the next five years based on current capital activity plans. Currently, this growth area accounts for 27 percent of the Corporation's production. By 2015, it is expected to generate about 35 percent of total volumes. The remainder of the Corporation's production is expected to be sourced from Asia, Europe, Africa and Australia, with contributions from both established operations and new projects.

In addition to an evolving geographic mix, there will also be continued change in the type of opportunities from which volumes are produced. Production from diverse resource types utilizing specialized technologies such as arctic technology, deepwater drilling and production systems, heavy oil recovery processes, unconventional gas production and LNG is expected to grow from about 40 percent to around 55 percent of the Corporation's output between now and 2015. We do not anticipate that the expected change in the geographic mix of production volumes, and in the types of opportunities from which volumes will be produced, will have a material impact on the nature and the extent of the risks disclosed in Item 1A of ExxonMobil's 2010 Form 10-K, or result in a material change in our level of unit operating expenses. The Corporation's overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2011-2015. However, actual volumes will vary from year to year due to the timing of individual project start-ups and other capital activities, operational outages, reservoir performance, performance of enhanced oil recovery projects, regulatory changes, asset sales, weather events, price effects under production sharing contracts and other factors described in Item 1A of ExxonMobil's 2010 Form 10-K. Enhanced oil recovery projects extract hydrocarbons from reservoirs in excess of that which may be produced through primary recovery, i.e., through pressure depletion or natural aquifer support. They include the injection of water, gases or chemicals into a reservoir to produce hydrocarbons otherwise unobtainable.

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

Downstream

ExxonMobil's Downstream is a large, diversified business with refining and marketing complexes around the world. The Corporation has a strong presence in mature markets in North America and Europe, as well as the growing Asia Pacific region. ExxonMobil's fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizing on integration across ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectiveness, and providing quality, valued products and services to customers.

ExxonMobil has an ownership interest in 36 refineries, located in 21 countries, with distillation capacity of 6.3 million barrels per day and lubricant basestock manufacturing capacity of about 131 thousand barrels per day. ExxonMobil's fuels and lubes marketing business portfolios include operations around the world, with multiple channels to market serving a globally diverse customer base.

The downstream industry environment remains challenging. Although demand for refined products has improved from the lower levels in 2009 due to the recent global economic recession, we expect the challenging business environment to continue, reflecting the increase in global refining capacity and regulatory-related policies. Over the prior 20-year period, inflation-adjusted refining margins have been flat.

Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, currency fluctuations, seasonal demand, weather and political climate.

ExxonMobil's long-term outlook is that refining margins will remain weak as competition in the refining industry remains intense and, in the near term, new capacity additions outpace the growth in global demand. Additionally, as described in more detail in Item 1A of ExxonMobil's 2010 Form 10-K, proposed carbon policy and other climate-related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the refining business.

In the retail fuels marketing business, competition continues to cause inflation-adjusted margins to decline. In 2010, ExxonMobil progressed the transition of the direct served (i.e., dealer, company-operated) retail network in the U.S. to a branded distributor model. This transition was announced in 2008 and will be a multiyear process.

ExxonMobil takes a disciplined approach to managing the Downstream capital employed. The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. These investments capitalize on the Corporation's world-class scale and integration, industry-leading efficiency, leading-edge technology and respected brands, enabling ExxonMobil to take advantage of attractive emerging-growth opportunities around the globe. In 2010, ExxonMobil invested over $1 billion in three refineries to increase the supply of cleaner-burning diesel by about 140 thousand barrels per day. The company completed construction of new units and modification of existing facilities at its Baton Rouge, Louisiana; Baytown, Texas; and Antwerp, Belgium, refineries. In addition, construction has commenced at the Sriracha, Thailand, refinery to produce lower sulfur diesel and gasoline to meet upcoming product specifications in Thailand. Completion is expected in the fourth quarter of 2011. At the Jurong/PAC refinery in Singapore, plans are under way to build a new diesel hydrotreater, which will add a capacity of more than 2 million gallons per day to meet increasing demand in the Asia Pacific region.

Chemical

Worldwide petrochemical demand recovered from the economic downturn in 2008 and the first half of 2009. Tighter industry supply/ demand balances throughout the year supported improved industry margins, particularly in the U.S. Asia Pacific commodity margins were lower, reflecting the start-up of significant new industry capacity in the region.

ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of commodity petrochemical products, ExxonMobil Chemical also has a number of less-cyclical business lines, which delivered strong results in 2010. Chemical's competitive advantages are due to its business mix, broad geographic coverage, investment and cost discipline, integration with refineries or upstream gas processing facilities, superior feedstock management, leading proprietary technology and product application expertise.

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REVIEW OF 2010 AND 2009 RESULTS

2010 2009 2008
(millions of dollars)

Earnings (U.S. GAAP)

$ 30,460 $ 19,280 $ 45,220

2010

Earnings in 2010 of $30,460 million increased $11,180 million from 2009. Earnings for 2010 did not include any special items.

2009

Earnings in 2009 of $19,280 million decreased $25,940 million from 2008. Earnings for 2009 included an after-tax special charge of $140 million for interest related to the Valdez punitive damages award.

Upstream

2010 2009 2008

(millions of dollars)

Upstream

United States

$ 4,272 $ 2,893 $ 6,243

Non-U.S.

19,825 14,214 29,159

Total

$ 24,097 $ 17,107 $ 35,402

2010

Upstream earnings were $24,097 million, up $6,990 million from 2009. Higher realizations increased earnings approximately $6.5 billion. Higher volumes increased earnings by $1.2 billion, while all other items, including higher operating costs, decreased earnings by $690 million. On an oil-equivalent basis, production was up 13 percent compared to 2009. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 14 percent. Liquids production of 2,422 kbd (thousands of barrels per day) increased 35 kbd compared with 2009. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production increased 2 percent from 2009, as project ramp-ups in Qatar were offset by net field decline. Natural gas production of 12,148 mcfd (millions of cubic feet per day) increased 2,875 mcfd from 2009, driven by higher volumes from Qatar projects and additional U.S. unconventional gas volumes. Earnings from U.S. Upstream operations for 2010 were $4,272 million, an increase of $1,379 million from 2009. Non-U.S. Upstream earnings were $19,825 million, up $5,611 million from 2009.

2009

Upstream earnings for 2009 were $17,107 million, down $18,295 million from 2008, including the absence of an after-tax special gain in 2008 of $1,620 million from the sale of a natural gas transportation business in Germany. Lower crude oil and natural gas realizations reduced earnings $15.2 billion. Volume and mix effects increased earnings $700 million. Higher operating expenses and increased exploration activities decreased earnings $1.4 billion. Lower gains on asset divestments reduced earnings approximately $900 million. Oil-equivalent production increased slightly versus 2008, including impacts from entitlement effects, quotas and divestments. Excluding these items, oil-equivalent production was up about 2 percent. Liquids production of 2,387 kbd decreased 18 kbd. Production increases from new projects in the U.S., Qatar and Africa along with higher volumes in Kazakhstan were offset by field decline. Natural gas production of 9,273 mcfd increased 178 mcfd from 2008. Higher volumes from projects in Qatar were partially offset by field decline. Earnings from U.S. Upstream operations for 2009 were $2,893 million, a decrease of $3,350 million. Earnings outside the U.S. for 2009 of $14,214 million declined $14,945 million.

Downstream

2010 2009 2008
(millions of dollars)

Downstream

United States

$ 770 $ (153 $ 1,649

Non-U.S.

2,797 1,934 6,502

Total

$ 3,567 $ 1,781 $ 8,151

2010

Downstream earnings of $3,567 million were $1,786 million higher than 2009. Higher industry refining margins increased earnings by $1.2 billion. Positive volume and mix effects increased earnings by $420 million, while all other items, including lower operating expenses, increased earnings by $210 million. Petroleum product sales of 6,414 kbd decreased 14 kbd. U.S. Downstream earnings were $770 million, up $923 million from 2009. Non-U.S. Downstream earnings were $2,797 million, $863 million higher than 2009.

2009

Downstream earnings were $1,781 million, down $6.4 billion from 2008. Weaker margins reduced earnings $5.1 billion. Lower divestment activity reduced earnings about $1.0 billion. Volumes decreased earnings approximately $300 million. Petroleum product sales of 6,428 kbd decreased 333 kbd, mainly reflecting asset divestments and lower demand. Refinery throughput was 5,350 kbd, down 66 kbd from 2008. Earnings from the U.S. Downstream were $1,802 million lower than in 2008. Non-U.S. Downstream earnings were $1,934 million, down $4,568 million from 2008.

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

Chemical

2010 2009 2008

(millions of dollars)

Chemical

United States

$ 2,422 $ 769 $ 724

Non-U.S.

2,491 1,540 2,233

Total

$ 4,913 $ 2,309 $ 2,957

2010

Chemical earnings were a record $4,913 million, up $2,604 million from 2009. Improved margins increased earnings by $2.0 billion while higher volumes increased earnings $380 million. Prime product sales of 25,891 kt were up 1,066 kt from 2009. Prime product sales are total chemical product sales, including ExxonMobil's share of equity-company volumes and finished product transfers to the Downstream business. U.S. Chemical earnings of $2,422 million increased $1,653 million. Non-U.S. Chemical earnings of $2,491 million increased $951 million.

2009

Earnings declined $648 million versus 2008 to a total of $2,309 million. Weaker margins reduced earnings by $340 million, mostly in commodities. Lower volumes decreased earnings $190 million. All other items, including unfavorable foreign exchange impacts, reduced earnings $115 million. Prime product sales of 24,825 kt decreased 157 kt from 2008. U.S. Chemical earnings of $769 million increased $45 million. Non-U.S. Chemical earnings were $1,540 million, down $693 million.

Corporate and Financing

2010 2009 2008

(millions of dollars)

Corporate and financing

$ (2,117 $ (1,917 $ (1,290

2010

Corporate and financing expenses were $2,117 million, up $200 million from 2009 mainly due to a tax charge related to the U.S. health care legislation during the first quarter of 2010 and financing activities, partially offset by the absence of a 2009 charge for interest related to the Valdez punitive damages award.

2009

Corporate and financing expenses of $1,917 million in 2009 increased $627 million, primarily due to lower interest income.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

2010 2009 2008
(millions of dollars)

Net cash provided by/(used in)

Operating activities

$ 48,413 $ 28,438 $ 59,725

Investing activities

(24,204 (22,419 (15,499

Financing activities

(26,924 (27,283 (44,027

Effect of exchange rate changes

(153 520 (2,743

Increase/(decrease) in cash and cash equivalents

$ (2,868 $ (20,744 $ (2,544

(Dec. 31)

Cash and cash equivalents

$ 7,825 $ 10,693 $ 31,437

Cash and cash equivalents – restricted

628 -   -  

Total cash and cash equivalents

$ 8,453 $ 10,693 $ 31,437

Total cash and cash equivalents were $8.5 billion at the end of 2010, $2.2 billion lower than the prior year. Higher earnings and reduced share purchases were offset by a higher level of capital spending and increased level of debt repurchases. Included in total cash and cash equivalents at year-end 2010 was $0.6 billion of restricted cash.

Cash and cash equivalents were $10.7 billion at the end of 2009, $20.7 billion lower than the prior year, reflecting lower earnings and a higher level of capital spending partially offset by a lower level of purchases of ExxonMobil shares. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows.

Although the Corporation has access to significant capacity of long-term and short-term liquidity, 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 to ensure it is secure and readily available to meet the Corporation's cash requirements and to optimize returns on the cash balances.

To support cash flows in future periods the Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all the Corporation's existing oil and gas fields and without new projects, ExxonMobil's production is expected to decline at an average of approximately 3 percent per year over the next few years. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. Furthermore, the Corporation's net interest in production for individual fields can vary with price and contractual terms.

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The Corporation has long been successful at offsetting the effects of natural field decline through disciplined investments in quality opportunities and project execution. Over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. Projects are in progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including project start-up timing, operational outages, reservoir performance, crude oil and natural gas prices, weather events, and regulatory changes. The Corporation's cash flows are also highly dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks.

The Corporation's financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2010 were $32.2 billion, reflecting the Corporation's continued active investment program. The Corporation expects annual expenditures to range from $33 billion to $37 billion for the next several years. Actual spending could vary depending on the progress of individual projects. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation's Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation's liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas properties have not had a significant impact on the amount or timing of cash flows from operating activities.

Cash Flow from Operating Activities

2010

Cash provided by operating activities totaled $48.4 billion in 2010, $20.0 billion higher than 2009. The major source of funds was net income including noncontrolling interests of $31.4 billion, adjusted for the noncash provision of $14.8 billion for depreciation and depletion, both of which increased. The net effects of changes in prices and the timing of collection of accounts receivable and of payments of accounts and other payables and of income taxes payable increased cash provided by operating activities in 2010 compared to a decrease in 2009, and resulted in net working capital of $(3.6) billion as total current liabilities of $62.6 billion exceeded total current assets of $59.0 billion at year-end 2010.

2009

Cash provided by operating activities totaled $28.4 billion in 2009, $31.3 billion lower than 2008. The major source of funds was net income including noncontrolling interests of $19.7 billion, adjusted for the noncash provision of $11.9 billion for depreciation and depletion, both of which declined. Pension fund contributions in 2009 of $4.5 billion increased from $1.0 billion in 2008. The net effects of changes in prices and the timing of collection of accounts receivable and of payments of accounts and other payables and of income taxes payable reduced cash provided by operating activities in 2009 compared to an increase in 2008.

Cash Flow from Investing Activities

2010

Cash used in investment activities netted to $24.2 billion in 2010, $1.8 billion higher than in 2009. Spending for property, plant and equipment of $26.9 billion increased $4.4 billion from 2009. Proceeds from the sale of subsidiaries, investments and property, plant and equipment of $3.3 billion in 2010 compared to $1.5 billion in 2009, the increase reflecting the sale of some U.S. service stations and Upstream Gulf of Mexico and other producing properties.

2009

Cash used in investing activities netted to $22.4 billion in 2009, $6.9 billion higher than in 2008. Spending for property, plant and equipment of $22.5 billion in 2009 increased $3.2 billion from 2008. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $1.5 billion in 2009 compared to $6.0 billion in 2008, the decrease reflecting the absence of the sale of the natural gas transportation business in Germany and lower sales of Downstream assets and investments.

Cash Flow from Financing Activities

2010

Cash used in financing activities was $26.9 billion in 2010, $0.4 billion lower than 2009. Dividend payments on common shares increased to $1.74 per share from $1.66 per share and totaled $8.5 billion, a pay-out of 28 percent. Total debt increased to $15.0 billion at year end, an increase of $5.4 billion from 2009, primarily as a result of debt assumed with the XTO merger.

ExxonMobil share of equity increased $36.3 billion to $146.8 billion. The addition to equity for earnings of $30.5 billion and the issuance of stock for the XTO merger of $24.7 billion was partially offset by reductions to equity for distributions to ExxonMobil shareholders of $8.5 billion of dividends and $11.2 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding.

        During 2010, Exxon Mobil Corporation issued 416 million shares for the XTO merger. Exxon Mobil Corporation purchased 199 million shares of its common stock for the treasury at a gross cost of $13.1 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding increased by 5.3 percent from 4,727 million at the end of 2009 to 4,979 million at the end of 2010. Purchases were made in both the open market and negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.

2009

Cash used in financing activities was $27.3 billion in 2009, $16.7 billion lower than 2008, reflecting a lower level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.66 per share from $1.55 per share and totaled $8.0 billion, a pay-out of 42 percent. Total consolidated short-term and long-term debt increased

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

$0.2 billion to $9.6 billion at year-end 2009.

ExxonMobil share of equity decreased $2.4 billion in 2009, to $110.6 billion. The addition to equity for earnings of $19.3 billion was more than offset by reductions for distributions to ExxonMobil shareholders of $8.0 billion of dividends and $18.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Equity, and net assets and liabilities, increased $3.3 billion, representing the foreign exchange translation effects of generally stronger foreign currencies at the end of 2009 on ExxonMobil's operations outside the United States. The change in the funded status of the postretirement benefits reserves in 2009 increased equity by $1.2 billion.

During 2009, Exxon Mobil Corporation purchased 277 million shares of its common stock for the treasury at a gross cost of $19.7 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 5.0 percent from 4,976 million at the end of 2008 to 4,727 million at the end of 2009. Purchases were made in both the open market and through negotiated transactions.

Commitments

Set forth below is information about the outstanding commitments of the Corporation's consolidated subsidiaries at December 31, 2010. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.

Payments Due by Period

Commitments

Note
Reference
Number
2011 2012-
2015
2016
and
Beyond
Total
(millions of dollars)

Long-term debt (1)

13 $ -   $ 5,464 $ 6,763 $ 12,227

- Due in one year (2)

5 345 -   -   345

Asset retirement obligations (3)

8 775 2,196 6,643 9,614

Pension and other postretirement obligations (4)

16 2,541 4,130 13,231 19,902

Operating leases (5)

10 2,095 3,943 1,738 7,776

Unconditional purchase obligations (6)

15 287 748 487 1,522

Take-or-pay obligations (7)

1,704 6,275 8,832 16,811

Firm capital commitments (8)

14,851 12,329 948 28,128

This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these purchases will be offset in the same periods by cash received from the related sales transactions. The table also excludes unrecognized tax benefits totaling $4.1 billion as of December 31, 2010, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in note 18, Income, Sales-Based and Other Taxes.

Notes:

(1) Includes capitalized lease obligations of $304 million.
(2) The amount due in one year is included in notes and loans payable of $2,787 million.
(3) The fair value of asset retirement obligations, primarily upstream asset removal costs at the completion of field life.
(4) The amount by which the benefit obligations exceeded the fair value of fund assets for certain U.S. and non-U.S. pension and other postretirement plans at year end. The payments by period include expected contributions to funded pension plans in 2011 and estimated benefit payments for unfunded plans in all years.
(5) Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties.
(6) Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $1,522 million mainly pertain to pipeline throughput agreements and include $996 million of obligations to equity companies.
(7) Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $16,811 million mainly pertain to manufacturing supply, pipeline and terminaling agreements and include $507 million of obligations to equity companies.
(8) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $28.1 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $17.2 billion was associated with projects in Australia, Africa, Malaysia and Canada. The Corporation expects to fund the majority of these projects through internal cash flow.

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Guarantees

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2010, for $8,771 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of $5,290 million, representing ExxonMobil's share of obligations of certain equity companies. The below-mentioned guarantees are not reasonably likely to have a material effect on the Corporation's financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Dec. 31, 2010
Equity
Company
Obligations
Other
Third-Party
Obligations
Total
(millions of dollars)

Guarantees

$ 5,290 $ 3,481 $ 8,771

Financial Strength

On December 31, 2010, unused credit lines for short-term financing totaled approximately $5.6 billion (note 5).

The table below shows the Corporation's fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation's creditworthiness.

2010 2009 2008

Fixed-charge coverage ratio (times)

42.2 25.8 54.6

Debt to capital (percent)

9.0 7.7 7.4

Net debt to capital (percent)

4.5 (1.0 (23.0

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.

Litigation and Other Contingencies

Litigation. As discussed in note 15, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation's operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

Other Contingencies. In accordance with a nationalization decree issued by Venezuela's president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a "mixed enterprise" and an increase in PdVSA's or one of its affiliate's ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed enterprise within a specified period of time, the government would "directly assume the activities" carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil's 41.67 percent interest in the Cerro Negro Project.

On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes (ICSID) invoking ICSID jurisdiction under Venezuela's Investment Law and the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID Tribunal issued a decision on June 10, 2010, finding that it had jurisdiction to proceed on the basis of the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID arbitration proceeding is continuing and a hearing on the merits is currently scheduled for the first quarter of 2012. An affiliate of ExxonMobil has also filed an arbitration under the rules of the International Chamber of Commerce (ICC) against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. A hearing on the merits of the ICC arbitration concluded in September 2010 and the parties have filed post-hearing briefs. At this time, the net impact of this matter on the Corporation's consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporation's operations or financial condition. ExxonMobil's remaining net book investment in Cerro Negro producing assets is about $750 million.

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CAPITAL AND EXPLORATION EXPENDITURES

2010 2009
U.S. Non-U.S. U.S. Non-U.S.

(millions of dollars)

Upstream (1)

$ 6,349 $ 20,970 $ 3,585 $ 17,119

Downstream

982 1,523 1,511 1,685

Chemical

279 1,936 319 2,829

Other

187 -   44 -  

Total

$ 7,797 $ 24,429 $ 5,459 $ 21,633

(1) Exploration expenses included.

Capital and exploration expenditures in 2010 were $32.2 billion, reflecting the Corporation's continued active investment program. The Corporation expects annual expenditures to range from $33 billion to $37 billion for the next several years. Actual spending could vary depending on the progress of individual projects.

Upstream spending of $27.3 billion in 2010 was up 32 percent from 2009, reflecting unconventional gas activities in the U.S. and continued progress on world-class projects in Canada, Australia and Papua New Guinea. The majority of expenditures are on development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves was 69 percent of total proved reserves at year-end 2010, and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $2.5 billion in 2010, a decrease of $0.7 billion from 2009, due to completion of environmental-related refining projects, primarily in the U.S. The Chemical capital expenditures of $2.2 billion were $0.9 billion lower in 2010 as investments in Asia to meet demand growth progressed toward completion.

TAXES

2010 2009 2008
(millions of dollars)

Income taxes

$ 21,561 $ 15,119 $ 36,530

Effective income tax rate

45% 47% 46%

Sales-based taxes

28,547 25,936 34,508

All other taxes and duties

39,127 37,571 45,223

Total

$ 89,235 $ 78,626 $ 116,261

2010

Income, sales-based and all other taxes and duties totaled $89.2 billion in 2010, an increase of $10.6 billion or 13 percent from 2009. Income tax expense, both current and deferred, was $21.6 billion, $6.4 billion higher than 2009, reflecting higher pre-tax income in 2010. A lower share of pre-tax income from the Upstream segment in 2010 decreased the effective tax rate to 45 percent compared to 47 percent in 2009. Sales-based and all other taxes and duties of $67.7 billion in 2010 increased $4.2 billion, reflecting higher prices.

2009

Income, sales-based and all other taxes and duties totaled $78.6 billion in 2009, a decrease of $37.6 billion or 32 percent from 2008. Income tax expense, both current and deferred, was $15.1 billion, $21.4 billion lower than 2008, reflecting lower pre-tax income in 2009. A higher share of total income from the Upstream segment in 2009 increased the effective income tax rate to 47 percent compared to 46 percent in 2008. Sales-based and all other taxes and duties of $63.5 billion in 2009 decreased $16.2 billion from 2008, reflecting lower prices and foreign exchange effects.

ENVIRONMENTAL MATTERS

Environmental Expenditures

2010 2009
(millions of dollars)

Capital expenditures

$ 1,947 $ 2,481

Other expenditures

2,593 2,610

Total

$ 4,540 $ 5,091

Throughout ExxonMobil's businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to monitor and reduce nitrogen oxide, sulfur oxide and greenhouse gas emissions and expenditures for asset retirement obligations. ExxonMobil's 2010 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil's share of equity company expenditures, were about $4.5 billion. The total cost for such activities is expected to remain in this range in 2011 and 2012 (with capital expenditures approximately 40 percent of the total).

Environmental Liabilities

The Corporation accrues environmental liabilities 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. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil's actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil's operations or financial condition. Consolidated company provisions made in 2010 for environmental liabilities were $448 million ($504 million in 2009) and the balance sheet reflects accumulated liabilities of $948 million as of December 31, 2010, and $943 million as of December 31, 2009.

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Asset Retirement Obligations

The fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time assets are installed, with an offsetting amount booked as additions to property, plant and equipment ($1,094 million for 2010). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($563 million in 2010). Consolidated company expenditures for asset retirement obligations in 2010 were $638 million and the obligations recorded on the balance sheet at December 31, 2010, totaled $9,614 million.

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

Worldwide Average Realizations (1)

2010 2009 2008

Crude oil and NGL ($/barrel)

$ 74.04 $ 57.86 $ 90.96

Natural gas ($/kcf)

4.31 4.00 7.54

(1) Consolidated subsidiaries.

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $375 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $200 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.

In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.

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 as a competitive advantage.

In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 40 percent of the Corporation's intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.

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 economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its investments over a broad range of future prices. 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.

The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation's strategic objectives. The result is an efficient capital base, and the Corporation has seldom had to write down the carrying value of assets, even during periods of low commodity prices.

Risk Management

The Corporation's size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation's enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. With respect to derivatives activities, the Corporation believes that there are no material market or credit risks to the Corporation's financial position, results of operations or liquidity as a result of the derivatives described in note 12. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. Credit risk associated with the Corporation's derivative position is mitigated by several factors, including the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.

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The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. 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. Although the Corporation issues long-term debt from time to time and maintains a commercial paper program, internally generated funds are expected to cover the majority of its net near-term financial requirements. However, some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.

The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil's geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation's limited use of the currency exchange contracts are not material. The Corporation makes limited use of commodity forwards, swaps and futures contracts to mitigate the impact of changes in commodity prices. A substantial portion of the commodity futures contracts and swap agreements acquired as part of the XTO merger settled during 2010 and the majority of the remainder will settle by year-end 2011.

Inflation and Other Uncertainties

The general rate of inflation in many major countries of operation has remained moderate over the past few years, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation works to counter upward pressure on costs through its economies of scale in global procurement and its efficient project management practices.

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. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment. Oil and gas reserves include both proved and unproved reserves. Consistent with the definitions in the Securities and Exchange Commission's Rule 4-10(a) of Regulation S-X, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.

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 assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Reserves Technical Oversight group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation.

Key features of the reserves estimation process include:

rigorous peer-reviewed technical evaluations and analysis of well and field performance information (such as flow rates and reservoir pressure declines) and

a requirement that management make significant funding commitments toward the development of the reserves prior to reporting as proved.

Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.

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Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves was 69 percent of total proved reserves at year-end 2010 (including both consolidated and equity company reserves), and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status. Over time, these undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to collect and deliver the production from existing and future wells are installed. Major development projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in prices and costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.

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. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method. 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 actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the 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. While the 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. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

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. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

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 assessing 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. Trigger events for impairment evaluation include a significant decrease in current and projected reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and forecast operating losses.

In general, the Corporation does not view temporarily low oil and gas 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 significantly, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted. Accordingly, any impairment tests that the Corporation performs make use of the Corporation's price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used

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for capital investment decisions. Volumes are based on individual field production profiles, which are updated annually. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements. Future prices used for any impairment tests will vary from the one used in the supplemental oil and gas disclosure and could be lower or higher for any given year.

Suspended Exploratory Well Costs

The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether a project has made sufficient progress is a subjective area and requires careful consideration of the relevant facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2010 are disclosed in note 9 to the financial statements.

Consolidations

The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation's share of the undivided interest in certain 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, advances and long-term receivables"; the Corporation's share of the net income of these companies is included in the Consolidated Statement of Income caption "Income from equity affiliates." The accounting for these non-consolidated companies is referred to as the equity method of accounting.

Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans and management compensation and succession plans.

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 6.

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 its 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 of 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.

Pension Benefits

The Corporation and its affiliates sponsor approximately 100 defined benefit (pension) plans in about 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the Corporation operates. Pension and Other Postretirement Benefits (note 16) provides details on pension obligations, fund assets and pension expense.

Some of these plans (primarily non-U.S.) provide pension benefits that 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.

For funded plans, including those in the United States, 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 that differ from those used for accounting purposes.

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.

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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. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2010 was 7.5 percent. The 10-year and 20-year actual returns on U.S. pension plan assets are 4 percent and 10 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $140 million before tax.

Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.

Litigation Contingencies

A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in note 15.

GAAP requires that liabilities for contingencies be recorded when it is probable that a liability has been incurred by the date of the balance sheet and that the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss.

Significant management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a materially adverse effect on operations or financial condition. In the Corporation's experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.

Tax Contingencies

The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.

GAAP requires recognition and measurement of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns. The benefit of an uncertain tax position can only be recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken in an income tax return and the amount recognized in the financial statements. The Corporation's unrecognized tax benefits and a description of open tax years are summarized in note 18.

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 Chemical operations use the local currency, except in countries with a history of high inflation (primarily in Latin America) and 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. Upstream operations using the U.S. dollar as their functional currency are primarily in Asia and Africa.

Factors considered by management when determining the functional currency for a subsidiary include: the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of inflation in the country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.

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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 criteria established in 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, 2010.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation's internal control over financial reporting as of December 31, 2010, as stated in their report included in the Financial Section of this report .

Rex W. Wilson Donald D. Humphreys Patrick T. Mulva
Chief Executive Officer Sr. Vice President and Treasurer Vice President and Controller
(Principal Financial Officer) (Principal Accounting Officer)

REPORT OF INDEPENDENT REGISTRATION PUBLIC ACCOUNTING FIRM

To the Shareholders of Exxon Mobil Corporation:

In our opinion, the accompanying Consolidated Balance Sheets and the related Consolidated Statements of Income, Comprehensive Income, Changes in Equity and Cash Flows present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2010, and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporation's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Dallas, Texas

February 25, 2011

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CONSOLIDATED STATEMENT OF INCOME

Note
Reference
Number
2010 2009 2008
(millions of dollars)

Revenues and other income

Sales and other operating revenue (1)

$ 370,125 $ 301,500 $ 459,579

Income from equity affiliates

6 10,677 7,143 11,081

Other income (2)

2,419 1,943 6,699

Total revenues and other income

$ 383,221 $ 310,586 $ 477,359

Costs and other deductions

Crude oil and product purchases

$ 197,959 $ 152,806 $ 249,454

Production and manufacturing expenses

35,792 33,027 37,905

Selling, general and administrative expenses

14,683 14,735 15,873

Depreciation and depletion

14,760 11,917 12,379

Exploration expenses, including dry holes

2,144 2,021 1,451

Interest expense

259 548 673

Sales-based taxes (1)

18 28,547 25,936 34,508

Other taxes and duties

18 36,118 34,819 41,719

Total costs and other deductions

$ 330,262 $ 275,809 $ 393,962

Income before income taxes

$ 52,959 $ 34,777 $ 83,397

Income taxes

18 21,561 15,119 36,530

Net income including noncontrolling interests

$ 31,398 $ 19,658 $ 46,867

Net income attributable to noncontrolling interests

938 378 1,647

Net income attributable to ExxonMobil

$ 30,460 $ 19,280 $ 45,220

Earnings per common share (dollars)

11 $ 6.24 $ 3.99 $ 8.70

Earnings per common share – assuming dilution (dollars)

11 $ 6.22 $ 3.98 $ 8.66

(1) Sales and other operating revenue includes sales-based taxes of $28,547 million for 2010, $25,936 million for 2009 and $34,508 million for 2008.
(2) Other income for 2008 includes a $62 million gain from the sale of a non-U.S. investment and a related $143 million foreign exchange loss.

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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CONSOLIDATED BALANCE SHEET

Note
Reference
Number
Dec. 31
2010
Dec. 31
2009
(millions of dollars)

Assets

Current assets

Cash and cash equivalents

$ 7,825 $ 10,693

Cash and cash equivalents – restricted

3 628 -  

Marketable securities

2 169

Notes and accounts receivable, less estimated doubtful amounts

5 32,284 27,645

Inventories

Crude oil, products and merchandise

3 9,852 8,718

Materials and supplies

3,124 2,835

Other current assets

5,269 5,175

Total current assets

$ 58,984 $ 55,235

Investments, advances and long-term receivables

7 35,338 31,665

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

8 199,548 139,116

Other assets, including intangibles, net

8,640 7,307

Total assets

$ 302,510 $ 233,323

Liabilities

Current liabilities

Notes and loans payable

5 $ 2,787 $ 2,476

Accounts payable and accrued liabilities

5 50,034 41,275

Income taxes payable

9,812 8,310

Total current liabilities

$ 62,633 $ 52,061

Long-term debt

13 12,227 7,129

Postretirement benefits reserves

16 19,367 17,942

Deferred income tax liabilities

18 35,150 23,148

Other long-term obligations

20,454 17,651

Total liabilities

$ 149,831 $ 117,931

Commitments and contingencies

15

Equity

Common stock without par value

$ 9,371 $ 5,503

(9,000 million shares authorized, 8,019 million shares issued)

Earnings reinvested

298,899 276,937

Accumulated other comprehensive income

Cumulative foreign exchange translation adjustment

5,011 4,402

Postretirement benefits reserves adjustment

(9,889 (9,863

Unrealized gain/(loss) on cash flow hedges

55 -  

Common stock held in treasury (3,040 million shares in 2010 and 3,292 million shares in 2009)

(156,608 (166,410

ExxonMobil share of equity

$ 146,839 $ 110,569

Noncontrolling interests

5,840 4,823

Total equity

152,679 115,392

Total liabilities and equity

$ 302,510 $ 233,323

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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CONSOLIDATED STATEMENT OF CASH FLOWS

Note
Reference
Number
2010 2009 2008
(millions of dollars)

Cash flows from operating activities

Net income including noncontrolling interests

$ 31,398 $ 19,658 $ 46,867

Adjustments for noncash transactions

Depreciation and depletion

14,760 11,917 12,379

Deferred income tax charges/(credits)

(1,135 -   1,399

Postretirement benefits expense in excess of/(less than) net payments

1,700 (1,722 57

Other long-term obligation provisions in excess of/(less than) payments

160 731 (63

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

(596 (483 921

Changes in operational working capital, excluding cash and debt

Reduction/(increase) – Notes and accounts receivable

(5,863 (3,170 8,641

                                   – Inventories

(1,148 459 (1,285

                                   – Other current assets

913 132 (509

Increase/(reduction) – Accounts and other payables

9,943 1,420 (5,415

Net (gain) on asset sales

4 (1,401 (488 (3,757

All other items – net

(318 (16 490

Net cash provided by operating activities

$ 48,413 $ 28,438 $ 59,725

Cash flows from investing activities

Additions to property, plant and equipment

$ (26,871 $ (22,491 $ (19,318

Sales of subsidiaries, investments and property, plant and equipment

4 3,261 1,545 5,985

Decrease/(increase) in restricted cash and cash equivalents

3 (628 -   -  

Additional investments and advances

(1,239 (2,752 (2,495

Collection of advances

1,133 724 574

Additions to marketable securities

(15 (16 (2,113

Sales of marketable securities

155 571 1,868

Net cash used in investing activities

$ (24,204 $ (22,419 $ (15,499

Cash flows from financing activities

Additions to long-term debt

$ 1,143 $ 225 $ 79

Reductions in long-term debt

(6,224 (68 (192

Additions to short-term debt

598 1,336 1,067

Reductions in short-term debt

(2,436 (1,575 (1,624

Additions/(reductions) in debt with three months or less maturity

709 (71 143

Cash dividends to ExxonMobil shareholders

(8,498 (8,023 (8,058

Cash dividends to noncontrolling interests

(281 (280 (375

Changes in noncontrolling interests

(7 (113 (419

Tax benefits related to stock-based awards

122 237 333

Common stock acquired

(13,093 (19,703 (35,734

Common stock sold

1,043 752 753

Net cash used in financing activities

$ (26,924 $ (27,283 $ (44,027

Effects of exchange rate changes on cash

$ (153 $ 520 $ (2,743

Increase/(decrease) in cash and cash equivalents

$ (2,868 $ (20,744 $ (2,544

Cash and cash equivalents at beginning of year

10,693 31,437 33,981

Cash and cash equivalents at end of year

$ 7,825 $ 10,693 $ 31,437

Non-Cash Transactions

The Corporation acquired all the outstanding equity of XTO Energy Inc.

in an all-stock transaction valued at $24,659 million in 2010 (see note 19).

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

ExxonMobil Share of Equity
Common
Stock
Earnings
Reinvested
Accumulated
Other
Comprehensive
Income
Common
Stock
Held  in
Treasury
ExxonMobil
Share of
Equity
Noncontrolling
Interests
Total
Equity

(millions of dollars)

Balance as of December 31, 2007

$ 4,933 $ 228,518 $ 1,989 $ (113,678 $ 121,762 $ 4,282 $ 126,044

Amortization of stock-based awards

618 618 618

Tax benefits related to stock-based awards

315 315 315

Other

(552 (552 (552

Net income for the year

45,220 45,220 1,647 46,867

Dividends – common shares

(8,058 (8,058 (375 (8,433

Foreign exchange translation adjustment

(6,964 (6,964 (334 (7,298

Adjustment for foreign exchange translation loss included in net income

138 138 17 155

Postretirement benefits reserves adjustment (note 16)

(5,853 (5,853 (224 (6,077

Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs (note 16)

759 759 759

Acquisitions, at cost

(35,734 (35,734 (675 (36,409

Dispositions

1,314 1,314 220 1,534

Balance as of December 31, 2008

$ 5,314 $ 265,680 $ (9,931 $ (148,098 $ 112,965 $ 4,558 $ 117,523

Amortization of stock-based awards

685 685 685

Tax benefits related to stock-based awards

140 140 140

Other

(636 (636 (636

Net income for the year

19,280 19,280 378 19,658

Dividends – common shares

(8,023 (8,023 (280 (8,303

Foreign exchange translation adjustment

3,256 3,256 373 3,629

Postretirement benefits reserves adjustment (note 16)

(196 (196 (144 (340

Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs (note 16)

1,410 1,410 51 1,461

Acquisitions, at cost

(19,703 (19,703 (127 (19,830

Dispositions

1,391 1,391 14 1,405

Balance as of December 31, 2009

$ 5,503 $ 276,937 $ (5,461 $ (166,410 $ 110,569 $ 4,823 $ 115,392

Amortization of stock-based awards

751 751 751

Tax benefits related to stock-based awards

280 280 280

Other

(683 (683 10 (673

Net income for the year

30,460 30,460 938 31,398

Dividends – common shares

(8,498 (8,498 (281 (8,779

Foreign exchange translation adjustment

584 584 450 1,034

Adjustment for foreign exchange translation loss included in net income

25 25 25

Postretirement benefits reserves adjustment (note 16)

(1,014 (1,014 (147 (1,161

Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs (note 16)

988 988 52 1,040

Change in fair value of cash flow hedges

184 184 184

Realized (gain)/loss from settled cash flow hedges included in net income

(129 (129 (129

Acquisitions at cost

(13,093 (13,093 (5 (13,098

Issued for XTO merger

3,520 21,139 24,659 24,659

Other dispositions

1,756 1,756 1,756

Balance as of December 31, 2010

$ 9,371 $ 298,899 $ (4,823 $ (156,608 $ 146,839 $ 5,840 $ 152,679

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (continued)

Common Stock Share Activity

Issued Held in
Treasury
Outstanding
(millions of shares)

Balance as of December 31, 2007

8,019 (2,637 5,382

Acquisitions

(434 (434

Dispositions

28 28

Balance as of December 31, 2008

8,019 (3,043 4,976

Acquisitions

(277 (277

Dispositions

28 28

Balance as of December 31, 2009

8,019 (3,292 4,727

Acquisitions

(199 (199

Issued for XTO merger

416 416

Other dispositions

35 35

Balance as of December 31, 2010

8,019 (3,040 4,979

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

2010 2009 2008
(millions of dollars)

Net income including noncontrolling interests

$ 31,398 $ 19,658 $ 46,867

Other comprehensive income (net of income taxes)

Foreign exchange translation adjustment

1,034 3,629 (7,298

Adjustment for foreign exchange translation loss included in net income

25 -   155

Postretirement benefits reserves adjustment (excluding amortization)

(1,161 (340 (6,077

Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs

1,040 1,461 759

Change in fair value of cash flow hedges

184 -   -  

Realized (gain)/ loss from settled cash flow hedges included in net income

(129 -   -  

Comprehensive income including noncontrolling interests

32,391 24,408 34,406

Comprehensive income attributable to noncontrolling interests

1,293 658 1,106

Comprehensive income attributable to ExxonMobil

$ 31,098 $ 23,750 $ 33,300

The information in the Notes to Consolidated Financial Statements is an integral part of these statements.

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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 (Chemical) and participates in electric power generation (Upstream).

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) 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. Prior years' data has been reclassified in certain cases to conform to the 2010 presentation basis.

1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of those 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 certain upstream assets and liabilities.

Amounts representing the Corporation's percentage interest in the underlying net assets of other subsidiaries and less-than-majority-owned companies in which a significant ownership percentage interest is held are included in "Investments, advances and long-term receivables"; the Corporation's share of the net income of these companies is included in the Consolidated Statement of Income caption "Income from equity affiliates." The Corporation's share of the cumulative foreign exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Changes in Equity. Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporation's investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee's business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. In all cases, revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured.

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

Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.

Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs). This gross reporting basis is footnoted on the Consolidated Statement of Income.

Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged 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 that arise from existing assets, liabilities and forecasted transactions. For derivatives designated as cash flow hedges, the Corporation's activity is intended to manage the price risk posed by physical transactions.

The Corporation records all derivatives on the balance sheet at fair value. The change in fair value of derivatives designated as fair value hedges is recognized in earnings, offset by the change in fair value of the hedged item. The change in fair value of derivatives designated as cash flow hedges is recorded in other comprehensive income and recognized in earnings when the hedged transaction is recognized in earnings. The change in fair value of derivatives not designated as hedging instruments is recognized in earnings. Any ineffectiveness between the derivative and the hedged item is recorded in earnings.

Hedge effectiveness is reviewed at least quarterly and is generally based on the most recent relevant correlation between the derivative and the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

item hedged. Hedge ineffectiveness is calculated based on the difference between the change in fair value of the derivative and change in cash flow or fair value of the items hedged. If it is determined that a derivative is no longer highly effective, hedge accounting is then discontinued and the change in fair value since inception that is on the balance sheet either as other comprehensive income for cash flow hedges, or the underlying hedged item for fair value hedges, is recorded in earnings.

Fair Value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.

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). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. 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, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets.

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. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method.

The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense.

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred.

Unit-of-production depreciation is applied to property, plant and equipment, including capitalized exploratory drilling and development costs, associated with productive depletable extractive properties in the Upstream segment. Unit-of-production rates are based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods.

Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Corporation's wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to

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Table of Contents Index to Financial Statements

operate the wells and related equipment; and administrative expenses related to the production activity.

Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Corporation. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

Proved oil and gas 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. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation purposes. Cash flow estimates for impairment testing exclude derivative instruments.

Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. Impairments are measured by the amount the carrying value exceeds the fair value.

Goodwill. Goodwill is the excess of the consideration transferred over the value of net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is evaluated for impairment on at least an annual basis.

Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.

Liabilities for environmental costs 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 Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates. Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.

Stock-Based Payments. The Corporation awards stock-based compensation to employees in the form of restricted stock and restricted stock units. Compensation expense is measured by the market price of the restricted shares at the date of grant and is recognized in the income statement over the requisite service period of each award. See note 14, Incentive Program, for further details.

2. Accounting Changes

Variable-Interest Entities. Effective January 1, 2010, ExxonMobil adopted the authoritative guidance for variable-interest entities (VIEs). The guidance requires the enterprise to qualitatively assess if it is the primary beneficiary of the VIE and, if so, the VIE must be consolidated. The adoption of the guidance did not have a material impact on the Corporation's financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. Miscellaneous Financial Information

Research and development costs totaled $1,012 million in 2010, $1,050 million in 2009 and $847 million in 2008.

Net income included before-tax aggregate foreign exchange transaction losses of $251 million, and gains of $54 million and $54 million in 2010, 2009 and 2008, respectively.

In 2010, 2009 and 2008, net income included gains of $317 million, $207 million and $341 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 $21.3 billion and $17.1 billion at December 31, 2010, and 2009, respectively.

Crude oil, products and merchandise as of year-end 2010 and 2009 consist of the following:

2010 2009
(billions of dollars)

Petroleum products

$ 3.5 $ 3.2

Crude oil

3.8 3.2

Chemical products

2.1 2.0

Gas/other

0.5 0.3

Total

$ 9.9 $ 8.7

The December 31, 2010, total cash and cash equivalents balance of $8,453 million includes $628 million of restricted funds.

4. 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.

The "Net (gain) on asset sales" in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes before-tax gains from the sale of some Upstream Gulf of Mexico and other producing properties, the sale of U.S. service stations and other Downstream assets and investments and the formation of a Chemical joint venture in 2010; from the sale of Downstream assets and investments and producing properties in the Upstream in 2009; and from the sale of a natural gas transportation business in Germany and other producing properties in the Upstream and Downstream assets and investments in 2008. These gains are reported in "Other income" on the Consolidated Statement of Income.

2010 2009 2008
(millions of dollars)

Cash payments for interest

$ 703 $ 820 $ 650

Cash payments for income taxes

$ 18,941 $ 15,427 $ 33,941

5. Additional Working Capital Information

Dec. 31
2010
Dec. 31
2009
(millions of dollars)

Notes and accounts receivable

Trade, less reserves of $152 million and $198 million

$ 25,439 $ 22,186

Other, less reserves of $34 million and $31 million

6,845 5,459

Total

$ 32,284 $ 27,645

Notes and loans payable

Bank loans

$ 532 $ 1,043

Commercial paper

1,346 201

Long-term debt due within one year

345 348

Other

564 884

Total

$ 2,787 $ 2,476

Accounts payable and accrued liabilities

Trade payables

$ 30,780 $ 24,236

Payables to equity companies

5,450 4,979

Accrued taxes other than income taxes

6,778 5,921

Other

7,026 6,139

Total

$ 50,034 $ 41,275

On December 31, 2010, unused credit lines for short-term financing totaled approximately $5.6 billion. Of this total, $2.8 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2010, and 2009, was 1.2 percent and 3.6 percent, respectively.

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6. 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; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several power generation, refining, petrochemical manufacturing and chemical ventures. The Corporation's ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 18 percent, 19 percent and 21 percent in the years 2010, 2009 and 2008, respectively.

2010 2009 2008

Equity Company Financial Summary

Total ExxonMobil
Share
Total ExxonMobil
Share
Total ExxonMobil
Share
(millions of dollars)

Total revenues

$ 153,020 $ 48,355 $ 112,153 $ 36,570 $ 148,477 $ 49,999

Income before income taxes

$ 48,075 $ 14,735 $ 28,472 $ 9,632 $ 42,588 $ 15,082

Income taxes

13,962 4,058 7,775 2,489 12,020 4,001

Income from equity affiliates

$ 34,113 $ 10,677 $ 20,697 $ 7,143 $ 30,568 $ 11,081

Current assets

$ 48,573 $ 15,860 $ 37,376 $ 12,843 $ 29,358 $ 9,920

Long-term assets

90,646 29,805 88,153 27,983 87,442 28,339

Total assets

$ 139,219 $ 45,665 $ 125,529 $ 40,826 $ 116,800 $ 38,259

Current liabilities

$ 33,160 $ 10,260 $ 24,854 $ 8,085 $ 26,221 $ 8,707

Long-term liabilities

59,596 17,976 57,384 16,999 50,895 15,094

Net assets

$ 46,463 $ 17,429 $ 43,291 $ 15,742 $ 39,684 $ 14,458

A list of significant equity companies as of December 31, 2010, together with the Corporation's percentage ownership interest, is detailed below:

Percentage
Ownership
Interest

Upstream

Aera Energy LLC

48

BEB Erdgas und Erdoel GmbH

50

Cameroon Oil Transportation Company S.A.

41

Castle Peak Power Company Limited

60

Golden Pass LNG Terminal LLC

18

Nederlandse Aardolie Maatschappij B.V.

50

Qatar Liquefied Gas Company Limited

10

Qatar Liquefied Gas Company Limited 2

24

Ras Laffan Liquefied Natural Gas Company Limited

25

Ras Laffan Liquefied Natural Gas Company Limited II

31

Ras Laffan Liquefied Natural Gas Company Limited (3)

30

South Hook LNG Terminal Company Limited

24

Tengizchevroil, LLP

25

Terminale GNL Adriatico S.r.l.

69

Downstream

Chalmette Refining, LLC

50

Fujian Refining & Petrochemical Co. Ltd.

25

Saudi Aramco Mobil Refinery Company Ltd.

50

Chemical

Al-Jubail Petrochemical Company

50

Infineum Holdings B.V.

50

Saudi Yanbu Petrochemical Co.

50

Toray Tonen Specialty Separator Godo Kaisha

50

73

Table of Contents Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Investments, Advances and Long-Term Receivables

Dec 31
2010
Dec 31
2009
(millions of dollars)

Companies carried at equity in underlying assets

Investments

$ 17,429 $ 15,742

Advances

9,286 8,669
$ 26,715 $ 24,411

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

1,557 1,577
$ 28,272 $ 25,988

Long-term receivables and miscellaneous investments at cost or less, net of reserves of $292 million and $368 million

7,066 5,677

Total

$ 35,338 $ 31,665

8. Property, Plant and Equipment and Asset Retirement Obligations

Dec. 31, 2010 Dec. 31, 2009

Property, Plant and Equipment

Cost Net Cost Net
(millions of dollars)

Upstream

$ 264,136 $ 148,152 $ 198,036 $ 88,319

Downstream

68,652 30,095 68,092 30,499

Chemical

29,524 14,255 28,464 13,511

Other

11,626 7,046 11,314 6,787

Total

$ 373,938 $ 199,548 $ 305,906 $ 139,116

In the Upstream segment, depreciation is generally on a unit-of production basis, so depreciable life will vary by field. In the Downstream segment, investments in refinery and lubes basestock manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life and service station buildings and fixed improvements over a 20-year life. In the Chemical segment, investments in process equipment are generally depreciated on a straight-line basis over a 20-year life.

Accumulated depreciation and depletion totaled $174,390 million at the end of 2010 and $166,790 million at the end of 2009. Interest capitalized in 2010, 2009 and 2008 was $532 million, $425 million and $510 million, respectively.

Asset Retirement Obligations

The Corporation incurs retirement obligations for its upstream assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The Corporation uses estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; technical assessments of the assets; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. AROs incurred in the current period were Level 3 (unobservable inputs) fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations.

The following table summarizes the activity in the liability for asset retirement obligations:

2010 2009
(millions of dollars)

Beginning balance

$ 8,473 $ 5,352

Accretion expense and other provisions

563 372

Reduction due to property sales

(183 (18

Payments made

(638 (448

Liabilities incurred

1,094 156

Foreign currency translation

(45 535

Revisions

350 2,524

Ending balance

$ 9,614 $ 8,473

74

Table of Contents Index to Financial Statements

9. Accounting for Suspended Exploratory Well Costs

The Corporation continues capitalization of exploratory well costs beyond one year after the well is completed if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project.

The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs.

Change in capitalized suspended exploratory well costs:

2010 2009 2008
(millions of dollars)

Balance beginning at January 1

$ 2,005 $ 1,585 $ 1,291

Additions pending the determination of proved reserves

1,103 624 448

Charged to expense

(104 (51 -  

Reclassifications to wells, facilities and equipment based on the determination of proved reserves

(136 (200 (101

Other

25 47 (53

Ending balance

$ 2,893 $ 2,005 $ 1,585

Ending balance attributed to equity companies included above

$ -   $ 9 $ 10

Period end capitalized suspended exploratory well costs:

2010 2009 2008

(millions of dollars)

Capitalized for a period of one year or less

$ 1,103 $ 624 $ 448

Capitalized for a period of between one and five years

1,294 924 636

Capitalized for a period of between five and ten years

278 220 225

Capitalized for a period of greater than ten years

218 237 276

Capitalized for a period greater than one year – subtotal

$ 1,790 $ 1,381 $ 1,137

Total

$ 2,893 $ 2,005 $ 1,585

Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.

2010 2009 2008

Number of projects with first capitalized well drilled in the preceding 12 months

9 18 12

Number of projects that have exploratory well costs capitalized for a period of greater than 12 months

59 57 50

Total

68 75 62

75

Table of Contents Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Of the 59 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2010, 25 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 34 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 34 projects, which total $692 million.

Country/Project

Dec. 31,
2010
Years Wells
Drilled

Comment

(millions of dollars)

Angola

- Perpetua-Zina-Acacia

$ 15 2008 - 2009 Oil field near Pazflor development, awaiting capacity in existing/planned infrastructure.

Australia

- East Pilchard

10 2001 Gas field near Kipper/Tuna development, awaiting capacity in existing/planned infrastructure.

Indonesia

- Natuna

118 1981 - 1983 Development activity under way, while continuing discussions with the government on contract terms pursuant to recently executed Heads of Agreement.

Kazakhstan

- Kairan

53 2004 - 2007 Declarations involving field commerciality filed with Kazakhstan government in 2008; progressing commercialization and field development studies.

Nigeria

- Bolia

15 2002 - 2006 Evaluating development plan, while continuing discussions with the government regarding regional hub strategy.

- Bonga North

34 2004 - 2009 Pursuing alignment with operator and government regarding development plan.

- Bosi

79 2002 - 2006 Development activity under way while continuing discussions with the government regarding development plan.

- Other (5 projects)

16 2001 - 2002 Pursuing development of several additional offshore satellite discoveries which will tie back to existing/planned production facilities.

Norway

- Gamma

20 2008 - 2009 Evaluating development plan for tieback to existing production facilities.

- H-North

15 2007 Discovery near existing facilities in Fram area; evaluating development options.

- Lavrans

23 1995 - 1999 Development awaiting capacity in existing Kristin production facility; evaluating development concepts for phased ullage scenarios.

- Noatun

19 2008 Evaluating development plan for tieback to existing production facilities.

- Nyk High

20 2008 Evaluating field development alternatives.

- Other (8 projects)

34 1992 - 2009 Evaluating development plans, including potential for tieback to existing production facilities.

Papua New Guinea

- Juha

28 2007 Working on development plans to tie into planned LNG facilities.

United Kingdom

- Fram

55 2009 Progressing development and commercialization plans.

- Other (3 projects)

21 2001 - 2008 Projects primarily awaiting capacity in existing or planned infrastructure.

United States

- Julia Unit

78 2007 - 2008 Julia Unit owners are progressing development plans and have agreed to share funding on facilities at the Chevron-operated Jack-Saint Malo platform. Suspension of Production for the Julia Unit is under review by the Bureau of Ocean Energy Management, Regulation and Enforcement.

- Tip Top

31 2009 Evaluating development concept and requisite facility upgrades.

Other

- Various (2 projects)

8 1979 - 1995 Projects primarily awaiting capacity in existing or planned infrastructure.

Total 2010 (34 projects)

$ 692

76

Table of Contents Index to Financial Statements

10. Leased Facilities

At December 31, 2010, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $7,776 million as indicated in the table. Estimated related rental income from noncancelable subleases is $62 million.

Lease Payments
Under Minimum
Commitments
Related
Sublease Rental
Income
(millions of dollars)

2011

$ 2,095 $ 8

2012

1,570 8

2013

1,061 7

2014

731 6

2015

581 6

2016 and beyond

1,738 27

Total

$ 7,776 $ 62

Net rental cost under both cancelable and noncancelable operating leases incurred during 2010, 2009 and 2008 were as follows:

2010 2009 2008
(millions of dollars)

Rental cost

$ 3,762 $ 4,426 $ 4,115

Less sublease rental income

90 98 123

Net rental cost

$ 3,672 $ 4,328 $ 3,992

11. Earnings Per Share

2010 2009 2008

Earnings per common share

Net income attributable to ExxonMobil (millions of dollars)

$ 30,460 $ 19,280 $ 45,220

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

4,885 4,832 5,194

Earnings per common share (dollars)

$ 6.24 $ 3.99 $ 8.70

Earnings per common share – assuming dilution

Net income attributable to ExxonMobil (millions of dollars)

$ 30,460 $ 19,280 $ 45,220

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

4,885 4,832 5,194

Effect of employee stock-based awards

12 16 27

Weighted average number of common shares outstanding – assuming dilution

4,897 4,848 5,221

Earnings per common share – assuming dilution (dollars)

$ 6.22 $ 3.98 $ 8.66

Dividends paid per common share (dollars)

$ 1.74 $ 1.66 $ 1.55

77

Table of Contents Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. Financial Instruments and Derivatives

Financial Instruments. The fair value of financial instruments is determined by reference to observable market data and other valuation techniques as appropriate. The only category of financial instruments where the difference between fair value and recorded book value is notable is long-term debt. The estimated fair value of total long-term debt, including capitalized lease obligations, was $12.8 billion and $7.7 billion at December 31, 2010, and 2009, respectively, as compared to recorded book values of $12.2 billion and $7.1 billion at December 31, 2010, and 2009, respectively. The fair value hierarchy for long-term debt is primarily Level 1 (quoted prices for identical assets in active markets).

Derivative Instruments. The Corporation's size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation's enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged 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 that arise from existing assets, liabilities and forecasted transactions. For derivatives designated as cash flow hedges, the Corporation's activity is intended to manage the price risk posed by physical transactions.

The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net asset of $172 million at year-end 2010 and a net liability of $5 million at year-end 2009. This is the amount that the Corporation would have received from, or paid to, third parties if these derivatives had been settled in the open market. Assets and liabilities associated with derivatives are predominantly recorded either in "Other current assets" or "Accounts payable and accrued liabilities." The year-end 2010 net asset balance includes the Corporation's outstanding cash flow hedge position, acquired as a result of the XTO merger, of $219 million. As the current cash flow hedge positions settle, these programs will be discontinued.

The Corporation's fair value measurement of its derivative instruments uses primarily Level 2 inputs (derivatives that are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices).

The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $221 million, $(73) million and $154 million during 2010, 2009 and 2008, respectively. Income statement effects associated with derivatives are recorded either in "Sales and other operating revenue" or "Crude oil and product purchases." Of the amount stated above for 2010, cash flow hedges resulted in a before-tax gain of $218 million. The ineffective portion of derivatives designated as hedges is de minimis.

The principal natural gas futures contracts and swap agreements acquired as part of the XTO merger that are in place as of December 31, 2010, will expire by the end of 2011. The associated volume of natural gas is 250 mcfd at a weighted average NYMEX price of $7.02 per thousand cubic feet. These derivative contracts qualify for cash flow hedge accounting. The Corporation will receive the cash flow related to these derivative contracts at the price indicated above. However, the amount of the income statement gain or loss realized from these contracts will be limited to the change in fair value of the derivative instruments from the acquisition date of XTO.

The Corporation believes that there are no material market or credit risks to the Corporation's financial position, results of operations or liquidity as a result of the derivative activities described above. The fair value of derivatives outstanding at year-end 2010 and the gain recognized during the year are immaterial.

78

Table of Contents Index to Financial Statements

13. Long-term Debt

At December 31, 2010, long-term debt consisted of $11,610 million due in U.S. dollars and $617 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 $345 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, 2011, in millions of dollars, are: 2012 – $3,222, 2013 – $1,019, 2014 – $622 and 2015 – $601. At December 31, 2010, the Corporation's unused long-term credit lines were not material.

Summarized long-term debt at year-end 2010 and 2009 are shown in the table below:

2010 2009
(millions of dollars)

SeaRiver Maritime Financial Holdings, Inc. (1)

Guaranteed debt securities due 2011 (2)

$ -   $ 13

Guaranteed deferred interest debentures due 2012
– Face value net of unamortized discount plus accrued interest

2,389 2,144

XTO Energy Inc. (premium in millions of dollars)

7.500% senior note due 2012 includes premium of $15

199 -  

5.900% senior note due 2012 includes premium of $16

233 -  

6.250% senior note due 2013 includes premium of $18

193 -  

4.625% senior note due 2013 includes premium of $9

149 -  

5.750% senior note due 2013 includes premium of $37

359 -  

4.900% senior note due 2014 includes premium of $19

267 -  

5.000% senior note due 2015 includes premium of $13

142 -  

5.300% senior note due 2015 includes premium of $28

262 -  

5.650% senior note due 2016 includes premium of $27

227 -  

6.250% senior note due 2017 includes premium of $80

534 -  

5.500% senior note due 2018 includes premium of $49

420 -  

6.500% senior note due 2018 includes premium of $86

524 -  

6.100% senior note due 2036 includes premium of $29

204 -  

6.750% senior note due 2037 includes premium of $69

329 -  

6.375% senior note due 2038 includes premium of $46

258 -  

Mobil Services (Bahamas) Ltd.

Variable note due 2035 (3)

972 972

Variable note due 2034 (4)

311 311

Mobil Producing Nigeria Unlimited (5)

Variable notes due 2012-2017

415 621

Esso (Thailand) Public Company Ltd. (6)

Variable notes due 2012-2017

522 165

Mobil Corporation

8.625% debentures due 2021

248 248

Industrial revenue bonds due 2012-2040 (7)

2,247 1,685

Other U.S. dollar obligations (8)

454 536

Other foreign currency obligations

65 66

Capitalized lease obligations (9)

304 368

Total long-term debt

$ 12,227 $ 7,129

(1) Additional information is provided for this subsidiary on the following pages.
(2) Average effective interest rate of 1.6% in 2009.
(3) Average effective interest rate of 0.3% in 2010 and 0.3% in 2009.
(4) Average effective interest rate of 0.4% in 2010 and 0.9% in 2009.
(5) Average effective interest rate of 4.6% in 2010 and 5.4% in 2009.
(6) Average effective interest rate of 1.7% in 2010 and 2.2% in 2009.
(7) Average effective interest rate of 0.2% in 2010 and 0.2% in 2009.
(8) Average effective interest rate of 4.7% in 2010 and 5.0% in 2009.
(9) Average imputed interest rate of 8.1% in 2010 and 8.8% in 2009.

79

Table of Contents Index to Financial Statements

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 deferred interest debentures due 2012 ($2,389 million long-term debt at December 31, 2010) and the debt securities due 2011 ($13 million short-term) of SeaRiver Maritime Financial Holdings, Inc.

SeaRiver Maritime Financial Holdings, Inc. is a 100-percent-owned subsidiary of Exxon Mobil Corporation.

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

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

Condensed consolidated statement of income for 12 months ended December 31, 2010

Revenues and other income

Sales and other operating revenue, including sales-based taxes

$ 15,382 $ -   $ 354,743 $ -   $ 370,125

Income from equity affiliates

28,401 (2 10,589 (28,311 10,677

Other income

790 -   1,629 -   2,419

Intercompany revenue

39,433 4 332,483 (371,920 -  

Total revenues and other income

84,006 2 699,444 (400,231 383,221

Costs and other deductions

Crude oil and product purchases

40,788 -   518,961 (361,790 197,959

Production and manufacturing expenses

7,627 -   33,400 (5,235 35,792

Selling, general and administrative expenses

2,871 -   12,482 (670 14,683

Depreciation and depletion

1,761 -   12,999 -   14,760

Exploration expenses, including dry holes

251 -   1,893 -   2,144

Interest expense

217 246 4,035 (4,239 259

Sales-based taxes

-   -   28,547 -   28,547

Other taxes and duties

29 -   36,089 -   36,118

Total costs and other deductions

53,544 246 648,406 (371,934 330,262

Income before income taxes

30,462 (244 51,038 (28,297 52,959

Income taxes

2 (90 21,649 -   21,561

Net income including noncontrolling interests

30,460 (154 29,389 (28,297 31,398

Net income attributable to noncontrolling interests

-   -   938 -   938

Net income attributable to ExxonMobil

$ 30,460 $ (154 $ 28,451 $ (28,297 $ 30,460

80

Table of Contents Index to Financial Statements
Exxon  Mobil
Corporation
Parent
Guarantor
SeaRiver
Maritime
Financial
Holdings, Inc.
All Other
Subsidiaries
Consolidating
and
Eliminating
Adjustments
Consolidated

(millions of dollars)

Condensed consolidated statement of income for 12 months ended December 31, 2009

Revenues and other income

Sales and other operating revenue, including sales-based taxes

$ 11,352 $ -   $ 290,148 $ -   $ 301,500

Income from equity affiliates

19,852 7 7,060 (19,776 7,143

Other income

813 -   1,130 -   1,943

Intercompany revenue

30,889 4 271,663 (302,556 -  

Total revenues and other income

62,906 11 570,001 (322,332 310,586

Costs and other deductions

Crude oil and product purchases

31,419 -   411,689 (290,302 152,806

Production and manufacturing expenses

7,811 -   30,805 (5,589 33,027

Selling, general and administrative expenses

2,574 -   12,852 (691 14,735

Depreciation and depletion

1,571 -   10,346 -   11,917

Exploration expenses, including dry holes

230 -   1,791 -   2,021

Interest expense

1,200 222 5,126 (6,000 548

Sales-based taxes

-   -   25,936 -   25,936

Other taxes and duties

(29 -   34,848 -   34,819

Total costs and other deductions

44,776 222 533,393 (302,582 275,809

Income before income taxes

18,130 (211 36,608 (19,750 34,777

Income taxes

(1,150 (81 16,350 -   15,119

Net income including noncontrolling interests

19,280 (130 20,258 (19,750 19,658

Net income attributable to noncontrolling interests

-   -   378 -   378

Net income attributable to ExxonMobil

$ 19,280 $ (130 $ 19,880 $ (19,750 $ 19,280

Condensed consolidated statement of income for 12 months ended December 31, 2008

Revenues and other income

Sales and other operating revenue, including sales-based taxes

$ 17,481 $ -   $ 442,098 $ -   $ 459,579

Income from equity affiliates

45,664 9 11,055 (45,647 11,081

Other income

302 -   6,397 -   6,699

Intercompany revenue

48,414 45 442,305 (490,764 -  

Total revenues and other income

111,861 54 901,855 (536,411 477,359

Costs and other deductions

Crude oil and product purchases

48,346 -   669,107 (467,999 249,454

Production and manufacturing expenses

8,327 -   35,298 (5,720 37,905

Selling, general and administrative expenses

3,349 -   13,364 (840 15,873

Depreciation and depletion

1,552 -   10,827 -   12,379

Exploration expenses, including dry holes

192 -   1,259 -   1,451

Interest expense

3,859 207 13,143 (16,536 673

Sales-based taxes

-   -   34,508 -   34,508

Other taxes and duties

67 -   41,652 -   41,719

Total costs and other deductions

65,692 207 819,158 (491,095 393,962

Income before income taxes

46,169 (153 82,697 (45,316 83,397

Income taxes

949 (56 35,637 -   36,530

Net income including noncontrolling interests

45,220 (97 47,060 (45,316 46,867

Net income attributable to noncontrolling interests

-   -   1,647 -   1,647

Net income attributable to ExxonMobil

$ 45,220 $ (97 $ 45,413 $ (45,316 $ 45,220

81

Table of Contents Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

Exxon Mobil
Corporation
Parent
Guarantor
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, 2010

Cash and cash equivalents

$ 309 $ -   $ 7,516 $ -   $ 7,825

Cash and cash equivalents – restricted

371 -   257 -   628

Marketable securities

-   -   2 -   2

Notes and accounts receivable – net

2,104 -   30,346 (166 32,284

Inventories

1,457 -   11,519 -   12,976

Other current assets

239 -   5,030 -   5,269

Total current assets

4,480 -   54,670 (166 58,984

Investments, advances and long-term receivables

254,781 446 454,489 (674,378 35,338

Property, plant and equipment – net

18,830 -   180,718 -   199,548

Other long-term assets

224 12 8,404 -   8,640

Intercompany receivables

18,186 2,457 528,405 (549,048 -  

Total assets

$ 296,501 $ 2,915 $ 1,226,686 $ (1,223,592 $ 302,510

Notes and loans payable

$ 1,042 $ 13 $ 1,732 $ -   $ 2,787

Accounts payable and accrued liabilities

2,987 -   47,047 -   50,034

Income taxes payable

-   3 9,975 (166 9,812

Total current liabilities

4,029 16 58,754 (166 62,633

Long-term debt

295 2,389 9,543 -   12,227

Postretirement benefits reserves

9,660 -   9,707 -   19,367

Deferred income tax liabilities

642 107 34,401 -   35,150

Other long-term liabilities

5,632 -   14,822 -   20,454

Intercompany payables

129,404 382 419,262 (549,048 -  

Total liabilities

149,662 2,894 546,489 (549,214 149,831

Earnings reinvested

298,899 (848 132,357 (131,509 298,899

Other equity

(152,060 869 542,000 (542,869 (152,060

ExxonMobil share of equity

146,839 21 674,357 (674,378 146,839

Noncontrolling interests

-   -   5,840 -   5,840

Total equity

146,839 21 680,197 (674,378 152,679

Total liabilities and equity

$ 296,501 $ 2,915 $ 1,226,686 $ (1,223,592 $ 302,510

Condensed consolidated balance sheet for year ended December 31, 2009

Cash and cash equivalents

$ 449 $ -   $ 10,244 $ -   $ 10,693

Marketable securities

-   -   169 -   169

Notes and accounts receivable – net

2,050 -   25,858 (263 27,645

Inventories

1,202 -   10,351 -   11,553

Other current assets

313 -   4,862 -   5,175

Total current assets

4,014 -   51,484 (263 55,235

Investments, advances and long-term receivables

199,110 449 439,712 (607,606 31,665

Property, plant and equipment – net

18,015 -   121,101 -   139,116

Other long-term assets

207 24 7,076 -   7,307

Intercompany receivables

19,637 2,257 442,903 (464,797 -  

Total assets

$ 240,983 $ 2,730 $ 1,062,276 $ (1,072,666 $ 233,323

Notes and loans payable

$ 43 $ 13 $ 2,420 $ -   $ 2,476

Accounts payable and accrued liabilities

2,779 -   38,496 -   41,275

Income taxes payable

-   2 8,571 (263 8,310

Total current liabilities

2,822 15 49,487 (263 52,061

Long-term debt

279 2,157 4,693 -   7,129

Postretirement benefits reserves

8,673 -   9,269 -   17,942

Deferred income tax liabilities

818 151 22,179 -   23,148

Other long-term liabilities

5,286 -   12,365 -   17,651

Intercompany payables

112,536 382 351,879 (464,797 -  

Total liabilities

130,414 2,705 449,872 (465,060 117,931

Earnings reinvested

276,937 (694 109,603 (108,909 276,937

Other equity

(166,368 719 497,978 (498,697 (166,368

ExxonMobil share of equity

110,569 25 607,581 (607,606 110,569

Noncontrolling interests

-   -   4,823 -   4,823

Total equity

110,569 25 612,404 (607,606 115,392

Total liabilities and equity

$ 240,983 $ 2,730 $ 1,062,276 $ (1,072,666 $ 233,323

82

Table of Contents Index to Financial Statements
Exxon  Mobil
Corporation
Parent
Guarantor
SeaRiver
Maritime
Financial
Holdings, Inc
All Other
Subsidiaries
Consolidating
and
Eliminating
Adjustments
Consolidated

(millions of dollars)

Condensed consolidated statement of cash flows for 12 months ended December 31, 2010

Cash provided by/(used in) operating activities

$ 35,740 $ 63 $ 18,307 $ (5,697 $ 48,413

Cash flows from investing activities

Additions to property, plant and equipment

(2,922 -   (23,949 -   (26,871

Sales of long-term assets

1,484 -   1,777 -   3,261

Decrease/(increase) in restricted cash and cash equivalents

(371 -   (257 -   (628

Net intercompany investing

(13,966 (200 13,813 353 -  

All other investing, net

(672 -   706 -   34

Net cash provided by/(used in) investing activities

(16,447 (200 (7,910 353 (24,204

Cash flows from financing activities

Additions to short- and long-term debt

-   -   1,741 -   1,741

Reductions in short- and long-term debt

(3 (13 (8,644 -   (8,660

Additions/(reductions) in debt with three months or less maturity

997 -   (288 -   709

Cash dividends

(8,498 -   (5,697 5,697 (8,498

Common stock acquired

(13,093 -   -   -   (13,093

Net intercompany financing activity

-   -   202 (202 -  

All other financing, net

1,164 150 (286 (151 877

Net cash provided by/(used in) financing activities

(19,433 137 (12,972 5,344 (26,924

Effects of exchange rate changes on cash

-   -   (153 -   (153

Increase/(decrease) in cash and cash equivalents

$ (140 $ -   $ (2,728 $ -   $ (2,868

Condensed consolidated statement of cash flows for 12 months ended December 31, 2009

Cash provided by/(used in) operating activities

$ 27,424 $ 72 $ 28,024 $ (27,082 $ 28,438

Cash flows from investing activities

Additions to property, plant and equipment

(2,686 -   (19,805 -   (22,491

Sales of long-term assets

228 -   1,317 -   1,545

Decrease/(increase) in restricted cash and cash equivalents

-   -   -   -   -  

Net intercompany investing

(1,826 (209 1,717 318 -  

All other investing, net

-   -   (1,473 -   (1,473

Net cash provided by/(used in) investing activities