Edgar Filing: EXXON MOBIL CORP

Form 10-K

Index to Financial Statements

2009

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, 2009

¨ 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 (4,721,273,113 shares outstanding at January 31, 2010)		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, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $69.91 on the New York Stock Exchange composite tape, was in excess of $335 billion.

Documents Incorporated by Reference:

None

Index to Financial Statements

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009

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

Item 4.	Submission of Matters to a Vote of Security Holders	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	33

Item 6.	Selected Financial Data	34

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	34

Item 8.	Financial Statements and Supplementary Data	34

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	35

Item 9A.	Controls and Procedures	35

Item 9B.	Other Information	35

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	36

Item 11.	Executive Compensation	36

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	37

Item 13.	Certain Relationships and Related Transactions, and Director Independence	37

Item 14.	Principal Accounting Fees and Services	38

PART IV

Item 15.	Exhibits, Financial Statement Schedules	38

Financial Section		39

Proxy Information Section		107

Signatures		148

Index to Exhibits		150

Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges

Exhibits 31 and 32 — Certifications

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 December 13, 2009, ExxonMobil and XTO Energy Inc. entered into an Agreement and Plan of Merger. Under the terms of the agreement, (i) each share of XTO Energy common stock will be converted into the right to receive 0.7098 shares of common stock of the Corporation (the “Exchange Ratio”) and (ii) all outstanding XTO Energy options will be converted into options to purchase shares of common stock of the Corporation, with the number of shares of XTO Energy common stock subject to the option, and the option’s exercise price, adjusted based on the Exchange Ratio. The transaction includes XTO Energy debt, which was approximately $10.5 billion at December 31, 2009. Consummation of the Merger is subject to regulatory clearance, XTO Energy stockholder approval, and other customary conditions.

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 2009 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $5.1 billion, of which $2.5 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 2010 and 2011 (with capital expenditures approximately 45 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

Index to Financial Statements

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 2009. For technology licensed to third parties, revenues totaled approximately $88 million in 2009. 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 80.7 thousand, 79.9 thousand and 80.8 thousand at years ended 2009, 2008 and 2007, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 22.0 thousand, 24.8 thousand and 26.3 thousand at years ended 2009, 2008 and 2007, 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. We discuss some of these risks in more detail below.

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.

Index to Financial Statements

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, or natural disasters 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; 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

Index to Financial Statements

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, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive 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.

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 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

Index to Financial Statements

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.

Preparedness. Our operations may be disrupted by severe weather events, natural disasters, 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 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.

Index to Financial Statements

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 2009

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, 2009, 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
	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	1,211	—	—	7,492	2,460
Canada/South America	152	468	691	1,200	1,511
Europe	376	—	—	3,920	1,029
Africa	1,122	—	—	739	1,245
Asia Pacific/Middle East	1,335	—	—	8,351	2,727
Russia/Caspian	86	—	—	318	139

Total Consolidated	4,282	468	691	22,020	9,111
Equity Companies
United States	279	—	—	90	294
Europe	10	—	—	8,862	1,487
Asia Pacific/Middle East	1,053	—	—	16,978	3,883
Russia/Caspian	555	—	—	821	692

Total Equity Company	1,897	—	—	26,751	6,356

Total Developed	6,179	468	691	48,771	15,467
Undeveloped
Consolidated Subsidiaries
United States	405	—	—	4,196	1,104
Canada/South America	20	1,587	—	168	1,635
Europe	111	—	—	803	245
Africa	785	—	—	181	815
Asia Pacific/Middle East	311	—	—	6,665	1,422
Russia/Caspian	555	—	—	409	623

Total Consolidated	2,187	1,587	—	12,422	5,844
Equity Companies
United States	77	—	—	24	81
Europe	20	—	—	2,588	451
Asia Pacific/Middle East	195	—	—	3,595	794
Russia/Caspian	247	—	—	607	348

Total Equity Company	539	—	—	6,814	1,674

Total Undeveloped	2,726	1,587	—	19,236	7,518

Total Proved Reserves	8,905	2,055	691	68,007	22,985

(1)

Liquids includes crude, condensate and natural gas liquids.

Index to Financial Statements

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 2010-2014. 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 2009

Additions to ExxonMobil’s proved reserves in 2009 were based on estimates generated through the integration of available and appropriate 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. 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.

Index to Financial Statements

The Reserves Technical Oversight group maintains a central computerized database containing the official company global reserves estimates and production data. 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 2009, approximately 7.5 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped, which represented 33 percent of the 23.0 GOEB reported in proved reserves. This compares to 38 percent proved undeveloped reported at the end of 2008. The net reduction from 2008 is reflective of our active development programs on many projects worldwide. This percentage is inclusive of both consolidated subsidiaries and equity company reserves. Significant progress was made in converting proved undeveloped reserves into proved developed reserves in 2009. During the year, ExxonMobil completed development work in over 100 fields and participated in numerous major project start-ups that resulted in the transfer of approximately 2.4 GOEB from proved undeveloped to proved developed reserves by year-end. This represented the movement of 28 percent of the proved undeveloped reserves into the proved developed category or an average turnover time of about four years. The largest transfers were associated with two liquefied natural gas (LNG) trains and the second phase of a domestic gas supply project 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 2009, new approved projects added approximately 1.3 GOEB of proved undeveloped reserves. The largest of these were the Gorgon LNG project in Australia and the Papua New Guinea LNG project. Overall, investments of $12.7 billion were made by the Corporation during 2009 to progress the development of reported proved undeveloped reserves, including $11.6 billion for oil and gas producing activities and an additional $1.1 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 61 percent of the $20.7 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in the United States, Kazakhstan, Qatar, Nigeria, Netherlands and Canada have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure and the pace of co-venturers/Government funding, as well as the time required to develop and complete the 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. The two largest projects that have been reported with proved undeveloped reserves for five or more years

Index to Financial Statements

are in Qatar and Kazakhstan. In Qatar, the construction of the Ras Laffan 3 Train 7 LNG liquefaction train is now complete. In Kazakhstan, ExxonMobil participates in the North Caspian Production Sharing Agreement, which includes the giant Kashagan field located offshore in the Caspian Sea. Phase 1 of the Kashagan field is currently under construction and includes an offshore production and separation hub on an artificial island, several drilling islands, three onshore oil-stabilization trains, two onshore gas treatment plants and an onshore sulfur treatment plant. ExxonMobil also participates in the Tengizchevroil joint venture in Kazakhstan 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.

Index to Financial Statements

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.


	2009	2008	2007
	(thousands of barrels daily)
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States	311	289	310
Canada/South America	82	106	129
Europe	374	423	474
Africa	685	652	717
Asia Pacific/Middle East	286	313	328
Russia/Caspian	66	73	110

Total Consolidated Subsidiaries	1,804	1,856	2,068

Equity Companies
United States	73	78	82
Europe	5	5	6
Asia Pacific/Middle East	204	193	190
Russia/Caspian	116	87	75

Total Equity Companies	398	363	353


Total crude oil and natural gas liquids production	2,202	2,219	2,421

Bitumen production
Consolidated Subsidiaries
Canada/South America	120	124	130

Synthetic oil production
Consolidated Subsidiaries
Canada/South America	65	62	65

Total liquids production	2,387	2,405	2,616


	(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States	1,274	1,245	1,467
Canada/South America	643	640	808
Europe	2,071	2,253	2,307
Africa	19	32	26
Asia Pacific/Middle East	1,691	1,758	1,890
Russia/Caspian	38	37	31

Total Consolidated Subsidiaries	5,736	5,965	6,529

Equity Companies
United States	1	1	1
Europe	1,618	1,696	1,503
Asia Pacific/Middle East	1,803	1,356	1,272
Russia/Caspian	115	77	79

Total Equity Companies	3,537	3,130	2,855


Total natural gas production available for sale	9,273	9,095	9,384


	(thousands of oil-equivalent barrels daily)

Oil-equivalent production	3,932	3,921	4,180

Index to Financial Statements

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.


	United States		Canada/ S. America		Europe		Africa		Asia Pacific/ Middle East		Russia/ Caspian		Total
	United States		Canada/ S. America		Europe		Africa		Asia Pacific/ Middle East		Russia/ Caspian		Total
During 2009
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel	$	53.43	$	54.07	$	56.88	$	60.10	$	59.58	$	58.42	$	57.86
Natural gas, per thousand cubic feet		3.10		3.19		5.61		1.70		3.08		2.11		4.00
Bitumen, per barrel		—		45.22		—		—		—		—		45.22
Synthetic oil, per barrel		—		61.26		—		—		—		—		61.26
Average production costs, per barrel - total		11.80		17.75		10.19		8.07		6.89		7.84		10.25
Average production costs, per barrel - bitumen		—		14.77		—		—		—		—		14.77

Equity Companies
Average production prices
Crude oil and NGL, per barrel		56.54		—		58.20		—		60.10		49.09		56.22
Natural gas, per thousand cubic feet		5.75		—		8.20		—		3.94		1.41		5.81
Average production costs, per barrel - total		18.07		—		2.48		—		0.49		3.23		2.72

Total
Average production prices
Crude oil and NGL, per barrel		54.02		54.07		56.89		60.10		59.79		52.46		57.56
Natural gas, per thousand cubic feet		3.10		3.19		6.74		1.70		3.52		1.58		4.69
Bitumen, per barrel		—		45.22		—		—		—		—		45.22
Synthetic oil, per barrel		—		61.26		—		—		—		—		61.26
Average production costs, per barrel - total		12.57		17.75		8.06		8.07		3.88		4.83		8.36
Average production costs, per barrel - bitumen		—		14.77		—		—		—		—		14.77

During 2008
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel	$	87.41	$	89.46	$	89.65	$	92.69	$	92.28	$	94.20	$	90.96
Natural gas, per thousand cubic feet		7.22		7.82		10.12		3.33		4.55		2.08		7.54
Bitumen, per barrel		—		65.45		—		—		—		—		65.45
Synthetic oil, per barrel		—		100.35		—		—		—		—		100.35
Average production costs, per barrel - total		11.80		18.03		8.97		6.66		5.19		9.64		9.38
Average production costs, per barrel - bitumen		—		19.55		—		—		—		—		19.55

Equity Companies
Average production prices
Crude oil and NGL, per barrel		89.94		—		85.08		—		94.21		84.14		90.80
Natural gas, per thousand cubic feet		13.97		—		11.09		—		8.86		1.38		9.89
Average production costs, per barrel - total		18.55		—		4.06		—		0.75		4.83		3.86

Total
Average production prices
Crude oil and NGL, per barrel		87.95		89.46		89.59		92.69		93.01		89.06		90.93
Natural gas, per thousand cubic feet		7.23		7.82		10.54		3.33		6.43		1.61		8.35
Bitumen, per barrel		—		65.45		—		—		—		—		65.45
Synthetic oil, per barrel		—		100.35		—		—		—		—		100.35
Average production costs, per barrel - total		12.72		18.03		7.67		6.66		3.38		6.96		8.14
Average production costs, per barrel - bitumen		—		19.55		—		—		—		—		19.55

Index to Financial Statements


	United States		Canada/ S. America		Europe		Africa		Asia Pacific/ Middle East		Russia/ Caspian		Total
During 2007	United States		Canada/ S. America		Europe		Africa		Asia Pacific/ Middle East		Russia/ Caspian		Total
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel	$	62.35	$	64.10	$	68.01	$	70.00	$	69.58	$	69.15	$	67.89
Natural gas, per thousand cubic feet		5.93		5.77		6.22		2.26		3.54		1.79		5.29
Bitumen, per barrel		—		36.63		—		—		—		—		36.63
Synthetic oil, per barrel		—		74.79		—		—		—		—		74.79
Average production costs, per barrel - total		9.03		13.17		9.12		4.48		4.09		5.79		7.58
Average production costs, per barrel - bitumen		—		13.26		—		—		—		—		13.26

Equity Companies
Average production prices
Crude oil and NGL, per barrel		64.79		—		73.23		—		71.91		63.60		68.51
Natural gas, per thousand cubic feet		10.44		—		8.52		—		5.76		0.90		7.08
Average production costs, per barrel - total		14.95		—		4.10		—		0.58		4.34		3.49

Total
Average production prices
Crude oil and NGL, per barrel		62.86		64.10		68.08		70.00		70.44		66.89		67.98
Natural gas, per thousand cubic feet		5.93		5.77		7.13		2.26		4.43		1.15		5.83
Bitumen, per barrel		—		36.63		—		—		—		—		36.63
Synthetic oil, per barrel		—		74.79		—		—		—		—		74.79
Average production costs, per barrel - total		9.80		13.17		7.97		4.48		2.74		5.16		6.77
Average production costs, per barrel - bitumen		—		13.26		—		—		—		—		13.26

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.

Index to Financial Statements

4. Drilling and Other Exploratory and Development Activities

A. Number of Net Productive and Dry Wells Drilled


	2009	2008	2007
Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States	10	10	12
Canada/South America	4	—	1
Europe	2	3	—
Africa	2	3	2
Asia Pacific/Middle East	1	2	1
Russia/Caspian	—	—	1

Total Consolidated Subsidiaries	19	18	17

Equity Companies
United States	—	—	—
Europe	1	1	2
Asia Pacific/Middle East	—	—	—
Russia/Caspian	—	—	—

Total Equity Companies	1	1	2

Total productive exploratory wells drilled	20	19	19

Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States	1	3	8
Canada/South America	—	—	1
Europe	4	2	2
Africa	3	2	4
Asia Pacific/Middle East	1	1	1
Russia/Caspian	—	—	—

Total Consolidated Subsidiaries	9	8	16

Equity Companies
United States	—	—	—
Europe	—	—	—
Asia Pacific/Middle East	—	1	—
Russia/Caspian	—	—	—

Total Equity Companies	—	1	—

Total dry exploratory wells drilled	9	9	16

Index to Financial Statements


	2009	2008	2007
Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States	165	105	118
Canada/South America	291	223	377
Europe	10	8	15
Africa	45	39	43
Asia Pacific/Middle East	13	14	18
Russia/Caspian	3	5	3

Total Consolidated Subsidiaries	527	394	574

Equity Companies
United States	287	321	333
Europe	1	2	1
Asia Pacific/Middle East	14	14	8
Russia/Caspian	—	—	1

Total Equity Companies	302	337	343

Total productive development wells drilled	829	731	917

Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States	3	3	15
Canada/South America	—	1	—
Europe	1	—	3
Africa	—	—	1
Asia Pacific/Middle East	1	—	—
Russia/Caspian	—	—	—

Total Consolidated Subsidiaries	5	4	19

Equity Companies
United States	—	—	—
Europe	—	—	—
Asia Pacific/Middle East	—	—	—
Russia/Caspian	—	—	—

Total Equity Companies	—	—	—

Total dry development wells drilled	5	4	19

Total number of net wells drilled	863	763	971

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. The Syncrude operation, located near Fort McMurray, Alberta, Canada, mines a portion of the Athabasca oil sands deposit. Syncrude joint venture owners hold eight oil sands leases covering about 250,000 acres in the Athabasca oil sands deposit. Since startup in 1978, Syncrude has produced about 2.0 billion barrels of synthetic crude oil. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta, by Alberta Oil Sands Pipeline Ltd. In 2009, Syncrude’s net production of synthetic crude oil was about 259,000 barrels per day and gross production was about 280,000 barrels per day. The company’s share of net production in 2009 was about 65,000 barrels per day. There are no approved plans for major future expansion projects.

Kearl Project

The Kearl oil sands 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. The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada.

Kearl is expected to be developed in 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.

The Kearl project received approvals from the Province of Alberta in 2007 and the Government of Canada in 2008. The Province of Alberta issued an operating and construction license in 2008, which permits the project to mine oil sands and produce bitumen from approved development areas on oil sands leases. Kearl is comprised of six oil sands leases covering about 48,000 acres in the Athabasca oil sands deposit.

Production from the first phase is expected to be at an initial rate of approximately 110,000 gross barrels of bitumen a day. About $2 billion has been spent on the project through 2009. In 2009, pipeline transportation agreements were concluded, infrastructure construction continued and more than half of the detailed engineering was completed.

Index to Financial Statements

5. Present Activities

A. Wells Drilling


	Year-end 2009		Year-end 2008
	Gross	Net	Gross	Net
Wells Drilling
Consolidated Subsidiaries
United States	185	146	201	136
Canada/South America	83	57	297	173
Europe	20	4	27	7
Africa	24	8	19	7
Asia Pacific/Middle East	6	3	5	2
Russia/Caspian	18	3	25	4

Total Consolidated Subsidiaries	336	221	574	329

Equity Companies
United States	10	5	2	1
Europe	16	5	1	—
Asia Pacific/Middle East	5	—	17	9
Russia/Caspian	—	—	—	—

Total Equity Companies	31	10	20	10

Total gross and net wells drilling	367	231	594	339

B. Review of Principal Ongoing Activities

During 2009, ExxonMobil’s activities were conducted, either directly or through affiliated companies, by ExxonMobil Exploration Company (for exploration), by ExxonMobil Development Company (for large development activities), by ExxonMobil Production Company (for producing and smaller development activities) and by ExxonMobil Gas & Power Marketing Company (for gas marketing). During this same period, some of ExxonMobil’s exploration, development, production and gas marketing activities were also conducted in Canada by Imperial Oil Limited, which is 69.6 percent owned by ExxonMobil.

UNITED STATES

ExxonMobil’s year-end 2009 acreage holdings totaled 10.2 million net acres, of which 2.3 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During 2009, 435.2 net exploration and development wells were completed in the inland lower 48 states and 2.0 net development wells were completed offshore in the Pacific. Tight gas development continued in the Piceance Basin of Colorado as the Piceance Phase 1 tight gas project came onstream in 2009. Participation in Alaska production and development continued and a total of 22.5 net development wells were drilled. On Alaska’s North Slope, activity continued on the Western Region Development with development drilling and facility upgrades.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2009 was 2.2 million acres. A total of 6.0 net exploration and development wells were completed during the year. In 2009, the Rockefeller field was brought onstream.

Construction of the Golden Pass LNG regasification terminal in Texas continued in 2009. The terminal will have the capacity to deliver up to two billion cubic feet of gas per day.

Index to Financial Statements

CANADA / SOUTH AMERICA

Canada

Oil and Gas Operations

ExxonMobil’s year-end 2009 acreage holdings totaled 6.8 million net acres, of which 3.1 million net acres were offshore. A total of 234.0 net exploration and development wells were completed during the year.

In Situ Bitumen Operations

ExxonMobil’s year-end 2009 in situ bitumen acreage holdings totaled 0.6 million net onshore acres. A total of 60.0 net development wells were completed during the year. The only current in situ bitumen production comes from the Cold Lake field. To maintain production at Cold Lake, additional production wells and associated facilities are required periodically. In 2009, a development drilling program began within the approved development area to add additional productive capacity from undeveloped areas.

Argentina

ExxonMobil’s net acreage totaled 0.2 million onshore acres at year-end 2009, and there were 1.8 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 4.9 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2009, with 3.6 net exploration and development wells drilled during the year.

Italy

The Adriatic LNG regasification terminal received its first cargo and commenced regasification operations in 2009. The terminal can supply up to 775 million cubic feet of gas per day to the Italian gas market.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.4 million acres at year-end 2009, of which 1.2 million acres are onshore. A total of 2.5 net exploration and development wells were completed during the year. The multi-year project to renovate Groningen production clusters, install new compression to maintain capacity and extend field life was completed and the project to redevelop the Schoonebeek oil field was progressed.

Norway

ExxonMobil’s net interest in licenses at year-end 2009 totaled approximately 0.7 million acres, all offshore. ExxonMobil participated in 6.6 net exploration and development well completions in 2009. Production was initiated at the Tyrihans field.

Index to Financial Statements

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2009 totaled approximately 0.4 million acres, all offshore. A total of 3.7 net exploration and development wells were completed during the year including the successful Fram appraisal.

The South Hook LNG regasification terminal in Wales commenced operations in 2009 and received its first deliveries. The terminal has the capacity to deliver up to 2.1 billion cubic feet of gas per day into the natural gas grid.

AFRICA

Angola

ExxonMobil’s year-end 2009 acreage holdings totaled 0.7 million net offshore acres and 7.9 net exploration and development wells were completed during the year. On Block 15, development drilling continued at Kizomba A, Kizomba B and Kizomba C. Project work continued on the Angola Gas Gathering project and the Kizomba Satellites Phase 1 project in 2009. On the non-operated Block 17, project work continued on the Pazflor project and development drilling continued at Dalia. On the non-operated Block 31, project work continued on the Plutao-Saturno-Venus-Marte project.

Cameroon

ExxonMobil’s net acreage holdings totaled 0.1 million offshore acres.

Chad

ExxonMobil’s net year-end 2009 acreage holdings consisted of 0.1 million onshore acres, with 34.4 net development wells completed during the year. Production began from the Timbre field in 2009.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.1 million net offshore acres at year-end 2009.

Nigeria

ExxonMobil’s net acreage totaled 1.0 million offshore acres at year-end 2009, with 6.7 net exploration and development wells completed during the year. Work continued on the deepwater Usan project in 2009. Projects to replace crude oil pipelines and to reduce flaring were progressed. A 3-D seismic acquisition program continued on the Nigerian Shelf joint venture acreage and a 4-D seismic survey was completed at the Erha field.

ASIA PACIFIC / MIDDLE EAST

Australia

ExxonMobil’s net year-end 2009 offshore acreage holdings totaled 1.9 million acres. During 2009, a total of 7.6 net exploration and development wells were drilled. Work continued on the Kipper/Tuna gas project and Turrum Phase 2 development. The Gorgon liquefied natural gas project was approved for development in 2009.

Indonesia

At year-end 2009, ExxonMobil had 5.4 million net acres, including 4.3 million net acres offshore and 1.1 million net acres onshore. A total of 0.8 net exploration wells were completed during the year. During 2009, early oil production commenced at the Banyu Urip field in the Cepu contract area. A new deepwater block was acquired in 2009 as well as three coalbed methane production sharing contracts.

Index to Financial Statements

Japan

ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2009.

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2009. In 2009, a new production sharing contract was signed with PETRONAS and PETRONAS Carigali. During the year, a total of 5.0 net development wells were completed.

Papua New Guinea

A total of 0.4 million net onshore acres were held by ExxonMobil at year-end 2009, with 1.1 net development wells completed during the year. In 2009, all co-venturers agreed to proceed with the development of the Papua New Guinea liquefied natural gas project.

Qatar

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

Qatar Liquefied Gas Company Limited — (QG I)

Qatar Liquefied Gas Company Limited (2) — (QG 2)

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

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

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

In addition, the Al Khaleej Gas (AKG) project supplied pipeline gas to domestic industrial customers. With the initial start-up of AKG Phase 2 in December 2009, the AKG facilities provide sales gas capacity of up to 2 billion cubic feet per day with associated condensate, ethane and liquid petroleum gas.

At the end of 2009, with the conclusion of the drilling program for the RL 3 and AKG 2 projects, 136 gross wells supplied natural gas to currently-producing LNG and pipeline gas sales facilities. During 2009, 8.9 net development wells were completed.

Total Qatar LNG capacity volumes (gross) at year-end 2009 was 53.8 MTA (millions of metric tons per annum), with the start up in 2009 of QG 2 trains 4 and 5 as well as the start-up of RL 3 train 6. Capacity consists of 9.7 MTA in QG I trains 1-3, a combined 20.7 MTA in RL I trains 1-2 and RL II trains 3-5, 15.6 MTA in QG 2 trains 4-5 and 7.8 MTA in RL 3 train 6 . In addition, RL 3 train 7 will add planned capacity of 7.8 MTA when completed.

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

Republic of Yemen

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2009.

Index to Financial Statements

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2009.

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi oil concessions was 0.6 million acres at year-end 2009, of which 0.4 million acres were onshore and 0.2 million acres offshore. During the year, 6.0 net development wells were completed. During 2009, work progressed on multiple field development projects, both onshore and offshore, to sustain and increase oil production capacity.

RUSSIA/CASPIAN

Azerbaijan

At year-end 2009, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 0.1 million acres. At the Azeri-Chirag-Gunashli field, 0.7 net development wells were completed.

Kazakhstan

ExxonMobil’s net acreage totaled 0.2 million acres onshore and 0.2 million acres offshore at year-end 2009, with 1.2 net exploration and development wells completed during 2009. Production continued to increase as a result of the latest Tengiz expansion that came onstream in 2008. Construction of the initial phase of the Kashagan field continued during 2009.

Russia

ExxonMobil’s net acreage holdings at year-end 2009 were 0.1 million acres, all offshore. A total of 0.6 net development wells were completed in the Chayvo field during the year. Development of the initial phase of the Odoptu field is underway with the construction of field separation facilities, a flowline to the Chayvo onshore processing plant and completion of 0.6 net development wells.

WORLDWIDE EXPLORATION

At year-end 2009, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 49.1 million net acres were held at year-end 2009, and 3.8 net exploration wells were completed during the year in these countries.

Index to Financial Statements

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

A. Gross and Net Productive Wells


	Year-end 2009				Year-end 2008
	Oil		Gas		Oil		Gas
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Gross and Net Productive Wells
Consolidated Subsidiaries
United States	15,606	4,821	9,261	5,645	15,275	4,588	9,084	5,511
Canada/South America	5,357	4,828	6,728	3,408	5,527	5,007	6,189	3,189
Europe	1,395	389	649	292	1,318	377	618	282
Africa	1,081	432	13	5	943	381	14	6
Asia Pacific/Middle East	1,380	507	238	183	1,345	484	229	179
Russia/Caspian	93	15	—	—	74	12	—	—

Total Consolidated Subsidiaries	24,912	10,992	16,889	9,533	24,482	10,849	16,134	9,167
Equity Companies
United States	11,592	5,452	8	4	11,972	5,598	8	4
Europe	27	14	576	187	27	14	599	196
Asia Pacific/Middle East	775	74	126	36	837	80	84	20
Russia/Caspian	98	24	—	—	68	17	—	—

Total Equity Companies	12,492	5,564	710	227	12,904	5,709	691	220

Total gross and net productive wells	37,404	16,556	17,599	9,760	37,386	16,558	16,825	9,387

There were 16,587 gross and 13,737 net operated wells at year-end 2009 and 16,286 gross and 13,573 net operated wells at year-end 2008. In 2009, 1,039 gross wells had multiple completions.

B. Gross and Net Developed Acreage


	Year-end 2009		Year-end 2008
	Gross	Net	Gross		Net
	(thousands of acres)
Gross and Net Developed Acreage
Consolidated Subsidiaries
United States	9,866	5,061	8,526		5,075
Canada/South America	5,570	2,460	5,558	*	2,488	*
Europe	5,359	2,454	5,976		2,682
Africa	1,958	758	1,958		756
Asia Pacific/Middle East	3,031	1,210	2,814		1,120
Russia/Caspian	151	21	151		21

Total Consolidated Subsidiaries	25,935	11,964	24,983		12,142
Equity Companies
United States	165	59	220		73
Europe	4,325	1,352	4,196		1,344
Asia Pacific/Middle East	5,437	553	5,347		531
Russia/Caspian	380	95	380		95

Total Equity Companies	10,307	2,059	10,143		2,043


Total gross and net developed acreage	36,242	14,023	35,126		14,185

Revised to include oil sands mining acreage.

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

Index to Financial Statements

C. Gross and Net Undeveloped Acreage


	Year-end 2009		Year-end 2008
	Gross	Net	Gross		Net
	(thousands of acres)
Gross and Net Undeveloped Acreage
Consolidated Subsidiaries
United States	7,650	5,034	8,818		5,600
Canada/South America	26,074	17,107	33,016	*	19,953	*
Europe	25,420	13,462	16,464		7,844
Africa	15,768	10,555	40,440		26,439
Asia Pacific/Middle East	33,384	25,260	18,609		12,168
Russia/Caspian	1,964	356	1,724		315

Total Consolidated Subsidiaries	110,260	71,774	119,071		72,319
Equity Companies
United States	208	77	246		91
Europe	53	8	411		69
Asia Pacific/Middle East	—	—	90		22
Russia/Caspian	228	57	228		57

Total Equity Companies	489	142	975		239

Total gross and net undeveloped acreage	110,749	71,916	120,046		72,558

Revised to include oil sands mining acreage.

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

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 completing specified work. Production leases are held as long as there is production on the lease. The majority of Cold Lake leases were taken for an initial 21-year term in 1968-1969 and renewed for a second 21-year term in 1989-1990. The exploration acreage in eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.

Index to Financial Statements

Argentina

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

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 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

Index to Financial Statements

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. ExxonMobil’s licenses issued in 2005 as part of the 23rd licensing round have an initial term of four years with a second term extension of four years and a final term of 18 years. There is 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.

Cameroon

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

Chad

Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended at the discretion of the government. In May 2007, Chad enacted a new Petroleum Code which would govern new acquisitions.

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.

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-

Index to Financial Statements

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 PACIFIC / MIDDLE EAST

Australia

Exploration and production activities are conducted offshore and 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 (if no operations for the recovery of petroleum have been carried on for five years, the license may be terminated). Effective from July 1998, new production licenses are granted “indefinitely”.

Indonesia

Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract, negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. Formerly this activity was carried out by Pertamina, the government owned oil company, which is now a competing limited liability company.

Japan

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

Malaysia

Exploration and production activities are governed by seven production sharing contracts (PSCs) negotiated with the national oil company, three governing exploration and production activities and four governing production activities only. 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

Index to Financial Statements

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.

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.

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.

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 oilfields 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 1, 2006, for a term expiring March 9, 2026, on fiscal terms consistent with the Company’s existing interests in Abu Dhabi.

Index to Financial Statements

RUSSIA/CASPIAN

Azerbaijan

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

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

Kazakhstan

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

Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period was 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.

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.

Index to Financial Statements

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 2009 ⁽¹⁾


		ExxonMobil Share KBD (2)	ExxonMobil Interest %
United States
Torrance	California	150	100
Joliet	Illinois	238	100
Baton Rouge	Louisiana	504	100
Baytown	Texas	576	100
Beaumont	Texas	345	100
Other (2 refineries)		157

Total United States		1,970

Canada
Strathcona	Alberta	187	69.6
Dartmouth	Nova Scotia	82	69.6
Nanticoke	Ontario	112	69.6
Sarnia	Ontario	121	69.6

Total Canada		502

Europe
Antwerp	Belgium	305	100
Fos-sur-Mer	France	119	82.9
Port-Jerome-Gravenchon	France	233	82.9
Augusta	Italy	198	100
Trecate	Italy	174	75.4
Rotterdam	Netherlands	191	100
Slagen	Norway	116	100
Fawley	United Kingdom	329	100
Other (2 refineries)		78

Total Europe		1,743

Asia Pacific
Kawasaki	Japan	296	50
Sakai	Japan	139	50
Wakayama	Japan	160	50
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		6,271

(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.

Index to Financial Statements

The marketing operations sell products and services throughout the world. Our Exxon, Esso and Mobil brands serve customers at nearly 28,000 retail service stations.

Retail Sites Year-End 2009


United States
Owned/leased		1,921
Distributors/resellers		8,295

Total United States		10,216

Canada
Owned/leased		518
Distributors/resellers		1,326

Total Canada		1,844

Europe
Owned/leased		4,153
Distributors/resellers		2,674

Total Europe		6,827

Asia Pacific
Owned/leased		2,305
Distributors/resellers		3,960

Total Asia Pacific		6,265

Latin America
Owned/leased		587
Distributors/resellers		1,350

Total Latin America		1,937

Middle East/Africa
Owned/leased		481
Distributors/resellers		150

Total Middle East/Africa		631

Worldwide
Owned/leased		9,965
Distributors/resellers		17,755

Total worldwide		27,720

Index to Financial Statements

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 2009 ⁽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⁾
Fawley	United Kingdom	0.1	—	—	—	100
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		1.4	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		8.9	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%.

Index to Financial Statements

Item 3. Legal Proceedings.

As reported in the Corporation’s Form 10-Q for the third quarter of 2009, in September 2009, two shareholders filed purported shareholder derivative petitions, which have been consolidated and captioned In re Exxon Mobil, Corp. Derivative Litigation, in the District Court of Dallas County, Texas, naming certain current and former directors as defendants and ExxonMobil as a nominal defendant. The petitions claim that the individual defendants breached their fiduciary duties by, among other things, allegedly failing to properly supervise the management of land leases overlaying hydrocarbon resources in the Point Thomson Unit on the Northern Slope of Alaska. The petitions also allege that the individual defendants caused the company to make materially false and misleading statements concerning the leases and caused the waste of corporate assets. The petitions seek damages from the individual defendants in favor of ExxonMobil, equitable relief to remedy their alleged breaches, and costs and expenses of the action. The defendants have filed pleadings with the court seeking dismissal of both cases for failure to make a demand on the Corporation and failure to plead particularized facts to excuse a demand.

As reported in the Corporation’s Form 10-Q for the third quarter of 2009, 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 present directors, 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 also alleges, on behalf of the Corporation, that these acts injured the company, breached fiduciary duties and constituted waste. 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 from the individual defendants in favor of ExxonMobil, and costs and expenses of the action. The defendants plan to file a motion seeking dismissal of the lawsuit.

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.

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

None.

Index to Financial Statements

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


Name	Age as of March 1, 2010	Title (Held Office Since)
R. W. Tillerson	57	Chairman of the Board (2006)
M. W. Albers	53	Senior Vice President (2007)
M. J. Dolan	56	Senior Vice President (2008)
D. D. Humphreys	62	Senior Vice President (2006) and Treasurer (2004)
A. P. Swiger	53	Senior Vice President (2009)
S. J. Balagia	58	Vice President and General Counsel (Effective March 1, 2010)
A. T. Cejka	58	Vice President (2004)
W. M. Colton	56	Vice President - Strategic Planning (2009)
H. R. Cramer	59	Vice President (1999)
N. W. Duffin	53	President, ExxonMobil Development Company (2007)
R. S. Franklin	52	Vice President (2009)
S. J. Glass, Jr.	62	Vice President (2008)
A. J. Kelly	52	Vice President (2007)
R. M. Kruger	50	Vice President (2008)
P. T. Mulva	58	Vice President and Controller (2004)
S. D. Pryor	60	Vice President (2004)
D. S. Rosenthal	53	Vice President - Investor Relations and Secretary (2008)
J. M. Spellings	48	Vice President and General Tax Counsel (Effective March 1, 2010)
T. R. Walters	55	Vice President (2009)

For at least the past five years, Messrs. Cejka, Cramer, Dolan, Humphreys, Mulva, Pryor and Tillerson have been employed as executives of the registrant. Mr. Tillerson was a Senior Vice President and then President, a title he continues to hold, before becoming Chairman of the Board. Mr. Albers was President of ExxonMobil Development Company before becoming Senior Vice President. Mr. Dolan was President of ExxonMobil Chemical Company before becoming Senior Vice President. Mr. Humphreys was Vice President and Controller and then Vice President and Treasurer before becoming Senior Vice President and Treasurer. Mr. Balagia was Assistant General Counsel before becoming Vice President and General Counsel. Mr. Colton was Assistant Treasurer before becoming Vice President—Strategic Planning. Mr. Spellings was Associate General Tax Counsel before becoming Vice President and General Tax Counsel. Mr. Mulva was Vice President—Investor Relations and Secretary before becoming Vice President and Controller. Mr. Rosenthal was Assistant Controller before becoming Vice President—Investor Relations and Secretary. Mr. Swiger was President of ExxonMobil Gas & Power Marketing Company before becoming Senior Vice President.

The following executive officers of the registrant have also served as executives of the subsidiaries, affiliates or divisions of the registrant shown opposite their names during the five years preceding December 31, 2009.


ExxonMobil Chemical Company				Dolan, Glass, Jr. and Pryor
ExxonMobil Development Company				Albers, Duffin and Walters
ExxonMobil Exploration Company				Cejka
ExxonMobil Fuels Marketing Company				Cramer
ExxonMobil Gas & Power Marketing Company				Colton, Franklin, Swiger and Walters
ExxonMobil Lubricants & Petroleum Specialties Company				Kelly
ExxonMobil Production Company				Duffin, Kruger, Rosenthal, Swiger and Walters
ExxonMobil Refining & Supply Company				Dolan, Glass, Jr. and Pryor

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.

Index to Financial Statements

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, 2009
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, 2009	18,265,518	71.06	18,265,518
November, 2009	5,615,488	73.78	5,615,488
December, 2009	9,172,391	71.88	9,172,391

Total	33,053,397	71.75	33,053,397	(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. 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 February 1, 2010, the Corporation stated that first quarter 2010 share purchases are continuing at a pace consistent with fourth quarter 2009 share reduction spending of $2.0 billion. However, total purchases for the quarter may be less due to trading restrictions during the proxy solicitation period for the XTO merger. 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.

Index to Financial Statements

Item 6. Selected Financial Data.


	Years Ended December 31,
	2009		2008		2007		2006		2005
	(millions of dollars, except per share amounts)

Sales and other operating revenue ⁽¹⁾⁽²⁾	$	301,500	$	459,579	$	390,328	$	365,467	$	358,955
(1) Sales-based taxes included.	$	25,936	$	34,508	$	31,728	$	30,381	$	30,742
(2) Includes amounts for purchases/sales contracts with the same counterparty for 2005.

Net income attributable to ExxonMobil	$	19,280	$	45,220	$	40,610	$	39,500	$	36,130

Earnings per common share⁽³⁾	$	3.99	$	8.70	$	7.31	$	6.64	$	5.74

Earnings per common share - assuming dilution⁽³⁾	$	3.98	$	8.66	$	7.26	$	6.60	$	5.70
(3) Prior periods have been adjusted retrospectively. See “Earnings per Share” in “Note 2: Accounting Changes” in the Financial Section of this report

Cash dividends per common share	$	1.66	$	1.55	$	1.37	$	1.28	$	1.14

Total assets	$	233,323	$	228,052	$	242,082	$	219,015	$	208,335

Long-term debt	$	7,129	$	7,025	$	7,183	$	6,645	$	6,220

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 26, 2010, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 18: Income, Sales-Based and Other Taxes”;

•

“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.

Index to Financial Statements

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

None.

Item 9A. Controls and Procedures.

Management’s Evaluation of Disclosure Controls and Procedures

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2009. 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, 2009.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2009, 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, 2010, the annual salary for M.J. Dolan will increase to $935,000. Like all other ExxonMobil executive officers, Mr. Dolan is an “at will” employee of the Corporation and does not have an employment contract.

Index to Financial Statements

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

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

•

The section entitled “Director Information”;

•

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

•

The portions entitled “Director Qualifications” and “Code of Ethics and Business Conduct” of the section entitled “Corporate Governance”.

The Board has appointed an Audit Committee. The members of the Audit Committee are: M. J. Boskin, L. R. Faulkner and S. S Reinemund. The Board has determined that all members of the Committee are financially literate within the meaning of the NYSE standards, and that all are “audit committee financial experts” as defined in the SEC rules.

The procedures by which shareholders may recommend nominees for consideration by the Board Affairs Committee as director nominees have not changed materially since last year.

Item 11. Executive Compensation.

Reference is made to the sections entitled “Director Compensation,” “Compensation Committee Report”, “Compensation Discussion and Analysis” and “Executive Compensation Tables” of the Proxy Information Section of this report.

The Compensation Committee determines whether ExxonMobil’s compensation policies and practices could result in inappropriate risk-taking. Based on it’s assessment, the Committee does not believe that ExxonMobil’s compensation policies and practices create any material adverse risks for the Company for the following reasons:

Inappropriate risk-taking is discouraged by requiring senior executives to hold a substantial portion of their equity incentive award for their entire career and beyond retirement. These lengthy holding periods are tailored to our business model. The Compensation Committee requires that these equity grants with long holding periods comprise 50 to 70 percent of total compensation for Named Executive Officers as depicted on page 133 of the “Compensation Discussion and Analysis,” whereas the annual bonus award was only about 10 percent of total annual compensation in 2009.

Payout of 50 percent of the annual bonus is delayed and subject to risk of forfeiture, which is a unique feature of the annual bonus program relative to many comparator companies and further discourages inappropriate risk-taking; the timing of the delayed payout is determined by earnings performance.

Executives below the Named Executive Officers participate in the same plans which are also reviewed by the Compensation Committee; therefore, inappropriate risk-taking is discouraged at all levels of the Company through similar compensation design features and allocation of awards.

Finally, it should also be noted that a large percentage of career compensation for all executives and employees is in the form of a defined benefit pension which requires many years of dedicated service to the Company to have material value and is based on a standard retirement age of 65, with early retirement eligibility at age 55 with a minimum of 15 years of service. This is another dimension of total compensation that discourages inappropriate risk-taking; instead, it encourages executives to take a long-term view when making business decisions and to focus on achieving sustainable growth for shareholders.

Index to Financial Statements

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 included in the section entitled “Director and Executive Officer Stock Ownership” of the Proxy Information Section of this report. Reference is also made to the section entitled “Certain Beneficial Owners” of the Proxy Information Section of this report.

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	50,375,746⁽²⁾	$40.92	153,372,424⁽³⁾⁽⁴⁾

Equity compensation plans not approved by security holders	0	0	0

Total	50,375,746	$40.92	153,372,424

(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 three prior option grants that are still outstanding.

(2)

Includes 41,473,406 options granted under the 1993 Incentive Program and 8,902,340 restricted stock units to be settled in shares.

(3)

Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 152,591,224 shares available for award under the 2003 Incentive Program and 781,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan.

(4)

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.

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

Information provided in response to this Item 13 is included in the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section entitled “Corporate Governance” of the Proxy Information Section of this report.

Index to Financial Statements

Item 14. Principal Accounting Fees and Services.

Reference is made to the section entitled “Auditor Information” of the Proxy Information Section of this report.

The Audit Committee has adopted specific policies and procedures for pre-approving fees paid to the independent auditors. Under the Audit Committee’s approach, an annual program of work is approved each October for the following categories of services: Audit, Audit-Related, and Tax. Additional engagements may be brought forward from time to time for pre-approval by the Audit Committee. Pre-approvals apply to engagements within a category of service, and cannot be transferred between categories. If fees might otherwise exceed pre-approved amounts for any category of permissible services, the incremental amounts must be reviewed and pre-approved prior to commitment. The complete text of the Audit Committee’s pre-approval policies and procedures is posted on the Corporate Governance section of ExxonMobil’s website.

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.

Index to Financial Statements

FINANCIAL SECTION

TABLE OF CONTENTS


Business Profile		40
Financial Summary		41
Frequently Used Terms		42
Quarterly Information		44
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Functional Earnings		45
Forward-Looking Statements		46
Overview		46
Business Environment and Risk Assessment		46
Review of 2009 and 2008 Results		49
Liquidity and Capital Resources		50
Capital and Exploration Expenditures		53
Taxes		54
Environmental Matters		54
Market Risks, Inflation and Other Uncertainties		55
Recently Issued Statements of Financial Accounting Standards		56
Critical Accounting Policies		56
Management’s Report on Internal Control Over Financial Reporting		60
Report of Independent Registered Public Accounting Firm		60
Consolidated Financial Statements
Statement of Income		62
Balance Sheet		63
Statement of Cash Flows		64
Statement of Changes in Equity		65
Statement of Comprehensive Income		66
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies		67
2. Accounting Changes		68
3. Miscellaneous Financial Information		69
4. Cash Flow Information		69
5. Additional Working Capital Information		69
6. Equity Company Information		70
7. Investments, Advances and Long-Term Receivables		71
8. Property, Plant and Equipment and Asset Retirement Obligations		71
9. Accounting for Suspended Exploratory Well Costs		72
10. Leased Facilities		74
11. Earnings Per Share		74
12. Financial Instruments and Derivatives		75
13. Long-Term Debt		75
14. Incentive Program		80
15. Litigation and Other Contingencies		82
16. Pension and Other Postretirement Benefits		84
17. Disclosures about Segments and Related Information		90
18. Income, Sales-Based and Other Taxes		92
Supplemental Information on Oil and Gas Exploration and Production Activities		94
Operating Summary		106

Index to Financial Statements

BUSINESS PROFILE


Financial	Earnings After Income Taxes				Average Capital Employed				Return on Average Capital Employed		Capital and Exploration Expenditures
Financial	2009		2008		2009		2008		2009	2008	2009		2008
	*(millions of dollars)*								*(percent)*		*(millions of dollars)*
Upstream
United States	$	2,893	$	6,243	$	15,865	$	14,651	18.2	42.6	$	3,585	$	3,334
Non-U.S.		14,214		29,159		57,336		51,413	24.8	56.7		17,119		16,400

Total	$	17,107	$	35,402	$	73,201	$	66,064	23.4	53.6	$	20,704	$	19,734

Downstream
United States	$	(153)	$	1,649	$	7,306	$	6,963	(2.1)	23.7	$	1,511	$	1,636
Non-U.S.		1,934		6,502		17,793		18,664	10.9	34.8		1,685		1,893

Total	$	1,781	$	8,151	$	25,099	$	25,627	7.1	31.8	$	3,196	$	3,529

Chemical
United States	$	769	$	724	$	4,370	$	4,535	17.6	16.0	$	319	$	441
Non-U.S.		1,540		2,233		12,190		9,990	12.6	22.4		2,829		2,378

Total	$	2,309	$	2,957	$	16,560	$	14,525	13.9	20.4	$	3,148	$	2,819

Corporate and financing		(1,917)		(1,290)		10,190		23,467	—	—		44		61

Total	$	19,280	$	45,220	$	125,050	$	129,683	16.3	34.2	$	27,092	$	26,143

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


Operating	2009	2008
	*(thousands of barrels daily)*
Net liquids production
United States	384	367
Non-U.S.	2,003	2,038

Total	2,387	2,405


	*(millions of cubic feet daily)*
Natural gas production available for sale
United States	1,275	1,246
Non-U.S.	7,998	7,849

Total	9,273	9,095


	*(thousands of oil-equivalent barrels daily)*
Oil-equivalent production (1)	3,932	3,921

	*(thousands of barrels daily)*
Refinery throughput
United States	1,767	1,702
Non-U.S.	3,583	3,714

Total	5,350	5,416


	*(thousands of barrels daily)*
Petroleum product sales
United States	2,523	2,540
Non-U.S.	3,905	4,221

Total	6,428	6,761


	*(thousands of metric tons)*
Chemical prime product sales
United States	9,649	9,526
Non-U.S.	15,176	15,456

Total	24,825	24,982

(1)

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

Index to Financial Statements

FINANCIAL SUMMARY


	2009			2008			2007			2006			2005
	*(millions of dollars, except per share amounts)*
Sales and other operating revenue (1) (2)	$	301,500		$	459,579		$	390,328		$	365,467		$	358,955

Earnings
Upstream	$	17,107		$	35,402		$	26,497		$	26,230		$	24,349
Downstream		1,781			8,151			9,573			8,454			7,992
Chemical		2,309			2,957			4,563			4,382			3,943
Corporate and financing		(1,917	)		(1,290	)		(23	)		434			(154	)

Net income attributable to ExxonMobil	$	19,280		$	45,220		$	40,610		$	39,500		$	36,130

Earnings per common share	$	3.99		$	8.70		$	7.31		$	6.64		$	5.74
Earnings per common share – assuming dilution	$	3.98		$	8.66		$	7.26		$	6.60		$	5.70

Cash dividends per common share	$	1.66		$	1.55		$	1.37		$	1.28		$	1.14

Earnings to average ExxonMobil share of equity (percent)		17.3			38.5			34.5			35.1			33.9

Working capital	$	3,174		$	23,166		$	27,651		$	26,960		$	27,035
Ratio of current assets to current liabilities (times)		1.06			1.47			1.47			1.55			1.58

Additions to property, plant and equipment	$	22,491		$	19,318		$	15,387		$	15,462		$	13,839
Property, plant and equipment, less allowances	$	139,116		$	121,346		$	120,869		$	113,687		$	107,010
Total assets	$	233,323		$	228,052		$	242,082		$	219,015		$	208,335

Exploration expenses, including dry holes	$	2,021		$	1,451		$	1,469		$	1,181		$	964
Research and development costs	$	1,050		$	847		$	814		$	733		$	712

Long-term debt	$	7,129		$	7,025		$	7,183		$	6,645		$	6,220
Total debt	$	9,605		$	9,425		$	9,566		$	8,347		$	7,991
Fixed-charge coverage ratio (times)		26.1			52.2			49.9			46.3			50.2
Debt to capital (percent)		7.7			7.4			7.1			6.6			6.5
Net debt to capital (percent) (3)		(1.0	)		(23.0	)		(24.0	)		(20.4	)		(22.0	)

ExxonMobil share of equity at year end	$	110,569		$	112,965		$	121,762		$	113,844		$	111,186
ExxonMobil share of equity per common share	$	23.39		$	22.70		$	22.62		$	19.87		$	18.13
Weighted average number of common shares outstanding (millions)		4,832			5,194			5,557			5,948			6,295

Number of regular employees at year end (thousands) (4)		80.7			79.9			80.8			82.1			83.7

CORS employees not included above (thousands) (5)		22.0			24.8			26.3			24.3			22.4

(1)

Sales and other operating revenue includes sales-based taxes of $25,936 million for 2009, $34,508 million for 2008, $31,728 million for 2007, $30,381 million for 2006 and $30,742 million for 2005.

(2)

Sales and other operating revenue includes $30,810 million for 2005 for purchases/sales contracts with the same counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income.

(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.

Index to Financial Statements

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	2009			2008			2007
	*(millions of dollars)*
Net cash provided by operating activities	$	28,438		$	59,725		$	52,002
Sales of subsidiaries, investments and property, plant and equipment		1,545			5,985			4,204

Cash flow from operations and asset sales	$	29,983		$	65,710		$	56,206

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	2009			2008			2007
	*(millions of dollars)*
Business uses: asset and liability perspective
Total assets	$	233,323		$	228,052		$	242,082
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable		(49,585	)		(46,700	)		(55,929	)
Total long-term liabilities excluding long-term debt		(58,741	)		(54,404	)		(50,543	)
Noncontrolling interests share of assets and liabilities		(5,642	)		(6,044	)		(5,332	)
Add ExxonMobil share of debt-financed equity company net assets		5,043			4,798			3,386

Total capital employed	$	124,398		$	125,702		$	133,664

Total corporate sources: debt and equity perspective
Notes and loans payable	$	2,476		$	2,400		$	2,383
Long-term debt		7,129			7,025			7,183
ExxonMobil share of equity		110,569			112,965			121,762
Less noncontrolling interests share of total debt		(819	)		(1,486	)		(1,050	)
Add ExxonMobil share of equity company debt		5,043			4,798			3,386

Total capital employed	$	124,398		$	125,702		$	133,664

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	2009			2008			2007
	*(millions of dollars)*
Net income attributable to ExxonMobil	$	19,280		$	45,220		$	40,610
Financing costs (after tax)
Gross third-party debt		(303	)		(343	)		(339	)
ExxonMobil share of equity companies		(285	)		(325	)		(204	)
All other financing costs – net		(483	)		1,485			268

Total financing costs		(1,071	)		817			(275	)

Earnings excluding financing costs	$	20,351		$	44,403		$	40,885

Average capital employed	$	125,050		$	129,683		$	128,760

Return on average capital employed – corporate total		16.3	%		34.2	%		31.8	%

Index to Financial Statements

QUARTERLY INFORMATION


	2009						2008
	First Quarter		Second Quarter	Third Quarter	Fourth Quarter	Year	First Quarter		Second Quarter	Third Quarter	Fourth Quarter	Year
Volumes
	*(thousands of barrels daily)*
Production of crude oil and natural gas liquids, synthetic oil and bitumen		2,476	2,346	2,335	2,393	2,387		2,468	2,391	2,290	2,472	2,405
Refinery throughput		5,381	5,290	5,352	5,379	5,350		5,526	5,472	5,354	5,313	5,416
Petroleum product sales		6,434	6,487	6,301	6,489	6,428		6,821	6,775	6,688	6,761	6,761

	*(millions of cubic feet daily)*
Natural gas production available for sale		10,187	8,041	8,155	10,717	9,273		10,229	8,489	7,820	9,849	9,095

	*(thousands of oil-equivalent barrels daily)*
Oil-equivalent production (1)		4,174	3,686	3,694	4,179	3,932		4,173	3,806	3,593	4,113	3,921

	*(thousands of metric tons)*
Chemical prime product sales		5,527	6,267	6,356	6,675	24,825		6,578	6,718	6,060	5,626	24,982

Summarized financial data
	*(millions of dollars)*
Sales and other operating revenue (2)	$	62,128	72,167	80,090	87,115	301,500	$	113,223	133,776	132,085	80,495	459,579
Gross profit (3)	$	23,562	24,231	27,377	28,580	103,750	$	40,255	43,925	45,901	29,760	159,841
Net income attributable to ExxonMobil	$	4,550	3,950	4,730	6,050	19,280	$	10,890	11,680	14,830	7,820	45,220

Per share data
	*(dollars per share)*
Earnings per common share (4)	$	0.92	0.82	0.98	1.27	3.99	$	2.03	2.24	2.86	1.55	8.70
Earnings per common share – assuming dilution (4)	$	0.92	0.81	0.98	1.27	3.98	$	2.02	2.22	2.85	1.54	8.66
Dividends per common share	$	0.40	0.42	0.42	0.42	1.66	$	0.35	0.40	0.40	0.40	1.55
Common stock prices
High	$	82.73	74.83	72.79	76.54	82.73	$	94.74	96.12	89.63	83.64	96.12
Low	$	61.86	64.50	64.46	66.11	61.86	$	77.55	84.26	71.51	56.51	56.51

(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 525,529 registered shareholders of ExxonMobil common stock at December 31, 2009. At January 31, 2010, the registered shareholders of ExxonMobil common stock numbered 523,748.

On January 27, 2010, the Corporation declared a $0.42 dividend per common share, payable March 10, 2010.

Index to Financial Statements

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


FUNCTIONAL EARNINGS	2009			2008			2007
	*(millions of dollars, except per share amounts)*
Earnings (U.S. GAAP)
Upstream
United States	$	2,893		$	6,243		$	4,870
Non-U. S.		14,214			29,159			21,627
Downstream
United States		(153	)		1,649			4,120
Non-U. S.		1,934			6,502			5,453
Chemical
United States		769			724			1,181
Non-U. S.		1,540			2,233			3,382
Corporate and financing		(1,917	)		(1,290	)		(23	)

Net income attributable to ExxonMobil	$	19,280		$	45,220		$	40,610


Earnings per common share	$	3.99		$	8.70		$	7.31
Earnings per common share – assuming dilution	$	3.98		$	8.66		$	7.26

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.

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; and benefits realized from the XTO Energy transaction 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, including the timing and conditions of clearance for the XTO Energy transaction; our ability to integrate XTO Energy’s business with our own; and other factors discussed herein and in Item 1A of ExxonMobil’s 2009 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. Our consistent, conservative approach to financing the capital-intensive needs of the Corporation has helped ExxonMobil to sustain the “triple-A” status of its long-term debt securities for 91 years.

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 2.7 percent per year. This combination of population and economic growth is expected to lead to an increase in primary energy demand of almost 35 percent by 2030 versus 2005 even with substantial efficiency gains. This demand increase is expected to be concentrated in developing countries.

As economic progress drives demand higher, the use of more energy-efficient, lower-emission technologies and practices will become increasingly important, leading to a significantly lower level of energy consumption and emissions per unit of economic output by 2030. 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 over 35 percent from 2005 to 2030. The global growth in transportation demand will be met primarily by oil, which is expected to provide almost 95 percent of all transportation fuel by 2030, down from about 98 percent in 2005, as biofuels and natural gas gain market share.

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. Coal will retain the largest share. However, natural gas, nuclear and renewables are all expected to gain market share.

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 104 million barrels of oil-equivalent per day or close to 25 percent more than in 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.

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 35 percent. From 2005 to 2030, natural gas is expected to grow the fastest of the fossil fuels and overtake coal as the second-largest energy source. Nuclear power is projected to grow significantly, surpassing coal in terms of absolute growth and reaching the level of 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.

Index to Financial Statements

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 through 2030 will be close to $480 billion per year on average, or about $11.1 trillion (measured in 2009 dollars) in total over the period 2008-2030. 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 for energy-related greenhouse gas emissions in its long-term Energy Outlook, which is used for assessing the business environment and in its investment evaluations.

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 bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2014. Oil and natural gas output from West Africa, the Caspian region, the Middle East and Russia is expected to increase over the next five years based on current capital project execution plans. Currently, these growth areas account for 42 percent of the Corporation’s production. By 2014, they are expected to generate about 50 percent of total volumes. The remainder of the Corporation’s production is expected to be sourced from established areas, including Europe, North America and Asia Pacific.

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 30 percent to over 40 percent of the Corporation’s output between now and 2014. 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 2009 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 2010-2014. However, actual volumes will vary from year to year due to the timing of individual project start-ups, 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 2009 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.

Merger Agreement

On December 13, 2009, ExxonMobil and XTO Energy Inc. (XTO) entered into an Agreement and Plan of Merger (the “Merger Agreement”). Under the terms of the Merger Agreement, (i) each share of XTO common stock will be converted into the right to receive 0.7098 shares of common stock of the Corporation (the “Exchange Ratio”) and (ii) all outstanding XTO options will be converted into options to purchase shares of common stock of the Corporation, with the number of shares of XTO common stock subject to the option, and the option’s exercise price, adjusted based on the Exchange Ratio. The transaction includes XTO debt, which was approximately $10.5 billion at December 31, 2009.

XTO’s reported year-end 2009 proved reserves of 14.8 trillion cubic feet of natural gas equivalents include shale gas, tight gas, coal-bed methane and shale oil. These will complement ExxonMobil’s holdings in the United States, Canada, Germany, Poland and Argentina. XTO’s resource base, technical expertise and highly skilled employees together with ExxonMobil’s operational and financial strengths should enable development of additional supplies of unconventional natural gas and oil resources.

Consummation of the merger is subject to customary conditions, including (i) the adoption of the Merger Agreement by the holders of XTO common stock, (ii) the absence of any law or order prohibiting the closing, (iii) the expiration or termination of the applicable Hart-Scott-Rodino waiting period and receipt of antitrust clearance under Dutch competition laws, (iv) subject to certain exceptions, the accuracy of representations and warranties and performance of covenants, (v) the effectiveness of the registration statement for the common stock of the Corporation being issued in the merger and (vi) the delivery of customary opinions from counsel to the Corporation and counsel to XTO that the merger will qualify as a reorganization for federal income tax purposes.

The Corporation and XTO have made customary representations, warranties and covenants in the Merger Agreement, including, among others, covenants to conduct their respective businesses in the ordinary course consistent with past practice between the execution of the Merger Agreement and consummation of the merger. In addition, XTO has covenanted (i) to cause a stockholder meeting to be held to consider approval of the transactions contemplated by the Merger Agreement, (ii) subject to certain exceptions, for its board of directors to recommend approval by its stockholders of the transactions contemplated by the Merger Agreement, (iii) not to solicit proposals relating to alternative business combination transactions and (iv) subject to certain exceptions, not to enter into discussions concerning or provide confidential information in connection with alternative business combination transactions.

Index to Financial Statements

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

Assuming the merger is approved by XTO stockholders and is cleared by regulatory authorities, the transaction will be accounted for as a purchase, with XTO’s assets and liabilities reflected in ExxonMobil’s books at fair value. The transaction should be accretive to ExxonMobil’s production growth and cash flow. Depending on the market price for gas, it is not likely to be accretive to near-term earnings per share and may be dilutive.

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 with other 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 37 refineries, located in 21 countries, with distillation capacity of 6.3 million barrels per day and lubricant basestock manufacturing capacity of about 143 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 very challenging. The recent global economic recession had a negative impact on the global demand for refined products, and thus put considerable downward pressure on worldwide refining margins. Further, in prior years, the industry has experienced a period of robust refining margins, which encouraged the construction of additional industry capacity. Over the prior 20-year period, inflation-adjusted refining margins have been flat, with the recent prior years’ stronger margins offsetting the longer-term trend of declining margins.

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 continues to be that refining margins will generally decline 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 2009 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, ongoing intense competition continues to drive down inflation-adjusted margins by about 2 percent per year. In 2009, 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 2009, ExxonMobil completed commissioning new cogeneration facilities in Fujian, China, and Antwerp, Belgium, representing a total of 375 megawatts, that help improve our refinery efficiency. Additionally, ExxonMobil is progressing with announced plans to invest over $1 billion in three refineries to increase the supply of cleaner-burning diesel by about 140 thousand barrels per day. The company will construct new units and modify existing facilities at its Baton Rouge, La., Baytown, Texas, and Antwerp, Belgium, refineries. In the Asia Pacific region, ExxonMobil and its partners Sinopec, Fujian Province and Saudi Aramco started up the integrated refining and petrochemicals facility in Fujian Province, China. This project expanded the existing 80-thousand-barrel-per-day refinery to a 240-thousand-barrel-per-day high-conversion facility. Additionally, the project encompasses a new world-scale integrated chemical plant. The partnership also includes a fuels marketing joint venture that includes over 750 retail sites and a network of distribution terminals.

Chemical

Worldwide petrochemical demand continued to be weak in the first half of 2009, due to the soft economy. Demand increased in the second half of the year, reflecting improved economic activity, particularly in Asia Pacific. Industry operating rates improved in the second half of the year on stronger demand and were further supported by industry capacity rationalizations and delays in start-up of new capacity. Tighter industry supply/demand balances in the second half of the year supported higher product prices and improved industry margins.

ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of primary petrochemical products, ExxonMobil Chemical also has a number of less-cyclical business lines. Chemical’s competitive advantages are achieved through its business mix, broad geographic coverage, investment discipline, integration of chemical capacity with large refineries or upstream gas processing facilities, advantaged feedstock capabilities, leading proprietary technology and product application expertise.

Index to Financial Statements

REVIEW OF 2009 AND 2008 RESULTS


	2009		2008		2007
	*(millions of dollars)*
Earnings (U.S. GAAP)	$	19,280	$	45,220	$	40,610

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.

2008

Earnings in 2008 of $45,220 million increased $4,610 million from 2007. Earnings for 2008 included an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany and after-tax special charges of $460 million related to the Valdez litigation.

Upstream


	2009		2008		2007
	*(millions of dollars)*
Upstream
United States	$	2,893	$	6,243	$	4,870
Non-U.S.		14,214		29,159		21,627

Total	$	17,107	$	35,402	$	26,497

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 (thousands of barrels per day) decreased 18 kbd. Production increases from new projects in the U.S., Qatar and West Africa along with higher volumes in Kazakhstan were offset by field decline. Natural gas production of 9,273 mcfd (millions of cubic feet per day) 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.

2008

Upstream earnings for 2008 totaled $35,402 million, an increase of $8,905 million from 2007, including an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany. Higher crude oil and natural gas realizations increased earnings approximately $11.8 billion. Lower sales volumes reduced earnings about $3.7 billion. Higher taxes and increased operating costs decreased earnings approximately $1.5 billion, partially offset by favorable foreign exchange. Oil-equivalent production decreased 6 percent versus 2007, including impacts from lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Excluding these impacts, total oil-equivalent production decreased 3 percent. Liquids production of 2,405 kbd decreased 211 kbd from 2007. Production increases from new projects in West Africa were more than offset by field decline, lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Natural gas production of 9,095 mcfd decreased 289 mcfd from 2007. Higher volumes from North Sea, Malaysia and Qatar projects and higher European demand were more than offset by field decline. Earnings from U.S. Upstream operations for 2008 were $6,243 million, an increase of $1,373 million. Earnings outside the U.S. for 2008, including a $1,620 million gain related to the sale of the German natural gas transportation business, were $29,159 million, $7,532 million higher than in 2007.

Downstream


	2009			2008		2007
	*(millions of dollars)*
Downstream
United States	$	(153	)	$	1,649	$	4,120
Non-U.S.		1,934			6,502		5,453

Total	$	1,781		$	8,151	$	9,573

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.

2008

Downstream earnings of $8,151 million were $1,422 million lower than in 2007. Lower margins reduced earnings approximately $900 million, as weaker refining margins more than offset stronger marketing margins. Higher operating costs, mainly associated with planned work activity, reduced earnings about $700 million, while unfavorable foreign exchange effects decreased earnings approximately $600 million. Improved refinery operations provided a partial offset, increasing earnings about $800 million. Petroleum product sales of 6,761 kbd decreased from 7,099 kbd in 2007, primarily reflecting asset sales and lower demand. Refinery throughput was 5,416 kbd compared with 5,571 kbd in 2007. U.S. Downstream earnings were $1,649 million, down $2,471 million from 2007. Non-U.S. Downstream earnings of $6,502 million were $1,049 million higher than in 2007.

Index to Financial Statements

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

Chemical


	2009		2008		2007
	*(millions of dollars)*
Chemical
United States	$	769	$	724	$	1,181
Non-U.S.		1,540		2,233		3,382

Total	$	2,309	$	2,957	$	4,563

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 (thousands of metric tons) decreased 157 kt from 2008. 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 $769 million increased $45 million. Non-U.S. Chemical earnings were $1,540 million, down $693 million.

2008

Chemical earnings totaled $2,957 million, a decrease of $1,606 million from 2007. Lower margins reduced earnings approximately $1.2 billion, while lower volumes decreased earnings about $500 million. Prime product sales were 24,982 kt, a decrease of 2,498 kt from 2007. U.S. Chemical earnings of $724 million decreased $457 million. Non-U.S. Chemical earnings of $2,233 million were $1,149 million lower than in 2007.

Corporate and Financing


	2009			2008			2007
	*(millions of dollars)*
Corporate and financing	$	(1,917	)	$	(1,290	)	$	(23	)

2009

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

2008

Corporate and financing expenses of $1,290 million in 2008 increased $1,267 million from 2007, mainly due to charges of $460 million related to the Valdez litigation, net higher taxes and lower interest income.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash


	2009			2008			2007
	*(millions of dollars)*
Net cash provided by/(used in)
Operating activities	$	28,438		$	59,725		$	52,002
Investing activities		(22,419	)		(15,499	)		(9,728	)
Financing activities		(27,283	)		(44,027	)		(38,345	)
Effect of exchange rate changes		520			(2,743	)		1,808

Increase/(decrease) in cash and cash equivalents	$	(20,744	)	$	(2,544	)	$	5,737

	*(Dec. 31)*
Cash and cash equivalents	$	10,693		$	31,437		$	33,981

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 and cash equivalents were $31.4 billion at the end of 2008, $2.5 billion lower than the prior year, reflecting $2.7 billion of foreign exchange reductions from the strengthening of the U.S. dollar in 2008. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows.

Although the Corporation could issue long-term debt and has access to 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 that 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 5 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.

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

Index to Financial Statements

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, as evidenced by its AAA/Aaa debt rating, enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2009 were $27.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 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

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.

2008

Cash provided by operating activities totaled $59.7 billion in 2008, a $7.7 billion increase from 2007. The major source of funds was net income including noncontrolling interests of $46.9 billion, adjusted for the noncash provision of $12.4 billion for depreciation and depletion, both of which increased. The net effects of lower prices and the timing of collection of accounts receivable and of payments of accounts and other payables and of income taxes payable added to cash provided by operating activities.

Cash Flow from Investing Activities

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.

2008

Cash used in investing activities netted to $15.5 billion in 2008, $5.8 billion higher than in 2007. Spending for property, plant and equipment of $19.3 billion in 2008 increased $3.9 billion from 2007. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $6.0 billion in 2008 compared to $4.2 billion in 2007, the increase reflecting the sale of the German natural gas transportation business in 2008. Cash used in investing activities in 2008 was higher due to the absence of the $4.6 billion positive cash flow in 2007 from the release of the restriction on the restricted cash and cash equivalents. Net cash used for investments and advances and the change in marketable securities was $1.0 billion lower in 2008.

Cash Flow from Financing Activities

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 $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. Purchases may be increased, decreased or discontinued at any time without prior notice.

2008

Cash used in financing activities was $44.0 billion in 2008, an increase of $5.7 billion from 2007, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.55 per share from $1.37 per share and totaled $8.1 billion, a pay-out of 18 percent. Total consolidated short-term and long-term debt decreased $0.2 billion to $9.4 billion at year-end 2008.

ExxonMobil share of equity decreased $8.8 billion in 2008, to $113.0 billion. Earnings of $45.2 billion, reduced by distributions to ExxonMobil shareholders of $8.1 billion of dividends and $32.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding, added to equity. Equity, and net assets and liabilities, decreased $6.8 billion, representing the foreign exchange translation effects of generally weaker

Index to Financial Statements

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

foreign currencies at the end of 2008 on ExxonMobil’s operations outside the United States. The change in the funded status of the postretirement benefits reserves in 2008 lowered equity by $5.1 billion.

During 2008, Exxon Mobil Corporation purchased 434 million shares of its common stock for the treasury at a gross cost of $35.7 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 7.5 percent from 5,382 million at the end of 2007 to 4,976 million at the end of 2008. 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, 2009. 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	2010		2011- 2014		2015 and Beyond		Total
	*(millions of dollars)*
Long-term debt (1)	13	$	—	$	3,531	$	3,598	$	7,129
– Due in one year (2)			348		—		—		348
Asset retirement obligations (3)	8		693		1,944		5,836		8,473
Pension and other post retirement obligations (4)	16		1,540		4,024		12,317		17,881
Operating leases (5)	10		2,444		5,561		2,360		10,365
Unconditional purchase obligations (6)	15		314		902		568		1,784
Take-or-pay obligations (7)			1,208		4,241		7,594		13,043
Firm capital commitments (8)			12,250		12,525		688		25,463

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 $4.7 billion as of December 31, 2009, 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 $368 million.

(2)	The amount due in one year is included in notes and loans payable of $2,476 million (note 5).

(3)	The fair value of upstream asset retirement obligations, primarily 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 2010 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 and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $1,784 million mainly pertain to pipeline throughput agreements and include $1,141 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 $13,043 million mainly pertain to manufacturing supply, pipeline and terminaling agreements and include $501 million of obligations to equity companies.

(8)

Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $25.5 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $14.5 billion was associated with projects in West Africa, Kazakhstan, Papua New Guinea and Australia. The Corporation expects to fund the majority of these projects through internal cash flow.

Guarantees

The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2009, for $8,786 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of $5,629 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, 2009
	Equity Company Obligations		Other Third-Party Obligations		Total
	*(millions of dollars)*
Total guarantees	$	5,629	$	3,157	$	8,786

Index to Financial Statements

Financial Strength

On December 31, 2009, unused credit lines for short-term financing totaled approximately $4.8 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. Throughout this period, the Corporation’s long-term debt securities maintained the top credit rating from both Standard & Poor’s (AAA) and Moody’s (Aaa), a rating it has sustained for 91 years.


	2009	2008	2007
Fixed-charge coverage ratio (times)	26.1	52.2	49.9
Debt to capital (percent)	7.7	7.4	7.1
Net debt to capital (percent)	(1.0)	(23.0)	(24.0)
Credit rating	AAA/Aaa	AAA/Aaa	AAA/Aaa

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.

The Corporation makes limited use of derivative instruments, which are discussed in note 12.

Litigation and Other Contingencies

Litigation

As discussed in note 15, a number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims and the punitive damage award have been paid.

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 or financial condition. 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. An affiliate of ExxonMobil has also filed an arbitration under the rules of the International Chamber of Commerce against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. Both arbitration proceedings continue. 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.

CAPITAL AND EXPLORATION EXPENDITURES


	2009				2008
	U.S.		Non-U.S.		U.S.		Non-U.S.
	*(millions of dollars)*
Upstream (1)	$	3,585	$	17,119	$	3,334	$	16,400
Downstream		1,511		1,685		1,636		1,893
Chemical		319		2,829		441		2,378
Other		44		—		61		—

Total	$	5,459	$	21,633	$	5,472	$	20,671

(1)

Exploration expenses included.

Capital and exploration expenditures in 2009 were $27.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could vary depending on the progress of individual projects.

Upstream spending of $20.7 billion in 2009 was up 5 percent from 2008, mainly due to increased exploration and production drilling activity. The majority of these 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 67 percent of total proved reserves at year-end 2009, and has been over 60 percent for the last five years, indicating that proved reserves are

Index to Financial Statements

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

consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $3.2 billion in 2009, a decrease of $0.3 billion from 2008, due to lower refining project and fuels marketing expenditures. Chemical 2009 capital expenditures of $3.1 billion were up $0.3 billion from 2008 due to increased investment in Asia Pacific to meet demand growth.

TAXES


	2009			2008			2007
	*(millions of dollars)*
Income taxes	$	15,119		$	36,530		$	29,864
Effective income tax rate		47	%		46	%		44	%
Sales-based taxes		25,936			34,508			31,728
All other taxes and duties		37,571			45,223			44,091

Total	$	78,626		$	116,261		$	105,683

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.

2008

Income, sales-based and all other taxes and duties totaled $116.3 billion in 2008, an increase of $10.6 billion or 10 percent from 2007. Income tax expense, both current and deferred, was $36.5 billion, $6.7 billion higher than 2007, reflecting higher pre-tax income in 2008. A higher share of total income from the Upstream segment in 2008 increased the effective income tax rate to 46 percent compared to 44 percent in 2007. Sales-based and all other taxes and duties of $79.7 billion in 2008 increased $3.9 billion from 2007, reflecting higher prices.

ENVIRONMENTAL MATTERS

Environmental Expenditures


	2009		2008
	*(millions of dollars)*
Capital expenditures	$	2,481	$	2,485
Other expenditures		2,610		2,730

Total	$<