Edgar Filing: EXXON MOBIL CORP

Form 10-K

Index to Financial Statements

2011

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

¨ 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

13-5409005

(State or other jurisdiction of

incorporation or organization)

(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 (4,713,220,567 shares
outstanding at January 31, 2012)

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 þ 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 þ

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 þ 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 þ 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. ¨

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 þ 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 þ

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $81.38 on the New York Stock Exchange composite tape, was in excess of $395 billion.

Documents Incorporated by Reference:

Proxy Statement for the 2012 Annual Meeting of Shareholders (Part III)

Index to Financial Statements

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

TABLE OF CONTENTS


		Page Number
PART I

Item 1.	Business		1

Item 1A.	Risk Factors		2

Item 1B.	Unresolved Staff Comments		4

Item 2.	Properties		5

Item 3.	Legal Proceedings		26

Item 4.	Mine Safety Disclosures		26

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]			27

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		30

Item 6.	Selected Financial Data		30

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		30

Item 8.	Financial Statements and Supplementary Data		31

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		31

Item 9A.	Controls and Procedures		31

Item 9B.	Other Information		31

PART III

Item 10.	Directors, Executive Officers and Corporate Governance		32

Item 11.	Executive Compensation		32

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		32

Item 13.	Certain Relationships and Related Transactions, and Director Independence		33

Item 14.	Principal Accounting Fees and Services		33

PART IV

Item 15.	Exhibits, Financial Statement Schedules		33

Financial Section			35

Signatures			109

Index to Exhibits			111

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.

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 2011 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.9 billion, of which $3.2 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to remain in this range in 2012 and 2013 (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 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 10 thousand active patents worldwide at the end of 2011. For technology licensed to third parties, revenues totaled approximately $129 million in 2011. 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 82.1 thousand, 83.6 thousand and 80.7 thousand at years ended 2011, 2010 and 2009, 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 17.0 thousand, 20.1 thousand and 22.0 thousand at years ended 2011, 2010 and 2009, 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

Index to Financial Statements

and Code of Ethics and Business Conduct, as well as the charters of the audit, compensation and nominating committees of the Board of Directors. Information on our website is not incorporated into this report.

ITEM 1A.

RISK FACTORS.

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

Supply and Demand

The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and earnings may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on refined products. Oil, gas, petrochemical and product prices and margins in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity.

Economic conditions. The demand for energy and petrochemicals correlates closely with general economic growth rates. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates, periods of civil unrest, government austerity programs, or currency exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt downgrades, defaults, inability to access debt markets due to credit or legal constraints, liquidity crises, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, and other events or 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.

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

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

Other market factors. ExxonMobil’s business results are also exposed to potential negative impacts due to changes in 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.

Index to Financial Statements

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

Regulatory and litigation risks. Even in countries with well-developed legal systems where ExxonMobil does business, we remain exposed to changes in law (including changes that result from international treaties and accords) that could adversely affect our results, such as:

•

increases in taxes or government royalty rates (including retroactive claims);

•

price controls;

•

changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business opportunities (including changes in laws related to offshore drilling operations, water use, or hydraulic fracturing);

•

adoption of regulations mandating the use of alternative fuels or uncompetitive fuel components;

•

adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information, or that could cause us to violate the non-disclosure laws of other countries; and

•

government actions to cancel contracts, re-denominate the official currency, renounce or default on obligations, renegotiate terms unilaterally, or expropriate assets.

Legal remedies available to compensate us for expropriation or other takings may be inadequate.

We also may be adversely affected by the outcome of litigation or other legal proceedings, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur.

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

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

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

Management Effectiveness

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

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

Project management. The success of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including

Index to Financial Statements

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

Business risks also include the risk of cybersecurity breaches. If our systems for protecting against cybersecurity risks prove not to be sufficient, ExxonMobil could be adversely affected such as by having its business systems compromised, its proprietary information altered, lost or stolen, or its business operations disrupted.

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

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

ITEM 1B.

UNRESOLVED STAFF COMMENTS.

As in other years, we received comments from the SEC staff regarding our Form 10-K for 2010. We received an initial letter from the staff on July 5, 2011, which included comments and requests for supplemental information on a variety of topics. We responded to these comments on August 25, 2011. On December 7, 2011, we received several follow-up comments from the staff, to which we responded on January 11, 2012. On February 7, 2012, we received one follow-up comment from the staff, to which we responded on February 21, 2012. We do not believe the remaining comment is material and expect it to be fully resolved in the near future. Disclosures responsive to the SEC staff’s comments have been included in this report.

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 2011

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, 2011, that would cause a significant change in the estimated proved reserves as of that date.


	Crude Oil		Natural Gas Liquids		Bitumen		Synthetic Oil		Natural Gas		Oil-Equivalent Basis
	(million bbls)		(million bbls)		(million bbls)		(million bbls)		(billion cubic ft)		(million bbls)
Proved Reserves
Developed
Consolidated Subsidiaries
United States		1,211		241		–		–		15,450		4,027
Canada/South America (1)		92		17		519		653		658		1,391
Europe		258		44		–		–		3,041		809
Africa		858		192		–		–		853		1,192
Asia		994		166		–		–		5,762		2,120
Australia/Oceania		71		55		–		–		1,070		304
Total Consolidated		3,484		715		519		653		26,834		9,843

Equity Companies
United States		266		4		–		–		83		284
Europe		28		–		–		–		7,588		1,293
Asia		1,023		434		–		–		19,305		4,674
Total Equity Company		1,317		438		–		–		26,976		6,251
Total Developed		4,801		1,153		519		653		53,810		16,094

Undeveloped
Consolidated Subsidiaries
United States		449		118		–		–		10,804		2,368
Canada/South America (1)		26		–		2,587		–		177		2,643
Europe		59		15		–		–		545		164
Africa		605		20		–		–		129		647
Asia		727		–		–		–		709		845
Australia/Oceania		99		37		–		–		6,177		1,166
Total Consolidated		1,965		190		2,587		–		18,541		7,833

Equity Companies
United States		82		1		–		–		29		88
Europe		1		–		–		–		2,581		431
Asia		232		44		–		–		1,261		486
Total Equity Company		315		45		–		–		3,871		1,005
Total Undeveloped		2,280		235		2,587		–		22,412		8,838
Total Proved Reserves		7,081		1,388		3,106		653		76,222		24,932

(1)

South America includes proved developed reserves of 0.6 million barrels of crude oil and natural gas liquids and 72 billion cubic feet of natural gas and proved undeveloped reserves of 0.6 million barrels of crude oil and natural gas liquids and 65 billion cubic feet of natural gas.

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 2012-2016. 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 2011

Additions to ExxonMobil’s proved reserves in 2011 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results.

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

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

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

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

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

Index to Financial Statements

2. Proved Undeveloped Reserves

At year-end 2011, approximately 8.8 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 35 percent of the 24.9 GOEB reported in proved reserves. This compares to the 7.7 GOEB of proved undeveloped reserves reported at the end of 2010. The net increase of 1.1 GOEB is primarily due to the addition of new projects in Canada and the United States. During the year, ExxonMobil conducted development activities in over 100 fields that resulted in the transfer of approximately 0.5 GOEB from proved undeveloped to proved developed reserves by year-end. The largest individual transfer was related to completion of drilling and the initiation of production activities on new pad locations in the Cold Lake field in Canada.

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 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 2011, discoveries and extensions related to new projects added approximately 1.5 GOEB of proved undeveloped reserves. The largest of these additions were related to the Kearl Expansion project in Canada and additions for planned drilling in the United States. Overall, investments of $23.1 billion were made by the Corporation during 2011 to progress the development of reported proved undeveloped reserves, including $20.5 billion for oil and gas producing activities and an additional $2.6 billion for other non-oil and gas producing activities such as the construction of LNG trains, support infrastructure and other related facilities that were undertaken to progress the development of proved undeveloped reserves. These investments represented 70 percent of the $33.1 billion in total reported Upstream capital and exploration expenditures.

Proved undeveloped reserves in the United States, Kazakhstan, the Netherlands, Nigeria and Canada have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure and the pace of co-venturer/government funding, as well as the time required to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance and regulatory approvals. Approximately one-third of the proved undeveloped reserves that have been reported for five or more years are located in three fields in Kazakhstan and the Netherlands. In Kazakhstan, the first is the initial development of the giant offshore Kashagan field which is included in the North Caspian Production Sharing Agreement in which ExxonMobil participates. The second is the Tengizchevroil joint venture which includes a production license in the Tengiz field and the nearby Korolev field. The joint venture is producing and proved undeveloped reserves will continue to move to proved developed as approved development phases progress. The third is the Groningen gas field in the Netherlands. Proved undeveloped reserves reported for this field are related to installation of future stages of compression. These reserves will move to proved developed when the additional stages of compression are installed to maintain field delivery pressure.

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.


	2011		2010		2009
	(thousands of barrels daily)
Crude oil and natural gas liquids production
Consolidated Subsidiaries
United States		357		339		311
Canada/South America (1)		65		81		82
Europe		265		330		374
Africa		508		628		685
Asia		383		326		287
Australia/Oceania		51		58		65
Total Consolidated Subsidiaries		1,629		1,762		1,804

Equity Companies
United States		66		69		73
Europe		5		5		5
Asia		425		404		320
Total Equity Companies		496		478		398

Total crude oil and natural gas liquids production		2,125		2,240		2,202

Bitumen production
Consolidated Subsidiaries
Canada/South America		120		115		120

Synthetic oil production
Consolidated Subsidiaries
Canada/South America		67		67		65
Total liquids production		2,312		2,422		2,387

	(millions of cubic feet daily)
Natural gas production available for sale
Consolidated Subsidiaries
United States		3,917		2,595		1,274
Canada/South America (1)		412		569		643
Europe		1,701		1,859		2,071
Africa		7		14		19
Asia		1,879		1,847		1,414
Australia/Oceania		331		332		315
Total Consolidated Subsidiaries		8,247		7,216		5,736

Equity Companies
United States		–		1		1
Europe		1,747		1,977		1,618
Asia		3,168		2,954		1,918
Total Equity Companies		4,915		4,932		3,537
Total natural gas production available for sale		13,162		12,148		9,273

	(thousands of oil-equivalent barrels daily)

Oil-equivalent production		4,506		4,447		3,932

(1)

South America includes liquids production for 2011, 2010 and 2009 of one thousand barrels daily for each year respectively and natural gas production available for sale for 2011, 2010 and 2009 of 45 million, 52 million, and 58 million cubic feet daily for each year respectively.

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		Australia/ Oceania		Total
During 2011
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel	$	90.65	$	97.10	$	102.20	$	109.69	$	98.79	$	96.28	$	100.79
Natural gas, per thousand cubic feet		3.45		3.29		9.32		2.83		3.37		3.98		4.65
Bitumen, per barrel		–		64.65		–		–		–		–		64.65
Synthetic oil, per barrel		–		102.80		–		–		–		–		102.80
Average production costs, per oil-equivalent barrel - total		11.14		23.58		13.58		14.04		6.58		12.85		12.33
Average production costs, per barrel - bitumen		–		19.80		–		–		–		–		19.80
Average production costs, per barrel - synthetic oil		–		47.68		–		–		–		–		47.68

Equity Companies
Average production prices
Crude oil and NGL, per barrel		104.44		–		103.23		–		100.14		–		100.74
Natural gas, per thousand cubic feet		5.08		–		8.61		–		7.78		–		8.08
Average production costs, per oil-equivalent barrel - total		19.96		–		2.92		–		1.09		–		2.45

Total
Average production prices
Crude oil and NGL, per barrel		92.80		97.10		102.22		109.69		99.50		96.28		100.78
Natural gas, per thousand cubic feet		3.45		3.29		8.96		2.83		6.14		3.98		5.93
Bitumen, per barrel		–		64.65		–		–		–		–		64.65
Synthetic oil, per barrel		–		102.80		–		–		–		–		102.80
Average production costs, per oil-equivalent barrel - total		11.68		23.58		9.85		14.04		3.41		12.85		9.45
Average production costs, per barrel - bitumen		–		19.80		–		–		–		–		19.80
Average production costs, per barrel - synthetic oil		–		47.68		–		–		–		–		47.68

During 2010
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel	$	70.22	$	69.92	$	73.37	$	78.08	$	72.96	$	68.91	$	74.04
Natural gas, per thousand cubic feet		3.92		3.41		6.44		2.15		3.19		3.31		4.31
Bitumen, per barrel		–		56.61		–		–		–		–		56.61
Synthetic oil, per barrel		–		78.42		–		–		–		–		78.42
Average production costs, per oil-equivalent barrel - total		9.92		20.07		11.62		9.63		5.65		11.20		10.54
Average production costs, per barrel - bitumen		–		17.81		–		–		–		–		17.81
Average production costs, per barrel - synthetic oil		–		42.79		–		–		–		–		42.79

Equity Companies
Average production prices
Crude oil and NGL, per barrel		74.70		–		74.14		–		72.67		–		72.98
Natural gas, per thousand cubic feet		8.30		–		6.91		–		5.42		–		6.02
Average production costs, per oil-equivalent barrel - total		19.11		–		2.41		–		0.98		–		2.31

Total
Average production prices
Crude oil and NGL, per barrel		70.98		69.92		73.38		78.08		72.80		68.91		73.81
Natural gas, per thousand cubic feet		3.92		3.41		6.68		2.15		4.56		3.31		5.00
Bitumen, per barrel		–		56.61		–		–		–		–		56.61
Synthetic oil, per barrel		–		78.42		–		–		–		–		78.42
Average production costs, per oil-equivalent barrel - total		10.67		20.07		8.46		9.63		2.91		11.20		8.14
Average production costs, per barrel - bitumen		–		17.81		–		–		–		–		17.81
Average production costs, per barrel - synthetic oil		–		42.79		–		–		–		–		42.79

Index to Financial Statements


	United States		Canada/ S. America		Europe		Africa		Asia		Australia/ Oceania		Total
During 2009
Consolidated Subsidiaries
Average production prices
Crude oil and NGL, per barrel	$	53.43	$	54.07	$	56.88	$	60.10	$	60.38	$	54.84	$	57.86
Natural gas, per thousand cubic feet		3.10		3.19		5.61		1.70		3.07		2.97		4.00
Bitumen, per barrel		–		45.22		–		–		–		–		45.22
Synthetic oil, per barrel		–		61.26		–		–		–		–		61.26
Average production costs, per oil-equivalent barrel - total		11.80		17.75		10.19		8.07		6.55		8.98		10.25
Average production costs, per barrel - bitumen		–		14.77		–		–		–		–		14.77
Average production costs, per barrel - synthetic oil		–		37.47		–		–		–		–		37.47

Equity Companies
Average production prices
Crude oil and NGL, per barrel		56.54		–		58.20		–		56.12		–		56.22
Natural gas, per thousand cubic feet		5.75		–		8.20		–		3.79		–		5.81
Average production costs, per oil-equivalent barrel - total		18.07		–		2.48		–		1.07		–		2.72

Total
Average production prices
Crude oil and NGL, per barrel		54.02		54.07		56.89		60.10		58.18		54.84		57.56
Natural gas, per thousand cubic feet		3.10		3.19		6.74		1.70		3.48		2.97		4.69
Bitumen, per barrel		–		45.22		–		–		–		–		45.22
Synthetic oil, per barrel		–		61.26		–		–		–		–		61.26
Average production costs, per oil-equivalent barrel - total		12.57		17.75		8.06		8.07		3.53		8.98		8.36
Average production costs, per barrel - bitumen		–		14.77		–		–		–		–		14.77
Average production costs, per barrel - synthetic oil		–		37.47		–		–		–		–		37.47

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


	2011		2010		2009

Net Productive Exploratory Wells Drilled
Consolidated Subsidiaries
United States		12		17		10
Canada/South America		6		12		4
Europe		1		3		2
Africa		1		1		2
Asia		2		–		–
Australia/Oceania		1		2		1
Total Consolidated Subsidiaries		23		35		19

Equity Companies
United States		1		–		–
Europe		1		2		1
Asia		–		–		–
Total Equity Companies		2		2		1
Total productive exploratory wells drilled		25		37		20

Net Dry Exploratory Wells Drilled
Consolidated Subsidiaries
United States		2		2		1
Canada/South America		–		1		–
Europe		4		–		4
Africa		–		1		3
Asia		5		2		1
Australia/Oceania		–		1		–
Total Consolidated Subsidiaries		11		7		9

Equity Companies
United States		–		–		–
Europe		–		–		–
Asia		–		–		–
Total Equity Companies		–		–		–
Total dry exploratory wells drilled		11		7		9

Index to Financial Statements


	2011		2010		2009

Net Productive Development Wells Drilled
Consolidated Subsidiaries
United States		1,069		604		165
Canada/South America		154		229		291
Europe		7		11		10
Africa		44		60		45
Asia		30		7		9
Australia/Oceania		–		2		7
Total Consolidated Subsidiaries		1,304		913		527

Equity Companies
United States		236		282		287
Europe		10		1		1
Asia		4		4		14
Total Equity Companies		250		287		302
Total productive development wells drilled		1,554		1,200		829

Net Dry Development Wells Drilled
Consolidated Subsidiaries
United States		14		2		3
Canada/South America		–		–		–
Europe		1		–		1
Africa		–		2		–
Asia		1		–		–
Australia/Oceania		–		1		1
Total Consolidated Subsidiaries		16		5		5

Equity Companies
United States		–		–		–
Europe		–		–		–
Asia		–		–		–
Total Equity Companies		–		–		–
Total dry development wells drilled		16		5		5

Total number of net wells drilled		1,606		1,249		863

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

Syncrude Operations

Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2011, the company’s share of net production of synthetic crude oil was about 67 thousand barrels per day and share of net acreage was about 63 thousand acres in the Athabasca oil sands deposit.

Kearl Project

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

The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada and is expected to be developed in two phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a blend of bitumen and diluent, is planned to be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline. At year-end 2011, the initial development of the Kearl project was more than 85 percent complete with expected startup in 2012. The Kearl Expansion project was funded in 2011.

Index to Financial Statements

5. Present Activities

A. Wells Drilling


	Year-end 2011				Year-end 2010
	Gross		Net		Gross		Net
Wells Drilling
Consolidated Subsidiaries
United States		1,276		527		1,088		491
Canada/South America		83		69		92		30
Europe		26		8		27		8
Africa		34		11		54		19
Asia		102		63		98		66
Australia/Oceania		9		2		1		–
Total Consolidated Subsidiaries		1,530		680		1,360		614

Equity Companies
United States		2		1		1		1
Europe		13		4		34		10
Asia		32		2		7		1
Total Equity Companies		47		7		42		12
Total gross and net wells drilling		1,577		687		1,402		626

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2011 acreage holdings totaled 15.6 million net acres, of which 1.9 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During 2011, 1,318.0 net exploration and development wells were completed in the inland lower 48 states, including development activities in the Barnett Shale of North Texas, the Freestone Trend of East Texas, the Haynesville Shale of Texas and Louisiana, the Fayetteville Shale of Arkansas, the Woodford Shale of Oklahoma, the Bakken oil play in North Dakota and Montana, the Marcellus Shale of Pennsylvania and West Virginia, the Eagle Ford Shale of South Texas, the Piceance Basin of Colorado, the San Joaquin Basin of California and the Permian Basin of West Texas.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2011 was 1.8 million acres. A total of 1.3 net exploration and development wells were completed during the year after the offshore drilling moratorium was lifted. The deepwater Hadrian South project and the non-operated Lucius project were both funded in 2011, and project activities are under way. Project work continued on the non-operated St. Malo project. Offshore California 1.0 net development well was completed.

Participation in Alaska production and development continued and a total of 13.6 net development wells were completed.

CANADA / SOUTH AMERICA

Canada

Oil and Gas Operations

ExxonMobil’s year-end 2011 acreage holdings totaled 5.2 million net acres, of which 1.5 million net acres were offshore. A total of 124.2 net exploration and development wells were completed during the year. The Horn River Pilot project was funded in 2011. Project activities continued on the Hibernia Southern Extension project.

In Situ Bitumen Operations

ExxonMobil’s year-end 2011 in situ bitumen acreage holdings totaled 0.5 million net onshore acres. A total of 34.0 net development wells were completed during the year.

Index to Financial Statements

Argentina

ExxonMobil’s net acreage totaled 1.0 million onshore acres at year-end 2011, and there were 1.3 net development wells completed during the year.

Venezuela

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

EUROPE

Germany

A total of 4.8 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2011, with 7.3 net exploration and development wells completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.6 million acres at year-end 2011, of which 1.2 million acres are onshore. A total of 11.1 net exploration and development wells were completed during the year. The non-operated project to redevelop the Schoonebeek oil field started up in 2011.

Norway

ExxonMobil’s net interest in licenses at year-end 2011 totaled approximately 1.0 million acres, all offshore. ExxonMobil participated in 2.4 net exploration and development well completions in 2011. The non-operated Aasgard Subsea Compression project was funded in 2011.

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2011 totaled approximately 0.3 million acres, all offshore. The divestment of Mobil North Sea Limited (MNSL) was completed in 2011. A total of 0.8 net development wells were completed during the year.

AFRICA

Angola

ExxonMobil’s year-end 2011 acreage holdings totaled 0.6 million net offshore acres, and 5.2 net exploration and development wells were completed during the year. On Block 15, development drilling continued at Kizomba A and Kizomba C. The Angola Gas Gathering project was completed in 2011, and project work continued on Kizomba Satellites Phase 1. On the non-operated Block 17, the Pazflor project started up in 2011 and work continued on the Cravo-Lirio-Orquidea-Violeta project. Development drilling continued at Dalia, Girassol and Rosa. On the non-operated Block 31, project work continued on the Plutao-Saturno-Venus-Marte project.

Chad

ExxonMobil’s net year-end 2011 acreage holdings consisted of 46 thousand onshore acres, with 28.0 net development wells completed during the year. The undeveloped concessions of M’Biku, Belanga and Mangara were relinquished in 2011.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.1 million net offshore acres at year-end 2011, with 3.8 net development wells completed during the year.

Nigeria

ExxonMobil’s net acreage totaled 1.0 million offshore acres at year-end 2011, with 7.3 net exploration and development wells completed during the year. Work continued on the deepwater Usan project, and the first phase of the Satellite Field Development project is under way.

Index to Financial Statements

ASIA

Azerbaijan

At year-end 2011, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.5 net development wells were completed during the year. Work continued on the Chirag Oil project.

Indonesia

At year-end 2011, ExxonMobil had 5.2 million net acres, 3.4 million net acres offshore and 1.8 million net acres onshore. A total of 3.4 net exploration wells were completed during the year. The full field development at Banyu Urip was funded in 2011 and project activities are under way.

Iraq

At year-end 2011, ExxonMobil’s onshore acreage was 0.9 million net acres. A total of 20.8 net development wells were completed at the West Qurna Phase I oil field during the year. In 2010, a contract was signed with South Oil Company of the Iraqi Ministry of Oil to redevelop and expand the West Qurna Phase I oil field. The term of the contract is 20 years with the right to extend for five years. In 2010 initial field rehabilitation activities commenced. Field rehabilitation activities across the life of this project will include drilling of new wells, working over of existing wells, optimization and debottlenecking of existing facilities, and the establishment of field offices and camps. During 2011, production sharing contracts were negotiated with the regional government of Kurdistan.

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2011. Working with our partners, construction of the initial phase of the Kashagan field continued during 2011.

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore at year-end 2011. During the year, a total of 8.5 net development wells were completed. The Tapis and Telok projects were funded in 2011 and project activities are under way.

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2011. During the year, a total of 0.4 net development wells were completed. ExxonMobil participated in 61.8 million tonnes per year gross liquefied natural gas capacity at year end. The development agreements associated with the Barzan project were signed in 2011.

Republic of Yemen

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2011.

Russia

ExxonMobil’s net acreage holdings at year-end 2011 were 85 thousand acres, all offshore. A total of 0.6 net development wells were completed. The Sakhalin-1 Chayvo Expansion and Arkutun-Dagi projects continued development activities in 2011. ExxonMobil and Rosneft signed a Strategic Cooperation Agreement in 2011 to jointly participate in exploration and development activities in Russia, the United States and other parts of the world.

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2011.

Index to Financial Statements

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2011, with 0.6 net exploration wells completed during the year.

ExxonMobil’s net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2011, of which 0.4 million acres are onshore. During the year, a total of 3.7 net development wells were completed.

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s year-end 2011 acreage holdings totaled 1.7 million net acres offshore. During 2011, a total of 1.3 net exploration wells were completed. Offshore installation continued for the Kipper Tuna Turrum project.

Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2011. The project consists of a subsea infrastructure for offshore production and transportation of the gas, and a 15 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.

Papua New Guinea

A total of 0.5 million net onshore acres were held by ExxonMobil at year-end 2011, with 0.1 net development well completed during the year. Work continued on the Papua New Guinea (PNG) LNG project. The project consists of conditioning facilities in the southern PNG Highlands, a 6.6 million tonnes per year LNG facility near Port Moresby and approximately 430 miles of onshore and offshore pipelines.

WORLDWIDE EXPLORATION

At year-end 2011, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 36.5 million net acres were held at year-end 2011, and 6.5 net exploration wells were completed during the year in these countries.

6. Delivery Commitments

ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 3,000 billion cubic feet of natural gas for the period from 2012 through 2014. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and spot market purchases as necessary.

Index to Financial Statements

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

A. Gross and Net Productive Wells


	Year-end 2011								Year-end 2010
	Oil				Gas				Oil				Gas
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Gross and Net Productive Wells
Consolidated Subsidiaries
United States		23,891		8,219		41,453		24,858		23,789		8,076		36,189		21,429
Canada/South America		5,347		4,870		3,299		1,259		5,609		5,092		6,650		3,361
Europe		1,340		357		647		265		1,438		395		672		291
Africa		1,167		465		12		5		1,126		454		14		6
Asia		783		399		224		178		845		411		207		173
Australia/Oceania		712		171		32		16		687		163		27		13
Total Consolidated Subsidiaries		33,240		14,481		45,667		26,581		33,494		14,591		43,759		25,273

Equity Companies
United States		11,068		5,200		1		–		11,270		5,295		7		3
Europe		61		23		593		191		28		14		594		194
Asia		894		100		121		30		883		99		121		30
Total Equity Companies		12,023		5,323		715		221		12,181		5,408		722		227
Total gross and net productive wells		45,263		19,804		46,382		26,802		45,675		19,999		44,481		25,500

There were 37,692 gross and 31,683 net operated wells at year-end 2011 and 35,691 gross and 30,494 net operated wells at year-end 2010. The number of wells with multiple completions was 1,775 gross in 2011 and 1,725 gross in 2010.

Index to Financial Statements

B. Gross and Net Developed Acreage


	Year-end 2011				Year-end 2010
	Gross		Net		Gross		Net
	(thousands of acres)
Gross and Net Developed Acreage
Consolidated Subsidiaries
United States		17,255		10,256		16,621		9,861
Canada/South America (1)		4,570		1,959		5,450		2,439
Europe		3,563		1,511		3,956		1,630
Africa		1,850		700		1,772		684
Asia		1,326		590		1,411		623
Australia/Oceania		1,955		719		1,955		719
Total Consolidated Subsidiaries		30,519		15,735		31,165		15,956

Equity Companies
United States		131		55		137		58
Europe		4,343		1,357		4,363		1,356
Asia		5,732		640		5,818		648
Total Equity Companies		10,206		2,052		10,318		2,062
Total gross and net developed acreage		40,725		17,787		41,483		18,018

(1)

Includes gross and net developed acreage in South America of 618 gross and 202 net thousands of acres for 2011 and 618 gross and 202 net thousands of acres for 2010.

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

C. Gross and Net Undeveloped Acreage


	Year-end 2011				Year-end 2010
	Gross		Net		Gross		Net
	(thousands of acres)
Gross and Net Undeveloped Acreage
Consolidated Subsidiaries
United States		8,718		5,229		8,393		4,845
Canada/South America (1)		19,183		9,877		20,612		11,977
Europe		36,153		16,107		34,787		16,118
Africa		13,242		8,100		14,733		8,612
Asia		23,883		19,914		24,203		19,086
Australia/Oceania		5,892		1,476		4,966		1,352
Total Consolidated Subsidiaries		107,071		60,703		107,694		61,990

Equity Companies
United States		302		97		188		69
Europe		–		–		–		–
Asia		72		5		–		–
Total Equity Companies		374		102		188		69
Total gross and net undeveloped acreage		107,445		60,805		107,882		62,059

(1)

Includes gross and net undeveloped acreage in South America of 10,922 gross and 5,680 net thousands of acres for 2011 and 10,111 gross and 7,442 net thousands of acres for 2010.

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

Index to Financial Statements

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 licenses or leases are acquired for varying periods of time with renewals or extensions possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to continue existing licenses or leases upon completing specified work. In general, license and lease agreements are held as long as there is production on the licenses and leases. The majority of Cold Lake leases are held in this manner. The exploration acreage in eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.

Argentina

The federal onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration period and up to two years for the third exploration period. A 50-percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been developed. Argentine provinces are entitled to modify the concession terms granted within their territories. The concession terms of the exploration permits granted by Neuquen Province are up to six years for the initial exploration period, up to four years for the second exploration period and up to three years for the third exploration period depending on the classification of the area. An extension after the third exploration period is possible for up to one year.

EUROPE

Germany

Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three years each. Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple possible extensions as long as there is production on the license. In 2007, ExxonMobil affiliates acquired four exploration licenses in the state of Lower Saxony. The exploration licenses are for a period of five years during which exploration work programs will be carried out. In 2009, ExxonMobil affiliates acquired two exploration licenses in the state of North Rhine Westphalia for an initial period of five years and an extension to one of the Lower Saxony licenses.

Netherlands

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

Index to Financial Statements

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 producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a case-by-case basis until they become producing areas; or licenses terminate in all other areas. The licensing regime was last updated in 2002, and the majority of licenses issued have an initial term of four years with a second term extension of four years and a final term of 18 years with a mandatory relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.

AFRICA

Angola

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

Chad

Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended at the discretion of the government.

Equatorial Guinea

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years while the production period for gas is 50 years. Under the Hydrocarbons Law enacted in 2006, 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-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.

Index to Financial Statements

ASIA

Azerbaijan

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

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

Indonesia

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

Iraq

Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraqi Ministry of Oil. An ExxonMobil affiliate entered into a contract with South Oil Company of the Iraqi Ministry of Oil for the rights to participate in the development and production activities of the West Qurna Phase I oil and gas field effective March 1, 2010. The term of the contract is 20 years with the right to extend for five years. The contract provides for cost recovery plus per-barrel fees for incremental production above specified levels.

Exploration and production activities in the Kurdistan region of Iraq are governed by production sharing contracts negotiated with the regional government of Kurdistan in 2011. The exploration term is for five years with the possibility of two-year extensions. The production period is 20 years with the right to extend for five years.

Kazakhstan

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

Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.

Malaysia

Exploration and production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The more recent PSCs governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, with possible extensions to the exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed relinquished. The development period is from four to six years from commercial discovery, with the possibility of extensions under special circumstances. Areas from which commercial production has not started by the end of the development period will be deemed relinquished if no extension is granted. All extensions are subject to the national oil company’s prior written approval. The total production period is 15 to 25 years from first commercial lifting, not to exceed the overall term of the contract.

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

Index to Financial Statements

Qatar

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

Republic of Yemen

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

Russia

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

Thailand

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

United Arab Emirates

Exploration and production activities for the major onshore oil fields in the Emirate of Abu Dhabi are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi. An interest in the Upper Zakum field, a major offshore field, was acquired effective as of January 2006, for a term expiring March 2026.

AUSTRALIA/OCEANIA

Australia

Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable at the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter “indefinitely”, i.e., for the life of the field. Effective from July 1998, new production licenses are granted “indefinitely”. In each case, a production license may be terminated if no production operations have been carried on for five years.

Papua New Guinea

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

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 2011(1)


		ExxonMobil *Share KBD(2)***		ExxonMobil Interest %
United States
Torrance	California		150		100
Joliet	Illinois		238		100
Baton Rouge	Louisiana		502		100
Baytown	Texas		561		100
Beaumont	Texas		345		100
Other (2 refineries)			155
Total United States			1,951

Canada
Strathcona	Alberta		189		69.6
Dartmouth	Nova Scotia		85		69.6
Nanticoke	Ontario		113		69.6
Sarnia	Ontario		119		69.6
Total Canada			506

Europe
Antwerp	Belgium		307		100
Fos-sur-Mer	France		129		82.9
Port-Jerome-Gravenchon	France		235		82.9
Karlsruhe	Germany		78		25
Augusta	Italy		198		100
Trecate	Italy		174		74.1
Rotterdam	Netherlands		191		100
Slagen	Norway		116		100
Fawley	United Kingdom		330		100
Total Europe			1,758

Asia Pacific
Kawasaki	Japan		240		50.1
Sakai	Japan		139		50.1
Wakayama	Japan		160		50.1
Jurong/PAC	Singapore		605		100
Sriracha	Thailand		174		66
Other (5 refineries)			340
Total Asia Pacific			1,658

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			6,218

(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 over 25,000 retail service stations.

Retail Sites At Year-End 2011


United States
Owned/leased			451
Distributors/resellers			8,558
Total United States			9,009

Canada
Owned/leased			483
Distributors/resellers			1,330
Total Canada			1,813
Europe
Owned/leased			3,944
Distributors/resellers			2,397
Total Europe			6,341

Asia Pacific
Owned/leased			1,866
Distributors/resellers			3,467
Total Asia Pacific			5,333

Latin America
Owned/leased			544
Distributors/resellers			1,350
Total Latin America			1,894

Middle East/Africa
Owned/leased			465
Distributors/resellers			165
Total Middle East/Africa			630

Worldwide
Owned/leased			7,753
Distributors/resellers			17,267
Total Worldwide			25,020

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 2011(1)(2)


		Ethylene		Polyethylene		Polypropylene		Paraxylene		ExxonMobil Interest %
North America
Baton Rouge	Louisiana		1.0		1.3		0.4		–		100
Baytown	Texas		2.2		–		0.8		0.6		100
Beaumont	Texas		0.8		1.0		–		0.3		100
Mont Belvieu	Texas		–		1.0		–		–		100
Sarnia	Ontario		0.3		0.5		–		–		69.6
Total North America			4.3		3.8		1.2		0.9

Europe
Antwerp	Belgium		0.5		0.4		–		–		35	⁽³⁾
Fife	United Kingdom		0.4		–		–		–		50
Meerhout	Belgium		–		0.5		–		–		100
Notre-Dame-de-Gravenchon	France		0.4		0.4		0.3		–		100
Rotterdam	Netherlands		–		–		–		0.7		100
Total Europe			1.3		1.3		0.3		0.7

Middle East
Al Jubail	Saudi Arabia		0.6		0.6		–		–		50
Yanbu	Saudi Arabia		1.0		0.7		0.2		–		50
Total Middle East			1.6		1.3		0.2		–

Asia Pacific
Fujian	China		0.2		0.2		0.1		0.2		25
Kawasaki	Japan		0.5		0.1		–		–		50
Singapore	Singapore		0.9		0.6		0.4		0.9		100
Sriracha	Thailand		–		–		–		0.5		66
Total Asia Pacific			1.6		0.9		0.5		1.6

All Other			–		–		–		0.6
Total Worldwide			8.8		7.3		2.2		3.8

(1)

Capacity for ethylene, polyethylene, polypropylene and paraxylene in millions of metric tons per year.

(2)

Capacity reflects 100 percent for operations of ExxonMobil and majority-owned subsidiaries. For companies owned 50 percent or less, capacity is ExxonMobil’s interest.

(3)

Net ExxonMobil ethylene capacity is 35 percent. Net ExxonMobil polyethylene capacity is 100 percent.

Index to Financial Statements

ITEM 3.

LEGAL PROCEEDINGS.

Regarding a matter previously reported in the Corporation’s Form 10-Q for the second quarter of 2009, the Corporation has resolved a Consolidated Compliance Order & Notice of Potential Penalty issued by the Louisiana Department of Environmental Quality (LDEQ) to the Corporation’s Baton Rouge Resins Finishing Plant (BRFP) on October 16, 2008, relating to alleged exceedances of air permit limits for certain volatile organic compounds and hazardous air pollutants. BRFP had self-disclosed these emission results to the LDEQ and proposed a number of specific corrective action steps. The settlement terms, which have been agreed to and were subject to public notice and comment until February 20, 2012, include a total payment of approximately $360 thousand, which consists of an administrative penalty of approximately $306 thousand and payment of approximately $54 thousand for certain Beneficial Environmental Projects.

Regarding a matter previously reported in the Corporation’s Form 10-Q for the first quarter of 2010, the Corporation has resolved issues raised by the LDEQ relating to a leak of propylene detected on January 10, 2010 at the Ethylene Purification Unit at the Corporation’s Baton Rouge, Louisiana chemical plant. The settlement terms, which have been agreed to and are subject to public notice and comment until March 2, 2012, include a total payment of approximately $250 thousand, which consists of an administrative penalty of approximately $123 thousand, the Corporation’s purchase of a camera for detection of certain emissions at a cost of approximately $79 thousand and payment for certain Beneficial Environmental Projects totaling $48 thousand.

With regard to a matter previously reported in the Corporation’s Form 10-Q for the third quarter of 2011, on January 19, 2012, ExxonMobil Pipeline Company (EMPCo) entered into an agreed Administrative Order on Consent (AOC) with the Montana Department of Environmental Quality (MDEQ) to resolve civil and related liabilities under state environmental laws resulting from the July 1, 2011 discharge of crude oil into the Yellowstone River from EMPCo’s Silvertip Pipeline. Under the AOC, EMPCo will: (1) pay a civil penalty totaling $1.6 million, including $300 thousand in cash payments and $1.3 million in Supplemental Environmental Projects to be decided upon by the MDEQ; (2) reimburse the state for past costs associated with cleanup efforts, totaling approximately $760 thousand; (3) reimburse the State of Montana’s future oversight costs; (4) monitor and document the degradation of remaining visible oil over time at selected locations; and, (5) continue its soil and water monitoring program, which was agreed upon with the MDEQ in October 2011. The AOC will terminate when EMPCo certifies that all required activities have been performed and the MDEQ has approved the certification. The order was subject to a 30-day public comment period which expired on February 21, 2012.

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.

MINE SAFETY DISCLOSURES.

Not applicable.

Index to Financial Statements

Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)] (ages as of February 29, 2012).


Rex W. Tillerson	Chairman of the Board

Held current title since:	January 1, 2006	Age: 59
Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004. He became Chairman of the Board and Chief Executive Officer on January 1, 2006. He still holds these positions as of this filing date.


Mark W. Albers	Senior Vice President

Held current title since:	April 1, 2007	Age: 55
Mr. Mark W. Albers was President of ExxonMobil Development Company October 1, 2004 – April 13, 2007. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2007, a position he still holds as of this filing date.


Michael J. Dolan	Senior Vice President

Held current title since:	April 1, 2008	Age: 58
Mr. Michael J. Dolan was President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation September 1, 2004 – March 31, 2008. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2008, a position he still holds as of this filing date.


Donald D. Humphreys	Senior Vice President

Held current title since:	January 25, 2006	Age: 64
Mr. Donald D. Humphreys became Senior Vice President of Exxon Mobil Corporation on January 25, 2006, a position he still holds as of this filing date. Over this period, he was Treasurer of Exxon Mobil Corporation through April 30, 2011.


Andrew P. Swiger	Senior Vice President

Held current title since:	April 1, 2009	Age: 55
Mr. Andrew P. Swiger was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation October 1, 2006 – March 31, 2009. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds as of this filing date.


S. Jack Balagia	Vice President and General Counsel

Held current title since:	March 1, 2010	Age: 60
Mr. S. Jack Balagia was Assistant General Counsel of Exxon Mobil Corporation April 1, 2004 – March 1, 2010. He became Vice President and General Counsel of Exxon Mobil Corporation on March 1, 2010, positions he still holds as of this filing date.


William M. Colton	Vice President - Strategic Planning

Held current title since:	February 1, 2009	Age: 58
Mr. William M. Colton was Assistant Treasurer of Exxon Mobil Corporation January 25, 2006 – January 31, 2009. He became Vice President—Strategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.


Neil W. Duffin	President, ExxonMobil Development Company

Held current title since:	April 13, 2007	Age: 55
Mr. Neil W. Duffin was Executive Vice President of ExxonMobil Development Company September 1, 2006 – April 13, 2007, becoming President on April 13, 2007, a position he still holds as of this filing date.

Index to Financial Statements


Robert S. Franklin	Vice President

Held current title since:	May 1, 2009	Age: 54
Mr. Robert S. Franklin was Vice President, New Business Development of ExxonMobil Gas & Power Marketing Company July 1, 2001 – April 15, 2007. He was Executive Assistant to the Chairman, Exxon Mobil Corporation April 16, 2007 – March 31, 2008. He was Vice President, Europe/Russia/Caspian of ExxonMobil Production Company April 1, 2008 – May 1, 2009. He became Vice President of Exxon Mobil Corporation and President, ExxonMobil Upstream Ventures on May 1, 2009, positions he still holds as of this filing date.


Sherman J. Glass, Jr.	Vice President

Held current title since:	April 1, 2008	Age: 64
Mr. Sherman J. Glass, Jr. was Senior Vice President of ExxonMobil Chemical Company September 1, 2005 – March 31, 2008. He became President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.


Stephen M. Greenlee	Vice President

Held current title since:	September 1, 2010	Age: 54
Mr. Stephen M. Greenlee was Vice President of ExxonMobil Exploration Company June 1, 2004 – June 1, 2009. He was President of ExxonMobil Upstream Research Company June 1, 2009 – August 31, 2010. He became President of ExxonMobil Exploration Company and Vice President of Exxon Mobil Corporation on September 1, 2010, positions he still holds as of this filing date.


Alan J. Kelly	Vice President

Held current title since:	December 1, 2007	Age: 54
Mr. Alan J. Kelly was on Special Assignment for the National Petroleum Council March 1, 2006 – November 30, 2007. He became President of ExxonMobil Lubricants & Petroleum Specialties Company and Vice President of Exxon Mobil Corporation on December 1, 2007. On February 1, 2012, the businesses of ExxonMobil Lubricants & Petroleum Specialties Company and ExxonMobil Fuels Marketing Company were consolidated and Mr. Kelly became President of the combined ExxonMobil Fuels, Lubricants & Specialties Marketing Company as well as Vice President of Exxon Mobil Corporation, positions he still holds as of this filing date.


Richard M. Kruger	Vice President

Held current title since:	April 1, 2008	Age: 52
Mr. Richard M. Kruger was Executive Vice President of ExxonMobil Production Company October 1, 2006 – March 31, 2008. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.


Patrick T. Mulva	Vice President and Controller

Held current title since:	February 1, 2002 (Vice President) July 1, 2004 (Controller)	Age: 60
Mr. Patrick T. Mulva became Vice President and Controller of Exxon Mobil Corporation on July 1, 2004, positions he still holds as of this filing date.


Stephen D. Pryor	Vice President

Held current title since:	December 1, 2004	Age: 62
Mr. Stephen D. Pryor was President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation December 1, 2004 – March 31, 2008. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.


David S. Rosenthal	Vice President - Investor Relations and Secretary

Held current title since:	October 1, 2008	Age: 55
Mr. David S. Rosenthal was Assistant Controller of Exxon Mobil Corporation June 1, 2006 – September 30, 2008. He became Vice President—Investor Relations and Secretary of Exxon Mobil Corporation on October 1, 2008, positions he still holds as of this filing date.

Index to Financial Statements


Robert N. Schleckser	Vice President and Treasurer

Held current title since:	May 1, 2011	Age: 55
Mr. Robert N. Schleckser was Downstream Treasurer, Downstream Business Services May 1, 2005 – January 31, 2009. He was Assistant Treasurer of Exxon Mobil Corporation February 1, 2009 – April 30, 2011. He became Vice President and Treasurer of Exxon Mobil Corporation on May 1, 2011, positions he still holds as of this filing date.


James M. Spellings, Jr.	Vice President and General Tax Counsel

Held current title since:	March 1, 2010	Age: 50
Mr. James M. Spellings, Jr. was General Manager—Corporate Planning of Exxon Mobil Corporation February 1, 2005 – March 31, 2007. He was Associate General Tax Counsel April 1, 2007 – March 1, 2010. He became Vice President and General Tax Counsel on March 1, 2010, positions he still holds as of this filing date.


Thomas R. Walters	Vice President

Held current title since:	April 1, 2009	Age: 57
Mr. Thomas R. Walters was President of ExxonMobil Global Services Company from September 1, 2005 – April 4, 2007. He was Executive Vice President of ExxonMobil Development Company April 13, 2007 – April 1, 2009. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on April 1, 2009, positions he still holds as of this filing date.


Jack P. Williams, Jr.	President, XTO Energy Inc.

Held current title since:	June 25, 2010	Age: 48
Mr. Jack P. Williams, Jr. was Upstream Advisor, Exxon Mobil Corporation July 1, 2005 – May 1, 2007. He was Vice President, Engineering, ExxonMobil Production Company May 1, 2007 – April 30, 2009. He was Vice President of ExxonMobil Development Company May 1, 2009 – July 1, 2010. He became President of XTO Energy Inc. on June 25, 2010, a position he still holds as of this filing date.

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

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, 2011
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, 2011		22,659,131		77.15		22,659,131
November, 2011		23,409,517		77.67		23,409,517
December, 2011		22,796,769		81.40		22,796,769
Total		68,865,417		78.73		68,865,417		(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 January 31, 2012, the Corporation stated that first quarter 2012 share purchases are continuing at a pace consistent with fourth quarter 2011 share reduction spending of $5 billion. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

ITEM 6.

SELECTED FINANCIAL DATA.


	Years Ended December 31,
	2011		2010		2009		2008		2007
	(millions of dollars, except per share amounts)

Sales and other operating revenue (1)	$	467,029	$	370,125	$	301,500	$	459,579	$	390,328
(1) Sales-based taxes included	$	33,503	$	28,547	$	25,936	$	34,508	$	31,728
Net income attributable to ExxonMobil	$	41,060	$	30,460	$	19,280	$	45,220	$	40,610
Earnings per common share	$	8.43	$	6.24	$	3.99	$	8.70	$	7.31
Earnings per common share - assuming dilution	$	8.42	$	6.22	$	3.98	$	8.66	$	7.26
Cash dividends per common share	$	1.85	$	1.74	$	1.66	$	1.55	$	1.37
Total assets	$	331,052	$	302,510	$	233,323	$	228,052	$	242,082
Long-term debt	$	9,322	$	12,227	$	7,129	$	7,025	$	7,183

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.

Index to Financial Statements

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 24, 2012, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 20: Subsequent Event”;

•

“Quarterly Information” (unaudited);

•

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

•

“Frequently Used Terms” (unaudited).

Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

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, 2011. 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, 2011.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2011, 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, 2012, the annual salary for Michael J. Dolan will increase to $1,100,000. 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.

Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2012 annual meeting of shareholders (the “2012 Proxy Statement”):

•

The section entitled “Election of Directors”;

•

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

•

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

•

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

ITEM 11.

EXECUTIVE COMPENSATION.

Incorporated by reference to the sections entitled “Director Compensation,” “Compensation Committee Report,” “Compensation Discussion and Analysis” and “Executive Compensation Tables” of the registrant’s 2012 Proxy Statement.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The information required under Item 403 of Regulation S-K is incorporated by reference to the sections “Director and Executive Officer Stock Ownership” and “Certain Beneficial Owners” of the registrant’s 2012 Proxy Statement.

Equity Compensation Plan Information


	(a)			(b)		(c)
Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights			Weighted- Average Exercise Price of Outstanding Options, Warrants and Rights		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		10,003,584	(1)(2)		—		133,900,228	(2)(3)(4)

Equity compensation plans not approved by security holders		—			—		—

Total		10,003,584			—		133,900,228

(1)

The number of restricted stock units to be settled in shares.

(2)

Does not include options that ExxonMobil assumed in the 2010 merger with XTO Energy Inc. At year-end 2011, the number of securities to be issued upon exercise of outstanding options under XTO Energy Inc. plans was 5,548,629, and the weighted-average exercise price of such options was $69.76. No additional awards may be made under those plans.

(3)

Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 133,182,528 shares available for award under the 2003 Incentive Program and 717,700 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.

Index to Financial Statements

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Information provided in response to this Item 13 is incorporated by reference to the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section entitled “Corporate Governance” of the registrant’s 2012 Proxy Statement.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES.

Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratification of Independent Auditors” of the registrant’s 2012 Proxy Statement.

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

(a)

(1) and (2) Financial Statements:

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

(a)

(3) Exhibits:

See Index to Exhibits of this report.

Index to Financial Statements

[THIS PAGE INTENTIONALLY LEFT BLANK]

Index to Financial Statements

FINANCIAL SECTION

TABLE OF CONTENTS


Business Profile			36
Financial Summary			37
Frequently Used Terms			38
Quarterly Information			40
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Functional Earnings			41
Forward-Looking Statements			42
Overview			42
Business Environment and Risk Assessment			42
Review of 2011 and 2010 Results			44
Liquidity and Capital Resources			46
Capital and Exploration Expenditures			49
Taxes			49
Environmental Matters			49
Market Risks, Inflation and Other Uncertainties			50
Critical Accounting Estimates			51
Management’s Report on Internal Control Over Financial Reporting			54
Report of Independent Registered Public Accounting Firm			55
Consolidated Financial Statements
Statement of Income			56
Balance Sheet			57
Statement of Cash Flows			58
Statement of Changes in Equity			59
Statement of Comprehensive Income			60
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies			61
2. Accounting Changes			63
3. Miscellaneous Financial Information			63
4. Cash Flow Information			63
5. Additional Working Capital Information			64
6. Equity Company Information			64
7. Investments, Advances and Long-Term Receivables			65
8. Property, Plant and Equipment and Asset Retirement Obligations			65
9. Accounting for Suspended Exploratory Well Costs			66
10. Leased Facilities			68
11. Earnings Per Share			68
12. Financial Instruments and Derivatives.			68
13. Long-Term Debt			69
14. Incentive Program.			76
15. Litigation and Other Contingencies			78
16. Pension and Other Postretirement Benefits			80
17. Disclosures about Segments and Related Information			87
18. Income, Sales-Based and Other Taxes			89
19. Acquisition of XTO Energy Inc.			91
20. Subsequent Event			92
Supplemental Information on Oil and Gas Exploration and Production Activities			93
Operating Summary			108

Index to Financial Statements

BUSINESS PROFILE


	Earnings After Income Taxes						Average Capital Employed						Return on Average Capital Employed				Capital and Exploration Expenditures
Financial	2011			2010			2011			2010			2011		2010		2011		2010
	(millions of dollars)												(percent)				(millions of dollars)
Upstream
United States	$	5,096		$	4,272		$	54,994		$	34,969			9.3		12.2	$	10,741	$	6,349
Non-U.S.		29,343			19,825			74,813			68,318			39.2		29.0		22,350		20,970
Total	$	34,439		$	24,097		$	129,807		$	103,287			26.5		23.3	$	33,091	$	27,319
Downstream
United States	$	2,268		$	770		$	5,340		$	6,154			42.5		12.5	$	518	$	982
Non-U.S.		2,191			2,797			18,048			17,976			12.1		15.6		1,602		1,523
Total	$	4,459		$	3,567		$	23,388		$	24,130			19.1		14.8	$	2,120	$	2,505
Chemical
United States	$	2,215		$	2,422		$	4,791		$	4,566			46.2		53.0	$	290	$	279
Non-U.S.		2,168			2,491			15,007			14,114			14.4		17.6		1,160		1,936
Total	$	4,383		$	4,913		$	19,798		$	18,680			22.1		26.3	$	1,450	$	2,215
Corporate and financing		(2,221	)		(2,117	)		(2,272	)		(880	)		–		–		105		187
Total	$	41,060		$	30,460		$	170,721		$	145,217			24.2		21.7	$	36,766	$	32,226
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
Operating	2011			2010													2011		2010
(thousands of barrels daily)																	(thousands of barrels daily)
Net liquids production								Refinery throughput
United States		423			408			United States										1,784		1,753
Non-U.S.		1,889			2,014			Non-U.S.										3,430		3,500
Total		2,312			2,422			Total										5,214		5,253

(millions of cubic feet daily)																	(thousands of barrels daily)
Natural gas production available for sale								Petroleum product sales
United States		3,917			2,596			United States										2,530		2,511
Non-U.S.		9,245			9,552			Non-U.S.										3,883		3,903
Total		13,162			12,148			Total										6,413		6,414

(thousands of oil-equivalent barrels daily)																	(thousands of metric tons)
Oil-equivalent production (1)		4,506			4,447			Chemical prime product sales
								United States										9,250		9,815
								Non-U.S.										15,756		16,076
								Total										25,006		25,891

(1)

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

Index to Financial Statements

FINANCIAL SUMMARY


	2011			2010			2009			2008			2007
	(millions of dollars, except per share amounts)

Sales and other operating revenue (1)	$	467,029		$	370,125		$	301,500		$	459,579		$	390,328
Earnings
Upstream	$	34,439		$	24,097		$	17,107		$	35,402		$	26,497
Downstream		4,459			3,567			1,781			8,151			9,573
Chemical		4,383			4,913			2,309			2,957			4,563
Corporate and financing		(2,221	)		(2,117	)		(1,917	)		(1,290	)		(23	)
Net income attributable to ExxonMobil	$	41,060		$	30,460		$	19,280		$	45,220		$	40,610
Earnings per common share	$	8.43		$	6.24		$	3.99		$	8.70		$	7.31
Earnings per common share – assuming dilution	$	8.42		$	6.22		$	3.98		$	8.66		$	7.26
Cash dividends per common share	$	1.85		$	1.74		$	1.66		$	1.55		$	1.37

Earnings to average ExxonMobil share of equity (percent)		27.3			23.7			17.3			38.5			34.5

Working capital	$	(4,542	)	$	(3,649	)	$	3,174		$	23,166		$	27,651
Ratio of current assets to current liabilities (times)		0.94			0.94			1.06			1.47			1.47

Additions to property, plant and equipment	$	33,638		$	74,156		$	22,491		$	19,318		$	15,387
Property, plant and equipment, less allowances	$	214,664		$	199,548		$	139,116		$	121,346		$	120,869
Total assets	$	331,052		$	302,510		$	233,323		$	228,052		$	242,082

Exploration expenses, including dry holes	$	2,081		$	2,144		$	2,021		$	1,451		$	1,469
Research and development costs	$	1,044		$	1,012		$	1,050		$	847		$	814

Long-term debt	$	9,322		$	12,227		$	7,129		$	7,025		$	7,183
Total debt	$	17,033		$	15,014		$	9,605		$	9,425		$	9,566
Fixed-charge coverage ratio (times)		53.2			42.2			25.8			54.6			51.6
Debt to capital (percent)		9.6			9.0			7.7			7.4			7.1
Net debt to capital (percent) (2)		2.6			4.5			(1.0	)		(23.0	)		(24.0	)

ExxonMobil share of equity at year-end	$	154,396		$	146,839		$	110,569		$	112,965		$	121,762
ExxonMobil share of equity per common share	$	32.61		$	29.48		$	23.39		$	22.70		$	22.62
Weighted average number of common shares outstanding (millions)		4,870			4,885			4,832			5,194			5,557

Number of regular employees at year-end (thousands) (3)		82.1			83.6			80.7			79.9			80.8

CORS employees not included above (thousands) (4)		17.0			20.1			22.0			24.8			26.3

(1)

Sales and other operating revenue includes sales-based taxes of $33,503 million for 2011, $28,547 million for 2010, $25,936 million for 2009, $34,508 million for 2008 and $31,728 million for 2007.

(2)

Debt net of cash, excluding restricted cash.

(3)

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.

(4)

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 associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments 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 proceeds associated with asset sales 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	2011		2010		2009
	(millions of dollars)

Net cash provided by operating activities	$	55,345	$	48,413	$	28,438
Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments		11,133		3,261		1,545
Cash flow from operations and asset sales	$	66,478	$	51,674	$	29,983

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	2011			2010			2009
	(millions of dollars)
Business uses: asset and liability perspective
Total assets	$	331,052		$	302,510		$	233,323
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable		(69,794	)		(59,846	)		(49,585	)
Total long-term liabilities excluding long-term debt		(83,481	)		(74,971	)		(58,741	)
Noncontrolling interests share of assets and liabilities		(7,314	)		(6,532	)		(5,642	)
Add ExxonMobil share of debt-financed equity company net assets		4,943			4,875			5,043
Total capital employed	$	175,406		$	166,036		$	124,398

Total corporate sources: debt and equity perspective
Notes and loans payable	$	7,711		$	2,787		$	2,476
Long-term debt		9,322			12,227			7,129
ExxonMobil share of equity		154,396			146,839			110,569
Less noncontrolling interests share of total debt		(966	)		(692	)		(819	)
Add ExxonMobil share of equity company debt		4,943			4,875			5,043
Total capital employed	$	175,406		$	166,036		$	124,398

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	2011			2010			2009
	(millions of dollars)

Net income attributable to ExxonMobil	$	41,060		$	30,460		$	19,280
Financing costs (after tax)
Gross third-party debt		(153	)		(803	)		(303	)
ExxonMobil share of equity companies		(219	)		(333	)		(285	)
All other financing costs – net		116			35			(483	)
Total financing costs		(256	)		(1,101	)		(1,071	)
Earnings excluding financing costs	$	41,316		$	31,561		$	20,351
Average capital employed	$	170,721		$	145,217		$	125,050
Return on average capital employed – corporate total		24.2%			21.7%			16.3%

Index to Financial Statements

QUARTERLY INFORMATION


	2011										2010
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year		First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Year
Volumes
Production of crude oil		(thousands of barrels daily)
and natural gas liquids,		2,399		2,351		2,249		2,250		2,312		2,414		2,325		2,421		2,526		2,422
synthetic oil and bitumen
Refinery throughput		5,180		5,193		5,232		5,250		5,214		5,156		5,192		5,364		5,298		5,253
Petroleum product sales		6,267		6,331		6,558		6,493		6,413		6,195		6,304		6,595		6,555		6,414

Natural gas production		(millions of cubic feet daily)
available for sale		14,525		12,267		12,197		13,677		13,162		11,689		10,025		12,192		14,652		12,148

		(thousands of oil-equivalent barrels daily)
Oil-equivalent production (1)		4,820		4,396		4,282		4,530		4,506		4,362		3,996		4,453		4,968		4,447

		(thousands of metric tons)
Chemical prime product sales		6,322		6,181		6,232		6,271		25,006		6,488		6,496		6,558		6,349		25,891

Summarized financial data
Sales and other operating		(millions of dollars)
revenue (2)	$	109,251		121,394		120,475		115,909		467,029	$	87,037		89,693		92,353		101,042		370,125
Gross profit (3)	$	35,473		37,744		37,121		34,306		144,644	$	28,537		29,482		30,652		32,943		121,614
Net income attributable to ExxonMobil	$	10,650		10,680		10,330		9,400		41,060	$	6,300		7,560		7,350		9,250		30,460

Per share data		(dollars per share)
Earnings per common share (4)	$	2.14		2.19		2.13		1.97		8.43	$	1.33		1.61		1.44		1.86		6.24
Earnings per common share
– assuming dilution (4)	$	2.14		2.18		2.13		1.97		8.42	$	1.33		1.60		1.44		1.85		6.22
Dividends per common share	$	0.44		0.47		0.47		0.47		1.85	$	0.42		0.44		0.44		0.44		1.74

Common stock prices
High	$	88.23		88.13		85.41		85.63		88.23	$	70.60		70.00		62.99		73.69		73.69
Low	$	73.64		76.72		67.03		69.21		67.03	$	63.56		56.92		55.94		61.80		55.94

(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 488,846 registered shareholders of ExxonMobil common stock at December 31, 2011. At January 31, 2012, the registered shareholders of ExxonMobil common stock numbered 486,416.

On January 25, 2012, the Corporation declared a $0.47 dividend per common share, payable March 9, 2012.

Index to Financial Statements

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


FUNCTIONAL EARNINGS	2011			2010			2009
	(millions of dollars, except per share amounts)
Earnings (U.S. GAAP)
Upstream
United States	$	5,096		$	4,272		$	2,893
Non-U.S.		29,343			19,825			14,214
Downstream
United States		2,268			770			(153	)
Non-U.S.		2,191			2,797			1,934
Chemical
United States		2,215			2,422			769
Non-U.S.		2,168			2,491			1,540
Corporate and financing		(2,221	)		(2,117	)		(1,917	)
Net income attributable to ExxonMobil	$	41,060		$	30,460		$	19,280

Earnings per common share	$	8.43		$	6.24		$	3.99
Earnings per common share – assuming dilution	$	8.42		$	6.22		$	3.98

Special item included in earnings
Corporate and financing
Valdez litigation	$	–		$	–		$	(140	)

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; could differ materially depending on a number of factors, such as changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; the outcome of commercial negotiations; political or regulatory events, and other factors discussed herein and in Item 1A. Risk Factors.

OVERVIEW

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

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

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

By 2040, the world’s population is projected to grow to approximately 8.7 billion people, or about 1.9 billion more than in 2010. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. Expanding prosperity across a growing global population is expected to coincide with an increase in primary energy demand of about 30 percent by 2040 versus 2010, even with substantial efficiency gains around the world. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development).

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

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by nearly 45 percent from 2010 to 2040. The global growth in transportation demand is likely to account for approximately 75 percent of the growth in liquids demand over this period. Nearly all the world’s transportation fleets are likely to continue to run on liquid fuels because they provide a large quantity of energy in small volumes, making them easy to transport and widely available.

Demand for electricity around the world is estimated to increase approximately 80 percent by 2040, led by growth in developing countries. Consistent with this projection, power generation will remain the largest and fastest-growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Natural gas demand is likely to grow most significantly and gain the most market share. Coal is likely to retain the leading share of power generation fuels in 2040, albeit at a much lower share than in 2010 as policies are gradually adopted to reduce environmental impacts including those related to local air quality and greenhouse gas emissions. Nuclear power and renewables, led by wind, are likely to grow significantly over the period.

Liquid fuels provide the largest share of energy supply today due to their broad-based availability, affordability and ease of transport to meet consumer needs. By 2040, global demand for liquids is expected to grow to approximately 112 million barrels of oil-equivalent per day, an increase of more than 25 percent from 2010. Global demand for liquid fuels will be met by a wide variety of sources. Conventional crude and condensate production is expected to remain relatively flat through 2040. However, growth is expected from a wide variety of sources, including deep-water resources, oil sands, tight oil, natural gas liquids, and biofuels. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic supply options. However, access to resources and timely investments will remain critical to meeting global needs with reliable, affordable supplies.

Natural gas is a versatile fuel for a wide variety of applications, and is expected to be the fastest growing major fuel source through 2040. Global demand is expected to rise 60 percent by 2040 compared to 2010, with demand increases in major regions around the world requiring new sources of supply. We expect that a significant growth in supplies of unconventional gas – the

Index to Financial Statements

natural gas found in shale and other rock formations that was once considered uneconomic to produce – will help meet these needs. By 2040, unconventional gas is likely to account for about 30 percent of global gas supplies, up from 10 percent in 2010. Growing natural gas demand is likely to also stimulate significant growth in the worldwide liquefied natural gas (LNG) market, which is expected to reach 15 percent of global gas demand by 2040.

The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas by approximately 2025. The share of natural gas is expected to exceed 25 percent by 2040, while the share of coal falls to less than 20 percent. Nuclear power is projected to grow significantly, albeit at a slower pace than otherwise expected in the aftermath of the Fukushima incident in Japan following the earthquake and tsunami in March 2011. Total renewable energy is likely to reach close to 15 percent of total energy by 2040, including biomass, hydro and geothermal at a combined share of about 11 percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 500 percent from 2010 to 2040, reaching a combined share of approximately 4 percent of world energy.

The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide over the period 2011-2035 will be close to $20 trillion (measured in 2010 dollars) or close to $780 billion per year on average.

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

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

Upstream

ExxonMobil continues to maintain a diverse 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 capturing the highest quality exploration opportunities, maximizing the profitability of existing oil and gas production, investing in projects that deliver superior returns, capitalizing on growing natural gas and power markets, and maximizing resource value through high-impact technologies. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees, and investment in the communities within which we operate.

As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2016. Oil and natural gas output from North America is expected to increase over the next five years based on current capital activity plans. Currently, this growth area accounts for 30 percent of the Corporation’s production. By 2016, it is expected to generate about 35 percent of total volumes. The remainder of the Corporation’s production is expected to include contributions from both established operations and new projects around the globe.

In addition to an evolving geographic mix, we expect 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 and oil sands recovery processes, unconventional gas and oil production and LNG is expected to grow from about 45 percent to around 50 percent of the Corporation’s output between now and 2016. 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. Risk Factors, 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 2012-2016. However, actual volumes will vary from year to year due to the timing of individual project start-ups and other capital activities, operational outages, reservoir performance, performance of enhanced oil recovery projects, regulatory changes, asset sales, weather events, price effects under production sharing contracts and other factors described in Item 1A. Risk Factors. 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.

Downstream

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

Index to Financial Statements

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

ExxonMobil has an ownership interest in 36 refineries, located in 21 countries, with distillation capacity of 6.2 million barrels per day and lubricant basestock manufacturing capacity of 131 thousand barrels per day. ExxonMobil’s fuels and lubes marketing business portfolios include operations around the world, with multiple channels to market serving a globally diverse customer base. Our world-class brands, including Exxon, Mobil and Esso, are well-known.

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

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

ExxonMobil’s long-term outlook is that refining margins will remain weak as competition in the 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. Risk Factors, proposed carbon policy and other climate-related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the refining business.

In the retail fuels marketing business, competition continues to cause inflation-adjusted margins to decline. In 2011, ExxonMobil progressed the transition of the direct served (i.e., dealer, company-operated) retail network in the U.S. to a more capital-efficient branded distributor model. This transition was announced in 2008 and is expected to be complete in 2012.

Our Lubricants and Specialties business continues to grow. ExxonMobil is a market leader in high-value synthetic lubricants, and we continue to grow our business in key markets such as China, India and Russia at rates considerably faster than industry.

The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. In 2011, we announced divestments of our Downstream businesses in Argentina, Uruguay, Paraguay, Central America, Malaysia, and Switzerland. In January 2012, we also announced the restructuring of our holdings in Japan which is disclosed in Note 20. 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 2011, the company completed construction of new units and modification of existing facilities at the Sriracha, Thailand, refinery to produce lower sulfur diesel and gasoline to meet upcoming product specifications in Thailand. At the Jurong/PAC refinery in Singapore, plans are under way to build a new diesel hydrotreater, which will add capacity of more than 2 million gallons per day to meet increasing demand in the Asia Pacific region. Additionally, construction of a lower sulfur fuels project has begun at the joint Saudi Aramco and ExxonMobil SAMREF Refinery in Yanbu, Saudi Arabia. The project will include new gasoline and expanded diesel hydrotreating and sulfur recovery equipment, and completion is expected by the end of 2013. We are also expanding our Singapore and China lube oil blending plants to support future demand growth in these emerging markets.

Chemical

Worldwide petrochemical demand grew modestly in 2011. In North America, unconventional natural gas continued to provide advantaged ethane feedstock for steam crackers and a favorable margin environment for integrated chemical producers. Margins in Asia Pacific remained low, with new supply capacity outpacing demand. Specialty products overall saw firm global demand and margins.

ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of commodity petrochemical products, ExxonMobil Chemical also has a number of less-cyclical Specialties business lines, which delivered strong results in 2011. Chemical’s competitive advantages are due to its business mix, broad geographic coverage, investment and cost discipline, integration with refineries or upstream gas processing facilities, superior feedstock management, leading proprietary technology and product application expertise.

REVIEW OF 2011 AND 2010 RESULTS


	2011		2010		2009
	(millions of dollars)

Earnings (U.S. GAAP)	$	41,060	$	30,460	$	19,280

2011

Earnings in 2011 of $41,060 million increased $10,600 million from 2010. Earnings for 2011 did not include any special items.

2010

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

Upstream


	2011		2010		2009
	(millions of dollars)
Upstream
United States	$	5,096	$	4,272	$	2,893
Non-U.S.		29,343		19,825		14,214
Total	$	34,439	$	24,097	$	17,107

Index to Financial Statements

2011

Upstream earnings were $34,439 million, up $10,342 million from 2010. Higher crude oil and natural gas realizations increased earnings by $10.6 billion, while volume and production mix effects decreased earnings by $2.5 billion. All other items increased earnings by $2.2 billion, driven by higher gains on asset sales of $2.7 billion, partly offset by increased operating activity. On an oil-equivalent basis, production was up 1 percent compared to 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 4 percent. Liquids production of 2,312 kbd (thousands of barrels per day) decreased 110 kbd from 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was in line with 2010, as higher volumes from Qatar, the U.S., and Iraq offset field decline. Natural gas production of 13,162 mcfd (millions of cubic feet per day) increased 1,014 mcfd from 2010, driven by additional U.S. unconventional gas volumes and project ramp-ups in Qatar. Earnings from U.S. Upstream operations for 2011 were $5,096 million, an increase of $824 million. Earnings outside the U.S. were $29,343 million, up $9,518 million.

2010

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

Downstream


	2011		2010		2009
	(millions of dollars)
Downstream
United States	$	2,268	$	770	$	(153	)
Non-U.S.		2,191		2,797		1,934
Total	$	4,459	$	3,567	$	1,781

2011

Downstream earnings of $4,459 million increased $892 million from 2010. Margins, mainly refining, increased earnings by $800 million. Volume and mix effects improved earnings by $630 million. All other items, primarily the absence of favorable tax effects and higher expenses, decreased earnings by $540 million. Petroleum product sales of 6,413 kbd were in line with 2010. U.S. Downstream earnings were $2,268 million, up $1,498 million from 2010. Non-U.S. Downstream earnings were $2,191 million, $606 million lower than last year.

2010

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

Chemical


	2011		2010		2009
	(millions of dollars)
Chemical
United States	$	2,215	$	2,422	$	769
Non-U.S.		2,168		2,491		1,540
Total	$	4,383	$	4,913	$	2,309

2011

Chemical earnings of $4,383 million were down $530 million from 2010. Stronger margins increased earnings by $260 million, while lower volumes reduced earnings by $180 million. Other items, including unfavorable tax effects and higher planned maintenance expense, decreased earnings by $610 million. Prime product sales of 25,006 kt (thousands of metric tons) were down 885 kt from 2010. 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 were $2,215 million, down $207 million from 2010. Non-U.S. Chemical earnings were $2,168 million, $323 million lower than last year.

2010

Chemical earnings were a record $4,913 million, up $2,604 million from 2009. Improved margins increased earnings by $2.0 billion while higher volumes increased earnings $380 million. Prime product sales of 25,891 kt were up 1,066 kt from 2009. U.S. Chemical earnings of $2,422 million increased $1,653 million. Non-U.S. Chemical earnings of $2,491 million increased $951 million.

Corporate and Financing


	2011			2010			2009
	(millions of dollars)

Corporate and financing	$	(2,221	)	$	(2,117	)	$	(1,917	)

2011

Corporate and financing expenses were $2,221 million, up $104 million from 2010.

2010

Corporate and financing expenses were $2,117 million, up $200 million from 2009 mainly due to a tax charge related to the U.S.

Index to Financial Statements

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

health care legislation during the first quarter of 2010 and financing activities, partially offset by the absence of a 2009 charge for interest related to the Valdez punitive damages award.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash


	2011			2010			2009
	(millions of dollars)
Net cash provided by/(used in)
Operating activities	$	55,345		$	48,413		$	28,438
Investing activities		(22,165	)		(24,204	)		(22,419	)
Financing activities		(28,256	)		(26,924	)		(27,283	)
Effect of exchange rate changes		(85	)		(153	)		520
Increase/(decrease) in cash and cash equivalents	$	4,839		$	(2,868	)	$	(20,744	)
	(Dec. 31)
Cash and cash equivalents	$	12,664		$	7,825		$	10,693
Cash and cash equivalents – restricted		404			628			–
Total cash and cash equivalents	$	13,068		$	8,453		$	10,693

Total cash and cash equivalents were $13.1 billion at the end of 2011, $4.6 billion higher than the prior year. Higher earnings, proceeds associated with asset sales, including a $3.6 billion deposit for a potential asset sale, and a net debt increase in contrast with prior year debt repurchases were partially offset by a higher level of purchases of ExxonMobil shares and a higher level of capital spending. Included in total cash and cash equivalents at year-end 2011 was $0.4 billion of restricted cash.

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

Although the Corporation has access to significant capacity of long-term and short-term liquidity, internally generated funds cover the majority of its financial requirements. Cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure it is secure and readily available to meet the Corporation’s cash requirements and to optimize returns.

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

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

The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2011 were $36.8 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment profile of about $37 billion per year 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

2011

Cash provided by operating activities totaled $55.3 billion in 2011, $6.9 billion higher than 2010. The major source of funds was net income including noncontrolling interests of $42.2 billion, adjusted for the noncash provision of $15.6 billion for depreciation and depletion, both of which increased. Changes in operational working capital, excluding cash and debt, and the adjustment for net gains on asset sales decreased cash in 2011. Net working capital continued to be negative as total current liabilities of $77.5 billion exceeded total current assets of $73.0 billion at year-end 2011.

2010

Cash provided by operating activities totaled $48.4 billion in 2010, $20.0 billion higher than 2009. The major source of funds was net income including noncontrolling interests of $31.4 billion, adjusted for the noncash provision of $14.8 billion for depreciation and depletion, both of which increased. The net effects of changes in prices and the timing of collection of accounts receivable and of

Index to Financial Statements

payments of accounts and other payables and of income taxes payable increased cash provided by operating activities in 2010 compared to a decrease in 2009, and resulted in net working capital of $(3.6) billion as total current liabilities of $62.6 billion exceeded total current assets of $59.0 billion at year-end 2010.

Cash Flow from Investing Activities

2011

Cash used in investment activities netted to $22.2 billion in 2011, $2.0 billion lower than 2010. Spending for property, plant and equipment of $31.0 billion increased $4.1 billion from 2010. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $11.1 billion compared to $3.3 billion in 2010. The increase primarily reflects the sale of Upstream Canadian, U.K. and other producing properties and assets, the sale of U.S. service stations, and a $3.6 billion deposit for a potential asset sale. Additional investments and advances were $2.3 billion higher in 2011.

2010

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

Cash Flow from Financing Activities

2011

Cash used in financing activities was $28.3 billion in 2011, $1.3 billion higher than 2010. Dividend payments on common shares increased to $1.85 per share from $1.74 per share and totaled $9.0 billion, a pay-out of 22 percent. Total debt increased $2.0 billion to $17.0 billion at year-end.

ExxonMobil share of equity increased $7.6 billion to $154.4 billion. The addition to equity for earnings of $41.1 billion was partially offset by reductions for distributions to ExxonMobil shareholders of $9.0 billion of dividends and $20.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. The change in the funded status of the postretirement benefits reserves in 2011 decreased equity by $4.6 billion.

During 2011, Exxon Mobil Corporation purchased 278 million shares of its common stock for the treasury at a gross cost of $22.1 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 4.9 percent from 4,979 million to 4,734 million at the end of 2011. 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.

2010

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

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

During 2010, Exxon Mobil Corporation issued 416 million shares for the XTO merger. Exxon Mobil Corporation purchased 199 million shares of its common stock for the treasury at a gross cost of $13.1 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding increased by 5.3 percent from 4,727 million at the end of 2009 to 4,979 million at the end of 2010. Purchases were made in both the open market and through negotiated transactions.

Commitments

Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2011. 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		2012		2013- 2016		2017 and Beyond		Total
	(millions of dollars)

Long-term debt (1)		13	$	–	$	2,947	$	6,375	$	9,322
– Due in one year (2)		5		3,431		–		–		3,431
Asset retirement obligations (3)		8		922		2,748		6,908		10,578
Pension and other postretirement obligations (4)		16		3,890		4,150		17,632		25,672
Operating leases (5)		10		2,152		4,132		1,630		7,914
Unconditional purchase obligations (6)		15		243		660		410		1,313
Take-or-pay obligations (7)				2,241		7,505		9,275		19,021
Firm capital commitments (8)				16,024		11,287		629		27,940

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 $4.9 billion as of December 31, 2011, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements

Index to Financial Statements

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

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 $260 million.

(2)

The amount due in one year is included in notes and loans payable of $7,711 million.

(3)

The fair value of asset retirement obligations, primarily upstream asset removal costs at the completion of field life.

(4)

The amount by which the benefit obligations exceeded the fair value of fund assets for certain U.S. and non-U.S. pension and other postretirement plans at year end. The payments by period include expected contributions to funded pension plans in 2012 and estimated benefit payments for unfunded plans in all years.

(5)

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

(6)

Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $1,313 million mainly pertain to pipeline throughput agreements and include $856 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 $19,021 million mainly pertain to manufacturing supply, pipeline and terminaling agreements and include $316 million of obligations to equity companies.

(8)

Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $27.9 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $13.9 billion was associated with projects in Africa, Australia, Malaysia and Canada. 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, 2011, for guarantees relating to notes, loans and performance under contracts (Note 15). 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, 2011
	Equity Company Obligations(1)		Other Third-Party Obligations		Total
	(millions of dollars)
Guarantees
Debt-related	$	1,546	$	65	$	1,611
Other		3,061		3,784		6,845
Total	$	4,607	$	3,849	$	8,456

(1)

ExxonMobil share.

Financial Strength

On December 31, 2011, unused credit lines for short-term financing totaled approximately $5.5 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.


	2011		2010		2009
Fixed-charge coverage ratio (times)		53.2		42.2		25.8
Debt to capital (percent)		9.6		9.0		7.7
Net debt to capital (percent)		2.6		4.5		(1.0	)

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

Litigation and Other Contingencies

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

Index to Financial Statements

CAPITAL AND EXPLORATION EXPENDITURES


	2011				2010
	U.S.		Non-U.S		U.S.		Non-U.S.
	(millions of dollars)

Upstream (1)	$	10,741	$	22,350	$	6,349	$	20,970
Downstream		518		1,602		982		1,523
Chemical		290		1,160		279		1,936
Other		105		–		187		–
Total	$	11,654	$	25,112	$	7,797	$	24,429

(1)

Exploration expenses included.

Capital and exploration expenditures in 2011 were $36.8 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment profile of about $37 billion per year for the next several years. Actual spending could vary depending on the progress of individual projects.

Upstream spending of $33.1 billion in 2011 was up 21 percent from 2010, reflecting unconventional gas activities in the U.S. and continued progress on world-class projects in Australia, Canada and Papua New Guinea. The majority of expenditures are on development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves was 65 percent of total proved reserves at year-end 2011, and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $2.1 billion in 2011, a decrease of $0.4 billion from 2010, due to completion of environmental-related refining projects, primarily in the U.S. The Chemical capital expenditures of $1.5 billion were $0.8 billion lower in 2011 as investments in Asia to meet demand growth progressed toward completion.

TAXES


	2011		2010		2009
	(millions of dollars)

Income taxes	$	31,051	$	21,561	$	15,119
Effective income tax rate		46%		45%		47%
Sales-based taxes		33,503		28,547		25,936
All other taxes and duties		43,544		39,127		37,571
Total	$	108,098	$	89,235	$	78,626

2011

Income, sales based and all other taxes and duties totaled $108.1 billion in 2011, an increase of $18.9 billion or 21 percent from 2010. Income tax expense, both current and deferred, was $31.1 billion, $9.5 billion higher than 2010, reflecting higher pre-tax income in 2011. A higher share of pre-tax income from the Upstream segment in 2011 increased the effective tax rate to 46 percent compared to 45 percent in 2010. Sales-based and all other taxes and duties of $77.0 billion in 2011 increased $9.4 billion, reflecting higher prices.

2010

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

ENVIRONMENTAL MATTERS

Environmental Expenditures


	2011		2010
	(millions of dollars)

Capital expenditures	$	1,636	$	1,947
Other expenditures		3,248		2,593
Total	$	4,884	$	4,540

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 2011 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $4.9 billion. The total cost for such activities is expected to remain in this range in 2012 and 2013 (with capital expenditures approximately 45 percent of the total).

Environmental Liabilities

The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2011 for environmental liabilities were $420 million ($448 million in 2010) and the balance sheet reflects accumulated liabilities of $886 million as of December 31, 2011, and $948 million as of December 31, 2010.

Index to Financial Statements

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

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES


Worldwide Average Realizations (1)	2011		2010		2009
Crude oil and NGL ($/barrel)	$	100.79	$	74.04	$	57.86
Natural gas ($/kcf)		4.65		4.31		4.00

(1)

Consolidated subsidiaries.

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $350 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $200 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.

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

The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.

In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 35 percent of the Corporation’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.

Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its investments over a broad range of future prices. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs.

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

Risk Management

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

The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings, cash flow or fair value. Although the Corporation issues long-term debt from time to time and maintains a commercial paper program, internally generated funds are expected to cover the majority of its net near-term financial requirements. However, some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.

The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s limited use of the currency exchange contracts are not material.

Index to Financial Statements

Inflation and Other Uncertainties

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

CRITICAL ACCOUNTING ESTIMATES

The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1.

Oil and Gas Reserves

Evaluations of oil and gas reserves are important to the effective management of Upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment.

Oil and gas reserves include both proved and unproved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.

The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Reserves Technical Oversight group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 2.

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

Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves was 65 percent of total proved reserves at year-end 2011 (including both consolidated and equity company reserves), and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status.

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

The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method.

Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.

Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds the asset’s fair value.

Index to Financial Statements

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

properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluation include a significant decrease in current and projected reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and forecast operating losses.

In general, the Corporation does not view temporarily low oil and gas prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted.

Accordingly, any impairment tests that the Corporation performs make use of the Corporation’s price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on field production profiles, which are updated annually. Cash flow estimates for impairment testing exclude the effects of derivative instruments.

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

Asset Retirement Obligations (ARO)

The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair value of these obligations are recorded as liabilities on a discounted basis. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. AROs are disclosed in Note 8 to the financial statements.

Suspended Exploratory Well Costs

The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2011 are disclosed in Note 9 to the financial statements.

Consolidations

The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the underlying net assets of other significant entities that it does not control, but over which it exercises significant influence, are accounted for using the equity method of accounting.

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

Pension Benefits

The Corporation and its affiliates sponsor over 100 defined benefit (pension) plans in about 50 countries. Pension and Other Postretirement Benefits (Note 16) provides details on pension obligations, fund assets and pension expense.

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

Index to Financial Statements

For funded plans, including those in the United States, pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.

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

Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2011 was 7.5 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 6 percent and 9 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $140 million before tax.

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

Litigation Contingencies

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

The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management believes should be disclosed.

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

Tax Contingencies

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

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

Foreign Currency Translation

The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment.

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

Index to Financial Statements

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, 2011.

LOGO

Rex W. Tillerson

Chief Executive Officer

Donald D. Humphreys

Senior Vice President

(Principal Financial Officer)

Patrick T. Mulva

Vice President and Controller

(Principal Accounting Officer)

Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

LOGO

To the Shareholders of Exxon Mobil Corporation:

In our opinion, the accompanying Consolidated Balance Sheets and the related Consolidated Statements of Income, Comprehensive Income, Changes in Equity and Cash Flows present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2011, and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

February 24, 2012

Index to Financial Statements

CONSOLIDATED STATEMENT OF INCOME


	Note Reference Number		2011		2010		2009
			(millions of dollars)
Revenues and other income
Sales and other operating revenue (1)			$	467,029	$	370,125	$	301,500
Income from equity affiliates		6		15,289		10,677		7,143
Other income				4,111		2,419		1,943
Total revenues and other income			$	486,429	$	383,221	$	310,586
Costs and other deductions
Crude oil and product purchases			$	266,534	$	197,959	$	152,806
Production and manufacturing expenses				40,268		35,792		33,027
Selling, general and administrative expenses				14,983		14,683		14,735
Depreciation and depletion				15,583		14,760		11,917
Exploration expenses, including dry holes				2,081		2,144		2,021
Interest expense				247		259		548
Sales-based taxes (1)		18		33,503		28,547		25,936
Other taxes and duties		18		39,973		36,118		34,819
Total costs and other deductions			$	413,172	$	330,262	$	275,809
Income before income taxes			$	73,257	$	52,959	$	34,777
Income taxes		18		31,051		21,561		15,119
Net income including noncontrolling interests			$	42,206	$	31,398	$	19,658
Net income attributable to noncontrolling interests				1,146		938		378
Net income attributable to ExxonMobil			$	41,060	$	30,460	$	19,280

Earnings per common share (dollars)		11	$	8.43	$	6.24	$	3.99

Earnings per common share – assuming dilution (dollars)		11	$	8.42	$	6.22	$	3.98

(1)

Sales and other operating revenue includes sales-based taxes of $33,503 million for 2011, $28,547 million for 2010 and $25,936 million for 2009.

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

Index to Financial Statements

CONSOLIDATED BALANCE SHEET


	Note Reference Number		Dec. 31 2011			Dec. 31 2010
			(millions of dollars)
Assets
Current assets
Cash and cash equivalents			$	12,664		$	7,825
Cash and cash equivalents – restricted				404			628
Notes and accounts receivable, less estimated doubtful amounts		5		38,642			32,284
Inventories
Crude oil, products and merchandise		3		11,665			9,852
Materials and supplies				3,359			3,124
Other current assets				6,229			5,271
Total current assets			$	72,963		$	58,984
Investments, advances and long-term receivables		7		34,333			35,338
Property, plant and equipment, at cost, less accumulated depreciation and depletion		8		214,664			199,548
Other assets, including intangibles, net				9,092			8,640
Total assets			$	331,052		$	302,510

Liabilities
Current liabilities
Notes and loans payable		5	$	7,711		$	2,787
Accounts payable and accrued liabilities		5		57,067			50,034
Income taxes payable				12,727			9,812
Total current liabilities			$	77,505		$	62,633
Long-term debt		13		9,322			12,227
Postretirement benefits reserves		16		24,994			19,367
Deferred income tax liabilities		18		36,618			35,150
Other long-term obligations				21,869			20,454
Total liabilities			$	170,308		$	149,831

Commitments and contingencies		15

Equity
Common stock without par value (9,000 million shares authorized, 8,019 million shares issued)			$	9,512		$	9,371
Earnings reinvested				330,939			298,899
Accumulated other comprehensive income
Cumulative foreign exchange translation adjustment				4,168			5,011
Postretirement benefits reserves adjustment				(13,291	)		(9,889	)
Unrealized gain on cash flow hedges				–			55
Common stock held in treasury (3,285 million shares in 2011 and 3,040 million shares in 2010)				(176,932	)		(156,608	)
ExxonMobil share of equity			$	154,396		$	146,839
Noncontrolling interests				6,348			5,840
Total equity				160,744			152,679
Total liabilities and equity			$	331,052		$	302,510

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

Index to Financial Statements

CONSOLIDATED STATEMENT OF CASH FLOWS


	Note Reference Number		2011			2010			2009
			(millions of dollars)
Cash flows from operating activities
Net income including noncontrolling interests			$	42,206		$	31,398		$	19,658
Adjustments for noncash transactions
Depreciation and depletion				15,583			14,760			11,917
Deferred income tax charges/(credits)				142			(1,135	)		–
Postretirement benefits expense in excess of/(less than) net payments				544			1,700			(1,722	)
Other long-term obligation provisions in excess of/(less than) payments				(151	)		160			731
Dividends received greater than/(less than) equity in current earnings of equity companies				(273	)		(596	)		(483	)
Changes in operational working capital, excluding cash and debt
Reduction/(increase) – Notes and accounts receivable				(7,906	)		(5,863	)		(3,170	)
– Inventories				(2,208	)		(1,148	)		459
– Other current assets				222			913			132
Increase/(reduction) – Accounts and other payables				8,880			9,943			1,420
Net (gain) on asset sales		4		(2,842	)		(1,401	)		(488	)
All other items – net				1,148			(318	)		(16	)
Net cash provided by operating activities			$	55,345		$	48,413		$	28,438

Cash flows from investing activities
Additions to property, plant and equipment			$	(30,975	)	$	(26,871	)	$	(22,491	)
Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments		4		11,133			3,261			1,545
Decrease/(increase) in restricted cash and cash equivalents				224			(628	)		–
Additional investments and advances				(3,586	)		(1,239	)		(2,752	)
Collection of advances				1,119			1,133			724
Additions to marketable securities				(1,754	)		(15	)		(16	)
Sales of marketable securities				1,674			155			571
Net cash used in investing activities			$	(22,165	)	$	(24,204	)	$	(22,419	)

Cash flows from financing activities
Additions to long-term debt			$	702		$	1,143		$	225
Reductions in long-term debt				(266	)		(6,224	)		(68	)
Additions to short-term debt				1,063			598			1,336
Reductions in short-term debt				(1,103	)		(2,436	)		(1,575	)
Additions/(reductions) in debt with three months or less maturity				1,561			709			(71	)
Cash dividends to ExxonMobil shareholders				(9,020	)		(8,498	)		(8,023	)
Cash dividends to noncontrolling interests				(306	)		(281	)		(280	)
Changes in noncontrolling interests				(16	)		(7	)		(113	)
Tax benefits related to stock-based awards				260			122			237
Common stock acquired				(22,055	)		(13,093	)		(19,703	)
Common stock sold				924			1,043			752
Net cash used in financing activities			$	(28,256	)	$	(26,924	)	$	(27,283	)
Effects of exchange rate changes on cash			$	(85	)	$	(153	)	$	520
Increase/(decrease) in cash and cash equivalents			$	4,839		$	(2,868	)	$	(20,744	)
Cash and cash equivalents at beginning of year				7,825			10,693			31,437
Cash and cash equivalents at end of year			$	12,664		$	7,825		$	10,693

Non-Cash Transactions

The Corporation acquired all the outstanding equity of XTO Energy Inc. in an all-stock transaction valued at $24,659 million in 2010 (see Note 19).

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

Index to Financial Statements

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY


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

Balance as of December 31, 2008	$	5,314		$	265,680		$	(9,931	)	$	(148,098	)	$	112,965		$	4,558		$	117,523
Amortization of stock-based awards		685			–			–			–			685			–			685
Tax benefits related to stock-based awards		140			–			–			–			140			–			140
Other		(636	)		–			–			–			(636	)		–			(636	)
Net income for the year		–			19,280			–			–			19,280			378			19,658
Dividends – common shares		–			(8,023	)		–			–			(8,023	)		(280	)		(8,303	)
Foreign exchange translation adjustment		–			–			3,256			–			3,256			373			3,629
Postretirement benefits reserves adjustment (Note 16)		–			–			(196	)		–			(196	)		(144	)		(340	)
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs (Note 16)		–			–			1,410			–			1,410			51			1,461
Acquisitions, at cost		–			–			–			(19,703	)		(19,703	)		(127	)		(19,830	)
Dispositions		–			–			–			1,391			1,391			14			1,405
Balance as of December 31, 2009	$	5,503		$	276,937		$	(5,461	)	$	(166,410	)	$	110,569		$	4,823		$	115,392
Amortization of stock-based awards		751			–			–			–			751			–			751
Tax benefits related to stock-based awards		280			–			–			–			280			–			280
Other		(683	)		–			–			–			(683	)		10			(673	)
Net income for the year		–			30,460			–			–			30,460			938			31,398
Dividends – common shares		–			(8,498	)		–			–			(8,498	)		(281	)		(8,779	)
Foreign exchange translation adjustment		–			–			584			–			584			450			1,034
Adjustment for foreign exchange translation loss included in net income		–			–			25			–			25			–			25
Postretirement benefits reserves adjustment (Note 16)		–			–			(1,014	)		–			(1,014	)		(147	)		(1,161	)
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs (Note 16)		–			–			988			–			988			52			1,040
Change in fair value of cash flow hedges		–			–			184			–			184			–			184
Realized (gain)/loss from settled cash flow hedges included in net income		–			–			(129	)		–			(129	)		–			(129	)
Acquisitions, at cost		–			–			–			(13,093	)		(13,093	)		(5	)		(13,098	)
Issued for XTO merger		3,520			–			–			21,139			24,659			–			24,659
Other dispositions		–			–			–			1,756			1,756			–			1,756
Balance as of December 31, 2010	$	9,371		$	298,899		$	(4,823	)	$	(156,608	)	$	146,839		$	5,840		$	152,679
Amortization of stock-based awards		742			–			–			–			742			–			742
Tax benefits related to stock-based awards		202			–			–			–			202			–			202
Other		(803	)		–			–			–			(803	)		(5	)		(808	)
Net income for the year		–			41,060			–			–			41,060			1,146			42,206
Dividends – common shares		–			(9,020	)		–			–			(9,020	)		(306	)		(9,326	)
Foreign exchange translation adjustment		–			–			(843	)		–			(843	)		(24	)		(867	)
Postretirement benefits reserves adjustment (Note 16)		–			–			(4,557	)		–			(4,557	)		(350	)		(4,907	)
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs (Note 16)		–			–			1,155			–			1,155			62			1,217
Change in fair value of cash flow hedges		–			–			28			–			28			–			28
Realized (gain)/loss from settled cash flow hedges included in net income		–			–			(83	)		–			(83	)		–			(83	)
Acquisitions, at cost		–			–			–			(22,055	)		(22,055	)		(15	)		(22,070	)
Dispositions		–			–			–			1,731			1,731			–			1,731
Balance as of December 31, 2011	$	9,512		$	330,939		$	(9,123	)	$	(176,932	)	$	154,396		$	6,348		$	160,744

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

Index to Financial Statements

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (continued)


Common Stock Share Activity	Issued		Held in Treasury			Outstanding
	(millions of shares)

Balance as of December 31, 2008		8,019		(3,043	)		4,976
Acquisitions		–		(277	)		(277	)
Dispositions		–		28			28
Balance as of December 31, 2009		8,019		(3,292	)		4,727
Acquisitions		–		(199	)		(199	)
Issued for XTO merger		–		416			416
Other dispositions		–		35			35
Balance as of December 31, 2010		8,019		(3,040	)		4,979
Acquisitions		–		(278	)		(278	)
Dispositions		–		33			33
Balance as of December 31, 2011		8,019		(3,285	)		4,734

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME


	2011			2010			2009
	(millions of dollars)

Net income including noncontrolling interests	$	42,206		$	31,398		$	19,658
Other comprehensive income (net of income taxes)
Foreign exchange translation adjustment		(867	)		1,034			3,629
Adjustment for foreign exchange translation loss included in net income		–			25			–
Postretirement benefits reserves adjustment (excluding amortization)		(4,907	)		(1,161	)		(340	)
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs		1,217			1,040			1,461
Change in fair value of cash flow hedges		28			184			–
Realized (gain)/ loss from settled cash flow hedges included in net income		(83	)		(129	)		–
Comprehensive income including noncontrolling interests		37,594			32,391			24,408
Comprehensive income attributable to noncontrolling interests		834			1,293			658
Comprehensive income attributable to ExxonMobil	$	36,760		$	31,098		$	23,750

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

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2011 presentation basis.

1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities.

Amounts representing the Corporation’s percentage interest in the underlying net assets of entities that it does not control, but over which it exercises significant influence, are included in “Investments, advances and long-term receivables”. The Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.”

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

The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Changes in Equity.

Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.

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

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

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

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

Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions.

The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the underlying hedged item.

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

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.

Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.

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

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

Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.

Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods.

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

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

Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

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

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

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.

Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Corporation.

Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

Index to Financial Statements

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

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

Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates.

Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets.

For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.

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

2. Accounting Changes

The Corporation did not adopt authoritative guidance in 2011 that had a material impact on the Corporation’s financial statements.

3. Miscellaneous Financial Information

Research and development costs totaled $1,044 million in 2011, $1,012 million in 2010 and $1,050 million in 2009.

Net income included before-tax aggregate foreign exchange transaction losses of $184 million and $251 million, and gains of $54 million in 2011, 2010 and 2009, respectively.

In 2011, 2010 and 2009, net income included gains of $292 million, $317 million and $207 million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $25.6 billion and $21.3 billion at December 31, 2011, and 2010, respectively.

Crude oil, products and merchandise as of year-end 2011 and 2010 consist of the following:


	2011		2010
	(billions of dollars)

Petroleum products	$	4.1	$	3.5
Crude oil		4.8		3.8
Chemical products		2.3		2.1
Gas/other		0.5		0.5
Total	$	11.7	$	9.9

4. Cash Flow Information

The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.

The “Net (gain) on asset sales” in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes before-tax gains from the sale of some Upstream Canadian, U.K. and other producing properties and assets, and the sale of U.S. service stations in 2011; from the sale of some Upstream Gulf of Mexico and other producing properties, the sale of U.S. service stations and other Downstream assets and investments and the formation of a Chemical joint venture in 2010; and from the sale of Downstream assets and investments and producing properties in the Upstream in 2009. These gains are reported in “Other income” on the Consolidated Statement of Income.

Included in “Proceeds associated with sales of subsidiaries, property, plant, and equipment, and sales and returns of investments” in 2011 is a $3.6 billion deposit for a potential asset sale.


	2011		2010		2009
	(millions of dollars)

Cash payments for interest	$	557	$	703	$	820

Cash payments for income taxes	$	27,254	$	18,941	$	15,427

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5. Additional Working Capital Information


	Dec. 31 2011		Dec. 31 2010
	(millions of dollars)
Notes and accounts receivable
Trade, less reserves of $128 million and $152 million	$	30,044	$	25,439
Other, less reserves of $39 million and $34 million		8,598		6,845
Total	$	38,642	$	32,284

Notes and loans payable
Bank loans	$	1,237	$	532
Commercial paper		2,281		1,346
Long-term debt due within one year		3,431		345
Other		762		564
Total	$	7,711	$	2,787

Accounts payable and accrued liabilities
Trade payables	$	33,969	$	30,780
Payables to equity companies		5,553		5,450
Accrued taxes other than income taxes		7,123		6,778
Other		10,422		7,026
Total	$	57,067	$	50,034

On December 31, 2011, unused credit lines for short-term financing totaled approximately $5.5 billion. Of this total, $2.8 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2011, and 2010, was 1.9 percent and 1.2 percent, respectively.

6. Equity Company Information

The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several power generation, refining, petrochemical manufacturing and chemical ventures. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 19 percent, 18 percent and 19 percent in the years 2011, 2010 and 2009, respectively.


	2011				2010				2009
Equity Company Financial Summary	Total		ExxonMobil Share		Total		ExxonMobil Share		Total		ExxonMobil Share
	(millions of dollars)

Total revenues	$	204,635	$	65,147	$	153,020	$	48,355	$	112,153	$	36,570
Income before income taxes	$	68,908	$	20,892	$	48,075	$	14,735	$	28,472	$	9,632
Income taxes		19,812		5,603		13,962		4,058		7,775		2,489
Income from equity affiliates	$	49,096	$	15,289	$	34,113	$	10,677	$	20,697	$	7,143

Current assets	$	52,879	$	17,317	$	48,573	$	15,860	$	37,376	$	12,843
Long-term assets		96,908		30,833		90,646		29,805		88,153		27,983
Total assets	$	149,787	$	48,150	$	139,219	$	45,665	$	125,529	$	40,826
Current liabilities	$	41,016	$	12,454	$	33,160	$	10,260	$	24,854	$	8,085
Long-term liabilities		62,472		18,728		59,596		17,976		57,384		16,999
Net assets	$	46,299	$	16,968	$	46,463	$	17,429	$	43,291	$	15,742

Index to Financial Statements

A list of significant equity companies as of December 31, 2011, together with the Corporation’s percentage ownership interest, is detailed below:



	Percentage Ownership Interest
Upstream
Aera Energy LLC		48
BEB Erdgas und Erdoel GmbH		50
Cameroon Oil Transportation Company S.A.		41
Castle Peak Power Company Limited		60
Golden Pass LNG Terminal LLC		18
Nederlandse Aardolie Maatschappij B.V.		50
Qatar Liquefied Gas Company Limited		10
Qatar Liquefied Gas Company Limited 2		24
Ras Laffan Liquefied Natural Gas Company Limited		25
Ras Laffan Liquefied Natural Gas Company Limited II		31
Ras Laffan Liquefied Natural Gas Company Limited (3)		30
South Hook LNG Terminal Company Limited		24
Tengizchevroil, LLP		25
Terminale GNL Adriatico S.r.l.		71
Downstream
Chalmette Refining, LLC		50
Fujian Refining & Petrochemical Co. Ltd.		25
Saudi Aramco Mobil Refinery Company Ltd.		50

Chemical
Al-Jubail Petrochemical Company		50
Infineum Holdings B.V.		50
Saudi Yanbu Petrochemical Co.		50
Toray Tonen Specialty Separator Godo Kaisha		50

7. Investments, Advances and Long-Term Receivables


	Dec. 31, 2011		Dec. 31, 2010
	(millions of dollars)
Companies carried at equity in underlying assets
Investments	$	16,968	$	17,429
Advances		9,740		9,286
Total equity company investments and advances	$	26,708	$	26,715
Companies carried at cost or less and stock investments carried at fair value		1,544		1,557
Long-term receivables and miscellaneous investments at cost or less, net of reserves of $469 million and $292 million		6,081		7,066
Total	$	34,333	$	35,338

8. Property, Plant and Equipment and Asset Retirement Obligations


	Dec. 31, 2011				Dec. 31, 2010
Property, Plant and Equipment	Cost		Net		Cost		Net
	(millions of dollars)

Upstream	$	283,710	$	163,975	$	264,136	$	148,152
Downstream		67,900		28,801		68,652		30,095
Chemical		30,405		14,469		29,524		14,255
Other		11,980		7,419		11,626		7,046
Total	$	393,995	$	214,664	$	373,938	$	199,548

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

Accumulated depreciation and depletion totaled $179,331 million at the end of 2011 and $174,390 million at the end of 2010. Interest capitalized in 2011, 2010 and 2009 was $593 million, $532 million and $425 million, respectively.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Asset Retirement Obligations

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

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


	2011			2010
	(millions of dollars)

Beginning balance	$	9,614		$	8,473
Accretion expense and other provisions		581			563
Reduction due to property sales		(854	)		(183	)
Payments made		(662	)		(638	)
Liabilities incurred		117			1,094
Foreign currency translation		(62	)		(45	)
Revisions		1,844			350
Ending balance	$	10,578		$	9,614

9. Accounting for Suspended Exploratory Well Costs

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

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

Change in capitalized suspended exploratory well costs:


	2011			2010			2009
	(millions of dollars)

Balance beginning at January 1	$	2,893		$	2,005		$	1,585
Additions pending the determination of proved reserves		310			1,103			624
Charged to expense		(213	)		(104	)		(51	)
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(149	)		(136	)		(200	)
Other		40			25			47
Ending balance	$	2,881		$	2,893		$	2,005
Ending balance attributed to equity companies included above	$	–		$	–		$	9

Period end capitalized suspended exploratory well costs:


	2011		2010		2009
	(millions of dollars)

Capitalized for a period of one year or less	$	310	$	1,103	$	624
Capitalized for a period of between one and five years		1,922		1,294		924
Capitalized for a period of between five and ten years		409		278		220
Capitalized for a period of greater than ten years		240		218		237
Capitalized for a period greater than one year – subtotal	$	2,571	$	1,790	$	1,381
Total	$	2,881	$	2,893	$	2,005

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


	2011		2010		2009
Number of projects with first capitalized well drilled in the preceding 12 months		4		9		18
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months		58		59		57
Total		62		68		75

Index to Financial Statements

Of the 58 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2011, 26 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 32 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 32 projects, which total $1,133 million.


Country/Project	Dec. 31, 2011		Years Wells Drilled	Comment
(millions of dollars)
Angola
– Perpetua-Zina-Acacia	$	15	2008 - 2009	Oil field near Pazflor development, awaiting capacity in existing/planned infrastructure.
Australia
– East Pilchard		10	2001	Gas field near Kipper/Tuna development, awaiting capacity in existing/planned infrastructure.
– SE Longtom		15	2010	Gas field near Tuna development, awaiting capacity in existing/planned infrastructure.
Indonesia
– Natuna		118	1981 - 1983	Development activity under way, while continuing discussions with the government on contract terms pursuant to executed Heads of Agreement.
Kazakhstan
– Kairan		53	2004 - 2007	Declarations involving field commerciality filed with Kazakhstan government in 2008; progressing commercialization and field development studies.
Malaysia
– Besar		18	1992 - 2010	Gas field off the east coast of Malaysia; progressing development plan.
– Other (2 projects)		8	1979 - 1995	Projects primarily awaiting capacity in existing or planned infrastructure.
Nigeria
– Bolia		15	2002 - 2006	Evaluating development plan, while continuing discussions with the government regarding regional hub strategy.
– Bosi		79	2002 - 2006	Development activity under way, while continuing discussions with the government regarding development plan.
– Pegi		32	2009	Awaiting capacity in existing/planned infrastructure
– Other (4 projects)		13	2002	Pursuing development of several additional offshore satellite discoveries which will tie back to existing/planned production facilities.
Norway
– Gamma		20	2008 - 2009	Evaluating development plan for tieback to existing production facilities.
– H-North		15	2007	Discovery near existing facilities in Fram area; progressing development plans.
– Lavrans		22	1995 - 1999	Development awaiting capacity in existing Kristin production facility; evaluating development concepts for phased ullage scenarios.
– Nyk High		19	2008	Evaluating field development alternatives.
– Other (6 projects)		26	1992 - 2010	Evaluating development plans, including potential for tieback to existing production facilities.
Papua New Guinea
– Juha		28	2007	Working on development plans to tie into planned LNG facilities.
United Kingdom
– Fram		55	2009	Progressing development and commercialization plans.
– Other (2 projects)		14	2001 - 2004	Projects primarily awaiting capacity in existing or planned infrastructure.
United States
– Julia Unit		78	2007 - 2008	Reached agreement with the Department of Interior and Department of Justice providing for suspension of production; progressing development plans with partners.
– Point Thomson		449	1977 - 2010	Continuing discussions with government and partners on development plan.
– Tip Top		31	2009	Evaluating development concept and requisite facility upgrades.
Total 2011 (32 projects)	$	1,133

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Leased Facilities

At December 31, 2011, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $7,914 million as indicated in the table. Estimated related rental income from noncancelable subleases is $107 million.


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

2012	$	2,152	$	18
2013		1,696		17
2014		1,219		15
2015		802		12
2016		415		10
2017 and beyond		1,630		35
Total	$	7,914	$	107

Net rental cost under both cancelable and noncancelable operating leases incurred during 2011, 2010 and 2009 were as follows:


	2011		2010		2009
	(millions of dollars)

Rental cost	$	4,061	$	3,762	$	4,426
Less sublease rental income		74		90		98
Net rental cost	$	3,987	$	3,672	$	4,328

11. Earnings Per Share


	2011		2010		2009
Earnings per common share

Net income attributable to ExxonMobil (millions of dollars)	$	41,060	$	30,460	$	19,280

Weighted average number of common shares outstanding (millions of shares)		4,870		4,885		4,832

Earnings per common share (dollars)	$	8.43	$	6.24	$	3.99

Earnings per common share – assuming dilution

Net income attributable to ExxonMobil (millions of dollars)	$	41,060	$	30,460	$	19,280

Weighted average number of common shares outstanding (millions of shares)		4,870		4,885		4,832
Effect of employee stock-based awards		5		12		16
Weighted average number of common shares outstanding – assuming dilution		4,875		4,897		4,848

Earnings per common share – assuming dilution (dollars)	$	8.42	$	6.22	$	3.98

Dividends paid per common share (dollars)	$	1.85	$	1.74	$	1.66

12. Financial Instruments and Derivatives

Financial Instruments. The fair value of financial instruments is determined by reference to observable market data and other valuation techniques as appropriate. The only category of financial instruments where the difference between fair value and recorded book value is notable is long-term debt. The estimated fair value of total long-term debt, including capitalized lease obligations, was $9.8 billion and $12.8 billion at December 31, 2011, and 2010, respectively, as compared to recorded book values of $9.3 billion and $12.2 billion at December 31, 2011, and 2010, respectively. The fair value hierarchy for long-term debt is primarily Level 1 (quoted prices for identical assets in active markets).

Index to Financial Statements

Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features.

When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions. The cash flow hedge positions acquired as a result of the XTO merger were settled by December 31, 2011, and those programs have been discontinued.

The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net liability of $3 million at year-end 2011 and a net asset of $172 million at year-end 2010. Assets and liabilities associated with derivatives are predominantly recorded either in “Other current assets” or “Accounts payable and accrued liabilities.”

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

The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $131 million, $221 million and $(73) million during 2011, 2010 and 2009, respectively. Income statement effects associated with derivatives are recorded either in “Sales and other operating revenue” or “Crude oil and product purchases.” Of the amount stated above for 2011, cash flow hedges resulted in a before-tax gain of $136 million.

The Corporation believes there are no material market or credit risks to the Corporation’s financial position, results of operations or liquidity as a result of the derivative activities described above.

13. Long-Term Debt

At December 31, 2011, long-term debt consisted of $8,855 million due in U.S. dollars and $467 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $3,431 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, in each of the four years after December 31, 2012, in millions of dollars, are: 2013 – $967, 2014 – $871, 2015 – $606 and 2016 – $503. At December 31, 2011, the Corporation’s unused long-term credit lines were not material.

Summarized long-term debt at year-end 2011 and 2010 are shown in the table below:


	2011		2010
	(millions of dollars)
SeaRiver Maritime Financial Holdings, Inc. (1)
Guaranteed deferred interest debentures due 2012
– Face value net of unamortized discount plus accrued interest	$	—	$	2,389

XTO Energy Inc. (2)
7.500% senior note due 2012		—		199
5.900% senior note due 2012		—		233
6.250% senior note due 2013		185		193
4.625% senior note due 2013		145		149
5.750% senior note due 2013		346		359
4.900% senior note due 2014		260		267
5.000% senior note due 2015		138		142
5.300% senior note due 2015		255		262
5.650% senior note due 2016		222		227
6.250% senior note due 2017		513		534
5.500% senior note due 2018		402		420
6.500% senior note due 2018		506		524
6.100% senior note due 2036		203		204
6.750% senior note due 2037		317		329
6.375% senior note due 2038		241		258

Mobil Services (Bahamas) Ltd.
Variable note due 2035 (3)		972		972
Variable note due 2034 (4)		311		311

Mobil Producing Nigeria Unlimited (5)
Variable notes due 2012-2017		543		415

Esso (Thailand) Public Company Ltd. (6)
Variable notes due 2012-2017		413		522

Mobil Corporation
8.625% debentures due 2021		248		248

Industrial revenue bonds due 2012-2051 (7)		2,315		2,247
Other U.S. dollar obligations (8)		496		454
Other foreign currency obligations		31		65
Capitalized lease obligations (9)		260		304
Total long-term debt	$	9,322	$	12,227

(1)

Additional information is provided for this subsidiary on the following pages.

(2)

Includes premiums of $421 million.

(3)

Average effective interest rate of 0.2% in 2011 and 0.3% in 2010.

(4)

Average effective interest rate of 0.3% in 2011 and 0.4% in 2010.

(5)

Average effective interest rate of 4.2% in 2011 and 4.6% in 2010.

(6)

Average effective interest rate of 3.2% in 2011 and 1.7% in 2010.

(7)

Average effective interest rate of 0.1% in 2011 and 0.2% in 2010.

(8)

Average effective interest rate of 4.8% in 2011 and 4.7% in 2010.

(9)

Average imputed interest rate of 8.5% in 2011 and 8.1% in 2010.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

Exxon Mobil Corporation has fully and unconditionally guaranteed the deferred interest debentures due 2012 ($2,662 million short-term) of SeaRiver Maritime Financial Holdings, Inc., a 100-percent-owned subsidiary of Exxon Mobil Corporation.

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

		Consolidating		Consolidating			Consolidating		Consolidating			Consolidating
	Exxon Mobil Corporation Parent Guarantor		SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated statement of income for 12 months ended December 31, 2011
Revenues and other income
Sales and other operating revenue, including sales-based taxes	$	17,942	$	–		$	449,087	$	–		$	467,029
Income from equity affiliates		39,198		(14	)		15,196		(39,091	)		15,289
Other income		472		–			3,639		–			4,111
Intercompany revenue		54,891		3			451,627		(506,521	)		–
Total revenues and other income		112,503		(11	)		919,549		(545,612	)		486,429
Costs and other deductions
Crude oil and product purchases		57,604		–			704,125		(495,195	)		266,534
Production and manufacturing expenses		7,827		–			38,234		(5,793	)		40,268
Selling, general and administrative expenses		2,936		–			12,748		(701	)		14,983
Depreciation and depletion		1,660		–			13,923		–			15,583
Exploration expenses, including dry holes		219		–			1,862		–			2,081
Interest expense		305		274			4,512		(4,844	)		247
Sales-based taxes		–		–			33,503		–			33,503
Other taxes and duties		40		–			39,933		–			39,973
Total costs and other deductions		70,591		274			848,840		(506,533	)		413,172
Income before income taxes		41,912		(285	)		70,709		(39,079	)		73,257
Income taxes		852		(101	)		30,300		–			31,051
Net income including noncontrolling interests		41,060		(184	)		40,409		(39,079	)		42,206
Net income attributable to noncontrolling interests		–		–			1,146		–			1,146
Net income attributable to ExxonMobil	$	41,060	$	(184)		$	39,263	$	(39,079	)	$	41,060

Index to Financial Statements

		Consolidating			Consolidating			Consolidating		Consolidating			Consolidating
	Exxon Mobil Corporation Parent Guarantor			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated statement of income for 12 months ended December 31, 2010
Revenues and other income
Sales and other operating revenue, including sales-based taxes	$	15,382		$	–		$	354,743	$	–		$	370,125
Income from equity affiliates		28,401			(2	)		10,589		(28,311	)		10,677
Other income		790			–			1,629		–			2,419
Intercompany revenue		39,433			4			332,483		(371,920	)		–
Total revenues and other income		84,006			2			699,444		(400,231	)		383,221
Costs and other deductions
Crude oil and product purchases		40,788			–			518,961		(361,790	)		197,959
Production and manufacturing expenses		7,627			–			33,400		(5,235	)		35,792
Selling, general and administrative expenses		2,871			–			12,482		(670	)		14,683
Depreciation and depletion		1,761			–			12,999		–			14,760
Exploration expenses, including dry holes		251			–			1,893		–			2,144
Interest expense		217			246			4,035		(4,239	)		259
Sales-based taxes		–			–			28,547		–			28,547
Other taxes and duties		29			–			36,089		–			36,118
Total costs and other deductions		53,544			246			648,406		(371,934	)		330,262
Income before income taxes		30,462			(244	)		51,038		(28,297	)		52,959
Income taxes		2			(90	)		21,649		–			21,561
Net income including noncontrolling interests		30,460			(154	)		29,389		(28,297	)		31,398
Net income attributable to noncontrolling interests		–			–			938		–			938
Net income attributable to ExxonMobil	$	30,460		$	(154	)	$	28,451	$	(28,297	)	$	30,460

Condensed consolidated statement of income for 12 months ended December 31, 2009
Revenues and other income
Sales and other operating revenue, including sales-based taxes	$	11,352		$	–		$	290,148	$	–		$	301,500
Income from equity affiliates		19,852			7			7,060		(19,776	)		7,143
Other income		813			–			1,130		–			1,943
Intercompany revenue		30,889			4			271,663		(302,556	)		–
Total revenues and other income		62,906			11			570,001		(322,332	)		310,586
Costs and other deductions
Crude oil and product purchases		31,419			–			411,689		(290,302	)		152,806
Production and manufacturing expenses		7,811			–			30,805		(5,589	)		33,027
Selling, general and administrative expenses		2,574			–			12,852		(691	)		14,735
Depreciation and depletion		1,571			–			10,346		–			11,917
Exploration expenses, including dry holes		230			–			1,791		–			2,021
Interest expense		1,200			222			5,126		(6,000	)		548
Sales-based taxes		–			–			25,936		–			25,936
Other taxes and duties		(29	)		–			34,848		–			34,819
Total costs and other deductions		44,776			222			533,393		(302,582	)		275,809
Income before income taxes		18,130			(211	)		36,608		(19,750	)		34,777
Income taxes		(1,150	)		(81	)		16,350		–			15,119
Net income including noncontrolling interests		19,280			(130	)		20,258		(19,750	)		19,658
Net income attributable to noncontrolling interests		–			–			378		–			378
Net income attributable to ExxonMobil	$	19,280		$	(130	)	$	19,880	$	(19,750	)	$	19,280

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

		Consolidating			Consolidating			Consolidating		Consolidating			Consolidating
	Exxon Mobil Corporation Parent Guarantor			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries		Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated balance sheet for year ended December 31, 2011
Cash and cash equivalents	$	1,354		$	–		$	11,310	$	–		$	12,664
Cash and cash equivalents – restricted		239			–			165		–			404
Notes and accounts receivable – net		2,719			–			36,569		(646	)		38,642
Inventories		1,634			–			13,390		–			15,024
Other current assets		353			–			5,876		–			6,229
Total current assets		6,299			–			67,310		(646	)		72,963
Investments and other assets		260,410			393			485,157		(702,535	)		43,425
Property, plant and equipment – net		19,687			–			194,977		–			214,664
Intercompany receivables		17,325			2,726			543,844		(563,895	)		—
Total assets	$	303,721		$	3,119		$	1,291,288	$	(1,267,076	)	$	331,052
Notes and loans payable	$	1,851		$	2,662		$	3,198	$	–		$	7,711
Accounts payable and accrued liabilities		3,117			57			53,893		–			57,067
Income taxes payable		–			2			13,371		(646	)		12,727
Total current liabilities		4,968			2,721			70,462		(646	)		77,505
Long-term debt		293			–			9,029		–			9,322
Postretirement benefits reserves		12,344			–			12,650		–			24,994
Deferred income tax liabilities		1,450			–			35,168		–			36,618
Other long-term liabilities		5,215			–			16,654		–			21,869
Intercompany payables		125,055			386			438,454		(563,895	)		–
Total liabilities		149,325			3,107			582,417		(564,541	)		170,308
Earnings reinvested		330,939			(1,032	)		141,467		(140,435	)		330,939
Other equity		(176,543	)		1,044			561,056		(562,100	)		(176,543	)
ExxonMobil share of equity		154,396			12			702,523		(702,535	)		154,396
Noncontrolling interests		–			–			6,348		–			6,348
Total equity		154,396			12			708,871		(702,535	)		160,744
Total liabilities and equity	$	303,721		$	3,119		$	1,291,288	$	(1,267,076	)	$	331,052

Index to Financial Statements

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

Condensed consolidated balance sheet for year ended December 31, 2010
Cash and cash equivalents	$	309		$	–		$	7,516	$	–		$	7,825
Cash and cash equivalents – restricted		371			–			257		–			628
Notes and accounts receivable – net		2,104			–			30,346		(166	)		32,284
Inventories		1,457			–			11,519		–			12,976
Other current assets		239			–			5,032		–			5,271
Total current assets		4,480			–			54,670		(166	)		58,984
Investments and other assets		255,005			458			462,893		(674,378	)		43,978
Property, plant and equipment – net		18,830			–			180,718		–			199,548
Intercompany receivables		18,186			2,457			528,405		(549,048	)		–
Total assets	$	296,501		$	2,915		$	1,226,686	$	(1,223,592	)	$	302,510
Notes and loans payable	$	1,042		$	13		$	1,732	$	–		$	2,787
Accounts payable and accrued liabilities		2,987			–			47,047		–			50,034
Income taxes payable		–			3			9,975		(166	)		9,812
Total current liabilities		4,029			16			58,754		(166	)		62,633
Long-term debt		295			2,389			9,543		–			12,227
Postretirement benefits reserves		9,660			–			9,707		–			19,367
Deferred income tax liabilities		642			107			34,401		–			35,150
Other long-term liabilities		5,632			–			14,822		–			20,454
Intercompany payables		129,404			382			419,262		(549,048	)		–
Total liabilities		149,662			2,894			546,489		(549,214	)		149,831
Earnings reinvested		298,899			(848	)		132,357		(131,509	)		298,899
Other equity		(152,060	)		869			542,000		(542,869	)		(152,060	)
ExxonMobil share of equity		146,839			21			674,357		(674,378	)		146,839
Noncontrolling interests		–			–			5,840		–			5,840
Total equity		146,839			21			680,197		(674,378	)		152,679
Total liabilities and equity	$	296,501		$	2,915		$	1,226,686	$	(1,223,592	)	$	302,510

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

		Consolidating			Consolidating			Consolidating			Consolidating			Consolidating
	Exxon Mobil Corporation Parent Guarantor			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries			Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated statement of cash flows for 12 months ended December 31, 2011
Cash provided by/(used in) operating activities	$	37,752		$	63		$	47,683		$	(30,153	)	$	55,345
Cash flows from investing activities
Additions to property, plant and equipment		(2,516	)		–			(28,459	)		–			(30,975	)
Proceeds associated with sales of long-term assets		667			–			10,466			–			11,133
Decrease/(increase) in restricted cash and cash equivalents		132			–			92			–			224
Net intercompany investing		(4,227	)		(229	)		4,015			441			–
All other investing, net		(1,679	)		–			(868	)		–			(2,547	)
Net cash provided by/(used in) investing activities		(7,623	)		(229	)		(14,754	)		441			(22,165	)
Cash flows from financing activities
Additions to short- and long-term debt		–			–			1,765			–			1,765
Reductions in short- and long-term debt		(2	)		(13	)		(1,354	)		–			(1,369	)
Additions/(reductions) in debt with three months or less maturity		809			–			752			–			1,561
Cash dividends		(9,020	)		–			(30,153	)		30,153			(9,020	)
Common stock acquired		(22,055	)		–			–			–			(22,055	)
Net intercompany financing activity		–			4			262			(266	)		–
All other financing, net		1,184			175			(322	)		(175	)		862
Net cash provided by/(used in) financing activities		(29,084	)		166			(29,050	)		29,712			(28,256	)
Effects of exchange rate changes on cash		–			–			(85	)		–			(85	)
Increase/(decrease) in cash and cash equivalents	$	1,045		$	–		$	3,794		$	–		$	4,839

Condensed consolidated statement of cash flows for 12 months ended December 31, 2010
Cash provided by/(used in) operating activities	$	35,740		$	63		$	18,307		$	(5,697	)	$	48,413
Cash flows from investing activities
Additions to property, plant and equipment		(2,922	)		–			(23,949	)		–			(26,871	)
Proceeds associated with sales of long-term assets		1,484			–			1,777			–			3,261
Decrease/(increase) in restricted cash and cash equivalents		(371	)		–			(257	)		–			(628	)
Net intercompany investing		(13,966	)		(200	)		13,813			353			–
All other investing, net		(672	)		–			706			–			34
Net cash provided by/(used in) investing activities		(16,447	)		(200	)		(7,910	)		353			(24,204	)
Cash flows from financing activities
Additions to short- and long-term debt		–			–			1,741			–			1,741
Reductions in short- and long-term debt		(3	)		(13	)		(8,644	)		–			(8,660	)
Additions/(reductions) in debt with three months or less maturity		997			–			(288	)		–			709
Cash dividends		(8,498	)		–			(5,697	)		5,697			(8,498	)
Common stock acquired		(13,093	)		–			–			–			(13,093	)
Net intercompany financing activity		–			–			202			(202	)		–
All other financing, net		1,164			150			(286	)		(151	)		877
Net cash provided by/(used in) financing activities		(19,433	)		137			(12,972	)		5,344			(26,924	)
Effects of exchange rate changes on cash		–			–			(153	)		–			(153	)
Increase/(decrease) in cash and cash equivalents	$	(140	)	$	–		$	(2,728	)	$	–		$	(2,868	)

Index to Financial Statements

		Consolidating			Consolidating			Consolidating			Consolidating			Consolidating
	Exxon Mobil Corporation Parent Guarantor			SeaRiver Maritime Financial Holdings, Inc.			All Other Subsidiaries			Consolidating and Eliminating Adjustments			Consolidated
	(millions of dollars)
Condensed consolidated statement of cash flows for 12 months ended December 31, 2009
Cash provided by/(used in) operating activities	$	27,424		$	72		$	28,024		$	(27,082	)	$	28,438
Cash flows from investing activities
Additions to property, plant and equipment		(2,686	)		–			(19,805	)		–			(22,491	)
Proceeds associated with sales of long-term assets		228			–			1,317			–			1,545
Decrease/(increase) in restricted cash and cash equivalents		–			–			–			–			–
Net intercompany investing		(1,826	)		(209	)		1,717			318			–
All other investing, net		–			–			(1,473	)		–			(1,473	)
Net cash provided by/(used in) investing activities		(4,284	)		(209	)		(18,244	)		318			(22,419	)
Cash flows from financing activities
Additions to short- and long-term debt		–			–			1,561			–			1,561
Reductions in short- and long-term debt		(3	)		(13	)		(1,627	)		–			(1,643	)
Additions/(reductions) in debt with three months or less maturity		39			–			(110	)		–			(71	)
Cash dividends		(8,023	)		–			(27,082	)		27,082			(8,023	)
Common stock acquired		(19,703	)		–			–			–			(19,703	)
Net intercompany financing activity		–			–			168			(168	)		–
All other financing, net		988			150			(392	)		(150	)		596
Net cash provided by/(used in) financing activities		(26,702	)		137			(27,482	)		26,764			(27,283	)
Effects of exchange rate changes on cash		–			–			520			–			520
Increase/(decrease) in cash and cash equivalents	$	(3,562	)	$	–		$	(17,182	)	$	–		$	(20,744	)

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. Incentive Program

The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited, expire or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2011, remaining shares available for award under the 2003 Incentive Program were 133,183 thousand.

Restricted Stock. Awards totaling 10,533 thousand, 10,648 thousand (excluding XTO merger-related grants), and 10,133 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2011, 2010 and 2009, respectively. Compensation expense for these awards is based on the price of the stock at the date of grant and is recognized in income over the requisite service period. These shares are issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. Awards granted to a small number of senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.

Additionally, in 2010 long-term incentive awards totaling 4,206 thousand shares of restricted (nonvested) common stock, with a value of $250 million, were granted in association with the XTO merger. The majority of these awards vest over periods of up to three years after the initial grant.

The Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in conjunction with benefit plans and programs. Purchases may be discontinued at any time without prior notice.

The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2011.


	2011
Restricted stock and units outstanding	Shares			Weighted Average Grant-Date Fair Value per Share
	(thousands)

Issued and outstanding at January 1		47,306		$	69.74
2010 award issued in 2011		10,639		$	68.74
Vested		(10,628	)	$	64.37
Forfeited		(536	)	$	67.35
Issued and outstanding at December 31		46,781		$	70.76


Value of restricted stock and units	2011		2010		2009
Grant price	$	79.52	$	66.07	$	75.40
Value at date of grant:
	(millions of dollars)
Restricted stock and units settled in stock	$	766	$	672	$	711
Merger-related granted and converted XTO awards		–		250		–
Units settled in cash		72		60		53
Total value	$	838	$	982	$	764

As of December 31, 2011, there was $2,168 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.5 years. The compensation cost charged against income for the restricted stock and restricted units was $793 million, $801 million and $723 million for 2011, 2010 and 2009, respectively. The income tax benefit recognized in income related to this compensation expense was $73 million, $81 million and $76 million for the same periods, respectively. The fair value of shares and units vested in 2011, 2010 and 2009 was $801 million, $718 million and $763 million, respectively. Cash payments of $46 million, $42 million and $41 million for vested restricted stock units settled in cash were made in 2011, 2010 and 2009, respectively.

Index to Financial Statements

Stock Options. The Corporation has not granted any stock options under the 2003 Incentive Program. In 2010, the Corporation granted 12,393 thousand of converted XTO stock options with a grant-date fair value of $182 million as a result of the XTO merger. The grant included 893 thousand of unvested options. Compensation expense for these awards is based on estimated grant-date fair values.

These stock options generally vest and become exercisable ratably over a three-year period, and may include a provision for accelerated vesting when the common stock price reaches specified levels. Some stock option tranches vest only when the common stock price reaches specified levels. As of December 31, 2011, unvested stock options of 226 thousand included 10 thousand options that vest ratably over three years and 216 thousand options that vest at a stock price of $126.80.

Changes that occurred in the Corporation’s stock options in 2011 are summarized below:


	2011
Stock options	Shares			Avg. Exercise Price		Weighted Average Remaining Contractual Term
	(thousands)

Outstanding at January 1		29,509		$	44.65
Exercised		(23,880	)	$	38.81
Forfeited		(80	)	$	48.01
Outstanding at December 31		5,549		$	69.76	3.0 Years

Exercisable at December 31		5,323		$	68.65	3.0 Years

Compensation expense of $1 million in 2011 and $2 million in 2010 fully expensed the nonvested merger-related XTO stock options. No compensation expense was recognized for stock options in 2009 as all remaining outstanding stock options at that time were fully vested. Cash received from stock option exercises was $924 million, $1,043 million and $752 million for 2011, 2010 and 2009, respectively. The cash tax benefit realized for the options exercised was $221 million, $89 million and $164 million for 2011, 2010 and 2009, respectively. The aggregate intrinsic value of stock options exercised in 2011, 2010 and 2009 was $986 million, $539 million and $563 million, respectively. The intrinsic value for the balance of outstanding stock options at December 31, 2011, was $98 million. The intrinsic value for the balance of exercisable stock options at December 31, 2011, was $97 million.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15. Litigation and Other Contingencies

Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters as well as other matters which management believes should be disclosed. ExxonMobil will continue to defend itself vigorously in these matters. 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 material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole.

On June 30, 2011, a state district court jury in Baltimore County, Maryland returned a verdict against Exxon Mobil Corporation in Allison, et al v. Exxon Mobil Corporation, a case involving an accidental 26,000 gallon gasoline leak at a suburban Baltimore service station. The verdict included approximately $497 million in compensatory damages and approximately $1.0 billion in punitive damages in a finding that ExxonMobil fraudulently misled the plantiff-residents about the events leading up to the leak, the leak’s discovery, and the nature and extent of any groundwater contamination. ExxonMobil believes the verdict is not justified by the evidence and that the amount of the compensatory award is grossly excessive and the imposition of punitive damages is improper and unconstitutional. The trial court denied a post-trial motion that ExxonMobil filed to overturn the punitive damages verdict. Following the entry of a final judgment, ExxonMobil will appeal the verdict and judgment. In a prior trial involving the same leak, the jury awarded plantiff-residents compensatory damages but decided against punitive damages. The plaintiffs did not appeal the jury’s denial of punitive damages. Following an appeal by ExxonMobil of the compensatory damages award, on February 9, 2012, the Maryland Special Court of Appeals reversed in part and affirmed in part the trial court’s decision on compensatory damages. The ultimate outcome of this litigation is not expected to have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole.

Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2011, for guarantees relating to notes, loans and performance under contracts.


	Dec. 31, 2011
	Equity Company Obligations(1)		Other Third-Party Obligations		Total
	(millions of dollars)
Guarantees
Debt-related	$	1,546	$	65	$	1,611
Other		3,061		3,784		6,845
Total	$	4,607	$	3,849	$	8,456

(1)

ExxonMobil share.

Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition. Unconditional purchase obligations as defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.


	Payments Due by Period
	2012		2013- 2016		2017 and Beyond		Total
	(millions of dollars)

Unconditional purchase obligations (1)	$	243	$	660	$	410	$	1,313

(1)

Undiscounted obligations of $1,313 million mainly pertain to pipeline throughput agreements and include $856 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $229 million, totaled $1,084 million.

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

Index to Financial Statements

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. ExxonMobil’s remaining net book investment in Cerro Negro producing assets was about $750 million at year-end 2011.

On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes (ICSID) invoking ICSID jurisdiction under Venezuela’s Investment Law and the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID Tribunal issued a decision on June 10, 2010, finding that it had jurisdiction to proceed on the basis of the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID arbitration proceeding is continuing and a hearing on the merits was held in February 2012. At this time, the net impact of these matters on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition.

An affiliate of ExxonMobil, Mobil Cerro Negro, Ltd. (MCN), also filed an arbitration under the rules of the International Chamber of Commerce (ICC) against PdVSA and a PdVSA affiliate, PdVSA CN, for breach of their contractual obligations under certain Cerro Negro Project agreements. On December 23, 2011, the tribunal rendered its award which found PdVSA and PdVSA CN jointly and severally liable to MCN in the amount of about $908 million. The tribunal deducted approximately $161 million of uncontested debt owed by MCN to PdVSA and PdVSA CN, leaving a balance of about $747 million. Post-award interest on this net amount was set at the New York prime rate compounded annually and running from the date of the award. The tribunal granted PdVSA and PdVSA CN a sixty-day grace period in which to comply with the award. On January 26, 2012, MCN filed a motion to confirm the award against PdVSA CN. In response to an order to show cause filed by PdVSA on January 17, 2012, the United States District Court for the Southern District of New York, on February 1, 2012, ordered the release to MCN of approximately $305 million of PdVSA CN funds previously attached in connection with the arbitration in partial satisfaction of the award. MCN received those funds on February 10, 2012. In further satisfaction of the award, PdVSA cancelled approximately $195 million in MCN bond debt on February 13, 2012. PdVSA paid MCN the balance of the monetary portion of the award on February 14, 2012.

An affiliate of ExxonMobil is one of the Contractors under a Production Sharing Contract (PSC) with the Nigerian National Petroleum Corporation (NNPC) covering the Erha block located in the offshore waters of Nigeria. ExxonMobil’s affiliate is the operator of the block and owns a 56.25 percent interest under the PSC. The Contractors are in dispute with NNPC regarding NNPC’s lifting of crude oil in excess of its entitlement under the terms of the PSC. In accordance with the terms of the PSC, the Contractors initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member arbitral Tribunal issued an award upholding the Contractors’ position in all material respects and awarding damages to the Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors have petitioned a Nigerian federal court for enforcement of the award, and NNPC has petitioned the same court to have the award set aside. Those proceedings are pending. At this time, the net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. However, regardless of the outcome of enforcement proceedings, the Corporation does not expect the proceedings to have a material effect upon the Corporation’s operations or financial condition.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. Pension and Other Postretirement Benefits

The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31.


	Pension Benefits												Other Postretirement Benefits
	U.S.						Non-U.S.						Other Postretirement Benefits
	2011			2010			2011			2010			2011			2010
	(percent)
Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate		5.00			5.50			4.00			4.80			5.00			5.50
Long-term rate of compensation increase		5.75			5.25			5.40			5.20			5.75			5.25

	(millions of dollars)
Change in benefit obligation
Benefit obligation at January 1	$	15,007		$	13,981		$	25,722		$	23,344		$	7,331		$	6,748
Service cost		546			468			574			480			121			101
Interest cost		792			798			1,267			1,175			393			395
Actuarial loss/(gain)		1,954			553			3,086			1,672			427			277
Benefits paid (1) (2)		(1,264	)		(873	)		(1,470	)		(1,281	)		(473	)		(394	)
Foreign exchange rate changes		–			–			(303	)		169			(11	)		26
Plan amendments, other		–			80			192			163			92			178
Benefit obligation at December 31	$	17,035		$	15,007		$	29,068		$	25,722		$	7,880		$	7,331
Accumulated benefit obligation at December 31	$	14,081		$	12,764		$	25,480		$	22,958		$	–		$	–

(1)

Benefit payments for funded and unfunded plans.

(2)

For 2011 and 2010, other postretirement benefits paid are net of $29 million and $15 million of Medicare subsidy receipts, respectively.

For U.S. plans, the discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using bond portfolios with an average maturity approximating that of the liabilities or spot yield curves, both of which are constructed using high-quality, local-currency-denominated bonds.

The measurement of the accumulated postretirement benefit obligation assumes an initial health care cost trend rate of 5.5 percent that declines to 4.5 percent by 2015. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $63 million and the postretirement benefit obligation by $696 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $49 million and the postretirement benefit obligation by $567 million.


	Pension Benefits												Other Postretirement Benefits
	U.S.						Non-U.S.						Other Postretirement Benefits
	2011			2010			2011			2010			2011			2010
	(millions of dollars)
Change in plan assets
Fair value at January 1	$	10,835		$	10,277		$	16,765		$	15,401		$	558		$	514
Actual return on plan assets		505			1,235			123			1,482			–			63
Foreign exchange rate changes		–			–			(192	)		99			–			–
Company contribution		370			–			1,623			1,184			39			38
Benefits paid (1)		(1,054	)		(677	)		(1,046	)		(873	)		(59	)		(59	)
Other		–			–			(156	)		(528	)		–			2
Fair value at December 31	$	10,656		$	10,835		$	17,117		$	16,765		$	538		$	558

(1)

Benefit payments for funded plans.

Index to Financial Statements

The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.


	Pension Benefits
	U.S.						Non-U.S.
	2011			2010			2011			2010
	(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans	$	(4,141	)	$	(2,349	)	$	(5,319	)	$	(2,769	)
Unfunded plans		(2,238	)		(1,823	)		(6,632	)		(6,188	)
Total	$	(6,379	)	$	(4,172	)	$	(11,951	)	$	(8,957	)

The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.


	Pension Benefits												Other Postretirement Benefits
	U.S.						Non-U.S.						Other Postretirement Benefits
	2011			2010			2011			2010			2011			2010
	(millions of dollars)
Assets in excess of/(less than) benefit obligation
Balance at December 31 (1)	$	(6,379	)	$	(4,172	)	$	(11,951	)	$	(8,957	)	$	(7,342	)	$	(6,773	)

Amounts recorded in the consolidated balance sheet consist of:
Other assets	$	1		$	1		$	245		$	400		$	–		$	–
Current liabilities		(237	)		(257	)		(346	)		(336	)		(341	)		(343	)
Postretirement benefits reserves		(6,143	)		(3,916	)		(11,850	)		(9,021	)		(7,001	)		(6,430	)
Total recorded	$	(6,379	)	$	(4,172	)	$	(11,951	)	$	(8,957	)	$	(7,342	)	$	(6,773	)

Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)	$	6,475		$	5,028		$	11,170		$	7,795		$	2,291		$	1,985
Prior service cost		74			83			745			674			119			154
Total recorded in accumulated other comprehensive income	$	6,549		$	5,111		$	11,915		$	8,469		$	2,410		$	2,139

(1)

Fair value of assets less benefit obligation shown on the preceding page.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class.


	Pension Benefits																		Other Postretirement Benefits
	U.S.									Non-U.S.									Other Postretirement Benefits
	2011			2010			2009			2011			2010			2009			2011			2010			2009
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31		(percent)
Discount rate		5.50			6.00			6.25			4.80			5.20			5.50			5.50			6.00			6.25
Long-term rate of return on funded assets		7.50			7.50			8.00			6.80			6.70			7.30			7.50			7.50			8.00
Long-term rate of compensation increase		5.25			5.25			5.00			5.20			5.00			4.70			5.25			5.25			5.00

Components of net periodic benefit cost		(millions of dollars)
Service cost	$	546		$	468		$	438		$	574		$	480		$	421		$	121		$	101		$	94
Interest cost		792			798			809			1,267			1,175			1,121			393			395			408
Expected return on plan assets		(769	)		(726	)		(656	)		(1,168	)		(1,010	)		(886	)		(41	)		(37	)		(35	)
Amortization of actuarial loss/(gain)		485			525			694			647			554			648			162			147			176
Amortization of prior service cost		9			2			–			103			84			79			35			52			69
Net pension enhancement and curtailment/settlement expense		286			321			485			34			9			2			–			–			–
Net periodic benefit cost	$	1,349		$	1,388		$	1,770		$	1,457		$	1,292		$	1,385		$	670		$	658		$	712
Changes in amounts recorded in accumulated other comprehensive income:
Net actuarial loss/(gain)	$	2,218		$	44		$	(231	)	$	4,133		$	1,202		$	(33	)	$	468		$	251		$	(107	)
Amortization of actuarial (loss)/gain		(771	)		(846	)		(1,179	)		(681	)		(563	)		(650	)		(162	)		(147	)		(176	)
Prior service cost/(credit)		–			80			–			187			160			69			–			26			–
Amortization of prior service (cost)/credit		(9	)		(2	)		–			(103	)		(84	)		(79	)		(35	)		(52	)		(69	)
Foreign exchange rate changes		–			–			–			(90	)		96			608			–			2			2
Total recorded in other comprehensive income		1,438			(724	)		(1,410	)		3,446			811			(85	)		271			80			(350	)
Total recorded in net periodic benefit cost and other comprehensive income, before tax	$	2,787		$	664		$	360		$	4,903		$	2,103		$	1,300		$	941		$	738		$	362

Costs for defined contribution plans were $378 million, $347 million and $339 million in 2011, 2010 and 2009, respectively.

A summary of the change in accumulated other comprehensive income is shown in the table below:


	Total Pension and Other Postretirement Benefits
	2011			2010			2009
(Charge)/credit to other comprehensive income, before tax	(millions of dollars)
U.S. pension	$	(1,438	)	$	724		$	1,410
Non-U.S. pension		(3,446	)		(811	)		85
Other postretirement benefits		(271	)		(80	)		350
Total (charge)/credit to other comprehensive income, before tax		(5,155	)		(167	)		1,845
(Charge)/credit to income tax (see Note 18)		1,495			35			(591	)
(Charge)/credit to investment in equity companies		(30	)		11			(133	)
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax	$	(3,690	)	$	(121	)	$	1,121
Charge/(credit) to equity of noncontrolling interests		288			95			93
(Charge)/credit to other comprehensive income attributable to ExxonMobil	$	(3,402	)	$	(26	)	$	1,214

Index to Financial Statements

The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive equity and fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in high-quality corporate and government debt securities.

Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for the U.S. benefit plans is 50 percent equity securities and 50 percent debt securities. The target asset allocation for the non-U.S. plans in aggregate is 47 percent equities, 50 percent debt and 3 percent real estate funds. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily focus on early-stage venture capital of 5 percent and 3 percent, respectively.

The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.

The 2011 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:


	U.S. Pension										Non-U.S. Pension
	Fair Value Measurement at December 31, 2011, Using:										Fair Value Measurement at December 31, 2011, Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total		Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	(millions of dollars)										(millions of dollars)
Asset category:
Equity securities
U.S.	$	–	$	2,247	⁽¹⁾	$	–		$	2,247	$	–		$	2,589	⁽¹⁾	$	–		$	2,589
Non-U.S.		–		2,636	⁽¹⁾		–			2,636		194	⁽²⁾		4,835	⁽¹⁾		–			5,029
Private equity		–		–			458	⁽³⁾		458		–			–			393	⁽³⁾		393
Debt securities
Corporate		–		2,728	⁽⁴⁾		–			2,728		2	⁽⁵⁾		1,857	⁽⁴⁾		–			1,859
Government		–		2,482	⁽⁴⁾		–			2,482		186	⁽⁵⁾		6,317	⁽⁴⁾		–			6,503
Asset-backed		–		11	⁽⁴⁾		–			11		–			102	⁽⁴⁾		–			102
Private mortgages		–		–			–			–		–			–			4	⁽⁶⁾		4
Real estate funds		–		–			–			–		–			–			397	⁽⁷⁾		397
Cash		–		71	⁽⁸⁾		–			71		76			13	⁽⁹⁾		–			89
Total at fair value	$	–	$	10,175		$	458		$	10,633	$	458		$	15,713		$	794		$	16,965
Insurance contracts at contract value										23											152
Total plan assets									$	10,656										$	17,117

(1)

For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.

(2)

For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

(3)

For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(4)

For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(5)

For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(6)

For private mortgages, fair value is based on proprietary credit spread matrices developed using market data and monthly surveys of active mortgage bankers.

(7)

For real estate funds, fair value is based on appraised values developed using comparable market transactions.

(8)

For cash balances held in the form of short-term fund units that are redeemable at the measurement date, the fair value is treated as a Level 2 input.

(9)

For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Index to Financial Statements

The 2010 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:


	U.S. Pension										Non-U.S. Pension
	Fair Value Measurement at December 31, 2010, Using:										Fair Value Measurement at December 31, 2010, Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total		Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	(millions of dollars)										(millions of dollars)
Asset category:
Equity securities
U.S.	$	–	$	2,648	⁽¹⁾	$	–		$	2,648	$	–		$	2,443	⁽¹⁾	$	–		$	2,443
Non-U.S.		–		3,530	⁽¹⁾		–			3,530		228	⁽²⁾		6,502	⁽¹⁾		–			6,730
Private equity		–		–			408	⁽³⁾		408		–			–			315	⁽³⁾		315
Debt securities
Corporate		–		1,152	⁽⁴⁾		–			1,152		2	⁽⁵⁾		1,629	⁽⁴⁾		–			1,631
Government		–		2,847	⁽⁴⁾		–			2,847		146	⁽⁵⁾		4,709	⁽⁴⁾		–			4,855
Asset-backed		–		31	⁽⁴⁾		–			31		–			98	⁽⁴⁾		–			98
Private mortgages		–		–			128	⁽⁶⁾		128		–			–			4	⁽⁶⁾		4
Real estate funds		–		–			–			–		–			–			417	⁽⁷⁾		417
Cash		68		–			–			68		63			51	⁽⁸⁾		–			114
Total at fair value	$	68	$	10,208		$	536		$	10,812	$	439		$	15,432		$	736		$	16,607
Insurance contracts at contract value										23											158
Total plan assets									$	10,835										$	16,765

(1)

(2)

For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.

(3)

For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(4)

For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(5)

For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.

(6)

For private mortgages, fair value is based on proprietary credit spread matrices developed using market data and monthly surveys of active mortgage bankers.

(7)

For real estate funds, fair value is based on appraised values developed using comparable market transactions.

(8)

For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Other Postretirement
	Fair Value Measurement at December 31, 2010, Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
	(millions of dollars)
Asset category:
Equity securities
U.S.	$	–	$	180	⁽¹⁾	$	–		$	180
Non-U.S.		–		191	⁽¹⁾		–			191
Private equity		–		–			5	⁽²⁾		5
Debt securities
Corporate		–		49	⁽³⁾		–			49
Government		–		117	⁽³⁾		–			117
Asset-backed		–		13	⁽³⁾		–			13
Private mortgages		–		–			2	⁽⁴⁾		2
Cash		1		–			–			1
Total at fair value	$	1	$	550		$	7		$	558

(1)

(2)

For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.

(3)

For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.

(4)

For private mortgages, fair value is based on proprietary credit spread matrices developed using market data and monthly surveys of active mortgage bankers.

The change in the fair value in 2010 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:


	2010
	Pension														Other Postretirement
	U.S.					Non U.S.
	Private Equity		Private Mortgages			Private Equity			Private Mortgages			Real Estate			Private Equity		Private Mortgages
	(millions of dollars)

Fair value at January 1	$	349	$	280		$	239		$	5		$	413		$	4	$	3

Net realized gains/(losses)		–		36			(1	)		(1	)		–			–		1
Net unrealized gains/(losses)		47		(3	)		26			1			(4	)		1		–
Net purchases/(sales)		12		(185	)		51			(1	)		8			–		(2	)
Fair value at December 31	$	408	$	128		$	315		$	4		$	417		$	5	$	2

Index to Financial Statements

A summary of pension plans with an accumulated benefit obligation in excess of plan assets is shown in the table below:


	Pension Benefits
	U.S.				Non-U.S.
	2011		2010		2011		2010
	(millions of dollars)
For funded pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation	$	14,797	$	13,184	$	17,668	$	9,865
Accumulated benefit obligation		12,606		11,383		16,175		9,074
Fair value of plan assets		10,655		10,834		12,832		7,131

For unfunded pension plans:
Projected benefit obligation	$	2,238	$	1,823	$	6,632	$	6,188
Accumulated benefit obligation		1,475		1,381		5,753		5,413


	Pension Benefits				Other Postretirement Benefits
	U.S.		Non-U.S.		Other Postretirement Benefits
	(millions of dollars)
Estimated 2012 amortization from accumulated other comprehensive income:
Net actuarial loss/(gain) (1)	$	1,033	$	889	$	173
Prior service cost (2)		7		109		34

(1)

The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service period of active plan participants.

(2)

The Corporation amortizes prior service cost on a straight-line basis as permitted under authoritative guidance for defined benefit pension and other postretirement benefit plans.


	Pension Benefits				Other Postretirement Benefits
	U.S.		Non-U.S.		Gross		Medicare Subsidy Receipt
	(millions of dollars)

Contributions expected in 2012	$	1,650	$	1,250	$	–	$	–
Benefit payments expected in:
2012		1,490		1,342		442		23
2013		1,579		1,360		458		25
2014		1,547		1,383		472		26
2015		1,524		1,418		485		27
2016		1,489		1,462		497		28
2017 - 2021		6,616		7,731		2,611		163

17. Disclosures about Segments and Related Information

The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete financial information is available.

Earnings after income tax include special items, and transfers are at estimated market prices. Earnings for 2009 included a special charge of $140 million in the corporate and financing segment for interest related to the Valdez punitive damages award.

Interest expense includes non-debt-related interest expense of $165 million, $41 million and $500 million in 2011, 2010 and 2009, respectively. Higher expenses in 2009 primarily reflect interest provisions related to the Valdez litigation.

In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Upstream				Downstream						Chemical					Corporate and Financing			Corporate Total
	U.S.		Non-U.S.		U.S.			Non-U.S.			U.S.		Non-U.S.			Corporate and Financing			Corporate Total
	(millions of dollars)
As of December 31, 2011
Earnings after income tax	$	5,096	$	29,343	$	2,268		$	2,191		$	2,215	$	2,168		$	(2,221	)	$	41,060
Earnings of equity companies included above		2,045		11,768		7			353			198		1,365			(447	)		15,289
Sales and other operating revenue (1)		14,023		32,419		120,844			257,779			15,466		26,476			22			467,029
Intersegment revenue		9,807		49,910		18,489			73,549			12,226		10,563			262			–
Depreciation and depletion expense		4,879		7,021		650			1,560			380		458			635			15,583
Interest revenue		–		–		–			–			–		–			135			135
Interest expense		30		36		10			24			2		(1	)		146			247
Income taxes		2,852		25,755		1,123			696			1,027		465			(867	)		31,051
Additions to property, plant and equipment		10,887		18,934		400			1,334			241		910			932			33,638
Investments in equity companies		2,963		8,439		210			1,358			253		3,973			(228	)		16,968
Total assets		82,900		127,977		18,354			51,132			7,245		19,862			23,582			331,052
As of December 31, 2010
Earnings after income tax	$	4,272	$	19,825	$	770		$	2,797		$	2,422	$	2,491		$	(2,117	)	$	30,460
Earnings of equity companies included above		1,261		8,415		23			225			171		1,163			(581	)		10,677
Sales and other operating revenue (1)		8,895		26,046		93,599			206,042			13,402		22,119			22			370,125
Intersegment revenue		8,102		39,066		13,546			52,697			9,694		8,421			282			–
Depreciation and depletion expense		3,506		7,574		681			1,565			421		432			581			14,760
Interest revenue		–		–		–			–			–		–			118			118
Interest expense		20		25		1			19			1		4			189			259
Income taxes		2,219		18,627		360			560			736		347			(1,288	)		21,561
Additions to property, plant and equipment		52,300		16,937		888			1,332			247		1,733			719			74,156
Investments in equity companies		2,636		9,625		254			1,240			285		3,586			(197	)		17,429
Total assets		76,725		115,646		18,378			47,402			7,148		19,087			18,124			302,510
As of December 31, 2009
Earnings after income tax	$	2,893	$	14,214	$	(153	)	$	1,934		$	769	$	1,540		$	(1,917	)	$	19,280
Earnings of equity companies included above		1,216		5,269		(102	)		188			164		906			(498	)		7,143
Sales and other operating revenue (1)		3,406		21,355		76,467			173,404			9,962		16,885			21			301,500
Intersegment revenue		6,718		32,982		10,168			39,190			7,185		6,947			284			–
Depreciation and depletion expense		1,768		6,376		687			1,665			400		457			564			11,917
Interest revenue		–		–		–			–			–		–			179			179
Interest expense		38		27		10			18			4		1			450			548
Income taxes		1,451		15,183		(164	)		(22	)		281		(182	)		(1,428	)		15,119
Additions to property, plant and equipment		2,973		13,307		1,449			1,447			294		2,553			468			22,491
Investments in equity companies		2,440		8,864		323			1,190			259		2,873			(207	)		15,742
Total assets		24,940		102,372		17,493			45,098			7,044		17,117			19,259			233,323


Geographic Sales and other operating revenue (1)	2011		2010		2009
	(millions of dollars)

United States	$	150,343	$	115,906	$	89,847
Non-U.S.		316,686		254,219		211,653
Total	$	467,029	$	370,125	$	301,500
Significant non-U.S. revenue sources include:
United Kingdom	$	34,833	$	24,637	$	20,293
Canada		34,626		27,243		21,151
Japan		31,925		27,143		22,054
Belgium		26,926		21,139		16,857
France		18,510		13,920		12,042
Germany		17,034		14,301		14,839
Italy		16,288		14,132		12,997
Singapore		14,400		11,088		8,400


Long-lived assets	2011		2010		2009
	(millions of dollars)

United States	$	91,146	$	86,021	$	37,138
Non-U.S.		123,518		113,527		101,978
Total	$	214,664	$	199,548	$	139,116
Significant non-U.S. long-lived assets include:
Canada	$	24,458	$	20,879	$	15,919
Nigeria		11,806		11,429		11,046
Angola		10,395		8,570		7,320
Australia		9,474		6,570		4,247
Singapore		9,285		8,610		7,238
Kazakhstan		7,022		5,938		4,748
Norway		6,039		6,988		7,251
United Kingdom		5,008		6,177		7,609

(1)

Sales and other operating revenue includes sales-based taxes of $33,503 million for 2011, $28,547 million for 2010 and $25,936 million for 2009. See Note 1, Summary of Accounting Policies.

Index to Financial Statements

18. Income, Sales-Based and Other Taxes


	2011							2010								2009
	U.S.		Non-U.S.			Total		U.S.		Non-U.S.			Total			U.S.			Non-U.S.			Total
	(millions of dollars)
Income tax expense
Federal and non-U.S.
Current	$	1,547	$	28,849		$	30,396	$	1,224	$	21,093		$	22,317		$	(838	)	$	15,830		$	14,992
Deferred – net		1,577		(1,417	)		160		49		(1,191	)		(1,142	)		650			(665	)		(15	)
U.S. tax on non-U.S. operations		15		–			15		46		–			46			32			–			32
Total federal and non-U.S.		3,139		27,432			30,571		1,319		19,902			21,221			(156	)		15,165			15,009
State		480		–			480		340		–			340			110			–			110
Total income tax expense		3,619		27,432			31,051		1,659		19,902			21,561			(46	)		15,165			15,119
Sales-based taxes		5,652		27,851			33,503		6,182		22,365			28,547			6,271			19,665			25,936
All other taxes and duties
Other taxes and duties		1,539		38,434			39,973		776		35,342			36,118			581			34,238			34,819
Included in production and manufacturing expenses		1,342		1,425			2,767		1,001		1,237			2,238			699			1,318			2,017
Included in SG&A expenses		181		623			804		201		570			771			197			538			735
Total other taxes and duties		3,062		40,482			43,544		1,978		37,149			39,127			1,477			36,094			37,571
Total	$	12,333	$	95,765		$	108,098	$	9,819	$	79,416		$	89,235		$	7,702		$	70,924		$	78,626

All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include net credits of $330 million in 2011 and $9 million in 2009 and a net charge of $175 million in 2010 for the effect of changes in tax laws and rates.

Income taxes (charged)/credited directly to equity were:


	2011			2010			2009
	(millions of dollars)
Cumulative foreign exchange translation adjustment	$	89		$	(42	)	$	(247	)
Postretirement benefits reserves adjustment:
Net actuarial loss/(gain)		2,016			553			(94	)
Amortization of actuarial loss/(gain)		(503	)		(609	)		(649	)
Prior service cost		47			92			20
Amortization of prior service cost		(41	)		(45	)		(43	)
Foreign exchange rate changes		(24	)		44			175
Total postretirement benefits reserves adjustment		1,495			35			(591	)
Other components of equity		236			246			140

The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2011, 2010 and 2009 is as follows:


	2011			2010			2009
	(millions of dollars)
Income before income taxes
United States	$	11,511		$	7,711		$	2,576
Non-U.S.		61,746			45,248			32,201
Total	$	73,257		$	52,959		$	34,777
Theoretical tax	$	25,640		$	18,536		$	12,172
Effect of equity method of accounting		(5,351	)		(3,737	)		(2,500	)
Non-U.S. taxes in excess of theoretical U.S. tax		10,385			7,293			5,948
U.S. tax on non-U.S. operations		15			46			32
State taxes, net of federal tax benefit		312			221			72
Other U.S.		50			(798	)		(605	)
Total income tax expense	$	31,051		$	21,561		$	15,119

Effective tax rate calculation
Income taxes	$	31,051		$	21,561		$	15,119
ExxonMobil share of equity company income taxes		5,603			4,058			2,489
Total income taxes		36,654			25,619			17,608
Net income including noncontrolling interests		42,206			31,398			19,658
Total income before taxes	$	78,860		$	57,017		$	37,266

Effective income tax rate		46%			45%			47%

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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


Tax effects of temporary differences for:	2011			2010
	(millions of dollars)

Property, plant and equipment	$	45,951		$	42,657
Other liabilities		4,281			4,278
Total deferred tax liabilities	$	50,232		$	46,935
Pension and other postretirement benefits	$	(7,930	)	$	(5,634	)
Asset retirement obligations		(5,302	)		(4,461	)
Tax loss carryforwards		(3,166	)		(3,243	)
Other assets		(7,079	)		(6,070	)
Total deferred tax assets	$	(23,477	)	$	(19,408	)
Asset valuation allowances		1,304			1,183
Net deferred tax liabilities	$	28,059		$	28,710

Deferred income tax (assets) and liabilities are included in the balance sheet as shown below. Deferred income tax (assets) and liabilities are classified as current or long term consistent with the classification of the related temporary difference – separately by tax jurisdiction.


Balance sheet classification	2011			2010
	(millions of dollars)

Other current assets	$	(4,549	)	$	(3,359	)
Other assets, including intangibles, net		(4,218	)		(3,527	)
Accounts payable and accrued liabilities		208			446
Deferred income tax liabilities		36,618			35,150
Net deferred tax liabilities	$	28,059		$	28,710

The Corporation had $47 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.

Unrecognized Tax Benefits

The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. Resolution of the related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the Corporation. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 50 percent in the next 12 months, with no material impact on near-term earnings. Given the long time periods involved in resolving tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporation’s effective income tax rate in any given year.

The following table summarizes the movement in unrecognized tax benefits.


Gross unrecognized tax benefits	2011			2010			2009
	(millions of dollars)

Balance at January 1	$	4,148		$	4,725		$	4,976
Additions based on current year’s tax positions		822			830			547
Additions for prior years’ tax positions		451			620			262
Reductions for prior years’ tax positions		(329	)		(505	)		(594	)
Reductions due to lapse of the statute of limitations		–			(534	)		–
Settlements with tax authorities		(145	)		(999	)		(592	)
Foreign exchange effects/other		(25	)		11			126
Balance at December 31	$	4,922		$	4,148		$	4,725

The additions and reductions in unrecognized tax benefits shown above include effects related to net income and equity, and timing differences for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2011, 2010 and 2009 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income or cash flow.

The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:


Country of Operation		Open Tax Years
Abu Dhabi		2000 - 2011
Angola		2007 - 2011
Australia		2000 - 2011
Canada		1994 - 2011
Equatorial Guinea		2006 - 2011
Germany		1999 - 2011
Japan		2004 - 2011
Malaysia		2005 - 2011
Nigeria		1998 - 2011
Norway		2000 - 2011
United Kingdom		2009 - 2011
United States		2004 - 2011

The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.

The Corporation incurred $62 million in interest expense on income tax reserves in 2011. For 2010, interest expense was a credit of $39 million, reflecting the effect of credits from the net favorable resolution of prior year tax positions. The Corporation incurred approximately $135 million in interest expense on income tax reserves in 2009. The related interest payable balances were $662 million and $636 million at December 31, 2011, and 2010, respectively.

Index to Financial Statements

19. Acquisition of XTO Energy Inc.

Description of the Transaction. On June 25, 2010, ExxonMobil acquired XTO Energy Inc. (XTO) by merging a wholly-owned subsidiary of ExxonMobil with and into XTO (the “merger”), with XTO continuing as the surviving corporation and wholly-owned subsidiary of ExxonMobil. XTO is involved in the exploration for, production of, and transportation and sale of crude oil and natural gas.

At the effective time of the merger, each share of XTO common stock was converted into the right to receive 0.7098 shares of common stock of ExxonMobil (the “Exchange Ratio”), with cash being paid in lieu of any fractional shares of ExxonMobil stock. Also at the effective time, each outstanding option to purchase XTO common stock was converted into an option to purchase a number of shares of ExxonMobil stock based on the Exchange Ratio, and each outstanding stock-based award of XTO was converted into a stock-based award of ExxonMobil stock based on the Exchange Ratio.

The components of the consideration transferred follow:


(millions of dollars)
Consideration attributable to stock issued (1) (2)	$	24,480
Consideration attributable to converted stock options (2)		179
Total consideration transferred	$	24,659

(1)

The fair value of the Corporation’s common stock on the acquisition date was $59.10 per share based on the closing value on the NYSE. The Corporation issued 416 million shares of stock previously held in treasury. The treasury stock issued, based on the average cost, was valued at $21,139 million. The excess of the fair value of the consideration transferred over the cost of treasury stock issued was $3,520 million and was included in common stock without par value.

(2)

The portion of the fair value of XTO converted stock-based awards attributable to pre-merger employee service was part of consideration. The remaining fair value of the awards is recognized over the requisite service period.

Recording of Assets Acquired and Liabilities Assumed. The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.

The following table summarizes the assets acquired and liabilities assumed:


(millions of dollars)
Current assets	$	2,053
Property, plant and equipment (1)		47,300
Goodwill (2)		39
Other assets		620
Total assets acquired	$	50,012
Current liabilities	$	2,615
Long-term debt (3)		10,574
Deferred income tax liabilities (4)		11,204
Other long-term obligations		960
Total liabilities assumed	$	25,353
Net assets acquired	$	24,659

(1)

Property, plant and equipment were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included XTO resources, assumed future production profiles, commodity prices (mainly based on observable market inputs), risk adjusted discount rate of 7 percent, inflation of 2 percent and assumptions on the timing and amount of future development and operating costs. The property, plant and equipment additions were segmented to the Upstream business, with substantially all of the assets in the United States.

(2)

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill was recognized in the Upstream reporting unit. Goodwill is not amortized and is not deductible for tax purposes.

(3)

Long-term debt was recognized at market rates at closing (Level 1).

(4)

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

The 2010 unaudited pro forma revenues of $373 billion, net income attributable to ExxonMobil of $31 billion, earnings per common share of $6.03 and earnings per common share assuming dilution of $6.01 for the Corporation were calculated as if the merger of XTO had occurred at the beginning of 2010. The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the merger and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the merger been completed on January 1, 2010. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. The unaudited pro forma consolidated results reflect pro forma adjustments for the elimination of deferred gains and losses recognized in earnings for derivatives outstanding at the beginning of the year, depreciation expense related to the fair value adjustment to property, plant and equipment acquired, additional amortization expense related to the fair value of identifiable intangible assets acquired, capitalization of interest expense and applicable income tax impacts.

Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

20. Subsequent Event

On January 29, 2012, the Corporation announced that it had entered into an agreement which will result in the restructuring of its Downstream and Chemical holdings in Japan. Under the agreement, TonenGeneral Sekiyu K. K. (TG), a consolidated subsidiary owned 50 percent by the Corporation, will purchase for approximately $3.9 billion the Corporation’s shares of a wholly-owned affiliate in Japan, ExxonMobil Yugen Kaisha, which will result in TG acquiring approximately 200 million of its shares currently owned by the Corporation along with other assets. As a result of the restructuring the Corporation’s effective ownership of TG will be reduced to approximately 22 percent. Closing is anticipated in mid-2012.

The major classes of assets and liabilities that would have been classified as held for sale if the transaction had met the criteria for held for sale accounting at December 31, 2011, were as follows:


(millions of dollars)

Assets
Current assets (1)	$	6,862
Net property, plant and equipment		4,740
Other assets		1,757
Total assets	$	13,359

Liabilities
Current liabilities	$	8,450
Postretirement benefits reserves		2,103
Other long-term obligations		1,179
Total liabilities	$	11,732

Equity
ExxonMobil share of equity (2)	$	(467	)
Noncontrolling interests		2,094
Total equity	$	1,627
Total liabilities and equity	$	13,359

(1)

Current assets include $1,882 million of crude oil, products and merchandise inventory.

(2)

On the date the Corporation transfers control to TG, the ExxonMobil share of accumulated other comprehensive income will be recycled as a benefit to earnings. At December 31, 2011, the total accumulated other comprehensive income was $1,482 million.

Index to Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical service agreements, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity companies totaled $2,600 million in 2011, $249 million in 2010, and $536 million in 2009. Oil sands mining operations are included in the results of operations in accordance with Securities and Exchange Commission and Financial Accounting Standards Board rules.


Results of Operations	United States		Canada/ South America		Europe		Africa		Asia		Australia/ Oceania		Total
	(millions of dollars)

Consolidated Subsidiaries
2011 – Revenue
Sales to third parties	$	8,579	$	1,056	$	8,050	$	3,507	$	6,813	$	1,061	$	29,066
Transfers		8,190		7,022		7,694		16,704		9,388		1,213		50,211
	$	16,769	$	8,078	$	15,744	$	20,211	$	16,201	$	2,274	$	79,277
Production costs excluding taxes		4,107		2,751		2,722		2,608		1,672		497		14,357
Exploration expenses		268		290		599		233		618		73		2,081
Depreciation and depletion		4,664		980		1,928		2,159		1,680		236		11,647
Taxes other than income		2,157		79		631		2,055		2,164		295		7,381
Related income tax		2,445		969		6,842		7,888		6,026		353		24,523
Results of producing activities for consolidated subsidiaries	$	3,128	$	3,009	$	3,022	$	5,268	$	4,041	$	820	$	19,288

Equity Companies
2011 – Revenue
Sales to third parties	$	1,356	$	–	$	5,580	$	–	$	18,855	$	–	$	25,791
Transfers		1,163		–		103		–		5,666		–		6,932
	$	2,519	$	–	$	5,683	$	–	$	24,521	$	–	$	32,723
Production costs excluding taxes		482		–		315		–		378		–		1,175
Exploration expenses		10		–		13		–		–		–		23
Depreciation and depletion		151		–		160		–		576		–		887
Taxes other than income		36		–		2,995		–		6,173		–		9,204
Related income tax		–		–		847		–		8,036		–		8,883
Results of producing activities for equity companies	$	1,840	$	–	$	1,353	$	–	$	9,358	$	–	$	12,551

Total results of operations	$	4,968	$	3,009	$	4,375	$	5,268	$	13,399	$	820	$	31,839

Index to Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)


Results of Operations	United States		Canada/ South America		Europe		Africa		Asia		Australia/ Oceania		Total
	(millions of dollars)

Consolidated Subsidiaries
2010 – Revenue
Sales to third parties	$	5,334	$	1,218	$	6,055	$	4,227	$	4,578	$	696	$	22,108
Transfers		7,070		5,832		7,120		13,295		6,031		1,123		40,471
	$	12,404	$	7,050	$	13,175	$	17,522	$	10,609	$	1,819	$	62,579
Production costs excluding taxes		2,794		2,612		2,717		2,215		1,308		462		12,108
Exploration expenses		283		464		394		587		360		56		2,144
Depreciation and depletion		3,350		1,015		2,531		2,580		1,141		219		10,836
Taxes other than income		1,188		86		482		1,742		1,298		204		5,000
Related income tax		2,093		715		4,728		6,068		3,852		262		17,718
Results of producing activities for consolidated subsidiaries	$	2,696	$	2,158	$	2,323	$	4,330	$	2,650	$	616	$	14,773

Equity Companies
2010 – Revenue
Sales to third parties	$	1,012	$	–	$	5,050	$	–	$	12,682	$	–	$	18,744
Transfers		867		–		68		–		3,817		–		4,752
	$	1,879	$	–	$	5,118	$	–	$	16,499	$	–	$	23,496
Production costs excluding taxes		481		–		294		–		320		–		1,095
Exploration expenses		4		–		19		–		2		–		25
Depreciation and depletion		157		–		188		–		455		–		800
Taxes other than income		32		–		2,515		–		3,844		–		6,391
Related income tax		–		–		815		–		5,295		–		6,110
Results of producing activities for equity companies	$	1,205	$	–	$	1,287	$	–	$	6,583	$	–	$	9,075

Total results of operations	$	3,901	$	2,158	$	3,610	$	4,330	$	9,233	$	616	$	23,848

Consolidated Subsidiaries
2009 – Revenue
Sales to third parties	$	1,859	$	1,345	$	5,900	$	3,012	$	2,637	$	586	$	15,339
Transfers		5,652		4,538		5,977		11,868		5,433		1,066		34,534
	$	7,511	$	5,883	$	11,877	$	14,880	$	8,070	$	1,652	$	49,873
Production costs excluding taxes		2,255		2,428		2,675		2,027		1,247		386		11,018
Exploration expenses		219		339		375		662		393		33		2,021
Depreciation and depletion		1,670		948		2,078		2,293		816		195		8,000
Taxes other than income		730		78		593		1,343		991		252		3,987
Related income tax		1,127		597		4,277		4,667		2,822		237		13,727
Results of producing activities for consolidated subsidiaries	$	1,510	$	1,493	$	1,879	$	3,888	$	1,801	$	549	$	11,120

Equity Companies
2009 – Revenue
Sales to third parties	$	818	$	–	$	4,889	$	–	$	6,148	$	–	$	11,855
Transfers		686		–		53		–		2,960		–		3,699
	$	1,504	$	–	$	4,942	$	–	$	9,108	$	–	$	15,554
Production costs excluding taxes		481		–		248		–		251		–		980
Exploration expenses		1		–		12		–		–		–		13
Depreciation and depletion		163		–		168		–		366		–		697
Taxes other than income		37		–		2,233		–		2,120		–		4,390
Related income tax		–		–		902		–		3,121		–		4,023
Results of producing activities for equity companies	$	822	$	–	$	1,379	$	–	$	3,250	$	–	$	5,451

Total results of operations	$	2,332	$	1,493	$	3,258	$	3,888	$	5,051	$	549	$	16,571

Index to Financial Statements

Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $6,651 million less at year-end 2011 and $4,729 million less at year-end 2010 than the amounts reported as investments in property, plant and equipment for the Upstream in Note 8. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations have been included in the capitalized costs for 2011 and 2010 in accordance with Financial Accounting Standards Board rules.


Capitalized Costs	United States		Canada/ South America		Europe		Africa		Asia		Australia/ Oceania		Total
	(millions of dollars)
Consolidated Subsidiaries
As of December 31, 2011
Property (acreage) costs – Proved	$	10,969	$	3,837	$	96	$	919	$	1,567	$	954	$	18,342
– Unproved		25,398		1,402		67		430		755		128		28,180
Total property costs	$	36,367	$	5,239	$	163	$	1,349	$	2,322	$	1,082	$	46,522
Producing assets		65,941		20,393		40,646		32,059		22,675		6,035		187,749
Incomplete construction		4,652		12,385		964		9,831		9,922		4,131		41,885
Total capitalized costs	$	106,960	$	38,017	$	41,773	$	43,239	$	34,919	$	11,248	$	276,156
Accumulated depreciation and depletion		33,037		16,296		31,706		18,449		14,960		4,384		118,832
Net capitalized costs for consolidated subsidiaries	$	73,923	$	21,721	$	10,067	$	24,790	$	19,959	$	6,864	$	157,324

Equity Companies
As of December 31, 2011
Property (acreage) costs – Proved	$	76	$	–	$	4	$	–	$	–	$	–	$	80
– Unproved		25		–		–		–		–		–		25
Total property costs	$	101	$	–	$	4	$	–	$	–	$	–	$	105
Producing assets		3,510		–		5,383		–		8,155		–		17,048
Incomplete construction		183		–		212		–		548		–		943
Total capitalized costs	$	3,794	$	–	$	5,599	$	–	$	8,703	$	–	$	18,096
Accumulated depreciation and depletion		1,354		–		4,267		–		3,068		–		8,689
Net capitalized costs for equity companies	$	2,440	$	–	$	1,332	$	–	$	5,635	$	–	$	9,407

Consolidated Subsidiaries
As of December 31, 2010
Property (acreage) costs – Proved	$	8,031	$	4,166	$	199	$	929	$	1,451	$	905	$	15,681
– Unproved		24,697		1,260		75		418		229		211		26,890
Total property costs	$	32,728	$	5,426	$	274	$	1,347	$	1,680	$	1,116	$	42,571
Producing assets		60,231		22,115		43,592		28,354		22,264		5,842		182,398
Incomplete construction		4,029		8,109		1,126		9,180		7,658		2,543		32,645
Total capitalized costs	$	96,988	$	35,650	$	44,992	$	38,881	$	31,602	$	9,501	$	257,614
Accumulated depreciation and depletion		29,199		17,561		33,484		16,318		13,412		4,217		114,191
Net capitalized costs for consolidated subsidiaries	$	67,789	$	18,089	$	11,508	$	22,563	$	18,190	$	5,284	$	143,423

Equity Companies
As of December 31, 2010
Property (acreage) costs – Proved	$	76	$	–	$	8	$	–	$	–	$	–	$	84
– Unproved		2		–		–		–		–		–		2
Total property costs	$	78	$	–	$	8	$	–	$	–	$	–	$	86
Producing assets		3,446		–		5,197		–		7,845		–		16,488
Incomplete construction		116		–		384		–		214		–		714
Total capitalized costs	$	3,640	$	–	$	5,589	$	–	$	8,059	$	–	$	17,288
Accumulated depreciation and depletion		1,418		–		4,252		–		2,484		–		8,154
Net capitalized costs for equity companies	$	2,222	$	–	$	1,337	$	–	$	5,575	$	–	$	9,134

Index to Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

Oil and Gas Exploration and Production Costs (continued)

The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2011 were $30,754 million, down $40,058 million from 2010, due primarily to the absence of the acquisition of XTO Energy Inc. 2010 costs were $70,812 million, up $50,305 million from 2009, due primarily to the acquisition of XTO Energy Inc. Total equity company costs incurred in 2011 were $1,226 million, up $312 million from 2010, due primarily to higher development costs.


Costs incurred in property acquisitions, exploration and development activities	United States		Canada/ South America		Europe		Africa		Asia		Australia/ Oceania		Total
	(millions of dollars)

During 2011
Consolidated Subsidiaries
Property acquisition costs – Proved	$	259	$	–	$	–	$	–	$	96	$	–	$	355
– Unproved		2,685		178		–		–		546		–		3,409
Exploration costs		465		372		640		303		518		154		2,452
Development costs		8,166		5,478		1,899		4,316		2,969		1,710		24,538
Total costs incurred for consolidated subsidiaries	$	11,575	$	6,028	$	2,539	$	4,619	$	4,129	$	1,864	$	30,754

Equity Companies
Property acquisition costs – Proved	$	–	$	–	$	–	$	–	$	–	$	–	$	–
– Unproved		23		–		–		–		–		–		23
Exploration costs		19		–		32		–		–		–		51
Development costs		339		–		164		–		649		–		1,152
Total costs incurred for equity companies	$	381	$	–	$	196	$	–	$	649	$	–	$	1,226

During 2010
Consolidated Subsidiaries
Property acquisition costs – Proved	$	21,633	$	–	$	41	$	3	$	115	$	–	$	21,792
– Unproved		23,509		136		23		–		–		–		23,668
Exploration costs		690		527		550		453		545		228		2,993
Development costs		7,947		4,757		1,227		4,390		2,892		1,146		22,359
Total costs incurred for consolidated subsidiaries	$	53,779	$	5,420	$	1,841	$	4,846	$	3,552	$	1,374	$	70,812

Equity Companies
Property acquisition costs – Proved	$	–	$	–	$	–	$	–	$	–	$	–	$	–
– Unproved		1		–		–		–		–		–		1
Exploration costs		4		–		56		–		2		–		62
Development costs		323		–		225		–		303		–		851
Total costs incurred for equity companies	$	328	$	–	$	281	$	–	$	305	$	–	$	914

During 2009
Consolidated Subsidiaries
Property acquisition costs – Proved	$	17	$	–	$	–	$	600	$	59	$	–	$	676
– Unproved		188		353		1		5		62		–		609
Exploration costs		548		498		471		880		529		130		3,056
Development costs		2,482		2,394		3,384		4,596		2,542		768		16,166
Total costs incurred for consolidated subsidiaries	$	3,235	$	3,245	$	3,856	$	6,081	$	3,192	$	898	$	20,507

Equity Companies
Property acquisition costs – Proved	$	–	$	–	$	–	$	–	$	–	$	–	$	–
– Unproved		–		–		–		–		–		–		–
Exploration costs		1		–		54		–		–		–		55
Development costs		305		–		255		–		404		–		964
Total costs incurred for equity companies	$	306	$	–	$	309	$	–	$	404	$	–	$	1,019

Index to Financial Statements

Oil and Gas Reserves

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2009, 2010, and 2011.

The definitions used are in accordance with the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves.

In accordance with the Securities and Exchange Commission’s rules, the year-end reserves volumes as well as the reserves change categories shown in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow.

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

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

In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies.

Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves that we report for these types of arrangements typically vary inversely with oil and gas price changes. As oil and gas prices increase, the cash flow and value received by the company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2011 that were associated with production sharing contract arrangements was 14 percent of liquids, 9 percent of natural gas and 11 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported in the Operating Summary due to volumes consumed or flared and inventory changes.

In accordance with the Securities and Exchange Commission’s rules, bitumen extracted through mining activities and hydrocarbons from other non-traditional resources are reported as oil and gas reserves beginning in 2009.

The rules in 2009 adopted a reliable technology definition that permits reserves to be added based on technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated.

The changes between 2010 year-end proved reserves and 2011 year-end proved reserves reflect the initial booking of the Kearl Expansion project in Canada.

Index to Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)


Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves
	Crude Oil and Natural Gas Liquids																					Bitumen			Synthetic Oil
	United States			Canada/ S. Amer.			Europe			Africa			Asia			Australia/ Oceania			Total			Canada/ S. Amer.			Canada/ S. Amer.			Total
	(millions of barrels)
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2009		1,644			812			533			2,137			2,219			231			7,576			–			–			7,576
Revisions		82			(610	)⁽¹⁾		93			(33	)		(130	)		9			(589	)		2,099	⁽¹⁾		715			2,225
Improved recovery		–			–			–			–			–			–			–			–			–			–
Purchases		–			–			–			–			–			–			–			–			–			–
Sales		(1	)		–			(2	)		–			–			–			(3	)		–			–			(3	)
Extensions/discoveries		3			–			–			53			15			71			142			–			–			142
Production		(112	)		(30	)		(137	)		(250	)		(105	)		(23	)		(657	)		(44	)		(24	)		(725	)

December 31, 2009		1,616			172			487			1,907			1,999			288			6,469			2,055			691			9,215

Proportional interest in proved reserves of equity companies
January 1, 2009		327			–			27			–			2,205			–			2,559			–			–			2,559
Revisions		56			–			5			–			(54	)		–			7			–			–			7
Improved recovery		–			–			–			–			15			–			15			–			–			15
Purchases		–			–			–			–			–			–			–			–			–			–
Sales		–			–			–			–			–			–			–			–			–			–
Extensions/discoveries		–			–			–			–			–			–			–			–			–			–
Production		(27	)		–			(2	)		–			(116	)		–			(145	)		–			–			(145	)

December 31, 2009		356			–			30			–			2,050			–			2,436			–			–			2,436

Total liquids proved reserves at December 31, 2009		1,972			172			517			1,907			4,049			288			8,905			2,055			691			11,651

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2010		1,616			172			487			1,907			1,999			288			6,469			2,055			691			9,215
Revisions		57			10			53			89			49			7			265			89			14			368
Improved recovery		4			–			–			–			–			1			5			–			–			5
Purchases		374			–			–			–			4			–			378			–			–			378
Sales		(19	)		–			–			(2	)		–			–			(21	)		–			–			(21	)
Extensions/discoveries		43			11			4			34			90			–			182			–			–			182
Production		(123	)		(30	)		(121	)		(229	)		(119	)		(21	)		(643	)		(42	)		(24	)		(709	)

December 31, 2010		1,952			163			423			1,799			2,023			275			6,635			2,102			681			9,418

Proportional interest in proved reserves of equity companies
January 1, 2010		356			–			30			–			2,050			–			2,436			–			–			2,436
Revisions		17			–			3			–			(30	)		–			(10	)		–			–			(10	)
Improved recovery		–			–			–			–			–			–			–			–			–			–
Purchases		–			–			–			–			–			–			–			–			–			–
Sales		–			–			–			–			–			–			–			–			–			–
Extensions/discoveries		3			–			–			–			–			–			3			–			–			3
Production		(25	)		–			(2	)		–			(147	)		–			(174	)		–			–			(174	)

December 31, 2010		351			–			31			–			1,873			–			2,255			–			–			2,255

Total liquids proved reserves at December 31, 2010		2,303			163			454			1,799			3,896			275			8,890			2,102			681			11,673

(1)

Total proved reserves of 630 million barrels at January 1, 2009, associated with the Cold Lake field in Canada are reported as bitumen reserves under the amended Securities and Exchange Commission’s Rule 4-10 of Regulation S-X.

Index to Financial Statements


Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves (continued)
	Crude Oil																					Natural Gas Liquids (1)			Bitumen			Synthetic Oil
	United States			Canada/ S. Amer.			Europe			Africa			Asia			Australia/ Oceania			Total			Worldwide			Canada/ S. Amer.			Canada/ S. Amer.			Total
	(millions of barrels)
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2011		1,679			138			350			1,589			1,839			178			5,773			862			2,102			681			9,418
Revisions		29			10			68			52			(55	)		5			109			106			53			(4	)		264
Improved recovery		–			–			–			–			–			–			–			–			–			–			–
Purchases		2			–			–			–			–			–			2			14			–			–			16
Sales		(3	)		(11	)		(24	)		–			–			–			(38	)		(14	)		–			–			(52	)
Extensions/discoveries		55			–			3			1			57			–			116			18			995			–			1,129
Production		(102	)		(19	)		(80	)		(179	)		(120	)		(13	)		(513	)		(81	)		(44	)		(24	)		(662	)

December 31, 2011		1,660			118			317			1,463			1,721			170			5,449			905			3,106			653			10,113

Proportional interest in proved reserves of equity companies
January 1, 2011		350			–			31			–			1,394			–			1,775			480			–			–			2,255
Revisions		24			–			–			–			(21	)		–			3			3			–			–			6
Improved recovery		–			–			–			–			–			–			–			–			–			–			–
Purchases		–			–			–			–			–			–			–			–			–			–			–
Sales		(2	)		–			–			–			–			–			(2	)		–			–			–			(2	)
Extensions/discoveries		–			–			–			–			12			–			12			25			–			–			37
Production		(24	)		–			(2	)		–			(130	)		–			(156	)		(25	)		–			–			(181	)

December 31, 2011		348			–			29			–			1,255			–			1,632			483			–			–			2,115

Total liquids proved reserves at December 31, 2011		2,008			118			346			1,463			2,976			170			7,081			1,388			3,106			653			12,228

(1)

Includes total proved reserves attributable to Imperial Oil Limited of 10 million barrels, as well as proved developed reserves of 10 million barrels, in which there is a 30.4 percent noncontrolling interest.

Index to Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)


Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves (continued)
	Crude Oil and Natural Gas Liquids															Bitumen		Synthetic Oil
	United States		Canada/ S. Amer. (1)		Europe		Africa		Asia		Australia/ Oceania		Total			Canada/ S. Amer. (2)		Canada/ S. Amer. (3)		Total
	(millions of barrels)
Proved developed reserves, as of December 31, 2009
Consolidated subsidiaries		1,211		152		376		1,122		1,268		153		4,282			468		691		5,441
Equity companies		279		–		10		–		1,608		–		1,897			–		–		1,897

Proved undeveloped reserves, as of December 31, 2009
Consolidated subsidiaries		405		20		111		785		731		135		2,187			1,587		–		3,774
Equity companies		77		–		20		–		442		–		539			–		–		539

Total liquids proved reserves at December 31, 2009		1,972		172		517		1,907		4,049		288		8,905			2,055		691		11,651

Proved developed reserves, as of December 31, 2010
Consolidated subsidiaries		1,478		133		361		1,055		1,306		139		4,472			519		681		5,672
Equity companies		271		–		21		–		1,623		–		1,915			–		–		1,915

Proved undeveloped reserves, as of December 31, 2010
Consolidated subsidiaries		474		30		62		744		717		136		2,163			1,583		–		3,746
Equity companies		80		–		10		–		250		–		340			–		–		340

Total liquids proved reserves at December 31, 2010		2,303		163		454		1,799		3,896		275		8,890			2,102		681		11,673

Proved developed reserves, as of December 31, 2011
Consolidated subsidiaries		1,452		109		302		1,050		1,160		126		4,199			519		653		5,371
Equity companies		270		–		28		–		1,457		–		1,755			–		–		1,755

Proved undeveloped reserves, as of December 31, 2011
Consolidated subsidiaries		567		26		74		625		727		136		2,155			2,587		–		4,742
Equity companies		83		–		1		–		276		–		360			–		–		360

Total liquids proved reserves at December 31, 2011		2,372		135		405		1,675		3,620		262		8,469	⁽⁴⁾		3,106		653		12,228

(1)

Includes total proved reserves attributable to Imperial Oil Limited of 63 million barrels in 2009, 57 million barrels in 2010 and 55 million barrels in 2011, as well as proved developed reserves of 62 million barrels in 2009, 56 million barrels in 2010 and 55 million barrels in 2011, and in addition, proved undeveloped reserves of 1 million barrels in 2009 and 1 million barrels in 2010, in which there is a 30.4 percent noncontrolling interest.

(2)

Includes total proved reserves attributable to Imperial Oil Limited of 1,661 million barrels in 2009, 1,715 million barrels in 2010 and 2,413 million barrels in 2011, as well as proved developed reserves of 468 million barrels in 2009, 519 million barrels in 2010 and 519 million barrels in 2011, and in addition, proved undeveloped reserves of 1,193 million barrels in 2009, 1,196 million barrels in 2010 and 1,894 million barrels in 2011, in which there is a 30.4 percent noncontrolling interest.

(3)

Includes total proved reserves attributable to Imperial Oil Limited of 691 million barrels in 2009, 681 million barrels in 2010 and 653 million barrels in 2011, as well as proved developed reserves of 691 million barrels in 2009, 681 million barrels in 2010 and 653 million barrels in 2011, in which there is a 30.4 percent noncontrolling interest.

(4)

See previous page for natural gas liquids proved reserves attributable to consolidated subsidiaries and equity companies. For additional information on natural gas liquids proved reserves see Item 2. Properties in ExxonMobil’s 2011 Form 10-K.

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Index to Financial Statements


Natural Gas and Oil-Equivalent Proved Reserves
	Natural Gas																					Oil-Equivalent Total All Products *(2)*
	United States			Canada/ S. Amer. (1)			Europe			Africa			Asia			Australia/ Oceania			Total			Oil-Equivalent Total All Products *(2)*
							(billions of cubic feet)															(millions of oil-equivalent barrels)
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2009		11,778			1,383			5,445			918			9,857			2,021			31,402			12,810
Revisions		320			248			79			45			(980	)		40			(248	)		2,183
Improved recovery		–			–			–			–			–			–			–			–
Purchases		8			–			–			–			–			–			8			1
Sales		(10	)		(2	)		(1	)		–			–			–			(13	)		(5	)
Extensions/discoveries		158			–			–			–			11			5,507			5,676			1,088
Production		(566	)		(261	)		(800	)		(43	)		(585	)		(128	)		(2,383	)		(1,122	)
December 31, 2009		11,688			1,368			4,723			920			8,303			7,440			34,442			14,955

Proportional interest in proved reserves of equity companies
January 1, 2009		112			–			11,839			–			22,526			–			34,477			8,305
Revisions		8			–			186			–			189			–			383			71
Improved recovery		–			–			–			–			–			–			–			15
Purchases		–			–			–			–			–			–			–			–
Sales		–			–			–			–			–			–			–			–
Extensions/discoveries		–			–			18			–			–			–			18			3
Production		(6	)		–			(593	)		–			(714	)		–			(1,313	)		(364	)
December 31, 2009		114			–			11,450			–			22,001			–			33,565			8,030
Total proved reserves at December 31, 2009		11,802			1,368			16,173			920			30,304			7,440			68,007			22,985

Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2010		11,688			1,368			4,723			920			8,303			7,440			34,442			14,955
Revisions		832			123			(26	)		6			(333	)		42			644			475
Improved recovery		–			–			–			–			–			–			–			5
Purchases		12,774			–			15			–			–			–			12,789			2,510
Sales		(104	)		(2	)		–			–			–			–			(106	)		(38	)
Extensions/discoveries		1,861			3			49			25			25			1			1,964			509
Production		(1,057	)		(234	)		(719	)		(43	)		(735	)		(132	)		(2,920	)		(1,196	)
December 31, 2010		25,994			1,258			4,042			908			7,260			7,351			46,813			17,220

Proportional interest in proved reserves of equity companies
January 1, 2010		114			–			11,450			–			22,001			–			33,565			8,030
Revisions		8			–			(4	)		–			231			–			235			30
Improved recovery		–			–			–			–			–			–			–			–
Purchases		–			–			–			–			–			–			–			–
Sales		–			–			–			–			–			–			–			–
Extensions/discoveries		–			–			24			–			–			–			24			7
Production		(5	)		–			(724	)		–			(1,093	)		–			(1,822	)		(478	)
December 31, 2010		117			–			10,746			–			21,139			–			32,002			7,589

Total proved reserves at December 31, 2010		26,111			1,258			14,788			908			28,399			7,351			78,815			24,809

(See footnotes on next page)

101

Index to Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)


Natural Gas and Oil-Equivalent Proved Reserves (continued)
	Natural Gas																					Oil-Equivalent Total All Products *(2)*
	United States			Canada/ S. Amer. (1)			Europe			Africa			Asia			Australia/ Oceania			Total			Oil-Equivalent Total All Products *(2)*
							(billions of cubic feet)															(millions of oil-equivalent barrels)
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2011		25,994			1,258			4,042			908			7,260			7,351			46,813			17,220
Revisions		(236	)		55			310			113			(231	)		28			39			271
Improved recovery		–			–			–			–			–			–			–			–
Purchases		303			–			–			–			–			–			303			67
Sales		(32	)		(347	)		(140	)		–			–			–			(519	)		(138	)
Extensions/discoveries		1,779			42			29			–			192			–			2,042			1,469
Production		(1,554	)		(173	)		(655	)		(39	)		(750	)		(132	)		(3,303	)		(1,213	)
December 31, 2011		26,254			835			3,586			982			6,471			7,247			45,375			17,676

Proportional interest in proved reserves of equity companies
January 1, 2011		117			–			10,746			–			21,139			–			32,002			7,589
Revisions		1			–			53			–			(29	)		–			25			10
Improved recovery		–			–			–			–			–			–			–			–
Purchases		–			–			–			–			–			–			–			–
Sales		(1	)		–			(3	)		–			–			–			(4	)		(3	)
Extensions/discoveries		–			–			13			–			627			–			640			144
Production		(5	)		–			(640	)		–			(1,171	)		–			(1,816	)		(484	)
December 31, 2011		112			–			10,169			–			20,566			–			30,847			7,256

Total proved reserves at December 31, 2011		26,366			835			13,755			982			27,037			7,247			76,222			24,932

(1)

Includes total proved reserves attributable to Imperial Oil Limited of 590 billion cubic feet in 2009, 576 billion cubic feet in 2010 and 422 billion cubic feet in 2011, as well as proved developed reserves of 526 billion cubic feet in 2009, 507 billion cubic feet in 2010 and 360 billion cubic feet in 2011, and in addition, proved undeveloped reserves of 64 billion cubic feet in 2009, 69 billion cubic feet in 2010 and 62 billion cubic feet in 2011, in which there is a 30.4 percent noncontrolling interest.

(2)

Natural gas is converted to oil-equivalent basis at six million cubic feet per one thousand barrels.

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Index to Financial Statements


Natural Gas and Oil-Equivalent Proved Reserves (continued)
	Natural Gas														Oil-Equivalent Total All Products *(2)*
	United States		Canada/ S. Amer. (1)		Europe		Africa		Asia		Australia/ Oceania		Total		Oil-Equivalent Total All Products *(2)*
					(billions of cubic feet)										(millions of oil-equivalent barrels)
Proved developed reserves, as of December 31, 2009
Consolidated subsidiaries		7,492		1,200		3,920		739		7,407		1,262		22,020		9,111
Equity companies		90		–		8,862		–		17,799		–		26,751		6,356

Proved undeveloped reserves, as of December 31, 2009
Consolidated subsidiaries		4,196		168		803		181		896		6,178		12,422		5,844
Equity companies		24		–		2,588		–		4,202		–		6,814		1,674

Total proved reserves at December 31, 2009		11,802		1,368		16,173		920		30,304		7,440		68,007		22,985

Proved developed reserves, as of December 31, 2010
Consolidated subsidiaries		15,344		1,077		3,516		711		6,593		1,174		28,415		10,408
Equity companies		97		–		8,167		–		20,494		–		28,758		6,708

Proved undeveloped reserves, as of December 31, 2010
Consolidated subsidiaries		10,650		181		526		197		667		6,177		18,398		6,812
Equity companies		20		–		2,579		–		645		–		3,244		881

Total proved reserves at December 31, 2010		26,111		1,258		14,788		908		28,399		7,351		78,815		24,809

Proved developed reserves, as of December 31, 2011
Consolidated subsidiaries		15,450		658		3,041		853		5,762		1,070		26,834		9,843
Equity companies		83		–		7,588		–		19,305		–		26,976		6,251

Proved undeveloped reserves, as of December 31, 2011
Consolidated subsidiaries		10,804		177		545		129		709		6,177		18,541		7,833
Equity companies		29		–		2,581		–		1,261		–		3,871		1,005

Total proved reserves at December 31, 2011		26,366		835		13,755		982		27,037		7,247		76,222		24,932

(See footnotes on previous page)

103

Index to Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

Standardized Measure of Discounted Future Cash Flows

As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.


Standardized Measure of Discounted Future Cash Flows	United States		Canada/ South America (1)		Europe		Africa		Asia		Australia/ Oceania		Total
	(millions of dollars)
Consolidated Subsidiaries
As of December 31, 2009
Future cash inflows from sales of oil and gas	$	112,408	$	147,597	$	54,074	$	110,475	$	121,110	$	39,127	$	584,791
Future production costs		47,660		62,241		16,412		28,679		29,769		12,571		197,332
Future development costs		15,544		25,738		12,565		15,155		10,256		11,655		90,913
Future income tax expenses		22,058		14,572		16,065		32,784		46,286		4,739		136,504
Future net cash flows	$	27,146	$	45,046	$	9,032	$	33,857	$	34,799	$	10,162	$	160,042
Effect of discounting net cash flows at 10%		15,563		31,980		2,569		14,192		20,698		9,194		94,196
Discounted future net cash flows	$	11,583	$	13,066	$	6,463	$	19,665	$	14,101	$	968	$	65,846

Equity Companies
As of December 31, 2009
Future cash inflows from sales of oil and gas	$	19,705	$	–	$	94,401	$	–	$	180,253	$	–	$	294,359
Future production costs		5,847		–		60,869		–		54,493		–		121,209
Future development costs		2,862		–		3,220		–		2,759		–		8,841
Future income tax expenses		–		–		12,003		–		44,733		–		56,736
Future net cash flows	$	10,996	$	–	$	18,309	$	–	$	78,268	$	–	$	107,573
Effect of discounting net cash flows at 10%		6,332		–		9,845		–		42,086		–		58,263
Discounted future net cash flows	$	4,664	$	–	$	8,464	$	–	$	36,182	$	–	$	49,310

Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	16,247	$	13,066	$	14,927	$	19,665	$	50,283	$	968	$	115,156

(1)

Includes discounted future net cash flows attributable to Imperial Oil Limited of $10,088 million in 2009, in which there is a 30.4 percent noncontrolling interest.

104

Index to Financial Statements


Standardized Measure of Discounted Future Cash Flows (continued)	United States		Canada/ South America (1)		Europe		Africa		Asia		Australia/ Oceania		Total
	(millions of dollars)
Consolidated Subsidiaries
As of December 31, 2010
Future cash inflows from sales of oil and gas	$	221,298	$	184,671	$	60,086	$	137,476	$	156,337	$	55,087	$	814,955
Future production costs		76,992		69,765		15,246		31,189		36,318		16,347		245,857
Future development costs		28,905		22,130		12,155		15,170		13,716		11,652		103,728
Future income tax expenses		44,128		21,798		21,736		46,145		59,477		9,591		202,875
Future net cash flows	$	71,273	$	70,978	$	10,949	$	44,972	$	46,826	$	17,497	$	262,495
Effect of discounting net cash flows at 10%		39,545		45,607		2,765		18,046		28,883		13,411		148,257
Discounted future net cash flows	$	31,728	$	25,371	$	8,184	$	26,926	$	17,943	$	4,086	$	114,238

Equity Companies
As of December 31, 2010
Future cash inflows from sales of oil and gas	$	26,110	$	–	$	73,222	$	–	$	232,334	$	–	$	331,666
Future production costs		6,369		–		49,010		–		73,508		–		128,887
Future development costs		2,883		–		2,719		–		2,523		–		8,125
Future income tax expenses		–		–		8,348		–		57,041		–		65,389
Future net cash flows	$	16,858	$	–	$	13,145	$	–	$	99,262	$	–	$	129,265
Effect of discounting net cash flows at 10%		9,612		–		6,857		–		51,512		–		67,981
Discounted future net cash flows	$	7,246	$	–	$	6,288	$	–	$	47,750	$	–	$	61,284

Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	38,974	$	25,371	$	14,472	$	26,926	$	65,693	$	4,086	$	175,522

Consolidated Subsidiaries
As of December 31, 2011
Future cash inflows from sales of oil and gas	$	264,991	$	280,991	$	71,847	$	179,337	$	203,007	$	86,456	$	1,086,629
Future production costs		105,391		98,135		15,045		36,309		43,442		23,381		321,703
Future development costs		31,452		35,121		11,987		15,384		16,010		10,052		120,006
Future income tax expenses		53,507		34,542		32,004		67,256		79,975		17,287		284,571
Future net cash flows	$	74,641	$	113,193	$	12,811	$	60,388	$	63,580	$	35,736	$	360,349
Effect of discounting net cash flows at 10%		42,309		79,303		3,525		22,029		38,066		22,873		208,105
Discounted future net cash flows	$	32,332	$	33,890	$	9,286	$	38,359	$	25,514	$	12,863	$	152,244

Equity Companies
As of December 31, 2011
Future cash inflows from sales of oil and gas	$	37,398	$	–	$	88,417	$	–	$	324,283	$	–	$	450,098
Future production costs		6,862		–		62,377		–		104,040		–		173,279
Future development costs		3,072		–		2,701		–		3,636		–		9,409
Future income tax expenses		–		–		9,035		–		76,825		–		85,860
Future net cash flows	$	27,464	$	–	$	14,304	$	–	$	139,782	$	–	$	181,550
Effect of discounting net cash flows at 10%		15,941				7,131				71,918				94,990
Discounted future net cash flows	$	11,523	$	–	$	7,173	$	–	$	67,864	$	–	$	86,560

Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	43,855	$	33,890	$	16,459	$	38,359	$	93,378	$	12,863	$	238,804

(1)

Includes discounted future net cash flows attributable to Imperial Oil Limited of $19,834 million in 2010 and $27,568 million in 2011, in which there is a 30.4 percent noncontrolling interest.

105

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)

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


Consolidated and Equity Interests	2009
	Consolidated Subsidiaries			Share of Equity Method Investees			Total Consolidated and Equity Interests
	(millions of dollars)

Discounted future net cash flows as of December 31, 2008	$	40,569		$	45,449		$	86,018

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs		2,138			280			2,418
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs		(35,384	)		(10,288	)		(45,672	)
Development costs incurred during the year		13,549			1,017			14,566
Net change in prices, lifting and development costs		51,627			9,245			60,872
Revisions of previous reserves estimates		8,805			858			9,663
Accretion of discount		6,943			5,214			12,157
Net change in income taxes		(22,401	)		(2,465	)		(24,866	)
Total change in the standardized measure during the year	$	25,277		$	3,861		$	29,138	(1)(2)

Discounted future net cash flows as of December 31, 2009	$	65,846		$	49,310		$	115,156

(1)

Discounted future net cash flows associated with synthetic oil reserves and bitumen mining operations in 2009 were $5,268 million. Cold Lake bitumen operations had been included in discounted future net cash flows in previous years as an oil and gas operation.

(2)

The estimated impact of adopting the reliable technology definition and changing from year-end price to first-day-of-the-month average prices in the Securities and Exchange Commission’s Rule 4-10 of Regulation S-X was de minimis on discounted future net cash flows for consolidated and equity subsidiaries in 2009.


Consolidated and Equity Interests	2010
	Consolidated Subsidiaries			Share of Equity Method Investees			Total Consolidated and Equity Interests
	(millions of dollars)

Discounted future net cash flows as of December 31, 2009	$	65,846		$	49,310		$	115,156

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs		20,093			210			20,303
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs		(46,078	)		(16,050	)		(62,128	)
Development costs incurred during the year		20,975			843			21,818
Net change in prices, lifting and development costs		61,612			23,135			84,747
Revisions of previous reserves estimates		14,770			3,605			18,375
Accretion of discount		10,399			5,775			16,174
Net change in income taxes		(33,379	)		(5,544	)		(38,923	)
Total change in the standardized measure during the year	$	48,392		$	11,974		$	60,366

Discounted future net cash flows as of December 31, 2010	$	114,238		$	61,284		$	175,522

106

Index to Financial Statements

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


Consolidated and Equity Interests (continued)	2011
	Consolidated Subsidiaries			Share of Equity Method Investees			Total Consolidated and Equity Interests
	(millions of dollars)

Discounted future net cash flows as of December 31, 2010	$	114,238		$	61,284		$	175,522

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs		6,608			309			6,917
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs		(58,308	)		(22,402	)		(80,710	)
Development costs incurred during the year		22,843			1,153			23,996
Net change in prices, lifting and development costs		79,435			46,304			125,739
Revisions of previous reserves estimates		10,462			3,127			13,589
Accretion of discount		16,802			7,196			23,998
Net change in income taxes		(39,836	)		(10,411	)		(50,247	)
Total change in the standardized measure during the year	$	38,006		$	25,276		$	63,282

Discounted future net cash flows as of December 31, 2011	$	152,244		$	86,560		$	238,804

107

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OPERATING SUMMARY (unaudited)


	2011		2010		2009		2008		2007
	(thousands of barrels daily)
Production of crude oil, natural gas liquids, synthetic oil and bitumen
Net production
United States		423		408		384		367		392
Canada/South America		252		263		267		292		324
Europe		270		335		379		428		480
Africa		508		628		685		652		717
Asia		808		730		607		599		629
Australia/Oceania		51		58		65		67		74
Worldwide		2,312		2,422		2,387		2,405		2,616
	(millions of cubic feet daily)
Natural gas production available for sale
Net production
United States		3,917		2,596		1,275		1,246		1,468
Canada/South America		412		569		643		640		808
Europe		3,448		3,836		3,689		3,949		3,810
Africa		7		14		19		32		26
Asia		5,047		4,801		3,332		2,870		2,883
Australia/Oceania		331		332		315		358		389
Worldwide		13,162		12,148		9,273		9,095		9,384
	(thousands of oil-equivalent barrels daily)

Oil-equivalent production (1)		4,506		4,447		3,932		3,921		4,180
	(thousands of barrels daily)
Refinery throughput
United States		1,784		1,753		1,767		1,702		1,746
Canada		430		444		413		446		442
Europe		1,528		1,538		1,548		1,601		1,642
Asia Pacific		1,180		1,249		1,328		1,352		1,416
Other Non-U.S.		292		269		294		315		325
Worldwide		5,214		5,253		5,350		5,416		5,571
Petroleum product sales (2)
United States		2,530		2,511		2,523		2,540		2,717
Canada		455		450		413		444		461
Europe		1,596		1,611		1,625		1,712		1,773
Asia Pacific and other Eastern Hemisphere		1,556		1,562		1,588		1,646		1,701
Latin America		276		280		279		419		447
Worldwide		6,413		6,414		6,428		6,761		7,099
Gasoline, naphthas		2,541		2,611		2,573		2,654		2,850
Heating oils, kerosene, diesel oils		2,019		1,951		2,013		2,096		2,094
Aviation fuels		492		476		536		607		641
Heavy fuels		588		603		598		636		715
Specialty petroleum products		773		773		708		768		799
Worldwide		6,413		6,414		6,428		6,761		7,099
	(thousands of metric tons)
Chemical prime product sales
United States		9,250		9,815		9,649		9,526		10,855
Non-U.S.		15,756		16,076		15,176		15,456		16,625
Worldwide		25,006		25,891		24,825		24,982		27,480

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

(1)

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

(2)

Petroleum product sales data reported net of purchases/sales contracts with the same counterparty.

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Index to Financial Statements

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


EXXON MOBIL CORPORATION

By:		/s/ REX W. TILLERSON
		(Rex W. Tillerson, Chairman of the Board)

Dated February 24, 2012

POWER OF ATTORNEY

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

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 24, 2012.



/s/ REX W. TILLERSON (Rex W. Tillerson)				Chairman of the Board (Principal Executive Officer)

/s/ MICHAEL J. BOSKIN (Michael J. Boskin)				Director

/s/ PETER BRABECK-LETMATHE (Peter Brabeck-Letmathe)				Director

/s/ LARRY R. FAULKNER (Larry R. Faulkner)				Director

/s/ JAY S. FISHMAN (Jay S. Fishman)				Director

/s/ KENNETH C. FRAZIER (Kenneth C. Frazier)				Director

/s/ WILLIAM W. GEORGE (William W. George)				Director

109

Index to Financial Statements



/s/ MARILYN CARLSON NELSON (Marilyn Carlson Nelson)				Director

/s/ SAMUEL J. PALMISANO (Samuel J. Palmisano)				Director

/s/ STEVEN S REINEMUND (Steven S Reinemund)				Director

/s/ EDWARD E. WHITACRE, JR. (Edward E. Whitacre, Jr.)				Director

/s/ DONALD D. HUMPHREYS (Donald D. Humphreys)				Senior Vice President (Principal Financial Officer)

/s/ PATRICK T. MULVA (Patrick T. Mulva)				Controller (Principal Accounting Officer)

110

Index to Financial Statements

INDEX TO EXHIBITS


3(i)		Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).

3(ii)		By-Laws, as revised to April 27, 2011 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K on April 29, 2011).

10(iii)(a.1)		2003 Incentive Program (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008).*

10(iii)(a.2)		Form of restricted stock agreement with executive officers (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K of November 30, 2011).*

10(iii)(a.3)		Extended Provisions for Restricted Stock Unit Agreements-Settlement in Shares.*

10(iii)(b.1)		Short Term Incentive Program, as amended (incorporated by reference to Exhibit 99.3 to the Registrant’s Report on Form 8-K on December 1, 2009).*

10(iii)(b.2)		Form of Earnings Bonus Unit granted to executive officers (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on November 30, 2011).*

10(iii)(c.1)		ExxonMobil Supplemental Savings Plan.*

10(iii)(c.2)		ExxonMobil Supplemental Pension Plan.*

10(iii)(c.3)		ExxonMobil Additional Payments Plan.*

10(iii)(d)		ExxonMobil Executive Life Insurance and Death Benefit Plan.*

10(iii)(f.1)		2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).*

10(iii)(f.2)		Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K on September 27, 2007).*

10(iii)(f.3)		Form of restricted stock grant letter for non-employee directors (incorporated by reference to Exhibit 10(iii)(f.3) to the Registrant’s Annual Report on Form 10-K for 2009).*

10(iii)(f.4)		Standing resolution for non-employee director cash fees dated October 26, 2011 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).*

10(iii)(g.3)		1984 Mobil Compensation Management Retention Plan.*

12		Computation of ratio of earnings to fixed charges.

14		Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2008).

21		Subsidiaries of the registrant.

23		Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

31.1		Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.

31.2		Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Financial Officer.

31.3		Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.

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

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

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

101		Interactive data files.

111

Index to Financial Statements

INDEX TO EXHIBITS—(continued)

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

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

112