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

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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	$