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Index to Financial Statements

2010

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

or

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to               

Commission File Number 1-2256

EXXON MOBIL CORPORATION

(Exact name of registrant as specified in its charter)

 

NEW JERSEY

(State or other jurisdiction of
incorporation or organization)

 

13-5409005

(I.R.S. Employer
Identification Number)

 

5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298

(Address of principal executive offices) (Zip Code)

(972) 444-1000

(Registrant’s telephone number, including area code)

 

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

Title of Each Class

   Name of Each Exchange
on Which Registered

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

   New York Stock Exchange
Registered securities guaranteed by Registrant:   

SeaRiver Maritime Financial Holdings, Inc.

  

Twenty-Five Year Debt Securities due October 1, 2011

   New York Stock Exchange

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes   ü    No        

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes   ü    No        

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ü   

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer    ü           Accelerated filer                 

Non-accelerated filer                  Smaller reporting company        

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

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $57.07 on the New York Stock Exchange composite tape, was in excess of $290 billion.

Documents Incorporated by Reference:

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

 

 


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Index to Financial Statements

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

 

TABLE OF CONTENTS

 

     Page
Number
 
PART I   
Item 1.   

Business

     1   
Item 1A.   

Risk Factors

     2   
Item 1B.   

Unresolved Staff Comments

     5   
Item 2.   

Properties

     6   
Item 3.   

Legal Proceedings

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

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

     36   
Item 6.   

Selected Financial Data

     36   
Item 7.   

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

     37   
Item 7A.   

Quantitative and Qualitative Disclosures About Market Risk

     37   
Item 8.   

Financial Statements and Supplementary Data

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

Directors, Executive Officers and Corporate Governance

     38   
Item 11.   

Executive Compensation

     39   
Item 12.   

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

     39   
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

     40   
Item 14.   

Principal Accounting Fees and Services

     40   
PART IV   
Item 15.   

Exhibits, Financial Statement Schedules

     40   

Financial Section

     41   
Signatures      119   
Index to Exhibits      121   
Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges   
Exhibits 31 and 32 — Certifications   


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PART I

 

Item 1.    Business.

 

Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil also has interests in electric power generation facilities. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.

 

Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso or Mobil. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso and Mobil, as well as terms like Corporation, Company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.

 

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

 

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

 

The energy and petrochemical industries are highly competitive. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. The Corporation competes with other firms in the sale or purchase of needed goods and services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes.

 

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

 

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

 

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

 

The number of regular employees was 83.6 thousand, 80.7 thousand and 79.9 thousand at years ended 2010, 2009 and 2008, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 20.1 thousand, 22.0 thousand and 24.8 thousand at years ended 2010, 2009 and 2008, respectively.

 

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

 

ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit, compensation and nominating committees of the Board of Directors. Information on our website is not incorporated into this report.

 

Item 1A.     Risk Factors.

 

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

 

Supply and Demand.

 

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

 

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

 

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

 

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

 

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

 

Government and Political Factors.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Management Effectiveness.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Item 1B.     Unresolved Staff Comments.

 

None.

 

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Item 2.    Properties.

 

Information with regard to oil and gas producing activities follows:

 

1.     Disclosure of Reserves

 

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

 

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

 

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

Proved Reserves

         

Developed

         

Consolidated Subsidiaries

         

United States

    1,478        —          —          15,344        4,035   

Canada/South America(2)

    133        519        681        1,077        1,512   

Europe

    361        —          —          3,516        947   

Africa

    1,055        —          —          711        1,174   

Asia

    1,306        —          —          6,593        2,405   

Australia/Oceania

    139        —          —          1,174        335   
                                       

Total Consolidated

    4,472        519        681        28,415        10,408   

Equity Companies

         

United States

    271        —          —          97        287   

Europe

    21        —          —          8,167        1,382   

Asia

    1,623        —          —          20,494        5,039   
                                       

Total Equity Company

    1,915        —          —          28,758        6,708   
                                       

Total Developed

    6,387        519        681        57,173        17,116   

Undeveloped

         

Consolidated Subsidiaries

         

United States

    474        —          —          10,650        2,249   

Canada/South America(2)

    30        1,583        —          181        1,643   

Europe

    62        —          —          526        150   

Africa

    744        —          —          197        777   

Asia

    717        —          —          667        828   

Australia/Oceania

    136        —          —          6,177        1,165   
                                       

Total Consolidated

    2,163        1,583        —          18,398        6,812   

Equity Companies

         

United States

    80        —          —          20        83   

Europe

    10        —          —          2,579        440   

Asia

    250        —          —          645        358   
                                       

Total Equity Company

    340        —          —          3,244        881   
                                       

Total Undeveloped

    2,503        1,583        —          21,642        7,693   
                                       

Total Proved Reserves

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

 

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

 

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In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.

 

The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the period 2011-2015. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, weather events, price effects on production sharing contracts and other factors as described in Item 1A—Risk Factors of this report.

 

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

 

B. Technologies Used in Establishing Proved Reserves Additions in 2010

 

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

 

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

 

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

 

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

 

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

 

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

 

2.    Proved Undeveloped Reserves

 

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

 

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

 

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

 

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

 

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

 

A. Oil and Gas Production

 

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

 

     2010      2009      2008  
     (thousands of barrels daily)  

Crude oil and natural gas liquids production

        

Consolidated Subsidiaries

        

United States

     339         311         289   

Canada/South America(1)

     81         82         106   

Europe

     330         374         423   

Africa

     628         685         652   

Asia

     326         287         319   

Australia/Oceania

     58         65         67   
                          

Total Consolidated Subsidiaries

     1,762         1,804         1,856   
        

Equity Companies

        

United States

     69         73         78   

Europe

     5         5         5   

Asia

     404         320         280   
                          

Total Equity Companies

     478         398         363   
                          

Total crude oil and natural gas liquids production

     2,240         2,202         2,219   

Bitumen production

        

Consolidated Subsidiaries

        

Canada/South America

     115         120         124   

Synthetic oil production

        

Consolidated Subsidiaries

        

Canada/South America

     67         65         62   
                          

Total liquids production

     2,422         2,387         2,405   
                          
    

(millions of cubic feet daily)

 

Natural gas production available for sale

        

Consolidated Subsidiaries

        

United States

     2,595         1,274         1,245   

Canada/South America(1)

     569         643         640   

Europe

     1,859         2,071         2,253   

Africa

     14         19         32   

Asia

     1,847         1,414         1,437   

Australia/Oceania

     332         315         358   
                          

Total Consolidated Subsidiaries

     7,216         5,736         5,965   
        

Equity Companies

        

United States

     1         1         1   

Europe

     1,977         1,618         1,696   

Asia

     2,954         1,918         1,433   
                          

Total Equity Companies

     4,932         3,537         3,130   
                          

Total natural gas production available for sale

     12,148         9,273         9,095   
                          
    

(thousands of oil-equivalent
barrels daily)

 
        

Oil-equivalent production

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

 

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B. Production Prices and Production Costs

 

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

 

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

Consolidated Subsidiaries

                    

Average production prices

                    

Crude oil and NGL, per barrel

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

Natural gas, per thousand cubic feet

     3.92         3.41         6.44         2.15         3.19         3.31         4.31   

Bitumen, per barrel

             56.61                                         56.61   

Synthetic oil, per barrel

             78.42                                         78.42   

Average production costs, per oil-equivalent barrel - total

     9.92         20.07         11.62         9.63         5.65         11.20         10.54   

Average production costs, per barrel - bitumen

             17.81                                         17.81   

Average production costs, per barrel - synthetic oil

             42.79                                         42.79   

Equity Companies

                    

Average production prices

                    

Crude oil and NGL, per barrel

     74.70                 74.14                 72.67                 72.98   

Natural gas, per thousand cubic feet

     8.30                 6.91                 5.42                 6.02   

Average production costs, per oil-equivalent barrel - total

     19.11                 2.41                 0.98                 2.31   

Total

                    

Average production prices

                    

Crude oil and NGL, per barrel

     70.98         69.92         73.38         78.08         72.80         68.91         73.81   

Natural gas, per thousand cubic feet

     3.92         3.41         6.68         2.15         4.56         3.31         5.00   

Bitumen, per barrel

             56.61                                         56.61   

Synthetic oil, per barrel

             78.42                                         78.42   

Average production costs, per oil-equivalent barrel - total

     10.67         20.07         8.46         9.63         2.91         11.20         8.14   

Average production costs, per barrel - bitumen

             17.81                                         17.81   

Average production costs, per barrel - synthetic oil

             42.79                                         42.79   

During 2009

                    

Consolidated Subsidiaries

                    

Average production prices

                    

Crude oil and NGL, per barrel

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

Natural gas, per thousand cubic feet

     3.10         3.19         5.61         1.70         3.07         2.97         4.00   

Bitumen, per barrel

             45.22                                         45.22   

Synthetic oil, per barrel

             61.26                                         61.26   

Average production costs, per oil-equivalent barrel - total

     11.80         17.75         10.19         8.07         6.55         8.98         10.25   

Average production costs, per barrel - bitumen

             14.77                                         14.77   

Average production costs, per barrel - synthetic oil

             37.47                                         37.47   

Equity Companies

                    

Average production prices

                    

Crude oil and NGL, per barrel

     56.54                 58.20                 56.12                 56.22   

Natural gas, per thousand cubic feet

     5.75                 8.20                 3.79                 5.81   

Average production costs, per oil-equivalent barrel - total

     18.07                 2.48                 1.07                 2.72   

Total

                    

Average production prices

                    

Crude oil and NGL, per barrel

     54.02         54.07         56.89         60.10         58.18         54.84         57.56   

Natural gas, per thousand cubic feet

     3.10         3.19         6.74         1.70         3.48         2.97         4.69   

Bitumen, per barrel

             45.22                                         45.22   

Synthetic oil, per barrel

             61.26                                         61.26   

Average production costs, per oil-equivalent barrel - total

     12.57         17.75         8.06         8.07         3.53         8.98         8.36   

Average production costs, per barrel - bitumen

             14.77                                         14.77   

Average production costs, per barrel - synthetic oil

             37.47                                         37.47   

 

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

Consolidated Subsidiaries

                    

Average production prices

                    

Crude oil and NGL, per barrel

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

Natural gas, per thousand cubic feet

     7.22         7.82         10.12         3.33         4.88         2.97         7.54   

Bitumen, per barrel

             65.45                                         65.45   

Synthetic oil, per barrel

             100.35                                         100.35   

Average production costs, per oil-equivalent barrel - total

     11.80         18.03         8.97         6.66         5.37         7.18         9.38   

Average production costs, per barrel - bitumen

             19.55                                         19.55   

Average production costs, per barrel - synthetic oil

             41.47                                         41.47   

Equity Companies

                    

Average production prices

                    

Crude oil and NGL, per barrel

     89.94                 85.08                 91.16                 90.80   

Natural gas, per thousand cubic feet

     13.97                 11.09                 8.46                 9.89   

Average production costs, per oil-equivalent barrel - total

     18.55                 4.06                 1.54                 3.86   

Total

                    

Average production prices

                    

Crude oil and NGL, per barrel

     87.95         89.46         89.59         92.69         92.72         86.08         90.93   

Natural gas, per thousand cubic feet

     7.23         7.82         10.54         3.33         6.67         2.97         8.35   

Bitumen, per barrel

             65.45                                         65.45   

Synthetic oil, per barrel

             100.35                                         100.35   

Average production costs, per oil-equivalent barrel - total

     12.72         18.03         7.67         6.66         3.53         7.18         8.14   

Average production costs, per barrel - bitumen

             19.55                                         19.55   

Average production costs, per barrel - synthetic oil

             41.47                                         41.47   

 

Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report due to volumes consumed or flared. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

 

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4.    Drilling and Other Exploratory and Development Activities

 

A. Number of Net Productive and Dry Wells Drilled

 

     2010      2009      2008  

Net Productive Exploratory Wells Drilled

        

Consolidated Subsidiaries

        

United States

     17         10         10   

Canada/South America

     12         4           

Europe

     3         2         3   

Africa

     1         2         3   

Asia

                     2   

Australia/Oceania

     2         1           
                          

Total Consolidated Subsidiaries

     35         19         18   

Equity Companies

        

United States

                       

Europe

     2         1         1   

Asia

                       
                          

Total Equity Companies

     2         1         1   
                          

Total productive exploratory wells drilled

     37         20         19   

Net Dry Exploratory Wells Drilled

        

Consolidated Subsidiaries

        

United States

     2         1         3   

Canada/South America

     1                   

Europe

             4         2   

Africa

     1         3         2   

Asia

     2         1           

Australia/Oceania

     1                 1   
                          

Total Consolidated Subsidiaries

     7         9         8   

Equity Companies

        

United States

                       

Europe

                       

Asia

                     1   
                          

Total Equity Companies

                     1   
                          

Total dry exploratory wells drilled

     7         9         9   

 

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     2010      2009      2008  

Net Productive Development Wells Drilled

        

Consolidated Subsidiaries

        

United States

     604         165         105   

Canada/South America

     229         291         223   

Europe

     11         10         8   

Africa

     60         45         39   

Asia

     7         9         16   

Australia/Oceania

     2         7         3   
                          

Total Consolidated Subsidiaries

     913         527         394   

Equity Companies

        

United States

     282         287         321   

Europe

     1         1         2   

Asia

     4         14         14   
                          

Total Equity Companies

     287         302         337   
                          

Total productive development wells drilled

     1,200         829         731   

Net Dry Development Wells Drilled

        

Consolidated Subsidiaries

        

United States

     2         3         3   

Canada/South America

                     1   

Europe

             1           

Africa

     2                   

Asia

                       

Australia/Oceania

     1         1           
                          

Total Consolidated Subsidiaries

     5         5         4   

Equity Companies

        

United States

                       

Europe

                       

Asia

                       
                          

Total Equity Companies

                       
                          

Total dry development wells drilled

     5         5         4   
                          

Total number of net wells drilled

     1,249         863         763   
                          

 

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

 

Syncrude Operations

 

Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2010, the company’s share of net production of synthetic crude oil was about 67,000 barrels per day. The Syncrude leases cover about 63 thousand acres in the Athabasca oil sands deposit.

 

Kearl Project

 

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

 

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

 

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5.    Present Activities

 

A. Wells Drilling

 

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

Wells Drilling

           

Consolidated Subsidiaries

           

United States

     1,088         491         185         146   

Canada/South America

     92         30         83         57   

Europe

     27         8         20         4   

Africa

     54         19         24         8   

Asia

     98         66         20         4   

Australia/Oceania

     1                 4         2   
                                   

Total Consolidated Subsidiaries

     1,360         614         336         221   

Equity Companies

           

United States

     1         1         10         5   

Europe

     34         10         16         5   

Asia

     7         1         5           
                                   

Total Equity Companies

     42         12         31         10   
                                   

Total gross and net wells drilling

     1,402         626         367         231   
                                   

 

B. Review of Principal Ongoing Activities

 

UNITED STATES

 

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

 

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

 

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

 

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

 

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CANADA / SOUTH AMERICA

 

Canada

 

Oil and Gas Operations

 

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

 

In Situ Bitumen Operations

 

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

 

Argentina

 

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

 

Venezuela

 

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

 

EUROPE

 

Germany

 

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

 

Netherlands

 

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

 

Norway

 

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

 

United Kingdom

 

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

 

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AFRICA

 

Angola

 

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

 

Chad

 

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

 

Equatorial Guinea

 

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

 

Nigeria

 

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

 

ASIA

 

Azerbaijan

 

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

 

Indonesia

 

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

 

Iraq

 

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

 

Kazakhstan

 

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

 

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Malaysia

 

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

 

Qatar

 

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

 

Republic of Yemen

 

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

 

Russia

 

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

 

Thailand

 

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

 

United Arab Emirates

 

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

 

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

 

AUSTRALIA/OCEANIA

 

Australia

 

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

 

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

 

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Papua New Guinea

 

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

 

WORLDWIDE EXPLORATION

 

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

 

6.     Delivery Commitments

 

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

 

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

 

A. Gross and Net Productive Wells

 

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

Gross and Net Productive Wells

                       

Consolidated Subsidiaries

                       

United States

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

Canada/South America

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

Europe

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

Africa

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

Asia

     845         411         207         173         751         352         197         162   

Australia/Oceania

     687         163         27         13         722         170         41         21   
                                                                       

Total Consolidated Subsidiaries

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

Equity Companies

                       

United States

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

Europe

     28         14         594         194         27         14         576         187   

Asia

     883         99         121         30         873         98         126         36   
                                                                       

Total Equity Companies

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

Total gross and net productive wells

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

 

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

 

B. Gross and Net Developed Acreage

 

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

Gross and Net Developed Acreage

           

Consolidated Subsidiaries

           

United States

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

Canada/South America(1)

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

Europe

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

Africa

     1,772         684         1,958         758   

Asia

     1,411         623         1,226         512   

Australia/Oceania

     1,955         719         1,956         719   
                                   

Total Consolidated Subsidiaries

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

Equity Companies

           

United States

     137         58         165         59   

Europe

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

Asia

     5,818         648         5,817         648   
                                   

Total Equity Companies

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

Total gross and net developed acreage

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

 

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

 

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C. Gross and Net Undeveloped Acreage

 

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

Gross and Net Undeveloped Acreage

           

Consolidated Subsidiaries

           

United States

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

Canada/South America(1)

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

Europe

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

Africa

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

Asia

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

Australia/Oceania

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

Total Consolidated Subsidiaries

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

Equity Companies

           

United States

     188         69         208         77   

Europe

                     53         8   

Asia

                     228         57   
                                   

Total Equity Companies

     188         69         489         142   
                                   

Total gross and net undeveloped acreage

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

 

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

 

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

 

D. Summary of Acreage Terms

 

UNITED STATES

 

Oil and gas leases have an exploration period ranging from one to ten years, and a production period that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances, a “fee interest” is acquired where both the surface and the underlying mineral interests are owned outright.

 

CANADA / SOUTH AMERICA

 

Canada

 

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

 

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

 

Argentina

 

The federal onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration period and up to two years for the third exploration period. A 50-percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been developed. Argentine provinces are entitled to modify the concession terms granted within their territories. The exploration permit granted by Neuquen Province to an ExxonMobil affiliate in 2010 fixed the initial exploration period at three years, the second at two years and the third at one year, and one of these periods can be extended for an additional year.

 

EUROPE

 

Germany

 

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

 

Netherlands

 

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

 

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

 

Norway

 

Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for an initial period of up to six years (with extension of the initial period of one year at a time up to ten years after 1985), and an extension period of up to 30 years, with relinquishment of at least one-half of the original area required at the end of the initial period. Licenses issued after July 1, 1997, have an

 

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initial period of up to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half of the original area required at the end of the initial period.

 

United Kingdom

 

Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the first four licensing rounds provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. At the end of any such 40-year term, licenses may continue in producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a case-by-case basis until they become producing areas; or licenses terminate in all other areas. The licensing regime was last updated in 2002, and the majority of licenses issued have an initial term of four years with a second term extension of four years and a final term of 18 years with a mandatory relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.

 

AFRICA

 

Angola

 

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

 

Chad

 

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

 

Equatorial Guinea

 

Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years while the production period for gas is 50 years. A new Hydrocarbons Law was enacted in November 2006. Under the new law, the exploration terms for new production sharing contracts are four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.

 

Nigeria

 

Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase plus one or two optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the ten-year exploration period, and OMLs have a 20-year production period that may be extended.

 

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Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-renewable, while in all other areas the licenses are for five years and also are non-renewable. Demonstrating a commercial discovery is the basis for conversion of an OPL to an OML.

 

OMLs granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40 years in offshore areas and have been renewed, effective December 1, 2008, for a further period of 20 years, with a further renewal option of 20 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. In 2000, a Memorandum of Understanding (MOU) was executed defining commercial terms applicable to existing joint venture oil production. The MOU may be terminated on one calendar year’s notice.

 

OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for onshore or offshore location and are renewable, upon 12 months’ written notice, for another period of 20 years. OMLs not held by NNPC are also subject to a mandatory 50-percent relinquishment after the first ten years of their duration.

 

ASIA

 

Azerbaijan

 

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

 

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

 

Indonesia

 

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

 

Iraq

 

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

 

Kazakhstan

 

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

 

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

 

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Malaysia

 

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

 

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

 

Qatar

 

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

 

Republic of Yemen

 

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

 

Russia

 

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

 

Thailand

 

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

 

United Arab Emirates

 

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

 

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AUSTRALIA/OCEANIA

 

Australia

 

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

 

Papua New Guinea

 

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

 

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Information with regard to the Downstream segment follows:

 

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

 

Refining Capacity At Year-End 2010 (1)

 

          ExxonMobil
Share KBD (2)
     ExxonMobil
Interest  %
 

United States

        

Torrance

  

California

     150         100   

Joliet

  

Illinois

     238         100   

Baton Rouge

  

Louisiana

     504         100   

Baytown

  

Texas

     561         100   

Beaumont

  

Texas

     345         100   

Other (2 refineries)

     155      
              

Total United States

     1,953      

Canada

        

Strathcona

  

Alberta

     189         69.6   

Dartmouth

  

Nova Scotia

     83         69.6   

Nanticoke

  

Ontario

     113         69.6   

Sarnia

  

Ontario

     121         69.6   
              

Total Canada

     506      

Europe

        

Antwerp

  

Belgium

     307         100   

Fos-sur-Mer

  

France

     119         82.9   

Port-Jerome-Gravenchon

  

France

     233         82.9   

Karlsruhe

  

Germany

     78         25   

Augusta

  

Italy

     198         100   

Trecate

  

Italy

     174         74.1   

Rotterdam

  

Netherlands

     191         100   

Slagen

  

Norway

     116         100   

Fawley

  

United Kingdom

     329         100   
              

Total Europe

     1,745      

Asia Pacific

        

Kawasaki

  

Japan

     296         50.1   

Sakai

  

Japan

     139         50.1   

Wakayama

  

Japan

     160         50.1   

Jurong/PAC

  

Singapore

     605         100   

Sriracha

  

Thailand

     174         66   

Other (5 refineries)

     337      
              

Total Asia Pacific

     1,711      

Other Non-U.S.

        

Yanbu

  

Saudi Arabia

     200         50   

Laffan

  

Qatar

     14         10   

Other (4 refineries)

     131      
              

Total Other Non-U.S.

     345      
              

Total Worldwide

     6,260      
              

 

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

 

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

 

Retail Sites Year-End 2010

 

United States

  

Owned/leased

     1,243   

Distributors/resellers

     8,520   
        

Total United States

     9,763   

Canada

  

Owned/leased

     500   

Distributors/resellers

     1,349   
        

Total Canada

     1,849   

Europe

  

Owned/leased

     3,965   

Distributors/resellers

     2,584   
        

Total Europe

     6,549   

Asia Pacific

  

Owned/leased

     1,963   

Distributors/resellers

     3,631   
        

Total Asia Pacific

     5,594   

Latin America

  

Owned/leased

     567   

Distributors/resellers

     1,329   
        

Total Latin America

     1,896   

Middle East/Africa

  

Owned/leased

     472   

Distributors/resellers

     155   
        

Total Middle East/Africa

     627   

Worldwide

  

Owned/leased

     8,710   

Distributors/resellers

     17,568   
        

Total worldwide

     26,278   
        

 

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Information with regard to the Chemical segment follows:

 

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

 

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

 

        Ethylene     Polyethylene     Polypropylene     Paraxylene     ExxonMobil
Interest %
 

North America

           

Baton Rouge

 

Louisiana

    1.0        1.3        0.4               100   

Baytown

 

Texas

    2.2               0.8        0.6        100   

Beaumont

 

Texas

    0.8        1.0               0.3        100   

Mont Belvieu

 

Texas

           1.0                      100   

Sarnia

 

Ontario

    0.3        0.5                      69.6   
                                   

Total North America

    4.3        3.8        1.2        0.9     

Europe

           

Antwerp

 

Belgium

    0.5        0.4                      35 (3) 

Fife

 

United Kingdom

    0.4                             50   

Meerhout

 

Belgium

           0.5                      100   

Notre-Dame-de-
Gravenchon

 

France

    0.4        0.4        0.3               100   

Rotterdam

 

Netherlands

                         0.7        100   
                                   

Total Europe

    1.3        1.3        0.3        0.7     

Middle East

           

Al Jubail

 

Saudi Arabia

    0.6        0.6                      50   

Yanbu

 

Saudi Arabia

    1.0        0.7        0.2               50   
                                   

Total Middle East

    1.6        1.3        0.2            

Asia Pacific

           

Fujian

 

China

    0.2        0.2        0.1        0.2        25   

Kawasaki

 

Japan

    0.5        0.1                      50   

Singapore

 

Singapore

    0.9        0.6        0.4        0.9        100   

Sriracha

 

Thailand

                         0.5        66   
                                   

Total Asia Pacific

    1.6        0.9        0.5        1.6     

All Other

                         0.6     
                                   

Total Worldwide

    8.8        7.3        2.2        3.8     
                                   

 

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

 

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Item 3.    Legal Proceedings.

 

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

 

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

 

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

 

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

 

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

 

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

 

 

 

 

 

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

(ages as of March 1, 2011).

 

Rex W. Tillerson

       Chairman of the Board     

Held current title since:

       January 1, 2006    Age: 58

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

 

Mark W. Albers

       Senior Vice President     

Held current title since:

       April 1, 2007    Age: 54

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

 

Michael J. Dolan

       Senior Vice President     

Held current title since:

       April 1, 2008    Age: 57

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

 

Donald D. Humphreys

       Senior Vice President and Treasurer     

Held current title since:

      

January 25, 2006 (Senior Vice President)

July 1, 2004 (Treasurer)

   Age: 63

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

 

Andrew P. Swiger

       Senior Vice President     

Held current title since:

       April 1, 2009    Age: 54

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

 

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S. Jack Balagia

       Vice President and General Counsel     

Held current title since:

       March 1, 2010    Age: 59

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

 

William M. Colton

       Vice President - Strategic Planning     

Held current title since:

       February 1, 2009    Age: 57

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

 

Harold R. Cramer

       Vice President     

Held current title since:

       November 30, 1999    Age: 60

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

 

Neil W. Duffin

       President, ExxonMobil Development Company     

Held current title since:

       April 13, 2007    Age: 54

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

 

Robert S. Franklin

       Vice President     

Held current title since:

       May 1, 2009    Age: 53

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

 

Sherman J. Glass, Jr.

       Vice President     

Held current title since:

       April 1, 2008    Age: 63

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

 

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Stephen M. Greenlee

       Vice President     

Held current title since:

       September 1, 2010    Age: 53

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

 

Alan J. Kelly

       Vice President     

Held current title since:

       December 1, 2007    Age: 53

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

 

Richard M. Kruger

       Vice President     

Held current title since:

       April 1, 2008    Age: 51

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

 

Patrick T. Mulva

       Vice President and Controller     

Held current title since:

      

February 1, 2002 (Vice President)

July 1, 2004 (Controller)

   Age: 59

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

 

Stephen D. Pryor

       Vice President     

Held current title since:

       December 1, 2004    Age: 61

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

 

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David S. Rosenthal

       Vice President - Investor Relations and Secretary

Held current title since:

       October 1, 2008    Age: 54

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

 

James M. Spellings, Jr.

       Vice President and General Tax Counsel

Held current title since:

       March 1, 2010    Age: 49

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

 

Thomas R. Walters

       Vice President     

Held current title since:

       April 1, 2009    Age: 56

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

 

Jack P. Williams, Jr.

       President, XTO Energy Inc.     

Held current title since:

       June 25, 2010    Age: 47

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

 

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

 

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PART II

 

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

 

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

 

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

Period

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

October, 2010

     27,460,538         65.07         27,460,538      

November, 2010

     26,123,594         69.57         26,123,594      

December, 2010

     29,589,368         72.82         29,589,368      
                       

Total

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

 

Note 1—On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. Repurchases were temporarily suspended due to regulatory requirements in connection with the XTO transaction. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated January 31, 2011, the Corporation stated that first quarter 2011 share purchases are continuing at a pace consistent with fourth quarter 2010 share reduction spending of $5 billion. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

 

Item 6.    Selected Financial Data.

 

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

(2) Sales-based taxes included.

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

 

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

 

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

 

Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Financial Section of this report.

 

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

 

Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties”, excluding the part entitled “Inflation and Other Uncertainties,” in the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.

 

Item 8.    Financial Statements and Supplementary Data.

 

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

 

   

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

   

“Quarterly Information” (unaudited);

   

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

   

“Frequently Used Terms” (unaudited).

 

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

 

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

 

None.

 

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Item  9A.    Controls and Procedures.

 

Management’s Evaluation of Disclosure Controls and Procedures

 

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2010. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

 

Management’s Report on Internal Control Over Financial Reporting

 

Management, including the Corporation’s chief executive officer, principal financial officer and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2010.

 

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

 

Changes in Internal Control Over Financial Reporting

 

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

 

Item  9B.    Other Information.

 

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

 

PART III

 

Item 10.    Directors, Executive Officers and Corporate Governance.

 

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

 

   

The section entitled “Election of Directors”;

   

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

   

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

   

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

 

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Item 11.    Executive Compensation.

 

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

 

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

 

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

 

Equity Compensation Plan Information

      (a)   (b)    (c)

Plan Category

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

Equity compensation plans approved by security holders

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

Equity compensation plans not approved by security holders

       0         0          0  

Total

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

 

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

 

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

 

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

 

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

 

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

 

 

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

 

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

 

Item 14.    Principal Accounting Fees and Services.

 

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

 

PART IV

 

Item 15.    Exhibits, Financial Statement Schedules.

 

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

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

 

  (a) (3) Exhibits:

See Index to Exhibits of this report.

 

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FINANCIAL SECTION

TABLE OF CONTENTS

 

Business Profile

     42   

Financial Summary

     43   

Frequently Used Terms

     44   

Quarterly Information

     46   

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

  

Functional Earnings

     47   

Forward-Looking Statements

     48   

Overview

     48   

Business Environment and Risk Assessment

     48   

Review of 2010 and 2009 Results

     51   

Liquidity and Capital Resources

     52   

Capital and Exploration Expenditures

     56   

Taxes

     56   

Environmental Matters

     56   

Market Risks, Inflation and Other Uncertainties

     57   

Critical Accounting Policies

     58   

Management’s Report on Internal Control Over Financial Reporting

     62   

Report of Independent Registered Public Accounting Firm

     62   

Consolidated Financial Statements

  

Statement of Income

     64   

Balance Sheet

     65   

Statement of Cash Flows

     66   

Statement of Changes in Equity

     67   

Statement of Comprehensive Income

     68   

Notes to Consolidated Financial Statements

  

1. Summary of Accounting Policies

     69   

2. Accounting Changes

     71   

3. Miscellaneous Financial Information

     72   

4. Cash Flow Information

     72   

5. Additional Working Capital Information

     72   

6. Equity Company Information

     73   

7. Investments, Advances and Long-Term Receivables

     74   

8. Property, Plant and Equipment and Asset Retirement Obligations

     74   

9. Accounting for Suspended Exploratory Well Costs

     75   

10. Leased Facilities

     77   

11. Earnings Per Share

     77   

12. Financial Instruments and Derivatives

     78   

13. Long-Term Debt

     79   

14. Incentive Program

     84   

15. Litigation and Other Contingencies

     87   

16. Pension and Other Postretirement Benefits

     89   

17. Disclosures about Segments and Related Information

     97   

18. Income, Sales-Based and Other Taxes

     99   

19. Acquisition of XTO Energy Inc.

     101   

Supplemental Information on Oil and Gas Exploration and Production Activities

     103   

Operating Summary

     118   

 

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BUSINESS PROFILE

 

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

Financial

   2010     2009     2010     2009      2010      2009     2010      2009  
    

(millions of dollars)

     (percent)     (millions of dollars)  

Upstream

                   

United States

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

Non-U.S.

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

Total

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

Downstream

                   

United States

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

Non-U.S.

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

Total

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

Chemical

                   

United States

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

Non-U.S.

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

Total

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

Corporate and financing

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

Total

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

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

 

Operating

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

Net liquids production

        

Refinery throughput

     

United States

     408         384      

United States

     1,753         1,767   

Non-U.S.

     2,014         2,003      

Non-U.S.

     3,500         3,583   
                                      

Total

     2,422         2,387      

Total

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

Natural gas production available for sale

        

Petroleum product sales

     

United States

     2,596         1,275      

United States

     2,511         2,523   

Non-U.S.

     9,552         7,998      

Non-U.S.

     3,903         3,905   
                                      

Total

     12,148         9,273      

Total

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

Oil-equivalent production (1)

     4,447         3,932      

Chemical prime product sales

     
        

United States

     9,815         9,649   
        

Non-U.S.

     16,076         15,176   
                          
        

Total

     25,891         24,825   
                          

 

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

 

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FINANCIAL SUMMARY

 

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

Sales and other operating revenue (2)

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

Earnings

          

Upstream

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

Downstream

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

Chemical

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

Corporate and financing

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

Net income attributable to ExxonMobil

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

Earnings per common share

   $ 6.24      $ 3.99      $ 8.70      $ 7.31      $ 6.64   

Earnings per common share – assuming dilution

   $ 6.22      $ 3.98      $ 8.66      $ 7.26      $ 6.60   

Cash dividends per common share

   $ 1.74      $ 1.66      $ 1.55      $ 1.37      $ 1.28   

Earnings to average ExxonMobil share of equity (percent)

     23.7        17.3        38.5        34.5        35.1   

Working capital

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

Ratio of current assets to current liabilities (times)

     0.94        1.06        1.47        1.47        1.55   

Additions to property, plant and equipment

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

Property, plant and equipment, less allowances

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

Total assets

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

Exploration expenses, including dry holes

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

Research and development costs

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

Long-term debt

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

Total debt

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

Fixed-charge coverage ratio (times)

     42.2        25.8        54.6        51.6        47.8   

Debt to capital (percent)

     9.0        7.7        7.4        7.1        6.6   

Net debt to capital (percent) (3)

     4.5        (1.0     (23.0     (24.0     (20.4

ExxonMobil share of equity at year end

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

ExxonMobil share of equity per common share

   $ 29.48      $ 23.39      $ 22.70      $ 22.62      $ 19.87   

Weighted average number of common shares outstanding (millions)

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

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

     83.6        80.7        79.9        80.8        82.1   

CORS employees not included above (thousands) (5)

     20.1        22.0        24.8        26.3        24.3   

 

(1) See Note 19: Acquisition of XTO Energy Inc.
(2) Sales and other operating revenue includes sales-based taxes of $28,547 million for 2010, $25,936 million for 2009, $34,508 million for 2008, $31,728 million for 2007 and $30,381 million for 2006.
(3) Debt net of cash, excluding restricted cash.
(4) Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs.
(5) CORS employees are employees of company-operated retail sites.

 

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FREQUENTLY USED TERMS

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

CASH FLOW FROM OPERATIONS AND ASSET SALES

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

 

Cash flow from operations and asset sales

   2010      2009      2008  
    

(millions of dollars)

 

Net cash provided by operating activities

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

Sales of subsidiaries, investments and property, plant and equipment

     3,261         1,545         5,985   
                          

Cash flow from operations and asset sales

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

CAPITAL EMPLOYED

Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.

 

Capital employed

   2010     2009     2008  
     (millions of dollars)  

Business uses: asset and liability perspective

      

Total assets

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

Less liabilities and noncontrolling interests share of assets and liabilities

      

Total current liabilities excluding notes and loans payable

     (59,846     (49,585     (46,700

Total long-term liabilities excluding long-term debt

     (74,971     (58,741     (54,404

Noncontrolling interests share of assets and liabilities

     (6,532     (5,642     (6,044

Add ExxonMobil share of debt-financed equity company net assets

     4,875        5,043        4,798   
                        

Total capital employed

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

Total corporate sources: debt and equity perspective

      

Notes and loans payable

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

Long-term debt

     12,227        7,129        7,025   

ExxonMobil share of equity

     146,839        110,569        112,965   

Less noncontrolling interests share of total debt

     (692     (819     (1,486

Add ExxonMobil share of equity company debt

     4,875        5,043        4,798   
                        

Total capital employed

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

 

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RETURN ON AVERAGE CAPITAL EMPLOYED

Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow-based, are used to make investment decisions.

 

Return on average capital employed

   2010     2009     2008  
     (millions of dollars)  

Net income attributable to ExxonMobil

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

Financing costs (after tax)

      

Gross third-party debt

     (803     (303     (343

ExxonMobil share of equity companies

     (333     (285     (325

All other financing costs – net

     35        (483     1,485   
                        

Total financing costs

     (1,101     (1,071     817   
                        

Earnings excluding financing costs

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

Average capital employed

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

Return on average capital employed – corporate total

     21.7%        16.3%        34.2%   

 

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QUARTERLY INFORMATION

 

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

(thousands of barrels daily)

 

Volumes

                             

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

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

Refinery throughput

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

Petroleum product sales

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

Natural gas production available for sale

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

Oil-equivalent production (1)

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

Chemical prime product sales

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

Summarized financial data

                             

Sales and other operating revenue (2)

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

Gross profit (3)

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

Net income attributable to ExxonMobil

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

Per share data

                             

Earnings per common share (4)

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

Earnings per common share – assuming dilution (4)

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

Dividends per common share

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

Common stock prices

                             

High

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

Low

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

 

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

The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.

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

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

 

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

FUNCTIONAL EARNINGS

 

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

Earnings (U.S. GAAP)

      

Upstream

      

United States

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

Non-U.S.

     19,825        14,214        29,159   

Downstream

      

United States

     770        (153     1,649   

Non-U.S.

     2,797        1,934        6,502   

Chemical

      

United States

     2,422        769        724   

Non-U.S.

     2,491        1,540        2,233   

Corporate and financing

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

Net income attributable to ExxonMobil

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

Earnings per common share

   $ 6.24      $ 3.99      $ 8.70   

Earnings per common share – assuming dilution

   $ 6.22      $ 3.98      $ 8.66   

Special items included in earnings

      

Non-U.S. Upstream

      

Gain on German natural gas transportation business sale

   $ —        $ —        $ 1,620   

Corporate and financing

      

Valdez litigation

   $ —        $ (140   $ (460

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

 

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

 

FORWARD-LOOKING STATEMENTS

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

OVERVIEW

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

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

BUSINESS ENVIRONMENT AND RISK ASSESSMENT

Long-Term Business Outlook

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

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

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

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

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

 

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

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

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

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

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

Upstream

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

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

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

 

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

 

Downstream

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

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

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

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

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

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

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

Chemical

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

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

 

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REVIEW OF 2010 AND 2009 RESULTS

 

     2010      2009      2008  
     (millions of dollars)  

Earnings (U.S. GAAP)

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

2010

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

2009

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

Upstream

 

     2010      2009      2008  
    

(millions of dollars)

 

Upstream

        

United States

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

Non-U.S.

     19,825         14,214         29,159   
                          

Total

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

2010

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

2009

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

Downstream

 

     2010      2009     2008  
     (millions of dollars)  

Downstream

       

United States

   $ 770       $ (153   $ 1,649   

Non-U.S.

     2,797         1,934        6,502   
                         

Total

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

2010

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

2009

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

 

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Chemical

 

     2010      2009      2008  
    

(millions of dollars)

 

Chemical

        

United States

   $ 2,422       $ 769       $ 724   

Non-U.S.

     2,491         1,540         2,233   
                          

Total

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

2010

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

2009

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

Corporate and Financing

 

     2010     2009     2008  
    

(millions of dollars)

 

Corporate and financing

   $ (2,117   $ (1,917   $ (1,290

2010

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

2009

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

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

 

     2010     2009     2008  
     (millions of dollars)  

Net cash provided by/(used in)

      

Operating activities

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

Investing activities

     (24,204     (22,419     (15,499

Financing activities

     (26,924     (27,283     (44,027

Effect of exchange rate changes

     (153     520        (2,743
                        

Increase/(decrease) in cash and cash equivalents

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

(Dec. 31)

 

Cash and cash equivalents

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

Cash and cash equivalents – restricted

     628        —          —     
                        

Total cash and cash equivalents

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

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

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

Although the Corporation has access to significant capacity of long-term and short-term liquidity, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully controlled to ensure it is secure and readily available to meet the Corporation’s cash requirements and to optimize returns on the cash balances.

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

 

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

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

Cash Flow from Operating Activities

2010

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

2009

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

Cash Flow from Investing Activities

2010

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

2009

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

Cash Flow from Financing Activities

2010

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

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

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

2009

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

 

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

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

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

Commitments

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

 

     Payments Due by Period  

Commitments

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

Long-term debt (1)

   13    $ —         $ 5,464       $ 6,763       $ 12,227   

- Due in one year (2)

   5      345         —           —           345   

Asset retirement obligations (3)

   8      775         2,196         6,643         9,614   

Pension and other postretirement obligations (4)

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

Operating leases (5)

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

Unconditional purchase obligations (6)

   15      287         748         487         1,522   

Take-or-pay obligations (7)

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

Firm capital commitments (8)

        14,851         12,329         948         28,128   

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

Notes:

 

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

 

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Guarantees

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

 

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

Guarantees

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

Financial Strength

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

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

 

     2010      2009     2008  

Fixed-charge coverage ratio (times)

     42.2         25.8        54.6   

Debt to capital (percent)

     9.0         7.7        7.4   

Net debt to capital (percent)

     4.5         (1.0     (23.0

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

Litigation and Other Contingencies

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

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

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

 

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

 

CAPITAL AND EXPLORATION EXPENDITURES

 

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

(millions of dollars)

 

Upstream (1)

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

Downstream

     982         1,523         1,511         1,685   

Chemical

     279         1,936         319         2,829   

Other

     187         —           44         —     
                                   

Total

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

 

 

(1) Exploration expenses included.

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

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

TAXES

 

     2010      2009      2008  
     (millions of dollars)  

Income taxes

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

Effective income tax rate

     45%         47%         46%   

Sales-based taxes

     28,547         25,936         34,508   

All other taxes and duties

     39,127         37,571         45,223   
                          

Total

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

2010

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

2009

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

ENVIRONMENTAL MATTERS

Environmental Expenditures

 

     2010      2009  
     (millions of dollars)  

Capital expenditures

   $ 1,947       $ 2,481   

Other expenditures

     2,593         2,610   
                 

Total

   $ 4,540       $ 5,091   
                 

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

Environmental Liabilities

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

 

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Asset Retirement Obligations

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

MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES

 

Worldwide Average Realizations(1)

   2010      2009      2008  

Crude oil and NGL ($/barrel)

   $ 74.04       $ 57.86       $ 90.96   

Natural gas ($/kcf)

     4.31         4.00         7.54   

 

(1) Consolidated subsidiaries.

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

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

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

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

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

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

Risk Management

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

 

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

 

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

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

Inflation and Other Uncertainties

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

CRITICAL ACCOUNTING POLICIES

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

Oil and Gas Reserves

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

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

Key features of the reserves estimation process include:

 

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

 

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

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

 

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

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

The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method. The Corporation uses this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of the Corporation’s exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.

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

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

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

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

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

 

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

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

Suspended Exploratory Well Costs

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

Consolidations

The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in “Investments, advances and long-term receivables”; the Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.” The accounting for these non-consolidated companies is referred to as the equity method of accounting.

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

Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 6.

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

Pension Benefits

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

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

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

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

 

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

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

Litigation Contingencies

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

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

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

Tax Contingencies

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

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

Foreign Currency Translation

The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment. Downstream and Chemical operations use the local currency, except in countries with a history of high inflation (primarily in Latin America) and Singapore, which uses the U.S. dollar because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas production is predominantly sold in the export market in U.S. dollars. Upstream operations using the U.S. dollar as their functional currency are primarily in Asia and Africa.

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

 

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including the Corporation’s chief executive officer, principal financial officer, and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2010.

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

 

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

REPORT OF INDEPENDENT REGISTRATION PUBLIC ACCOUNTING FIRM

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To the Shareholders of Exxon Mobil Corporation:

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

 

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

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

Dallas, Texas

February 25, 2011

 

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CONSOLIDATED STATEMENT OF INCOME

 

     Note
Reference
Number
     2010      2009      2008  
            (millions of dollars)  

Revenues and other income

           

Sales and other operating revenue (1)

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

Income from equity affiliates

     6         10,677         7,143         11,081   

Other income (2)

        2,419         1,943         6,699   
                             

Total revenues and other income

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

Costs and other deductions

           

Crude oil and product purchases

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

Production and manufacturing expenses

        35,792         33,027         37,905   

Selling, general and administrative expenses

        14,683         14,735         15,873   

Depreciation and depletion

        14,760         11,917         12,379   

Exploration expenses, including dry holes

        2,144         2,021         1,451   

Interest expense

        259         548         673   

Sales-based taxes (1)

     18         28,547         25,936         34,508   

Other taxes and duties

     18         36,118         34,819         41,719   
                             

Total costs and other deductions

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

Income before income taxes

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

Income taxes

     18         21,561         15,119         36,530   
                             

Net income including noncontrolling interests

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

Net income attributable to noncontrolling interests

        938         378         1,647   
                             

Net income attributable to ExxonMobil

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

Earnings per common share (dollars)

     11       $ 6.24       $ 3.99       $ 8.70   

Earnings per common share – assuming dilution (dollars)

     11       $ 6.22       $ 3.98       $ 8.66   

 

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

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

 

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CONSOLIDATED BALANCE SHEET

 

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

Assets

       

Current assets

       

Cash and cash equivalents

      $ 7,825      $ 10,693   

Cash and cash equivalents – restricted

     3         628        —     

Marketable securities

        2        169   

Notes and accounts receivable, less estimated doubtful amounts

     5         32,284        27,645   

Inventories

       

Crude oil, products and merchandise

     3         9,852        8,718   

Materials and supplies

        3,124        2,835   

Other current assets

        5,269        5,175   
                   

Total current assets

      $ 58,984      $ 55,235   

Investments, advances and long-term receivables

     7         35,338        31,665   

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

     8         199,548        139,116   

Other assets, including intangibles, net

        8,640        7,307   
                   

Total assets

      $ 302,510      $ 233,323   
                   

Liabilities

       

Current liabilities

       

Notes and loans payable

     5       $ 2,787      $ 2,476   

Accounts payable and accrued liabilities

     5         50,034        41,275   

Income taxes payable

        9,812        8,310   
                   

Total current liabilities

      $ 62,633      $ 52,061   

Long-term debt

     13         12,227        7,129   

Postretirement benefits reserves

     16         19,367        17,942   

Deferred income tax liabilities

     18         35,150        23,148   

Other long-term obligations

        20,454        17,651   
                   

Total liabilities

      $ 149,831      $ 117,931   
                   

Commitments and contingencies

     15        

Equity

       

Common stock without par value

      $ 9,371      $ 5,503   

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

       

Earnings reinvested

        298,899        276,937   

Accumulated other comprehensive income

       

Cumulative foreign exchange translation adjustment

        5,011        4,402   

Postretirement benefits reserves adjustment

        (9,889     (9,863

Unrealized gain/(loss) on cash flow hedges

        55        —     

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

        (156,608     (166,410
                   

ExxonMobil share of equity

      $ 146,839      $ 110,569   

Noncontrolling interests

        5,840        4,823   
                   

Total equity

        152,679        115,392   
                   

Total liabilities and equity

      $ 302,510      $ 233,323   
                   

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

 

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CONSOLIDATED STATEMENT OF CASH FLOWS

 

     Note
Reference
Number
   2010     2009     2008  
          (millions of dollars)  

Cash flows from operating activities

         

Net income including noncontrolling interests

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

Adjustments for noncash transactions

         

Depreciation and depletion

        14,760        11,917        12,379   

Deferred income tax charges/(credits)

        (1,135     —          1,399   

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

        1,700        (1,722     57   

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

        160        731        (63

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

        (596     (483     921   

Changes in operational working capital, excluding cash and debt

         

Reduction/(increase) – Notes and accounts receivable

        (5,863     (3,170     8,641   

                                   – Inventories

        (1,148     459        (1,285

                                   – Other current assets

        913        132        (509

Increase/(reduction) – Accounts and other payables

        9,943        1,420        (5,415

Net (gain) on asset sales

   4      (1,401     (488     (3,757

All other items – net

        (318     (16     490   
                           

Net cash provided by operating activities

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

Cash flows from investing activities

         

Additions to property, plant and equipment

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

Sales of subsidiaries, investments and property, plant and equipment

   4      3,261        1,545        5,985   

Decrease/(increase) in restricted cash and cash equivalents

   3      (628     —          —     

Additional investments and advances

        (1,239     (2,752     (2,495

Collection of advances

        1,133        724        574   

Additions to marketable securities

        (15     (16     (2,113

Sales of marketable securities

        155        571        1,868   
                           

Net cash used in investing activities

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

Cash flows from financing activities

         

Additions to long-term debt

      $ 1,143      $ 225      $ 79   

Reductions in long-term debt

        (6,224     (68     (192

Additions to short-term debt

        598        1,336        1,067   

Reductions in short-term debt

        (2,436     (1,575     (1,624

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

        709        (71     143   

Cash dividends to ExxonMobil shareholders

        (8,498     (8,023     (8,058

Cash dividends to noncontrolling interests

        (281     (280     (375

Changes in noncontrolling interests

        (7     (113     (419

Tax benefits related to stock-based awards

        122        237        333   

Common stock acquired

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

Common stock sold

        1,043        752        753   
                           

Net cash used in financing activities

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

Effects of exchange rate changes on cash

      $ (153   $ 520      $ (2,743
                           

Increase/(decrease) in cash and cash equivalents

      $ (2,868   $ (20,744   $ (2,544

Cash and cash equivalents at beginning of year

        10,693        31,437        33,981   
                           

Cash and cash equivalents at end of year

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

Non-Cash Transactions

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

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

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

 

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

 

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

(millions of dollars)

 

Balance as of December 31, 2007

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

Amortization of stock-based awards

     618              618          618   

Tax benefits related to stock-based awards

     315              315          315   

Other

     (552           (552       (552

Net income for the year

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

Dividends – common shares

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

Foreign exchange translation adjustment

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

Adjustment for foreign exchange translation loss included in net income

         138          138        17        155   

Postretirement benefits reserves adjustment (note 16)

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

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

         759          759          759   

Acquisitions, at cost

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

Dispositions

           1,314        1,314        220        1,534   
                                                        

Balance as of December 31, 2008

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

Amortization of stock-based awards

     685              685          685   

Tax benefits related to stock-based awards

     140              140          140   

Other

     (636           (636       (636

Net income for the year

       19,280            19,280        378        19,658   

Dividends – common shares

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

Foreign exchange translation adjustment

         3,256          3,256        373        3,629   

Postretirement benefits reserves adjustment (note 16)

         (196       (196     (144     (340

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

         1,410          1,410        51        1,461   

Acquisitions, at cost

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

Dispositions

           1,391        1,391        14        1,405   
                                                        

Balance as of December 31, 2009

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

Amortization of stock-based awards

     751              751          751   

Tax benefits related to stock-based awards

     280              280          280   

Other

     (683           (683     10        (673

Net income for the year

       30,460            30,460        938        31,398   

Dividends – common shares

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

Foreign exchange translation adjustment

         584          584        450        1,034   

Adjustment for foreign exchange translation loss included in net income

         25          25          25   

Postretirement benefits reserves adjustment (note 16)

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

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

         988          988        52        1,040   

Change in fair value of cash flow hedges

         184          184          184   

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

         (129       (129       (129

Acquisitions at cost

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

Issued for XTO merger

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

Other dispositions

           1,756        1,756          1,756   
                                                        

Balance as of December 31, 2010

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

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

 

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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (continued)

 

Common Stock Share Activity

   Issued      Held in
Treasury
    Outstanding  
     (millions of shares)  

Balance as of December 31, 2007

     8,019         (2,637     5,382   

Acquisitions

        (434     (434

Dispositions

        28        28   
                         

Balance as of December 31, 2008

     8,019         (3,043     4,976   

Acquisitions

        (277     (277

Dispositions

        28        28   
                         

Balance as of December 31, 2009

     8,019         (3,292     4,727   

Acquisitions

        (199     (199

Issued for XTO merger

        416        416   

Other dispositions

        35        35   
                         

Balance as of December 31, 2010

     8,019         (3,040     4,979   
                         

 

 

 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

 

     2010     2009     2008  
     (millions of dollars)  

Net income including noncontrolling interests

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

Other comprehensive income (net of income taxes)

      

Foreign exchange translation adjustment

     1,034        3,629        (7,298

Adjustment for foreign exchange translation loss included in net income

     25        —          155   

Postretirement benefits reserves adjustment (excluding amortization)

     (1,161     (340     (6,077

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

     1,040        1,461        759   

Change in fair value of cash flow hedges

     184        —          —     

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

     (129     —          —     
                        

Comprehensive income including noncontrolling interests

     32,391        24,408        34,406   

Comprehensive income attributable to noncontrolling interests

     1,293        658        1,106   
                        

Comprehensive income attributable to ExxonMobil

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

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2010 presentation basis.

1. Summary of Accounting Policies

Principles of Consolidation. The Consolidated Financial Statements include the accounts of those subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the Corporation and for which other shareholders do not possess the right to participate in significant management decisions. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities.

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

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

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

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

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

Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions. For derivatives designated as cash flow hedges, the Corporation’s activity is intended to manage the price risk posed by physical transactions.

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

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

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

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

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

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

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

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

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

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

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

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

 

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

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

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

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

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

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

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

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

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

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

2. Accounting Changes

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

3. Miscellaneous Financial Information

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

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

In 2010, 2009 and 2008, net income included gains of $317 million, $207 million and $341 million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $21.3 billion and $17.1 billion at December 31, 2010, and 2009, respectively.

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

 

     2010      2009  
     (billions of dollars)  

Petroleum products

   $ 3.5       $ 3.2   

Crude oil

     3.8         3.2   

Chemical products

     2.1         2.0   

Gas/other

     0.5         0.3   
                 

Total

   $ 9.9       $ 8.7   
                 

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

4. Cash Flow Information

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

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

 

     2010      2009      2008  
     (millions of dollars)  

Cash payments for interest

   $ 703       $ 820       $ 650   

Cash payments for income taxes

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

5. Additional Working Capital Information

 

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

Notes and accounts receivable

     

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

   $ 25,439       $ 22,186   

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

     6,845         5,459   
                 

Total

   $ 32,284       $ 27,645   
                 

Notes and loans payable

     

Bank loans

   $ 532       $ 1,043   

Commercial paper

     1,346         201   

Long-term debt due within one year

     345         348   

Other

     564         884   
                 

Total

   $ 2,787       $ 2,476   
                 

Accounts payable and accrued liabilities

     

Trade payables

   $ 30,780       $ 24,236   

Payables to equity companies

     5,450         4,979   

Accrued taxes other than income taxes

     6,778         5,921   

Other

     7,026         6,139   
                 

Total

   $ 50,034       $ 41,275   
                 

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

 

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6. Equity Company Information

The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see note 1). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several power generation, refining, petrochemical manufacturing and chemical ventures. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 18 percent, 19 percent and 21 percent in the years 2010, 2009 and 2008, respectively.

 

     2010      2009      2008  

Equity Company Financial Summary

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

Total revenues

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

Income before income taxes

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

Income taxes

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

Income from equity affiliates

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

Current assets

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

Long-term assets

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

Total assets

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

Current liabilities

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

Long-term liabilities

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

Net assets

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

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

 

     Percentage
Ownership
Interest
 

Upstream

  

Aera Energy LLC

     48   

BEB Erdgas und Erdoel GmbH

     50   

Cameroon Oil Transportation Company S.A.

     41   

Castle Peak Power Company Limited

     60   

Golden Pass LNG Terminal LLC

     18   

Nederlandse Aardolie Maatschappij B.V.

     50   

Qatar Liquefied Gas Company Limited

     10   

Qatar Liquefied Gas Company Limited 2

     24   

Ras Laffan Liquefied Natural Gas Company Limited

     25   

Ras Laffan Liquefied Natural Gas Company Limited II

     31   

Ras Laffan Liquefied Natural Gas Company Limited (3)

     30   

South Hook LNG Terminal Company Limited

     24   

Tengizchevroil, LLP

     25   

Terminale GNL Adriatico S.r.l.

     69   

Downstream

  

Chalmette Refining, LLC

     50   

Fujian Refining & Petrochemical Co. Ltd.

     25   

Saudi Aramco Mobil Refinery Company Ltd.

     50   

Chemical

  

Al-Jubail Petrochemical Company

     50   

Infineum Holdings B.V.

     50   

Saudi Yanbu Petrochemical Co.

     50   

Toray Tonen Specialty Separator Godo Kaisha

     50   

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

7. Investments, Advances and Long-Term Receivables

 

     Dec 31
2010
     Dec 31
2009
 
     (millions of dollars)  

Companies carried at equity in underlying assets

     

Investments

   $ 17,429       $ 15,742   

Advances

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

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

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

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

     7,066         5,677   
                 

Total

   $ 35,338       $ 31,665   
                 

8. Property, Plant and Equipment and Asset Retirement Obligations

 

     Dec. 31, 2010      Dec. 31, 2009  

Property, Plant and Equipment

   Cost      Net      Cost      Net  
            (millions of dollars)         

Upstream

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

Downstream

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

Chemical

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

Other

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

Total

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

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

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

Asset Retirement Obligations

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

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

 

     2010     2009  
     (millions of dollars)  

Beginning balance

   $ 8,473      $ 5,352   

Accretion expense and other provisions

     563        372   

Reduction due to property sales

     (183     (18

Payments made

     (638     (448

Liabilities incurred

     1,094        156   

Foreign currency translation

     (45     535   

Revisions

     350        2,524   
                

Ending balance

   $ 9,614      $ 8,473   
                

 

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9. Accounting for Suspended Exploratory Well Costs

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

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

Change in capitalized suspended exploratory well costs:

 

     2010     2009     2008  
     (millions of dollars)  

Balance beginning at January 1

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

Additions pending the determination of proved reserves

     1,103        624        448   

Charged to expense

     (104     (51     —     

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

     (136     (200     (101

Other

     25        47        (53
                        

Ending balance

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

Ending balance attributed to equity companies included above

   $ —        $ 9      $ 10   

Period end capitalized suspended exploratory well costs:

 

     2010      2009      2008  
    

(millions of dollars)

 

Capitalized for a period of one year or less

   $ 1,103       $ 624       $ 448   

Capitalized for a period of between one and five years

     1,294         924         636   

Capitalized for a period of between five and ten years

     278         220         225   

Capitalized for a period of greater than ten years

     218         237         276   
                          

Capitalized for a period greater than one year – subtotal

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

Total

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

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

 

     2010      2009      2008  

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

     9         18         12   

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

     59         57         50   
                          

Total

     68         75         62   
                          

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

Country/Project

   Dec. 31,
2010
     Years Wells
Drilled
    

Comment

     (millions of dollars)              

Angola

        

- Perpetua-Zina-Acacia

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

Australia

        

- East Pilchard

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

Indonesia

        

- Natuna

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

Kazakhstan

        

- Kairan

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

Nigeria

        

- Bolia

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

- Bonga North

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

- Bosi

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

- Other (5 projects)

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

Norway

        

- Gamma

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

- H-North

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

- Lavrans

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

- Noatun

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

- Nyk High

     20         2008       Evaluating field development alternatives.

- Other (8 projects)

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

Papua New Guinea

        

- Juha

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

United Kingdom

        

- Fram

     55         2009       Progressing development and commercialization plans.

- Other (3 projects)

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

United States

        

- Julia Unit

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

- Tip Top

     31         2009       Evaluating development concept and requisite facility upgrades.

Other

        

- Various (2 projects)

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

Total 2010 (34 projects)

   $ 692         

 

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10. Leased Facilities

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

 

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

2011

   $ 2,095       $ 8   

2012

     1,570         8   

2013

     1,061         7   

2014

     731         6   

2015

     581         6   

2016 and beyond

     1,738         27   
                 

Total

   $ 7,776       $ 62   
                 

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

 

     2010      2009      2008  
     (millions of dollars)  

Rental cost

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

Less sublease rental income

     90         98         123   
                          

Net rental cost

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

11. Earnings Per Share

 

     2010      2009      2008  

Earnings per common share

        

Net income attributable to ExxonMobil (millions of dollars)

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

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

     4,885         4,832         5,194   

Earnings per common share (dollars)

   $ 6.24       $ 3.99       $ 8.70   

Earnings per common share – assuming dilution

        

Net income attributable to ExxonMobil (millions of dollars)

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

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

     4,885         4,832         5,194   

Effect of employee stock-based awards

     12         16         27   
                          

Weighted average number of common shares outstanding – assuming dilution

     4,897         4,848         5,221   
                          

Earnings per common share – assuming dilution (dollars)

   $ 6.22       $ 3.98       $ 8.66   

Dividends paid per common share (dollars)

   $ 1.74       $ 1.66       $ 1.55   

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

12. Financial Instruments and Derivatives

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

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

When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions. For derivatives designated as cash flow hedges, the Corporation’s activity is intended to manage the price risk posed by physical transactions.

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

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

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

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

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

 

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Index to Financial Statements

13. Long-term Debt

At December 31, 2010, long-term debt consisted of $11,610 million due in U.S. dollars and $617 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $345 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, together with sinking fund payments required, in each of the four years after December 31, 2011, in millions of dollars, are: 2012 – $3,222, 2013 – $1,019, 2014 – $622 and 2015 – $601. At December 31, 2010, the Corporation's unused long-term credit lines were not material.

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

 

     2010      2009  
     (millions of dollars)  

SeaRiver Maritime Financial Holdings, Inc. (1)

  

Guaranteed debt securities due 2011 (2)

   $ —         $ 13   

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

     2,389         2,144   

XTO Energy Inc. (premium in millions of dollars)

     

7.500% senior note due 2012 includes premium of $15

     199         —     

5.900% senior note due 2012 includes premium of $16

     233         —     

6.250% senior note due 2013 includes premium of $18

     193         —     

4.625% senior note due 2013 includes premium of $9

     149         —     

5.750% senior note due 2013 includes premium of $37

     359         —     

4.900% senior note due 2014 includes premium of $19

     267         —     

5.000% senior note due 2015 includes premium of $13

     142         —     

5.300% senior note due 2015 includes premium of $28

     262         —     

5.650% senior note due 2016 includes premium of $27

     227         —     

6.250% senior note due 2017 includes premium of $80

     534         —     

5.500% senior note due 2018 includes premium of $49

     420         —     

6.500% senior note due 2018 includes premium of $86

     524         —     

6.100% senior note due 2036 includes premium of $29

     204         —     

6.750% senior note due 2037 includes premium of $69

     329         —     

6.375% senior note due 2038 includes premium of $46

     258         —     

Mobil Services (Bahamas) Ltd.

     

Variable note due 2035 (3)

     972         972   

Variable note due 2034 (4)

     311         311   

Mobil Producing Nigeria Unlimited (5)

     

Variable notes due 2012-2017

     415         621   

Esso (Thailand) Public Company Ltd. (6)

     

Variable notes due 2012-2017

     522         165   

Mobil Corporation

     

8.625% debentures due 2021

     248         248   

Industrial revenue bonds due 2012-2040 (7)

     2,247         1,685   

Other U.S. dollar obligations (8)

     454         536   

Other foreign currency obligations

     65         66   

Capitalized lease obligations (9)

     304         368   
                 

Total long-term debt

   $ 12,227       $ 7,129   
                 

 

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

 

79


Table of Contents
Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

 

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

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

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

 

     Exxon  Mobil
Corporation

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

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

  

Revenues and other income

            

Sales and other operating revenue, including sales-based taxes

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

Income from equity affiliates

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

Other income

     790         —          1,629         —          2,419   

Intercompany revenue

     39,433         4        332,483         (371,920     —     
                                          

Total revenues and other income

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

Costs and other deductions

            

Crude oil and product purchases

     40,788         —          518,961         (361,790     197,959   

Production and manufacturing expenses

     7,627         —          33,400         (5,235     35,792   

Selling, general and administrative expenses

     2,871         —          12,482         (670     14,683   

Depreciation and depletion

     1,761         —          12,999         —          14,760   

Exploration expenses, including dry holes

     251         —          1,893         —          2,144   

Interest expense

     217         246        4,035         (4,239     259   

Sales-based taxes

     —           —          28,547         —          28,547   

Other taxes and duties

     29         —          36,089         —          36,118   
                                          

Total costs and other deductions

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

Income before income taxes

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

Income taxes

     2         (90     21,649         —          21,561   
                                          

Net income including noncontrolling interests

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

Net income attributable to noncontrolling interests

     —           —          938         —          938   
                                          

Net income attributable to ExxonMobil

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

 

80


Table of Contents
Index to Financial Statements
     Exxon  Mobil
Corporation

Parent
Guarantor
    SeaRiver
Maritime
Financial
Holdings, Inc.
    All Other
Subsidiaries
     Consolidating
and
Eliminating
Adjustments
    Consolidated  
    

(millions of dollars)

 

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

  

Revenues and other income

           

Sales and other operating revenue, including sales-based taxes

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

Income from equity affiliates

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

Other income

     813        —          1,130         —          1,943   

Intercompany revenue

     30,889        4        271,663         (302,556     —     
                                         

Total revenues and other income

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

Costs and other deductions

           

Crude oil and product purchases

     31,419        —          411,689         (290,302     152,806   

Production and manufacturing expenses

     7,811        —          30,805         (5,589     33,027   

Selling, general and administrative expenses

     2,574        —          12,852         (691     14,735   

Depreciation and depletion

     1,571        —          10,346         —          11,917   

Exploration expenses, including dry holes

     230        —          1,791         —          2,021   

Interest expense

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

Sales-based taxes

     —          —          25,936         —          25,936   

Other taxes and duties

     (29     —          34,848         —          34,819   
                                         

Total costs and other deductions

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

Income before income taxes

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

Income taxes

     (1,150     (81     16,350         —          15,119   
                                         

Net income including noncontrolling interests

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

Net income attributable to noncontrolling interests

     —          —          378         —          378   
                                         

Net income attributable to ExxonMobil

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

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

  

Revenues and other income

           

Sales and other operating revenue, including sales-based taxes

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

Income from equity affiliates

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

Other income

     302        —          6,397         —          6,699   

Intercompany revenue

     48,414        45        442,305         (490,764     —     
                                         

Total revenues and other income

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

Costs and other deductions

           

Crude oil and product purchases

     48,346        —          669,107         (467,999     249,454   

Production and manufacturing expenses

     8,327        —          35,298         (5,720     37,905   

Selling, general and administrative expenses

     3,349        —          13,364         (840     15,873   

Depreciation and depletion

     1,552        —          10,827         —          12,379   

Exploration expenses, including dry holes

     192        —          1,259         —          1,451   

Interest expense

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

Sales-based taxes

     —          —          34,508         —          34,508   

Other taxes and duties

     67        —          41,652         —          41,719   
                                         

Total costs and other deductions

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

Income before income taxes

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

Income taxes

     949        (56     35,637         —          36,530   
                                         

Net income including noncontrolling interests

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

Net income attributable to noncontrolling interests

     —          —          1,647         —          1,647   
                                         

Net income attributable to ExxonMobil

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

 

81


Table of Contents
Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

 

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

(millions of dollars)

 

Condensed consolidated balance sheet for year ended December 31, 2010

  

Cash and cash equivalents

   $ 309      $ —        $ 7,516       $ —        $ 7,825   

Cash and cash equivalents – restricted

     371        —          257         —          628   

Marketable securities

     —          —          2         —          2   

Notes and accounts receivable – net

     2,104        —          30,346         (166     32,284   

Inventories

     1,457        —          11,519         —          12,976   

Other current assets

     239        —          5,030         —          5,269   
                                         

Total current assets

     4,480        —          54,670         (166     58,984   

Investments, advances and long-term receivables

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

Property, plant and equipment – net

     18,830        —          180,718         —          199,548   

Other long-term assets

     224        12        8,404         —          8,640   

Intercompany receivables

     18,186        2,457        528,405         (549,048     —     
                                         

Total assets

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

Notes and loans payable

   $ 1,042      $ 13      $ 1,732       $ —        $ 2,787   

Accounts payable and accrued liabilities

     2,987        —          47,047         —          50,034   

Income taxes payable

     —          3        9,975         (166     9,812   
                                         

Total current liabilities

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

Long-term debt

     295        2,389        9,543         —          12,227   

Postretirement benefits reserves

     9,660        —          9,707         —          19,367   

Deferred income tax liabilities

     642        107        34,401         —          35,150   

Other long-term liabilities

     5,632        —          14,822         —          20,454   

Intercompany payables

     129,404        382        419,262         (549,048     —     
                                         

Total liabilities

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

Earnings reinvested

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

Other equity

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

ExxonMobil share of equity

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

Noncontrolling interests

     —          —          5,840         —          5,840   
                                         

Total equity

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

Total liabilities and equity

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

Condensed consolidated balance sheet for year ended December 31, 2009

  

Cash and cash equivalents

   $ 449      $ —        $ 10,244       $ —        $ 10,693   

Marketable securities

     —          —          169         —          169   

Notes and accounts receivable – net

     2,050        —          25,858         (263     27,645   

Inventories

     1,202        —          10,351         —          11,553   

Other current assets

     313        —          4,862         —          5,175   
                                         

Total current assets

     4,014        —          51,484         (263     55,235   

Investments, advances and long-term receivables

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

Property, plant and equipment – net

     18,015        —          121,101         —          139,116   

Other long-term assets

     207        24        7,076         —          7,307   

Intercompany receivables

     19,637        2,257        442,903         (464,797     —     
                                         

Total assets

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

Notes and loans payable

   $ 43      $ 13      $ 2,420       $ —        $ 2,476   

Accounts payable and accrued liabilities

     2,779        —          38,496         —          41,275   

Income taxes payable

     —          2        8,571         (263     8,310   
                                         

Total current liabilities

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

Long-term debt

     279        2,157        4,693         —          7,129   

Postretirement benefits reserves

     8,673        —          9,269         —          17,942   

Deferred income tax liabilities

     818        151        22,179         —          23,148   

Other long-term liabilities

     5,286        —          12,365         —          17,651   

Intercompany payables

     112,536        382        351,879         (464,797     —     
                                         

Total liabilities

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

Earnings reinvested

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

Other equity

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

ExxonMobil share of equity

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

Noncontrolling interests

     —          —          4,823         —          4,823   
                                         

Total equity

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

Total liabilities and equity

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

 

82


Table of Contents
Index to Financial Statements
     Exxon  Mobil
Corporation

Parent
Guarantor
    SeaRiver
Maritime
Financial
Holdings, Inc
    All Other
Subsidiaries
    Consolidating
and
Eliminating
Adjustments
    Consolidated  
    

(millions of dollars)

 

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

  

Cash provided by/(used in) operating activities

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

Cash flows from investing activities

          

Additions to property, plant and equipment

     (2,922     —          (23,949     —          (26,871

Sales of long-term assets

     1,484        —          1,777        —          3,261   

Decrease/(increase) in restricted cash and cash equivalents

     (371     —          (257     —          (628

Net intercompany investing

     (13,966     (200     13,813        353        —     

All other investing, net

     (672     —          706        —          34   
                                        

Net cash provided by/(used in) investing activities

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

Cash flows from financing activities

          

Additions to short- and long-term debt

     —          —          1,741        —          1,741   

Reductions in short- and long-term debt

     (3     (13     (8,644     —          (8,660

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

     997        —          (288     —          709   

Cash dividends

     (8,498     —          (5,697     5,697        (8,498

Common stock acquired

     (13,093     —          —          —          (13,093

Net intercompany financing activity

     —          —          202        (202     —     

All other financing, net

     1,164        150        (286     (151     877   
                                        

Net cash provided by/(used in) financing activities

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

Effects of exchange rate changes on cash

     —          —          (153     —          (153
                                        

Increase/(decrease) in cash and cash equivalents

   $ (140   $ —        $ (2,728   $ —        $ (2,868
                                        

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

  

Cash provided by/(used in) operating activities

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

Cash flows from investing activities

          

Additions to property, plant and equipment

     (2,686     —          (19,805     —          (22,491

Sales of long-term assets

     228        —          1,317        —          1,545   

Decrease/(increase) in restricted cash and cash equivalents

     —          —          —          —          —     

Net intercompany investing

     (1,826     (209     1,717        318        —     

All other investing, net

     —          —          (1,473     —          (1,473
                                        

Net cash provided by/(used in) investing activities

     (4,284     (209     (18,244     318        (22,419
                                        

Cash flows from financing activities

          

Additions to short- and long-term debt

     —          —          1,561        —          1,561   

Reductions in short- and long-term debt

     (3     (13     (1,627     —          (1,643

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

     39        —          (110     —          (71

Cash dividends

     (8,023     —          (27,082     27,082        (8,023

Common stock acquired

     (19,703     —          —          —          (19,703

Net intercompany financing activity

     —          —          168        (168     —     

All other financing, net

     988        150        (392     (150     596   
                                        

Net cash provided by/(used in) financing activities

     (26,702     137        (27,482     26,764        (27,283
                                        

Effects of exchange rate changes on cash

     —          —          520        —          520   
                                        

Increase/(decrease) in cash and cash equivalents

   $ (3,562   $ —        $ (17,182   $ —        $ (20,744
                                        

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed consolidating financial information related to guaranteed securities issued by subsidiaries

 

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

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

  

Cash provided by/(used in) operating activities

   $ 47,823      $ 68      $ 54,478      $ (42,644   $ 59,725   
                                        

Cash flows from investing activities

          

Additions to property, plant and equipment

     (2,154     —          (17,164     —          (19,318

Sales of long-term assets

     162        —          5,823        —          5,985   

Decrease/(increase) in restricted cash and cash equivalents

     —          —          —          —          —     

Net intercompany investing

     (502     (155     476        181        —     

All other investing, net

     —          —          (2,166     —          (2,166
                                        

Net cash provided by/(used in) investing activities

     (2,494     (155     (13,031     181        (15,499
                                        

Cash flows from financing activities

          

Additions to short- and long-term debt

     —          —          1,146        —          1,146   

Reductions in short- and long-term debt

     (4     (13     (1,799     —          (1,816

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

     —          —          143        —          143   

Cash dividends

     (8,058     —          (42,644     42,644        (8,058

Common stock acquired

     (35,734     —          —          —          (35,734

Net intercompany financing activity

     —          —          81        (81     —     

All other financing, net

     1,085        100        (793     (100     292   
                                        

Net cash provided by/(used in) financing activities

     (42,711     87        (43,866     42,463        (44,027
                                        

Effects of exchange rate changes on cash

     —          —          (2,743     —          (2,743
                                        

Increase/(decrease) in cash and cash equivalents

   $ 2,618      $ —        $ (5,162   $ —        $ (2,544
                                        

14. Incentive Program

The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited or expire, or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2010, remaining shares available for award under the 2003 Incentive Program were 141,939 thousand.

As under earlier programs, options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. Most of the options and SARs normally first become exercisable one year following the date of grant. All remaining stock options and SARs outstanding were either granted prior to 2002 or were converted XTO stock options as a result of the XTO merger.

Under the terms of the XTO merger agreement, outstanding XTO stock-based awards were converted into ExxonMobil stock-based awards based on the merger exchange ratio. The converted XTO awards, granted under XTO’s 1998 or 2004 Stock Incentive Plans, include restricted stock awards, stock options and performance stock awards. The grant date for the converted XTO awards is considered to be the effective date of the merger for purposes of calculating fair value. Compensation cost for the converted XTO awards is recognized in income over the requisite service period. The maximum term of the XTO awards is ten years under the 1998 plan and seven years under the 2004 plan. No additional awards will be issued under either XTO plan. In connection with the closing of the merger, the Corporation also made new grants of restricted stock under the Corporation’s 2003 Incentive Program to certain current or former XTO employees as described in more detail below.

Restricted Stock. Excluding XTO merger-related grants, long-term incentive awards totaling 10,648 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2010. Awards totaling 10,133 thousand and 10,116 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2009 and 2008, respectively. These shares are issued to employees from treasury stock. The total compensation expense is recognized over the requisite service period. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. A small

 

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number of awards granted to certain senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.

Additionally, long-term incentive awards totaling 4,206 thousand of restricted (nonvested) common stock were granted in 2010 in association with the XTO merger. This included the granting of 1,423 thousand of restricted common stock awards under the Corporation’s 2003 Incentive Program and 2,783 thousand of converted XTO restricted common stock awards. The majority of the converted XTO awards vest in three installments over a period of three years or three and a half years after the initial grant. The remainder of converted XTO awards that were granted to certain senior XTO employees will vest on the first anniversary of the effective date of the merger. Awards granted to certain former senior executives of XTO in connection with consulting agreements negotiated as part of the merger have vesting periods of one year for 50 percent of the award and of two or three years for the remaining 50 percent of the award, depending on the actual term of the consulting engagements.

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

In 2002, the Corporation began issuing restricted stock as stock-based compensation in lieu of stock options. Compensation expense for these awards is based on the price of the stock at the date of grant and has been recognized in income over the requisite service period. Prior to 2002, the Corporation issued stock options as stock-based compensation and since these awards vested prior to the effective date of current authoritative guidance, they continue to be accounted for under the prior prescribed method. Under this method, compensation expense for awards granted in the form of stock options is measured at the intrinsic value of the options (the difference between the market price of the stock and the exercise price of the options) on the date of grant. Since these two prices were the same on the date of grant, no compensation expense has been recognized in income for these awards.

The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2010.

 

      2010

Restricted stock and units outstanding

   Shares   Weighted Average
Grant-Date
Fair Value per Share
     (thousands)    

Issued and outstanding at January 1

       43,503       $ 67.52  

2009 award issued in 2010

       10,132       $ 75.40  

Merger-related granted and converted XTO awards

       4,206       $ 59.31  

Vested

       (10,377 )     $ 61.72  

Forfeited

       (158 )     $ 67.91  
                    

Issued and outstanding at December 31

       47,306       $ 69.74  
                    

 

Value of restricted stock and units

   2010      2009      2008  

Grant price

   $ 66.07       $ 75.40       $ 78.24   

Value at date of grant:

     (millions of dollars)   

Restricted stock and units settled in stock

   $ 672       $ 711       $ 735   

Merger-related granted and converted XTO awards

     250         —           —     

Units settled in cash

     60         53         56   
                          

Total value

   $ 982       $ 764       $ 791   
                          

As of December 31, 2010, there was $2,133 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.3 years. The compensation cost charged against income for the restricted stock and restricted units was $801 million, $723 million and $648 million for 2010, 2009 and 2008, respectively. The income tax benefit recognized in income related to this compensation expense was $81 million, $76 million and $75 million for the same periods, respectively. The fair value of shares and units vested in 2010, 2009 and 2008 was $718 million, $763 million and $438 million, respectively. Cash payments of $42 million, $41 million and $25 million for vested restricted stock units settled in cash were made in 2010, 2009 and 2008, respectively.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Performance Stock. The Corporation granted 157 thousand of converted XTO performance stock awards with a grant-date fair value of $5 million as a result of the merger. Compensation cost for the performance stock awards is based on the estimated grant-date fair value. Vesting of XTO performance stock awards depended on the achievement of certain XTO stock thresholds. Upon conversion of these awards to ExxonMobil performance stock awards in connection with the merger, the performance thresholds were adjusted to equivalent market price thresholds for common stock of the Corporation. The performance stock awards are subject to forfeiture if the performance criteria are not met within the maximum term. Otherwise, holders of performance stock awards generally have all voting, dividend and other rights of other common stockholders.

The following table provides information about these converted performance stock awards as of December 31, 2010.

 

     Dec. 31, 2010  

Performance stock awards

   Shares  
     (thousands)  

Vesting Price:

  

$108.49

     38   

$119.76

     38   

During 2010, 80 thousand performance share awards vested.

Unrecognized compensation cost was $1 million at December 31, 2010. Compensation expense recognized in 2010 was $3 million.

 

 

Stock Options. The Corporation granted 12,393 thousand of converted XTO stock options with a grant-date fair value of $182 million as a result of the XTO merger. The grant included 893 thousand of unvested options. The converted XTO stock option awards are accounted for under current authoritative guidance, which requires the measurement and recognition of compensation expense based on estimated grant-date fair values. Upon conversion of these stock options to ExxonMobil stock options in connection with the merger, the performance thresholds were adjusted to equivalent market price thresholds for common stock of the Corporation. These stock options generally vest and become exercisable ratably over a three-year period, and may include a provision for accelerated vesting when the common stock price reaches specified levels. Some stock option tranches vest only when the common stock price reaches specified levels. As of December 31, 2010, unvested stock options of 574 thousand included 130 thousand options that vest ratably over three years and 444 thousand options that vest at stock prices ranging from $76.08 to $126.80.

Changes that occurred in the Corporation’s stock options in 2010 are summarized below (shares in thousands):

 

     2010         

Stock options

   Shares     Avg. Exercise
Price
     Weighted Average
Remaining Contractual Term
 

Outstanding at January 1

     41,473      $ 40.92      

Merger-related converted XTO awards

     12,393      $ 55.15      

Exercised

     (24,305   $ 43.62      

Forfeited

     (52   $ 45.91      
             

Outstanding at December 31

     29,509      $ 44.65         2.0 Years   
             

Exercisable at December 31

     28,935      $ 43.94         1.9 Years   

Unrecognized compensation cost related to the nonvested merger-related converted XTO stock options was $1 million as of December 31, 2010. Compensation expense recognized in 2010 was $2 million. No compensation expense was recognized for stock options in 2009 and 2008, as all remaining outstanding stock options were granted prior to 2002 and were fully vested. Cash received from stock option exercises was $1,043 million, $752 million and $753 million for 2010, 2009 and 2008, respectively. The cash tax benefit realized for the options exercised was $89 million, $164 million and $273 million for 2010, 2009 and 2008, respectively. The aggregate intrinsic value of stock options exercised in 2010, 2009 and 2008 was $539 million, $563 million and $894 million, respectively. The intrinsic value for the balance of outstanding stock options at December 31, 2010, was $868 million. The intrinsic value for the balance of exercisable stock options at December 31, 2010, was $865 million.

 

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Estimated Fair Value of XTO Merger-Related Grants. For restricted stock grants, the fair value was equal to the price of the common stock on the grant date. For the converted XTO stock options and performance stock, the Corporation used a Monte Carlo simulation model to estimate fair value. The Monte Carlo simulation model requires inputs for the risk-free interest rate, dividend yield, volatility, contract term, target vesting price, post-vesting turnover rate and sub-optimal exercise factor. Expected life, derived vesting period and fair value are outputs of this model.

The risk-free interest rate is based on the constant maturity nominal rates of U.S. Treasury securities with remaining lives throughout the contract term on the day of the grant. The dividend yield is the expected common stock annual dividend yield over the expected life of the option or performance stock, expressed as a percentage of the stock price on the date of grant. The volatility factors are based on a combination of both the historical volatilities of ExxonMobil’s stock and the implied volatility of traded options on ExxonMobil common stock. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by certain employees who receive stock option grants, and subsequent events are not indicative of the reasonableness of the original fair value estimates.

The total estimated fair value calculated at the time of the merger for the converted XTO stock-based awards was $352 million.

Fair values were determined using the following assumptions:

 

Weighted average expected term

     2.5 years       

Range of risk-free interest rates

     0.1% - 2.6%     

Weighted average risk-free interest rates

     0.9%         

Dividend yield

     3.0%         

Weighted average volatility

     28.5%         

Range of volatility

     22.5% - 33.6%   

15. Litigation and Other Contingencies

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2010, for $8,771 million, primarily relating to guarantees for notes, loans and performance under contracts. Included in this amount were guarantees by consolidated affiliates of $5,290 million, representing ExxonMobil’s share of obligations of certain equity companies.

 

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

Guarantees

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

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

 

     Payments Due by Period  
     2011      2012-
2015
     2016
and
Beyond
     Total  
     (millions of dollars)  

Unconditional purchase obligations (1)

   $ 287       $ 748       $ 487       $ 1,522   

 

(1) Undiscounted obligations of $1,522 million mainly pertain to pipeline throughput agreements and include $996 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $273 million, totaled $1,249 million.

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

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

 

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16. Pension and Other Postretirement Benefits

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

 

     Pension Benefits     Other  Postretirement
Benefits
 
     U.S.     Non-U.S.    
     2010     2009     2010     2009     2010     2009  
    

(percent)

 

Weighted-average assumptions used to determine benefit obligations at December 31

            

Discount rate

     5.50        6.00        4.80        5.20        5.50        6.00   

Long-term rate of compensation increase

     5.00        5.00        5.20        5.00        5.00        5.00   
     (millions of dollars)  

Change in benefit obligation

  

Benefit obligation at January 1

   $ 13,981      $ 13,272      $ 23,344      $ 19,990      $ 6,748      $ 6,633   

Service cost

     468        438        480        421        101        94   

Interest cost

     798        809        1,175        1,121        395        408   

Actuarial loss/(gain)

     553        1,126        1,672        1,280        277        (49

Benefits paid (1) (2)

     (873     (1,665     (1,281     (1,174     (394     (480

Foreign exchange rate changes

     —          —          169        1,676        26        60   

Plan amendments, other

     80        1        163        30        178        82   
                                                

Benefit obligation at December 31

   $ 15,007      $ 13,981      $ 25,722      $ 23,344      $ 7,331      $ 6,748   
                                                

Accumulated benefit obligation at December 31

   $ 12,764      $ 11,615      $ 22,958      $ 20,909      $ —        $ —     

 

(1) Benefit payments for funded and unfunded plans.
(2) For 2010 and 2009, other postretirement benefits paid are net of $15 million and $28 million of Medicare subsidy receipts, respectively.

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

The measurement of the accumulated postretirement benefit obligation assumes an initial health care cost trend rate of 6.0 percent that declines to 4.5 percent by 2015. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $57 million and the postretirement benefit obligation by $599 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $45 million and the post-retirement benefit obligation by $494 million.

 

     Pension Benefits     Other  Postretirement
Benefits
 
     U.S.     Non-U.S.    
     2010     2009     2010     2009     2010     2009  
    

(millions of dollars)

 

Change in plan assets

          

Fair value at January 1

   $ 10,277      $ 6,634      $ 15,401      $ 11,260      $ 514      $ 443   

Actual return on plan assets

     1,235        2,013        1,482        2,201        63        93   

Foreign exchange rate changes

     —          —          99        1,300        —          —     

Company contribution

     —          3,070        1,184        1,456        38        36   

Benefits paid (1)

     (677     (1,440     (873     (795     (59     (57

Other

     —          —          (528     (21     2        (1
                                                

Fair value at December 31

   $ 10,835      $ 10,277      $ 16,765      $ 15,401      $ 558      $ 514   
                                                

 

(1) Benefit payments for funded plans.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

     Pension Benefits  
     U.S.     Non-U.S.  
     2010     2009     2010     2009  
     (millions of dollars)  

Assets in excess of/(less than) benefit obligation

  

Balance at December 31

        

Funded plans

   $ (2,349   $ (1,940   $ (2,769   $ (2,085

Unfunded plans

     (1,823     (1,764     (6,188     (5,858
                                

Total

   $ (4,172   $ (3,704   $ (8,957   $ (7,943
                                

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

 

     Pension Benefits     Other  Postretirement
Benefits
 
     U.S.     Non-U.S.    
     2010     2009     2010     2009     2010     2009  
     (millions of dollars)  

Assets in excess of/(less than) benefit obligation

          

Balance at December 31 (1)

   $ (4,172   $ (3,704   $ (8,957   $ (7,943   $ (6,773   $ (6,234
                                                

Amounts recorded in the consolidated balance sheet consist of:

            

Other assets

   $ 1      $ 1      $ 400      $ 961      $ —        $ —     

Current liabilities

     (257     (235     (336     (348     (343     (318

Postretirement benefits reserves

     (3,916     (3,470     (9,021     (8,556     (6,430     (5,916
                                                

Total recorded

   $ (4,172   $ (3,704   $ (8,957   $ (7,943   $ (6,773   $ (6,234
                                                

Amounts recorded in accumulated other comprehensive income consist of:

            

Net actuarial loss/(gain)

   $ 5,028      $ 5,830      $ 7,795      $ 7,036      $ 1,985      $ 1,878   

Prior service cost

     83        5        674        622        154        181   
                                                

Total recorded in accumulated other comprehensive income

   $ 5,111      $ 5,835      $ 8,469      $ 7,658      $ 2,139      $ 2,059   
                                                

 

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

 

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

A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class.

 

     Pension Benefits     Other Postretirement  
     U.S.     Non-U.S.     Benefits  
     2010     2009     2008     2010     2009     2008     2010     2009     2008  
    

(percent)

 

Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31

                  

Discount rate

     6.00        6.25        6.25        5.20        5.50        5.40        6.00        6.25        6.25   

Long-term rate of return on funded assets

     7.50        8.00        9.00        6.70        7.30        7.50        7.50        8.00        9.00   

Long-term rate of compensation increase

     5.00        5.00        5.00        5.00        4.70        4.50        5.00        5.00        5.00   
    

(millions of dollars)

 

Components of net periodic benefit cost

              

Service cost

   $ 468      $ 438      $ 378      $ 480      $ 421      $ 434      $ 101      $ 94      $ 100   

Interest cost

     798        809        729        1,175        1,121        1,152        395        408        414   

Expected return on plan assets

     (726     (656     (915     (1,010     (886     (1,200     (37     (35     (59

Amortization of actuarial loss/(gain)

     525        694        239        554        648        318        147        176        197   

Amortization of prior service cost

     2        —          (2     84        79        93        52        69        76   

Net pension enhancement and curtailment/settlement expense

     321        485        174        9        2        32        —          —          —     
                                                                        

Net periodic benefit cost

   $ 1,388      $ 1,770      $ 603      $ 1,292      $ 1,385      $ 829      $ 658      $ 712      $ 728   
                                                                        

Changes in amounts recorded in accumulated other comprehensive income:

                  

Net actuarial loss/(gain)

   $ 44      $ (231   $ 5,275      $ 1,202      $ (33   $ 4,837      $ 251      $ (107   $ 13   

Amortization of actuarial (loss)/gain

     (846     (1,179     (413     (563     (650     (350     (147     (176     (197

Prior service cost/(credit)

     80        —          —          160        69        16        26        —          —     

Amortization of prior service (cost)

     (2     —          2        (84     (79     (93     (52     (69     (76

Foreign exchange rate changes

     —          —          —          96        608        (997     2        2        (3
                                                                        

Total recorded in other comprehensive income

     (724     (1,410     4,864        811        (85     3,413        80        (350     (263

Total recorded in net periodic benefit cost and other comprehensive income, before tax

   $ 664      $ 360      $ 5,467      $ 2,103      $ 1,300      $ 4,242      $ 738      $ 362      $ 465   
                                                                        

Costs for defined contribution plans were $347 million, $339 million and $309 million in 2010, 2009 and 2008, respectively.

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

 

     Total Pension and Other Postretirement Benefits  
     2010     2009     2008  
     (millions of dollars)  

(Charge)/credit to other comprehensive income, before tax

  

U.S. pension

   $ 724      $ 1,410      $ (4,864

Non-U.S. pension

     (811     85        (3,413

Other postretirement benefits

     (80     350        263   
                        

Total (charge)/credit to other comprehensive income, before tax

     (167     1,845        (8,014

(Charge)/credit to income tax (see note 18)

     35        (591     2,723   

(Charge)/credit to investment in equity companies

     11        (133     (27
                        

(Charge)/credit to other comprehensive income including noncontrolling interests, after tax

   $ (121   $ 1,121      $ (5,318

Charge/(credit) to equity of noncontrolling interests

     95        93        224   
                        

(Charge)/credit to other comprehensive income attributable to ExxonMobil

   $ (26   $ 1,214      $ (5,094
                        

 

91


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Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for the U.S. benefit plans is 60% equity securities and 40% debt securities. The target asset allocation for the non-U.S. plans in aggregate is 56% equities, 41% debt and 3% real estate funds. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily focus on early-stage venture capital of 5% and 3%, respectively.

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

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

 

    U.S. Pension     Non-U.S. Pension  
    Fair Value Measurement at
December 31, 2010, Using:
          Fair Value Measurement at
December 31, 2010, Using:
       
    Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
    Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
    Total     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
    Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
    Total  
   

(millions of dollars)

   

(millions of dollars)

 

Asset category:

               

Equity securities

               

U.S.

  $ —        $ 2,648 (1)    $ —        $ 2,648      $ —        $ 2,443 (1)    $ —        $ 2,443   

Non-U.S.

    —          3,530 (1)      —          3,530        228 (2)      6,502 (1)      —          6,730   

Private equity

    —          —          408 (3)      408        —          —          315 (3)      315   

Debt securities

               

Corporate

    —          1,152 (4)      —          1,152        2 (5)      1,629 (4)      —          1,631   

Government

    —          2,847 (4)      —          2,847        146 (5)      4,709 (4)      —          4,855   

Asset-backed

    —          31 (4)      —          31        —          98 (4)      —          98   

Private mortgages

    —          —          128 (6)      128        —          —          4 (6)      4   

Real estate funds

    —          —          —          —          —          —          417 (7)      417   

Cash

    68        —          —          68        63        51 (8)      —          114   
                                                               

Total at fair value

  $ 68      $ 10,208      $ 536      $ 10,812      $ 439      $ 15,432      $ 736      $ 16,607   

Insurance contracts at contract value

          23              158   
                           

Total plan assets

        $ 10,835            $ 16,765   
                           

 

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.
(2) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(3) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.
(4) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(5) For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(6) For private mortgages, fair value is based on proprietary credit spread matrices developed using market data and monthly surveys of active mortgage bankers.
(7) For real estate funds, fair value is based on appraised values developed using comparable market transactions.
(8) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

 

92


Table of Contents
Index to Financial Statements
     Other Postretirement  
     Fair Value Measurement at
December 31, 2010, Using:
       
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
    Total  
    

(millions of dollars)

 

Asset category:

         

Equity securities

         

U.S.

   $ —         $ 180 (1)    $ —        $ 180   

Non-U.S.

     —           191 (1)      —          191   

Private equity

     —           —          5 (2)      5   

Debt securities

         

Corporate

     —           49 (3)      —          49   

Government

     —           117 (3)      —          117   

Asset-backed

     —           13 (3)      —          13   

Private mortgages

     —           —          2 (4)      2   

Cash

     1         —          —          1   
                                 

Total at fair value

   $ 1       $ 550      $ 7      $ 558   
                                 

 

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.
(2) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.
(3) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(4) For private mortgages, fair value is based on proprietary credit spread matrices developed using market data and monthly surveys of active mortgage bankers.

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

 

     2010  
     Pension     Other Postretirement  
     U.S.     Non U.S.               
     Private
Equity
     Private
Mortgages
    Private
Equity
    Private
Mortgages
    Real
Estate
    Private
Equity
     Private
Mortgages
 
    

(millions of dollars)

 

Fair value at January 1

   $ 349       $ 280      $ 239      $ 5      $ 413      $ 4       $ 3   

Net realized gains/(losses)

     —           36        (1     (1     —          —           1   

Net unrealized gains/(losses)

     47         (3     26        1        (4     1         —     

Net purchases/(sales)

     12         (185     51        (1     8        —           (2
                                                          

Fair value at December 31

   $ 408       $ 128      $ 315      $ 4      $ 417      $ 5       $ 2   
                                                          

 

93


Table of Contents
Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The 2009 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:

 

    U.S. Pension     Non-U.S. Pension  
    Fair Value Measurement at
December 31, 2009, Using:
          Fair Value Measurement at
December 31, 2009, Using:
       
    Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
    Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
    Total     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
    Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
    Total  
   

(millions of dollars)

    (millions of dollars)  

Asset category:

               

Equity securities

               

U.S.

  $ —        $ 2,503 (1)    $ —        $ 2,503      $ —        $ 2,244 (1)    $ —        $ 2,244   

Non-U.S.

    —          3,341 (1)      —          3,341        227 (2)      5,946 (1)      —          6,173   

Private equity

    —          —          349 (3)      349        —          —          239 (3)      239   

Debt securities

               

Corporate

    —          1,040 (4)      —          1,040        2 (5)       1,637 (4)      —          1,639   

Government

    —          2,570 (4)      —          2,570        70 (5)      4,217 (4)      —          4,287   

Asset-backed

    —          30 (4)      —          30        —          119 (4)      —          119   

Private mortgages

    —          —          280 (6)      280        —          —          5 (6)      5   

Real estate funds

    —          —          —          —          —          —          413 (7)      413   

Cash

    140        —          —          140        79        55 (8)      —          134   
                                                               

Total at fair value

  $ 140      $ 9,484      $ 629      $ 10,253      $ 378      $ 14,218      $ 657      $ 15,253   

Insurance contracts at contract value

          24              148   
                           

Total plan assets

        $ 10,277            $ 15,401   
                           

 

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.
(2) For non-U.S. equity securities held in separate accounts, fair value is based on observable quoted prices on active exchanges.
(3) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.
(4) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(5) For corporate and government debt securities that are traded on active exchanges, fair value is based on observable quoted prices.
(6) For private mortgages, fair value is based on proprietary credit spread matrices developed using market data and monthly surveys of active mortgage bankers.
(7) For real estate funds, fair value is based on appraised values developed using comparable market transactions.
(8) For cash balances that are subject to withdrawal penalties or other adjustments, the fair value is treated as a Level 2 input.

 

94


Table of Contents
Index to Financial Statements
     Other Postretirement  
     Fair Value Measurement at
December 31, 2009, Using:
       
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
    Significant
Unobservable
Inputs

(Level 3)
    Total  
    

(millions of dollars)

 

Asset category:

         

Equity securities

         

U.S.

   $ —         $ 166 (1)    $ —        $ 166   

Non-U.S.

     —           181 (1)      —          181   

Private equity

     —           —          4 (2)      4   

Debt securities

         

Corporate

     —           51 (3)      —          51   

Government

     —           95 (3)      —          95   

Asset-backed

     —           11 (3)      —          11   

Private mortgages

     —           —          3 (4)      3   

Cash

     3         —          —          3   
                                 

Total at fair value

   $ 3       $ 504      $ 7      $ 514   
                                 

 

(1) For U.S. and non-U.S. equity securities held in the form of fund units that are redeemable at the measurement date, the unit value is treated as a Level 2 input. The fair value of the securities owned by the funds is based on observable quoted prices on active exchanges, which are Level 1 inputs.
(2) For private equity, fair value is generally established by using revenue or earnings multiples or other relevant market data including Initial Public Offerings.
(3) For corporate, government and asset-backed debt securities, fair value is based on observable inputs of comparable market transactions.
(4) For private mortgages, fair value is based on proprietary credit spread matrices developed using market data and monthly surveys of active mortgage bankers.

The change in the fair value in 2009 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:

 

     2009  
     Pension     Other Postretirement  
     U.S.     Non U.S.               
     Private
Equity
    Private
Mortgages
    Private
Equity
    Private
Mortgages
     Real
Estate
    Private
Equity
     Private
Mortgages
 
    

(millions of dollars)

 

Fair value at January 1

   $ 346      $ 476      $ 238      $ 5       $ 409      $ 4       $ 6   

Net realized gains/(losses)

     4        11        (10     —           (7     —           —     

Net unrealized gains/(losses)

     (35     7        (35     —           (11     —           —     

Net purchases/(sales)

     34        (214     46        —           22        —           (3
                                                          

Fair value at December 31

   $ 349      $ 280      $ 239      $ 5       $ 413      $ 4       $ 3   
                                                          

 

95


Table of Contents
Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

 

     Pension Benefits  
     U.S.      Non-U.S.  
     2010      2009      2010      2009  
    

(millions of dollars)

 

For funded pension plans with an accumulated benefit obligation in excess of plan assets:

           

Projected benefit obligation

   $ 13,184       $ 12,217       $ 9,865       $ 13,152   

Accumulated benefit obligation

     11,383         10,312         9,074         12,260   

Fair value of plan assets

     10,834         10,276         7,131         10,447   

For unfunded pension plans:

           

Projected benefit obligation

   $ 1,823       $ 1,764       $ 6,188       $ 5,858   

Accumulated benefit obligation

     1,381         1,303         5,413         5,180   
     Pension Benefits      Other Postretirement  
     U.S.      Non-U.S.      Benefits  
    

(millions of dollars)

 

Estimated 2011 amortization from accumulated other comprehensive income:

           

Net actuarial loss/(gain) (1)

   $ 835       $ 615         $        159               

Prior service cost (2)

     9         97         35               

 

(1) The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service period of active plan participants.
(2) The Corporation amortizes prior service cost on a straight-line basis as permitted under authoritative guidance for defined benefit pension and other postretirement benefit plans.

 

     Pension Benefits      Other Postretirement Benefits  
     U.S.      Non-U.S.      Gross      Medicare Subsidy Receipt  
    

(millions of dollars)

 

Contributions expected in 2011

   $ 270       $ 1,130       $ —         $ —     

Benefit payments expected in:

           

2011

     1,454         1,299         440         23   

2012

     1,483         1,281         456         25   

2013

     1,512         1,316         474         26   

2014

     1,451         1,362         489         28   

2015

     1,392         1,393         502         29   

2016 - 2020

     6,079         8,325         2,662         163   

 

96


Table of Contents
Index to Financial Statements

17. Disclosures about Segments and Related Information

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

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

Earnings after income tax include special items, and transfers are at estimated market prices. Earnings for 2009 included a special charge of $140 million in the corporate and financing segment for interest related to the Valdez punitive damages award. Special items included in 2008 after-tax earnings were a $1,620 million gain in Non-U.S. Upstream on the sale of a natural gas transportation business in Germany and special charges of $460 million in the corporate and financing segment related to the Valdez litigation.

Interest expense includes non-debt-related interest expense of $41 million, $500 million and $498 million in 2010, 2009 and 2008, respectively. Higher expenses in 2009 and 2008 primarily reflect interest provisions related to the Valdez litigation.

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

 

97


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Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Upstream      Downstream     Chemical     Corporate and     Corporate  
     U.S.      Non-U.S.      U.S.     Non-U.S.     U.S.      Non-U.S.     Financing     Total  
    

(millions of dollars)

 

As of December 31, 2010

                   

Earnings after income tax

   $ 4,272       $ 19,825       $ 770      $ 2,797      $ 2,422       $ 2,491      $ (2,117   $ 30,460   

Earnings of equity companies included above

     1,261         8,415         23        225        171         1,163        (581     10,677   

Sales and other operating revenue (1)

     8,895         26,046         93,599        206,042        13,402         22,119        22        370,125   

Intersegment revenue

     8,102         39,066         13,546        52,697        9,694         8,421        282        —     

Depreciation and depletion expense

     3,506         7,574         681        1,565        421         432        581        14,760   

Interest revenue

     —           —           —          —          —           —          118        118   

Interest expense

     20         25         1        19        1         4        189        259   

Income taxes

     2,219         18,627         360        560        736         347        (1,288     21,561   

Additions to property, plant and equipment

     52,300         16,937         888        1,332        247         1,733        719        74,156   

Investments in equity companies

     2,636         9,625         254        1,240        285         3,586        (197     17,429   

Total assets

     76,725         115,646         18,378        47,402        7,148         19,087        18,124        302,510   
                                                                   

As of December 31, 2009

                   

Earnings after income tax

   $ 2,893       $ 14,214       $ (153   $ 1,934      $ 769       $ 1,540      $ (1,917   $ 19,280   

Earnings of equity companies included above

     1,216         5,269         (102     188        164         906        (498     7,143   

Sales and other operating revenue (1)

     3,406         21,355         76,467        173,404        9,962         16,885        21        301,500   

Intersegment revenue

     6,718         32,982         10,168        39,190        7,185         6,947        284        —     

Depreciation and depletion expense

     1,768         6,376         687        1,665        400         457        564        11,917   

Interest revenue

     —           —           —          —          —           —          179        179   

Interest expense

     38         27         10        18        4         1        450        548   

Income taxes

     1,451         15,183         (164     (22     281         (182     (1,428     15,119   

Additions to property, plant and equipment

     2,973         13,307         1,449        1,447        294         2,553        468        22,491   

Investments in equity companies

     2,440         8,864         323        1,190        259         2,873        (207     15,742   

Total assets

     24,940         102,372         17,493        45,098        7,044         17,117        19,259        233,323   
                                                                   

As of December 31, 2008

                   

Earnings after income tax

   $ 6,243       $ 29,159       $ 1,649      $ 6,502      $ 724       $ 2,233      $ (1,290   $ 45,220   

Earnings of equity companies included above

     1,954         7,597         (2     518        105         1,411        (502     11,081   

Sales and other operating revenue (1)

     6,767         32,346         116,701        265,359        14,136         24,252        18        459,579   

Intersegment revenue

     9,617         55,069         16,225        65,723        9,925         9,749        273        —     

Depreciation and depletion expense

     1,391         7,266         656        1,672        410         422        562        12,379   

Interest revenue

     —           —           —          —          —           —          1,400        1,400   

Interest expense

     47         63         9        28        3         4        519        673   

Income taxes

     3,451         30,654         728        1,990        177         10        (480     36,530   

Additions to property, plant and equipment

     2,699         10,545         1,550        1,552        413         1,987        572        19,318   

Investments in equity companies

     2,248         7,787         456        1,382        241         2,384        (40     14,458   

Total assets

     23,056         83,750         16,328        42,044        6,856         13,300        42,718        228,052   
                                                                   

 

Geographic

Sales and other operating revenue (1)

   2010      2009      2008  
    

(millions of dollars)

 

United States

   $ 115,906       $ 89,847       $ 137,615   

Non-U.S.

     254,219         211,653         321,964   
                          

Total

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

Significant non-U.S. revenue sources include:

  

  

Canada

   $ 27,243       $ 21,151       $ 33,677   

Japan

     27,143         22,054         30,126   

United Kingdom

     24,637         20,293         29,764   

Belgium

     21,139         16,857         25,399   

Germany

     14,301         14,839         20,591   

Italy

     14,132         12,997         17,953   

France

     13,920         12,042         18,530   

Singapore

     11,088         8,400         11,059   

Long-lived assets

   2010      2009      2008  
     (millions of dollars)  

United States

   $ 86,021       $ 37,138       $ 35,548   

Non-U.S.

     113,527         101,978         85,798   
                          

Total

   $ 199,548       $ 139,116       $ 121,346   
                          

Significant non-U.S. long-lived assets include:

        

Canada

   $ 20,879       $ 15,919       $ 12,018   

Nigeria

     11,429         11,046         9,227   

Singapore

     8,610         7,238         5,113   

Angola

     8,570         7,320         6,129   

Norway

     6,988         7,251         5,856   

Australia

     6,570         4,247         2,857   

United Kingdom

     6,177         7,609         5,778   

Kazakhstan

     5,938         4,748         3,535   

 

(1) Sales and other operating revenue includes sales-based taxes of $28,547 million for 2010, $25,936 million for 2009 and $34,508 million for 2008.

See note 1, Summary of Accounting Policies.

 

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Index to Financial Statements

18. Income, Sales-Based and Other Taxes

 

    2010     2009     2008  
    U.S.     Non-U.S.     Total     U.S.     Non-U.S.     Total     U.S.     Non-U.S.     Total  

Income taxes

    (millions of dollars)   

Federal and non-U.S.

                 

Current

  $ 1,224      $ 21,093      $ 22,317      $ (838   $ 15,830      $ 14,992      $ 3,005      $ 31,377      $ 34,382   

Deferred – net

    49        (1,191     (1,142     650        (665     (15     168        1,289        1,457   

U.S. tax on non-U.S. operations

    46        —          46        32        —          32        230        —          230   
                                                                       

Total federal and non-U.S.

    1,319        19,902        21,221        (156     15,165        15,009        3,403        32,666        36,069   

State

    340        —          340        110        —          110        461        —          461   
                                                                       

Total income taxes

    1,659        19,902        21,561        (46     15,165        15,119        3,864        32,666        36,530   

Sales-based taxes

    6,182        22,365        28,547        6,271        19,665        25,936        6,646        27,862        34,508   

All other taxes and duties

                 

Other taxes and duties

    776        35,342        36,118        581        34,238        34,819        1,663        40,056        41,719   

Included in production and manufacturing expenses

    1,001        1,237        2,238        699        1,318        2,017        915        1,720        2,635   

Included in SG&A expenses

    201        570        771        197        538        735        209        660        869   
                                                                       

Total other taxes and duties

    1,978        37,149        39,127        1,477        36,094        37,571        2,787        42,436        45,223   
                                                                       

Total

  $ 9,819      $ 79,416      $ 89,235      $ 7,702      $ 70,924      $ 78,626      $ 13,297      $ 102,964      $ 116,261   
                                                                       

All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include a net charge of $175 million in 2010 and net credits of $9 million in 2009 and $300 million in 2008 for the effect of changes in tax laws and rates.

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

 

     2010     2009     2008  
     (millions of dollars)  

Cumulative foreign exchange translation adjustment

   $ (42   $ (247   $ 360   

Postretirement benefits reserves adjustment:

      

Net actuarial loss/(gain)

     553        (94     3,361   

Amortization of actuarial loss/(gain)

     (609     (649     (317

Prior service cost

     92        20        4   

Amortization of prior service cost

     (45     (43     (51

Foreign exchange rate changes

     44        175        (274
                        

Total postretirement benefits reserves adjustment

     35        (591     2,723   

Other components of equity

     246        140        315   

The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2010, 2009 and 2008 is as follows:

 

     2010     2009     2008  
     (millions of dollars)  

Income before income taxes

      

United States

   $ 7,711      $ 2,576      $ 10,152   

Non-U.S.

     45,248        32,201        73,245   
                        

Total

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

Theoretical tax

   $ 18,536      $ 12,172      $ 29,189   

Effect of equity method of accounting

     (3,737     (2,500     (3,878

Non-U.S. taxes in excess of theoretical U.S. tax

     7,293        5,948        10,188   

U.S. tax on non-U.S. operations

     46        32        230   

State taxes, net of federal tax benefit

     221        72        300   

Other U.S.

     (798     (605     501   
                        

Total income tax expense

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

Effective tax rate calculation

      

Income taxes

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

ExxonMobil share of equity company income taxes

     4,058        2,489        4,001   
                        

Total income taxes

     25,619        17,608        40,531   

Net income including noncontrolling interests

     31,398        19,658        46,867   
                        

Total income before taxes

   $ 57,017      $ 37,266      $ 87,398   
                        

Effective income tax rate

     45     47     46

 

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Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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

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

 

Tax effects of temporary differences for:

   2010     2009  
     (millions of dollars)  

Property, plant and equipment

   $ 42,657      $ 29,931   

Other liabilities

     4,278        4,102   
                

Total deferred tax liabilities

   $ 46,935      $ 34,033   
                

Pension and other postretirement benefits

   $ (5,634   $ (5,442

Asset retirement obligations

     (4,461     (3,978

Tax loss carryforwards

     (3,243     (3,693

Other assets

     (6,070     (4,700
                

Total deferred tax assets

   $ (19,408   $ (17,813
                

Asset valuation allowances

     1,183        1,495   
                

Net deferred tax liabilities

   $ 28,710      $ 17,715   
                

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

 

Balance sheet classification

   2010     2009  
     (millions of dollars)  

Other current assets

   $ (3,359   $ (3,322

Other assets, including intangibles, net

     (3,527     (2,263

Accounts payable and accrued liabilities

     446        152   

Deferred income tax liabilities

     35,150        23,148   
                

Net deferred tax liabilities

   $ 28,710      $ 17,715   
                

The Corporation had $35 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.

Unrecognized Tax Benefits

The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. Resolution of the related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the Corporation. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 20 percent or decrease by up to 5 percent in the next 12 months. Given the long time periods involved in resolving tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporation’s effective income tax rate in any given year.

The following table summarizes the movement in unrecognized tax benefits.

 

Gross unrecognized tax benefits

   2010     2009     2008  
     (millions of dollars)  

Balance at January 1

   $ 4,725      $ 4,976      $ 5,232   

Additions based on current year’s tax positions

     830        547        656   

Additions for prior years’ tax positions

     620        262        294   

Reductions for prior years’ tax positions

     (505     (594     (328

Reductions due to lapse of the statute of limitations

     (534     —          (27

Settlements with tax authorities

     (999     (592     (681

Foreign exchange effects/other

     11        126        (170
                        

Balance at December 31

   $ 4,148      $ 4,725      $ 4,976   
                        

The additions and reductions in unrecognized tax benefits shown above include effects related to net income and equity, and timing differences for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2010, 2009 and 2008 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income or cash flow.

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

 

Country of Operation    Open Tax Years

Abu Dhabi

   2000 -2010

Angola

   2007 -2010

Australia

   2000 -2010

Canada

   1994 -2010

Equatorial Guinea

   2005 -2010

Germany

   1999 -2010

Japan

   2003 -2010

Malaysia

   2004 -2010

Nigeria

   1998 -2010

Norway

   2000 -2010

United Kingdom

   2004 -2010

United States:

   1991 -1996
   1998 -2000
   2004 -2010

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

In 2010, the Corporation’s resolution of certain tax positions with tax jurisdictions resulted in a decrease in the total amount of unrecognized tax benefits and the related interest payable. For 2010, net interest expense was a credit of $39 million, reflecting the effect of credits from the net favorable resolution of these prior year tax positions. The Corporation incurred approximately $135 million and $137 million in interest expense on income tax reserves in 2009 and 2008, respectively. The related interest payable balances were $636 million and $771 million at December 31, 2010, and 2009, respectively.

 

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Index to Financial Statements

19. Acquisition of XTO Energy Inc.

Description of the Transaction. On June 25, 2010, ExxonMobil acquired XTO Energy Inc. (XTO) by merging a wholly-owned subsidiary of ExxonMobil with and into XTO (the “merger”), with XTO continuing as the surviving corporation and wholly-owned subsidiary of ExxonMobil. XTO is involved in the exploration for, production of, and transportation and sale of crude oil and natural gas. XTO’s asset base, technical capabilities and operating expertise, together with ExxonMobil’s extensive research and development expertise, project management and operational skills, global scale and financial capacity, should enable effective development of additional supplies of unconventional oil and gas resources.

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

The components of the consideration transferred follow:

 

     (millions of dollars)  

Consideration attributable to stock issued (1) (2)

   $ 24,480   

Consideration attributable to converted stock options (2)

     179   
        

Total consideration transferred

   $ 24,659   
        

 

(1) The fair value of the Corporation’s common stock on the acquisition date was $59.10 per share based on the closing value on the NYSE. The Corporation issued 416 million shares of stock previously held in treasury. The treasury stock issued, based on the average cost, was valued at $21,139 million. The excess of the fair value of the consideration transferred over the cost of treasury stock issued was $3,520 million and was included in common stock without par value.
(2) The portion of the fair value of XTO converted stock-based awards attributable to pre-merger employee service was part of consideration. The remaining fair value of the awards will be recognized in future periods over the requisite service period.

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

The following table summarizes the assets acquired and liabilities assumed:

 

     (millions of dollars)  

Cash and cash equivalents

   $ 47   

Notes and accounts receivable

     925   

Inventories

     170   

Other current assets (1)

     911   

Investments, advances and long-term receivables

     52   

Property, plant and equipment (2)

     47,300   

Identifiable intangible assets (3)

     493   

Goodwill (4)

     39   

Other assets (1)

     75   
        

Total assets acquired

   $ 50,012   
        

Notes and loans payable (5)

   $ 1,026   

Accounts payable and accrued liabilities (1) (6)

     1,788   

Income taxes payable

     (199

Long-term debt (5)

     10,574   

Postretirement benefits reserves

     65   

Deferred income tax liabilities (6)

     11,204   

Other long-term obligations

     895   
        

Total liabilities assumed

   $ 25,353   
        

Net assets acquired

   $ 24,659   
        

 

(1) Derivatives were measured using Level 1 inputs for derivatives that are traded directly on the NYMEX and Level 2 inputs for derivatives that are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices.
(2) Property, plant and equipment were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included XTO resources, assumed future production profiles, commodity prices (mainly based on observable market inputs), risk adjusted discount rate of 7.0 percent, inflation of 2.0 percent and assumptions on the timing and amount of future development and operating costs. The property, plant and equipment additions were segmented to the Upstream business, with substantially all of the assets in the United States.

 

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Index to Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

(3) Identifiable intangible assets and other assets were measured using a combination of an income approach and a market approach (Level 3). Identifiable intangible assets will be amortized over 20 years.
(4) Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill was recognized in the Upstream reporting unit. Goodwill is not amortized and is not deductible for tax purposes.
(5) Long-term debt was recognized mainly at market rates at closing (Level 1).
(6) Deferred income taxes reflect the temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.

XTO Results and Pro Forma Impact of Merger. The following table presents revenues and earnings for XTO for the periods presented:

 

     Acquisition Date
Through
December  31, 2010
 
     (millions of dollars)  

Revenues

   $ 4,448   

Upstream earnings

   $ 262   

Transaction-related costs were expensed as incurred. The Corporation recognized $18 million in transaction costs related to the merger in 2010.

The following table presents unaudited pro forma information for the Corporation as if the merger of XTO had occurred at the beginning of each year presented:

 

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

Revenues

   $ 373,273       $ 307,456   

Net income attributable to ExxonMobil

   $ 30,668       $ 19,672   

Earnings per common share

   $ 6.03       $ 3.75   

Earnings per common share – assuming dilution

   $ 6.01       $ 3.74   

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the merger and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the merger been completed on January 1, 2010, or on January 1, 2009. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. The unaudited pro forma consolidated results reflect pro forma adjustments for the elimination of deferred gains and losses recognized in earnings for derivatives outstanding at the beginning of the year presented, depreciation expense related to the fair value adjustment to property, plant and equipment acquired, additional amortization expense related to the fair value of identifiable intangible assets acquired, capitalization of interest expense and applicable income tax impacts.

 

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Index to Financial Statements

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

The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical service agreements, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity companies totaled $249 million in 2010, $536 million in 2009, and $3,834 million in 2008. Oil sands mining operations were in the excluded amounts for 2008. However, beginning in 2009, oil sands mining operations are included in the results of operations in accordance with revised Securities and Exchange Commission and Financial Accounting Standards Board rules. The amounts included for oil sands mining operations in the results of operations for 2009 are shown in footnote 1 on page 104.

 

Results of Operations –

  Consolidated Subsidiaries

   United States      Canada/
South America
     Europe      Africa      Asia      Australia/
Oceania
     Total  
        

(millions of dollars)

 

2010  –

 

Revenue

                    
 

Sales to third parties

   $ 5,334       $ 1,218       $ 6,055       $ 4,227       $ 4,578       $ 696       $ 22,108   
 

Transfers

     7,070         5,832         7,120         13,295         6,031         1,123         40,471   
                                                                
     $ 12,404       $ 7,050       $ 13,175       $ 17,522       $ 10,609       $ 1,819       $ 62,579   
 

Production costs excluding taxes

     2,794         2,612         2,717         2,215         1,308         462         12,108   
 

Exploration expenses

     283         464         394         587         360         56         2,144   
 

Depreciation and depletion

     3,350         1,015         2,531         2,580         1,141         219         10,836   
 

Taxes other than income

     1,188         86         482         1,742         1,298         204         5,000   
 

Related income tax

     2,093         715         4,728         6,068         3,852         262         17,718   
                                                                
 

Results of producing activities for consolidated subsidiaries

   $ 2,696       $ 2,158       $ 2,323       $ 4,330       $ 2,650       $ 616       $ 14,773   
                                                                

Results of Operations – Equity Companies

                                                

2010  –

 

Revenue

                    
 

Sales to third parties

   $ 1,012       $ —         $ 5,050       $ —         $ 12,682       $ —         $ 18,744   
 

Transfers

     867         —           68         —           3,817         —           4,752   
                                                                
     $ 1,879       $ —         $ 5,118       $ —         $ 16,499       $ —         $ 23,496   
 

Production costs excluding taxes

     481         —           294         —           320         —           1,095   
 

Exploration expenses

     4         —           19         —           2         —           25   
 

Depreciation and depletion

     157         —           188         —           455         —           800   
 

Taxes other than income

     32         —           2,515         —           3,844         —           6,391   
 

Related income tax

     —           —           815         —           5,295         —           6,110   
                                                                
 

Results of producing activities for equity companies

   $ 1,205       $ —         $ 1,287       $ —         $ 6,583       $ —         $ 9,075   
                                                                

Total results of operations

   $ 3,901       $ 2,158       $ 3,610       $ 4,330       $ 9,233       $ 616       $ 23,848   
                                                                

 

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

 

Results of Operations –

  Consolidated Subsidiaries

   United States      Canada/
South  America(1)
     Europe      Africa      Asia      Australia/
Oceania
     Total  
        

(millions of dollars)

 

2009  –

 

Revenue

                    
 

Sales to third parties

   $ 1,859       $ 1,345       $ 5,900       $ 3,012       $ 2,637       $ 586       $ 15,339   
 

Transfers

     5,652         4,538         5,977         11,868         5,433         1,066         34,534   
                                                                
     $ 7,511       $ 5,883       $ 11,877       $ 14,880       $ 8,070       $ 1,652       $ 49,873   
 

Production costs excluding taxes

     2,255         2,428         2,675         2,027         1,247         386         11,018   
 

Exploration expenses

     219         339         375         662         393         33         2,021   
 

Depreciation and depletion

     1,670         948         2,078         2,293         816         195         8,000   
 

Taxes other than income

     730         78         593         1,343         991         252         3,987   
 

Related income tax

     1,127         597         4,277         4,667         2,822         237         13,727   
                                                                
 

Results of producing activities for consolidated subsidiaries

   $ 1,510       $ 1,493       $ 1,879       $ 3,888       $ 1,801       $ 549       $ 11,120   
                                                                

Results of Operations – Equity Companies

                                                

2009  –

 

Revenue

                    
 

Sales to third parties

   $ 818       $ —         $ 4,889       $ —         $ 6,148       $ —         $ 11,855   
 

Transfers

     686         —           53         —           2,960         —           3,699   
                                                                
     $ 1,504       $ —         $ 4,942       $ —         $ 9,108       $ —         $ 15,554   
 

Production costs excluding taxes

     481         —           248         —           251         —           980   
 

Exploration expenses

     1         —           12         —           —           —           13   
 

Depreciation and depletion

     163         —           168         —           366         —           697   
 

Taxes other than income

     37         —           2,233         —           2,120         —           4,390   
 

Related income tax

     —           —           902         —           3,121         —           4,023   
                                                                
 

Results of producing activities for equity companies

   $ 822       $ —         $ 1,379       $ —         $ 3,250       $ —         $ 5,451   
                                                                

Total results of operations

   $ 2,332       $ 1,493       $ 3,258       $ 3,888       $ 5,051       $ 549       $ 16,571   
                                                                

Results of Operations

                                                

2008  –

 

Revenue

                    
 

Sales to third parties

   $ 3,980       $ 4,591       $ 11,239       $ 2,284       $ 4,294       $ 808       $ 27,196   
 

Transfers

     8,525         3,518         10,859         18,361         9,417         1,692         52,372   
                                                                
     $ 12,505       $ 8,109       $ 22,098       $ 20,645       $ 13,711       $ 2,500       $ 79,568   
 

Production costs excluding taxes

     2,143         1,686         2,623         1,603         1,100         332         9,487   
 

Exploration expenses

     189         232         180         439         292         109         1,441   
 

Depreciation and depletion

     1,303         906         2,510         2,471         965         179         8,334   
 

Taxes other than income

     1,983         58         971         1,815         2,333         665         7,825   
 

Related income tax

     3,191         1,501         10,715         8,119         5,357         399         29,282   
                                                                
 

Results of producing activities for consolidated subsidiaries

   $ 3,696       $ 3,726       $ 5,099       $ 6,198       $ 3,664       $ 816       $ 23,199   
                                                                
 

Proportional interest in results of producing activities of equity companies

   $ 1,885       $ —         $ 1,918       $ —         $ 4,566       $ —         $ 8,369   
                                                                

 

(1) The impact of including synthetic oil reserves and bitumen mining operations in the results of operations for 2009 was $1,447 million in revenue and $279 million in earnings. Cold Lake bitumen operations had no net impact as they had already been included in the results of operations in previous years as an oil and gas operation.

 

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Oil and Gas Exploration and Production Costs

The amounts shown for net capitalized costs of consolidated subsidiaries are $4,729 million less at year-end 2010 and $2,910 million less at year-end 2009 than the amounts reported as investments in property, plant and equipment for the Upstream in note 8. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations have been included in the capitalized costs for 2010 and 2009 in accordance with revised Financial Accounting Standards Board rules.

 

Capitalized Costs – Consolidated
  Subsidiaries

       United States     Canada/
South America
    Europe     Africa     Asia     Australia/
Oceania
    Total  
       

(millions of dollars)

 

As of December 31, 2010

             

Property (acreage) costs – Proved

  $ 8,031      $ 4,166      $ 199      $ 929      $ 1,451      $ 905      $ 15,681   
 

      – Unproved

    24,697        1,260        75        418        229        211        26,890   
                                                         

Total property costs

  $ 32,728      $ 5,426      $ 274      $ 1,347      $ 1,680      $ 1,116      $ 42,571   

Producing assets

    60,231        22,115        43,592        28,354        22,264        5,842        182,398   

Incomplete construction

    4,029        8,109        1,126        9,180        7,658        2,543        32,645   
                                                         

Total capitalized costs

  $ 96,988      $ 35,650      $ 44,992      $ 38,881      $ 31,602      $ 9,501      $ 257,614   

Accumulated depreciation and depletion

    29,199        17,561        33,484        16,318        13,412        4,217        114,191   
                                                         

Net capitalized costs for consolidated subsidiaries

  $ 67,789      $ 18,089      $ 11,508      $ 22,563      $ 18,190      $ 5,284      $ 143,423   
                                                         

Capitalized Costs – Equity Companies

                                         

As of December 31, 2010

             

Property (acreage) costs – Proved

  $ 76      $ —        $ 8      $ —        $ —        $ —        $ 84   
 

      – Unproved

    2        —          —          —          —          —          2   
                                                         

Total property costs

  $ 78      $ —        $ 8      $ —        $ —        $ —        $ 86   

Producing assets

    3,446        —          5,197        —          7,845        —          16,488   

Incomplete construction

    116        —          384        —          214        —          714   
                                                         

Total capitalized costs

  $ 3,640      $ —        $ 5,589      $ —        $ 8,059      $ —        $ 17,288   

Accumulated depreciation and depletion

    1,418        —          4,252        —          2,484        —          8,154   
                                                         

Net capitalized costs for equity companies

  $ 2,222      $ —        $ 1,337      $ —        $ 5,575      $ —        $ 9,134   
                                                         

Capitalized Costs – Consolidated Subsidiaries

                                         

As of December 31, 2009

             

Property (acreage) costs – Proved

  $ 3,225      $ 3,940      $ 204      $ 927      $ 1,257      $ 816      $ 10,369   
 

      – Unproved

    1,233        1,117        52        416        237        198        3,253   
                                                         

Total property costs

  $ 4,458      $ 5,057      $ 256      $ 1,343      $ 1,494      $ 1,014      $ 13,622   

Producing assets

    40,435        20,357        43,913        26,621        18,806        5,168        155,300   

Incomplete construction

    3,315        3,701        999        6,872        8,380        1,216        24,483   
                                                         

Total capitalized costs

  $ 48,208      $ 29,115      $ 45,168      $ 34,836      $ 28,680      $ 7,398      $ 193,405   

Accumulated depreciation and depletion

    29,934        15,707        32,236        13,919        12,527        3,673        107,996   
                                                         

Net capitalized costs for consolidated subsidiaries

  $ 18,274      $ 13,408      $ 12,932      $ 20,917      $ 16,153      $ 3,725      $ 85,409   
                                                         

Capitalized Costs – Equity Companies

                                         

As of December 31, 2009

               

Property (acreage) costs – Proved

  $ 76      $ —        $ 8      $ —        $ —        $ —        $ 84   
 

      – Unproved

    1        —          —          —          —          —          1   
                                                         

Total property costs

  $ 77      $ —        $ 8      $ —        $ —        $ —        $ 85   

Producing assets

    3,224        —          5,574        —          6,869        —          15,667   

Incomplete construction

    128        —          336        —          885        —          1,349   
                                                         

Total capitalized costs

  $ 3,429      $ —        $ 5,918      $ —        $ 7,754      $ —        $ 17,101   

Accumulated depreciation and depletion

    1,340        —          4,493        —          2,048        —          7,881   
                                                         

Net capitalized costs for equity companies

  $ 2,089      $ —        $ 1,425      $ —        $ 5,706      $ —        $ 9,220   
                                                         

 

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

 

Oil and Gas Exploration and Production Costs (continued)

 

The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2010 were $70,812 million, up $50,305 million from 2009, due primarily to the acquisition of XTO Energy Inc. 2009 costs were $20,507 million, up $4,691 million from 2008, due primarily to higher exploration and development costs as well as the inclusion in 2009 of costs incurred related to oil sands mining operations (see footnote 1 below). Total equity company costs incurred in 2010 were $914 million, down $105 million from 2009, due primarily to lower development costs.

 

Costs incurred in property acquisitions, exploration and
development activities – Consolidated Subsidiaries

   United States      Canada/
South America  (1)
     Europe      Africa      Asia      Australia/
Oceania
     Total  
     (millions of dollars)  

During 2010

                    

Property acquisition costs – Proved

   $ 21,633       $ —         $ 41       $ 3       $ 115       $ —         $ 21,792   

                                           – Unproved

     23,509         136         23         —           —           —           23,668   

Exploration costs

     690         527         550         453         545         228         2,993   

Development costs

     7,947         4,757         1,227         4,390         2,892         1,146         22,359   
                                                              

Total costs incurred for consolidated subsidiaries

   $ 53,779       $ 5,420       $ 1,841       $ 4,846       $ 3,552       $ 1,374       $ 70,812   
                                                              

Costs incurred in property acquisitions, exploration and
development activities – Equity Companies

                                                

Property acquisition costs – Proved

   $ —         $ —         $ —         $ —         $ —         $ —         $ —     

                                           – Unproved

     1         —           —           —           —           —           1   

Exploration costs

     4         —           56         —           2         —           62   

Development costs

     323         —           225         —           303         —           851   
                                                              

Total costs incurred for equity companies

   $ 328       $ —         $ 281       $ —         $ 305       $ —         $ 914   
                                                              

Costs incurred in property acquisitions, exploration and
development activities – Consolidated Subsidiaries

                                                

During 2009

                    

Property acquisition costs – Proved

   $ 17       $ —         $ —         $ 600       $ 59       $ —         $ 676   

                                           – Unproved

     188         353         1         5         62         —           609   

Exploration costs

     548         498         471         880         529         130         3,056   

Development costs

     2,482         2,394         3,384         4,596         2,542         768         16,166   
                                                              

Total costs incurred for consolidated subsidiaries

   $ 3,235       $ 3,245       $ 3,856       $ 6,081       $ 3,192       $ 898       $ 20,507   
                                                              

Costs incurred in property acquisitions, exploration and
development activities – Equity Companies

                                                

Property acquisition costs – Proved

   $ —         $ —         $ —         $ —         $ —         $ —         $ —     

                                           – Unproved

     —           —           —           —           —           —           —     

Exploration costs

     1         —           54         —           —           —           55   

Development costs

     305         —           255         —           404         —           964   
                                                              

Total costs incurred for equity companies

   $ 306       $ —         $ 309       $ —         $ 404       $ —         $ 1,019   
                                                              

During 2008

                    

Property acquisition costs – Proved

   $ —         $ 1       $ —         $ —         $ 60       $ —         $ 61   

                                           – Unproved

     281         125         25         82         13         76         602   

Exploration costs

     453         306         389         686         307         100         2,241   

Development costs

     2,255         907         1,634         4,783         2,890         443         12,912   
                                                              

Total costs incurred for consolidated subsidiaries

   $ 2,989       $ 1,339       $ 2,048       $ 5,551       $ 3,270       $ 619       $ 15,816   
                                                              

Proportional interest of costs incurred of equity companies

   $ 484       $ —         $ 241       $ —         $ 494       $ —         $ 1,219   
                                                              

 

(1) Costs incurred on synthetic oil reserves and bitumen mining operations in 2009 were $1,872 million, primarily on unproved property acquisition and development costs. Cold Lake bitumen operations had been included in costs incurred in previous years as an oil and gas operation.

 

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Oil and Gas Reserves

The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2008, 2009 and 2010.

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

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

In accordance with the Securities and Exchange Commission’s rules, the year-end reserves volumes for 2009 and 2010 as well as the reserves change categories for 2009 and 2010 shown in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. The year-end reserves volumes for 2008 as well as the reserves change categories for 2008 shown in the following tables were calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow.

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

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

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

Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves that we report for these types of arrangements typically vary inversely with oil and gas price changes. As oil and gas prices increase, the cash flow and value received by the company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2010 that were associated with production sharing contract arrangements was 16 percent of liquids, 10 percent of natural gas and 13 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).

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

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

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

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

Major changes between 2009 year-end proved reserves and 2010 year-end proved reserves included the initial booking of the properties acquired in the XTO Energy Inc. transaction.

 

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

 

Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves

 

 

 

      Crude Oil and Natural Gas Liquids     Bitumen     Synthetic Oil        
     United
States
    Canada/
S.  Amer.(1)
    Europe     Africa     Asia     Australia/
Oceania
    Total     Canada/
S.  Amer(2)
    Canada/
S. Amer.(3)
    Total  
     (millions of barrels)  

Net proved developed and undeveloped reserves of consolidated subsidiaries

                    

January 1, 2008

     1,851        939        673        2,058        2,010        213        7,744         

Revisions

     (104     (70     39        253        351        2        471         

Improved recovery

     —          —          —          —          —          —          —           

Purchases

     —          —          —          —          —          —          —           

Sales

     (4     (2     (28     —          (52     —          (86      

Extensions/discoveries

     5        29        4        65        28        40        171         

Production

     (104     (84     (155     (239     (118     (24     (724      
                                                              

December 31, 2008

     1,644        812        533        2,137        2,219        231        7,576         
                                                              

Proportional interest in proved reserves of equity companies

                    

End of year 2008

     327        —          27        —          2,205        —          2,559         
                                                              

Net proved developed and undeveloped reserves of consolidated subsidiaries

                    

January 1, 2009

     1,644        812        533        2,137        2,219        231        7,576        —          —          7,576   

Revisions

     82        (610 )(4)      93        (33     (130     9        (589     2,099 (4)      715        2,225   

Improved recovery

     —          —          —          —          —          —          —          —          —          —     

Purchases

     —          —          —          —          —          —          —          —          —          —     

Sales

     (1     —          (2     —          —          —          (3     —          —          (3

Extensions/discoveries

     3        —          —          53        15        71        142        —          —          142   

Production

     (112     (30     (137     (250     (105     (23     (657     (44     (24     (725
                                                                                

December 31, 2009

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

Proportional interest in proved reserves of equity companies

                    

January 1, 2009

     327        —          27        —          2,205        —          2,559        —          —          2,559   

Revisions

     56        —          5        —          (54     —          7        —          —          7   

Improved recovery

     —          —          —          —          15        —          15        —          —          15   

Purchases

     —          —          —          —          —          —          —          —          —          —     

Sales

     —          —          —          —          —          —          —          —          —          —     

Extensions/discoveries

     —          —          —          —          —          —          —          —          —          —     

Production

     (27     —          (2     —          (116     —          (145     —          —          (145
                                                                                

December 31, 2009

     356        —          30        —          2,050        —          2,436        —          —          2,436   
                                                                                

Total liquids proved reserves at December 31, 2009

     1,972        172        517        1,907        4,049        288        8,905        2,055        691        11,651   
                                                                                

 

(1) Includes total proved reserves attributable to Imperial Oil Limited of 694 million barrels in 2008, 63 million barrels in 2009 and 57 million barrels in 2010, as well as proved developed reserves of 488 million barrels in 2008, 62 million barrels in 2009 and 56 million barrels in 2010, and in addition, proved undeveloped reserves of 1 million barrels in 2009 and 1 million barrels in 2010, in which there is a 30.4 percent noncontrolling interest.
(2) Includes total proved reserves attributable to Imperial Oil Limited of 1,661 million barrels in 2009 and 1,715 million barrels in 2010, as well as proved developed reserves of 468 million barrels in 2009 and 519 million barrels in 2010, and in addition, proved undeveloped reserves of 1,193 million barrels in 2009 and 1,196 million barrels in 2010, in which there is a 30.4 percent noncontrolling interest.
(3) Includes total proved reserves attributable to Imperial Oil Limited of 691 million barrels in 2009 and 681 million barrels in 2010, as well as proved developed reserves of 691 million barrels in 2009 and 681 million barrels in 2010, in which there is a 30.4 percent noncontrolling interest.
(4) Total proved reserves of 630 million barrels at December 31, 2008, associated with the Cold Lake field in Canada are reported as bitumen reserves under the amended Securities and Exchange Commission’s Rule 4-10 of Regulation S-X.

 

108


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Index to Financial Statements

Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves (continued)

 

 

 

      Crude Oil and Natural Gas Liquids     Bitumen     Synthetic Oil        
      United
States
    Canada/
S.  Amer.(1)
    Europe     Africa     Asia     Australia/
Oceania
    Total     Canada/
S.  Amer.(2)
    Canada/
S.  Amer.(3)
    Total  
     (millions of barrels)  

Net proved developed and undeveloped reserves of consolidated subsidiaries

                    

January 1, 2010

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

Revisions

     57        10        53        89        49        7        265        89        14        368   

Improved recovery

     4        —          —          —          —          1        5        —          —          5   

Purchases

     374        —          —          —          4        —          378        —          —          378   

Sales

     (19     —          —          (2     —          —          (21     —          —          (21

Extensions/discoveries

     43        11        4        34        90        —          182        —          —          182   

Production

     (123     (30     (121     (229     (119     (21     (643     (42     (24     (709
                                                                                

December 31, 2010

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

Proportional interest in proved reserves of equity companies

                    

January 1, 2010

     356        —          30        —          2,050        —          2,436        —          —          2,436   

Revisions

     17        —          3        —          (30     —          (10     —          —          (10

Improved recovery

     —          —          —          —          —          —          —          —          —          —     

Purchases

     —          —          —          —          —          —          —          —          —          —     

Sales

     —          —          —          —          —          —          —          —          —          —     

Extensions/discoveries

     3        —          —          —          —          —          3        —          —          3   

Production

     (25     —          (2     —          (147     —          (174     —          —          (174
                                                                                

December 31, 2010

     351        —          31        —          1,873        —          2,255        —          —          2,255   
                                                                                

Total liquids proved reserves at December 31, 2010

     2,303        163        454        1,799        3,896        275        8,890        2,102        681        11,673   
                                                                                

(See footnotes on previous page)

 

109


Table of Contents
Index to Financial Statements

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

 

Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves (continued)

 

 

 

 

     Crude Oil and Natural Gas Liquids      Bitumen      Synthetic Oil         
     United
States
     Canada/
S.  Amer.(1)
     Europe      Africa      Asia      Australia/
Oceania
     Total      Canada/
S.  Amer.(2)
     Canada/
S. Amer.(3)
     Total  
     (millions of barrels)  

Proved developed reserves, as of January 1, 2008

                             

Consolidated subsidiaries

     1,327         682         518         1,202         1,033         185         4,947            

Equity companies

     299         —           8         —           1,181         —           1,488            

Proved developed reserves, as of December 31, 2008

                             

Consolidated subsidiaries

     1,257         580         410         1,284         1,097         165         4,793            

Equity companies

     264         —           9         —           1,417         —           1,690            

Proved developed reserves, as of December 31, 2009

                             

Consolidated subsidiaries

     1,211         152         376         1,122         1,268         153         4,282         468         691         5,441   

Equity companies

     279         —           10         —           1,608         —           1,897         —           —           1,897   

Proved undeveloped reserves, as of December 31, 2009

                             

Consolidated subsidiaries

     405         20         111         785         731         135         2,187         1,587         —           3,774   

Equity companies

     77         —           20         —           442         —           539         —           —           539   
                                                                                         

Total liquids proved reserves at December 31, 2009

     1,972         172         517         1,907         4,049         288         8,905         2,055         691         11,651   
                                                                                         

Proved developed reserves, as of December 31, 2010

                             

Consolidated subsidiaries

     1,478         133         361         1,055         1,306         139         4,472         519         681         5,672   

Equity companies

     271         —           21         —           1,623         —           1,915         —           —           1,915   

Proved undeveloped reserves, as of December 31, 2010

                             

Consolidated subsidiaries

     474         30         62         744         717         136         2,163         1,583         —           3,746   

Equity companies

     80         —           10         —           250         —           340         —           —           340   
                                                                                         

Total liquids proved reserves at December 31, 2010

     2,303         163         454         1,799         3,896         275         8,890         2,102         681         11,673   
                                                                                         

(See footnotes on page 108)

 

110


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Index to Financial Statements

Natural Gas and Oil-Equivalent Proved Reserves

 

 

 

     Natural Gas     Oil-Equivalent  
   United
States
    Canada/
S.  Amer.(1)
    Europe     Africa     Asia     Australia/
Oceania
    Total     Total All Products(2)  
     (billions of cubic feet)     (millions of
oil-equivalent barrels)
 

Net proved developed and undeveloped reserves of consolidated subsidiaries

                

January 1, 2008

     13,172        1,559        6,512        1,006        8,604        1,757        32,610     

Revisions

     (1,056     88        (193     (55     1,855        (4     635     

Improved recovery

     —          —          —          —          —          —          —       

Purchases

     —          —          —          —          —          —          —       

Sales

     (12     (17     (8     —          (24     —          (61  

Extensions/discoveries

     229        16        10        12        7        412        686     

Production

     (555     (263     (876     (45     (585     (144     (2,468  
                                                          

December 31, 2008

     11,778        1,383        5,445        918        9,857        2,021        31,402     

Proportional interest in proved reserves of equity companies

                

End of year 2008

     112        —          11,839        —          22,526        —          34,477     

Net proved developed and undeveloped reserves of consolidated subsidiaries

                

January 1, 2009

     11,778        1,383        5,445        918        9,857        2,021        31,402        12,810   

Revisions

     320        248        79        45        (980     40        (248     2,183   

Improved recovery

     —          —          —          —          —          —          —          —     

Purchases

     8        —          —          —          —          —          8        1   

Sales

     (10     (2     (1     —          —          —          (13     (5

Extensions/discoveries

     158        —          —          —          11        5,507        5,676        1,088   

Production

     (566     (261     (800     (43     (585     (128     (2,383     (1,122
                                                                

December 31, 2009

     11,688        1,368        4,723        920        8,303        7,440        34,442        14,955   
                                                                

Proportional interest in proved reserves of equity companies

                

January 1, 2009

     112        —          11,839        —          22,526        —          34,477        8,305   

Revisions

     8        —          186        —          189        —          383        71   

Improved recovery

     —          —          —          —          —          —          —          15   

Purchases

     —          —          —          —          —          —          —          —     

Sales

     —          —          —          —          —          —          —          —     

Extensions/discoveries

     —          —          18        —          —          —          18        3   

Production

     (6     —          (593     —          (714     —          (1,313     (364
                                                                

December 31, 2009

     114        —          11,450        —          22,001        —          33,565        8,030   
                                                                

Total proved reserves at December 31, 2009

     11,802        1,368        16,173        920        30,304        7,440        68,007        22,985   
                                                                

 

(1) Includes total proved reserves attributable to Imperial Oil Limited of 593 billion cubic feet in 2008, 590 billion cubic feet in 2009 and 576 billion cubic feet in 2010, as well as proved developed reserves of 513 billion cubic feet in 2008, 526 billion cubic feet in 2009 and 507 billion cubic feet in 2010, and in addition, proved undeveloped reserves of 64 billion cubic feet in 2009 and 69 billion cubic feet in 2010, in which there is a 30.4 percent noncontrolling interest.
(2) Natural gas is converted to oil-equivalent basis at six million cubic feet per one thousand barrels.

 

111


Table of Contents
Index to Financial Statements

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

 

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

 

     Natural Gas     Oil-Equivalent  
     United
States
    Canada/
S.  Amer.(1)
    Europe     Africa     Asia     Australia/
Oceania
    Total     Total All Products(2)  
     (billions of cubic feet)     (millions of
oil-equivalent barrels)
 

Net proved developed and undeveloped reserves of consolidated subsidiaries

                

January 1, 2010

     11,688        1,368        4,723        920        8,303        7,440        34,442        14,955   

Revisions

     832        123        (26     6        (333     42        644        475   

Improved recovery

     —          —          —          —          —          —          —          5   

Purchases

     12,774        —          15        —          —          —          12,789        2,510   

Sales

     (104     (2     —          —          —          —          (106     (38

Extensions/discoveries

     1,861        3        49        25        25        1        1,964        509   

Production

     (1,057     (234     (719     (43     (735     (132     (2,920     (1,196
                                                                

December 31, 2010

     25,994        1,258        4,042        908        7,260        7,351        46,813        17,220   
                                                                

Proportional interest in proved reserves of equity companies

                

January 1, 2010

     114        —          11,450        —          22,001        —          33,565        8,030   

Revisions

     8        —          (4     —          231        —          235        30   

Improved recovery

     —          —          —          —          —          —          —          —     

Purchases

     —          —          —          —          —          —          —          —     

Sales

     —          —          —          —          —          —          —          —     

Extensions/discoveries

     —          —          24        —          —          —          24        7   

Production

     (5     —          (724     —          (1,093     —          (1,822     (478
                                                                

December 31, 2010

     117        —          10,746        —          21,139        —          32,002        7,589   
                                                                

Total proved reserves at December 31, 2010

     26,111        1,258        14,788        908        28,399        7,351        78,815        24,809   
                                                                

(See footnotes on previous page)

 

112


Table of Contents
Index to Financial Statements

Natural Gas and Oil-Equivalent Proved Reserves (continued)

 

 

 

     Natural Gas      Oil-Equivalent  
     United
States
     Canada/
S.  Amer.(1)
     Europe      Africa      Asia      Australia/
Oceania
     Total      Total All Products(2)  
    

(billions of cubic feet)

     (millions of
oil-equivalent barrels)
 

Proved developed reserves, as of January 1, 2008

                       

Consolidated subsidiaries

     8,373         1,303         5,064         773         4,562         1,403         21,478      

Equity companies

     104         —           9,679         —           9,459         —           19,242      

Proved developed reserves, as of December 31, 2008

                       

Consolidated subsidiaries

     7,835         1,148         4,426         738         5,257         1,346         20,750      

Equity companies

     96         —           9,284         —           12,619         —           21,999      

Proved developed reserves, as of December 31, 2009

                       

Consolidated subsidiaries

     7,492         1,200         3,920         739         7,407         1,262         22,020         9,111   

Equity companies

     90         —           8,862         —           17,799         —           26,751         6,356   

Proved undeveloped reserves, as of December 31, 2009

                       

Consolidated subsidiaries

     4,196         168         803         181         896         6,178         12,422         5,844   

Equity companies

     24         —           2,588         —           4,202         —           6,814         1,674   
                                                                       

Total proved reserves at December 31, 2009

     11,802         1,368         16,173         920         30,304         7,440         68,007         22,985   
                                                                       

Proved developed reserves, as of December 31, 2010

                       

Consolidated subsidiaries

     15,344         1,077         3,516         711         6,593         1,174         28,415         10,408   

Equity companies

     97         —           8,167         —           20,494         —           28,758         6,708   

Proved undeveloped reserves, as of December 31, 2010

                       

Consolidated subsidiaries

     10,650         181         526         197         667         6,177         18,398         6,812   

Equity companies

     20         —           2,579         —           645         —           3,244         881   
                                                                       

Total proved reserves at December 31, 2010

     26,111         1,258         14,788         908         28,399         7,351         78,815         24,809   
                                                                       

(See footnotes on page 111)

 

113


Table of Contents
Index to Financial Statements

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

 

Standardized Measure of Discounted Future Cash Flows

As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows was computed through 2008 by applying year-end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. Beginning in 2009, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

 

Standardized Measure

of Discounted Future Cash Flows

   United
States
     Canada/
South  America(1)
    Europe      Africa      Asia      Australia/
Oceania
     Total  
     (millions of dollars)  

Consolidated Subsidiaries

                   

As of December 31, 2008

                   

Future cash inflows from sales of oil and gas

   $ 104,441       $ 22,952      $ 71,879       $ 74,426       $ 80,314       $ 10,437       $ 364,449   

Future production costs

     44,230         13,113        19,485         24,403         22,826         5,334         129,391   

Future development costs

     19,828         6,156        8,765         16,064         11,496         2,134         64,443   

Future income tax expenses

     17,857         961        24,729         16,870         26,218         917         87,552   
                                                             

Future net cash flows

   $ 22,526       $ 2,722      $ 18,900       $ 17,089       $ 19,774       $ 2,052       $ 83,063   

Effect of discounting net cash flows at 10%

     13,107         (239     7,602         8,052         13,031         941         42,494   
                                                             

Discounted future net cash flows

   $ 9,419       $ 2,961      $ 11,298       $ 9,037       $ 6,743       $ 1,111       $ 40,569   
                                                             

Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies

   $ 2,354       $ —        $ 12,507       $ —         $ 30,588       $ —         $ 45,449   
                                                             

Consolidated Subsidiaries

                   

As of December 31, 2009

                   

Future cash inflows from sales of oil and gas

   $ 112,408       $ 147,597      $ 54,074       $ 110,475       $ 121,110       $ 39,127       $ 584,791   

Future production costs

     47,660         62,241        16,412         28,679         29,769         12,571         197,332   

Future development costs

     15,544         25,738        12,565         15,155         10,256         11,655         90,913   

Future income tax expenses

     22,058         14,572        16,065         32,784         46,286         4,739         136,504   
                                                             

Future net cash flows

   $ 27,146       $ 45,046      $ 9,032       $ 33,857       $ 34,799       $ 10,162       $ 160,042   

Effect of discounting net cash flows at 10%

     15,563         31,980        2,569         14,192         20,698         9,194         94,196   
                                                             

Discounted future net cash flows

   $ 11,583       $ 13,066      $ 6,463       $ 19,665       $ 14,101       $ 968       $ 65,846   
                                                             

Equity Companies

                   

As of December 31, 2009

                   

Future cash inflows from sales of oil and gas

   $ 19,705       $ —        $ 94,401       $ —         $ 180,253       $ —         $ 294,359   

Future production costs

     5,847         —          60,869         —           54,493         —           121,209   

Future development costs

     2,862         —          3,220         —           2,759         —           8,841   

Future income tax expenses

     —           —          12,003         —           44,733         —           56,736   
                                                             

Future net cash flows

   $ 10,996       $ —        $ 18,309       $ —         $ 78,268       $ —         $ 107,573   

Effect of discounting net cash flows at 10%

     6,332         —          9,845         —           42,086         —           58,263   
                                                             

Discounted future net cash flows

   $ 4,664       $ —        $ 8,464       $ —         $ 36,182       $ —         $ 49,310   
                                                             

Total consolidated and equity interests in standardized measure of discounted future net cash flows

   $ 16,247       $ 13,066      $ 14,927       $ 19,665       $ 50,283       $ 968       $ 115,156   
                                                             

 

(1) Includes discounted future net cash flows attributable to Imperial Oil Limited of $1,033 million in 2008 and $10,088 million in 2009, in which there is a 30.4 percent noncontrolling interest.

 

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Standardized Measure

of Discounted Future Cash Flows (continued)

   United
States
     Canada/
South  America(1)
     Europe      Africa      Asia      Australia/
Oceania
     Total  
     (millions of dollars)  

Consolidated Subsidiaries

                    

As of December 31, 2010

                    

Future cash inflows from sales of oil and gas

   $ 221,298       $ 184,671       $ 60,086       $ 137,476       $ 156,337       $ 55,087       $ 814,955   

Future production costs

     76,992         69,765         15,246         31,189         36,318         16,347         245,857   

Future development costs

     28,905         22,130         12,155         15,170         13,716         11,652         103,728   

Future income tax expenses

     44,128         21,798         21,736         46,145         59,477         9,591         202,875   
                                                              

Future net cash flows

   $ 71,273       $ 70,978       $ 10,949       $ 44,972       $ 46,826       $ 17,497       $ 262,495   

Effect of discounting net cash flows at 10%

     39,545         45,607         2,765         18,046         28,883         13,411         148,257   
                                                              

Discounted future net cash flows

   $ 31,728       $ 25,371       $ 8,184       $ 26,926       $ 17,943       $ 4,086       $ 114,238   
                                                              

Equity Companies

                    

As of December 31, 2010

                    

Future cash inflows from sales of oil and gas

   $ 26,110       $       $ 73,222       $       $ 232,334       $       $ 331,666   

Future production costs

     6,369                 49,010                 73,508                 128,887   

Future development costs

     2,883                 2,719                 2,523                 8,125   

Future income tax expenses

                     8,348                 57,041                 65,389   
                                                              

Future net cash flows

   $ 16,858       $       $ 13,145       $       $ 99,262       $       $ 129,265   

Effect of discounting net cash flows at 10%

     9,612                 6,857                 51,512                 67,981   
                                                              

Discounted future net cash flows

   $ 7,246       $       $ 6,288       $       $ 47,750       $       $ 61,284   
                                                              

Total consolidated and equity interests in standardized measure of discounted future net cash flows

   $ 38,974       $ 25,371       $ 14,472       $ 26,926       $ 65,693       $ 4,086       $ 175,522   
                                                              

 

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

 

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

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

 

Consolidated Subsidiaries

   2008  
     (millions of dollars)  

Discounted future net cash flows as of December 31, 2007

   $ 126,173   

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs

     (303

Changes in value of previous-year reserves due to:

  

Sales and transfers of oil and gas produced during the year, net of production (lifting) costs

     (62,685

Development costs incurred during the year

     11,649   

Net change in prices, lifting and development costs

     (178,960

Revisions of previous reserves estimates

     7,652   

Accretion of discount

     21,463   

Net change in income taxes

     115,580   
        

Total change in the standardized measure during the year for consolidated subsidiaries

   $ (85,604

Discounted future net cash flows as of December 31, 2008

   $ 40,569   
        

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

 

Consolidated and Equity Interests

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

Discounted future net cash flows as of December 31, 2008

   $ 40,569      $ 45,449      $ 86,018   

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs

     2,138        280        2,418   

Changes in value of previous-year reserves due to:

      

Sales and transfers of oil and gas produced during the year, net of production (lifting) costs

     (35,384     (10,288     (45,672

Development costs incurred during the year

     13,549        1,017        14,566   

Net change in prices, lifting and development costs

     51,627        9,245        60,872   

Revisions of previous reserves estimates

     8,805        858        9,663   

Accretion of discount

     6,943        5,214        12,157   

Net change in income taxes

     (22,401     (2,465     (24,866
                        

Total change in the standardized measure during the year

   $ 25,277      $ 3,861      $ 29,138 (1)(2) 

Discounted future net cash flows as of December 31, 2009

   $ 65,846      $ 49,310      $ 115,156   
                        

 

(1) Discounted future net cash flows associated with synthetic oil reserves and bitumen mining operations in 2009 were $5,268 million. Cold Lake bitumen operations had been included in discounted future net cash flows in previous years as an oil and gas operation.
(2) The estimated impact of adopting the reliable technology definition and changing from year-end price to first-day-of-the-month average prices in the Securities and Exchange Commission’s Rule 4-10 of Regulation S-X was de minimis on discounted future net cash flows for consolidated and equity subsidiaries in 2009.

 

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

 

Consolidated and Equity Interests (continued)

 

     2010  
     Consolidated
Subsidiaries
    Share of
Equity Method
Investees
    Total
Consolidated
and Equity
Interests
 
    

(millions of dollars)

 

Discounted future net cash flows as of December 31, 2009

   $ 65,846      $ 49,310      $ 115,156   

Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs

     20,093        210        20,303   

Changes in value of previous-year reserves due to:

      

Sales and transfers of oil and gas produced during the year, net of production (lifting) costs

     (46,078     (16,050     (62,128

Development costs incurred during the year

     20,975        843        21,818   

Net change in prices, lifting and development costs

     61,612        23,135        84,747   

Revisions of previous reserves estimates

     14,770        3,605        18,375   

Accretion of discount

     10,399        5,775        16,174   

Net change in income taxes

     (33,379     (5,544     (38,923
                        

Total change in the standardized measure during the year

   $ 48,392      $ 11,974      $ 60,366   

Discounted future net cash flows as of December 31, 2010

   $ 114,238      $ 61,284      $ 175,522   
                        

 

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OPERATING SUMMARY (unaudited)

 

     2010      2009      2008      2007      2006  
     (thousands of barrels daily)  

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

              

Net production

              

United States

     408         384         367         392         414   

Canada/South America

     263         267         292         324         354   

Europe

     335         379         428         480         520   

Africa

     628         685         652         717         781   

Asia

     730         607         599         629         535   

Australia/Oceania

     58         65         67         74         77   
                                            

Worldwide

     2,422         2,387         2,405         2,616         2,681   
                                            
    

(millions of cubic feet daily)

 

Natural gas production available for sale

              

Net production

              

United States

     2,596         1,275         1,246         1,468         1,625   

Canada/South America

     569         643         640         808         935   

Europe

     3,836         3,689         3,949         3,810         4,086   

Africa

     14         19         32         26           

Asia

     4,801         3,332         2,870         2,883         2,358   

Australia/Oceania

     332         315         358         389         330   
                                            

Worldwide

     12,148         9,273         9,095         9,384         9,334   
                                            
    

(thousands of oil-equivalent barrels daily)

 

Oil-equivalent production (1)

     4,447         3,932         3,921         4,180         4,237   
                                            
    

(thousands of barrels daily)

 

Refinery throughput

              

United States

     1,753         1,767         1,702         1,746         1,760   

Canada

     444         413         446         442         442   

Europe

     1,538         1,548         1,601         1,642         1,672   

Asia Pacific

     1,249         1,328         1,352         1,416         1,434   

Other Non-U.S.

     269         294         315         325         295   
                                            

Worldwide

     5,253         5,350         5,416         5,571         5,603   
                                            

Petroleum product sales (2)

              

United States

     2,511         2,523         2,540         2,717         2,729   

Canada

     450         413         444         461         473   

Europe

     1,611         1,625         1,712         1,773         1,813   

Asia Pacific and other Eastern Hemisphere

     1,562         1,588         1,646         1,701         1,763   

Latin America

     280         279         419         447         469   
                                            

Worldwide

     6,414         6,428         6,761         7,099         7,247   
                                            

Gasoline, naphthas

     2,611         2,573         2,654         2,850         2,866   

Heating oils, kerosene, diesel oils

     1,951         2,013         2,096         2,094         2,191   

Aviation fuels

     476         536         607         641         651   

Heavy fuels

     603         598         636         715         682   

Specialty petroleum products

     773         708         768         799         857   
                                            

Worldwide

     6,414         6,428         6,761         7,099         7,247   
                                            
     (thousands of metric tons)  

Chemical prime product sales

              

United States

     9,815         9,649         9,526         10,855         10,703   

Non-U.S.

     16,076         15,176         15,456         16,625         16,647   
                                            

Worldwide

     25,891         24,825         24,982         27,480         27,350   
                                            

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

 

(1) Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels.
(2) Petroleum product sales data reported net of purchases/sales contracts with the same counterparty.

 

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SIGNATURES

 

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

 

EXXON MOBIL CORPORATION

By:

 

/s/    REX W. TILLERSON

 

(Rex W. Tillerson,

Chairman of the Board)

 

Dated February 25, 2011

 

 

 

POWER OF ATTORNEY

 

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

 

 

 

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

 

/s/    REX W. TILLERSON        

(Rex W. Tillerson)

  

Chairman of the Board

(Principal Executive Officer)

  February 25, 2011

/s/    MICHAEL J. BOSKIN        

(Michael J. Boskin)

   Director   February 25, 2011

/s/    PETER BRABECK-LETMATHE

(Peter Brabeck-Letmathe)

   Director   February 25, 2011

/s/    LARRY R. FAULKNER        

(Larry R. Faulkner)

   Director   February 25, 2011

 

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/s/    JAY S. FISHMAN        

(Jay S. Fishman)

   Director   February 25, 2011

/s/    KENNETH C. FRAZIER

(Kenneth C. Frazier)

   Director   February 25, 2011

/s/    WILLIAM W. GEORGE        

(William W. George)

   Director  

February 25, 2011

  /s/    MARILYN CARLSON NELSON

(Marilyn Carlson Nelson)

   Director  

February 25, 2011

/s/    SAMUEL J. PALMISANO        

(Samuel J. Palmisano)

   Director  

February 25, 2011

/s/    STEVEN S REINEMUND

(Steven S Reinemund)

   Director  

February 25, 2011

/s/    EDWARD E. WHITACRE, JR.

(Edward E. Whitacre, Jr.)

   Director  

February 25, 2011

/s/    DONALD D. HUMPHREYS        

(Donald D. Humphreys)

   Treasurer
(Principal Financial Officer)
 

February 25, 2011

/s/    PATRICK T. MULVA        

(Patrick T. Mulva)

   Controller
(Principal Accounting Officer)
 

February 25, 2011

 

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Index to Financial Statements

INDEX TO EXHIBITS

 

3(i)   

Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).

  
3(ii)   

By-Laws, as revised to July 31, 2002 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).

  
10(iii)(a.1)   

2003 Incentive Program (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008).*

  
10(iii)(a.2)   

Form of stock option granted to executive officers (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrant’s Annual Report on Form 10-K for 2009).*

  
10(iii)(a.3)   

Form of restricted stock agreement with executive officers (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K on November 30, 2010).*

  
10(iii)(b.1)   

Short Term Incentive Program, as amended (incorporated by reference to Exhibit 99.3 to the Registrant’s Report on Form 8-K on December 1, 2009).*

  
10(iii)(b.2)   

Form of Earnings Bonus Unit granted to executive officers (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on November 30, 2010).*

  
10(iii)(c.1)   

ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on November 2, 2007).*

  
10(iii)(c.2)   

ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant’s Report on Form 8-K on October 12, 2006).*

  
10(iii)(c.3)   

ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Report on Form 8-K on October 12, 2006).*

  
10(iii)(d)   

ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).*

  
10(iii)(f.1)   

2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).*

  
10(iii)(f.2)   

Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K on September 27, 2007).*

  
10(iii)(f.3)   

Form of restricted stock grant letter for non-employee directors (incorporated by reference to Exhibit 10(iii)(f.3) to the Registrant’s Annual Report on Form 10-K for 2009).*

  
10(iii)(f.4)   

Standing resolution for non-employee director cash fees dated September 28, 2009 (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on October 28, 2009).*

  
10(iii)(f.5)   

Extended Provisions for Restricted Stock Unit Agreements-Settlement in Shares.*

  

 

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INDEX TO EXHIBITS—(continued)

 

 

10(iii)(g.3)   

1984 Mobil Compensation Management Retention Plan, as amended and restated on September 27, 2007 (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on September 27, 2007).*

  
12   

Computation of ratio of earnings to fixed charges.

  
14   

Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2008).

  
21   

Subsidiaries of the registrant.

  
23   

Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

  

31.1

  

Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.

  

31.2

  

Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Financial Officer.

  

31.3

  

Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.

  

32.1

  

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.

  

32.2

  

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Financial Officer.

  

32.3

  

Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.

  

101

  

Interactive data files.

  

 

 

*   Compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K.

 

The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request.

 

122