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  • 10-K (Feb 25, 2011)
  • 10-K (Feb 26, 2010)

 
Quarterly Reports

 
8-K

 
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Exxon Mobil 10-K 2010
Form 10-K
Table of Contents
Index to Financial Statements

2009

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

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

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

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 (4,721,273,113 shares
outstanding at January 31, 2010)

   New York Stock Exchange
Registered securities guaranteed by Registrant:   

SeaRiver Maritime Financial Holdings, Inc.

  

Twenty-Five Year Debt Securities due October 1, 2011

   New York Stock Exchange

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

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

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

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

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

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

Large accelerated filer    ü           Accelerated filer                 

Non-accelerated filer                  Smaller reporting company        

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

The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $69.91 on the New York Stock Exchange composite tape, was in excess of $335 billion.

Documents Incorporated by Reference:

    None

 

 


Table of Contents
Index to Financial Statements

EXXON MOBIL CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009

 

TABLE OF CONTENTS

 

     Page
Number
PART I
Item 1.   

Business

   1
Item 1A.   

Risk Factors

   2
Item 1B.   

Unresolved Staff Comments

   5
Item 2.   

Properties

   6
Item 3.   

Legal Proceedings

   31
Item 4.   

Submission of Matters to a Vote of Security Holders

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

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

   33
Item 6.   

Selected Financial Data

   34
Item 7.   

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

   34
Item 7A.   

Quantitative and Qualitative Disclosures About Market Risk

   34
Item 8.   

Financial Statements and Supplementary Data

   34
Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure    35
Item 9A.    Controls and Procedures    35
Item 9B.    Other Information    35
PART III
Item 10.   

Directors, Executive Officers and Corporate Governance

   36
Item 11.   

Executive Compensation

   36
Item 12.   

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

   37
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

   37
Item 14.   

Principal Accounting Fees and Services

   38
PART IV
Item 15.   

Exhibits, Financial Statement Schedules

   38

Financial Section

   39
Proxy Information Section    107
Signatures    148
Index to Exhibits    150
Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges   
Exhibits 31 and 32 — Certifications   


Table of Contents
Index to Financial Statements

PART I

 

Item 1.    Business.

 

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

 

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

 

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

 

Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to monitor and reduce nitrogen oxide, sulfur oxide, and greenhouse gas emissions and expenditures for asset retirement obligations. ExxonMobil’s 2009 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $5.1 billion, of which $2.5 billion were capital expenditures and $2.6 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2010 and 2011 (with capital expenditures approximately 45 percent of the total).

 

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

 

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

 

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

 

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Index to Financial Statements

segments. Information on Company-sponsored research and development spending is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report. ExxonMobil held approximately 11 thousand active patents worldwide at the end of 2009. For technology licensed to third parties, revenues totaled approximately $88 million in 2009. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.

 

The number of regular employees was 80.7 thousand, 79.9 thousand and 80.8 thousand at years ended 2009, 2008 and 2007, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 22.0 thousand, 24.8 thousand and 26.3 thousand at years ended 2009, 2008 and 2007, respectively.

 

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

 

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

 

Item 1A.     Risk Factors.

 

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

 

Supply and Demand.

 

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

 

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

 

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Index to Financial Statements

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

 

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

 

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

 

Government and Political Factors.

 

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

 

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

 

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

 

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

 

Regulatory and litigation risks.    Even in countries with well-developed legal systems where ExxonMobil does business, we remain exposed to changes in law (including changes that result from international treaties and accords) that could adversely affect our results, such as increases in taxes or government royalty rates (including retroactive claims); price controls; changes in environmental regulations or other laws that increase our cost of compliance; adoption of regulations mandating the use of alternative fuels or uncompetitive fuel components; government actions to cancel contracts or renegotiate terms unilaterally; and expropriation. Legal remedies available to compensate us for

 

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Index to Financial Statements

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

 

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

 

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

 

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

 

Management Effectiveness.

 

In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that are at least in part within our control. The extent to which we manage these factors will impact our performance relative to competition.

 

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

 

Project management.    The success of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled project downtime; and influence the performance of project operators where ExxonMobil does not perform that role.

 

Operational efficiency.    An important component of ExxonMobil’s competitive performance, especially given the commodity-based nature of many of our businesses, is our ability to operate

 

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Index to Financial Statements

efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements and regular reappraisal of our asset portfolio.

 

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

 

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

 

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

 

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

 

Item 1B.     Unresolved Staff Comments.

 

None.

 

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Index to Financial Statements

Item 2.    Properties.

 

Information with regard to oil and gas producing activities follows:

 

1.     Disclosure of Reserves

 

A. Summary of Oil and Gas Reserves at Year-End 2009

 

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favorable or adverse event has occurred since December 31, 2009, that would cause a significant change in the estimated proved reserves as of that date.

 

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

(million bbls)

  (million bbls)  

(billion cubic ft)

  (million bbls)

Proved Reserves

         

Developed

         

Consolidated Subsidiaries

         

United States

  1,211   —     —     7,492   2,460

Canada/South America

  152   468   691   1,200   1,511

Europe

  376   —     —     3,920   1,029

Africa

  1,122   —     —     739   1,245

Asia Pacific/Middle East

  1,335   —     —     8,351   2,727

Russia/Caspian

  86   —     —     318   139
                   

Total Consolidated

  4,282   468   691   22,020   9,111

Equity Companies

         

United States

  279   —     —     90   294

Europe

  10   —     —     8,862   1,487

Asia Pacific/Middle East

  1,053   —     —     16,978   3,883

Russia/Caspian

  555   —     —     821   692
                   

Total Equity Company

  1,897   —     —     26,751   6,356
                   

Total Developed

  6,179   468   691   48,771   15,467

Undeveloped

         

Consolidated Subsidiaries

         

United States

  405   —     —     4,196   1,104

Canada/South America

  20   1,587   —     168   1,635

Europe

  111   —     —     803   245

Africa

  785   —     —     181   815

Asia Pacific/Middle East

  311   —     —     6,665   1,422

Russia/Caspian

  555   —     —     409   623
                   

Total Consolidated

  2,187   1,587   —     12,422   5,844

Equity Companies

         

United States

  77   —     —     24   81

Europe

  20   —     —     2,588   451

Asia Pacific/Middle East

  195   —     —     3,595   794

Russia/Caspian

  247   —     —     607   348
                   

Total Equity Company

  539   —     —     6,814   1,674
                   

Total Undeveloped

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

Total Proved Reserves

  8,905   2,055   691   68,007   22,985
                   
(1)   Liquids includes crude, condensate and natural gas liquids.

 

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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 2010-2014. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, weather events, price effects on production sharing contracts and other factors as described in Item 1A—Risk Factors of this report.

 

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

 

B. Technologies Used in Establishing Proved Reserves Additions in 2009

 

Additions to ExxonMobil’s proved reserves in 2009 were based on estimates generated through the integration of available and appropriate data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

 

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

 

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

 

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

 

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

 

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

 

2.    Proved Undeveloped Reserves

 

At year-end 2009, approximately 7.5 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped, which represented 33 percent of the 23.0 GOEB reported in proved reserves. This compares to 38 percent proved undeveloped reported at the end of 2008. The net reduction from 2008 is reflective of our active development programs on many projects worldwide. This percentage is inclusive of both consolidated subsidiaries and equity company reserves. Significant progress was made in converting proved undeveloped reserves into proved developed reserves in 2009. During the year, ExxonMobil completed development work in over 100 fields and participated in numerous major project start-ups that resulted in the transfer of approximately 2.4 GOEB from proved undeveloped to proved developed reserves by year-end. This represented the movement of 28 percent of the proved undeveloped reserves into the proved developed category or an average turnover time of about four years. The largest transfers were associated with two liquefied natural gas (LNG) trains and the second phase of a domestic gas supply project in Qatar.

 

One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. Development projects typically take two to four years from the time of first recording of proved reserves to the start of production of these reserves. However, the development time for large and complex projects can exceed five years. During 2009, new approved projects added approximately 1.3 GOEB of proved undeveloped reserves. The largest of these were the Gorgon LNG project in Australia and the Papua New Guinea LNG project. Overall, investments of $12.7 billion were made by the Corporation during 2009 to progress the development of reported proved undeveloped reserves, including $11.6 billion for oil and gas producing activities and an additional $1.1 billion for other non-oil and gas producing activities such as the construction of LNG trains, tankers and regasification facilities that were undertaken to progress the development of proved undeveloped reserves. These investments represented 61 percent of the $20.7 billion in total reported Upstream capital and exploration expenditures.

 

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

 

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are in Qatar and Kazakhstan. In Qatar, the construction of the Ras Laffan 3 Train 7 LNG liquefaction train is now complete. In Kazakhstan, ExxonMobil participates in the North Caspian Production Sharing Agreement, which includes the giant Kashagan field located offshore in the Caspian Sea. Phase 1 of the Kashagan field is currently under construction and includes an offshore production and separation hub on an artificial island, several drilling islands, three onshore oil-stabilization trains, two onshore gas treatment plants and an onshore sulfur treatment plant. ExxonMobil also participates in the Tengizchevroil joint venture in Kazakhstan which includes a production license in the Tengiz field, and the nearby Korolev field. The joint venture is producing and proved undeveloped reserves will continue to move to proved developed as approved development phases progress.

 

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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.

 

     2009    2008    2007
     (thousands of barrels daily)

Crude oil and natural gas liquids production

        

Consolidated Subsidiaries

        

United States

   311    289    310

Canada/South America

   82    106    129

Europe

   374    423    474

Africa

   685    652    717

Asia Pacific/Middle East

   286    313    328

Russia/Caspian

   66    73    110
              

Total Consolidated Subsidiaries

   1,804    1,856    2,068
        

Equity Companies

        

United States

   73    78    82

Europe

   5    5    6

Asia Pacific/Middle East

   204    193    190

Russia/Caspian

   116    87    75
              

Total Equity Companies

   398    363    353
              

Total crude oil and natural gas liquids production

   2,202    2,219    2,421

Bitumen production

        

Consolidated Subsidiaries

        

Canada/South America

   120    124    130

Synthetic oil production

        

Consolidated Subsidiaries

        

Canada/South America

   65    62    65
              

Total liquids production

   2,387    2,405    2,616
              
     (millions of cubic feet daily)

Natural gas production available for sale

        

Consolidated Subsidiaries

        

United States

   1,274    1,245    1,467

Canada/South America

   643    640    808

Europe

   2,071    2,253    2,307

Africa

   19    32    26

Asia Pacific/Middle East

   1,691    1,758    1,890

Russia/Caspian

   38    37    31
              

Total Consolidated Subsidiaries

   5,736    5,965    6,529
        

Equity Companies

        

United States

   1    1    1

Europe

   1,618    1,696    1,503

Asia Pacific/Middle East

   1,803    1,356    1,272

Russia/Caspian

   115    77    79
              

Total Equity Companies

   3,537    3,130    2,855
              

Total natural gas production available for sale

   9,273    9,095    9,384
              
     (thousands of oil-equivalent
barrels daily)
        

Oil-equivalent production

   3,932    3,921    4,180
              

 

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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.

 

     United
States
   Canada/
S. America
   Europe    Africa    Asia Pacific/
Middle East
   Russia/
Caspian
   Total
                    

During 2009

                    

Consolidated Subsidiaries

                    

Average production prices

                    

Crude oil and NGL, per barrel

   $ 53.43    $ 54.07    $ 56.88    $ 60.10    $ 59.58    $ 58.42    $ 57.86

Natural gas, per thousand cubic feet

     3.10      3.19      5.61      1.70      3.08      2.11      4.00

Bitumen, per barrel

          45.22                          45.22

Synthetic oil, per barrel

          61.26                          61.26

Average production costs, per barrel - total

     11.80      17.75      10.19      8.07      6.89      7.84      10.25

Average production costs, per barrel - bitumen

          14.77                          14.77

Equity Companies

                    

Average production prices

                    

Crude oil and NGL, per barrel

     56.54           58.20           60.10      49.09      56.22

Natural gas, per thousand cubic feet

     5.75           8.20           3.94      1.41      5.81

Average production costs, per barrel - total

     18.07           2.48           0.49      3.23      2.72

Total

                    

Average production prices

                    

Crude oil and NGL, per barrel

     54.02      54.07      56.89      60.10      59.79      52.46      57.56

Natural gas, per thousand cubic feet

     3.10      3.19      6.74      1.70      3.52      1.58      4.69

Bitumen, per barrel

          45.22                          45.22

Synthetic oil, per barrel

          61.26                          61.26

Average production costs, per barrel - total

     12.57      17.75      8.06      8.07      3.88      4.83      8.36

Average production costs, per barrel - bitumen

          14.77                          14.77

During 2008

                    

Consolidated Subsidiaries

                    

Average production prices

                    

Crude oil and NGL, per barrel

   $ 87.41    $ 89.46    $ 89.65    $ 92.69    $ 92.28    $ 94.20    $ 90.96

Natural gas, per thousand cubic feet

     7.22      7.82      10.12      3.33      4.55      2.08      7.54

Bitumen, per barrel

          65.45                          65.45

Synthetic oil, per barrel

          100.35                          100.35

Average production costs, per barrel - total

     11.80      18.03      8.97      6.66      5.19      9.64      9.38

Average production costs, per barrel - bitumen

          19.55                          19.55

Equity Companies

                    

Average production prices

                    

Crude oil and NGL, per barrel

     89.94           85.08           94.21      84.14      90.80

Natural gas, per thousand cubic feet

     13.97           11.09           8.86      1.38      9.89

Average production costs, per barrel - total

     18.55           4.06           0.75      4.83      3.86

Total

                    

Average production prices

                    

Crude oil and NGL, per barrel

     87.95      89.46      89.59      92.69      93.01      89.06      90.93

Natural gas, per thousand cubic feet

     7.23      7.82      10.54      3.33      6.43      1.61      8.35

Bitumen, per barrel

          65.45                          65.45

Synthetic oil, per barrel

          100.35                          100.35

Average production costs, per barrel - total

     12.72      18.03      7.67      6.66      3.38      6.96      8.14

Average production costs, per barrel - bitumen

          19.55                          19.55

 

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     United
States
   Canada/
S. America
   Europe    Africa    Asia Pacific/
Middle East
   Russia/
Caspian
   Total

During 2007

                    

Consolidated Subsidiaries

                    

Average production prices

                    

Crude oil and NGL, per barrel

   $ 62.35    $ 64.10    $ 68.01    $ 70.00    $ 69.58    $ 69.15    $ 67.89

Natural gas, per thousand cubic feet

     5.93      5.77      6.22      2.26      3.54      1.79      5.29

Bitumen, per barrel

          36.63                          36.63

Synthetic oil, per barrel

          74.79                          74.79

Average production costs, per barrel - total

     9.03      13.17      9.12      4.48      4.09      5.79      7.58

Average production costs, per barrel - bitumen

          13.26                          13.26

Equity Companies

                    

Average production prices

                    

Crude oil and NGL, per barrel

     64.79           73.23           71.91      63.60      68.51

Natural gas, per thousand cubic feet

     10.44           8.52           5.76      0.90      7.08

Average production costs, per barrel - total

     14.95           4.10           0.58      4.34      3.49

Total

                    

Average production prices

                    

Crude oil and NGL, per barrel

     62.86      64.10      68.08      70.00      70.44      66.89      67.98

Natural gas, per thousand cubic feet

     5.93      5.77      7.13      2.26      4.43      1.15      5.83

Bitumen, per barrel

          36.63                          36.63

Synthetic oil, per barrel

          74.79                          74.79

Average production costs, per barrel - total

     9.80      13.17      7.97      4.48      2.74      5.16      6.77

Average production costs, per barrel - bitumen

          13.26                          13.26

 

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

 

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4.    Drilling and Other Exploratory and Development Activities

 

A. Number of Net Productive and Dry Wells Drilled

 

     2009    2008    2007

Net Productive Exploratory Wells Drilled

        

Consolidated Subsidiaries

        

United States

   10    10    12

Canada/South America

   4       1

Europe

   2    3   

Africa

   2    3    2

Asia Pacific/Middle East

   1    2    1

Russia/Caspian

         1
              

Total Consolidated Subsidiaries

   19    18    17

Equity Companies

        

United States

        

Europe

   1    1    2

Asia Pacific/Middle East

        

Russia/Caspian

        
              

Total Equity Companies

   1    1    2
              

Total productive exploratory wells drilled

   20    19    19

Net Dry Exploratory Wells Drilled

        

Consolidated Subsidiaries

        

United States

   1    3    8

Canada/South America

         1

Europe

   4    2    2

Africa

   3    2    4

Asia Pacific/Middle East

   1    1    1

Russia/Caspian

        
              

Total Consolidated Subsidiaries

   9    8    16

Equity Companies

        

United States

        

Europe

        

Asia Pacific/Middle East

      1   

Russia/Caspian

        
              

Total Equity Companies

      1   
              

Total dry exploratory wells drilled

   9    9    16

 

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     2009    2008    2007

Net Productive Development Wells Drilled

        

Consolidated Subsidiaries

        

United States

   165    105    118

Canada/South America

   291    223    377

Europe

   10    8    15

Africa

   45    39    43

Asia Pacific/Middle East

   13    14    18

Russia/Caspian

   3    5    3
              

Total Consolidated Subsidiaries

   527    394    574

Equity Companies

        

United States

   287    321    333

Europe

   1    2    1

Asia Pacific/Middle East

   14    14    8

Russia/Caspian

         1
              

Total Equity Companies

   302    337    343
              

Total productive development wells drilled

   829    731    917

Net Dry Development Wells Drilled

        

Consolidated Subsidiaries

        

United States

   3    3    15

Canada/South America

      1   

Europe

   1       3

Africa

         1

Asia Pacific/Middle East

   1      

Russia/Caspian

        
              

Total Consolidated Subsidiaries

   5    4    19

Equity Companies

        

United States

        

Europe

        

Asia Pacific/Middle East

        

Russia/Caspian

        
              

Total Equity Companies

        
              

Total dry development wells drilled

   5    4    19
              

Total number of net wells drilled

   863    763    971
              

 

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

 

Kearl Project

 

The Kearl oil sands project is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada.

 

Kearl is expected to be developed in phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a blend of bitumen and diluent, is planned to be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline.

 

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

 

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

 

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5.    Present Activities

 

A. Wells Drilling

 

     Year-end
2009
   Year-end
2008
     Gross    Net    Gross    Net

Wells Drilling

           

Consolidated Subsidiaries

           

United States

   185    146    201    136

Canada/South America

   83    57    297    173

Europe

   20    4    27    7

Africa

   24    8    19    7

Asia Pacific/Middle East

   6    3    5    2

Russia/Caspian

   18    3    25    4
                   

Total Consolidated Subsidiaries

   336    221    574    329

Equity Companies

           

United States

   10    5    2    1

Europe

   16    5    1   

Asia Pacific/Middle East

   5       17    9

Russia/Caspian

           
                   

Total Equity Companies

   31    10    20    10
                   

Total gross and net wells drilling

   367    231    594    339
                   

 

B. Review of Principal Ongoing Activities

 

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

 

UNITED STATES

 

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

 

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

 

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

 

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

 

 

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CANADA / SOUTH AMERICA

 

Canada

 

Oil and Gas Operations

 

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

 

In Situ Bitumen Operations

 

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

 

Argentina

 

ExxonMobil’s net acreage totaled 0.2 million onshore acres at year-end 2009, and there were 1.8 net development wells completed during the year.

 

Venezuela

 

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

 

EUROPE

 

Germany

 

A total of 4.9 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2009, with 3.6 net exploration and development wells drilled during the year.

 

Italy

 

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

 

Netherlands

 

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

 

Norway

 

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

 

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United Kingdom

 

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

 

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

 

AFRICA

 

Angola

 

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

 

Cameroon

 

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

 

Chad

 

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

 

Equatorial Guinea

 

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

 

Nigeria

 

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

 

ASIA PACIFIC / MIDDLE EAST

 

Australia

 

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

 

Indonesia

 

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

 

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Japan

 

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

 

Malaysia

 

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

 

Papua New Guinea

 

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

 

Qatar

 

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

 

Qatar Liquefied Gas Company Limited — (QG I)

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

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

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

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

 

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

 

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

 

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

 

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

 

Republic of Yemen

 

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

 

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Thailand

 

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

 

United Arab Emirates

 

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

 

RUSSIA/CASPIAN

 

Azerbaijan

 

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

 

Kazakhstan

 

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

 

Russia

 

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

 

WORLDWIDE EXPLORATION

 

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

 

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

 

A. Gross and Net Productive Wells

 

     Year-end 2009    Year-end 2008
     Oil    Gas    Oil    Gas
     Gross    Net    Gross    Net    Gross    Net    Gross    Net

Gross and Net Productive Wells

                       

Consolidated Subsidiaries

                       

United States

   15,606    4,821    9,261    5,645    15,275    4,588    9,084    5,511

Canada/South America

   5,357    4,828    6,728    3,408    5,527    5,007    6,189    3,189

Europe

   1,395    389    649    292    1,318    377    618    282

Africa

   1,081    432    13    5    943    381    14    6

Asia Pacific/Middle East

   1,380    507    238    183    1,345    484    229    179

Russia/Caspian

   93    15          74    12      
                                       

Total Consolidated Subsidiaries

   24,912    10,992    16,889    9,533    24,482    10,849    16,134    9,167

Equity Companies

                       

United States

   11,592    5,452    8    4    11,972    5,598    8    4

Europe

   27    14    576    187    27    14    599    196

Asia Pacific/Middle East

   775    74    126    36    837    80    84    20

Russia/Caspian

   98    24          68    17      
                                       

Total Equity Companies

   12,492    5,564    710    227    12,904    5,709    691    220
                                       

Total gross and net productive wells

   37,404    16,556    17,599    9,760    37,386    16,558    16,825    9,387
                                       

 

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

 

B. Gross and Net Developed Acreage

 

     Year-end 2009    Year-end 2008  
     Gross    Net    Gross     Net  
     (thousands of acres)  

Gross and Net Developed Acreage

          

Consolidated Subsidiaries

          

United States

   9,866    5,061    8,526      5,075   

Canada/South America

   5,570    2,460    5,558   2,488

Europe

   5,359    2,454    5,976      2,682   

Africa

   1,958    758    1,958      756   

Asia Pacific/Middle East

   3,031    1,210    2,814      1,120   

Russia/Caspian

   151    21    151      21   
                      

Total Consolidated Subsidiaries

   25,935    11,964    24,983      12,142   

Equity Companies

          

United States

   165    59    220      73   

Europe

   4,325    1,352    4,196      1,344   

Asia Pacific/Middle East

   5,437    553    5,347      531   

Russia/Caspian

   380    95    380      95   
                      

Total Equity Companies

   10,307    2,059    10,143      2,043   
                      
          

Total gross and net developed acreage

   36,242    14,023    35,126      14,185   
                      
*   Revised to include oil sands mining acreage.

 

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

 

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C. Gross and Net Undeveloped Acreage

 

     Year-end 2009    Year-end 2008  
     Gross    Net    Gross     Net  
     (thousands of acres)  

Gross and Net Undeveloped Acreage

  

Consolidated Subsidiaries

          

United States

   7,650    5,034    8,818      5,600   

Canada/South America

   26,074    17,107    33,016   19,953

Europe

   25,420    13,462    16,464      7,844   

Africa

   15,768    10,555    40,440      26,439   

Asia Pacific/Middle East

   33,384    25,260    18,609      12,168   

Russia/Caspian

   1,964    356    1,724      315   
                      

Total Consolidated Subsidiaries

   110,260    71,774    119,071      72,319   

Equity Companies

          

United States

   208    77    246      91   

Europe

   53    8    411      69   

Asia Pacific/Middle East

         90      22   

Russia/Caspian

   228    57    228      57   
                      

Total Equity Companies

   489    142    975      239   
                      

Total gross and net undeveloped acreage

   110,749    71,916    120,046      72,558   
                      

 

*   Revised to include oil sands mining acreage.

 

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

 

D. Summary of Acreage Terms

 

UNITED STATES

 

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

 

CANADA / SOUTH AMERICA

 

Canada

 

Exploration permits are granted for varying periods of time with renewals possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to obtain leases upon completing specified work. Production leases are held as long as there is production on the lease. The majority of Cold Lake leases were taken for an initial 21-year term in 1968-1969 and renewed for a second 21-year term in 1989-1990. The exploration acreage in eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.

 

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Argentina

 

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

 

EUROPE

 

Germany

 

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

 

Netherlands

 

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

 

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

 

Norway

 

Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for an initial period of up to six years (with extension of the initial period of one year at a time up to ten years after 1985), and an extension period of up to 30 years, with relinquishment of at least one-half of the original area required at the end of the initial period. Licenses issued after July 1, 1997, have an initial period of up to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half of the original area required at the end of the initial period.

 

United Kingdom

 

Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the first four licensing rounds provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. At the end of any such 40-year term, licenses may continue in

 

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producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a case-by-case basis until they become producing areas; or licenses terminate in all other areas. ExxonMobil’s licenses issued in 2005 as part of the 23rd licensing round have an initial term of four years with a second term extension of four years and a final term of 18 years. There is a mandatory relinquishment of 50-percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.

 

AFRICA

 

Angola

 

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

 

Cameroon

 

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

 

Chad

 

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

 

Equatorial Guinea

 

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

 

Nigeria

 

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

 

Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-

 

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renewable, while in all other areas the licenses are for five years and also are non-renewable. Demonstrating a commercial discovery is the basis for conversion of an OPL to an OML.

 

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

 

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

 

ASIA PACIFIC / MIDDLE EAST

 

Australia

 

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

 

Indonesia

 

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

 

Japan

 

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

 

Malaysia

 

Exploration and production activities are governed by seven production sharing contracts (PSCs) negotiated with the national oil company, three governing exploration and production activities and four governing production activities only. The more recent PSCs governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, with possible extensions to the exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed relinquished. The development period is from four to six years from commercial discovery, with the

 

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possibility of extensions under special circumstances. Areas from which commercial production has not started by the end of the development period will be deemed relinquished if no extension is granted. All extensions are subject to the national oil company’s prior written approval. The total production period is 15 to 25 years from first commercial lifting, not to exceed the overall term of the contract.

 

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

 

Papua New Guinea

 

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

 

Qatar

 

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

 

Republic of Yemen

 

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

 

Thailand

 

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

 

United Arab Emirates

 

Exploration and production activities for the major onshore oilfields in the Emirate of Abu Dhabi are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi. An interest in the Upper Zakum field, a major offshore field, was acquired effective as of January 1, 2006, for a term expiring March 9, 2026, on fiscal terms consistent with the Company’s existing interests in Abu Dhabi.

 

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RUSSIA/CASPIAN

 

Azerbaijan

 

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

 

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

 

Kazakhstan

 

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

 

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

 

Russia

 

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

 

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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 2009 (1)

 

          ExxonMobil
Share KBD (2)
   ExxonMobil
Interest %

United States

        

Torrance

  

California

   150    100

Joliet

  

Illinois

   238    100

Baton Rouge

  

Louisiana

   504    100

Baytown

  

Texas

   576    100

Beaumont

  

Texas

   345    100

Other (2 refineries)

   157   
          

Total United States

   1,970   

Canada

        

Strathcona

  

Alberta

   187    69.6

Dartmouth

  

Nova Scotia

   82    69.6

Nanticoke

  

Ontario

   112    69.6

Sarnia

  

Ontario

   121    69.6
          

Total Canada

   502   

Europe

        

Antwerp

  

Belgium

   305    100

Fos-sur-Mer

  

France

   119    82.9

Port-Jerome-Gravenchon

  

France

   233    82.9

Augusta

  

Italy

   198    100

Trecate

  

Italy

   174    75.4

Rotterdam

  

Netherlands

   191    100

Slagen

  

Norway

   116    100

Fawley

  

United Kingdom

   329    100

Other (2 refineries)

   78   
          

Total Europe

   1,743   

Asia Pacific

        

Kawasaki

  

Japan

   296    50

Sakai

  

Japan

   139    50

Wakayama

  

Japan

   160    50

Jurong/PAC

  

Singapore

   605    100

Sriracha

  

Thailand

   174    66

Other (5 refineries)

   337   
          

Total Asia Pacific

   1,711   

Other Non-U.S.

        

Yanbu

  

Saudi Arabia

   200    50

Laffan

  

Qatar

   14    10

Other (4 refineries)

   131   
          

Total Other Non-U.S.

   345   
          

Total Worldwide

   6,271   
          

 

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

 

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

 

Retail Sites Year-End 2009

 

United States

  

Owned/leased

   1,921

Distributors/resellers

   8,295
    

Total United States

   10,216

Canada

  

Owned/leased

   518

Distributors/resellers

   1,326
    

Total Canada

   1,844

Europe

  

Owned/leased

   4,153

Distributors/resellers

   2,674
    

Total Europe

   6,827

Asia Pacific

  

Owned/leased

   2,305

Distributors/resellers

   3,960
    

Total Asia Pacific

   6,265

Latin America

  

Owned/leased

   587

Distributors/resellers

   1,350
    

Total Latin America

   1,937

Middle East/Africa

  

Owned/leased

   481

Distributors/resellers

   150
    

Total Middle East/Africa

   631

Worldwide

  

Owned/leased

   9,965

Distributors/resellers

   17,755
    

Total worldwide

   27,720
    

 

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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 2009 (1)(2)

 

        Ethylene   Polyethylene   Polypropylene   Paraxylene   ExxonMobil
Interest %
 

North America

           

Baton Rouge

 

Louisiana

  1.0   1.3   0.4     100   

Baytown

 

Texas

  2.2     0.8   0.6   100   

Beaumont

 

Texas

  0.8   1.0     0.3   100   

Mont Belvieu

 

Texas

    1.0       100   

Sarnia

 

Ontario

  0.3   0.5       69.6   
                   

Total North America

  4.3   3.8   1.2   0.9  

Europe

           

Antwerp

 

Belgium

  0.5   0.4       35 (3) 

Fawley

 

United Kingdom

  0.1         100   

Fife

 

United Kingdom

  0.4         50   

Meerhout

 

Belgium

    0.5       100   

Notre-Dame-de-
Gravenchon

 

France

  0.4   0.4   0.3     100   

Rotterdam

 

Netherlands

        0.7   100   
                   

Total Europe

  1.4   1.3   0.3   0.7  

Middle East

           

Al Jubail

 

Saudi Arabia

  0.6   0.6       50   

Yanbu

 

Saudi Arabia

  1.0   0.7   0.2     50   
                   

Total Middle East

  1.6   1.3   0.2    

Asia Pacific

           

Fujian

 

China

  0.2   0.2   0.1   0.2   25   

Kawasaki

 

Japan

  0.5   0.1       50   

Singapore

 

Singapore

  0.9   0.6   0.4   0.9   100   

Sriracha

 

Thailand

        0.5   66   
                   

Total Asia Pacific

  1.6   0.9   0.5   1.6  

All Other

        0.6  
                   

Total Worldwide

  8.9   7.3   2.2   3.8  
                   

 

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

 

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Item 3.    Legal Proceedings.

 

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

 

As reported in the Corporation’s Form 10-Q for the third quarter of 2009, in October 2009, a purported shareholder complaint captioned Resnik v. Boskin et al., alleging direct and derivative claims, was filed in the United States District Court for the District of New Jersey, naming the present directors, the “named executive officers” listed in the Corporation’s 2009 Proxy Statement (as defined in Securities and Exchange Commission regulations) and ExxonMobil as defendants. The complaint was amended in December 2009, alleging that the defendants made materially false or misleading proxy solicitations in connection with the 2008 and 2009 shareholder votes regarding the election of directors and failed to seek stockholder reapproval of the Exxon Mobil Corporation 2003 Incentive Program to qualify certain incentive compensation paid to the named executive officers as properly deductible expenditures. The amended complaint also alleges, on behalf of the Corporation, that these acts injured the company, breached fiduciary duties and constituted waste. The amended complaint seeks various injunctive remedies, including corrective disclosure, new election of directors after corrective disclosure, enjoining candidates from serving on the Board until a new election occurs, stockholder reapproval of the program, enjoining payments under the program and short term incentive program to the named executive officers, damages from the individual defendants in favor of ExxonMobil, and costs and expenses of the action. The defendants plan to file a motion seeking dismissal of the lawsuit.

 

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

 

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

 

None.

 

 

 

31


Table of Contents
Index to Financial Statements

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

 

Name

 

Age as of
March 1,

2010

 

Title (Held Office Since)

R. W. Tillerson

 

57

 

Chairman of the Board (2006)

M. W. Albers

 

53

 

Senior Vice President (2007)

M. J. Dolan

 

56

 

Senior Vice President (2008)

D. D. Humphreys

 

62

 

Senior Vice President (2006) and Treasurer (2004)

A. P. Swiger

 

53

 

Senior Vice President (2009)

S. J. Balagia

 

58

 

Vice President and General Counsel (Effective March 1, 2010)

A. T. Cejka

 

58

 

Vice President (2004)

W. M. Colton

 

56

 

Vice President - Strategic Planning (2009)

H. R. Cramer

 

59

 

Vice President (1999)

N. W. Duffin

 

53

 

President, ExxonMobil Development Company (2007)

R. S. Franklin

 

52

 

Vice President (2009)

S. J. Glass, Jr.

  62  

Vice President (2008)

A. J. Kelly

 

52

 

Vice President (2007)

R. M. Kruger

  50  

Vice President (2008)

P. T. Mulva

 

58

 

Vice President and Controller (2004)

S. D. Pryor

 

60

 

Vice President (2004)

D. S. Rosenthal

  53  

Vice President - Investor Relations and Secretary (2008)

J. M. Spellings

  48  

Vice President and General Tax Counsel (Effective March 1, 2010)

T. R. Walters

  55   Vice President (2009)

 

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

 

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

 

ExxonMobil Chemical Company

   Dolan, Glass, Jr. and Pryor

ExxonMobil Development Company

   Albers, Duffin and Walters

ExxonMobil Exploration Company

   Cejka

ExxonMobil Fuels Marketing Company

   Cramer

ExxonMobil Gas & Power Marketing Company

   Colton, Franklin, Swiger and Walters

ExxonMobil Lubricants & Petroleum Specialties Company

   Kelly

ExxonMobil Production Company

   Duffin, Kruger, Rosenthal, Swiger and Walters

ExxonMobil Refining & Supply Company

   Dolan, Glass, Jr. and Pryor

 

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

 

32


Table of Contents
Index to Financial Statements

PART II

 

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

 

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

 

Issuer Purchases of Equity Securities for Quarter Ended December 31, 2009   

Period

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

October, 2009

   18,265,518    71.06    18,265,518   

November, 2009

   5,615,488    73.78    5,615,488   

December, 2009

   9,172,391    71.88    9,172,391   
               

Total

   33,053,397    71.75    33,053,397    (See note 1

 

Note 1—On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated February 1, 2010, the Corporation stated that first quarter 2010 share purchases are continuing at a pace consistent with fourth quarter 2009 share reduction spending of $2.0 billion. However, total purchases for the quarter may be less due to trading restrictions during the proxy solicitation period for the XTO merger. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.

 

33


Table of Contents
Index to Financial Statements

Item 6.    Selected Financial Data.

 

    Years Ended December 31,
    2009   2008   2007   2006   2005
    (millions of dollars, except per share amounts)
Sales and other operating revenue (1)(2)   $ 301,500   $ 459,579   $ 390,328   $ 365,467   $ 358,955

(1) Sales-based taxes included.

  $ 25,936   $ 34,508   $ 31,728   $ 30,381   $ 30,742

(2) Includes amounts for purchases/sales contracts with the same counterparty for 2005.

Net income attributable to ExxonMobil   $ 19,280   $ 45,220   $ 40,610   $ 39,500   $ 36,130
Earnings per common share (3)   $ 3.99   $ 8.70   $ 7.31   $ 6.64   $ 5.74
Earnings per common share - assuming dilution (3)   $ 3.98   $ 8.66   $ 7.26   $ 6.60   $ 5.70

(3)   Prior periods have been adjusted retrospectively. See “Earnings per Share” in “Note 2: Accounting Changes” in the Financial Section of this report

Cash dividends per common share   $ 1.66   $ 1.55   $ 1.37   $ 1.28   $ 1.14
Total assets   $ 233,323   $ 228,052   $ 242,082   $ 219,015   $ 208,335
Long-term debt   $ 7,129   $ 7,025   $ 7,183   $ 6,645   $ 6,220

 

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

 

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

 

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

 

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

 

Item 8.    Financial Statements and Supplementary Data.

 

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

 

   

Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 26, 2010, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 18: Income, Sales-Based and Other Taxes”;

   

“Quarterly Information” (unaudited);

   

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

   

“Frequently Used Terms” (unaudited).

 

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

 

34


Table of Contents
Index to Financial Statements

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

 

None.

 

Item  9A.    Controls and Procedures.

 

Management’s Evaluation of Disclosure Controls and Procedures

 

As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2009. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

 

Management’s Report on Internal Control Over Financial Reporting

 

Management, including the Corporation’s chief executive officer, principal financial officer and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2009.

 

PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2009, as stated in their report included in the Financial Section of this report.

 

Changes in Internal Control Over Financial Reporting

 

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

 

Item  9B.    Other Information.

 

Effective April 1, 2010, the annual salary for M.J. Dolan will increase to $935,000. Like all other ExxonMobil executive officers, Mr. Dolan is an “at will” employee of the Corporation and does not have an employment contract.

 

35


Table of Contents
Index to Financial Statements

PART III

 

Item 10.    Directors, Executive Officers and Corporate Governance.

 

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

 

   

The section entitled “Director Information”;

   

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

   

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

 

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

 

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

 

Item 11.    Executive Compensation.

 

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

 

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

 

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

 

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

 

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

 

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

 

36


Table of Contents
Index to Financial Statements

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

 

The information required under Item 403 of Regulation S-K is included in the section entitled “Director and Executive Officer Stock Ownership” of the Proxy Information Section of this report. Reference is also made to the section entitled “Certain Beneficial Owners” of the Proxy Information Section of this report.

 

Equity Compensation Plan Information

      (a)   (b)   (c)

Plan Category

   Number of Securities to be
Issued Upon Exercise of
Outstanding Options,
Warrants and Rights
  Weighted-
Average

Exercise Price of
Outstanding
Options,

Warrants and
Rights (1)
  Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation
Plans

[Excluding Securities
Reflected in Column (a)]

Equity compensation plans approved by security holders

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

Equity compensation plans not approved by security holders

  

0        

  0  

0        

      

Total

  

50,375,746      

 

$40.92  

 

153,372,424        

 

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

 

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

 

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

 

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

 

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

 

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

 

37


Table of Contents
Index to Financial Statements

Item 14.    Principal Accounting Fees and Services.

 

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

 

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

 

PART IV

 

Item 15.    Exhibits, Financial Statement Schedules.

 

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

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

 

  (a) (3) Exhibits:

See Index to Exhibits of this report.

 

38


Table of Contents
Index to Financial Statements

FINANCIAL SECTION

TABLE OF CONTENTS

 

Business Profile

   40

Financial Summary

   41

Frequently Used Terms

   42

Quarterly Information

   44

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

    

Functional Earnings

   45

Forward-Looking Statements

   46

Overview

   46

Business Environment and Risk Assessment

   46

Review of 2009 and 2008 Results

   49

Liquidity and Capital Resources

   50

Capital and Exploration Expenditures

   53

Taxes

   54

Environmental Matters

   54

Market Risks, Inflation and Other Uncertainties

   55

Recently Issued Statements of Financial Accounting Standards

   56

Critical Accounting Policies

   56

Management’s Report on Internal Control Over Financial Reporting

   60

Report of Independent Registered Public Accounting Firm

   60

Consolidated Financial Statements

    

Statement of Income

   62

Balance Sheet

   63

Statement of Cash Flows

   64

Statement of Changes in Equity

   65

Statement of Comprehensive Income

   66

Notes to Consolidated Financial Statements

    

1. Summary of Accounting Policies

   67

2. Accounting Changes

   68

3. Miscellaneous Financial Information

   69

4. Cash Flow Information

   69

5. Additional Working Capital Information

   69

6. Equity Company Information

   70

7. Investments, Advances and Long-Term Receivables

   71

8. Property, Plant and Equipment and Asset Retirement Obligations

   71

9. Accounting for Suspended Exploratory Well Costs

   72

10. Leased Facilities

   74

11. Earnings Per Share

   74

12. Financial Instruments and Derivatives

   75

13. Long-Term Debt

   75

14. Incentive Program

   80

15. Litigation and Other Contingencies

   82

16. Pension and Other Postretirement Benefits

   84

17. Disclosures about Segments and Related Information

   90

18. Income, Sales-Based and Other Taxes

   92

Supplemental Information on Oil and Gas Exploration and Production Activities

   94

Operating Summary

   106

 

39


Table of Contents
Index to Financial Statements

BUSINESS PROFILE

 

Financial


   Earnings After
Income Taxes

   Average Capital
Employed

  Return on
Average Capital
Employed

   Capital and
Exploration
Expenditures

   2009

   2008

   2009

   2008

  2009

  2008

   2009

   2008

     (millions of dollars)   (percent)    (millions of dollars)

Upstream

                                                 

United States

   $ 2,893     $ 6,243     $ 15,865     $ 14,651    18.2    42.6     $ 3,585     $ 3,334 

Non-U.S.

     14,214       29,159       57,336       51,413    24.8    56.7       17,119       16,400 
    

  

  

  

 
 
  

  

Total

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

  

  

  

 
 
  

  

Downstream

                                                 

United States

   $ (153)    $ 1,649     $ 7,306     $ 6,963    (2.1)   23.7     $ 1,511     $ 1,636 

Non-U.S.

     1,934       6,502       17,793       18,664    10.9    34.8       1,685       1,893 
    

  

  

  

 
 
  

  

Total

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

  

  

  

 
 
  

  

Chemical

                                                 

United States

   $ 769     $ 724     $ 4,370     $ 4,535    17.6    16.0     $ 319     $ 441 

Non-U.S.

     1,540       2,233       12,190       9,990    12.6    22.4       2,829       2,378 
    

  

  

  

 
 
  

  

Total

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

  

  

  

 
 
  

  

Corporate and financing

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

  

  

  

 
 
  

  

Total

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

  

  

  

 
 
  

  

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

 

Operating


   2009

     2008

     (thousands of barrels daily)

Net liquids production

           

United States

   384      367

Non-U.S.

   2,003      2,038
    
    

Total

   2,387      2,405
    
    
     (millions of cubic feet daily)

Natural gas production available for sale

           

United States

   1,275      1,246

Non-U.S.

   7,998      7,849
    
    

Total

   9,273      9,095
    
    
     (thousands of oil-equivalent barrels daily)

Oil-equivalent production (1)

   3,932      3,921
     (thousands of barrels daily)

Refinery throughput

           

United States

   1,767      1,702

Non-U.S.

   3,583      3,714
    
    

Total

   5,350      5,416
    
    
     (thousands of barrels daily)

Petroleum product sales

           

United States

   2,523      2,540

Non-U.S.

   3,905      4,221
    
    

Total

   6,428      6,761
    
    
     (thousands of metric tons)

Chemical prime product sales

           

United States

   9,649      9,526

Non-U.S.

   15,176      15,456
    
    

Total

   24,825      24,982
    
    

 

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

 

40


Table of Contents
Index to Financial Statements

FINANCIAL SUMMARY

 

     2009

    2008

    2007

    2006

    2005

 
   (millions of dollars, except per share amounts)  

Sales and other operating revenue (1) (2)

   $ 301,500      $ 459,579      $ 390,328      $ 365,467      $ 358,955   

Earnings

                                        

Upstream

   $ 17,107      $ 35,402      $ 26,497      $ 26,230      $ 24,349   

Downstream

     1,781        8,151        9,573        8,454        7,992   

Chemical

     2,309        2,957        4,563        4,382        3,943   

Corporate and financing

     (1,917     (1,290     (23     434        (154
    


 


 


 


 


Net income attributable to ExxonMobil

   $ 19,280      $ 45,220      $ 40,610      $ 39,500      $ 36,130   
    


 


 


 


 


Earnings per common share

   $ 3.99      $ 8.70      $ 7.31      $ 6.64      $ 5.74   

Earnings per common share – assuming dilution

   $ 3.98      $ 8.66      $ 7.26      $ 6.60      $ 5.70   

Cash dividends per common share

   $ 1.66      $ 1.55      $ 1.37      $ 1.28      $ 1.14   

Earnings to average ExxonMobil share of equity (percent)

     17.3        38.5        34.5        35.1        33.9   

Working capital

   $ 3,174      $ 23,166      $ 27,651      $ 26,960      $ 27,035   

Ratio of current assets to current liabilities (times)

     1.06        1.47        1.47        1.55        1.58   

Additions to property, plant and equipment

   $ 22,491      $ 19,318      $ 15,387      $ 15,462      $ 13,839   

Property, plant and equipment, less allowances

   $ 139,116      $ 121,346      $ 120,869      $ 113,687      $ 107,010   

Total assets

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

Exploration expenses, including dry holes

   $ 2,021      $ 1,451      $ 1,469      $ 1,181      $ 964   

Research and development costs

   $ 1,050      $ 847      $ 814      $ 733      $ 712   

Long-term debt

   $ 7,129      $ 7,025      $ 7,183      $ 6,645      $ 6,220   

Total debt

   $ 9,605      $ 9,425      $ 9,566      $ 8,347      $ 7,991   

Fixed-charge coverage ratio (times)

     26.1        52.2        49.9        46.3        50.2   

Debt to capital (percent)

     7.7        7.4        7.1        6.6        6.5   

Net debt to capital (percent) (3)

     (1.0     (23.0     (24.0     (20.4     (22.0

ExxonMobil share of equity at year end

   $ 110,569      $ 112,965      $ 121,762      $ 113,844      $ 111,186   

ExxonMobil share of equity per common share

   $ 23.39      $ 22.70      $ 22.62      $ 19.87      $ 18.13   

Weighted average number of common shares outstanding (millions)

     4,832        5,194        5,557        5,948        6,295   

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

     80.7        79.9        80.8        82.1        83.7   

CORS employees not included above (thousands) (5)

     22.0        24.8        26.3        24.3        22.4   

 

(1) Sales and other operating revenue includes sales-based taxes of $25,936 million for 2009, $34,508 million for 2008, $31,728 million for 2007, $30,381 million for 2006 and $30,742 million for 2005.
(2) Sales and other operating revenue includes $30,810 million for 2005 for purchases/sales contracts with the same counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income.
(3) Debt net of cash, excluding restricted cash.
(4) Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs.
(5) CORS employees are employees of company-operated retail sites.

 

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Table of Contents
Index to Financial Statements

FREQUENTLY USED TERMS

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

CASH FLOW FROM OPERATIONS AND ASSET SALES

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

 

Cash flow from operations and asset sales  


   2009

    2008

    2007

 
     (millions of dollars)  

Net cash provided by operating activities

   $ 28,438      $ 59,725      $ 52,002   

Sales of subsidiaries, investments and property, plant and equipment

     1,545        5,985        4,204   
    


 


 


Cash flow from operations and asset sales

   $ 29,983      $ 65,710      $ 56,206