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Exxon Mobil 10-K 2010 Documents found in this filing:Table of ContentsIndex to Financial Statements2009
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)
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:
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 ContentsIndex to Financial StatementsFORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
TABLE OF CONTENTS
Table of ContentsIndex to Financial StatementsPART 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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Table of ContentsIndex to Financial Statementssegments. 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.
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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Table of ContentsIndex to Financial StatementsOther 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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Table of ContentsIndex to Financial Statementsexpropriation 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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Table of ContentsIndex to Financial Statementsefficiently, 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.
None.
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Table of ContentsIndex to Financial StatementsItem 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.
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Table of ContentsIndex to Financial StatementsIn 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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Table of ContentsIndex to Financial StatementsThe 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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Table of ContentsIndex to Financial Statementsare 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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Table of ContentsIndex to Financial Statements3. 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.
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Table of ContentsIndex to Financial StatementsB. 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.
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Table of ContentsIndex to Financial Statements
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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Table of ContentsIndex to Financial Statements4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
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Table of ContentsIndex to Financial Statements
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Table of ContentsIndex to Financial StatementsB. 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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Table of ContentsIndex to Financial Statements5. Present Activities
A. Wells Drilling
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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Table of ContentsIndex to Financial StatementsCANADA / 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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Table of ContentsIndex to Financial StatementsUnited 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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Table of ContentsIndex to Financial StatementsJapan
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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Table of ContentsIndex to Financial StatementsThailand
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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Table of ContentsIndex to Financial Statements6. Oil and Gas Properties, Wells, Operations and Acreage
A. Gross and Net Productive Wells
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
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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Table of ContentsIndex to Financial StatementsC. Gross and Net Undeveloped 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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Table of ContentsIndex to Financial StatementsArgentina
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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Table of ContentsIndex to Financial Statementsproducing 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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Table of ContentsIndex to Financial Statementsrenewable, 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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Table of ContentsIndex to Financial Statementspossibility 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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Table of ContentsIndex to Financial StatementsRUSSIA/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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Table of ContentsIndex to Financial StatementsInformation 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)
28
Table of ContentsIndex to Financial StatementsThe 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
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Table of ContentsIndex to Financial StatementsInformation 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)
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Table of ContentsIndex to Financial StatementsItem 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.
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Table of ContentsIndex to Financial StatementsExecutive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].
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.
Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.
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Table of ContentsIndex to Financial StatementsPART II
Reference is made to the “Quarterly Information” portion of the Financial Section of this report.
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.
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Table of ContentsIndex to Financial StatementsItem 6. Selected Financial Data.
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:
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.
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Table of ContentsIndex to Financial StatementsItem 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.
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Table of ContentsIndex to Financial StatementsPART III
Item 10. Directors, Executive Officers and Corporate Governance.
Reference is made to the following in the Proxy Information Section of this report:
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.
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Table of ContentsIndex to Financial StatementsItem 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
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.
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Table of ContentsIndex to Financial StatementsItem 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.
See Table of Contents of the Financial Section of this report.
See Index to Exhibits of this report.
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Table of ContentsIndex to Financial StatementsFINANCIAL SECTION TABLE OF CONTENTS
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Table of ContentsIndex to Financial StatementsBUSINESS PROFILE
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
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Table of ContentsIndex to Financial StatementsFINANCIAL SUMMARY
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Table of ContentsIndex to Financial StatementsFREQUENTLY 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.
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Table of ContentsIndex to Financial StatementsRETURN ON AVERAGE CAPITAL EMPLOYED Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow-based, are used to make investment decisions.
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Table of ContentsIndex to Financial StatementsQUARTERLY INFORMATION
The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States. There were 525,529 registered shareholders of ExxonMobil common stock at December 31, 2009. At January 31, 2010, the registered shareholders of ExxonMobil common stock numbered 523,748. On January 27, 2010, the Corporation declared a $0.42 dividend per common share, payable March 10, 2010.
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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
References in this discussion to total corporate earnings mean net income attributable to ExxonMobil (U.S. GAAP) from the consolidated income statement. Unless otherwise indicated, references to earnings, special items, Upstream, Downstream, Chemical and Corporate and Financing segment earnings, and earnings per share are ExxonMobil’s share after excluding amounts attributable to noncontrolling interests.
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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING STATEMENTS Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including demand growth and energy source mix; capacity increases; production growth and mix; rates of field decline; financing sources; the resolution of contingencies and uncertain tax positions; environmental and capital expenditures; and benefits realized from the XTO Energy transaction could differ materially depending on a number of factors, such as changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; the outcome of commercial negotiations; political or regulatory events, including the timing and conditions of clearance for the XTO Energy transaction; our ability to integrate XTO Energy’s business with our own; and other factors discussed herein and in Item 1A of ExxonMobil’s 2009 Form 10-K. OVERVIEW The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, manufacturing and marketing of hydrocarbons and hydrocarbon-based products. The Corporation’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods. Our consistent, conservative approach to financing the capital-intensive needs of the Corporation has helped ExxonMobil to sustain the “triple-A” status of its long-term debt securities for 91 years. ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new energy supplies. While commodity prices are volatile on a short-term basis and depend on supply and demand, ExxonMobil’s investment decisions are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Prices for crude oil, natural gas and refined products are based on corporate plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects. BUSINESS ENVIRONMENT AND RISK ASSESSMENT Long-Term Business Outlook By 2030, the world’s population is projected to grow to approximately 8 billion people, or about 1.5 billion more than in 2005. Coincident with this population increase, the Corporation expects worldwide economic growth to average 2.7 percent per year. This combination of population and economic growth is expected to lead to an increase in primary energy demand of almost 35 percent by 2030 versus 2005 even with substantial efficiency gains. This demand increase is expected to be concentrated in developing countries. As economic progress drives demand higher, the use of more energy-efficient, lower-emission technologies and practices will become increasingly important, leading to a significantly lower level of energy consumption and emissions per unit of economic output by 2030. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the introduction of new technologies, as well as many other improvements that span the residential, commercial and industrial sectors. Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by over 35 percent from 2005 to 2030. The global growth in transportation demand will be met primarily by oil, which is expected to provide almost 95 percent of all transportation fuel by 2030, down from about 98 percent in 2005, as biofuels and natural gas gain market share. Demand for electricity around the world will grow significantly through 2030. Consistent with this projection, power generation will remain the largest and fastest-growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Coal will retain the largest share. However, natural gas, nuclear and renewables are all expected to gain market share. Liquid fuels provide the largest share of energy supply today due to their availability, affordability and ease of transport. By 2030, global demand for liquids is expected to grow to approximately 104 million barrels of oil-equivalent per day or close to 25 percent more than in 2005. Global demand for liquid fuels will be met by a wide variety of sources. Conventional non-OPEC crude and condensate production is expected to remain relatively flat through 2030. However, growth is expected from a number of supply sources, including biofuels, oil sands and natural gas liquids, as well as crude oil from OPEC countries. While the world’s resource base is sufficient to meet projected demand, access to resources and timely investments will remain critical to meeting global needs with reliable, affordable supplies. Increases in natural gas demand in North America, Europe and Asia Pacific will require new sources of supply. Helping meet these needs will be additional local supplies of unconventional natural gas – the result of recent improvements in technologies used to tap these hard-to-produce resources – as well as imports. The growing need for natural gas imports will have a dramatic impact on the worldwide liquefied natural gas (LNG) market, which is expected to approximately triple in volume from 2005 to 2030. The world’s energy mix is highly diverse and will remain so through 2030. Oil is expected to remain the largest source of energy supply at close to 35 percent. From 2005 to 2030, natural gas is expected to grow the fastest of the fossil fuels and overtake coal as the second-largest energy source. Nuclear power is projected to grow significantly, surpassing coal in terms of absolute growth and reaching the level of biomass as the fourth-largest source of energy. Hydro and geothermal will also grow, though remain limited by the availability of natural sites. Wind, solar and biofuels are expected to grow at close to 10 percent per year on average, the highest growth rate of all fuels, and are projected to reach approximately 2.5 percent of world energy by 2030.
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Table of ContentsIndex to Financial StatementsThe Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide through 2030 will be close to $480 billion per year on average, or about $11.1 trillion (measured in 2009 dollars) in total over the period 2008-2030. International accords and underlying regional and national regulations for greenhouse gas reduction are evolving with uncertain timing and outcome, making it difficult to predict their business impact. ExxonMobil includes estimates of potential costs for energy-related greenhouse gas emissions in its long-term Energy Outlook, which is used for assessing the business environment and in its investment evaluations. Upstream ExxonMobil continues to maintain a large portfolio of exploration and development opportunities, which enables the Corporation to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental Upstream business strategies guide our global exploration, development, production, and gas and power marketing activities. These strategies include identifying and selectively pursuing the highest quality exploration opportunities, investing in projects that deliver superior returns, maximizing profitability of existing oil and gas production, and capitalizing on growing natural gas and power markets. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees and investment in the communities in which we operate. As future development projects bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2014. Oil and natural gas output from West Africa, the Caspian region, the Middle East and Russia is expected to increase over the next five years based on current capital project execution plans. Currently, these growth areas account for 42 percent of the Corporation’s production. By 2014, they are expected to generate about 50 percent of total volumes. The remainder of the Corporation’s production is expected to be sourced from established areas, including Europe, North America and Asia Pacific. In addition to an evolving geographic mix, there will also be continued change in the type of opportunities from which volumes are produced. Production from diverse resource types utilizing specialized technologies such as arctic technology, deepwater drilling and production systems, heavy oil recovery processes, unconventional gas production and LNG is expected to grow from about 30 percent to over 40 percent of the Corporation’s output between now and 2014. We do not anticipate that the expected change in the geographic mix of production volumes, and in the types of opportunities from which volumes will be produced, will have a material impact on the nature and the extent of the risks disclosed in Item 1A of ExxonMobil’s 2009 Form 10-K, or result in a material change in our level of unit operating expenses. The Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2010-2014. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, performance of enhanced oil recovery projects, regulatory changes, asset sales, weather events, price effects under production sharing contracts and other factors described in Item 1A of ExxonMobil’s 2009 Form 10-K. Enhanced oil recovery projects extract hydrocarbons from reservoirs in excess of that which may be produced through primary recovery, i.e., through pressure depletion or natural aquifer support. They include the injection of water, gases or chemicals into a reservoir to produce hydrocarbons otherwise unobtainable. Merger Agreement On December 13, 2009, ExxonMobil and XTO Energy Inc. (XTO) entered into an Agreement and Plan of Merger (the “Merger Agreement”). Under the terms of the Merger Agreement, (i) each share of XTO common stock will be converted into the right to receive 0.7098 shares of common stock of the Corporation (the “Exchange Ratio”) and (ii) all outstanding XTO options will be converted into options to purchase shares of common stock of the Corporation, with the number of shares of XTO common stock subject to the option, and the option’s exercise price, adjusted based on the Exchange Ratio. The transaction includes XTO debt, which was approximately $10.5 billion at December 31, 2009. XTO’s reported year-end 2009 proved reserves of 14.8 trillion cubic feet of natural gas equivalents include shale gas, tight gas, coal-bed methane and shale oil. These will complement ExxonMobil’s holdings in the United States, Canada, Germany, Poland and Argentina. XTO’s resource base, technical expertise and highly skilled employees together with ExxonMobil’s operational and financial strengths should enable development of additional supplies of unconventional natural gas and oil resources. Consummation of the merger is subject to customary conditions, including (i) the adoption of the Merger Agreement by the holders of XTO common stock, (ii) the absence of any law or order prohibiting the closing, (iii) the expiration or termination of the applicable Hart-Scott-Rodino waiting period and receipt of antitrust clearance under Dutch competition laws, (iv) subject to certain exceptions, the accuracy of representations and warranties and performance of covenants, (v) the effectiveness of the registration statement for the common stock of the Corporation being issued in the merger and (vi) the delivery of customary opinions from counsel to the Corporation and counsel to XTO that the merger will qualify as a reorganization for federal income tax purposes. The Corporation and XTO have made customary representations, warranties and covenants in the Merger Agreement, including, among others, covenants to conduct their respective businesses in the ordinary course consistent with past practice between the execution of the Merger Agreement and consummation of the merger. In addition, XTO has covenanted (i) to cause a stockholder meeting to be held to consider approval of the transactions contemplated by the Merger Agreement, (ii) subject to certain exceptions, for its board of directors to recommend approval by its stockholders of the transactions contemplated by the Merger Agreement, (iii) not to solicit proposals relating to alternative business combination transactions and (iv) subject to certain exceptions, not to enter into discussions concerning or provide confidential information in connection with alternative business combination transactions.
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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Assuming the merger is approved by XTO stockholders and is cleared by regulatory authorities, the transaction will be accounted for as a purchase, with XTO’s assets and liabilities reflected in ExxonMobil’s books at fair value. The transaction should be accretive to ExxonMobil’s production growth and cash flow. Depending on the market price for gas, it is not likely to be accretive to near-term earnings per share and may be dilutive. Downstream ExxonMobil’s Downstream is a large, diversified business with refining and marketing complexes around the world. The Corporation has a strong presence in mature markets in North America and Europe, as well as the growing Asia Pacific region. ExxonMobil’s fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizing on integration with other ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectiveness, and providing quality, valued products and services to customers. ExxonMobil has an ownership interest in 37 refineries, located in 21 countries, with distillation capacity of 6.3 million barrels per day and lubricant basestock manufacturing capacity of about 143 thousand barrels per day. ExxonMobil’s fuels and lubes marketing business portfolios include operations around the world, with multiple channels to market serving a globally diverse customer base. The downstream industry environment remains very challenging. The recent global economic recession had a negative impact on the global demand for refined products, and thus put considerable downward pressure on worldwide refining margins. Further, in prior years, the industry has experienced a period of robust refining margins, which encouraged the construction of additional industry capacity. Over the prior 20-year period, inflation-adjusted refining margins have been flat, with the recent prior years’ stronger margins offsetting the longer-term trend of declining margins. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, currency fluctuations, seasonal demand, weather and political climate. ExxonMobil’s long-term outlook continues to be that refining margins will generally decline as competition in the refining industry remains intense and, in the near term, new capacity additions outpace the growth in global demand. Additionally, as described in more detail in Item 1A of ExxonMobil’s 2009 Form 10-K, proposed carbon policy and other climate-related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the refining business. In the retail fuels marketing business, ongoing intense competition continues to drive down inflation-adjusted margins by about 2 percent per year. In 2009, ExxonMobil progressed the transition of the direct served (i.e., dealer, company-operated) retail network in the U.S. to a branded distributor model. This transition was announced in 2008 and will be a multiyear process. ExxonMobil takes a disciplined approach to managing the Downstream capital employed. The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. These investments capitalize on the Corporation’s world-class scale and integration, industry-leading efficiency, leading-edge technology and respected brands, enabling ExxonMobil to take advantage of attractive emerging-growth opportunities around the globe. In 2009, ExxonMobil completed commissioning new cogeneration facilities in Fujian, China, and Antwerp, Belgium, representing a total of 375 megawatts, that help improve our refinery efficiency. Additionally, ExxonMobil is progressing with announced plans to invest over $1 billion in three refineries to increase the supply of cleaner-burning diesel by about 140 thousand barrels per day. The company will construct new units and modify existing facilities at its Baton Rouge, La., Baytown, Texas, and Antwerp, Belgium, refineries. In the Asia Pacific region, ExxonMobil and its partners Sinopec, Fujian Province and Saudi Aramco started up the integrated refining and petrochemicals facility in Fujian Province, China. This project expanded the existing 80-thousand-barrel-per-day refinery to a 240-thousand-barrel-per-day high-conversion facility. Additionally, the project encompasses a new world-scale integrated chemical plant. The partnership also includes a fuels marketing joint venture that includes over 750 retail sites and a network of distribution terminals. Chemical Worldwide petrochemical demand continued to be weak in the first half of 2009, due to the soft economy. Demand increased in the second half of the year, reflecting improved economic activity, particularly in Asia Pacific. Industry operating rates improved in the second half of the year on stronger demand and were further supported by industry capacity rationalizations and delays in start-up of new capacity. Tighter industry supply/demand balances in the second half of the year supported higher product prices and improved industry margins. ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of primary petrochemical products, ExxonMobil Chemical also has a number of less-cyclical business lines. Chemical’s competitive advantages are achieved through its business mix, broad geographic coverage, investment discipline, integration of chemical capacity with large refineries or upstream gas processing facilities, advantaged feedstock capabilities, leading proprietary technology and product application expertise.
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Table of ContentsIndex to Financial StatementsREVIEW OF 2009 AND 2008 RESULTS
2009 Earnings in 2009 of $19,280 million decreased $25,940 million from 2008. Earnings for 2009 included an after-tax special charge of $140 million for interest related to the Valdez punitive damages award. 2008 Earnings in 2008 of $45,220 million increased $4,610 million from 2007. Earnings for 2008 included an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany and after-tax special charges of $460 million related to the Valdez litigation. Upstream
2009 Upstream earnings for 2009 were $17,107 million, down $18,295 million from 2008, including the absence of an after-tax special gain in 2008 of $1,620 million from the sale of a natural gas transportation business in Germany. Lower crude oil and natural gas realizations reduced earnings $15.2 billion. Volume and mix effects increased earnings $700 million. Higher operating expenses and increased exploration activities decreased earnings $1.4 billion. Lower gains on asset divestments reduced earnings approximately $900 million. Oil-equivalent production increased slightly versus 2008, including impacts from entitlement effects, quotas and divestments. Excluding these items, oil-equivalent production was up about 2 percent. Liquids production of 2,387 kbd (thousands of barrels per day) decreased 18 kbd. Production increases from new projects in the U.S., Qatar and West Africa along with higher volumes in Kazakhstan were offset by field decline. Natural gas production of 9,273 mcfd (millions of cubic feet per day) increased 178 mcfd from 2008. Higher volumes from projects in Qatar were partially offset by field decline. Earnings from U.S. Upstream operations for 2009 were $2,893 million, a decrease of $3,350 million. Earnings outside the U.S. for 2009 of $14,214 million declined $14,945 million. 2008 Upstream earnings for 2008 totaled $35,402 million, an increase of $8,905 million from 2007, including an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany. Higher crude oil and natural gas realizations increased earnings approximately $11.8 billion. Lower sales volumes reduced earnings about $3.7 billion. Higher taxes and increased operating costs decreased earnings approximately $1.5 billion, partially offset by favorable foreign exchange. Oil-equivalent production decreased 6 percent versus 2007, including impacts from lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Excluding these impacts, total oil-equivalent production decreased 3 percent. Liquids production of 2,405 kbd decreased 211 kbd from 2007. Production increases from new projects in West Africa were more than offset by field decline, lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Natural gas production of 9,095 mcfd decreased 289 mcfd from 2007. Higher volumes from North Sea, Malaysia and Qatar projects and higher European demand were more than offset by field decline. Earnings from U.S. Upstream operations for 2008 were $6,243 million, an increase of $1,373 million. Earnings outside the U.S. for 2008, including a $1,620 million gain related to the sale of the German natural gas transportation business, were $29,159 million, $7,532 million higher than in 2007. Downstream
2009 Downstream earnings were $1,781 million, down $6.4 billion from 2008. Weaker margins reduced earnings $5.1 billion. Lower divestment activity reduced earnings about $1.0 billion. Volumes decreased earnings approximately $300 million. Petroleum product sales of 6,428 kbd decreased 333 kbd, mainly reflecting asset divestments and lower demand. Refinery throughput was 5,350 kbd, down 66 kbd from 2008. Earnings from the U.S. Downstream were $1,802 million lower than in 2008. Non-U.S. Downstream earnings were $1,934 million, down $4,568 million from 2008. 2008 Downstream earnings of $8,151 million were $1,422 million lower than in 2007. Lower margins reduced earnings approximately $900 million, as weaker refining margins more than offset stronger marketing margins. Higher operating costs, mainly associated with planned work activity, reduced earnings about $700 million, while unfavorable foreign exchange effects decreased earnings approximately $600 million. Improved refinery operations provided a partial offset, increasing earnings about $800 million. Petroleum product sales of 6,761 kbd decreased from 7,099 kbd in 2007, primarily reflecting asset sales and lower demand. Refinery throughput was 5,416 kbd compared with 5,571 kbd in 2007. U.S. Downstream earnings were $1,649 million, down $2,471 million from 2007. Non-U.S. Downstream earnings of $6,502 million were $1,049 million higher than in 2007.
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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Chemical
2009 Earnings declined $648 million versus 2008 to a total of $2,309 million. Weaker margins reduced earnings by $340 million, mostly in commodities. Lower volumes decreased earnings $190 million. All other items, including unfavorable foreign exchange impacts, reduced earnings $115 million. Prime product sales of 24,825 kt (thousands of metric tons) decreased 157 kt from 2008. Prime product sales are total chemical product sales, including ExxonMobil’s share of equity-company volumes and finished-product transfers to the Downstream business. U.S. Chemical earnings of $769 million increased $45 million. Non-U.S. Chemical earnings were $1,540 million, down $693 million. 2008 Chemical earnings totaled $2,957 million, a decrease of $1,606 million from 2007. Lower margins reduced earnings approximately $1.2 billion, while lower volumes decreased earnings about $500 million. Prime product sales were 24,982 kt, a decrease of 2,498 kt from 2007. U.S. Chemical earnings of $724 million decreased $457 million. Non-U.S. Chemical earnings of $2,233 million were $1,149 million lower than in 2007. Corporate and Financing
2009 Corporate and financing expenses of $1,917 million in 2009 increased $627 million, primarily due to lower interest income. 2008 Corporate and financing expenses of $1,290 million in 2008 increased $1,267 million from 2007, mainly due to charges of $460 million related to the Valdez litigation, net higher taxes and lower interest income. LIQUIDITY AND CAPITAL RESOURCES Sources and Uses of Cash
Cash and cash equivalents were $10.7 billion at the end of 2009, $20.7 billion lower than the prior year, reflecting lower earnings and a higher level of capital spending partially offset by a lower level of purchases of ExxonMobil shares. Cash and cash equivalents were $31.4 billion at the end of 2008, $2.5 billion lower than the prior year, reflecting $2.7 billion of foreign exchange reductions from the strengthening of the U.S. dollar in 2008. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows. Although the Corporation could issue long-term debt and has access to short-term liquidity, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully controlled to ensure that it is secure and readily available to meet the Corporation’s cash requirements and to optimize returns on the cash balances. To support cash flows in future periods the Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all the Corporation’s existing oil and gas fields and without new projects, ExxonMobil’s production is expected to decline at an average of approximately 5 percent per year over the next few years. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and contractual terms. The Corporation has long been successful at offsetting the effects of natural field decline through disciplined investments in quality opportunities and project execution. Over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. Projects are in progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including project start-up timing, operational outages, reservoir performance, crude oil and natural gas prices, weather events, and regulatory changes. The Corporation’s cash flows are also
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Table of ContentsIndex to Financial Statementshighly dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks. The Corporation’s financial strength, as evidenced by its AAA/Aaa debt rating, enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2009 were $27.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could vary depending on the progress of individual projects. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas properties have not had a significant impact on the amount or timing of cash flows from operating activities. Cash Flow from Operating Activities 2009 Cash provided by operating activities totaled $28.4 billion in 2009, $31.3 billion lower than 2008. The major source of funds was net income including noncontrolling interests of $19.7 billion, adjusted for the noncash provision of $11.9 billion for depreciation and depletion, both of which declined. Pension fund contributions in 2009 of $4.5 billion increased from $1.0 billion in 2008. The net effects of changes in prices and the timing of collection of accounts receivable and of payments of accounts and other payables and of income taxes payable reduced cash provided by operating activities in 2009 compared to an increase in 2008. 2008 Cash provided by operating activities totaled $59.7 billion in 2008, a $7.7 billion increase from 2007. The major source of funds was net income including noncontrolling interests of $46.9 billion, adjusted for the noncash provision of $12.4 billion for depreciation and depletion, both of which increased. The net effects of lower prices and the timing of collection of accounts receivable and of payments of accounts and other payables and of income taxes payable added to cash provided by operating activities. Cash Flow from Investing Activities 2009 Cash used in investing activities netted to $22.4 billion in 2009, $6.9 billion higher than in 2008. Spending for property, plant and equipment of $22.5 billion in 2009 increased $3.2 billion from 2008. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $1.5 billion in 2009 compared to $6.0 billion in 2008, the decrease reflecting the absence of the sale of the natural gas transportation business in Germany and lower sales of Downstream assets and investments. 2008 Cash used in investing activities netted to $15.5 billion in 2008, $5.8 billion higher than in 2007. Spending for property, plant and equipment of $19.3 billion in 2008 increased $3.9 billion from 2007. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $6.0 billion in 2008 compared to $4.2 billion in 2007, the increase reflecting the sale of the German natural gas transportation business in 2008. Cash used in investing activities in 2008 was higher due to the absence of the $4.6 billion positive cash flow in 2007 from the release of the restriction on the restricted cash and cash equivalents. Net cash used for investments and advances and the change in marketable securities was $1.0 billion lower in 2008. Cash Flow from Financing Activities 2009 Cash used in financing activities was $27.3 billion in 2009, $16.7 billion lower than 2008, reflecting a lower level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.66 per share from $1.55 per share and totaled $8.0 billion, a pay-out of 42 percent. Total consolidated short-term and long-term debt increased $0.2 billion to $9.6 billion at year-end 2009. ExxonMobil share of equity decreased $2.4 billion in 2009, to $110.6 billion. The addition to equity for earnings of $19.3 billion was more than offset by reductions for distributions to ExxonMobil shareholders of $8.0 billion of dividends and $18.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Equity, and net assets and liabilities, increased $3.3 billion, representing the foreign exchange translation effects of generally stronger foreign currencies at the end of 2009 on ExxonMobil’s operations outside the United States. The change in the funded status of the postretirement benefits reserves in 2009 increased equity by $1.2 billion. During 2009, Exxon Mobil Corporation purchased 277 million shares of its common stock for the treasury at a gross cost of $19.7 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 5.0 percent from 4,976 million at the end of 2008 to 4,727 million at the end of 2009. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice. 2008 Cash used in financing activities was $44.0 billion in 2008, an increase of $5.7 billion from 2007, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.55 per share from $1.37 per share and totaled $8.1 billion, a pay-out of 18 percent. Total consolidated short-term and long-term debt decreased $0.2 billion to $9.4 billion at year-end 2008. ExxonMobil share of equity decreased $8.8 billion in 2008, to $113.0 billion. Earnings of $45.2 billion, reduced by distributions to ExxonMobil shareholders of $8.1 billion of dividends and $32.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding, added to equity. Equity, and net assets and liabilities, decreased $6.8 billion, representing the foreign exchange translation effects of generally weaker
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foreign currencies at the end of 2008 on ExxonMobil’s operations outside the United States. The change in the funded status of the postretirement benefits reserves in 2008 lowered equity by $5.1 billion. During 2008, Exxon Mobil Corporation purchased 434 million shares of its common stock for the treasury at a gross cost of $35.7 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 7.5 percent from 5,382 million at the end of 2007 to 4,976 million at the end of 2008. Purchases were made in both the open market and through negotiated transactions. Commitments Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2009. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.
This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these purchases will be offset in the same periods by cash received from the related sales transactions. The table also excludes unrecognized tax benefits totaling $4.7 billion as of December 31, 2009, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in note 18, Income, Sales-Based and Other Taxes. Notes:
Guarantees The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2009, for $8,786 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of $5,629 million, representing ExxonMobil’s share of obligations of certain equity companies. The below-mentioned guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
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Table of ContentsIndex to Financial StatementsFinancial Strength On December 31, 2009, unused credit lines for short-term financing totaled approximately $4.8 billion (note 5). The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness. Throughout this period, the Corporation’s long-term debt securities maintained the top credit rating from both Standard & Poor’s (AAA) and Moody’s (Aaa), a rating it has sustained for 91 years.
Management views the Corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The Corporation’s sound financial position gives it the opportunity to access the world’s capital markets in the full range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value. The Corporation makes limited use of derivative instruments, which are discussed in note 12. Litigation and Other Contingencies Litigation As discussed in note 15, a number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims and the punitive damage award have been paid. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation’s operations or financial condition. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Other Contingencies In accordance with a nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project. On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes. An affiliate of ExxonMobil has also filed an arbitration under the rules of the International Chamber of Commerce against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. Both arbitration proceedings continue. At this time, the net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition. ExxonMobil’s remaining net book investment in Cerro Negro producing assets is about $750 million. CAPITAL AND EXPLORATION EXPENDITURES
Capital and exploration expenditures in 2009 were $27.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could vary depending on the progress of individual projects. Upstream spending of $20.7 billion in 2009 was up 5 percent from 2008, mainly due to increased exploration and production drilling activity. The majority of these expenditures are on development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves was 67 percent of total proved reserves at year-end 2009, and has been over 60 percent for the last five years, indicating that proved reserves are
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consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $3.2 billion in 2009, a decrease of $0.3 billion from 2008, due to lower refining project and fuels marketing expenditures. Chemical 2009 capital expenditures of $3.1 billion were up $0.3 billion from 2008 due to increased investment in Asia Pacific to meet demand growth. TAXES
2009 Income, sales-based and all other taxes and duties totaled $78.6 billion in 2009, a decrease of $37.6 billion or 32 percent from 2008. Income tax expense, both current and deferred, was $15.1 billion, $21.4 billion lower than 2008, reflecting lower pre-tax income in 2009. A higher share of total income from the Upstream segment in 2009 increased the effective income tax rate to 47 percent compared to 46 percent in 2008. Sales-based and all other taxes and duties of $63.5 billion in 2009 decreased $16.2 billion from 2008, reflecting lower prices and foreign exchange effects. 2008 Income, sales-based and all other taxes and duties totaled $116.3 billion in 2008, an increase of $10.6 billion or 10 percent from 2007. Income tax expense, both current and deferred, was $36.5 billion, $6.7 billion higher than 2007, reflecting higher pre-tax income in 2008. A higher share of total income from the Upstream segment in 2008 increased the effective income tax rate to 46 percent compared to 44 percent in 2007. Sales-based and all other taxes and duties of $79.7 billion in 2008 increased $3.9 billion from 2007, reflecting higher prices. Environmental Expenditures
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. 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). Environmental Liabilities The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2009 for environmental liabilities were $504 million ($507 million in 2008) and the balance sheet reflects accumulated liabilities of $943 million as of December 31, 2009, and $884 million as of December 31, 2008. Asset Retirement Obligations The fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time assets are installed, with an offsetting amount booked as additions to property, plant and equipment ($156 million for 2009). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($372 million in 2009). Consolidated company expenditures for asset retirement obligations in 2009 were $448 million and the ending balance of the obligations recorded on the balance sheet at December 31, 2009, totaled $8,473 million.
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Table of ContentsIndex to Financial StatementsMARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $375 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $175 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period. In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength, including the AAA and Aaa ratings of its long-term debt securities by Standard & Poor’s and Moody’s, as a competitive advantage. In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 40 percent of the Corporation’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products. Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its investments over a broad range of future prices. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs. Investment opportunities are tested against a variety of market conditions, including low-price scenarios. The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic objectives. The result is an efficient capital base, and the Corporation has seldom had to write down the carrying value of assets, even during periods of low commodity prices. Risk Management The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. Note 12 summarizes the fair value of derivatives outstanding at year end and the gains or losses that have been recognized in net income. The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings, cash flow or fair value. The Corporation’s cash balances exceeded total debt at year-end 2009 and 2008. The Corporation is not dependent on the credit markets to fund current operations. However, some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.
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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts, commodity forwards, swaps and futures contracts to mitigate the impact of changes in currency values and commodity prices. Exposures related to the Corporation’s limited use of the above contracts are not material. Inflation and Other Uncertainties The general rate of inflation in many major countries of operation increased in 2008 before moderating in 2009, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation works to counter upward pressure on costs through its economies of scale in global procurement and its efficient project management practices. RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS Variable-Interest Entities In 2009, the FASB issued an accounting standard for variable-interest entities (VIEs), which became effective January 1, 2010. The standard requires the enterprise to qualitatively assess if it is the primary beneficiary of the VIE and, if so, the VIE must be consolidated. The Corporation does not expect the adoption of this standard to have a material impact on the Corporation’s financial statements. CRITICAL ACCOUNTING POLICIES The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The following summary provides further information about the critical accounting policies and the judgments that are made by the Corporation in the application of those policies. Oil and Gas Reserves Evaluations of oil and gas reserves are important to the effective management of Upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment. Oil and gas reserves include both proved and unproved reserves. Consistent with the definitions in the Securities and Exchange Commission’s amended Rule 4-10(a) of Regulation S-X, proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not. The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Reserves Technical Oversight group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the reserves estimation process include:
Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels. Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves was 67 percent of total proved reserves at year-end 2009 (including both consolidated and equity company reserves), and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status. Over time, these undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to collect and deliver the production from existing and future wells are installed. Major development projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.
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Table of ContentsIndex to Financial StatementsRevisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in prices and costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity. The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method. The Corporation uses this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of the Corporation’s exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects. Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base. Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value. The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluation include a significant decrease in current and projected reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and forecast operating losses. In general, the Corporation does not view temporarily low oil and gas prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted. Accordingly, any impairment tests that the Corporation performs make use of the Corporation’s price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on individual field production profiles, which are updated annually. Cash flow estimates for impairment testing exclude the use of derivative instruments. Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements. Future prices used for any impairment tests will vary from the one used in the supplemental oil and gas disclosure and could be lower or higher for any given year. Suspended Exploratory Well Costs The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether a project has made sufficient progress is a subjective area and requires careful consideration of the relevant facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2009 are disclosed in note 9 to the financial statements.
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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Consolidations The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in “Investments, advances and long-term receivables”; the Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.” The accounting for these non-consolidated companies is referred to as the equity method of accounting. Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans and management compensation and succession plans. Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 6. Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to balance worldwide risks and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their percentage ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its percentage share of all assets and liabilities in these partially owned companies rather than only its percentage in the net equity. This method of accounting for investments in partially owned companies is not permitted by GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by GAAP standards, the Corporation includes its share of debt of these partially owned companies in the determination of average capital employed. Pension Benefits The Corporation and its affiliates sponsor approximately 100 defined benefit (pension) plans in about 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the Corporation operates. Pension and Other Postretirement Benefits (note 16) provides details on pension obligations, fund assets and pension expense. Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets. For funded plans, including those in the United States, pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes. The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate. Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2009 was 8.0 percent. The 10-year and 20-year actual returns on U.S. pension plan assets are 3 percent and 9 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return
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Table of ContentsIndex to Financial Statementsfor the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $130 million before tax. Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees. Litigation Contingencies A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in note 15. GAAP requires that liabilities for contingencies be recorded when it is probable that a liability has been incurred by the date of the balance sheet and that the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. Significant management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a materially adverse effect on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement. Tax Contingencies The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. GAAP requires recognition and measurement of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns. The benefit of an uncertain tax position can only be recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken in an income tax return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in note 18. Foreign Currency Translation The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment. Downstream and Chemical operations use the local currency, except in countries with a history of high inflation (primarily in Latin America) and Singapore, which uses the U.S. dollar because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas production is predominantly sold in the export market in U.S. dollars. Upstream operations using the U.S. dollar as their functional currency are primarily in Asia, West Africa, Russia and the Middle East. Factors considered by management when determining the functional currency for a subsidiary include: the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of inflation in the country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.
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Table of ContentsIndex to Financial StatementsMANAGEMENT’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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Exxon Mobil Corporation: In our opinion, the accompanying Consolidated Balance Sheets and the related Consolidated Statements of Income, Comprehensive Income, Changes in Equity and Cash Flows present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2009, and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
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Table of ContentsIndex to Financial StatementsA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Dallas, Texas February 26, 2010
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Table of ContentsIndex to Financial StatementsCONSOLIDATED STATEMENT OF INCOME
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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Table of ContentsIndex to Financial StatementsCONSOLIDATED BALANCE SHEET
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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Table of ContentsIndex to Financial StatementsCONSOLIDATED STATEMENT OF CASH FLOWS
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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Table of ContentsIndex to Financial StatementsCONSOLIDATED STATEMENT OF CHANGES IN EQUITY
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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Table of ContentsIndex to Financial StatementsCONSOLIDATED STATEMENT OF CHANGES IN EQUITY (continued)
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
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Table of ContentsIndex to Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide manufacturer and marketer of petrochemicals (Chemical) and participates in electric power generation (Upstream). The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2009 presentation basis. Subsequent events have been evaluated through February 26, 2010, the date the financial statements were issued. 1. Summary of Accounting Policies Principles of Consolidation. The Consolidated Financial Statements include the accounts of those subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the Corporation and for which other shareholders do not possess the right to participate in significant management decisions. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the underlying net assets of other subsidiaries and less-than-majority-owned companies in which a significant ownership percentage interest is held are included in “Investments, advances and long-term receivables”; the Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.” The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Changes in Equity. Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value. Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. In all cases, revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured. Revenues from the production of natural gas properties in which the Corporation has an interest with other producers are recognized on the basis of the Corporation’s net working interest. Differences between actual production and net working interest volumes are not significant. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold. Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs). This gross reporting basis is footnoted on the Consolidated Statement of Income. Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and transactions. The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the underlying hedged items. Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less. Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets. The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method. The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion
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as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. The cost of properties that are not individually significant are aggregated by groups and amortized over the average holding period of the properties of the groups. The valuation allowances are reviewed at least annually. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred. Unit-of-production depreciation is applied to property, plant and equipment, including capitalized exploratory drilling and development costs, associated with productive depletable extractive properties in the Upstream segment. Unit-of-production rates are based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Corporation’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Corporation. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation purposes. Cash flow estimates for impairment testing exclude derivative instruments. Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. Impairments are measured by the amount the carrying value exceeds the fair value. Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted. Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates. Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia, West Africa, Russia and the Middle East, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Share-Based Payments. The Corporation awards share-based compensation to employees in the form of restricted stock and restricted stock units. Compensation expense is measured by the market price of the restricted shares at the date of grant and is recognized in the income statement over the requisite service period of each award. See note 14, Incentive Program, for further details. 2. Accounting Changes Fair Value Measurements. Effective January 1, 2009, ExxonMobil adopted the authoritative guidance for fair value measurements as they relate to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis. The guidance defines fair value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measures. The adoption did not have a material impact on the Corporation’s financial statements. The Corporation previously adopted the guidance as it relates to financial assets and liabilities that are measured at fair value and for nonfinancial assets and liabilities that are measured at fair value on a recurring basis. Noncontrolling Interests. Effective January 1, 2009, ExxonMobil adopted the authoritative guidance on consolidation as it relates to noncontrolling interests. The guidance changed the accounting and reporting
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Table of ContentsIndex to Financial Statementsfor minority interests, which were recharacterized as noncontrolling interests and classified as a component of equity. The guidance requires retrospective adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of the guidance will be applied prospectively. The adoption of the guidance did not have a material impact on the Corporation’s financial statements. Business Combinations. Effective January 1, 2009, ExxonMobil adopted the authoritative guidance for business combinations. This guidance applies prospectively to all transactions in which an entity obtains control of one or more other businesses. In general, the guidance requires the acquiring entity in a business combination to recognize the fair value of all assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the fair value measurement point; and modifies disclosure requirements. It also modifies the accounting treatment for transaction costs by requiring that these be expensed as incurred. The adoption of the guidance did not have a material impact on the Corporation’s financial statements. Earnings Per Share. Effective January 1, 2009, ExxonMobil adopted the authoritative guidance for earnings per share as it relates to determining whether instruments granted in share-based payment transactions are participating securities. The guidance requires that all unvested share-based payment awards that contain nonforfeitable rights to dividends should be included in the basic Earnings Per Share (EPS) calculation. Prior-year EPS numbers have been adjusted retrospectively on a consistent basis with 2009 reporting. This guidance did not affect the consolidated financial position or results of operations. Oil and Gas Reserves. Effective December 31, 2009, ExxonMobil adopted the authoritative guidance for estimating and disclosing oil and gas reserve quantities. Year-end 2009 proved reserve volumes as well as the 2009 reserve change categories were calculated using average prices during the 12-month period. Year-end 2008 and 2007 reserve volumes were calculated using December 31 prices. The effect on unit-of-production depreciation rates of using 12-month average versus December 31 prices will be applied prospectively commencing in 2010. Additionally, the definition of “oil and gas producing activities” has been expanded to include bitumen extracted through mining activities and hydrocarbons from other non-traditional resources. The amended rules also adopted a reliable technology definition that permits reserves to be added based on field-tested technologies. The adoption of this guidance is not expected to have a material impact on the Corporation’s consolidated financial position or results of operations. 3. Miscellaneous Financial Information Research and development costs totaled $1,050 million in 2009, $847 million in 2008 and $814 million in 2007. Net income included before-tax aggregate foreign exchange transaction gains of $54 million, $54 million and $229 million in 2009, 2008 and 2007, respectively. In 2009, 2008 and 2007, net income included gains of $207 million, $341 million and $327 million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $17.1 billion and $10.0 billion at December 31, 2009, and 2008, respectively. Crude oil, products and merchandise as of year-end 2009 and 2008 consist of the following:
4. Cash Flow Information The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents. The “Net (gain) on asset sales” in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes before-tax gains from the sale of Downstream assets and investments and producing properties in the Upstream in 2009; from the sale of a natural gas transportation business in Germany and other producing properties in the Upstream and Downstream assets and investments in 2008; and from the sale of producing properties in the Upstream and Downstream assets and investments in 2007. These gains are reported in “Other income” on the Consolidated Statement of Income. The restriction on $4.6 billion of cash and cash equivalents was released in 2007 following an Alabama Supreme Court judgment in ExxonMobil’s favor.
5. Additional Working Capital Information
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Table of ContentsIndex to Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On December 31, 2009, unused credit lines for short-term financing totaled approximately $4.8 billion. Of this total, $2.3 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2009, and 2008, was 3.6 percent and 5.7 percent, respectively. 6. Equity Company Information The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see note 1). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several power generation, refining, petrochemical/lubes manufacturing and chemical ventures. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 19 percent, 21 percent and 23 percent in the years 2009, 2008 and 2007, respectively.
A list of significant equity companies as of December 31, 2009, together with the Corporation’s percentage ownership interest, is detailed below:
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Table of ContentsIndex to Financial Statements7. Investments, Advances and Long-Term Receivables
8. Property, Plant and Equipment and Asset Retirement Obligations
In the Upstream segment, depreciation is generally on a unit-of-production basis, so depreciable life will vary by field. In the Downstream segment, investments in refinery and lubes basestock manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life and service station buildings and fixed improvements over a 20-year life. In the Chemical segment, investments in process equipment are generally depreciated on a straight-line basis over a 20-year life. Accumulated depreciation and depletion totaled $166,790 million at the end of 2009 and $149,499 million at the end of 2008. Interest capitalized in 2009, 2008 and 2007 was $425 million, $510 million and $557 million, respectively. Asset Retirement Obligations The Corporation incurs retirement obligations for its upstream assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The Corporation uses estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; technical assessments of the assets; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. AROs incurred in the current period were Level 3 (unobservable inputs) fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. The following table summarizes the activity in the liability for asset retirement obligations:
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9. Accounting for Suspended Exploratory Well Costs The Corporation continues capitalization of exploratory well costs beyond one year after the well is completed if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs. Change in capitalized suspended exploratory well costs:
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Table of ContentsIndex to Financial StatementsOf the 57 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2009, 29 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 28 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 28 projects, which total $497 million.
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10. Leased Facilities At December 31, 2009, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $10,365 million as indicated in the table. Estimated related rental income from noncancelable subleases is $128 million.
Net rental cost under both cancelable and noncancelable operating leases incurred during 2009, 2008 and 2007 were as follows:
11. Earnings Per Share
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Table of ContentsIndex to Financial Statements12. Financial Instruments and Derivatives The fair value of financial instruments is determined by reference to various market data and other valuation techniques as appropriate. The estimated fair value of total long-term debt, including capitalized lease obligations, at December 31, 2009, and 2008, was $7.7 billion and $7.6 billion, respectively, as compared to recorded book values of $7.1 billion and $7.0 billion. The fair value hierarchy for long-term debt is primarily Level 2 (observable input). The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. The estimated fair value of derivatives outstanding and recorded on the balance sheet was a net payable of $5 million at year-end 2009 and a net receivable of $118 million at year-end 2008. This is the amount that the Corporation would have paid to, or received from, third parties if these derivatives had been settled in the open market. The Corporation recognized a before-tax loss of $60 million and a before-tax gain of $89 million and $66 million related to derivatives during 2009, 2008 and 2007, respectively. The fair value of derivatives outstanding at year-end 2009 and loss recognized during the year are immaterial in relation to the Corporation’s year-end cash balance of $10.7 billion, total assets of $233.3 billion or net income for the year of $19.3 billion. 13. Long-Term Debt At December 31, 2009, long-term debt consisted of $6,865 million due in U.S. dollars and $264 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $348 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, together with sinking fund payments required, in each of the four years after December 31, 2010, in millions of dollars, are: 2011 – $344, 2012 – $2,725, 2013 – $160 and 2014 – $302. At December 31, 2009, the Corporation’s unused long-term credit lines were not material. Summarized long-term debt at year-end 2009 and 2008 are shown in the table below:
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Table of ContentsIndex to Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Condensed consolidating financial information related to guaranteed securities issued by subsidiaries Exxon Mobil Corporation has fully and unconditionally guaranteed the deferred interest debentures due 2012 ($2,144 million long-term debt at December 31, 2009) and the debt securities due 2010 and 2011 ($13 million long-term and $13 million short-term) of SeaRiver Maritime Financial Holdings, Inc. SeaRiver Maritime Financial Holdings, Inc. is a 100-percent-owned subsidiary of Exxon Mobil Corporation. The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for SeaRiver Maritime Financial Holdings, Inc., as issuer, as an alternative to providing separate financial statements for the issuer. The accounts of Exxon Mobil Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the equity method of accounting for investments in subsidiaries.
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14. Incentive Program The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited or expire, or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2009, remaining shares available for award under the 2003 Incentive Program were 152,591 thousand. As under earlier programs, options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. Most of the options and SARs normally first become exercisable one year following the date of grant. All remaining stock options and SARs outstanding were granted prior to 2002. Long-term incentive awards totaling 10,133 thousand, 10,116 thousand and 10,226 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2009, 2008 and 2007, respectively. These shares are issued to employees from treasury stock. The total compensation expense is recognized over the requisite service period. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. A small number of awards granted to certain senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.
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Table of ContentsIndex to Financial StatementsThe Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in conjunction with benefit plans and programs. Purchases may be discontinued at any time without prior notice. In 2002, the Corporation began issuing restricted stock as share-based compensation in lieu of stock options. Compensation expense for these awards is based on the price of the stock at the date of grant and has been recognized in income over the requisite service period. Prior to 2002, the Corporation issued stock options as share-based compensation and since these awards vested prior to the effective date of current authoritative guidance, they continue to be accounted for under the prior prescribed method. Under this method, compensation expense for awards granted in the form of stock options is measured at the intrinsic value of the options (the difference between the market price of the stock and the exercise price of the options) on the date of grant. Since these two prices were the same on the date of grant, no compensation expense has been recognized in income for these awards. The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2009.
As of December 31, 2009, there was $2,038 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.5 years. The compensation cost charged against income for the restricted stock and restricted units was $723 million, $648 million and $590 million for 2009, 2008 and 2007, respectively. The income tax benefit recognized in income related to this compensation expense was $76 million, $75 million and $81 million for the same periods, respectively. The fair value of shares and units vested in 2009, 2008 and 2007 was $763 million, $438 million and $581 million, respectively. Cash payments of $41 million, $25 million and $29 million for vested restricted stock units settled in cash were made in 2009, 2008 and 2007, respectively.
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Table of ContentsIndex to Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Changes that occurred in stock options in 2009 are summarized below (shares in thousands):
No compensation expense was recognized for stock options in 2009, 2008 and 2007, as all remaining outstanding stock options were granted prior to 2002 and are fully vested. Cash received from stock option exercises was $752 million, $753 million and $1,079 million for 2009, 2008 and 2007, respectively. The cash tax benefit realized for the options exercised was $164 million, $273 million and $304 million for 2009, 2008 and 2007, respectively. The aggregate intrinsic value of stock options exercised in 2009, 2008 and 2007 was $563 million, $894 million and $1,359 million, respectively. The intrinsic value for the balance of outstanding stock options at December 31, 2009, was $1,131 million. 15. Litigation and Other Contingencies Litigation A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation’s operations or financial condition. A number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims and the punitive damage award have been paid.
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Table of ContentsIndex to Financial StatementsOther Contingencies The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2009, for $8,786 million, primarily relating to guarantees for notes, loans and performance under contracts. Included in this amount were guarantees by consolidated affiliates of $5,629 million, representing ExxonMobil’s share of obligations of certain equity companies.
Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition. Unconditional purchase obligations as defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.
In accordance with a nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project. On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes. An affiliate of ExxonMobil has also filed an arbitration under the rules of the International Chamber of Commerce against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. Both arbitration proceedings continue. At this time, the net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition. ExxonMobil’s remaining net book investment in Cerro Negro producing assets is about $750 million.
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16. Pension and Other Postretirement Benefits The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31.
For U.S. plans, the discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using bond portfolios with an average maturity approximating that of the liabilities or spot yield curves, both of which are constructed using high-quality, local-currency-denominated bonds. The measurement of the accumulated postretirement benefit obligation assumes an initial health care cost trend rate of 6.5 percent that declines to 4.5 percent by 2015. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $50 million and the postretirement benefit obligation by $532 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $40 million and the post-retirement benefit obligation by $442 million.
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Table of ContentsIndex to Financial StatementsThe funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
The authoritative guidance for defined benefit pension and other post-retirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.
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Table of ContentsIndex to Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The long-term expected rate of return on funded assets shown below is established for each benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class.
Costs for defined contribution plans were $339 million, $309 million and $287 million in 2009, 2008 and 2007, respectively. A summary of the change in accumulated other comprehensive income is shown in the table below:
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Table of ContentsIndex to Financial StatementsThe Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive equity and fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in high-quality corporate and government debt securities. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for the U.S. benefit plans is 60% equity securities and 40% debt securities. The target asset allocation for the non-U.S. plans in aggregate is 56% equities, 41% debt and 3% real estate funds. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily focus on early-stage venture capital of 5% and 3%, respectively. The authoritative guidance for fair value measurements provides a framework for measuring fair value. The framework establishes a three-level fair value hierarchy based on the nature of the information used to measure fair value. The terms “Level 1,” “Level 2” and “Level 3” are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment. The 2009 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
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The change in the fair value in 2009 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:
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Table of ContentsIndex to Financial StatementsA summary of pension plans with an accumulated benefit obligation in excess of plan assets is shown in the table below:
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17. Disclosures about Segments and Related Information The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries. These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete financial information is available. Earnings after income tax include special items, and transfers are at estimated market prices. Earnings for 2009 included a special charge of $140 million in the corporate and financing segment for interest related to the Valdez punitive damages award. Special items included in 2008 after-tax earnings were a $1,620 million gain in Non-U.S. Upstream on the sale of a natural gas transportation business in Germany and special charges of $460 million in the corporate and financing segment related to the Valdez litigation. There were no special items in 2007. Interest expense includes non-debt-related interest expense of $500 million, $498 million and $290 million in 2009, 2008 and 2007, respectively. Higher expenses in 2009 and 2008 primarily reflect interest provisions related to the Valdez litigation. In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities.
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Table of ContentsIndex to Financial StatementsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS 18. Income, Sales-Based and Other Taxes
All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include net credits for the effect of changes in tax laws and rates of $9 million in 2009, $300 million in 2008 and $258 million in 2007. Income taxes (charged)/credited directly to equity were:
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2009, 2008 and 2007 is as follows:
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Table of ContentsIndex to Financial StatementsDeferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax liabilities/(assets) are comprised of the following at December 31:
Deferred income tax (assets) and liabilities are included in the balance sheet as shown below. Deferred income tax (assets) and liabilities are classified as current or long term consistent with the classification of the related temporary difference – separately by tax jurisdiction.
The Corporation had $42 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material. Unrecognized Tax Benefits Effective January 1, 2007, the Corporation adopted the authoritative guidance for accounting for uncertainty in income taxes. Upon the adoption of this guidance, the Corporation recognized a transition gain of $267 million in equity. The gain reflected the recognition of several refund claims, partly offset by increased liability reserves. The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. Resolution of the related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for individual tax positions since such timing is not entirely within the control of the Corporation. However, it is reasonably possible that resolutions could be reached with tax jurisdictions within the next 12 months that could result in a decrease of up to 15 percent in the total amount of unrecognized tax benefits. Given the long time periods involved in resolving individual tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporation’s effective income tax rate in any given year. The following table summarizes the movement in unrecognized tax benefits.
The additions and reductions in unrecognized tax benefits shown above include effects related to net income and equity, and timing differences for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2009, 2008 and 2007 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income or cash flow. The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense. The Corporation incurred approximately $135 million, $137 million and $128 million in interest expense on income tax reserves in 2009, 2008 and 2007 respectively, and had a related interest payable of $771 million and $671 million at December 31, 2009, and 2008, respectively.
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Table of ContentsIndex to Financial StatementsSUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited) The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical service agreements, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity companies totaled $536 million in 2009, $3,834 million in 2008 and $2,271 million in 2007. Oil sands mining operations were in the excluded amounts for 2008 and 2007. However, beginning in 2009, oil sands mining operations are included in the results of operations in accordance with revised Securities and Exchange Commission and Financial Accounting Standards Board rules. The amounts included for oil sands mining operations in the results of operations for 2009 are shown in footnote 1 below.
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Table of ContentsIndex to Financial StatementsSUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited) Oil and Gas Exploration and Production Costs The amounts shown for net capitalized costs of consolidated subsidiaries are $2,910 million less at year-end 2009 and $5,779 million less at year-end 2008 than the amounts reported as investments in property, plant and equipment for the Upstream in note 8. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations were excluded in 2008 but have been included in the capitalized costs for 2009 in accordance with revised Financial Accounting Standards Board rules.
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Table of ContentsIndex to Financial StatementsOil and Gas Exploration and Production Costs (continued) The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2009 were $20,507 million, up $4,691 million from 2008, due primarily to higher exploration and development costs as well as the inclusion in 2009 of costs incurred related to oil sands mining operations (see footnote 1 below). 2008 costs were $15,816 million, up $3,741 million from 2007, due primarily to higher exploration and development costs. Total equity company costs incurred in 2009 were $1,019 million, down $200 million from 2008, due primarily to lower development costs.
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Table of ContentsIndex to Financial StatementsSUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited) Oil and Gas Reserves The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2007, 2008 and 2009. The definitions used are in accordance with the Securities and Exchange Commission’s amended Rule 4-10 (a) of Regulation S-X. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. In accordance with the Securities and Exchange Commission’s amended rules, the year-end reserves volumes for 2009 as well as the reserves change categories for 2009 shown in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. The year-end reserves volumes for 2007 and 2008 as well as the reserves change categories for 2007 and 2008 shown in the following tables were calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in average prices and year-end costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/ facility capacity. Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and ExxonMobil’s ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids. In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies. Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves that we report for these types of arrangements typically vary inversely with oil and gas price changes. As oil and gas prices increase, the cash flow and value received by the company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2009 that were associated with production sharing contract arrangements was 17 percent of liquids, 13 percent of natural gas and 15 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels). Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported in the Operating Summary due to volumes consumed or flared and inventory changes. As a result of the Securities and Exchange Commission’s amended Rule 4-10, bitumen extracted through mining activities and hydrocarbons from other non-traditional resources are permitted to be reported as oil and gas reserves. Included in 2009 reported proved reserves for the first time were synthetic oil reserves of 691 million barrels, representing the Corporation’s interest in the Syncrude project in Canada and bitumen reserves of 1,356 million barrels, representing the Corporation’s interest in the Kearl project in Canada. The amended rules also adopted a reliable technology definition that permits reserves to be added based on technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated. The estimated impact of changing to an average of the first-day-of-the-month prices and the use of reliable technology was de minimis on the Corporation’s proved reserves volumes in 2009. Major changes between 2008 year-end proved reserves and 2009 year-end proved reserves included the initial booking of the Gorgon Jansz liquefied natural gas (LNG) project in Australia and the Papua New Guinea LNG project and an upwards revision to the Kearl project.
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Table of ContentsIndex to Financial StatementsCrude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves
(See footnotes on next page)
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Table of ContentsIndex to Financial StatementsSUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
Crude Oil, Natural Gas Liquids, Synthetic Oil and Bitumen Proved Reserves (continued)
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Table of ContentsIndex to Financial StatementsNatural Gas and Oil-Equivalent Proved Reserves
(See footnotes on next page)
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Table of ContentsIndex to Financial StatementsSUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
Natural Gas and Oil-Equivalent Proved Reserves (continued)
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Table of ContentsIndex to Financial StatementsStandardized Measure of Discounted Future Cash Flows As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows was computed through 2008 by applying year-end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. Beginning in 2009, the standardized measure of discounted future net cash flow is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
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Table of ContentsIndex to Financial StatementsSUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
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Table of ContentsIndex to Financial StatementsChange in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
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Operating statistics include 100 percent of operations of majority-owned subsidiaries; for other companies, crude production, gas, petroleum product and chemical prime product sales include ExxonMobil’s ownership percentage and refining throughput includes quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is made in kind or cash.
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Table of ContentsIndex to Financial StatementsPROXY INFORMATION SECTION TABLE OF CONTENTS
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Table of ContentsIndex to Financial StatementsDirector Qualifications The Board has adopted guidelines outlining the qualifications sought when considering non-employee director candidates and they are published on our Web site at exxonmobil.com/governance. In part, the guidelines describe the necessary experiences and skills expected of director candidates as follows: “Candidates for non-employee director of Exxon Mobil Corporation should be individuals who have achieved prominence in their fields, with experience and demonstrated expertise in managing large, relatively complex organizations, and/or, in a professional or scientific capacity, be accustomed to dealing with complex situations preferably those with worldwide scope.” The key criteria the Board seeks across its membership to achieve a balance of experiences important to the Corporation include: financial expertise; experience as the CEO of a significant company or organization or as a next-level executive with responsibilities for global operations; experience managing large, complex organizations; experience on one or more boards of significant public or non-profit organizations; and expertise resulting from significant academic, scientific or research activities. The table below describes the particular experience, qualifications, attributes, and skills of each director that led the Board to conclude that such person should serve as a director of the Company.
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Director Independence Our Corporate Governance Guidelines require that a substantial majority of the Board consist of independent directors. In general the Guidelines require that an independent director must have no material relationship with ExxonMobil, directly or indirectly, except as a director. The Board determines independence on the basis of the standards specified by the New York Stock Exchange (NYSE), the additional standards referenced in our Corporate Governance Guidelines, and other facts and circumstances the Board considers relevant. Under ExxonMobil’s Corporate Governance Guidelines, a director will not be independent if a reportable
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Table of ContentsIndex to Financial Statements“related person transaction” exists with respect to that director or a member of the director’s family for the current or most recently completed fiscal year. See the Guidelines for Review of Related Person Transactions posted on the Corporate Governance section of our Web site and described in more detail under “Related Person Transactions and Procedures” on pages 111-112. The Board has reviewed relevant relationships between ExxonMobil and each non-employee director and director nominee to determine compliance with the NYSE standards and ExxonMobil’s additional standards. The Board has also evaluated whether there are any other facts or circumstances that might impair a director’s independence. Based on that review, the Board has determined that all ExxonMobil non-employee directors and director nominees are independent. The Board has also determined that each member of the Audit, Board Affairs, Compensation, and Public Issues and Contributions Committees is independent. In recommending that each director and nominee be found independent, the Board Affairs Committee reviewed the following transactions, relationships, or arrangements. All matters described below fall within the NYSE and ExxonMobil independence standards.
Code of Ethics and Business Conduct The Board maintains policies and procedures (which we refer to as the “Code”) that represent both the code of ethics for the principal executive officer, principal financial officer, and principal accounting officer under SEC rules, and the code of business conduct and ethics for directors, officers, and employees under NYSE listing standards. The Code applies to all directors, officers, and employees. The Code includes a Conflicts of Interest Policy under which directors, officers, and employees are expected to avoid any actual or apparent conflict between their own personal interests and the interests of the Corporation. The Code is posted on the ExxonMobil Web site at exxonmobil.com/governance. The Code is also included as an exhibit to our Annual Report on Form 10-K. Any amendment of the Code will be posted promptly on our Web site. The Corporation maintains procedures for administering and reviewing potential issues under the Code, including procedures that allow employees to make complaints without identifying themselves. The Corporation also conducts periodic mandatory business practice training sessions and requires each regular employee and non-employee director to make an annual compliance certification. The Board Affairs Committee will initially review any suspected violation of the Code involving an executive officer or director and will report its findings to the Board. The Board does not envision that any waiver of the Code will be granted. Should such a waiver occur, it will be promptly disclosed on our Web site.
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Table of ContentsIndex to Financial StatementsRelated Person Transactions and Procedures In accordance with SEC rules, ExxonMobil maintains Guidelines for Review of Related Person Transactions. These Guidelines are available on the Corporate Governance section of our Web site. In accordance with the Related Person Transaction Guidelines, all executive officers, directors, and director nominees are required to identify, to the best of their knowledge after reasonable inquiry, business and financial affiliations involving themselves or their immediate family members that could reasonably be expected to give rise to a reportable related person transaction. Covered persons must also advise the Secretary of the Corporation promptly of any change in the information provided, and will be asked periodically to review and re-affirm their information. For the above purposes, “immediate family member” includes a person’s spouse, parents, siblings, children, in-laws, and step-relatives. Based on this information, we review the Company’s own records and make follow-up inquiries as may be necessary to identify potentially reportable transactions. A report summarizing such transactions and including a reasonable level of detail is then provided to the Board Affairs Committee. The Committee oversees the Related Person Transaction Guidelines generally and reviews specific items to assess materiality. In assessing materiality for this purpose, information will be considered material if, in light of all the circumstances, there is a substantial likelihood a reasonable investor would consider the information important in deciding whether to buy or sell ExxonMobil stock or in deciding how to vote shares of ExxonMobil stock. A director will abstain from the decision on any transactions involving that director or his or her immediate family members. Under SEC rules, certain transactions are deemed not to involve a material interest (including transactions in which the amount involved in any 12-month period is less than $120,000 and transactions with entities where a related person’s interest is limited to service as a non-employee director). In addition based on a consideration of ExxonMobil’s facts and circumstances, the Committee will presume that the following transactions do not involve a material interest for purposes of reporting under SEC rules:
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Table of ContentsIndex to Financial StatementsTransactions or relationships not covered by the above standards will be assessed by the Committee on the basis of the specific facts and circumstances. The following disclosures are made as of February 24, 2010, the date of the most recent Board Affairs Committee review of potential related person transactions. ExxonMobil and its affiliates have about 81,000 employees around the world and employees related by birth or marriage may be found at all levels of the organization. The spouse of T.R. Walters, a Vice President of the Corporation, retired from ExxonMobil in 2009. Excluding pension and other retirement-related distributions, her partial-year compensation was less than $120,000. ExxonMobil employees do not receive preferential treatment by reason of being related to an executive officer, and executive officers do not participate in hiring, performance evaluation, or compensation decisions for family members. ExxonMobil’s employment guidelines state: “Relatives of Company employees may be employed on a non-preferential basis. However an employee should not be employed by or assigned to work under the direct supervision of a relative, or to report to a supervisor who in turn reports to a relative of the employee.” Accordingly, consistent with ExxonMobil’s Related Person Transaction Guidelines, we do not consider the relationship noted above to be material within the meaning of the related person transaction disclosure rules. P.T. Mulva (Vice President and Controller) has a brother currently serving as Chairman and CEO of ConocoPhillips. As is the case with most other major companies in the oil and gas industry, ExxonMobil has a variety of business transactions with ConocoPhillips. These transactions include routine purchases and sales of crude oil, petroleum products, and pipeline transportation capacity. Affiliates of ExxonMobil and ConocoPhillips have joint ownership of a refinery in Germany and a number of pipelines, terminals, emergency response companies, and service companies, and also have undivided interests in a variety of exploration, development, and production projects. All of these transactions are entered into in the ordinary course of business without influence from P.T. Mulva. Neither P.T. Mulva nor, to our knowledge after reasonable inquiry, his brother, has any interest in these transactions different from the general interest of other employees and shareholders. Accordingly, consistent with ExxonMobil’s Related Person Transaction Guidelines, we do not consider these transactions to be material within the meaning of the related person transaction disclosure rules. S.R. LaSala (retired Vice President and General Tax Counsel) has a son who is a partner of a law firm that performs work for ExxonMobil. Mr. LaSala is not involved in decisions to retain the firm, and, therefore, we do not consider the relationship to be material within the meaning of the related person transaction disclosure rules. S.J. Glass, Jr. (Vice President) has a brother who is a partner of a law firm that performs work for ExxonMobil. Mr. Glass is not involved in decisions to retain the firm, and, therefore, we do not consider the relationship to be material within the meaning of the related person transaction disclosure rules. The Board Affairs Committee also reviewed ExxonMobil’s ordinary course business with companies for which non-employee directors serve as executive officers and determined that, in accordance with the categorical standards described above, none of those matters represent reportable related person transactions. See “Director Independence” on page 109. We are not aware of any related person transaction required to be reported under applicable SEC rules since the beginning of the last fiscal year where our policies and procedures did not require review, or where such policies and procedures were not followed. The Corporation’s Related Person Transaction Guidelines are intended to assist the Corporation in complying with its disclosure obligations under SEC rules. These procedures are in addition to, not in lieu of, the Corporation’s Code of Ethics and Business Conduct.
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Table of ContentsIndex to Financial StatementsDIRECTOR INFORMATION
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DIRECTOR COMPENSATION Director compensation elements are designed to:
Non-employee director compensation levels are reviewed by the Board Affairs Committee each year, and resulting recommendations are presented to the full Board for approval. The Committee uses an independent consultant, Pearl Meyer & Partners, to provide information on current developments and practices in director compensation. Pearl Meyer & Partners is the same consultant retained by the Compensation Committee to advise on executive compensation, but performs no other work for ExxonMobil. ExxonMobil employees receive no additional pay for serving as directors.
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Table of ContentsIndex to Financial StatementsNon-employee directors receive compensation consisting of cash and equity in the form of restricted stock. Non-employee directors are also reimbursed for reasonable expenses incurred to attend board meetings or other functions relating to their responsibilities as a director of Exxon Mobil Corporation. The annual cash retainer for non-employee directors is $100,000 per year. Chairs of the Audit and Compensation Committees and the Presiding Director (effective January 2010) receive an additional $10,000 per year. A significant portion of director compensation is paid in restricted stock to align director compensation with the long-term interests of shareholders. The annual restricted stock award grant for incumbent non-employee directors is 2,500 shares. A new non-employee director receives a one-time grant of 8,000 shares of restricted stock upon first being elected to the Board. While on the Board, the non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the non-employee director is not allowed to sell the shares. The restricted shares may be forfeited if the non-employee director leaves the Board early, i.e., before the retirement age of 72, as specified for non-employee directors. Current and former non-employee directors of Exxon Mobil Corporation are eligible to participate in the ExxonMobil Foundation’s Educational and Cultural Matching Gift Programs under the same terms as the Corporation’s U.S. employees. Director Compensation for 2009
Each director (other than Mr. Frazier, who joined the Board in May 2009) received an annual grant of 2,500 restricted shares in January 2009. The valuation of these awards is based on a market price of $80.51 on the date of grant. Mr. Frazier received a one-time grant of 8,000 restricted shares upon being first elected to the Board in May 2009. The valuation of this award is based on a market price of $69.29 on the date of grant.
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Table of ContentsIndex to Financial StatementsAt year-end 2009, the aggregate number of restricted shares held by each director was as follows:
The non-employee directors are not entitled to any additional payments or benefits as a result of leaving the Board or death except as described above. The non-employee directors are not entitled to any payments or benefits resulting from a change in control of the Corporation. CERTAIN BENEFICIAL OWNERS Based on our review of ownership reports filed with the SEC, the firm listed below is the only beneficial owner of more than 5 percent of ExxonMobil’s outstanding common stock as of December 31, 2009.
DIRECTOR AND EXECUTIVE OFFICER STOCK OWNERSHIP These tables show the number of ExxonMobil common stock shares each executive named in the “Summary Compensation Table” on page 136 and each non-employee director or director nominee owned on January 31, 2010. In these tables, ownership means the right to direct the voting or the sale of shares, even if those rights are shared with someone else. None of these individuals owns more than 0.04 percent of the outstanding shares.
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On January 31, 2010, ExxonMobil’s incumbent directors and executive officers (28 people) together owned 8,481,906 shares of ExxonMobil stock and 1,924,903 shares covered by exercisable options, representing about 0.2 percent of the outstanding shares. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities and Exchange Act of 1934 requires that our executive officers and directors file reports of their ownership and changes in ownership of ExxonMobil stock on Forms 3, 4, and 5 with the SEC and NYSE. We are not aware of any unfiled reports and are not aware of any late reports for 2009. AUDITOR INFORMATION The Audit Committee has appointed PricewaterhouseCoopers LLP (PwC) to audit ExxonMobil’s financial statements for 2010. Total Fees The total fees for PwC professional services rendered to ExxonMobil for the year ended December 31, 2009, were $33.5 million, a decrease of $1.4 million from 2008. The Audit Committee reviewed and pre-approved all services in accordance with the service pre-approval policies and procedures, which can be found on the ExxonMobil Web site at exxonmobil.com/governance. The Audit Committee did not use the “de minimis” exception to pre-approval that is available under SEC rules. The following table summarizes the fees, which are described in more detail below.
Audit Fees The aggregate fees for PwC professional services rendered for the annual audits of ExxonMobil’s financial statements for the year ended December 31, 2009, and for the reviews of the financial statements included in our quarterly reports on Form 10-Q for that year were $26.2 million (versus $24.8 million for 2008).
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Table of ContentsIndex to Financial StatementsAudit-Related Fees The aggregate fees for PwC Audit-Related services rendered to ExxonMobil for the year ended December 31, 2009, were $5.4 million (versus $6.1 million in 2008). These services were mainly related to asset dispositions, benefit plan and joint venture audits, and attestation procedures related to cost certifications. Tax Fees The aggregate fees for PwC Tax services rendered to ExxonMobil for the year ended December 31, 2009, were $1.9 million (versus $4.0 million for 2008). These services are described below.
All Other Fees The aggregate fees for PwC services rendered to ExxonMobil, other than the services described above under “Audit Fees,” “Audit-Related Fees,” and “Tax Fees,” for the year ended December 31, 2009, were zero (also zero in 2008). PwC has been ExxonMobil’s independent auditing firm for many years, and we believe they are well-qualified for the job. A PwC representative will be at the annual meeting to answer appropriate questions and to make a statement if he desires. COMPENSATION COMMITTEE REPORT The Compensation Committee of the Board of Directors has reviewed and discussed the “Compensation Discussion and Analysis” for 2009 with management of the Corporation. Based on that review and discussion, we recommended to the Board that the “Compensation Discussion and Analysis” be included in the Corporation’s proxy statement for the 2010 annual meeting of shareholders, and also in the Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009.
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Table of ContentsIndex to Financial StatementsCOMPENSATION DISCUSSION AND ANALYSIS The Compensation Discussion and Analysis and Executive Compensation Tables are organized as follows:
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Table of ContentsIndex to Financial StatementsOverview Providing energy to meet the world’s demands is a complex business. We meet this challenge by taking a long-term view rather than reacting to short-term business cycles. The compensation program of ExxonMobil aligns with and supports the long-term business fundamentals and core business strategies outlined below and illustrated in the model on page 123. Business Environment
Key Business Strategies
Key Elements of the Compensation Program The key elements of our compensation program and staffing objectives that support the business fundamentals and strategies are:
Other Supporting Compensation and Staffing Practices
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Business Performance and Basis for Compensation Decisions
Key Changes for Named Executive Officers in 2009
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Table of ContentsIndex to Financial StatementsPeople and Business Strategies Model The following summary illustrates how the compensation and executive development strategies support and integrate with ExxonMobil’s business model. This integrated approach supports long-term growth in shareholder value. Fully Integrated People and Business Strategies Model
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Table of ContentsIndex to Financial StatementsKey Elements of the Compensation Program Career Orientation
Salary
Bonus
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Equity
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Rationale
Restriction Periods
Forfeiture Risk and Hedging Policy
Share Utilization
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Table of ContentsIndex to Financial StatementsPrior Stock Programs
Stock Ownership
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Table of ContentsIndex to Financial StatementsRetirement Common Programs
Pension Plans
Qualified Savings Plan
Nonqualified Savings Plan
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Table of ContentsIndex to Financial StatementsCompensation Committee Decisions The Committee sets the compensation for the Named Executive Officers and certain other senior executives. The following describes the basis on which the Committee made decisions in 2009.
Analytical Tools Tally Sheets
Pension Modeling
Benchmarking
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Performance Measurements Decisions made by the Compensation Committee in 2009 were based on the Company’s operating and financial performance, as well as individual performance, experience and level of responsibility as described below.
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Table of ContentsIndex to Financial StatementsBusiness Results Considered The operating and financial performance measurements listed below and the Company’s continued maintenance of sound business controls and a strong corporate governance environment formed the basis for the salary and incentive award decisions made by the Committee in 2009. The Committee considered the results in the aggregate and over multiple years, in recognition of the long-term nature of our business.
Performance Assessment Process
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Individual Experience and Responsibility Experience and assigned responsibilities are factors in assessing the contribution of individual executives. The current responsibilities, tenure in the current job, and recent past experience of each Named Executive Officer are described below. Refer to page 136 for information on the leadership structure of the Company.
As discussed on page 124, the career service for Named Executive Officers ranges from 29 to over 38 years. Pay Awarded to Named Executive Officers
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Table of ContentsIndex to Financial StatementsCEO
Other Named Executive Officers
Compensation Allocation
Salary
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Restricted Stock
Other Compensation
Award Timing
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Table of ContentsIndex to Financial StatementsSummary Compensation Table for 2009
Leadership Structure
Employment Arrangements ExxonMobil’s Compensation Committee believes senior executives should be “at will” employees of the Corporation. Accordingly, the CEO and other executive officers, including the other officers named in these tables, do not have employment contracts, severance agreements, or change-in-control arrangements with the Company.
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Table of ContentsIndex to Financial StatementsSalary
Bonus
Stock Awards
Change in Pension Value and Nonqualified Deferred Compensation Earnings The amounts shown in this column in the “Summary Compensation Table” for years 2009 and 2008 represent the change in pension value. For year 2007, the amount also includes nonqualified deferred earnings for Messrs. Tillerson, Humphreys, and Cramer. Pension Value
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Nonqualified Deferred Earnings
All Other Compensation The following table breaks down the amounts included in the “All Other Compensation” column of the “Summary Compensation Table.” Note the table has been changed from last year as follows: removed the columns “Relocation” and “Tax Assistance” since the Named Executive Officers did not have any relocation costs or receive any tax assistance in 2009.
Life Insurance
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Table of ContentsIndex to Financial StatementsSavings Plan
Personal Security
Aircraft
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Car
Financial Planning
Grants of Plan-Based Awards for 2009
The awards granted in 2009 are in the form of restricted stock. Restrictions and Forfeiture Risk
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Grant Date
Outstanding Equity Awards at Fiscal Year-End for 2009
Option Awards
Stock Awards (Restricted Stock/Units)
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Option Exercises and Stock Vested for 2009
Option Awards
Stock Awards/Restriction Lapse in 2009
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Pension Benefits for 2009
Pension Plan
Supplemental Pension Plan
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Additional Payments Plan
Present Value Pension Calculations
Other Plan Terms
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Nonqualified Deferred Compensation for 2009
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Administrative Services for Retired Employee Directors
Health Care Benefits
Unused Vacation
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Table of ContentsIndex to Financial StatementsTermination and Change in Control
Payments in the Event of Death The only event that results in acceleration of the normal payment or vesting schedule of any benefit is death. In that event, the vesting period of outstanding restricted stock awards would be accelerated. Also in the event of death, the executive’s estate or beneficiaries would be entitled to payment of the life insurance or death benefit as described beginning on page 138. At year-end 2009, the amount of that life insurance benefit for each Named Executive Officer is as follows:
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Dated February 26, 2010
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Beverley A. Babcock, Randall M. Ebner and Robert N. Schleckser and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Table of ContentsIndex to Financial StatementsINDEX TO EXHIBITS—(continued)
The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request.
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