2011
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
For the transition period from to
Commission File Number 1-2256
EXXON MOBIL CORPORATION
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298
(Address of principal executive offices) (Zip Code)
(972) 444-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
on Which Registered
Common Stock, without par value (4,713,220,567 sharesoutstanding at January 31, 2012)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer ¨
Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes ¨ No þ
The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $81.38 on the New York Stock Exchange composite tape, was in excess of $395 billion.
Documents Incorporated by Reference:
Proxy Statement for the 2012 Annual Meeting of Shareholders (Part III)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011
TABLE OF CONTENTS
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits, Financial Statement Schedules
Financial Section
Signatures
Index to Exhibits
Exhibit 12 — Computation of Ratio of Earnings to Fixed Charges
Exhibits 31 and 32 — Certifications
PART I
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 includeExxonMobil, Exxon, Esso or Mobil. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso and Mobil, as well as terms like Corporation, Company,our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.
Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to monitor and reduce nitrogen oxide, sulfur oxide, and greenhouse gas emissions and expenditures for asset retirement obligations. ExxonMobil’s 2011 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were $4.9 billion, of which $3.2 billion were included in expenses with the remainder in capital expenditures. The total cost for such activities is expected to remain in this range in 2012 and 2013 (with capital expenditures approximately 45 percent of the total).
The energy and petrochemical industries are highly competitive. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. The Corporation competes with other firms in the sale or purchase of needed goods and services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes.
Operating data and industry segment information for the Corporation are contained in the Financial Section of this report under the following: “Quarterly Information”, “Note 17: Disclosures about Segments and Related Information” and “Operating Summary”. Information on oil and gas reserves is contained in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report.
ExxonMobil has a long-standing commitment to the development of proprietary technology. We have a wide array of research programs designed to meet the needs identified in each of our business segments. Information on Company-sponsored research and development spending is contained in “Note 3: Miscellaneous Financial Information” of the Financial Section of this report. ExxonMobil held approximately 10 thousand active patents worldwide at the end of 2011. For technology licensed to third parties, revenues totaled approximately $129 million in 2011. Although technology is an important contributor to the overall operations and results of our Company, the profitability of each business segment is not dependent on any individual patent, trade secret, trademark, license, franchise or concession.
The number of regular employees was 82.1 thousand, 83.6 thousand and 80.7 thousand at years ended 2011, 2010 and 2009, respectively. Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporation’s benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 17.0 thousand, 20.1 thousand and 22.0 thousand at years ended 2011, 2010 and 2009, respectively.
Information concerning the source and availability of raw materials used in the Corporation’s business, the extent of seasonality in the business, the possibility of renegotiation of profits or termination of contracts at the election of governments and risks attendant to foreign operations may be found in “Item 1A–Risk Factors” and “Item 2–Properties” in this report.
ExxonMobil maintains a website at exxonmobil.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines
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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. These risk factors include:
Supply and Demand
The oil, gas, and petrochemical businesses are fundamentally commodity businesses. This means ExxonMobil’s operations and earnings may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on refined products. Oil, gas, petrochemical and product prices and margins in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity.
Economic conditions. The demand for energy and petrochemicals correlates closely with general economic growth rates. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our results. Other factors that affect general economic conditions in the world or in a major region, such as changes in population growth rates, periods of civil unrest, government austerity programs, or currency exchange rate fluctuations, can also impact the demand for energy and petrochemicals. Sovereign debt downgrades, defaults, inability to access debt markets due to credit or legal constraints, liquidity crises, the breakup or restructuring of fiscal, monetary, or political systems such as the European Union, and other events or conditions that impair the functioning of financial markets and institutions also pose risks to ExxonMobil, including risks to the safety of our financial assets and to the ability of our partners and customers to fulfill their commitments to ExxonMobil.
Other demand-related factors. Other factors that may affect the demand for oil, gas and petrochemicals, and therefore impact our results, include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy sources that have so far generally not been competitive with oil and gas without the benefit of government subsidies or mandates; and changes in technology or consumer preferences that alter fuel choices, such as toward alternative fueled vehicles.
Other supply-related factors. Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity tend to reduce margins on the affected products. World oil, gas, and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries to OPEC production quotas and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, or unexpected unavailability of distribution channels that may disrupt supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.
Other market factors. ExxonMobil’s business results are also exposed to potential negative impacts due to changes in interest rates, inflation, and other local or regional market conditions. We generally do not use financial instruments to hedge market exposures.
Government and Political Factors
ExxonMobil’s results can be adversely affected by political or regulatory developments affecting our operations.
Access limitations. A number of countries limit access to their oil and gas resources, or may place resources off-limits from development altogether. Restrictions on foreign investment in the oil and gas sector tend to increase in times of high commodity prices, when national governments may have less need of outside sources of private capital. Many countries also restrict the import or export of certain products based on point of origin.
Restrictions on doing business. As a U.S. company, ExxonMobil is subject to laws prohibiting U.S. companies from doing business in certain countries, or restricting the kind of business that may be conducted. Such restrictions may provide a competitive advantage to our non-U.S. competitors unless their own home countries impose comparable restrictions.
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Lack of legal certainty. Some countries in which we do business lack well-developed legal systems, or have not yet adopted clear regulatory frameworks for oil and gas development. Lack of legal certainty exposes our operations to increased risk of adverse or unpredictable actions by government officials, and also makes it more difficult for us to enforce our contracts. In some cases these risks can be partially offset by agreements to arbitrate disputes in an international forum, but the adequacy of this remedy may still depend on the local legal system to enforce an award.
Regulatory and litigation risks. Even in countries with well-developed legal systems where ExxonMobil does business, we remain exposed to changes in law (including changes that result from international treaties and accords) that could adversely affect our results, such as:
increases in taxes or government royalty rates (including retroactive claims);
price controls;
changes in environmental regulations or other laws that increase our cost of compliance or reduce or delay available business opportunities (including changes in laws related to offshore drilling operations, water use, or hydraulic fracturing);
adoption of regulations mandating the use of alternative fuels or uncompetitive fuel components;
adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information, or that could cause us to violate the non-disclosure laws of other countries; and
government actions to cancel contracts, re-denominate the official currency, renounce or default on obligations, renegotiate terms unilaterally, or expropriate assets.
Legal remedies available to compensate us for expropriation or other takings may be inadequate.
We also may be adversely affected by the outcome of litigation or other legal proceedings, especially in countries such as the United States in which very large and unpredictable punitive damage awards may occur.
Security concerns. Successful operation of particular facilities or projects may be disrupted by civil unrest, acts of sabotage or terrorism, and other local security concerns. Such concerns may require us to incur greater costs for security or to shut down operations for a period of time.
Climate change and greenhouse gas restrictions. Due to concern over the risk of climate change, a number of countries have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These include adoption of cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. These requirements could make our products more expensive, lengthen project implementation times, and reduce demand for hydrocarbons, as well as shifting hydrocarbon demand toward relatively lower-carbon sources such as natural gas. Current and pending greenhouse gas regulations may also increase our compliance costs, such as for monitoring or sequestering emissions.
Government sponsorship of alternative energy. Many governments are providing tax advantages and other subsidies and mandates to make alternative energy sources more competitive against oil and gas. Governments are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources. We are conducting our own research efforts into alternative energy, such as through sponsorship of the Global Climate and Energy Project at Stanford University and research into hydrogen fuel cells and fuel-producing algae. Our future results may depend in part on the success of our research efforts and on our ability to adapt and apply the strengths of our current business model to providing the competitive energy products of the future. See “Management Effectiveness” below.
Management Effectiveness
In addition to external economic and political factors, our future business results also depend on our ability to manage successfully those factors that are at least in part within our control. The extent to which we manage these factors will impact our performance relative to competition. For projects in which we are not the operator, we depend on the management effectiveness of one or more co-venturers whom we do not control.
Exploration and development program. Our ability to maintain and grow our oil and gas production depends on the success of our exploration and development efforts. Among other factors, we must continuously improve our ability to identify the most promising resource prospects and apply our project management expertise to bring discovered resources on line on schedule.
Project management. The success of ExxonMobil’s Upstream, Downstream, and Chemical businesses depends on complex, long-term, capital intensive projects. These projects in turn require a high degree of project management expertise to maximize efficiency. Specific factors that can affect the performance of major projects include our ability to: negotiate successfully with joint venturers, partners, governments, suppliers, customers, or others; model and optimize reservoir performance; develop markets for project outputs, whether through long-term contracts or the development of effective spot markets; manage changes in operating conditions and costs, including
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costs of third party equipment or services such as drilling rigs and shipping; prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled project downtime; and influence the performance of project operators where ExxonMobil does not perform that role.
Operational efficiency. An important component of ExxonMobil’s competitive performance, especially given the commodity-based nature of many of our businesses, is our ability to operate efficiently, including our ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements and regular reappraisal of our asset portfolio.
Research and development. To maintain our competitive position, especially in light of the technological nature of our businesses and the need for continuous efficiency improvement, ExxonMobil’s research and development organizations must be successful and able to adapt to a changing market and policy environment.
Safety, business controls, and environmental risk management. Our results depend on management’s ability to minimize the inherent risks of oil, gas, and petrochemical operations, to control effectively our business activities and to minimize the potential for human error. We apply rigorous management systems and continuous focus to workplace safety and to avoiding spills or other adverse environmental events. For example, we work to minimize spills through a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. Similarly, we are implementing cost-effective new technologies and adopting new operating practices to reduce air emissions, not only in response to government requirements but also to address community priorities. We also maintain a disciplined framework of internal controls and apply a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if our management systems and controls do not function as intended. The ability to insure against such risks is limited by the capacity of the applicable insurance markets, which may not be sufficient.
Business risks also include the risk of cybersecurity breaches. If our systems for protecting against cybersecurity risks prove not to be sufficient, ExxonMobil could be adversely affected such as by having its business systems compromised, its proprietary information altered, lost or stolen, or its business operations disrupted.
Preparedness. Our operations may be disrupted by severe weather events, natural disasters, human error, and similar events. For example, hurricanes may damage our offshore production facilities or coastal refining and petrochemical plants in vulnerable areas. Our ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of our rigorous disaster preparedness and response planning, as well as business continuity planning.
Projections, estimates and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 1A, 2, 7 and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report.
As in other years, we received comments from the SEC staff regarding our Form 10-K for 2010. We received an initial letter from the staff on July 5, 2011, which included comments and requests for supplemental information on a variety of topics. We responded to these comments on August 25, 2011. On December 7, 2011, we received several follow-up comments from the staff, to which we responded on January 11, 2012. On February 7, 2012, we received one follow-up comment from the staff, to which we responded on February 21, 2012. We do not believe the remaining comment is material and expect it to be fully resolved in the near future. Disclosures responsive to the SEC staff’s comments have been included in this report.
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Information with regard to oil and gas producing activities follows:
1. Disclosure of Reserves
A. Summary of Oil and Gas Reserves at Year-End 2011
The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favorable or adverse event has occurred since December 31, 2011, that would cause a significant change in the estimated proved reserves as of that date.
Crude
Oil
Synthetic
Natural
Gas
Oil-Equivalent
Basis
Proved Reserves
Developed
Consolidated Subsidiaries
United States
Canada/South America(1)
Europe
Africa
Asia
Australia/Oceania
Total Consolidated
Equity Companies
Total Equity Company
Total Developed
Undeveloped
Total Undeveloped
Total Proved Reserves
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In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.
The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the period 2012-2016. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, weather events, price effects on production sharing contracts and other factors as described in Item 1A—Risk Factors of this report.
The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and gas price levels.
B. Technologies Used in Establishing Proved Reserves Additions in 2011
Additions to ExxonMobil’s proved reserves in 2011 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements including high-quality 2-D and 3-D seismic data, calibrated with available well control information. Where applicable, surface geological information was also utilized. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software and commercially available data analysis packages.
In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.
C. Qualifications of Reserves Technical Oversight Group and Internal Controls over Proved Reserves
ExxonMobil has a dedicated Reserves Technical Oversight group that is separate from the operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with Securities and Exchange Commission (SEC) rules and regulations, review of annual changes in reserves estimates, and the reporting of ExxonMobil’s proved reserves. This group also maintains the official company reserves estimates for ExxonMobil’s proved reserves of crude and natural gas liquids, bitumen, synthetic oil and natural gas. In addition, the group provides training to personnel involved in the reserves estimation and reporting process within ExxonMobil and its affiliates. The group is managed by and staffed with individuals that have an average of more than 20 years of technical experience in the petroleum industry, including expertise in the classification and categorization of reserves under the SEC guidelines. This group includes several individuals who hold advanced degrees in either Engineering or Geology, as well as individuals who hold Bachelor’s degrees in various technical disciplines. Several members of the group hold professional registrations in their field of expertise and several have served on the Oil and Gas Reserves Committee of the Society of Petroleum Engineers.
The Reserves Technical Oversight group maintains a central computerized database containing the official company global reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central computerized database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations and analysis of well and field performance and a rigorous peer review. No changes may be made to the reserves estimates in the central database, including additions of any new initial reserves estimates or subsequent revisions, unless these changes have been thoroughly reviewed and evaluated by duly authorized personnel within the operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and approval of the appropriate level of management within the operating organization before the changes may be made in the central database. Endorsement by the Reserves Technical Oversight group for all proved reserves changes is a mandatory component of this review process. After all changes are made, reviews are held with senior management for final endorsement.
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2. Proved Undeveloped Reserves
At year-end 2011, approximately 8.8 billion oil-equivalent barrels (GOEB) of ExxonMobil’s proved reserves were classified as proved undeveloped. This represents 35 percent of the 24.9 GOEB reported in proved reserves. This compares to the 7.7 GOEB of proved undeveloped reserves reported at the end of 2010. The net increase of 1.1 GOEB is primarily due to the addition of new projects in Canada and the United States. During the year, ExxonMobil conducted development activities in over 100 fields that resulted in the transfer of approximately 0.5 GOEB from proved undeveloped to proved developed reserves by year-end. The largest individual transfer was related to completion of drilling and the initiation of production activities on new pad locations in the Cold Lake field in Canada.
One of ExxonMobil’s requirements for reporting proved reserves is that management has made significant funding commitments toward the development of the reserves. ExxonMobil has a disciplined investment strategy and many major fields require long lead-time in order to be developed. Development projects typically take two to four years from the time of first recording of proved reserves to the start of production of these reserves. However, the development time for large and complex projects can exceed five years. During 2011, discoveries and extensions related to new projects added approximately 1.5 GOEB of proved undeveloped reserves. The largest of these additions were related to the Kearl Expansion project in Canada and additions for planned drilling in the United States. Overall, investments of $23.1 billion were made by the Corporation during 2011 to progress the development of reported proved undeveloped reserves, including $20.5 billion for oil and gas producing activities and an additional $2.6 billion for other non-oil and gas producing activities such as the construction of LNG trains, support infrastructure and other related facilities that were undertaken to progress the development of proved undeveloped reserves. These investments represented 70 percent of the $33.1 billion in total reported Upstream capital and exploration expenditures.
Proved undeveloped reserves in the United States, Kazakhstan, the Netherlands, Nigeria and Canada have remained undeveloped for five years or more primarily due to constraints on the capacity of infrastructure and the pace of co-venturer/government funding, as well as the time required to complete development for very large projects. The Corporation is reasonably certain that these proved reserves will be produced; however, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance and regulatory approvals. Approximately one-third of the proved undeveloped reserves that have been reported for five or more years are located in three fields in Kazakhstan and the Netherlands. In Kazakhstan, the first is the initial development of the giant offshore Kashagan field which is included in the North Caspian Production Sharing Agreement in which ExxonMobil participates. The second is the Tengizchevroil joint venture which includes a production license in the Tengiz field and the nearby Korolev field. The joint venture is producing and proved undeveloped reserves will continue to move to proved developed as approved development phases progress. The third is the Groningen gas field in the Netherlands. Proved undeveloped reserves reported for this field are related to installation of future stages of compression. These reserves will move to proved developed when the additional stages of compression are installed to maintain field delivery pressure.
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3. Oil and Gas Production, Production Prices and Production Costs
A. Oil and Gas Production
The table below summarizes production by final product sold and by geographic area for the last three years.
(thousands of barrels daily)
Crude oil and natural gas liquids production
Total Consolidated Subsidiaries
Total Equity Companies
Total crude oil and natural gas liquids production
Bitumen production
Canada/South America
Synthetic oil production
Total liquids production
(millions of cubic feet daily)
Natural gas production available for sale
Total natural gas production available for sale
(thousands of oil-equivalent
barrels daily)
Oil-equivalent production
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B. Production Prices and Production Costs
The table below summarizes average production prices and average production costs by geographic area and by product type for the last three years.
Canada/
S. America
Australia/
Oceania
During 2011
Average production prices
Crude oil and NGL, per barrel
Natural gas, per thousand cubic feet
Bitumen, per barrel
Synthetic oil, per barrel
Average production costs, per oil-equivalent barrel - total
Average production costs, per barrel - bitumen
Average production costs, per barrel - synthetic oil
Total
During 2010
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During 2009
Average production prices have been calculated by using sales quantities from the Corporation’s own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the oil and gas production table in section 3.A. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and are also shown in section 3.A. The natural gas available for sale volumes are different from those shown in the reserves table in the “Oil and Gas Reserves” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report due to volumes consumed or flared. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
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4. Drilling and Other Exploratory and Development Activities
A. Number of Net Productive and Dry Wells Drilled
Net Productive Exploratory Wells Drilled
Total productive exploratory wells drilled
Net Dry Exploratory Wells Drilled
Total dry exploratory wells drilled
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Net Productive Development Wells Drilled
Total productive development wells drilled
Net Dry Development Wells Drilled
Total dry development wells drilled
Total number of net wells drilled
B. Exploratory and Development Activities Regarding Oil and Gas Resources Extracted by Mining Technologies
Syncrude Operations
Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. Imperial Oil Limited is the owner of a 25 percent interest in the joint venture. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited. In 2011, the company’s share of net production of synthetic crude oil was about 67 thousand barrels per day and share of net acreage was about 63 thousand acres in the Athabasca oil sands deposit.
Kearl Project
The Kearl project is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. Imperial Oil Limited holds a 70.96 percent interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. Exxon Mobil Corporation has a 69.6 percent interest in Imperial Oil Limited and a 100 percent interest in ExxonMobil Canada Properties. Kearl is comprised of six oil sands leases covering about 48 thousand acres in the Athabasca oil sands deposit.
The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta, Canada and is expected to be developed in two phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a blend of bitumen and diluent, is planned to be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline. At year-end 2011, the initial development of the Kearl project was more than 85 percent complete with expected startup in 2012. The Kearl Expansion project was funded in 2011.
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5. Present Activities
A. Wells Drilling
Wells Drilling
Total gross and net wells drilling
B. Review of Principal Ongoing Activities
ExxonMobil’s year-end 2011 acreage holdings totaled 15.6 million net acres, of which 1.9 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.
During 2011, 1,318.0 net exploration and development wells were completed in the inland lower 48 states, including development activities in the Barnett Shale of North Texas, the Freestone Trend of East Texas, the Haynesville Shale of Texas and Louisiana, the Fayetteville Shale of Arkansas, the Woodford Shale of Oklahoma, the Bakken oil play in North Dakota and Montana, the Marcellus Shale of Pennsylvania and West Virginia, the Eagle Ford Shale of South Texas, the Piceance Basin of Colorado, the San Joaquin Basin of California and the Permian Basin of West Texas.
ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2011 was 1.8 million acres. A total of 1.3 net exploration and development wells were completed during the year after the offshore drilling moratorium was lifted. The deepwater Hadrian South project and the non-operated Lucius project were both funded in 2011, and project activities are under way. Project work continued on the non-operated St. Malo project. Offshore California 1.0 net development well was completed.
Participation in Alaska production and development continued and a total of 13.6 net development wells were completed.
CANADA / SOUTH AMERICA
Canada
Oil and Gas Operations
ExxonMobil’s year-end 2011 acreage holdings totaled 5.2 million net acres, of which 1.5 million net acres were offshore. A total of 124.2 net exploration and development wells were completed during the year. The Horn River Pilot project was funded in 2011. Project activities continued on the Hibernia Southern Extension project.
In Situ Bitumen Operations
ExxonMobil’s year-end 2011 in situ bitumen acreage holdings totaled 0.5 million net onshore acres. A total of 34.0 net development wells were completed during the year.
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Argentina
ExxonMobil’s net acreage totaled 1.0 million onshore acres at year-end 2011, and there were 1.3 net development wells completed during the year.
Venezuela
ExxonMobil’s acreage holdings and assets were expropriated in 2007. Refer to the relevant portion of “Note 15: Litigation and Other Contingencies” of the Financial Section of this report for additional information.
EUROPE
Germany
A total of 4.8 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2011, with 7.3 net exploration and development wells completed during the year.
Netherlands
ExxonMobil’s net interest in licenses totaled approximately 1.6 million acres at year-end 2011, of which 1.2 million acres are onshore. A total of 11.1 net exploration and development wells were completed during the year. The non-operated project to redevelop the Schoonebeek oil field started up in 2011.
Norway
ExxonMobil’s net interest in licenses at year-end 2011 totaled approximately 1.0 million acres, all offshore. ExxonMobil participated in 2.4 net exploration and development well completions in 2011. The non-operated Aasgard Subsea Compression project was funded in 2011.
United Kingdom
ExxonMobil’s net interest in licenses at year-end 2011 totaled approximately 0.3 million acres, all offshore. The divestment of Mobil North Sea Limited (MNSL) was completed in 2011. A total of 0.8 net development wells were completed during the year.
AFRICA
Angola
ExxonMobil’s year-end 2011 acreage holdings totaled 0.6 million net offshore acres, and 5.2 net exploration and development wells were completed during the year. On Block 15, development drilling continued at Kizomba A and Kizomba C. The Angola Gas Gathering project was completed in 2011, and project work continued on Kizomba Satellites Phase 1. On the non-operated Block 17, the Pazflor project started up in 2011 and work continued on the Cravo-Lirio-Orquidea-Violeta project. Development drilling continued at Dalia, Girassol and Rosa. On the non-operated Block 31, project work continued on the Plutao-Saturno-Venus-Marte project.
Chad
ExxonMobil’s net year-end 2011 acreage holdings consisted of 46 thousand onshore acres, with 28.0 net development wells completed during the year. The undeveloped concessions of M’Biku, Belanga and Mangara were relinquished in 2011.
Equatorial Guinea
ExxonMobil’s acreage totaled 0.1 million net offshore acres at year-end 2011, with 3.8 net development wells completed during the year.
Nigeria
ExxonMobil’s net acreage totaled 1.0 million offshore acres at year-end 2011, with 7.3 net exploration and development wells completed during the year. Work continued on the deepwater Usan project, and the first phase of the Satellite Field Development project is under way.
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ASIA
Azerbaijan
At year-end 2011, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.5 net development wells were completed during the year. Work continued on the Chirag Oil project.
Indonesia
At year-end 2011, ExxonMobil had 5.2 million net acres, 3.4 million net acres offshore and 1.8 million net acres onshore. A total of 3.4 net exploration wells were completed during the year. The full field development at Banyu Urip was funded in 2011 and project activities are under way.
Iraq
At year-end 2011, ExxonMobil’s onshore acreage was 0.9 million net acres. A total of 20.8 net development wells were completed at the West Qurna Phase I oil field during the year. In 2010, a contract was signed with South Oil Company of the Iraqi Ministry of Oil to redevelop and expand the West Qurna Phase I oil field. The term of the contract is 20 years with the right to extend for five years. In 2010 initial field rehabilitation activities commenced. Field rehabilitation activities across the life of this project will include drilling of new wells, working over of existing wells, optimization and debottlenecking of existing facilities, and the establishment of field offices and camps. During 2011, production sharing contracts were negotiated with the regional government of Kurdistan.
Kazakhstan
ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2011. Working with our partners, construction of the initial phase of the Kashagan field continued during 2011.
Malaysia
ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore at year-end 2011. During the year, a total of 8.5 net development wells were completed. The Tapis and Telok projects were funded in 2011 and project activities are under way.
Qatar
Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2011. During the year, a total of 0.4 net development wells were completed. ExxonMobil participated in 61.8 million tonnes per year gross liquefied natural gas capacity at year end. The development agreements associated with the Barzan project were signed in 2011.
Republic of Yemen
ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2011.
Russia
ExxonMobil’s net acreage holdings at year-end 2011 were 85 thousand acres, all offshore. A total of 0.6 net development wells were completed. The Sakhalin-1 Chayvo Expansion and Arkutun-Dagi projects continued development activities in 2011. ExxonMobil and Rosneft signed a Strategic Cooperation Agreement in 2011 to jointly participate in exploration and development activities in Russia, the United States and other parts of the world.
Thailand
ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2011.
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United Arab Emirates
ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2011, with 0.6 net exploration wells completed during the year.
ExxonMobil’s net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2011, of which 0.4 million acres are onshore. During the year, a total of 3.7 net development wells were completed.
AUSTRALIA / OCEANIA
Australia
ExxonMobil’s year-end 2011 acreage holdings totaled 1.7 million net acres offshore. During 2011, a total of 1.3 net exploration wells were completed. Offshore installation continued for the Kipper Tuna Turrum project.
Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2011. The project consists of a subsea infrastructure for offshore production and transportation of the gas, and a 15 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.
Papua New Guinea
A total of 0.5 million net onshore acres were held by ExxonMobil at year-end 2011, with 0.1 net development well completed during the year. Work continued on the Papua New Guinea (PNG) LNG project. The project consists of conditioning facilities in the southern PNG Highlands, a 6.6 million tonnes per year LNG facility near Port Moresby and approximately 430 miles of onshore and offshore pipelines.
WORLDWIDE EXPLORATION
At year-end 2011, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 36.5 million net acres were held at year-end 2011, and 6.5 net exploration wells were completed during the year in these countries.
6. Delivery Commitments
ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 3,000 billion cubic feet of natural gas for the period from 2012 through 2014. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and spot market purchases as necessary.
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7. Oil and Gas Properties, Wells, Operations and Acreage
A. Gross and Net Productive Wells
Gross and Net Productive Wells
Total gross and net productive wells
There were 37,692 gross and 31,683 net operated wells at year-end 2011 and 35,691 gross and 30,494 net operated wells at year-end 2010. The number of wells with multiple completions was 1,775 gross in 2011 and 1,725 gross in 2010.
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B. Gross and Net Developed Acreage
(thousands of acres)
Gross and Net Developed Acreage
Total 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.
C. Gross and Net Undeveloped Acreage
Gross and Net Undeveloped Acreage
Total 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. The scheduled expiration of leases and concessions for undeveloped acreage over the next three years is not expected to have a material adverse impact on the Corporation.
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D. Summary of Acreage Terms
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.
Exploration licenses or leases are acquired for varying periods of time with renewals or extensions possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to continue existing licenses or leases upon completing specified work. In general, license and lease agreements are held as long as there is production on the licenses and leases. The majority of Cold Lake leases are held in this manner. The exploration acreage in eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.
The federal onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration period and up to two years for the third exploration period. A 50-percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been developed. Argentine provinces are entitled to modify the concession terms granted within their territories. The concession terms of the exploration permits granted by Neuquen Province are up to six years for the initial exploration period, up to four years for the second exploration period and up to three years for the third exploration period depending on the classification of the area. An extension after the third exploration period is possible for up to one year.
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.
Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the license and are based on the Mining Law.
Production rights granted prior to January 1, 2003, remain subject to their existing terms, and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.
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
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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.
Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the first four licensing rounds provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. At the end of any such 40-year term, licenses may continue in producing areas until cessation of production; or licenses may continue in development areas for periods agreed on a case-by-case basis until they become producing areas; or licenses terminate in all other areas. The licensing regime was last updated in 2002, and the majority of licenses issued have an initial term of four years with a second term extension of four years and a final term of 18 years with a mandatory relinquishment of 50 percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.
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.
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.
Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years while the production period for gas is 50 years. Under the Hydrocarbons Law enacted in 2006, the exploration terms for new production sharing contracts are four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.
Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase plus one or two optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the ten-year exploration period, and OMLs have a 20-year production period that may be extended.
Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-renewable, while in all other areas the licenses are for five years and also are non-renewable. Demonstrating a commercial discovery is the basis for conversion of an OPL to an OML.
OMLs granted prior to the 1969 Petroleum Act (i.e., under the Mineral Oils Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40 years in offshore areas and have been renewed, effective December 1, 2008, for a further period of 20 years, with a further renewal option of 20 years. Operations under these pre-1969 OMLs are conducted under a joint venture agreement with NNPC rather than a PSC. In 2000, a Memorandum of Understanding (MOU) was executed defining commercial terms applicable to existing joint venture oil production. The MOU may be terminated on one calendar year’s notice.
OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for onshore or offshore location and are renewable, upon 12 months’ written notice, for another period of 20 years. OMLs not held by NNPC are also subject to a mandatory 50-percent relinquishment after the first ten years of their duration.
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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.
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.
Development and production activities in the state-owned oil and gas fields are governed by contracts with regional oil companies of the Iraqi Ministry of Oil. An ExxonMobil affiliate entered into a contract with South Oil Company of the Iraqi Ministry of Oil for the rights to participate in the development and production activities of the West Qurna Phase I oil and gas field effective March 1, 2010. The term of the contract is 20 years with the right to extend for five years. The contract provides for cost recovery plus per-barrel fees for incremental production above specified levels.
Exploration and production activities in the Kurdistan region of Iraq are governed by production sharing contracts negotiated with the regional government of Kurdistan in 2011. The exploration term is for five years with the possibility of two-year extensions. The production period is 20 years with the right to extend for five years.
Onshore exploration and production activities are governed by the production license, exploration license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.
Offshore exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.
Exploration and production activities are governed by production sharing contracts (PSCs) negotiated with the national oil company. The more recent PSCs governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, with possible extensions to the exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed relinquished. The development period is from four to six years from commercial discovery, with the possibility of extensions under special circumstances. Areas from which commercial production has not started by the end of the development period will be deemed relinquished if no extension is granted. All extensions are subject to the national oil company’s prior written approval. The total production period is 15 to 25 years from first commercial lifting, not to exceed the overall term of the contract.
In 2008, the Company reached agreement with the national oil company for a new PSC, which was subsequently signed in 2009. Under the new PSC, from 2008 until March 31, 2012, the Company is entitled to undertake new development and production activities in oil fields under an existing PSC, subject to new minimum work and spending commitments, including an enhanced oil recovery project in one of the oil fields. When the existing PSC expires on March 31, 2012, the producing fields covered by the existing PSC will automatically become part of the new PSC, which has a 25-year duration from April 2008.
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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.
The Jannah production sharing agreement has a development period extending 20 years from first commercial declaration, which was made in June 1995.
Terms for ExxonMobil’s acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, which would be 2021. The term may be extended thereafter in ten-year increments as specified in the PSA.
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.
Exploration and production activities for the major onshore oil fields in the Emirate of Abu Dhabi are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi. An interest in the Upper Zakum field, a major offshore field, was acquired effective as of January 2006, for a term expiring March 2026.
AUSTRALIA/OCEANIA
Exploration and production activities conducted offshore in Commonwealth waters are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable at the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter “indefinitely”, i.e., for the life of the field. Effective from July 1998, new production licenses are granted “indefinitely”. In each case, a production license may be terminated if no production operations have been carried on for five years.
Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum Development licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Minister’s discretion. Petroleum Retention licenses may be granted for gas resources that are not commercially viable at the time of application, but may become commercially viable within the maximum possible retention time of 15 years. Petroleum Retention licenses are granted for five-year terms, and may be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years. Extensions of Petroleum Retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources could become commercially viable in less than five years.
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Information with regard to the Downstream segment follows:
ExxonMobil’s Downstream segment manufactures and sells petroleum products. The refining and supply operations encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants and other products and feedstocks to our customers around the world.
Refining Capacity At Year-End 2011(1)
ExxonMobil
Share KBD(2)
Interest %
Torrance
California
Joliet
Illinois
Baton Rouge
Louisiana
Baytown
Texas
Beaumont
Other (2 refineries)
Total United States
Strathcona
Alberta
Dartmouth
Nova Scotia
Nanticoke
Ontario
Sarnia
Total Canada
Antwerp
Belgium
Fos-sur-Mer
France
Port-Jerome-Gravenchon
Karlsruhe
Augusta
Italy
Trecate
Rotterdam
Slagen
Fawley
Total Europe
Asia Pacific
Kawasaki
Japan
Sakai
Wakayama
Jurong/PAC
Singapore
Sriracha
Other (5 refineries)
Total Asia Pacific
Other Non-U.S.
Yanbu
Saudi Arabia
Laffan
Other (4 refineries)
Total Other Non-U.S.
Total Worldwide
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The marketing operations sell products and services throughout the world. Our Exxon,Esso and Mobil brands serve customers at over 25,000 retail service stations.
Retail Sites At Year-End 2011
Owned/leased
Distributors/resellers
Latin America
Total Latin America
Middle East/Africa
Total Middle East/Africa
Worldwide
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Information with regard to the Chemical segment follows:
ExxonMobil’s Chemical segment manufactures and sells petrochemicals. The Chemical business supplies olefins, polyolefins, aromatics, and a wide variety of other petrochemicals.
Chemical Complex Capacity At Year-End 2011(1)(2)
North America
Mont Belvieu
Total North America
Fife
Meerhout
Notre-Dame-de-Gravenchon
Middle East
Al Jubail
Total Middle East
Fujian
China
All Other
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Regarding a matter previously reported in the Corporation’s Form 10-Q for the second quarter of 2009, the Corporation has resolved a Consolidated Compliance Order & Notice of Potential Penalty issued by the Louisiana Department of Environmental Quality (LDEQ) to the Corporation’s Baton Rouge Resins Finishing Plant (BRFP) on October 16, 2008, relating to alleged exceedances of air permit limits for certain volatile organic compounds and hazardous air pollutants. BRFP had self-disclosed these emission results to the LDEQ and proposed a number of specific corrective action steps. The settlement terms, which have been agreed to and were subject to public notice and comment until February 20, 2012, include a total payment of approximately $360 thousand, which consists of an administrative penalty of approximately $306 thousand and payment of approximately $54 thousand for certain Beneficial Environmental Projects.
Regarding a matter previously reported in the Corporation’s Form 10-Q for the first quarter of 2010, the Corporation has resolved issues raised by the LDEQ relating to a leak of propylene detected on January 10, 2010 at the Ethylene Purification Unit at the Corporation’s Baton Rouge, Louisiana chemical plant. The settlement terms, which have been agreed to and are subject to public notice and comment until March 2, 2012, include a total payment of approximately $250 thousand, which consists of an administrative penalty of approximately $123 thousand, the Corporation’s purchase of a camera for detection of certain emissions at a cost of approximately $79 thousand and payment for certain Beneficial Environmental Projects totaling $48 thousand.
With regard to a matter previously reported in the Corporation’s Form 10-Q for the third quarter of 2011, on January 19, 2012, ExxonMobil Pipeline Company (EMPCo) entered into an agreed Administrative Order on Consent (AOC) with the Montana Department of Environmental Quality (MDEQ) to resolve civil and related liabilities under state environmental laws resulting from the July 1, 2011 discharge of crude oil into the Yellowstone River from EMPCo’s Silvertip Pipeline. Under the AOC, EMPCo will: (1) pay a civil penalty totaling $1.6 million, including $300 thousand in cash payments and $1.3 million in Supplemental Environmental Projects to be decided upon by the MDEQ; (2) reimburse the state for past costs associated with cleanup efforts, totaling approximately $760 thousand; (3) reimburse the State of Montana’s future oversight costs; (4) monitor and document the degradation of remaining visible oil over time at selected locations; and, (5) continue its soil and water monitoring program, which was agreed upon with the MDEQ in October 2011. The AOC will terminate when EMPCo certifies that all required activities have been performed and the MDEQ has approved the certification. The order was subject to a 30-day public comment period which expired on February 21, 2012.
Refer to the relevant portions of “Note 15: Litigation and Other Contingencies” of the Financial Section of this report for additional information on legal proceedings.
Not applicable.
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Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)] (ages as of February 29, 2012).
Held current title since:
Mr. Rex W. Tillerson became a Director and President of Exxon Mobil Corporation on March 1, 2004. He became Chairman of the Board and Chief Executive Officer on January 1, 2006. He still holds these positions as of this filing date.
Mr. Mark W. Albers was President of ExxonMobil Development Company October 1, 2004 – April 13, 2007. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2007, a position he still holds as of this filing date.
Mr. Michael J. Dolan was President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation September 1, 2004 – March 31, 2008. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2008, a position he still holds as of this filing date.
January 25, 2006
Mr. Donald D. Humphreys became Senior Vice President of Exxon Mobil Corporation on January 25, 2006, a position he still holds as of this filing date. Over this period, he was Treasurer of Exxon Mobil Corporation through April 30, 2011.
Mr. Andrew P. Swiger was President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation October 1, 2006 – March 31, 2009. He became Senior Vice President of Exxon Mobil Corporation on April 1, 2009, a position he still holds as of this filing date.
Mr. S. Jack Balagia was Assistant General Counsel of Exxon Mobil Corporation April 1, 2004 – March 1, 2010. He became Vice President and General Counsel of Exxon Mobil Corporation on March 1, 2010, positions he still holds as of this filing date.
Mr. William M. Colton was Assistant Treasurer of Exxon Mobil Corporation January 25, 2006 – January 31, 2009. He became Vice President—Strategic Planning of Exxon Mobil Corporation on February 1, 2009, a position he still holds as of this filing date.
Mr. Neil W. Duffin was Executive Vice President of ExxonMobil Development Company September 1, 2006 – April 13, 2007, becoming President on April 13, 2007, a position he still holds as of this filing date.
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Mr. Robert S. Franklin was Vice President, New Business Development of ExxonMobil Gas & Power Marketing Company July 1, 2001 – April 15, 2007. He was Executive Assistant to the Chairman, Exxon Mobil Corporation April 16, 2007 – March 31, 2008. He was Vice President, Europe/Russia/Caspian of ExxonMobil Production Company April 1, 2008 – May 1, 2009. He became Vice President of Exxon Mobil Corporation and President, ExxonMobil Upstream Ventures on May 1, 2009, positions he still holds as of this filing date.
Mr. Sherman J. Glass, Jr. was Senior Vice President of ExxonMobil Chemical Company September 1, 2005 – March 31, 2008. He became President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.
Mr. Stephen M. Greenlee was Vice President of ExxonMobil Exploration Company June 1, 2004 – June 1, 2009. He was President of ExxonMobil Upstream Research Company June 1, 2009 – August 31, 2010. He became President of ExxonMobil Exploration Company and Vice President of Exxon Mobil Corporation on September 1, 2010, positions he still holds as of this filing date.
Mr. Alan J. Kelly was on Special Assignment for the National Petroleum Council March 1, 2006 – November 30, 2007. He became President of ExxonMobil Lubricants & Petroleum Specialties Company and Vice President of Exxon Mobil Corporation on December 1, 2007. On February 1, 2012, the businesses of ExxonMobil Lubricants & Petroleum Specialties Company and ExxonMobil Fuels Marketing Company were consolidated and Mr. Kelly became President of the combined ExxonMobil Fuels, Lubricants & Specialties Marketing Company as well as Vice President of Exxon Mobil Corporation, positions he still holds as of this filing date.
Mr. Richard M. Kruger was Executive Vice President of ExxonMobil Production Company October 1, 2006 – March 31, 2008. He became President of ExxonMobil Production Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.
February 1, 2002 (Vice President)
July 1, 2004 (Controller)
Mr. Patrick T. Mulva became Vice President and Controller of Exxon Mobil Corporation on July 1, 2004, positions he still holds as of this filing date.
Mr. Stephen D. Pryor was President of ExxonMobil Refining & Supply Company and Vice President of Exxon Mobil Corporation December 1, 2004 – March 31, 2008. He became President of ExxonMobil Chemical Company and Vice President of Exxon Mobil Corporation on April 1, 2008, positions he still holds as of this filing date.
Mr. David S. Rosenthal was Assistant Controller of Exxon Mobil Corporation June 1, 2006 – September 30, 2008. He became Vice President—Investor Relations and Secretary of Exxon Mobil Corporation on October 1, 2008, positions he still holds as of this filing date.
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Mr. Robert N. Schleckser was Downstream Treasurer, Downstream Business Services May 1, 2005 – January 31, 2009. He was Assistant Treasurer of Exxon Mobil Corporation February 1, 2009 – April 30, 2011. He became Vice President and Treasurer of Exxon Mobil Corporation on May 1, 2011, positions he still holds as of this filing date.
Mr. James M. Spellings, Jr. was General Manager—Corporate Planning of Exxon Mobil Corporation February 1, 2005 – March 31, 2007. He was Associate General Tax Counsel April 1, 2007 – March 1, 2010. He became Vice President and General Tax Counsel on March 1, 2010, positions he still holds as of this filing date.
Mr. Thomas R. Walters was President of ExxonMobil Global Services Company from September 1, 2005 – April 4, 2007. He was Executive Vice President of ExxonMobil Development Company April 13, 2007 – April 1, 2009. He became President of ExxonMobil Gas & Power Marketing Company and Vice President of Exxon Mobil Corporation on April 1, 2009, positions he still holds as of this filing date.
Mr. Jack P. Williams, Jr. was Upstream Advisor, Exxon Mobil Corporation July 1, 2005 – May 1, 2007. He was Vice President, Engineering, ExxonMobil Production Company May 1, 2007 – April 30, 2009. He was Vice President of ExxonMobil Development Company May 1, 2009 – July 1, 2010. He became President of XTO Energy Inc. on June 25, 2010, a position he still holds as of this filing date.
Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.
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PART II
Reference is made to the “Quarterly Information” portion of the Financial Section of this report.
Issuer Purchases of Equity Securities for Quarter Ended December 31, 2011
October, 2011
November, 2011
December, 2011
Note 1—On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated January 31, 2012, the Corporation stated that first quarter 2012 share purchases are continuing at a pace consistent with fourth quarter 2011 share reduction spending of $5 billion. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.
Years Ended December 31,
(millions of dollars, except per share amounts)
Sales and other operating revenue (1)
(1) Sales-based taxes included
Net income attributable to ExxonMobil
Earnings per common share
Earnings per common share - assuming dilution
Cash dividends per common share
Total assets
Long-term debt
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.
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.
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Reference is made to the following in the Financial Section of this report:
Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 24, 2012, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 20: Subsequent Event”;
“Quarterly Information” (unaudited);
“Supplemental Information on Oil and Gas Exploration and Production Activities” (unaudited); and
“Frequently Used Terms” (unaudited).
Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
None.
Management’s Evaluation of Disclosure Controls and Procedures
As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2011. Based on that evaluation, these officers have concluded that the Corporation’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the Corporation in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Management’s Report on Internal Control Over Financial Reporting
Management, including the Corporation’s chief executive officer, principal financial officer and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2011.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2011, as stated in their report included in the Financial Section of this report.
Changes in Internal Control Over Financial Reporting
There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corporation’s internal control over financial reporting.
Effective April 1, 2012, the annual salary for Michael J. Dolan will increase to $1,100,000. Like all other ExxonMobil executive officers, Mr. Dolan is an “at-will” employee of the Corporation and does not have an employment contract.
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PART III
Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2012 annual meeting of shareholders (the “2012 Proxy Statement”):
The section entitled “Election of Directors”;
The portion entitled “Section 16(a) Beneficial Ownership Reporting Compliance” of the section entitled “Director and Executive Officer Stock Ownership”;
The portions entitled “Director Qualifications” and “Code of Ethics and Business Conduct” of the section entitled “Corporate Governance”; and
The “Audit Committee” portion and the membership table of the portion entitled “Board Meetings and Committees; Annual Meeting Attendance” of the section entitled “Corporate Governance”.
Incorporated by reference to the sections entitled “Director Compensation,” “Compensation Committee Report,” “Compensation Discussion and Analysis” and “Executive Compensation Tables” of the registrant’s 2012 Proxy Statement.
The information required under Item 403 of Regulation S-K is incorporated by reference to the sections “Director and Executive Officer Stock Ownership” and “Certain Beneficial Owners” of the registrant’s 2012 Proxy Statement.
Equity Compensation Plan Information
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
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Information provided in response to this Item 13 is incorporated by reference to the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section entitled “Corporate Governance” of the registrant’s 2012 Proxy Statement.
Incorporated by reference to the portion entitled “Audit Committee” of the section entitled “Corporate Governance” and the section entitled “Ratification of Independent Auditors” of the registrant’s 2012 Proxy Statement.
PART IV
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FINANCIAL SECTION
Business Profile
Financial Summary
Frequently Used Terms
Quarterly Information
Functional Earnings
Forward-Looking Statements
Overview
Business Environment and Risk Assessment
Review of 2011 and 2010 Results
Liquidity and Capital Resources
Capital and Exploration Expenditures
Taxes
Environmental Matters
Market Risks, Inflation and Other Uncertainties
Critical Accounting Estimates
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Statement of Income
Balance Sheet
Statement of Cash Flows
Statement of Changes in Equity
Statement of Comprehensive Income
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies
2. Accounting Changes
3. Miscellaneous Financial Information
4. Cash Flow Information
5. Additional Working Capital Information
6. Equity Company Information
7. Investments, Advances and Long-Term Receivables
8. Property, Plant and Equipment and Asset Retirement Obligations
9. Accounting for Suspended Exploratory Well Costs
10. Leased Facilities
11. Earnings Per Share
12. Financial Instruments and Derivatives.
13. Long-Term Debt
14. Incentive Program.
15. Litigation and Other Contingencies
16. Pension and Other Postretirement Benefits
17. Disclosures about Segments and Related Information
18. Income, Sales-Based and Other Taxes
19. Acquisition of XTO Energy Inc.
20. Subsequent Event
Supplemental Information on Oil and Gas Exploration and Production Activities
Operating Summary
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BUSINESS PROFILE
Earnings After
Income Taxes
Average Capital
Employed
Capital and
Exploration
Expenditures
Upstream
Non-U.S.
Downstream
Chemical
Corporate and financing
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
Net liquids production
Refinery throughput
Petroleum product sales
Oil-equivalent production (1)
Chemical prime product sales
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FINANCIAL SUMMARY
Earnings
Earnings per common share – assuming dilution
Earnings to average ExxonMobil share of equity (percent)
Working capital
Ratio of current assets to current liabilities (times)
Additions to property, plant and equipment
Property, plant and equipment, less allowances
Exploration expenses, including dry holes
Research and development costs
Total debt
Fixed-charge coverage ratio (times)
Debt to capital (percent)
Net debt to capital (percent) (2)
ExxonMobil share of equity at year-end
ExxonMobil share of equity per common share
Weighted average number of common shares outstanding (millions)
Number of regular employees at year-end (thousands) (3)
CORS employees not included above (thousands) (4)
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FREQUENTLY USED TERMS
Listed below are definitions of several of ExxonMobil’s key business and financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation.
CASH FLOW FROM OPERATIONS AND ASSET SALES
Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments from the Consolidated Statement of Cash Flows. This cash flow reflects the total sources of cash from both operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider proceeds associated with asset sales together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
Net cash provided by operating activities
Proceeds associated with sales of subsidiaries, property, plant and equipment,and sales and returns of investments
Cash flow from operations and asset sales
CAPITAL EMPLOYED
Capital employed is a measure of net investment. When viewed from the perspective of how the capital is used by the businesses, it includes ExxonMobil’s net share of property, plant and equipment and other assets less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the Corporation, it includes ExxonMobil’s share of total debt and equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.
Business uses: asset and liability perspective
Less liabilities and noncontrolling interests share of assets and liabilities
Total current liabilities excluding notes and loans payable
Total long-term liabilities excluding long-term debt
Noncontrolling interests share of assets and liabilities
Add ExxonMobil share of debt-financed equity company net assets
Total capital employed
Total corporate sources: debt and equity perspective
Notes and loans payable
ExxonMobil share of equity
Less noncontrolling interests share of total debt
Add ExxonMobil share of equity company debt
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RETURN ON AVERAGE CAPITAL EMPLOYED
Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income attributable to ExxonMobil excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow based, are used to make investment decisions.
Financing costs (after tax)
Gross third-party debt
ExxonMobil share of equity companies
All other financing costs – net
Total financing costs
Earnings excluding financing costs
Average capital employed
Return on average capital employed – corporate total
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QUARTERLY INFORMATION
First
Quarter
Second
Third
Fourth
Volumes
Production of crude oil
and natural gas liquids,
synthetic oil and bitumen
Natural gas production
available for sale
Summarized financial data
Sales and other operating
revenue(2)
Gross profit(3)
Per share data
Earnings per common share (4)
– assuming dilution (4)
Dividends per common share
Common stock prices
High
Low
The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States.
There were 488,846 registered shareholders of ExxonMobil common stock at December 31, 2011. At January 31, 2012, the registered shareholders of ExxonMobil common stock numbered 486,416.
On January 25, 2012, the Corporation declared a $0.47 dividend per common share, payable March 9, 2012.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Earnings (U.S. GAAP)
Special item included in earnings
Valdez litigation
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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FORWARD-LOOKING STATEMENTS
Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including demand growth and energy source mix; capacity increases; production growth and mix; rates of field decline; financing sources; the resolution of contingencies and uncertain tax positions; environmental and capital expenditures; could differ materially depending on a number of factors, such as changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; the outcome of commercial negotiations; political or regulatory events, and other factors discussed herein and in Item 1A. Risk Factors.
OVERVIEW
The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, manufacturing and marketing of hydrocarbons and hydrocarbon-based products. The Corporation’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.
ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new energy supplies. While commodity prices are volatile on a short-term basis and depend on supply and demand, ExxonMobil’s investment decisions are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Prices for crude oil, natural gas and refined products are based on corporate plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
Long-Term Business Outlook
By 2040, the world’s population is projected to grow to approximately 8.7 billion people, or about 1.9 billion more than in 2010. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. Expanding prosperity across a growing global population is expected to coincide with an increase in primary energy demand of about 30 percent by 2040 versus 2010, even with substantial efficiency gains around the world. This demand increase is expected to be concentrated in developing countries (i.e., those that are not member nations of the Organization for Economic Cooperation and Development).
As economic progress drives demand higher, increasing penetration of energy-efficient and lower-emission fuels, technologies and practices are expected to contribute to significantly lower levels of energy consumption and emissions per unit of economic output over time. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the introduction of new technologies, as well as many other improvements that span the residential, commercial and industrial sectors.
Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by nearly 45 percent from 2010 to 2040. The global growth in transportation demand is likely to account for approximately 75 percent of the growth in liquids demand over this period. Nearly all the world’s transportation fleets are likely to continue to run on liquid fuels because they provide a large quantity of energy in small volumes, making them easy to transport and widely available.
Demand for electricity around the world is estimated to increase approximately 80 percent by 2040, led by growth in developing countries. Consistent with this projection, power generation will remain the largest and fastest-growing major segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Natural gas demand is likely to grow most significantly and gain the most market share. Coal is likely to retain the leading share of power generation fuels in 2040, albeit at a much lower share than in 2010 as policies are gradually adopted to reduce environmental impacts including those related to local air quality and greenhouse gas emissions. Nuclear power and renewables, led by wind, are likely to grow significantly over the period.
Liquid fuels provide the largest share of energy supply today due to their broad-based availability, affordability and ease of transport to meet consumer needs. By 2040, global demand for liquids is expected to grow to approximately 112 million barrels of oil-equivalent per day, an increase of more than 25 percent from 2010. Global demand for liquid fuels will be met by a wide variety of sources. Conventional crude and condensate production is expected to remain relatively flat through 2040. However, growth is expected from a wide variety of sources, including deep-water resources, oil sands, tight oil, natural gas liquids, and biofuels. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic supply options. However, access to resources and timely investments will remain critical to meeting global needs with reliable, affordable supplies.
Natural gas is a versatile fuel for a wide variety of applications, and is expected to be the fastest growing major fuel source through 2040. Global demand is expected to rise 60 percent by 2040 compared to 2010, with demand increases in major regions around the world requiring new sources of supply. We expect that a significant growth in supplies of unconventional gas – the
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natural gas found in shale and other rock formations that was once considered uneconomic to produce – will help meet these needs. By 2040, unconventional gas is likely to account for about 30 percent of global gas supplies, up from 10 percent in 2010. Growing natural gas demand is likely to also stimulate significant growth in the worldwide liquefied natural gas (LNG) market, which is expected to reach 15 percent of global gas demand by 2040.
The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to one-third in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas by approximately 2025. The share of natural gas is expected to exceed 25 percent by 2040, while the share of coal falls to less than 20 percent. Nuclear power is projected to grow significantly, albeit at a slower pace than otherwise expected in the aftermath of the Fukushima incident in Japan following the earthquake and tsunami in March 2011. Total renewable energy is likely to reach close to 15 percent of total energy by 2040, including biomass, hydro and geothermal at a combined share of about 11 percent. Total energy supplied from wind, solar and biofuels is expected to increase close to 500 percent from 2010 to 2040, reaching a combined share of approximately 4 percent of world energy.
The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide over the period 2011-2035 will be close to $20 trillion (measured in 2010 dollars) or close to $780 billion per year on average.
International accords and underlying regional and national regulations for greenhouse gas reduction are evolving with uncertain timing and outcome, making it difficult to predict their business impact. ExxonMobil includes estimates of potential costs related to possible public policies covering energy-related greenhouse gas emissions in its long-term Energy Outlook, which is used for assessing the business environment and in its investment evaluations.
The information provided in the Long-Term Business Outlook includes ExxonMobil’s internal estimates and forecasts based upon internal data and analyses as well as publicly available information from external sources including the International Energy Agency.
ExxonMobil continues to maintain a diverse portfolio of exploration and development opportunities, which enables the Corporation to be selective, maximizing shareholder value and mitigating political and technical risks. ExxonMobil’s fundamental Upstream business strategies guide our global exploration, development, production, and gas and power marketing activities. These strategies include identifying and selectively capturing the highest quality exploration opportunities, maximizing the profitability of existing oil and gas production, investing in projects that deliver superior returns, capitalizing on growing natural gas and power markets, and maximizing resource value through high-impact technologies. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees, and investment in the communities within which we operate.
As future development projects and drilling activities bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2016. Oil and natural gas output from North America is expected to increase over the next five years based on current capital activity plans. Currently, this growth area accounts for 30 percent of the Corporation’s production. By 2016, it is expected to generate about 35 percent of total volumes. The remainder of the Corporation’s production is expected to include contributions from both established operations and new projects around the globe.
In addition to an evolving geographic mix, we expect there will also be continued change in the type of opportunities from which volumes are produced. Production from diverse resource types utilizing specialized technologies such as arctic technology, deepwater drilling and production systems, heavy oil and oil sands recovery processes, unconventional gas and oil production and LNG is expected to grow from about 45 percent to around 50 percent of the Corporation’s output between now and 2016. We do not anticipate that the expected change in the geographic mix of production volumes, and in the types of opportunities from which volumes will be produced, will have a material impact on the nature and the extent of the risks disclosed in Item 1A. Risk Factors, or result in a material change in our level of unit operating expenses. The Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2012-2016. However, actual volumes will vary from year to year due to the timing of individual project start-ups and other capital activities, operational outages, reservoir performance, performance of enhanced oil recovery projects, regulatory changes, asset sales, weather events, price effects under production sharing contracts and other factors described in Item 1A. Risk Factors. Enhanced oil recovery projects extract hydrocarbons from reservoirs in excess of that which may be produced through primary recovery, i.e., through pressure depletion or natural aquifer support. They include the injection of water, gases or chemicals into a reservoir to produce hydrocarbons otherwise unobtainable.
ExxonMobil’s Downstream is a large, diversified business with refining and marketing complexes around the world. The Corporation has a strong presence in mature markets in North America and Europe, as well as the growing Asia Pacific region. ExxonMobil’s fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizing on integration across ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectiveness, and providing quality, valued products and services to customers.
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ExxonMobil has an ownership interest in 36 refineries, located in 21 countries, with distillation capacity of 6.2 million barrels per day and lubricant basestock manufacturing capacity of 131 thousand barrels per day. ExxonMobil’s fuels and lubes marketing business portfolios include operations around the world, with multiple channels to market serving a globally diverse customer base. Our world-class brands, including Exxon, Mobil and Esso, are well-known.
The downstream industry environment remains challenging. Although demand for refined products has improved from the lower levels in 2009 due to the global economic recession, we expect the challenging business environment to continue, reflecting the increase in global refining capacity and regulatory related policies. Over the prior 20-year period, inflation-adjusted refining margins have been flat.
Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published prices, including those quoted on multiple exchanges around the world (e.g., New York Mercantile Exchange and Intercontinental Exchange). Prices for these commodities are determined by the global marketplace and are influenced by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, currency fluctuations, seasonal demand, weather and political climate.
ExxonMobil’s long-term outlook is that refining margins will remain weak as competition in the industry remains intense and, in the near term, new capacity additions outpace the growth in global demand. Additionally, as described in more detail in Item 1A. Risk Factors, proposed carbon policy and other climate-related regulations in many countries, as well as the continued growth in biofuels mandates, could have negative impacts on the refining business.
In the retail fuels marketing business, competition continues to cause inflation-adjusted margins to decline. In 2011, ExxonMobil progressed the transition of the direct served (i.e., dealer, company-operated) retail network in the U.S. to a more capital-efficient branded distributor model. This transition was announced in 2008 and is expected to be complete in 2012.
Our Lubricants and Specialties business continues to grow. ExxonMobil is a market leader in high-value synthetic lubricants, and we continue to grow our business in key markets such as China, India and Russia at rates considerably faster than industry.
The Downstream portfolio is continually evaluated during all parts of the business cycle, and numerous asset divestments have been made over the past decade. In 2011, we announced divestments of our Downstream businesses in Argentina, Uruguay, Paraguay, Central America, Malaysia, and Switzerland. In January 2012, we also announced the restructuring of our holdings in Japan which is disclosed in Note 20. When investing in the Downstream, ExxonMobil remains focused on selective and resilient projects. These investments capitalize on the Corporation’s world-class scale and integration, industry leading efficiency, leading-edge technology and respected brands, enabling ExxonMobil to take advantage of attractive emerging growth opportunities around the globe. In 2011, the company completed construction of new units and modification of existing facilities at the Sriracha, Thailand, refinery to produce lower sulfur diesel and gasoline to meet upcoming product specifications in Thailand. At the Jurong/PAC refinery in Singapore, plans are under way to build a new diesel hydrotreater, which will add capacity of more than 2 million gallons per day to meet increasing demand in the Asia Pacific region. Additionally, construction of a lower sulfur fuels project has begun at the joint Saudi Aramco and ExxonMobil SAMREF Refinery in Yanbu, Saudi Arabia. The project will include new gasoline and expanded diesel hydrotreating and sulfur recovery equipment, and completion is expected by the end of 2013. We are also expanding our Singapore and China lube oil blending plants to support future demand growth in these emerging markets.
Worldwide petrochemical demand grew modestly in 2011. In North America, unconventional natural gas continued to provide advantaged ethane feedstock for steam crackers and a favorable margin environment for integrated chemical producers. Margins in Asia Pacific remained low, with new supply capacity outpacing demand. Specialty products overall saw firm global demand and margins.
ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of commodity petrochemical products, ExxonMobil Chemical also has a number of less-cyclical Specialties business lines, which delivered strong results in 2011. Chemical’s competitive advantages are due to its business mix, broad geographic coverage, investment and cost discipline, integration with refineries or upstream gas processing facilities, superior feedstock management, leading proprietary technology and product application expertise.
REVIEW OF 2011 AND 2010 RESULTS
Earnings in 2011 of $41,060 million increased $10,600 million from 2010. Earnings for 2011 did not include any special items.
2010
Earnings in 2010 of $30,460 million increased $11,180 million from 2009. Earnings for 2010 did not include any special items.
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Upstream earnings were $34,439 million, up $10,342 million from 2010. Higher crude oil and natural gas realizations increased earnings by $10.6 billion, while volume and production mix effects decreased earnings by $2.5 billion. All other items increased earnings by $2.2 billion, driven by higher gains on asset sales of $2.7 billion, partly offset by increased operating activity. On an oil-equivalent basis, production was up 1 percent compared to 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 4 percent. Liquids production of 2,312 kbd (thousands of barrels per day) decreased 110 kbd from 2010. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production was in line with 2010, as higher volumes from Qatar, the U.S., and Iraq offset field decline. Natural gas production of 13,162 mcfd (millions of cubic feet per day) increased 1,014 mcfd from 2010, driven by additional U.S. unconventional gas volumes and project ramp-ups in Qatar. Earnings from U.S. Upstream operations for 2011 were $5,096 million, an increase of $824 million. Earnings outside the U.S. were $29,343 million, up $9,518 million.
Upstream earnings were $24,097 million, up $6,990 million from 2009. Higher realizations increased earnings approximately $6.5 billion. Higher volumes increased earnings by $1.2 billion, while all other items, including higher operating costs, decreased earnings by $690 million. On an oil-equivalent basis, production was up 13 percent compared to 2009. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was up 14 percent. Liquids production of 2,422 kbd increased 35 kbd compared with 2009. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, liquids production increased 2 percent from 2009, as project ramp-ups in Qatar were offset by net field decline. Natural gas production of 12,148 mcfd increased 2,875 mcfd from 2009, driven by higher volumes from Qatar projects and additional U.S. unconventional gas volumes. Earnings from U.S. Upstream operations for 2010 were $4,272 million, an increase of $1,379 million from 2009. Non-U.S. Upstream earnings were $19,825 million, up $5,611 million from 2009.
Downstream earnings of $4,459 million increased $892 million from 2010. Margins, mainly refining, increased earnings by $800 million. Volume and mix effects improved earnings by $630 million. All other items, primarily the absence of favorable tax effects and higher expenses, decreased earnings by $540 million. Petroleum product sales of 6,413 kbd were in line with 2010. U.S. Downstream earnings were $2,268 million, up $1,498 million from 2010. Non-U.S. Downstream earnings were $2,191 million, $606 million lower than last year.
Downstream earnings of $3,567 million were $1,786 million higher than 2009. Higher industry refining margins increased earnings by $1.2 billion. Positive volume and mix effects increased earnings by $420 million, while all other items, including lower operating expenses, increased earnings by $210 million. Petroleum product sales of 6,414 kbd decreased 14 kbd. U.S. Downstream earnings were $770 million, up $923 million from 2009. Non-U.S. Downstream earnings were $2,797 million, $863 million higher than 2009.
Chemical earnings of $4,383 million were down $530 million from 2010. Stronger margins increased earnings by $260 million, while lower volumes reduced earnings by $180 million. Other items, including unfavorable tax effects and higher planned maintenance expense, decreased earnings by $610 million. Prime product sales of 25,006 kt (thousands of metric tons) were down 885 kt from 2010. Prime product sales are total chemical product sales, including ExxonMobil’s share of equity-company volumes and finished product transfers to the Downstream business. U.S. Chemical earnings were $2,215 million, down $207 million from 2010. Non-U.S. Chemical earnings were $2,168 million, $323 million lower than last year.
Chemical earnings were a record $4,913 million, up $2,604 million from 2009. Improved margins increased earnings by $2.0 billion while higher volumes increased earnings $380 million. Prime product sales of 25,891 kt were up 1,066 kt from 2009. U.S. Chemical earnings of $2,422 million increased $1,653 million. Non-U.S. Chemical earnings of $2,491 million increased $951 million.
Corporate and Financing
Corporate and financing expenses were $2,221 million, up $104 million from 2010.
Corporate and financing expenses were $2,117 million, up $200 million from 2009 mainly due to a tax charge related to the U.S.
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health care legislation during the first quarter of 2010 and financing activities, partially offset by the absence of a 2009 charge for interest related to the Valdez punitive damages award.
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
Net cash provided by/(used in)
Operating activities
Investing activities
Financing activities
Effect of exchange rate changes
Increase/(decrease) in cash and cash equivalents
Cash and cash equivalents
Cash and cash equivalents – restricted
Total cash and cash equivalents
Total cash and cash equivalents were $13.1 billion at the end of 2011, $4.6 billion higher than the prior year. Higher earnings, proceeds associated with asset sales, including a $3.6 billion deposit for a potential asset sale, and a net debt increase in contrast with prior year debt repurchases were partially offset by a higher level of purchases of ExxonMobil shares and a higher level of capital spending. Included in total cash and cash equivalents at year-end 2011 was $0.4 billion of restricted cash.
Total cash and cash equivalents were $8.5 billion at the end of 2010, $2.2 billion lower than the prior year. Higher earnings and reduced share purchases were offset by a higher level of capital spending and increased level of debt repurchases. Included in total cash and cash equivalents at year-end 2010 was $0.6 billion of restricted cash. For additional details, see the Consolidated Statement of Cash Flows.
Although the Corporation has access to significant capacity of long-term and short-term liquidity, internally generated funds cover the majority of its financial requirements. Cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure it is secure and readily available to meet the Corporation’s cash requirements and to optimize returns.
To support cash flows in future periods the Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all the Corporation’s existing oil and gas fields and without new projects, ExxonMobil’s production is expected to decline at an average of approximately 3 percent per year over the next few years. Decline rates can vary widely by individual field due to a number of factors, including, but not limited to, the type of reservoir, fluid properties, recovery mechanisms, work activity, and age of the field. Furthermore, the Corporation’s net interest in production for individual fields can vary with price and contractual terms.
The Corporation has long been successful at offsetting the effects of natural field decline through disciplined investments in quality opportunities and project execution. Over the last decade, this has resulted in net annual additions to proved reserves that have exceeded the amount produced. Projects are in progress or planned to increase production capacity. However, these volume increases are subject to a variety of risks including project start-up timing, operational outages, reservoir performance, crude oil and natural gas prices, weather events, and regulatory changes. The Corporation’s cash flows are also highly dependent on crude oil and natural gas prices. Please refer to Item 1A. Risk Factors for a more complete discussion of risks.
The Corporation’s financial strength enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2011 were $36.8 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment profile of about $37 billion per year for the next several years. Actual spending could vary depending on the progress of individual projects. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas properties have not had a significant impact on the amount or timing of cash flows from operating activities.
Cash Flow from Operating Activities
Cash provided by operating activities totaled $55.3 billion in 2011, $6.9 billion higher than 2010. The major source of funds was net income including noncontrolling interests of $42.2 billion, adjusted for the noncash provision of $15.6 billion for depreciation and depletion, both of which increased. Changes in operational working capital, excluding cash and debt, and the adjustment for net gains on asset sales decreased cash in 2011. Net working capital continued to be negative as total current liabilities of $77.5 billion exceeded total current assets of $73.0 billion at year-end 2011.
Cash provided by operating activities totaled $48.4 billion in 2010, $20.0 billion higher than 2009. The major source of funds was net income including noncontrolling interests of $31.4 billion, adjusted for the noncash provision of $14.8 billion for depreciation and depletion, both of which increased. The net effects of changes in prices and the timing of collection of accounts receivable and of
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payments of accounts and other payables and of income taxes payable increased cash provided by operating activities in 2010 compared to a decrease in 2009, and resulted in net working capital of $(3.6) billion as total current liabilities of $62.6 billion exceeded total current assets of $59.0 billion at year-end 2010.
Cash Flow from Investing Activities
Cash used in investment activities netted to $22.2 billion in 2011, $2.0 billion lower than 2010. Spending for property, plant and equipment of $31.0 billion increased $4.1 billion from 2010. Proceeds associated with sales of subsidiaries, property, plant and equipment, and sales and returns of investments of $11.1 billion compared to $3.3 billion in 2010. The increase primarily reflects the sale of Upstream Canadian, U.K. and other producing properties and assets, the sale of U.S. service stations, and a $3.6 billion deposit for a potential asset sale. Additional investments and advances were $2.3 billion higher in 2011.
Cash used in investment activities netted to $24.2 billion in 2010, $1.8 billion higher than in 2009. Spending for property, plant and equipment of $26.9 billion increased $4.4 billion from 2009. Proceeds from the sale of subsidiaries, investments and property, plant and equipment of $3.3 billion in 2010 compared to $1.5 billion in 2009, the increase reflecting the sale of some U.S. service stations and Upstream Gulf of Mexico and other producing properties.
Cash Flow from Financing Activities
Cash used in financing activities was $28.3 billion in 2011, $1.3 billion higher than 2010. Dividend payments on common shares increased to $1.85 per share from $1.74 per share and totaled $9.0 billion, a pay-out of 22 percent. Total debt increased $2.0 billion to $17.0 billion at year-end.
ExxonMobil share of equity increased $7.6 billion to $154.4 billion. The addition to equity for earnings of $41.1 billion was partially offset by reductions for distributions to ExxonMobil shareholders of $9.0 billion of dividends and $20.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. The change in the funded status of the postretirement benefits reserves in 2011 decreased equity by $4.6 billion.
During 2011, Exxon Mobil Corporation purchased 278 million shares of its common stock for the treasury at a gross cost of $22.1 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 4.9 percent from 4,979 million to 4,734 million at the end of 2011. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.
Cash used in financing activities was $26.9 billion in 2010, $0.4 billion lower than 2009. Dividend payments on common shares increased to $1.74 per share from $1.66 per share and totaled $8.5 billion, a pay-out of 28 percent. Total debt increased to $15.0 billion at year end, an increase of $5.4 billion from 2009, primarily as a result of debt assumed with the XTO merger.
ExxonMobil share of equity increased $36.3 billion to $146.8 billion. The addition to equity for earnings of $30.5 billion and the issuance of stock for the XTO merger of $24.7 billion was partially offset by reductions to equity for distributions to ExxonMobil shareholders of $8.5 billion of dividends and $11.2 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding.
During 2010, Exxon Mobil Corporation issued 416 million shares for the XTO merger. Exxon Mobil Corporation purchased 199 million shares of its common stock for the treasury at a gross cost of $13.1 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding increased by 5.3 percent from 4,727 million at the end of 2009 to 4,979 million at the end of 2010. Purchases were made in both the open market and through negotiated transactions.
Commitments
Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2011. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.
Long-term debt(1)
– Due in one year (2)
Asset retirement obligations (3)
Pension and other postretirement obligations (4)
Operating leases (5)
Unconditional purchase obligations (6)
Take-or-pay obligations(7)
Firm capital commitments (8)
This table excludes commodity purchase obligations (volumetric commitments but no fixed or minimum price) which are resold shortly after purchase, either in an active, highly liquid market or under long-term, unconditional sales contracts with similar pricing terms. Examples include long-term, noncancelable LNG and natural gas purchase commitments and commitments to purchase refinery products at market prices. Inclusion of such commitments would not be meaningful in assessing liquidity and cash flow, because these purchases will be offset in the same periods by cash received from the related sales transactions. The table also excludes unrecognized tax benefits totaling $4.9 billion as of December 31, 2011, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements
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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, 2011, for guarantees relating to notes, loans and performance under contracts (Note 15). The below-mentioned guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Debt-related
Other
Financial Strength
On December 31, 2011, unused credit lines for short-term financing totaled approximately $5.5 billion (Note 5).
The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness.
Net debt to capital (percent)
Management views the Corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The Corporation’s sound financial position gives it the opportunity to access the world’s capital markets in the full range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.
Litigation and Other Contingencies
As discussed in Note 15, a variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Refer to Note 15 for additional information on legal proceedings and other contingencies.
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CAPITAL AND EXPLORATION EXPENDITURES
Upstream (1)
Capital and exploration expenditures in 2011 were $36.8 billion, reflecting the Corporation’s continued active investment program. The Corporation anticipates an investment profile of about $37 billion per year for the next several years. Actual spending could vary depending on the progress of individual projects.
Upstream spending of $33.1 billion in 2011 was up 21 percent from 2010, reflecting unconventional gas activities in the U.S. and continued progress on world-class projects in Australia, Canada and Papua New Guinea. The majority of expenditures are on development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves was 65 percent of total proved reserves at year-end 2011, and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital investments in the Downstream totaled $2.1 billion in 2011, a decrease of $0.4 billion from 2010, due to completion of environmental-related refining projects, primarily in the U.S. The Chemical capital expenditures of $1.5 billion were $0.8 billion lower in 2011 as investments in Asia to meet demand growth progressed toward completion.
TAXES
Income taxes
Effective income tax rate
Sales-based taxes
All other taxes and duties
Income, sales based and all other taxes and duties totaled $108.1 billion in 2011, an increase of $18.9 billion or 21 percent from 2010. Income tax expense, both current and deferred, was $31.1 billion, $9.5 billion higher than 2010, reflecting higher pre-tax income in 2011. A higher share of pre-tax income from the Upstream segment in 2011 increased the effective tax rate to 46 percent compared to 45 percent in 2010. Sales-based and all other taxes and duties of $77.0 billion in 2011 increased $9.4 billion, reflecting higher prices.
Income, sales-based and all other taxes and duties totaled $89.2 billion in 2010, an increase of $10.6 billion or 13 percent from 2009. Income tax expense, both current and deferred, was $21.6 billion, $6.4 billion higher than 2009, reflecting higher pre-tax income in 2010. A lower share of pre-tax income from the Upstream segment in 2010 decreased the effective tax rate to 45 percent compared to 47 percent in 2009. Sales-based and all other taxes and duties of $67.7 billion in 2010 increased $4.2 billion, reflecting higher prices.
ENVIRONMENTAL MATTERS
Environmental Expenditures
Capital expenditures
Other 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 2011 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $4.9 billion. The total cost for such activities is expected to remain in this range in 2012 and 2013 (with capital expenditures approximately 45 percent of the total).
Environmental Liabilities
The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobil’s actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil’s operations or financial condition. Consolidated company provisions made in 2011 for environmental liabilities were $420 million ($448 million in 2010) and the balance sheet reflects accumulated liabilities of $886 million as of December 31, 2011, and $948 million as of December 31, 2010.
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MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Crude oil and NGL ($/barrel)
Natural gas ($/kcf)
Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $350 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $200 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.
In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.
The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength as a competitive advantage.
In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 35 percent of the Corporation’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.
Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its investments over a broad range of future prices. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs.
The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic objectives. The result is an efficient capital base, and the Corporation has seldom had to write down the carrying value of assets, even during periods of low commodity prices.
Risk Management
The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. With respect to derivatives activities, the Corporation believes that there are no material market or credit risks to the Corporation’s financial position, results of operations or liquidity as a result of the derivatives described in Note 12. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. Credit risk associated with the Corporation’s derivative position is mitigated by several factors, including the quality of and financial limits placed on derivative counterparties. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.
The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings, cash flow or fair value. Although the Corporation issues long-term debt from time to time and maintains a commercial paper program, internally generated funds are expected to cover the majority of its net near-term financial requirements. However, some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.
The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts to mitigate the impact of changes in currency values, and exposures related to the Corporation’s limited use of the currency exchange contracts are not material.
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Inflation and Other Uncertainties
The general rate of inflation in many major countries of operation has remained moderate over the past few years, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation works to counter upward pressure on costs through its economies of scale in global procurement and its efficient project management practices.
CRITICAL ACCOUNTING ESTIMATES
The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Corporation’s accounting policies are summarized in Note 1.
Oil and Gas Reserves
Evaluations of oil and gas reserves are important to the effective management of Upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment.
Oil and gas reserves include both proved and unproved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.
The estimation of proved reserves is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals, assisted by the Reserves Technical Oversight group which has significant technical experience, culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation. Key features of the reserve estimation process are covered in Disclosure of Reserves in Item 2.
Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.
Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves was 65 percent of total proved reserves at year-end 2011 (including both consolidated and equity company reserves), and has been over 60 percent for the last five years, indicating that proved reserves are consistently moved from undeveloped to developed status.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in prices and costs that are used in the estimation of reserves. Revisions can also result from significant changes in development strategy or production equipment/facility capacity.
The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method.
Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.
Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than the asset’s carrying value. Impairments are measured by the amount by which the carrying value exceeds the asset’s fair value.
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
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properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluation include a significant decrease in current and projected reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and forecast operating losses.
In general, the Corporation does not view temporarily low oil and gas prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted.
Accordingly, any impairment tests that the Corporation performs make use of the Corporation’s price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on field production profiles, which are updated annually. Cash flow estimates for impairment testing exclude the effects of derivative instruments.
Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements. Future prices used for any impairment tests will vary from the ones used in the supplemental oil and gas disclosure and could be lower or higher for any given year.
Asset Retirement Obligations (ARO)
The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair value of these obligations are recorded as liabilities on a discounted basis. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. AROs are disclosed in Note 8 to the financial statements.
Suspended Exploratory Well Costs
The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2011 are disclosed in Note 9 to the financial statements.
Consolidations
The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the underlying net assets of other significant entities that it does not control, but over which it exercises significant influence, are accounted for using the equity method of accounting.
Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to balance worldwide risks, and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their percentage ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its percentage share of all assets and liabilities in these partially owned companies rather than only its percentage in the net equity. This method of accounting for investments in partially owned companies is not permitted by GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by GAAP standards, the Corporation includes its share of debt of these partially-owned companies in the determination of average capital employed.
Pension Benefits
The Corporation and its affiliates sponsor over 100 defined benefit (pension) plans in about 50 countries. Pension and Other Postretirement Benefits (Note 16) provides details on pension obligations, fund assets and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
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For funded plans, including those in the United States, pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted as appropriate to reflect changes in market rates and outlook. The long-term expected earnings rate on U.S. pension plan assets in 2011 was 7.5 percent. The 10-year and 20-year actual returns on U.S. pension plan assets were 6 percent and 9 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $140 million before tax.
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.
Litigation Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in Note 15.
The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable, and the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our litigation contingency disclosures, “significant” includes material matters as well as other items which management believes should be disclosed.
Management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a material adverse effect on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.
Tax Contingencies
The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
The benefits of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken or expected to be taken in an income tax return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in Note 18.
Foreign Currency Translation
The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment.
Factors considered by management when determining the functional currency for a subsidiary include the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of inflation in the country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.
53
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Corporation’s chief executive officer, principal financial officer, and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporation’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporation’s internal control over financial reporting was effective as of December 31, 2011.
Rex W. Tillerson
Chief Executive Officer
Donald D. Humphreys
Senior Vice President
(Principal Financial Officer)
Patrick T. Mulva
Vice President and Controller
(Principal Accounting Officer)
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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, 2011, and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporation’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 24, 2012
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CONSOLIDATED STATEMENT OF INCOME
Note
Reference
Number
Revenues and other income
Income from equity affiliates
Other income
Total revenues and other income
Costs and other deductions
Crude oil and product purchases
Production and manufacturing expenses
Selling, general and administrative expenses
Depreciation and depletion
Interest expense
Sales-based taxes(1)
Other taxes and duties
Total costs and other deductions
Income before income taxes
Net income including noncontrolling interests
Net income attributable to noncontrolling interests
Earnings per common share (dollars)
Earnings per common share – assuming dilution (dollars)
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
56
CONSOLIDATED BALANCE SHEET
Assets
Current assets
Notes and accounts receivable, less estimated doubtful amounts
Inventories
Crude oil, products and merchandise
Materials and supplies
Other current assets
Total current assets
Investments, advances and long-term receivables
Property, plant and equipment, at cost, less accumulated depreciation and depletion
Other assets, including intangibles, net
Liabilities
Current liabilities
Accounts payable and accrued liabilities
Income taxes payable
Total current liabilities
Postretirement benefits reserves
Deferred income tax liabilities
Other long-term obligations
Total liabilities
Commitments and contingencies
Equity
Common stock without par value(9,000 million shares authorized, 8,019 million shares issued)
Earnings reinvested
Accumulated other comprehensive income
Cumulative foreign exchange translation adjustment
Postretirement benefits reserves adjustment
Unrealized gain on cash flow hedges
Common stock held in treasury (3,285 million shares in 2011 and 3,040 million shares in 2010)
Noncontrolling interests
Total equity
Total liabilities and equity
57
CONSOLIDATED STATEMENT OF CASH FLOWS
Cash flows from operating activities
Adjustments for noncash transactions
Deferred income tax charges/(credits)
Postretirement benefits expense in excess of/(less than) net payments
Other long-term obligation provisions in excess of/(less than) payments
Dividends received greater than/(less than) equity in current earnings of equity companies
Changes in operational working capital, excluding cash and debt
Reduction/(increase) – Notes and accounts receivable
– Inventories
– Other current assets
Increase/(reduction) – Accounts and other payables
Net (gain) on asset sales
All other items – net
Cash flows from investing activities
Proceeds associated with sales of subsidiaries, property, plant and equipment,
and sales and returns of investments
Decrease/(increase) in restricted cash and cash equivalents
Additional investments and advances
Collection of advances
Additions to marketable securities
Sales of marketable securities
Net cash used in investing activities
Cash flows from financing activities
Additions to long-term debt
Reductions in long-term debt
Additions to short-term debt
Reductions in short-term debt
Additions/(reductions) in debt with three months or less maturity
Cash dividends to ExxonMobil shareholders
Cash dividends to noncontrolling interests
Changes in noncontrolling interests
Tax benefits related to stock-based awards
Common stock acquired
Common stock sold
Net cash used in financing activities
Effects of exchange rate changes on cash
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Non-Cash Transactions
The Corporation acquired all the outstanding equity of XTO Energy Inc. in an all-stock transaction valued at $24,659 million in 2010 (see Note 19).
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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Common
Stock
Reinvested
Accumulated
Comprehensive
Income
Held in
Treasury
Share of
Noncontrolling
Interests
Balance as of December 31, 2008
Amortization of stock-based awards
Net income for the year
Dividends – common shares
Foreign exchange translation adjustment
Postretirement benefits reserves adjustment (Note 16)
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs (Note 16)
Acquisitions, at cost
Dispositions
Balance as of December 31, 2009
Adjustment for foreign exchange translation loss included in net income
Change in fair value of cash flow hedges
Realized (gain)/loss from settled cash flow hedges included in net income
Issued for XTO merger
Other dispositions
Balance as of December 31, 2010
Balance as of December 31, 2011
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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (continued)
Acquisitions
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Other comprehensive income (net of income taxes)
Postretirement benefits reserves adjustment (excluding amortization)
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs
Realized (gain)/ loss from settled cash flow hedges included in net income
Comprehensive income including noncontrolling interests
Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to ExxonMobil
60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.
The Corporation’s principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide manufacturer and marketer of petrochemicals (Chemical) and participates in electric power generation (Upstream).
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 2011 presentation basis.
Principles of Consolidation. The Consolidated Financial Statements include the accounts of subsidiaries the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities.
Amounts representing the Corporation’s percentage interest in the underlying net assets of entities that it does not control, but over which it exercises significant influence, are included in “Investments, advances and long-term receivables”. The Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.”
Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans, and management compensation and succession plans.
The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Changes in Equity.
Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.
Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. Revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured.
Revenues from the production of natural gas properties in which the Corporation has an interest with other producers are recognized on the basis of the Corporation’s net working interest. Differences between actual production and net working interest volumes are not significant.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.
Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs).
Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions.
The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the underlying hedged item.
Fair Value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.
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Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.
Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets.
The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.
Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using unit-of-production rates based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods.
Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.
Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Corporation’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.
Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign currency exchange rates. Annual volumes are based on field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation purposes. Cash flow estimates for impairment testing exclude derivative instruments.
Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. Impairments are measured by the amount the carrying value exceeds the fair value.
Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.
Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Corporation.
Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
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Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.
Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted.
Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates.
Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia and Africa, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets.
For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.
Stock-Based Payments. The Corporation awards stock-based compensation to employees in the form of restricted stock and restricted stock units. Compensation expense is measured by the market price of the restricted shares at the date of grant and is recognized in the income statement over the requisite service period of each award. See Note 14, Incentive Program, for further details.
The Corporation did not adopt authoritative guidance in 2011 that had a material impact on the Corporation’s financial statements.
Research and development costs totaled $1,044 million in 2011, $1,012 million in 2010 and $1,050 million in 2009.
Net income included before-tax aggregate foreign exchange transaction losses of $184 million and $251 million, and gains of $54 million in 2011, 2010 and 2009, respectively.
In 2011, 2010 and 2009, net income included gains of $292 million, $317 million and $207 million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $25.6 billion and $21.3 billion at December 31, 2011, and 2010, respectively.
Crude oil, products and merchandise as of year-end 2011 and 2010 consist of the following:
Petroleum products
Crude oil
Chemical products
Gas/other
The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.
The “Net (gain) on asset sales” in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes before-tax gains from the sale of some Upstream Canadian, U.K. and other producing properties and assets, and the sale of U.S. service stations in 2011; from the sale of some Upstream Gulf of Mexico and other producing properties, the sale of U.S. service stations and other Downstream assets and investments and the formation of a Chemical joint venture in 2010; and from the sale of Downstream assets and investments and producing properties in the Upstream in 2009. These gains are reported in “Other income” on the Consolidated Statement of Income.
Included in “Proceeds associated with sales of subsidiaries, property, plant, and equipment, and sales and returns of investments” in 2011 is a $3.6 billion deposit for a potential asset sale.
Cash payments for interest
Cash payments for income taxes
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Dec. 31
Notes and accounts receivable
Trade, less reserves of $128 million and $152 million
Other, less reserves of $39 million and $34 million
Bank loans
Commercial paper
Long-term debt due within one year
Trade payables
Payables to equity companies
Accrued taxes other than income taxes
On December 31, 2011, unused credit lines for short-term financing totaled approximately $5.5 billion. Of this total, $2.8 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2011, and 2010, was 1.9 percent and 1.2 percent, respectively.
The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see Note 1). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several power generation, refining, petrochemical manufacturing and chemical ventures. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 19 percent, 18 percent and 19 percent in the years 2011, 2010 and 2009, respectively.
Share
Total revenues
Long-term assets
Long-term liabilities
Net assets
64
A list of significant equity companies as of December 31, 2011, together with the Corporation’s percentage ownership interest, is detailed below:
Percentage
Ownership
Interest
Aera Energy LLC
BEB Erdgas und Erdoel GmbH
Cameroon Oil Transportation Company S.A.
Castle Peak Power Company Limited
Golden Pass LNG Terminal LLC
Nederlandse Aardolie Maatschappij B.V.
Qatar Liquefied Gas Company Limited
Qatar Liquefied Gas Company Limited 2
Ras Laffan Liquefied Natural Gas Company Limited
Ras Laffan Liquefied Natural Gas Company Limited II
Ras Laffan Liquefied Natural Gas Company Limited (3)
South Hook LNG Terminal Company Limited
Tengizchevroil, LLP
Terminale GNL Adriatico S.r.l.
Chalmette Refining, LLC
Fujian Refining & Petrochemical Co. Ltd.
Saudi Aramco Mobil Refinery Company Ltd.
Al-Jubail Petrochemical Company
Infineum Holdings B.V.
Saudi Yanbu Petrochemical Co.
Toray Tonen Specialty Separator Godo Kaisha
Dec. 31,
Companies carried at equity in underlying assets
Investments
Advances
Total equity company investments and advances
Companies carried at cost or less and stock investments carried at fair value
Long-term receivables and miscellaneous investments at cost or less, net of reserves of $469 million and $292 million
In the Upstream segment, depreciation is generally on a unit-of-production basis, so depreciable life will vary by field. In the Downstream segment, investments in refinery and lubes basestock manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life and service station buildings and fixed improvements over a 20-year life. In the Chemical segment, investments in process equipment are generally depreciated on a straight-line basis over a 20-year life.
Accumulated depreciation and depletion totaled $179,331 million at the end of 2011 and $174,390 million at the end of 2010. Interest capitalized in 2011, 2010 and 2009 was $593 million, $532 million and $425 million, respectively.
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Asset Retirement Obligations
The Corporation incurs retirement obligations for its upstream assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The Corporation uses estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; technical assessments of the assets; estimated amounts and timing of settlements; discount rates; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 (unobservable inputs) fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations.
The following table summarizes the activity in the liability for asset retirement obligations:
Beginning balance
Accretion expense and other provisions
Reduction due to property sales
Payments made
Liabilities incurred
Foreign currency translation
Revisions
Ending balance
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:
Balance beginning at January 1
Additions pending the determination of proved reserves
Charged to expense
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
Ending balance attributed to equity companies included above
Period end capitalized suspended exploratory well costs:
Capitalized for a period of one year or less
Capitalized for a period of between one and five years
Capitalized for a period of between five and ten years
Capitalized for a period of greater than ten years
Capitalized for a period greater than one year – subtotal
Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.
Number of projects with first capitalized well drilled in the preceding 12 months
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months
66
Of the 58 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2011, 26 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 32 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 32 projects, which total $1,133 million.
(millions of dollars)
– Perpetua-Zina-Acacia
– East Pilchard
– SE Longtom
– Natuna
– Kairan
– Besar
– Other (2 projects)
– Bolia
– Bosi
– Pegi
– Other (4 projects)
– Gamma
– H-North
– Lavrans
– Nyk High
– Other (6 projects)
– Juha
– Fram
– Julia Unit
– Point Thomson
– Tip Top
Total 2011 (32 projects)
67
At December 31, 2011, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $7,914 million as indicated in the table. Estimated related rental income from noncancelable subleases is $107 million.
Lease Payments
Under Minimum
Related
SubleaseRental
2012
2013
2014
2015
2016
2017 and beyond
Net rental cost under both cancelable and noncancelable operating leases incurred during 2011, 2010 and 2009 were as follows:
Rental cost
Less sublease rental income
Net rental cost
Net income attributable to ExxonMobil (millions of dollars)
Weighted average number of common shares outstanding (millions of shares)
Earnings per common share(dollars)
Effect of employee stock-based awards
Weighted average number of common shares outstanding – assuming dilution
Dividends paid per common share(dollars)
12. Financial Instruments and Derivatives
Financial Instruments. The fair value of financial instruments is determined by reference to observable market data and other valuation techniques as appropriate. The only category of financial instruments where the difference between fair value and recorded book value is notable is long-term debt. The estimated fair value of total long-term debt, including capitalized lease obligations, was $9.8 billion and $12.8 billion at December 31, 2011, and 2010, respectively, as compared to recorded book values of $9.3 billion and $12.2 billion at December 31, 2011, and 2010, respectively. The fair value hierarchy for long-term debt is primarily Level 1 (quoted prices for identical assets in active markets).
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Derivative Instruments. The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features.
When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and forecasted transactions. The cash flow hedge positions acquired as a result of the XTO merger were settled by December 31, 2011, and those programs have been discontinued.
The estimated fair value of derivative instruments outstanding and recorded on the balance sheet was a net liability of $3 million at year-end 2011 and a net asset of $172 million at year-end 2010. Assets and liabilities associated with derivatives are predominantly recorded either in “Other current assets” or “Accounts payable and accrued liabilities.”
The Corporation’s fair value measurement of its derivative instruments uses primarily Level 2 inputs (derivatives that are determined by either market prices on an active market for similar assets or by prices quoted by a broker or other market-corroborated prices).
The Corporation recognized a before-tax gain or (loss) related to derivative instruments of $131 million, $221 million and $(73) million during 2011, 2010 and 2009, respectively. Income statement effects associated with derivatives are recorded either in “Sales and other operating revenue” or “Crude oil and product purchases.” Of the amount stated above for 2011, cash flow hedges resulted in a before-tax gain of $136 million.
The Corporation believes there are no material market or credit risks to the Corporation’s financial position, results of operations or liquidity as a result of the derivative activities described above.
At December 31, 2011, long-term debt consisted of $8,855 million due in U.S. dollars and $467 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $3,431 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, in each of the four years after December 31, 2012, in millions of dollars, are: 2013 – $967, 2014 – $871, 2015 – $606 and 2016 – $503. At December 31, 2011, the Corporation’s unused long-term credit lines were not material.
Summarized long-term debt at year-end 2011 and 2010 are shown in the table below:
SeaRiver Maritime Financial Holdings, Inc. (1)
Guaranteed deferred interest debentures due 2012
– Face value net of unamortized discount plus accrued interest
XTO Energy Inc.(2)
7.500% senior note due 2012
5.900% senior note due 2012
6.250% senior note due 2013
4.625% senior note due 2013
5.750% senior note due 2013
4.900% senior note due 2014
5.000% senior note due 2015
5.300% senior note due 2015
5.650% senior note due 2016
6.250% senior note due 2017
5.500% senior note due 2018
6.500% senior note due 2018
6.100% senior note due 2036
6.750% senior note due 2037
6.375% senior note due 2038
Mobil Services (Bahamas) Ltd.
Variable note due 2035(3)
Variable note due 2034(4)
Mobil Producing Nigeria Unlimited (5)
Variable notes due 2012-2017
Esso (Thailand) Public Company Ltd. (6)
Mobil Corporation
8.625% debentures due 2021
Industrial revenue bonds due 2012-2051 (7)
Other U.S. dollar obligations (8)
Other foreign currency obligations
Capitalized lease obligations (9)
Total long-term debt
69
Condensed consolidating financial information related to guaranteed securities issued by subsidiaries
Exxon Mobil Corporation has fully and unconditionally guaranteed the deferred interest debentures due 2012 ($2,662 million short-term) of SeaRiver Maritime Financial Holdings, Inc., a 100-percent-owned subsidiary of Exxon Mobil Corporation.
The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for SeaRiver Maritime Financial Holdings, Inc., as issuer, as an alternative to providing separate financial statements for the issuer. The accounts of Exxon Mobil Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the equity method of accounting for investments in subsidiaries.
Exxon Mobil
Corporation
Parent
Guarantor
SeaRiver
Maritime
Financial
Holdings, Inc.
Condensed consolidated statement of income for 12 months ended December 31, 2011
Sales and other operating revenue, including sales-based taxes
Intercompany revenue
70
Condensed consolidated statement of income for 12 months ended December 31, 2010
Condensed consolidated statement of income for 12 months ended December 31, 2009
71
Condensed consolidated balance sheet for year ended December 31, 2011
Notes and accounts receivable – net
Investments and other assets
Property, plant and equipment – net
Intercompany receivables
Other long-term liabilities
Intercompany payables
Other equity
72
Condensed consolidated balance sheet for year ended December 31, 2010
73
Condensed consolidated statement of cash flows for 12 months ended December 31, 2011
Cash provided by/(used in) operating activities
Proceeds associated with sales of long-term assets
Net intercompany investing
All other investing, net
Net cash provided by/(used in) investing activities
Additions to short- and long-term debt
Reductions in short- and long-term debt
Cash dividends
Net intercompany financing activity
All other financing, net
Net cash provided by/(used in) financing activities
Condensed consolidated statement of cash flows for 12 months ended December 31, 2010
74
Condensed consolidated statement of cash flows for 12 months ended December 31, 2009
75
14. Incentive Program
The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited, expire or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2011, remaining shares available for award under the 2003 Incentive Program were 133,183 thousand.
Restricted Stock. Awards totaling 10,533 thousand, 10,648 thousand (excluding XTO merger-related grants), and 10,133 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2011, 2010 and 2009, respectively. Compensation expense for these awards is based on the price of the stock at the date of grant and is recognized in income over the requisite service period. These shares are issued to employees from treasury stock. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. Awards granted to a small number of senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.
Additionally, in 2010 long-term incentive awards totaling 4,206 thousand shares of restricted (nonvested) common stock, with a value of $250 million, were granted in association with the XTO merger. The majority of these awards vest over periods of up to three years after the initial grant.
The Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in conjunction with benefit plans and programs. Purchases may be discontinued at any time without prior notice.
The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2011.
Weighted Average
Grant-Date
Fair Value per Share
Issued and outstanding at January 1
2010 award issued in 2011
Vested
Forfeited
Issued and outstanding at December 31
Grant price
Restricted stock and units settled in stock
Merger-related granted and converted XTO awards
Units settled in cash
Total value
As of December 31, 2011, there was $2,168 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.5 years. The compensation cost charged against income for the restricted stock and restricted units was $793 million, $801 million and $723 million for 2011, 2010 and 2009, respectively. The income tax benefit recognized in income related to this compensation expense was $73 million, $81 million and $76 million for the same periods, respectively. The fair value of shares and units vested in 2011, 2010 and 2009 was $801 million, $718 million and $763 million, respectively. Cash payments of $46 million, $42 million and $41 million for vested restricted stock units settled in cash were made in 2011, 2010 and 2009, respectively.
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Stock Options. The Corporation has not granted any stock options under the 2003 Incentive Program. In 2010, the Corporation granted 12,393 thousand of converted XTO stock options with a grant-date fair value of $182 million as a result of the XTO merger. The grant included 893 thousand of unvested options. Compensation expense for these awards is based on estimated grant-date fair values.
These stock options generally vest and become exercisable ratably over a three-year period, and may include a provision for accelerated vesting when the common stock price reaches specified levels. Some stock option tranches vest only when the common stock price reaches specified levels. As of December 31, 2011, unvested stock options of 226 thousand included 10 thousand options that vest ratably over three years and 216 thousand options that vest at a stock price of $126.80.
Changes that occurred in the Corporation’s stock options in 2011 are summarized below:
Avg. Exercise
Price
Remaining Contractual Term
Outstanding at January 1
Exercised
Outstanding at December 31
Exercisable at December 31
Compensation expense of $1 million in 2011 and $2 million in 2010 fully expensed the nonvested merger-related XTO stock options. No compensation expense was recognized for stock options in 2009 as all remaining outstanding stock options at that time were fully vested. Cash received from stock option exercises was $924 million, $1,043 million and $752 million for 2011, 2010 and 2009, respectively. The cash tax benefit realized for the options exercised was $221 million, $89 million and $164 million for 2011, 2010 and 2009, respectively. The aggregate intrinsic value of stock options exercised in 2011, 2010 and 2009 was $986 million, $539 million and $563 million, respectively. The intrinsic value for the balance of outstanding stock options at December 31, 2011, was $98 million. The intrinsic value for the balance of exercisable stock options at December 31, 2011, was $97 million.
77
Litigation. A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of our contingency disclosures, “significant” includes material matters as well as other matters which management believes should be disclosed. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole.
On June 30, 2011, a state district court jury in Baltimore County, Maryland returned a verdict against Exxon Mobil Corporation in Allison, et al v. Exxon Mobil Corporation, a case involving an accidental 26,000 gallon gasoline leak at a suburban Baltimore service station. The verdict included approximately $497 million in compensatory damages and approximately $1.0 billion in punitive damages in a finding that ExxonMobil fraudulently misled the plantiff-residents about the events leading up to the leak, the leak’s discovery, and the nature and extent of any groundwater contamination. ExxonMobil believes the verdict is not justified by the evidence and that the amount of the compensatory award is grossly excessive and the imposition of punitive damages is improper and unconstitutional. The trial court denied a post-trial motion that ExxonMobil filed to overturn the punitive damages verdict. Following the entry of a final judgment, ExxonMobil will appeal the verdict and judgment. In a prior trial involving the same leak, the jury awarded plantiff-residents compensatory damages but decided against punitive damages. The plaintiffs did not appeal the jury’s denial of punitive damages. Following an appeal by ExxonMobil of the compensatory damages award, on February 9, 2012, the Maryland Special Court of Appeals reversed in part and affirmed in part the trial court’s decision on compensatory damages. The ultimate outcome of this litigation is not expected to have a material adverse effect upon the Corporation’s operations, financial condition, or financial statements taken as a whole.
Other Contingencies. The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2011, for guarantees relating to notes, loans and performance under contracts.
Company
Obligations(1)
Third-Party
Obligations
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.
2013-
2017
and
Beyond
Unconditional purchase obligations (1)
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
78
affiliate’s ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project. ExxonMobil’s remaining net book investment in Cerro Negro producing assets was about $750 million at year-end 2011.
On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes (ICSID) invoking ICSID jurisdiction under Venezuela’s Investment Law and the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID Tribunal issued a decision on June 10, 2010, finding that it had jurisdiction to proceed on the basis of the Netherlands-Venezuela Bilateral Investment Treaty. The ICSID arbitration proceeding is continuing and a hearing on the merits was held in February 2012. At this time, the net impact of these matters on the Corporation’s consolidated financial results cannot be reasonably estimated. Regardless, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition.
An affiliate of ExxonMobil, Mobil Cerro Negro, Ltd. (MCN), also filed an arbitration under the rules of the International Chamber of Commerce (ICC) against PdVSA and a PdVSA affiliate, PdVSA CN, for breach of their contractual obligations under certain Cerro Negro Project agreements. On December 23, 2011, the tribunal rendered its award which found PdVSA and PdVSA CN jointly and severally liable to MCN in the amount of about $908 million. The tribunal deducted approximately $161 million of uncontested debt owed by MCN to PdVSA and PdVSA CN, leaving a balance of about $747 million. Post-award interest on this net amount was set at the New York prime rate compounded annually and running from the date of the award. The tribunal granted PdVSA and PdVSA CN a sixty-day grace period in which to comply with the award. On January 26, 2012, MCN filed a motion to confirm the award against PdVSA CN. In response to an order to show cause filed by PdVSA on January 17, 2012, the United States District Court for the Southern District of New York, on February 1, 2012, ordered the release to MCN of approximately $305 million of PdVSA CN funds previously attached in connection with the arbitration in partial satisfaction of the award. MCN received those funds on February 10, 2012. In further satisfaction of the award, PdVSA cancelled approximately $195 million in MCN bond debt on February 13, 2012. PdVSA paid MCN the balance of the monetary portion of the award on February 14, 2012.
An affiliate of ExxonMobil is one of the Contractors under a Production Sharing Contract (PSC) with the Nigerian National Petroleum Corporation (NNPC) covering the Erha block located in the offshore waters of Nigeria. ExxonMobil’s affiliate is the operator of the block and owns a 56.25 percent interest under the PSC. The Contractors are in dispute with NNPC regarding NNPC’s lifting of crude oil in excess of its entitlement under the terms of the PSC. In accordance with the terms of the PSC, the Contractors initiated arbitration in Abuja, Nigeria, under the Nigerian Arbitration and Conciliation Act. On October 24, 2011, a three-member arbitral Tribunal issued an award upholding the Contractors’ position in all material respects and awarding damages to the Contractors jointly in an amount of approximately $1.8 billion plus $234 million in accrued interest. The Contractors have petitioned a Nigerian federal court for enforcement of the award, and NNPC has petitioned the same court to have the award set aside. Those proceedings are pending. At this time, the net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. However, regardless of the outcome of enforcement proceedings, the Corporation does not expect the proceedings to have a material effect upon the Corporation’s operations or financial condition.
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The benefit obligations and plan assets associated with the Corporation’s principal benefit plans are measured on December 31.
Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate
Long-term rate of compensation increase
Change in benefit obligation
Benefit obligation at January 1
Service cost
Interest cost
Actuarial loss/(gain)
Benefits paid (1) (2)
Foreign exchange rate changes
Plan amendments, other
Benefit obligation at December 31
Accumulated benefit obligation at 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 5.5 percent that declines to 4.5 percent by 2015. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $63 million and the postretirement benefit obligation by $696 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $49 million and the postretirement benefit obligation by $567 million.
Change in plan assets
Fair value at January 1
Actual return on plan assets
Company contribution
Benefits paid(1)
Fair value at December 31
80
The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
Assets in excess of/(less than) benefit obligation
Balance at December 31
Funded plans
Unfunded plans
The authoritative guidance for defined benefit pension and other postretirement plans requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.
Balance at December 31 (1)
Amounts recorded in the consolidated balance sheet consist of:
Other assets
Total recorded
Amounts recorded in accumulated other comprehensive income consist of:
Net actuarial loss/(gain)
Prior service cost
Total recorded in accumulated other comprehensive income
81
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.
Other Postretirement
Benefits
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31
Long-term rate of return on funded assets
Components of net periodic benefit cost
Expected return on plan assets
Amortization of actuarial loss/(gain)
Amortization of prior service cost
Net pension enhancement and curtailment/settlement expense
Net periodic benefit cost
Changes in amounts recorded in accumulated other comprehensive income:
Amortization of actuarial (loss)/gain
Prior service cost/(credit)
Amortization of prior service (cost)/credit
Total recorded in other comprehensive income
Total recorded in net periodic benefit cost and other comprehensive income, before tax
Costs for defined contribution plans were $378 million, $347 million and $339 million in 2011, 2010 and 2009, respectively.
A summary of the change in accumulated other comprehensive income is shown in the table below:
U.S. pension
Non-U.S. pension
Other postretirement benefits
Total (charge)/credit to other comprehensive income, before tax
(Charge)/credit to income tax (see Note 18)
(Charge)/credit to investment in equity companies
(Charge)/credit to other comprehensive income including noncontrolling interests, after tax
Charge/(credit) to equity of noncontrolling interests
(Charge)/credit to other comprehensive income attributable to ExxonMobil
82
The Corporation’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The benefit plan assets are primarily invested in passive equity and fixed income index funds to diversify risk while minimizing costs. The equity funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. The fixed income funds are largely invested in high-quality corporate and government debt securities.
Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for the U.S. benefit plans is 50 percent equity securities and 50 percent debt securities. The target asset allocation for the non-U.S. plans in aggregate is 47 percent equities, 50 percent debt and 3 percent real estate funds. The equity targets for the U.S. and non-U.S. plans include an allocation to private equity partnerships that primarily focus on early-stage venture capital of 5 percent and 3 percent, respectively.
The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment.
The 2011 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
Quoted Prices
in Active
Markets for
Identical
(Level 1)
Significant
Observable
Inputs
(Level 2)
Unobservable
(Level 3)
Asset category:
Equity securities
U.S.
Private equity
Debt securities
Corporate
Government
Asset-backed
Private mortgages
Real estate funds
Cash
Total at fair value
Insurance contracts at contract value
Total plan assets
83
The change in the fair value in 2011 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:
Private
Mortgages
Real
Estate
Net realized gains/(losses)
Net unrealized gains/(losses)
Net purchases/(sales)
84
The 2010 fair value of the benefit plan assets, including the level within the fair value hierarchy, is shown in the tables below:
85
Quoted Pricesin ActiveMarkets forIdenticalAssets
The change in the fair value in 2010 of Level 3 assets that use significant unobservable inputs to measure fair value is shown in the table below:
86
A summary of pension plans with an accumulated benefit obligation in excess of plan assets is shown in the table below:
For funded pension plans with an accumulated benefit obligation in excess of plan assets:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
For unfunded pension plans:
Estimated 2012 amortization from accumulated other comprehensive income:
Net actuarial loss/(gain)(1)
Prior service cost(2)
Contributions expected in 2012
Benefit payments expected in:
2017 - 2021
The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.
These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete financial information is available.
Earnings after income tax include special items, and transfers are at estimated market prices. Earnings for 2009 included a special charge of $140 million in the corporate and financing segment for interest related to the Valdez punitive damages award.
Interest expense includes non-debt-related interest expense of $165 million, $41 million and $500 million in 2011, 2010 and 2009, respectively. Higher expenses in 2009 primarily reflect interest provisions related to the Valdez litigation.
In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities.
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As of December 31, 2011
Earnings after income tax
Earnings of equity companies included above
Intersegment revenue
Depreciation and depletion expense
Interest revenue
Investments in equity companies
As of December 31, 2010
As of December 31, 2009
Significant non-U.S. revenue sources include:
Long-lived assets
Significant non-U.S. long-lived assets include:
88
Income tax expense
Federal and non-U.S.
Current
Deferred – net
U.S. tax on non-U.S. operations
Total federal and non-U.S.
State
Total income tax expense
Included in production and manufacturing expenses
Included in SG&A expenses
Total other taxes and duties
All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include net credits of $330 million in 2011 and $9 million in 2009 and a net charge of $175 million in 2010 for the effect of changes in tax laws and rates.
Income taxes (charged)/credited directly to equity were:
Postretirement benefits reserves adjustment:
Total postretirement benefits reserves adjustment
Other components of equity
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2011, 2010 and 2009 is as follows:
Theoretical tax
Effect of equity method of accounting
Non-U.S. taxes in excess of theoretical U.S. tax
State taxes, net of federal tax benefit
Other U.S.
Effective tax rate calculation
ExxonMobil share of equity company income taxes
Total income taxes
Total income before taxes
89
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.
Deferred tax liabilities/(assets) are comprised of the following at December 31:
Property, plant and equipment
Other liabilities
Total deferred tax liabilities
Pension and other postretirement benefits
Asset retirement obligations
Tax loss carryforwards
Total deferred tax assets
Asset valuation allowances
Net deferred tax liabilities
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 $47 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.
Unrecognized Tax Benefits
The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. Resolution of the related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the Corporation. It is reasonably possible that the total amount of unrecognized tax benefits could increase by up to 50 percent in the next 12 months, with no material impact on near-term earnings. Given the long time periods involved in resolving tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporation’s effective income tax rate in any given year.
The following table summarizes the movement in unrecognized tax benefits.
Balance at January 1
Additions based on current year’stax positions
Additions for prior years’ tax positions
Reductions for prior years’ tax positions
Reductions due to lapse of the statuteof limitations
Settlements with tax authorities
Foreign exchange effects/other
The additions and reductions in unrecognized tax benefits shown above include effects related to net income and equity, and timing differences for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2011, 2010 and 2009 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income or cash flow.
The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
Abu Dhabi
2004 - 2011
The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.
The Corporation incurred $62 million in interest expense on income tax reserves in 2011. For 2010, interest expense was a credit of $39 million, reflecting the effect of credits from the net favorable resolution of prior year tax positions. The Corporation incurred approximately $135 million in interest expense on income tax reserves in 2009. The related interest payable balances were $662 million and $636 million at December 31, 2011, and 2010, respectively.
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Description of the Transaction. On June 25, 2010, ExxonMobil acquired XTO Energy Inc. (XTO) by merging a wholly-owned subsidiary of ExxonMobil with and into XTO (the “merger”), with XTO continuing as the surviving corporation and wholly-owned subsidiary of ExxonMobil. XTO is involved in the exploration for, production of, and transportation and sale of crude oil and natural gas.
At the effective time of the merger, each share of XTO common stock was converted into the right to receive 0.7098 shares of common stock of ExxonMobil (the “Exchange Ratio”), with cash being paid in lieu of any fractional shares of ExxonMobil stock. Also at the effective time, each outstanding option to purchase XTO common stock was converted into an option to purchase a number of shares of ExxonMobil stock based on the Exchange Ratio, and each outstanding stock-based award of XTO was converted into a stock-based award of ExxonMobil stock based on the Exchange Ratio.
The components of the consideration transferred follow:
Consideration attributable to stock issued (1) (2)
Consideration attributable to converted stock options (2)
Total consideration transferred
Recording of Assets Acquired and Liabilities Assumed. The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.
The following table summarizes the assets acquired and liabilities assumed:
Property, plant and equipment (1)
Goodwill (2)
Total assets acquired
Long-term debt (3)
Deferred income tax liabilities (4)
Total liabilities assumed
Net assets acquired
The 2010 unaudited pro forma revenues of $373 billion, net income attributable to ExxonMobil of $31 billion, earnings per common share of $6.03 and earnings per common share assuming dilution of $6.01 for the Corporation were calculated as if the merger of XTO had occurred at the beginning of 2010. The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the merger and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the merger been completed on January 1, 2010. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. The unaudited pro forma consolidated results reflect pro forma adjustments for the elimination of deferred gains and losses recognized in earnings for derivatives outstanding at the beginning of the year, depreciation expense related to the fair value adjustment to property, plant and equipment acquired, additional amortization expense related to the fair value of identifiable intangible assets acquired, capitalization of interest expense and applicable income tax impacts.
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On January 29, 2012, the Corporation announced that it had entered into an agreement which will result in the restructuring of its Downstream and Chemical holdings in Japan. Under the agreement, TonenGeneral Sekiyu K. K. (TG), a consolidated subsidiary owned 50 percent by the Corporation, will purchase for approximately $3.9 billion the Corporation’s shares of a wholly-owned affiliate in Japan, ExxonMobil Yugen Kaisha, which will result in TG acquiring approximately 200 million of its shares currently owned by the Corporation along with other assets. As a result of the restructuring the Corporation’s effective ownership of TG will be reduced to approximately 22 percent. Closing is anticipated in mid-2012.
The major classes of assets and liabilities that would have been classified as held for sale if the transaction had met the criteria for held for sale accounting at December 31, 2011, were as follows:
Current assets(1)
Net property, plant and equipment
ExxonMobil share of equity(2)
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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
The results of operations for producing activities shown below do not include earnings from other activities that ExxonMobil includes in the Upstream function, such as oil and gas transportation operations, LNG liquefaction and transportation operations, coal and power operations, technical service agreements, other nonoperating activities and adjustments for noncontrolling interests. These excluded amounts for both consolidated and equity companies totaled $2,600 million in 2011, $249 million in 2010, and $536 million in 2009. Oil sands mining operations are included in the results of operations in accordance with Securities and Exchange Commission and Financial Accounting Standards Board rules.
Results of Operations
South America
2011 – Revenue
Sales to third parties
Transfers
Production costs excluding taxes
Exploration expenses
Taxes other than income
Related income tax
Results of producing activities for consolidated subsidiaries
Results of producing activities for equity companies
Total results of operations
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2010 – Revenue
2009 – Revenue
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Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $6,651 million less at year-end 2011 and $4,729 million less at year-end 2010 than the amounts reported as investments in property, plant and equipment for the Upstream in Note 8. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to LNG operations. Assets related to oil sands and oil shale mining operations have been included in the capitalized costs for 2011 and 2010 in accordance with Financial Accounting Standards Board rules.
Capitalized Costs
Property (acreage) costs – Proved
– Unproved
Total property costs
Producing assets
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for consolidated subsidiaries
Net capitalized costs for equity companies
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Oil and Gas Exploration and Production Costs (continued)
The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2011 were $30,754 million, down $40,058 million from 2010, due primarily to the absence of the acquisition of XTO Energy Inc. 2010 costs were $70,812 million, up $50,305 million from 2009, due primarily to the acquisition of XTO Energy Inc. Total equity company costs incurred in 2011 were $1,226 million, up $312 million from 2010, due primarily to higher development costs.
Costs incurred in property acquisitions,
exploration and development activities
Property acquisition costs – Proved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Total costs incurred for equity companies
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The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2009, 2010, and 2011.
The definitions used are in accordance with the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves.
In accordance with the Securities and Exchange Commission’s rules, the year-end reserves volumes as well as the reserves change categories shown in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in average prices and year-end costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.
Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and ExxonMobil’s ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.
In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies.
Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The production and reserves that we report for these types of arrangements typically vary inversely with oil and gas price changes. As oil and gas prices increase, the cash flow and value received by the company increase; however, the production volumes and reserves required to achieve this value will typically be lower because of the higher prices. When prices decrease, the opposite effect generally occurs. The percentage of total liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2011 that were associated with production sharing contract arrangements was 14 percent of liquids, 9 percent of natural gas and 11 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil’s oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported in the Operating Summary due to volumes consumed or flared and inventory changes.
In accordance with the Securities and Exchange Commission’s rules, bitumen extracted through mining activities and hydrocarbons from other non-traditional resources are reported as oil and gas reserves beginning in 2009.
The rules in 2009 adopted a reliable technology definition that permits reserves to be added based on technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated.
The changes between 2010 year-end proved reserves and 2011 year-end proved reserves reflect the initial booking of the Kearl Expansion project in Canada.
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S. Amer.
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2009
Improved recovery
Purchases
Sales
Extensions/discoveries
Production
December 31, 2009
Proportional interest in proved reservesof equity companies
Total liquids proved reserves at December 31, 2009
January 1, 2010
December 31, 2010
Total liquids proved reserves at December 31, 2010
98
January 1, 2011
December 31, 2011
Total liquids proved reservesat December 31, 2011
99
Proved developed reserves, as of December 31, 2009
Consolidated subsidiaries
Equity companies
Proved undeveloped reserves, as of December 31, 2009
Proved developed reserves, as of December 31, 2010
Proved undeveloped reserves, as of December 31, 2010
Proved developed reserves, as of December 31, 2011
Proved undeveloped reserves, as of December 31, 2011
Total liquids proved reserves at December 31, 2011
100
Total All Products (2)
Net proved developed and undeveloped reservesof consolidated subsidiaries
Total proved reserves at December 31, 2009
Total proved reserves at December 31, 2010
(See footnotes on next page)
101
Total proved reserves at December 31, 2011
102
(See footnotes on previous page)
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Standardized Measure of Discounted Future Cash Flows
As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporation’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
Standardized Measure
of Discounted Future Cash Flows
SouthAmerica (1)
Future cash inflowsfrom sales of oil and gas
Future production costs
Future development costs
Future income tax expenses
Future net cash flows
Effect of discounting net cash flows at 10%
Discounted future net cash flows
Total consolidated and equity interests in standardized measure of discounted future net cash flows
104
of Discounted Future Cash Flows (continued)
Future cash inflows from sales of oil and gas
105
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated
Subsidiaries
Equity Method
Investees
and Equity
Discounted future net cash flows as of December 31, 2008
Value of reserves added during the year due to extensions, discoveries, improved recoveryand net purchases less related costs
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs
Development costs incurred during the year
Net change in prices, lifting and development costs
Revisions of previous reserves estimates
Accretion of discount
Net change in income taxes
Total change in the standardized measure during the year
Discounted future net cash flows as of December 31, 2009
Discounted future net cash flows as of December 31, 2010
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Discounted future net cash flows as of December 31, 2011
107
OPERATING SUMMARY (unaudited)
Production of crude oil, natural gas liquids, synthetic oil and bitumen
Net production
Petroleum product sales(2)
Asia Pacific and other Eastern Hemisphere
Gasoline, naphthas
Heating oils, kerosene, diesel oils
Aviation fuels
Heavy fuels
Specialty petroleum products
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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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
(Rex W. Tillerson,
Chairman of the Board)
Dated February 24, 2012
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Randall M. Ebner, Leonard M. Fox and Catherine C. Shae and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on February 24, 2012.
/s/ REX W. TILLERSON
(Rex W. Tillerson)
Chairman of the Board
(Principal Executive Officer)
/s/ MICHAEL J. BOSKIN
(Michael J. Boskin)
/s/ PETER BRABECK-LETMATHE
(Peter Brabeck-Letmathe)
/s/ LARRY R. FAULKNER
(Larry R. Faulkner)
/s/ JAY S. FISHMAN
(Jay S. Fishman)
/s/ KENNETH C. FRAZIER
(Kenneth C. Frazier)
/s/ WILLIAM W. GEORGE
(William W. George)
109
/s/ MARILYN CARLSON NELSON
(Marilyn Carlson Nelson)
/s/ SAMUEL J. PALMISANO
(Samuel J. Palmisano)
/s/ STEVEN S REINEMUND
(Steven S Reinemund)
/s/ EDWARD E. WHITACRE, JR.
(Edward E. Whitacre, Jr.)
/s/ DONALD D. HUMPHREYS
(Donald D. Humphreys)
/s/ PATRICK T. MULVA
(Patrick T. Mulva)
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INDEX TO EXHIBITS
Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
By-Laws, as revised to April 27, 2011 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Report on Form 8-K on April 29, 2011).
2003 Incentive Program (incorporated by reference to Exhibit 10(iii)(a.1) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008).*
Form of restricted stock agreement with executive officers (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K of November 30, 2011).*
Extended Provisions for Restricted Stock Unit Agreements-Settlement in Shares.*
Short Term Incentive Program, as amended (incorporated by reference to Exhibit 99.3 to the Registrant’s Report on Form 8-K on December 1, 2009).*
Form of Earnings Bonus Unit granted to executive officers (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on November 30, 2011).*
ExxonMobil Supplemental Savings Plan.*
ExxonMobil Supplemental Pension Plan.*
ExxonMobil Additional Payments Plan.*
ExxonMobil Executive Life Insurance and Death Benefit Plan.*
2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f.1) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).*
Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K on September 27, 2007).*
Form of restricted stock grant letter for non-employee directors (incorporated by reference to Exhibit 10(iii)(f.3) to the Registrant’s Annual Report on Form 10-K for 2009).*
Standing resolution for non-employee director cash fees dated October 26, 2011 (incorporated by reference to Exhibit 10(iii)(f.4) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).*
1984 Mobil Compensation Management Retention Plan.*
Computation of ratio of earnings to fixed charges.
Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrant’s Annual Report on Form 10-K for 2008).
Subsidiaries of the registrant.
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Financial Officer.
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Financial Officer.
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.
Interactive data files.
111
INDEX 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.
112