2008
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2008
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)
NEW JERSEY
(State or other jurisdiction ofincorporation or organization)
13-5409005
(I.R.S. EmployerIdentification Number)
5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298
(Address of principal executive offices) (Zip Code)
(972) 444-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, without par value (4,941,630,490 sharesoutstanding at January 31, 2009)
SeaRiver Maritime Financial Holdings, Inc.
Twenty-Five Year Debt Securities due October 1, 2011
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ü No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No ü
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ü No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ü
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ü Accelerated filer
Non-accelerated filer Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Act). Yes No ü
The aggregate market value of the voting stock held by non-affiliates of the registrant on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $88.13 on the New York Stock Exchange composite tape, was in excess of $457 billion.
Documents Incorporated by Reference:
Proxy Statement for the 2009 Annual Meeting of Shareholders (Part III)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008
TABLE OF CONTENTS
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Submission of Matters to a Vote of Security Holders
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
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
PART I
Item 1. Business.
Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil also has interests in electric power generation facilities. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.
Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso or Mobil. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso and Mobil, as well as terms like Corporation, Company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.
Throughout ExxonMobil’s businesses, new and ongoing measures are taken to prevent and minimize the impact of our operations on air, water and ground. These include a significant investment in refining infrastructure and technology to manufacture clean fuels as well as projects to reduce nitrogen oxide and sulfur oxide emissions and expenditures for asset retirement obligations. ExxonMobil’s 2008 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $5.2 billion, of which $2.5 billion were capital expenditures and $2.7 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2009 and 2010 (with capital expenditures approximately 50 percent of the total).
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 11 thousand active patents worldwide at the end of 2008. For technology licensed to third parties, revenues totaled approximately $125 million in 2008. 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 79.9 thousand, 80.8 thousand and 82.1 thousand at years ended 2008, 2007 and 2006, 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 24.8 thousand, 26.3 thousand and 24.3 thousand at years ended 2008, 2007 and 2006, respectively.
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
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furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available on the Corporation’s website are the Company’s Corporate Governance Guidelines and Code of Ethics and Business Conduct, as well as the charters of the audit, compensation and nominating committees of the Board of Directors. All of these documents are available in print without charge to shareholders who request them. 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 and gas business. 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 factors include the following:
Industry and Economic Factors: The oil and gas business is fundamentally a commodity business. This means the operations and earnings of the Corporation and its affiliates throughout the world may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on gasoline and other 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. These events or conditions are generally not predictable and include, among other things:
general economic growth rates and the occurrence of economic recessions;
the development of new supply sources;
adherence by countries to OPEC quotas;
supply disruptions;
weather, including seasonal patterns that affect regional energy demand (such as the demand for heating oil or gas in winter) as well as severe weather events (such as hurricanes) that can disrupt supplies or interrupt the operation of ExxonMobil facilities;
technological advances, including advances in exploration, production, refining and petrochemical manufacturing technology and advances in technology relating to energy usage;
changes in demographics, including population growth rates and consumer preferences; and
the competitiveness of alternative hydrocarbon or other energy sources.
Under certain market conditions, factors that have a positive impact on one segment of our business may have a negative impact on another segment and vice versa.
Competitive Factors: 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.
A key component of the Corporation’s competitive position, particularly given the commodity-based nature of many of its businesses, is ExxonMobil’s ability to manage expenses successfully. This requires continuous management focus on reducing unit costs and improving efficiency including through technology improvements, cost control, productivity enhancements and regular reappraisal of our asset portfolio.
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Political and Legal Factors: The operations and earnings of the Corporation and its affiliates throughout the world have been, and may in the future be, affected from time to time in varying degree by political and legal factors including:
political instability or lack of well-established and reliable legal systems in areas where the Corporation operates;
other political developments and laws and regulations, such as expropriation or forced divestiture of assets, unilateral cancellation or modification of contract terms, and regulation of certain energy markets;
laws and regulations related to environmental or energy security matters, including those addressing alternative energy sources and the risks of global climate change;
restrictions on exploration, production, imports and exports;
restrictions on the Corporation’s ability to do business with certain countries, or to engage in certain areas of business within a country;
price controls;
tax or royalty increases, including retroactive claims;
war or other international conflicts; and
civil unrest.
Both the likelihood of these occurrences and their overall effect upon the Corporation vary greatly from country to country and are not predictable.
Project Factors: In addition to some of the factors cited above, ExxonMobil’s results depend upon the Corporation’s ability to develop and operate major projects and facilities as planned. The Corporation’s results will therefore be affected by events or conditions that impact the advancement, operation, cost or results of such projects or facilities, including:
the outcome of negotiations with co-venturers, governments, suppliers, customers or others (including, for example, our ability to negotiate favorable long-term contracts with customers, or the development of reliable spot markets, that may be necessary to support the development of particular production projects);
reservoir performance and natural field decline;
changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping;
security concerns or acts of terrorism that threaten or disrupt the safe operation of company facilities; and
the occurrence of unforeseen technical difficulties (including technical problems that may delay start-up or interrupt production from an Upstream project or that may lead to unexpected downtime of refineries or petrochemical plants).
The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the period 2009-2013. 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 described above.
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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.
Market Risk Factors:
Worldwide Average Realizations—Consolidated Subsidiaries
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 $375 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $175 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.
In the very competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels of products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather.
The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the Corporation’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the Corporation’s financial strength, including the AAA and Aaa ratings of its long-term debt securities by Standard & Poor’s and Moody’s, as a competitive advantage.
In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Instead, where such sales take place, they are the result of efficiencies and competitive advantages of integrated refinery/chemical complexes. Additionally, intersegment sales are at market-based prices. The products bought and sold between segments can also be acquired in worldwide markets that have substantial liquidity, capacity and transportation capabilities. About 40 percent of the Corporation’s intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.
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Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its investments over a broad range of future prices. The Corporation’s assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs. Investment opportunities are tested against a variety of market conditions, including low-price scenarios.
The Corporation has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the Corporation’s strategic objectives. The result is an efficient capital base, and the Corporation has seldom had to write down the carrying value of assets, even during periods of low commodity prices.
Risk Management
The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. “Note 12: Financial Instruments and Derivatives” of the Financial Section of this report summarizes the fair value of derivatives outstanding at year end and the gains or losses that have been recognized in net income.
The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings, cash flow or fair value. The Corporation’s cash balances exceeded total debt at year-end 2008 and 2007. During 2008, credit markets tightened and the global economy slowed. The Corporation is not dependent on the credit markets to fund current operations. However, some joint-venture partners are dependent on the credit markets and their funding ability may impact the development pace of joint-venture projects.
The Corporation conducts business in many foreign currencies and is subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in exchange rates on ExxonMobil’s geographically and functionally diverse operations are varied and often offsetting in amount. The Corporation makes limited use of currency exchange contracts, commodity forwards, swaps and futures contracts to mitigate the impact of changes in currency values and commodity prices. Exposures related to the Corporation’s limited use of the above contracts are not material.
Inflation and Other Uncertainties
The general rate of inflation in many major countries of operation increased in 2008 versus the relatively low rates in recent years, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased global
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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.
Projections, estimates and descriptions of ExxonMobil’s plans and objectives included or incorporated in Items 1, 2, 7 and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report.
None.
Item 2. Properties.
Part of the information in response to this item and to the Securities Exchange Act Industry Guide 2 is contained in “Note 8: Property, Plant and Equipment and Asset Retirement Obligations” and in the “Supplemental Information on Oil and Gas Exploration and Production Activities,” both included in the Financial Section of this report.
Information with regard to oil and gas producing activities follows:
Estimated proved reserves are shown 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. No major discovery or other favorable or adverse event has occurred since December 31, 2008, that would cause a significant change in the estimated proved reserves as of that date. For information on the standardized measure of discounted future net cash flows relating to proved oil and gas reserves, see the “Standardized Measure of Discounted Future Cash Flows” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report.
The table below summarizes the oil-equivalent proved reserves in each geographic area for consolidated subsidiaries as detailed 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 for the year ended December 31, 2008. The Corporation has reported proved reserves on the basis of December 31 prices and costs. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
United States
Canada/South America
Europe
Africa
Asia Pacific/Middle East
Russia/Caspian
Total consolidated
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Additional detail on developed and undeveloped oil-equivalent proved reserves is shown in the table below.
Consolidated Subsidiaries
Total
Equity Companies
In the preceding reserves information, and in the reserves tables 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, 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 2009-2013. 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.
2. Estimates of Total Net Proved Oil and Gas Reserves Filed with Other Federal Agencies
During 2008, ExxonMobil filed proved reserves estimates with the U.S. Department of Energy on Forms EIA-23 and EIA-28. The information on Form EIA-28 is presented on the same basis as the registrant’s Annual Report on Form 10-K for 2007, which shows ExxonMobil’s net interests in all liquids and gas reserve volumes and changes thereto from both ExxonMobil-operated properties and properties operated by others. The data on Form EIA-23, although consistent with the data on Form EIA-28, is presented on a different basis, and includes 100 percent of the oil and gas volumes from ExxonMobil-operated properties only, regardless of the company’s net interest. In addition,
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Form EIA-23 information does not include gas plant liquids. The difference between the oil reserves and gas reserves reported on EIA-23 and those reported in the registrant’s Annual Report on Form 10-K for 2007 exceeds five percent.
3. Average Sales Prices and Production Costs per Unit of Production
Reference is made to the “Results of Operations” part of the “Supplemental Information on Oil and Gas Exploration and Production Activities” portion of the Financial Section of this report. Average sales 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 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. The volumes of natural gas used in the calculation are the production volumes of natural gas available for sale and thus 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.
4. Gross and Net Productive Wells
There were 16,286 gross and 13,573 net operated wells at year-end 2008 and 16,797 gross and 13,945 net operated wells at year-end 2007.
5. Gross and Net Developed Acreage
Note: Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.
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6. 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.
7. 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.
CANADA / SOUTH AMERICA
Canada
Exploration permits are granted for varying periods of time with renewals possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to obtain leases upon completing specified work. Production leases are held as long as there is production on the lease. The majority of Cold Lake leases were taken for an initial 21-year term in 1968-1969 and renewed for a second 21-year term in 1989-1990. The exploration acreage in eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.
Argentina
The onshore concession terms in Argentina are up to four years for the initial exploration period, up to three years for the second exploration period and up to two years for the third exploration period. A 50-percent relinquishment is required after each exploration period. An extension after the third exploration period is possible for up to five years. The total production term is 25 years with a ten-year extension possible, once a field has been developed.
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EUROPE
Germany
Exploration concessions are granted for an initial maximum period of five years, with an unlimited number of extensions of up to three years each. Extensions are subject to specific, minimum work commitments. Production licenses are normally granted for 20 to 25 years with multiple possible extensions as long as there is production on the license. In May 2007, ExxonMobil affiliates acquired four exploration licenses over 1.3 million acres in the Lower Saxony Basin. The exploration licenses are for a period of five years during which exploration work programs will be carried out.
Netherlands
Under the Mining Law, effective January 1, 2003, exploration and production licenses for both onshore and offshore areas are issued for a period as explicitly defined in the license. The term is based on the period of time necessary to perform the activities for which the license is issued. License conditions are stipulated in the Mining Law.
Production rights granted prior to January 1, 2003, remain subject to their existing terms, and differ slightly for onshore and offshore areas. Onshore production licenses issued prior to 1988 were indefinite; from 1988 they were issued for a period as explicitly defined in the license, ranging from 35 to 45 years. Offshore production licenses issued before 1976 were issued for a fixed period of 40 years; from 1976 they were again issued for a period as explicitly defined in the license, ranging from 15 to 40 years.
Norway
Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for an initial period of up to six years (with extension of the initial period of one year at a time up to ten years after 1985), and an extension period of up to 30 years, with relinquishment of at least one-half of the original area required at the end of the initial period. Licenses issued after July 1, 1997, have an initial period of up to ten years and a normal extension period of up to 30 years or in special cases of up to 50 years, and with relinquishment of at least one-half of the original area required at the end of the initial period.
United Kingdom
Acreage terms are fixed by the government and are periodically changed. For example, many of the early licenses issued under the first four licensing rounds provided for an initial term of six years with relinquishment of at least one-half of the original area at the end of the initial term, subject to extension for a further 40 years. ExxonMobil’s licenses issued in 2005 as part of the 23rd licensing round have an initial term of four years with a second term extension of four years and a final term of 18 years. There is a mandatory relinquishment of 50-percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.
AFRICA
Angola
Exploration and production activities are governed by production sharing agreements with an initial exploration term of four years and an optional second phase of two to three years. The production period is for 25 years, and agreements generally provide for a negotiated extension.
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Cameroon
Exploration and production activities are governed by various agreements negotiated with the national oil company and the government of Cameroon. Exploration permits are granted for terms from four to 16 years and are generally renewable for multiple periods up to four years each. Upon commercial discovery, mining concessions are issued for a period of 25 years with one 25-year extension.
Chad
Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended at the discretion of the government. In May 2007, Chad enacted a new Petroleum Code which would govern new acquisitions.
Equatorial Guinea
Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years while the production period for gas is 50 years. A new Hydrocarbons Law was enacted in November 2006. Under the new law, the exploration terms for new production sharing contracts are four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.
Nigeria
Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company, the Nigerian National Petroleum Corporation (NNPC). NNPC holds the underlying Oil Prospecting License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs are generally 30 years, including a ten-year exploration period (an initial exploration phase plus one or two optional periods) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required under the PSC at the end of the ten-year exploration period, and OMLs have a 20-year production period that may be extended.
Some exploration activities are carried out in deepwater by joint ventures with local companies holding interests in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-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 are renewable upon 12 months’ written notice, for further periods of 30 and 40 years, respectively. 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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ASIA PACIFIC / MIDDLE EAST
Australia
Exploration and production activities are conducted offshore and are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. Retention leases may be granted for resources that are not commercially viable at the time of application, but are expected to become commercially viable within 15 years. These are granted for periods of five years and renewals may be requested. Prior to July 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter “indefinitely”, i.e., for the life of the field (if no operations for the recovery of petroleum have been carried on for five years, the license may be terminated). Effective from July 1998, new production licenses are granted “indefinitely”.
Indonesia
Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract, negotiated with BPMIGAS, a government agency established in 2002 to manage upstream oil and gas activities. Formerly this activity was carried out by Pertamina, the government owned oil company, which is now a competing limited liability company.
Japan
The Mining Law provides for the granting of concessions that convey exploration and production rights. Exploration rights are granted for an initial two-year period, and may be extended for two two-year periods for gas and three two-year periods for oil. Production rights have no fixed term and continue until abandonment so long as the rights holder is fulfilling its obligations.
Malaysia
Exploration and production activities are governed by seven production sharing contracts (PSCs) negotiated with the national oil company, three governing exploration and production activities and four governing production activities only. The more recent PSCs governing exploration and production activities have an overall term of 24 to 38 years, depending on water depth, with possible extensions to the exploration and/or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries will be deemed relinquished. The development period is from four to six years from commercial discovery, with the 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. Under the new PSC, from 2008 until March 31, 2012, the Company is entitled to undertake new development and production activities of areas, in oil fields under an existing PSC, subject to new minimum work and spending commitments. When the existing PSC expires on March 31, 2012, the producing fields covered by the existing PSC, as well as those areas developed by the Company under the new PSC, all automatically become part of the new PSC, which has a 25-year duration from April 2008.
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Papua New Guinea
Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum Development licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Minister’s discretion. Petroleum Retention licenses may be granted for gas resources that are not commercially viable at the time of application, but may become commercially viable within the maximum possible retention time of 15 years. Petroleum Retention licenses are granted for five-year terms, and may be extended, at the Minister’s discretion, twice for the maximum retention time of 15 years. Recent amendments of the Oil and Gas Act provide that extensions of Petroleum Retention licenses may be for periods of less than one year, renewable annually, if the Minister considers at the time of extension that the resources could become commercially viable in less than five years.
Qatar
The State of Qatar grants gas production development project rights to develop and supply gas from the offshore North Field to permit the economic development and production of gas reserves sufficient to satisfy the gas and LNG sales obligations of these projects.
Republic of Yemen
Existing production operations under the production sharing agreements (PSAs) have a development period extending 20 years from first commercial declaration made in November 1985 for the Marib PSA and June 1995 for the Jannah PSA. The Government of Yemen awarded a five-year extension of the Marib PSA, but later repudiated the extension and expelled the concession holders. The concession holders brought an action for arbitration over the Government’s actions, but the arbitration panel in 2008 ruled in favor of the Government.
Thailand
The Petroleum Act of 1971 allows production under ExxonMobil’s concession for 30 years with a ten-year extension at terms generally prevalent at the time.
United Arab Emirates
Exploration and production activities for the major onshore oilfields in the Emirate of Abu Dhabi are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi. An interest in the Upper Zakum field, a major offshore field, was acquired effective as of January 1, 2006, for a term expiring March 9, 2026, on fiscal terms consistent with the Company’s existing interests in Abu Dhabi.
RUSSIA/CASPIAN
Azerbaijan
The production sharing agreement (PSA) for the development of the Azeri-Chirag-Gunashli field is established for an initial period of 30 years starting from the PSA execution date in 1994.
Other exploration and production activities are governed by PSAs negotiated with the national oil company of Azerbaijan. The exploration period consists of three or four years with the possibility of a one to three-year extension. The production period, which includes development, is for 25 years or 35 years with the possibility of one or two five-year extensions.
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Kazakhstan
Onshore: Exploration and production activities are governed by the production license, exploration license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.
Offshore: Exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period was six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.
Russia
Terms for ExxonMobil’s acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, which would be 2021. The term may be extended thereafter in 10-year increments as specified in the PSA.
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8. Number of Net Productive and Dry Wells Drilled
A. Net Productive Exploratory Wells Drilled
B. Net Dry Exploratory Wells Drilled
C. Net Productive Development Wells Drilled
D. Net Dry Development Wells Drilled
Total number of net wells drilled
9. Present Activities
A. Wells Drilling
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B. Review of Principal Ongoing Activities
During 2008, ExxonMobil’s activities were conducted, either directly or through affiliated companies, by ExxonMobil Exploration Company (for exploration), by ExxonMobil Development Company (for large development activities), by ExxonMobil Production Company (for producing and smaller development activities) and by ExxonMobil Gas & Power Marketing Company (for gas marketing). During this same period, some of ExxonMobil’s exploration, development, production and gas marketing activities were also conducted in Canada by the Resources Division of Imperial Oil Limited, which is 69.6 percent owned by ExxonMobil.
ExxonMobil’s year-end 2008 acreage holdings totaled 10.8 million net acres, of which 2.3 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.
During 2008, 416.4 net exploration and development wells were completed in the inland lower 48 states and 2.0 net development wells were completed offshore in the Pacific. Tight gas development continued in the Piceance Basin of Colorado. Participation in Alaska production and development continued and a total of 20.5 net development wells were drilled. On Alaska’s North Slope, activity continued on the Western Region Development (primarily the Orion field) with development drilling and engineering design for future facility expansions.
ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2008 was 2.1 million acres. A total of 3.5 net exploration and development wells were completed during the year. Activity on the Thunder Horse project continued, with production from the deepwater semi-submersible development commencing in 2008. Work to rebuild and reinstall subsea equipment resulting from subsea manifold failures continued.
Construction of the Golden Pass LNG regasification terminal in Texas continued in 2008. The terminal will have the capacity to deliver up to two billion cubic feet of gas per day.
ExxonMobil’s year-end 2008 acreage holdings totaled 8.0 million net acres, of which 3.9 million net acres were offshore. A total of 221.2 net development wells were completed during the year.
ExxonMobil’s net acreage totaled 0.2 million onshore acres at year-end 2008, and there were 3.3 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.
A total of 3.1 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2008, with 3.5 net development and exploration wells drilled during the year.
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Italy
Construction of the Adriatic LNG regasification terminal continued in 2008. The terminal was moved from its construction site to its final location offshore Italy for commissioning. The terminal will have the capacity to supply up to 775 million cubic feet of gas per day to the Italian gas market.
ExxonMobil’s net interest in licenses totaled approximately 1.5 million acres at year-end 2008, of which 1.2 million acres were onshore. A total of 2.7 net exploration and development wells were completed during the year. Offshore, construction of the L09 project was completed. Onshore, the project to redevelop the previously abandoned Schoonebeek oil field commenced. In addition, the multi-year project to renovate Groningen production clusters, install new compression to maintain capacity, and extend field life continued.
ExxonMobil’s net interest in licenses at year-end 2008 totaled approximately 0.8 million acres, all offshore. ExxonMobil participated in 8.3 net exploration and development well completions in 2008. Production was initiated at Volve and construction on the Tyrihans project continued.
ExxonMobil’s net interest in licenses at year-end 2008 totaled approximately 1.4 million acres, all offshore. A total of 1.2 net exploration and development wells were completed during the year. The Starling and Caravel projects started up in 2008, while the St. Fergus gas processing facilities refurbishment project continued to make progress.
Construction of the South Hook LNG regasification terminal in Wales continued in 2008. The terminal will have the capacity to deliver up to two billion cubic feet of gas per day into the natural gas grid.
ExxonMobil’s year-end 2008 acreage holdings totaled 0.7 million net offshore acres and 10.5 net exploration and development wells were completed during the year. On Block 15, development drilling continued at Kizomba A and Kizomba B. The Block’s fourth major development, Kizomba C, began production from the Mondo and Saxi/Batuque fields in 2008. A block-wide 3D and 4D seismic acquisition program concluded during the year. On the non-operated Block 17, project work continued on the Pazflor project in 2008 and development drilling continued at Rosa and Dalia. The Plutao-Saturno-Venus-Marte (PSVM) project on Block 31 (non-operated) was approved in 2008.
ExxonMobil’s net acreage holdings totaled 0.1 million offshore acres.
ExxonMobil’s net year-end 2008 acreage holdings consisted of 3.3 million onshore acres, with 22.8 net development wells completed during the year. Work began on the Timbre field, with production expected in 2009.
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ExxonMobil’s acreage totaled 0.2 million net offshore acres at year-end 2008.
ExxonMobil’s net acreage totaled 1.0 million offshore acres at year-end 2008, with 10.9 net exploration and development wells completed during the year. The ExxonMobil-operated East Area Natural Gas Liquids II project started up in 2008. This project reduced flared gas and will recover high-value natural gas liquids from the gas stream. Work continued on the deepwater Usan project in 2008. A 3D seismic acquisition program that will provide enhanced resolution of existing fields and target deeper formations progressed. Appraisal drilling continued at Bonga North, Erha North East and Bosi North Deep fields.
ExxonMobil’s net year-end 2008 offshore acreage holdings totaled 2.4 million acres. During 2008, a total of 3.0 net development wells were drilled. Work continued on the Kipper gas project and the Turrum Phase 2 development project was approved in 2008.
At year-end 2008, ExxonMobil had 5.1 million net acres, 4.1 million acres offshore and 1.0 million acres onshore and 1.4 net exploration wells were completed during the year. Project activities continued on the Banyu Urip development in the Cepu Contract area.
ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2008.
ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2008. During the year, a total of 9.8 net development wells were completed. The Tapis F and Jerneh B gas platforms started up in 2008.
A total of 0.4 million net onshore acres were held by ExxonMobil at year-end 2008, with 0.9 net exploration and development wells completed during the year.
Production and development activities continued on natural gas projects in Qatar. Liquefied natural gas (LNG) operating companies include:
Qatar Liquefied Gas Company Limited — (QG I)
Qatar Liquefied Gas Company Limited (II) — (QG II)
Ras Laffan Liquefied Natural Gas Company Limited — (RL I)
Ras Laffan Liquefied Natural Gas Company Limited (II) — (RL II)
Ras Laffan Liquefied Natural Gas Company Limited (3) — (RL 3)
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In addition, ExxonMobil’s Al Khaleej Gas (AKG) Phase 1 project supplied pipeline gas to domestic industrial customers. The AKG facilities have sales gas capacity of up to 750 mcfd (millions of cubic feet per day) and produce associated condensate and LPG (Liquid Petroleum Gas). The AKG Phase 2 project is planned to add sales gas capacity of up to 1,250 mcfd, while recovering associated condensate and LPG.
At the end of 2008, 93 (gross) wells supplied natural gas to currently-producing LNG and pipeline gas sales facilities and drilling is underway to complete wells that will supply the new QG II, RL 3 and AKG 2 projects. At year-end 2008, ExxonMobil had 0.1 million net offshore acres. During 2008, 10.3 net exploration and development wells were completed.
Qatar LNG capacity volumes (gross) at year-end 2008 included 9.7 MTA (millions of metric tons per annum) in QG trains 1-3 and a combined 20.7 MTA in RL I trains 1-2 and RL II trains 3-5. In November 2008 commissioning activities commenced at QG II train 4. Construction of QG II trains 4-5 will add planned capacity of 15.6 MTA when complete. In addition, construction of RL 3 trains 6-7 will add planned capacity of 15.6 MTA when complete.
The conversion factor to translate Qatar LNG volumes (millions of metric tons – MT) into gas volumes (billions of cubic feet – BCF) is dependent on the gas quality and the quality of the LNG produced. The conversion factors are approximately 46 BCF/MT for QG I trains 1-3, RL I trains 1-2, and RL II train 3, and approximately 49 BCF/MT for QG II trains 4-5, RL II trains 4-5, and RL 3 trains 6-7.
ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end.
ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2008.
ExxonMobil’s net acreage in the Abu Dhabi oil concessions was 0.6 million acres at year-end 2008, of which 0.4 million acres were onshore and 0.2 million acres offshore. During the year, a total of 5.7 net exploration and development wells were completed. During 2008, work progressed on multiple field development projects, both onshore and offshore, to sustain and increase oil production capacity.
At year-end 2008, ExxonMobil’s net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 0.1 million acres. At the Azeri-Chirag-Gunashli field, 1.2 net development wells were completed and production ramp-up continued. The Phase 3 Deep Water Gunashli project started up in 2008.
ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2008, with 0.7 net development wells completed during 2008. The initial phase of the Tengiz expansion started up in 2007, followed by the full expansion in 2008. Construction of the initial phase of the Kashagan field continued during 2008.
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ExxonMobil’s net acreage holdings at year-end 2008 were 0.1 million acres, all offshore. A total of 2.7 net development wells were completed in the Chayvo field during the year. Phase 1 facilities include an offshore platform, onshore well site (from which extended reach horizontal drilling was completed in 2008), an onshore processing plant, an oil pipeline from Sakhalin Island to the Russian mainland, a mainland crude storage and loading terminal and an offshore loading buoy for loading shipments of oil by tanker.
WORLDWIDE EXPLORATION
At year-end 2008, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 46 million net acres were held at year-end 2008. No net exploration wells were completed during the year in these countries.
Information with regard to mining activities follows:
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 to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, Canada, mines a portion of the Athabasca oil sands deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. Since start-up in 1978, Syncrude has produced about 1.9 billion barrels of 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.
Operating License and Leases
Syncrude has an operating license issued by the Province of Alberta which is effective until 2035. This license permits Syncrude to mine oil sands and produce synthetic crude oil from approved development areas on oil sands leases. Syncrude holds eight oil sands leases covering approximately 250,000 acres in the Athabasca oil sands deposit which were issued by the Province of Alberta. The leases are automatically renewable as long as oil sands operations are ongoing or the leases are part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within a development plan approved by the Province of Alberta. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.
Operations, Plant and Equipment
Operations at Syncrude involve three main processes: open pit mining, extraction of crude bitumen and upgrading of crude bitumen into synthetic crude oil. The Base mine (located on lease 17) was depleted and ceased production in 2007. In the North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. Production from the Aurora mine commenced in 2000. The extraction facilities, which separate crude bitumen from sand, are capable of processing approximately 830,000 tons of oil sands per day, producing 150 million barrels of crude bitumen per year. This represents recovery capability of about 93 percent of the crude bitumen contained in the mined oil sands.
Crude bitumen extracted from oil sands is refined to a marketable hydrocarbon product through a combination of carbon removal in three large, high-temperature, fluid-coking vessels and by hydrogen
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addition in high-temperature, high-pressure, hydrocracking vessels. These processes remove carbon and sulfur and reformulate the crude into a low viscosity, low sulfur, high-quality synthetic crude oil product. In 2008, this upgrading process yielded 0.859 barrels of synthetic crude oil per barrel of crude bitumen. In 2008 about 39 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 61 percent was pipelined to refineries in eastern Canada and exported, primarily to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 160 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. Recycled water is the primary water source, and incremental raw water is drawn, under license, from the Athabasca River. Imperial Oil Limited’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities was about $2.8 billion at year-end 2008.
Synthetic Crude Oil Reserves
The crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 50 to 150 feet of overburden, have bitumen grades ranging from 4 to 14 weight percent and ore thickness of 115 to 180 feet. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. In active mining areas, the approximate well spacing is 400 feet (150 wells per section) and in future mining areas, the well spacing is approximately 1,150 feet (20 wells per section). Proven reserves are within the operating North and Aurora mines. In accordance with the approved mining plan, there are extractable oil sands in the North and Aurora mines, with average bitumen grades of 10.6 and 11.2 weight percent, respectively. After deducting royalties payable to the Province of Alberta, Imperial Oil Limited estimates that its 25 percent net share of proven reserves at year-end 2008 was equivalent to 734 million barrels of synthetic crude oil. Imperial’s reserve assessment uses a 6 percent and 7 percent bitumen grade cut-off for the North mine and Aurora mine respectively, a 90 percent overall extraction recovery, a 97 percent mining dilution factor and an 88 percent upgrading yield.
In 2001, the Syncrude owners endorsed a further development of the Syncrude resource in the area and expansion of the upgrading facilities. The Syncrude Aurora 2 and Upgrader Expansion 1 project added a remote mining train and expanded the central processing and upgrading plant. This increased upgrading capacity came on stream in 2006 and increased production capacity to 355 thousand barrels of synthetic crude oil per day (gross). Additional mining trains in the North mine and Aurora mine were also completed in 2005. There are no approved plans for major future expansion projects.
On May 1, 2007, the company implemented a management services agreement under which Syncrude will be provided with operational, technical and business management services from Imperial Oil Limited and Exxon Mobil Corporation. The agreement has an initial term of 10 years and may be terminated with at least two years prior written notice.
In November 2008, Imperial Oil Limited, along with the other Syncrude joint-venture owners, signed an agreement with the Government of Alberta to amend the existing Syncrude Crown Agreement. Under the amended agreement, beginning January 1, 2010, Syncrude will begin transitioning to the new oil sands royalty regime by paying additional royalties, the exact amount of which will depend on production levels from 2010 to 2015. Also, beginning January 1, 2009, Syncrude’s royalty will be based on bitumen value with upgrading costs and revenues excluded from the calculation.
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ExxonMobil Net Proven Syncrude Reserves (1)
January 1, 2008
Revision of previous estimate
Production
December 31, 2008
Syncrude Operating Statistics (total operation)
Operating Statistics
Total mined overburden (millions of cubic yards)(1)
Mined overburden to oil sands ratio(1)
Oil sands mined (millions of tons)
Average bitumen grade (weight percent)
Crude bitumen in mined oil sands (millions of tons)
Average extraction recovery (percent)
Crude bitumen production (millions of barrels)(2)
Average upgrading yield (percent)
Gross synthetic crude oil produced (millions of barrels)
ExxonMobil net share (millions of barrels)(3)
Kearl Project
Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. The Kearl project is located approximately 40 miles north of Fort McMurray, Alberta. The location is currently accessible by an existing road. Imperial Oil Limited holds a 70.96 percent participating 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 will be developed in three 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 heavy oil blend of bitumen and diluent, will be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline.
The Kearl project received approvals from the Province of Alberta in 2007 and the Government of Canada in 2008. The Province of Alberta issued an operating and construction license in 2008, which permits the project to mine oil sands and produce bitumen from approved development areas on oil sands leases. Kearl is comprised of six oil sands leases covering about 48,000 acres in the Athabasca oil
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sands deposit. The leases, which are issued by the Province of Alberta, are automatically renewable as long as the oil sands operations are ongoing or the leases are part of an approved development plan. The leases involved in the first phase of the project are 6, 87 and 88A (which contain proven reserves) and 31A, 36 and 88B (which do not currently contain proven reserves). There were no known previous commercial operations on these leases.
Production from the first phase is expected to average approximately 110,000 barrels of bitumen a day, before royalties. About $500 million has been spent on the first phase. Activities in 2008 focused on engineering work to define the project design and execution plan. Other activities in 2008 also included site access road construction, site preparation and earthworks. Significant progress has also been made on transportation system agreements.
Kearl will be subject to the Alberta generic oil sands royalty regime, which was modified in 2007 and which will take effect in 2009. Royalty rates will be based upon a sliding scale, determined by the price of crude oil.
Operations at Kearl will involve three main processes: open-pit mining, extraction of crude bitumen and diluent blending. The open-pit mining will utilize truck, shovel and hydrotransport systems. The extraction separates crude bitumen from sand through a froth processing plant. Electricity will be provided initially through the Alberta grid. Recycled water will be the primary water source, and incremental raw water will be drawn, under license, from the Athabasca River.
Proven Reserves
Bitumen deposits at Kearl are found throughout sandstones within the Lower, Middle and Upper McMurray members, concentrated primarily within the Middle and Upper McMurray members. The oil sands occur over depths ranging from approximately 30 feet to as much as 450 feet below surface. The oil sands are about 130 feet in net thickness, but can be as thick as 230 feet. Mined bitumen reserve estimates are based upon detailed geological and engineering assessments of in-place crude bitumen volumes, the mining plan, demonstrated extraction recovery factors, planned operating capacity and operating approval limits. The in-place volume, depth and grade of the first phase were established through extensive and closely spaced core drilling with spacing of approximately 1,400 feet (14 wells per section). The determination of reserves uses a seven percent bitumen grade cut-off by weight, a 77 percent overall extraction recovery (paraffinic froth treatment process) and a 95 percent mining dilution factor.
ExxonMobil Net Proven Kearl Reserves (1)
Additions
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.
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Refining Capacity At Year-End 2008 (1)
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
Augusta
Trecate
Rotterdam
Slagen
Fawley
Total Europe
Asia Pacific
Kawasaki (3)
Sakai (3)
Wakayama (3)
Jurong/PAC
Singapore
Sriracha
Other (6 refineries)
Total Asia Pacific
Other Non-U.S.
Yanbu
Saudi Arabia
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, Mobil and On the Run brands serve customers at nearly 29,000 retail service stations.
Retail Sites Year-End 2008
Owned/leased
Distributors/resellers
Latin America
Total Latin America
Middle East/Africa
Total Middle East/Africa
Worldwide
Total 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 2008 (1)(2)
North America
Mont Belvieu
Total North America
Fife
Meerhout
Notre-Dame-de-Gravenchon
Middle East
Al Jubail
Total Middle East
Kawasaki
All Other
Item 3. Legal Proceedings.
On November 21, 2008, the Louisiana Department of Environmental Quality (LDEQ) issued a Consolidated Compliance Order and Notice of Potential Penalty to the Corporation’s refinery located in Baton Rouge, Louisiana. The Order requires the refinery to take corrective actions related to self-disclosed emissions exceedances involving the refinery’s wet gas scrubber and wastewater treatment. Although penalties have not yet been assessed, they are likely to exceed $100,000. The LDEQ has also issued interim permit limits for these sources until the required corrective action steps can be completed during an upcoming scheduled turnaround.
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Regarding a previously reported matter, the Corporation and Chalmette Refining, LLC have agreed to pay stipulated penalties demanded by the United States Environmental Protection Agency (EPA) for alleged noncompliance under their respective 2005 and 2006 consent decrees relating to EPA’s New Source Review Enforcement Initiative. The EPA issued its demand for stipulated penalties to Chalmette Refining, LLC ($273,500) on October 17, 2008, and to the Corporation ($6,064,500) on December 17, 2008. Most of the penalties are associated with alleged noncompliance with New Source Performance Standards Subpart J. Chalmette Refining, LLC paid its penalty in November, 2008, and the Corporation paid its penalty in February, 2009.
Regarding a previously reported matter, on December 23, 2008, the office of the United States Attorney for the District of Massachusetts filed a misdemeanor criminal information alleging that ExxonMobil Pipeline Company violated 33 U.S.C. Sections 1319(c)(1) and 1321(b)(3) of the Clean Water Act resulting from a spill that occurred on or about January 9-10, 2006, on the Island End River near the Corporation’s Everett Terminal facility in Everett, Massachusetts. A plea agreement intended to resolve the case was also filed with the Federal District Court on that same date. The plea agreement requires that ExxonMobil Pipeline Company plead guilty to a misdemeanor violation 33 U.S.C. Section 1319(c)(1) of the Clean Water Act and agree to the following: (1) a term of probation of three years; (2) fund and implement an environmental compliance plan for the three year probationary period; (3) pay a fine of $359,018 and a special assessment of $125 (4) pay $5,640,982 in community service payments to the North American Wetlands Conservation Act Fund; and (5) pay $179,509 for spill-related cleanup costs. A hearing was held by the court on January 22, 2009, to review the plea agreement. The court took the matter under consideration, with sentencing to occur in the future.
Refer to the relevant portions of “Note 15: Litigation and Other Contingencies” of the Financial Section of this report for additional information on legal proceedings.
Item 4. Submission of Matters to a Vote of Security Holders.
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Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].
Name
Age as ofMarch 1,
2009
Title (Held Office Since)
R. W. Tillerson
56
Chairman of the Board (2006)
M. W. Albers
52
Senior Vice President (2007)
M. J. Dolan
55
Senior Vice President (2008)
D. D. Humphreys
61
Senior Vice President (2006) and Treasurer (2004)
A. T. Cejka
57
Vice President (2004)
W. M. Colton
Vice President - Strategic Planning (2009)
H. R. Cramer
58
Vice President (1999)
N. W. Duffin
President, ExxonMobil Development Company (2007)
S. J. Glass, Jr.
Vice President (2008)
A. J. Kelly
51
Vice President (2007)
R. M. Kruger
S. R. LaSala
64
Vice President and General Tax Counsel (2007)
C. W. Matthews
Vice President and General Counsel (1995)
P. T. Mulva
Vice President and Controller (2004)
S. D. Pryor
59
D. S. Rosenthal
Vice President - Investor Relations and Secretary (2008)
A. P. Swiger
For at least the past five years, Messrs. Cramer, Humphreys, LaSala, Matthews, Mulva and Tillerson have been employed as executives of the registrant. Mr. Tillerson was a Senior Vice President and then President, a title he continues to hold, before becoming Chairman of the Board. Mr. Albers was President of ExxonMobil Development Company before becoming Senior Vice President. Mr. Dolan was President of ExxonMobil Chemical Company before becoming Senior Vice President. Mr. Humphreys was Vice President and Controller and then Vice President and Treasurer before becoming Senior Vice President and Treasurer. Mr. Colton was Assistant Treasurer before becoming Vice President—Strategic Planning. Mr. LaSala was Associate General Tax Counsel before becoming Vice President and General Tax Counsel. Mr. Mulva was Vice President—Investor Relations and Secretary before becoming Vice President and Controller. Mr. Rosenthal was Assistant Controller before becoming Vice President—Investor Relations and Secretary.
The following executive officers of the registrant have also served as executives of the subsidiaries, affiliates or divisions of the registrant shown opposite their names during the five years preceding December 31, 2008.
Esso Exploration and Production Chad Inc.
Esso UK Limited
ExxonMobil Chemical Company
ExxonMobil Development Company
ExxonMobil Exploration Company
ExxonMobil Fuels Marketing Company
ExxonMobil Gas & Power Marketing Company
ExxonMobil Lubricants & Petroleum Specialties Company
ExxonMobil Production Company
ExxonMobil Refining & Supply Company
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.
Period
October, 2008
November, 2008
December, 2008
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 30, 2009, the Corporation stated that share purchases to reduce shares outstanding are anticipated to equal $7.0 billion through the first quarter of 2009. Purchases may be made in both the open market and through negotiated transactions, and purchases may be increased, decreased or discontinued at any time without prior notice.
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Item 6. Selected Financial Data.
(millions of dollars, except per share amounts)
(1) Sales-based taxes included.
(2) Includes amounts for purchases/sales contracts with the same counterparty for 2004-2005.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Financial Section of this report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties”, excluding the part entitled “Inflation and Other Uncertainties,” in the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the following in the Financial Section of this report:
Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 27, 2009, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” and continuing through “Note 18: Income, Sales-Based and Other Taxes”;
“Quarterly Information” (unaudited);
“Supplemental Information on Oil and Gas Exploration and Production Activities” (unaudited); and
“Frequently Used Terms” (unaudited).
Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
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Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
Item 9A. Controls and Procedures.
Management’s Evaluation of Disclosure Controls and Procedures
As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 2008. 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, 2008.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2008, as stated in their report included in the Financial Section of this report.
Changes in Internal Control Over Financial Reporting
There were no changes during the Corporation’s last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corporation’s internal control over financial reporting.
Item 9B. Other Information.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Incorporated by reference to the following from the registrant’s definitive proxy statement for the 2009 annual meeting of shareholders (the “2009 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 portion entitled “Code of Ethics and Business Conduct” of the section entitled “Corporate Governance”; and
The “Audit Committee” portion and the membership table of the portion entitled “Board Meetings and Committees; Annual Meeting Attendance” of the section entitled “Corporate Governance”.
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Item 11. Executive Compensation.
Incorporated by reference to the sections entitled “Director Compensation,” “Compensation Committee Report,” “Compensation Discussion and Analysis” and “Executive Compensation Tables” of the registrant’s 2009 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required under Item 403 of Regulation S-K is incorporated by reference to the section entitled “Director and Executive Officer Stock Ownership” of the registrant’s 2009 Proxy Statement.
Equity Compensation Plan Information
Plan Category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders
0
67,018,885
$41.18
162,531,817
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Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information provided in response to this Item 13 is incorporated by reference to the portions entitled “Related Person Transactions and Procedures” and “Director Independence” of the section entitled “Corporate Governance” in the registrant’s 2009 Proxy Statement.
Item 14. Principal Accounting Fees and Services.
Incorporated by reference to the section entitled “Ratification of Independent Auditors” and the portion entitled “Audit Committee” of the section entitled “Corporate Governance” of the registrant’s 2009 Proxy Statement.
PART IV
Item 15. Exhibits, Financial Statement Schedules.
See Table of Contents of the Financial Section of this report.
See Index to Exhibits of this report.
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FINANCIAL SECTION
Business Profile
Financial Summary
Frequently Used Terms
Quarterly Information
Functional Earnings
Forward-Looking Statements
Overview
Business Environment and Risk Assessment
Review of 2008 and 2007 Results
Liquidity and Capital Resources
Capital and Exploration Expenditures
Taxes
Environmental Matters
Market Risks, Inflation and Other Uncertainties
Recently Issued Statements of Financial Accounting Standards
Critical Accounting Policies
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Statement of Income
Balance Sheet
Statement of Shareholders’ Equity
Statement of Cash Flows
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies
2. Accounting Change for Fair Value Measurements
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
Supplemental Information on Oil and Gas Exploration and Production Activities
Operating Summary
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BUSINESS PROFILE
Financial
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.
Operating
Net liquids production
Natural gas production available for sale
Oil-equivalent production (1)
Refinery throughput
Petroleum product sales
Chemical prime product sales
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FINANCIAL SUMMARY
Sales and other operating revenue (1) (2)
Earnings
Net income
Net income per common share
Net income per common share – assuming dilution
Cash dividends per common share
Net income to average shareholders’ equity (percent)
Working capital
Ratio of current assets to current liabilities (times)
Additions to property, plant and equipment
Property, plant and equipment, less allowances
Total assets
Exploration expenses, including dry holes
Research and development costs
Long-term debt
Total debt
Fixed-charge coverage ratio (times)
Debt to capital (percent)
Net debt to capital (percent) (3)
Shareholders’ equity at year end
Shareholders’ equity per common share
Weighted average number of common shares outstanding (millions)
Number of regular employees at year end (thousands) (4)
CORS employees not included above (thousands) (5)
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FREQUENTLY USED TERMS
Listed below are definitions of several of ExxonMobil’s key business and financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation.
CASH FLOW FROM OPERATIONS AND ASSET SALES
Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from sales of subsidiaries, investments and property, plant and equipment from the Consolidated Statement of Cash Flows. This cash flow reflects the total sources of cash from both operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
Cash flow from operations and asset sales
Net cash provided by operating activities
Sales of subsidiaries, investments and property, plant and equipment
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 shareholders’ equity. Both of these views include ExxonMobil’s share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.
Capital employed
Business uses: asset and liability perspective
Less liabilities and minority share of assets and liabilities
Total current liabilities excluding notes and loans payable
Total long-term liabilities excluding long-term debt and equity of minority interests
Minority 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
Shareholders’ equity
Less minority 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 excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow-based, are used to make investment decisions.
Return on average capital employed
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
Volumes
Production of crude oil and natural gas liquids
Summarized financial data
Sales and other operating revenue (2)
Gross profit (3)
Per share data
Net income per common share (4)
Net income per common share – 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 546,588 registered shareholders of ExxonMobil common stock at December 31, 2008. At January 31, 2009, the registered shareholders of ExxonMobil common stock numbered 540,892.
On January 28, 2009, the Corporation declared a $0.40 dividend per common share, payable March 10, 2009.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUNCTIONAL EARNINGS
Net income (U.S. GAAP)
Special items included in net income
Non-U.S. Upstream
Gain on German natural gas transportation business sale
Tax-related benefit
Valdez litigation
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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; financing sources; the resolution of contingencies and uncertain tax positions; the effect of changes in prices; interest rates and other market conditions; and environmental and capital expenditures could differ materially depending on a number of factors, such as the outcome of commercial negotiations; changes in the supply of and demand for crude oil, natural gas, and petroleum and petrochemical products; political or regulatory events; and other factors discussed herein and in Item 1A of ExxonMobil’s 2008 Form 10-K.
OVERVIEW
The following discussion and analysis of ExxonMobil’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, manufacturing and marketing of hydrocarbons and hydrocarbon-based products. The Corporation’s business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods. Our consistent, conservative approach to financing the capital-intensive needs of the Corporation has helped ExxonMobil to sustain the “triple-A” status of its long-term debt securities for 90 years.
ExxonMobil, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new energy supplies. While commodity prices are volatile on a short-term basis and depend on supply and demand, ExxonMobil’s investment decisions are based on our long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Prices for crude oil, natural gas and refined products are based on corporate plan assumptions developed annually by major region and are utilized for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.
BUSINESS ENVIRONMENT AND RISK ASSESSMENT
Long-Term Business Outlook
By 2030, the world’s population is projected to grow to approximately 8 billion people, or about 1.5 billion more than in 2005. Coincident with this population increase, the Corporation expects worldwide economic growth to average close to 3 percent per year. This combination of population and economic growth is expected to lead to an increase in primary energy demand of approximately 35 percent by 2030 versus 2005 even with substantial efficiency gains. The vast majority (over 90 percent) of the demand increase is expected to occur in developing countries.
As economic progress drives demand higher, the use of more energy-efficient technologies and practices will become increasingly important, leading to a significantly lower level of energy consumption per unit of economic output by 2030. Efficiency gains will result from anticipated improvements in the transportation and power generation sectors, driven by the introduction of new technologies, as well as many other improvements that span the residential, commercial and industrial sectors.
Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by 40 percent from 2005 to 2030. The global growth in transportation demand will be met primarily by oil, which is expected to provide almost 95 percent of all transportation fuel by 2030, down from about 98 percent in 2005, as biofuels and natural gas gain market share.
Demand for electricity around the world will grow significantly through 2030. Consistent with this projection, power generation will remain the largest and fastest-growing segment of global energy demand. Meeting the expected growth in power demand will require a diverse set of energy sources. Coal will retain the largest share, however natural gas, nuclear and renewables are all expected to gain market share.
Liquid fuels provide the largest share of energy supply today due to their availability, affordability and ease of transport. By 2030, global demand for liquids is expected to grow to approximately 108 million barrels of oil-equivalent per day or close to 30 percent more than in 2005. Global demand for liquid fuels will be met by a wide variety of sources. Conventional non-OPEC crude and condensate production is expected to remain relatively flat through 2030. However, growth is expected from a number of supply sources, including biofuels, oil sands and natural gas liquids, as well as crude oil from OPEC countries. While the world’s resource base is sufficient to meet projected demand, access to resources and timely investments will remain critical to meeting global needs.
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Increases in natural gas demand in North America, Europe and Asia Pacific will require new sources of supply, primarily from imports. The growing need for natural gas imports will have a dramatic impact on the worldwide liquefied natural gas (LNG) market, which is expected to more than triple in volume by 2030.
The world’s energy mix is highly diverse and will remain so through 2030. Oil is expected to remain the largest source of energy supply at close to 35 percent. Natural gas is expected to grow the fastest of the fossil fuels and overtake coal as the second-largest energy source. Nuclear power is projected to grow significantly, surpassing coal in terms of absolute growth and becoming the fourth-largest fuel source. Hydro and geothermal will also grow, though remain limited by the availability of natural sites. Wind, solar and biofuels are expected to grow at about 9 percent per year on average, the highest growth rate of all fuels, and are projected to reach approximately 2 percent of world energy by 2030.
The Corporation anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from reserve increases in previously discovered fields. Technology will underpin these increases. The cost to develop and supply these resources will be significant. According to the International Energy Agency, the investment required to meet total oil and gas energy needs worldwide through 2030 will be close to $500 billion per year on average, or about $11.7 trillion (measured in 2007 dollars) in total for 2007-2030.
ExxonMobil continues to maintain a large portfolio of development and exploration 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 pursuing all attractive exploration opportunities, investing in projects that deliver superior returns, maximizing profitability of existing oil and gas production, and capitalizing on growing natural gas and power markets. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees and investment in the communities in which we operate.
As future development projects bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2013. Oil and natural gas output from West Africa, the Caspian region, the Middle East and Russia is expected to increase over the next five years based on current capital project execution plans. Currently, these growth areas account for 39 percent of the Corporation’s production. By 2013, they are expected to generate about 50 percent of total volumes. The remainder of the Corporation’s production is expected to be sourced from established areas, including Europe, North America and Asia Pacific.
In addition to a changing geographic mix, there will also be a change in the type of opportunities from which volumes are produced. Nonconventional production utilizing specialized technology such as arctic technology, deepwater drilling and production systems, heavy oil recovery processes, tight gas production and LNG is expected to grow from about 30 percent to over 40 percent of the Corporation’s output between now and 2013. The Corporation’s overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2009-2013. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, performance of enhanced oil recovery projects, regulatory changes, asset sales, weather events, price effects under production sharing contracts and other factors described in Item 1A of ExxonMobil’s 2008 Form 10-K. Enhanced oil recovery projects extract hydrocarbons from reservoirs in excess of that which may be produced through primary recovery, i.e., through pressure depletion or natural aquifer support. They include the injection of water, gases or chemicals into a reservoir to produce hydrocarbons otherwise unobtainable.
ExxonMobil’s Downstream is a large, diversified business with refining and marketing complexes around the world. The Corporation has a strong presence in mature markets in North America and Europe, as well as the growing Asia Pacific region. ExxonMobil’s fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizing on integration with other ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectiveness, and providing quality, valued products and services to customers.
ExxonMobil has an ownership interest in 37 refineries, located in 20 countries, with distillation capacity of 6.2 million barrels per day and lubricant basestock manufacturing capacity of about 140 thousand barrels per day. ExxonMobil’s fuels and lubes marketing business portfolios include operations around the world, serving a globally diverse customer base.
The downstream industry environment remains competitive. The industry has experienced a period of robust refining margins, which has encouraged the construction of additional industry capacity. However, over the prior 20-year period, inflation-adjusted refining margins have declined at an average rate of about 1 percent per year. 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, seasonal demand, weather and political climate.
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ExxonMobil’s long-term outlook continues to be that refining margins will generally decline as refineries continue to improve efficiency and, in the near term, new capacity additions outpace the growth in global demand.
In the retail fuels marketing business, ongoing intense competition continues to drive down inflation-adjusted margins by about 3 percent per year. In 2008, ExxonMobil announced its intention to transition out of the direct served (i.e., dealer, company-operated) retail business in U.S. markets and to convert a majority of markets to a branded distributor model. This transition will be a multiyear process.
ExxonMobil’s Downstream capital expenditures remain focused on selective and resilient investments. 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. For example, in 2008, ExxonMobil announced plans to invest over $1 billion in three refineries to increase the supply of cleaner burning diesel by about 140 thousand barrels per day. The company will construct new units and modify existing facilities at its Baton Rouge, La., Baytown, Texas, and Antwerp, Belgium, refineries. ExxonMobil is also participating in an integrated refining, petrochemicals and fuels marketing venture in Fujian, China, with our partners Saudi Aramco, Sinopec and Fujian Province. The manufacturing portion of the venture will expand an existing 80-thousand-barrel-per-day refinery in the Fujian Province to a 240-thousand-barrel-per-day high-conversion facility. The project also includes a new world-scale integrated chemical plant. The project is expected to start up in 2009. The fuels marketing portion of the venture includes approximately 750 retail sites and a network of distribution terminals.
Worldwide petrochemical demand decreased in 2008, reflecting the global economic slowdown in the second half of the year. Despite record high feedstock costs, chemical growth continued in the first half of the year fueled by increased demand in Asia Pacific, particularly China. As a result, supply/demand balances supported higher product prices during this period. Demand dropped sharply in the second half of the year, reflecting slower economic growth and broad supply chain inventory de-stocking during rapid feedstock cost declines. With this demand decrease, margins weakened and industry operating rates were cut back.
ExxonMobil benefited from continued operational excellence and a balanced portfolio of products. In addition to being a worldwide supplier of primary petrochemical products, ExxonMobil Chemical also has a number of less-cyclical business lines. Chemical’s competitive advantages are achieved through its business mix, broad geographic coverage, investment discipline, integration of chemical capacity with large refineries or upstream gas processing facilities, advantaged feedstock capabilities, leading proprietary technology and product application expertise.
REVIEW OF 2008 AND 2007 RESULTS
Net income in 2008 of $45,220 million was a record for the Corporation, up $4,610 million from 2007. Net income for 2008 included an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany and after-tax special charges of $460 million related to the Valdez litigation.
2007
Net income in 2007 of $40,610 million was up $1,110 million from 2006. Net income for 2006 included a $410 million gain from the recognition of tax benefits related to historical investments in non-U.S. assets.
Upstream earnings for 2008 totaled $35,402 million, an increase of $8,905 million from 2007, including an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany. Record high crude oil and natural gas realizations increased earnings approximately $11.8 billion. Lower sales volumes reduced earnings about $3.7 billion. Higher taxes and increased operating costs decreased earnings approximately $1.5 billion, partially offset by favorable foreign exchange. Oil-equivalent production decreased 6 percent versus 2007, including impacts from lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Excluding these impacts, total oil-equivalent production decreased 3 percent. Liquids production of 2,405 kbd (thousands of barrels per day) decreased 211 kbd from 2007. Production increases from new projects in West Africa were more than offset by field decline, lower entitlement volumes, the expropriation of assets in Venezuela and divestments. Natural gas production of 9,095 mcfd (millions of cubic feet per day) decreased 289 mcfd from 2007. Higher volumes from North Sea, Malaysia and Qatar projects and higher European demand were more than offset by field decline. Earnings from U.S. Upstream operations for 2008 were $6,243 million, an increase of $1,373 million. Earnings outside the U.S. for 2008, including a $1,620 million gain related to the sale of the German natural gas transportation business, were $29,159 million, $7,532 million higher than in 2007.
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Upstream earnings for 2007 totaled $26,497 million, an increase of $267 million from 2006. Higher liquids realizations increased earnings approximately $3.1 billion, while lower natural gas realizations decreased earnings about $600 million. Higher operating expenses and unfavorable tax effects reduced earnings about $2.2 billion. Oil-equivalent production decreased 1 percent versus 2006, including the expropriation of assets in Venezuela, divestments, OPEC quota effects, and price and spend impacts on volumes. Excluding these impacts, total oil-equivalent production increased 1 percent. Liquids production of 2,616 kbd decreased 65 kbd from 2006. Production increases from new projects in West Africa and higher Russia volumes were offset by field decline and production sharing contract net interest reductions. Natural gas production of 9,384 mcfd increased 50 mcfd from 2006. Higher volumes from projects in Qatar and the North Sea were mostly offset by mature field decline. Earnings from U.S. Upstream operations for 2007 were $4,870 million, a decrease of $298 million. Earnings outside the U.S. for 2007 were $21,627 million, an increase of $565 million.
Downstream earnings of $8,151 million were $1,422 million lower than in 2007. Lower margins reduced earnings approximately $900 million, as weaker refining margins more than offset stronger marketing margins. Higher operating costs, mainly associated with planned work activity, reduced earnings about $700 million, while unfavorable foreign exchange effects decreased earnings approximately $600 million. Improved refinery operations provided a partial offset, increasing earnings about $800 million. Petroleum product sales of 6,761 kbd decreased from 7,099 kbd in 2007, primarily reflecting asset sales and lower demand. Refinery throughput was 5,416 kbd compared with 5,571 kbd in 2007. U.S. Downstream earnings were $1,649 million, down $2,471 million from 2007. Non-U.S. Downstream earnings of $6,502 million were $1,049 million higher than in 2007.
Downstream earnings totaled $9,573 million, an increase of $1,119 million from 2006. Improved worldwide refining operations increased earnings approximately $800 million, while higher gains on asset sales improved earnings about $900 million. Lower refining margins decreased earnings approximately $600 million. Petroleum product sales of 7,099 kbd decreased from 7,247 kbd in 2006, primarily due to divestment impacts. Refinery throughput was 5,571 kbd compared with 5,603 kbd in 2006. U.S. Downstream earnings of $4,120 million decreased $130 million. Non-U.S. Downstream earnings of $5,453 million were $1,249 million higher than in 2006.
Chemical earnings totaled $2,957 million, a decrease of $1,606 million from 2007. Lower margins reduced earnings approximately $1.2 billion, while lower volumes decreased earnings about $500 million. Prime product sales were 24,982 kt (thousands of metric tons), a decrease of 2,498 kt from last year. Prime product sales are total chemical product sales, including ExxonMobil’s share of equity-company volumes and finished-product transfers to the Downstream business. Carbon black oil and sulfur volumes are excluded. U.S. Chemical earnings of $724 million decreased $457 million. Non-U.S. Chemical earnings of $2,233 million were $1,149 million lower than in 2007.
Chemical earnings totaled $4,563 million, an increase of $181 million from 2006. Higher sales volumes and favorable foreign exchange effects increased earnings approximately $450 million, while lower margins reduced earnings about $325 million. Prime product sales were 27,480 kt, an increase of 130 kt. U.S. Chemical earnings of $1,181 million decreased $179 million. Non-U.S. Chemical earnings of $3,382 million were $360 million higher than in 2006.
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Corporate and Financing
Corporate and financing expenses of $1,290 million in 2008 increased $1,267 million from 2007, mainly due to charges of $460 million related to the Valdez litigation, net higher taxes and lower interest income.
Corporate and financing expenses were $23 million in 2007, compared to an earnings contribution of $434 million in 2006, which included a $410 million gain from tax benefits related to historical investments in non-U.S. assets.
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
Cash and cash equivalents were $31.4 billion at the end of 2008, $2.5 billion lower than the prior year, reflecting $2.7 billion of foreign exchange reductions from the strengthening of the U.S. dollar in 2008.
Cash and cash equivalents were $34.0 billion at the end of 2007, $5.7 billion higher than the prior year, reflecting a $4.6 billion increase due to the release of the restriction on the restricted cash and cash equivalents and $1.8 billion of positive foreign exchange effects from the weakening of the U.S. dollar in 2007. There were no restricted cash and cash equivalents at the end of 2007 (see note 4). Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows.
Although the Corporation could issue long-term debt and has access to short-term liquidity, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Corporation’s immediate needs is carefully controlled to ensure that it is secure and readily available to meet the Corporation’s cash requirements and to optimize returns on the cash balances.
To support cash flows in future periods the Corporation will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. After a period of production at plateau rates, it is the nature of oil and gas fields eventually to produce at declining rates for the remainder of their economic life. Averaged over all the Corporation’s existing oil and gas fields and without new projects, ExxonMobil’s production is expected to decline at approximately 6 percent per year, consistent with recent historical performance. 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, 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 and anticipates similar results in the future. 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.
The Corporation’s financial strength, as evidenced by its AAA/Aaa debt rating, enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2008 were $26.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could vary depending on the progress of individual projects. The Corporation has a large and diverse portfolio of development projects and exploration opportunities, which helps mitigate the overall political and technical risks of the Corporation’s Upstream segment and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Corporation’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. The purchase and sale of oil and gas properties have not had a significant impact on the amount or timing of cash flows from operating activities.
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Cash Flow from Operating Activities
Cash provided by operating activities totaled $59.7 billion in 2008, a $7.7 billion increase from 2007. The major source of funds was net income of $45.2 billion, adjusted for the noncash provision of $12.4 billion for depreciation and depletion, both of which increased. The net effects of lower prices and the timing of collection of accounts receivable and of payments of accounts and other payables and of income taxes payable added to cash provided by operating activities.
Cash provided by operating activities totaled $52.0 billion in 2007, a $2.7 billion increase from 2006. The major source of funds was net income of $40.6 billion, adjusted for the noncash provision of $12.3 billion for depreciation and depletion, both of which increased.
Cash Flow from Investing Activities
Cash used in investing activities netted to $15.5 billion in 2008, $5.8 billion higher than in 2007. Spending for property, plant and equipment of $19.3 billion in 2008 increased $3.9 billion from 2007. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $6.0 billion in 2008 compared to $4.2 billion in 2007, the increase reflecting the sale of the German natural gas transportation business in 2008. Cash used in investing activities in 2008 was higher due to the absence of the $4.6 billion positive cash flow in 2007 from the release of the restriction on the restricted cash and cash equivalents. Net cash used for investments and advances and the change in marketable securities was $1.0 billion lower in 2008.
Cash used in investing activities netted to $9.7 billion in 2007, $4.5 billion lower than in 2006. Spending for property, plant and equipment of $15.4 billion in 2007 was comparable to the prior year. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $4.2 billion in 2007 increased $1.1 billion, reflecting a higher level of asset sales in the Downstream business. Additions from the release of the restriction on the restricted cash and cash equivalents were $4.6 billion. Net investments and advances and net additions to marketable securities were $1.3 billion higher in 2007.
Cash Flow from Financing Activities
Cash used in financing activities was $44.0 billion in 2008, an increase of $5.7 billion from 2007, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.55 per share from $1.37 per share and totaled $8.1 billion, a pay-out of 18 percent. Total consolidated short-term and long-term debt decreased $0.2 billion to $9.4 billion at year-end 2008.
Shareholders’ equity decreased $8.8 billion in 2008, to $113.0 billion. Net income of $45.2 billion, reduced by distributions to ExxonMobil shareholders of $8.1 billion of dividends and $32.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding, added to shareholders’ equity. Shareholders’ equity, and net assets and liabilities, decreased $6.8 billion, representing the foreign exchange translation effects of generally weaker foreign currencies at the end of 2008 on ExxonMobil’s operations outside the United States. The change in the funded status of the postretirement benefits reserves in 2008 lowered shareholders’ equity by $5.1 billion.
During 2008, Exxon Mobil Corporation purchased 434 million shares of its common stock for the treasury at a gross cost of $35.7 billion. These purchases were to reduce the number of shares outstanding and to offset shares issued in conjunction with company benefit plans and programs. Shares outstanding were reduced by 7.5 percent from 5,382 million at the end of 2007 to 4,976 million at the end of 2008. Purchases were made in both the open market and through negotiated transactions. Purchases may be increased, decreased or discontinued at any time without prior notice.
Cash used in financing activities was $38.3 billion, an increase of $2.1 billion from 2006, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.37 per share from $1.28 per share and totaled $7.6 billion, a payout of 19 percent. Total consolidated short-term and long-term debt increased $1.2 billion to $9.6 billion at year-end 2007.
Shareholders’ equity increased $7.9 billion in 2007, to $121.8 billion, reflecting $40.6 billion of net income reduced by distributions to ExxonMobil shareholders of $7.6 billion of dividends and $28.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Shareholders’ equity, and net assets and liabilities, increased $4.2 billion, representing the foreign exchange translation effects of stronger foreign currencies at the end of 2007 on ExxonMobil’s operations outside the United States.
During 2007, Exxon Mobil Corporation purchased 386 million shares of its common stock for the treasury at a gross cost of $31.8 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 6.1 percent from 5,729 million at the end of 2006 to 5,382 million at the end of 2007. Purchases were made in both the open market and through negotiated transactions.
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Commitments
Set forth below is information about the outstanding commitments of the Corporation’s consolidated subsidiaries at December 31, 2008. 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 $5.0 billion as of December 31, 2008, because the Corporation is unable to make reasonably reliable estimates of the timing of cash settlements with the respective taxing authorities. Further details on the unrecognized tax benefits can be found in note 18, Income, Sales-Based and Other Taxes.
Notes:
Guarantees
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2008, for $7,847 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of $6,102 million, representing ExxonMobil’s share of obligations of certain equity companies. The below-mentioned guarantees are not reasonably likely to have a material effect on the Corporation’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Total guarantees
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Financial Strength
On December 31, 2008, unused credit lines for short-term financing totaled approximately $5.3 billion (note 5).
The table below shows the Corporation’s fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporation’s creditworthiness. Throughout this period, the Corporation’s long-term debt securities maintained the top credit rating from both Standard & Poor’s (AAA) and Moody’s (Aaa), a rating it has sustained for 90 years.
Net debt to capital (percent)
Credit rating
Management views the Corporation’s financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The Corporation’s sound financial position gives it the opportunity to access the world’s capital markets in the full range of market conditions, and enables the Corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.
The Corporation makes limited use of derivative instruments, which are discussed in note 12.
Litigation and Other Contingencies
Litigation
As discussed in note 15, a number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims have been resolved and paid. All of the punitive damage claims were consolidated in the civil trial that began in 1994. On June 25, 2008, the U.S. Supreme Court vacated the $2.5 billion punitive damage award previously entered by the Ninth Circuit Court of Appeals and remanded the case to the Circuit Court with an instruction that punitive damages in the case may not exceed a maximum amount of $507.5 million. Exxon Mobil Corporation recorded an after-tax charge of $290 million in the second quarter of 2008, reflecting the maximum amount of the punitive damages. The parties have filed briefs in the Ninth Circuit Court of Appeals on the issue of post-judgment interest and recovery of costs. Exxon Mobil Corporation recorded an after-tax charge of $170 million in the third quarter of 2008, reflecting its estimate of the resolution of those issues.
Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation’s operations or financial condition. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.
Other Contingencies
In accordance with a nationalization decree issued by Venezuela’s president in February 2007, by May 1, 2007, a subsidiary of the Venezuelan National Oil Company (PdVSA) assumed the operatorship of the Cerro Negro Heavy Oil Project. This Project had been operated and owned by ExxonMobil affiliates holding a 41.67 percent ownership interest in the Project. The decree also required conversion of the Cerro Negro Project into a “mixed enterprise” and an increase in PdVSA’s or one of its affiliate’s ownership interest in the Project, with the stipulation that if ExxonMobil refused to accept the terms for the formation of the mixed enterprise within a specified period of time, the government would “directly assume the activities” carried out by the joint venture. ExxonMobil refused to accede to the terms proffered by the government, and on June 27, 2007, the government expropriated ExxonMobil’s 41.67 percent interest in the Cerro Negro Project.
On September 6, 2007, affiliates of ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes. An affiliate of ExxonMobil has also filed an arbitration under the rules of the International Chamber of Commerce against PdVSA and a PdVSA affiliate for breach of their contractual obligations under certain Cerro Negro Project agreements. At this time, the net impact of this matter on the Corporation’s consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporation’s operations or financial condition. ExxonMobil’s remaining net book investment in Cerro Negro producing assets is about $750 million.
CAPITAL AND EXPLORATION EXPENDITURES
Upstream (1)
Other
Capital and exploration expenditures in 2008 were $26.1 billion, reflecting the Corporation’s continued active investment program. The Corporation expects annual expenditures to range from $25 billion to $30 billion for the next several years. Actual spending could vary depending on the progress of individual projects.
Upstream spending of $19.7 billion in 2008 was up 26 percent from 2007, mainly due to increased project and exploration expenditures. During the past three years, Upstream capital and exploration expenditures averaged $17.2 billion. The majority of these expenditures are on development projects, which typically take two to four years from the time of recording proved undeveloped reserves to the start of production from those reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total proved reserves, indicating that proved reserves are consistently moved from undeveloped to developed status. Capital and exploration expenditures are not tracked by the undeveloped and developed proved reserve categories. Capital investments in the
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Downstream totaled $3.5 billion in 2008, an increase of $0.2 billion from 2007, due to higher environmental expenditures. Chemical 2008 capital expenditures of $2.8 billion were up $1.0 billion from 2007 due to increased investment in Asia Pacific to meet demand growth.
TAXES
Income taxes
Sales-based taxes
All other taxes and duties
Effective income tax rate
Income, sales-based and all other taxes totaled $116.3 billion in 2008, an increase of $10.6 billion or 10 percent from 2007. Income tax expense, both current and deferred, was $36.5 billion, $6.7 billion higher than 2007, reflecting higher pre-tax income in 2008. A higher share of total income from the non-U.S. Upstream segment in 2008 increased the effective tax rate to 47 percent compared to 44 percent in 2007. Sales-based and all other taxes and duties of $79.7 billion in 2008 increased $3.9 billion from 2007, reflecting higher prices.
Income, sales-based and all other taxes totaled $105.7 billion in 2007, an increase of $5.0 billion or 5 percent from 2006. Income tax expense, both current and deferred, was $29.9 billion, $2.0 billion higher than 2006, reflecting higher pre-tax income in 2007. The effective tax rate was 44 percent in 2007, compared to 43 percent in 2006. Sales-based and all other taxes and duties of $75.8 billion in 2007 increased $3.0 billion from 2006, 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 reduce nitrogen oxide and sulfur oxide emissions and expenditures for asset retirement obligations. ExxonMobil’s 2008 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobil’s share of equity company expenditures, were about $5.2 billion. The total cost for such activities is expected to remain in this range in 2009 and 2010 (with capital expenditures approximately 50 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 2008 for environmental liabilities were $507 million ($432 million in 2007) and the balance sheet reflects accumulated liabilities of $884 million as of December 31, 2008, and $916 million as of December 31, 2007.
Asset Retirement Obligations
The fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time assets are installed, with an offsetting amount booked as additions to property, plant and equipment ($195 million for 2008). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($335 million in 2008). Consolidated company expenditures for asset retirement obligations in 2008 were $258 million and the ending balance of the obligations recorded on the balance sheet at December 31, 2008, totaled $5,352 million.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Worldwide Average Realizations (1)
Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. In the Upstream, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $375 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $175 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide broad indicators of changes in the earnings experienced in any particular period.
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The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivative instruments to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity. Note 12 summarizes the fair value of derivatives outstanding at year end and the gains or losses that have been recognized in net income.
The Corporation is exposed to changes in interest rates, primarily on its short-term debt and the portion of long-term debt that carries floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporation’s debt would not be material to earnings, cash flow or fair value. The Corporation’s cash balances exceeded total debt at year-end 2008 and 2007. During 2008, credit markets tightened and the global economy slowed. The Corporation is not dependent on the credit markets to fund current operations. However, some joint-venture partners are dependent on the credit markets, and their funding ability may impact the development pace of joint-venture projects.
The general rate of inflation in many major countries of operation increased in 2008 versus the relatively low rates in recent years, and the associated impact on non-energy costs has generally been mitigated by cost reductions from efficiency and productivity improvements. Increased global demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation works to counter upward pressure on costs through its economies of scale in global procurement and its efficient project management practices.
RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 160 (FAS 160), “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51.” FAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests and classified as a component of equity.
FAS 160 must be adopted by the Corporation no later than January 1, 2009. FAS 160 requires retrospective adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of FAS 160 will be applied prospectively. The Corporation does not expect the adoption of FAS 160 to have a material impact on the Corporation’s financial statements.
Revisions to the Earnings Per Share Calculation
In 2008, the FASB issued a Staff Position (FSP) on the Emerging Issues Task Force (EITF) Issue No. 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.” The FSP clarified that all unvested share-based payment awards that contain nonforfeitable rights to dividends should be included in the basic Earnings Per Share (EPS) calculation. The FSP will be effective for first quarter 2009 reporting. The implementation of this standard for the Corporation will result in changes in the calculation of basic and diluted EPS that are not expected to be material. Prior-year EPS numbers will be adjusted retrospectively on a consistent basis. This standard will not affect the consolidated financial position or results of operations.
CRITICAL ACCOUNTING POLICIES
The Corporation’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The following summary provides further information about the critical accounting policies and the judgments that are made by the Corporation in the application of those policies.
Oil and Gas Reserves
Evaluations of oil and gas reserves are important to the effective management of Upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment. Oil and gas reserves include both proved and unproved reserves. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.
The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals (assisted by a central reserves group with significant technical experience), culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation.
Key features of the reserves estimation process include:
rigorous peer-reviewed technical evaluations and analysis of well and field performance information (such as flow rates and reservoir pressure declines) and
a requirement that management make significant funding commitments toward the development of the reserves prior to reporting as proved.
Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.
Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total proved reserves (including both consolidated and equity company reserves), indicating that proved reserves are consistently moved from undeveloped to developed status. Over time, these undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to collect and deliver the production from existing and future wells are installed. Major development projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.
The year-end reserves volumes as well as the reserves change categories shown in the proved reserves tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. We understand that the use of December 31 prices and costs is intended to provide a point in time measure to calculate reserves and to enhance comparability between companies. However, the use of year-end prices for reserves estimation introduces short-term price volatility into the process, which
is inconsistent with the long-term nature of the upstream business, since annual adjustments are required based on prices occurring on a single day. As a result, the use of prices from a single date is not relevant to the investment decisions made by the Corporation.
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 year-end prices and costs that are used in the determination of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.
The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method. The Corporation uses this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of the Corporation’s exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.
Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.
Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluation include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current operating losses.
In general, the Corporation does not view temporarily low oil and gas prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Corporation performs make use of the Corporation’s price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on individual field production profiles, which are updated annually. Cash flow estimates for impairment testing exclude the use of derivative instruments.
Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements. The standardized measure of discounted future cash flows is based on the year-end price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (FAS 69), “Disclosure about Oil and Gas Producing Activities.” Future prices used for any impairment tests will vary from the one used in the FAS 69 disclosure and could be lower or higher for any given year.
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Suspended Exploratory Well Costs
The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether a project has made sufficient progress is a subjective area and requires careful consideration of the relevant facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2008 are disclosed in note 9 to the financial statements.
Consolidations
The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporation’s percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in “Investments, advances and long-term receivables”; the Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.” The accounting for these non-consolidated companies is referred to as the equity method of accounting.
Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans and management compensation and succession plans.
Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 6.
Investments in companies that are partially owned by the Corporation are integral to the Corporation’s operations. In some cases they serve to balance worldwide risks and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their percentage ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its percentage share of all assets and liabilities in these partially owned companies rather than only its percentage in the net equity. This method of accounting for investments in partially owned companies is not permitted by GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by GAAP standards, the Corporation includes its share of debt of these partially owned companies in the determination of average capital employed.
Pension Benefits
The Corporation and its affiliates sponsor approximately 100 defined benefit (pension) plans in about 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the Corporation operates. Pension and Other Postretirement Benefits (note 16) provides details on pension obligations, fund assets and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
For funded plans, including those in the United States, pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
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 2008 was 9.0 percent. The 10-year and 20-year actual returns on U.S. pension plan assets are 5 percent and 9 percent, respectively. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return
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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 $90 million before tax.
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.
Litigation Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in note 15.
GAAP requires that liabilities for contingencies be recorded when it is probable that a liability has been incurred by the date of the balance sheet and that the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss.
Significant management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a materially adverse effect on operations or financial condition. In the Corporation’s experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.
Tax Contingencies
The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
GAAP requires recognition and measurement of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns. The benefit of an uncertain tax position can only be recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken in an income tax return and the amount recognized in the financial statements. The Corporation’s unrecognized tax benefits and a description of open tax years are summarized in note 18.
Foreign Currency Translation
The method of translating the foreign currency financial statements of the Corporation’s international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment. Downstream and Chemical operations use the local currency, except in countries with a history of high inflation (primarily in Latin America) and Singapore, which uses the U.S. dollar because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas production is predominantly sold in the export market in U.S. dollars. Operations using the U.S. dollar as their functional currency are primarily in Asia, West Africa, Russia and the Middle East.
Factors considered by management when determining the functional currency for a subsidiary include: the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of inflation in the country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.
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, 2008.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Exxon Mobil Corporation:
In our opinion, the consolidated financial statements listed under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2008, and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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, 2008, 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 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.
As discussed in Note 18 to the consolidated financial statements, the Corporation changed its method of accounting for uncertainty in income taxes in 2007.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Dallas, Texas
February 27, 2009
CONSOLIDATED STATEMENT OF INCOME
Revenues and other income
Sales and other operating revenue (1)
Income from equity affiliates
Other income (2)
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
Income applicable to minority interests
Total costs and other deductions
Income before income taxes
Net income per common share (dollars)
Net income per common share – assuming dilution (dollars)
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
CONSOLIDATED BALANCE SHEET
Assets
Current assets
Marketable securities
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
Equity of minority interests
Total liabilities
Commitments and contingencies
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
Common stock held in treasury (3,043 million shares in 2008 and 2,637 million shares in 2007)
Total shareholders’ equity
Total liabilities and shareholders’ equity
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
Common stock
At beginning of year
Restricted stock amortization
Tax benefits related to stock-based awards
Cumulative effect of accounting change
At end of year
Net income for the year
Dividends – common shares
Foreign exchange translation adjustment
Adjustment for foreign exchange translation loss included in net income
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs
Minimum pension liability adjustment
Common stock held in treasury
Acquisitions, at cost
Dispositions
Shareholders’ equity at end of year
Issued
Held in treasury
Acquisitions
Common shares outstanding at end of year
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CONSOLIDATED STATEMENT OF CASH FLOWS
Cash flows from operating activities
Accruing to ExxonMobil shareholders
Accruing to minority interests
Adjustments for noncash transactions
Deferred income tax charges/(credits)
Postretirement benefits expense in excess of/(less than) 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
Decrease 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 minority interests
Changes in minority interests and sales/(purchases) of affiliate stock
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
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 2008 presentation basis.
Principles of Consolidation. The Consolidated Financial Statements include the accounts of those subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the Corporation and for which other shareholders do not possess the right to participate in significant management decisions. They also include the Corporation’s share of the undivided interest in certain upstream assets and liabilities.
Amounts representing the Corporation’s percentage interest in the underlying net assets of other subsidiaries and less-than-majority-owned companies in which a significant ownership percentage interest is held are included in “Investments, advances and long-term receivables”; the Corporation’s share of the net income of these companies is included in the Consolidated Statement of Income caption “Income from equity affiliates.” The Corporation’s share of the cumulative foreign exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Shareholders’ Equity. Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporation’s investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.
Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. In all cases, revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured.
Revenues from the production of natural gas properties in which the Corporation has an interest with other producers are recognized on the basis of the Corporation’s net working interest. Differences between actual production and net working interest volumes are not significant.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.
Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs). This gross reporting basis is footnoted on the Consolidated Statement of Income.
Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and transactions.
The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the underlying hedged items.
Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method – LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.
Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets.
The Corporation uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method.
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The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. The cost of properties that are not individually significant are aggregated by groups and amortized over the average holding period of the properties of the groups. The valuation allowances are reviewed at least annually. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred.
Unit-of-production depreciation is applied to property, plant and equipment, including capitalized exploratory drilling and development costs, associated with productive depletable extractive properties in the Upstream segment. Unit-of-production rates are based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods.
Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.
Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Corporation’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.
Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Corporation. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation purposes. Cash flow estimates for impairment testing exclude derivative instruments.
Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. Impairments are measured by the amount the carrying value exceeds the fair value.
Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.
Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted.
Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates. Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia, West Africa, Russia and the Middle East, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.
Share-Based Payments. The Corporation awards share-based compensation to employees in the form of restricted stock and restricted stock units. Compensation expense is measured by the market price of the restricted shares at the date of grant and is recognized in the income statement over the requisite service period of each award. See note 14, Incentive Program, for further details.
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Effective January 1, 2008, the Corporation adopted the Financial Accounting Standards Board’s (FASB) Statement No. 157 (FAS 157), “Fair Value Measurements,” for financial assets and liabilities that are measured at fair value and nonfinancial assets and liabilities that are measured at fair value on a recurring basis. FAS 157 defines fair value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measurements. The initial application of FAS 157 is limited to the Corporation’s investments in derivative instruments and some debt and equity securities. The fair value measurements for these instruments are based on quoted prices or observable market inputs. The value of these instruments is immaterial to the Corporation’s financial statements, and the related gains or losses from periodic measurement at fair value are de minimis. Effective January 1, 2009, FAS 157 is applicable to all nonfinancial assets and liabilities that are measured at fair value.
Research and development costs totaled $847 million in 2008, $814 million in 2007 and $733 million in 2006.
Net income included before-tax aggregate foreign exchange transaction gains of $54 million, $229 million and $278 million in 2008, 2007 and 2006, respectively.
In 2008, 2007 and 2006, net income included gains of $341 million, $327 million and $401 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 $10.0 billion and $25.4 billion at December 31, 2008, and 2007, respectively.
Crude oil, products and merchandise as of year-end 2008 and 2007 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 a natural gas transportation business in Germany and other producing properties in the Upstream and Downstream assets and investments in 2008; from the sale of producing properties in the Upstream and of Downstream assets and investments in 2007; and from the sale of Upstream producing properties in 2006. These gains are reported in “Other income” on the Consolidated Statement of Income.
The restriction on $4.6 billion of cash and cash equivalents was released in 2007 following an Alabama Supreme Court judgment in ExxonMobil’s favor.
Cash payments for interest
Cash payments for income taxes
Notes and accounts receivable
Trade, less reserves of $219 million and $258 million
Other, less reserves of $43 million and $36 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, 2008, unused credit lines for short-term financing totaled approximately $5.3 billion. Of this total, $2.7 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2008, and 2007, was 5.7 percent and 5.5 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/lubes manufacturing and chemical ventures. The Corporation’s ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 21 percent, 23 percent and 24 percent in the years 2008, 2007 and 2006, respectively.
Equity Company Financial Summary
Total revenues
Property, plant and equipment, less accumulated depreciation
Other long-term assets
Short-term debt
Other current liabilities
Other long-term liabilities
Advances from shareholders
Net assets
A list of significant equity companies as of December 31, 2008, together with the Corporation’s percentage ownership interest, is detailed below:
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 II
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.
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Companies carried at equity in underlying assets
Investments
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 $1,288 million and $1,197 million
Property, Plant and Equipment
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 $149,499 million at the end of 2008 and $159,471 million at the end of 2007. Interest capitalized in 2008, 2007 and 2006 was $510 million, $557 million and $530 million, respectively.
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 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
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In accounting for suspended exploratory well costs, the Corporation utilizes Financial Accounting Standards Board Staff Position FAS 19-1 (FSP 19-1), “Accounting for Suspended Well Costs.” FSP 19-1 amended Statement of Financial Accounting Standards No. 19 (FAS 19), “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to permit the continued 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) the entity is making sufficient progress 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
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Of the 50 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2008, 31 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 19 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 19 projects, which total $313 million.
(millions
of dollars)
– East Pilchard
– Hibernia
– Natuna
– Aktote
– Kairan
– Etoro-Isobo
– Other (4 projects)
– H-North
– Carrack West
– Phyllis
– Various (6 projects)
Total – 2008 (19 projects)
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At December 31, 2008, 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 $11,188 million as indicated in the table. Estimated related rental income from noncancelable subleases is $155 million.
2010
2011
2012
2013
2014 and beyond
Net rental expenses under both cancelable and noncancelable operating leases incurred during 2008, 2007 and 2006 were as follows:
Rental expense
Less sublease rental income
Net rental expense
Net income (millions of dollars)
Weighted average number of common shares outstanding (millions of shares)
Effect of employee stock-based awards
Weighted average number of common shares outstanding – assuming dilution
Dividends paid per common share (dollars)
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The fair value of financial instruments is determined by reference to various 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 of significance is long-term debt. The estimated fair value of total long-term debt, including capitalized lease obligations, at December 31, 2008, and 2007, was $7.6 billion and $7.9 billion, respectively, as compared to recorded book values of $7.0 billion and $7.2 billion.
The Corporation’s size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporation’s enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The Corporation’s limited derivative activities pose no material credit or market risks to ExxonMobil’s operations, financial condition or liquidity.
The estimated fair value of derivatives outstanding and recorded on the balance sheet was a net receivable of $118 million and $31 million at year-end 2008 and 2007, respectively. This is the amount that the Corporation would have received from third parties if these derivatives had been settled in the open market. The Corporation recognized a before-tax gain of $89 million, $66 million and $397 million related to derivatives during 2008, 2007 and 2006, respectively.
The fair value of derivatives outstanding at year-end 2008 and gain recognized during the year are immaterial in relation to the Corporation’s year-end cash balance of $31.4 billion, total assets of $228.1 billion or net income for the year of $45.2 billion.
At December 31, 2008, long-term debt consisted of $6,662 million due in U.S. dollars and $363 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 $368 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, together with sinking fund payments required, in each of the four years after December 31, 2009, in millions of dollars, are: 2010 – $306, 2011 – $301, 2012 – $2,433 and 2013 – $135. At December 31, 2008, the Corporation’s unused long-term credit lines were not material.
Summarized long-term debt at year-end 2008 and 2007 are shown in the table below:
SeaRiver Maritime Financial Holdings, Inc. (1)
Guaranteed debt securities due 2009-2011 (2)
Guaranteed deferred interest debentures due 2012
– Face value net of unamortized discount plus accrued interest
Mobil Services (Bahamas) Ltd.
Variable notes due 2035 (3)
Variable notes due 2034 (4)
Mobil Producing Nigeria Unlimited (5)
Variable notes due 2009-2016
Esso (Thailand) Public Company Ltd. (6)
Variable note due 2009-2012
Mobil Corporation
8.625% debentures due 2021
Industrial revenue bonds due 2012-2039 (7)
Other U.S. dollar obligations (8)
Other foreign currency obligations
Capitalized lease obligations (9)
Total long-term debt
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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 ($1,925 million long-term debt at December 31, 2008) and the debt securities due 2009 to 2011 ($26 million long-term and $13 million short-term) of SeaRiver Maritime Financial Holdings, Inc.
SeaRiver Maritime Financial Holdings, Inc. is a 100-percent-owned subsidiary of Exxon Mobil Corporation.
The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for SeaRiver Maritime Financial Holdings, Inc., as issuer, as an alternative to providing separate financial statements for the issuer. The accounts of Exxon Mobil Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the equity method of accounting for investments in subsidiaries.
Sales and other operating revenue, including sales-based taxes
Other income
Intercompany revenue
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72
Condensed consolidated balance sheet for year ended December 31, 2008
Notes and accounts receivable – net
Property, plant and equipment – net
Intercompany receivables
Intercompany payables
Other shareholders’ equity
Condensed consolidated balance sheet for year ended December 31, 2007
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Condensed consolidated statement of cash flows for 12 months ended December 31, 2008
Cash provided by/(used in) operating activities
Sales of long-term assets
Decrease/(increase) in restricted cash and cash equivalents
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, 2007
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Condensed consolidated statement of cash flows for 12 months ended December 31, 2006
The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited or expire, or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2008, remaining shares available for award under the 2003 Incentive Program were 161,718 thousand.
As under earlier programs, options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. Most of the options and SARs normally first become exercisable one year following the date of grant. All remaining stock options and SARs outstanding were granted prior to 2002.
Long-term incentive awards totaling 10,116 thousand, 10,226 thousand and 10,187 thousand of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2008, 2007 and 2006, respectively. These shares are issued to employees from treasury stock. The total compensation expense is recognized over the requisite service period. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. A small number of awards granted to certain senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.
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The Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in conjunction with benefit plans and programs. Purchases may be discontinued at any time without prior notice.
In 2002, the Corporation began issuing restricted stock as share-based compensation in lieu of stock options. Compensation expense for these awards is based on the price of the stock at the date of grant and has been recognized in income over the requisite service period, which is the same method of accounting as under FAS 123R. Prior to 2002, the Corporation issued stock options as share-based compensation and since these awards vested prior to the effective date of FAS 123R, they continue to be accounted for by the method prescribed in APB 25, “Accounting for Stock Issued to Employees.” Under this method, compensation expense for awards granted in the form of stock options is measured at the intrinsic value of the options (the difference between the market price of the stock and the exercise price of the options) on the date of grant. Since these two prices were the same on the date of grant, no compensation expense has been recognized in income for these awards.
The following tables summarize information about restricted stock and restricted stock units for the year ended December 31, 2008.
Restricted stock and units outstanding
Issued and outstanding at January 1
2007 award issued in 2008
Vested
Forfeited
Issued and outstanding at December 31
Grant value of restricted stock and units
Grant price
Value at date of grant:
Restricted stock and units settled in stock
Units settled in cash
Total value
As of December 31, 2008, there was $2,014 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.6 years. The compensation cost charged against income for the restricted stock and restricted units was $648 million, $590 million and $527 million for 2008, 2007 and 2006, respectively. The income tax benefit recognized in income related to this compensation expense was $75 million, $81 million and $72 million for the same periods, respectively. The fair value of shares and units vested in 2008, 2007 and 2006 was $438 million, $581 million and $310 million, respectively. Cash payments of $25 million, $29 million and $18 million for vested restricted stock units settled in cash were made in 2008, 2007 and 2006, respectively.
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Changes that occurred in stock options in 2008 are summarized below (shares in thousands):
Stock options
Outstanding at January 1
Exercised
Outstanding at December 31
Exercisable at December 31
No compensation expense was recognized for stock options in 2008, 2007 and 2006, as all remaining outstanding stock options were granted prior to 2002 and are fully vested. Cash received from stock option exercises was $753 million, $1,079 million and $1,173 million for 2008, 2007 and 2006, respectively. The cash tax benefit realized for the options exercised was $273 million, $304 million and $416 million for 2008, 2007 and 2006, respectively. The aggregate intrinsic value of stock options exercised in 2008, 2007 and 2006 was $894 million, $1,359 million and $1,304 million, respectively. The intrinsic value for the balance of outstanding stock options at December 31, 2008, was $2,336 million.
A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporation’s operations or financial condition.
A number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims have been resolved and paid. All of the punitive damage claims were consolidated in the civil trial that began in 1994. On June 25, 2008, the U.S. Supreme Court vacated the $2.5 billion punitive damage award previously entered by the Ninth Circuit Court of Appeals and remanded the case to the Circuit Court with an instruction that punitive damages in the case may not exceed a maximum amount of $507.5 million. Exxon Mobil Corporation recorded an after-tax charge of $290 million in the second quarter of 2008, reflecting the maximum amount of the punitive damages. The parties have filed briefs in the Ninth Circuit Court of Appeals on the issue of post-judgment interest and recovery of costs. Exxon Mobil Corporation recorded an after-tax charge of $170 million in the third quarter of 2008, reflecting its estimate of the resolution of those issues.
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The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2008, for $7,847 million, primarily relating to guarantees for notes, loans and performance under contracts. Included in this amount were guarantees by consolidated affiliates of $6,102 million, representing ExxonMobil’s share of obligations of certain equity companies.
Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporation’s operations or financial condition. Unconditional purchase obligations as defined by accounting standards are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.
Unconditional purchase obligations (1)
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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 benefitobligations 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 a health care cost trend rate of 7.5 percent for 2009 that declines to 4.5 percent by 2014. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $52 million and the postretirement benefit obligation by $530 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $42 million and the post-retirement benefit obligation by $441 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
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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
Effective December 31, 2006, Exxon Mobil Corporation implemented FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which 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
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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)
Total recorded in net periodic benefit cost and accumulated other comprehensive income, before tax
Costs for defined contribution plans were $309 million, $287 million and $260 million in 2008, 2007 and 2006, respectively.
A summary of the change in accumulated other comprehensive income is shown in the table below:
(Charge)/credit to accumulated other comprehensive income, before tax
U.S. pension
Non-U.S. pension
Other postretirement benefits
Total (charge)/credit to accumulated other comprehensive income, before tax
(Charge)/credit to income tax (see note 18)
Charge/(credit) to equity of minority shareholders
(Charge)/credit to investment in equity companies
(Charge)/credit to accumulated other comprehensive income, after tax
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The long-term expected rate of return on funded assets for each plan is established 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. The majority of pension assets are invested in equities, as illustrated in the table below, which shows asset allocation.
Funded benefit plan asset allocation
Equity securities
Debt securities
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 Corporation primarily invests in funds that follow an index-based strategy to achieve its objectives of diversifying risk while minimizing costs. The funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for equity securities of 75 percent for the U.S. benefit plans and 64 percent for non-U.S. plans reflects the long-term nature of the liability. The balance of the funds is largely targeted to debt securities.
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 accumulated benefit obligations in excess of plan assets:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
For unfunded pension plans:
Estimated 2009 amortization from accumulated other comprehensive income:
Net actuarial loss/(gain) (1)
Prior service cost (2)
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Contributions expected in 2009
Benefit payments expected in:
2014 - 2018
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. Special items included in 2008 after-tax earnings were a $1,620 million gain in Non-U.S. Upstream on the sale of a natural gas transportation business in Germany and special charges of $460 million in the corporate and financing segment related to the Valdez litigation. There were no special items in 2007. After-tax earnings in 2006 included a $410 million special gain in the corporate and financing segment from the recognition of tax benefits related to historical investments in non-U.S. assets.
Interest expense includes non-debt-related interest expense of $498 million, $290 million and $535 million in 2008, 2007 and 2006, respectively. The increase of $208 million in 2008 primarily reflects an interest provision related to the Valdez litigation. The decrease of $245 million in 2007 primarily reflects changes in tax-related interest.
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, 2008
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, 2007
As of December 31, 2006
Geographic Sales and other operating revenue (1)
Significant non-U.S. revenue sources include:
(1) Sales and other operating revenue includes sales-based taxes of $34,508 million for 2008, $31,728 million for 2007 and $30,381 million for 2006. See note 1, Summary of Accounting Policies.
Long-lived assets
Significant non-U.S. long-lived assets include:
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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 taxes
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 for the effect of changes in tax laws and rates of $300 million in 2008, $258 million in 2007 and $169 million in 2006.
Income taxes (charged)/credited directly to shareholders’ equity were:
Postretirement benefits reserves adjustment:
Total postretirement benefits reserves adjustment
Other components of shareholders’ equity
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2008, 2007 and 2006 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.
Total income tax expense
Effective tax rate calculation
ExxonMobil share of equity company income taxes
Income from continuing operations
Total income before taxes
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Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.
Deferred tax liabilities/(assets) are comprised of the following at December 31:
Tax effects of temporary differences for:
Depreciation
Intangible development costs
Capitalized interest
Other liabilities
Total deferred tax liabilities
Pension and other postretirement benefits
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.
Balance sheet classification
The Corporation had $62 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.
Unrecognized Tax Benefits
Effective January 1, 2007, the Corporation adopted the Financial Accounting Standards Board’s Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes.” Upon the adoption of FIN 48, the Corporation recognized a transition gain of $267 million in shareholders’ equity. The gain reflected the recognition of several refund claims, partly offset by increased liability reserves.
The Corporation is subject to income taxation in many jurisdictions around the world. Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. Resolution of the related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. It is difficult to predict the timing of resolution for individual tax positions since such timing is not entirely within the control of the Corporation. However, it is reasonably possible that resolutions could be reached with tax jurisdictions within the next 12 months that could result in a decrease of up to 25 percent in the total amount of unrecognized tax benefits. Given the long time periods involved in resolving individual tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporation’s effective income tax rate in any given year.
The following table summarizes the movement in unrecognized tax benefits.
Gross unrecognized tax benefits
Balance at January 1
Additions based on current year’s tax positions
Additions for prior years’ tax positions
Reductions for prior years’ tax positions
Reductions due to lapse of the statute of 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 shareholders’ 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 2008 and 2007 changes in unrecognized tax benefits did not have a material effect on the Corporation’s net income or cash flow.
The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
Country of Operation
Open Tax Years
Abu Dhabi
The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.
The Corporation incurred approximately $137 million and $128 million in interest expense on income tax reserves in 2008 and 2007, respectively, and had a related interest payable of $671 million and $597 million at December 31, 2008, and 2007, respectively.
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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES(unaudited)
The results of operations for producing activities shown below are presented in accordance with Statement of Financial Accounting Standards No. 69. As such, they do not include earnings from other activities that ExxonMobil includes in the Upstream function such as oil and gas transportation operations, oil sands operations, LNG liquefaction and transportation operations, coal and power operations, technical services agreements, other nonoperating activities and adjustments for minority interests. These excluded amounts for both consolidated and equity companies totaled $3,834 million in 2008, $2,271 million in 2007 and $2,431 million in 2006.
Results of Operations
2008 – 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
Proportional interest in results of producing activities of equity companies
2007 – Revenue
2006 – Revenue
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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
Average sales 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 proved reserves table of this report. The volumes for natural gas used for this calculation are the production volumes of natural gas available for sale and thus are different than those shown in the proved reserves table of this report due to volumes consumed or flared. The volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.
Average sales prices and production costs per
unit of production – consolidated subsidiaries
During 2008
Average sales prices
Crude oil and NGL, per barrel
Natural gas, per thousand cubic feet
Average production costs, per barrel (1)
During 2007
During 2006
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Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $5,779 million less at year-end 2008 and $6,381 million less at year-end 2007 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 the oil sands and LNG operations, all as required by Statement of Financial Accounting Standards No. 19.
Capitalized Costs
Property (acreage) costs – Proved
– Unproved
Total property costs
Producing assets
Support facilities
Incomplete construction
Total capitalized costs
Accumulated depreciation and depletion
Net capitalized costs for consolidated subsidiaries
Proportional interest of net capitalized costs of 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 2008 were $15,816 million, up $3,741 million from 2007, due primarily to higher exploration and development costs. 2007 costs were $12,075 million, down $938 million from 2006, due primarily to lower development and property acquisition costs.
Costs incurred in property acquisitions,
exploration and development activities
Property acquisition costs – Proved
Exploration costs
Development costs
Total costs incurred for consolidated subsidiaries
Proportional interest of costs incurred of 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 2006, 2007 and 2008.
The definitions used are in accordance with the Securities and Exchange Commission’s Rule 4-10 (a) of Regulation S-X, paragraphs (2) through (2)iii, (3) and (4).
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves.
The year-end reserves volumes as well as the reserves change categories shown in the following tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. We understand that the use of December 31 prices and costs is intended to provide a point in time measure to calculate reserves and to enhance comparability between companies. However, the use of year-end prices for reserves estimation introduces short-term price volatility into the process, which is inconsistent with the long-term nature of the upstream business, since annual adjustments are required based on prices occurring on a single day. As a result, the use of prices from a single date is not relevant to the investment decisions made by the Corporation.
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 percentage of conventional liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2008 that were associated with production sharing contract arrangements was 22 percent of liquids, 16 percent of natural gas and 19 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. Undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells.
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.
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Crude Oil and Natural Gas Liquids
Net proved developed and undeveloped reserves of consolidated subsidiaries
January 1, 2006
Purchases
Sales
Improved recovery
Extensions and discoveries
December 31, 2006
December 31, 2007
Proportional interest in proved reserves of equity companies
End of year 2006
End of year 2007
End of year 2008
Proved developed reserves, included above, as of December 31, 2006
Consolidated subsidiaries
Equity companies
Proved developed reserves, included above, as of December 31, 2007
Proved developed reserves, included above, as of December 31, 2008
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Oil and Gas Reserves (continued)
Natural Gas
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Natural Gas (continued)
INFORMATION ON CANADIAN OIL SANDS PROVEN RESERVES NOT INCLUDED ABOVE
In addition to conventional liquids and natural gas proved reserves, ExxonMobil has significant interests in proven oil sands reserves in Canada associated with the Syncrude and Kearl projects. For internal management purposes, ExxonMobil views these reserves and their development as an integral part of total upstream operations. However, for financial reporting purposes, these reserves are required to be reported separately from the oil and gas reserves.
The oil sands reserves are not considered in the standardized measure of discounted future cash flows for conventional oil and gas reserves, which is on the following page.
Oil Sands Reserves
At December 31, 2006
At December 31, 2007
At December 31, 2008
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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 year-end prices, 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 year-end prices, which represent a single point 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
Future cash inflows from 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
Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies
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Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Value of reserves added during the year due to extensions, discoveries, improved recovery and 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
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OPERATING SUMMARY (unaudited)
Net production
Petroleum product sales (2)
Asia Pacific and other Eastern Hemisphere
Purchases/sales with the same counterparty included above
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.
By:
/s/ REX W. TILLERSON
(Rex W. Tillerson,
Chairman of the Board)
Dated February 27, 2009
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Beverley A. Babcock, Richard E. Gutman and Robert N. Schleckser and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
(Rex W. Tillerson)
Chairman of the Board
(Principal Executive Officer)
/s/ MICHAEL J. BOSKIN
(Michael J. Boskin)
/s/ LARRY R. FAULKNER
(Larry R. Faulkner)
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/s/ WILLIAM W. GEORGE
(William W. George)
/s/ JAMES R. HOUGHTON
(James R. Houghton)
/s/ REATHA CLARK KING
(Reatha Clark King)
/s/ MARILYN CARLSON NELSON
(Marilyn Carlson Nelson)
/s/ SAMUEL J. PALMISANO
(Samuel J. Palmisano)
/s/ STEVEN S REINEMUND
(Steven S Reinemund)
/s/ WALTER V. SHIPLEY
(Walter V. Shipley)
/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, 2006).
By-Laws, as revised to July 31, 2002 (incorporated by reference to Exhibit 3(ii) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).
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 stock option granted to executive officers (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrant’s Annual Report on Form 10-K for 2004).*
Form of restricted stock agreement with executive officers (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K on December 2, 2008).*
Short Term Incentive Program, as amended (incorporated by reference to Exhibit 99.2 to the Registrant’s Report on Form 8-K on November 2, 2007).*
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 December 2, 2008).*
ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on November 2, 2007).*
ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrant’s Report on Form 8-K on October 12, 2006).*
ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrant’s Report on Form 8-K on October 12, 2006).*
ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).*
2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Appendix B to the Proxy Statement of Exxon Mobil Corporation dated April 14, 2004).*
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.*
Standing resolution for non-employee director cash fees dated September 26, 2007 (incorporated by reference to Exhibit 99.3 to the Registrant’s Report on Form 8-K on September 27, 2007).*
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INDEX TO EXHIBITS—(continued)
2001 Nonemployee Directors’ Deferred Compensation Plan, as amended and restated on September 27, 2007 (incorporated by reference to Exhibit 99.4 to the Registrant’s Report on Form 8-K on September 27, 2007).*
1995 Mobil Incentive Compensation and Stock Ownership Plan (incorporated by reference to Exhibit 10(iii)(g.1) to the Registrant’s Annual Report on Form 10-K for 2005).*
Form of stock option granted to Mobil executive officers (incorporated by reference to Exhibit 10(iii)(g.2) to the Registrant’s Annual Report on Form 10-K for 2004).*
1984 Mobil Compensation Management Retention Plan, as amended and restated on September 27, 2007 (incorporated by reference to Exhibit 99.1 to the Registrant’s Report on Form 8-K on September 27, 2007).*
Computation of ratio of earnings to fixed charges.
Code of Ethics and Business Conduct.
Subsidiaries of the registrant.
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
31.1
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer.
31.2
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Financial Officer.
31.3
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer.
32.1
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer.
32.2
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Financial Officer.
32.3
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer.
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.
101