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Exxon Mobil 10-K 2009 Documents found in this filing:
Table of ContentsIndex to Financial Statements2008 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 THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File Number 1-2256 EXXON MOBIL CORPORATION (Exact name of registrant as specified in its charter)
5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298 (Address of principal executive offices) (Zip Code) (972) 444-1000 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ü No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No ü
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ü No
Indicate by check mark 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)
Table of ContentsIndex to Financial StatementsFORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008
TABLE OF CONTENTS
Table of ContentsIndex to Financial StatementsPART I
Item 1. Business.
Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil also has interests in electric power generation facilities. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.
Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that include ExxonMobil, Exxon, Esso or Mobil. For convenience and simplicity, in this report the terms ExxonMobil, Exxon, Esso and Mobil, as well as terms like Corporation, Company, our, we and its, are sometimes used as abbreviated references to specific affiliates or groups of affiliates. The precise meaning depends on the context in question.
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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Table of ContentsIndex to Financial Statementsfurnished 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:
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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Table of ContentsIndex to Financial StatementsPolitical 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:
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 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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Table of ContentsIndex to Financial StatementsThe 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:
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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Table of ContentsIndex to Financial StatementsAlthough 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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Table of ContentsIndex to Financial Statementsdemand 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.
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Table of ContentsIndex to Financial StatementsAdditional detail on developed and undeveloped oil-equivalent proved reserves is shown in the table below.
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.
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.
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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Table of ContentsIndex to Financial StatementsForm 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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Table of ContentsIndex to Financial Statements6. 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
UNITED STATES
Oil and gas leases have an exploration period ranging from one to ten years, and a production period that normally remains in effect until production ceases. Under certain circumstances, a lease may be held beyond its exploration term even if production has not commenced. In some instances, a “fee interest” is acquired where both the surface and the underlying mineral interests are owned outright.
CANADA / SOUTH AMERICA
Canada
Exploration permits are granted for varying periods of time with renewals possible. Exploration rights in onshore areas acquired from Canadian provinces entitle the holder to obtain leases upon completing specified work. Production leases are held as long as there is production on the lease. The majority of Cold Lake leases were taken for an initial 21-year term in 1968-1969 and renewed for a second 21-year term in 1989-1990. The exploration acreage in eastern Canada and the block in the Beaufort Sea acquired in 2007 are currently held by work commitments of various amounts.
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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Table of ContentsIndex to Financial Statements
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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Table of ContentsIndex to Financial StatementsCameroon
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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Table of ContentsIndex to Financial StatementsASIA 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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Table of ContentsIndex to Financial StatementsPapua 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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Table of ContentsIndex to Financial StatementsKazakhstan
Onshore: Exploration and production activities are governed by the production license, exploration license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.
Offshore: Exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period was six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.
Russia
Terms for ExxonMobil’s acreage are fixed by the production sharing agreement (PSA) that became effective in 1996 between the Russian government and the Sakhalin-1 consortium, of which ExxonMobil is the operator. The term of the PSA is 20 years from the Declaration of Commerciality, which would be 2021. The term may be extended thereafter in 10-year increments as specified in the PSA.
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Table of ContentsIndex to Financial Statements8. Number of Net Productive and Dry Wells Drilled
9. Present Activities
A. Wells Drilling
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Table of ContentsIndex to Financial StatementsB. 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.
UNITED STATES
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.
CANADA / SOUTH AMERICA
Canada
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.
Argentina
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.
EUROPE
Germany
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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Table of ContentsIndex to Financial StatementsItaly
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.
Netherlands
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.
Norway
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.
United Kingdom
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.
AFRICA
Angola
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.
Cameroon
ExxonMobil’s net acreage holdings totaled 0.1 million offshore acres.
Chad
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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Table of ContentsIndex to Financial StatementsEquatorial Guinea
ExxonMobil’s acreage totaled 0.2 million net offshore acres at year-end 2008.
Nigeria
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.
ASIA PACIFIC / MIDDLE EAST
Australia
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.
Indonesia
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.
Japan
ExxonMobil’s net offshore acreage was 36 thousand acres at year-end 2008.
Malaysia
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.
Papua New Guinea
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.
Qatar
Production and development activities continued on natural gas projects in Qatar. Liquefied natural gas (LNG) operating companies include:
Qatar Liquefied Gas Company Limited — (QG I) Qatar Liquefied Gas Company Limited (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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Table of ContentsIndex to Financial StatementsIn 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.
Republic of Yemen
ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end.
Thailand
ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2008.
United Arab Emirates
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.
RUSSIA/CASPIAN
Azerbaijan
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.
Kazakhstan
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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Table of ContentsIndex to Financial StatementsRussia
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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Table of ContentsIndex to Financial Statementsaddition 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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Table of ContentsIndex to Financial StatementsExxonMobil Net Proven Syncrude Reserves (1)
Syncrude Operating Statistics (total operation)
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.
Operating License and Leases
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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Table of ContentsIndex to Financial Statementssands 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.
Operations, Plant and Equipment
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)
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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Table of ContentsIndex to Financial StatementsRefining Capacity At Year-End 2008 (1)
24
Table of ContentsIndex to Financial Statements
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
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Table of ContentsIndex to Financial StatementsInformation with regard to the Chemical segment follows:
ExxonMobil’s Chemical segment manufactures and sells petrochemicals. The Chemical business supplies olefins, polyolefins, aromatics, and a wide variety of other petrochemicals.
Chemical Complex Capacity at Year-End 2008 (1) (2)
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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Table of ContentsIndex to Financial StatementsRegarding 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.
None.
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Table of ContentsIndex to Financial StatementsExecutive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].
For at least the past five years, Messrs. 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.
Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.
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Table of ContentsIndex to Financial StatementsPART II
Reference is made to the “Quarterly Information” portion of the Financial Section of this report.
Note 1—On August 1, 2000, the Corporation announced its intention to resume purchases of shares of its common stock for the treasury both to offset shares issued in conjunction with company benefit plans and programs and to gradually reduce the number of shares outstanding. The announcement did not specify an amount or expiration date. The Corporation has continued to purchase shares since this announcement and to report purchased volumes in its quarterly earnings releases. In its most recent earnings release dated 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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Table of ContentsIndex to Financial StatementsItem 6. Selected Financial Data.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Reference is made to the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Financial Section of this report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Reference is made to the section entitled “Market Risks, Inflation and Other Uncertainties”, excluding the part entitled “Inflation and Other Uncertainties,” in the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the following in the Financial Section of this report:
Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
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Table of ContentsIndex to Financial StatementsItem 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Management’s Evaluation of Disclosure Controls and Procedures
As indicated in the certifications in Exhibit 31 of this report, the Corporation’s chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporation’s disclosure controls and procedures as of December 31, 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.
None.
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”):
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Table of ContentsIndex to Financial StatementsItem 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
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Table of ContentsIndex to Financial StatementsItem 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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Table of ContentsIndex to Financial StatementsFINANCIAL SECTION TABLE OF CONTENTS
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Table of ContentsIndex to Financial StatementsBUSINESS PROFILE
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
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Table of ContentsIndex to Financial StatementsFINANCIAL SUMMARY
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Table of ContentsIndex to Financial StatementsFREQUENTLY USED TERMS Listed below are definitions of several of ExxonMobil’s key business and financial performance measures. These definitions are provided to facilitate understanding of the terms and their calculation. CASH FLOW FROM OPERATIONS AND ASSET SALES Cash flow from operations and asset sales is the sum of the net cash provided by operating activities and proceeds from sales of subsidiaries, investments and property, plant and equipment from the Consolidated Statement of Cash Flows. This cash flow reflects the total sources of cash from both operating the Corporation’s assets and from the divesting of assets. The Corporation employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the Corporation’s strategic objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
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.
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Table of ContentsIndex to Financial StatementsRETURN ON AVERAGE CAPITAL EMPLOYED Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobil’s share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporation’s total ROCE is net income excluding the after-tax cost of financing, divided by total corporate average capital employed. The Corporation has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in our capital-intensive, long-term industry, both to evaluate management’s performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow-based, are used to make investment decisions.
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Table of ContentsIndex to Financial StatementsQUARTERLY INFORMATION
The price range of ExxonMobil common stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil common stock is traded. The principal market where ExxonMobil common stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States. There were 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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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including demand growth and energy source mix; capacity increases; production growth and mix; 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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Table of ContentsIndex to Financial StatementsIncreases 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. Upstream 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. Downstream ExxonMobil’s Downstream is a large, diversified business with refining and marketing complexes around the world. The Corporation has a strong presence in mature markets in North America and Europe, as well as the growing Asia Pacific region. ExxonMobil’s fundamental Downstream business strategies position the company to deliver long-term growth in shareholder value that is superior to competition across a range of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technologies, capitalizing on integration with other ExxonMobil businesses, selectively investing for resilient, advantaged returns, leading the industry in efficiency and effectiveness, and providing quality, valued products and services to customers. ExxonMobil has an ownership interest in 37 refineries, located in 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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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Chemical 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
2008 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
2008 Upstream earnings for 2008 totaled $35,402 million, an increase of $8,905 million from 2007, including an after-tax gain of $1,620 million from the sale of a natural gas transportation business in Germany. 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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Table of ContentsIndex to Financial Statements2007 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
2008 Downstream earnings of $8,151 million were $1,422 million lower than in 2007. Lower margins reduced earnings approximately $900 million, as weaker refining margins more than offset stronger marketing margins. Higher operating costs, mainly associated with planned work activity, reduced earnings about $700 million, while unfavorable foreign exchange effects decreased earnings approximately $600 million. Improved refinery operations provided a partial offset, increasing earnings about $800 million. Petroleum product sales of 6,761 kbd decreased from 7,099 kbd in 2007, primarily reflecting asset sales and lower demand. Refinery throughput was 5,416 kbd compared with 5,571 kbd in 2007. U.S. Downstream earnings were $1,649 million, down $2,471 million from 2007. Non-U.S. Downstream earnings of $6,502 million were $1,049 million higher than in 2007. 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
2008 Chemical earnings totaled $2,957 million, a decrease of $1,606 million from 2007. Lower margins reduced earnings approximately $1.2 billion, while lower volumes decreased earnings about $500 million. Prime product sales were 24,982 kt (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. 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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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Corporate and Financing
2008 Corporate and financing expenses of $1,290 million in 2008 increased $1,267 million from 2007, mainly due to charges of $460 million related to the Valdez litigation, net higher taxes and lower interest income. 2007 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
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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Table of ContentsIndex to Financial StatementsCash Flow from Operating Activities 2008 Cash provided by operating activities totaled $59.7 billion in 2008, a $7.7 billion increase from 2007. The major source of funds was net income 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. 2007 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 2008 Cash used in investing activities netted to $15.5 billion in 2008, $5.8 billion higher than in 2007. Spending for property, plant and equipment of $19.3 billion in 2008 increased $3.9 billion from 2007. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $6.0 billion in 2008 compared to $4.2 billion in 2007, the increase reflecting the sale of the German natural gas transportation business in 2008. Cash used in investing activities in 2008 was higher due to the absence of the $4.6 billion positive cash flow in 2007 from the release of the restriction on the restricted cash and cash equivalents. Net cash used for investments and advances and the change in marketable securities was $1.0 billion lower in 2008. 2007 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 2008 Cash used in financing activities was $44.0 billion in 2008, an increase of $5.7 billion from 2007, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.55 per share from $1.37 per share and totaled $8.1 billion, a pay-out of 18 percent. Total consolidated short-term and long-term debt decreased $0.2 billion to $9.4 billion at year-end 2008. 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. 2007 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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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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.
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Table of ContentsIndex to Financial StatementsFinancial 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.
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
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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Table of ContentsIndex to Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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
2008 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. 2007 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 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
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