2007
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, 2007
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-2256
EXXON MOBIL CORPORATION
(Exact name of registrant as specified in its charter)
NEW JERSEY (State or other jurisdiction of |
13-5409005 (I.R.S. Employer |
5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298
(Address of principal executive offices) (Zip Code)
(972) 444-1000
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class |
Name of Each Exchange on Which Registered | |
Common Stock, without par value (5,350,027,205 shares |
New York Stock Exchange | |
Registered securities guaranteed by Registrant: | ||
SeaRiver Maritime Financial Holdings, Inc. |
||
Twenty-Five Year Debt Securities due October 1, 2011 |
New York Stock Exchange |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ü No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No ü
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ü No
Indicate by check mark 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 registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer 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 29, 2007, the last business day of the registrants most recently completed second fiscal quarter, based on the closing price on that date of $83.88 on the New York Stock Exchange composite tape, was in excess of $465 billion.
Documents Incorporated by Reference:
Proxy Statement for the 2008 Annual Meeting of Shareholders (Part III)
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007
TABLE OF CONTENTS
Page Number | ||||
PART I | ||||
Item 1. | 1 | |||
Item 1A. | 2 | |||
Item 1B. | 4 | |||
Item 2. | 4 | |||
Item 3. | 20 | |||
Item 4. | 20 | |||
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)] | 21 | |||
PART II | ||||
Item 5. | 22 | |||
Item 6. | 23 | |||
Item 7. | Managements Discussion and Analysis of Financial Condition and Results of Operations |
23 | ||
Item 7A. | 23 | |||
Item 8. | 23 | |||
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 24 | ||
Item 9A. | Controls and Procedures | 24 | ||
Item 9B. | Other Information | 24 | ||
PART III | ||||
Item 10. | 25 | |||
Item 11. | 25 | |||
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
25 | ||
Item 13. | Certain Relationships and Related Transactions, and Director Independence |
26 | ||
Item 14. | 26 | |||
PART IV | ||||
Item 15. | 26 | |||
Financial Section | 27 | |||
Signatures | 91 | |||
Index to Exhibits | 93 | |||
Exhibit 12 Computation of Ratio of Earnings to Fixed Charges | ||||
Exhibits 31 and 32 Certifications |
PART I
Exxon Mobil Corporation was incorporated in the State of New Jersey in 1882. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and most other countries of the world. Their principal business is energy, involving exploration for, and production of, crude oil and natural gas, manufacture of petroleum products and transportation and sale of crude oil, natural gas and petroleum products. ExxonMobil is a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil also has interests in electric power generation facilities. Affiliates of ExxonMobil conduct extensive research programs in support of these businesses.
Exxon Mobil Corporation has several divisions and hundreds of affiliates, many with names that 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 ExxonMobils 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. ExxonMobils 2007 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobils share of equity company expenditures, were about $3.8 billion, of which $1.5 billion were capital expenditures and $2.3 billion were included in expenses. The total cost for such activities is expected to remain in this range in 2008 and 2009 (with capital expenditures approximately 45 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. Information on Company-sponsored research and development activities is contained in Note 3: Miscellaneous Financial Information of the Financial Section of this report.
The number of regular employees was 80.8 thousand, 82.1 thousand and 83.7 thousand at years ended 2007, 2006 and 2005, 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 Corporations benefit plans and programs. Regular employees do not include employees of the company-operated retail sites (CORS). The number of CORS employees was 26.3 thousand, 24.3 thousand and 22.4 thousand at years ended 2007, 2006 and 2005, 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 furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available through our website as soon as reasonably practical after we electronically file or furnish the reports to the Securities and Exchange Commission. Also available on the Corporations website are the Companys
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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.
Item 1A. | Risk Factors. |
ExxonMobils financial and operating results are subject to a number of factors, many of which are not within the Companys control. These factors include the following:
Industry and Economic Factors: The oil and gas business is fundamentally a commodity business. This means the operations and earnings of the Corporation and its affiliates throughout the world may be significantly affected by changes in oil, gas and petrochemical prices and by changes in margins on gasoline and other refined products. Oil, gas, petrochemical and product prices and margins in turn depend on local, regional and global events or conditions that affect supply and demand for the relevant commodity. These events or conditions are generally not predictable and include, among other things:
| general economic growth rates and the occurrence of economic recessions; |
| the development of new supply sources; |
| adherence by countries to OPEC quotas; |
| supply disruptions; |
| weather, including seasonal patterns that affect regional energy demand (such as the demand for heating oil or gas in winter) as well as severe weather events (such as hurricanes) that can disrupt supplies or interrupt the operation of ExxonMobil facilities; |
| technological advances, including advances in exploration, production, refining and petrochemical manufacturing technology and advances in technology relating to energy usage; |
| changes in demographics, including population growth rates and consumer preferences; and |
| the competitiveness of alternative hydrocarbon or other energy sources. |
Under certain market conditions, factors that have a positive impact on one segment of our business may have a negative impact on another segment and vice versa.
Competitive Factors: The energy and petrochemical industries are highly competitive. There is competition within the industries and also with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. The Corporation competes with other firms in the sale or purchase of needed goods and services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes.
A key component of the Corporations competitive position, particularly given the commodity-based nature of many of its businesses, is ExxonMobils 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 as described elsewhere in this report.
Political and Legal Factors: The operations and earnings of the Corporation and its affiliates throughout the world have been, and may in the future be, affected from time to time in varying degree by political and legal factors including:
| political instability or lack of well-established and reliable legal systems in areas where the Corporation operates; |
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| other political developments and laws and regulations, such as expropriation or forced divestiture of assets, unilateral cancellation or modification of contract terms, and regulation of certain energy markets; |
| laws and regulations related to environmental or energy security matters, including those addressing alternative energy sources and the risks of global climate change; |
| restrictions on exploration, production, imports and exports; |
| restrictions on the Corporations ability to do business with certain countries, or to engage in certain areas of business within a country; |
| price controls; |
| tax or royalty increases, including retroactive claims; |
| war or other international conflicts; and |
| civil unrest. |
Both the likelihood of these occurrences and their overall effect upon the Corporation vary greatly from country to country and are not predictable. A key component of the Corporations strategy for managing political risk is geographic diversification of the Corporations assets and operations.
Project Factors: In addition to some of the factors cited above, ExxonMobils results depend upon the Corporations ability to develop and operate major projects and facilities as planned. The Corporations results will therefore be affected by events or conditions that impact the advancement, operation, cost or results of such projects or facilities, including:
| the outcome of negotiations with co-venturers, governments, suppliers, customers or others (including, for example, our ability to negotiate favorable long-term contracts with customers, or the development of reliable spot markets, that may be necessary to support the development of particular production projects); |
| reservoir performance and natural field decline; |
| changes in operating conditions and costs, including costs of third party equipment or services such as drilling rigs and shipping; |
| security concerns or acts of terrorism that threaten or disrupt the safe operation of company facilities; and |
| the occurrence of unforeseen technical difficulties (including technical problems that may delay start-up or interrupt production from an Upstream project or that may lead to unexpected downtime of refineries or petrochemical plants). |
See section 1 of Item 2 of this report for a discussion of additional factors affecting future capacity growth and the timing and ultimate recovery of reserves.
Market Risk Factors: See the Market Risks, Inflation and Other Uncertainties portion of the Financial Section of this report for discussion of the impact of market risks, inflation and other uncertainties.
Projections, estimates and descriptions of ExxonMobils 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.
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Item 1B. | Unresolved Staff Comments. |
None.
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:
1. | Net Reserves of Crude Oil and Natural Gas Liquids and Natural Gas at Year-End 2007 |
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, 2007, 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, 2007. 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.
Liquids |
Natural Gas |
Oil-Equivalent Basis | ||||
(millions of barrels) | (billions of cubic feet) | (millions of barrels) | ||||
United States |
1,851 | 13,172 | 4,046 | |||
Canada/South America |
939 | 1,559 | 1,199 | |||
Europe |
673 | 6,512 | `1,758 | |||
Africa |
2,058 | 1,006 | 2,226 | |||
Asia Pacific/Middle East |
1,510 | 9,634 | 3,116 | |||
Russia/Caspian |
713 | 727 | 834 | |||
Total consolidated |
7,744 | 32,610 | 13,179 | |||
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Additional detail on developed and undeveloped oil-equivalent proved reserves is shown in the table below.
Year-End 2007 |
Year-End 2006 | |||||||
Developed |
Undeveloped |
Developed |
Undeveloped | |||||
(millions of oil-equivalent barrels) | ||||||||
Consolidated Subsidiaries |
||||||||
United States |
2,723 | 1,323 | 3,013 | 879 | ||||
Canada/South America |
899 | 300 | 1,173 | 553 | ||||
Europe |
1,362 | 396 | 1,448 | 482 | ||||
Africa |
1,331 | 895 | 1,416 | 837 | ||||
Asia Pacific/Middle East |
2,055 | 1,061 | 2,070 | 814 | ||||
Russia/Caspian |
157 | 677 | 183 | 739 | ||||
Total |
8,527 | 4,652 | 9,303 | 4,304 | ||||
Equity Companies |
||||||||
United States |
316 | 79 | 329 | 84 | ||||
Europe |
1,621 | 462 | 1,675 | 429 | ||||
Asia Pacific/Middle East |
2,121 | 2,929 | 1,948 | 2,995 | ||||
Russia/Caspian |
637 | 413 | 679 | 364 | ||||
Total |
4,695 | 3,883 | 4,631 | 3,872 | ||||
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 Corporations overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the period 2008-2012. 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 1ARisk 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 2007, 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 registrants Annual Report on Form 10-K for 2006, which shows ExxonMobils 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 companys net interest. In addition,
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Form EIA-23 information does not include gas plant liquids. The difference between the oil reserves and gas reserves reported on EIA-23 and those reported in the registrants Annual Report on Form 10-K for 2006 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 Corporations 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. The volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.
4. Gross and Net Productive Wells
Year-End 2007 |
Year-End 2006 | |||||||||||||||
Oil |
Gas |
Oil |
Gas | |||||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net |
Gross |
Net | |||||||||
United States |
27,444 | 10,320 | 9,112 | 5,516 | 28,139 | 10,644 | 9,059 | 5,468 | ||||||||
Canada/South America |
5,714 | 5,092 | 6,211 | 3,240 | 5,816 | 5,039 | 5,942 | 3,088 | ||||||||
Europe |
1,599 | 477 | 1,188 | 472 | 1,780 | 528 | 1,300 | 509 | ||||||||
Africa |
853 | 350 | 16 | 6 | 823 | 348 | 12 | 5 | ||||||||
Asia Pacific/Middle East |
2,195 | 573 | 272 | 183 | 2,191 | 587 | 267 | 184 | ||||||||
Russia/Caspian |
119 | 24 | | | 82 | 17 | | | ||||||||
Total |
37,924 | 16,836 | 16,799 | 9,417 | 38,831 | 17,163 | 16,580 | 9,254 | ||||||||
The numbers of wells operated at year-end 2007 were 16,797 gross wells and 13,945 net wells. At year-end 2006, the numbers of operated wells were 16,914 gross wells and 13,988 net wells.
5. Gross and Net Developed Acreage
Year-End 2007 |
Year-End 2006 | |||||||
Gross |
Net |
Gross |
Net | |||||
(thousands of acres) | ||||||||
United States |
9,001 | 5,174 | 9,045 | 5,178 | ||||
Canada/South America |
5,391 | 2,337 | 5,502 | 2,331 | ||||
Europe |
10,730 | 4,194 | 10,678 | 4,418 | ||||
Africa |
1,889 | 729 | 1,842 | 717 | ||||
Asia Pacific/Middle East |
8,124 | 1,649 | 8,210 | 1,655 | ||||
Russia/Caspian |
531 | 116 | 531 | 116 | ||||
Total |
35,666 | 14,199 | 35,808 | 14,415 | ||||
Note: Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage.
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6. Gross and Net Undeveloped Acreage
Year-End 2007 |
Year-End 2006 | |||||||
Gross |
Net |
Gross |
Net | |||||
(thousands of acres) | ||||||||
United States |
9,104 | 5,539 | 9,917 | 6,062 | ||||
Canada/South America |
32,399 | 22,353 | 31,462 | 22,014 | ||||
Europe |
13,552 | 6,002 | 8,089 | 2,727 | ||||
Africa |
39,935 | 24,835 | 39,306 | 24,075 | ||||
Asia Pacific/Middle East |
20,904 | 13,167 | 13,466 | 7,462 | ||||
Russia/Caspian |
1,952 | 392 | 2,181 | 449 | ||||
Total |
117,846 | 72,288 | 104,421 | 62,789 | ||||
ExxonMobils 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 in Key Areas
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. 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. 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.
Venezuela
Until the recent Venezuelan Government actions described below, exploration and production activities were governed by Association Agreements containing risk/profit provisions negotiated with the national oil company or its affiliates. Association Agreements were awarded for a term not to
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exceed 39 years. These agreements had an exploration and a production phase. The term of production began after the exploration phase for a duration of 20 years with the possibility of an extension, so long as the total contract term did not exceed 39 years.
Strategic association agreements (such as the Cerro Negro project) were typically limited to those projects that required vertical integration for extra heavy crude oil. Contracts were awarded for 35 years. Significant amendments to the contract terms required Venezuelan congressional approval.
On February 26, 2007, President Chavez issued Law Decree N° 5200 which mandated the Conversion of the Orinoco Belt Association Agreements (Cerro Negro) and Oil Profit Sharing Agreements (La Ceiba) into Mixed Enterprises (the Nationalization Decree). The Nationalization Decree further ordered the transfer of operations to PdVSA Petroleos, S. A. (PdVSA) by April 30, 2007. The ExxonMobil affiliates in Venezuela were unable to reach agreement to migrate to a Mixed Enterprise by June 26, 2007, as required by the Nationalization Decree. Assets were expropriated on June 27, 2007. On September 6, 2007, the ExxonMobil affiliates filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes against Venezuela. ExxonMobil also has 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.
Refer to the relevant portion of Note 15: Litigation and Other Contingencies of the Financial Section of this report for additional information.
EUROPE
Germany
Exploration concessions are granted for an initial maximum period of five years with possible extensions of up to three years for an indefinite period. 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
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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. ExxonMobils licenses issued in 2005 as part of the 23rd licensing round have an initial term of four years with a second term extension of four years and a final term of 18 years. There is a mandatory relinquishment of 50-percent of the acreage after the initial term and of all acreage that is not covered by a development plan at the end of the second term.
AFRICA
Angola
Exploration and production activities are governed by production sharing agreements with an initial exploration term of four years and an optional second phase of two to three years. The production period is for 25 years, and agreements generally provide for a negotiated extension.
Cameroon
Exploration and production activities are governed by various agreements negotiated with the national oil company and the government of Cameroon. Exploration permits are granted for terms from four to 16 years and are generally renewable for multiple periods up to four years each. Upon commercial discovery, mining concessions are issued for a period of 25 years with one 25-year extension.
Chad
Exploration permits are issued for a period of five years, and are renewable for one or two further five-year periods. The terms and conditions of the permits, including relinquishment obligations, are specified in a negotiated convention. The production term is for 30 years and may be extended at the discretion of the government. In May 2007, Chad enacted a new Petroleum Code which would govern new acquisitions.
Equatorial Guinea
Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines, Industry and Energy. The exploration periods are for ten to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude oil is 30 years while the production period for gas is 50 years. A new Hydrocarbons Law was enacted in November 2006. Under the new law, the exploration terms for new production sharing contracts are expected to be four to five years with a maximum of two one-year extensions, unless the Ministry agrees otherwise.
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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 years notice.
OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for onshore or offshore location and are renewable, upon 12 months written notice, for another period of 20 years. OMLs not held by NNPC are also subject to a mandatory 50-percent relinquishment after the first ten years of their duration.
ASIA PACIFIC / MIDDLE EAST
Australia
Exploration and production activities are conducted offshore and are governed by Federal legislation. Exploration permits are granted for an initial term of six years with two possible five-year renewal periods. A 50-percent relinquishment of remaining area is mandatory at the end of each renewal period. 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.
10
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 production sharing contracts negotiated with the national oil company. The more recent contracts 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 companys 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.
Papua New Guinea
Exploration and production activities are governed by the Oil and Gas Act. Petroleum Prospecting licenses are granted for an initial term of six years with a five-year extension possible (an additional extension of three years is possible in certain circumstances). Generally, a 50-percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Petroleum Development licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Ministers 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 Ministers 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
Production sharing agreements (PSAs) negotiated with the government entitle the company to participate in exploration operations within a designated area during the exploration period. In the event of a commercial oil discovery, the company is entitled to proceed with development and production operations during the development period. The length of these periods and other specific terms are negotiated prior to executing the PSA. Existing production operations have a development period extending 20 years from first commercial declaration made in November 1985 for the Marib
11
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 parties are now in arbitration over the validity of the extension.
Thailand
The Petroleum Act of 1971 allows production under ExxonMobils 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 Companys 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.
Kazakhstan
Onshore: Exploration and production activities are governed by the production license, exploration license and joint venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993.
Offshore: Exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period was six years followed by separate appraisal periods for each discovery. The production period for each discovery, which includes development, is for 20 years from the date of declaration of commerciality with the possibility of two ten-year extensions.
Russia
Terms for ExxonMobils 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.
12
8. Number of Net Productive and Dry Wells Drilled
2007 |
2006 |
2005 | ||||
A. Net Productive Exploratory Wells Drilled |
||||||
United States |
12 | 10 | 13 | |||
Canada/South America |
1 | 3 | 1 | |||
Europe |
2 | 2 | 4 | |||
Africa |
2 | 4 | 5 | |||
Asia Pacific/Middle East |
1 | 2 | 1 | |||
Russia/Caspian |
1 | | | |||
Total |
19 | 21 | 24 | |||
B. Net Dry Exploratory Wells Drilled |
||||||
United States |
8 | 5 | 5 | |||
Canada/South America |
1 | 1 | | |||
Europe |
2 | 2 | 1 | |||
Africa |
4 | 4 | 5 | |||
Asia Pacific/Middle East |
1 | | 1 | |||
Russia/Caspian |
| | 1 | |||
Total |
16 | 12 | 13 | |||
C. Net Productive Development Wells Drilled |
||||||
United States |
451 | 552 | 537 | |||
Canada/South America |
377 | 373 | 272 | |||
Europe |
16 | 22 | 19 | |||
Africa |
43 | 64 | 61 | |||
Asia Pacific/Middle East |
26 | 25 | 50 | |||
Russia/Caspian |
4 | 5 | 7 | |||
Total |
917 | 1,041 | 946 | |||
D. Net Dry Development Wells Drilled |
||||||
United States |
15 | 5 | 8 | |||
Canada/South America |
| 1 | 2 | |||
Europe |
3 | 4 | 2 | |||
Africa |
1 | 1 | | |||
Asia Pacific/Middle East |
| | 2 | |||
Russia/Caspian |
| | | |||
Total |
19 | 11 | 14 | |||
Total number of net wells drilled |
971 | 1,085 | 997 | |||
9. Present Activities
A. Wells Drilling
Year-End 2007 |
Year-End 2006 | |||||||
Gross |
Net |
Gross |
Net | |||||
United States |
118 | 65 | 214 | 109 | ||||
Canada/South America |
187 | 125 | 226 | 183 | ||||
Europe |
41 | 6 | 55 | 11 | ||||
Africa |
30 | 11 | 50 | 19 | ||||
Asia Pacific/Middle East |
46 | 25 | 49 | 14 | ||||
Russia/Caspian |
36 | 5 | 33 | 6 | ||||
Total |
458 | 237 | 627 | 342 | ||||
13
B. Review of Principal Ongoing Activities in Key Areas
During 2007, ExxonMobils 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 ExxonMobils 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.
Some of the more significant ongoing activities are set forth below:
UNITED STATES
ExxonMobils year-end 2007 acreage holdings totaled 10.7 million net acres, of which 2.1 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.
During 2007, 459.7 net exploration and development wells were completed in the inland lower 48 states and 4.0 net exploration and development wells were completed offshore in the Pacific. Tight gas development continued in the Piceance Basin of Colorado and the Barnett Shale in Texas. Participation in Alaska production and development continued and a total of 16.7 net development wells were drilled. On Alaskas North Slope, activity continued on the Western Region Development Project (primarily the Orion field) with development drilling and engineering design for future facility expansions.
ExxonMobils net acreage in the Gulf of Mexico at year-end 2007 was 2.0 million acres. A total of 6.2 net exploration and development wells were completed during the year. Activity on the Thunder Horse project progressed in 2007, including work to rebuild and reinstall subsea equipment resulting from the 2005 listing incident and from subsea manifold failures. Start-up is anticipated in 2008.
The Golden Pass LNG regasification terminal in Texas is under construction. The terminal will have the capacity to supply two billion cubic feet of gas per day.
CANADA / SOUTH AMERICA
Canada
ExxonMobils year-end 2007 acreage holdings totaled 7.3 million net acres, of which 3.3 million net acres were offshore. A total of 373.8 net exploration and development wells were completed during the year.
Argentina
ExxonMobils net acreage totaled 0.2 million onshore acres at year-end 2007, and there were 4.3 net development wells completed during the year.
Venezuela
ExxonMobils 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 2007, with 5.2 net development and exploration wells drilled during the year.
14
Netherlands
ExxonMobils net interest in licenses totaled approximately 1.6 million acres at year-end 2007, of which 1.3 million acres were onshore. A total of 3.8 net exploration and development wells were completed during the year. The offshore L09 project was progressed while the Waddenzee project started up. The multi-year Groningen onshore project to renovate production clusters, install new compression to maintain capacity and extend field life continued. The project to redevelop the previously abandoned Schoonebeek oil field was approved in 2007.
Norway
ExxonMobils net interest in licenses at year-end 2007 totaled approximately 0.8 million acres, all offshore. ExxonMobil participated in 7.1 net exploration and development well completions in 2007. The Ormen Lange and Statfjord Late Life projects and the Njord Gas Export project started up in 2007. The Volve and Tyrihans projects are in progress.
United Kingdom
ExxonMobils net interest in licenses at year-end 2007 totaled approximately 1.6 million acres, all offshore. A total of 6.7 net development wells were completed during the year. Divestment of the mature Southern North Sea operated acreage was completed in 2007 (0.2 million acres). Significant projects progressed during the year include Starling, Caravel, and the St. Fergus gas processing facilities refurbishment. The South Hook LNG regasification terminal in Wales is anticipated to start up in 2008. The terminal will have the capacity to supply two billion cubic feet of gas per day into the natural gas grid.
AFRICA
Angola
ExxonMobils year-end 2007 acreage holdings totaled 0.7 million net offshore acres. 12.0 net exploration and development wells were completed during the year. On Block 15, development drilling continued on Kizomba A and Kizomba B. The Marimba development project, which was a tie-back to the Kizomba A FPSO, started up in 2007. The Kizomba C Mondo project started up in January 2008 and will be followed by the Kizomba C Saxi/Batuque project later in the year. A block-wide 3D seismic acquisition program began in the fourth quarter of 2007. On the non-operated Block 17, the Rosa project started up in June 2007. The Pazflor project was approved in 2007. Production operations continue at Kizomba A, Kizomba B, Xikomba and the non-operated Girassol, Jasmim and Dalia fields.
Cameroon
ExxonMobils acreage was 0.1 million net offshore acres.
Chad
ExxonMobils net year-end 2007 acreage holdings consisted of 3.3 million onshore acres, with 19.6 net exploration and development wells completed during the year. Production began from the Maikeri field.
Equatorial Guinea
ExxonMobils acreage totaled 0.2 million net offshore acres at year-end 2007, with 4.9 net exploration and development wells completed during the year.
15
Nigeria
ExxonMobils net acreage totaled 1.3 million offshore acres at year-end 2007, with 12.8 net exploration and development wells completed during the year. Production was initiated from the Erha North Expansion area in December 2007. Construction continued on the ExxonMobil-operated East Area Natural Gas Liquids II project with startup planned for 2008. A 3D seismic acquisition program was initiated to both enhance resolution of existing fields and target deeper formations. Major contracts on the Usan project are expected to be awarded in early 2008.
ASIA PACIFIC / MIDDLE EAST
Australia
ExxonMobils net year-end 2007 offshore acreage holdings totaled 2.4 million offshore acres. During 2007, a total of 9.3 net exploration and development wells were drilled. The Kipper gas project was approved for development in 2007.
Indonesia
At year-end 2007, ExxonMobil had 4.9 million net acres, 4.1 million acres offshore and 0.8 million acres onshore, with 0.5 net exploration wells completed during the year. Project activities continued on the Banyu Urip development in the Cepu Contract area.
Japan
ExxonMobils net offshore acreage was 36 thousand acres at year-end 2007.
Malaysia
ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore Malaysia at year-end 2007. During the year, a total of 3.5 net development wells were completed. Infill drilling wells were successfully completed at the Tabu B and Angsi platforms. Project-related drilling activity was completed at Tabu B and is currently ongoing at Tabu A. Project work continued on the Jerneh B platform installation.
Papua New Guinea
A total of 0.5 million net onshore acres were held by ExxonMobil at year-end 2007, with 1.3 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)
In addition, ExxonMobils Al Khaleej Gas (AKG) Phase 1 project supplied pipeline gas to domestic industrial customers. The AKG facilities add sales gas capacity of up to 750 mcfd (millions of cubic feet per day) and produces 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.
16
At the end of 2007, 70 (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 2007, ExxonMobil had 1.1 million net acres, 1.0 million acres onshore and 0.1 million acres offshore. During 2007, 8.2 net development and exploration wells were completed.
Qatar LNG capacity volumes at year-end 2007 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 2006 production commenced at RL II train 5, with the offshore facilities completed in January 2007. 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, 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
ExxonMobils net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end.
Thailand
ExxonMobils net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2007, with a total of 0.1 net development wells completed during the year.
United Arab Emirates
ExxonMobils net acreage in the Abu Dhabi oil concessions was 0.6 million acres at year-end 2007, of which 0.4 million acres were onshore and 0.2 million acres offshore. During the year, a total of 5.2 net development and exploration wells were completed. During 2007, work progressed on multiple field development projects, both onshore and offshore, to sustain and increase oil production capacity.
RUSSIA / CASPIAN
Azerbaijan
At year-end 2007, ExxonMobils net acreage, located in the Caspian Sea offshore of Azerbaijan, totaled 60 thousand acres. At the Azeri-Chirag-Gunashli field, 0.9 net development wells were completed and production ramp-up continued. Construction continued on the Phase 3 Deep Water Gunashli project with production start up anticipated in 2008.
Kazakhstan
ExxonMobils net acreage totaled 0.2 million acres onshore and 0.2 million acres offshore at year-end 2007, with 0.9 net exploration and development wells completed during 2007. Initial oil production from the first expansion at Tengiz was achieved in 2007 with activities ongoing to complete the project. Construction of the initial phase of the Kashagan field continued during 2007.
17
Russia
ExxonMobils net acreage holdings at year-end 2007 were 0.1 million acres, all offshore. A total of 3.0 net development wells were completed in the Chayvo field during the year and Phase 1 drilling activities are continuing. Full-field production (Phase 1) began in the fourth quarter 2006. Phase 1 facilities include an offshore platform, onshore drill site for extended-reach drilling to offshore oil zones, an onshore processing plant, an oil pipeline from Sakhalin Island to the Russian mainland, a mainland terminal and an offshore loading buoy for shipment of oil by tanker.
WORLDWIDE EXPLORATION
At year-end 2007, exploration activities were underway in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 45 million net acres were held at year-end 2007, and 1.0 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 1.8 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 248,300 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 a day, producing 150 million barrels of crude bitumen a year. This represents recovery capability of about 93 percent of the crude bitumen contained in the mined oil sands.
18
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 addition in high-temperature, high-pressure, hydrocracking vessels. These processes remove carbon and sulfur and reformulate the crude into a low viscosity, low sulfur, high-quality synthetic crude oil product. In 2007, this upgrading process yielded 0.843 barrels of synthetic crude oil per barrel of crude bitumen. In 2007 about 38 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 62 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 Limiteds 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities was about $3.4 billion at year-end 2007.
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 160 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 2007 was equivalent to 694 million barrels of synthetic crude oil. Imperials 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.
In 2007, the Alberta government proposed changes to the generic oil sands royalty regime beginning in 2009. The Syncrude Joint Venture owners have a Crown Agreement with the Province of Alberta that codifies the royalty rates through December 31, 2015. The Syncrude Joint Venture owners are in discussions with the Alberta government to determine if an amended agreement can be negotiated that would transition Syncrude to the new generic royalty regime before 2016.
19
ExxonMobil Share of Net Proven Syncrude Reserves(1)
Synthetic Crude Oil |
|||||||||
Base Mine and North Mine |
Aurora Mine |
Total |
|||||||
(millions of barrels) | |||||||||
January 1, 2007 |
199 | 519 | 718 | ||||||
Revision of previous estimate |
| | | ||||||
Production |
(11 | ) | (13 | ) | (24 | ) | |||
December 31, 2007 |
188 | 506 | 694 | ||||||
(1) | Net reserves are the companys share of reserves after deducting royalties payable to the Province of Alberta. |
Syncrude Operating Statistics (total operation)
2007 |
2006 |
2005 |
2004 |
2003 | ||||||
Operating Statistics |
||||||||||
Total mined overburden (millions of cubic yards)(1) |
132.2 | 128.2 | 97.1 | 100.3 | 109.2 | |||||
Mined overburden to oil sands ratio(1) |
1.06 | 1.18 | 1.02 | 0.94 | 1.15 | |||||
Oil sands mined (millions of tons) |
221.0 | 195.5 | 168.0 | 188.0 | 168.0 | |||||
Average bitumen grade (weight percent) |
11.6 | 11.4 | 11.1 | 11.1 | 11.0 | |||||
Crude bitumen in mined oil sands (millions of tons) |
25.6 | 22.2 | 18.6 | 20.9 | 18.5 | |||||
Average extraction recovery (percent) |
91.8 | 90.3 | 89.1 | 87.3 | 88.6 | |||||
Crude bitumen production (millions of barrels)(2) |
132.5 | 111.6 | 94.2 | 103.3 | 92.3 | |||||
Average upgrading yield (percent) |
84.3 | 84.9 | 85.3 | 85.5 | 86.0 | |||||
Gross synthetic crude oil produced (millions of barrels) |
113.0 | 95.5 | 79.3 | 88.4 | 78.4 | |||||
ExxonMobil net share (millions of barrels)(3) |
24 | 21 | 19 | 22 | 19 |
(1) | Includes pre-stripping of mine areas and reclamation volumes. |
(2) | Crude bitumen production is equal to crude bitumen in mined oil sands multiplied by the average extraction recovery and the appropriate conversion factor. |
(3) | Reflects ExxonMobils 25 percent interest in production less applicable royalties payable to the Province of Alberta. |
On October 4, 2007, the Company received a proposed agreed order from the Texas Commission on Environmental Quality (TCEQ) relating to an alleged unauthorized air emission event at the Companys Baytown, Texas chemical plant on May 14, 2007. The TCEQ is seeking an administrative penalty of $118,675, and it has referred the matter to its litigation division. ExxonMobil disputes the penalty calculation methodology utilized by the TCEQ. Once this matter is accepted by the State Office for Administrative Hearings, the Company will have the opportunity to meet with the TCEQ to attempt to resolve the penalty calculation dispute.
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.
20
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].
Name |
Age as of 2008 |
Title (Held Office Since) | ||
R. W. Tillerson |
55 |
Chairman of the Board (2006) | ||
M. W. Albers |
51 |
Senior Vice President (2007) | ||
D. D. Humphreys |
60 |
Senior Vice President (2006) and Treasurer (2004) | ||
J. S. Simon |
64 |
Senior Vice President (2004) | ||
A. T. Cejka |
56 |
Vice President (2004) | ||
H. R. Cramer |
57 |
Vice President (1999) | ||
M. J. Dolan |
54 |
Vice President (2004) | ||
N. W. Duffin |
51 |
President, ExxonMobil Development Company (2007) | ||
M. E. Foster |
64 |
Vice President (2004) | ||
H. H. Hubble |
55 |
Vice PresidentInvestor Relations and Secretary (2004) | ||
A. J. Kelly |
50 |
Vice President (2007) | ||
S. R. LaSala |
63 |
Vice President and General Tax Counsel (2007) | ||
C. W. Matthews |
63 |
Vice President and General Counsel (1995) | ||
P. T. Mulva |
56 |
Vice President and Controller (2004) | ||
S. D. Pryor |
58 |
Vice President (2004) | ||
A. P. Swiger |
51 |
Vice President (2006) |
For at least the past five years, Messrs. Cramer, Humphreys, LaSala, Matthews, Mulva, Simon 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. Humphreys was Vice President and Controller and then Vice President and Treasurer before becoming Senior Vice President and Treasurer. Mr. Simon was President of ExxonMobil Refining & Supply Company before becoming Senior Vice President. Mr. LaSala was Associate General Tax Counsel before becoming Vice President and General Tax Counsel. Mr. Mulva was Vice PresidentInvestor Relations and Secretary before becoming Vice President and Controller.
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, 2007.
Esso Exploration and Production Chad Inc. |
Albers and Duffin | |||
Exxon Azerbaijan Caspian Sea Limited |
Swiger | |||
Exxon Azerbaijan Limited |
Swiger | |||
Exxon Chemical Arabia Inc. |
Dolan and Pryor | |||
ExxonMobil Chemical Company |
Dolan and Pryor | |||
ExxonMobil Development Company |
Albers, Duffin and Foster | |||
ExxonMobil Exploration Company |
Cejka | |||
ExxonMobil Fuels Marketing Company |
Cramer | |||
ExxonMobil Gas & Power Marketing Company |
Swiger | |||
ExxonMobil Lubricants & Petroleum Specialties Company |
Kelly | |||
ExxonMobil Production Company |
Foster and Swiger | |||
ExxonMobil Refining & Supply Company |
Dolan, Hubble, Pryor and Simon |
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.
21
PART II
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Reference is made to the Quarterly Information portion of the Financial Section of this report.
Issuer Purchases of Equity Securities for Quarter Ended December 31, 2007 | |||||||||
Period |
Total Number of Shares Purchased |
Average Price Paid per Share |
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs |
|||||
October, 2007 |
30,511,333 | 92.42 | 30,511,333 | ||||||
November, 2007 |
30,452,285 | 87.25 | 30,452,285 | ||||||
December, 2007 |
26,816,392 | 91.77 | 26,816,392 | ||||||
Total |
87,780,010 | 90.43 | 87,780,010 | (See note 1 | ) |
Note 1On 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. 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.
22
Item 6. Selected Financial Data.
Years Ended December 31, | |||||||||||||||
2007 |
2006 |
2005 |
2004 |
2003 | |||||||||||
(millions of dollars, except per share amounts) | |||||||||||||||
Sales and other operating revenue(1)(2) |
$ | 390,328 | $ | 365,467 | $ | 358,955 | $ | 291,252 | $ | 237,054 | |||||
(1) Sales-based taxes included. |
$ | 31,728 | $ | 30,381 | $ | 30,742 | $ | 27,263 | $ | 23,855 | |||||
(2) Includes amounts for purchases/sales contracts with the same counterparty for 2003-2005. | |||||||||||||||
Net income |
|||||||||||||||
Income from continuing operations |
$ | 40,610 | $ | 39,500 | $ | 36,130 | $ | 25,330 | $ | 20,960 | |||||
Cumulative effect of accounting change, net of income tax |
| | | | 550 | ||||||||||
Net income |
$ | 40,610 | $ | 39,500 | $ | 36,130 | $ | 25,330 | $ | 21,510 | |||||
Net income per common share |
|||||||||||||||
Income from continuing operations |
$ | 7.36 | $ | 6.68 | $ | 5.76 | $ | 3.91 | $ | 3.16 | |||||
Cumulative effect of accounting change, net of income tax |
| | | | 0.08 | ||||||||||
Net income |
$ | 7.36 | $ | 6.68 | $ | 5.76 | $ | 3.91 | $ | 3.24 | |||||
Net income per common share - assuming dilution |
|||||||||||||||
Income from continuing operations |
$ | 7.28 | $ | 6.62 | $ | 5.71 | $ | 3.89 | $ | 3.15 | |||||
Cumulative effect of accounting change, net of income tax |
| | | | 0.08 | ||||||||||
Net income |
$ | 7.28 | $ | 6.62 | $ | 5.71 | $ | 3.89 | $ | 3.23 | |||||
Cash dividends per common share | $ | 1.37 | $ | 1.28 | $ | 1.14 | $ | 1.06 | $ | 0.98 | |||||
Total assets | $ | 242,082 | $ | 219,015 | $ | 208,335 | $ | 195,256 | $ | 174,278 | |||||
Long-term debt | $ | 7,183 | $ | 6,645 | $ | 6,220 | $ | 5,013 | $ | 4,756 |
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
Reference is made to the section entitled Managements Discussion and Analysis of Financial Condition and Results of Operations in the Financial Section of this report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Reference is made to the section entitled Market Risks, Inflation and Other Uncertainties, excluding the part entitled Inflation and Other Uncertainties, in the Financial Section of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the following in the Financial Section of this report:
| Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 28, 2008, beginning with the section entitled Report of Independent Registered Public Accounting Firm and continuing through Note 18: Income, Sales-Based and Other Taxes; |
| Quarterly Information (unaudited); |
23
| Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited); and |
| Frequently Used Terms (unaudited). |
Financial Statement Schedules have been omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Managements Evaluation of Disclosure Controls and Procedures
As indicated in the certifications in Exhibit 31 of this report, the Corporations chief executive officer, principal financial officer and principal accounting officer have evaluated the Corporations disclosure controls and procedures as of December 31, 2007. Based on that evaluation, these officers have concluded that the Corporations 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 Commissions rules and forms.
Managements Report on Internal Control over Financial Reporting
Management, including the Corporations chief executive officer, principal financial officer and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporations financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporations internal control over financial reporting was effective as of December 31, 2007.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporations internal control over financial reporting as of December 31, 2007, 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 Corporations last fiscal quarter that materially affected, or are reasonably likely to materially affect, the Corporations internal control over financial reporting.
None.
24
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Incorporated by reference to the following from the registrants definitive proxy statement for the 2008 annual meeting of shareholders (the 2008 Proxy Statement):
| The section entitled Election of Directors; |
| The portion entitled Section 16(a) Beneficial Ownership Reporting Compliance of the section entitled Executive Compensation Tables; |
| The portion entitled Code of Ethics and Business Conduct of the section entitled Corporate Governance; and |
| The Audit Committee portion and the membership table of the portion entitled Board Meetings and Committees; Annual Meeting Attendance of the section entitled Corporate Governance. |
Item 11. Executive Compensation.
Incorporated by reference to the sections entitled Director Compensation, Compensation Committee Report, Compensation Discussion and Analysis and Executive Compensation Tables of the registrants 2008 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 registrants 2008 Proxy Statement.
Equity Compensation Plan Information
(a) | (b) | (c) | ||||
Plan Category |
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights |
Weighted- Average Exercise Price of Outstanding Options, Warrants and Rights (1) |
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans [Excluding Securities Reflected in Column (a)] | |||
Equity compensation plans approved by security holders |
81,590,508 (2)(3) | $40.82(3) | 171,550,342(3)(4)(5) | |||
Equity compensation plans not approved by security holders |
0 |
0 | 0 | |||
Total |
81,590,508 |
$40.82 |
171,550,342 |
(1) | The exercise price of each option reflected in this table is equal to the fair market value of the Companys common stock on the date the option was granted. The weighted-average price reflects five prior option grants that are still outstanding. |
(2) | Includes 73,630,135 options granted under the 1993 Incentive Program and 7,960,373 restricted stock units to be settled in shares. |
(3) | Does not include options that ExxonMobil assumed in the 1999 merger with Mobil Corporation. At year-end 2007, the number of securities to be issued upon exercise of outstanding options under Mobil Corporation plans was 6,658,578, and the weighted-average exercise price of such options was $30.78. No additional awards may be made under those plans. |
(4) | Available shares can be granted in the form of restricted stock, options, or other stock-based awards. Includes 170,695,142 shares available for award under the 2003 Incentive Program and 855,200 shares available for award under the 2004 Non-Employee Director Restricted Stock Plan. |
25
(5) | Under the 2004 Non-Employee Director Restricted Stock Plan approved by shareholders in May 2004, and the related standing resolution adopted by the Board, each non-employee director automatically receives 8,000 shares of restricted stock when first elected to the Board and, if the director remains in office, an additional 4,000 restricted shares each following year. Effective January 1, 2008, the annual share grant was changed from 4,000 to 2,500 restricted shares. While on the Board, each non-employee director receives the same cash dividends on restricted shares as a holder of regular common stock, but the director is not allowed to sell the shares. The restricted shares may be forfeited if the director leaves the Board early. |
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The registrant has concluded that it has no disclosable matters under Item 404(a) of Regulation S-K. Additional 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 registrants 2008 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 registrants 2008 Proxy Statement.
PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a) | (1) and (2) Financial Statements: |
See Table of Contents of the Financial Section of this report.
(a) | (3) Exhibits: |
See Index to Exhibits of this report.
26
TABLE OF CONTENTS | ||
28 | ||
29 | ||
30 | ||
32 | ||
Managements Discussion and Analysis of Financial Condition and Results of Operations |
||
33 | ||
34 | ||
34 | ||
34 | ||
35 | ||
37 | ||
41 | ||
41 | ||
42 | ||
42 | ||
Recently Issued Statements of Financial Accounting Standards |
43 | |
44 | ||
Managements Report on Internal Control Over Financial Reporting |
48 | |
48 | ||
Consolidated Financial Statements |
||
50 | ||
51 | ||
52 | ||
53 | ||
54 | ||
56 | ||
56 | ||
57 | ||
57 | ||
58 | ||
59 | ||
8. Property, Plant and Equipment and Asset Retirement Obligations |
59 | |
60 | ||
62 | ||
62 | ||
63 | ||
63 | ||
68 | ||
70 | ||
72 | ||
76 | ||
78 | ||
Supplemental Information on Oil and Gas Exploration and Production Activities |
80 | |
90 |
27
Earnings After Income Taxes |
Average Capital Employed |
Return on Average Capital Employed |
Capital and Exploration Expenditures | ||||||||||||||||||||
Financial |
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
2007 |
2006 | |||||||||||||||
(millions of dollars) | (percent) | (millions of dollars) | |||||||||||||||||||||
Upstream |
|||||||||||||||||||||||
United States |
$ | 4,870 | $ | 5,168 | $ | 14,026 | $ | 13,940 | 34.7 | 37.1 | $ | 2,212 | $ | 2,486 | |||||||||
Non-U.S. |
21,627 | 21,062 | 49,539 | 43,931 | 43.7 | 47.9 | 13,512 | 13,745 | |||||||||||||||
Total |
$ | 26,497 | $ | 26,230 | $ | 63,565 | $ | 57,871 | 41.7 | 45.3 | $ | 15,724 | $ | 16,231 | |||||||||
Downstream |
|||||||||||||||||||||||
United States |
$ | 4,120 | $ | 4,250 | $ | 6,331 | $ | 6,456 | 65.1 | 65.8 | $ | 1,128 | $ | 824 | |||||||||
Non-U.S. |
5,453 | 4,204 | 18,983 | 17,172 | 28.7 | 24.5 | 2,175 | 1,905 | |||||||||||||||
Total |
$ | 9,573 | $ | 8,454 | $ | 25,314 | $ | 23,628 | 37.8 | 35.8 | $ | 3,303 | $ | 2,729 | |||||||||
Chemical |
|||||||||||||||||||||||
United States |
$ | 1,181 | $ | 1,360 | $ | 4,748 | $ | 4,911 | 24.9 | 27.7 | $ | 360 | $ | 280 | |||||||||
Non-U.S. |
3,382 | 3,022 | 8,682 | 8,272 | 39.0 | 36.5 | 1,422 | 476 | |||||||||||||||
Total |
$ | 4,563 | $ | 4,382 | $ | 13,430 | $ | 13,183 | 34.0 | 33.2 | $ | 1,782 | $ | 756 | |||||||||
Corporate and financing |
(23 | ) | 434 | 26,451 | 27,891 | | | 44 | 139 | ||||||||||||||
Total |
$ | 40,610 | $ | 39,500 | $ | 128,760 | $ | 122,573 | 31.8 | 32.2 | $ | 20,853 | $ | 19,855 | |||||||||
See Frequently Used Terms for a definition and calculation of capital employed and return on average capital employed.
Operating |
2007 |
2006 | ||
(thousands of barrels daily) | ||||
Net liquids production |
||||
United States |
392 | 414 | ||
Non-U.S. |
2,224 | 2,267 | ||
Total |
2,616 | 2,681 | ||
(millions of cubic feet daily) | ||||
Natural gas production available for sale |
||||
United States |
1,468 | 1,625 | ||
Non-U.S. |
7,916 | 7,709 | ||
Total |
9,384 | 9,334 | ||
(thousands of oil-equivalent barrels daily) | ||||
Oil-equivalent production (1) |
4,180 | 4,237 | ||
(thousands of barrels daily) | ||||
Refinery throughput |
||||
United States |
1,746 | 1,760 | ||
Non-U.S. |
3,825 | 3,843 | ||
Total |
5,571 | 5,603 | ||
(thousands of barrels daily) | ||||
Petroleum product sales |
||||
United States |
2,717 | 2,729 | ||
Non-U.S. |
4,382 | 4,518 | ||
Total |
7,099 | 7,247 | ||
(thousands of metric tons) | ||||
Chemical prime product sales |
||||
United States |
10,855 | 10,703 | ||
Non-U.S. |
16,625 | 16,647 | ||
Total |
27,480 | 27,350 | ||
(1) | Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels. |
28
2007 |
2006 |
2005 |
2004 |
2003 |
||||||||||||||||
(millions of dollars, except per share amounts) | ||||||||||||||||||||
Sales and other operating revenue (1) (2) |
$ | 390,328 | $ | 365,467 | $ | 358,955 | $ | 291,252 | $ | 237,054 | ||||||||||
Earnings |
||||||||||||||||||||
Upstream |
$ | 26,497 | $ | 26,230 | $ | 24,349 | $ | 16,675 | $ | 14,502 | ||||||||||
Downstream |
9,573 | 8,454 | 7,992 | 5,706 | 3,516 | |||||||||||||||
Chemical |
4,563 | 4,382 | 3,943 | 3,428 | 1,432 | |||||||||||||||
Corporate and financing |
(23 | ) | 434 | (154 | ) | (479 | ) | 1,510 | ||||||||||||
Income from continuing operations |
$ | 40,610 | $ | 39,500 | $ | 36,130 | $ | 25,330 | $ | 20,960 | ||||||||||
Cumulative effect of accounting change, net of income tax |
| | | | 550 | |||||||||||||||
Net income |
$ | 40,610 | $ | 39,500 | $ | 36,130 | $ | 25,330 | $ | 21,510 | ||||||||||
Net income per common share |
||||||||||||||||||||
Income from continuing operations |
$ | 7.36 | $ | 6.68 | $ | 5.76 | $ | 3.91 | $ | 3.16 | ||||||||||
Net income per common share assuming dilution |
||||||||||||||||||||
Income from continuing operations |
$ | 7.28 | $ | 6.62 | $ | 5.71 | $ | 3.89 | $ | 3.15 | ||||||||||
Cumulative effect of accounting change, net of income tax |
| | | | 0.08 | |||||||||||||||
Net income |
$ | 7.28 | $ | 6.62 | $ | 5.71 | $ | 3.89 | $ | 3.23 | ||||||||||
Cash dividends per common share |
$ | 1.37 | $ | 1.28 | $ | 1.14 | $ | 1.06 | $ | 0.98 | ||||||||||
Net income to average shareholders equity (percent) |
34.5 | 35.1 | 33.9 | 26.4 | 26.2 | |||||||||||||||
Working capital |
$ | 27,651 | $ | 26,960 | $ | 27,035 | $ | 17,396 | $ | 7,574 | ||||||||||
Ratio of current assets to current liabilities |
1.47 | 1.55 | 1.58 | 1.40 | 1.20 | |||||||||||||||
Additions to property, plant and equipment |
$ | 15,387 | $ | 15,462 | $ | 13,839 | $ | 11,986 | $ | 12,859 | ||||||||||
Property, plant and equipment, less allowances |
$ | 120,869 | $ | 113,687 | $ | 107,010 | $ | 108,639 | $ | 104,965 | ||||||||||
Total assets |
$ | 242,082 | $ | 219,015 | $ | 208,335 | $ | 195,256 | $ | 174,278 | ||||||||||
Exploration expenses, including dry holes |
$ | 1,469 | $ | 1,181 | $ | 964 | $ | 1,098 | $ | 1,010 | ||||||||||
Research and development costs |
$ | 814 | $ | 733 | $ | 712 | $ | 649 | $ | 618 | ||||||||||
Long-term debt |
$ | 7,183 | $ | 6,645 | $ | 6,220 | $ | 5,013 | $ | 4,756 | ||||||||||
Total debt |
$ | 9,566 | $ | 8,347 | $ | 7,991 | $ | 8,293 | $ | 9,545 | ||||||||||
Fixed-charge coverage ratio (times) |
49.9 | 46.3 | 50.2 | 36.1 | 30.8 | |||||||||||||||
Debt to capital (percent) |
7.1 | 6.6 | 6.5 | 7.3 | 9.3 | |||||||||||||||
Net debt to capital (percent) (3) |
(24.0 | ) | (20.4 | ) | (22.0 | ) | (10.7 | ) | (1.2 | ) | ||||||||||
Shareholders equity at year end |
$ | 121,762 | $ | 113,844 | $ | 111,186 | $ | 101,756 | $ | 89,915 | ||||||||||
Shareholders equity per common share |
$ | 22.62 | $ | 19.87 | $ | 18.13 | $ | 15.90 | $ | 13.69 | ||||||||||
Weighted average number of common shares outstanding (millions) |
5,517 | 5,913 | 6,266 | 6,482 | 6,634 | |||||||||||||||
Number of regular employees at year end (thousands) (4) |
80.8 | 82.1 | 83.7 | 85.9 | 88.3 | |||||||||||||||
CORS employees not included above (thousands) (5) |
26.3 | 24.3 | 22.4 | 19.3 | 17.4 |
(1) | Sales and other operating revenue includes sales-based taxes of $31,728 million for 2007, $30,381 million for 2006, $30,742 million for 2005, $27,263 million for 2004 and $23,855 million for 2003. |
(2) | Sales and other operating revenue includes $30,810 million for 2005, $25,289 million for 2004 and $20,936 million for 2003 for purchases/sales contracts with the same counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies. |
(3) | Debt net of cash, excluding restricted cash. |
(4) | Regular employees are defined as active executive, management, professional, technical and wage employees who work full time or part time for the Corporation and are covered by the Corporations benefit plans and programs. |
(5) | CORS employees are employees of company-operated retail sites. |
29
Listed below are definitions of several of ExxonMobils 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 Corporations 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 Corporations strategic and financial objectives. Assets are divested when they are no longer meeting these objectives or are worth considerably more to others. Because of the regular nature of this activity, we believe it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
Cash flow from operations and asset sales |
2007 |
2006 |
2005 | ||||||
(millions of dollars) | |||||||||
Net cash provided by operating activities |
$ | 52,002 | $ | 49,286 | $ | 48,138 | |||
Sales of subsidiaries, investments and property, plant and equipment |
4,204 | 3,080 | 6,036 | ||||||
Cash flow from operations and asset sales |
$ | 56,206 | $ | 52,366 | $ | 54,174 | |||
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 ExxonMobils 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 ExxonMobils share of total debt and shareholders equity. Both of these views include ExxonMobils share of amounts applicable to equity companies, which the Corporation believes should be included to provide a more comprehensive measure of capital employed.
Capital employed |
2007 |
2006 |
2005 |
|||||||||
(millions of dollars) | ||||||||||||
Business uses: asset and liability perspective |
||||||||||||
Total assets |
$ | 242,082 | $ | 219,015 | $ | 208,335 | ||||||
Less liabilities and minority share of assets and liabilities |
||||||||||||
Total current liabilities excluding notes and loans payable |
(55,929 | ) | (47,115 | ) | (44,536 | ) | ||||||
Total long-term liabilities excluding long-term debt and equity of minority and preferred shareholders in affiliated companies |
(50,543 | ) | (45,905 | ) | (41,095 | ) | ||||||
Minority share of assets and liabilities |
(5,332 | ) | (4,948 | ) | (4,863 | ) | ||||||
Add ExxonMobil share of debt-financed equity company net assets |
3,386 | 2,808 | 3,450 | |||||||||
Total capital employed |
$ | 133,664 | $ | 123,855 | $ | 121,291 | ||||||
Total corporate sources: debt and equity perspective |
||||||||||||
Notes and loans payable |
$ | 2,383 | $ | 1,702 | $ | 1,771 | ||||||
Long-term debt |
7,183 | 6,645 | 6,220 | |||||||||
Shareholders equity |
121,762 | 113,844 | 111,186 | |||||||||
Less minority share of total debt |
(1,050 | ) | (1,144 | ) | (1,336 | ) | ||||||
Add ExxonMobil share of equity company debt |
3,386 | 2,808 | 3,450 | |||||||||
Total capital employed |
$ | 133,664 | $ | 123,855 | $ | 121,291 | ||||||
30
RETURN ON AVERAGE CAPITAL EMPLOYED
Return on average capital employed (ROCE) is a performance measure ratio. From the perspective of the business segments, ROCE is annual business segment earnings divided by average business segment capital employed (average of beginning and end-of-year amounts). These segment earnings include ExxonMobils share of segment earnings of equity companies, consistent with our capital employed definition, and exclude the cost of financing. The Corporations 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 managements performance and to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow-based, are used to make investment decisions.
Return on average capital employed |
2007 |
2006 |
2005 |
|||||||||
(millions of dollars) | ||||||||||||
Net income |
$ | 40,610 | $ | 39,500 | $ | 36,130 | ||||||
Financing costs (after tax) |
||||||||||||
Gross third-party debt |
(339 | ) | (264 | ) | (261 | ) | ||||||
ExxonMobil share of equity companies |
(204 | ) | (156 | ) | (144 | ) | ||||||
All other financing costs net |
268 | 499 | (35 | ) | ||||||||
Total financing costs |
(275 | ) | 79 | (440 | ) | |||||||
Earnings excluding financing costs |
$ | 40,885 | $ | 39,421 | $ | 36,570 | ||||||
Average capital employed |
$ | 128,760 | $ | 122,573 | $ | 116,961 | ||||||
Return on average capital employed corporate total |
31.8 | % | 32.2 | % | 31.3 | % |
31
2007 |
2006 | |||||||||||||||||||||
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Year |
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Year | |||||||||||||
Volumes |
||||||||||||||||||||||
(thousands of barrels daily) | ||||||||||||||||||||||
Production of crude oil and natural gas liquids |
2,746 | 2,668 | 2,537 | 2,517 | 2,616 | 2,698 | 2,702 | 2,647 | 2,678 | 2,681 | ||||||||||||
Refinery throughput |
5,705 | 5,279 | 5,582 | 5,717 | 5,571 | 5,548 | 5,407 | 5,756 | 5,698 | 5,603 | ||||||||||||
Petroleum product sales |
7,198 | 6,973 | 7,100 | 7,125 | 7,099 | 7,177 | 7,060 | 7,302 | 7,447 | 7,247 | ||||||||||||
(millions of cubic feet daily) | ||||||||||||||||||||||
Natural gas production available for sale |
10,114 | 8,733 | 8,283 | 10,414 | 9,384 | 11,175 | 8,754 | 8,139 | 9,301 | 9,334 | ||||||||||||
(thousands of oil-equivalent barrels daily) | ||||||||||||||||||||||
Oil-equivalent production (1) |
4,432 | 4,123 | 3,918 | 4,253 | 4,180 | 4,560 | 4,161 | 4,004 | 4,228 | 4,237 | ||||||||||||
(thousands of metric tons) | ||||||||||||||||||||||
Chemical prime product sales |
6,805 | 6,897 | 6,729 | 7,049 | 27,480 | 6,916 | 6,855 | 6,752 | 6,827 | 27,350 | ||||||||||||
Summarized financial data |
||||||||||||||||||||||
(millions of dollars) | ||||||||||||||||||||||
Sales and other operating revenue (2) |
$ | 84,174 | 95,059 | 99,130 | 111,965 | 390,328 | $ | 86,317 | 96,024 | 96,268 | 86,858 | 365,467 | ||||||||||
Gross profit (3) |
$ | 33,907 | 36,760 | 36,114 | 39,914 | 146,695 | $ | 33,428 | 37,668 | 37,117 | 33,764 | 141,977 | ||||||||||
Net income |
$ | 9,280 | 10,260 | 9,410 | 11,660 | 40,610 | $ | 8,400 | 10,360 | 10,490 | 10,250 | 39,500 | ||||||||||
Per share data |
||||||||||||||||||||||
(dollars per share) | ||||||||||||||||||||||
Net income per common share |
$ | 1.64 | 1.85 | 1.72 | 2.15 | 7.36 | $ | 1.38 | 1.74 | 1.79 | 1.77 | 6.68 | ||||||||||
Net income per common share assuming dilution |
$ | 1.62 | 1.83 | 1.70 | 2.13 | 7.28 | $ | 1.37 | 1.72 | 1.77 | 1.76 | 6.62 | ||||||||||
Dividends per common share |
$ | 0.32 | 0.35 | 0.35 | 0.35 | 1.37 | $ | 0.32 | 0.32 | 0.32 | 0.32 | 1.28 | ||||||||||
Common stock prices |
||||||||||||||||||||||
High |
$ | 76.35 | 86.58 | 93.66 | 95.27 | 95.27 | $ | 63.96 | 65.00 | 71.22 | 79.00 | 79.00 | ||||||||||
Low |
$ | 69.02 | 75.28 | 78.76 | 83.37 | 69.02 | $ | 56.42 | 56.64 | 61.63 | 64.84 | 56.42 |
(1) | Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels. |
(2) | Includes amounts for sales-based taxes. |
(3) | Gross profit equals sales and other operating revenue less estimated costs associated with products sold. |
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 566,565 registered shareholders of ExxonMobil common stock at December 31, 2007. At January 31, 2008, the registered shareholders of ExxonMobil common stock numbered 561,103.
On January 30, 2008, the Corporation declared a $0.35 dividend per common share, payable March 10, 2008.
32
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
2007 |
2006 |
2005 |
||||||||
(millions of dollars, except per share amounts) | |||||||||||
Net income (U.S. GAAP) |
|||||||||||
Upstream |
|||||||||||
United States |
$ | 4,870 | $ | 5,168 | $ | 6,200 | |||||
Non-U.S. |
21,627 | 21,062 | 18,149 | ||||||||
Downstream |
|||||||||||
United States |
4,120 | 4,250 | 3,911 | ||||||||
Non-U.S. |
5,453 | 4,204 | 4,081 | ||||||||
Chemical |
|||||||||||
United States |
1,181 | 1,360 | 1,186 | ||||||||
Non-U.S. |
3,382 | 3,022 | 2,757 | ||||||||
Corporate and financing |
(23 | ) | 434 | (154 | ) | ||||||
Net income |
$ | 40,610 | $ | 39,500 | $ | 36,130 | |||||
Net income per common share |
$ | 7.36 | $ | 6.68 | $ | 5.76 | |||||
Net income per common share assuming dilution |
$ | 7.28 | $ | 6.62 | $ | 5.71 | |||||
Special items included in net income |
|||||||||||
Non-U.S. Upstream |
|||||||||||
Gain on Dutch gas restructuring |
$ | | $ | | $ | 1,620 | |||||
U.S. Downstream |
|||||||||||
Allapattah lawsuit provision |
$ | | $ | | $ | (200 | ) | ||||
Non-U.S. Downstream |
|||||||||||
Sale of Sinopec shares |
$ | | $ | | $ | 310 | |||||
Non-U.S. Chemical |
|||||||||||
Sale of Sinopec shares |
$ | | $ | | $ | 150 | |||||
Joint venture litigation |
$ | | $ | | $ | 390 | |||||
Corporate and financing |
|||||||||||
Tax-related benefit |
$ | | $ | 410 | $ | |
33
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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; 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; and other factors discussed herein and in Item 1A of ExxonMobils 2007 Form 10-K.
The following discussion and analysis of ExxonMobils 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 Corporations accounting and financial reporting fairly reflect its straightforward business model involving the extracting, manufacturing and marketing of hydrocarbons and hydrocarbon-based products. The Corporations 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 89 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, ExxonMobils 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 worlds population is projected to grow to approximately 8 billion, more than 20 percent higher than todays level. 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 a primary energy demand increase of approximately 40 percent by 2030 versus 2005. The vast majority (~80 percent) of the increase is expected to occur in developing countries.
As demand rises, energy efficiency will become increasingly important, with the rate of improvement projected to increase. 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. A wide variety of energy sources will be required to meet increasing global demand. Oil, gas and coal are expected to remain the predominant energy sources with approximately 80 percent share of total energy. Oil and gas are projected to maintain close to a 60 percent share. These well-established fuel sources are the only ones with the versatility and scale to meet the majority of the worlds growing energy needs over the outlook period. Nuclear power will likely be a growing option to meet electricity needs. Among renewable energy sources, wind, solar and biofuels are anticipated to grow rapidly at about 9 percent per year, reflecting government subsidies and mandates. These energy sources are projected to reach approximately 2 percent of world energy by 2030, up from 0.5 percent currently.
Demand for liquid fuels is expected to grow at 1.3 percent per year from 2005 to 2030, primarily due to increasing transportation requirements, especially related to light- and heavy-duty vehicles. The global fleet of light-duty vehicles will increase significantly, with related demand partly offset by improvements in fuel economy. Natural gas and coal are projected to grow at 1.7 and 0.9 percent per year, respectively, driven by rising needs for electric power generation. The Corporation expects the liquefied natural gas (LNG) market to increase over 250 percent by 2030, with LNG imports helping to meet growing demand in Europe, North America and Asia. With equity positions in many of the largest remote gas accumulations in the world, the Corporation is positioned to benefit from its technological advances in gas liquefaction, transportation and regasification that enable distant gas supplies to reach markets economically.
The Corporation anticipates that the worlds oil and gas resource base will grow not only from new discoveries, but also from increases to known reserves. Technology will underpin these increases. The cost to develop 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 about $380 billion per year, or about $9.5 trillion (measured in 2006 dollars) in total for 2006-2030.
Upstream
ExxonMobil continues to maintain a large portfolio of development and exploration opportunities, which enables the Corporation to be selective, optimizing total profitability and mitigating overall political and technical risks. As future development projects bring new production online, the Corporation expects a shift in the geographic mix of its production volumes between now and 2012. Oil and natural gas output from West Africa, the Caspian, 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 38 percent of the Corporations production. By 2012, they are expected to generate about 50 percent of total volumes. The remainder of the Corporations production is expected to be sourced from established areas, including Europe, North America and Asia Pacific.
34
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 and LNG is expected to grow from about 30 percent to over 40 percent of the Corporations output between now and 2012. The Corporations overall volume capacity outlook, based on projects coming onstream as anticipated, is for production capacity to grow over the period 2008-2012. 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 under production sharing contracts and other factors described in Item 1A of ExxonMobils 2007 Form 10-K.
Downstream
ExxonMobils Downstream is a large, diversified business with marketing and refining complexes around the world. The Corporation has a strong presence in mature markets as well as in growing areas, such as the Asia Pacific region. The objective of ExxonMobils Downstream strategies is to position the Corporation to be the industry leader under a variety of market conditions. These strategies include maintaining best-in-class operations in all aspects of the business, maximizing value from leading-edge technology, capitalizing on integration with other ExxonMobil businesses, and providing quality, valued products and services to the Corporations customers.
The downstream industry environment remains very competitive. Refining margins have been relatively strong over the past few years. However, inflation-adjusted refining margins over the prior 20 years have declined at a rate of about 1 percent per year. The intense competition in the retail fuels market has similarly driven down inflation-adjusted margins by about 3 percent per year. Refining margins 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 IntercontinentalExchange). Prices for these commodities (crude and various products) 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.
ExxonMobil has an ownership interest in 38 refineries, located in 21 countries, with distillation capacity of 6.3 million barrels per day and lubricant basestock manufacturing capacity of about 140 thousand barrels per day. ExxonMobils fuels and lubes marketing business portfolios include operations around the world, serving a globally diverse customer base.
ExxonMobils Downstream capital expenditures are focused on selective and resilient investments. These investments capitalize on the Corporations 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 mid-2007, ExxonMobil along with our partners Saudi Aramco, Sinopec and the Fujian Province formed the only fully integrated refining, petrochemicals and fuels marketing venture with foreign participation in China. In addition, ExxonMobil successfully started up several projects that produce lower-sulfur motor fuels, including gasoline projects in Japan and diesel projects in North America and Europe, with additional start-ups planned for 2008.
Chemical
The strength of the global economy supported continued solid demand growth for petrochemicals in 2007. Strong economic and industrial production growth increased demand in Asia Pacific, particularly China. North American and European growth were moderate, similar to that of GDP. Overall the global supply/demand balance remained tight, supporting continued strong margins despite higher feedstock costs.
ExxonMobil benefited from continued operational excellence, as well as a portfolio of products that includes many of the largest-volume and highest-growth petrochemicals in the global economy. In addition to being a worldwide supplier of primary petrochemical products, ExxonMobil Chemical also has a diverse portfolio of less-cyclical business lines. Chemicals competitive advantages are achieved through its business mix, broad geographic coverage, investment discipline, integration of chemical capacity with large refining complexes or Upstream gas processing, advantaged feedstock capabilities, leading proprietary technology and product application expertise.
REVIEW OF 2007 AND 2006 RESULTS
2007 |
2006 |
2005 | |||||||
(millions of dollars) | |||||||||
Net income (U.S. GAAP) |
$ | 40,610 | $ | 39,500 | $ | 36,130 |
2007
Net income in 2007 of $40,610 million was the highest ever for the Corporation, 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. Earnings in 2007 were also at record levels for each business segment.
2006
Net income in 2006 of $39,500 million was up $3,370 million from 2005. Net income for 2006 included a $410 million gain from the recognition of tax benefits related to historical investments in non-U.S. assets.
35
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Upstream
2007 |
2006 |
2005 | |||||||
(millions of dollars) | |||||||||
Upstream |
|||||||||
United States |
$ | 4,870 | $ | 5,168 | $ | 6,200 | |||
Non-U.S. |
21,627 | 21,062 | 18,149 | ||||||
Total |
$ | 26,497 | $ | 26,230 | $ | 24,349 | |||
2007
Upstream earnings for 2007 totaled $26,497 million, an increase of $267 million from 2006. Higher liquids realizations were mostly offset by higher operating expenses and net unfavorable tax effects. Oil-equivalent production decreased 1 percent versus 2006, including the Venezuela expropriation, divestments, OPEC quota effects and price and spend impacts on volumes. Excluding these impacts, total oil-equivalent production increased by 1 percent. Liquids production of 2,616 kbd (thousands of barrels per day) decreased by 65 kbd from 2006. Production increases from new projects in West Africa and higher Russia volumes were offset by mature field decline and production sharing contract net interest reductions. Natural gas production of 9,384 mcfd (millions of cubic feet per day) 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.
2006
Upstream earnings for 2006 totaled $26,230 million, an increase of $1,881 million from 2005, including a $1,620 million gain related to the Dutch gas restructuring in 2005. Higher liquids and natural gas realizations were partly offset by higher operating expenses. Oil-equivalent production increased 4 percent versus 2005. Liquids production of 2,681 kbd increased by 158 kbd from 2005. Production increases from new projects in West Africa and increased Abu Dhabi volumes were partly offset by mature field decline, entitlement effects and divestment impacts. Natural gas production of 9,334 mcfd increased 83 mcfd from 2005. Higher volumes from projects in Qatar were partly offset by mature field decline. Earnings from U.S. Upstream operations for 2006 were $5,168 million, a decrease of $1,032 million. Earnings outside the U.S. for 2006 were $21,062 million, an increase of $2,913 million, including a $1,620 million gain related to the Dutch gas restructuring in 2005.
Downstream
2007 |
2006 |
2005 | |||||||
(millions of dollars) | |||||||||
Downstream |
|||||||||
United States |
$ | 4,120 | $ | 4,250 | $ | 3,911 | |||
Non-U.S. |
5,453 | 4,204 | 4,081 | ||||||
Total |
$ | 9,573 | $ | 8,454 | $ | 7,992 | |||
2007
Downstream earnings totaled $9,573 million, an increase of $1,119 million from 2006. Improved worldwide refining operations and higher gains on asset sales, primarily outside the U.S., were partly offset by lower refining margins. 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, with the decrease again due to divestments. U.S. Downstream earnings of $4,120 million decreased by $130 million. Non-U.S. Downstream earnings of $5,453 million were $1,249 million higher than 2006.
2006
Downstream earnings totaled $8,454 million, an increase of $462 million from 2005, including a $310 million gain for the 2005 Sinopec share sale and a special charge of $200 million related to the 2005 Allapattah lawsuit provision. Stronger worldwide refining and marketing margins were partly offset by lower refining throughput. Petroleum product sales of 7,247 kbd decreased from 7,519 kbd in 2005, primarily due to lower refining throughput and divestment impacts. Refinery throughput was 5,603 kbd compared with 5,723 kbd in 2005. U.S. Downstream earnings of $4,250 million increased by $339 million, including a 2005 special charge related to the Allapattah lawsuit provision. Non-U.S. Downstream earnings of $4,204 million were $123 million higher than 2005 earnings, which included a gain for the Sinopec share sale.
Chemical
2007 |
2006 |
2005 | |||||||
(millions of dollars) | |||||||||
Chemical |
|||||||||
United States |
$ | 1,181 | $ | 1,360 | $ | 1,186 | |||
Non-U.S. |
3,382 | 3,022 | 2,757 | ||||||
Total |
$ | 4,563 | $ | 4,382 | $ | 3,943 | |||
2007
Chemical earnings totaled $4,563 million, an increase of $181 million from 2006. Increased 2007 earnings were driven by higher sales volumes and favorable foreign exchange effects partly offset by lower margins. Prime product sales were 27,480 kt (thousands of metric tons), an increase of 130 kt. Prime product sales are total chemical product sales, including ExxonMobils 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 $1,181 million decreased by $179 million. Non-U.S. Chemical earnings of $3,382 million were $360 million higher than 2006.
36
2006
Chemical earnings totaled $4,382 million, an increase of $439 million from 2005, including a $390 million gain from the favorable resolution of joint venture litigation in 2005 and a $150 million gain for the 2005 Sinopec share sale. Increased 2006 earnings were driven by higher margins and increased sales volumes. Prime product sales were 27,350 kt, an increase of 573 kt. U.S. Chemical earnings of $1,360 million increased by $174 million. Non-U.S. Chemical earnings of $3,022 million were $265 million higher than 2005 earnings, which included gains from the favorable resolution of joint venture litigation and the Sinopec share sale.
Corporate and Financing
2007 |
2006 |
2005 |
|||||||||
(millions of dollars) | |||||||||||
Corporate and financing |
$ | (23 | ) | $ | 434 | $ | (154 | ) |
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.
2006
The corporate and financing segment contributed $434 million to earnings in 2006, up $588 million from 2005, primarily due to a $410 million gain from tax benefits related to historical investments in non-U.S. assets and higher interest income.
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
2007 |
2006 |
|||||||
(millions of dollars) | ||||||||
Net cash provided by/(used in) |
||||||||
Operating activities |
$ | 52,002 | $ | 49,286 | ||||
Investing activities |
(9,728 | ) | (14,230 | ) | ||||
Financing activities |
(38,345 | ) | (36,210 | ) | ||||
Effect of exchange rate changes |
1,808 | 727 | ||||||
Increase/(decrease) in cash and cash equivalents |
$ | 5,737 | $ | (427 | ) | |||
(Dec. 31) | ||||||||
Cash and cash equivalents |
$ | 33,981 | $ | 28,244 | ||||
Cash and cash equivalents restricted |
| 4,604 | ||||||
Total cash and cash equivalents |
$ | 33,981 | $ | 32,848 | ||||
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 3 and note 15).
Cash and cash equivalents were $28.2 billion at the end of 2006, comparable to the prior year, as a net reduction from operating, investing and financing activities was partly offset by $0.7 billion of positive foreign exchange effects from the weakening of the U.S. dollar in 2006. Including restricted cash and cash equivalents of $4.6 billion (see note 3 and note 15), total cash and cash equivalents were $32.8 billion at the end of 2006. Cash flows from operating, investing and financing activities are discussed below. For additional details, see the Consolidated Statement of Cash Flows.
Although the Corporation issues long-term debt from time to time 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 Corporations immediate needs is carefully controlled, both to optimize returns on cash balances, and to ensure that it is secure and readily available to meet the Corporations cash requirements.
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 Corporations existing oil and gas fields and without new projects, ExxonMobils 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 Corporations 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 Corporations cash flows are also highly dependent on crude oil and natural gas prices.
The Corporations financial strength, as evidenced by its AAA/Aaa debt rating, enables it to make large, long-term capital expenditures. Capital and exploration expenditures in 2007 were $20.9 billion, reflecting the Corporations continued active investment program. The Corporation expects spending in the 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 Corporations 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 Corporations 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.
37
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cash Flow from 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.
2006
Cash provided by operating activities totaled $49.3 billion in 2006, a $1.1 billion increase from 2005. The major source of funds was net income of $39.5 billion, adjusted for the noncash provision of $11.4 billion for depreciation and depletion, both of which increased. The net timing effects of receipts of notes and accounts receivable, payments of accounts and other payables and contributions to pension funds in 2006 provided a partial offset.
Cash Flow from Investing Activities
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.
2006
Cash used in investing activities totaled $14.2 billion in 2006, $4.0 billion higher than 2005. Spending for property, plant and equipment increased $1.6 billion. Proceeds from the sales of subsidiaries, investments and property, plant and equipment of $3.1 billion in 2006 decreased $3.0 billion, reflecting a lower level of asset sales and the absence of almost $1.4 billion from the sale of the Corporations interest in Sinopec in 2005.
Cash Flow from Financing Activities
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 ExxonMobils 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. Purchases may be increased, decreased or discontinued at any time without prior notice.
2006
Cash used in financing activities was $36.2 billion, an increase of $9.3 billion from 2005, reflecting a higher level of purchases of ExxonMobil shares. Dividend payments on common shares increased to $1.28 per share from $1.14 per share and totaled $7.6 billion, a payout of 19 percent. Total consolidated short-term and long-term debt increased $0.3 billion to $8.3 billion at year-end 2006.
Shareholders equity increased $2.7 billion in 2006, to $113.8 billion, reflecting $39.5 billion of net income reduced by distributions to ExxonMobil shareholders of $7.6 billion of dividends and $25.0 billion of purchases of shares of ExxonMobil stock to reduce shares outstanding. Shareholders equity, and net assets and liabilities, increased $2.8 billion, representing the foreign exchange translation effects of stronger foreign currencies at the end of 2006 on ExxonMobils operations outside the United States. Recognition of the Postretirement benefits reserves adjustment under Financial Accounting Standard No. 158 (see note 16) reduced shareholders equity by $6.5 billion.
During 2006, Exxon Mobil Corporation purchased 451 million shares of its common stock for the treasury at a gross cost of $29.6 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 6.6 percent from 6,133 million at the end of 2005 to 5,729 million at the end of 2006. Purchases were made in both the open market and through negotiated transactions.
38
Commitments
Set forth below is information about the outstanding commitments of the Corporations consolidated subsidiaries at December 31, 2007. It combines data from the Consolidated Balance Sheet and from individual notes to the Consolidated Financial Statements.
Payments Due by Period | ||||||||||||||
Commitments |
Note Reference Number |
2008 |
2009- 2012 |
2013 and Beyond |
Total | |||||||||
(millions of dollars) | ||||||||||||||
Long-term debt (1) |
13 | $ | | $ | 2,910 | $ | 4,273 | $ | 7,183 | |||||
Due in one year (2) |
318 | | | 318 | ||||||||||
Asset retirement obligations (3) |
8 | 307 | 1,182 | 3,652 | 5,141 | |||||||||
Pension and other postretirement obligations (4) |
16 | 1,392 | 3,654 | 7,851 | 12,897 | |||||||||
Operating leases (5) |
10 | 1,994 | 5,358 | 2,564 | 9,916 | |||||||||
Unconditional purchase obligations (6) |
15 | 490 | 1,497 | 778 | 2,765 | |||||||||
Take-or-pay obligations (7) |
956 | 2,851 | 2,369 | 6,176 | ||||||||||
Firm capital commitments (8) |
7,290 | 6,332 | 1,512 | 15,134 |
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 net unrecognized tax benefits totaling $4.5 billion as of December 31, 2007, 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:
(1) | Includes capitalized lease obligations of $409 million. |
(2) | The amount due in one year is included in notes and loans payable of $2,383 million (note 5). |
(3) | The discounted present value of upstream asset retirement obligations, primarily asset removal costs at the completion of field life. |
(4) | The amount by which the benefit obligations exceeded the fair value of fund assets for certain U.S. and non-U.S. pension and other postretirement plans at year end. The payments by period include expected contributions to funded pension plans in 2008 and estimated benefit payments for unfunded plans in all years. |
(5) | Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties. |
(6) | Unconditional purchase obligations (UPOs) are those long-term commitments that are noncancelable and that third parties have used to secure financing for the facilities that will provide the contracted goods or services. The undiscounted obligations of $2,765 million mainly pertain to pipeline throughput agreements and include $1,847 million of obligations to equity companies. The present value of the total commitments, which excludes imputed interest of $562 million, was $2,203 million. |
(7) | Take-or-pay obligations are noncancelable, long-term commitments for goods and services other than UPOs. The undiscounted obligations of $6,176 million mainly pertain to manufacturing supply, pipeline and terminaling agreements and include $1,526 million of obligations to equity companies. The present value of the total commitments, which excludes imputed interest of $1,308 million, totaled $4,868 million. |
(8) | Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $15.1 billion. These commitments were primarily associated with Upstream projects outside the U.S., of which $5.5 billion was associated with West African projects. The Corporation expects to fund the majority of these projects through internal cash flow. |
Guarantees
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2007, for $5,148 million, primarily relating to guarantees for notes, loans and performance under contracts (note 15). Included in this amount were guarantees by consolidated affiliates of $4,591 million, representing ExxonMobils share of obligations of certain equity companies. The below-mentioned guarantees are not reasonably likely to have a material effect on the Corporations financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Dec. 31, 2007 | |||||||||
Equity Company Obligations |
Other Third-Party Obligations |
Total | |||||||
(millions of dollars) | |||||||||
Total guarantees |
$ | 4,591 | $ | 557 | $ | 5,148 |
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MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financial Strength
On December 31, 2007, unused credit lines for short-term financing totaled approximately $5.7 billion (note 5).
The table below shows the Corporations fixed-charge coverage and consolidated debt-to-capital ratios. The data demonstrate the Corporations creditworthiness. Throughout this period, the Corporations long-term debt securities maintained the top credit rating from both Standard & Poors (AAA) and Moodys (Aaa), a rating it has sustained for 89 years.
2007 |
2006 |
2005 | ||||
Fixed-charge coverage ratio (times) |
49.9 | 46.3 | 50.2 | |||
Debt to capital (percent) |
7.1 | 6.6 | 6.5 | |||
Net debt to capital (percent) |
(24.0) | (20.4) | (22.0) | |||
Credit rating |
AAA/Aaa | AAA/Aaa | AAA/Aaa |
Management views the Corporations financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The Corporations sound financial position gives it the opportunity to access the worlds 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. The first judgment from the United States District Court for the District of Alaska in the amount of $5 billion was vacated by the United States Court of Appeals for the Ninth Circuit as being excessive under the Constitution. The second judgment in the amount of $4 billion was vacated by the Ninth Circuit panel without argument and sent back for the District Court to reconsider in light of the recent U.S. Supreme Court decision in Campbell v. State Farm. The most recent District Court judgment for punitive damages was for $4.5 billion plus interest and was entered in January 2004. The Corporation posted a $5.4 billion letter of credit. ExxonMobil and the plaintiffs appealed this decision to the Ninth Circuit, which ruled on December 22, 2006, that the award be reduced to $2.5 billion. On January 12, 2007, ExxonMobil petitioned the Ninth Circuit Court of Appeals for a rehearing en banc of its appeal. On May 23, 2007, with two dissenting opinions, the Ninth Circuit determined not to re-hear ExxonMobils appeal before the full court. ExxonMobil filed a petition for writ of certiorari to the U.S. Supreme Court on August 20, 2007. On October 29, 2007, the U.S. Supreme Court granted ExxonMobils petition for a writ of certiorari. Oral argument was held on February 27, 2008. While it is reasonably possible that a liability for punitive damages may have been incurred from the Exxon Valdez grounding, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.
In December 2000, a jury in the 15th Judicial Circuit Court of Montgomery County, Alabama, returned a verdict against the Corporation in a dispute over royalties in the amount of $88 million in compensatory damages and $3.4 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court in May 2001. In December 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and in November 2003, a state district court jury in Montgomery, Alabama, returned a verdict against Exxon Mobil Corporation. The verdict included $63.5 million in compensatory damages and $11.8 billion in punitive damages. In March 2004, the district court judge reduced the amount of punitive damages to $3.5 billion. ExxonMobil appealed the decision to the Alabama Supreme Court. On November 1, 2007, the Alabama Supreme Court reversed the trial courts fraud judgment and instructed the district court to enter judgment for ExxonMobil on the fraud claim, eliminating the punitive damage award. The Court also ruled in ExxonMobils favor on some of the disputed lease issues, reducing the compensatory award to $52 million plus interest. Following the Alabama Supreme Courts decision, an appeal bond was canceled and the collateral was subsequently released.
In 2001, a Louisiana state court jury awarded compensatory damages of $56 million and punitive damages of $1 billion to a landowner for damage caused by a third party that leased the property from the landowner. The third party provided pipe cleaning and storage services for the Corporation and other entities. The Louisiana Fourth Circuit Court of Appeals reduced the punitive damage award to $112 million in 2005. The Corporation appealed this decision to the Louisiana Supreme Court which, in March 2006, refused to hear the appeal. ExxonMobil has fully accrued and paid the compensatory and punitive damage awards. The Corporation appealed the punitive damage award to the U.S. Supreme Court, which on February 26, 2007, vacated the judgment and remanded the case to the Louisiana Fourth Circuit Court of Appeals for reconsideration in light of the recent U.S. Supreme Court decision in Williams v. Phillip Morris USA. On August 8, 2007, the Fourth Circuit issued its decision on remand and declined to reduce the punitive damage award. On November 16, 2007, the Louisiana Supreme Court denied ExxonMobils writ for review of the Fourth Circuits decision. ExxonMobil has appealed to the U.S. Supreme Court.
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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 Corporations 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 Venezuelas 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 PdVSAs or one of its affiliates 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 PdVSA, and on June 27, 2007, the government expropriated ExxonMobils 41.67 percent interest in the Cerro Negro Project.
To date, discussions with Venezuelan authorities have not resulted in an agreement on the amount of compensation to be paid to ExxonMobil. On September 6, 2007, ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes. 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 Corporations consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporations operations or financial condition. At the time the assets were expropriated, ExxonMobils remaining net book investment in Cerro Negro producing assets was about $750 million.
CAPITAL AND EXPLORATION EXPENDITURES
2007 |
2006 | |||||||||||
U.S. |
Non-U.S. |
U.S. |
Non-U.S. | |||||||||
(millions of dollars) | ||||||||||||
Upstream (1) |
$ | 2,212 | $ | 13,512 | $ | 2,486 | $ | 13,745 | ||||
Downstream |
1,128 | 2,175 | 824 | 1,905 | ||||||||
Chemical |
360 | 1,422 | 280 | 476 | ||||||||
Other |
44 | | 130 | 9 | ||||||||
Total |
$ | 3,744 | $ | 17,109 | $ | 3,720 | $ | 16,135 | ||||
(1) | Exploration expenses included. |
Capital and exploration expenditures in 2007 were $20.9 billion, reflecting the Corporations 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 $15.7 billion in 2007 was down 3 percent from 2006, mainly due to timing of project implementation and related expenditures. During the past three years, Upstream capital and exploration expenditures averaged $15.5 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 Downstream totaled $3.3 billion in 2007, an increase of $0.6 billion from 2006, as a result of new investment in China and higher environmental expenditures. Chemical 2007 capital expenditures of $1.8 billion were up $1.0 billion from 2006 due to increased investment in Singapore and China to meet Asia Pacific demand growth.
2007 |
2006 |
2005 |
||||||||||
(millions of dollars) | ||||||||||||
Income taxes |
$ | 29,864 | $ | 27,902 | $ | 23,302 | ||||||
Sales-based taxes |
31,728 | 30,381 | 30,742 | |||||||||
All other taxes and duties |
44,091 | 42,393 | 44,571 | |||||||||
Total |
$ | 105,683 | $ | 100,676 | $ | 98,615 | ||||||
Effective income tax rate |
44 | % | 43 | % | 41 | % |
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.
2006
Income, sales-based and all other taxes and duties totaled $100.7 billion in 2006, an increase of $2.1 billion or 2 percent from 2005. Income tax expense, both current and deferred, was $27.9 billion, $4.6 billion higher than 2005, reflecting higher pre-tax income in 2006. The effective tax rate was 43 percent in 2006, compared to 41 percent in 2005. During both periods, the Corporation continued to benefit from the favorable resolution of tax-related issues. Sales-based and all other taxes and duties of $72.8 billion in 2006 decreased $2.5 billion from 2005, reflecting the tax impact of net reporting of purchases and sales of inventory with the same counterparty, only partly offset by the effects of higher prices.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Expenditures
2007 |
2006 | |||||
(millions of dollars) | ||||||
Capital expenditures |
$ | 1,525 | $ | 1,081 | ||
Other expenditures |
2,272 | 2,127 | ||||
Total |
$ | 3,797 | $ | 3,208 | ||
Throughout ExxonMobils 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. ExxonMobils 2007 worldwide environmental expenditures for all such preventative and remediation steps, including ExxonMobils share of equity company expenditures, were about $3.8 billion. The total cost for such activities is expected to remain in this range in 2008 and 2009 (with capital expenditures approximately 45 percent of the total).
Environmental Liabilities
The Corporation accrues environmental liabilities when it is probable that obligations have been incurred and the amounts can be reasonably estimated. This policy applies to assets or businesses currently owned or previously disposed. ExxonMobil has accrued liabilities for probable environmental remediation obligations at various sites, including multiparty sites where the U.S. Environmental Protection Agency has identified ExxonMobil as one of the potentially responsible parties. The involvement of other financially responsible companies at these multiparty sites could mitigate ExxonMobils actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobils operations or financial condition. Consolidated company provisions made in 2007 for environmental liabilities were $432 million ($350 million in 2006) and the balance sheet reflects accumulated liabilities of $916 million as of December 31, 2007, and $864 million as of December 31, 2006.
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 ($113 million for 2007). Over time, the liabilities are accreted for the increase in their present value, with this effect included in expenses ($322 million in 2007). Consolidated company expenditures for asset retirement obligations in 2007 were $352 million and the ending balance of the obligations recorded on the balance sheet at December 31, 2007, totaled $5,141 million.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
Worldwide Average Realizations (1) |
2007 |
2006 |
2005 | ||||||
Crude oil and NGL ($/barrel) |
$ | 66.02 | $ | 58.34 | $ | 48.23 | |||
Natural gas ($/kcf) |
5.29 | 6.08 | 5.96 |
(1) | Consolidated subsidiaries. |
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, based on the 2007 worldwide production levels, a $1 per barrel change in the weighted-average realized price of oil would have approximately a $400 million annual after-tax effect on Upstream consolidated plus equity company earnings. Similarly, a $0.10 per kcf change in the worldwide average gas realization would have approximately a $200 million annual after-tax effect on Upstream consolidated plus equity company earnings. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil, taxes and other government take impacts, price adjustment lags in long-term gas contracts, and crude and gas production volumes. Accordingly, changes in benchmark prices for crude oil and natural gas only provide a broad indicator 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 Corporations 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 Corporations financial strength, including the AAA and Aaa ratings of its long-term debt securities by Standard & Poors and Moodys, 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 Corporations intersegment sales are crude oil produced by the Upstream and sold to the Downstream. Other intersegment sales include those between refineries and chemical plants related to raw materials, feedstocks and finished products.
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Although price levels of crude oil and natural gas may rise or fall significantly over the short to medium term due to political events, OPEC actions and other factors, industry economics over the long term will continue to be driven by market supply and demand. Accordingly, the Corporation tests the viability of all of its assets over a broad range of future prices. The Corporations 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. As a result, investments that would succeed only in highly favorable price environments are screened out of the investment plan.
The Corporation has had an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program involves a disciplined, regular review to ensure that all assets are contributing to the Corporations strategic and financial objectives. The result has been the creation of an efficient capital base and has meant that the Corporation has seldom been required to write down the carrying value of assets, even during periods of low commodity prices.
Risk Management
The Corporations size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporations 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 Corporations limited derivative activities pose no material credit or market risks to ExxonMobils operations, financial condition or liquidity. Note 12 summarizes the fair value of derivatives outstanding at year end and the gains or losses that have been recognized in net income.
The Corporation is exposed to changes in interest rates, primarily as a result of its short-term debt and long-term debt carrying floating interest rates. The impact of a 100-basis-point change in interest rates affecting the Corporations debt would not be material to earnings, cash flow or fair value. The Corporations cash balances exceeded total debt at year-end 2007 and 2006.
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 ExxonMobils 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 Corporations limited use of the above contracts are not material.
Inflation and Other Uncertainties
The general rate of inflation in most major countries of operation has been relatively low in recent years and the associated impact on costs has generally been countered by cost reductions from efficiency and productivity improvements. Increased global demand for certain services and materials has resulted in higher operating and capital costs in recent years. The Corporation continues to mitigate these effects through its economies of scale in global procurement and its efficient project management practices.
RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS
Fair Value Measurements
In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157 (FAS 157), Fair Value Measurements. FAS 157 defines fair value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measurements.
FAS 157 must be adopted by the Corporation no later than January 1, 2008, for all financial assets and liabilities that are measured at fair value and nonfinancial assets and liabilities that are remeasured at fair value at least annually. FAS 157 must be adopted no later than January 1, 2009, for nonfinancial assets and liabilities that are not remeasured at fair value at least annually. The Corporation does not expect the adoption of FAS 157 to have a material impact on the Corporations financial statements.
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, the FASB issued Statement No. 160 (FAS 160), Noncontrolling Interests in Consolidated Financial Statements an Amendment of ARB No. 51. FAS 160 changes the accounting and reporting for minority interests, which will be recharacterized as non-controlling interests and classified as a component of equity.
FAS 160 must be adopted by the Corporation no later than January 1, 2009. FAS 160 requires retrospective adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of FAS 160 will be applied prospectively. The Corporation does not expect the adoption FAS 160 to have a material impact on the Corporations financial statements.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Corporations accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The following summary provides further information about the critical accounting policies and the judgments that are made by the Corporation in the application of those policies.
Oil and Gas Reserves
Evaluations of oil and gas reserves are important to the effective management of Upstream assets. They are integral to making investment decisions about oil and gas properties such as whether development should proceed or enhanced recovery methods should be undertaken. Oil and gas reserve quantities are also used as the basis for calculating unit-of-production depreciation rates and for evaluating impairment. Oil and gas reserves include both proved and unproved reserves. Proved reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Unproved reserves are those with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that are more likely to be recovered than not.
The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessment, and detailed analysis of well information such as flow rates and reservoir pressure declines. The estimation of proved reserves is controlled by the Corporation through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior level geoscience and engineering professionals (assisted by a central reserves group with significant technical experience), culminating in reviews with and approval by senior management. Notably, the Corporation does not use specific quantitative reserve targets to determine compensation.
Key features of the reserves estimation process include:
| rigorous peer-reviewed technical evaluations and analysis of well and field performance information (such as flow rates and reservoir pressure declines) and |
| a requirement that management make significant funding commitments toward the development of the reserves prior to reporting as proved. |
Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.
Proved reserves can be further subdivided into developed and undeveloped reserves. The percentage of proved developed reserves has remained relatively stable over the past five years at over 60 percent of total proved reserves (including both consolidated and equity company reserves), indicating that proved reserves are consistently moved from undeveloped to developed status. Over time, these undeveloped reserves will be reclassified to the developed category as new wells are drilled, existing wells are recompleted and/or facilities to collect and deliver the production from existing and future wells are installed. Major development projects typically take two to four years from the time of recording proved reserves to the start of production from these reserves.
The year-end reserves volumes as well as the reserves change categories shown in the proved reserves tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. We understand that the use of December 31 prices and costs is intended to provide a point in time measure to calculate reserves and to enhance comparability between companies.
Regulations preclude the Corporation from showing in this document the reserves that are calculated in a manner that is consistent with the basis that the Corporation uses to make its investment decisions. The use of year-end prices for reserves estimation introduces short-term price volatility into the process, since annual adjustments are required based on prices occurring on a single day. The Corporation believes that this approach is inconsistent with the long-term nature of the upstream business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the Corporation and annual variations in reserves based on such year-end prices are not of consequence in how the business is actually managed.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in year-end prices and costs that are used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.
The Corporation uses the successful efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method. The Corporation uses this accounting policy instead of the full cost method because it provides a more timely accounting of the success or failure of the Corporations exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects.
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Impact of Oil and Gas Reserves on Depreciation. The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of upstream assets. It is the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods), applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. While the revisions the Corporation has made in the past are an indicator of variability, they have had a very small impact on the unit-of-production rates because they have been small compared to the large reserves base.
Impact of Oil and Gas Reserves and Prices on Testing for Impairment. Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
The Corporation performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the Corporation in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluation include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current operating losses.
In general, the Corporation does not view temporarily low oil and gas prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. On the supply side, industry production from mature fields is declining, but this is being offset by production from new discoveries and field developments. OPEC production policies also have an impact on world oil supplies. The demand side is largely a function of global economic growth. The relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Corporation performs make use of the Corporations price assumptions developed in the annual planning and budgeting process for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on individual field production profiles, which are updated annually. Cash flow estimates for impairment testing exclude the use of derivative instruments.
Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements. The standardized measure of discounted future cash flows is based on the year-end price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (FAS 69), Disclosure about Oil and Gas Producing Activities. Future prices used for any impairment tests will vary from the one used in the FAS 69 disclosure and could be lower or higher for any given year.
Suspended Exploratory Well Costs
The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether a project has made sufficient progress is a subjective area and requires careful consideration of the relevant facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells as of year-end 2007 are disclosed in note 9 to the financial statements.
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MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Consolidations
The Consolidated Financial Statements include the accounts of those subsidiaries that the Corporation controls. They also include the Corporations share of the undivided interest in certain upstream assets and liabilities. Amounts representing the Corporations percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in Investments, advances and long-term receivables; the Corporations share of the net income of these companies is included in the Consolidated Statement of Income caption Income from equity affiliates. The accounting for these non-consolidated companies is referred to as the equity method of accounting.
Majority ownership is normally the indicator of control that is the basis on which subsidiaries are consolidated. However, certain factors may indicate that a majority-owned investment is not controlled and therefore should be accounted for using the equity method of accounting. These factors occur where the minority shareholders are granted by law or by contract substantive participating rights. These include the right to approve operating policies, expense budgets, financing and investment plans and management compensation and succession plans.
Additional disclosures of summary balance sheet and income information for those subsidiaries accounted for under the equity method of accounting can be found in note 6.
Investments in companies that are partially owned by the Corporation are integral to the Corporations operations. In some cases they serve to balance worldwide risks and in others they provide the only available means of entry into a particular market or area of interest. The other parties who also have an equity interest in these companies are either independent third parties or host governments that share in the business results according to their percentage ownership. The Corporation does not invest in these companies in order to remove liabilities from its balance sheet. In fact, the Corporation has long been on record supporting an alternative accounting method that would require each investor to consolidate its percentage share of all assets and liabilities in these partially owned companies rather than only its percentage in the net equity. This method of accounting for investments in partially owned companies is not permitted by GAAP except where the investments are in the direct ownership of a share of upstream assets and liabilities. However, for purposes of calculating return on average capital employed, which is not covered by GAAP standards, the Corporation includes its share of debt of these partially owned companies in the determination of average capital employed.
Pension Benefits
The Corporation and its affiliates sponsor approximately 100 defined benefit (pension) plans in about 50 countries. The funding arrangement for each plan depends on the prevailing practices and regulations of the countries where the Corporation operates. Pension and Other Postretirement Benefits (note 16) provides details on pension obligations, fund assets and pension expense.
Some of these plans (primarily non-U.S.) provide pension benefits that are paid directly by their sponsoring affiliates out of corporate cash flow rather than a separate pension fund. Book reserves are established for these plans because tax conventions and regulatory practices do not encourage advance funding. The portion of the pension cost attributable to employee service is expensed as services are rendered. The portion attributable to the increase in pension obligations due to the passage of time is expensed over the term of the obligations, which ends when all benefits are paid. The primary difference in pension expense for unfunded versus funded plans is that pension expense for funded plans also includes a credit for the expected long-term return on fund assets.
For funded plans, including many in the United States, pension obligations are financed in advance through segregated assets or insurance arrangements. These plans are managed in compliance with the requirements of governmental authorities and meet or exceed required funding levels as measured by relevant actuarial and government standards at the mandated measurement dates. In determining liabilities and required contributions, these standards often require approaches and assumptions that differ from those used for accounting purposes.
The Corporation will continue to make contributions to these funded plans as necessary. All defined-benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
Pension accounting requires explicit assumptions regarding, among others, the long-term expected earnings rate on fund assets, the discount rate for the benefit obligations and the long-term rate for future salary increases. Pension assumptions are reviewed annually by outside actuaries and senior management. These assumptions are adjusted only as appropriate to reflect changes in market rates and outlook. For example, the long-term expected earnings rate on U.S. pension plan assets in 2007 was 9.0 percent. This compares to an actual rate of return over the past decade of 10 percent. The Corporation establishes the long-term expected rate of return by developing a forward-looking, long-term return assumption for each pension fund asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. A worldwide reduction of 0.5 percent in the long-term rate of return on assets would increase annual pension expense by approximately $140 million before tax.
46
Differences between actual returns on fund assets and the long-term expected return are not recognized in pension expense in the year that the difference occurs. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees.
Litigation Contingencies
A variety of claims have been made against the Corporation and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The status of significant claims is summarized in note 15.
GAAP requires that liabilities for contingencies be recorded when it is probable that a liability has been incurred by the date of the balance sheet and that the amount can be reasonably estimated. These amounts are not reduced by amounts that may be recovered under insurance or claims against third parties, but undiscounted receivables from insurers or other third parties may be accrued separately. The Corporation revises such accruals in light of new information. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss.
Significant management judgment is required related to contingent liabilities and the outcome of litigation because both are difficult to predict. However, the Corporation has been successful in defending litigation in the past. Payments have not had a materially adverse effect on operations or financial condition. In the Corporations experience, large claims often do not result in large awards. Large awards are often reversed or substantially reduced as a result of appeal or settlement.
Tax Contingencies
The Corporation is subject to income taxation in many jurisdictions around the world. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
GAAP requires recognition and measurement of uncertain tax positions that the Corporation has taken or expects to take in its income tax returns. The benefit of an uncertain tax position can only be recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken in an income tax return and the amount recognized in the financial statements. The Corporations unrecognized tax benefits and a description of open tax years are summarized in note 18.
Foreign Currency Translation
The method of translating the foreign currency financial statements of the Corporations international subsidiaries into U.S. dollars is prescribed by GAAP. Under these principles, it is necessary to select the functional currency of these subsidiaries. The functional currency is the currency of the primary economic environment in which the subsidiary operates. Management selects the functional currency after evaluating this economic environment. Downstream and Chemical operations use the local currency, except in countries with a history of high inflation (primarily in Latin America) and Singapore, which uses the U.S. dollar because it predominantly sells into the U.S. dollar export market. Upstream operations also use the local currency as the functional currency, except where crude and natural gas production is predominantly sold in the export market in U.S. dollars. Operations using the U.S. dollar as their functional currency include Malaysia, Indonesia, Angola, Nigeria, Equatorial Guinea, Russia and the Middle East.
Factors considered by management when determining the functional currency for a subsidiary include: the currency used for cash flows related to individual assets and liabilities; the responsiveness of sales prices to changes in exchange rates; the history of inflation in the country; whether sales are into local markets or exported; the currency used to acquire raw materials, labor, services and supplies; sources of financing; and significance of intercompany transactions.
47
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Corporations chief executive officer, principal financial officer, and principal accounting officer, is responsible for establishing and maintaining adequate internal control over the Corporations financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Exxon Mobil Corporations internal control over financial reporting was effective as of December 31, 2007.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the Corporations internal control over financial reporting as of December 31, 2007, as stated in their report included in the Financial Section of this report.
Rex W. Tillerson | Donald D. Humphreys | Patrick T. Mulva | ||
Chief Executive Officer | Sr. Vice President and Treasurer (Principal Financial Officer) |
Vice President and Controller (Principal Accounting Officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Exxon Mobil Corporation:
In our opinion, the consolidated financial statements listed under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiaries at December 31, 2007, and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Corporations management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Managements Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Corporations internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
48
As discussed in Note 2 to the consolidated financial statements, the Corporation changed its method of accounting for uncertainty in income taxes in 2007.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Dallas, Texas
February 28, 2008
49
CONSOLIDATED STATEMENT OF INCOME
Note Reference Number |
2007 |
2006 |
2005 | ||||||||
(millions of dollars) | |||||||||||
Revenues and other income |
|||||||||||
Sales and other operating revenue (1) (2) |
$ | 390,328 | $ | 365,467 | $ | 358,955 | |||||
Income from equity affiliates |
6 | 8,901 | 6,985 | 7,583 | |||||||
Other income |
5,323 | 5,183 | 4,142 | ||||||||
Total revenues and other income |
$ | 404,552 | $ | 377,635 | $ | 370,680 | |||||
Costs and other deductions |
|||||||||||
Crude oil and product purchases |
$ | 199,498 | $ | 182,546 | $ | 185,219 | |||||
Production and manufacturing expenses |
31,885 | 29,528 | 26,819 | ||||||||
Selling, general and administrative expenses |
14,890 | 14,273 | 14,402 | ||||||||
Depreciation and depletion |
12,250 | 11,416 | 10,253 | ||||||||
Exploration expenses, including dry holes |
1,469 | 1,181 | 964 | ||||||||
Interest expense |
400 | 654 | 496 | ||||||||
Sales-based taxes (1) |
18 | 31,728 | 30,381 | 30,742 | |||||||
Other taxes and duties |
18 | 40,953 | 39,203 | 41,554 | |||||||
Income applicable to minority and preferred interests |
1,005 | 1,051 | 799 | ||||||||
Total costs and other deductions |
$ | 334,078 | $ | 310,233 | $ | 311,248 | |||||
Income before income taxes |
$ | 70,474 | $ | 67,402 | $ | 59,432 | |||||
Income taxes |
18 | 29,864 | 27,902 | 23,302 | |||||||
Net income |
$ | 40,610 | $ | 39,500 | $ | 36,130 | |||||
Net income per common share (dollars) |
11 | $ | 7.36 | $ | 6.68 | $ | 5.76 | ||||
Net income per common share assuming dilution (dollars) |
11 | $ | 7.28 | $ | 6.62 | $ | 5.71 |
(1) | Sales and other operating revenue includes sales-based taxes of $31,728 million for 2007, $30,381 million for 2006 and $30,742 million for 2005. |
(2) | Sales and other operating revenue includes $30,810 million for 2005 for purchases/sales contracts with the same counterparty. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies. |
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
50
Note Reference Number |
Dec. 31 2007 |
Dec. 31 2006 |
||||||||
(millions of dollars) | ||||||||||
Assets |
||||||||||
Current assets |
||||||||||
Cash and cash equivalents |
$ | 33,981 | $ | 28,244 | ||||||
Cash and cash equivalents restricted |
3, 15 | | 4,604 | |||||||
Marketable securities |
519 | | ||||||||
Notes and accounts receivable, less estimated doubtful amounts |
5 | 36,450 | 28,942 | |||||||
Inventories |
||||||||||
Crude oil, products and merchandise |
3 | 8,863 | 8,979 | |||||||
Materials and supplies |
2,226 | 1,735 | ||||||||
Prepaid taxes and expenses |
3,924 | 3,273 | ||||||||
Total current assets |
$ | 85,963 | $ | 75,777 | ||||||
Investments, advances and long-term receivables |
7 | 28,194 | 23,237 | |||||||
Property, plant and equipment, at cost, less accumulated depreciation and depletion |
8 | 120,869 | 113,687 | |||||||
Other assets, including intangibles, net |
7,056 | 6,314 | ||||||||
Total assets |
$ | 242,082 | $ | 219,015 | ||||||
Liabilities |
||||||||||
Current liabilities |
||||||||||
Notes and loans payable |
5 | $ | 2,383 | $ | 1,702 | |||||
Accounts payable and accrued liabilities |
5 | 45,275 | 39,082 | |||||||
Income taxes payable |
10,654 | 8,033 | ||||||||
Total current liabilities |
$ | 58,312 | $ | 48,817 | ||||||
Long-term debt |
13 | 7,183 | 6,645 | |||||||
Postretirement benefits reserves |
16 | 13,278 | 13,931 | |||||||
Deferred income tax liabilities |
18 | 22,899 | 20,851 | |||||||
Other long-term obligations |
14,366 | 11,123 | ||||||||
Equity of minority and preferred shareholders in affiliated companies |
4,282 | 3,804 | ||||||||
Total liabilities |
$ | 120,320 | $ | 105,171 | ||||||
Commitments and contingencies |
15 | |||||||||
Shareholders equity |
||||||||||
Common stock without par value |
$ | 4,933 | $ | 4,786 | ||||||
(9,000 million shares authorized, 8,019 million shares issued) |
||||||||||
Earnings reinvested |
228,518 | 195,207 | ||||||||
Accumulated other comprehensive income |
||||||||||
Cumulative foreign exchange translation adjustment |
7,972 | 3,733 | ||||||||
Postretirement benefits reserves adjustment |
(5,983 | ) | (6,495 | ) | ||||||
Common stock held in treasury (2,637 million shares in 2007 and 2,290 million shares in 2006) |
(113,678 | ) | (83,387 | ) | ||||||
Total shareholders equity |
$ | 121,762 | $ | 113,844 | ||||||
Total liabilities and shareholders equity |
$ | 242,082 | $ | 219,015 | ||||||
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
51
CONSOLIDATED STATEMENT OF SHAREHOLDERS EQUITY
2007 |
2006 |
2005 |
|||||||||||||||||||||||
Note Reference Number |
Shareholders Equity |
Comprehensive Income |
Shareholders Equity |
Comprehensive Income (1) |
Shareholders Equity |
Comprehensive Income |
|||||||||||||||||||
(millions of dollars) | |||||||||||||||||||||||||
Common stock |
|||||||||||||||||||||||||
At beginning of year |
$ | 4,786 | $ | 4,477 | $ | 4,053 | |||||||||||||||||||
Restricted stock amortization |
531 | 480 | 356 | ||||||||||||||||||||||
Tax benefits related to stock-based awards |
113 | 169 | 224 | ||||||||||||||||||||||
Cumulative effect of accounting change |
2 | (55 | ) | | | ||||||||||||||||||||
Other |
(442 | ) | (340 | ) | (156 | ) | |||||||||||||||||||
At end of year |
$ | 4,933 | $ | 4,786 | $ | 4,477 | |||||||||||||||||||
Earnings reinvested |
|||||||||||||||||||||||||
At beginning of year |
195,207 | 163,335 | 134,390 | ||||||||||||||||||||||
Net income for the year |
40,610 | $ | 40,610 | 39,500 | $ | 39,500 | 36,130 | $ | 36,130 | ||||||||||||||||
Cumulative effect of accounting change |
2 | 322 | | | |||||||||||||||||||||
Dividends common shares |
(7,621 | ) | (7,628 | ) | (7,185 | ) | |||||||||||||||||||
At end of year |
$ | 228,518 | $ | 195,207 | $ | 163,335 | |||||||||||||||||||
Accumulated other comprehensive income |
|||||||||||||||||||||||||
At beginning of year |
(2,762 | ) | (1,279 | ) | 1,527 | ||||||||||||||||||||
Foreign exchange translation adjustment |
4,239 | 4,239 | 2,754 | 2,754 | (2,619 | ) | (2,619 | ) | |||||||||||||||||
Postretirement benefits reserves adjustment |
16 | (326 | ) | (326 | ) | (6,495 | ) | | | | |||||||||||||||
Amortization of postretirement benefits reserves adjustment included in net periodic benefit costs |
16 | 838 | 838 | | | | | ||||||||||||||||||
Minimum pension liability adjustment |
| | 2,258 | 749 | 241 | 241 | |||||||||||||||||||
Reclassification adjustment for gain on sale of stock investment included in net income |
| | | | (428 | ) | (428 | ) | |||||||||||||||||
At end of year |
$ | 1,989 | $ | (2,762 | ) | $ | (1,279 | ) | |||||||||||||||||
Total |
$ | 45,361 | $ | 43,003 | $ | 33,324 | |||||||||||||||||||
Common stock held in treasury |
|||||||||||||||||||||||||
At beginning of year |
(83,387 | ) | (55,347 | ) | (38,214 | ) | |||||||||||||||||||
Acquisitions, at cost |
(31,822 | ) | (29,558 | ) | (18,221 | ) | |||||||||||||||||||
Dispositions |
1,531 | 1,518 | 1,088 | ||||||||||||||||||||||
At end of year |
$ | (113,678 | ) | $ | (83,387 | ) | $ | (55,347 | ) | ||||||||||||||||
Shareholders equity at end of year |
$ | 121,762 | $ | 113,844 | $ | 111,186 | |||||||||||||||||||
Share Activity |
|||||||||||||||||||||||||
2007 |
2006 |
2005 |
|||||||||||||||||||||||
(millions of shares) | |||||||||||||||||||||||||
Common stock |
|||||||||||||||||||||||||
Issued |
|||||||||||||||||||||||||
At beginning of year |
8,019 | 8,019 | 8,019 | ||||||||||||||||||||||
Issued |
| | | ||||||||||||||||||||||
At end of year |
8,019 | 8,019 | 8,019 | ||||||||||||||||||||||
Held in treasury |
|||||||||||||||||||||||||
At beginning of year |
(2,290 | ) | (1,886 | ) | (1,618 | ) | |||||||||||||||||||
Acquisitions |
(386 | ) | (451 | ) | (311 | ) | |||||||||||||||||||
Dispositions |
39 | 47 | 43 | ||||||||||||||||||||||
At end of year |
(2,637 | ) | (2,290 | ) | (1,886 | ) | |||||||||||||||||||
Common shares outstanding at end of year |
5,382 | 5,729 | 6,133 | ||||||||||||||||||||||
(1) | Includes pre-FAS 158 adoption change in minimum pension liability. |
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
52
CONSOLIDATED STATEMENT OF CASH FLOWS
Note Reference Number |
2007 |
2006 |
2005 |
|||||||||||
(millions of dollars) | ||||||||||||||
Cash flows from operating activities |
||||||||||||||
Net income |
||||||||||||||
Accruing to ExxonMobil shareholders |
$ | 40,610 | $ | 39,500 | $ | 36,130 | ||||||||
Accruing to minority and preferred interests |
1,005 | 1,051 | 799 | |||||||||||
Adjustments for noncash transactions |
||||||||||||||
Depreciation and depletion |
12,250 | 11,416 | 10,253 | |||||||||||
Deferred income tax charges/(credits) |
124 | 1,717 | (429 | ) | ||||||||||
Postretirement benefits expense in excess of/(less than) payments |
(1,314 | ) | (1,787 | ) | 254 | |||||||||
Other long-term obligation provisions in excess of/(less than) payments |
1,065 | (666 | ) | 398 | ||||||||||
Dividends received greater than/(less than) equity in current earnings of equity companies |
(714 | ) | (579 | ) | (734 | ) | ||||||||
Changes in operational working capital, excluding cash and debt |
||||||||||||||
Reduction/(increase) Notes and accounts receivable |
(5,441 | ) | (181 | ) | (3,700 | ) | ||||||||
Inventories |
72 | (1,057 | ) | (434 | ) | |||||||||
Prepaid taxes and expenses |
280 | (385 | ) | (7 | ) | |||||||||
Increase/(reduction) Accounts and other payables |
6,228 | 1,160 | 7,806 | |||||||||||
Net (gain) on asset sales |
4 | (2,217 | ) | (1,531 | ) | (1,980 | ) | |||||||
All other items net |
54 | 628 | (218 | ) | ||||||||||
Net cash provided by operating activities |
$ | 52,002 | $ | 49,286 | $ | 48,138 | ||||||||
Cash flows from investing activities |
||||||||||||||
Additions to property, plant and equipment |
$ | (15,387 | ) | $ | (15,462 | ) | $ | (13,839 | ) | |||||
Sales of subsidiaries, investments and property, plant and equipment |
4 | 4,204 | 3,080 | 6,036 | ||||||||||
Decrease in restricted cash and cash equivalents |
3,15 | 4,604 | | | ||||||||||
Additional investments and advances |
(3,038 | ) | (2,604 | ) | (2,810 | ) | ||||||||
Collection of advances |
391 | 756 | 343 | |||||||||||
Additions to marketable securities |
(646 | ) | | | ||||||||||
Sales of marketable securities |
144 | | | |||||||||||
Net cash used in investing activities |
$ | (9,728 | ) | $ | (14,230 | ) | $ | (10,270 | ) | |||||
Cash flows from financing activities |
||||||||||||||
Additions to long-term debt |
$ | 592 | $ | 318 | $ | 195 | ||||||||
Reductions in long-term debt |
(209 | ) | (33 | ) | (81 | ) | ||||||||
Additions to short-term debt |
1,211 | 334 | 377 | |||||||||||
Reductions in short-term debt |
(809 | ) | (451 | ) | (687 | ) | ||||||||
Additions/(reductions) in debt with less than 90-day maturity |
(187 | ) | (95 | ) | (1,306 | ) | ||||||||
Cash dividends to ExxonMobil shareholders |
(7,621 | ) | (7,628 | ) | (7,185 | ) | ||||||||
Cash dividends to minority interests |
(289 | ) | (239 | ) | (293 | ) | ||||||||
Changes in minority interests and sales/(purchases) of affiliate stock |
(659 | ) | (493 | ) | (681 | ) | ||||||||
Tax benefits related to stock-based awards |
369 | 462 | | |||||||||||
Common stock acquired |
(31,822 | ) | (29,558 | ) | (18,221 | ) | ||||||||
Common stock sold |
1,079 | 1,173 | 941 | |||||||||||
Net cash used in financing activities |
$ | (38,345 | ) | $ | (36,210 | ) | $ | (26,941 | ) | |||||
Effects of exchange rate changes on cash |
$ | 1,808 | $ | 727 | $ | (787 | ) | |||||||
Increase/(decrease) in cash and cash equivalents |
$ | 5,737 | $ | (427 | ) | $ | 10,140 | |||||||
Cash and cash equivalents at beginning of year |
28,244 | 28,671 | 18,531 | |||||||||||
Cash and cash equivalents at end of year |
$ | 33,981 | $ | 28,244 | $ | 28,671 | ||||||||
The information in the Notes to Consolidated Financial Statements is an integral part of these statements.
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation.
The Corporations principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (Upstream) and the manufacture, transportation and sale of petroleum products (Downstream). The Corporation is also a major worldwide manufacturer and marketer of petrochemicals (Chemical) and participates in electric power generation (Upstream).
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years data has been reclassified in certain cases to conform to the 2007 presentation basis.
1. Summary of Accounting Policies
Principles of Consolidation. The Consolidated Financial Statements include the accounts of those subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the Corporation and for which other shareholders do not possess the right to participate in significant management decisions. They also include the Corporations share of the undivided interest in certain upstream assets and liabilities.
Amounts representing the Corporations percentage interest in the underlying net assets of other subsidiaries and less-than-majority-owned companies in which a significant ownership percentage interest is held are included in Investments, advances and long-term receivables; the Corporations share of the net income of these companies is included in the Consolidated Statement of Income caption Income from equity affiliates. The Corporations share of the cumulative foreign exchange translation adjustment for equity method investments is reported in the Consolidated Statement of Shareholders Equity. Evidence of loss in value that might indicate impairment of investments in companies accounted for on the equity method is assessed to determine if such evidence represents a loss in value of the Corporations investment that is other than temporary. Examples of key indicators include a history of operating losses, a negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investees business segment or geographic region. If evidence of an other than temporary loss in fair value below carrying amount is determined, an impairment is recognized. In the absence of market prices for the investment, discounted cash flows are used to assess fair value.
Revenue Recognition. The Corporation generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments. In all cases, revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured.
Revenues from the production of natural gas properties in which the Corporation has an interest with other producers are recognized on the basis of the Corporations net working interest. Differences between actual production and net working interest volumes are not significant.
Effective January 1, 2006, the Corporation adopted the Emerging Issues Task Force (EITF) consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold. In prior periods, the Corporation recorded certain crude oil, natural gas, petroleum product and chemical sales and purchases contemporaneously negotiated with the same counterparty as revenues and purchases. As a result of the EITF consensus, the Corporations accounts Sales and other operating revenue, Crude oil and product purchases and Other taxes and duties on the Consolidated Statement of Income were reduced prospectively from 2006 by associated amounts with no impact on net income. All operating segments were affected by this change, with the largest impact in the Downstream.
Sales-Based Taxes. The Corporation reports sales, excise and value-added taxes on sales transactions on a gross basis in the Consolidated Statement of Income (included in both revenues and costs). This gross reporting basis is footnoted on the Consolidated Statement of Income.
Derivative Instruments. The Corporation makes limited use of derivative instruments. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. When the Corporation does enter into derivative transactions, it is to offset exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices that arise from existing assets, liabilities and transactions.
The gains and losses resulting from changes in the fair value of derivatives are recorded in income. In some cases, the Corporation designates derivatives as fair value hedges, in which case the gains and losses are offset in income by the gains and losses arising from changes in the fair value of the underlying hedged items.
54
Inventories. Crude oil, products and merchandise inventories are carried at the lower of current market value or cost (generally determined under the last-in, first-out method LIFO). Inventory costs include expenditures and other charges (including depreciation) directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials and supplies are valued at cost or less.
Property, Plant and Equipment. Depreciation, depletion and amortization, based on cost less estimated salvage value of the asset, are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
Interest costs incurred to finance expenditures during the construction phase of multiyear projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets.
The Corporation uses the successful efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method.
The Corporation carries as an asset exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the Corporation is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense.
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that the Corporation expects to hold the properties. The cost of properties that are not individually significant are aggregated by groups and amortized over the average holding period of the properties of the groups. The valuation allowances are reviewed at least annually. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred.
Unit-of-production depreciation is applied to property, plant and equipment, including capitalized exploratory drilling and development costs, associated with productive depletable extractive properties in the Upstream segment. Unit-of-production rates are based on the amount of proved developed reserves of oil, gas and other minerals that are estimated to be recoverable from existing facilities using current operating methods. Additional oil and gas to be obtained through the application of improved recovery techniques is included when, or to the extent that, the requisite commercial-scale facilities have been installed and the required wells have been drilled.
Under the unit-of-production method, oil and gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank.
Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Corporations wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labor costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.
Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Corporation. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
Proved oil and gas properties held and used by the Corporation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The Corporation estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products are based on corporate plan assumptions developed annually by major region and also for investment evaluation purposes. Cash flow estimates for impairment testing exclude derivative instruments.
Impairment analyses are generally based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. Impairments are measured by the amount the carrying value exceeds the fair value.
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Asset Retirement Obligations and Environmental Liabilities. The Corporation incurs retirement obligations for certain assets at the time they are installed. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value.
Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted.
Foreign Currency Translation. The Corporation selects the functional reporting currency for its international subsidiaries based on the currency of the primary economic environment in which each subsidiary operates. Downstream and Chemical operations primarily use the local currency. However, the U.S. dollar is used in countries with a history of high inflation (primarily in Latin America) and Singapore, which predominantly sells into the U.S. dollar export market. Upstream operations which are relatively self-contained and integrated within a particular country, such as Canada, the United Kingdom, Norway and continental Europe, use the local currency. Some Upstream operations, primarily in Asia, West Africa, Russia and the Middle East, use the U.S. dollar because they predominantly sell crude and natural gas production into U.S. dollar-denominated markets. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income.
Share-Based Payments. The Corporation awards share-based compensation to employees in the form of restricted stock and restricted stock units. Compensation expense is measured by the market price of the restricted shares at the date of grant and is recognized in the income statement over the requisite service period of each award. See note 14, Incentive Program, for further details.
2. Accounting Change for Uncertainty in Income Taxes
Effective January 1, 2007, the Corporation adopted the Financial Accounting Standards Boards (FASB) Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes. FIN 48 is an interpretation of FASB Statement 109, Accounting for Income Taxes, and prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that the Corporation has taken or expects to take in its income tax returns. Upon the adoption of FIN 48, the Corporation recognized a transition gain of $267 million in shareholders equity. The gain reflected the recognition of several refund claims, partly offset by increased liability reserves. FIN 48 also resulted in a reclassification of amounts previously reported net on the balance sheet. The balance sheet reclassifications resulted in a $2.4 billion increase to investments, advances and long-term receivables, a $1.0 billion decrease to current liabilities, primarily income taxes payable, and a $3.1 billion increase to other long-term obligations. See note 18, Income, Sales-Based and Other Taxes, for additional disclosures.
3. Miscellaneous Financial Information
Research and development costs totaled $814 million in 2007, $733 million in 2006 and $712 million in 2005.
Net income included aggregate foreign exchange transaction gains of $229 million and $278 million in 2007 and 2006, respectively, and losses of $138 million in 2005.
In 2007, 2006 and 2005, net income included gains of $327 million, $401 million and $215 million, respectively, attributable to the combined effects of LIFO inventory accumulations and draw-downs. The aggregate replacement cost of inventories was estimated to exceed their LIFO carrying values by $25.4 billion and $15.9 billion at December 31, 2007, and 2006, respectively.
Crude oil, products and merchandise as of year-end 2007 and 2006 consist of the following:
2007 |
2006 | |||||
(billions of dollars) | ||||||
Petroleum products |
$ | 3.8 | $ | 3.8 | ||
Crude oil |
2.6 | 2.8 | ||||
Chemical products |
2.1 | 2.1 | ||||
Gas/other |
0.4 | 0.3 | ||||
Total |
$ | 8.9 | $ | 9.0 | ||
The restriction on approximately $4.6 billion of cash and cash equivalents was released in 2007 following an Alabama Supreme Court judgment in ExxonMobils favor (see note 15).
56
The Consolidated Statement of Cash Flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents.
The Net (gain) on asset sales in net cash provided by operating activities on the Consolidated Statement of Cash Flows includes the before-tax gain from the Corporations sale of its investment in Sinopec in 2005. Other gains are primarily from the sale of Downstream assets and investments in 2007 and from the sale of Upstream producing properties in 2006 and 2005. These gains are reported in Other income on the Consolidated Statement of Income.
2007 |
2006 |
2005 | |||||||
(millions of dollars) | |||||||||
Cash payments for interest |
$ | 555 | $ | 1,382 | $ | 473 | |||
Cash payments for income taxes |
$ | 26,342 | $ | 26,165 | $ | 22,535 |
5. Additional Working Capital Information
Dec. 31 2007 |
Dec. 31 2006 | |||||
(millions of dollars) | ||||||
Notes and accounts receivable |
||||||
Trade, less reserves of $258 million and $306 million |
$ | 30,775 | $ | 25,076 | ||
Other, less reserves of $36 million and $64 million |
5,675 | 3,866 | ||||
Total |
$ | 36,450 | $ | 28,942 | ||
Notes and loans payable |
||||||
Bank loans |
$ | 1,238 | $ | 753 | ||
Commercial paper |
205 | 274 | ||||
Long-term debt due within one year |
318 | 459 | ||||
Other |
622 | 216 | ||||
Total |
$ | 2,383 | $ | 1,702 | ||
Accounts payable and accrued liabilities |
||||||
Trade payables |
$ | 29,239 | $ | 25,084 | ||
Payables to equity companies |
3,556 | 2,597 | ||||
Accrued taxes other than income taxes |
6,485 | 6,052 | ||||
Other |
5,995 | 5,349 | ||||
Total |
$ | 45,275 | $ | 39,082 | ||
On December 31, 2007, unused credit lines for short-term financing totaled approximately $5.7 billion. Of this total, $3.6 billion support commercial paper programs under terms negotiated when drawn. The weighted-average interest rate on short-term borrowings outstanding at December 31, 2007, and 2006, was 5.5 percent.
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The summarized financial information below includes amounts related to certain less-than-majority-owned companies and majority-owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see note 1). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution and downstream operations in Europe; crude production in Kazakhstan; and liquefied natural gas (LNG) operations in Qatar. Also included are several power generation, refining, petrochemical/lubes manufacturing and chemical ventures. The Corporations ownership in these ventures is in the form of shares in corporate joint ventures as well as interests in partnerships. The share of total equity company revenues from sales to ExxonMobil consolidated companies was 23 percent, 24 percent and 22 percent in the years 2007, 2006 and 2005, respectively.
2007 |
2006 |
2005 | ||||||||||||||||
Equity Company Financial Summary |
Total |
ExxonMobil Share |
Total |
ExxonMobil Share |
Total |
ExxonMobil Share | ||||||||||||
(millions of dollars) | ||||||||||||||||||
Total revenues |
$ | 109,149 | $ | 37,724 | $ | 98,542 | $ | 33,505 | $ | 88,003 | $ | 31,395 | ||||||
Income before income taxes |
$ | 30,505 | $ | 11,448 | $ | 24,094 | $ | 8,905 | $ | 24,070 | $ | 9,809 | ||||||
Income taxes |
7,557 | 2,547 | 5,582 | 1,920 | 5,574 | 2,226 | ||||||||||||
Net income |
$ | 22,948 | $ | 8,901 | $ | 18,512 | $ | 6,985 | $ | 18,496 | $ | 7,583 | ||||||
Current assets |
$ | 29,268 | $ | 10,228 | $ | 24,684 | $ | 8,484 | $ | 24,931 | $ | 8,645 | ||||||
Property, plant and equipment, less accumulated depreciation |
70,591 | 22,638 | 59,691 | 19,602 | 50,622 | 17,149 | ||||||||||||
Other long-term assets |
6,667 | 3,092 | 7,209 | 4,206 | 6,900 | 3,919 | ||||||||||||
Total assets |
$ | 106,526 | $ | 35,958 | $ | 91,584 | $ | 32,292 | $ | 82,453 | $ | 29,713 | ||||||
Short-term debt |
$ | 3,127 | $ | 1,117 | $ | 2,669 | $ | 888 | $ | 3,412 | $ | 1,179 | ||||||
Other current liabilities |
20,861 | 7,124 | 16,543 | 5,852 | 15,330 | 5,414 | ||||||||||||
Long-term debt |
19,821 | 2,269 | 16,442 | 1,920 | 13,419 | 2,271 | ||||||||||||
Other long-term liabilities |
8,142 | 3,395 | 7,946 | 3,250 | 7,477 | 3,153 | ||||||||||||
Advances from shareholders |
18,422 | 8,353 | 15,791 | 6,803 | 14,390 | 5,580 | ||||||||||||
Net assets |
$ | 36,153 | $ | 13,700 | $ | 32,193 | $ | 13,579 | $ | 28,425 | $ | 12,116 | ||||||
A list of significant equity companies as of December 31, 2007, together with the Corporations percentage ownership interest, is detailed below:
Percentage Ownership Interest | ||
Upstream |
||
Aera Energy LLC |
48 | |
BEB Erdgas und Erdoel GmbH |
50 | |
Cameroon Oil Transportation Company S.A. |
41 | |
Castle Peak Power Company Limited |
60 | |
Nederlandse Aardolie Maatschappij B.V. |
50 | |
Qatar Liquefied Gas Company Limited |
10 | |
Qatar Liquefied Gas Company Limited II |
24 | |
Ras Laffan Liquefied Natural Gas Company Limited |
25 | |
Ras Laffan Liquefied Natural Gas Company Limited II |
30 | |
Tengizchevroil, LLP |
25 | |
Terminale GNL Adriatico S.r.l. |
45 | |
Downstream |
||
Chalmette Refining, LLC |
50 | |
Fujian Refining & Petrochemical Company Ltd. |
25 | |
Saudi Aramco Mobil Refinery Company Ltd. |
50 | |
Chemical |
||
Al-Jubail Petrochemical Company |
50 | |
Infineum Holdings B.V. |
50 | |
Saudi Yanbu Petrochemical Co. |
50 |
58
7. Investments, Advances and Long-Term Receivables
Dec. 31 2007 |
Dec. 31 2006 | |||||
(millions of dollars) | ||||||
Companies carried at equity in underlying assets |
||||||
Investments |
$ | 13,700 | $ | 13,579 | ||
Advances |
8,353 | 6,803 | ||||
$ | 22,053 | $ | 20,382 | |||
Companies carried at cost or less and stock investments carried at fair value |
1,647 | 1,678 | ||||
$ | 23,700 | $ | 22,060 | |||
Long-term receivables and miscellaneous investments at cost or less |
4,494 | 1,177 | ||||
Total |
$ | 28,194 | $ | 23,237 | ||
8. Property, Plant and Equipment and Asset Retirement Obligations
Dec. 31, 2007 |
Dec. 31, 2006 | |||||||||||
Property, Plant and Equipment |
Cost |
Net |
Cost |
Net | ||||||||
(millions of dollars) | ||||||||||||
Upstream |
$ | 178,712 | $ | 73,524 | $ | 163,087 | $ | 68,410 | ||||
Downstream |
65,841 | 30,148 | 62,392 | 28,918 | ||||||||
Chemical |
24,081 | 10,071 | 22,197 | 9,319 | ||||||||
Other |
11,706 | 7,126 | 11,608 | 7,040 | ||||||||
Total |
$ | 280,340 | $ | 120,869 | $ | 259,284 | $ | 113,687 | ||||
In the Upstream segment, depreciation is on a unit-of-production basis, so depreciable life will vary by field. In the Downstream segment, investments in refinery and lubes basestock manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life and service station buildings and fixed improvements over a 20-year life. In the Chemical segment, investments in process equipment are generally depreciated on a straight-line basis over a 20-year life.
Accumulated depreciation and depletion totaled $159,471 million at the end of 2007 and $145,597 million at the end of 2006. Interest capitalized in 2007, 2006 and 2005 was $557 million, $530 million and $434 million, respectively.
Asset Retirement Obligations
The Corporation incurs retirement obligations for its upstream assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations.
The following table summarizes the activity in the liability for asset retirement obligations:
2007 |
2006 |
|||||||
(millions of dollars) | ||||||||
Beginning balance |
$ | 4,703 | $ | 3,568 | ||||
Accretion expense and other provisions |
322 | 243 | ||||||
Reduction due to property sales |
(271 | ) | (202 | ) | ||||
Payments made |
(352 | ) | (238 | ) | ||||
Liabilities incurred |
113 | 263 | ||||||
Revisions |
348 | 832 | ||||||
Foreign currency translation/other |
278 | 237 | ||||||
Ending balance |
$ | 5,141 | $ | 4,703 | ||||
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. Accounting for Suspended Exploratory Well Costs
In accounting for suspended exploratory well costs, the Corporation utilizes Financial Accounting Standards Board Staff Position FAS 19-1 (FSP 19-1), Accounting for Suspended Well Costs. FSP 19-1 amended Statement of Financial Accounting Standards No. 19 (FAS 19), Financial Accounting and Reporting by Oil and Gas Producing Companies, to permit the continued capitalization of exploratory well costs beyond one year after the well is completed if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.
The following two tables provide details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs.
Change in capitalized suspended exploratory well costs:
2007 |
2006 |
2005 |
||||||||||
(millions of dollars) | ||||||||||||
Balance beginning at January 1 |
$ | 1,305 | $ | 1,139 | $ | 1,070 | ||||||
Additions pending the determination of proved reserves |
228 | 257 | 233 | |||||||||
Charged to expense |
(108 | ) | (54 | ) | (62 | ) | ||||||
Reclassifications to wells, facilities and equipment based on the determination of proved reserves |
(82 | ) | (22 | ) | (82 | ) | ||||||
Other |
(52 | ) | (15 | ) | (20 | ) | ||||||
Ending balance |
$ | 1,291 | $ | 1,305 | $ | 1,139 | ||||||
Ending balance attributed to equity companies included above |
$ | 3 | $ | 17 | $ | 2 |
Period end capitalized suspended exploratory well costs:
2007 |
2006 |
2005 | |||||||
(millions of dollars) | |||||||||
Capitalized for a period of one year or less |
$ | 228 | $ | 257 | $ | 233 | |||
Capitalized for a period of between one and five years |
566 | 566 | 485 | ||||||
Capitalized for a period of between five and ten years |
255 | 213 | 167 | ||||||
Capitalized for a period of greater than ten years |
242 | 269 | 254 | ||||||
Capitalized for a period greater than one year subtotal |
$ | 1,063 | $ | 1,048 | $ | 906 | |||
Total |
$ | 1,291 | $ | 1,305 | $ | 1,139 | |||
Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. The table below provides a numerical breakdown of the number of projects with suspended exploratory well costs which had their first capitalized well drilled in the preceding 12 months and those that have had exploratory well costs capitalized for a period greater than 12 months.
2007 |
2006 |
2005 | ||||
Number of projects with first capitalized well drilled in the preceding 12 months |
4 | 13 | 16 | |||
Number of projects that have exploratory well costs capitalized for a period of greater than 12 months |
49 | 53 | 56 | |||
Total |
53 | 66 | 72 | |||
60
Of the 49 projects that have exploratory well costs capitalized for a period greater than 12 months as of December 31, 2007, 29 projects have drilling in the preceding 12 months or exploratory activity planned in the next two years, while the remaining 20 projects are those with completed exploratory activity progressing toward development. The table below provides additional detail for those 20 projects, which total $291 million.
Country/Project | Dec. 31, 2007 |
Years Wells Drilled |
Comment | |||
(millions of dollars) |
||||||
Australia | ||||||
East Pilchard |
$9 | 2001 | Gas field near Kipper/Tuna development, awaiting capacity in existing/planned infrastructure. | |||
Canada |
||||||
Hibernia |
36 | 2006 | Progressing development plan and regulatory approvals for tieback to Hibernia gravity-based structure. | |||
Indonesia | ||||||
Natuna |
118 | 1981 - 1983 | Intent to proceed to the next phase of development communicated to government in 2004; discussions with government on near-term development work plans and contract terms are in progress; further technical evaluation and gas marketing activities continued to progress in 2007. | |||
Kazakhstan | ||||||
Aktote |
42 | 2003 - 2004 | Development study under way to examine tieback to Kashagan field and/or potential development with Kairan field that is still in the exploration phase. | |||
Nigeria |
||||||
Etoro-Isobo |
9 | 2002 | Offshore satellite development which will tie back to a planned production facility. | |||
Other (4 projects) |
12 | 2001 - 2002 | Actively pursuing development of several additional offshore satellite discoveries which will tie back to existing/planned production facilities. | |||
United Kingdom |
||||||
Carrack West |
8 | 2001 | Planned tieback to Carrack production facility; awaiting capacity. | |||
Phyllis |
10 | 2004 | Assessing co-development option with nearby 2005 Barbara discovery. | |||
United States |
||||||
Point Thomson |
28 | 1977 - 1980 | The Point Thomson Unit owners are progressing plans to put the unit into production. A project team continues evaluating gas transportation alternatives. The 2006 order of the Alaska Department of Natural Resources terminating the Point Thomson Unit was reversed on appeal by order of the Alaska Superior Court. | |||
Other | ||||||
Various (8 projects) |
19 | 1979 - 2005 | Projects primarily awaiting capacity in existing or planned infrastructure. | |||
Total 2007 (20 projects) |
$291 |
61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 2007, the Corporation and its consolidated subsidiaries held noncancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum undiscounted lease commitments totaling $9,916 million as indicated in the table. Estimated related rental income from noncancelable subleases is $191 million.
Lease Payments Under Minimum Commitments |
Related Sublease Rental Income | |||||
(millions of dollars) | ||||||
2008 |
$ | 1,994 | $ | 37 | ||
2009 |
1,917 | 32 | ||||
2010 |
1,546 | 28 | ||||
2011 |
1,130 | 24 | ||||
2012 |
765 | 18 | ||||
2013 and beyond |
2,564 | 52 | ||||
Total |
$ | 9,916 | $ | 191 | ||
Net rental expenses under both cancelable and noncancelable operating leases incurred during 2007, 2006 and 2005 were as follows:
2007 |
2006 |
2005 | |||||||
(millions of dollars) | |||||||||
Rental expense |
$ | 3,367 | $ | 3,576 | $ | 2,966 | |||
Less sublease rental income |
168 | 172 | 176 | ||||||
Net rental expense |
$ | 3,199 | $ | 3,404 | $ | 2,790 | |||
2007 |
2006 |
2005 | |||||||
Net income per common share |
|||||||||
Net income (millions of dollars) |
$ | 40,610 | $ | 39,500 | $ | 36,130 | |||
Weighted average number of common shares outstanding (millions of shares) |
5,517 | 5,913 | 6,266 | ||||||
Net income per common share (dollars) |
$ | 7.36 | $ | 6.68 | $ | 5.76 | |||
Net income per common share assuming dilution |
|||||||||
Net income (millions of dollars) |
$ | 40,610 | $ | 39,500 | $ | 36,130 | |||
Weighted average number of common shares outstanding (millions of shares) |
5,517 | 5,913 | 6,266 | ||||||
Effect of employee stock-based awards |
60 | 57 | 56 | ||||||
Weighted average number of common shares outstanding assuming dilution |
5,577 | 5,970 | 6,322 | ||||||
Net income per common share (dollars) |
$ | 7.28 | $ | 6.62 | $ | 5.71 | |||
Dividends paid per common share (dollars) |
$ | 1.37 | $ | 1.28 | $ | 1.14 |
62
12. Financial Instruments and Derivatives
The fair value of financial instruments is determined by reference to various market data and other valuation techniques as appropriate. Long-term debt is the only category of financial instruments whose fair value differs materially from the recorded book value. The estimated fair value of total long-term debt, including capitalized lease obligations, at December 31, 2007, and 2006, was $7.9 billion and $7.2 billion, respectively, as compared to recorded book values of $7.2 billion and $6.6 billion.
The Corporations size, strong capital structure, geographic diversity and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the Corporations enterprise-wide risk from changes in interest rates, currency rates and commodity prices. As a result, the Corporation makes limited use of derivatives to mitigate the impact of such changes. The Corporation does not engage in speculative derivative activities or derivative trading activities nor does it use derivatives with leveraged features. The Corporation maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. The Corporations limited derivative activities pose no material credit or market risks to ExxonMobils operations, financial condition or liquidity.
The estimated fair value of derivatives outstanding and recorded on the balance sheet was a net receivable of $31 million at year-end 2007 and a net payable of $64 million at year-end 2006. This is the amount that the Corporation would have received from, or paid to, third parties if these derivatives had been settled in the open market. The Corporation recognized a before-tax gain of $66 million and $397 million and a loss of $312 million related to derivatives during 2007, 2006 and 2005, respectively.
The fair value of derivatives outstanding at year-end 2007 and gain recognized during the year are immaterial in relation to the Corporations year-end cash balance of $34.0 billion, total assets of $242.1 billion or net income for the year of $40.6 billion.
At December 31, 2007, long-term debt consisted of $6,689 million due in U.S. dollars and $494 million representing the U.S. dollar equivalent at year-end exchange rates of amounts payable in foreign currencies. These amounts exclude that portion of long-term debt, totaling $318 million, which matures within one year and is included in current liabilities. The amounts of long-term debt maturing, together with sinking fund payments required, in each of the four years after December 31, 2008, in millions of dollars, are: 2009 $255, 2010 $203, 2011 $206 and 2012 $2,246. At December 31, 2007, the Corporations unused long-term credit lines were not material.
Summarized long-term borrowings at year-end 2007 and 2006 were as shown in the table below:
2007 |
2006 | |||||
(millions of dollars) | ||||||
Exxon Capital Corporation |
||||||
6.125% Guaranteed notes due 2008 |
$ | | $ | 160 | ||
SeaRiver Maritime Financial Holdings, Inc. (1) |
||||||
Guaranteed debt securities due 2008-2011 (2) |
39 | 52 | ||||
Guaranteed deferred interest debentures due 2012 |
||||||
Face value net of unamortized discount plus accrued interest |
1,727 | 1,550 | ||||
Mobil Services (Bahamas) Ltd. |
||||||
Variable notes due 2035 (3) |
972 | 972 | ||||
Variable notes due 2034 (4) |
311 | 311 | ||||
Mobil Producing Nigeria Unlimited (5) |
||||||
Variable notes due 2012-2016 |
708 | 489 | ||||
Esso (Thailand) Public Company Ltd. (6) |
||||||
Variable note due 2009-2012 |
326 | | ||||
Mobil Corporation |
||||||
8.625% debentures due 2021 |
248 | 248 | ||||
Industrial revenue bonds due 2012-2039 (7) |
1,694 | 1,697 | ||||
Other U.S. dollar obligations (8) |
629 | 786 | ||||
Other foreign currency obligations |
120 | 160 | ||||
Capitalized lease obligations (9) |
409 | 220 | ||||
Total long-term debt |
$ | 7,183 | $ | 6,645 | ||
(1) | Additional information is provided for this subsidiary on the following pages. |
(2) | Average effective interest rate of 5.3% in 2007 and 5.1% in 2006. |
(3) | Average effective interest rate of 5.3% in 2007 and 5.1% in 2006. |
(4) | Average effective interest rate of 5.4% in 2007 and 5.1% in 2006. |
(5) | Average effective interest rate of 8.8% in 2007 and 8.6% in 2006. |
(6) | Average effective interest rate of 4.5% in 2007. |
(7) | Average effective interest rate of 3.9% in 2007 and 3.7% in 2006. |
(8) | Average effective interest rate of 6.6% in 2007 and 6.6% in 2006. |
(9) | Average imputed interest rate of 7.3% in 2007 and 7.6% in 2006. |
63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed consolidating financial information related to guaranteed securities issued by subsidiaries
Exxon Mobil Corporation has fully and unconditionally guaranteed the deferred interest debentures due 2012 ($1,727 million long-term debt at December 31, 2007) and the debt securities due 2008 to 2011 ($39 million long-term and $13 million short-term) of SeaRiver Maritime Financial Holdings, Inc.
SeaRiver Maritime Financial Holdings, Inc. is a 100-percent-owned subsidiary of Exxon Mobil Corporation.
The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for SeaRiver Maritime Financial Holdings, Inc., as issuer, as an alternative to providing separate financial statements for the issuer. The accounts of Exxon Mobil Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the equity method of accounting for investments in subsidiaries.
Exxon Mobil Corporation Parent Guarantor |
SeaRiver Maritime Financial Holdings, Inc. |
All Other Subsidiaries |
Consolidating and Eliminating Adjustments |
Consolidated | |||||||||||||
(millions of dollars) | |||||||||||||||||
Condensed consolidated statement of income for 12 months ended December 31, 2007 | |||||||||||||||||
Revenues and other income |
|||||||||||||||||
Sales and other operating revenue, including sales-based taxes |
$ | 16,502 | $ | | $ | 373,826 | $ | | $ | 390,328 | |||||||
Income from equity affiliates |
40,800 | 4 | 8,859 | (40,762 | ) | 8,901 | |||||||||||
Other income |
488 | | 4,835 | | 5,323 | ||||||||||||
Intercompany revenue |
39,490 | 101 | 361,263 | (400,854 | ) | | |||||||||||
Total revenues and other income |
97,280 | 105 | 748,783 | (441,616 | ) | 404,552 | |||||||||||
Costs and other deductions |
|||||||||||||||||
Crude oil and product purchases |
38,260 | | 535,973 | (374,735 | ) | 199,498 | |||||||||||
Production and manufacturing expenses |
7,147 | | 30,003 | (5,265 | ) | 31,885 | |||||||||||
Selling, general and administrative expenses |
2,581 | | 13,116 | (807 | ) | 14,890 | |||||||||||
Depreciation and depletion |
1,661 | | 10,589 | | 12,250 | ||||||||||||
Exploration expenses, including dry holes |
276 | | 1,193 | | 1,469 | ||||||||||||
Interest expense |
5,997 | 201 | 14,601 | (20,399 | ) | 400 | |||||||||||
Sales-based taxes |
| | 31,728 | | 31,728 | ||||||||||||
Other taxes and duties |
48 | | 40,905 | | 40,953 | ||||||||||||
Income applicable to minority and preferred interests |
| | 1,005 | | 1,005 | ||||||||||||
Total costs and other deductions |
55,970 | 201 | 679,113 | (401,206 | ) | 334,078 | |||||||||||
Income before income taxes |
41,310 | (96 | ) | 69,670 | (40,410 | ) | 70,474 | ||||||||||
Income taxes |
700 | (34 | ) | 29,198 | | 29,864 | |||||||||||
Net income |
$ | 40,610 | $ | (62 | ) | $ | 40,472 | $ | (40,410 | ) | $ | 40,610 | |||||
64
Exxon Mobil Corporation Parent Guarantor |
SeaRiver Maritime Financial Holdings, Inc. |
All Other Subsidiaries |
Consolidating and Eliminating Adjustments |
Consolidated | |||||||||||||
(millions of dollars) | |||||||||||||||||
Condensed consolidated statement of income for 12 months ended December 31, 2006 | |||||||||||||||||
Revenues and other income |
|||||||||||||||||
Sales and other operating revenue, including sales-based taxes |
$ | 16,317 | $ | | $ | 349,150 | $ | | $ | 365,467 | |||||||
Income from equity affiliates |
37,911 | 14 | 6,974 | (37,914 | ) | 6,985 | |||||||||||
Other income |
944 | | 4,239 | | 5,183 | ||||||||||||
Intercompany revenue |
39,265 | 95 | 328,452 | (367,812 | ) | | |||||||||||
Total revenues and other income |
94,437 | 109 | 688,815 | (405,726 | ) | 377,635 | |||||||||||
Costs and other deductions |
|||||||||||||||||
Crude oil and product purchases |
37,365 | | 491,169 | (345,988 | ) | 182,546 | |||||||||||
Production and manufacturing expenses |
7,357 | | 27,120 | (4,949 | ) | 29,528 | |||||||||||
Selling, general and administrative expenses |
2,634 | | 12,297 | (658 | ) | 14,273 | |||||||||||
Depreciation and depletion |
1,431 | | 9,985 | | 11,416 | ||||||||||||
Exploration expenses, including dry holes |
272 | | 909 | | 1,181 | ||||||||||||
Interest expense |
4,829 | 182 | 12,388 | (16,745 | ) | 654 | |||||||||||
Sales-based taxes |
| | 30,381 | | 30,381 | ||||||||||||
Other taxes and duties |
36 | | 39,167 | | 39,203 | ||||||||||||
Income applicable to minority and preferred interests |
| | 1,051 | | 1,051 | ||||||||||||
Total costs and other deductions |
53,924 | 182 | 624,467 | (368,340 | ) | 310,233 | |||||||||||
Income before income taxes |
40,513 | (73 | ) | 64,348 | (37,386 | ) | 67,402 | ||||||||||
Income taxes |
1,013 | (30 | ) | 26,919 | | 27,902 | |||||||||||
Net income |
$ | 39,500 | $ | (43 | ) | $ | 37,429 | $ | (37,386 | ) | $ | 39,500 | |||||
Condensed consolidated statement of income for 12 months ended December 31, 2005 | |||||||||||||||||
Revenues and other income |
|||||||||||||||||
Sales and other operating revenue, including sales-based taxes |
$ | 15,081 | $ | | $ | 343,874 | $ | | $ | 358,955 | |||||||
Income from equity affiliates |
32,996 | 6 | 7,584 | (33,003 | ) | 7,583 | |||||||||||
Other income |
834 | | 3,308 | | 4,142 | ||||||||||||
Intercompany revenue |
33,546 | 56 | 274,757 | (308,359 | ) | | |||||||||||
Total revenues and other income |
82,457 | 62 | 629,523 | (341,362 | ) | 370,680 | |||||||||||
Costs and other deductions |
|||||||||||||||||
Crude oil and product purchases |
30,451 | | 447,251 | (292,483 | ) | 185,219 | |||||||||||
Production and manufacturing expenses |
7,177 | | 24,859 | (5,217 | ) | 26,819 | |||||||||||
Selling, general and administrative expenses |
2,434 | | 12,480 | (512 | ) | 14,402 | |||||||||||
Depreciation and depletion |
1,341 | | 8,912 | | 10,253 | ||||||||||||
Exploration expenses, including dry holes |
137 | | 827 | | 964 | ||||||||||||
Interest expense |
2,723 | 159 | 7,790 | (10,176 | ) | 496 | |||||||||||
Sales-based taxes |
| | 30,742 | | 30,742 | ||||||||||||
Other taxes and duties |
21 | | 41,533 | | 41,554 | ||||||||||||
Income applicable to minority and preferred interests |
| | 799 | | 799 | ||||||||||||
Total costs and other deductions |
44,284 | 159 | 575,193 | (308,388 | ) | 311,248 | |||||||||||
Income before income taxes |
38,173 | (97 | ) | 54,330 | (32,974 | ) | 59,432 | ||||||||||
Income taxes |
2,043 | (36 | ) | 21,295 | | 23,302 | |||||||||||
Net income |
$ | 36,130 | $ | (61 | ) | $ | 33,035 | $ | (32,974 | ) | $ | 36,130 | |||||
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed consolidating financial information related to guaranteed securities issued by subsidiaries
Exxon Mobil Corporation Parent Guarantor |
SeaRiver Maritime Financial Holdings, Inc. |
All Other Subsidiaries |
Consolidating and Eliminating Adjustments |
Consolidated |
|||||||||||||||
(millions of dollars) | |||||||||||||||||||
Condensed consolidated balance sheet for year ended December 31, 2007 |
| ||||||||||||||||||
Cash and cash equivalents |
$ | 1,393 | $ | | $ | 32,588 | $ | | $ | 33,981 | |||||||||
Cash and cash equivalents restricted |
| | | | | ||||||||||||||
Marketable securities |
| | 519 | | 519 | ||||||||||||||
Notes and accounts receivable net |
3,733 | 2 | 34,338 | (1,623 | ) | 36,450 | |||||||||||||
Inventories |
1,198 | | 9,891 | | 11,089 | ||||||||||||||
Prepaid taxes and expenses |
373 | | 3,551 | | 3,924 | ||||||||||||||
Total current assets |
6,697 | 2 | 80,887 | (1,623 | ) | 85,963 | |||||||||||||
Investments, advances and long-term receivables |
208,062 | 362 | 420,262 | (600,492 | ) | 28,194 | |||||||||||||
Property, plant and equipment net |
16,291 | | 104,578 | | 120,869 | ||||||||||||||
Other long-term assets |
221 | 51 | 6,784 | | 7,056 | ||||||||||||||
Intercompany receivables |
14,577 | 1,961 | 437,433 | (453,971 | ) | | |||||||||||||
Total assets |
$ | 245,848 | $ | 2,376 | $ | 1,049,944 | $ | (1,056,086 | ) | $ | 242,082 | ||||||||
Notes and loans payable |
$ | 3 | $ | 13 | $ | 2,367 | $ | | $ | 2,383 | |||||||||
Accounts payable and accrued liabilities |
3,038 | 1 | 42,236 | | 45,275 | ||||||||||||||
Income taxes payable |
| | 12,277 | (1,623 | ) | 10,654 | |||||||||||||
Total current liabilities |
3,041 | 14 | 56,880 | (1,623 | ) | 58,312 | |||||||||||||
Long-term debt |
276 | 1,766 | 5,141 | | 7,183 | ||||||||||||||
Deferred income tax liabilities |
1,829 | 212 | 20,858 | | 22,899 | ||||||||||||||
Other long-term liabilities |
11,308 | | 20,618 | | 31,926 | ||||||||||||||
Intercompany payables |
107,632 | 382 | 345,957 | (453,971 | ) | | |||||||||||||
Total liabilities |
124,086 | 2,374 | 449,454 | (455,594 | ) | 120,320 | |||||||||||||
Earnings reinvested |
228,518 | (467 | ) | 114,037 | (113,570 | ) | 228,518 | ||||||||||||
Other shareholders equity |
(106,756 | ) | 469 | 486,453 | (486,922 | ) | (106,756 | ) | |||||||||||
Total shareholders equity |
121,762 | 2 | 600,490 | (600,492 | ) | 121,762 | |||||||||||||
Total liabilities and shareholders equity |
$ | 245,848 | $ | 2,376 | $ | 1,049,944 | $ | (1,056,086 | ) | $ | 242,082 | ||||||||
Condensed consolidated balance sheet for year ended December 31, 2006 |
| ||||||||||||||||||
Cash and cash equivalents |
$ | 6,355 | $ | | $ | 21,889 | $ | | $ | 28,244 | |||||||||
Cash and cash equivalents restricted |
| | 4,604 | | 4,604 | ||||||||||||||
Notes and accounts receivable net |
2,057 | | 26,885 | | 28,942 | ||||||||||||||
Inventories |
1,213 | | 9,501 | | 10,714 | ||||||||||||||
Prepaid taxes and expenses |
357 | | 2,916 | | 3,273 | ||||||||||||||
Total current assets |
9,982 | | 65,795 | | 75,777 | ||||||||||||||
Investments, advances and long-term receivables |
200,982 | 359 | 409,935 | (588,039 | ) | 23,237 | |||||||||||||
Property, plant and equipment net |
16,730 | | 96,957 | | 113,687 | ||||||||||||||
Other long-term assets |
275 | 64 | 5,975 | | 6,314 | ||||||||||||||
Intercompany receivables |
16,501 | 1,883 | 435,221 | (453,605 | ) | | |||||||||||||
Total assets |
$ | 244,470 | $ | 2,306 | $ | 1,013,883 | $ | (1,041,644 | ) | $ | 219,015 | ||||||||
Notes and loans payable |
$ | 90 | $ | 13 | $ | 1,599 | $ | | $ | 1,702 | |||||||||
Accounts payable and accrued liabilities |
3,025 | 1 | 36,056 | | 39,082 | ||||||||||||||
Income taxes payable |
548 | 1 | 7,484 | | 8,033 | ||||||||||||||
Total current liabilities |
3,663 | 15 | 45,139 | | 48,817 | ||||||||||||||
Long-term debt |
274 | 1,602 | 4,769 | | 6,645 | ||||||||||||||
Deferred income tax liabilities |
1,975 | 237 | 18,639 | | 20,851 | ||||||||||||||
Other long-term liabilities |
8,044 | | 20,814 | | 28,858 | ||||||||||||||
Intercompany payables |
116,670 | 387 | 336,548 | (453,605 | ) | | |||||||||||||
Total liabilities |
130,626 | 2,241 | 425,909 | (453,605 | ) | 105,171 | |||||||||||||
Earnings reinvested |
195,207 | (404 | ) | 144,607 | (144,203 | ) | 195,207 | ||||||||||||
Other shareholders equity |
(81,363 | ) | 469 | 443,367 | (443,836 | ) | (81,363 | ) | |||||||||||
Total shareholders equity |
113,844 | 65 | 587,974 | (588,039 | ) | 113,844 | |||||||||||||
Total liabilities and shareholders equity |
$ | 244,470 | $ | 2,306 | $ | 1,013,883 | $ | (1,041,644 | ) | $ | 219,015 | ||||||||
66
Exxon Mobil Corporation Parent Guarantor |
SeaRiver Maritime Financial Holdings, Inc. |
All Other Subsidiaries |
Consolidating and Eliminating Adjustments |
Consolidated |
||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Condensed consolidated statement of cash flows for 12 months ended December 31, 2007 |
| |||||||||||||||||||
Cash provided by/(used in) operating activities |
$ | 73,813 | $ | 97 | $ | 49,185 | $ | (71,093 | ) | $ | 52,002 | |||||||||
Cash flows from investing activities |
||||||||||||||||||||
Additions to property, plant and equipment |
(1,252 | ) | | (14,135 | ) | | (15,387 | ) | ||||||||||||
Sales of long-term assets |
251 | | 3,953 | | 4,204 | |||||||||||||||
Decrease/(increase) in restricted cash and cash equivalents |
| | 4,604 | | 4,604 | |||||||||||||||
Net intercompany investing |
(39,679 | ) | (79 | ) | 39,676 | 82 | | |||||||||||||
All other investing, net |
| | (3,149 | ) | | (3,149 | ) | |||||||||||||
Net cash provided by/(used in) investing activities |
(40,680 | ) | (79 | ) | 30,949 | 82 | (9,728 | ) | ||||||||||||
Cash flows from financing activities |
||||||||||||||||||||
Additions to short- and long-term debt |
| | 1,803 | | 1,803 | |||||||||||||||
Reductions in short- and long-term debt |
(3 | ) | (13 | ) | (1,002 | ) | | (1,018 | ) | |||||||||||
Additions/(reductions) in debt with less than |
||||||||||||||||||||
90-day maturity |
(97 | ) | | (90 | ) | | (187 | ) | ||||||||||||
Cash dividends |
(7,621 | ) | | (71,093 | ) | 71,093 | (7,621 | ) | ||||||||||||
Common stock acquired |
(31,822 | ) | | | | (31,822 | ) | |||||||||||||
Net intercompany financing activity |
| (5 | ) | 87 | (82 | ) | | |||||||||||||
All other financing, net |
1,448 | | (948 | ) | | 500 | ||||||||||||||
Net cash provided by/(used in) financing activities |
(38,095 | ) | (18 | ) | (71,243 | ) | 71,011 | (38,345 | ) | |||||||||||
Effects of exchange rate changes on cash |
| | 1,808 | | 1,808 | |||||||||||||||
Increase/(decrease) in cash and cash equivalents |
$ | (4,962 | ) | $ | | $ | 10,699 | $ | | $ | 5,737 | |||||||||
Condensed consolidated statement of cash flows for 12 months ended December 31, 2006 |
| |||||||||||||||||||
Cash provided by/(used in) operating activities |
$ | 3,678 | $ | 112 | $ | 47,111 | $ | (1,615 | ) | $ | 49,286 | |||||||||
Cash flows from investing activities |
||||||||||||||||||||
Additions to property, plant and equipment |
(1,571 | ) | | (13,891 | ) | | (15,462 | ) | ||||||||||||
Sales of long-term assets |
421 | | 2,659 | | 3,080 | |||||||||||||||
Decrease/(increase) in restricted cash and cash equivalents |
4,604 | | (4,604 | ) | | | ||||||||||||||
Net intercompany investing |
23,067 | (107 | ) | (23,091 | ) | 131 | | |||||||||||||
All other investing, net |
| | (1,848 | ) | | (1,848 | ) | |||||||||||||
Net cash provided by/(used in) investing activities |
26,521 | (107 | ) | (40,775 | ) | 131 | (14,230 | ) | ||||||||||||
Cash flows from financing activities |
||||||||||||||||||||
Additions to short- and long-term debt |
| | 652 | | 652 | |||||||||||||||
Reductions in short- and long-term debt |
| (10 | ) | (474 | ) | | (484 | ) | ||||||||||||
Additions/(reductions) in debt with less than |
||||||||||||||||||||
90-day maturity |
(368 | ) | | 273 | | (95 | ) | |||||||||||||
Cash dividends |
(7,628 | ) | | (1,615 | ) | 1,615 | (7,628 | ) | ||||||||||||
Common stock acquired |
(29,558 | ) | | | | (29,558 | ) | |||||||||||||
Net intercompany financing activity |
| 5 | 126 | (131 | ) | | ||||||||||||||
All other financing, net |
1,634 | | (731 | ) | | 903 | ||||||||||||||
Net cash provided by/(used in) financing activities |
(35,920 | ) | (5 | ) | (1,769 | ) | 1,484 | (36,210 | ) | |||||||||||
Effects of exchange rate changes on cash |
| | 727 | | 727 | |||||||||||||||
Increase/(decrease) in cash and cash equivalents |
$ | (5,721 | ) | $ | | $ | 5,294 | $ | | $ | (427 | ) | ||||||||
67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed consolidating financial information related to guaranteed securities issued by subsidiaries
Exxon Mobil Corporation Parent Guarantor |
SeaRiver Maritime Financial Holdings, Inc. |
All Other Subsidiaries |
Consolidating and Eliminating Adjustments |
Consolidated |
||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Condensed consolidated statement of cash flows for 12 months ended December 31, 2005 |
| |||||||||||||||||||
Cash provided by/(used in) operating activities |
$ | 11,538 | $ | 129 | $ | 42,099 | $ | (5,628 | ) | $ | 48,138 | |||||||||
Cash flows from investing activities |
||||||||||||||||||||
Additions to property, plant and equipment |
(1,296 | ) | | (12,543 | ) | | (13,839 | ) | ||||||||||||
Sales of long-term assets |
314 | | 5,722 | | 6,036 | |||||||||||||||
Decrease/(increase) in restricted cash and cash equivalents |
| | | | | |||||||||||||||
Net intercompany investing |
15,483 | (173 | ) | (15,545 | ) | 235 | | |||||||||||||
All other investing, net |
1 | | (2,468 | ) | | (2,467 | ) | |||||||||||||
Net cash provided by/(used in) investing activities |
14,502 | (173 | ) | (24,834 | ) | 235 | (10,270 | ) | ||||||||||||
Cash flows from financing activities |
||||||||||||||||||||
Additions to short- and long-term debt |
| | 572 | | 572 | |||||||||||||||
Reductions in short- and long-term debt |
| (10 | ) | (758 | ) | | (768 | ) | ||||||||||||
Additions/(reductions) in debt with less than 90-day maturity |
446 | | (1,752 | ) | | (1,306 | ) | |||||||||||||
Cash dividends |
(7,185 | ) | | (5,628 | ) | 5,628 | (7,185 | ) | ||||||||||||
Common stock acquired |
(18,221 | ) | | | | (18,221 | ) | |||||||||||||
Net intercompany financing activity |
| (21 | ) | 181 | (160 | ) | | |||||||||||||
All other financing, net |
941 | 75 | (974 | ) | (75 | ) | (33 | ) | ||||||||||||
Net cash provided by/(used in) financing activities |
(24,019 | ) | 44 | (8,359 | ) | 5,393 | (26,941 | ) | ||||||||||||
Effects of exchange rate changes on cash |
| | (787 | ) | | (787 | ) | |||||||||||||
Increase/(decrease) in cash and cash equivalents |
$ | 2,021 | $ | | $ | 8,119 | $ | | $ | 10,140 | ||||||||||
The 2003 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted to eligible employees of the Corporation and those affiliates at least 50 percent owned. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. The maximum number of shares of stock that may be issued under the 2003 Incentive Program is 220 million. Awards that are forfeited or expire, or are settled in cash, do not count against this maximum limit. The 2003 Incentive Program does not have a specified term. New awards may be made until the available shares are depleted, unless the Board terminates the plan early. At the end of 2007, remaining shares available for award under the 2003 Incentive Program were 170,695 thousand.
As under earlier programs, options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. Most of the options and SARs normally first become exercisable one year following the date of grant. All remaining stock options and SARs outstanding were granted prior to 2002.
Long-term incentive awards totaling 10,226 thousand, 10,187 thousand and 11,071 thousand shares of restricted (nonvested) common stock and restricted (nonvested) common stock units were granted in 2007, 2006 and 2005, respectively. These shares are issued to employees from treasury stock. The total compensation expense is recognized over the requisite service period. The units that are settled in cash are recorded as liabilities and their changes in fair value are recognized over the vesting period. During the applicable restricted periods, the shares may not be sold or transferred and are subject to forfeiture. The majority of the awards have graded vesting periods, with 50 percent of the shares in each award vesting after three years and the remaining 50 percent vesting after seven years. A small number of awards granted to certain senior executives have vesting periods of five years for 50 percent of the award and of 10 years or retirement, whichever occurs later, for the remaining 50 percent of the award.
68
The Corporation has purchased shares in the open market and through negotiated transactions to offset shares issued in conjunction with benefit plans and programs. Purchases may be discontinued at any time without prior notice.
In 2002, the Corporation began issuing restricted stock as share-based compensation in lieu of stock options. Compensation expense for these awards is based on the price of the stock at the date of grant and has been recognized in income over the requisite service period, which is the same method of accounting as under FAS 123R. Prior to 2002, the Corporation issued stock options as share-based compensation and since these awards vested prior to the effective date of FAS 123R, they continue to be accounted for by the method prescribed in APB 25, Accounting for Stock Issued to Employees. Under this method, compensation expense for awards granted in the form of stock options is measured at the intrinsic value of the options (the difference between the market price of the stock and the exercise price of the options) on the date of grant. Since these two prices were the same on the date of grant, no compensation expense has been recognized in income for these awards.
The following table summarizes information about restricted stock and restricted stock units, including those shares from former Mobil plans, for the year ended December 31, 2007.
Restricted Stock and Units Outstanding |
Shares |
Weighted Average Grant-Date Fair Value per Share | ||||
(thousands) | ||||||
Issued and outstanding at January 1, 2007 |
36,124 | $ | 47.30 | |||
2006 award issued in 2007 |
10,167 | $ | 73.47 | |||
Vested |
(6,795 | ) | $ | 46.02 | ||
Forfeited |
(281 | ) | $ | 53.57 | ||
Issued and outstanding at December 31, 2007 |
39,215 | $ | 54.26 | |||
Grant Value of Restricted Stock and Units |
2007 |
2006 |
2005 | ||||||
Grant price |
$ | 87.14 | $ | 73.47 | $ | 58.43 | |||
(millions of dollars) | |||||||||
Value at date of grant: |
|||||||||
Restricted stock and units settled in stock |
$ | 827 | $ | 704 | $ | 611 | |||
Units settled in cash |
64 | 44 | 36 | ||||||
Total value |
$ | 891 | $ | 748 | $ | 647 | |||
As of December 31, 2007, there was $1,892 million of unrecognized compensation cost related to the nonvested restricted awards. This cost is expected to be recognized over a weighted-average period of 4.7 years. The compensation cost charged against income for the restricted stock and restricted units was $590 million, $527 million and $387 million for 2007, 2006 and 2005, respectively. The income tax benefit recognized in income related to this compensation expense was $81 million, $72 million and $69 million for the same periods, respectively. The fair value of shares and units vested in 2007, 2006 and 2005 was $581 million, $310 million and $288 million, respectively. Cash payments of $29 million, $18 million and $15 million for vested restricted stock units settled in cash were made in 2007, 2006 and 2005, respectively.
69
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes that occurred in stock options in 2007 are summarized below (shares in thousands):
2007 |
||||||||
Stock Options |
Shares |
Avg. Exercise Price |
Weighted Average Remaining Contractual Term | |||||
Outstanding at January 1 |
110,487 | $ | 38.86 | |||||
Exercised |
(30,168 | ) | $ | 35.88 | ||||
Forfeited |
(30 | ) | $ | 37.11 | ||||
Outstanding at December 31 |
80,289 | $ | 39.98 | 2.7 Years | ||||
Exercisable at December 31 |
80,289 | $ | 39.98 | 2.7 Years |
No compensation expense was recognized for stock options in 2007, 2006 and 2005, as all remaining outstanding stock options were granted prior to 2002 and are fully vested. Cash received from stock option exercises was $1,079 million, $1,173 million and $941 million for 2007, 2006 and 2005, respectively. The cash tax benefit realized for the options exercised was $304 million, $416 million and $295 million for 2007, 2006 and 2005, respectively. The aggregate intrinsic value of stock options exercised in 2007, 2006 and 2005 was $1,359 million, $1,304 million and $954 million, respectively. The intrinsic value for the balance of outstanding stock options at December 31, 2007, was $4,312 million.
15. Litigation and Other Contingencies
Litigation
A variety of claims have been made against ExxonMobil and certain of its consolidated subsidiaries in a number of pending lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The Corporation accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The Corporation does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and which are significant, the Corporation discloses the nature of the contingency and, where feasible, an estimate of the possible loss. ExxonMobil will continue to defend itself vigorously in these matters. Based on a consideration of all relevant facts and circumstances, the Corporation does not believe the ultimate outcome of any currently pending lawsuit against ExxonMobil will have a materially adverse effect upon the Corporations operations or financial condition.
A number of lawsuits, including class actions, were brought in various courts against Exxon Mobil Corporation and certain of its subsidiaries relating to the accidental release of crude oil from the tanker Exxon Valdez in 1989. All the compensatory claims have been resolved and paid. All of the punitive damage claims were consolidated in the civil trial that began in 1994. The first judgment from the United States District Court for the District of Alaska in the amount of $5 billion was vacated by the United States Court of Appeals for the Ninth Circuit as being excessive under the Constitution. The second judgment in the amount of $4 billion was vacated by the Ninth Circuit panel without argument and sent back for the District Court to reconsider in light of the recent U.S. Supreme Court decision in Campbell v. State Farm. The most recent District Court judgment for punitive damages was for $4.5 billion plus interest and was entered in January 2004. The Corporation posted a $5.4 billion letter of credit. ExxonMobil and the plaintiffs appealed this decision to the Ninth Circuit, which ruled on December 22, 2006, that the award be reduced to $2.5 billion. On January 12, 2007, ExxonMobil petitioned the Ninth Circuit Court of Appeals for a rehearing en banc of its appeal. On May 23, 2007, with two dissenting opinions, the Ninth Circuit determined not to re-hear ExxonMobils appeal before the full court. ExxonMobil filed a petition for writ of certiorari to the U.S. Supreme Court on August 20, 2007. On October 29, 2007, the U.S. Supreme Court granted ExxonMobils petition for a writ of certiorari. Oral argument was held on February 27, 2008. While it is reasonably possible that a liability for punitive damages may have been incurred from the Exxon Valdez grounding, it is not possible to predict the ultimate outcome or to reasonably estimate any such potential liability.
In December 2000, a jury in the 15th Judicial Circuit Court of Montgomery County, Alabama, returned a verdict against the Corporation in a dispute over royalties in the amount of $88 million in compensatory damages and $3.4 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court in May 2001. In December 2002, the Alabama Supreme Court vacated the $3.5 billion jury verdict. The case was retried and in November 2003, a state district court jury in Montgomery, Alabama, returned a verdict against Exxon Mobil Corporation. The verdict included $63.5 million in compensatory damages and $11.8 billion in punitive damages. In March 2004, the district court judge reduced the amount of punitive damages to $3.5 billion. ExxonMobil appealed the decision to the Alabama Supreme Court. On November 1, 2007, the Alabama Supreme Court reversed the trial courts fraud judgment and instructed the district court to enter judgment for ExxonMobil on the fraud claim, eliminating the punitive damage award. The Court also ruled in ExxonMobils favor on some of the disputed lease issues, reducing the compensatory award to $52 million plus interest. Following the Alabama Supreme Courts decision, an appeal bond was canceled and the collateral was subsequently released.
70
In 2001, a Louisiana state court jury awarded compensatory damages of $56 million and punitive damages of $1 billion to a landowner for damage caused by a third party that leased the property from the landowner. The third party provided pipe cleaning and storage services for the Corporation and other entities. The Louisiana Fourth Circuit Court of Appeals reduced the punitive damage award to $112 million in 2005. The Corporation appealed this decision to the Louisiana Supreme Court which, in March 2006, refused to hear the appeal. ExxonMobil has fully accrued and paid the compensatory and punitive damage awards. The Corporation appealed the punitive damage award to the U.S. Supreme Court, which on February 26, 2007, vacated the judgment and remanded the case to the Louisiana Fourth Circuit Court of Appeals for reconsideration in light of the recent U.S. Supreme Court decision in Williams v. Phillip Morris USA. On August 8, 2007, the Fourth Circuit issued its decision on remand and declined to reduce the punitive damage award. On November 16, 2007, the Louisiana Supreme Court denied ExxonMobils writ for review of the Fourth Circuits decision. ExxonMobil has appealed to the U.S. Supreme Court.
Other Contingencies
The Corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2007, for $5,148 million, primarily relating to guarantees for notes, loans and performance under contracts. Included in this amount were guarantees by consolidated affiliates of $4,591 million, representing ExxonMobils share of obligations of certain equity companies.
Dec. 31, 2007 | |||||||||
Equity Company Obligations |
Other Third-Party Obligations |
Total | |||||||
(millions of dollars) | |||||||||
Total guarantees |
$ | 4,591 | $ | 557 | $ | 5,148 |
Additionally, the Corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the Corporations operations or financial condition. Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are noncancelable or cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services.
Payments Due by Period | ||||||||||||
2008 |
2009- 2012 |
2013 and Beyond |
Total | |||||||||
(millions of dollars) | ||||||||||||
Unconditional purchase obligations (1) |
$ | 490 | $ | 1,497 | $ | 778 | $ | 2,765 |
(1) | Undiscounted obligations of $2,765 million mainly pertain to pipeline throughput agreements and include $1,847 million of obligations to equity companies. The present value of these commitments, which excludes imputed interest of $562 million, totaled $2,203 million. |
In accordance with a nationalization decree issued by Venezuelas 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 PdVSAs or one of its affiliates 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 PdVSA, and on June 27, 2007, the government expropriated ExxonMobils 41.67 percent interest in the Cerro Negro Project.
To date, discussions with Venezuelan authorities have not resulted in an agreement on the amount of compensation to be paid to ExxonMobil. On September 6, 2007, ExxonMobil filed a Request for Arbitration with the International Centre for Settlement of Investment Disputes. 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 Corporations consolidated financial results cannot be reasonably estimated. However, the Corporation does not expect the resolution to have a material effect upon the Corporations operations or financial condition. At the time the assets were expropriated, ExxonMobils remaining net book investment in Cerro Negro producing assets was about $750 million.
71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. Pension and Other Postretirement Benefits
The benefit obligations and plan assets associated with the Corporations principal benefit plans are measured on December 31.
Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||||||||||
U.S. |
Non-U.S. |
|||||||||||||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||||||||||||||
(percent) | ||||||||||||||||||||||||
Weighted-average assumptions used to determine benefit obligations at December 31 |
||||||||||||||||||||||||
Discount rate |
6.25 | 6.00 | 5.40 | 4.70 | 6.25 | 6.00 | ||||||||||||||||||
Long-term rate of compensation increase |
5.00 | 4.50 | 4.50 | 4.20 | 5.00 | 4.50 | ||||||||||||||||||
(millions of dollars) | ||||||||||||||||||||||||
Change in benefit obligation |
||||||||||||||||||||||||
Benefit obligation at January 1 |
$ | 11,305 | $ | 11,181 | $ | 20,956 | $ | 19,310 | $ | 6,843 | $ | 5,370 | ||||||||||||
Service cost |
360 | 335 | 451 | 428 | 109 | 76 | ||||||||||||||||||
Interest cost |
687 | 632 | 1,011 | 911 | 403 | 308 | ||||||||||||||||||
Actuarial loss/(gain) |
896 | 484 | (665 | ) | (38 | ) | (275 | ) | 1,440 | |||||||||||||||
Benefits paid (1) (2) |
(1,091 | ) | (1,329 | ) | (1,197 | ) | (1,153 | ) | (416 | ) | (419 | ) | ||||||||||||
Foreign exchange rate changes |
| | 1,937 | 1,424 | 73 | | ||||||||||||||||||
Plan amendments, other |
(95 | ) | 2 | (18 | ) | 74 | 91 | 68 | ||||||||||||||||
Benefit obligation at December 31 |
$ | 12,062 | $ | 11,305 | $ | 22,475 | $ | 20,956 | $ | 6,828 | $ | 6,843 | ||||||||||||
Accumulated benefit obligation at December 31 |
$ | 10,244 | $ | 9,811 | $ | 20,151 | $ | 18,883 | $ | | $ | |
(1) | Benefit payments for funded and unfunded plans. |
(2) | For 2007 and 2006, other postretirement benefits paid are net of $19 million and $20 million Medicare subsidy receipts, respectively. |
For U.S. plans, the discount rate is determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments. For major non-U.S. plans, the discount rate is determined by using bond portfolios with an average maturity approximating that of the liabilities or spot yield curves, both of which are constructed using high-quality, local-currency-denominated bonds.
The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 7.5 percent for 2008 that declines to 4.5 percent by 2014. A one-percentage-point increase in the health care cost trend rate would increase service and interest cost by $54 million and the postretirement benefit obligation by $564 million. A one-percentage-point decrease in the health care cost trend rate would decrease service and interest cost by $44 million and the post-retirement benefit obligation by $468 million.
The Corporation offers a Medicare supplement plan to Medicare-eligible retirees that provides prescription drug benefits. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 provides a federal subsidy to employers sponsoring retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Corporation believes that its Medicare supplement plan is at least actuarially equivalent to Medicare Part D.
Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||||||||||
U.S. |
Non-U.S. |
|||||||||||||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||||||||||||||
(millions of dollars) | ||||||||||||||||||||||||
Change in plan assets |
||||||||||||||||||||||||
Fair value at January 1 |
$ | 9,752 | $ | 7,250 | $ | 14,387 | $ | 12,063 | $ | 501 | $ | 456 | ||||||||||||
Actual return on plan assets |
970 | 1,207 | 761 | 1,669 | 23 | 66 | ||||||||||||||||||
Foreign exchange rate changes |
| | 1,284 | 891 | | | ||||||||||||||||||
Company contribution |
800 | 2,383 | 1,666 | 724 | 191 | 34 | ||||||||||||||||||
Benefits paid (1) |
(905 | ) | (1,088 | ) | (816 | ) | (796 | ) | (56 | ) | (55 | ) | ||||||||||||
Other |
| | (90 | ) | (164 | ) | | | ||||||||||||||||
Fair value at December 31 |
$ | 10,617 | $ | 9,752 | $ | 17,192 | $ | 14,387 | $ | 659 | $ | 501 | ||||||||||||
(1) | Benefit payments for funded plans. |
72
The funding levels of all qualified pension plans are in compliance with standards set by applicable law or regulation. As shown in the table below, certain smaller U.S. pension plans and a number of non-U.S. pension plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. All defined benefit pension obligations, regardless of the funding status of the underlying plans, are fully supported by the financial strength of the Corporation or the respective sponsoring affiliate.
In 2007 and 2006, the Corporation contributed $800 million and $2,383 million, respectively, to the U.S. funded pension plan, approximately the maximum tax-deductible amount. As a result, year-end 2007 U.S. pension assets of $10,617 million were $1,493 million greater than the funded plan accumulated benefit obligation of $9,124 million.
Pension Benefits |
||||||||||||||||
U.S. |
Non-U.S. |
|||||||||||||||
2007 |
2006 |
2007 |
2006 |
|||||||||||||
(millions of dollars) | ||||||||||||||||
Assets in excess of/(less than) benefit obligation |
||||||||||||||||
Balance at December 31 |
||||||||||||||||
Funded plans |
$ | (64 | ) | $ | (254 | ) | $ | 192 | $ | (1,479 | ) | |||||
Unfunded plans |
(1,381 | ) | (1,299 | ) | (5,475 | ) | (5,090 | ) | ||||||||
Total |
$ | (1,445 | ) | $ | (1,553 | ) | $ | (5,283 | ) | $ | (6,569 | ) | ||||
Effective December 31, 2006, Exxon Mobil Corporation implemented FASB Statement No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, which requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income.
Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||||||||||
U.S. |
Non-U.S. |
|||||||||||||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||||||||||||||
(millions of dollars) | ||||||||||||||||||||||||
Assets in excess of/(less than) benefit obligation |
||||||||||||||||||||||||
Balance at December 31 (1) |
$ | (1,445 | ) | $ | (1,553 | ) | $ | (5,283 | ) | $ | (6,569 | ) | $ | (6,169 | ) | $ | (6,342 | ) | ||||||
Amounts recorded in the consolidated balance sheet consist of: |
||||||||||||||||||||||||
Other assets |
$ | 43 | $ | 36 | $ | 1,168 | $ | 196 | $ | | $ | | ||||||||||||
Current liabilities |
(177 | ) | (160 | ) | (329 | ) | (294 | ) | (324 | ) | (311 | ) | ||||||||||||
Postretirement benefits reserves |
(1,311 | ) | (1,429 | ) | (6,122 | ) | (6,471 | ) | (5,845 | ) | (6,031 | ) | ||||||||||||
Total recorded |
$ | (1,445 | ) | $ | (1,553 | ) | $ | (5,283 | ) | $ | (6,569 | ) | $ | (6,169 | ) | $ | (6,342 | ) | ||||||
Amounts recorded in accumulated other comprehensive income consist of: |
||||||||||||||||||||||||
Net actuarial loss/(gain) |
$ | 2,378 | $ | 2,044 | $ | 3,520 | $ | 3,838 | $ | 2,346 | $ | 2,831 | ||||||||||||
Prior service cost |
3 | 121 | 810 | 780 | 326 | 401 | ||||||||||||||||||
Total recorded in accumulated other comprehensive income |
$ | 2,381 | $ | 2,165 | $ | 4,330 | $ | 4,618 | $ | 2,672 | $ | 3,232 | ||||||||||||
(1) | Fair value of assets less benefit obligation shown on the preceding page. |
73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||||||||||||||||||||||
U.S. |
Non-U.S. |
|||||||||||||||||||||||||||||||||||
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
2007 |
2006 |
2005 |
||||||||||||||||||||||||||||
(percent) | ||||||||||||||||||||||||||||||||||||
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 |
||||||||||||||||||||||||||||||||||||
Discount rate |
6.00 | 5.75 | 5.75 | 4.70 | 4.50 | 4.90 | 6.00 | 5.75 | 5.75 | |||||||||||||||||||||||||||
Long-term rate of return on funded assets |
9.00 | 9.00 | 9.00 | 7.70 | 7.70 | 7.70 | 9.00 | 9.00 | 9.00 | |||||||||||||||||||||||||||
Long-term rate of compensation increase |
4.50 | 4.50 | 4.50 | 4.20 | 3.90 | 3.80 | 4.50 | 4.50 | 4.50 | |||||||||||||||||||||||||||
(millions of dollars) | ||||||||||||||||||||||||||||||||||||
Components of net periodic benefit cost |
||||||||||||||||||||||||||||||||||||
Service cost |
$ | 360 | $ | 335 | $ | 330 | $ | 451 | $ | 428 | $ | 382 | $ | 109 | $ | 76 | $ | 70 | ||||||||||||||||||
Interest cost |
687 | 632 | 611 | 1,011 | 911 | 834 | 403 | 308 | 301 | |||||||||||||||||||||||||||
Expected return on plan assets |
(844 | ) | (620 | ) | (629 | ) | (1,105 | ) | (982 | ) | (789 | ) | (44 | ) | (41 | ) | (39 | ) | ||||||||||||||||||
Amortization of actuarial loss/(gain) |
246 | 249 | 247 | 362 | 434 | 360 | 243 | 145 | 131 | |||||||||||||||||||||||||||
Amortization of prior service cost |
23 | 24 | 27 | 89 | 79 | 64 | 75 | 73 | 73 | |||||||||||||||||||||||||||
Net pension enhancement and curtailment/settlement expense |
190 | 157 | 123 | 19 | 47 | 10 | 9 | | | |||||||||||||||||||||||||||
Net periodic benefit cost |
$ | 662 | $ | 777 | $ | 709 | $ | 827 | $ | 917 | $ | 861 | $ | 795 | $ | 561 | $ | 536 | ||||||||||||||||||
Changes in amounts recorded in accumulated other comprehensive income: |
||||||||||||||||||||||||||||||||||||
Net actuarial loss/(gain) |
$ | 770 | $ | 1,265 | $ | (196 | ) | $ | (294 | ) | $ | 914 | $ | (74 | ) | $ | (245 | ) | $ | 2,831 | $ | | ||||||||||||||
Amortization of actuarial (loss)/gain |
(436 | ) | | | (381 | ) | | | (252 | ) | | | ||||||||||||||||||||||||
Prior service cost/(credit) |
(95 | ) | 121 | | 72 | 780 | | | 401 | | ||||||||||||||||||||||||||
Amortization of prior service (cost) |
(23 | ) | | | (89 | ) | | | (75 | ) | | | ||||||||||||||||||||||||
Foreign exchange rate changes |
| | | 404 | | | 12 | | | |||||||||||||||||||||||||||
Total recorded in accumulated other comprehensive income |
216 | 1,386 | (196 | ) | (288 | ) | 1,694 | (74 | ) | (560 | ) | 3,232 | | |||||||||||||||||||||||
Total recorded in net periodic benefit cost and accumulated other comprehensive income, before tax |
$ | 878 | $ | 2,163 | $ | 513 | $ | 539 | $ | 2,611 | $ | 787 | $ | 235 | $ | 3,793 | $ | 536 | ||||||||||||||||||
Costs for defined contribution plans were $287 million, $260 million and $251 million in 2007, 2006 and 2005, respectively.
A summary of the change in accumulated other comprehensive income is shown in the table below:
Total Pension and Other Postretirement Benefits |
||||||||||||
2007 |
2006 |
2005 |
||||||||||
(millions of dollars) | ||||||||||||
(Charge)/credit to accumulated other comprehensive income, before tax |
||||||||||||
U.S. pension |
$ | (216 | ) | $ | (1,386 | ) | $ | 196 | ||||
Non-U.S. pension |
288 | (1,694 | ) | 74 | ||||||||
Other postretirement benefits |
560 | (3,232 | ) | | ||||||||
Total (charge)/credit to accumulated other comprehensive income, before tax |
632 | (6,312 | ) | 270 | ||||||||
(Charge)/credit to income tax (see note 18) |
(207 | ) | 2,105 | (90 | ) | |||||||
Charge/(credit) to equity of minority shareholders |
61 | 38 | 61 | |||||||||
(Charge)/credit to investment in equity companies |
26 | (68 | ) | | ||||||||
(Charge)/credit to accumulated other comprehensive income, after tax |
$ | 512 | $ | (4,237 | ) | $ | 241 | |||||
74
The long-term expected rate of return on funded assets for each plan is established by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. The majority of pension assets are invested in equities, as illustrated in the table below, which shows asset allocation.
Pension Benefits |
Other Postretirement Benefits |
|||||||||||||||||
U.S. |
Non-U.S. |
|||||||||||||||||
2007 |
2006 |
2007 |
2006 |
2007 |
2006 |
|||||||||||||
(percent) | ||||||||||||||||||
Funded benefit plan asset allocation |
||||||||||||||||||
Equity securities |
75 | % | 75 | % | 65 | % | 69 | % | 75 | % | 75 | % | ||||||
Debt securities |
25 | 25 | 30 | 27 | 25 | 25 | ||||||||||||
Other |
| | 5 | 4 | | | ||||||||||||
Total |
100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | ||||||
The Corporations investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The Corporation primarily invests in funds that follow an index-based strategy to achieve its objectives of diversifying risk while minimizing costs. The funds hold ExxonMobil stock only to the extent necessary to replicate the relevant equity index. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for equity securities of 75 percent for the U.S. benefit plans and 64 percent for non-U.S. plans reflects the long-term nature of the liability. The balance of the funds is largely targeted to debt securities.
A summary of pension plans with an accumulated benefit obligation in excess of plan assets is shown in the table below:
Pension Benefits | ||||||||||||
U.S. |
Non-U.S. | |||||||||||
2007 |
2006 |
2007 |
2006 | |||||||||
(millions of dollars) | ||||||||||||
For funded pension plans with accumulated benefit obligations in excess of plan assets: |
||||||||||||
Projected benefit obligation |
$ | | $ | 4 | $ | 2,697 | $ | 8,971 | ||||
Accumulated benefit obligation |
| 3 | 2,527 | 8,322 | ||||||||
Fair value of plan assets |
| 2 | 1,919 | 7,265 | ||||||||
For unfunded pension plans: |
||||||||||||
Projected benefit obligation |
$ | 1,381 | $ | 1,299 | $ | 5,475 | $ | 5,090 | ||||
Accumulated benefit obligation |
1,120 | 1,120 | 4,827 | 4,502 |
Pension Benefits |
Other Postretirement Benefits | |||||||||
U.S. |
Non-U.S. |
|||||||||
(millions of dollars) | ||||||||||
Estimated 2008 amortization from accumulated other comprehensive income: |
||||||||||
Net actuarial loss/(gain) (1) |
$ | 382 | $ | 311 | $ | 203 | ||||
Prior service cost (2) |
(2 | ) | 97 | 76 |
(1) | The Corporation amortizes the net balance of actuarial losses/(gains) as a component of net periodic benefit cost over the average remaining service period of active plan participants. |
(2) | The Corporation amortizes prior service cost on a straight-line basis as permitted under FAS 87 and FAS 106. |
75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension Benefits |
Other Postretirement Benefits | ||||||||||
U.S. |
Non-U.S. |
Gross |
Medicare Subsidy Receipt | ||||||||
(millions of dollars) | |||||||||||
Contributions expected in 2008 |
$ | | $ | 529 | $ | | $ | ||||
Benefit payments expected in: |
|||||||||||
2008 |
962 | 1,244 | 415 | 23 | |||||||
2009 |
1,014 | 1,227 | 437 | 24 | |||||||
2010 |
1,058 | 1,274 | 460 | 26 | |||||||
2011 |
1,089 | 1,286 | 482 | 27 | |||||||
2012 |
1,140 | 1,338 | 499 | 29 | |||||||
2013 - 2017 |
5,741 | 7,615 | 2,709 | 169 |
17. Disclosures about Segments and Related Information
The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Upstream segment is organized and operates to explore for and produce crude oil and natural gas. The Downstream segment is organized and operates to manufacture and sell petroleum products. The Chemical segment is organized and operates to manufacture and sell petrochemicals. These segments are broadly understood across the petroleum and petrochemical industries.
These functions have been defined as the operating segments of the Corporation because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Corporations chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance; and (3) for which discrete financial information is available.
Earnings after income tax include special items, and transfers are at estimated market prices. There were no special items in 2007. After-tax earnings in 2006 included a $410 million special gain in the corporate and financing segment from the recognition of tax benefits related to historical investments in non-U.S. assets. Special items included in 2005 after-tax earnings are a $1,620 million gain in Non-U.S. Upstream for the restructuring of a Dutch gas equity company, a $390 million gain in Non-U.S. Chemical relating to joint venture litigation, gains of $310 million and $150 million in Non-U.S. Downstream and Non-U.S. Chemical, respectively, for the Sinopec share sale and a charge of $200 million in U.S. Downstream relating to the Allapattah lawsuit provision.
Interest expense includes non-debt-related interest expense of $290 million, $535 million and $369 million in 2007, 2006 and 2005, respectively. The decrease of $245 million in 2007 and the increase of $166 million in 2006 primarily reflect changes in tax-related interest.
In corporate and financing activities, interest revenue relates to interest earned on cash deposits and marketable securities.
76
Upstream |
Downstream |
Chemical |
Corporate and Financing |
Corporate Total | |||||||||||||||||||||
U.S. |
Non-U.S. |
U.S. |
Non-U.S. |
U.S. |
Non-U.S. |
||||||||||||||||||||
(millions of dollars) | |||||||||||||||||||||||||
As of December 31, 2007 |
|||||||||||||||||||||||||
Earnings after income tax |
$ | 4,870 | $ | 21,627 | $ | 4,120 | $ | 5,453 | $ | 1,181 | $ | 3,382 | $ | (23 | ) | $ | 40,610 | ||||||||
Earnings of equity companies included above |
1,455 | 5,393 | 208 | 641 | 120 | 1,558 | (474 | ) | 8,901 | ||||||||||||||||
Sales and other operating revenue (1) |
5,661 | 22,995 | 101,671 | 223,145 | 13,790 | 23,036 | 30 | 390,328 | |||||||||||||||||
Intersegment revenue |
7,596 | 47,498 | 13,942 | 52,403 | 8,710 | 7,881 | 303 | | |||||||||||||||||
Depreciation and depletion expense |
1,469 | 7,126 | 639 | 1,662 | 405 | 418 | 531 | 12,250 | |||||||||||||||||
Interest revenue |
| | | | | | 1,672 | 1,672 | |||||||||||||||||
Interest expense |
57 | 75 | 14 | 26 | 2 | 2 | 224 | 400 | |||||||||||||||||
Income taxes |
2,686 | 23,328 | 2,141 | 1,405 | 392 | 591 | (679 | ) | 29,864 | ||||||||||||||||
Additions to property, plant and equipment |
1,595 | 9,139 | 1,061 | 1,578 | 335 | 1,078 | 601 | 15,387 | |||||||||||||||||
Investments in equity companies |
2,016 | 7,194 | 488 | 1,172 | 224 | 2,650 | (44 | ) | 13,700 | ||||||||||||||||
Total assets |
21,782 | 84,440 | 18,569 | 54,883 | 7,617 | 13,801 | 40,990 | 242,082 | |||||||||||||||||
As of December 31, 2006 |
|||||||||||||||||||||||||
Earnings after income tax |
$ | 5,168 | $ | 21,062 | $ | 4,250 | $ | 4,204 | $ | 1,360 | $ | 3,022 | $ | 434 | $ | 39,500 | |||||||||
Earnings of equity companies included above |
1,323 | 4,236 | 227 | 279 | 84 | 1,180 | (344 | ) | 6,985 | ||||||||||||||||
Sales and other operating revenue (1) |
6,054 | 26,821 | 93,437 | 205,020 | 13,273 | 20,825 | 37 | 365,467 | |||||||||||||||||
Intersegment revenue |
7,118 | 39,963 | 12,603 | 46,675 | 7,849 | 6,997 | 292 | | |||||||||||||||||
Depreciation and depletion expense |
1,263 | 6,482 | 632 | 1,605 | 427 | 473 | 534 | 11,416 | |||||||||||||||||
Interest revenue |
| | | | | | 1,571 | 1,571 | |||||||||||||||||
Interest expense |
103 | 264 | 1 | 34 | | | 252 | 654 | |||||||||||||||||
Income taxes |
3,130 | 20,932 | 2,318 | 1,174 | 654 | 700 | (1,006 | ) | 27,902 | ||||||||||||||||
Additions to property, plant and equipment |
1,942 | 9,735 | 718 | 1,757 | 257 | 384 | 669 | 15,462 | |||||||||||||||||
Investments in equity companies |
1,665 | 8,065 | 451 | 949 | 245 | 2,261 | (57 | ) | 13,579 | ||||||||||||||||
Total assets |
21,119 | 75,090 | 16,740 | 47,694 | 7,652 | 11,885 | 38,835 | 219,015 | |||||||||||||||||
As of December 31, 2005 |
|||||||||||||||||||||||||
Earnings after income tax |
$ | 6,200 | $ | 18,149 | $ | 3,911 | $ | 4,081 | $ | 1,186 | $ | 2,757 | $ | (154 | ) | $ | 36,130 | ||||||||
Earnings of equity companies included above |
1,106 | 5,084 | 165 | 471 | 53 | 954 | (250 | ) | 7,583 | ||||||||||||||||
Sales and other operating revenue (1) |
6,730 | 23,324 | 91,954 | 205,726 | 11,842 | 19,344 | 35 | 358,955 | |||||||||||||||||
Intersegment revenue |
7,230 | 31,371 | 9,817 | 40,255 | 6,521 | 5,413 | 290 | | |||||||||||||||||
Depreciation and depletion expense |
1,293 | 5,407 | 615 | 1,611 | 416 | 410 | 501 | 10,253 | |||||||||||||||||
Interest revenue |
| | | | | | 946 | 946 | |||||||||||||||||
Interest expense |
30 | 32 | 230 | 34 | 4 | 4 | 162 | 496 | |||||||||||||||||
Income taxes |
3,516 | 15,968 | 2,139 | 1,362 | 447 | 794 | (924 | ) | 23,302 | ||||||||||||||||
Additions to property, plant and equipment |
1,763 | 8,796 | 662 | 1,618 | 218 | 268 | 514 | 13,839 | |||||||||||||||||
Investments in equity companies |
1,470 | 6,735 | 420 | 937 | 275 | 2,282 | (3 | ) | 12,116 | ||||||||||||||||
Total assets |
20,827 | 66,239 | 16,110 | 47,691 | 7,794 | 11,702 | 37,972 | 208,335 | |||||||||||||||||
Geographic Sales and other operating revenue (1) |
2007 |
2006 |
2005 | ||||||
(millions of dollars) | |||||||||
United States |
$ | 121,144 | $ | 112,787 | $ | 110,553 | |||
Non-U.S. |
269,184 | 252,680 | 248,402 | ||||||
Total |
$ | 390,328 | $ | 365,467 | $ | 358,955 | |||
Significant non-U.S. revenue sources include: |
|||||||||
Canada |
$ | 27,284 | $ | 25,281 | $ | 28,842 | |||
Japan |
26,146 | 27,368 | 28,963 | ||||||
United Kingdom |
25,113 | 24,646 | 24,805 | ||||||
Belgium |
20,550 | 16,271 | 11,281 | ||||||
Germany |
17,445 | 19,458 | 21,653 | ||||||
Italy |
16,255 | 15,332 | 17,160 | ||||||
France |
14,287 | 13,537 | 14,412 |
(1) | Sales and other operating revenue includes sales-based taxes of $31,728 million for 2007, $30,381 million for 2006 and $30,742 million for 2005. Includes $30,810 million for purchases/sales contracts with the same counterparty for 2005. Associated costs were included in Crude oil and product purchases. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income. See note 1, Summary of Accounting Policies. |
Long-lived assets |
2007 |
2006 |
2005 | ||||||
(millions of dollars) | |||||||||
United States |
$ | 33,630 | $ | 33,233 | $ | 33,117 | |||
Non-U.S. |
87,239 | 80,454 | 73,893 | ||||||
Total |
$ | 120,869 | $ | 113,687 | $ | 107,010 | |||
Significant non-U.S. long-lived assets include: |
|||||||||
Canada |
$ | 14,167 | $ | 12,323 | $ | 12,273 | |||
United Kingdom |
8,589 | 9,128 | 7,757 | ||||||
Norway |
7,920 | 6,977 | 6,472 | ||||||
Nigeria |
7,504 | 7,350 | 6,409 | ||||||
Angola |
5,084 | 4,271 | 3,803 | ||||||
Japan |
4,077 | 4,008 | 4,016 | ||||||
Singapore |
3,598 | 2,964 | 2,968 | ||||||
Australia |
3,331 | 2,966 | 2,717 |
77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. Income, Sales-Based and Other Taxes
2007 |
2006 |
2005 |
|||||||||||||||||||||||||||||
U.S. |
Non-U.S. |
Total |
U.S. |
Non-U.S. |
Total |
U.S. |
Non-U.S. |
Total |
|||||||||||||||||||||||
(millions of dollars) | |||||||||||||||||||||||||||||||
Income taxes |
|||||||||||||||||||||||||||||||
Federal and non-U.S. |
|||||||||||||||||||||||||||||||
Current |
$ | 4,666 | $ | 24,329 | $ | 28,995 | $ | 2,851 | $ | 22,666 | $ | 25,517 | $ | 5,462 | $ | 17,052 | $ | 22,514 | |||||||||||||
Deferred net |
(439 | ) | 415 | (24 | ) | 1,194 | 165 | 1,359 | (584 | ) | 362 | (222 | ) | ||||||||||||||||||
U.S. tax on non-U.S. operations |
263 | | 263 | 239 | | 239 | 208 | | 208 | ||||||||||||||||||||||
Total federal and non-U.S. |
4,490 | 24,744 | 29,234 | 4,284 | 22,831 | 27,115 | 5,086 | 17,414 | 22,500 | ||||||||||||||||||||||
State |
630 | | 630 | 787 | | 787 | 802 | | 802 | ||||||||||||||||||||||
Total income taxes |
5,120 | 24,744 | 29,864 | 5,071 | 22,831 | 27,902 | 5,888 | 17,414 | 23,302 | ||||||||||||||||||||||
Sales-based taxes |
7,154 | 24,574 | 31,728 | 7,100 | 23,281 | 30,381 | 7,072 | 23,670 | 30,742 | ||||||||||||||||||||||
All other taxes and duties |
|||||||||||||||||||||||||||||||
Other taxes and duties |
1,008 | 39,945 | 40,953 | 392 | 38,811 | 39,203 | 51 | 41,503 | 41,554 | ||||||||||||||||||||||
Included in production and manufacturing expenses |
825 | 1,445 | 2,270 | 976 | 1,431 | 2,407 | 1,182 | 1,075 | 2,257 | ||||||||||||||||||||||
Included in SG&A expenses |
215 | 653 | 868 | 211 | 572 | 783 | 202 | 558 | 760 | ||||||||||||||||||||||
Total other taxes and duties |
2,048 | 42,043 | 44,091 | 1,579 | 40,814 | 42,393 | 1,435 | 43,136 | 44,571 | ||||||||||||||||||||||
Total |
$ | 14,322 | $ | 91,361 | $ | 105,683 | $ | 13,750 | $ | 86,926 | $ | 100,676 | $ | 14,395 | $ | 84,220 | $ | 98,615 | |||||||||||||
All other taxes and duties include taxes reported in production and manufacturing and selling, general and administrative (SG&A) expenses. The above provisions for deferred income taxes include net credits for the effect of changes in tax laws and rates of $258 million in 2007, $169 million in 2006 and $199 million in 2005.
Income taxes (charged)/credited directly to shareholders equity were:
2007 |
2006 |
2005 |
||||||||||
(millions of dollars) | ||||||||||||
Cumulative foreign exchange translation adjustment |
$ | (269 | ) | $ | (36 | ) | $ | 158 | ||||
Postretirement benefits reserves adjustment: |
||||||||||||
Net actuarial loss/(gain) |
102 | |||||||||||
Amortization of actuarial loss/(gain) |
(358 | ) | ||||||||||
Prior service cost |
(23 | ) | ||||||||||
Amortization of prior service cost |
(60 | ) | ||||||||||
Foreign exchange rate changes |
132 | |||||||||||
Total postretirement benefits reserves adjustment |
(207 | ) | 3,372 | | ||||||||
Minimum pension liability adjustment |
| (1,267 | ) | (90 | ) | |||||||
Gains and losses on stock investments |
| | 236 | |||||||||
Other components of shareholders equity |
113 | 169 | 224 |
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2007, 2006 and 2005, is as follows:
2007 |
2006 |
2005 |
||||||||||
(millions of dollars) | ||||||||||||
Income before income taxes |
||||||||||||
United States |
$ | 13,700 | $ | 15,507 | $ | 16,900 | ||||||
Non-U.S. |
56,774 | 51,895 | 42,532 | |||||||||
Total |
$ | 70,474 | $ | 67,402 | $ | 59,432 | ||||||
Theoretical tax |
$ | 24,666 | $ | 23,591 | $ | 20,801 | ||||||
Effect of equity method of accounting |
(3,115 | ) | (2,445 | ) | (2,654 | ) | ||||||
Non-U.S. taxes in excess of theoretical U.S. tax |
7,364 | 6,541 | 4,719 | |||||||||
U.S. tax on non-U.S. operations |
263 | 239 | 208 | |||||||||
State taxes, net of federal tax benefit |
410 | 512 | 522 | |||||||||
Other U.S. |
276 | (536 | ) | (294 | ) | |||||||
Total income tax expense |
$ | 29,864 | $ | 27,902 | $ | 23,302 | ||||||
Effective tax rate calculation |
||||||||||||
Income taxes |
$ | 29,864 | $ | 27,902 | $ | 23,302 | ||||||
ExxonMobil share of equity company income taxes |
2,547 | 1,920 | 2,226 | |||||||||
Total income taxes |
32,411 | 29,822 | 25,528 | |||||||||
Income from continuing operations |
40,610 | 39,500 | 36,130 | |||||||||
Total income before taxes |
$ | 73,021 | $ | 69,322 | $ | 61,658 | ||||||
Effective income tax rate |
44 | % | 43 | % | 41 | % |
78
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.
Deferred tax liabilities/(assets) are comprised of the following at December 31:
Tax effects of temporary differences for: |
2007 |
2006 |
||||||
(millions of dollars) | ||||||||
Depreciation |
$ | 18,810 | $ | 17,518 | ||||
Intangible development costs |
4,890 | 4,742 | ||||||
Capitalized interest |
2,575 | 2,499 | ||||||
Other liabilities |
3,955 | 3,240 | ||||||
Total deferred tax liabilities |
$ | 30,230 | $ | 27,999 | ||||
Pension and other postretirement benefits |
$ | (3,837 | ) | $ | (4,135 | ) | ||
Tax loss carryforwards |
(2,162 | ) | (2,002 | ) | ||||
Other assets |
(5,848 | ) | (4,894 | ) | ||||
Total deferred tax assets |
$ | (11,847 | ) | $ | (11,031 | ) | ||
Asset valuation allowances |
637 | 657 | ||||||
Net deferred tax liabilities |
$ | 19,020 | $ | 17,625 | ||||
Deferred income tax (assets) and liabilities are included in the balance sheet as shown below. Deferred income tax (assets) and liabilities are classified as current or long term consistent with the classification of the related temporary difference separately by tax jurisdiction.
Balance sheet classification |
2007 |
2006 |
||||||
(millions of dollars) | ||||||||
Prepaid taxes and expenses |
$ | (2,497 | ) | $ | (1,636 | ) | ||
Other assets, including intangibles, net |
(1,451 | ) | (1,656 | ) | ||||
Accounts payable and accrued liabilities |
69 | 66 | ||||||
Deferred income tax liabilities |
22,899 | 20,851 | ||||||
Net deferred tax liabilities |
$ | 19,020 | $ | 17,625 | ||||
The Corporation had $56 billion of indefinitely reinvested, undistributed earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes on remittance of these funds are not expected to be material.
Unrecognized Tax Benefits
The Corporation is subject to income taxation in many jurisdictions around the world. The total amounts of unrecognized tax benefits at January 1, 2007, and December 31, 2007, are shown in the following table. Resolution of the related tax positions through negotiations with the relevant tax authorities or through litigation will take many years to complete. Accordingly, it is difficult to predict the timing of resolution for individual tax positions. However, the Corporation does not anticipate that the total amount of unrecognized tax benefits will significantly increase or decrease in the next 12 months. Given the long time periods involved in resolving individual tax positions, the Corporation does not expect that the recognition of unrecognized tax benefits will have a material impact on the Corporations effective income tax rate in any given year.
The following table summarizes the movement in uncertain tax benefits from January 1 to December 31, 2007. The unrecognized tax benefits are shown on both a gross basis and a net basis, reflecting the impact of funds placed on deposit with tax authorities. Such deposits do not acknowledge agreement with the tax authorities positions, but prevent further interest accretion on potential tax assessments. For balance sheet reporting, the Corporation reports unrecognized tax benefits net of such deposits where there is a legal right and intent to offset under the local tax law.
Gross Unrecognized Tax Benefits |
Deposits |
Net Unrecognized Tax Benefits |
||||||||||
(millions of dollars) | ||||||||||||
January 1, 2007, balance |
$ | 4,583 | $ | (879 | ) | $ | 3,704 | |||||
Additions based on current year tax positions |
832 | 832 | ||||||||||
Additions for prior years tax positions |
463 | 463 | ||||||||||
Reductions for prior years tax positions |
(609 | ) | (609 | ) | ||||||||
Reductions due to a lapse of the statute of limitations |
(84 | ) | (84 | ) | ||||||||
Settlements with tax authorities |
(25 | ) | (25 | ) | ||||||||
Foreign exchange effects/change in deposit balance |
72 | 109 | 181 | |||||||||
December 31, 2007, balance |
$ | 5,232 | $ | (770 | ) | $ | 4,462 | |||||
The additions and reductions in unrecognized tax benefits shown above include effects related to net income and shareholders equity, and timing differences for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. The 2007 changes in unrecognized tax benefits did not have a material effect on the Corporations net income or cash flow.
The following table summarizes the tax years that remain subject to examination by major tax jurisdiction:
Country of Operation |
Open Tax Years | |
Abu Dhabi |
2000 - 2007 | |
Angola |
2002 - 2007 | |
Australia |
2000 - 2007 | |
Canada |
1990 - 2007 | |
Equatorial Guinea |
2004 - 2007 | |
Germany |
1998 - 2007 | |
Japan |
2002 - 2007 | |
Malaysia |
1983 - 2007 | |
Nigeria |
1998 - 2007 | |
Norway |
1993 - 2007 | |
United Kingdom |
2003 - 2007 | |
United States |
1989 - 2007 |
The Corporation classifies interest on income tax-related balances as interest expense or interest income and classifies tax-related penalties as operating expense.
The Corporation incurred approximately $128 million in interest expense on income tax reserves in 2007 and had a related interest payable of $597 million at December 31, 2007.
79
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
The results of operations for producing activities shown below are presented in accordance with Statement of Financial Accounting Standards No. 69. As such, they do not include earnings from other activities that ExxonMobil includes in the Upstream function such as oil and gas transportation operations, oil sands operations, LNG liquefaction and transportation operations, coal and power operations, technical services agreements, other nonoperating activities and adjustments for minority interests. These excluded amounts for both consolidated and equity companies totaled $2,271 million in 2007, $2,431 million in 2006 and $3,546 million in 2005.
Results of Operations |
United States |
Canada/ South America |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total | ||||||||||||||
(millions of dollars) | |||||||||||||||||||||
2007 Revenue |
|||||||||||||||||||||
Sales to third parties |
$ | 3,677 | $ | 3,720 | $ | 7,282 | $ | 807 | $ | 3,363 | $ | 678 | $ | 19,527 | |||||||
Transfers |
6,554 | 2,783 | 9,780 | 17,048 | 7,276 | 2,087 | 45,528 | ||||||||||||||
$ | 10,231 | $ | 6,503 | $ | 17,062 | $ | 17,855 | $ | 10,639 | $ | 2,765 | $ | 65,055 | ||||||||
Production costs excluding taxes |
1,827 | 1,492 | 2,859 | 1,180 | 961 | 243 | 8,562 | ||||||||||||||
Exploration expenses |
280 | 264 | 164 | 470 | 226 | 67 | 1,471 | ||||||||||||||
Depreciation and depletion |
1,377 | 1,121 | 2,441 | 2,101 | 763 | 453 | 8,256 | ||||||||||||||
Taxes other than income |
1,313 | 111 | 718 | 1,599 | 2,067 | 1 | 5,809 | ||||||||||||||
Related income tax |
2,429 | 1,041 | 7,236 | 7,263 | 4,105 | 598 | 22,672 | ||||||||||||||
Results of producing activities for consolidated subsidiaries |
$ | 3,005 | $ | 2,474 | $ | 3,644 | $ | 5,242 | $ | 2,517 | $ | 1,403 | $ | 18,285 | |||||||
Proportional interest in results of producing activities of equity companies |
$ | 1,342 | $ | | $ | 1,465 | $ | | $ | 2,138 | $ | 996 | $ | 5,941 | |||||||
2006 Revenue |
|||||||||||||||||||||
Sales to third parties |
$ | 4,027 | $ | 4,390 | $ | 9,382 | $ | 1,145 | $ | 4,393 | $ | 533 | $ | 23,870 | |||||||
Transfers |
6,250 | 2,638 | 8,607 | 16,108 | 4,900 | 580 | 39,083 | ||||||||||||||
$ | 10,277 | $ | 7,028 | $ | 17,989 | $ | 17,253 | $ | 9,293 | $ | 1,113 | $ | 62,953 | ||||||||
Production costs excluding taxes |
1,916 | 1,410 | 2,290 | 965 | 824 | 118 | 7,523 | ||||||||||||||
Exploration expenses |
245 | 172 | 161 | 330 | 157 | 116 | 1,181 | ||||||||||||||
Depreciation and depletion |
1,155 | 1,023 | 2,166 | 2,096 | 674 | 305 | 7,419 | ||||||||||||||
Taxes other than income |
802 | 139 | 846 | 1,612 | 2,652 | 1 | 6,052 | ||||||||||||||
Related income tax |
2,711 | 1,143 | 8,032 | 6,878 | 2,820 | 217 | 21,801 | ||||||||||||||
Results of producing activities for consolidated subsidiaries |
$ | 3,448 | $ | 3,141 | $ | 4,494 | $ | 5,372 | $ | 2,166 | $ | 356 | $ | 18,977 | |||||||
Proportional interest in results of producing activities of equity companies |
$ | 1,236 | $ | | $ | 1,164 | $ | | $ | 1,555 | $ | 867 | $ | 4,822 | |||||||
2005 Revenue |
|||||||||||||||||||||
Sales to third parties |
$ | 4,842 | $ | 3,728 | $ | 8,383 | $ | 40 | $ | 2,357 | $ | 357 | $ | 19,707 | |||||||
Transfers |
6,277 | 3,582 | 7,040 | 12,293 | 3,143 | 279 | 32,614 | ||||||||||||||
$ | 11,119 | $ | 7,310 | $ | 15,423 | $ | 12,333 | $ | 5,500 | $ | 636 | $ | 52,321 | ||||||||
Production costs excluding taxes |
1,367 | 1,370 | 2,174 | 840 | 567 | 123 | 6,441 | ||||||||||||||
Exploration expenses |
158 | 137 | 64 | 310 | 122 | 164 | 955 | ||||||||||||||
Depreciation and depletion |
1,181 | 1,041 | 2,133 | 1,319 | 666 | 137 | 6,477 | ||||||||||||||
Taxes other than income |
738 | 56 | 690 | 1,158 | 839 | 2 | 3,483 | ||||||||||||||
Related income tax |
3,138 | 1,641 | 6,572 | 5,143 | 1,313 | 111 | 17,918 | ||||||||||||||
Results of producing activities for consolidated subsidiaries |
$ | 4,537 | $ | 3,065 | $ | 3,790 | $ | 3,563 | $ | 1,993 | $ | 99 | $ | 17,047 | |||||||
Proportional interest in results of producing activities of equity companies |
$ | 1,043 | $ | | $ | 1,003 | $ | | $ | 1,009 | $ | 701 | $ | 3,756 | |||||||
80
Average sales prices have been calculated by using sales quantities from the Corporations own production as the divisor. Average production costs have been computed by using net production quantities for the divisor. The volumes of crude oil and natural gas liquids (NGL) production used for this computation are shown in the proved reserves table of this report. The volumes for natural gas used for this calculation are the production volumes of natural gas available for sale and thus are different than those shown in the proved reserves table of this report due to volumes consumed or flared. The volumes of natural gas were converted to oil-equivalent barrels based on a conversion factor of six thousand cubic feet per barrel.
Average sales prices and production costs per unit of production consolidated subsidiaries |
United States |
Canada/ South America |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total | ||||||||||||||
During 2007 |
|||||||||||||||||||||
Average sales prices |
|||||||||||||||||||||
Crude oil and NGL, per barrel |
$ | 62.35 | $ | 50.41 | $ | 68.01 | $ | 70.00 | $ | 69.58 | $ | 69.15 | $ | 66.02 | |||||||
Natural gas, per thousand cubic feet |
5.93 | 5.77 | 6.22 | 2.26 | 3.54 | 1.79 | 5.29 | ||||||||||||||
Average production costs, per barrel (1) |
9.03 | 10.38 | 9.12 | 4.48 | 4.09 | 5.79 | 7.14 | ||||||||||||||
During 2006 |
|||||||||||||||||||||
Average sales prices |
|||||||||||||||||||||
Crude oil and NGL, per barrel |
$ | 55.13 | $ | 47.70 | $ | 59.90 | $ | 61.26 | $ | 62.02 | $ | 57.38 | $ | 58.34 | |||||||
Natural gas, per thousand cubic feet |
6.22 | 5.81 | 7.48 | | 3.87 | 2.31 | 6.08 | ||||||||||||||
Average production costs, per barrel (1) |
8.78 | 8.55 | 6.64 | 3.39 | 3.90 | 5.45 | 6.04 | ||||||||||||||
During 2005 |
|||||||||||||||||||||
Average sales prices |
|||||||||||||||||||||
Crude oil and NGL, per barrel |
$ | 46.11 | $ | 38.68 | $ | 50.32 | $ | 51.21 | $ | 52.89 | $ | 51.65 | $ | 48.23 | |||||||
Natural gas, per thousand cubic feet |
7.30 | 6.90 | 5.64 | | 4.16 | 1.35 | 5.96 | ||||||||||||||
Average production costs, per barrel (1) |
5.56 | 7.36 | 5.95 | 3.46 | 3.85 | 9.49 | 5.36 |
(1) | Production costs exclude depreciation and depletion and all taxes. Natural gas included by conversion to crude oil-equivalent. |
81
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are $6,381 million less at year-end 2007 and $5,463 million less at year-end 2006 than the amounts reported as investments in property, plant and equipment for the Upstream in note 8. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to the oil sands and LNG operations, all as required by Statement of Financial Accounting Standards No. 19.
Capitalized Costs |
United States |
Canada/ South America |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total | ||||||||||||||
(millions of dollars) | |||||||||||||||||||||
As of December 31, 2007 |
|||||||||||||||||||||
Property (acreage) costs Proved |
$ | 3,227 | $ | 4,102 | $ | 272 | $ | 200 | $ | 1,172 | $ | 521 | $ | 9,494 | |||||||
Unproved |
556 | 524 | 30 | 540 | 1,142 | 45 | 2,837 | ||||||||||||||
Total property costs |
$ | 3,783 | $ | 4,626 | $ | 302 | $ | 740 | $ | 2,314 | $ | 566 | $ | 12,331 | |||||||
Producing assets |
35,830 | 15,370 | 48,673 | 19,633 | 17,302 | 2,796 | 139,604 | ||||||||||||||
Support facilities |
694 | 269 | 619 | 461 | 1,186 | 428 | 3,657 | ||||||||||||||
Incomplete construction |
2,406 | 950 | 891 | 3,576 | 3,133 | 3,040 | 13,996 | ||||||||||||||
Total capitalized costs |
$ | 42,713 | $ | 21,215 | $ | 50,485 | $ | 24,410 | $ | 23,935 | $ | 6,830 | $ | 169,588 | |||||||
Accumulated depreciation and depletion |
27,427 | 13,529 | 36,520 | 9,261 | 14,674 | 1,034 | 102,445 | ||||||||||||||
Net capitalized costs for consolidated subsidiaries |
$ | 15,286 | $ | 7,686 | $ | 13,965 | $ | 15,149 | $ | 9,261 | $ | 5,796 | $ | 67,143 | |||||||
Proportional interest of net capitalized costs of equity companies |
$ | 1,662 | $ | | $ | 1,461 | $ | | $ | 1,413 | $ | 3,346 | $ | 7,882 | |||||||
As of December 31, 2006 |
|||||||||||||||||||||
Property (acreage) costs Proved |
$ | 3,260 | $ | 3,532 | $ | 277 | $ | 200 | $ | 1,164 | $ | 512 | $ | 8,945 | |||||||
Unproved |
574 | 429 | 31 | 523 | 1,070 | 99 | 2,726 | ||||||||||||||
Total property costs |
$ | 3,834 | $ | 3,961 | $ | 308 | $ | 723 | $ | 2,234 | $ | 611 | $ | 11,671 | |||||||
Producing assets |
34,852 | 12,800 | 44,719 | 16,748 | 16,295 | 2,324 | 127,738 | ||||||||||||||
Support facilities |
740 | 257 | 581 | 442 | 1,158 | 308 | 3,486 | ||||||||||||||
Incomplete construction |
2,273 | 893 | 1,439 | 3,533 | 1,537 | 2,605 | 12,280 | ||||||||||||||
Total capitalized costs |
$ | 41,699 | $ | 17,911 | $ | 47,047 | $ | 21,446 | $ | 21,224 | $ | 5,848 | $ | 155,175 | |||||||
Accumulated depreciation and depletion |
26,696 | 10,780 | 33,302 | 7,166 | 13,649 | 635 | 92,228 | ||||||||||||||
Net capitalized costs for consolidated subsidiaries |
$ | 15,003 | $ | 7,131 | $ | 13,745 | $ | 14,280 | $ | 7,575 | $ | 5,213 | $ | 62,947 | |||||||
Proportional interest of net capitalized costs of equity companies |
$ | 1,527 | $ | | $ | 1,437 | $ | | $ | 1,238 | $ | 3,033 | $ | 7,235 | |||||||
82
Oil and Gas Exploration and Production Costs (continued)
The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Total consolidated costs incurred in 2007 were $12,075 million, down $938 million from 2006, due primarily to lower development and property acquisition costs. 2006 costs were $13,013 million, up $2,229 million from 2005, due primarily to higher development and property acquisition costs.
Costs incurred in property acquisitions, exploration and development activities |
United States |
Canada/ South America |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total | ||||||||||||||
(millions of dollars) | |||||||||||||||||||||
During 2007 |
|||||||||||||||||||||
Property acquisition costs Proved |
$ | 24 | $ | | $ | | $ | 3 | $ | | $ | 10 | $ | 37 | |||||||
Unproved |
39 | 93 | | 10 | 15 | | 157 | ||||||||||||||
Exploration costs |
375 | 222 | 201 | 584 | 261 | 80 | 1,723 | ||||||||||||||
Development costs |
1,558 | 645 | 1,826 | 2,846 | 2,156 | 1,127 | 10,158 | ||||||||||||||
Total costs incurred for consolidated subsidiaries |
$ | 1,996 | $ | 960 | $ | 2,027 | $ | 3,443 | $ | 2,432 | $ | 1,217 | $ | 12,075 | |||||||
Proportional interest of costs incurred of equity companies |
$ | 303 | $ | | $ | 218 | $ | 1 | $ | 249 | $ | 414 | $ | 1,185 | |||||||
During 2006 |
|||||||||||||||||||||
Property acquisition costs Proved |
$ | 11 | $ | | $ | 6 | $ | | $ | 206 | $ | 11 | $ | 234 | |||||||
Unproved |
43 | | 5 | 16 | 199 | | 263 | ||||||||||||||
Exploration costs |
380 | 225 | 178 | 518 | 219 | 126 | 1,646 | ||||||||||||||
Development costs |
1,555 | 850 | 2,443 | 3,433 | 1,475 | 1,114 | 10,870 | ||||||||||||||
Total costs incurred for consolidated subsidiaries |
$ | 1,989 | $ | 1,075 | $ | 2,632 | $ | 3,967 | $ | 2,099 | $ | 1,251 | $ | 13,013 | |||||||
Proportional interest of costs incurred of equity companies |
$ | 285 | $ | | $ | 241 | $ | | $ | 243 | $ | 351 | $ | 1,120 | |||||||
During 2005 |
|||||||||||||||||||||
Property acquisition costs Proved |
$ | | $ | | $ | | $ | | $ | | $ | 174 | $ | 174 | |||||||
Unproved |
11 | 18 | | 53 | 41 | 156 | 279 | ||||||||||||||
Exploration costs |
286 | 121 | 133 | 507 | 171 | 159 | 1,377 | ||||||||||||||
Development costs |
1,426 | 722 | 1,302 | 3,189 | 541 | 1,774 | 8,954 | ||||||||||||||
Total costs incurred for consolidated subsidiaries |
$ | 1,723 | $ | 861 | $ | 1,435 | $ | 3,749 | $ | 753 | $ | 2,263 | $ | 10,784 | |||||||
Proportional interest of costs incurred of equity companies |
$ | 269 | $ | | $ | 210 | $ | | $ | 319 | $ | 384 | $ | 1,182 | |||||||
83
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
Oil and Gas Reserves
The following information describes changes during the years and balances of proved oil and gas reserves at year-end 2005, 2006 and 2007.
The definitions used are in accordance with the Securities and Exchange Commissions Rule 4-10 (a) of Regulation S-X, paragraphs (2) through (2)iii, (3) and (4).
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions. In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves.
The year-end reserves volumes as well as the reserves change categories shown in the following tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. We understand that the use of December 31 prices and costs is intended to provide a point in time measure to calculate reserves and to enhance comparability between companies.
Regulations preclude the Corporation from showing in this document, however, the reserves that are calculated in a manner that is consistent with the basis that the Corporation uses to make its investment decisions. The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments are required based on prices occurring on a single day. The Corporation believes that this approach is inconsistent with the long-term nature of the upstream business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the Corporation and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in year-end prices and costs that are used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.
Proved reserves include 100 percent of each majority-owned affiliates participation in proved reserves and ExxonMobils ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.
In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, the Corporation does not view equity company reserves any differently than those from consolidated companies.
Reserves reported under production sharing and other nonconcessionary agreements are based on the economic interest as defined by the specific fiscal terms in the agreement. The percentage of conventional liquids and natural gas proved reserves (consolidated subsidiaries plus equity companies) at year-end 2007 that were associated with production sharing contract arrangements was 18 percent of liquids, 13 percent of natural gas and 15 percent on an oil-equivalent basis (gas converted to oil-equivalent at 6 billion cubic feet = 1 million barrels).
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells.
Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobils oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported in the Operating Summary due to volumes consumed or flared and inventory changes.
84
Crude Oil and Natural Gas Liquids |
United States |
Canada/ South America (1) |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total |
||||||||||||||
(millions of barrels) | |||||||||||||||||||||
Net proved developed and undeveloped reserves of consolidated subsidiaries |
|||||||||||||||||||||
January 1, 2005 |
2,593 | 1,105 | 1,014 | 2,444 | 515 | 724 | 8,395 | ||||||||||||||
Revisions |
(256 | ) | 336 | 17 | (8 | ) | 78 | (27 | ) | 140 | |||||||||||
Purchases |
| | | | | 93 | 93 | ||||||||||||||
Sales |
(96 | ) | (49 | ) | (1 | ) | | (11 | ) | (70 | ) | (227 | ) | ||||||||
Improved recovery |
2 | | 3 | | | | 5 | ||||||||||||||
Extensions and discoveries |
6 | 16 | 47 | 120 | | | 189 | ||||||||||||||
Production |
(136 | ) | (125 | ) | (197 | ) | (244 | ) | (67 | ) | (13 | ) | (782 | ) | |||||||
December 31, 2005 |
2,113 | 1,283 | 883 | 2,312 | 515 | 707 | 7,813 | ||||||||||||||
Revisions |
(99 | ) | 247 | 50 | 24 | 19 | 105 | 346 | |||||||||||||
Purchases |
4 | | 8 | | 734 | | 746 | ||||||||||||||
Sales |
(41 | ) | (27 | ) | (18 | ) | | | | (86 | ) | ||||||||||
Improved recovery |
21 | | | | | | 21 | ||||||||||||||
Extensions and discoveries |
2 | | 13 | 38 | 133 | | 186 | ||||||||||||||
Production |
(116 | ) | (108 | ) | (188 | ) | (285 | ) | (114 | ) | (21 | ) | (832 | ) | |||||||
December 31, 2006 |
1,884 | 1,395 | 748 | 2,089 | 1,287 | 791 | 8,194 | ||||||||||||||
Revisions |
76 | 15 | 89 | 99 | 342 | (38 | ) | 583 | |||||||||||||
Purchases |
| | | | | | | ||||||||||||||
Sales |
(8 | ) | (426 | )(2) | (1 | ) | | | | (435 | ) | ||||||||||
Improved recovery |
8 | 5 | 8 | 4 | | | 25 | ||||||||||||||
Extensions and discoveries |
2 | 45 | 2 | 128 | 1 | | 178 | ||||||||||||||
Production |
(111 | ) | (95 | ) | (173 | ) | (262 | ) | (120 | ) | (40 | ) | (801 | ) | |||||||
December 31, 2007 |
1,851 | 939 | 673 | 2,058 | 1,510 | 713 | 7,744 | ||||||||||||||
Proportional interest in proved reserves of equity companies |
|||||||||||||||||||||
End of year 2005 |
413 | | 11 | | 1,381 | 873 | 2,678 | ||||||||||||||
End of year 2006 |
391 | | 12 | | 1,412 | 841 | 2,656 | ||||||||||||||
End of year 2007 |
374 | | 26 | | 1,428 | 808 | 2,636 | ||||||||||||||
Proved developed reserves, included above, as of December 31, 2005 |
|||||||||||||||||||||
Consolidated subsidiaries |
1,680 | 834 | 656 | 1,218 | 464 | 55 | 4,907 | ||||||||||||||
Equity companies |
326 | | 9 | | 725 | 574 | 1,634 | ||||||||||||||
Proved developed reserves, included above, as of December 31, 2006 |
|||||||||||||||||||||
Consolidated subsidiaries |
1,466 | 902 | 557 | 1,279 | 1,090 | 108 | 5,402 | ||||||||||||||
Equity companies |
311 | | 11 | | 630 | 544 | 1,496 | ||||||||||||||
Proved developed reserves, included above, as of December 31, 2007 |
|||||||||||||||||||||
Consolidated subsidiaries |
1,327 | 682 | 518 | 1,202 | 1,127 | 91 | 4,947 | ||||||||||||||
Equity companies |
299 | | 8 | | 670 | 511 | 1,488 |
(1) | Includes total proved reserves attributable to Imperial Oil Limited of 634 million barrels in 2005, 812 million barrels in 2006 and 799 million barrels in 2007, as well as proved developed reserves of 449 million barrels in 2005, 572 million barrels in 2006 and 565 million barrels in 2007, in which there is a 30.4 percent minority interest. |
(2) | Includes 425 million barrels of proved reserves in Venezuela which were expropriated. See note 15, Litigation and Other Contingencies. |
85
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
Oil and Gas Reserves (continued)
Natural Gas |
United States |
Canada/ South America (1) |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total |
||||||||||||||
(billions of cubic feet) | |||||||||||||||||||||
Net proved developed and undeveloped reserves of consolidated subsidiaries |
|||||||||||||||||||||
January 1, 2005 |
12,329 | 2,652 | 9,185 | 771 | 6,391 | 515 | 31,843 | ||||||||||||||
Revisions |
1,943 | 83 | 242 | 35 | 1,402 | (18 | ) | 3,687 | |||||||||||||
Purchases |
| | | | | 53 | 53 | ||||||||||||||
Sales |
(105 | ) | (25 | ) | (73 | ) | | | (26 | ) | (229 | ) | |||||||||
Improved recovery |
| | | | | | | ||||||||||||||
Extensions and discoveries |
289 | 26 | 116 | 57 | 32 | 300 | 820 | ||||||||||||||
Production |
(764 | ) | (412 | ) | (1,072 | ) | (22 | ) | (546 | ) | (3 | ) | (2,819 | ) | |||||||
December 31, 2005 |
13,692 | 2,324 | 8,398 | 841 | 7,279 | 821 | 33,355 | ||||||||||||||
Revisions |
(1,179 | ) | 73 | (457 | ) | 170 | 414 | (20 | ) | (999 | ) | ||||||||||
Purchases |
19 | | 38 | | | | 57 | ||||||||||||||
Sales |
(57 | ) | (44 | ) | (3 | ) | | | | (104 | ) | ||||||||||
Improved recovery |
12 | | | | | | 12 | ||||||||||||||
Extensions and discoveries |
268 | 10 | 117 | 1 | 2,534 | | 2,930 | ||||||||||||||
Production |
(706 | ) | (379 | ) | (1,004 | ) | (26 | ) | (644 | ) | (12 | ) | (2,771 | ) | |||||||
December 31, 2006 |
12,049 | 1,984 | 7,089 | 986 | 9,583 | 789 | 32,480 | ||||||||||||||
Revisions |
1,566 | 124 | 375 | (22 | ) | 813 | (43 | ) | 2,813 | ||||||||||||
Purchases |
9 | | | | | | 9 | ||||||||||||||
Sales |
(19 | ) | (231 | )(2) | (70 | ) | | | | (320 | ) | ||||||||||
Improved recovery |
| 1 | | | | | 1 | ||||||||||||||
Extensions and discoveries |
208 | 8 | 13 | 81 | | | 310 | ||||||||||||||
Production |
(641 | ) | (327 | ) | (895 | ) | (39 | ) | (762 | ) | (19 | ) | (2,683 | ) | |||||||
December 31, 2007 |
13,172 | 1,559 | 6,512 | 1,006 | 9,634 | 727 | 32,610 | ||||||||||||||
Proportional interest in proved reserves of equity companies |
|||||||||||||||||||||
End of year 2005 |
136 | | 13,024 | | 19,119 | 1,273 | 33,552 | ||||||||||||||
End of year 2006 |
131 | | 12,551 | | 21,184 | 1,214 | 35,080 | ||||||||||||||
End of year 2007 |
125 | | 12,341 | | 21,733 | 1,453 | 35,652 | ||||||||||||||
(1) | Includes total proved reserves attributable to Imperial Oil Limited of 747 billion cubic feet in 2005, 710 billion cubic feet in 2006 and 635 billion cubic feet in 2007, in which there is a 30.4 percent minority interest. |
(2) | Includes 219 billion cubic feet of proved reserves in Venezuela which were expropriated. See note 15, Litigation and Other Contingencies. |
86
Natural Gas (continued) |
United States |
Canada/ South America (1) |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total | |||||||
(billions of cubic feet) | ||||||||||||||
Proved developed reserves, included above, as of December 31, 2005 |
||||||||||||||
Consolidated subsidiaries |
10,386 | 1,840 | 6,332 | 376 | 6,067 | 227 | 25,228 | |||||||
Equity companies |
113 | | 10,226 | | 7,276 | 835 | 18,450 | |||||||
Proved developed reserves, included above, as of December 31, 2006 |
||||||||||||||
Consolidated subsidiaries |
9,280 | 1,628 | 5,346 | 823 | 5,882 | 447 | 23,406 | |||||||
Equity companies |
109 | | 9,985 | | 7,906 | 811 | 18,811 | |||||||
Proved developed reserves, included above, as of December 31, 2007 |
||||||||||||||
Consolidated subsidiaries |
8,373 | 1,303 | 5,064 | 773 | 5,570 | 395 | 21,478 | |||||||
Equity companies |
104 | | 9,679 | | 8,702 | 757 | 19,242 |
(1) | Includes proved developed reserves attributable to Imperial Oil Limited of 643 billion cubic feet in 2005, 608 billion cubic feet in 2006 and 539 billion cubic feet in 2007, in which there is a 30.4 percent minority interest. |
INFORMATION ON CANADIAN OIL SANDS PROVEN RESERVES NOT INCLUDED ABOVE
In addition to conventional liquids and natural gas proved reserves, ExxonMobil has significant interests in proven oil sands reserves in Canada associated with the Syncrude project. For internal management purposes, ExxonMobil views these reserves and their development as an integral part of total upstream operations. However, for financial reporting purposes, these reserves are required to be reported separately from the oil and gas reserves.
The oil sands reserves are not considered in the standardized measure of discounted future cash flows for conventional oil and gas reserves, which is on the following page.
Oil Sands Reserves |
Canada (1) | |
(millions of barrels) | ||
At December 31, 2005 |
738 | |
At December 31, 2006 |
718 | |
At December 31, 2007 |
694 |
(1) | Oil sands proven reserves are attributable to Imperial Oil Limited, in which there is a 30.4 percent minority interest. |
87
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (unaudited)
Standardized Measure of Discounted Future Cash Flows
As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year-end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Corporation believes the standardized measure does not provide a reliable estimate of the Corporations expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including year-end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change.
Standardized Measure of Discounted Future Cash Flows |
United States |
Canada/ South America (1) |
Europe |
Africa |
Asia Pacific/ Middle East |
Russia/ Caspian |
Total | ||||||||||||||
(millions of dollars) | |||||||||||||||||||||
Consolidated subsidiaries |
|||||||||||||||||||||
As of December 31, 2005 |
|||||||||||||||||||||
Future cash inflows from sales of oil and gas |
$ | 200,119 | $ | 54,953 | $ | 107,127 | $ | 127,584 | $ | 44,411 | $ | 35,757 | $ | 569,951 | |||||||
Future production costs |
34,100 | 14,460 | 19,958 | 21,856 | 12,515 | 5,324 | 108,213 | ||||||||||||||
Future development costs |
8,935 | 3,562 | 8,552 | 12,464 | 2,651 | 4,000 | 40,164 | ||||||||||||||
Future income tax expenses |
67,581 | 12,343 | 47,999 | 51,610 | 13,151 | 6,608 | 199,292 | ||||||||||||||
Future net cash flows |
$ | 89,503 | $ | 24,588 | $ | 30,618 | $ | 41,654 | $ | 16,094 | $ | 19,825 | $ | 222,282 | |||||||
Effect of discounting net cash flows at 10% |
53,919 | 10,641 | 9,988 | 15,337 | 6,800 | 12,379 | 109,064 | ||||||||||||||
Discounted future net cash flows |
$ | 35,584 | $ | 13,947 | $ | 20,630 | $ | 26,317 | $ | 9,294 | $ | 7,446 | $ | 113,218 | |||||||
Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies |
$ | 7,000 | $ | | $ | 11,043 | $ | | $ | 34,214 | $ | 7,735 | $ | 59,992 | |||||||
Consolidated subsidiaries |
|||||||||||||||||||||
As of December 31, 2006 |
|||||||||||||||||||||
Future cash inflows from sales of oil and gas |
$ | 139,843 | $ | 61,187 | $ | 83,854 | $ | 117,068 | $ | 100,751 | $ | 42,264 | $ | 544,967 | |||||||
Future production costs |
39,829 | 20,639 | 19,134 | 22,316 | 36,008 | 3,597 | 141,523 | ||||||||||||||
Future development costs |
11,134 | 4,023 | 10,245 | 10,429 | 6,098 | 5,307 | 47,236 | ||||||||||||||
Future income tax expenses |
42,665 | 12,951 | 34,050 | 48,235 | 35,200 | 8,156 | 181,257 | ||||||||||||||
Future net cash flows |
$ | 46,215 | $ | 23,574 | $ | 20,425 | $ | 36,088 | $ | 23,445 | $ | 25,204 | $ | 174,951 | |||||||
Effect of discounting net cash flows at 10% |
28,428 | 11,429 | 6,464 | 12,069 | 12,777 | 16,932 | 88,099 | ||||||||||||||
Discounted future net cash flows |
$ | 17,787 | $ | 12,145 | $ | 13,961 | $ | 24,019 | $ | 10,668 | $ | 8,272 | $ | 86,852 | |||||||
Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies |
$ | 6,337 | $ | | $ | 7,952 | $ | | $ | 27,136 | $ | 8,490 | $ | 49,915 | |||||||
Consolidated subsidiaries |
|||||||||||||||||||||
As of December 31, 2007 |
|||||||||||||||||||||
Future cash inflows from sales of oil and gas |
$ | 216,287 | $ | 49,985 | $ | 115,741 | $ | 184,358 | $ | 158,292 | $ | 64,351 | $ | 789,014 | |||||||
Future production costs |
59,154 | 17,422 | 21,356 | 34,721 | 38,098 | 6,537 | 177,288 | ||||||||||||||
Future development costs |
13,422 | 5,487 | 10,166 | 21,258 | 5,903 | 7,513 | 63,749 | ||||||||||||||
Future income tax expenses |
63,042 | 7,383 | 54,065 | 75,441 | 83,349 | 13,387 | 296,667 | ||||||||||||||
Future net cash flows |
$ | 80,669 | $ | 19,693 | $ | 30,154 | $ | 52,938 | $ | 30,942 | $ | 36,914 | $ | 251,310 | |||||||
Effect of discounting net cash flows at 10% |
51,521 | 7,607 | 9,515 | 20,099 | 14,021 | 25,935 | 128,698 | ||||||||||||||
Discounted future net cash flows |
$ | 29,148 | $ | 12,086 | $ | 20,639 | $ | 32,839 | $ | 16,921 | $ | 10,979 | $ | 122,612 | |||||||
Proportional interest in standardized measure of discounted future net cash flows related to proved reserves of equity companies |
$ | 12,045 | $ | | $ | 11,041 | $ | | $ | 53,067 | $ | 15,791 | $ | 91,944 | |||||||
(1) | Includes discounted future net cash flows attributable to Imperial Oil Limited of $3,723 million in 2005, $5,505 million in 2006 and $6,304 million in 2007, in which there is a 30.4 percent minority interest. |
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Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries |
2007 |
2006 |
2005 |
|||||||||
(millions of dollars) | ||||||||||||
Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs |
$ | (1,680 | )(1) | $ | 14,316 | $ | 4,619 | |||||
Changes in value of previous-year reserves due to: |
||||||||||||
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs |
(51,093 | ) | (49,732 | ) | (42,606 | ) | ||||||
Development costs incurred during the year |
9,668 | 9,465 | 8,617 | |||||||||
Net change in prices, lifting and development costs |
108,967 | (35,342 | ) | 85,049 | ||||||||
Revisions of previous reserves estimates |
15,855 | 9,438 | 9,050 | |||||||||
Accretion of discount |
15,267 | 17,368 | 9,021 | |||||||||
Net change in income taxes |
(61,224 | ) | 8,121 | (41,616 | ) | |||||||
Total change in the standardized measure during the year |
$ | 35,760 | $ | (26,366 | ) | $ | 32,134 | |||||
(1) | Includes impact of expropriation of proved reserves in Venezuela. See note 15, Litigation and Other Contingencies. |
89
2007 |
2006 |
2005 |
2004 |
2003 |
||||||||
(thousands of barrels daily) | ||||||||||||
Production of crude oil and natural gas liquids |
||||||||||||
Net production |
||||||||||||
United States |
392 | 414 | 477 | 557 | 610 | |||||||
Canada/South America |
324 | 354 | 395 | 408 | 411 | |||||||
Europe |
480 | 520 | 546 | 583 | 579 | |||||||
Africa |
717 | 781 | 666 | 572 | 442 | |||||||
Asia Pacific/Middle East |
518 | 485 | 332 | 360 | 386 | |||||||
Russia/Caspian |
185 | 127 | 107 | 91 | 88 | |||||||
Worldwide |
2,616 | 2,681 | 2,523 | 2,571 | 2,516 | |||||||
(millions of cubic feet daily) | ||||||||||||
Natural gas production available for sale |
||||||||||||
Net production |
||||||||||||
United States |
1,468 | 1,625 | 1,739 | 1,947 | 2,246 | |||||||
Canada/South America |
808 | 935 | 1,006 | 1,069 | 1,044 | |||||||
Europe |
3,810 | 4,086 | 4,315 | 4,614 | 4,498 | |||||||
Africa |
26 | | | | | |||||||
Asia Pacific/Middle East |
3,162 | 2,596 | 2,114 | 2,161 | 2,258 | |||||||
Russia/Caspian |
110 | 92 | 77 | 73 | 73 | |||||||
Worldwide |
9,384 | 9,334 | 9,251 | 9,864 | 10,119 | |||||||
(thousands of oil-equivalent barrels daily) | ||||||||||||
Oil-equivalent production (1) |
4,180 | 4,237 | 4,065 | 4,215 | 4,203 | |||||||
(thousands of barrels daily) | ||||||||||||
Refinery throughput |
||||||||||||
United States |
1,746 | 1,760 | 1,794 | 1,850 | 1,806 | |||||||
Canada |
442 | 442 | 466 | 468 | 450 | |||||||
Europe |
1,642 | 1,672 | 1,672 | 1,663 | 1,566 | |||||||
Asia Pacific |
1,416 | 1,434 | 1,490 | 1,423 | 1,390 | |||||||
Other Non-U.S. |
325 | 295 | 301 | 309 | 298 | |||||||
Worldwide |
5,571 | 5,603 | 5,723 | 5,713 | 5,510 | |||||||
Petroleum product sales (2) |
||||||||||||
United States |
2,717 | 2,729 | 2,822 | 2,872 | 2,729 | |||||||
Canada |
461 | 473 | 498 | 615 | 602 | |||||||
Europe |
1,773 | 1,813 | 1,824 | 2,139 | 2,061 | |||||||
Asia Pacific and other Eastern Hemisphere |
1,701 | 1,763 | 1,902 | 2,080 | 2,075 | |||||||
Latin America |
447 | 469 | 473 | 504 | 490 | |||||||
Purchases/sales with the same counterparty included above |
| | | (699 | ) | (687 | ) | |||||
Worldwide |
7,099 | 7,247 | 7,519 | 7,511 | 7,270 | |||||||
Gasoline, naphthas |
2,850 | 2,866 | 2,957 | 3,301 | 3,238 | |||||||
Heating oils, kerosene, diesel oils |
2,094 | 2,191 | 2,230 | 2,517 | 2,432 | |||||||
Aviation fuels |
641 | 651 | 676 | 698 | 662 | |||||||
Heavy fuels |
715 | 682 | 689 | 659 | 638 | |||||||
Specialty petroleum products |
799 | 857 | 967 | 1,035 | 987 | |||||||
Purchases/sales with the same counterparty included above |
| | | (699 | ) | (687 | ) | |||||
Worldwide |
7,099 | 7,247 | 7,519 | 7,511 | 7,270 | |||||||
(thousands of metric tons) | ||||||||||||
Chemical prime product sales |
||||||||||||
United States |
10,855 | 10,703 | 10,369 | 11,521 | 10,740 | |||||||
Non-U.S. |
16,625 | 16,647 | 16,408 | 16,267 | 15,827 | |||||||
Worldwide |
27,480 | 27,350 | 26,777 | 27,788 | 26,567 | |||||||
Operating statistics include 100 percent of operations of majority-owned subsidiaries; for other companies, crude production, gas, petroleum product and chemical prime product sales include ExxonMobils ownership percentage and refining throughput includes quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is made in kind or cash.
(1) | Gas converted to oil-equivalent at 6 million cubic feet = 1 thousand barrels. |
(2) | 2007, 2006 and 2005 petroleum product sales data reported net of purchases/sales contracts with the same counterparty. |
90
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
EXXON MOBIL CORPORATION | ||
By: |
/s/ REX W. TILLERSON | |
(Rex W. Tillerson, Chairman of the Board) |
Dated February 28, 2008
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints William M. Colton, Richard E. Gutman and David S. Rosenthal, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ REX W. TILLERSON (Rex W. Tillerson) |
Chairman of the Board (Principal Executive Officer) |
February 28, 2008 | ||
/s/ MICHAEL J. BOSKIN (Michael J. Boskin) |
Director | February 28, 2008 | ||
/s/ LARRY R. FAULKNER (Larry R. Faulkner) |
Director | February 28, 2008 |
91
/s/ WILLIAM W. GEORGE (William W. George) |
Director | February 28, 2008 | ||
/s/ JAMES R. HOUGHTON (James R. Houghton) |
Director | February 28, 2008 | ||
/s/ WILLIAM R. HOWELL (William R. Howell) |
Director | February 28, 2008 | ||
/s/ REATHA CLARK KING (Reatha Clark King) |
Director | February 28, 2008 | ||
/s/ PHILIP E. LIPPINCOTT (Philip E. Lippincott) |
Director | February 28, 2008 | ||
/s/ MARILYN CARLSON NELSON (Marilyn Carlson Nelson) |
Director | February 28, 2008 | ||
/s/ SAMUEL J. PALMISANO (Samuel J. Palmisano) |
Director | February 28, 2008 | ||
/s/ STEVEN S REINEMUND (Steven S Reinemund) |
Director | February 28, 2008 | ||
/s/ WALTER V. SHIPLEY (Walter V. Shipley) |
Director | February 28, 2008 | ||
/s/ J. STEPHEN SIMON (J. Stephen Simon) |
Director | February 28, 2008 | ||
/s/ DONALD D. HUMPHREYS (Donald D. Humphreys) |
Treasurer (Principal Financial Officer) |
February 28, 2008 | ||
/s/ PATRICK T. MULVA (Patrick T. Mulva) |
Controller (Principal Accounting Officer) |
February 28, 2008 |
92
3(i). | Restated Certificate of Incorporation, as restated November 30, 1999, and as further amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the Registrants Quarterly Report on Form 10-Q for the quarter ended June 30, 2006). |
|||
3(ii). | By-Laws, as revised to July 31, 2002 (incorporated by reference to Exhibit 3(ii) to the Registrants Quarterly Report on Form 10-Q for the quarter ended June 30, 2007). |
|||
10(iii)(a.1). | 2003 Incentive Program (incorporated by reference to Appendix B to the Proxy Statement of Exxon Mobil Corporation dated April 17, 2003).* |
|||
10(iii)(a.2). | Form of stock option granted to executive officers (incorporated by reference to Exhibit 10(iii)(a.2) to the Registrants Annual Report on Form 10-K for 2004).* |
|||
10(iii)(a.3). | Form of restricted stock agreement with executive officers (incorporated by reference to Exhibit 99.2 to the Registrants Report on Form 8-K on December 4, 2007).* |
|||
10(iii)(b.1). | Short Term Incentive Program, as amended (incorporated by reference to Exhibit 99.2 to the Registrants Report on Form 8-K on November 2, 2007).* |
|||
10(iii)(b.2). | Form of Earnings Bonus Unit granted to executive officers (incorporated by reference to Exhibit 99.1 to the Registrants Report on Form 8-K on December 4, 2007).* |
|||
10(iii)(c.1). | ExxonMobil Supplemental Savings Plan (incorporated by reference to Exhibit 99.1 to the Registrants Report on Form 8-K on November 2, 2007).* |
|||
10(iii)(c.2). | ExxonMobil Supplemental Pension Plan (incorporated by reference to Exhibit 10(iii)(c.2) to the Registrants Report on Form 8-K on October 12, 2006).* |
|||
10(iii)(c.3). | ExxonMobil Additional Payments Plan (incorporated by reference to Exhibit 10(iii)(c.3) to the Registrants Report on Form 8-K on October 12, 2006).* |
|||
10(iii)(d). | ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the Registrants Quarterly Report on Form 10-Q for the quarter ended September 30, 2007).* |
|||
10(iii)(f.1). | 2004 Non-Employee Director Restricted Stock Plan (incorporated by reference to Appendix B to the Proxy Statement of Exxon Mobil Corporation dated April 14, 2004).* |
|||
10(iii)(f.2). | Standing resolution for non-employee director restricted grants dated September 26, 2007 (incorporated by reference to Exhibit 99.2 to the Registrants Report on Form 8-K on September 27, 2007).* |
|||
10(iii)(f.3). | Form of restricted stock grant letter for non-employee directors (incorporated by reference to Exhibit 99.3 to the Registrants Report on Form 8-K on January 4, 2005).* |
|||
10(iii)(f.4). | Standing resolution for non-employee director cash fees dated September 26, 2007 (incorporated by reference to Exhibit 99.3 to the Registrants Report on Form 8-K on September 27, 2007).* |
93
INDEX TO EXHIBITS(continued)
10(iii)(f.5). | 2001 Nonemployee Directors Deferred Compensation Plan, as amended and restated on September 27, 2007 (incorporated by reference to Exhibit 99.4 to the Registrants Report on Form 8-K on September 27, 2007).* |
|||
10(iii)(g.1). | 1995 Mobil Incentive Compensation and Stock Ownership Plan (incorporated by reference to Exhibit 10(iii)(g.1) to the Registrants Annual Report on Form 10-K for 2005).* |
|||
10(iii)(g.2). | Form of stock option granted to Mobil executive officers (incorporated by reference to Exhibit 10(iii)(g.2) to the Registrants Annual Report on Form 10-K for 2004).* |
|||
10(iii)(g.3). | 1984 Mobil Compensation Management Retention Plan, as amended and restated on September 27, 2007 (incorporated by reference to Exhibit 99.1 to the Registrants Report on Form 8-K on September 27, 2007).* |
|||
12. | Computation of ratio of earnings to fixed charges. |
|||
14. | Code of Ethics and Business Conduct (incorporated by reference to Exhibit 14 to the Registrants Annual Report on Form 10-K for 2003). |
|||
21. | Subsidiaries of the registrant. |
|||
23. | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm. |
|||
31.1 |
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Chief Executive Officer. |
|||
31.2 |
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Financial Officer. |
|||
31.3 |
Certification (pursuant to Securities Exchange Act Rule 13a-14(a)) by Principal Accounting Officer. |
|||
32.1 |
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Chief Executive Officer. |
|||
32.2 |
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Financial Officer. |
|||
32.3 |
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Accounting Officer. |
* | Compensatory plan or arrangement required to be identified pursuant to Item 15(a)(3) of this Annual Report on Form 10-K. |
The registrant has not filed with this report copies of the instruments defining the rights of holders of long-term debt of the registrant and its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed. The registrant agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon request.
94