2001 ================================================================================ 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, 2001 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 13-5409005 (State or other (I.R.S. jurisdiction Employer Identification of incorporation or Number) organization) 5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298 (Address of principal executive offices) (Zip Code) (972) 444-1000 (Registrant's telephone number, including area code) ----------------- Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange Title of Each Class on Which Registered ------------------- ----------------------- Common Stock, without par value (6,792,598,170 shares outstanding at February 28, 2002) 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 Exxon Capital Corporation Twelve Year 6% Notes due July 1, 2005 New York Stock Exchange
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 _(X)_ No ____ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ___ The aggregate market value of the voting stock held by non-affiliates of the registrant on February 28, 2002, based on the closing price on that date of $41.30 on the New York Stock Exchange composite tape, was in excess of $280 billion. Documents Incorporated by Reference: Proxy Statement for the 2002 Annual Meeting of Shareholders (Part III) ================================================================================ EXXON MOBIL CORPORATION FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 TABLE OF CONTENTS
Page Number ------ PART I Item 1. Business.................................................................. 1-2 Item 2. Properties................................................................ 2-16 Item 3. Legal Proceedings......................................................... 16 Item 4. Submission of Matters to a Vote of Security Holders....................... 16 Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]..................................................................... 17 PART II Item 5. Market for Registrant's Common Stock and Related Shareholder Matters...... 18 Item 6. Selected Financial Data................................................... 18 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................................................ 18 Item 7A. Quantitative and Qualitative Disclosures About Market Risk................ 19 Item 8. Financial Statements and Supplementary Data............................... 19 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................................................ 19 PART III Item 10. Directors and Executive Officers of the Registrant........................ 19 Item 11. Executive Compensation.................................................... 19 Item 12. Security Ownership of Certain Beneficial Owners and Management............ 19 Item 13. Certain Relationships and Related Transactions............................ 19 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 19 Financial Section.................................................................. 20-62 Signatures......................................................................... 63-65 Index to Exhibits.................................................................. 66 Exhibit 12 -- Computation of Ratio of Earnings to Fixed Charges
PART I Item 1. Business. Exxon Mobil Corporation ("ExxonMobil"), formerly named Exxon Corporation, was incorporated in the State of New Jersey in 1882. On November 30, 1999, Mobil Corporation ("Mobil") became a wholly-owned subsidiary of Exxon Corporation ("Exxon") and Exxon changed its name to Exxon Mobil Corporation. Divisions and affiliated companies of ExxonMobil operate or market products in the United States and about 200 other countries and territories. 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 basic petrochemicals, including olefins, aromatics, polyethylene and polypropylene plastics and a wide variety of specialty products. ExxonMobil is engaged in exploration for, and mining and sale of coal, copper and other minerals. 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. In 2001, the corporation spent $1,782 million (of which $505 million were capital expenditures) on environmental projects and expenses worldwide, mostly dealing with air and water conservation. Total expenditures for such activities are expected to be about $2.5 billion in both 2002 and 2003 (with capital expenditures representing about 50 percent of the total). The projected increase is primarily for capital projects to implement refining technology to manufacture low-sulfur motor fuels in many parts of the world. Operating data and industry segment information for the corporation are contained on pages 55, 56 and 62; information on oil and gas reserves is contained on pages 59 and 60 and information on company-sponsored research and development activities is contained on page 40 of the Financial Section of this report. Factors Affecting Future Results - -------------------------------- 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 industry and individual consumers. The corporation competes with other firms in the sale or purchase of various goods or services in many national and international markets and employs all methods of competition which are lawful and appropriate for such purposes. A key component of the corporation's competitive position, particularly given the commodity-based nature of many of its products, is its ability to manage operating expenses successfully, which requires continuous management focus on reducing unit costs and improving efficiency. Political 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 instability and by other political developments and laws and regulations, such as forced divestiture of assets; restrictions on production, imports and exports; war or other international conflicts; civil unrest and local security concerns that threaten the safe operation of company facilities; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of 1 contract rights; and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the corporation vary greatly from country to country and are not predictable. Industry and Economic Factors: The operations and earnings of the corporation and its affiliates throughout the world are affected by local, regional and global events or conditions that affect supply and demand for oil, natural gas, petroleum products, petrochemicals and other ExxonMobil products. 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 energy demand and severe weather events that can disrupt operations; 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 energy sources or product substitutes. Project Factors: In addition to the factors cited above, the advancement, cost and results of particular ExxonMobil projects depend on the outcome of negotiations with partners, governments, suppliers, customers or others; changes in operating conditions or costs; and the occurrence of unforeseen technical difficulties. Market Risk Factors: See pages 29 and 30 of the Financial Section of this report for discussion of the impact of market risks, inflation and other uncertainties. Projections, estimates and descriptions of ExxonMobil's plans and objectives included or incorporated in Items 1, 2, 7 and 7A of this report are forward-looking statements. Actual future results, including project completion dates, production rates, capital expenditures, costs and business plans could differ materially due to, among other things, the factors discussed above and elsewhere in this report. Item 2. Properties. Part of the information in response to this item and to the Securities Exchange Act Industry Guide 2 is contained in the Financial Section of this report in Note 10, which note appears on page 42, and on pages 57 through 62. Information with regard to oil and gas producing activities follows: - ------------------------------------------------------------------- 1. Net Reserves of Crude Oil and Natural Gas Liquids (millions of barrels) and Natural Gas (billions of cubic feet) at Year-End 2001 Estimated proved reserves are shown on pages 59 and 60 of the Financial Section of this report. No major discovery or other favorable or adverse event has occurred since December 31, 2001, 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 page 61 of the Financial Section of this report. 2. Estimates of Total Net Proved Oil and Gas Reserves Filed with Other Federal Agencies During 2001, ExxonMobil filed proved reserves estimates with the U.S. Department of Energy on Forms EIA-23 and EIA-28. The information on Form EIA-28 is presented on the same basis as the registrant's Annual Report on Form 10-K for 2000, which shows ExxonMobil's net interests in all liquids and gas reserve volumes and changes thereto from both ExxonMobil-operated properties and properties operated by others. The data on Form EIA-23, although consistent with the data on 2 Form EIA-28, is presented on a different basis, and includes 100 percent of the oil and gas volumes from ExxonMobil-operated properties only, regardless of the company's net interest. In addition, Form EIA-23 information does not include gas plant liquids. The difference between the oil reserves reported on EIA-23 and those reported in the registrant's Annual Report on Form 10-K for 2000 exceeds five percent. The difference in gas reserves did not exceed five percent. 3. Average Sales Prices and Production Costs per Unit of Production Reference is made to page 57 of the Financial Section of this report. Average sales prices have been calculated by using sales quantities from our 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 on page 59 of the Financial Section of this report. The net production volumes of natural gas available for sale used in this calculation are shown on page 62 of the Financial Section of this report. 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 2001 Year-End 2000 -------------------------- -------------------------- Oil Gas Oil Gas ------------- ------------ ------------- ------------ Gross Net Gross Net Gross Net Gross Net ------ ------ ------ ----- ------ ------ ------ ----- United States.... 35,610 14,020 9,905 5,872 35,552 14,067 9,857 5,930 Canada........... 6,551 5,266 5,096 2,548 6,428 5,188 4,926 2,489 Europe........... 1,710 548 1,356 479 1,702 546 1,331 480 Asia-Pacific..... 1,401 527 760 266 1,394 518 718 256 Africa........... 325 139 1 1 362 154 -- -- Other............ 1,086 202 123 39 974 176 137 41 ------ ------ ------ ----- ------ ------ ------ ----- Total.......... 46,683 20,702 17,241 9,205 46,412 20,649 16,969 9,196 ====== ====== ====== ===== ====== ====== ====== =====
Note: Year-end 2000 well counts for net oil and gas wells in the United States and gross oil and gas wells in Canada were restated. 5. Gross and Net Developed Acreage
Year-End 2001 Year-End 2000 ------------- ------------- Gross Net Gross Net ------ ------ ------ ------ (Thousands of acres) United States.... 9,528 5,714 9,578 5,993 Canada........... 4,538 2,414 4,577 2,390 Europe........... 11,206 4,819 11,576 4,816 Asia-Pacific..... 5,203 1,640 4,605 1,528 Africa........... 2,108 630 894 387 Other............ 9,223 1,846 9,175 1,821 ------ ------ ------ ------ Total.......... 41,806 17,063 40,405 16,935 ====== ====== ====== ======
Note: Separate acreage data for oil and gas are not maintained because, in many instances, both are produced from the same acreage. 3 6. Gross and Net Undeveloped Acreage
Year-End 2001 Year-End 2000 -------------- -------------- Gross Net Gross Net ------- ------ ------- ------ (Thousands of acres) United States.... 11,801 7,669 11,527 7,399 Canada........... 21,151 9,552 22,136 9,619 Europe........... 13,218 4,624 16,283 6,244 Asia-Pacific..... 28,295 14,161 38,037 19,641 Africa........... 43,660 15,736 47,325 20,111 Other............ 33,190 20,456 51,718 26,363 ------- ------ ------- ------ Total.......... 151,315 72,198 187,026 89,377 ======= ====== ======= ======
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 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 is currently held by work commitments of various amounts. EUROPE France Exploration permits are granted for periods of three to five years, and are renewable up to two times accompanied by substantial acreage relinquishments: 50 percent of the acreage at first renewal; 25 percent of the remaining acreage at second renewal. A 1994 law requires a bidding process prior to granting of an exploration permit. Upon discovery of commercial hydrocarbons, a production concession is granted for up to 50 years, renewable in periods of 25 years each. 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. Italy Exploration permits are awarded for a period of six years, subject to specific, minimum work commitments (an exploration well is usually included). If permit obligations have been fulfilled, the titleholder of the permit is entitled to two subsequent extensions of three years each. The program of both the first and second extension period must include the drilling of a further well. Production licenses are awarded for a period of 20 years upon discovery of commercial hydrocarbons. After 15 years, the license holder can apply for an extension of ten years. After seven years of the first extension period, the license holder can apply for a further extension. 4 Netherlands Onshore: Permits are issued for a period of time necessary to perform the activities for which the permit is issued. Production concessions are granted after discoveries have been made, under conditions that are negotiated with the government. Normally, they are field-life concessions covering an area defined by hydrocarbon occurrences. Offshore: Prospecting licenses issued prior to March 1976 were for a 15-year period, with relinquishment of about 50 percent of the original area required at the end of ten years. Prospecting licenses issued between 1976 and 1996 were for a ten-year period, with relinquishment of about 50 percent of the original area required at the end of six years. Current licenses are for a period of time necessary to perform the activities for which the permit is issued. For commercial discoveries within a prospecting license, a production license is normally issued for a 40-year period. Norway Licenses issued prior to 1972 were for an initial period of six years and an extension period of 40 years, with relinquishment of at least one-fourth of the original area required at the end of the sixth year and another one-fourth at the end of the ninth year. Licenses issued between 1972 and 1997 were for an initial period of up to ten years 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 sixth year. Licenses issued after July 1, 1997 have an initial period of four 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, the regulations governing licenses issued between 1996 and 1998 provided for an initial term of three years with possible extensions of six, 15 and 24 years for a license period of 45 more years. After the second extension, the license must be surrendered in part. In recent licensing rounds, the initial term has generally been for six years. After possible surrender of acreage, the license may continue for 30 more years. ASIA-PACIFIC Australia Onshore: Acreage terms are fixed by the individual state and territory governments. These terms and conditions vary significantly between the states and territories. Exploration permits are normally granted for a term of two to six years (in some states the Petroleum Minister fixes the term) with possible renewals and relinquishment. Production licenses in South Australia are granted for an initial term of 21 years, with subsequent renewals, each for 21 years, for the full area. Production licenses in Queensland are granted for varying periods consistent with expected field lives, with renewals on a similar basis. Offshore: Acreage terms are fixed by the federal government beyond the three nautical mile limit offshore (applying to all of ExxonMobil's offshore acreage), in most cases by legislation, but in some cases by the Joint Authority (composed of federal and state ministers) at the time of grant. Exploration permits are granted for six years with possible renewals of five-year 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 5 and renewals may be requested. Prior to September 1998, production licenses were granted initially for 21 years, with a further renewal of 21 years and thereafter renewals at the discretion of the Joint Authority. Effective September 1998, new production licenses are to be granted "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). Indonesia Exploration and production activities in Indonesia are generally governed by cooperation contracts, usually in the form of a production sharing contract, negotiated with the national oil company. However, effective November 23, 2001, pursuant to the new Oil and Gas Law, the national oil company's role as manager of upstream activities under existing and future contracts will be transferred to an upstream regulatory body (still to be established) reporting to the Minister of Energy and Mineral Resources. Existing cooperation contracts will be amended to reflect the transfer of authority to the upstream regulatory body; however, the terms and conditions of the existing contracts will remain unchanged. Future cooperation contracts will be entered into with the upstream regulatory body. Regulations are being developed to implement the new law. 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 37 years with possible extensions to the exploration or development periods. The exploration period is five to seven years with the possibility of extensions, after which time areas with no commercial discoveries must be relinquished. The development period is four to five 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 must be relinquished if no extension is granted. 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. Exploration licenses are granted for an initial term of six years with a five-year extension possible. Generally, a 50 percent relinquishment of the license area is required at the end of the initial six-year term, if extended. Production licenses are granted for an initial 25-year period. An extension of up to 20 years may be granted at the Minister's discretion. Petroleum retention licenses may be granted for gas resources that are not commercially viable at the time of application, but that may become commercially viable. These licenses are granted for five-year terms, and may be extended twice for a maximum retention time of 15 years. Thailand The Petroleum Act of 1972 allows production under ExxonMobil's concession for 30 years (through 2021) with a possible ten-year extension at terms generally prevalent at the time. 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. 6 Cameroon Exploration and production activities are governed by agreements negotiated with the national oil company. The concessions have various agreements with regard to license extension, terms and conditions for the exploration and production phase. Chad Exploration permits are issued for a period of five years, and are renewable for two further five-year periods. The production term is for 30 years. Equatorial Guinea Exploration and production activities are governed by production sharing contracts negotiated with the State Ministry of Mines and Energy. The exploration term is 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. Nigeria Exploration and production activities in the deepwater offshore areas are typically governed by production sharing contracts (PSCs) with the national oil company. The national oil company 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 (six-year initial exploration phase plus a four-year optional period) covered by an OPL. Upon commercial discovery, an OPL may be converted to an OML. Partial relinquishment is required 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 indigenous 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 Minerals 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. OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs, have a maximum term of 20 years without distinction for on- or offshore location and are renewable, upon 12 months' written notice, for another period of 20 years. OMLs not held by the national oil company are also subject to a mandatory 50 percent relinquishment after the first ten years of their duration. The MOU (Memorandum of Understanding) defining commercial terms applicable to existing oil production was renegotiated and executed in 2000 and is effective for a minimum of three years with possible extensions on mutual agreement. OTHER COUNTRIES Abu Dhabi Exploration and production activities are governed by a 75-year oil concession agreement executed in 1939 and subsequently amended through various agreements with the government of Abu Dhabi. 7 Argentina The onshore concession terms in Argentina are two to three years for the initial exploration period, one to two years for the second exploration period and zero to one year for the third exploration period. The offshore concession terms in Argentina are four years for the initial exploration period, three years for the second exploration period and three 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 four years. The total exploration and production term is 25 years. A ten-year extension is possible once a field has been developed. Azerbaijan The production sharing agreement (PSA) for the development of the area known as the Megastructure 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. 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 joint-venture agreements negotiated with the Republic of Kazakhstan. Existing production operations have a 40-year production period that commenced in 1993. Offshore: Exploration and production activities are governed by a production sharing agreement negotiated with the Republic of Kazakhstan. The exploration period is six years with the possibility of a two-year extension. The production period, which includes development, is for 20 years with the possibility of two ten-year extensions. Qatar The State of Qatar grants rights to develop and supply gas from the offshore North Field development projects. These rights permit the economic development and production of sufficient gas reserves to satisfy the gas sales obligations of these projects. Republic of Yemen Production sharing agreements (PSAs) negotiated with the government entitle the company to participate in exploration operations, and if successful, development and production operations within a designated area, under terms negotiated prior to executing the PSA. Existing production operations have a 20-year term from first commercial declaration--made in November 1985 for the Marib PSA, and June 1995 for the Jannah PSA. Venezuela Exploration and production activities are governed by contracts negotiated with the national oil company. Exploration activity is covered by risk/profit sharing contracts where exploration blocks are awarded for 35 years. Production licenses are awarded for 20 years under production service agreements. Heavy oil strategic association agreements (such as the Cerro Negro project) are typically limited to those projects that require vertical integration of the production and upgrading of extra heavy crude oil. Contracts are awarded for 35 years. Significant amendments to the contract terms require Venezuelan congressional approval. 8 8. Number of Net Productive and Dry Wells Drilled
2001 2000 1999 ----- ----- ---- A. Net Productive Exploratory Wells Drilled United States........................... 4 2 16 Canada.................................. 30 49 4 Europe.................................. 3 3 7 Asia-Pacific............................ 7 5 4 Africa.................................. 4 2 8 Other................................... 3 1 1 ----- ----- ---- Total................................. 51 62 40 ----- ----- ---- B. Net Dry Exploratory Wells Drilled United States........................... 4 2 11 Canada.................................. 22 12 2 Europe.................................. 3 3 5 Asia-Pacific............................ 2 3 10 Africa.................................. 4 4 2 Other................................... 6 2 1 ----- ----- ---- Total................................. 41 26 31 ----- ----- ---- C. Net Productive Development Wells Drilled United States........................... 733 604 419 Canada.................................. 451 213 308 Europe.................................. 32 40 51 Asia-Pacific............................ 44 30 47 Africa.................................. 23 16 10 Other................................... 30 31 32 ----- ----- ---- Total................................. 1,313 934 867 ----- ----- ---- D. Net Dry Development Wells Drilled United States........................... 14 7 16 Canada.................................. 6 -- 12 Europe.................................. 3 5 2 Asia-Pacific............................ 1 1 -- Africa.................................. -- -- -- Other................................... -- -- 1 ----- ----- ---- Total................................. 24 13 31 ----- ----- ---- Total number of net wells drilled....... 1,429 1,035 969 ===== ===== ====
9. Present Activities A. Wells Drilling
Year-End Year-End 2001 2000 --------- --------- Gross Net Gross Net ----- --- ----- --- United States............................ 138 83 151 69 Canada................................... 33 19 63 12 Europe................................... 7 2 26 9 Asia-Pacific............................. 26 14 9 4 Africa................................... 13 4 5 2 Other.................................... 10 3 9 3 --- --- --- -- Total................................ 227 125 263 99 === === === ==
9 B. Review of Principal Ongoing Activities in Key Areas During 2001, ExxonMobil's activities were conducted, either directly or through affiliated companies, for exploration by ExxonMobil Exploration Company, for large development activities by ExxonMobil Development Company, for producing and smaller development activities by ExxonMobil Production Company, and for gas marketing by ExxonMobil Gas Marketing Company. During this same period, some of ExxonMobil's exploration, development, production and gas marketing activities were also conducted in California by Aera Energy, LLC, a 48.2 percent-owned ExxonMobil joint venture with Shell Oil Company, and 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 Exploration and delineation of additional hydrocarbon resources continued in 2001. At year-end 2001, ExxonMobil's acreage totaled 13.4 million net acres. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska. A total of 8.4 net exploration and delineation wells were completed during 2001. During 2001, 662.6 net development wells were completed within and around mature fields in the inland lower 48 states. Participation in Alaska production and development continued and a total of 36.2 net development wells were drilled. ExxonMobil's net acreage in the Gulf of Mexico at year-end 2001 was 3.5 million acres. A total of 51.0 net exploration and development wells were completed during the year and development continued on several Gulf of Mexico projects. . In April 2001, production began from Nile, a one well subsea development in 3,500 feet of water, tied back to the Marlin host platform. . In June 2001, production began from the ExxonMobil-operated Mica field, a remote deepwater subsea development located in 4,500 feet water depth tied back to the Pompano host platform. . The ExxonMobil-operated Marshall and Madison fields, located in 4,300 - 4,900 feet water depth, were tied back to the Hoover-Diana host facilities. Production started at Marshall in October 2001 and is projected to start at Madison in 2002. . Appraisal drilling and development planning continued on the Thunder Horse discovery, the largest discovery to date in the U.S. offshore Gulf of Mexico. A floating semi-submersible platform has been selected as the design concept for the field. CANADA ExxonMobil's year-end acreage holdings totaled 12.0 million net acres. A total of 509.3 net exploration and development wells were completed during the year. Gross production from Cold Lake averaged 128 thousand barrels per day during 2001. Field work continued on the next expansion targeted to start up in late 2002. In Eastern Canada, the Terra Nova oil development project, offshore Newfoundland, underwent final commissioning in 2001 and came on stream in early 2002. Development of the Sable Offshore Energy Project continues, with the second phase to be completed over the 2003-2006 period. ExxonMobil reached agreement with co-venturers to assume operatorship of the Sable Offshore Energy Project in late 2001, and assumed operatorship on February 1, 2002. 10 EUROPE France ExxonMobil's acreage at year-end 2001 was 0.8 million net acres, with 0.5 net development wells completed during the year. Germany A total of 2.5 million net acres were held by ExxonMobil at year-end 2001, with 1.6 net development wells drilled during the year. Italy ExxonMobil's acreage was 0.3 million net acres at year-end 2001. Netherlands ExxonMobil's interest in licenses totaled 2.1 million net acres at year-end 2001. During 2001, 2.9 net exploration and development wells were drilled. Norway ExxonMobil's net interest in licenses at year-end 2001 totaled 1.2 million acres, all offshore. ExxonMobil participated in 11.4 net exploration and development well completions in 2001. Production was initiated on Ringhorne and Snorre B in 2001. Field development projects at Sigyn, Mikkel, Grane and Fram West are in progress. United Kingdom ExxonMobil's net interest in licenses at year-end 2001 totaled approximately 2.5 million acres, all offshore. A total of 23.9 net exploration and development wells were completed during the year. Several projects started up including Skene, Brigantine, Elgin/Franklin and Kestrel. Several projects were underway including Penguins, Madoes, Mirren, Maclure and Otter. ASIA-PACIFIC Australia ExxonMobil's net year-end 2001 acreage holdings totaled 6.5 million acres. ExxonMobil drilled a total of 21.8 net exploration and development wells in 2001, both offshore and onshore. Construction of a gas pipeline in the offshore Gippsland Basin from the Bream A platform to shore commenced in 2001. Indonesia ExxonMobil had acreage of 7.4 million net acres at year-end 2001, with 3.0 exploration wells completed during the year. Malaysia ExxonMobil has interests in production sharing contracts covering 1.2 million net acres offshore Malaysia at year-end 2001. During the year, a total of 27.7 net exploration and development wells were completed. Development and infill drilling were successfully completed at three platforms, Seligi-E, 11 Bekok-C and Dulang-B. First oil was produced from the Angsi-A platform in December 2001 and from the Larut field in February 2002. Development projects are currently in progress at Bintang and Tapis-F. These are scheduled for installation and start-up in the 2002 to 2003 timeframe. Papua New Guinea A total of 0.6 million net acres were held by ExxonMobil at year-end 2001, with 0.7 net development wells completed during the year. Work continued on the Moran field development project. Thailand ExxonMobil's net acreage in the Khorat concession totaled 15 thousand net acres at year-end 2001. AFRICA Angola ExxonMobil's year-end 2001 acreage holdings totaled 3.6 million net acres and 5.5 net exploration and development wells were completed during the year. The Girassol field in Block 17 started production in late 2001. Construction has begun on ExxonMobil-operated Kizomba A on Block 15, the first of several projects planned on this block. In addition, engineering and design work was initiated on Dalia, a non-operated Block 17 discovery. Cameroon ExxonMobil's acreage totaled 0.3 million net acres at year-end 2001, with 1.3 net development wells completed during the year. The D1b field is under development with first oil planned by early 2002. Chad ExxonMobil's net year-end 2001 acreage holdings consisted of 4.1 million acres. Construction has commenced on the Chad-Cameroon oil development and pipeline project, which will develop discovered oil fields in landlocked southern Chad and transport produced oil to the coast of Cameroon. Equatorial Guinea ExxonMobil's acreage totaled 0.6 million net acres at year-end 2001, with 5.1 net exploration and development wells completed during the year. Nigeria ExxonMobil's net acreage totaled 1.4 million acres at year-end 2001, with 18.6 net exploration and development wells completed during the year. Initial production is expected from the ExxonMobil- operated Yoho project by late 2002. Development is underway at the Bonga field (OML 118) and development planning continues for the ExxonMobil-operated Erha (OPL 209) discovery. Expected start-up is 2004 for Bonga and 2005 for Erha. OTHER COUNTRIES Abu Dhabi ExxonMobil's net acreage in the onshore oil concession was 0.5 million acres at year-end 2001. During the year, 4.8 net development wells were completed. 12 Argentina ExxonMobil's acreage totaled 0.4 net million acres at year-end 2001, with 5.2 net exploration and development wells completed during the year. Azerbaijan At year-end 2001, ExxonMobil's net acreage totaled 0.2 million acres located in the Caspian Sea offshore of Azerbaijan. During the year, 0.6 net exploration and development wells were completed. At the Megastructure Early Oil project, water injection to support reservoir pressure is ongoing, with additional producers and injectors planned for 2002. The next phase of development on the Megastructure was approved in 2001. Engineering and construction efforts have begun on the Phase I platform, with production expected by late 2005. Kazakhstan ExxonMobil's net acreage totaled 0.4 million acres at year-end 2001, with 1.7 net exploration and development wells completed during 2001. Production capacity from the Tengiz field has increased with the full year impact of the fifth processing train and the implementation of gas handling debottlenecking projects. Development planning to further increase production is ongoing. The Caspian Pipeline Consortium pipeline for transporting oil from Tengiz, and other Caspian fields and nearby areas, to the Russian Black Sea port of Novorossiysk started up in late 2001. The pipeline will mitigate the high cost of rail and barge transportation. Appraisal and initial development planning continue for the offshore Kashagan discovery. Qatar Production and development activities continued on two major Liquefied Natural Gas (LNG) projects in Qatar--Qatargas (Qatar Liquefied Gas Company Limited) and RasGas (Ras Laffan Liquefied Natural Gas Company Ltd.). The Qatargas LNG facilities have three LNG trains with a total combined sales capacity of 7.4 MTA (million metric tons per annum) of LNG plus associated condensate. In October 2001, Qatargas awarded Engineering, Procurement and Construction (EPC) contracts for the debottlenecking of the three LNG trains, which will increase total sales capacity to 8.9 MTA by 2005. The RasGas LNG facilities have two LNG trains with a total combined sales capacity of 6.6 MTA of LNG plus associated condensate. In an ongoing effort to expand LNG sales capacity from Qatar, in April 2001, RasGas awarded an EPC contract for a third LNG train with sales capacity of 4.7 MTA of LNG plus associated condensate as part of the RasGas Expansion Project. In addition to the two existing LNG projects in Qatar, the Enhanced Gas Utilization (EGU) project will provide 1.75 billion cubic feet per day of gas sales plus associated condensate production and liquefied petroleum gases (LPGs) exports from Qatar's North Field. Engineering and design of the EGU gas production facilities were completed in 2000 with engineering and design of the associated natural gas liquids fractionation and LPG export facilities continuing through 2001. Gas from the EGU project is targeted for domestic use and inter-regional sales via pipeline. An agreement in principle on key terms to supply Kuwait with Qatari gas from the EGU project was announced in January 2002. A memorandum of understanding was signed with Bahrain for additional pipeline sales from the EGU project. Republic of Yemen ExxonMobil's net acreage in the Republic of Yemen production sharing areas totaled 0.9 million acres onshore at year-end 2001. During the year, 4.4 net development wells were completed. 13 Venezuela ExxonMobil's net acreage totaled 0.3 million acres at year-end 2001 with 16.0 net exploration and development wells completed during the year. The Cerro Negro heavy oil project began production in 1999 and the Central Processing Facility was completed in the fourth quarter 2000. Construction activities on the Upgrader Facility at the Jose Industrial Complex were completed mid-2001 and the entire project was officially inaugurated in September 2001. WORLDWIDE EXPLORATION At year-end 2001 exploration activities were underway in several areas in which ExxonMobil has no established production operations. A total of 25.8 million net acres were held at year-end 2001, and 6.8 net exploration wells were completed during the year. Information with regard to mining activities follows: - ---------------------------------------------------- Syncrude Operations Syncrude is a joint-venture established to recover shallow deposits of tar 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, exploits 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 in the Alberta Oil Sands Pipeline owned by the Pembina Oil Sands Pipeline Limited Partnership. Since start-up in 1978, Syncrude has produced about 1.3 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 tar sands and produce synthetic crude oil from approved development areas on tar sands leases. Syncrude holds eight tar sands leases covering approximately 255,000 acres in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta, the leases are automatically renewable as long as tar 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's Department of Resource Development. 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. In the Base mine (lease 17), the mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. 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 545,000 tons of tar sands a day, producing 110 million barrels of crude bitumen a year. This represents recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands. Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two large, high-temperature, fluid-coking vessels and by hydrogen 14 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 2001, this upgrading process yielded 0.845 barrels of synthetic crude oil per barrel of crude bitumen. About two-thirds of the synthetic crude oil is processed by Edmonton area refineries and the remaining one-third is pipelined to refineries in eastern Canada and the mid-western United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and an 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. Imperial Oil Limited's 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities was $750 million at year end 2001. 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, historical 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. Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the approved mining plan, there are an estimated 3,500 million tons of extractable tar sands in the Base and North mines, with an average bitumen grade of 10.4 weight percent. In addition, at the Aurora mine, there are an estimated 4,090 million tons of extractable tar sands at an average bitumen grade of 11.3 weight percent. 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 2001 was equivalent to 821 million barrels of synthetic crude oil. 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 adds a remote mining development and expands the central processing and upgrading plant. This expansion increases proven Syncrude reserves by 230 million barrels and will lead to total production of about 370 thousand barrels of synthetic crude oil per day (gross) when completed. ExxonMobil Share of Net Proven Syncrude Reserves(1)
Synthetic Crude Oil ------------------------------ Base Mine and North Mine Aurora Mine Total ------------- ----------- ----- (millions of barrels) January 1, 2001.............. 373 237 610 Revision of previous estimate -- 230 230 Production................... (15) (4) (19) --- --- --- December 31, 2001............ 358 463 821 === === ===
- -------- (1) Net reserves are the company's share of reserves after deducting royalties payable to the Province of Alberta. 15 Syncrude Operating Statistics (total operation)
2001 2000 1999 1998 1997 ----- ----- ----- ----- ----- Operating Statistics Total mined volume (millions of cubic yards)(1)......... 118.3 85.1 100.1 98.4 71.1 Mined volume to tar sands ratio(1)...................... 1.15 0.96 0.99 1.05 0.75 Tar sands mined (million of tons)....................... 181.2 156.4 178.7 165.9 166.7 Average bitumen grade (weight percent).................. 11.0 11.0 10.8 10.7 10.6 ----- ----- ----- ----- ----- Crude bitumen in mined tar sands (millions of tons)..... 19.9 17.2 19.3 17.8 17.7 Average extraction recovery (percent)................... 87.0 89.7 91.4 91.6 91.0 ----- ----- ----- ----- ----- Crude bitumen production (millions of barrels)(2)....... 97.6 86.8 99.6 92.1 90.3 Average upgrading yield (percent)....................... 84.5 84.3 83.9 84.6 84.5 ----- ----- ----- ----- ----- Gross synthetic crude oil produced (millions of barrels) 82.4 73.2 83.6 77.9 76.3 ExxonMobil net share (millions of barrels)(3)........... 19 15 20 19 17
- -------- (1) Includes pre-stripping of mine areas and reclamation volumes. (2) Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor. (3) Reflects ExxonMobil's 25 percent interest in production less applicable royalties payable to the Province of Alberta. Item 3. Legal Proceedings. On December 20, 2001, the U.S. Environmental Protection Agency ("EPA") issued a Notice of Violation ("NOV") regarding the corporation's Beaumont, Texas refinery, alleging that the corporation failed to obtain Prevention of Significant Deterioration permits relating to turnaround projects at the refinery that allegedly resulted in significant net emission increases of nitrogen oxides and sulfur oxides. On December 20, 2001, the EPA issued an NOV for a refinery in Chalmette, Louisiana that is operated and 50 percent-owned by wholly owned subsidiaries of the corporation. The EPA alleges several violations of the Clean Air Act at the refinery, including failure to properly monitor fugitive emissions leaks at the isomerization and reformer units, failure to maintain air pollution control equipment on a separator, and burning fuel gas with elevated hydrogen sulfide concentrations in two heaters. Although the EPA has not yet made a demand for specific fines or penalties in either of the NOVs described above, it is possible that the EPA could seek penalties in excess of $100,000. The New Mexico Environment Department ("NMED") has issued a compliance order requiring compliance and assessing a civil penalty with respect to alleged violations of implementing regulations of the New Mexico Air Quality Control Act at the Mobil Pipe Line Company's tank battery station in Buckeye, New Mexico. The alleged violations include a failure to install a control device on a storage tank, failure to obtain a permit prior to construction of a storage tank, and failure to test, monitor, report and keep records for a storage tank. Pursuant to the order, issued on June 13, 2001, the NMED is seeking a civil penalty of $231,120. Mobil Pipe Line Company has appealed this order, and the hearing has been postponed indefinitely pending the status of settlement discussions. Settlement discussions with the NMED to resolve this matter are ongoing. Refer to the relevant portions of Note 17 on page 51 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. ----------------- 16 Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].
Age as of March 31, Name 2002 Title (Held Office Since) ---- --------- --------------------------------------------------- L. R. Raymond........ 63 Chairman of the Board (1993) R. Dahan............. 60 Executive Vice President (2001) H. J. Longwell....... 60 Executive Vice President (2001) E. G. Galante........ 51 Senior Vice President (2001) R. W. Tillerson...... 50 Senior Vice President (2001) H. R. Cramer......... 51 Vice President (1999) M. E. Foster......... 59 President, ExxonMobil Development Company (1999) D. D. Humphreys...... 54 Vice President and Controller (1997) G. L. Kohlenberger... 49 Vice President (2002) K. T. Koonce......... 63 Vice President (1999) C. W. Matthews....... 57 Vice President and General Counsel (1995) S. R. McGill......... 59 Vice President (1998) J. T. McMillan....... 65 Vice President (1997) P. T. Mulva.......... 50 Vice President -- Investor Relations and Secretary (2002) F. A. Risch.......... 59 Vice President and Treasurer (1999) D. S. Sanders........ 62 Vice President (1999) J. S. Simon.......... 58 Vice President (1999) P. E. Sullivan....... 58 Vice President and General Tax Counsel (1995) J. L. Thompson....... 62 Vice President (1991)
For at least the past five years, Messrs. Dahan, Humphreys, Longwell, Matthews, Raymond, Risch, Sullivan and Thompson have been employed as executives of the registrant. Mr. Raymond also holds the title of president. The following executive officers of the registrant have also served as executives of the subsidiaries, affiliates or divisions of the registrant shown opposite their names during the five years preceding December 31, 2001. Esso Italiana S.r.l...................................... Simon Esso (Thailand) Public Company Limited................... Galante Exxon Company, International............................. McGill and Simon Exxon Company, U.S.A..................................... Foster and McMillan Exxon Upstream Development Company....................... Foster Exxon Ventures (CIS) Inc................................. Koonce and Tillerson Exxon Yemen Inc.......................................... Tillerson ExxonMobil Chemical Company.............................. Sanders and Galante ExxonMobil Coal and Minerals Company..................... McMillan ExxonMobil Development Company........................... Tillerson ExxonMobil Fuels Marketing Company....................... Cramer ExxonMobil Gas Marketing Company......................... McGill ExxonMobil Global Services Company....................... Kohlenberger ExxonMobil Lubricants & Petroleum Specialities Company... Kohlenberger ExxonMobil Production Company............................ Koonce ExxonMobil Refining & Supply Company..................... Simon Imperial Oil Limited..................................... Mulva Mobil Business Resources Corporation..................... Kohlenberger Mobil Corporation........................................ Cramer Mobil Europe and Central Asia Limited.................... Cramer
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. 17 PART II Item 5. Market for Registrant's Common Stock and Related Shareholder Matters. Reference is made to the quarterly information which appears on page 56 of the Financial Section of this report. In accordance with the registrant's 1997 Nonemployee Director Restricted Stock Plan, as amended, each incumbent nonemployee director (10 persons) was granted 2,400 shares of restricted stock on January 1, 2002. These grants are exempt from registration under bonus stock interpretations such as the "no-action" letter to Pacific Telesis Group (June 30, 1992). Item 6. Selected Financial Data.
Years Ended December 31, ----------------------------------------------- 2001 2000 1999 1998 1997 -------- -------- -------- -------- -------- (millions of dollars, except per share amounts) Sales and other operating revenue, including excise taxes.............................. $209,417 $228,439 $182,529 $165,627 $197,735 Net income Before extraordinary item and cumulative effect of accounting change............ $ 15,105 $ 15,990 $ 7,910 $ 8,144 $ 11,732 Extraordinary gain, net of income tax.... $ 215 $ 1,730 $ -- $ -- $ -- Cumulative effect of accounting change... $ -- $ -- $ -- $ (70) $ -- -------- -------- -------- -------- -------- Net income............................... $ 15,320 $ 17,720 $ 7,910 $ 8,074 $ 11,732 Net income per common share Before extraordinary item and cumulative effect of accounting change............ $ 2.20 $ 2.30 $ 1.14 $ 1.16 $ 1.66 Extraordinary gain, net of income tax.... $ 0.03 $ 0.25 $ -- $ -- $ -- Cumulative effect of accounting change... $ -- $ -- $ -- $ (0.01) $ -- -------- -------- -------- -------- -------- Net income............................... $ 2.23 $ 2.55 $ 1.14 $ 1.15 $ 1.66 Net income per common share - assuming dilution Before extraordinary item and cumulative effect of accounting change............ $ 2.18 $ 2.27 $ 1.12 $ 1.15 $ 1.64 Extraordinary gain, net of income tax.... $ 0.03 $ 0.25 $ -- $ -- $ -- Cumulative effect of accounting change... $ -- $ -- $ -- $ (0.01) $ -- -------- -------- -------- -------- -------- Net income............................... $ 2.21 $ 2.52 $ 1.12 $ 1.14 $ 1.64 Cash dividends per common share............. $ 0.910 $ 0.880 $ 0.844 $ 0.833 $ 0.810 Total assets................................ $143,174 $149,000 $144,521 $139,335 $143,751 Long-term debt.............................. $ 7,099 $ 7,280 $ 8,402 $ 8,532 $ 10,868
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Reference is made to the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 23 of the Financial Section of this report. 18 Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Reference is made to the section entitled "Market Risks, Inflation and Other Uncertainties" beginning on page 29, excluding the part entitled "Inflation and Other Uncertainties," of 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 consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP dated February 27, 2002, appearing on pages 33 to 55; the Quarterly Information appearing on page 56 and the Supplemental Information on Oil and Gas Exploration and Production Activities appearing on pages 57 to 61 of the Financial Section of this report. Consolidated 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. PART III Item 10. Directors and Executive Officers of the Registrant. Incorporated by reference to the sections entitled "Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" of the registrant's definitive proxy statement for the 2002 annual meeting of shareholders (the "2002 Proxy Statement"). Item 11. Executive Compensation. Incorporated by reference to the section entitled "Director Compensation" and the section entitled "Executive Compensation Tables" of the registrant's 2002 Proxy Statement. Item 12. Security Ownership of Certain Beneficial Owners and Management. Incorporated by reference to the section entitled "Director and Executive Officer Stock Ownership" of the registrant's 2002 Proxy Statement. Item 13. Certain Relationships and Related Transactions. None. PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. (a)(1) and (a) (2) Financial Statements: See Table of Contents on page 20 of the Financial Section of this report. (a)(3) Exhibits: See Index to Exhibits on page 66 of this report. (b)Reports on Form 8-K. The Registrant did not file any reports on Form 8-K during the last quarter of 2001. 19 FINANCIAL SECTION TABLE OF CONTENTS
Business Profile ............................................................................................ 21 Financial Summary ........................................................................................... 22 Management's Discussion and Analysis of Financial Condition and Results of Operations Functional Earnings ...................................................................................... 23 Review of 2001 and 2000 Results .......................................................................... 24 Liquidity and Capital Resources .......................................................................... 26 Capital and Exploration Expenditures ..................................................................... 28 Merger of Exxon Corporation and Mobil Corporation ........................................................ 28 Merger Expenses and Reorganization Reserves .............................................................. 28 Site Restoration and Other Environmental Costs ........................................................... 29 Taxes .................................................................................................... 29 Market Risks, Inflation and Other Uncertainties .......................................................... 29 Recently Issued Financial Accounting Standards ........................................................... 30 Critical Accounting Policies ............................................................................. 30 Forward Looking Statements ............................................................................... 32 Report of Independent Accountants ........................................................................... 33 Consolidated Financial Statements Statement of Income ...................................................................................... 34 Balance Sheet ............................................................................................ 35 Statement of Shareholders' Equity ........................................................................ 36 Statement of Cash Flows .................................................................................. 37 Notes to Consolidated Financial Statements 1. Summary of Accounting Policies ...................................................................... 38 2. Extraordinary Item and Accounting Change ............................................................ 39 3. Merger of Exxon Corporation and Mobil Corporation ................................................... 39 4. Merger Expenses and Reorganization Reserves ......................................................... 39 5. Miscellaneous Financial Information ................................................................. 40 6. Cash Flow Information ............................................................................... 40 7. Additional Working Capital Data ..................................................................... 40 8. Equity Company Information .......................................................................... 41 9. Investments and Advances ............................................................................ 41 10. Investment in Property, Plant and Equipment ......................................................... 42 11. Leased Facilities ................................................................................... 42 12. Employee Stock Ownership Plans ...................................................................... 42 13. Capital ............................................................................................. 43 14. Financial Instruments and Derivatives ............................................................... 44 15. Long-Term Debt ...................................................................................... 44 16. Incentive Program ................................................................................... 50 17. Litigation and Other Contingencies .................................................................. 51 18. Annuity Benefits and Other Postretirement Benefits .................................................. 52 19. Income, Excise and Other Taxes ...................................................................... 54 20. Disclosures about Segments and Related Information .................................................. 55 Quarterly Information ....................................................................................... 56 Supplemental Information on Oil and Gas Exploration and Production Activities ............................... 57-61 Operating Summary ........................................................................................... 62
20 BUSINESS PROFILE
Return on Capital and Earnings After Average Capital Average Capital Exploration Income Taxes Employed Employed Expenditures -------------------------------------------------------------------------------------- Financial 2001 2000 2001 2000 2001 2000 2001 2000 - ------------------------------------------------------------------------------------------------------------------------------- (millions of dollars) (percent) (millions of dollars) Petroleum and natural gas Upstream United States $ 3,932 $ 4,545 $ 12,900 $ 12,804 30.5 35.5 $ 2,418 $ 1,859 Non-U.S 6,497 7,824 25,037 26,235 25.9 29.8 6,345 5,040 -------------------------------------------- -------------------- Total $ 10,429 $ 12,369 $ 37,937 $ 39,039 27.5 31.7 $ 8,763 $ 6,899 -------------------------------------------- -------------------- Downstream United States $ 1,924 $ 1,561 $ 7,711 $ 7,976 25.0 19.6 $ 961 $ 1,077 Non-U.S. 2,303 1,857 18,610 19,756 12.4 9.4 1,361 1,541 -------------------------------------------- -------------------- Total $ 4,227 $ 3,418 $ 26,321 $ 27,732 16.1 12.3 $ 2,322 $ 2,618 -------------------------------------------- -------------------- Total petroleum and natural gas $ 14,656 $ 15,787 $ 64,258 $ 66,771 22.8 23.6 $ 11,085 $ 9,517 -------------------------------------------- -------------------- Chemicals United States $ 398 $ 644 $ 5,506 $ 5,644 7.2 11.4 $ 432 $ 351 Non-U.S. 484 517 8,333 8,170 5.8 6.3 440 1,117 -------------------------------------------- -------------------- Total $ 882 $ 1,161 $ 13,839 $ 13,814 6.4 8.4 $ 872 $ 1,468 Other operations 489 551 3,721 3,992 13.1 13.8 285 163 Corporate and financing (222) (589) 6,182 2,886 -- -- 69 20 Merger expenses (525) (920) -- -- -- -- -- -- Gain from required asset divestitures 40 1,730 -- -- -- -- -- -- -------------------------------------------- -------------------- Net income $ 15,320 $ 17,720 $ 88,000 $ 87,463 17.8 20.6 $ 12,311 $ 11,168 ============================================ ====================
Operating 2001 2000 - ---------------------------------------------------------------------------- (thousands of barrels daily) Net liquids production United States 712 733 Non-U.S. 1,830 1,820 -------------- Total 2,542 2,553 (millions of cubic feet daily) Natural gas production available for sale United States 2,598 2,856 Non-U.S. 7,681 7,487 -------------- Total 10,279 10,343 (thousands of barrels daily) Petroleum product sales United States 2,751 2,669 Non-U.S. 5,220 5,324 -------------- Total 7,971 7,993 (thousands of barrels daily) Refinery throughput United States 1,840 1,862 Non-U.S. 3,731 3,780 -------------- Total 5,571 5,642 (thousands of metric tons) Chemical prime product sales 25,780 25,637 (millions of metric tons) Coal production United States 3 2 Non-U.S. 10 15 -------------- Total 13 17 (thousands of metric tons) Copper production 252 254 21 FINANCIAL SUMMARY
2001 2000 1999 1998 1997 - ------------------------------------------------------------------------------------------------------------------------------ (millions of dollars, except per share amounts) Sales and other operating revenue Petroleum and natural gas $ 192,680 $ 210,006 $ 167,802 $ 151,109 $ 179,137 Chemicals 15,943 17,501 13,777 13,589 16,190 Other 794 932 950 929 2,408 ------------------------------------------------------------- Sales and other operating revenue, including excise taxes $ 209,417 $ 228,439 $ 182,529 $ 165,627 $ 197,735 Earnings from equity interests and other revenue 4,071 4,309 2,998 4,015 4,011 ------------------------------------------------------------- Total revenue $ 213,488 $ 232,748 $ 185,527 $ 169,642 $ 201,746 ============================================================= Earnings Petroleum and natural gas Upstream $ 10,429 $ 12,369 $ 5,886 $ 3,352 $ 6,905 Downstream 4,227 3,418 1,227 3,474 3,088 ------------------------------------------------------------- Total petroleum and natural gas $ 14,656 $ 15,787 $ 7,113 $ 6,826 $ 9,993 Chemicals 882 1,161 1,354 1,394 1,771 Other operations 489 551 426 384 434 Corporate and financing (222) (589) (514) (460) (466) Merger expenses (525) (920) (469) -- -- Gain from required asset divestitures 40 1,730 -- -- -- Accounting change -- -- -- (70) -- ------------------------------------------------------------- Net income $ 15,320 $ 17,720 $ 7,910 $ 8,074 $ 11,732 ============================================================= Net income per common share $ 2.23 $ 2.55 $ 1.14 $ 1.15 $ 1.66 Net income per common share - assuming dilution $ 2.21 $ 2.52 $ 1.12 $ 1.14 $ 1.64 Cash dividends per common share $ 0.910 $ 0.880 $ 0.844 $ 0.833 $ 0.810 Net income to average shareholders' equity (percent) 21.3 26.4 12.6 12.9 18.7 Net income to total revenue (percent) 7.2 7.6 4.3 4.8 5.8 Working capital $ 5,567 $ 2,208 $ (7,592) $ (5,187) $ (377) Ratio of current assets to current liabilities 1.18 1.06 0.80 0.85 0.99 Total additions to property, plant and equipment $ 9,989 $ 8,446 $ 10,849 $ 12,730 $ 11,652 Property, plant and equipment, less allowances $ 89,602 $ 89,829 $ 94,043 $ 92,583 $ 93,527 Total assets $ 143,174 $ 149,000 $ 144,521 $ 139,335 $ 143,751 Exploration expenses, including dry holes $ 1,175 $ 936 $ 1,246 $ 1,506 $ 1,252 Research and development costs $ 603 $ 564 $ 630 $ 753 $ 763 Long-term debt $ 7,099 $ 7,280 $ 8,402 $ 8,532 $ 10,868 Total debt $ 10,802 $ 13,441 $ 18,972 $ 17,016 $ 17,182 Fixed charge coverage ratio (times) 17.8 15.7 6.6 6.9 9.9 Debt to capital (percent) 12.4 15.4 22.0 20.6 20.3 Shareholders' equity at year-end $ 73,161 $ 70,757 $ 63,466 $ 62,120 $ 63,121 Shareholders' equity per common share $ 10.74 $ 10.21 $ 9.13 $ 8.98 $ 9.04 Average number of common shares outstanding (millions) 6,868 6,953 6,906 6,937 7,022 Number of regular employees at year-end (thousands) 97.9 99.6 106.9 111.6 114.5
Note: Prior period per share amounts restated for the two-for-one stock split effective June 20, 2001. 22 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUNCTIONAL EARNINGS 2001 2000 1999 - --------------------------------------------------------------------------------------------------------------------- (millions of dollars, except per share amounts) Earnings Including Merger Effects and Special Items Upstream United States $ 3,932 $ 4,545 $ 1,842 Non-U.S. 6,497 7,824 4,044 Downstream United States 1,924 1,561 577 Non-U.S. 2,303 1,857 650 Chemicals United States 398 644 738 Non-U.S. 484 517 616 Other operations 489 551 426 Corporate and financing (222) (589) (514) Merger expenses (525) (920) (469) Gain from required asset divestitures 40 1,730 -- ------------------------------------------ Net income $ 15,320 $ 17,720 $ 7,910 ========================================== Net income per common share $ 2.23 $ 2.55 $ 1.14 Net income per common share - assuming dilution $ 2.21 $ 2.52 $ 1.12 ==================================================================================================================== Merger Effects and Special Items Upstream United States $ -- $ -- $ -- Non-U.S. -- -- 119 Downstream United States -- -- -- Non-U.S. -- -- (120) Chemicals United States (extraordinary item) 100 -- -- Non-U.S. (extraordinary item) 75 -- -- Merger expenses (525) (920) (469) Gain from required asset divestitures (extraordinary item) 40 1,730 -- ------------------------------------------ Total $ (310) $ 810 $ (470) ========================================== ==================================================================================================================== Earnings Excluding Merger Effects and Special Items Upstream United States $ 3,932 $ 4,545 $ 1,842 Non-U.S. 6,497 7,824 3,925 Downstream United States 1,924 1,561 577 Non-U.S. 2,303 1,857 770 Chemicals United States 298 644 738 Non-U.S. 409 517 616 Other operations 489 551 426 Corporate and financing (222) (589) (514) ------------------------------------------ Total $ 15,630 $ 16,910 $ 8,380 ========================================== Earnings per common share $ 2.28 $ 2.43 $ 1.21 Earnings per common share-assuming dilution $ 2.26 $ 2.40 $ 1.19 ====================================================================================================================
Note: Prior period per share amounts restated for the two-for-one stock split effective June 20, 2001. 23 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis of ExxonMobil's financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Exxon Mobil Corporation. The corporation's accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The corporation's business model involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods. This straightforward approach extends to the financing of the business. In evaluating business or investment opportunities, the corporation views as economically equivalent any debt obligation, whether disclosed on the face of the consolidated balance sheet, or disclosed as other debt-like obligations in notes to the financial statements, such as those summarized in the table on page 26. This 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 more than eighty years. REVIEW OF 2001 RESULTS Earnings excluding merger effects and special items were $15,630 million, a decrease of $1,280 million from 2000. Net income in 2001 was $15,320 million, including $215 million of extraordinary gains and $525 million of merger costs, a decrease of $2,400 million from 2000, which benefited from $810 million in net favorable merger effects including gains from divestments required as a condition of regulatory approval of the merger. Upstream (Exploration and Production) earnings in 2001 declined, following lower crude oil realizations, which on average were down 18 percent versus 2000. Upstream volumes in 2001, on an oil equivalent basis, were up 1 percent excluding the effect of reduced natural gas production operations in Indonesia due to security concerns. Downstream (Refining and Marketing) earnings improved from 2000, reflecting stronger U.S. refining margins and improved marketing results outside of the U.S. Chemicals earnings declined versus 2000, as lower product realizations and weakening demand conditions put significant pressure on commodity margins and more than offset the $175 million of extraordinary gains associated with asset management activities. Prime product sales volumes were 1 percent higher than 2000, reflecting capacity additions in Singapore and Saudi Arabia. Merger implementation activities in 2001 reduced earnings by a net $485 million. Gains from asset divestitures that were a condition of regulatory approval of the merger added $40 million to earnings, partly offsetting merger implementation expenses of $525 million. Revenue for 2001 totaled $213 billion, down 8 percent from 2000. Excluding merger expenses, the combined total of operating costs (including operating, selling, general, administrative, exploration, depreciation and depletion expenses from the consolidated statement of income and ExxonMobil's share of similar costs for equity companies) in 2001 was $44.0 billion, up $400 million from 2000. Cost increases associated with new operations, higher energy costs and higher pension-related expenses were substantially offset by the favorable impact of continuing efficiency initiatives carried out in all business lines. The impact of these initiatives, including the capture of merger synergies, reduced operating costs by $1.2 billion in 2001, and cumulatively by $4 billion since 1998. Interest expense in 2001 was $293 million compared to $589 million in 2000 reflecting lower debt levels and interest rates. Upstream Upstream earnings of $10,429 million decreased $1,940 million, or 16 percent from last year's record level, primarily due to lower crude oil prices. The impacts of lower crude realizations and higher exploration expenses in future growth areas were partly offset by higher average natural gas realizations, principally in North America and Europe. U.S. and Canadian natural gas prices reached historical highs early in 2001 but dropped through the remainder of the year. Liquids production in 2001 of 2,542 kbd (thousands of barrels daily) was down slightly from 2000, as natural field declines in mature areas were largely offset by new volumes from work programs and new developments in the North Sea, U.S., Equatorial Guinea and Kazakhstan, some of which have not yet reached full capacity. Absent the effect of reduced Arun operations in Indonesia due to security concerns, worldwide gas production was up about 2 percent, with increases in Europe, Australia, Canada and Qatar. Including the impact of lower Indonesia volumes, full-year 2001 worldwide natural gas production of 10,279 mcfd (millions of cubic feet daily) compared with 10,343 mcfd in 2000. Combined liquids and gas volumes, on an oil equivalent basis, were up 1 percent excluding the effect of reduced natural gas production operations in Indonesia. Earnings from U.S. upstream operations were $3,932 million, a decrease of $613 million. Earnings outside the U.S. were $6,497 million, $1,327 million lower than 2000. Downstream Downstream earnings of $4,227 million were a record and improved 24 percent over 2000. Results benefited from higher refining margins early in the year, particularly in the U.S., improved worldwide refining operations and higher marketing margins outside the U.S. Refining margins in most areas peaked in the second quarter and declined during the second half of 2001. Earnings also benefited from a planned reduction in inventories as a result of optimizing operations around the world. Petroleum product sales of 7,971 kbd compared with 7,993 kbd in the prior year. Excluding the effect of the required merger related divestments in 2000, volumes were up slightly. Refinery throughput was 5,571 kbd compared with 5,642 kbd in 2000. U.S. downstream earnings were $1,924 million, up $363 million, reflecting stronger refining margins and improved operations. Earnings outside the U.S. of $2,303 million were $446 million higher than 2000. The improvement was driven by stronger marketing margins, partly offset by weaker European refining margins. Chemicals Chemicals earnings totaled $882 million, including $175 million of net gains on asset management activities. Absent this special item, chemicals earnings were $707 million, a decrease of $454 million from 2000. Most of the reduction occurred in the U.S. as lower product realizations and weakening demand conditions put significant pressure on 24 commodity margins. Record prime product sales volumes of 25,780 kt (thousands of metric tons) were 1 percent above the prior year's record level as higher sales outside the U.S., reflecting capacity additions in Singapore and Saudi Arabia, were partly offset by lower sales in the U.S. reflecting weaker industrial demand. Other Operations Earnings from other operating segments totaled $489 million, a decrease of $62 million from 2000, reflecting lower copper prices. Corporate and Financing Corporate and financing expenses decreased $367 million to $222 million, reflecting lower net interest costs due to lower debt levels and higher cash balances, along with favorable foreign exchange and tax effects. REVIEW OF 2000 RESULTS Earnings excluding merger effects and special items were $16,910 million, an increase of $8,530 million from 1999. Net income in 2000 of $17,720 million, including net favorable merger effects of $810 million, increased $9,810 million from 1999. Upstream earnings benefited from higher crude oil and natural gas realizations, which on average were up about 60 percent and 45 percent, respectively, versus 1999. Excluding the effects of lower entitlements caused by higher crude prices, liquids production was 3 percent higher than 1999. Downstream earnings improved from the very depressed results in 1999, driven by stronger worldwide refining margins and better refining operations. However, downstream profitability was restrained by difficulties in recovering the significant increases in raw material costs that occurred over much of the year. Merger implementation activities in 2000 added a net $810 million to net income, reflecting $1,730 million of extraordinary gains from asset divestitures that were a condition of regulatory approval of the merger. These gains more than offset merger implementation expenses of $920 million. Results in 1999 included $470 million of net charges for special items, primarily merger expenses with other special items essentially offsetting. Revenue for 2000 totaled $233 billion, up 25 percent from 1999, and the cost of crude oil and product purchases increased by 41 percent, both influenced by higher prices. Excluding merger expenses, the combined total of operating costs (including operating, selling, general, administrative, exploration, depreciation and depletion expenses from the consolidated statement of income and ExxonMobil's share of similar costs for equity companies) in 2000 was $43.6 billion, down about $700 million from 1999. The impact of efficiency initiatives, including the capture of merger synergies, reduced operating costs by $1.6 billion. Interest expense in 2000 was $589 million compared to $695 million in 1999 as the effect of lower debt levels was partly offset by higher interest rates. Upstream Upstream earnings of $12,369 million were a record and increased due to higher crude oil and natural gas realizations, up about 60 percent and 45 percent, respectively. Liquids production of 2,553 kbd increased from 2,517 kbd in 1999. Excluding the effects of lower entitlements caused by higher crude prices, liquids production was 3 percent higher than 1999, mainly reflecting new production from fields in the North Sea and Venezuela and increased production from eastern Canada and Alaska. These increases more than offset the effects of natural field declines. Natural gas production of 10,343 mcfd was about the same as 1999 reflecting higher production in eastern Canada, Europe and Qatar, offset by lower production in Indonesia. Excluding entitlement impacts, natural gas production increased about 1 percent. Lower exploration expenses also benefited 2000 upstream earnings. Earnings from U.S. upstream operations were $4,545 million, an increase of $2,703 million from 1999. Earnings outside the U.S. were $7,824 million, $3,899 million higher than last year, excluding a $141 million deferred tax benefit and a $22 million property write-off in 1999. Downstream Downstream earnings of $3,418 million improved over $2 billion from the very depressed results in 1999, driven by stronger worldwide refining margins and better refining operations. Earnings also benefited from a planned reduction in inventories as a result of merging Exxon and Mobil operations around the world. Petroleum product sales of 7,993 kbd compared with 8,887 kbd in 1999. The decrease reflected the effects of the required divestiture of Mobil's European fuels joint venture and of U.S. marketing and refining assets, as well as lower supply sales in Asia-Pacific resulting from the low margin environment. Refinery throughput was 5,642 kbd compared with 5,977 kbd in 1999. Excluding the effects of the divestments, refinery throughput in 2000 was at the same level as 1999 and petroleum product sales were down about 4 percent. Earnings from U.S. downstream operations were $1,561 million, up $984 million from the depressed results of 1999, reflecting stronger refining margins and improved operations, partly offset by weaker marketing margins. Earnings outside the U.S. of $1,857 million were $1,087 million higher than 1999 after excluding special charges in 1999 in Japan of $80 million for non-merger related restructuring of downstream operations and a $40 million write-off associated with the cancellation of a power project. The improvement was driven by stronger European and to a much lesser extent Southeast Asian refining margins and improved refining operations, partly offset by weaker marketing margins. Chemicals Chemicals earnings totaled $1,161 million compared with $1,354 million in 1999. Prime product sales volumes of 25,637 kt were up 354 kt. The decline in earnings was driven by higher feedstock and energy costs and unfavorable foreign exchange effects. Other Operations Earnings from other operating segments totaled $551 million, an increase of $125 million from 1999, reflecting record copper and coal sales, higher copper prices, lower operating expenses and favorable foreign exchange effects, partly offset by lower coal prices. Corporate and Financing Corporate and financing expenses of $589 million compared with $514 million in 1999. The increase resulted from unfavorable foreign exchange effects and lower tax-related benefits, partly offset by a reduction in administrative expenses as a result of combining Exxon and Mobil headquarters operations. The effect of lower debt levels was partly offset by higher interest rates during the year. 25 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS LIQUIDITY AND CAPITAL RESOURCES In 2001, cash provided by operating activities totaled $22.9 billion, the same level as 2000. Major sources of funds were net income of $15.3 billion and non-cash provisions of $7.9 billion for depreciation and depletion. Cash used in investing activities totaled $8.2 billion, up $4.9 billion from 2000 due to lower proceeds from sales of subsidiaries, investments and property, plant and equipment resulting from the absence of the asset divestitures in 2000 that were required as a condition of the regulatory approval of the merger, and due to higher additions to property, plant and equipment. Cash used in financing activities was $15.0 billion, up $0.9 billion, driven by higher purchases of common shares, offset by lower debt reductions. Dividend payments on common shares increased from $0.88 per share to $0.91 per share and totaled $6.3 billion, a payout of 41 percent. Total consolidated short-term and long-term debt declined by $2.6 billion to $10.8 billion. Shareholders' equity increased by $2.4 billion to $73.2 billion. During 2001, Exxon Mobil Corporation purchased 139 million shares of its common stock for the treasury at a gross cost of $5,721 million. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,930 million at the end of 2000 to 6,809 million at the end of 2001. Purchases were made in both the open market and through negotiated transactions, and may be discontinued at any time. In 2000, cash provided by operating activities totaled $22.9 billion, up $7.9 billion from 1999. Major sources of funds were net income of $17.7 billion and non-cash provisions of $8.1 billion for depreciation and depletion. Cash used in investing activities totaled $3.3 billion, down $7.7 billion from 1999 due to higher proceeds from sales of subsidiaries, investments and property, plant and equipment resulting from asset divestitures that were required as a condition of the regulatory approval of the merger, and due to lower additions to property, plant and equipment. Cash used in financing activities was $14.2 billion, up $9.4 billion, driven by debt reductions in the current year versus debt increases in 1999, along with higher purchases of common shares. Dividend payments on common shares increased from $0.844 per share to $0.880 per share and totaled $6.1 billion, a payout of 35 percent. Total consolidated short-term and long-term debt declined by $5.6 billion to $13.4 billion. Shareholders' equity increased by $7.3 billion to $70.8 billion. Prior to the merger, the corporation purchased shares of its common stock for the treasury. Consistent with pooling accounting requirements, this repurchase program was terminated effective with the close of the ExxonMobil merger on November 30, 1999. On August 1, 2000, the corporation announced its intention to purchase shares of its common stock. During 2000, Exxon Mobil Corporation purchased 54 million shares of its common stock for the treasury at a gross cost of $2,352 million. These purchases were to offset shares issued in conjunction with company benefit plans and programs and to reduce the number of shares outstanding. Shares outstanding were reduced from 6,955 million at the end of 1999 to 6,930 million at the end of 2000. Purchases were made in both the open market and through negotiated transactions. Although the corporation issues long-term debt from time to time and maintains a revolving commercial paper program, 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 its secure, ready availability to meet the corporations' cash requirements as they arise. Long-Term Contractual Obligations and Other Commercial Commitments Set forth below is information about the corporations' long-term contractual obligations and other commercial commitments outstanding at December 31, 2001. It brings together data for easy reference from the consolidated balance sheet and from individual notes to consolidated financial statements. This information is important in understanding the financial position of the corporation. In considering the economic viablity of investment opportunities, the corporation views any source of financing, whether it be operating leases, third party guarantees or equity company debt, as being economically equivalent to consolidated debt of the corporation.
Payments due by Period ---------------------------- Long-Term Contractual Footnote 2003- 2007 and Total Obligations Reference 2002 2006 Beyond Amount - ---------------------------------------------------------------------------------------- (millions of dollars) Long-term debt (1) Note 15 $ -- $3,498 $ 3,601 $ 7,099 - Due in one year (2) 339 -- -- 339 ExxonMobil share of equity company long-term debt (3) Note 8 -- 1,922 2,028 3,950 - Due in one year (2) 590 -- -- 590 Operating leases (4) Note 11 1,327 2,910 2,687 6,924 Unconditional purchase obligations (5) Note 17 156 544 1,329 2,029 Firm capital commitments (6) 1,996 911 978 3,885 -------------------------------------- Total $4,408 $9,785 $10,623 $24,816 =======================================
Notes: (1) Includes capitalized lease obligations of $266 million. (2) The amounts due in one year are included in notes and loans payable of $3,703 million (note 7) for consolidated companies and in short-term debt of $1,232 million (note 8) for equity companies. (3) The corporation includes its share of equity company debt in its calculation of return on average capital employed. (4) Minimum commitments for operating leases, shown on an undiscounted basis, cover drilling equipment, tankers, service stations and other properties. 26 (5) Unconditional purchase obligations, shown on an undiscounted basis, mainly pertain to pipeline throughput agreements. The present value of these commitments, excluding imputed interest of $733 million, totaled $1,296 million. (6) Firm commitments related to capital projects, shown on an undiscounted basis, totaled approximately $3.9 billion at the end of 2001, compared with $4.6 billion at year-end 2000. The largest single commitment outstanding at year-end 2001 was $2.1 billion associated with the development of crude oil and natural gas resources in Malaysia. The corporation expects to fund the majority of these commitments through internal cash flow. Other Commercial Commitments The corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2001, for $3,921 million, primarily relating to guarantees for notes, loans and performance under contracts (note 17). This included $672 million representing guarantees of non-U.S. excise taxes and customs duties of other companies, entered into as a normal business practice, under reciprocal arrangements. Also included in this amount were guarantees by consolidated affiliates of $1,641 million, representing ExxonMobil's share of obligations of certain equity companies. On December 31, 2001, unused credit lines for short-term financing totaled approximately $5.3 billion (note 7). The table below shows the corporation's 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 and Poor's (AAA) and Moody's (Aaa), a rating it has sustained for 83 years. 2001 2000 1999 --------------------------------- Fixed charge coverage ratio (times) 17.8 15.7 6.6 Debt to capital (percent) 12.4 15.4 22.0 Net debt to capital (percent) (1) 5.3 7.9 20.4 Credit rating AAA/Aaa AAA/Aaa AAA/Aaa (1) Debt net of all cash Management views the corporation's financial strength, as evidenced by the above financial ratios and other similar measures, to be a competitive advantage of strategic importance. The corporation's sound financial position gives it the opportunity to access the world's capital markets in the full range of market conditions, and enables the corporation to take on large, long-term capital commitments in the pursuit of maximizing shareholder value. In addition to the above commitments, the corporation makes limited use of derivative instruments, which are discussed in Risk Management on page 29 and note 14 on page 44. Litigation and Other Contingencies As discussed in note 17 to the consolidated financial statements, 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. The vast majority of the claims have been resolved leaving a few compensatory damages cases to be tried. All of the punitive damage claims were consolidated in the civil trial that began in May 1994. In that trial, on September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5.058 billion. The District Court awarded approximately $19.6 million in compensatory damages to fisher plaintiffs, $38 million in prejudgment interest on the compensatory damages and $5 billion in punitive damages to a class composed of all persons and entities who asserted claims for punitive damages from the corporation as a result of the Exxon Valdez grounding. The District Court also ordered that these awards shall bear interest from and after entry of the judgment. The District Court stayed execution on the judgment pending appeal based on a $6.75 billion letter of credit posted by the corporation. ExxonMobil appealed the judgment. On November 7, 2001, the United States Court of Appeals for the Ninth Circuit vacated the punitive damage award as being excessive under the Constitution and remanded the case to the District Court for it to determine the amount of the punitive damage award consistent with the Ninth Circuit's holding. The Ninth Circuit upheld the compensatory damage award which has been paid. The letter of credit was terminated on February 1, 2002. The ultimate cost to the corporation from the lawsuits arising from the Exxon Valdez grounding is not possible to predict and may not be resolved for a number of years. On December 19, 2000, a jury in Montgomery County, Alabama, returned a verdict against the corporation in a contract dispute over royalties in the amount of $87.69 million in compensatory damages and $3.42 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court on May 4, 2001. ExxonMobil has appealed the judgment and believes it should be set aside or substantially reduced on factual and constitutional grounds. The ultimate outcome is not expected to have a materially adverse effect upon the corporation's operations or financial condition. On May 22, 2001, a state court jury in New Orleans, Louisiana, returned a verdict against the corporation and three other entities in a case brought by a landowner claiming damage to his property. The property had been leased by the landowner to a company that performed pipe cleaning and storage services for customers, including the corporation. The jury awarded the plaintiff $56 million in compensatory damages (90 percent to be paid by the corporation) and $1 billion in punitive damages (all to be paid by the corporation). The damage related to the presence of naturally occurring radioactive material (NORM) on the site resulting from pipe cleaning operations. The award has been upheld at the trial court. ExxonMobil will appeal the judgment to the Louisiana Fourth Circuit Court of Appeals and believes that the judgment should be set aside or substantially reduced on factual and constitutional grounds. The ultimate outcome is not expected to have a materially adverse effect upon the corporation's operations or financial condition. The U.S. Tax Court has decided the issue with respect to the pricing of crude oil purchased from Saudi Arabia for the years 1979-1981 in favor of the corporation. This decision is subject to appeal. Certain other issues for the years 1979-1993 remain pending before the Tax Court. The ultimate resolution of these issues and several other tax and legal issues, including resolution of tax issues related to the gas lifting imbalance along the German/Dutch border, is not expected to have a materially adverse effect upon the corporation's operations or financial condition. 27 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. CAPITAL AND EXPLORATION EXPENDITURES Capital and exploration expenditures in 2001 were $12.3 billion, up from $11.2 billion in 2000, reflecting the corporation's active investment program. Upstream spending was up 27 percent to $8.8 billion in 2001, from $6.9 billion in 2000, as a result of higher spending on major projects in Africa, the North Sea, and Canada, and increased drilling activity. Capital investments in the downstream totaled $2.3 billion in 2001, down $0.3 billion from 2000, primarily reflecting timing of investments in China partly offset by increased spending in the retail businesses. Chemicals capital expenditures were $0.9 billion in 2001, down from $1.5 billion in 2000, due to the completion of major projects in Singapore and Saudi Arabia, and timing of investment in China. Capital and exploration expenditures in the U.S. totaled $3.9 billion in 2001, an increase of $0.6 billion from 2000, reflecting higher spending in both the upstream and chemicals, partly offset by lower spending in the downstream. Spending outside the U.S. of $8.4 billion in 2001 was up $0.5 billion from 2000, reflecting higher expenditures in the upstream, partly offset by lower expenditures in the downstream and chemicals. MERGER OF EXXON CORPORATION AND MOBIL CORPORATION On November 30, 1999, a wholly-owned subsidiary of Exxon Corporation (Exxon) merged with Mobil Corporation (Mobil) so that Mobil became a wholly-owned subsidiary of Exxon (the "Merger"). At the same time, Exxon changed its name to Exxon Mobil Corporation (ExxonMobil). Under the terms of the agreement, approximately 1.0 billion shares of ExxonMobil common stock were issued in exchange for all the outstanding shares of Mobil common stock based upon an exchange ratio of 1.32015. Following the exchange, former shareholders of Exxon owned approximately 70 percent of the corporation, while former Mobil shareholders owned approximately 30 percent of the corporation. Each outstanding share of Mobil preferred stock was converted into one share of a new class of ExxonMobil preferred stock. As a result of the Merger, the accounts of certain downstream and chemicals operations jointly controlled by the combining companies have been included in the consolidated financial statements. These operations were previously accounted for by Exxon and Mobil as separate companies using the equity method of accounting. The Merger was accounted for as a pooling of interests. Accordingly, the consolidated financial statements give retroactive effect to the merger, with all periods presented as if Exxon and Mobil had always been combined. As a condition of the approval of the Merger, the U.S. Federal Trade Commission and the European Commission required that certain property primarily downstream, pipeline and natural gas distribution assets be divested. The carrying value of these assets was approximately $3 billion and before-tax proceeds were approximately $5 billion. Net after-tax gains of $40 million and $1,730 million were reported in 2001 and 2000, respectively, as extraordinary items consistent with pooling of interests accounting requirements. The divested properties historically earned approximately $200 million per year. MERGER EXPENSES AND REORGANIZATION RESERVES In association with the merger between Exxon and Mobil, $748 million pre-tax ($525 million after-tax), $1,406 million pre-tax ($920 million after-tax) and $625 million pre-tax ($469 million after-tax) of costs were recorded as merger-related expenses in 2001, 2000 and 1999, respectively. Charges included separation expenses related to workforce reductions (approximately 8,000 employees at year-end 2001), plus implementation and merger closing costs. The separation reserve balance at year-end 2001 of approximately $197 million is expected to be expended in 2002. Merger-related expenses are expected to grow to approximately $2.9 billion pre-tax on a cumulative basis by the end of 2002. Pre-tax operating synergies associated with the Merger, which are on track with expectations, including cost savings, efficiency gains, and revenue enhancements, are expected to reach approximately $7 billion per year by 2002. In the first quarter of 1999, the corporation recorded a $120 million after-tax charge for the non-merger related reorganization of Japanese downstream operations in its wholly-owned Esso Sekiyu K.K. and 50.1 percent owned General Sekiyu K.K. affiliates. The reorganization resulted in the reduction of approximately 700 administrative, financial, logistics and marketing service employee positions. The Japanese affiliates recorded a combined charge of $216 million (before-tax) to selling, general and administrative expenses for the employee related costs. Substantially all cash expenditures anticipated in the restructuring provision were paid in 1999. General Sekiyu also recorded a $211 million (before-tax) charge to depreciation and depletion for the write-off of costs associated with the cancellation of a power plant project at the Kawasaki terminal. Workforce reduction savings associated with this reorganization are approximately $50 million per year after-tax. The following table summarizes the activity in the reorganization reserves. The 1999 opening balance represents accruals for provisions taken in prior years. Opening Balance at Balance Additions Deductions Year End - -------------------------------------------------------------------------------- (millions of dollars) 1999 $169 $563 $351 $381 2000 381 738 780 339 2001 339 187 329 197 28 SITE RESTORATION AND OTHER ENVIRONMENTAL COSTS Over the years the corporation has accrued provisions for estimated site restoration costs to be incurred at the end of the operating life of certain of its facilities and properties. In addition, the corporation accrues provisions for environmental liabilities in the many countries in which it does business 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. The corporation has accrued provisions for probable environmental remediation obligations at various sites, including multi-party sites where ExxonMobil has been identified as one of the potentially responsible parties by the U.S. Environmental Protection Agency. The involvement of other financially responsible companies at these multi-party sites mitigates ExxonMobils actual joint and several liability exposure. At present, no individual site is expected to have losses material to ExxonMobil's operations, financial condition or liquidity. Charges made against income for site restoration and environmental liabilities were $371 million in 2001, $311 million in 2000 and $219 million in 1999. At the end of 2001, accumulated site restoration and environmental provisions, after reduction for amounts paid, amounted to $3.7 billion. ExxonMobil believes that any cost in excess of the amounts already provided for in the financial statements would not have a materially adverse effect upon the corporation's operations, financial condition or liquidity. ExxonMobil's worldwide environmental costs in 2001 totaled $1,782 million of which $505 million were capital expenditures and $1,277 million were operating costs (including the $371 million of site restoration and environmental provisions noted above). These costs were mostly associated with air and water conservation. Total costs for such activities are expected to increase to about $2.5 billion in both 2002 and 2003 (with capital expenditures representing about 50 percent of the total). The projected increase is primarily for capital projects to implement refining technology to manufacture low-sulfur motor fuels in many parts of the world. TAXES Income, excise and all other taxes and duties totaled $66.6 billion in 2001, a decrease of $1.8 billion or 3 percent from 2000. Income tax expense, both current and deferred, was $9.0 billion compared to $11.1 billion in 2000, reflecting lower pre-tax income in 2001. The effective tax rate of 39.3 percent in 2001 compared to 42.4 percent in 2000, benefiting from a higher level of favorably resolved tax-related issues. Excise and all other taxes and duties were $57.6 billion. Income, excise and all other taxes and duties totaled $68.4 billion in 2000, an increase of $6.9 billion or 11 percent from 1999. Income tax expense, both current and deferred, was $11.1 billion compared to $3.2 billion in 1999, reflecting higher pre-tax income in 2000. The effective tax rate increased from 31.8 percent in 1999 to 42.4 percent in 2000 as a result of a larger share of total earnings coming from the more highly taxed non-U.S. upstream segment and lower benefits from resolution of tax-related issues. Excise and all other taxes and duties decreased $1.0 billion to $57.3 billion. MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES In the past, crude, natural gas, petroleum product and chemical prices have fluctuated widely in response to changing market forces. The impacts of these price fluctuations on earnings from upstream operations, downstream operations and chemicals operations have been varied, tending at times to be offsetting. Nonetheless, the global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the corporation's businesses. Such conditions, along with the capital intensive nature of the industry and very long lead times associated with many of our projects, underscore the importance of maintaining a strong financial position. Management views the corporation's financial strength, including the AAA and Aaa ratings of its long-term debt securities by Standard and Poor's and Moody's, as a competitive advantage. Although price levels of crude oil and natural gas will occasionally spike upwards or drop precipitously, industry prices over the long term will continue to be driven by market supply and demand fundamentals. Accordingly, the corporation tests the viability of its oil and gas operations based on long-term price projections. The corporation's assessment is that its operations will continue to be successful in a variety of market conditions. This is the outcome of disciplined investment and asset management programs. Investment opportunities are tested against a variety of market conditions, including low price scenarios. 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 under-performing 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 corporation's strategic and financial objectives. The result has been the creation of a very 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 corporation's size, geographic diversity and the complementary nature of the upstream, downstream and chemicals businesses mitigate the corporation's risk from changes in interest rates, currency rates and commodity prices. The corporation relies on these operating attributes and strengths to reduce enterprise-wide risk. As a result, the corporation makes limited use of derivatives to offset exposures arising from existing transactions. The corporation does not trade in derivatives nor does it use derivatives with leverage features. The corporation maintains a system of controls that includes a policy covering the authorization, reporting, and monitoring of derivative activity. The corporation's derivative activities pose no material credit or market risks to ExxonMobil's operations, financial condition or liquidity. Interest rate, foreign exchange rate and commodity price exposures arising from derivative contracts undertaken in accordance with the corporation's policies have not been significant. 29 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The fair value of derivatives outstanding and recorded on the balance sheet at December 31, 2001 was $50 million before-tax. This is the amount that the corporation would have had to pay to third parties if these derivatives had been settled at year-end. These derivative fair values were substantially offset by the fair values of the underlying exposures being hedged. During 2001, the corporation recognized a before-tax gain of $23 million related to derivative activity. This gain included the offsetting amounts from the changes in fair value of the items being hedged by the derivatives. The fair value of derivatives outstanding at year-end and gains recognized during the year are immaterial in relation to the corporation's year-end cash balance of $6.5 billion, total assets of $143.2 billion, or net income for the year of $15.3 billion. Debt-Related Instruments 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 corporation makes limited use of interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio. The impact of a 100 basis point change in interest rates affecting the corporation's debt would not be material to earnings, cash flow or fair value. Foreign Currency Exchange Rate Instruments The corporation conducts business in many foreign currencies and is subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. The impacts of fluctuations in foreign currency exchange rates on ExxonMobil's geographically diverse operations are varied and often offsetting in amount. The corporation makes limited use of currency exchange contracts to reduce the risk of adverse foreign currency movements related to certain foreign currency debt obligations. Exposure from market rate fluctuations related to these contracts is not material. Aggregate foreign exchange transaction gains and losses included in net income are discussed in note 5 to the consolidated financial statements. Commodity Instruments The corporation makes limited use of commodity forwards, swaps and futures contracts of short duration to mitigate the risk of unfavorable price movements on certain crude, natural gas and petroleum product purchases and sales. Commodity price exposure related to these contracts is 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 operating costs has been countered by cost reductions from efficiency and productivity improvements. 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 developments and laws and regulations, such as forced divestiture of assets; restrictions on production; imports and exports; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of contract rights and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the corporation vary greatly from country to country and are not predictable. RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS In June 2001, the Financial Accounting Standards Board issued Statements of Financial Accounting Standards No. 141 (FAS 141), "Business Combinations", and No. 142 (FAS 142), "Goodwill and Other Intangible Assets". Under FAS 141, the pooling of interests method of accounting is no longer permitted and the purchase method must be used for business combinations initiated after June 30, 2001. Under FAS 142, which will be effective for the corporation beginning January 1, 2002, goodwill and certain intangibles will no longer be amortized but will be subject to annual impairment tests. The effect of adoption of the new standards on the corporation's financial statements will be negligible. In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143 (FAS 143), "Accounting for Asset Retirement Obligations". FAS 143 is required to be adopted by the corporation no later than January 1, 2003 and its primary impact will be to change the method of accruing for upstream site restoration costs. These costs are currently accrued ratably over the productive lives of the assets. At the end of 2001 the cumulative amount accrued under this policy was approximately $3.2 billion. Under FAS 143, the fair value of asset retirement obligations will be recorded as liabilities when they are incurred, which are typically at the time the assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations. Over time the liabilities will be accrued for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The corporation is evaluating the impact of adopting FAS 143. In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144 (FAS 144), "Accounting for the Impairment or Disposal of Long-Lived Assets". FAS 144 is required to be adopted prospectively by the corporation no later than January 1, 2002. FAS 144 supercedes previous guidance related to the impairment or disposal of long-lived assets. For long-lived assets to be held and used, it resolves certain implementation issues of the former standards, but retains the basic requirements of recognition and measurement of impairment losses. For long-lived assets to be disposed of by sale, it broadens the definition of those disposals that should be reported separately as discontinued operations. There is no impact on the corporation of adopting FAS 144, except that future sales of long-lived assets may be required to be presented as discontinued operations, which would be a different presentation than under previous accounting standards. CRITICAL ACCOUNTING POLICIES The corporation's accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The following summary provides further information about the critical accounting policies and should be read in conjunction with note 1 on page 38. 30 Principles of Consolidation The consolidated financial statements include the accounts of those significant subsidiaries that the corporation controls. They also include the corporation's undivided interests in upstream assets and liabilities. Amounts representing the corporation's percentage interest in the underlying net assets of other significant affiliates that it does not control, but exercises significant influence, are included in "Investments and advances"; the corporation's share of the net income of these companies is included in the consolidated statement of income caption "Earnings from equity interests and other revenue". The accounting for these non-consolidated companies is referred to as the equity method of accounting. 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 8 on page 41. The corporation believes this to be important information necessary to a full understanding of the corporation's financial statements. Investments in companies that are partially owned by the corporation are integral to the corporation's operation's. 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 the 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 undivided interests in 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. Revenue Recognition Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and all other items are recorded when title passes to the customer. The corporation does not engage in arrangements whereby the corporation has ongoing relationships with its buyers that require it to repurchase its products or provide buyers with the right of return. As a result, the recognition of revenues is straightforward. Derivative Instruments As discussed on page 29, the corporation makes limited use of derivatives. Derivative instruments are not held for trading purposes nor do they have leverage features. The corporation's size, geographic diversity and the complementary nature of the upstream, downstream, and chemicals businesses mitigate the corporation's risk from changes in interest rates, currency rates, and commodity prices, reducing the corporation's need for derivatives to manage business risk. Because of their limited use, accounting policies for derivatives do not impact information that is significant or critical to an understanding of the corporation's financial condition and results of operations. Inventories Crude oil, products and merchandise are carried at the lower of current market value or cost (generally determined under the last-in, first-out method - LIFO). There are other acceptable methods of accounting for inventory such as first-in, first-out or average cost. The corporation uses the LIFO method because it charges each sale with the cost of the most recently purchased inventory. As such, the profit recognized on these sales is based on the latest cost structure and generally results in a better matching of costs and revenues. Property, Plant and Equipment The corporation's exploration and production activities are accounted for under the "successful efforts" method. 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. Unit-of-production rates are based on oil, gas and mineral reserves estimated to be recoverable from existing facilities. The straight-line method is based on estimated asset service life taking obsolescence into consideration. The service lives of refinery and chemicals components generally extend to 25 and 20 years, respectively, and reflect the corporation's long-term commitment to effective asset optimization. Under the "successful efforts" method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to ensure that commercial quantities of reserves have been found or that additional exploration work is underway or planned. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The corporation uses this accounting policy instead of the "full cost" method because it provides a more timely accounting of the success or failure of the corporation's exploration and production activities. If the full cost method were used, all costs would be capitalized and depreciated on a country-by-country basis. The capitalized costs would be subject to an impairment test by country. The full cost method would tend to delay the expense recognition of unsuccessful projects. Oil, gas and other 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. 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, except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. 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 develop- 31 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ment should proceed or enhanced recovery methods should be undertaken. Proved oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation and evaluating for impairment. These 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. The estimation of reserves is an ongoing process based on rigorous technical evaluations and extrapolations of well information such as flow rates and reservoir pressure declines. Supplemental information on oil and gas exploration and production activities can be found on pages 57 to 61. Included in that section on page 60 is information on Canadian tar sands proven reserves. This information is shown separately from the conventional liquids and natural gas proved reserves. For internal management purposes, the corporation does not view these reserves separately, but instead considers them and their development as an integral part of total upstream operations. Refining tar sands reserves produces the same petroleum products that are produced from refining conventional oil and gas reserves. However, U.S. Securities and Exchange Commission regulations define these tar sands reserves as mining reserves and not a part of conventional oil and gas reserves. Site Restoration and Environmental Conservation Costs Site restoration costs that may be incurred by the corporation at the end of the operating life of certain of its facilities and properties are accrued ratably over the asset's productive life. Liabilities for environmental conservation are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. The necessity of recording liabilities for these costs is prescribed by GAAP. Estimating the probability of whether obligations have been incurred and the amounts that should be recorded requires significant management judgment. This judgment is based on extensive cost and engineering studies using the latest available technology. Foreign Currency Translation The "functional currency" for translating the accounts of the majority of downstream and chemicals operations outside the U.S. is the local currency. Local currency is also used for upstream operations that are relatively self-contained and integrated within a particular country. The U.S. dollar is used for operations in highly inflationary economies and certain other countries. 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 chemicals operations normally use the local currency, except in highly inflationary countries, primarily Latin America, as well as in 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. These operations, which use the U.S. dollar as their functional currency, are in Malaysia, Indonesia, Nigeria, Equatorial Guinea and the Middle East countries. Litigation and Other Contingencies Claims for substantial amounts have been made against ExxonMobil and certain of its consolidated subsidiaries in pending lawsuits and tax disputes. These are summarized on page 27, with a more extensive discussion included in note 17 on page 51. The general guidance provided by GAAP requires that liabilities for contingencies should be recorded when it is probable that a liability has been incurred before the date of the balance sheet and that the amount can be reasonably estimated. Significant management judgment is required to comply with this guidance, and it includes management reviews with the corporation's attorneys, taking into consideration all of the relevant facts and circumstances. FORWARD-LOOKING STATEMENTS Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including merger expenses and synergies; 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 above and under the caption "Factors Affecting Future Results" in Item 1 of ExxonMobil's 2001 Form 10-K. 32 REPORT OF INDEPENDENT ACCOUNTANTS PricewaterhouseCoopers [LOGO] Dallas, Texas February 27, 2002 To the Shareholders of Exxon Mobil Corporation In our opinion, the consolidated financial statements appearing on pages 34 through 55 present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiary companies at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the corporation's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion. /s/ PricewaterhouseCoopers LLP 33 CONSOLIDATED STATEMENT OF INCOME
2001 2000 1999 - --------------------------------------------------------------------------------------------------------- (millions of dollars) Revenue Sales and other operating revenue, including excise taxes $ 209,417 $ 228,439 $ 182,529 Earnings from equity interests and other revenue 4,071 4,309 2,998 ------------------------------------- Total revenue $ 213,488 $ 232,748 $ 185,527 ------------------------------------- Costs and other deductions Crude oil and product purchases $ 92,286 $ 108,951 $ 77,011 Operating expenses 18,170 18,135 16,806 Selling, general and administrative expenses 12,900 12,044 13,134 Depreciation and depletion 7,944 8,130 8,304 Exploration expenses, including dry holes 1,175 936 1,246 Merger related expenses 748 1,406 625 Interest expense 293 589 695 Excise taxes 21,907 22,356 21,646 Other taxes and duties 33,377 32,708 34,765 Income applicable to minority and preferred interests 569 412 145 ------------------------------------- Total costs and other deductions $ 189,369 $ 205,667 $ 174,377 ------------------------------------- Income before income taxes $ 24,119 $ 27,081 $ 11,150 Income taxes 9,014 11,091 3,240 ------------------------------------- Income before extraordinary item $ 15,105 $ 15,990 $ 7,910 Extraordinary gain, net of income tax 215 1,730 -- ------------------------------------- Net income $ 15,320 $ 17,720 $ 7,910 ===================================== Net income per common share (dollars) Before extraordinary item $ 2.20 $ 2.30 $ 1.14 Extraordinary gain, net of income tax 0.03 0.25 -- ------------------------------------- Net income $ 2.23 $ 2.55 $ 1.14 ===================================== Net income per common share - assuming dilution (dollars) Before extraordinary item $ 2.18 $ 2.27 $ 1.12 Extraordinary gain, net of income tax 0.03 0.25 -- ------------------------------------- Net income $ 2.21 $ 2.52 $ 1.12 =====================================
The information on pages 38 through 55 is an integral part of these statements. 34 CONSOLIDATED BALANCE SHEET
Dec. 31 Dec. 31 2001 2000 - ------------------------------------------------------------------------------------------------------------------------------ (millions of dollars) Assets Current assets Cash and cash equivalents $ 6,547 $ 7,080 Notes and accounts receivable, less estimated doubtful amounts 19,549 22,996 Inventories Crude oil, products and merchandise 6,743 7,244 Materials and supplies 1,161 1,060 Prepaid taxes and expenses 1,681 2,019 --------------------- Total current assets $ 35,681 $ 40,399 Investments and advances 10,768 12,618 Property, plant and equipment, at cost, less accumulated depreciation and depletion 89,602 89,829 Other assets, including intangibles, net 7,123 6,154 --------------------- Total assets $ 143,174 $ 149,000 ===================== Liabilities Current liabilities Notes and loans payable $ 3,703 $ 6,161 Accounts payable and accrued liabilities 22,862 26,755 Income taxes payable 3,549 5,275 --------------------- Total current liabilities $ 30,114 $ 38,191 Long-term debt 7,099 7,280 Annuity reserves and accrued liabilities 12,475 11,934 Deferred income tax liabilities 16,359 16,442 Deferred credits 1,141 1,166 Equity of minority and preferred shareholders in affiliated companies 2,825 3,230 --------------------- Total liabilities $ 70,013 $ 78,243 --------------------- Shareholders' equity Benefit plan related balances $ (159) $ (235) Common stock without par value (9,000 million shares authorized) 3,789 3,661 Earnings reinvested 95,718 86,652 Accumulated other nonowner changes in equity Cumulative foreign exchange translation adjustment (5,947) (4,862) Minimum pension liability adjustment (535) (310) Unrealized gains/(losses) on stock investments (108) (17) Common stock held in treasury (1,210 million shares in 2001 and 1,089 million shares in 2000) (19,597) (14,132) --------------------- Total shareholders' equity $ 73,161 $ 70,757 --------------------- Total liabilities and shareholders' equity $ 143,174 $ 149,000 =====================
The information on pages 38 through 55 is an integral part of these statements. 35 CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
2001 2000 1999 ------------------------------------------------------------------------------- Nonowner Nonowner Nonowner Shareholders' Changes in Shareholders' Changes in Shareholders' Changes in Equity Equity Equity Equity Equity Equity ------------------------------------------------------------------------------- (millions of dollars) Benefit plan related balances $ (159) $ (235) $ (298) Common stock (see note 13) At beginning of year 3,661 3,403 4,870 Issued -- -- 92 Other 128 258 303 Cancellation of common stock held in treasury -- -- (1,862) ----------- ---------- -------------- At end of year $ 3,789 $ 3,661 $ 3,403 ----------- ---------- -------------- Earnings reinvested At beginning of year 86,652 75,055 75,109 Net income for the year 15,320 $ 15,320 17,720 $ 17,720 7,910 $ 7,910 Dividends - common and preferred shares (6,254) (6,123) (5,872) Cancellation of common stock held in treasury -- -- (2,092) ----------- ---------- ---------- At end of year $ 95,718 $ 86,652 $ 75,055 ----------- ---------- ---------- Accumulated other nonowner changes in equity At beginning of year (5,189) (2,568) (1,981) Foreign exchange translation adjustment (1,085) (1,085) (2,562) (2,562) (727) (727) Minimum pension liability adjustment (225) (225) (11) (11) 109 109 Unrealized gains/(losses) on stock investments (91) (91) (48) (48) 31 31 ----------- --------- ---------- At end of year $ (6,590) $ (5,189) $ (2,568) ----------- ---------- --------- -------- ---------- ---------- Total $ 13,919 $ 15,099 $ 7,323 ========== ======== ========== Common stock held in treasury At beginning of year (14,132) (12,126) (15,831) Acquisitions, at cost (5,721) (2,352) (976) Dispositions 256 346 727 Cancellation, returned to unissued -- -- 3,954 ----------- --------- ---------- At end of year $ (19,597) $ (14,132) $ (12,126) ----------- --------- ---------- Shareholders' equity at end of year $ 73,161 $ 70,757 $ 63,466 =========== ========= ========== Share Activity -------------------------------------------------------------- 2001 2000 1999 -------------------------------------------------------------- (millions of shares) Common stock Issued (see note 13) At beginning of year 8,019 8,019 8,338 Issued -- -- 8 Cancelled -- -- (327) ----------- --------- ---------- At end of year 8,019 8,019 8,019 ----------- --------- ---------- Held in treasury (see note 13) At beginning of year (1,089) (1,064) (1,422) Acquisitions, at cost (139) (54) (33) Dispositions 18 29 64 Cancellation, returned to unissued -- -- 327 ----------- --------- ---------- At end of year (1,210) (1,089) (1,064) ----------- --------- ---------- Common shares outstanding at end of year 6,809 6,930 6,955 =========== ========= ==========
The information on pages 38 through 55 is an integral part of these statements. 36 CONSOLIDATED STATEMENT OF CASH FLOWS 2001 2000 1999 - ------------------------------------------------------------------------------------------------------------------- (millions of dollars) Cash flows from operating activities Net income Accruing to ExxonMobil shareholders $ 15,320 $ 17,720 $ 7,910 Accruing to minority and preferred interests 569 412 145 Adjustments for non-cash transactions Depreciation and depletion 7,944 8,130 8,304 Deferred income tax charges/(credits) 650 10 (1,439) Annuity and accrued liability provisions 498 (662) 412 Dividends received greater than/(less than) equity in current earnings of equity companies 78 (387) 146 Extraordinary gain, before income tax (194) (2,038) -- Changes in operational working capital, excluding cash and debt Reduction/(increase) - Notes and accounts receivable 3,062 (4,832) (3,478) - Inventories 154 (297) 50 - Prepaid taxes and expenses 118 (204) 177 Increase/(reduction) - Accounts and other payables (5,103) 5,411 3,046 All other items - net (207) (326) (260) ---------------------------------- Net cash provided by operating activities $ 22,889 $ 22,937 $ 15,013 ---------------------------------- Cash flows from investing activities Additions to property, plant and equipment $ (9,989) $ (8,446) $ (10,849) Sales of subsidiaries, investments and property, plant and equipment 1,078 5,770 972 Additional investments and advances (1,035) (1,648) (1,476) Collection of advances 1,735 985 387 Additions to other marketable securities -- (41) (61) Sales of other marketable securities -- 82 42 ---------------------------------- Net cash used in investing activities $ (8,211) $ (3,298) $ (10,985) ---------------------------------- Net cash generation before financing activities $ 14,678 $ 19,639 $ 4,028 ---------------------------------- Cash flows from financing activities Additions to long-term debt $ 547 $ 238 $ 454 Reductions in long-term debt (506) (901) (341) Additions to short-term debt 705 500 1,870 Reductions in short-term debt (1,212) (2,413) (2,359) Additions/(reductions) in debt with less than 90 day maturity (2,306) (3,129) 2,210 Cash dividends to ExxonMobil shareholders (6,254) (6,123) (5,872) Cash dividends to minority interests (194) (251) (219) Changes in minority interests and sales/(purchases) of affiliate stock (401) (227) (200) Common stock acquired (5,721) (2,352) (670) Common stock sold 301 493 348 ---------------------------------- Net cash used in financing activities $(15,041) $ (14,165) $ (4,779) ---------------------------------- Effects of exchange rate changes on cash $ (170) $ (82) $ 53 ---------------------------------- Increase/(decrease) in cash and cash equivalents $ (533) $ 5,392 $ (698) Cash and cash equivalents at beginning of year 7,080 1,688 2,386 ---------------------------------- Cash and cash equivalents at end of year $ 6,547 $ 7,080 $ 1,688 ==================================
The information on pages 38 through 55 is an integral part of these statements. 37 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation. The corporation's principal business is energy, involving the worldwide exploration, production, transportation and sale of crude oil and natural gas (upstream) and the manufacture, transportation and sale of petroleum products (downstream). The corporation is also a major worldwide manufacturer and marketer of petrochemicals and participates in coal and minerals mining and electric power generation. The preparation of financial statements in conformity with Generally Accepted Accounting Principles 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. 1. Summary of Accounting Policies Principles of Consolidation. The consolidated financial statements include the accounts of those significant subsidiaries owned directly or indirectly with more than 50 percent of the voting rights held by the corporation, and for which other shareholders do not possess the right to participate in significant management decisions. They also include the corporation's share of the undivided interest in upstream assets and liabilities. Amounts representing the corporation's percentage interest in the underlying net assets of other significant subsidiaries and less than majority owned companies in which a significant equity ownership interest is held, are included in "Investments and advances"; the corporation's share of the net income of these companies is included in the consolidated statement of income caption "Earnings from equity interests and other revenue." Investments in other companies, none of which is significant, are generally included in "Investments and advances" at cost or less. Dividends from these companies are included in income as received. Revenue Recognition. Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and all other items are recorded when title passes to the customer. Revenues from the production of natural gas properties in which the corporation has an interest with the other producers are recognized on the basis of the company's net working interest. Differences between actual production and net working interest volumes are not significant. Derivative Instruments. The corporation makes limited use of derivatives. Derivative instruments are not held for trading purposes nor do they have leverage 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. The gains and losses resulting from the changes in fair value of these instruments are recorded in income, except when the instruments are designated as hedging the currency exposure of net investments in foreign subsidiaries, in which case they are recorded in the cumulative foreign exchange translation account, as part of shareholders equity. The gains and losses on derivative instruments that are designated as fair value hedges (i.e., those hedging the exposure to changes in the fair value of an asset or a liability or the changes in the fair value of a firm commitment), are offset by the gains and losses from the changes in fair value of the hedged items, which are also recognized in income. Most of these designated hedges are entered into at the same time that the hedged items are transacted, they are fully effective and in combination with the offsetting hedged items, they result in no net impact on income. In some situations, the corporation has chosen not to designate certain immaterial derivatives used for hedging economic exposure as hedges for accounting purposes due to the excessive administrative effort that would be required to account for these items as hedging transactions. These derivatives are recorded on the balance sheet at fair value and the gains and losses arising from changes in fair value are recognized in income. All derivatives activity is immaterial. 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). Costs include applicable purchase costs and operating expenses but not general and administrative expenses or research and development costs. 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. Unit-of-production rates are based on oil, gas and other mineral reserves estimated to be recoverable from existing facilities. The straight-line method of depreciation is based on estimated asset service life taking obsolescence into consideration. Maintenance and repairs are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. The corporation's upstream activities are accounted for under the "successful efforts" method. Under this method, costs of productive wells and development dry holes, both tangible and intangible, as well as productive acreage are capitalized and amortized on the unit-of-production method. Costs of that portion of undeveloped acreage likely to be unproductive, based largely on historical experience, are amortized over the period of exploration. Other exploratory expenditures, including geophysical costs, other dry hole costs and annual lease rentals, are expensed as incurred. Exploratory wells that find oil and gas in an area requiring a major capital expenditure before production can begin are evaluated annually to assure that commercial quantities of reserves have been found or that additional exploration work is underway or planned. Exploratory well costs not meeting either of these tests are charged to expense. Oil, gas and other 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. 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, except in circumstances where it is probable that additional resources will be developed and contribute to cash flows in the future. Site Restoration and Environmental Conservation Costs. Site restoration costs that may be incurred by the corporation at the end of the operating life of certain of its facilities and properties are reserved ratably over the asset's productive life. 38 Liabilities for environmental conservation 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 "functional currency" for translating the accounts of the majority of downstream and chemical operations outside the U.S. is the local currency. Local currency is also used for upstream operations that are relatively self-contained and integrated within a particular country, such as in Canada, the United Kingdom, Norway and Continental Europe. The U.S. dollar is used for operations in highly inflationary economies, in Singapore which is predominantly export oriented and for some upstream operations, primarily in Malaysia, Indonesia, Nigeria, Equatorial Guinea and the Middle East countries. For all operations, gains or losses on remeasuring foreign currency transactions into functional currency are included in income. 2. Extraordinary Item and Accounting Change Net income for 2001 included net after-tax gains from asset management activities in the chemicals segment and regulatory required asset divestitures in the amount of $215 million (including an income tax credit of $21 million), or $0.03 per common share. Net income for 2000 included net after-tax gains from regulatory required asset divestitures in the amount of $1,730 million (net $308 million of income taxes), or $0.25 per common share. These net after-tax gains were reported as extraordinary items according to accounting requirements for business combinations accounted for as pooling of interests. As of January 1, 2001, ExxonMobil adopted Financial Accounting Standards Board Statement No. 133 (FAS 133), "Accounting for Derivative Instruments and Hedging Activities" as amended by Statements No. 137 and 138. This statement requires that all derivatives be recognized as either assets or liabilities in the financial statements and be measured at fair value. Since the corporation makes limited use of derivatives, the effect of adoption of FAS 133 on the corporation's operations or financial condition was negligible. 3. Merger of Exxon Corporation and Mobil Corporation On November 30, 1999, a wholly-owned subsidiary of Exxon Corporation (Exxon) merged with Mobil Corporation (Mobil) so that Mobil became a wholly-owned subsidiary of Exxon (the "Merger"). At the same time, Exxon changed its name to Exxon Mobil Corporation (ExxonMobil). Under the terms of the agreement, approximately 1.0 billion shares of ExxonMobil common stock were issued in exchange for all the outstanding shares of Mobil common stock based upon an exchange ratio of 1.32015. Following the exchange, former shareholders of Exxon owned approximately 70 percent of the corporation, while former Mobil shareholders owned approximately 30 percent of the corporation. Each outstanding share of Mobil preferred stock was converted into one share of a new class of ExxonMobil preferred stock. As a result of the Merger, the accounts of certain downstream and chemicals operations jointly controlled by the combining companies have been included in the consolidated financial statements. These operations were previously accounted for by Exxon and Mobil as separate companies using the equity method of accounting. The Merger was accounted for as a pooling of interests. Accordingly, the consolidated financial statements give retroactive effect to the Merger, with all periods presented as if Exxon and Mobil had always been combined. Certain reclassifications have been made to conform the presentation of Exxon and Mobil. As a condition of the approval of the Merger, the U.S. Federal Trade Commission and the European Commission required that certain property -- primarily downstream, pipeline and natural gas distribution assets -- be divested. The carrying value of these assets was approximately $3 billion and net after-tax gains of $40 million and $1,730 million were reported as extraordinary items in 2001 and 2000, respectively. The divested properties historically earned approximately $200 million per year. 4. Merger Expenses and Reorganization Reserves In association with the Merger, $748 million pre-tax ($525 million after-tax), $1,406 million pre-tax ($920 million after-tax), and $625 million pre-tax ($469 million after-tax) of costs were recorded as merger-related expenses in 2001, 2000 and 1999, respectively. These cumulative charges of $2,779 million included separation expenses of approximately $1,345 million related to workforce reductions (approximately 8,000 employees at year-end 2001), plus implementation costs and merger closing costs. The separation reserve balance at year-end 2001 of approximately $197 million, is expected to be expended in 2002. In the first quarter of 1999, the corporation recorded a $120 million after-tax charge for the non-merger related reorganization of Japanese downstream operations in its wholly-owned Esso Sekiyu K.K. and 50.1 percent owned General Sekiyu K.K. affiliates. The reorganization resulted in the reduction of approximately 700 administrative, financial, logistics and marketing service employee positions. The Japanese affiliates recorded a combined charge of $216 million (before-tax) to selling, general and administrative expenses for the employee related costs. Substantially all cash expenditures anticipated in the restructuring provision have been paid as of the end of 1999. General Sekiyu also recorded a $211 million (before-tax) charge to depreciation and depletion for the write-off of costs associated with the cancellation of a power plant project at the Kawasaki terminal. The following table summarizes the activity in the reorganization reserves. The 1999 opening balance represents accruals for provisions taken in prior years. Opening Balance at Balance Additions Deductions Year End ------------------------------------------------------------------ (millions of dollars) 1999 $169 $563 $351 $381 2000 381 738 780 339 2001 339 187 329 197 39 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. Miscellaneous Financial Information Research and development costs totaled $603 million in 2001, $564 million in 2000 and $630 million in 1999. Net income included aggregate foreign exchange transaction losses of $142 million in 2001, $236 million in 2000 and $5 million in 1999. In 2001, 2000, and 1999, net income included gains of $238 million, and $175 million, and losses of $7 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 $4.2 billion and $6.7 billion at December 31, 2001 and 2000, respectively. 6. Cash Flow Information The consolidated statement of cash flows provides information about changes in cash and cash equivalents. Highly liquid investments with maturities of three months or less when acquired are classified as cash equivalents. Cash payments for interest were: 2001 - $562 million, 2000 - $729 million and 1999 - $882 million. Cash payments for income taxes were: 2001 - $9,855 million, 2000 - $8,671 million and 1999 - $3,805 million. 7. Additional Working Capital Data Dec. 31 Dec. 31 2001 2000 - -------------------------------------------------------------------------------- (millions of dollars) Notes and accounts receivable Trade, less reserves of $279 million and $258 million $ 13,597 $ 17,568 Other, less reserves of $62 million and $48 million 5,952 5,428 ------------------------ $ 19,549 $ 22,996 ======================== Notes and loans payable Bank loans $ 1,063 $ 1,244 Commercial paper 1,804 3,761 Long-term debt due within one year 339 650 Other 497 506 ------------------------ $ 3,703 $ 6,161 ======================== Accounts payable and accrued liabilities Trade payables $ 12,696 $ 15,357 Obligations to equity companies 632 586 Accrued taxes other than income taxes 4,768 5,423 Other 4,766 5,389 ------------------------ $ 22,862 $ 26,755 ======================== On December 31, 2001, unused credit lines for short-term financing totaled approximately $5.3 billion. Of this total, $2.1 billion support commercial paper programs under terms negotiated when drawn. The weighted average interest rate on short-term borrowings outstanding at December 31, 2001 and 2000 was 3.8 percent and 6.4 percent, respectively. 40 8. Equity Company Information The summarized financial information below includes amounts related to certain less than majority owned companies and majority owned subsidiaries where minority shareholders possess the right to participate in significant management decisions (see note 1). These companies are primarily engaged in crude production, natural gas marketing and refining operations in North America; natural gas production, natural gas distribution, and downstream operations in Europe and crude production in Kazakhstan and the Middle East. Also included are several power generation, petrochemical/lubes manufacturing and chemical ventures; 1999 included amounts related to Mobil's European Fuels joint venture which was divested as a condition of the Merger approval.
2001 2000 1999 ----------------------------------------------------------------- ExxonMobil ExxonMobil ExxonMobil Equity Company Financial Summary Total Share Total Share Total Share - ------------------------------------------------------------------------------------------------------------------------------------ (millions of dollars) Total revenues Percent of revenues from companies included in the ExxonMobil consolidation was 9% in 2001, 11% in 2000 and 8% in 1999 $ 95,009 $ 36,695 $ 81,371 $32,452 $94,534 $32,124 ---------------------------------------------------------------- Income before income taxes $ 6,952 $ 2,922 $ 7,632 $ 3,092 $ 4,100 $ 2,095 Less: Related income taxes (1,562) (748) (1,382) (658) (734) (449) ---------------------------------------------------------------- Net income $ 5,390 $ 2,174 $ 6,250 $ 2,434 $ 3,366 $ 1,646 ================================================================ Current assets $ 18,992 $ 7,369 $ 28,784 $11,479 $21,518 $ 7,739 Property, plant and equipment, less accumulated depreciation 36,565 13,135 36,553 13,733 44,213 15,509 Other long-term assets 5,127 2,284 6,656 2,979 4,806 2,106 ---------------------------------------------------------------- Total assets $ 60,684 $ 22,788 $ 71,993 $28,191 $70,537 $25,354 ---------------------------------------------------------------- Short-term debt $ 3,142 $ 1,232 $ 2,636 $ 1,093 $ 2,856 $ 1,129 Other current liabilities 16,218 6,349 25,377 10,357 18,129 6,324 Long-term debt 10,496 3,950 11,116 4,094 13,486 3,978 Other long-term liabilities 6,253 2,862 7,054 3,273 5,372 2,598 Advances from shareholders 8,443 2,179 8,485 2,510 3,636 1,919 ---------------------------------------------------------------- Net assets $ 16,132 $ 6,216 $ 17,325 $ 6,864 $27,058 $ 9,406 ================================================================ 9. Investments and Advances Dec. 31 Dec. 31 2001 2000 - ------------------------------------------------------------------------------------------------------------------------------------ (millions of dollars) Companies carried at equity in underlying assets Investments $ 6,216 $ 6,864 Advances 2,179 2,510 ---------------------- $ 8,395 $ 9,374 Companies carried at cost or less and stock investments carried at fair value 1,060 1,230 ---------------------- $ 9,455 $10,604 Long-term receivables and miscellaneous investments at cost or less 1,313 2,014 ---------------------- Total $10,768 $12,618 ======================
41 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Investment in Property, Plant and Equipment Dec. 31, 2001 Dec. 31, 2000 ------------------------------------------------ Cost Net Cost Net - --------------------------------------------------------------------------------------------------------- (millions of dollars) Petroleum and natural gas Upstream $ 109,616 $ 46,597 $ 106,287 $ 45,731 Downstream 50,691 25,560 51,862 26,730 ------------------------------------------------ Total petroleum and natural gas $ 160,307 $ 72,157 $ 158,149 $ 72,461 Chemicals 17,973 9,690 17,860 9,935 Other 12,223 7,755 11,737 7,433 ------------------------------------------------ Total $ 190,503 $ 89,602 $ 187,746 $ 89,829 ================================================
Accumulated depreciation and depletion totaled $100,901 million at the end of 2001 and $97,917 million at the end of 2000. Interest capitalized in 2001, 2000 and 1999 was $518 million, $641 million and $595 million, respectively. - -------------------------------------------------------------------------------- 11. Leased Facilities At December 31, 2001, the corporation and its consolidated subsidiaries held non-cancelable operating charters and leases covering drilling equipment, tankers, service stations and other properties with minimum lease commitments as indicated in the table. Net rental expenditures for 2001, 2000 and 1999 totaled $2,454 million, $1,935 million and $2,172 million, respectively, after being reduced by related rental income of $199 million, $195 million and $317 million, respectively. Minimum rental expenditures totaled $2,562 million in 2001, $1,992 million in 2000 and $2,311 million in 1999. Minimum Related Commitment Rental income - -------------------------------------------------------------------------------- (millions of dollars) 2002 $ 1,327 $ 110 2003 1,107 103 2004 801 95 2005 569 87 2006 433 48 2007 and beyond 2,687 103 --------------------------- Total $ 6,924 $ 546 =========================== - -------------------------------------------------------------------------------- 12. Employee Stock Ownership Plans In 1989, the Exxon leveraged employee stock ownership plan (Exxon LESOP) trust borrowed $1,000 million under the terms of notes guaranteed by Exxon. The Exxon LESOP trust used the proceeds of the borrowing to purchase shares of Exxon's convertible Class A Preferred Stock. The final Exxon LESOP note was repaid in 1999. By year-end 1999, all remaining shares of Exxon Class A Preferred Stock were converted to ExxonMobil common shares. In 1989, the Mobil Oil Corporation employee stock ownership plan (Mobil LESOP) trust borrowed $800 million under the terms of notes and debentures guaranteed by Mobil. The trust used the proceeds of the borrowing to purchase shares of Mobil's Series B Convertible Preferred Stock which upon the merger were converted into shares of ExxonMobil Class B Preferred Stock with similar terms. By year-end 1999, all remaining shares of Class B Preferred Stock were converted to ExxonMobil common shares. The Exxon LESOP and Mobil LESOP were merged in late 1999 to create the ExxonMobil LESOP. The ExxonMobil LESOP is a constituent part of the ExxonMobil Savings Plan which, effective February 8, 2002, is an employee stock ownership plan in its entirety. Employees eligible to participate in the ExxonMobil Savings Plan may elect to participate in the ExxonMobil LESOP. Corporate contributions to the plan and dividends are used to make principal and interest payments on the ExxonMobil LESOP trust notes. As corporate contributions and dividends are credited, common shares are allocated to participants' plan accounts. The corporation's contribution to the ExxonMobil LESOP, representing the amount by which debt service exceeded dividends on shares held by the ExxonMobil LESOP, was $58 million, $15 million, and $19 million in 2001, 2000 and 1999, respectively. Accounting for the plans has followed the principles that were in effect for the respective plans when they were established. The amount of compensation expense related to the plans and recorded by the corporation during the periods was $83 million in 2001, $13 million in 2000, and $5 million in 1999. The ExxonMobil LESOP trust held 104.2 million shares of ExxonMobil common stock at the end of 2001 and 109.2 million shares at the end of 2000. 42 13. Capital On May 30, 2001, the company's Board of Directors approved a two-for-one stock split of common stock for shareholders of record on June 20, 2001. The authorized common stock was increased from 4.5 billion shares without par value to 9 billion shares without par value, and the issued shares were split on a two-for-one basis on June 20, 2001. At the effective time of the merger of Exxon and Mobil, the authorized common stock of ExxonMobil was increased from 3 billion shares to 4.5 billion shares. Under the terms of the merger agreement, approximately 1.0 billion shares of ExxonMobil common stock were issued in exchange for all of the outstanding shares of Mobil's common stock based upon an exchange ratio of 1.32015 ExxonMobil shares for each Mobil share. Mobil's common stock accounted for as treasury stock was cancelled at the effective time of the merger. In 1989, $1,800 million of benefit related balances were recorded as debt and as a reduction to shareholders' equity, representing Exxon and Mobil guaranteed borrowings by the Exxon LESOP to purchase Exxon Class A Preferred Stock and the Mobil LESOP to purchase Mobil Class B Preferred Stock. As common shares are earned by employees and the debt is repaid, the benefit plan related balances are being reduced. Preferred dividends of $36 million were paid during 1999 on preferred shares described in note 12, all of which were converted to ExxonMobil common stock by year-end 1999. The table below summarizes the earnings per share calculations.
2001 2000 1999 ------------------------------- Net income per common share - --------------------------- Income before extraordinary item (millions of dollars) $ 15,105 $ 15,990 $ 7,910 Less: Preferred stock dividends -- -- (36) ------------------------------- Income available to common shares $ 15,105 $ 15,990 $ 7,874 =============================== Weighted average number of common shares outstanding (millions of shares) 6,868 6,953 6,906 Net income per common share Before extraordinary item $ 2.20 $ 2.30 $ 1.14 Extraordinary gain, net of income tax 0.03 0.25 -- ------------------------------- Net income $ 2.23 $ 2.55 $ 1.14 =============================== Net income per common share - assuming dilution - ----------------------------------------------- Income before extraordinary item (millions of dollars) $ 15,105 $ 15,990 $ 7,910 Adjustment for assumed dilution (4) (8) 1 ------------------------------- Income available to common shares $ 15,101 $ 15,982 $ 7,911 =============================== Weighted average number of common shares outstanding (millions of shares) 6,868 6,953 6,906 Plus: Issued on assumed exercise of stock options 73 80 88 Plus: Assumed conversion of preferred stock -- -- 42 ------------------------------- Weighted average number of common shares outstanding 6,941 7,033 7,036 =============================== Net income per common share Before extraordinary item $ 2.18 $ 2.27 $ 1.12 Extraordinary gain, net of income tax 0.03 0.25 -- ------------------------------- Net income $ 2.21 $ 2.52 $ 1.12 =============================== Dividends paid per common share $ 0.910 $ 0.880 $ 0.844
43 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. 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, 2001 and 2000, was $7.9 billion and $8.0 billion, respectively, as compared to recorded book values of $7.1 billion and $7.3 billion. The corporation's size, geographic diversity and the complementary nature of the upstream, downstream and chemicals businesses mitigate the corporation's risk from changes in interest rates, currency rates and commodity prices. The corporation relies on these operating attributes and strengths to reduce enterprise-wide risk. As a result, the corporation makes limited use of derivatives to offset exposures arising from existing transactions. The corporation does not trade in derivatives nor does it use derivatives with leveraged features. The corporation maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity. The corporation's derivative activities pose no material credit or market risks to ExxonMobil's operations, financial condition or liquidity. Interest rate, foreign exchange rate and commodity price exposures arising from derivative contracts undertaken in accordance with the corporation's policies have not been significant. The fair value of derivatives outstanding and recorded on the balance sheet at December 31, 2001 was $50 million before-tax. This is the amount that the corporation would have had to pay to third parties if these derivatives had been settled at year-end. These derivative fair values were substantially offset by the fair values of the underlying exposures being hedged. During 2001, the corporation recognized a before-tax gain of $23 million related to derivative activity. This gain included the offsetting amounts from the changes in fair value of the items being hedged by the derivatives. 15. Long-Term Debt At December 31, 2001, long-term debt consisted of $6,465 million due in U.S. dollars and $634 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 $339 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, 2002, in millions of dollars, are: 2003 - $880, 2004 - $2,176, 2005 - $328 and 2006 - $114. Certain of the borrowings described may from time to time be assigned to other ExxonMobil affiliates. At December 31, 2001, the corporation's unused long-term credit lines were not material. The total outstanding balance of defeased debt at year-end 2001 was $408 million. Summarized long-term borrowings at year-end 2001 and 2000 were as shown in the adjacent table: 2001 2000 - -------------------------------------------------------------------------------- (millions of dollars) Exxon Mobil Corporation Guaranteed zero coupon notes due 2004 - Face value ($1,146) net of unamortized discount $ 836 $ 749 Exxon Capital Corporation 6.0% Guaranteed notes due 2005 106 106 6.125% Guaranteed notes due 2008 160 175 SeaRiver Maritime Financial Holdings, Inc. Guaranteed debt securities due 2003-2011 (1) 105 115 Guaranteed deferred interest debentures due 2012 - Face value ($771) net of unamortized discount plus accrued interest 903 811 Imperial Oil Limited Variable rate notes due 2004 (2) 600 600 ExxonMobil Canada Ltd. 3.0% Swiss franc debentures due 2003 (3) 328 331 5.0% U.S. dollar Eurobonds due 2004 (4) 262 274 Mobil Producing Nigeria Unlimited 8.625% notes due 2003-2006 146 188 Mobil Corporation 8.625% debentures due 2021 247 247 7.625% debentures due 2033 204 203 Industrial revenue bonds due 2003-2033 (5) 1,535 1,469 ESOP Trust notes due 2003 65 100 Other U.S. dollar obligations (6) 751 1,062 Other foreign currency obligations 585 598 Capitalized lease obligations (7) 266 252 ------------------- Total long-term debt $7,099 $7,280 =================== (1) Average effective interest rate of 4.1% in 2001 and 6.4% in 2000. (2) Average effective interest rate of 4.2% in 2001 and 6.6% in 2000. (3) Swapped into floating rate U.S. dollar debt. (4) Swapped into floating rate debt. (5) Average effective interest rate of 3.0% in 2001 and 4.5% in 2000. (6) Average effective interest rate of 8.0% in 2001 and 7.8% in 2000. (7) Average imputed interest rate of 6.4% in 2001 and 7.2% in 2000. 44 Condensed consolidating financial information related to guaranteed securities issued by subsidiaries Exxon Mobil Corporation has fully and unconditionally guaranteed the 6.0% notes due 2005 ($106 million of long-term debt at year-end 2001) and the 6.125% notes due 2008 ($160 million) of Exxon Capital Corporation and the deferred interest debentures due 2012 ($903 million) and the debt securities due 2003-2011 ($105 million long-term and $10 million short-term) of SeaRiver Maritime Financial Holdings, Inc. Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc. are 100 percent owned subsidiaries of Exxon Mobil Corporation. The following condensed consolidating financial information is provided for Exxon Mobil Corporation, as guarantor, and for Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc., as issuers, as an alternative to providing separate financial statements for the issuers. The accounts of Exxon Mobil Corporation, Exxon Capital Corporation and SeaRiver Maritime Financial Holdings, Inc. are presented utilizing the equity method of accounting for investments in subsidiaries.
SeaRiver Exxon Mobil Maritime Consolidating Corporation Exxon Financial and Parent Capital Holdings, All Other Eliminating Guarantor Corporation Inc. Subsidiaries Adjustments Consolidated ------------------------------------------------------------------------ (millions of dollars) Condensed consolidated statement of income for twelve months ended December 31, 2001 - ------------------------------------------------------------------------------------ Revenue Sales and other operating revenue, including excise taxes $ 28,800 $ -- $ -- $ 180,617 $ -- $ 209,417 Earnings from equity interests and other revenue 13,535 -- 32 3,709 (13,205) 4,071 Intercompany revenue 6,252 584 62 106,498 (113,396) -- ----------------------------------------------------------------------- Total revenue 48,587 584 94 290,824 (126,601) 213,488 ----------------------------------------------------------------------- Costs and other deductions Crude oil and product purchases 19,483 -- -- 174,484 (101,681) 92,286 Operating expenses 5,702 3 1 17,613 (5,149) 18,170 Selling, general and administrative expenses 2,158 2 -- 10,802 (62) 12,900 Depreciation and depletion 1,584 5 3 6,352 -- 7,944 Exploration expenses, including dry holes 125 -- -- 1,050 -- 1,175 Merger related expenses 89 -- -- 771 (112) 748 Interest expense 1,043 531 114 4,924 (6,319) 293 Excise taxes 1,957 -- -- 19,950 -- 21,907 Other taxes and duties 14 -- -- 33,363 -- 33,377 Income applicable to minority and preferred interests -- -- -- 569 -- 569 ----------------------------------------------------------------------- Total costs and other deductions 32,155 541 118 269,878 (113,323) 189,369 ----------------------------------------------------------------------- Income before income taxes 16,432 43 (24) 20,946 (13,278) 24,119 Income taxes 1,327 15 (20) 7,692 -- 9,014 ----------------------------------------------------------------------- Income before extraordinary item 15,105 28 (4) 13,254 (13,278) 15,105 Extraordinary gain, net of income tax 215 -- -- -- -- 215 ----------------------------------------------------------------------- Net income $ 15,320 $ 28 $ (4) $ 13,254 $ (13,278) $ 15,320 =======================================================================
45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Condensed consolidating financial information related to guaranteed securities issued by subsidaries
SeaRiver Exxon Mobil Maritime Consolidating Corporation Exxon Financial and Parent Capital Holdings, All Other Eliminating Guarantor Corporation Inc. Subsidiaries Adjustments Consolidated ------------------------------------------------------------------------- (millions of dollars) Condensed consolidated statement of income for twelve months ended December 31, 2000 - ------------------------------------------------------------------------------------ Revenue Sales and other operating revenue, including excise taxes $ 36,211 $ -- $ -- $ 192,228 $ -- $ 228,439 Earnings from equity interests and other revenue 14,399 -- 35 3,577 (13,702) 4,309 Intercompany revenue 4,148 997 90 92,832 (98,067) -- ------------------------------------------------------------------------ Total revenue 54,758 997 125 288,637 (111,769) 232,748 ------------------------------------------------------------------------ Costs and other deductions Crude oil and product purchases 22,790 -- -- 173,012 (86,851) 108,951 Operating expenses 5,787 3 1 17,051 (4,707) 18,135 Selling, general and administrative expenses 1,978 -- -- 10,203 (137) 12,044 Depreciation and depletion 1,510 5 3 6,612 -- 8,130 Exploration expenses, including dry holes 115 -- -- 821 -- 936 Merger related expenses 402 -- -- 1,171 (167) 1,406 Interest expense 1,449 916 116 4,313 (6,205) 589 Excise taxes 2,614 -- -- 19,742 -- 22,356 Other taxes and duties 15 -- -- 32,693 -- 32,708 Income applicable to minority and preferred interests -- -- -- 412 -- 412 ------------------------------------------------------------------------ Total costs and other deductions 36,660 924 120 266,030 (98,067) 205,667 ------------------------------------------------------------------------ Income before income taxes 18,098 73 5 22,607 (13,702) 27,081 Income taxes 2,108 20 (10) 8,973 -- 11,091 ------------------------------------------------------------------------ Income before extraordinary item 15,990 53 15 13,634 (13,702) 15,990 Extraordinary gain, net of income tax 1,730 -- -- 962 (962) 1,730 ------------------------------------------------------------------------ Net income $ 17,720 $ 53 $ 15 $ 14,596 $ (14,664) $ 17,720 ======================================================================== Condensed consolidated statement of income for twelve months ended December 31, 1999 - ------------------------------------------------------------------------------------ Revenue Sales and other operating revenue, including excise taxes $ 25,758 $ -- $ -- $ 156,771 $ -- $ 182,529 Earnings from equity interests and other revenue 7,585 37 31 2,102 (6,757) 2,998 Intercompany revenue 1,585 660 61 35,825 (38,131) -- ------------------------------------------------------------------------ Total revenue 34,928 697 92 194,698 (44,888) 185,527 ------------------------------------------------------------------------ Costs and other deductions Crude oil and product purchases 13,926 -- -- 97,296 (34,211) 77,011 Operating expenses 4,669 3 1 13,285 (1,152) 16,806 Selling, general and administrative expenses 2,230 -- -- 10,908 (4) 13,134 Depreciation and depletion 1,396 5 3 6,900 -- 8,304 Exploration expenses, including dry holes 110 -- -- 1,136 -- 1,246 Merger related expenses 479 -- -- 146 -- 625 Interest expense 1,150 561 95 1,653 (2,764) 695 Excise taxes 2,846 -- -- 18,800 -- 21,646 Other taxes and duties 14 -- -- 34,751 -- 34,765 Income applicable to minority and preferred interests -- -- -- 145 -- 145 ------------------------------------------------------------------------ Total costs and other deductions 26,820 569 99 185,020 (38,131) 174,377 ------------------------------------------------------------------------ Income before income taxes 8,108 128 (7) 9,678 (6,757) 11,150 Income taxes 198 28 (13) 3,027 -- 3,240 ------------------------------------------------------------------------ Income before extraordinary item 7,910 100 6 6,651 (6,757) 7,910 Extraordinary gain, net of income tax -- -- -- -- -- -- ------------------------------------------------------------------------ Net income $ 7,910 $ 100 $ 6 $ 6,651 $ (6,757) $ 7,910 ========================================================================
46
Exxon Mobil SeaRiver Consolidating Corporation Exxon Maritime and Parent Capital Financial All Other Eliminating Guarantor Corporation Holdings, Inc. Subsidiaries Adjustments Consolidated -------------------------------------------------------------------------------- (millions of dollars) Condensed consolidated balance sheet for year ended December 31, 2001 - --------------------------------------------------------------------- Cash and cash equivalents $ 1,375 $ -- $ -- $ 5,172 $ -- $ 6,547 Notes and accounts receivable - net 2,458 -- -- 17,091 -- 19,549 Inventories 996 -- -- 6,908 -- 7,904 Prepaid taxes and expenses 155 5 8 1,513 -- 1,681 -------------------------------------------------------------------------------- Total current assets 4,984 5 8 30,684 -- 35,681 Investments and advances 92,091 -- 415 317,456 (399,194) 10,768 Property, plant and equipment - net 16,843 108 6 72,645 -- 89,602 Other long-term assets 753 -- 137 6,233 -- 7,123 Intercompany receivables 8,466 1,365 1,431 266,527 (277,789) -- -------------------------------------------------------------------------------- Total assets $123,137 $ 1,478 $1,997 $693,545 $(676,983) $143,174 ================================================================================ Notes and loans payable $ -- $ 35 $ 10 $ 3,658 $ -- $ 3,703 Accounts payable and accrued liabilities 2,735 6 1 20,120 -- 22,862 Income taxes payable 767 -- -- 2,782 -- 3,549 -------------------------------------------------------------------------------- Total current liabilities 3,502 41 11 26,560 -- 30,114 Long-term debt 1,258 266 1,008 4,567 -- 7,099 Deferred income tax liabilities 2,989 33 302 13,035 -- 16,359 Other long-term liabilities 4,373 -- -- 12,068 -- 16,441 Intercompany payables 37,854 248 382 239,305 (277,789) -- ------------------------------------------------------------------------------- Total liabilities 49,976 588 1,703 295,535 (277,789) 70,013 Earnings reinvested 95,718 84 (100) 48,907 (48,891) 95,718 Other shareholders' equity (22,557) 806 394 349,103 (350,303) (22,557) -------------------------------------------------------------------------------- Total shareholders' equity 73,161 890 294 398,010 (399,194) 73,161 -------------------------------------------------------------------------------- Total liabilities and shareholders' equity $123,137 $ 1,478 $1,997 $693,545 $(676,983) $143,174 ================================================================================ Condensed consolidated balance sheet for year ended December 31, 2000 - --------------------------------------------------------------------- Cash and cash equivalents $ 4,235 $ -- $ -- $ 2,845 $ -- $ 7,080 Notes and accounts receivable - net 4,427 -- -- 18,569 -- 22,996 Inventories 1,102 -- -- 7,202 -- 8,304 Prepaid taxes and expenses 262 -- 14 1,743 -- 2,019 -------------------------------------------------------------------------------- Total current assets 10,026 -- 14 30,359 -- 40,399 Investments and advances 79,589 -- 408 303,090 (370,469) 12,618 Property, plant and equipment - net 18,559 113 9 71,148 -- 89,829 Other long-term assets 508 2 150 5,494 -- 6,154 Intercompany receivables 9,339 19,124 1,355 212,790 (242,608) -- -------------------------------------------------------------------------------- Total assets $118,021 $ 19,239 $1,936 $622,881 $(613,077) $149,000 ================================================================================ Notes and loans payable $ 60 $ 74 $ 7 $ 6,020 $ -- $ 6,161 Accounts payable and accrued liabilities 3,918 8 2 22,827 -- 26,755 Income taxes payable 902 9 -- 4,364 -- 5,275 -------------------------------------------------------------------------------- Total current liabilities 4,880 91 9 33,211 -- 38,191 Long-term debt 1,209 281 925 4,865 -- 7,280 Deferred income tax liabilities 3,334 31 292 12,785 -- 16,442 Other long-term liabilities 4,428 9 -- 11,893 -- 16,330 Intercompany payables 33,413 17,965 412 190,818 (242,608) -- -------------------------------------------------------------------------------- Total liabilities 47,264 18,377 1,638 253,572 (242,608) 78,243 Earnings reinvested 86,652 56 (96) 36,946 (36,906) 86,652 Other shareholders' equity (15,895) 806 394 332,363 (333,563) (15,895) -------------------------------------------------------------------------------- Total shareholders' equity 70,757 862 298 369,309 (370,469) 70,757 -------------------------------------------------------------------------------- Total liabilities and shareholders' equity $118,021 $ 19,239 $1,936 $622,881 $(613,077) $149,000 ================================================================================
47 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Condensed consolidating financial information related to guaranteed securities issued by subsidiaries
Exxon Mobil SeaRiver Consolidating Corporation Exxon Maritime and Parent Capital Financial All Other Eliminating Guarantor Corporation Holdings, Inc. Subsidiaries Adjustments Consolidated ------------------------------------------------------------------------------- (millions of dollars) Condensed consolidated statement of cash flows for twelve months ended December 31, 2001 - ---------------------------------------------------------------------------------------- Cash provided by/(used in) operating activities $ 7,277 $ 12 $ 113 $ 16,239 $ (752) $ 22,889 ------------------------------------------------------------------------------- Cash flows from investing activities Additions to property, plant and equipment (2,058) -- -- (7,931) -- (9,989) Sales of long-term assets 536 -- -- 542 -- 1,078 Net intercompany investing 3,152 17,759 (76) (1,345) (19,490) -- All other investing, net (31) -- -- 731 -- 700 ------------------------------------------------------------------------------- Net cash provided by/(used in) investing activities 1,599 17,759 (76) (8,003) (19,490) (8,211) ------------------------------------------------------------------------------- Cash flows from financing activities Additions to short- and long-term debt -- -- -- 1,252 -- 1,252 Reductions in short- and long-term debt (62) (15) (7) (1,634) -- (1,718) Additions/(reductions) in debt with less than 90 day maturity -- (39) -- (2,267) -- (2,306) Cash dividends (6,254) -- -- (752) 752 (6,254) Common stock acquired (5,721) -- -- -- -- (5,721) Net intercompany financing activity -- (17,717) (30) (1,743) 19,490 -- All other financing, net 301 -- -- (595) -- (294) ------------------------------------------------------------------------------- Net cash provided by/(used in) financing activities (11,736) (17,771) (37) (5,739) 20,242 (15,041) ------------------------------------------------------------------------------- Effects of exchange rate changes on cash -- -- -- (170) -- (170) ------------------------------------------------------------------------------- Increase/(decrease) in cash and cash equivalents $ (2,860) $ -- $ -- $ 2,327 $ -- $ (533) =============================================================================== Condensed consolidated statement of cash flows for twelve months ended December 31, 2000 - ---------------------------------------------------------------------------------------- Cash provided by/(used in) operating activities $ 7,704 $ 61 $ 94 $ 16,063 $ (985) $ 22,937 ------------------------------------------------------------------------------- Cash flows from investing activities Additions to property, plant and equipment (1,832) -- -- (6,614) -- (8,446) Sales of long-term assets 1,088 -- -- 4,682 -- 5,770 Net intercompany investing 6,386 (7,143) (114) (6,285) 7,156 -- All other investing, net (26) -- -- (596) -- (622) ------------------------------------------------------------------------------- Net cash provided by/(used in) investing activities 5,616 (7,143) (114) (8,813) 7,156 (3,298) ------------------------------------------------------------------------------- Cash flows from financing activities Additions to short- and long-term debt 23 -- -- 715 -- 738 Reductions in short- and long-term debt (247) (214) (7) (2,846) -- (3,314) Additions/(reductions) in debt with less than 90 day maturity (990) 16 -- (2,155) -- (3,129) Cash dividends (6,123) -- -- (985) 985 (6,123) Common stock acquired (2,352) -- -- -- -- (2,352) Net intercompany financing activity -- 7,280 27 (151) (7,156) -- All other financing, net 493 -- -- (478) -- 15 ------------------------------------------------------------------------------- Net cash provided by/(used in) financing activities (9,196) 7,082 20 (5,900) (6,171) (14,165) ------------------------------------------------------------------------------- Effects of exchange rate changes on cash -- -- -- (82) -- (82) ------------------------------------------------------------------------------- Increase/(decrease) in cash and cash equivalents $ 4,124 $ -- $ -- $ 1,268 $ -- $ 5,392 ===============================================================================
48
Exxon Mobil SeaRiver Consolidating Corporation Exxon Maritime and Parent Capital Financial All Other Eliminating Guarantor Corporation Holdings, Inc. Subsidiaries Adjustments Consolidated --------------------------------------------------------------------------------- (millions of dollars) Condensed consolidated statement of cash flows for twelve months ended December 31, 1999 - ---------------------------------------------------------------------------------------- Cash provided by/(used in) operating activities $ 5,056 $ 78 $ 104 $ 12,916 $ (3,141) $ 15,013 --------------------------------------------------------------------------------- Cash flows from investing activities Additions to property, plant and equipment (1,968) -- -- (8,881) -- (10,849) Sales of long-term assets 294 -- -- 678 -- 972 Net intercompany investing 2,982 (751) (95) (6,468) 4,332 -- All other investing, net (31) -- -- (1,077) -- (1,108) --------------------------------------------------------------------------------- Net cash provided by/(used in) investing activities 1,277 (751) (95) (15,748) 4,332 (10,985) --------------------------------------------------------------------------------- Cash flows from financing activities Additions to short- and long-term debt 2 -- -- 2,322 -- 2,324 Reductions in short- and long-term debt (2) -- (7) (2,691) -- (2,700) Additions/(reductions) in debt with less than 90 day maturity (117) 10 -- 2,317 -- 2,210 Cash dividends (5,872) (2,000) -- (1,141) 3,141 (5,872) Common stock acquired (670) -- -- -- -- (670) Net intercompany financing activity -- 2,663 (2) 1,671 (4,332) -- All other financing, net 348 -- -- (419) -- (71) --------------------------------------------------------------------------------- Net cash provided by/(used in) financing activities (6,311) 673 (9) 2,059 (1,191) (4,779) --------------------------------------------------------------------------------- Effects of exchange rate changes on cash -- -- -- 53 -- 53 --------------------------------------------------------------------------------- Increase/(decrease) in cash and cash equivalents $ 22 $ -- $ -- $ (720) $ -- $ (698) =================================================================================
49 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. Incentive Program The 1993 Incentive Program provides for grants of stock options, stock appreciation rights (SARs), restricted stock and other forms of award. Awards may be granted over a 10-year period to eligible employees of the corporation and those affiliates at least 50 percent owned. The number of shares of stock which may be awarded each year under the 1993 Incentive Program may not exceed seven tenths of one percent (0.7%) of the total number of shares of common stock of the corporation outstanding (excluding shares held by the corporation) on December 31 of the preceding year. If the total number of shares effectively granted in any year is less than the maximum number of shares allowable, the balance may be carried over thereafter. Outstanding awards are subject to certain forfeiture provisions contained in the program or award instrument. Options and SARs may be granted at prices not less than 100 percent of market value on the date of grant and have a maximum life of 10 years. Most of the options and SARs normally first become exercisable one year following the date of grant. On the closing of the merger on November 30, 1999, outstanding options and SARs granted by Mobil under its 1995 Incentive Compensation and Stock Ownership Plan and prior plans were assumed by ExxonMobil and converted into rights to acquire ExxonMobil common stock with adjustments to reflect the exchange ratio. No further awards may be granted under the former Mobil plans. Shares available for granting under the 1993 Incentive Program were 133,115 thousand at the beginning of 2001 and 98,668 thousand at the end of 2001. At December 31, 2000 and 2001, respectively, 2,438 thousand and 2,559 thousand shares of restricted common stock were outstanding. Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation," was implemented in January 1996. As permitted by the Standard, ExxonMobil retained its prior method of accounting for stock compensation. If the provisions of Statement No. 123 had been adopted, net income and earnings per share (on both a basic and diluted basis) would have been reduced by $285 million, or $0.04 per share in 2001; $296 million, or $0.04 per share in 2000 and $149 million, or $0.02 per share in 1999. For the ExxonMobil plan, the average fair value of each option granted during 2001, 2000 and 1999 was $6.89, $10.18 and $9.85, respectively. The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions for 2001, 2000 and 1999, respectively: risk-free interest rates of 4.6 percent, 5.5 percent and 6.2 percent; expected life of 6 years for all years; volatility of 16 percent, 16 percent and 15 percent and a dividend yield of 2.5 percent, 2.0 percent and 2.1 percent. For the Mobil plans, the average fair value of each Mobil option granted during 1999 was $8.51. The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions for 1999: risk-free interest rate of 5.2 percent; expected life of 5 years; volatility of 20 percent and a dividend yield of 2.7 percent. Changes that occurred in options outstanding in 2001, 2000 and 1999, including the former Mobil plans, are summarized below (shares in thousands):
2001 2000 1999 ----------------------------------------------------------------------------- Avg. Exercise Avg. Exercise Avg. Exercise Shares Price Shares Price Shares Price ----------------------------------------------------------------------------- Outstanding at beginning of year 248,680 $28.70 242,232 $24.81 221,218 $21.02 Granted 34,717 37.12 36,224 45.19 44,198 39.00 Exercised (16,949) 16.63 (28,714) 16.35 (22,500) 15.16 Expired/Canceled (753) 39.44 (1,062) 37.13 (684) 33.09 ------- ------- ------- Outstanding at end of year 265,695 30.54 248,680 28.70 242,232 24.81 Exercisable at end of year 221,405 29.29 195,144 25.95 174,944 21.08
The following table summarizes information about stock options outstanding, including those from former Mobil plans, at December 31, 2001 (shares in thousands):
Options Outstanding Options Exercisable - --------------------------------------------------------------- ------------------------ Exercise Price Avg. Remaining Avg. Exercise Avg. Exercise Range Shares Contractual Life Price Shares Price - --------------------------------------------------------------- ------------------------ $11.64-16.54 48,548 2.5 years $15.08 48,548 $15.08 19.06-27.71 63,525 5.1 years 22.92 63,525 22.92 29.18-45.22 153,622 8.2 years 38.58 109,332 39.30 ------- ------- Total 265,695 6.4 years 30.54 221,405 29.29
50 17. Litigation and Other Contingencies 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. The vast majority of the claims have been resolved leaving a few compensatory damages cases to be tried. All of the punitive damage claims were consolidated in the civil trial that began in May 1994. In that trial, on September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5.058 billion. The District Court awarded approximately $19.6 million in compensatory damages to fisher plaintiffs, $38 million in prejudgment interest on the compensatory damages and $5 billion in punitive damages to a class composed of all persons and entities who asserted claims for punitive damages from the corporation as a result of the Exxon Valdez grounding. The District Court also ordered that these awards shall bear interest from and after entry of the judgment. The District Court stayed execution on the judgment pending appeal based on a $6.75 billion letter of credit posted by the corporation. ExxonMobil appealed the judgment. On November 7, 2001, the United States Court of Appeals for the Ninth Circuit vacated the punitive damage award as being excessive under the Constitution and remanded the case to the District Court for it to determine the amount of the punitive damage award consistent with the Ninth Circuit's holding. The Ninth Circuit upheld the compensatory damage award which has been paid. The letter of credit was terminated on February 1, 2002. On January 29, 1997, a settlement agreement was concluded resolving all remaining matters between the corporation and various insurers arising from the Valdez accident. Under terms of this settlement, ExxonMobil received $480 million. Final income statement recognition of this settlement continues to be deferred in view of uncertainty regarding the ultimate cost to the corporation of the Valdez accident. The ultimate cost to ExxonMobil from the lawsuits arising from the Exxon Valdez grounding is not possible to predict and may not be resolved for a number of years. Under the October 8, 1991, civil agreement and consent decrees with the U.S. and Alaska governments, the corporation made the final payment of $70 million in the third quarter of 2001. This payment, along with prior payments, was charged against the provision that was previously established to cover the costs of the settlement. A dispute with a Dutch affiliate concerning an overlift of natural gas by a German affiliate was resolved by payments by the German affiliate pursuant to an arbitration award. The German affiliate had paid royalties on the excess gas and recovered the royalties in 2001. The only substantive issue remaining is the taxes payable on the final compensation for the overlift. Resolution of this issue will not have a materially adverse effect upon the corporation's operations or financial condition. On December 19, 2000, a jury in Montgomery County, Alabama, returned a verdict against the corporation in a contract dispute over royalties in the amount of $87.69 million in compensatory damages and $3.42 billion in punitive damages in the case of Exxon Corporation v. State of Alabama, et al. The verdict was upheld by the trial court on May 4, 2001. ExxonMobil has appealed the judgment and believes that it should be set aside or substantially reduced on factual and constitutional grounds. The ultimate outcome is not expected to have a materially adverse effect upon the corporation's operations or financial condition. On May 22, 2001, a state court jury in New Orleans, Louisiana, returned a verdict against the corporation and three other entities in a case brought by a landowner claiming damage to his property. The property had been leased by the landowner to a company that performed pipe cleaning and storage services for customers, including the corporation. The jury awarded the plaintiff $56 million in compensatory damages (90 percent to be paid by the corporation) and $1 billion in punitive damages (all to be paid by the corporation). The damage related to the presence of naturally occurring radioactive material (NORM) on the site resulting from pipe cleaning operations. The award has been upheld at the trial court. ExxonMobil will appeal the judgment to the Louisiana Fourth Circuit Court of Appeals and believes that the judgment should be set aside or substantially reduced on factual and constitutional grounds. The ultimate outcome is not expected to have a materially adverse effect upon the corporation's operations or financial condition. The U.S. Tax Court has decided the issue with respect to the pricing of crude oil purchased from Saudi Arabia for the years 1979-1981 in favor of the corporation. This decision is subject to appeal. Certain other issues for the years 1979-1993 remain pending before the Tax Court. The ultimate resolution of these issues is not expected to have a materially adverse effect upon the corporation's operations or financial condition. Claims for substantial amounts have been made against ExxonMobil and certain of its consolidated subsidiaries in other pending lawsuits, the outcome of which is not expected to have a materially adverse effect upon the corporation's operations or financial condition. The corporation and certain of its consolidated subsidiaries were contingently liable at December 31, 2001, for $3,921 million, primarily relating to guarantees for notes, loans and performance under contracts. This included $672 million representing guarantees of non-U.S. excise taxes and customs duties of other companies, entered into as a normal business practice, under reciprocal arrangements. Also included in this amount were guarantees by consolidated affiliates of $1,641 million, representing ExxonMobil's share of obligations of certain equity companies. Additionally, the corporation and its affiliates have numerous long-term sales and purchase commitments in their various business activities, all of which are expected to be fulfilled with no adverse consequences material to the corporation's operations or financial condition. The present value of unconditional purchase obligations was $1,296 million at December 31, 2001. On an undiscounted basis, including imputed interest of $733 million, these commitments totaled $2,029 million. 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. 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 developments and laws and regulations, such as forced divestiture of assets; restrictions on production, imports and exports; price controls; tax increases and retroactive tax claims; expropriation of property; cancellation of contract rights and environmental regulations. Both the likelihood of such occurrences and their overall effect upon the corporation vary greatly from country to country and are not predictable. 51 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 18. Annuity Benefits and Other Postretirement Benefits
Annuity Benefits --------------------------------------------------- Other Postretirement U.S. Non-U.S. Benefits ----------------------- ------------------------ ------------------------ 2001 2000 1999 2001 2000 1999 2001 2000 1999 ------------------------------------------------------------------------------ Components of net benefit cost (millions of dollars) Service cost $ 200 $ 214 $ 249 $ 232 $ 245 $ 312 $ 27 $ 24 $ 36 Interest cost 579 592 555 598 603 608 205 201 190 Expected return on plan assets (623) (726) (601) (629) (641) (599) (43) (51) (48) Amortization of actuarial loss/(gain) and prior service cost (25) (168) (36) 78 55 167 4 -- 14 Net pension enhancement and curtailment/settlement expense 14 (175) 1 27 77 50 -- (5) -- ----------------------------------------------------------------------------- Net benefit cost $ 145 $(263) $ 168 $ 306 $ 339 $ 538 $ 193 $ 169 $ 192 =============================================================================
Costs for defined contribution plans were $132 million, $67 million and $69 million in 2001, 2000 and 1999, respectively.
Annuity Benefits -------------------------------------------- Other Postretirement U.S. Non-U.S. Benefits -------------------- -------------------- -------------------- 2001 2000 2001 2000 2001 2000 -------------------------------------------------------------------- Change in benefit obligation (millions of dollars) Benefit obligation at January 1 $ 7,651 $ 8,032 $ 11,063 $ 11,628 $ 2,942 $ 2,620 Service cost 200 214 232 245 27 24 Interest cost 579 592 598 603 205 201 Actuarial loss/(gain) 638 179 540 429 7 144 Benefits paid (868) (1,534) (710) (815) (258) (233) Foreign exchange rate changes -- -- (678) (811) (12) (8) Other 13 168 161 (216) 220 194 -------------------------------------------------------------------- Benefit obligation at December 31 $ 8,213 $ 7,651 $ 11,206 $ 11,063 $ 3,131 $ 2,942 ==================================================================== Change in plan assets Fair value at January 1 $ 6,795 $ 7,965 $ 7,780 $ 8,689 $ 446 $ 568 Actual return on plan assets (647) 208 (424) (12) (34) (30) Foreign exchange rate changes -- -- (422) (612) -- -- Payments directly to participants 135 156 225 311 187 166 Company contribution -- -- 299 232 32 38 Benefits paid (868) (1,534) (710) (815) (258) (233) Other -- -- 7 (13) 22 (63) --------------------------------------------------------------------- Fair value at December 31 $ 5,415 $ 6,795 $ 6,755 $ 7,780 $ 395 $ 446 ===================================================================== Assets in excess of/(less than) benefit obligation Balance at December 31 $ (2,798) $ (856) $ (4,451) $ (3,283) $ (2,736) $ (2,496) Unrecognized net transition liability/(asset) (2) (31) 34 49 -- -- Unrecognized net actuarial loss/(gain) 1,142 (788) 2,002 507 108 35 Unrecognized prior service cost 248 281 308 297 381 180 Intangible asset (226) (12) (135) (82) -- -- Equity of minority shareholders -- -- (82) (36) -- -- Minimum pension liability adjustment (144) (163) (805) (422) -- -- --------------------------------------------------------------------- Prepaid/(accrued) benefit cost $ (1,780) $ (1,569) $ (3,129) $ (2,970) $ (2,247) $ (2,281) ===================================================================== Assumptions as of December 31 (percent) Discount rate 7.25 7.5 2.6-6.8 3.0-7.0 7.25 7.5 Long-term rate of compensation increase 3.50 3.5 2.8-4.3 3.0-5.0 3.50 3.5 Long-term rate of return on funded assets 9.50 9.5 6.5-10.0 6.5-10.0 9.50 9.5
52 Annuity Benefits ------------------------------- U.S. Non-U.S. ------------------------------- 2001 2000 2001 2000 ------------------------------- (millions of dollars) For funded pension plans with accumulated ------ benefit obligations in excess of plan assets: Projected benefit obligation $7,140 $ -- $4,142 $2,234 Accumulated benefit obligation 6,226 -- 3,828 2,089 Fair value of plan assets 5,247 -- 2,855 1,333 For unfunded plans covered by book reserves: -------- Projected benefit obligation $ 963 $ 885 $3,197 $2,918 Accumulated benefit obligation 859 799 2,854 2,587 The preceding data conform with current accounting standards that specify use of a discount rate at which postretirement liabilities could be effectively settled. The discount rate for calculating year-end postretirement liabilities is based on the year-end rate of interest on high quality bonds. The return on the annuity fund's actual portfolio of assets has historically been higher than bonds as the majority of pension assets are invested in equities. The actual rate earned in the U.S. over the past decade has been 12 percent. All funded U.S. plans are fully funded in 2001 under the standards set by the Department of Labor and the Internal Revenue Service. The corporation will continue to make contributions as necessary to maintain the fully funded status of these plans according to those standards. Certain smaller U.S. plans and a number of non-U.S. plans are not funded because local tax conventions and regulatory practices do not encourage funding of these plans. Book reserves have been established for these plans to provide for future benefit payments. 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. 53 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 19. Income, Excise and Other Taxes
2001 2000 1999 - --------------------------------------------------------------------------------------------------------------------------------- United Non- United Non- United Non- States U.S. Total States U.S. Total States U.S. Total - --------------------------------------------------------------------------------------------------------------------------------- (millions of dollars) Income taxes Federal or non-U.S. Current $ 1,729 $ 6,084 $ 7,813 $ 2,635 $ 7,972 $10,607 $ 369 $ 3,973 $ 4,342 Deferred - net 712 169 881 433 (322) 111 214 (1,489) (1,275) U.S. tax on non-U.S. operations 91 -- 91 64 -- 64 25 -- 25 -------------------------------------------------------------------------------------------- $ 2,532 $ 6,253 $ 8,785 $ 3,132 $ 7,650 $10,782 $ 608 $ 2,484 $ 3,092 State 229 -- 229 309 -- 309 148 -- 148 -------------------------------------------------------------------------------------------- Total income taxes $ 2,761 $ 6,253 $ 9,014 $ 3,441 $ 7,650 $11,091 $ 756 $ 2,484 $ 3,240 Excise taxes 7,030 14,877 21,907 6,997 15,359 22,356 7,795 13,851 21,646 All other taxes and duties 1,177 34,485 35,662 1,253 33,685 34,938 1,021 35,616 36,637 -------------------------------------------------------------------------------------------- Total $ 10,968 $ 55,615 $ 66,583 $ 11,691 $56,694 $68,385 $ 9,572 $ 51,951 $ 61,523 ============================================================================================
All other taxes and duties include taxes reported in operating and selling, general and administrative expenses. The above provisions for deferred income taxes include net credits for the effect of changes in tax laws and rates of $31 million in 2001, $84 million in 2000 and $205 million in 1999. Income taxes (charged)/credited directly to shareholders' equity were:
2001 2000 1999 - -------------------------------------------------------------------------------- (millions of dollars) Cumulative foreign exchange translation adjustment $ 102 $ 221 $ (84) Minimum pension liability adjustment 139 27 (127) Unrealized gains and losses on stock investments 40 57 (45) Other components of shareholders' equity 83 111 50
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2001, 2000 and 1999, is as follows:
2001 2000 1999 - -------------------------------------------------------------------------------- (millions of dollars) Earnings before Federal and non-U.S. income taxes United States $ 8,310 $ 9,016 $ 3,187 Non-U.S. 15,580 17,756 7,815 -------------------------------- Total $ 23,890 $ 26,772 $ 11,002 -------------------------------- Theoretical tax $ 8,362 $ 9,370 $ 3,851 Effect of equity method accounting (761) (852) (576) Non-U.S. taxes in excess of theoretical U.S. tax 1,354 1,986 201 U.S. tax on non-U.S. operations 91 64 25 Other U.S. (261) 214 (409) -------------------------------- Federal and non-U.S. income tax expense $ 8,785 $ 10,782 $ 3,092 ================================ Total effective tax rate 39.3% 42.4% 31.8%
The effective income tax rate includes state income taxes and the corporation's share of income taxes of equity companies. Equity company taxes totaled $748 million in 2001, $658 million in 2000 and $449 million in 1999, primarily all outside the U.S. 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: 2001 2000 - ----------------------------------------------------------------------------- (millions of dollars) Depreciation $12,738 $13,358 Intangible development costs 3,445 3,282 Capitalized interest 1,989 1,891 Other liabilities 3,165 2,935 --------------------- Total deferred tax liabilities $21,337 $21,466 --------------------- Pension and other postretirement benefits $(1,911) $(1,923) Tax loss carryforwards (2,057) (1,763) Other assets (2,803) (3,465) --------------------- Total deferred tax assets $(6,771) $(7,151) --------------------- Asset valuation allowances 209 380 --------------------- Net deferred tax liabilities $14,775 $14,695 =====================
The corporation had $17 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. 54 20. Disclosures about Segments and Related Information The functional segmentation of operations reflected below is consistent with ExxonMobil's internal reporting. Earnings include special items and transfers are at estimated market prices. The interest revenue amount relates to interest earned on cash deposits and marketable securities. Interest expense includes non-debt related interest expense of $105 million, $142 million and $123 million in 2001, 2000 and 1999, respectively. All Other includes smaller operating segments, corporate and financing activities, merger expenses, and extraordinary gains from required asset divestitures of $40 million and $1,730 million in 2001 and 2000, respectively. U.S. chemicals and non-U.S. chemicals after-tax earnings in 2001 include net gains on asset management activities totaling $100 million and $75 million, respectively.
Upstream Downstream Chemicals ------------------- ------------------- --------------------- All Corporate U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. Other Total -------------------------------------------------------------------------------------- (millions of dollars) As of December 31, 2001 Earnings after income tax $ 3,932 $ 6,497 $ 1,924 $ 2,303 $ 398 $ 484 $ (218) $ 15,320 Earnings of equity companies included above 482 1,477 89 12 19 118 (23) 2,174 Sales and other operating revenue 5,606 12,889 50,988 123,197 6,918 9,025 794 209,417 Intersegment revenue 5,408 12,322 4,115 16,880 2,186 2,284 178 -- Depreciation and depletion expense 1,436 3,221 598 1,476 408 289 516 7,944 Interest revenue -- -- -- -- -- -- 380 380 Interest expense -- -- -- -- -- -- 293 293 Income taxes 2,093 5,547 1,075 744 82 149 (676) 9,014 Additions to property, plant and equipment 1,980 4,518 827 1,239 390 243 792 9,989 Investments in equity companies 1,371 2,043 329 831 333 1,291 18 6,216 Total assets 18,809 40,018 12,850 37,617 7,495 9,524 16,861 143,174 ====================================================================================== As of December 31, 2000 Earnings after income tax $ 4,545 $ 7,824 $ 1,561 $ 1,857 $ 644 $ 517 $ 772 $ 17,720 Earnings of equity companies included above 753 1,400 71 74 35 139 (38) 2,434 Sales and other operating revenue 5,669 15,774 56,080 132,483 8,198 9,303 932 228,439 Intersegment revenue 6,557 15,654 8,631 11,684 2,905 2,398 181 -- Depreciation and depletion expense 1,417 3,469 594 1,489 397 281 483 8,130 Interest revenue -- -- -- -- -- -- 258 258 Interest expense -- -- -- -- -- -- 589 589 Income taxes 2,489 7,137 889 850 344 210 (828) 11,091 Additions to property, plant and equipment 1,513 3,501 966 926 288 458 794 8,446 Investments in equity companies 1,261 1,971 264 1,456 492 1,395 25 6,864 Total assets 18,825 39,626 13,516 42,422 8,047 10,234 16,330 149,000 ====================================================================================== As of December 31, 1999 Earnings after income tax $ 1,842 $ 4,044 $ 577 $ 650 $ 738 $ 616 $ (557) $ 7,910 Earnings of equity companies included above 299 881 8 148 49 83 178 1,646 Sales and other operating revenue 3,104 11,353 43,376 109,969 6,554 7,223 950 182,529 Intersegment revenue 3,925 9,093 2,867 5,387 1,624 1,317 796 -- Depreciation and depletion expense 1,330 3,497 697 1,670 402 274 434 8,304 Interest revenue -- -- -- -- -- -- 153 153 Interest expense -- -- -- -- -- -- 695 695 Income taxes 1,008 2,703 343 (22) 338 63 (1,193) 3,240 Additions to property, plant and equipment 1,440 5,025 830 1,201 600 1,093 660 10,849 Investments in equity companies 1,171 2,647 280 3,304 429 1,537 38 9,406 Total assets 18,211 40,906 13,699 43,718 7,605 9,831 10,551 144,521 ======================================================================================
Geographic Sales and other operating revenue 2001 2000 1999 - ---------------------------------------------------------------------------------------------------------------- (millions of dollars) United States $ 63,603 $ 70,036 $ 53,214 Non-U.S. 145,814 158,403 129,315 ------------------------------------------- Total $ 209,417 $ 228,439 $ 182,529 Significant non-U.S. revenue sources include: Japan $ 21,788 $ 24,520 $ 19,727 United Kingdom 18,628 19,904 16,305 Canada 14,912 16,059 11,576
Long-lived assets 2001 2000 1999 - ---------------------------------------------------------------------------------------------------------------- (millions of dollars) United States $ 33,637 $ 33,087 $ 33,913 Non-U.S. 55,965 56,742 60,130 ------------------------------------------- Total $ 89,602 $ 89,829 $ 94,043 Significant non-U.S. long-lived assets include: United Kingdom $ 8,390 $ 9,024 $ 10,293 Canada 7,862 7,922 8,404 Norway 4,627 4,383 4,802
55 QUARTERLY INFORMATION
2001 2000 ---------------------------------------------------------------------------------------------------- First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Year Quarter Quarter Quarter Quarter Year - ---------------------------------------------------------------------------------------------------------------------------------- Volumes Production of crude oil (thousands of barrels daily) and natural gas liquids 2,620 2,539 2,484 2,527 2,542 2,602 2,514 2,497 2,600 2,553 Refinery throughput 5,687 5,406 5,605 5,587 5,571 5,528 5,572 5,736 5,732 5,642 Petroleum product sales 7,985 7,933 7,951 8,016 7,971 7,796 8,035 8,069 8,068 7,993 Natural gas production (millions of cubic feet daily) available for sale 12,119 9,090 8,561 11,373 10,279 12,146 9,247 8,735 11,252 10,343 (thousands of metric tons) Chemical prime product sales 6,533 6,418 6,457 6,372 25,780 6,519 6,596 6,038 6,484 25,637 Summarized financial data Sales and other operating (millions of dollars) revenue $56,076 55,101 51,132 47,108 209,417 $53,273 54,936 57,497 62,733 228,439 Gross profit* $24,233 22,873 21,855 22,056 91,017 $21,896 22,201 23,620 25,506 93,223 Net income before extraordinary item $ 4,960 4,285 3,180 2,680 15,105 $ 3,025 4,000 4,060 4,905 15,990 Extraordinary gain net of income tax $ 40 175 -- -- 215 $ 455 530 430 315 1,730 Net income $ 5,000 4,460 3,180 2,680 15,320 $ 3,480 4,530 4,490 5,220 17,720 Per share data Net income per common share (dollars per share) before extraordinary item $ 0.71 0.64 0.46 0.39 2.20 $ 0.44 0.58 0.57 0.71 2.30 Extraordinary gain net of income tax $ 0.01 0.02 -- -- 0.03 $ 0.06 0.08 0.06 0.05 0.25 Net income per common share $ 0.72 0.66 0.46 0.39 2.23 $ 0.50 0.66 0.63 0.76 2.55 Net income per common share - assuming dilution $ 0.71 0.65 0.46 0.39 2.21 $ 0.49 0.65 0.63 0.75 2.52 Dividends per common share $ 0.22 0.23 0.23 0.23 0.91 $ 0.22 0.22 0.22 0.22 0.88 Common stock prices High $44.875 45.835 44.400 42.700 45.835 $43.156 42.375 45.375 47.719 47.719 Low $37.600 38.500 35.010 36.410 35.010 $34.938 37.500 37.563 42.031 34.938
* Gross profit equals sales and other operating revenue less estimated costs associated with products sold. Note: Prior period per share amounts restated for the two-for-one stock split effective June 20, 2001. 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 698,770 registered shareholders of ExxonMobil common stock at December 31, 2001. At January 31, 2002, the registered shareholders of ExxonMobil common stock numbered 697,972. On January 30, 2002, the corporation declared a $0.23 dividend per common share, payable March 11, 2002. 56 SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Consolidated Subsidiaries ----------------------------------------------------------------- Non- United Consolidated Total Results of Operations States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide - ------------------------------------------------------------------------------------------------------------------------------------ (millions of dollars) 2001 - Revenue Sales to third parties $ 4,045 $ 1,784 $ 5,017 $1,269 $ 17 $ 342 $ 12,474 $ 3,326 $ 15,800 Transfers 4,547 1,203 3,927 1,917 2,894 250 14,738 1,306 16,044 ------------------------------------------------------------------------------------------ $ 8,592 $ 2,987 $ 8,944 $3,186 $2,911 $ ,592 $ 27,212 $ 4,632 $ 31,844 Production costs excluding taxes 1,389 633 1,425 549 414 210 4,620 580 5,200 Exploration expenses 215 109 117 103 217 412 1,173 18 1,191 Depreciation and depletion 1,392 570 1,644 557 318 148 4,629 354 4,983 Taxes other than income 545 54 484 410 375 5 1,873 1,160 3,033 Related income tax 1,957 543 2,567 622 1,023 (98) 6,614 1,037 7,651 ------------------------------------------------------------------------------------------ Results of producing activities $ 3,094 $ 1,078 $ 2,707 $ 945 $ 564 $ (85) $ 8,303 $ 1,483 $ 9,786 Other earnings* 354 (37) 132 (36) 33 (58) 388 255 643 ------------------------------------------------------------------------------------------ Total earnings $ 3,448 $ 1,041 $ 2,839 $ 909 $ 597 $ (143) $ 8,691 $ 1,738 $ 10,429 ========================================================================================== 2000 - Revenue Sales to third parties $ 4,060 $ 2,423 $ 4,387 $2,167 $ 20 $ 366 $ 13,423 $ 3,055 $ 16,478 Transfers 5,420 771 5,491 2,130 3,212 324 17,348 1,532 18,880 ------------------------------------------------------------------------------------------ $ 9,480 $ 3,194 $ 9,878 $4,297 $3,232 $ 690 $ 30,771 $ 4,587 $ 35,358 Production costs excluding taxes 1,231 595 1,627 543 400 181 4,577 621 5,198 Exploration expenses 145 81 135 164 196 211 932 22 954 Depreciation and depletion 1,373 586 1,906 556 340 141 4,902 399 5,301 Taxes other than income 637 33 358 506 446 4 1,984 997 2,981 Related income tax 2,419 736 3,274 1,005 1,093 97 8,624 975 9,599 ------------------------------------------------------------------------------------------ Results of producing activities $ 3,675 $ 1,163 $ 2,578 $1,523 $ 757 $ 56 $ 9,752 $ 1,573 $ 11,325 Other earnings* 117 (36) 521 144 31 (31) 746 298 1,044 ------------------------------------------------------------------------------------------ Total earnings $ 3,792 $ 1,127 $ 3,099 $1,667 $ 788 $ 25 $ 10,498 $ 1,871 $ 12,369 ========================================================================================== 1999 - Revenue Sales to third parties $ 2,419 $ 925 $ 3,287 $2,160 $ 13 $ 178 $ 8,982 $ 2,123 $ 11,105 Transfers 3,237 848 2,965 1,250 1,986 204 10,490 867 11,357 ------------------------------------------------------------------------------------------ $ 5,656 $ 1,773 $ 6,252 $3,410 $1,999 $ 382 $ 19,472 $ 2,990 $ 22,462 Production costs excluding taxes 1,347 504 1,499 566 394 157 4,467 617 5,084 Exploration expenses 232 93 280 144 236 261 1,246 29 1,275 Depreciation and depletion 1,260 486 1,932 678 318 173 4,847 443 5,290 Taxes other than income 425 31 246 288 309 2 1,301 591 1,892 Related income tax 893 252 929 521 534 (5) 3,124 546 3,670 ------------------------------------------------------------------------------------------ Results of producing activities $ 1,499 $ 407 $ 1,366 $1,213 $ 208 $ (206) $ 4,487 $ 764 $ 5,251 Other earnings* 42 32 391 6 17 (36) 452 183 635 ------------------------------------------------------------------------------------------ Total earnings $ 1,541 $ 439 $ 1,757 $1,219 $ 225 $ (242) $ 4,939 $ 947 $ 5,886 ========================================================================================== Average sales prices and production costs per unit of production - ------------------------------------------------------------------------------------------------------------------------------------ During 2001 Average sales prices Crude oil and NGL, per barrel $ 19.92 $ 15.95 $ 22.79 $24.36 $23.34 $20.21 $ 21.30 $ 19.64 $ 21.10 Natural gas, per thousand cubic feet 4.36 3.71 3.28 1.80 -- 1.44 3.37 3.48 3.39 Average production costs, per barrel** 3.68 3.88 3.40 2.98 3.32 5.85 3.54 2.53 3.39 During 2000 Average sales prices Crude oil and NGL, per barrel $ 23.94 $ 21.60 $ 26.96 $28.74 $28.17 $24.57 $ 25.77 $ 24.17 $ 25.59 Natural gas, per thousand cubic feet 3.85 3.58 2.69 2.59 -- 1.29 3.12 3.11 3.12 Average production costs, per barrel** 3.08 4.04 3.72 2.72 3.39 5.50 3.43 2.90 3.35 During 1999 Average sales prices Crude oil and NGL, per barrel $ 14.96 $ 14.47 $ 16.59 $17.96 $16.81 $18.57 $ 16.16 $ 14.52 $ 15.97 Natural gas, per thousand cubic feet 2.21 1.61 2.25 1.88 -- 1.21 2.08 2.47 2.15 Average production costs, per barrel** 3.42 3.69 3.64 2.40 3.31 6.20 3.38 3.02 3.33
* Includes earnings from transportation operations, tar sands operations, LNG operations, technical services agreements, other non-operating activities and adjustments for minority interests. ** Production costs exclude depreciation and depletion and all taxes. Natural gas included by conversion to crude oil equivalent. 57 SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES Oil and Gas Exploration and Production Costs The amounts shown for net capitalized costs of consolidated subsidiaries are $5,212 million less at year-end 2001 and $4,852 million less at year-end 2000 than the amounts reported as investments in property, plant and equipment for the upstream in note 10. This is due to the exclusion from capitalized costs of certain transportation and research assets and assets relating to the tar sands and LNG operations, and to the inclusion of accumulated provisions for site restoration costs, all as required in Statement of Financial Accounting Standards No. 19. The amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year. Total worldwide costs incurred in 2001 were $7,803 million, up $1,740 million from 2000, due primarily to higher development costs. 2000 costs were $6,063 million, down $1,696 million from 1999, due primarily to lower development costs.
Consolidated Subsidiaries ------------------------------------------------------------------ Non- United Consolidated Total Capitalized costs States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide - ----------------------------------------------------------------------------------------------------------------------------------- As of December 31, 2001 Property (acreage) costs - Proved $ 4,543 $ 2,656 $ 178 $ 689 $ 107 $ 957 $ 9,130 $ 11 $ 9,141 - Unproved 674 196 49 850 630 530 2,929 2 2,931 ----------------------------------------------------------------------------------------- Total property costs $ 5,217 $ 2,852 $ 227 $ 1,539 $ 737 $ 1,487 $ 12,059 $ 13 $ 12,072 Producing assets 33,379 6,662 27,628 11,764 4,300 1,992 85,725 5,710 91,435 Support facilities 488 83 449 925 208 159 2,312 257 2,569 Incomplete construction 1,050 334 1,306 684 1,433 346 5,153 495 5,648 ----------------------------------------------------------------------------------------- Total capitalized costs $ 40,134 $ 9,931 $ 29,610 $14,912 $ 6,678 $ 3,984 $105,249 $ 6,475 $111,724 Accumulated depreciation and depletion 25,754 4,888 19,398 9,705 2,323 1,796 63,864 3,127 66,991 ----------------------------------------------------------------------------------------- Net capitalized costs $ 14,380 $ 5,043 $ 10,212 $ 5,207 $ 4,355 $ 2,188 $ 41,385 $ 3,348 $ 44,733 ========================================================================================= As of December 31, 2000 Property (acreage) costs - Proved $ 4,686 $ 2,784 $ 161 $ 729 $ 54 $ 1,187 $ 9,601 $ 11 $ 9,612 - Unproved 700 236 50 1,044 641 314 2,985 3 2,988 ----------------------------------------------------------------------------------------- Total property costs $ 5,386 $ 3,020 $ 211 $ 1,773 $ 695 $ 1,501 $ 12,586 $ 14 $ 12,600 Producing assets 31,843 5,958 27,794 11,359 3,920 1,592 82,466 5,528 87,994 Support facilities 860 105 447 950 41 119 2,522 260 2,782 Incomplete construction 877 682 1,050 678 1,001 497 4,785 430 5,215 ----------------------------------------------------------------------------------------- Total capitalized costs $ 38,966 $ 9,765 $ 29,502 $14,760 $ 5,657 $ 3,709 $102,359 $ 6,232 $108,591 Accumulated depreciation and depletion 25,129 4,607 18,666 9,486 1,946 1,646 61,480 2,858 64,338 ----------------------------------------------------------------------------------------- Net capitalized costs $ 13,837 $ 5,158 $ 10,836 $ 5,274 $ 3,711 $ 2,063 $ 40,879 $ 3,374 $ 44,253 ========================================================================================= Costs incurred in property acquisitions, exploration and development activities - ----------------------------------------------------------------------------------------------------------------------------------- During 2001 Property acquisition costs - Proved $ -- $ -- $ -- $ -- $ 2 $ -- $ 2 $ -- $ 2 - Unproved 95 17 1 (1) -- 10 122 -- 122 Exploration costs 352 141 144 148 281 459 1,525 35 1,560 Development costs 1,648 664 1,498 666 995 219 5,690 429 6,119 ----------------------------------------------------------------------------------------- Total $ 2,095 $ 822 $ 1,643 $ 813 $ 1,278 $ 688 $ 7,339 $ 464 $ 7,803 ========================================================================================= During 2000 Property acquisition costs - Proved $ 1 $ 1 $ -- $ 1 $ -- $ -- $ 3 $ -- $ 3 - Unproved 72 15 4 96 2 49 238 -- 238 Exploration costs 219 145 187 145 272 297 1,265 23 1,288 Development costs 1,236 525 1,262 502 402 224 4,151 383 4,534 ----------------------------------------------------------------------------------------- Total $ 1,528 $ 686 $ 1,453 $ 744 $ 676 $ 570 $ 5,657 $ 406 $ 6,063 ========================================================================================= During 1999 Property acquisition costs - Proved $ -- $ -- $ 1 $ 18 $ -- $ -- $ 19 $ -- $ 19 - Unproved 8 5 8 -- 459 70 550 -- 550 Exploration costs 263 106 248 152 304 267 1,340 38 1,378 Development costs 1,263 787 1,822 576 547 408 5,403 409 5,812 ----------------------------------------------------------------------------------------- Total $ 1,534 $ 898 $ 2,079 $ 746 $ 1,310 $ 745 $ 7,312 $ 447 $ 7,759 =========================================================================================
58 Oil and Gas Reserves The following information describes changes during the years and balances of proved oil and gas reserves at year-end 1999, 2000 and 2001. The definitions used are in accordance with applicable Securities and Exchange Commission regulations. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which 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. Proved reserves include 100 percent of each majority owned affiliate's participation in proved reserves and ExxonMobil's ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of crude oil and natural gas liquids.
Consolidated Subsidiaries --------------------------------------------------------------- Non- United Consolidated Total Crude Oil and Natural Gas Liquids States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide - ------------------------------------------------------------------------------------------------------------------------------------ Net proved developed and undeveloped reserves (millions of barrels) January 1, 1999 2,804 1,154 1,708 786 1,821 710 8,983 1,970 10,953 Revisions 96 19 96 23 128 6 368 25 393 Purchases -- -- -- -- -- -- -- -- -- Sales (3) -- -- -- -- -- (3) (9) (12) Improved recovery 7 1 15 -- 3 -- 26 72 98 Extensions and discoveries 58 277 174 18 191 2 720 -- 720 Production (213) (96) (232) (112) (119) (18) (790) (102) (892) -------------------------------------------------------------------------------------- December 31, 1999 2,749 1,355 1,761 715 2,024 700 9,304 1,956 11,260 Revisions 410 9 25 29 50 24 547 33 580 Purchases -- -- -- -- -- -- -- -- -- Sales (1) (5) -- -- -- -- (6) -- (6) Improved recovery 40 34 20 -- 3 -- 97 26 123 Extensions and discoveries 8 33 5 39 425 4 514 3 517 Production (220) (96) (253) (93) (118) (26) (806) (107) (913) -------------------------------------------------------------------------------------- December 31, 2000 2,986 1,330 1,558 690 2,384 702 9,650 1,911 11,561 Revisions 89 (9) 68 (1) 94 15 256 8 264 Purchases -- -- -- -- -- -- -- -- -- Sales (6) -- -- -- -- -- (6) (3) (9) Improved recovery 57 5 5 -- 34 -- 101 20 121 Extensions and discoveries 112 53 79 23 74 -- 341 112 453 Production (210) (102) (234) (90) (125) (29) (790) (109) (899) -------------------------------------------------------------------------------------- December 31, 2001 3,028 1,277 1,476 622 2,461 688 9,552 1,939 11,491 Developed reserves, included above At December 31, 1999 2,383 608 1,086 615 1,048 186 5,926 1,333 7,259 At December 31, 2000 2,661 630 978 504 989 245 6,007 1,331 7,338 At December 31, 2001 2,567 593 881 477 1,022 232 5,772 1,440 7,212
59 SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES Net proved developed reserves are those volumes which are expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped reserves are those volumes which 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. Reserves attributable to certain oil and gas discoveries were not considered proved as of year-end 2001 due to geological, technological or economic uncertainties and therefore are not included in the tabulation. Crude oil and natural gas liquids and natural gas production quantities shown are the net volumes withdrawn from ExxonMobil's oil and gas reserves. The natural gas quantities differ from the quantities of gas delivered for sale by the producing function as reported on page 62 due to volumes consumed or flared and inventory changes. Such quantities amounted to approximately 391 billion cubic feet in 1999, 392 billion cubic feet in 2000 and 406 billion cubic feet in 2001.
Consolidated Subsidiaries ------------------------------------------------------------- Non- United Consolidated Total Natural Gas States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide - ------------------------------------------------------------------------------------------------------------------------------------ (billions of cubic feet) Net proved developed and undeveloped reserves January 1, 1999 13,057 3,489 11,401 9,998 113 615 38,673 19,333 58,006 Revisions 781 31 680 131 -- 42 1,665 142 1,807 Purchases -- -- -- -- -- -- -- -- -- Sales (18) (1) -- -- -- -- (19) -- (19) Improved recovery 2 14 105 -- -- -- 121 161 282 Extensions and discoveries 305 207 192 44 58 6 812 61 873 Production (1,126) (353) (1,150) (815) -- (55) (3,499) (654) (4,153) -------------------------------------------------------------------------------------- December 31, 1999 13,001 3,387 11,228 9,358 171 608 37,753 19,043 56,796 Revisions 987 69 970 (113) 147 62 2,122 85 2,207 Purchases -- 10 -- -- -- -- 10 -- 10 Sales (3) (5) -- -- -- -- (8) -- (8) Improved recovery 22 24 46 -- -- 24 116 50 166 Extensions and discoveries 195 430 96 11 70 26 828 45 873 Production (1,157) (399) (1,170) (710) (13) (53) (3,502) (676) (4,178) -------------------------------------------------------------------------------------- December 31, 2000 13,045 3,516 11,170 8,546 375 667 37,319 18,547 55,866 Revisions 612 (51) 564 (198) 8 (5) 930 (94) 836 Purchases -- 1 -- -- -- -- 1 -- 1 Sales (57) -- (2) (8) -- -- (67) (2) (69) Improved recovery 4 15 11 -- 2 -- 32 7 39 Extensions and discoveries 242 120 360 590 8 120 1,440 1,991 3,431 Production (1,114) (418) (1,172) (629) (14) (54) (3,401) (757) (4,158) -------------------------------------------------------------------------------------- December 31, 2001 12,732 3,183 10,931 8,301 379 728 36,254 19,692 55,946 Developed reserves, included above At December 31, 1999 10,820 2,475 7,764 6,471 2 426 27,958 8,643 36,601 At December 31, 2000 10,956 2,850 8,222 6,300 125 477 28,930 9,087 38,017 At December 31, 2001 10,366 2,517 7,824 6,005 122 404 27,238 8,784 36,022 ====================================================================================================================================
INFORMATION ON CANADIAN TAR SANDS PROVEN RESERVES NOT INCLUDED ABOVE In addition to conventional liquids and natural gas proved reserves, ExxonMobil has significant interests in proven tar 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, U.S. Securities and Exchange Commission regulations define these reserves as mining related and not a part of conventional oil and gas reserves. The tar sands reserves are not considered in the standardized measure of discounted future cash flows for conventional oil and gas reserves, which is found on page 61. Tar Sands Reserves Canada - -------------------------------------------------------- (millions of barrels) At December 31, 1999 577 At December 31, 2000 610 At December 31, 2001 821 60 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 corporation believes the standardized measure is not meaningful and may be misleading, due to a number of factors, including significant variability in cash flows due to changes in year-end prices.
Consolidated Subsidiaries ------------------------------------------------------------- Non- United Asia- Consolidated Total States Canada Europe Pacific Africa Other Total Interests Worldwide - ------------------------------------------------------------------------------------------------------------------------------------ (millions of dollars) As of December 31, 1999 Future cash inflows from sales of oil and gas $ 82,674 $29,360 $64,192 $34,771 $49,247 $13,780 $274,024 $94,767 $368,791 Future production costs 21,219 6,618 13,660 9,754 11,784 2,548 65,583 33,006 98,589 Future development costs 4,131 2,116 4,904 3,516 4,779 605 20,051 3,104 23,155 Future income tax expenses 20,103 8,096 23,396 7,680 20,405 2,493 82,173 26,573 108,746 ----------------------------------------------------------------------------------- Future net cash flows $ 37,221 $12,530 $22,232 $13,821 $12,279 $ 8,134 $106,217 $32,084 $138,301 Effect of discounting net cash flows at 10% 20,139 5,884 7,351 5,918 6,275 4,694 50,261 19,473 69,734 ----------------------------------------------------------------------------------- Discounted future net cash flows $ 17,082 $ 6,646 $14,881 $ 7,903 $ 6,004 $ 3,440 $ 55,956 $12,611 $ 68,567 =================================================================================== As of December 31, 2000 Future cash inflows from sales of oil and gas $177,178 $41,275 $70,208 $34,658 $52,651 $10,317 $386,287 $93,597 $479,884 Future production costs 26,417 7,857 15,979 9,977 10,953 3,467 74,650 38,011 112,661 Future development costs 3,977 2,806 5,552 3,405 7,516 798 24,054 3,901 27,955 Future income tax expenses 55,192 12,731 26,078 7,382 18,949 1,830 122,162 21,333 143,495 ----------------------------------------------------------------------------------- Future net cash flows $ 91,592 $17,881 $22,599 $13,894 $15,233 $ 4,222 $165,421 $30,352 $195,773 Effect of discounting net cash flows at 10% 48,876 6,795 7,779 5,638 8,158 2,450 79,696 18,825 98,521 ----------------------------------------------------------------------------------- Discounted future net cash flows $ 42,716 $11,086 $14,820 $ 8,256 $ 7,075 $ 1,772 $ 85,725 $11,527 $ 97,252 =================================================================================== As of December 31, 2001 Future cash inflows from sales of oil and gas $ 68,713 $19,573 $58,394 $24,452 $42,806 $10,370 $224,308 $87,828 $312,136 Future production costs 20,008 6,711 15,807 7,801 10,341 3,217 63,885 31,839 95,724 Future development costs 4,613 2,695 5,252 3,262 7,839 831 24,492 3,043 27,535 Future income tax expenses 16,620 3,908 17,416 4,325 13,485 2,091 57,845 22,046 79,891 ----------------------------------------------------------------------------------- Future net cash flows $ 27,472 $ 6,259 $19,919 $ 9,064 $11,141 $ 4,231 $ 78,086 $30,900 $108,986 Effect of discounting net cash flows at 10% 15,065 2,377 7,338 3,552 6,087 2,553 36,972 18,766 55,738 ----------------------------------------------------------------------------------- Discounted future net cash flows $ 12,407 $ 3,882 $12,581 $ 5,512 $ 5,054 $ 1,678 $ 41,114 $12,134 $ 53,248 ===================================================================================
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries 2001 2000 1999 - ------------------------------------------------------------------------------------------------------------------------------------ (millions of dollars) Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs $ 2,660 $ 6,029 $ 4,245 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 (20,748) (24,498) (13,395) Development costs incurred during the year 5,577 4,194 5,313 Net change in prices, lifting and development costs (79,693) 44,702 59,466 Revisions of previous reserves estimates 2,520 12,537 3,106 Accretion of discount 12,293 7,694 3,056 Net change in income taxes 32,780 (20,889) (30,833) -------------------------------- Total change in the standardized measure during the year $ (44,611) $ 29,769 $ 30,958 ================================
61 OPERATING SUMMARY
2001 2000 1999 1998 1997 - ------------------------------------------------------------------------------------------------------------------------------- (thousands of barrels daily) Production of crude oil and natural gas liquids Net production United States 712 733 729 745 803 Canada 331 304 315 322 287 Europe 653 704 650 635 641 Asia-Pacific 247 253 307 322 347 Africa 342 323 326 301 294 Other Non-U.S. 257 236 190 177 155 ------------------------------------------------------------------ Worldwide 2,542 2,553 2,517 2,502 2,527 ================================================================== (millions of cubic feet daily) Natural gas production available for sale Net production United States 2,598 2,856 2,871 3,140 3,223 Canada 1,006 844 683 667 600 Europe 4,595 4,463 4,438 4,245 4,283 Asia-Pacific 1,547 1,755 2,027 2,352 2,632 Other Non-U.S. 533 425 289 213 156 ------------------------------------------------------------------ Worldwide 10,279 10,343 10,308 10,617 10,894 ================================================================== (thousands of barrels daily) Refinery throughput United States 1,840 1,862 1,930 1,919 2,026 Canada 449 451 441 445 448 Europe 1,563 1,578 1,782 1,888 1,899 Asia-Pacific 1,436 1,462 1,537 1,554 1,559 Other Non-U.S. 283 289 287 287 302 ------------------------------------------------------------------ Worldwide 5,571 5,642 5,977 6,093 6,234 ================================================================== Petroleum product sales United States 2,751 2,669 2,918 2,804 2,777 Canada 585 577 587 579 574 Europe 2,079 2,129 2,597 2,646 2,609 Asia-Pacific and other Eastern Hemisphere 2,024 2,090 2,223 2,266 2,249 Latin America 532 528 562 578 564 ------------------------------------------------------------------ Worldwide 7,971 7,993 8,887 8,873 8,773 ================================================================== Gasoline, naphthas 3,165 3,122 3,428 3,417 3,317 Heating oils, kerosene, diesel oils 2,389 2,373 2,658 2,689 2,725 Aviation fuels 721 749 813 774 753 Heavy fuels 668 694 706 765 744 Specialty petroleum products 1,028 1,055 1,282 1,228 1,234 ------------------------------------------------------------------ Worldwide 7,971 7,993 8,887 8,873 8,773 ================================================================== (thousands of metric tons) Chemical prime product sales 25,780 25,637 25,283 23,628 23,838 ================================================================== (millions of metric tons) Coal production 13 17 17 15 15 ================================================================== (thousands of metric tons) Copper production 252 254 248 216 205 ==================================================================
Operating statistics include 100 percent of operations of majority owned subsidiaries; for other companies, crude production, gas, petroleum product and chemical prime product sales include ExxonMobil's ownership percentage, and refining throughput includes quantities processed for ExxonMobil. Net production excludes royalties and quantities due others when produced, whether payment is made in kind or cash. 62 SIGNATURES Pursuant to the requirements of Section 13 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/ LEE R. RAYMOND ---------------------------------- (Lee R. Raymond, Chairman of the Board) Dated March 27, 2002 ----------------- POWER OF ATTORNEY Each person whose signature appears below constitutes and appoints Richard E. Gutman, Paul A. Hanson and Brian A. Maher, 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/ LEE R. RAYMOND Chairman of the Board March 27, 2002 _____________________________ (Principal Executive Officer) (Lee R. Raymond) /s/ MICHAEL J. BOSKIN Director March 27, 2002 ___________________________ (Michael J. Boskin) /s/ RENE DAHAN Director March 27, 2002 _____________________________ (Rene Dahan) 63 /s/ WILLIAM T. ESREY Director March 27, 2002 _____________________________ (William T. Esrey) /s/ DONALD V. FITES Director March 27, 2002 _____________________________ (Donald V. Fites) /s/ JAMES R. HOUGHTON Director March 27, 2002 _____________________________ (James R. Houghton) /s/ WILLIAM R. HOWELL Director March 27, 2002 _____________________________ (William R. Howell) /s/ HELENE L. KAPLAN Director March 27, 2002 _____________________________ (Helene L. Kaplan) /s/ REATHA CLARK KING Director March 27, 2002 _____________________________ (Reatha Clark King) /s/ PHILIP E. LIPPINCOTT Director March 27, 2002 _____________________________ (Philip E. Lippincott) /s/ HARRY J. LONGWELL Director March 27, 2002 _____________________________ (Harry J. Longwell) /s/ MARILYN CARLSON NELSON Director March 27, 2002 _____________________________ (Marilyn Carlson Nelson) 64 /s/ WALTER V. SHIPLEY Director March 27, 2002 _____________________________ (Walter V. Shipley) /s/ DONALD D. HUMPHREYS Controller March 27, 2002 _____________________________ (Principal Accounting Officer) (Donald D. Humphreys) /s/ FRANK A. RISCH Treasurer March 27, 2002 _____________________________ (Principal Financial Officer) (Frank A. Risch) 65 INDEX TO EXHIBITS 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 registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). 3(ii). By-Laws, as revised to November 30, 1999 (incorporated by reference to Exhibit 3(ii) to the registrant's Annual Report on Form 10-K for 1999). 10(iii)(a). 1993 Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(a) of the registrant's Annual Report on Form 10-K for 1999).* 10(iii)(b). 2001 Nonemployee Directors' Deferred Compensation Plan (incorporated by reference to Exhibit 10(iii)(b) to the registrant's Annual Report on Form 10-K for 2000).* 10(iii)(c). Restricted Stock Plan for Nonemployee Directors, as amended.* 10(iii)(d). ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference to Exhibit 10(iii)(d) to the registrant's Annual Report on Form 10-K for 1999).* 10(iii)(e). Short Term Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(e) to the registrant's Annual Report on Form 10-K for 1999).* 10(iii)(f). 1997 Nonemployee Director Restricted Stock Plan (incorporated by reference to Exhibit 10(iii)(f) to the registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000).* 10(iii)(g). 1995 Mobil Incentive Compensation and Stock Ownership Plan (incorporated by reference to Exhibit 10(iii)(g) to the registrant's Annual Report on Form 10-K for 2000).* 10(iii)(i). Supplemental Employees Savings Plan of Mobil Oil Corporation (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K of Mobil Corporation filed March 31, 1999).* 12. Computation of ratio of earnings to fixed charges. 21. Subsidiaries of the registrant. 23. Consent of PricewaterhouseCoopers LLP, Independent Accountants.
- -------- * Compensatory plan or arrangement required to be identified pursuant to Item 14(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. 66