2000 - - - - - - ------------------------------------------------------------------------------- - - - - - - ------------------------------------------------------------------------------- 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, 2000 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 jurisdiction of (I.R.S. Employer Identification incorporation or organization) Number) 5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298 (Address of principal executive offices) (Zip Code) (972) 444-1000 (Registrant's telephone number, including area code) ---------------- Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange Title of Each Class on Which Registered ------------------- ----------------------- Common Stock, without par value (3,455,409,183 shares outstanding at February 28, 2001) 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, 2001, based on the closing price on that date of $81.05 on the New York Stock Exchange composite tape, was in excess of $280 billion. Documents Incorporated by Reference: Proxy Statement for the 2001 Annual Meeting of Shareholders (Part III) - - - - - - ------------------------------------------------------------------------------- - - - - - - ------------------------------------------------------------------------------- EXXON MOBIL CORPORATION FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 TABLE OF CONTENTS
Page Number ------ PART I Item 1. Business..................................................... 1-2 Item 2. Properties................................................... 2-14 Item 3. Legal Proceedings............................................ 15 Item 4. Submission of Matters to a Vote of Security Holders.......... 15 Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)]......................................... 16 PART II Item 5. Market for Registrant's Common Stock and Related Shareholder Matters...................................................... 17 Item 6. Selected Financial Data...................................... 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................... 17 Item 7A. Quantitative and Qualitative Disclosures About Market Risk... 17-18 Item 8. Financial Statements and Supplementary Data.................. 18 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................................... 18 PART III Item 10. Directors and Executive Officers of the Registrant........... 18 Item 11. Executive Compensation....................................... 18 Item 12. Security Ownership of Certain Beneficial Owners and Management................................................... 18 Item 13. Certain Relationships and Related Transactions............... 18 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K..................................................... 18 Financial Section...................................................... 19-57 Signatures............................................................. 58-60 Index to Exhibits...................................................... 61 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 December 1, 1998, Exxon Corporation ("Exxon") and Mobil Corporation ("Mobil") signed an agreement to merge the two companies subject to shareholder approval, regulatory reviews and other conditions. On November 30, 1999, pursuant to the agreement, a wholly-owned subsidiary of Exxon was merged with and into Mobil so that Mobil became a wholly-owned subsidiary of Exxon. At the same time, Exxon changed its name to Exxon Mobil Corporation. Coincident with the merger, ExxonMobil announced a new organization structure built on a concept of eleven separate global businesses designed to allow the company to compete more effectively in a changing worldwide energy industry: five upstream businesses--Exploration, Development, Production, Gas Marketing and Upstream Research; four downstream businesses-- Refining and Supply, Fuels Marketing, Lubricants and Petroleum Specialties, and Technology; plus a chemical company and a coal and minerals company. 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, manufacturing 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 the terms 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 2000, the corporation spent $1,529 million (of which $393 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 $1.8 billion in both 2001 and 2002 (with capital expenditures representing about 25 percent of the total). Operating data and industry segment information for the corporation are contained on pages 50, 56 and 57; information on oil and gas reserves is contained on pages 53 and 54 and information on company-sponsored research and development activities is contained on page 34 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. 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 1 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. Industry and Economic Factors: The operations and earnings of the corporation and its affiliates throughout the world are also 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, the development of new supply sources; supply disruptions; weather; international political events; technological advances; changes in demographics and consumer preferences and the competitiveness of alternative energy sources or product substitutes. Project Factors: The advancement, cost and results of particular ExxonMobil projects also 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. Merger-Related Factors: Realization of the benefits of the merger will depend, among other things, upon management's ability to integrate the businesses of Exxon and Mobil successfully and on schedule. Future results could also be affected by the diversion of management's focus and resources from other strategic opportunities during the merger integration process. Market Risk Factors: See also page 23 and 24 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 merger related expenses, synergy benefits from the merger (including cost savings, efficiency gains and revenue enhancements), 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 36, and on pages 51 through 55 and 57. 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 2000 Estimated proved reserves are shown on pages 53 and 54 of the Financial Section of this report. No major discovery or other favorable or adverse event has occurred since December 31, 2000, 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 55 of the Financial Section of this report. 2. Estimates of Total Net Proved Oil and Gas Reserves Filed with Other Federal Agencies During 2000, ExxonMobil filed proved reserves estimates with the U.S. Department of Energy on Forms EIA-23 and EIA-28. The information is consistent with the ExxonMobil 1999 Annual Report to shareholders with the exception of EIA-23 which covered total oil and gas reserves from 2 ExxonMobil-operated properties in the United States and does not include gas plant liquids. The differences between the oil reserves and gas reserves reported on EIA-23 and those reported in the 1999 Annual Report exceed five percent. 3. Average Sales Prices and Production Costs per Unit of Production Reference is made to page 51 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 53 of the Financial Section of this report. The net production volumes of natural gas available for sale by the producing function used in this calculation are shown on page 57 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 2000 -------------------------- Oil Gas ------------- ------------ Gross Net Gross Net ------ ------ ------ ----- United States..................................... 35,552 12,455 9,857 4,590 Canada............................................ 6,750 5,188 4,938 2,489 Europe............................................ 1,702 546 1,331 480 Asia-Pacific...................................... 1,394 518 718 256 Africa............................................ 362 154 -- -- Other............................................. 974 176 137 41 ------ ------ ------ ----- Total............................................ 46,734 19,037 16,981 7,856 ====== ====== ====== =====
5. Gross and Net Developed Acreage
Year-End 2000 --------------------- Gross Net ---------- ---------- (Thousands of acres) United States.......................................... 9,578 5,993 Canada................................................. 4,577 2,390 Europe................................................. 11,576 4,816 Asia-Pacific........................................... 4,605 1,528 Africa................................................. 894 387 Other.................................................. 9,175 1,821 ---------- ---------- Total................................................. 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. 6. Gross and Net Undeveloped Acreage
Year-End 2000 -------------------- Gross Net --------- ---------- (Thousands of acres) United States........................................... 11,527 7,399 Canada.................................................. 22,136 9,619 Europe.................................................. 16,283 6,244 Asia-Pacific............................................ 38,037 19,641 Africa.................................................. 47,325 20,111 Other................................................... 51,718 26,363 ---------- --------- Total.................................................. 187,026 89,377 ========== =========
3 7. Summary of Acreage Terms in Key Areas UNITED STATES Oil and gas exploration 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, 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. Netherlands Onshore: Exploration drilling permits are issued for a period of two to five years. Permits issued after 1996 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 are 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 are 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 10 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, 4 1997 have an initial period of from 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 provide 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 two to six years (in some states the 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 (all of the company'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 and renewals may be requested. Production licenses granted prior to September 1, 1998 were initially for 21 years, with a further renewal of 21 years and thereafter renewals at the discretion of the Joint Authority or Federal Minister. Effective from September 1, 1998, new production licenses are 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 production sharing contracts negotiated with the national oil company. Certain activities may also be subject to joint operating agreements and/or technical assistance contracts also negotiated with the national oil company. The more recent contracts have an overall term of up to 30 years with possible extensions in some contracts. The initial exploration period is from six to ten years. 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 current contract. 5 Papua New Guinea Exploration and production activities are governed by the Petroleum Act. Exploration permits are granted for an initial term of six years with renewals of five years. A 50 percent area relinquishment is mandatory at the end of the first term. Production licenses are granted for an initial 25-year period. Renewals of up to 20 years may be granted at the Minister's discretion. Petroleum retention licenses are granted for five-year terms, renewable twice for maximum retention time of 15 years. Thailand The company's concessions and the Petroleum Act of 1972 allow production 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 a negotiated extension is common. 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, 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 10 to 15 years with limited relinquishments in the absence of commercial discoveries. The production period for crude 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) with no required relinquishment after the initial phase, a 50 percent relinquishment requirement after the second phase and a 20-year production period that may be extended. Some exploration activities are carried out in deepwater by joint ventures with indigenous companies as direct participants in an OPL. OPLs in deepwater offshore areas are valid for ten years and are non-renewable, while in all other areas OPLs 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. 6 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. In all cases, renewal of OMLs is almost certain if lessee satisfies three conditions, namely, lessee: i) gives the requisite notice within the minimum stipulated period; ii) has paid up-to-date all rentals, royalties and fees and iii) has fulfilled all lessee's obligations under the OML. 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 extension on mutual agreement. Guidelines for Marginal Field Development were issued by the Government. OTHER COUNTRIES Argentina The concession terms for onshore 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 concession terms for offshore 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. Fifty 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 exploitation 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 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 a joint- venture agreement 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 consists of 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 concessions to LNG projects within Qatar's offshore North field to permit the economic development and production of sufficient gas to satisfy the LNG sales obligations of these projects. Republic of Yemen Production sharing agreements (PSAs) negotiated with the government entitle the company to participate in exploration operations within a designated area during the exploration period. In the 7 event of a commercial oil discovery, the company is entitled to proceed with development and production operations during the development period. The length of these periods and other specific terms are negotiated prior to executing the PSA. Existing production operations have a development period extending 20 years from first commercial declaration (made in November 1985 for the Marib 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 were awarded for 35 years. Production licenses are awarded for 20 years under production service agreements. Strategic association agreements (such as the Cerro Negro project) are limited to those projects that require vertical integration. Licenses are awarded for 35 years. Significant amendments to the contract terms require Venezuelan congressional approval. 8. Number of Net Productive and Dry Wells Drilled
2000 1999 1998 ----- ----- ----- A. Net Productive Exploratory Wells Drilled United States............................................... 2 16 23 Canada...................................................... 49 4 18 Europe...................................................... 3 7 8 Asia-Pacific................................................ 5 4 19 Africa...................................................... 2 8 6 Other....................................................... 1 1 8 ----- ----- ----- Total...................................................... 62 40 82 ----- ----- ----- B. Net Dry Exploratory Wells Drilled United States............................................... 2 11 20 Canada...................................................... 12 2 9 Europe...................................................... 3 5 11 Asia-Pacific................................................ 3 10 15 Africa...................................................... 4 2 8 Other....................................................... 2 1 1 ----- ----- ----- Total...................................................... 26 31 64 ----- ----- ----- C. Net Productive Development Wells Drilled United States............................................... 604 419 629 Canada...................................................... 213 308 149 Europe...................................................... 40 51 54 Asia-Pacific................................................ 30 47 69 Africa...................................................... 16 10 15 Other....................................................... 31 32 17 ----- ----- ----- Total...................................................... 934 867 933 ----- ----- ----- D. Net Dry Development Wells Drilled United States............................................... 7 16 21 Canada...................................................... -- 12 8 Europe...................................................... 5 2 4 Asia-Pacific................................................ 1 -- 3 Africa...................................................... -- -- -- Other....................................................... -- 1 2 ----- ----- ----- Total...................................................... 13 31 38 ----- ----- ----- Total number of net wells drilled........................... 1,035 969 1,117 ===== ===== =====
8 9. Present Activities A. Wells Drilling -- Year-End 2000
Gross Net ----- --- United States....................................................... 151 69 Canada.............................................................. 63 12 Europe.............................................................. 26 9 Asia-Pacific........................................................ 9 4 Africa.............................................................. 5 2 Other............................................................... 9 3 --- --- Total............................................................. 263 99 === ===
B. Review of Principal Ongoing Activities in Key Areas During 2000, 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 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: UNITED STATES Exploration and delineation of additional hydrocarbon resources continued. At year-end 2000, 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 3.9 net exploration and delineation wells were completed during 2000. During 2000, 539.1 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 21.0 net development wells were drilled in 2000. Equity realignment in the Prudhoe Bay field increased the company's net production by 30 thousand barrels per day. ExxonMobil's net acreage in the Gulf of Mexico at year-end 2000 was 3.5 million acres. A total of 47.1 net exploration and development wells were completed during the year and development continued on several Gulf of Mexico projects in 2000. . In May 2000, production began from the ExxonMobil-operated Hoover and Diana fields in the deepwater Gulf of Mexico using a Deep-Draft Caisson Vessel (DDCV). This DDCV, installed in 4,800 feet of water, set a world water-depth record for a combined drilling and production platform. . Activities to tie-in Nile, a one well subsea development in 3,500 feet of water, to the Marlin host platform are underway. First production is planned for second quarter 2001. . Construction and drilling activities advanced in the ExxonMobil-operated Mica field, a remote deepwater subsea development located in 4,500 feet water depth tied back to the Pompano host platform. First production is scheduled for mid-year 2001. 9 . Activities to tie-in the ExxonMobil-operated Marshall and Madison discoveries, located in 4,800 feet water depth, to the Hoover host facilities are underway. First production is planned for early 2002. CANADA ExxonMobil's year-end acreage holdings totaled 12.0 million net acres. A total of 273.7 net exploration and development wells were completed during the year. Gross production from Cold Lake averaged 119 thousand barrels per day during 2000. Field work began on the next expansion targeted to start up in 2003. In Eastern Canada, 2000 marked the first full year of gas production of the Sable Offshore Energy Project. The Terra Nova oil development project offshore Newfoundland is under construction. EUROPE France ExxonMobil's acreage at year-end 2000 was 0.8 million net acres, with 2.5 net exploration and development wells completed during the year. Germany A total of 2.8 million net acres were held by ExxonMobil at year-end 2000, with 4.8 net exploration and development wells drilled during the year. The offshore A6/B4 gas project in the North Sea came on stream in the third quarter of 2000. Netherlands ExxonMobil's interest in licenses totaled 2.5 million net acres at year-end 2000. During 2000, 2.7 net exploration and development wells were drilled. Significant, but smaller fields, are continuously being discovered, developed and brought on stream. Norway ExxonMobil's net interest in licenses at year-end 2000 totaled 1.4 million acres, all offshore. ExxonMobil participated in 12.7 net exploration and development well completions in 2000. Production was initiated on three developments: Aasgard B/C, Sygna and Oseberg South. Field development projects for Snorre B, Ringhorne and Grane fields are in progress. United Kingdom ExxonMobil's net interest in licenses at year-end 2000 totaled approximately 3.2 million acres, all offshore. A total of 28.2 net exploration and development wells were completed during the year. Several projects started up, including Shearwater, Triton, Cook and Skiff. Several major projects were underway including Skene, Brigantine and Elgin/Franklin. ASIA-PACIFIC Australia ExxonMobil's net year-end 2000 acreage holdings totaled 7.6 million acres. ExxonMobil drilled a total of 24.4 net exploration and development wells in 2000. A development drilling program was completed offshore Australia. 10 Indonesia ExxonMobil had acreage of 8.0 million net acres at year-end 2000. During the year ExxonMobil acquired an additional 51 percent interest in the Cepu block, bringing its total interest to 100 percent. Malaysia ExxonMobil has interests in production sharing contracts covering 4.5 million net acres offshore Malaysia. During the year, a total of 13.3 net exploration and development wells were completed. Development and infill drilling were successfully completed at Tapis-E, Pulai-A and Jerneh-A platforms. Major development projects currently in progress are Angsi, Larut and five satellite field developments. These are scheduled for installation and start-up in the 2001 to 2003 time frame. Papua New Guinea ExxonMobil's 2000 year-end acreage was 0.6 million net acres, with 0.5 net exploration and development wells completed in 2000. An extended well test commenced in the Moran field. Thailand ExxonMobil's acreage in the Khorat concession totaled 15 thousand net acres at year-end. AFRICA Angola ExxonMobil's year-end 2000 acreage holdings totaled 3.7 million net acres and 3.6 net exploration and development wells were completed during the year. Development continued on the Girassol field in Block 17 with first production scheduled in late 2001. Development planning is progressing on ExxonMobil- operated discoveries in Block 15 and non-operated Block 17 discoveries. Cameroon ExxonMobil's acreage totaled 0.3 million net acres at year-end, with 0.9 net exploration and development wells completed during the year. The D1b field is under development with first oil planned by year-end 2001. Chad ExxonMobil's net year-end 2000 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 net acreage totaled 0.6 million acres at year-end, with 4.4 net exploration and development wells completed during the year. Production from the Jade platform started in June 2000. Nigeria ExxonMobil's net acreage totaled 1.4 million acres at year-end, with 10.8 net exploration and development wells completed during the year. Development plans are being progressed for the Bonga discovery (OPL 212) and for the ExxonMobil-operated Erha (OPL 209) discovery. Expected start-up is 2004 for Bonga and 2005 for Ehra. 11 OTHER COUNTRIES Argentina ExxonMobil's acreage totaled 0.6 net million acres at year-end, with 4.0 net exploration and development wells completed during the year. Azerbaijan At year-end 2000, ExxonMobil's net acreage totaled 0.2 million acres located in the Caspian Sea offshore of Azerbaijan. At the Megastructure Early Oil project, water injection to support reservoir pressure was started in mid-2000. Engineering design of the next platform continues. Kazakhstan ExxonMobil's net acreage totaled 0.4 million acres at year-end 2000, with 1.2 net exploration and development wells completed during 2000. Production capacity from the Tengiz field has increased with the completion of a fifth processing train and the implementation of gas handling de-bottlenecking projects. Development planning to further increase production is ongoing. Substantial progress was made on construction of the Caspian Pipeline Consortium (CPC) project for transporting oil from Tengiz, and other Caspian fields and nearby areas, to the Russian Black Sea port of Novorossiysk. Start- up is projected in 2001. The pipeline will displace the high cost rail and barge transportation now being used. 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.). Initial RasGas operations commenced in 1999 from the first LNG train. A second train started up in March 2000, bringing total production capacity to 6.6 MTA (million metric tons per year) of LNG. Engineering and design was completed in 2000 for two new LNG trains as part of the RasGas Expansion project. In May 2000, a development and production sharing agreement was executed for the Enhanced Gas Utilization (EGU) project, which provides for up to 1.75 billion cubic feet per day of gas production, along with associated condensate and natural gas liquids, from Qatar's North field. Engineering and design of the EGU gas production facilities were completed in 2000. Gas from EGU is targeted for domestic use and regional sales via pipeline. Republic of Yemen ExxonMobil's net acreage in the Republic of Yemen production sharing areas totaled 0.9 million acres onshore at year-end. During the year, 5.7 net exploration and development wells were drilled and completed. Venezuela ExxonMobil's net acreage totaled 0.5 million acres at year-end with 19.3 net exploration and development wells completed during the year. The Cerro Negro heavy oil project began production in November 1999, and the Central Processing facility was completed in the fourth quarter of 2000. Construction activities on the Upgrader Facility at the Jose Industrial Complex are on schedule for a 2001 start-up. 12 WORLDWIDE EXPLORATION Exploration activities were underway in several areas in which ExxonMobil has no established production operations. A total of 35.2 million net acres were held at year-end, and 3.6 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 Alberta Energy Company Ltd. Since startup in 1978, Syncrude has produced 1.2 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), a truck, shovel and hydrotransport system is 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 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 2000 this upgrading process yielded 0.843 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 is $690 million. 13 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 3,535 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 1,645 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 its 25 percent net share of proven reserves is equivalent to 610 million barrels of synthetic crude oil. ExxonMobil Share of Net Proven Syncrude Reserves(1)
Synthetic Crude Oil ------------------------------- Base Mine and North Mine Aurora Mine Total ------------- ----------- ----- (millions of barrels) January 1, 2000................................. 387 190 577 Revision of previous estimate................... -- 48 48 Production...................................... (14) (1) (15) --- --- --- December 31, 2000............................... 373 237 610 === === ===
- - - - - - -------- (1) Net reserves are the company's share of reserves after deducting royalties payable to the Province of Alberta. Syncrude Operating Statistics (total operation)
2000 1999 1998 1997 1996 ----- ----- ----- ----- ----- Operating Statistics Total mined volume (millions of cubic yards)(1).. 85.1 100.1 98.4 71.1 63.4 Mined volume to tar sands ratio(1)............... 0.96 0.99 1.05 0.75 0.68 Tar sands mined (million of tons)................ 156.4 178.7 165.9 166.7 163.7 Average bitumen grade (weight percent)........... 11.0 10.8 10.7 10.6 10.4 ----- ----- ----- ----- ----- Crude bitumen in mined tar sands (millions of tons)........................................... 17.2 19.3 17.8 17.7 17.0 Average extraction recovery (percent)............ 89.7 91.4 91.6 91.0 90.0 ----- ----- ----- ----- ----- Crude bitumen production (millions of barrels)(2)..................................... 86.8 99.6 92.1 90.3 86.4 Average upgrading yield (percent)................ 84.3 83.9 84.6 84.5 84.2 ----- ----- ----- ----- ----- Gross synthetic crude oil produced (millions of barrels)........................................ 73.2 83.6 77.9 76.3 72.9 ExxonMobil net share (millions of barrels)(3).... 15 20 19 17 15
- - - - - - -------- (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. 14 Item 3. Legal Proceedings. A previously reported matter, involving a proceeding by the Texas Natural Resource Conservation Commission captioned "In the Matter of an Enforcement Action Concerning Exxon Mobil Corporation, Air Account No. JE-0067-I" and alleging that the corporation failed to timely install NOx RACT and meet other related requirements at the Mobil Oil Corporation Beaumont, Texas refinery in violation of the Texas Health and Safety Code and various Commission rules, was settled and a Final Agreed Order prepared during the fourth quarter of 2000. The Agreed Order requires payment of an administrative penalty of $64,800 in addition to a Supplemental Environmental Project (SEP). The SEP involves the purchase by the corporation of $64,800 worth of communications equipment for the Jefferson County Local Emergency Planning Commission to improve their ability to respond to local emergencies, including air pollution incidents. The Commission had initially sought an administrative penalty of $234,900. The Final Order will be executed during the first half of 2001. In November, 2000, the Illinois Attorney General's office made a demand for $275,000 in civil penalties in connection with a previously reported matter involving a suit commenced by the Attorney General of the State of Illinois and the State's Attorney for Will County, Illinois and alleging that a July 2, 1999 release of water and gas from the coker unit of Mobil Oil Corporation's Joliet, Illinois refinery violated several provisions of the Illinois Environmental Protection Act, created a public nuisance and violated a 1998 Consent Order. Penalties were previously unspecified. The corporation is reviewing the demand. The corporation, the U.S. Environmental Protection Agency and the California Regional Water Quality Control Board have reached an agreement in principle to settle penalty claims arising from a 1991 oil spill by Mobil Oil Corporation into the Santa Clara River upon payment of $1,250,000 in civil penalties. The agencies allege the spill resulted in violations of the Federal Clean Water Act, the California Water Code and the Federal Oil Pollution Act. The settlement, as well as an associated consent decree still to be negotiated, will ultimately require approval by the court and publication in the Federal Register to become effective. Refer to the relevant portions of Note 17 on page 46 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. ---------------- 15 Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K, Item 401(b)].
Age as of March 31, Name 2001 Title (Held Office Since) ---- --------- ------------------------------------------------ L. R. Raymond.... 62 Chairman of the Board (1993) R. Dahan......... 59 Senior Vice President (1995) H. J. Longwell... 59 Senior Vice President (1995) E. A. Renna...... 56 Senior Vice President (1999) H. R. Cramer..... 50 Vice President (1999) M. E. Foster..... 58 President, ExxonMobil Development Company (1999) D. D. Humphreys.. 53 Vice President and Controller (1997) K. T. Koonce..... 62 Vice President (1999) C. W. Matthews... 56 Vice President and General Counsel (1995) S. R. McGill..... 58 Vice President (1998) J. T. McMillan... 64 Vice President (1997) S. D. Pryor...... 51 Vice President (1999) F. A. Risch...... 58 Vice President and Treasurer (1999) D. S. Sanders.... 61 Vice President (1999) J. S. Simon...... 57 Vice President (1999) P. E. Sullivan... 57 Vice President and General Tax Counsel (1995) J. L. Thompson... 61 Vice President (1991) T. P. Townsend... 64 Vice President -- Investor Relations (1990) and Secretary (1995)
For at least the past five years, Messrs. Longwell, Matthews, Raymond, Risch, Sullivan, Thompson and Townsend 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, 2000. Esso Italiana S.p.A. ............................... Simon Esso Malaysia Berhad................................ Humphreys Esso Production Malaysia Inc. ...................... Humphreys Exxon Chemical Company.............................. Sanders Exxon Coal and Minerals Company..................... McMillan Exxon Company, International........................ Dahan, McGill and Simon Exxon Company, U.S.A................................ Foster and McMillan Exxon Upstream Development Company.................. Foster Exxon Ventures (CIS) Inc. .......................... Koonce ExxonMobil Chemical Company......................... Sanders ExxonMobil Coal and Minerals Company................ McMillan ExxonMobil Fuels Marketing Company.................. Cramer ExxonMobil Gas Marketing Company.................... McGill ExxonMobil Lubricants & Petroleum Specialties Company............................................ Pryor ExxonMobil Production Company....................... Koonce ExxonMobil Refining & Supply Company................ Simon Mobil Asia Pacific Pty. Ltd. ....................... Pryor Mobil Chemical Company.............................. Pryor Mobil Corporation................................... Cramer and Renna Mobil Europe and Central Asia Limited............... Cramer Mobil Europe Limited................................ Cramer Mobil Oil Corporation............................... Pryor and Renna Mobil South, Inc. .................................. Cramer
Officers are generally elected by the Board of Directors at its meeting on the day of each annual election of directors, each such officer to serve until his or her successor has been elected and qualified. 16 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 (13 persons) was granted 1,200 shares of restricted stock on January 1, 2001. 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, --------------------------------------------- 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- (millions of dollars, except per share amounts) Sales and other operating revenue, including excise taxes. $228,439 $182,529 $165,627 $197,732 $210,038 Net income Before extraordinary item and cumulative effect of accounting change............. $ 15,990 $ 7,910 $ 8,144 $ 11,732 $ 10,474 Extraordinary gain from required asset divestitures, net of income tax............. $ 1,730 $ -- $ -- $ -- $ -- Cumulative effect of accounting change........................ $ -- $ -- $ (70) $ -- $ -- -------- -------- -------- -------- -------- Net income..................... $ 17,720 $ 7,910 $ 8,074 $ 11,732 $ 10,474 Net income per common share Before extraordinary item and cumulative effect of accounting change............. $ 4.60 $ 2.28 $ 2.33 $ 3.32 $ 2.95 Extraordinary gain, net of income tax.................... $ 0.50 $ -- $ -- $ -- $ -- Cumulative effect of accounting change........................ $ -- $ -- $ (0.02) $ -- $ -- -------- -------- -------- -------- -------- Net income..................... $ 5.10 $ 2.28 $ 2.31 $ 3.32 $ 2.95 Net income per common share - assuming dilution Before extraordinary item and cumulative effect of accounting change............. $ 4.55 $ 2.25 $ 2.30 $ 3.28 $ 2.91 Extraordinary gain, net of income tax.................... $ 0.49 $ -- $ -- $ -- $ -- Cumulative effect of accounting change........................ $ -- $ -- $ (0.02) $ -- $ -- -------- -------- -------- -------- -------- Net income..................... $ 5.04 $ 2.25 $ 2.28 $ 3.28 $ 2.91 Cash dividends per common share . $ 1.760 $ 1.687 $ 1.666 $ 1.619 $ 1.538 Total assets..................... $149,000 $144,521 $139,335 $143,751 $146,939 Long-term debt................... $ 7,280 $ 8,402 $ 8,532 $ 10,868 $ 11,986
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 20 of the Financial Section of this report. Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Reference is made to the section entitled "Market Risks, Inflation and Other Uncertainties" beginning on page 23 excluding the part entitled "Inflation and Other Uncertainties" and to the 17 eleventh paragraph of the section entitled "Liquidity and Capital Resources" on page 25 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 28, 2001, appearing on pages 27 to 50; the Quarterly Information appearing on page 56 and the Supplemental Information on Oil and Gas Exploration and Production Activities appearing on pages 51 to 55 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 2001 annual meeting of shareholders (the "2001 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 2001 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 2001 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 19 of the Financial Section of this report. (a) (3) Exhibits: See Index to Exhibits on page 61 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 2000. 18 FINANCIAL SECTION TABLE OF CONTENTS Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................... 20-26 Report of Independent Accountants........................................ 27 Consolidated Financial Statements Statement of Income.................................................... 28 Balance Sheet.......................................................... 29 Statement of Shareholders' Equity...................................... 30 Statement of Cash Flows................................................ 31 Notes to Consolidated Financial Statements 1. Summary of Accounting Policies..................................... 32 2. Extraordinary Item and Accounting Change........................... 33 3. Merger of Exxon Corporation and Mobil Corporation.................. 33 4. Reorganization Costs............................................... 33 5. Miscellaneous Financial Information ............................... 34 6. Cash Flow Information.............................................. 34 7. Additional Working Capital Data ................................... 34 8. Equity Company Information ........................................ 35 9. Investments and Advances........................................... 35 10. Investment in Property, Plant and Equipment........................ 36 11. Leased Facilities ................................................. 36 12. Capital............................................................ 36 13. Employee Stock Ownership Plans .................................... 38 14. Financial Instruments ............................................. 38 15. Long-Term Debt..................................................... 39 16. Incentive Program.................................................. 45 17. Litigation and Other Contingencies ................................ 46 18. Annuity Benefits and Other Postretirement Benefits ................ 47 19. Income, Excise and Other Taxes .................................... 49 20. Disclosures about Segments and Related Information ................ 50 Supplemental Information on Oil and Gas Exploration and Production Activities ............................................................. 51-55 Quarterly Information ................................................... 56 Operating Summary ....................................................... 57
19 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FUNCTIONAL EARNINGS 2000 1999 1998 ____________________________________________________________________________________________________________ (millions of dollars) Earnings Including Merger Effects and Special Items Upstream United States $ 4,545 $1,842 $ 850 Non-U.S. 7,824 4,044 2,502 Downstream United States 1,561 577 1,199 Non-U.S. 1,857 650 2,275 Chemicals United States 644 738 792 Non-U.S. 517 616 602 Other operations 551 426 384 Corporate and financing (589) (514) (460) Merger expenses (920) (469) -- Gain from required asset divestitures 1,730 -- -- Accounting change -- -- (70) ----------------------- Net income $17,720 $7,910 $8,074 ======================= Net income per common share (dollars) $ 5.10 $ 2.28 $ 2.31 Net income per common share -- assuming dilution (dollars) $ 5.04 $ 2.25 $ 2.28 ============================================================================================================ Merger Effects and Special Items Upstream United States $ -- $ -- $ (185) Non-U.S. -- 119 (176) Downstream United States -- -- 8 Non-U.S. -- (120) (412) Chemicals United States -- -- (8) Non-U.S. -- -- (1) Corporate and financing -- -- 112 Merger expenses (920) (469) -- Gain from required asset divestitures 1,730 -- -- Accounting change -- -- (70) ----------------------- Total $ 810 $ (470) $ (732) ======================= ============================================================================================================ Earnings Excluding Merger Effects and Special Items Upstream United States $ 4,545 $1,842 $1,035 Non-U.S. 7,824 3,925 2,678 Downstream United States 1,561 577 1,191 Non-U.S. 1,857 770 2,687 Chemicals United States 644 738 800 Non-U.S. 517 616 603 Other operations 551 426 384 Corporate and financing (589) (514) (572) ----------------------- Total $16,910 $8,380 $8,806 ======================= Earnings per common share (dollars) $ 4.87 $ 2.41 $ 2.52 Earnings per common share -- assuming dilution (dollars) $ 4.81 $ 2.38 $ 2.49 ============================================================================================================
20 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 (Exploration and Production) 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 (Refining and Marketing) 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 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 were $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 increased due to higher crude oil and natural gas realizations, up about 60 percent and 45 percent, respectively. Liquids production of 2,553 kbd (thousands of barrels daily) 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 (millions of cubic feet daily) 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. Record prime product sales volumes of 25,637 kt (thousands of metric tons) 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, coal and electricity 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 21 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS exchange effects and lower tax-related benefits. Partly offsetting was 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. REVIEW OF 1999 RESULTS Earnings excluding merger expenses and special items were $8,380 million, down $426 million or 5 percent from 1998. Net income was $7,910 million, down from $8,074 million in 1998. The decline was primarily in the downstream where steeply rising crude oil costs could not be recovered in the marketplace. Crude oil prices rose about $14 per barrel from January to December 1999, depressing downstream margins in all geographic areas. Weaker chemicals margins and lower coal prices also adversely affected earnings. However, upstream results benefited from the increase in crude oil prices and partly offset the weakness in downstream business conditions. Record chemicals, coal and copper volumes and reduced expenses in every operating segment also benefited earnings. Results in 1999 included $470 million of net charges for special items -- $469 million of merger expenses with other special items essentially offsetting. Results in 1998 included $732 million of net special charges. Revenue for 1999 totaled $186 billion, up 9 percent from 1998, and the cost of crude oil and product purchases increased 24 percent. 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 1999 was $44.3 billion, down about $400 million from 1998. The impact of efficiency initiatives, including the capture of early merger synergies, reduced operating costs by $1.2 billion. Interest expense in 1999 was $695 million, $127 million higher than 1998, mainly due to a higher debt level and unfavorable foreign exchange effects. Upstream Upstream earnings of $5,886 million increased significantly from 1998 reflecting higher average crude oil prices, up over $5 per barrel from 1998. Average U.S. natural gas prices were 9 percent higher than the prior year, while European gas prices, which are tied to petroleum product prices on a lagged basis, were about 17 percent lower. Liquids production of 2,517 kbd was up 1 percent from 2,502 kbd in 1998 as production from new developments in the North Sea, the Gulf of Mexico, West Africa and the Caspian offset natural field declines in North America and lower liftings in Indonesia and Malaysia. Natural gas production of 10,308 mcfd compared with 10,617 mcfd in 1998. Upstream expenses were reduced from 1998 levels. Earnings from the U.S. upstream were $1,842 million, up $807 million after excluding $185 million of special charges related mainly to property write-downs in 1998. Outside the U.S. upstream earnings were $3,925 million, up $1,247 million after excluding a $141 million deferred tax benefit and a $22 million property write-off in 1999 and $176 million of other net special charges in 1998. Downstream Downstream earnings of $1,227 million declined from 1998's strong results primarily reflecting escalating crude oil costs and weaker downstream margins in all geographic areas. Unfavorable foreign exchange and inventory effects also reduced earnings. Higher volumes, mainly in the U.S., and lower operating expenses provided a partial offset. Petroleum product sales were 8,887 kbd compared with 8,873 kbd in 1998. Refinery throughput was 5,977 kbd compared with 6,093 kbd in 1998. In the U.S., downstream earnings were $577 million, down $614 million from 1998 after excluding $8 million of special credits related to inventory adjustments in 1998. Downstream operations outside of the U.S. earned $770 million, down $1,917 million from 1998 after excluding special charges from both years. Results in 1999 included $80 million of charges for non-merger related restructuring of Japanese downstream operations and a $40 million write- off associated with the cancellation of a power project in Japan, while 1998 results included $412 million of special charges largely related to the impact of lower prices on inventories and Mobil-British Petroleum (BP) alliance implementation costs. Chemicals Earnings from chemicals operations totaled $1,354 million, down $40 million or 3 percent from 1998. Industry margins declined due to lower product prices and higher feedstock costs. Prime product sales volumes of 25,283 kt were a record. Earnings also benefited from lower operating expenses. Chemicals' results included $9 million of special charges related to the impact of lower prices on inventories in 1998. Other Operations Earnings from other operating segments totaled $426 million, an increase of $42 million from 1998. The increase reflects record copper and coal production, lower operating expenses and favorable foreign exchange effects, partly offset by depressed coal prices. Corporate and Financing Corporate and financing expenses were $514 million, $54 million higher than 1998 which included a net special credit of $112 million related to settlement of prior years' tax disputes. Excluding special items, expenses were $58 million lower reflecting lower tax-related charges. 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. 22 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. These assets, with a carrying value of approximately $3 billion, were sold in the year 2000. Before-tax proceeds for these assets were approximately $5 billion. The net after-tax gain of $1,730 million was reported as an extraordinary item consistent with pooling of interests accounting requirements. The properties have historically earned approximately $200 million per year. REORGANIZATION COSTS In association with the merger between Exxon and Mobil, $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 2000 and 1999, respectively. Cumulative charges included separation expenses related to workforce reductions (approximately 6,000 employees at year-end 2000) and merger closing and implementation costs. The separation reserve balance at year-end 2000 of approximately $320 million is expected to be expended in 2001. Merger related expenses are expected to grow to approximately $2.5 billion pre-tax on a cumulative basis by 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 $4.6 billion per year by 2002. In the first quarter of 1999 the corporation recorded a $120 million after- tax charge for the 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. Manpower reduction savings associated with this reorganization are approximately $50 million per year after-tax in 2000. As indicated in note 4, during 1998 Mobil implemented reorganization programs in Australia, New Zealand and Latin America to integrate regional fuels and lubes operations. In 1997, Mobil and BP announced that their European downstream alliance would implement a major reorganization of its lubricant base oil refining business. Also in 1997, Mobil commenced two major cost savings initiatives in Asia-Pacific: one in Japan in response to the deregulated business environment and the other in Australia. After-tax costs for programs initiated in 1998 were $41 million and for the 1997 programs were $189 million. Benefits associated with these undertakings are estimated at $140 million per year after-tax. The following table summarizes the activity in the reorganization reserves. The 1998 opening balance represents accruals for provisions taken in prior years. Opening Balance at Balance Additions Deductions Year End ___________________________________________________________________________ (millions of dollars) 1998 $300 $ 50 $181 $169 1999 169 563 351 381 2000 381 738 780 339 CAPITAL AND EXPLORATION EXPENDITURES Capital and exploration expenditures in 2000 were $11.2 billion, down from $13.3 billion in 1999, primarily reflecting timing of completion of major project expenditures. Upstream spending was down 18 percent to $6.9 billion in 2000, from $8.4 billion in 1999, as a result of the completion of major projects in the North Sea, Canada and South America, and lower exploration expenses. Capital investments in the downstream totaled $2.6 billion in 2000, up $0.2 billion from 1999, primarily reflecting increased investments in China and higher spending at U.S. refineries. The increase was largely offset by lower spending in the European Fuels Joint Venture with BP which was divested in 2000 as a condition of regulatory approval of the merger, and lower spending in the retail businesses. Chemicals capital expenditures were $1.5 billion in 2000, down from $2.2 billion in 1999, due to the completion of major projects in the United States, Singapore, Saudi Arabia, and Thailand. Capital and exploration expenditures in the U.S. totaled $3.3 billion in 2000, a decrease of $0.1 billion from 1999, reflecting higher spending in both the upstream and downstream, offset by lower spending in chemicals. Spending outside the U.S. of $7.9 billion in 2000 compared with $9.9 billion in 1999, reflecting lower expenditures in the upstream and chemicals. Firm commitments related to capital projects totaled approximately $4.6 billion at the end of 2000, the same as at year-end 1999. The largest single commitment in 2000 was $2.3 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 internally generated funds. MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES In the past, crude, 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 chemical operations have been varied, tending at times to be offsetting. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally 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 23 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 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. In addition, the corporation has had an aggressive 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. 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. As a result, the corporation makes limited use of derivatives to offset exposures arising from existing transactions. Interest rate, foreign exchange rate and commodity price exposures from the contracts undertaken in accordance with the corporation's policies have not been significant. Derivative instruments are not held for trading purposes nor do they have leveraged features. Debt-Related Instruments The corporation is exposed to changes in interest rates, primarily as a result of its short-term and long-term debt with both fixed and 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 1998, the Financial Accounting Standards Board released Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities." Statement No. 133, as amended by Statements No. 137 and 138, must be adopted by the corporation no later than January 1, 2001. The statement establishes accounting and reporting standards for derivative instruments. It requires that all derivatives be recognized as either assets or liabilities in the financial statements and measured at fair value. It establishes the accounting for changes in the fair value of the derivatives depending on their intended use. Since the corporation makes very limited use of derivatives, the effect of adoption on the corporation's operations or financial condition will be negligible. 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 ExxonMobil's 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 $311 million in 2000, $219 million in 1999 and $240 million in 1998. At the end of 2000, 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. 24 In 2000, the corporation spent $1,529 million (of which $393 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 $1.8 billion in both 2001 and 2002 (with capital expenditures representing about 25 percent of the total). TAXES 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. Income, excise and all other taxes and duties totaled $61.5 billion in 1999, an increase of $1.6 billion or 3 percent from 1998. Income tax expense, both current and deferred, was $3.2 billion compared to $3.9 billion in 1998, reflecting lower pre-tax income in 1999, the impact of lower foreign tax rates and favorable resolution of tax-related issues. The effective tax rate was 31.8 percent in 1999 versus 35.2 percent in 1998. Excise and all other taxes and duties increased $2.3 billion to $58.3 billion, reflecting higher prices. LIQUIDITY AND CAPITAL RESOURCES 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 $1.687 per share to $1.760 per share and totaled $6.1 billion, a payout of 35 percent. Total consolidated debt declined by $5.6 billion to $13.4 billion. Shareholders' equity increased by $7.3 billion to $70.8 billion. The ratio of debt to capital decreased to 15 percent, reflecting lower debt levels and the higher shareholders' equity balance. 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 27.0 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 3,477 million at the end of 1999 to 3,465 million at the end of 2000. Purchases were made in both the open market and through negotiated transactions, and may be discontinued at any time. In 1999, cash provided by operating activities totaled $15.0 billion, down $1.4 billion from 1998. Major sources of funds were net income of $7.9 billion and non-cash provisions of $8.3 billion for depreciation and depletion. Cash used in investing activities totaled $11.0 billion, down $1.0 billion from 1998 primarily as a result of lower additions to property, plant and equipment, partly offset by lower sales of subsidiaries and property, plant and equipment. Cash used in financing activities was $4.8 billion, down $2.4 billion, primarily due to fewer common share purchases. Dividend payments on common shares increased from $1.666 per share to $1.687 per share and totaled $5.8 billion, a payout of 74 percent. Total consolidated debt increased by $2.0 billion to $19.0 billion. Shareholders' equity increased by $1.3 billion to $63.5 billion. The ratio of debt to capital increased to 22 percent, reflecting higher debt levels. During 1999, Exxon purchased 8.3 million shares of its common stock for the treasury at a cost of $648 million. These purchases were used to offset shares issued in conjunction with the company's benefit plans and programs. Purchases were made both in the open market and through negotiated transactions. Consistent with pooling of interest accounting requirements, these repurchases were terminated effective with the close of the ExxonMobil merger on November 30, 1999. Previously, as a consequence of the then proposed merger of Exxon and Mobil announced on December 1, 1998, both companies' repurchase programs to reduce the number of shares outstanding were discontinued. 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. As discussed in note 14 to the consolidated financial statements, the corporation's financial derivative activities are limited to simple risk management strategies. The corporation does not trade in financial derivatives nor does it use financial 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. 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. Essentially all of these lawsuits have now been resolved or are subject to appeal. 25 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS On September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5.058 billion in the Exxon Valdez civil trial that began in May 1994. 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 has appealed the judgment. The United States Court of Appeals for the Ninth Circuit heard oral arguments on the appeal on May 3, 1999. The corporation continues to believe that the punitive damages in this case are unwarranted and that the judgment should be set aside or substantially reduced by the appellate courts. 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. ExxonMobil will challenge the verdict and believes that the verdict is unwarranted and that the judgment should be set aside or substantially reduced. 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. Ultimate resolution of these issues and several other tax and legal issues, notably final resolution of royalty recovery and tax issues related to the gas lifting imbalance in the Common Area (along the German/Dutch border), is not expected to have a materially adverse effect upon the corporation's operations, financial condition or liquidity. 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. THE EURO On January 1, 1999, eleven European countries established fixed conversion rates between their existing sovereign currencies ("legacy currencies") and adopted the euro as their common legal currency. The euro and the legacy currencies are each legal tender for transactions now. Beginning January 1, 2002, the participating countries will issue euro-denominated bills and coins. By July 1, 2002 each country will withdraw its sovereign currency and transactions thereafter will be conducted solely in euros. Based on work to date, the conversion to the euro is not expected to have a material effect on the corporation's operations, financial condition or liquidity. FORWARD-LOOKING STATEMENTS Statements in this discussion regarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including merger related expenses; synergy benefits from the merger (including cost savings, efficiency gains and revenue enhancements); 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. These factors include management's ability to implement merger plans successfully and on schedule; the outcome of commercial negotiations; changes in the supply of and demand for crude oil, natural gas, and petroleum and petro-chemical products; and other factors discussed above and under the caption "Factors Affecting Future Results" in Item 1 of ExxonMobil's 2000 Form 10-K. 26 REPORT OF INDEPENDENT ACCOUNTANTS [LOGO OF PRICEWATERHOUSECOOPERS LLC] Dallas, Texas February 28, 2001 To the Shareholders of Exxon Mobil Corporation In our opinion, based on our audits and the report of other auditors, the consolidated financial statements appearing on pages 28 through 50 present fairly, in all material respects, the financial position of Exxon Mobil Corporation and its subsidiary companies at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, 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. The consolidated financial statements give retroactive effect to the merger of Mobil Corporation on November 30, 1999 in a transaction accounted for as a pooling of interests, as described in note 3 to the consolidated financial statements. We did not audit the financial statements of Mobil Corporation, which statements reflect total revenues of $53,531 million for the year ended December 31, 1998. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for Mobil Corporation, is based solely on the report of the other auditors. 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 and the report of the other auditors provide a reasonable basis for our opinion. As discussed in note 2 to the consolidated financial statements, the corporation changed its method of accounting for the cost of start-up activities in 1998. /s/ PRICEWATERHOUSECOOPERS LLP 27 CONSOLIDATED STATEMENT OF INCOME
2000 1999 1998 ______________________________________________________________________________________________________________________ (millions of dollars) Revenue Sales and other operating revenue, including excise taxes $228,439 $182,529 $165,627 Earnings from equity interests and other revenue 4,309 2,998 4,015 -------------------------- Total revenue $232,748 $185,527 $169,642 -------------------------- Costs and other deductions Crude oil and product purchases $108,951 $ 77,011 $ 62,145 Operating expenses 18,135 16,806 17,666 Selling, general and administrative expenses 12,044 13,134 12,925 Depreciation and depletion 8,130 8,304 8,355 Exploration expenses, including dry holes 936 1,246 1,506 Merger related expenses 1,406 625 -- Interest expense 589 695 568 Excise taxes 22,356 21,646 20,926 Other taxes and duties 32,708 34,765 33,203 Income applicable to minority and preferred interests 412 145 265 -------------------------- Total costs and other deductions $205,667 $174,377 $157,559 -------------------------- Income before income taxes $ 27,081 $ 11,150 $ 12,083 Income taxes 11,091 3,240 3,939 -------------------------- Income before extraordinary item and cumulative effect of accounting change $ 15,990 $ 7,910 $ 8,144 Extraordinary gain from required asset divestitures, net of income tax 1,730 -- -- Cumulative effect of accounting change -- -- (70) -------------------------- Net income $ 17,720 $ 7,910 $ 8,074 ========================== Net income per common share (dollars) Before extraordinary item and cumulative effect of accounting change $ 4.60 $ 2.28 $ 2.33 Extraordinary gain, net of income tax 0.50 -- -- Cumulative effect of accounting change -- -- (0.02) -------------------------- Net income $ 5.10 $ 2.28 $ 2.31 -------------------------- Net income per common share -- assuming dilution (dollars) Before extraordinary item and cumulative effect of accounting change $ 4.55 $ 2.25 $ 2.30 Extraordinary gain, net of income tax 0.49 -- -- Cumulative effect of accounting change -- -- (0.02) -------------------------- Net income $ 5.04 $ 2.25 $ 2.28 --------------------------
The information on pages 32 through 50 is an integral part of these statements. 28 CONSOLIDATED BALANCE SHEET
Dec. 31 Dec. 31 2000 1999 _____________________________________________________________________________________________________________________ (millions of dollars) Assets Current assets Cash and cash equivalents $ 7,080 $ 1,688 Other marketable securities 1 73 Notes and accounts receivable, less estimated doubtful amounts 22,996 19,155 Inventories Crude oil, products and merchandise 7,244 7,370 Materials and supplies 1,060 1,122 Prepaid taxes and expenses 2,018 1,733 ------------------- Total current assets $ 40,399 $ 31,141 Investments and advances 12,618 14,544 Property, plant and equipment, at cost, less accumulated depreciation and depletion 89,829 94,043 Other assets, including intangibles, net 6,154 4,793 ------------------- Total assets $149,000 $ 144,521 =================== Liabilities Current liabilities Notes and loans payable $ 6,161 $ 10,570 Accounts payable and accrued liabilities 26,755 25,492 Income taxes payable 5,275 2,671 ------------------- Total current liabilities $ 38,191 $ 38,733 Long-term debt 7,280 8,402 Annuity reserves and accrued liabilities 11,934 12,902 Deferred income tax liabilities 16,442 16,251 Deferred credits 1,166 1,079 Equity of minority and preferred shareholders in affiliated companies 3,230 3,688 ------------------- Total liabilities $ 78,243 $ 81,055 ------------------- Shareholders' equity Benefit plan related balances $ (235) $ (298) Common stock without par value (4,500 million shares authorized) 3,661 3,403 Earnings reinvested 86,652 75,055 Accumulated other nonowner changes in equity Cumulative foreign exchange translation adjustment (4,862) (2,300) Minimum pension liability adjustment (310) (299) Unrealized gains/(losses) on stock investments (17) 31 Common stock held in treasury (545 million shares in 2000 and 533 million shares in 1999) (14,132) (12,126) ------------------- Total shareholders' equity $ 70,757 $ 63,466 ------------------- Total liabilities and shareholders' equity $149,000 $ 144,521 ===================
The information on pages 32 through 50 is an integral part of these statements. 29 CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
2000 1999 1998 _____________________________________________________________________ Nonowner Nonowner Nonowner Changes Changes Changes Shareholders' in Shareholders' in Shareholders' in Equity Equity Equity Equity Equity Equity _____________________________________________________________________ (millions of dollars) Class A preferred stock outstanding at end of year $ -- $ -- $ 105 Class B preferred stock outstanding at end of year -- -- 641 Benefit plan related balances (235) (298) (793) Common stock (see note 12) At beginning of year 3,403 4,870 4,766 Issued -- 92 104 Other 258 303 -- Cancellation of common stock held in treasury -- (1,862) -- --------- --------- --------- At end of year $ 3,661 $ 3,403 $ 4,870 --------- --------- --------- Earnings reinvested At beginning of year 75,055 75,109 72,875 Net income for the year 17,720 $17,720 7,910 $7,910 8,074 $8,074 Dividends -- common and preferred shares (6,123) (5,872) (5,840) Cancellation of common stock held in treasury -- (2,092) -- --------- --------- --------- At end of year $ 86,652 $ 75,055 $ 75,109 --------- --------- --------- Accumulated other nonowner changes in equity At beginning of year (2,568) (1,981) (1,940) Foreign exchange translation adjustment (2,562) (2,562) (727) (727) 367 367 Minimum pension liability adjustment (11) (11) 109 109 (408) (408) Unrealized gains/(losses) on stock investments (48) (48) 31 31 -- -- --------- --------- --------- At end of year $ (5,189) $ (2,568) $ (1,981) --------- ------- --------- ------ --------- ------ Total $15,099 $7,323 $8,033 ======= ====== ====== Common stock held in treasury At beginning of year (12,126) (15,831) (12,881) Acquisitions, at cost (2,352) (976) (3,523) Dispositions 346 727 573 Cancellation, returned to unissued -- 3,954 -- --------- --------- --------- At end of year $ (14,132) $ (12,126) $ (15,831) --------- --------- --------- Shareholders' equity at end of year $ 70,757 $ 63,466 $ 62,120 ========= ========= =========
Share Activity ________________________________________________________ 2000 1999 1998 ________________________________________________________ (millions of shares) Class A preferred stock -- -- 2 Class B preferred stock -- -- 0.2 Common stock Issued (see note 12) At beginning of year 4,010 4,169 4,164 Issued -- 4 5 Cancelled -- (163) -- --------- --------- --------- At end of year 4,010 4,010 4,169 --------- --------- --------- Held in treasury (see note 12) At beginning of year (533) (711) (674) Acquisitions, at cost (27) (17) (53) Dispositions 15 32 16 Cancellation, returned to unissued -- 163 -- --------- --------- --------- At end of year (545) (533) (711) --------- --------- --------- Common shares outstanding at end of year 3,465 3,477 3,458 ========= ========= =========
The information on pages 32 through 50 is an integral part of these statements. 30 CONSOLIDATED STATEMENT OF CASH FLOWS
2000 1999 1998 ________________________________________________________________________________________________________________________________ (millions of dollars) Cash flows from operating activities Net income Accruing to ExxonMobil shareholders $ 17,720 $ 7,910 $ 8,074 Accruing to minority and preferred interests 412 145 265 Adjustments for non-cash transactions Depreciation and depletion 8,130 8,304 8,355 Deferred income tax charges/(credits) 10 (1,439) 318 Annuity and accrued liability provisions (662) 412 (251) Dividends received greater than/(less than) equity in current earnings of equity companies (387) 146 328 Extraordinary gain from required asset divestitures, before income tax (2,038) -- -- Changes in operational working capital, excluding cash and debt Reduction/(increase) -- Notes and accounts receivable (4,832) (3,478) 2,170 -- Inventories (297) 50 438 -- Prepaid taxes and expenses (204) 177 8 Increase/(reduction) -- Accounts and other payables 5,411 3,046 (3,010) All other items -- net (326) (260) (259) ---------------------------- Net cash provided by operating activities $ 22,937 $ 15,013 $ 16,436 ---------------------------- Cash flows from investing activities Additions to property, plant and equipment $ (8,446) $(10,849) $(12,730) Sales of subsidiaries, investments and property, plant and equipment 5,770 972 1,884 Additional investments and advances (1,648) (1,476) (1,469) Collection of advances 985 387 336 Additions to other marketable securities (41) (61) (61) Sales of other marketable securities 82 42 58 ---------------------------- Net cash used in investing activities $ (3,298) $(10,985) $(11,982) ---------------------------- Net cash generation before financing activities $ 19,639 $ 4,028 $ 4,454 ---------------------------- Cash flows from financing activities Additions to long-term debt $ 238 $ 454 $ 1,384 Reductions in long-term debt (901) (341) (305) Additions to short-term debt 500 1,870 930 Reductions in short-term debt (2,413) (2,359) (2,175) Additions/(reductions) in debt with less than 90 day maturity (3,129) 2,210 2,384 Cash dividends to ExxonMobil shareholders (6,123) (5,872) (5,843) Cash dividends to minority interests (251) (219) (387) Changes in minority interests and sales/(purchases) of affiliate stock (227) (200) (84) Common stock acquired (2,352) (670) (3,547) Common stock sold 493 348 507 ---------------------------- Net cash used in financing activities $(14,165) $ (4,779) $ (7,136) ---------------------------- Effects of exchange rate changes on cash $ (82) $ 53 $ 23 ---------------------------- Increase/(decrease) in cash and cash equivalents $ 5,392 $ (698) $ (2,659) Cash and cash equivalents at beginning of year 1,688 2,386 5,045 ---------------------------- Cash and cash equivalents at end of year $ 7,080 $ 1,688 $ 2,386 ============================
The information on pages 32 through 50 is an integral part of these statements. 31 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Exxon Mobil Corporation. 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. 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. As discussed in footnote 14, the corporation makes limited use of derivative instruments to hedge its exposures associated with interest rates, foreign currency exchange rates and hydrocarbon prices. Gains and losses on hedging contracts are recognized concurrent with the recognition of the economic impact of the underlying exposures using either the accrual or deferral method of accounting. In order to qualify for hedge accounting, the derivative instrument must be designated and effective as a hedge. The accrual method is used for interest rate swaps, cross-currency interest rate swaps and commodity swaps. Under the accrual method, differentials in the swapped amounts are recorded as adjustments of the underlying periodic cash flows that are being hedged. If these swaps are terminated, the gains and losses are amortized over the original lives of such contracts. The deferral method is used for futures exchange contracts, forward contracts and commodity swaps. Gains and losses resulting from changes in value of derivative instruments are deferred and recognized in the same period as the gains and losses of the items being hedged. Cash flow from derivative instruments that qualify for hedge accounting is included in the same category for cash flow purposes as the item being hedged. 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 could 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. Environmental Conservation and Site Restoration Costs. 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. 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. 32 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. 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 2000 included a net after-tax gain of $1,730 million (net of $308 million of income taxes), or $0.49 per common share -- assuming dilution, from asset divestments that were required as a condition of the regulatory approval of the Merger. The net after-tax gain on required divestments was reported as an extraordinary item according to accounting requirements for business combinations accounted for as a pooling of interests. Effective as of January 1, 1998, the corporation adopted the American Institute of Certified Public Accountants' Statement of Position 98-5, "Reporting on the Costs of Start-up Activities." This statement requires that costs of start-up activities and organizational costs be expensed as incurred. The cumulative effect of this accounting change on years prior to 1998 was a charge of $70 million (net of $70 million income tax effect), or $0.02 per common share. 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. The following table sets forth summary data for the separate companies and the combined amounts for periods prior to the Merger. Nine Months Year Ended Ended Sept. 30 Dec. 31 1999 1998 _______________________________________________________________________________ (millions of dollars) Revenues Exxon $ 89,378 $117,772 Mobil 42,782 53,531 Adjustments (1) 6,033 7,987 Eliminations (7,248) (9,648) ------------------ ExxonMobil $130,945 $169,642 ================== Net Income Exxon $ 3,725 $ 6,370 Mobil 1,901 1,704 ------------------ ExxonMobil $ 5,626 $ 8,074 ================== (1) Consolidation of activities previously accounted for using the equity method of accounting. 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. These assets, with a carrying value of approximately $3 billion, were sold in the year 2000. The net after-tax gain of $1,730 million was reported as an extraordinary item. The properties have historically earned approximately $200 million per year. 4. Reorganization Costs In association with the Merger, $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 2000 and 1999, respectively. Cumulative charges included separation expenses of approximately $1,125 million related to workforce reductions (approximately 6,000 employees at year-end 2000), plus implementation and merger closing costs. The separation reserve balance at year end 2000 of approximately $320 million, is expected to be expended in 2001. 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. Substancially 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 33 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS depreciation and depletion for the write-off of costs associated with the cancellation of a power plant project at the Kawasaki terminal. In 1998, Mobil implemented new reorganization programs in Australia and New Zealand and in Latin America to integrate regional fuels and lubes operations. These programs resulted in the elimination of approximately 500 positions as well as asset write-downs in Australia and New Zealand. A provision of $50 million ($41 million after-tax) was recorded in selling, general and administrative expenses and depreciation and depletion for these programs. In 1998 and 1999, a combination of cash for employee separation benefits and exit costs and noncash costs for the closure of facilities essentially depleted the reserve. In 1997, Mobil and BP announced that their alliance would implement a major restructuring of its lubricant base oil refining business. This program resulted in the elimination of approximately 460 positions and in write-downs and closure of certain facilities and was completed by the end of 1999. Reserves were recorded in 1997 of about $86 million ($82 million after-tax) mainly for employee severance costs associated with workforce reductions and for write-downs and closure of certain facilities. These costs were recorded in earnings from equity interests and selling, general and administrative expenses. Cash outlays have been approximately $70 million and non-cash costs about $20 million. There was no amount remaining in this reserve at December 31, 2000, for this program. Also in 1997, Mobil commenced two major cost savings initiatives in Asia- Pacific -- one in Japan in response to the deregulated business environment and the other in Australia. These programs resulted in the elimination of approximately 400 positions and the impairment of certain assets. In 1997, reserves were recorded in the amount of $172 million ($107 million after-tax) primarily for separation costs related to workforce reductions and for closure of certain facilities. The provisions were recorded in selling, general and administrative expenses; operating expenses; earnings from equity interests and other revenue and depreciation and depletion. At the end of 2000 the reserve was essentially depleted. The following table summarizes the activity in the reorganization reserves. The 1998 opening balance represents accruals for provisions taken in prior years. Opening Balance at Balance Additions Deductions Year End _______________________________________________________________________________ (millions of dollars) 1998 $300 $ 50 $181 $169 1999 169 563 351 381 2000 381 738 780 339 5. Miscellaneous Financial Information Research and development costs totaled $564 million in 2000, $630 million in 1999 and $753 million in 1998. Net income included aggregate foreign exchange transaction losses of $236 million in 2000 and $5 million in 1999, and gains of $20 million in 1998. In 2000, 1999, and 1998, net income included gains of $175 million, and losses of $7 million and $8 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 $6,706 million and $5,898 million at December 31, 2000 and 1999, respectively. In 1998, Mobil recorded a charge of $325 million before-tax ($270 million after-tax) to adjust certain inventories to their market value. Also in 1998, a charge of $491 million before-tax ($387 million after-tax) was recorded by Mobil to write down certain oil and gas properties to fair value. 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: 2000 -- $729 million, 1999 -- $882 million and 1998 -- $1,066 million. Cash payments for income taxes were: 2000 -- $8,671 million, 1999 -- $3,805 million and 1998 -- $4,629 million. 7. Additional Working Capital Data Dec. 31 Dec. 31 2000 1999 _______________________________________________________________________________ (millions of dollars) Notes and accounts receivable Trade, less reserves of $258 million and $231 million $ 17,568 $ 14,605 Other, less reserves of $48 million and $10 million 5,428 4,550 ----------------------- $ 22,996 $19,155 ======================= Notes and loans payable Bank loans $ 1,244 $ 2,223 Commercial paper 3,761 7,231 Long-term debt due within one year 650 407 Other 506 709 ----------------------- $ 6,161 $10,570 ======================= Accounts payable and accrued liabilities Trade payables $ 15,357 $13,524 Obligations to equity companies 586 608 Accrued taxes other than income taxes 5,423 6,005 Other 5,389 5,355 ----------------------- $ 26,755 $25,492 ======================= On December 31, 2000, unused credit lines for short-term financing totaled approximately $6.7 billion. Of this total, $3.3 billion support commercial paper programs under terms negotiated when drawn. The weighted average interest rate on short-term borrowings outstanding at December 31, 2000 and 1999 was 6.4 percent and 5.6 percent, respectively. 34 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; 1998 and 1999 included amounts related to Mobil's European Fuels joint venture which was divested as a condition of the Merger approval.
2000 1999 1998 _____________________________________________________ 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 7% in 1998, 8% in 1999 and 11% in 2000 $81,371 $32,452 $94,534 $32,124 $76,552 $24,740 ----------------------------------------------------- Income before income taxes $ 7,632 $ 3,092 $ 4,100 $ 2,095 $ 4,104 $ 2,002 Less: Related income taxes (1,382) (658) (734) (449) (1,071) (492) ----------------------------------------------------- Net income $ 6,250 $ 2,434 $ 3,366 $ 1,646 $ 3,033 $ 1,510 ===================================================== Current assets $28,784 $11,479 $21,518 $ 7,739 $19,037 $ 6,645 Property, plant and equipment, less accumulated depreciation 36,553 13,733 44,213 15,509 40,268 15,221 Other long-term assets 6,656 2,979 4,806 2,106 3,529 1,449 ----------------------------------------------------- Total assets $71,993 $28,191 $70,537 $25,354 $62,834 $23,315 ----------------------------------------------------- Short-term debt $ 2,636 $ 1,093 $ 2,856 $ 1,129 $ 2,628 $ 1,048 Other current liabilities 25,377 10,357 18,129 6,324 16,367 5,574 Long-term debt 11,116 4,094 13,486 3,978 11,316 3,488 Other long-term liabilities 7,054 3,273 5,372 2,598 4,974 2,362 Advances from shareholders 8,485 2,510 3,636 1,919 3,734 2,017 ----------------------------------------------------- Net assets $17,325 $ 6,864 $27,058 $ 9,406 $23,815 $ 8,826 =====================================================
9. Investments and Advances Dec. 31 Dec. 31 2000 1999 __________________________________________________________________________________________________________________________ (million of dollars) Companies carried at equity in underlying assets Investments $ 6,864 $ 9,406 Advances 2,510 1,919 ----------------- $ 9,374 $11,325 Companies carried at cost or less and stock investments carried at fair value 1,230 964 ----------------- $10,604 $12,289 Long-term receivables and miscellaneous investments at cost or less 2,014 2,255 ----------------- Total $12,618 $14,544 =================
35 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Investment in Property, Plant and Equipment Dec. 31, 2000 Dec. 31, 1999 ________________________________________________ Cost Net Cost Net _________________________________________________________________________________________________________________ (millions of dollars) Petroleum and natural gas Upstream $106,287 $ 45,731 $ 106,067 $ 48,100 Downstream 51,862 26,730 54,772 28,974 ------------------------------------------------ Total petroleum and natural gas $158,149 $ 72,461 $ 160,839 $ 77,074 Chemicals 17,860 9,935 17,564 9,969 Other 11,737 7,433 10,809 7,000 ------------------------------------------------ Total $187,746 $ 89,829 $ 189,212 $ 94,043 ================================================
Accumulated depreciation and depletion totaled $97,917 million at the end of 2000 and $95,169 million at the end of 1999. Interest capitalized in 2000, 1999 and 1998 was $641 million, $595 million and $545 million, respectively. ________________________________________________________________________________ 11. Leased Facilities At December 31, 2000, 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 2000, 1999 and 1998 totaled $1,935 million, $2,172 million and $2,760 million, respectively, after being reduced by related rental income of $195 million, $317 million and $331 million, respectively. Minimum rental expenditures totaled $1,992 million in 2000, $2,311 million in 1999 and $2,910 million in 1998. Minimum Related commitment rental income ________________________________________________________________________________ (millions of dollars) 2001 $ 1,219 $ 76 2002 814 65 2003 604 44 2004 462 29 2005 347 22 2006 and beyond 1,959 104 ________________________________________________________________________________ 12. Capital At the effective time of the merger of Exxon and Mobil, the authorized common stock of ExxonMobil was increased from three 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, Mobil sold 206 thousand shares of a new issue of Series B Convertible Preferred Stock to its employee stock ownership plan (Mobil ESOP) trust for $3,887.50 per share. Each preferred share was convertible into 100 shares of Mobil common stock. The proceeds of the issuance were used by Mobil for general corporate purposes. Dividends were cumulative and payable in an amount per share equal to $300 per annum. In connection with the merger, each outstanding share of Mobil's Series B Convertible Preferred Stock was converted into one share of ExxonMobil Class B Preferred Stock with similar terms. Each share of ExxonMobil Class B Preferred Stock was convertible into 132.015 shares of ExxonMobil common stock. In 1999 and 1998, Mobil Series B Convertible Preferred Stock totaling 6 thousand shares in each year were redeemed. In 1999, after the merger, 159 thousand shares of ExxonMobil Class B Preferred Stock totaling $618 million were converted to ExxonMobil common stock. No shares of Class B Preferred Stock remain outstanding. 36 In 1989, Exxon sold 16.3 million shares of a new issue of convertible Class A Preferred Stock to its leveraged employee stock ownership plan (Exxon LESOP) trust for $61.50 per share. The proceeds of the issuance were used by Exxon for general corporate purposes. If the common share price exceeded $30.75, one share of Exxon Class A Preferred Stock was convertible into two shares of common stock. If the price was $30.75 or less, one share of preferred stock was convertible into common shares having a value of $61.50. Dividends were cumulative and payable in an amount per share equal to $4.680 per annum. In 1999 and 1998, 1.7 million and 1.4 million shares of Exxon Class A Preferred Stock totaling $105 million and $85 million, respectively, were converted to common stock. At year-end 1999, no shares of Class A Preferred Stock remained outstanding. In 1989, $1,800 million of benefit plan related balances were recorded as debt and as a reduction to shareholders' equity, representing Exxon and Mobil guaranteed borrowings by the Mobil ESOP and Exxon LESOP trusts to purchase preferred stock. As the debt is repaid and common shares are earned by employees, the benefit plan related balances are being extinguished. Preferred dividends of $36 million and $60 million were paid during 1999 and 1998, respectively. The table below summarizes the earnings per share calculations. 2000 1999 1998 ________________________ Net income per common share - - - - - - --------------------------- Income before extraordinary item and cumulative effect of accounting change (millions of dollars) $15,990 $7,910 $ 8,144 Less: Preferred stock dividends -- (36) (60) ------------------------ Income available to common shares $15,990 $7,874 $ 8,084 ======================== Weighted average number of common shares outstanding (millions of shares) 3,477 3,453 3,468 Net income per common share Before extraordinary item and cumulative effect of accounting change $ 4.60 $ 2.28 $ 2.33 Extraordinary gain, net of income tax 0.50 -- -- Cumulative effect of accounting change -- -- (0.02) ------------------------ Net income $ 5.10 $ 2.28 $ 2.31 ======================== Net income per common share -- assuming dilution - - - - - - ------------------------------------------------ Income before extraordinary item and cumulative effect of accounting change (millions of dollars) $15,990 $7,910 $ 8,144 Adjustment for assumed dilution (8) 1 (7) ------------------------ Income available to common shares $15,982 $7,911 $ 8,137 ======================== Weighted average number of common shares outstanding (millions of shares) 3,477 3,453 3,468 Plus: Issued on assumed exercise of stock options 40 44 39 Plus: Assumed conversion of preferred stock -- 21 26 ------------------------ Weighted average number of common shares outstanding 3,517 3,518 3,533 ======================== Net income per common share Before extraordinary item and cumulative effect of accounting change $ 4.55 $ 2.25 $ 2.30 Extraordinary gain, net of income tax 0.49 -- -- Cumulative effect of accounting change -- -- (0.02) ------------------------ Net income $ 5.04 $ 2.25 $ 2.28 ======================== Dividends paid per common share $ 1.760 $1.687 $ 1.666
37 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. 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 maturing between 1990 and 1999. As further described in note 12, 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 matured in 1999 with the final principal payment of the outstanding debt. 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 ESOP) trust borrowed $800 million under the terms of notes and debentures guaranteed by Mobil. As further described in note 12, 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 outstanding shares of Class B Preferred Stock were converted to ExxonMobil common shares. The Exxon LESOP and Mobil ESOP were merged in late 1999 to create the ExxonMobil ESOP. Employees eligible to participate in ExxonMobil's Savings Plan may elect to participate in the ExxonMobil ESOP. Corporate contributions to the plan and dividends are used to make principal and interest payments on the notes and debentures. As contributions and dividends are credited, common shares are allocated to participants' accounts. When debt service exceeded dividends, ExxonMobil funded the excess. The excess for the ExxonMobil ESOP was $15 million, $19 million, and $15 million in 2000, 1999, and 1998, respectively. Accounting for the plans has followed the principles which 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 not significant. The ExxonMobil ESOP trust held 59.9 million shares of ExxonMobil common stock at the end of 1999 and 54.6 million shares at the end of 2000. 14. Financial Instruments 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, 2000 and 1999, was $8.0 billion and $8.9 billion, respectively, as compared to recorded book values of $7.3 billion and $8.4 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 rate, foreign currency rate and commodity prices. As a result, the corporation makes limited use of derivatives to offset exposures arising from existing transactions. Derivative instruments are not held for trading purposes nor do they have leveraged features. In addition, they are either purchased or sold over authorized exchanges or with counterparties of high credit standing. As a result of the above factors, the corporation's exposure to credit risks and market risks from derivative activities is negligible. The notional principal amounts of derivative financial instruments at December 31, are as follows: At December 31: 2000 1999 _______________ ____ ____ (millions of dollars) Debt-related instruments $ 970 $2,111 Nondebt-related foreign currency exchange rate instruments 63 4,245 Commodity financial instruments requiring cash settlement 1,367 1,988 ------------------- Total $2,400 $8,344 =================== 38 15. Long-Term Debt At December 31, 2000, long-term debt consisted of $6,630 million due in U.S. dollars and $650 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 $650 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, 2001, in millions of dollars, are: 2002 -- $368, 2003 - - - - - - -- $832, 2004 -- $2,245 and 2005 -- $359. Certain of the borrowings described may from time to time be assigned to other ExxonMobil affiliates. At December 31, 2000, the corporation's unused long-term credit lines were not material. The total outstanding balance of defeased debt at year-end 2000 was $480 million. Summarized long-term borrowings at year-end 2000 and 1999 were as follows: 2000 1999 _______________________________________________________________________________ (millions of dollars) Exxon Mobil Corporation 7.45% Guaranteed notes due 2001 $ -- $ 246 Guaranteed zero coupon notes due 2004 -- Face value ($1,146) net of unamortized discount 749 671 Exxon Capital Corporation 6.0% Guaranteed notes due 2005 106 246 6.125% Guaranteed notes due 2008 175 250 SeaRiver Maritime Financial Holdings, Inc. Guaranteed debt securities due 2002-2011(1) 115 122 Guaranteed deferred interest debentures due 2012 -- Face value ($771) net of unamortized discount plus accrued interest 811 728 Imperial Oil Limited 8.3% notes due 2001 -- 200 Variable rate notes due 2004(2) 600 600 Mobil Oil Canada, Ltd. 3.0% Swiss franc debentures due 2003(3) 331 331 5.0% U.S. dollar Eurobonds due 2004(4) 274 300 Mobil Producing Nigeria Unlimited 8.625% notes due 2002-2006 188 229 Mobil Corporation 8.625% debentures due 2021 247 247 7.625% debentures due 2033 203 213 Industrial revenue bonds due 2003-2033(5) 1,469 1,429 ESOP Trust notes due 2002-2003 100 351 Other U.S. dollar obligations(6) 1,062 1,045 Other foreign currency obligations 598 924 Capitalized lease obligations(7) 252 270 ----------------- Total long-term debt $7,280 $8,402 ================= 1. Average effective interest rate of 6.4% in 2000 and 5.3% in 1999. 2. Average effective interest rate of 6.6% in 2000 and 5.3% in 1999. 3. Swapped into floating rate U.S.$ debt. 4. Swapped principally into floating rate debt. 5. Average effective interest rate of 4.5% in 2000 and 4.0% in 1999. 6. Average effective interest rate of 7.8% in 2000 and 7.6% in 1999. 7. Average imputed interest rate of 7.2% in 2000 and 7.2% in 1999. 39 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Condensed consolidating financial information related to guaranteed securities issued by subsidiaries Exxon Mobil Corporation has fully and unconditionally guaranteed the 6.0% notes due 2005 and the 6.125% notes due 2008 of Exxon Capital Corporation and the deferred interest debentures due 2012 and the debt securities due 2000-2011 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.
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 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 and accounting change 15,990 53 15 13,634 (13,702) 15,990 Extraordinary gain, net of income tax 1,730 -- -- 962 (962) 1,730 Cumulative effect of accounting change -- -- -- -- -- -- --------------------------------------------------------------------------------- Net income $ 17,720 $ 53 $ 15 $ 14,596 $ (14,664) $ 17,720 =================================================================================
40
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 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 and accounting change 7,910 100 6 6,651 (6,757) 7,910 Extraordinary gain, net of income tax -- -- -- -- -- -- Cumulative effect of accounting change -- -- -- -- -- -- -------------------------------------------------------------------------- Net income $ 7,910 $ 100 $ 6 $ 6,651 $ (6,757) $ 7,910 ========================================================================== Condensed consolidated statement of income for twelve months ended December 31, 1998 ____________________________________________________________________________________ Revenue Sales and other operating revenue, including excise taxes $22,508 $ -- $ -- $143,119 $ -- $165,627 Earnings from equity interests and other revenue 8,256 207 36 3,372 (7,856) 4,015 Intercompany revenue 1,199 1,221 60 20,448 (22,928) -- -------------------------------------------------------------------------- Total revenue 31,963 1,428 96 166,939 (30,784) 169,642 -------------------------------------------------------------------------- Costs and other deductions Crude oil and product purchases 10,434 -- -- 69,729 (18,018) 62,145 Operating expenses 5,249 3 1 13,536 (1,123) 17,666 Selling, general and administrative expenses 1,902 (3) -- 11,026 -- 12,925 Depreciation and depletion 1,381 5 3 6,966 -- 8,355 Exploration expenses, including dry holes 239 -- -- 1,267 -- 1,506 Merger related expenses -- -- -- -- -- -- Interest expense 1,513 1,548 91 1,203 (3,787) 568 Excise taxes 2,743 -- -- 18,183 -- 20,926 Other taxes and duties 20 -- -- 33,183 -- 33,203 Income applicable to minority and preferred interests -- -- -- 265 -- 265 -------------------------------------------------------------------------- Total costs and other deductions 23,481 1,553 95 155,358 (22,928) 157,559 -------------------------------------------------------------------------- Income before income taxes 8,482 (125) 1 11,581 (7,856) 12,083 Income taxes 338 (29) (13) 3,643 -- 3,939 -------------------------------------------------------------------------- Income before extraordinary item and accounting change 8,144 (96) 14 7,938 (7,856) 8,144 Extraordinary gain, net of income tax -- -- -- -- -- -- Cumulative effect of accounting change (70) -- -- (39) 39 (70) -------------------------------------------------------------------------- Net income $ 8,074 $ (96) $ 14 $ 7,899 $ (7,817) $ 8,074 ==========================================================================
41 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 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 Other current assets 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 =========================================================================== Condensed consolidated balance sheet for year ended December 31,1999 ____________________________________________________________________ Cash and cash equivalents $ 112 $ -- $ -- $ 1,576 $ -- $ 1,688 Notes and accounts receivable -- net 2,968 -- -- 16,187 -- 19,155 Inventories 1,121 -- -- 7,371 -- 8,492 Other current assets 105 2 19 1,680 -- 1,806 --------------------------------------------------------------------------- Total current assets 4,306 2 19 26,814 -- 31,141 Investments and advances 68,065 -- 411 94,273 (148,205) 14,544 Property, plant and equipment -- net 19,037 118 12 74,876 -- 94,043 Other long-term assets 530 2 128 4,133 -- 4,793 Intercompany receivables 7,956 11,981 1,243 59,436 (80,616) -- --------------------------------------------------------------------------- Total assets $ 99,894 $12,103 $1,813 $259,532 $(228,821) $144,521 =========================================================================== Notes and loans payable $ 1,012 $ 57 $ 7 $ 9,494 $ -- $ 10,570 Accounts payable and accrued liabilities 4,900 14 2 20,576 -- 25,492 Income taxes payable 435 -- -- 2,236 -- 2,671 --------------------------------------------------------------------------- Total current liabilities 6,347 71 9 32,306 -- 38,733 Long-term debt 1,419 495 849 5,639 -- 8,402 Deferred income tax liabilities 3,232 33 289 12,697 -- 16,251 Other long-term liabilities 5,080 9 -- 12,580 -- 17,669 Intercompany payables 20,350 10,685 385 49,196 (80,616) -- --------------------------------------------------------------------------- Total liabilities 36,428 11,293 1,532 112,418 (80,616) 81,055 Earnings reinvested 75,055 4 (111) 28,258 (28,151) 75,055 Other shareholders' equity (11,589) 806 392 118,856 (120,054) (11,589) --------------------------------------------------------------------------- Total shareholders' equity 63,466 810 281 147,114 (148,205) 63,466 --------------------------------------------------------------------------- Total liabilities and shareholders' equity $ 99,894 $12,103 $1,813 $259,532 $(228,821) $144,521 ===========================================================================
42
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, 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 ========================================================================== 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) ==========================================================================
43 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, 1998 ________________________________________________________________________________________ Cash provided by/(used in) operating activities $ 13,969 $ (30) $ 99 $ 16,577 $(14,179) $ 16,436 ------------------------------------------------------------------------------- Cash flows from investing activities Additions to property, plant and equipment (2,157) -- -- (10,573) -- (12,730) Sales of long-term assets 181 -- -- 1,703 -- 1,884 Net intercompany investing (6,492) 8,172 (95) 4,597 (6,182) -- All other investing, net (26) -- -- (1,110) -- (1,136) ------------------------------------------------------------------------------- Net cash provided by/(used in) investing activities (8,494) 8,172 (95) (5,383) (6,182) (11,982) ------------------------------------------------------------------------------- Cash flows from financing activities Additions to short- and long-term debt 5 -- -- 2,309 -- 2,314 Reductions in short- and long-term debt (2) -- (7) (2,471) -- (2,480) Additions/(reductions) in debt with less than 90 day maturity 1,069 44 -- 1,271 -- 2,384 Cash dividends (5,843) (1,950) -- (12,229) 14,179 (5,843) Common stock acquired (3,547) -- -- -- -- (3,547) Net intercompany financing activity -- (6,236) 3 51 6,182 -- All other financing, net 507 -- -- (471) -- 36 ------------------------------------------------------------------------------- Net cash provided by/(used in) financing activities (7,811) (8,142) (4) (11,540) 20,361 (7,136) ------------------------------------------------------------------------------- Effects of exchange rate changes on cash -- -- -- 23 -- 23 ------------------------------------------------------------------------------- Increase/(decrease) in cash and cash equivalents $ (2,336) $ -- $ -- $ (323) $ -- $ (2,659) ===============================================================================
44 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 59,536 thousand at the beginning of 2000 and 42,303 thousand at the end of 2000. At December 31, 1999 and 2000, respectively, 1,077 thousand and 1,219 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 $296 million, or $0.08 per share in 2000; $149 million, or $0.04 per share in 1999 and $134 million, or $0.04 per share in 1998. For the ExxonMobil plan, the average fair value of each option granted during 2000, 1999, and 1998 was $20.36, $19.70 and $12.80, respectively. The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions for 2000, 1999 and 1998, respectively: risk-free interest rates of 5.5 percent, 6.2 percent and 4.8 percent; expected life of 6 years for all years; volatility of 16 percent, 15 percent and 13 percent and a dividend yield of 2.0 percent, 2.1 percent and 2.3 percent. For the Mobil plans, the average fair value of each Mobil option granted during 1999 and 1998 was $17.02 and $13.05, respectively. The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions for 1999 and 1998, respectively: risk-free interest rates of 5.2 percent and 5.7 percent; expected life of 5 years for both years; volatility of 20 percent and 18 percent and a dividend yield of 2.7 percent and 3.2 percent. Changes that occurred in options outstanding in 2000, 1999 and 1998 (including the former Mobil plans) are summarized below (shares in thousands):
2000 1999 1998 ________________________________________________________________________________ Avg. Exercise Avg. Exercise Avg. Exercise Shares Price Shares Price Shares Price ________________________________________________________________________________ Outstanding at beginning of year 121,116 $49.62 110,609 $42.03 112,341 $36.42 Granted 18,112 90.37 22,099 78.00 16,646 65.89 Exercised (14,357) 32.70 (11,250) 30.31 (17,907) 28.65 Expired/Canceled (531) 74.25 (342) 66.18 (471) 55.41 ------- ------- ------- Outstanding at end of year 124,340 57.40 121,116 49.62 110,609 42.03 Exercisable at end of year 97,572 51.89 87,472 42.16 83,258 36.76
The following table summarizes information about stock options outstanding, including those from former Mobil plans, at December 31, 2000 (shares in thousands):
Options Outstanding Options Exercisable _____________________________________________________________________ __________________________ Exercise Price Avg. Remaining Avg. Exercise Avg. Exercise Range Shares Contractual Life Price Shares Price _____________________________________________________________________ __________________________ $23.27-33.07 30,800 3.2 years $29.77 30,800 $29.77 38.12-55.42 33,329 6.2 years 45.80 29,819 44.84 58.36-90.44 60,211 8.7 years 77.96 36,953 76.02 ------ ------ Total 124,340 6.7 years 57.40 97,572 51.89
45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. Essentially all of these lawsuits have now been resolved or are subject to appeal. On September 24, 1996, the United States District Court for the District of Alaska entered a judgment in the amount of $5.058 billion in the Exxon Valdez civil trial that began in May 1994. 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 has appealed the judgment. The United States Court of Appeals for the Ninth Circuit heard oral arguments on the appeal on May 3, 1999. The corporation continues to believe that the punitive damages in this case are unwarranted and that the judgment should be set aside or substantially reduced by the appellate courts. 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 will make a final payment of $70 million in 2001. This payment, along with prior payments will be charged against the provision that was previously established to cover the costs of the settlement. German and Dutch affiliated companies are the concessionaires of a natural gas field subject to a treaty between the governments of Germany and the Netherlands under which the gas reserves in an undefined border or common area are to be shared equally. Entitlement to the reserves is determined by calculating the amount of gas which can be recovered from this area. Based on the final reserve determination, the German affiliate has received more gas than its entitlement. Arbitration proceedings, as provided in the agreements, were conducted to resolve issues concerning the compensation for the overlifted gas. By final award dated July 2, 1999, preceded by an interim award in 1996, an arbitral tribunal established the full amount of the compensation for the excess gas. This amount has now been paid and a petition to set the award aside has now been dismissed, rendering the award final in all respects. Other substantive matters remain outstanding, including recovery of royalties paid on such excess gas and the taxes payable on the final compensation amount. The net financial impact on the corporation is not possible to predict at this time. However, the ultimate outcome is not expected to 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. ExxonMobil will challenge the verdict and believes that the verdict is unwarranted and that the judgement should be set aside or substantially reduced. 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, 2000, for $2,184 million, primarily relating to guarantees for notes, loans and performance under contracts. This includes $770 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. Not included in this figure are guarantees by consolidated affiliates of $1,715 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 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. 46 18. Annuity Benefits and Other Postretirement Benefits
Annuity Benefits _________________________________________________________ Other Postretirement U.S. Non-U.S. Benefits ____________________________________________________________________________________ 2000 1999 1998 2000 1999 1998 2000 1999 1998 ____________________________________________________________________________________ (millions of dollars) Components of net benefit cost Service cost $ 214 $ 249 $ 229 $ 245 $ 312 $ 297 $ 24 $ 36 $ 34 Interest cost 592 555 549 603 608 625 201 190 191 Expected return on plan assets (726) (601) (622) (641) (599) (564) (51) (48) (41) Amortization of actuarial loss/(gain) and prior service cost (168) (36) (24) 55 167 111 -- 14 12 Net pension enhancement and curtailment/settlement expense (175) 1 1 77 50 (1) (5) -- -- ------------------------------------------------------------------------------------ Net benefit cost $ (263) $ 168 $ 133 $ 339 $ 538 $ 468 $169 $192 $ 196 ====================================================================================
Costs for defined contribution plans were $67 million, $69 million and $121 million in 2000, 1999 and 1998, respectively.
Annuity Benefits Other _____________________________________ Postretirement U.S. Non-U.S. Benefits ________________ __________________ ________________ 2000 1999 2000 1999 2000 1999 ________________________________________________________ (millions of dollars) Change in benefit obligation Benefit obligation at January 1 $ 8,032 $ 8,708 $11,628 $ 12,572 $ 2,620 $ 2,932 Service cost 214 249 245 312 24 36 Interest cost 592 555 603 608 201 190 Actuarial loss/(gain) 179 (746) 429 (948) 144 (333) Benefits paid (1,534) (859) (815) (814) (233) (259) Foreign exchange rate changes -- -- (811) (171) (8) 14 Other 168 125 (216) 69 194 40 -------------------------------------------------------- Benefit obligation at December 31 $ 7,651 $ 8,032 $ 11,063 $ 11,628 $ 2,942 $ 2,620 ======================================================== Change in plan assets Fair value at January 1 $ 7,965 $ 6,604 $ 8,689 $ 7,577 $ 568 $ 512 Actual return on plan assets 208 2,083 (12) 1,467 (30) 104 Foreign exchange rate changes -- -- (612) 14 -- -- Payments directly to participants 156 138 311 305 166 172 Company contribution -- -- 232 167 38 42 Benefits paid (1,534) (859) (815) (814) (233) (259) Other -- (1) (13) (27) (63) (3) -------------------------------------------------------- Fair value at December 31 $ 6,795 $ 7,965 $ 7,780 $ 8,689 $ 446 $ 568 ======================================================== Assets in excess of/(less than) benefit obligation Balance at December 31 $ (856) $ (67) $ (3,283) $ (2,939) $(2,496) $(2,052) Unrecognized net transition liability/(asset) (31) (102) 49 42 -- -- Unrecognized net actuarial loss/(gain) (788) (1,960) 507 (368) 35 (217) Unrecognized prior service cost 281 338 297 310 180 5 Intangible asset (12) (33) (82) (81) -- -- Equity of minority shareholders -- -- (36) (23) -- -- Minimum pension liability adjustment (163) (103) (422) (444) -- -- -------------------------------------------------------- Prepaid/(accrued) benefit cost $(1,569) $(1,927) $ (2,970) $ (3,503) $(2,281) $(2,264) ======================================================== Annuity assets and reserves in excess of accumulated benefit obligation $ 1,422 $ 2,833 $ 710 $ 1,760 -- -- Assumptions as of December 31 (percent) -------------------------------------------------------- Discount rate 7.5 7.75 3.0-7.0 3.0-7.3 7.5 7.75 Long-term rate of compensation increase 3.5 3.5 3.0-5.0 3.0-4.0 3.5 3.5 Long-term rate of return on funded assets 9.5 9.5 6.5-10.0 5.5-10.0 9.5 9.5
47 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The data shown on the previous page are reported as required by current accounting standards which specify use of a discount rate at which postretirement liabilities could be effectively settled. The discount rate stipulated for use in calculating year-end postretirement liabilities is based on the year-end rate of interest on high quality bonds. For determining the funding requirements of U.S. annuity plans in accordance with applicable federal government regulations, ExxonMobil uses the expected long-term rate of return of the annuity fund's actual portfolio as the discount rate. This rate has historically been higher than bonds as the majority of pension assets are invested in equities. In fact, the actual rate earned over the past decade has been 15 percent. On this basis, all funded U.S. plans meet the full funding requirements of the Department of Labor and the Internal Revenue Service as detailed in the table below. Certain smaller U.S. plans and a number of non- U.S. plans are not funded because of local tax conventions and regulatory practices which do not encourage funding of these plans. Book reserves have been established for these plans to provide for future benefit payments.
Status of U.S. annuity plans subject to federal government funding requirements 2000 1999 ________________________________________________________________________________________________________________ (millions of dollars) Funded assets at market value less total projected benefit obligation $ (856) $ (67) Differences between accounting and funding basis: Certain smaller plans unfunded due to lack of tax and regulatory incentives 884 874 Use of long-term rate of return on fund assets as the discount rate 981 1,061 Use of government required assumptions and other actuarial adjustments 364 (1,086) --------------- Funded assets in excess of obligations under government regulations $1,373 $ 782 ---------------
48 19. Income, Excise and Other Taxes
2000 1999 1998 ________________________________________________________________________________________________________________ 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 $ 2,635 $ 7,972 $10,607 $ 369 $ 3,973 $ 4,342 $ 801 $ 2,753 $ 3,554 Deferred -- net 433 (322) 111 214 (1,489) (1,275) 196 5 201 U.S. tax on non-U.S. operations 64 -- 64 25 -- 25 43 -- 43 ------------------------------------------------------------------------ $ 3,132 $ 7,650 $10,782 $ 608 $ 2,484 $ 3,092 $1,040 $ 2,758 $ 3,798 State 309 -- 309 148 -- 148 141 -- 141 ------------------------------------------------------------------------ Total income taxes $ 3,441 $ 7,650 $11,091 $ 756 $ 2,484 $ 3,240 $1,181 $ 2,758 $ 3,939 Excise taxes 6,997 15,359 22,356 7,795 13,851 21,646 7,459 13,467 20,926 All other taxes and duties 1,253 33,685 34,938 1,021 35,616 36,637 967 34,084 35,051 ------------------------------------------------------------------------ Total $11,691 $56,694 $68,385 $9,572 $51,951 $61,523 $9,607 $50,309 $59,916 ========================================================================
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 $84 million in 2000, $205 million in 1999 and $153 million in 1998. Income taxes (charged)/credited directly to shareholders' equity were:
2000 1999 1998 _______________________________________________________________________________________________ (millions of dollars) Cumulative foreign exchange translation adjustment $221 $ (84) $(21) Minimum pension liability adjustment 27 (127) 375 Unrealized gains and losses on stock investments 57 (45) -- Other components of shareholders' equity 111 50 88
The reconciliation between income tax expense and a theoretical U.S. tax computed by applying a rate of 35 percent for 2000, 1999 and 1998, is as follows:
2000 1999 1998 _______________________________________________________________________________________________ (millions of dollars) Earnings before Federal and non-U.S. income taxes United States $ 9,016 $ 3,187 $ 3,451 Non-U.S. 17,756 7,815 8,491 ------------------------- Total $26,772 $11,002 $11,942 ------------------------- Theoretical tax $ 9,370 $ 3,851 $ 4,180 Effect of equity method accounting (852) (576) (529) Non-U.S. taxes in excess of theoretical U.S. tax 1,986 201 256 U.S. tax on non-U.S. operations 64 25 43 Other U.S. 214 (409) (152) ------------------------- Federal and non-U.S. income tax expense $10,782 $ 3,092 $ 3,798 ========================= Total effective tax rate 42.4% 31.8% 35.2%
The effective income tax rate includes state income taxes and the corporation's share of income taxes of equity companies. Equity company taxes totaled $658 million in 2000, $449 million in 1999 and $492 million in 1998, 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: 2000 1999 ___________________________________________________________________________ (millions of dollars) Depreciation $13,358 $14,118 Intangible development costs 3,282 3,371 Capitalized interest 1,891 1,500 Other liabilities 2,935 2,028 ---------------- Total deferred tax liabilities $21,466 $21,017 ---------------- Pension and other postretirement benefits $(1,923) $(2,070) Tax loss carryforwards (1,763) (1,701) Other assets (3,465) (2,195) ---------------- Total deferred tax assets $(7,151) $(5,966) ---------------- Asset valuation allowances 380 651 ---------------- Net deferred tax liabilities $14,695 $15,702 ================
The corporation had $14 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. 49 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 20. Disclosures about Segments and Related Information The functional segmentation of operations reflected below is consistent with ExxonMobil's internal reporting. Earnings are before the cumulative effect of accounting changes and include special items. 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 $142 million, $123 million and $81 million in 2000, 1999 and 1998, respectively. All Other includes smaller operating segments, corporate and financing activities, merger expenses, and extraordinary gains from required asset divestitures of $1,730 million.
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, 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 ======================================================================== As of December 31, 1998 Earnings after income tax $ 850 $ 2,502 $ 1,199 $ 2,275 $ 792 $ 602 $ (76) $ 8,144 Earnings of equity companies included above 92 955 69 126 7 67 194 1,510 Sales and other operating revenue 3,017 10,493 36,642 100,957 5,940 7,649 929 165,627 Intersegment revenue 2,957 6,313 2,124 4,828 2,101 1,250 798 -- Depreciation and depletion expense 1,682 3,330 706 1,516 402 338 381 8,355 Interest revenue -- -- -- -- -- -- 185 185 Interest expense -- -- -- -- -- -- 568 568 Income taxes 476 1,490 666 1,204 329 132 (358) 3,939 Additions to property, plant and equipment 1,836 5,646 1,035 1,718 622 1,121 752 12,730 Investments in equity companies 1,161 2,523 313 3,345 365 1,058 61 8,826 Total assets 18,130 39,094 12,585 42,790 7,224 8,898 10,614 139,335 ========================================================================
Geographic Sales and other operating revenue 2000 1999 1998 Long-lived assets 2000 1999 1998 ________________________________________________________________ ________________________________________________________________ (millions of dollars) (millions of dollars) United States $ 70,036 $ 53,214 $ 45,783 United States $ 33,087 $ 33,913 $ 33,597 Non-U.S. 158,403 129,315 119,844 Non-U.S. 56,742 60,130 58,986 -------------------------- -------------------------- Total $228,439 $182,529 $165,627 Total $ 89,829 $ 94,043 $ 92,583 Significant non-U.S. revenue sources include: Significant non-U.S. long-lived assets include: Japan $ 24,520 $ 19,727 $ 22,982 United Kingdom $ 9,024 $ 10,293 $ 11,112 United Kingdom 19,904 16,305 16,012 Canada 7,922 8,404 7,526 Canada 16,059 11,576 9,995 Japan 5,532 6,545 6,055
50 SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Consolidated Subsidiaries _________________________________________________________________ Non- United Asia- Consolidated Total Results of Operations States Canada Europe Pacific Africa Other Total Interests Worldwide ___________________________________________________________________________________________________________________________________ (millions of dollars) 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 ======================================================================================== 1998 - Revenue Sales to third parties $ 2,297 $ 603 $ 3,427 $ 1,893 $ (8) $ 40 $ 8,252 $ 2,385 $10,637 Transfers 2,343 526 1,956 928 1,362 182 7,297 537 7,834 ---------------------------------------------------------------------------------------- $ 4,640 $1,129 $ 5,383 $ 2,821 $ 1,354 $ 222 $15,549 $ 2,922 $18,471 Production costs excluding taxes 1,505 501 1,731 514 284 241 4,776 542 5,318 Exploration expenses 317 74 299 210 248 352 1,500 69 1,569 Depreciation and depletion 1,649 423 1,726 813 254 197 5,062 388 5,450 Taxes other than income 343 40 195 164 225 6 973 595 1,568 Related income tax 313 (49) 499 509 196 30 1,498 513 2,011 ---------------------------------------------------------------------------------------- Results of producing activities $ 513 $ 140 $ 933 $ 611 $ 147 $ (604) $ 1,740 $ 815 $ 2,555 Other earnings* 269 51 556 5 (19) 17 879 (82) 797 ---------------------------------------------------------------------------------------- Total earnings $ 782 $ 191 $ 1,489 $ 616 $ 128 $ (587) $ 2,619 $ 733 $ 3,352 ======================================================================================== Average sales prices and production costs per unit of production ___________________________________________________________________________________________________________________________________ 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 During 1998 Average sales prices Crude oil and NGL, per barrel $ 9.87 $ 8.29 $ 12.59 $ 13.10 $ 12.42 $ 10.90 $ 11.29 $ 10.72 $ 11.23 Natural gas, per thousand cubic feet 2.01 1.27 2.62 1.50 -- 1.24 1.99 3.03 2.16 Average production costs, per barrel** 3.55 3.60 4.48 1.97 2.61 10.67 3.56 2.73 3.45
* 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. 51 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 $4,852 million less at year-end 2000 and $4,593 million less at year-end 1999 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 2000 were $6,063 million, down $1,696 million from 1999, due primarily to lower development costs. 1999 costs were $7,759 million, down $1,616 million from 1998, due primarily to lower development costs.
Consolidated Subsidiaries ______________________________________________________ Non- United Asia- Consolidated Total Capitalized costs States Canada Europe Pacific Africa Other Total Interests Worldwide ________________________________________________________________________________________________________________________________ (millions of dollars) 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 ============================================================================ As of December 31, 1999 Property (acreage) costs -- Proved $ 4,606 $ 2,952 $ 207 $ 931 $ 105 $1,246 $ 10,047 $ 14 $ 10,061 -- Unproved 664 214 59 926 662 254 2,779 3 2,782 ---------------------------------------------------------------------------- Total property costs $ 5,270 $ 3,166 $ 266 $ 1,857 $ 767 $1,500 $ 12,826 $ 17 $ 12,843 Producing assets 30,708 4,499 28,669 11,526 3,161 1,281 79,844 5,294 85,138 Support facilities 795 115 580 1,007 767 399 3,663 145 3,808 Incomplete construction 1,093 2,226 1,828 651 582 182 6,562 695 7,257 ---------------------------------------------------------------------------- Total capitalized costs $37,866 $10,006 $31,343 $15,041 $5,277 $3,362 $102,895 $ 6,151 $ 109,046 Accumulated depreciation and depletion 23,953 4,401 18,680 9,248 1,575 1,531 59,388 2,872 62,260 ---------------------------------------------------------------------------- Net capitalized costs $13,913 $ 5,605 $12,663 $ 5,793 $3,702 $1,831 $ 43,507 $ 3,279 $ 46,786 ============================================================================ Costs incurred in property acquisitions, exploration and development activities _______________________________________________________________________________________________________________________________ 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 ============================================================================ During 1998 Property acquisition costs -- Proved $ 21 $ 2 $ -- $ 1 $ -- $ -- $ 24 $ -- $ 24 -- Unproved 100 9 13 4 87 78 291 -- 291 Exploration costs 409 79 392 258 329 380 1,847 127 1,974 Development costs 1,469 731 2,596 757 584 286 6,423 663 7,086 ---------------------------------------------------------------------------- Total $1,999 $ 821 $3,001 $1,020 $ 1,000 $ 744 $ 8,585 $ 790 $ 9,375 ============================================================================
52 Oil and Gas Reserves The following information describes changes during the years and balances of proved oil and gas reserves at year-end 1998, 1999 and 2000. 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 Asia- Consolidated Total Crude Oil and Natural Gas Liquids States Canada Europe Pacific Africa Other Total Interests Worldwide _____________________________________________________________________________________________________________________________ (millions of barrels) Net proved developed and undeveloped reserves January 1, 1998 2,916 1,228 1,875 838 1,341 241 8,439 1,840 10,279 Revisions 73 (23) 13 41 230 11 345 117 462 Purchases -- -- -- -- -- -- -- -- -- Sales (5) (5) -- -- -- -- (10) (3) (13) Improved recovery 17 9 21 -- 1 -- 48 85 133 Extensions and discoveries 37 43 27 24 358 474 963 23 986 Production (234) (98) (228) (117) (109) (16) (802) (92) (894) ---------------------------------------------------------------------------- December 31, 1998 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 Developed reserves, included above At December 31, 1998 2,470 594 884 673 1,032 57 5,710 1,383 7,093 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
53 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 2000 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 57 due to volumes consumed or flared and inventory changes. Such quantities amounted to approximately 242 billion cubic feet in 1998, 391 billion cubic feet in 1999 and 392 billion cubic feet in 2000.
Consolidated Subsidiaries ____________________________________________________ Non- United Asia- Consolidated Total Natural Gas States Canada Europe Pacific Africa Other Total Interests Worldwide _____________________________________________________________________________________________________________________ (billions of cubic feet) Net proved developed and undeveloped reserves January 1, 1998 13,481 3,352 11,747 10,311 2 504 39,397 19,688 59,085 Revisions 643 (87) 456 245 -- 99 1,356 184 1,540 Purchases -- 10 -- -- -- -- 10 -- 10 Sales (52) (47) (10) (4) -- -- (113) (34) (147) Improved recovery 3 57 20 -- -- -- 80 34 114 Extensions and discoveries 195 503 191 362 111 60 1,422 99 1,521 Production (1,213) (299) (1,003) (916) -- (48) (3,479) (638) (4,117) -------------------------------------------------------------------------- December 31, 1998 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 Developed reserves, included above At December 31, 1998 10,690 2,254 7,939 6,871 2 389 28,145 7,967 36,112 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 ====================================================================================================================
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 55.
Tar Sands Reserves Canada ___________________________________________ (millions of barrels) At December 31, 1998 597 At December 31, 1999 577 At December 31, 2000 610
54 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.
Consolidated Subsidiaries ________________________________________________________ Non- United Asia- Consolidated Total States Canada Europe Pacific Africa Other Total Interests Worldwide _______________________________________________________________________________________________________________________________ (millions of dollars) As of December 31, 1998 Future cash inflows from sales of oil and gas $45,618 $13,255 $42,408 $21,640 $16,889 $ 6,539 $146,349 $62,642 $208,991 Future production costs 18,946 4,567 14,926 8,679 6,298 2,530 55,946 28,343 84,289 Future development costs 4,066 2,012 5,668 3,490 4,141 975 20,352 3,393 23,745 Future income tax expenses 7,359 2,411 8,290 2,725 2,585 667 24,037 11,734 35,771 ------------------------------------------------------------------------------- Future net cash flows $15,247 $ 4,265 $13,524 $ 6,746 $ 3,865 $ 2,367 $ 46,014 $19,172 $ 65,186 Effect of discounting net cash flows at 10% 7,395 2,011 4,951 3,060 2,058 1,541 21,016 12,207 33,223 ------------------------------------------------------------------------------- Discounted future net cash flows $ 7,852 $ 2,254 $ 8,573 $ 3,686 $ 1,807 $ 826 $ 24,998 $ 6,965 $ 31,963 =============================================================================== 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 ===============================================================================
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries 2000 1999 1998 _______________________________________________________________________________________________________________________________ (millions of dollars) Value of reserves added during the year due to extensions, discoveries, improved recovery and net purchases less related costs $ 6,029 $ 4,245 $ 1,329 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 (24,498) (13,395) (10,300) Development costs incurred during the year 4,194 5,313 6,104 Net change in prices, lifting and development costs 44,702 59,466 (34,611) Revisions of previous reserves estimates 12,537 3,106 1,281 Accretion of discount 7,694 3,056 5,865 Net change in income taxes (20,889) (30,833) 15,989 --------------------------- Total change in the standardized measure during the year $ 29,769 $ 30,958 $(14,343) ===========================
55 QUARTERLY INFORMATION
2000 1999 _______________________________________________________________________________ First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Year Quarter Quarter Quarter Quarter Year ______________________________________________________________________________________________________________ (thousands of barrels daily) Volumes Production of crude oil and natural gas liquids 2,602 2,514 2,497 2,600 2,553 2,540 2,473 2,477 2,579 2,517 Refinery throughput 5,528 5,572 5,736 5,732 5,642 6,068 5,950 5,899 5,991 5,977 Petroleum product sales 7,796 8,035 8,069 8,068 7,993 8,974 8,842 8,879 8,857 8,887 (millions of cubic feet daily) Natural gas production available for sale 12,146 9,247 8,735 11,252 10,343 11,516 9,178 8,700 11,851 10,308 (thousands of metric tons) Chemical prime product sales 6,519 6,596 6,038 6,484 25,637 6,076 6,262 6,288 6,657 25,283 (millions of dollars) Summarized financial data Sales and other operating revenue $53,273 54,936 57,497 62,733 228,439 $37,982 42,458 48,415 53,674 182,529 Gross profit* $21,896 22,201 23,620 25,506 93,223 $17,850 19,229 20,379 22,950 80,408 Net income before extraordinary item $ 3,025 4,000 4,060 4,905 15,990 $ 1,484 1,954 2,188 2,284 7,910 Extraordinary gain from required asset divestitures $ 455 530 430 315 1,730 -- -- -- -- -- Net income $ 3,480 4,530 4,490 5,220 17,720 $ 1,484 1,954 2,188 2,284 7,910 (dollars per share) Per share data Net income per common share before extraordinary item $ 0.87 1.15 1.17 1.41 4.60 $ 0.42 0.57 0.63 0.66 2.28 Extraordinary gain from required asset divestitures $ 0.13 0.15 0.12 0.10 0.50 $ -- -- -- -- -- Net income per common share $ 1.00 1.30 1.29 1.51 5.10 $ 0.42 0.57 0.63 0.66 2.28 Net income per common share -- assuming dilution $ 0.99 1.28 1.28 1.49 5.04 $ 0.42 0.56 0.62 0.65 2.25 Dividends per common share $0.4400 0.4400 0.4400 0.4400 1.7600 $0.4165 0.4165 0.4165 0.4375 1.6870 Common stock prices High $86.313 84.750 90.750 95.438 95.438 $76.375 87.250 83.000 86.563 87.250 Low $69.875 75.000 75.125 84.063 69.875 $64.313 69.438 72.125 70.063 64.313
* Gross profit equals sales and other operating revenue less estimated costs associated with products sold. The price range of ExxonMobil Common Stock is as reported on the composite tape of the several U.S. exchanges where ExxonMobil Common Stock is traded. The principal market where ExxonMobil Common Stock (XOM) is traded is the New York Stock Exchange, although the stock is traded on other exchanges in and outside the United States. Through December 1, 1999, the Common Stock traded under the name of Exxon Corporation (XON). There were 718,881 registered shareholders of ExxonMobil common stock at December 31, 2000. At January 31, 2001, the registered shareholders of ExxonMobil common stock numbered 715,020. On January 31, 2001, the corporation declared a $0.44 dividend per common share, payable March 9, 2001. 56 OPERATING SUMMARY
2000 1999 1998 1997 _______________________________________________________________________________ (thousands of barrels daily) Production of crude oil and natural gas liquids Net production United States 733 729 745 803 Canada 304 315 322 287 Europe 704 650 635 641 Asia-Pacific 253 307 322 347 Africa 323 326 301 294 Other Non-U.S. 236 190 177 155 --------------------------- Worldwide 2,553 2,517 2,502 2,527 =========================== (millions of cubic feet daily) Natural gas production available for sale Net production United States 2,856 2,871 3,140 3,223 Canada 844 683 667 600 Europe 4,463 4,438 4,245 4,283 Asia-Pacific 1,755 2,027 2,352 2,632 Other Non-U.S. 425 289 213 156 --------------------------- Worldwide 10,343 10,308 10,617 10,894 =========================== (thousands of barrels daily) Refinery throughput United States 1,862 1,930 1,919 2,026 Canada 451 441 445 448 Europe 1,578 1,782 1,888 1,899 Asia-Pacific 1,462 1,537 1,554 1,559 Other Non-U.S. 289 287 287 302 --------------------------- Worldwide 5,642 5,977 6,093 6,234 =========================== Petroleum product sales United States 2,669 2,918 2,804 2,777 Canada 577 587 579 574 Europe 2,129 2,597 2,646 2,609 Asia-Pacific and other Eastern Hemisphere 2,090 2,223 2,266 2,249 Latin America 528 562 578 564 --------------------------- Worldwide 7,993 8,887 8,873 8,773 =========================== Gasoline, naphthas 3,122 3,428 3,417 3,317 Heating oils, kerosene, diesel oils 2,373 2,658 2,689 2,725 Aviation fuels 749 813 774 753 Heavy fuels 694 706 765 744 Specialty petroleum products 1,055 1,282 1,228 1,234 --------------------------- Worldwide 7,993 8,887 8,873 8,773 =========================== (thousands of metric tons) Chemical prime product sales 25,637 25,283 23,628 23,838 =========================== (millions of metric tons) Coal production 17 17 15 15 =========================== (thousands of metric tons) Copper production 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. 57 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 28, 2001 ---------------- 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 28, 2001 ______________________________________ (Principal Executive (Lee R. Raymond) Officer) /s/ MICHAEL J. BOSKIN Director March 28, 2001 ______________________________________ (Michael J. Boskin) /s/ RENE DAHAN Director March 28, 2001 ______________________________________ (Rene Dahan)
58 /s/ WILLIAM T. ESREY Director March 28, 2001 ______________________________________ (William T. Esrey) /s/ DONALD V. FITES Director March 28, 2001 ______________________________________ (Donald V. Fites) /s/ JESS HAY Director March 28, 2001 ______________________________________ (Jess Hay) /s/ CHARLES A. HEIMBOLD, JR. Director March 28, 2001 ______________________________________ (Charles A. Heimbold, Jr.) /s/ JAMES R. HOUGHTON Director March 28, 2001 ______________________________________ (James R. Houghton) /s/ WILLIAM R. HOWELL Director March 28, 2001 ______________________________________ (William R. Howell) /s/ HELENE L. KAPLAN Director March 28, 2001 ______________________________________ (Helene L. Kaplan) /s/ REATHA CLARK KING Director March 28, 2001 ______________________________________ (Reatha Clark King) /s/ PHILIP E. LIPPINCOTT Director March 28, 2001 ______________________________________ (Philip E. Lippincott) /s/ HARRY J. LONGWELL Director March 28, 2001 ______________________________________ (Harry J. Longwell)
59 /s/ J. RICHARD MUNRO Director March 28, 2001 ______________________________________ (J. Richard Munro) /s/ MARILYN CARLSON NELSON Director March 28, 2001 ______________________________________ (Marilyn Carlson Nelson) /s/ EUGENE A. RENNA Director March 28, 2001 ______________________________________ (Eugene A. Renna) /s/ WALTER V. SHIPLEY Director March 28, 2001 ______________________________________ (Walter V. Shipley) /s/ DONALD D. HUMPHREYS Controller (Principal March 28, 2001 ______________________________________ Accounting Officer) (Donald D. Humphreys) /s/ FRANK A. RISCH Treasurer (Principal March 28, 2001 ______________________________________ Financial Officer) (Frank A. Risch)
60 INDEX TO EXHIBITS 3(i). Restated Certificate of Incorporation, as restated November 30, 1999 (incorporated by reference to Exhibit 3(i) to the registrant's Annual Report on Form 10-K for 1999). 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 Annual Report on Form 10-K for 1999).* 10(iii)(b). 2001 Nonemployee Director's Deferred Compensation Plan.* 10(iii)(c). Restricted Stock Plan for Nonemployee Directors, as amended (incorporated by reference to Exhibit 10(iii)(c) to the registrant's Annual Report on Form 10-K for 1996).* 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.* 10(iii)(h). Mobil Oil Corporation's Executive Life Insurance Program (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K of Mobil Corporation filed March 31, 1999).* 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. 23.1 Consent of PricewaterhouseCoopers LLP, Independent Accountants. 23.2 Consent of Ernst & Young LLP, Independent Auditors. 99. Report of Ernst & Young LLP, Independent Auditors.
- - - - - - -------- * 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. 61