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Slide 1: 2000 AN N UAL R E P O RT
Slide 2: CONTENTS 2 Letter to Stockholders 6 Exploration and Production 15 18 58 Refining and Marketing Index to Financial Information Directors and Officers C OV E R HESS EXPRESS Retail Facility in Florida
Slide 3: Financial and Operating Highlights Amerada Hess Corporation and Consolidated Subsidiaries Dollar amounts in millions, except per share data 2000 1999 FINANCIAL — FOR THE YEAR Sales and other operating revenues Operating earnings Net income Net income per share (diluted) Return on average capital employed(b) Common stock dividends per share Capital expenditures Weighted average shares outstanding (diluted) — in thousands FINANCIAL — AT YEAR-END Total assets Total debt Stockholders’ equity OPERATING — FOR THE YEAR Production — net Crude oil and natural gas liquids — thousands of barrels per day United States Foreign Total Natural gas — thousands of Mcf per day United States Foreign Total Barrels of oil equivalent — thousands of barrels per day Refining and marketing — thousands of barrels per day Refining crude runs — HOVENSA L.L.C.(c) Refined products sold $11,993 $ 987 $ 1,023(a) $ 11.38 20.4% $ .60 $ 938 89,878 $ 7,039 $ 307 $ 438(a) $ 4.85 10.5% $ .60 $ 797 90,280 $10,274 $ 2,050 $ 3,883 $ 7,728 $ 2,310 $ 3,038 67 194 261 65 167 232 288 391 679 338 305 643 374 339 211 366 209 344 (a) Includes after-tax income from special items of $36 million in 2000 and $131 million in 1999. (b) Net income excluding after-tax interest expense divided by average capital employed (total debt plus equity). (c) Reflects the Corporation’s 50% share of HOVENSA’s crude runs. See Management’s Discussion and Analysis of Results of Operations beginning on page 19. 1
Slide 4: To Our Stockholders The year 2000 was an extraordinary year for Amerada Hess. • We achieved record after-tax earnings of $1.023 billion ($11.38 per share), a 20% return on average capital employed. • We increased production to 374,000 barrels of oil equivalent per day from 339,000 barrels per day in 1999, a 10% increase. • We began construction of the coking unit at our HOVENSA joint venture Virgin Islands refinery. • We significantly expanded our retail marketing network. • We repurchased 3,444,000 shares of Common Stock for $220 million. We enter 2001 confident that we will have another year of strong earnings and production growth. We have a strong balance sheet and are poised to take steps for further growth and profitability. We continue to strive for excellence in our environmental, health and safety performance. E X P L O R AT I O N A N D P R O D U C T I O N In 2000, we achieved a 29% return on capital employed in exploration and production. Exploration and production will continue to be the primary vehicle for future income and growth. We will balance our efforts among exploration drilling, reserve development opportunities and acquisitions. We believe that increasing our international portfolio of lower-cost, long-life reserves and our exposure to natural gas in the United States is the best way to create value in our upstream business. Major milestones in 2000 included the successful development of the Conger and Northwestern Fields in the Gulf of Mexico, which will add about 16,000 barrels of oil equivalent per day to our United States production, the acquisition of the Gassi El Agreb redevelopment project in Algeria, which will add current net production of about 14,000 barrels of oil per day, and the acquisition of an additional interest in the Azeri, Chirag and Guneshli Fields in Azerbaijan, which offer lower-cost, long-life reserves. Early this year, the Atora Field in Gabon came onstream. We recently reached agreement to purchase natural gas properties onshore and offshore Louisiana for approximately $750 million. Net production from these properties will average about 200,000 Mcf of natural gas equivalent per day in 2001 and peak at about 250,000 Mcf per day in 2003. Early in 2001, we also acquired Gulf of Mexico properties that will have net production of about 2
Slide 5: 30,000 Mcf of natural gas equivalent per day in 2001. Both acquisitions offer excellent financial returns, production upside and increased exposure to United States natural gas markets. We expect our daily production to increase by about 12% to 420,000 barrels of oil equivalent per day in 2001 as a result of past exploration successes, field redevelopments and production from these acquisitions. We anticipate a further production increase in 2002. The per barrel profitability of our production, after eliminating the impact of higher crude oil and natural gas prices, has risen dramatically since we reshaped our upstream asset base. Management remains committed to enhancing financial returns. We replaced 129% of our production in 2000. However, we have not been satisfied with the results of our exploration program. During 2000, we brought in new management for our United States and international exploration programs. We are confident that the new exploration leadership will improve our exploration success rate and move us toward our finding cost target. During 2000, Amerada Hess made an offer for LASMO plc, a United Kingdom exploration and production company with significant international activities. We withdrew our offer in the face of a higher bid that would not have met our financial return standards and, we believe, would not have been in the best interests of our shareholders. We will continue to be disciplined and pursue acquisitions that meet our financial standards. REFI N I NG AN D MARKETI NG Our challenge in refining and marketing has been to achieve double-digit returns on capital employed in a business that has traditionally suffered from low margins and relatively poor financial performance. We successfully met this challenge in 2000. While returns were enhanced by improved refining margins, our refining and marketing financial results, relative to competitors, have improved dramatically since we reshaped our downstream asset base. Our return on capital employed from refining and marketing operations exceeded 12% in 2000. Construction of the 58,000 barrel per day delayed coking unit and related facilities has begun at the Virgin Islands refinery. The unit, which is scheduled to be completed during the second quarter of 2002, will further enhance financial returns. 3
Slide 6: We continue to invest in retail marketing because we believe that over time this business can deliver superior financial returns. In 2000, we acquired 178 Merit retail facilities, greatly strengthening our business in the metropolitan Philadelphia, New York and Boston markets. We have rebranded nearly all of these HESS. We have reached agreement to form a joint venture to own and operate 141 WILCO retail facilities, which are located primarily in North Carolina, South Carolina and Virginia. The gasoline will be sold under the HESS brand. We also have agreed to purchase 53 Gibbs retail facilities, located primarily in the Boston metropolitan area and southern New Hampshire. We will rebrand them HESS. At the end of 2001, we expect to have about 1,150 HESS retail facilities, more than double the number at the end of 1996, and we will be the leading independent convenience retail marketer on the East Coast. During 2000, we continued to expand our energy marketing business. Sales of distillates and residual fuel oil increased as a result of colder weather in the fourth quarter of 2000. Natural gas sales to industrial and commercial customers were in excess of 500,000 Mcf per day at year-end 2000. We also invested in innovative technologies to make alternate sources of energy available to our customers. We are manufacturing and marketing to industrial and commercial customers a cogeneration unit that generates electricity and thermal energy. We made an investment in a fuel cell company that designs and develops integrated fuel cell systems capable of using multiple fuels to produce cleaner energy for both the stationary and vehicular markets. C U R R E N T R ET U R N S TO S HAR E H O LD E R S At its March 7, 2001 meeting, the Corporation’s Board of Directors increased the regular quarterly dividend on the Common Stock to 30 cents per share from 15 cents per share. The Board’s action reflects the Corporation’s continuing commitment to increasing current returns to shareholders, the Corporation’s sound financial condition and the positive outlook for the future. In 2000, the Corporation’s Board of Directors authorized the expenditure of $300 million to repurchase shares of Amerada Hess Common Stock. During 2000, $220 million was spent, leaving $80 million available for continued share repurchases. Management and the Board of Directors continue to believe that the Corporation’s Common Stock is an excellent investment. 4
Slide 7: R E S U LT S O F O P E R AT I O N S Amerada Hess had record earnings of $1.023 billion ($11.38 per share) in 2000 compared with $438 million ($4.85 per share) in 1999. Earnings from operations were $987 million in 2000 compared with $307 million in 1999. Exploration and production operating earnings were $868 million in 2000 compared with $324 million in 1999. Operating earnings from refining and marketing amounted to $288 million in 2000 versus $133 million in 1999. Interest expense and other corporate charges were $169 million in 2000 compared with $150 million in 1999. Special items contributed $36 million in 2000 compared with $131 million in 1999. In 2000, sales and other operating revenues were $12 billion compared with $7 billion in 1999. Capital expenditures were $938 million versus $797 million in 1999. Details on results of operations appear under Management’s Discussion and Analysis of Results of Operations and Financial Condition beginning on page 19 of this Annual Report. We express our appreciation to our employees for their dedication and contributions. We are proud of their achievements in the past year. We thank our Directors for their guidance and leadership. We thank our stockholders for their strong support. JOH N B. H ES S Chairman of the Board and Chief Executive Officer W. S . H . L A I D L A W President and Chief Operating Officer March 7, 2001 5
Slide 8: Exploration and Production U N I T E D S TAT E S Amerada Hess, as operator, brought the Conger Field on Garden Banks Block 215, in which it has a 37.50% interest, onstream in December 2000. This Gulf of Mexico field is produced through a multiwell, sub-sea system with topside support and processing facilities. Innovative technology was required for the sub-sea system; it is the industry’s first use, on a field-wide scale, of 15,000 PSI horizontal subsea tree technology. When development is completed in the second quarter of 2001, net production for the Corporation is expected to peak at about 7,500 barrels of oil per day and 33,000 Mcf of natural gas per day. The Conger sub-sea system is tied back to the Enchilada Complex in which Amerada Hess has an interest. First production from the Amerada Hess operated Northwestern Field (AHC 50%), on Garden Banks Blocks 200 and 201, commenced in November 2000. The two-well, sub-sea system is tied back 16.5 miles to facilities at East Cameron Block 373. Production for Amerada Hess is expected to peak at 35,000 Mcf of natural gas and 800 barrels of condensate per day in 2001. Amerada Hess drilled a successful development well in the Penn State Field (AHC 50%) that will be completed in the second quarter of 2001, tied into existing sub-sea facilities and processed at the Baldpate platform. Net production from this well is expected to be 2,000 barrels of oil per day and 4,800 Mcf of natural gas per day. Amerada Hess operates the Baldpate and Penn State Fields, which are located on Garden Banks Blocks 259/260 and 216, respectively. The Tulane Field (AHC 100%), on Garden Banks Block 158, is being developed as a single-well, subsea satellite tieback. Detailed engineering is underway and initial production is expected late this year. Production is expected to reach 35,000 Mcf of natural gas per day in 2002. During 2000, Amerada Hess acquired interests in 22 blocks in Gulf of Mexico lease sales at a cost of $19.6 million. Of these blocks, 13 are operated by Amerada Hess and 13 are located in water depths exceeding 5,000 feet. Amerada Hess acquired 11 additional leases in the Gulf of Mexico in 2000 for $2.8 million. Onshore, Amerada Hess continued its drilling program in North Dakota, using horizontal drilling technology to optimize development of the Madison reservoir. The Corporation drilled 20 new wells in 2000 resulting in net incremental production of about 4,000 barrels of oil per day and 10,000 Mcf of natural gas per day. Amerada Hess has an average interest of 86% in these wells. Additional drilling is planned in this area for 2001. 6
Slide 9: CONGER FIELD — GULF OF MEXICO
Slide 10: BITTERN FIELD — NORTH SEA
Slide 11: UNITED KINGDOM Two new fields were brought onstream in the United Kingdom in 2000. The Bittern Field, in which Amerada Hess Limited, the Corporation’s British subsidiary, has a 28.28% interest, is being produced through the Triton floating production, storage and offloading vessel which Amerada Hess Limited operates. Production for Amerada Hess Limited from the Bittern Field is expected to average about 16,000 barrels of crude oil and natural gas liquids per day and 15,000 Mcf of natural gas per day during 2001. The Cook Field (AHL 28.46%) came onstream in April 2000 and also produces through a floating production, storage and offloading vessel. Amerada Hess Limited’s share of production is expected to peak at 5,100 barrels of oil per day in the second half of 2001. Amerada Hess Limited acquired an additional 34.46% interest in the Ivanhoe, Rob Roy and Hamish Fields in 2000 bringing its interest in those fields to more than 76%. The acquisition, plus additional successful drilling, resulted in net production from these mature fields increasing to 7,000 barrels of crude oil and natural gas liquids per day in 2000 compared with 4,100 barrels per day in 1999. Two new developments have begun in the United Kingdom North Sea. Approval for development of the Halley Field (AHL 40%) was received early in 2001. Production is expected to begin in 2001 and to reach 7,000 barrels of oil per day and 12,000 Mcf of natural gas per day for Amerada Hess Limited late in 2001. Development of the Skene Field (AHL 9.07%) is underway and is expected to produce first gas by the end of 2001. Production for Amerada Hess Limited will peak at 30,000 Mcf of natural gas per day in 2002. Further natural gas discoveries were made in 2000. On Block 47/4a, the Minerva discovery (AHL 35%) tested at rates exceeding 40,000 Mcf of natural gas per day. Minerva will be developed as part of the second phase of the Easington Catchment Area project and should come onstream by the end of 2002. A successful horizontal well discovered North Davy (AHL 28%) and tested at 100,000 Mcf of natural gas per day. Initial gas production is expected by the end of 2001, with Amerada Hess Limited’s share expected to peak at 12,000 Mcf of natural gas per day in 2002. Studies continue for the development of the Goldeneye and Western Hub natural gas discoveries (AHL 13.75%) in the Outer Moray Firth. Early in 2001, a successful appraisal well was drilled on the South Atlantic prospect (AHL 20%) which will be included in the development study. Other activities in the United Kingdom included taking the first steps for the possible development of the Clair Field, in which Amerada Hess Limited has a 9.29% interest, and the acquisition by Amerada Hess Limited of a 17.50% interest in Block 204/14, which contains the Suilven oil discovery northwest of the Schiehallion Field (AHL 15.67%). 9
Slide 12: N O R W AY Amerada Hess Norge A/S, the Corporation’s Norwegian subsidiary, and its partners have obtained approval for the enhanced-recovery, waterflood project for the Valhall Field in which Amerada Hess Norge has a 28.09% interest. Initial water injection is expected to begin in 2003. The water injection project will extend the life of the Valhall Field and is expected to increase Amerada Hess Norge’s share of production from 23,400 barrels of oil per day in 2000 to in excess of 30,000 barrels per day in 2003. The Valhall Field licenses have been extended to 2028 from 2011. Early in 2001, oil was discovered on License 202 in the Barents Sea, offshore northern Norway. The discovery will require further appraisal. Amerada Hess Norge has a 25% interest in the discovery. Production in Norway averaged 31,000 barrels of oil equivalent per day in 2000, essentially the same level of production as in 1999. DEN MARK The South Arne Field, operated by the Corporation’s Danish subsidiary, Amerada Hess ApS, completed its first full-year of production in 2000. Production for Amerada Hess ApS averaged 25,300 barrels of oil per day and 37,300 Mcf of natural gas per day. Development of the field continued in 2000 with one water injection well and two development wells completed. High-rate water injection began in the fourth quarter of 2000 to enhance recovery. Full-field water injection will begin in mid-2001 to increase production and extend the life of the field. Amerada Hess ApS is evaluating the possible drilling of an appraisal well on its Southern Tor prospect, a potential extension of the South Arne Field. Amerada Hess ApS has a 57.48% interest in the South Arne Field and in the Southern Tor prospect. FA R O E I S L A N D S Amerada Hess has been awarded operatorship of License 001 in the Faroes First Round of License Awards. This license covers parts of Blocks 6005/20, 6005/25 and 6004/16 in the Faroe Islands, which are northwest of the British Isles. An exploration well, in which Amerada Hess has a 42.76% interest, is planned for the second half of 2001. 10
Slide 13: B RAZ I L Amerada Hess Limitada, the Corporation’s Brazilian subsidiary, has interests in six blocks in Brazil comprising 5.1 million gross acres and 1.9 million net acres in water depths ranging from 200 to 9,900 feet. Amerada Hess Limitada drilled its initial exploration wells in Brazil in 2000 on Blocks BC-8 in the Campos Basin and BS-2 in the Santos Basin, in both of which it has a 32% interest. Both wells encountered hydrocarbons. A second well on Block BS-2 is scheduled to be drilled in the first half of 2001. Amerada Hess Limitada has a 16% interest in Block BCe-2 in the Potiguar Basin. A well is expected to be drilled in the first half of 2001. Extensive 3-D seismic covering Block BM-S-3 (AHL 45%) was acquired during 2000. Interpretation of this data is taking place and an exploration well is planned on this block in 2002. In the Brazilian Second Licensing Round, Amerada Hess Limitada acquired an 85% interest in the BM-Seal-5 Block and a 40% interest in the BM-Seal-4 Block, both of which are located in the SergipeAlagoas Basin. Seismic data is being acquired. I N DON ES IA Early in 2001, agreement was reached for the sale of natural gas from the Jabung Production Sharing Contract (PSC), in which Amerada Hess holds a 30% interest. Gross production from the Jabung PSC is expected to average approximately 60,000 Mcf of natural gas per day beginning in the third quarter of 2003 and reach a maximum rate of approximately 130,000 Mcf of natural gas per day late in the decade. As part of the project, liquefied petroleum gas and condensate are expected to be produced at gross rates of 15,000 barrels per day and 11,000 barrels per day, respectively. Current gross crude oil production is 21,000 barrels per day. Production for Amerada Hess in Indonesia averaged 4,000 barrels of oil per day and 10,000 Mcf of natural gas per day in 2000. THAI LAN D Net production for the Corporation from the Pailin Field in Thailand averaged 23,000 Mcf of natural gas per day and 1,200 barrels of condensate per day in 2000. Phase two of the development of the field has been approved and is expected to be brought onstream in July 2002. Phase two will provide the Corporation with additional production of 25,000 Mcf of natural gas per day. M A L AY S I A In 2001, Amerada Hess acquired an 85% interest in the Block F PSC off the northern coast of Sarawak, which covers approximately 8,000 square kilometers. The Company is processing existing seismic data and acquiring additional seismic. Early in 2001, exploration drilling began on Blocks SK-306 (AHC 46%) and PM-304 (AHC 41%) to evaluate the commercial potential of previous crude oil and natural gas discoveries on these blocks. 11
Slide 14: ALG E R IA In 2000, Amerada Hess acquired, for $55 million, the Gassi El Agreb redevelopment project in Algeria, which covers the El Gassi, El Agreb and Zotti Fields. The Corporation expects to invest approximately $500 million over the next five years to enhance recovery from the fields through an operating company named SonaHess, which is a joint venture between Amerada Hess and Sonatrach, the Algerian national oil company. The enhanced recovery project is designed to increase gross production from about 30,000 barrels of oil per day to 50,000 barrels per day late in 2003. Amerada Hess expects to receive net production of about 14,000 barrels of oil per day from these fields in 2001 with peak entitlement production expected to reach about 25,000 barrels of oil per day in 2006. Amerada Hess also acquired exploration rights on Block 401/c, which is adjacent to the Hassi Berkine region of Algeria, a prolific oil production area. GABON The Atora Field came onstream in February 2001. Amerada Hess Production Gabon, a 77.50% owned Gabonese subsidiary of the Corporation, has a 40% interest in the field and expects its share of production from the Atora Field to reach 6,000 barrels of oil per day in 2001 and to peak at 9,000 barrels of oil per day in 2002. Crude oil production for Amerada Hess in Gabon averaged 7,100 barrels per day in 2000 and is expected to increase to about 9,000 barrels per day in 2001. A Z E R BAIJAN Amerada Hess increased its equity interests in the Azeri, Chirag and Guneshli Fields in Azerbaijan to 2.72% from 1.68% in 2000. Production for Amerada Hess in 2001 is expected to average approximately 5,500 barrels of oil per day. Options for expanding the oil export pipeline system to handle increased volumes of oil production from Azerbaijan are being considered. The Corporation’s share of production in Azerbaijan has the potential to rise to in excess of 20,000 barrels of oil per day in 2008, if pipeline capacity is increased. 12
Slide 15: PRODUCTION FACILITY — ALGERIA
Slide 16: CONSTRUCTION OF DELAYED COKING UNIT — ST. CROIX
Slide 17: Refining and Marketing REFINING The St. Croix refinery, owned and operated by HOVENSA L.L.C., a joint venture between Amerada Hess and Petroleos de Venezuela, S.A., benefitted from significantly improved refining margins in 2000 and made a major contribution to the Corporation’s earnings. HOVENSA supplies refined petroleum products to both joint venture partners, including the bulk of the Corporation’s refined products for its East Coast marketing business. HOVENSA continued to supply California with gasoline and distillates that met that state’s strict environmental standards in 2000 during periods of shortages or tight supply. During the year, HOVENSA began construction of the 58,000 barrel per day delayed coking unit. Upon completion, the refinery will begin processing 115,000 barrels per day of heavy Venezuelan Merey crude oil. The coker will enable the refinery to process crude oil that is heavier and less costly relative to other crude oils processed at the refinery, thus improving profitability. The refinery will continue to process at least 155,000 barrels per day of lighter Venezuelan Mesa crude oil. The delayed coking unit is scheduled to come onstream in the second quarter of 2002. Early in 2001, HOVENSA brought the 140,000 barrel per day fluid catalytic cracking unit down for scheduled maintenance. This gasoline manufacturing unit was out of operation for approximately six weeks. Immediately after the fluid catalytic cracking unit was brought back onstream, HOVENSA shut down one of the large crude units at the refinery, both for scheduled maintenance and to upgrade it for integration with the delayed coking unit. Total refinery runs at HOVENSA averaged 422,000 barrels per day in 2000, approximately the same level as in 1999. The fluid catalytic cracking unit continued to operate at a peak rate of 140,000 barrels per day during most of the year. The Corporation’s Port Reading fluid catalytic cracking unit ran smoothly throughout 2000, generally at a rate of about 60,000 barrels per day. The fluid catalytic cracking unit processes vacuum gas oil and residual fuel oil to manufacture high-quality gasoline for HESS customers in the Northeast. MARKETI NG In November 2000, Convenience Store Decisions, a leading industry publication, named HESS EXPRESS “2000 Convenience Store Chain of the Year.” The annual award, in its eleventh year, recognizes excellence in convenience store chains in such areas as customer service, marketing innovation and market share growth. In 2000, Amerada Hess acquired 178 Merit retail gasoline stations which are concentrated in the New York City, Boston and Philadelphia metropolitan areas. Nearly all of these locations have been rebranded HESS, greatly strengthening the HESS brand in these areas. 15
Slide 18: Amerada Hess has agreed to purchase 53 company-operated retail facilities from Gibbs Oil Limited Partnership. The sites, most of which include convenience stores, are located primarily in the Boston metropolitan area and southern New Hampshire. All will be rebranded HESS after closing, expected in late April. Late in 2000, Amerada Hess announced its intention to form a joint venture with North Carolina retail marketer A.T. Williams Oil Company, which owns and operates 120 WILCO gasoline stations with convenience stores and 21 WILCO Travel Centers, located primarily in North Carolina, South Carolina and Virginia. Under the agreement, gasoline and diesel will be sold under the HESS brand. Amerada Hess continues to build high-volume HESS EXPRESS convenience retail facilities, upgrade existing gasoline stations and convenience stores, make acquisitions in key geographic areas and increase the number of independent HESS branded retailers. The number of HESS retail facilities increased to 929 at year-end 2000 from 701 at year-end 1999, and is expected to reach 1,150 by year-end 2001. Amerada Hess opened 25 new HESS EXPRESS convenience stores in 2000 and began construction on seven others. Forty-two retail sites were upgraded by adding convenience stores or rebuilding existing facilities. In energy marketing, a return to colder weather in the fourth quarter of 2000 resulted in an increase in sales and profitability in the Corporation’s distillate and fuel oil businesses. In addition, through a series of acquisitions, the Corporation nearly tripled its natural gas sales to industrial and commercial customers in its core East Coast market area. At the end of 2000, natural gas sales to East Coast industrial and commercial customers were averaging in excess of 500,000 Mcf per day. The Corporation is now the leading unregulated natural gas supplier to these markets and is in a position to grow its electricity sales as electricity markets open to competition. During 2000, Amerada Hess entered the distributed electric generation business through its Hess Microgen subsidiary. Hess Microgen manufactures and installs a reciprocating engine cogeneration unit that generates electricity and thermal energy at commercial and industrial customer locations, providing these customers with a low-cost alternative to purchasing power from higher cost local electric utilities. Approximately 20 of these units have been installed and are in operation. During 2000, Amerada Hess made a long-term technology development investment in fuel cells through an investment in Nuvera Fuel Cells, Inc. This technology, designed to produce cleaner energy, potentially has widespread applications in the automotive and onsite electricity generation sectors. Nuvera is a joint venture among Amerada Hess, Arthur D. Little, Inc. and DeNora New Energy Investments B.V., an Italian company. 16
Slide 19: HESS EXPRESS — KISSIMMEE, FLORIDA
Slide 20: Index to Financial Information Amerada Hess Corporation and Consolidated Subsidiaries 19 Financial Review 27 Statement of Consolidated Income; Statement of Consolidated Retained Earnings 28 Consolidated Balance Sheet 30 Statement of Consolidated Cash Flows 31 Statements of Consolidated Changes in Preferred Stock, Common Stock and Capital in Excess of Par Value; Statement of Consolidated Comprehensive Income 32 Notes to Consolidated Financial Statements 45 Report of Management 46 Report of Ernst & Young LLP, Independent Auditors 47 Supplementary Oil and Gas Data 52 Ten-Year Summary of Financial Data 56 Ten-Year Summary of Operating Data 18
Slide 21: FI NANCIAL REVI EW Amerada Hess Corporation and Consolidated Subsidiaries Management’s Discussion and Analysis of Results of Operations and Financial Condition Consolidated Results of Operations Net income amounted to $1,023 million in 2000, $438 million in 1999 and a loss of $459 million in 1998. Operating earnings (income excluding special items) amounted to $987 million in 2000 compared with $307 million in 1999 and a loss of $196 million in 1998. The after-tax results by major operating activity for 2000, 1999 and 1998 are summarized below: 2000 $ 868 288 (43) (126) 987 36 $1,023 1999 $ 324 133 (31) (119) 307 131 $ 438 1998 $ (18) (18) (37) (123) (196) (263) $ (459) The Corporation’s average selling prices, including the effects of hedging, were as follows: 2000 Crude oil (per barrel) United States Foreign Natural gas liquids (per barrel) United States Foreign Natural gas (per Mcf) United States Foreign $23.97 25.53 22.30 23.41 3.74 2.20 1999 $16.71 18.07 13.59 14.29 2.14 1.79 1998 $12.56 13.18 9.52 10.42 2.08 2.26 Millions of dollars Exploration and production Refining, marketing and shipping Corporate Interest Operating earnings (loss) Special items Net income (loss) Net income (loss) per share (diluted) The Corporation’s net daily worldwide production was as follows: 2000 Crude oil (thousands of barrels per day) United States Foreign Total Natural gas liquids (thousands of barrels per day) United States Foreign Total Natural gas (thousands of Mcf per day) United States Foreign Total Barrels of oil equivalent (thousands of barrels per day) 1999 1998 55 185 240 55 159 214 37 153 190 $11.38 $ 4.85 $(5.12) Comparison of Results Exploration and Production: Operating earnings from explo- 12 9 21 10 8 18 8 8 16 ration and production activities increased by $544 million in 2000, primarily due to significantly higher worldwide crude oil selling prices, increased United States natural gas selling prices and higher crude oil sales volumes. Operating earnings increased by $342 million in 1999, largely due to higher crude oil selling prices, increased sales volumes and reduced exploration expenses. 288 391 679 374 338 305 643 339 294 282 576 302 19
Slide 22: On a barrel of oil equivalent basis, the Corporation’s oil and gas production increased by 10% in 2000 and 12% in 1999. The increase in foreign crude oil production in 2000 was primarily due to a full year of production from the South Arne Field in Denmark. United Kingdom production was also higher, largely due to new production from the Bittern Field and an increased interest in the Ivanhoe and Rob Roy Fields. Increased natural gas production from new and existing fields in the United Kingdom, Denmark and Thailand offset declining natural gas production in the United States. Late in 2000, production commenced from the Conger and Northwestern Fields in the Gulf of Mexico, which will increase United States natural gas production in 2001. The 1999 increase in crude oil production was primarily attributable to the Baldpate Field in the Gulf of Mexico, which commenced production in late 1998, and new production from the South Arne Field. The 1999 increase in foreign natural gas production reflected increases in the North Sea, Indonesia and Thailand. Production expenses were higher in 2000, primarily due to increased oil and gas production volumes and, on a per barrel basis, due to changes in the mix of producing fields. Depreciation, depletion and amortization charges were higher in 2000, also reflecting increased production volumes, although the per barrel rate for depreciation and related costs was comparable to the 1999 and 1998 amounts. Exploration expense was higher in 2000, primarily due to increased drilling and seismic purchases in the Gulf of Mexico and increased exploration activity in international areas (outside of the North Sea). Exploration expense in 1999 was lower than in 1998 as a result of a planned reduction in the exploration program. General and administrative expenses related to exploration and production activities were comparable in 2000 and 1999, but somewhat lower than in 1998, due to cost reduction initiatives in the United States and United Kingdom. The total cost per barrel of production, depreciation, exploration and administrative expenses was $11.70 in 2000, $11.75 in 1999 and $13.80 in 1998 (excluding special charges). The effective income tax rate on exploration and production earnings in 2000 was 41%, compared to an effective rate of 44% in 1999. Generally, this rate will exceed the U.S. statutory rate because of special petroleum taxes, principally in the United Kingdom and Norway. The effective rate in 2000 was lower than in 1999 due to the timing of deductions for certain prior year foreign drilling costs. Crude oil and natural gas selling prices continue to be volatile, and should prices decline, there would be a negative effect on future earnings. However, the Corporation has hedged a substantial amount of 2001 crude oil production and, to a lesser extent 2002 production, which will mitigate the effect if prices decline in those years. Refining, Marketing and Shipping: Operating earnings for refining, marketing and shipping activities increased to $288 million in 2000 compared with income of $133 million in 1999 and a loss of $18 million in 1998. The Corporation’s downstream operations include HOVENSA L.L.C. (HOVENSA), a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA), accounted for on the equity method. Additional refining and marketing operations include a fluid catalytic cracking facility in Port Reading, New Jersey, as well as retail gasoline stations, energy marketing activities, shipping and trading. HOVENSA: The Corporation’s share of HOVENSA’s income was $121 million in 2000 compared with $7 million in 1999 and $24 million in 1998, when the refinery was wholly-owned for the first ten months of the year. Refined product margins were significantly improved in 2000, particularly for gasolines and distillates. Throughout most of 1999 refined product margins were weak. The Corporation’s share of HOVENSA’s refinery runs amounted to 211,000 barrels per day in 2000 and 209,000 in 1999. Income taxes on HOVENSA’s results are offset by available loss carryforwards. Operating earnings from refining, marketing and shipping activities also include interest income on the note received from PDVSA at the formation of the joint venture. Interest on the PDVSA note amounted to $48 million in 2000, $47 million in 1999 and $8 million in 1998. Interest is reflected in non-operating income in the income statement. 20
Slide 23: HOVENSA has been accounted for on the equity method since the formation of the joint venture in November 1998. Prior to that time, refinery results were consolidated. In 1998, the following amounts for HOVENSA were included in the Corporation’s income statement (in millions): sales revenue — $622, cost of products sold — $439, operating expenses — $83 and depreciation — $70. Retail, energy marketing and other: Results from retail gasoline operations declined in 2000 compared with 1999 as selling prices generally did not keep pace with rising product costs. Results of energy marketing activities improved in 2000, largely reflecting increased seasonal demand for fuel oils. Earnings from the Corporation’s catalytic cracking facility in New Jersey also improved in 2000 reflecting improved refining margins. Total refined product sales volumes increased to 134 million barrels in 2000 from 126 million barrels in 1999. Marketing expenses increased in 2000 compared with 1999 reflecting expanded retail operations, including the cost of operating acquired gasoline stations and an increased number of convenience stores. Other operating expenses increased in 2000, largely reflecting higher fuel costs for the catalytic cracking facility in New Jersey and the Corporation’s shipping operations. The Corporation has a 50% voting interest in a consolidated partnership which trades energy commodities and derivatives. The Corporation also takes forward positions on energy contracts in addition to its hedging program. The combined results of these trading activities were gains of $22 million in 2000, $19 million in 1999 and a loss of $26 million in 1998. Expenses of the trading partnership are included in marketing expenses in the income statement. Refining, marketing and shipping results were higher in 1999 than in 1998, primarily due to improved results from the catalytic cracking facility in New Jersey, higher earnings from retail operations and increased trading income. Future results of the Corporation’s refining and marketing operations will continue to be volatile, reflecting competitive industry conditions and supply and demand factors, including the effects of weather. Corporate: Net corporate expenses amounted to $43 mil- lion in 2000, $31 million in 1999 and $37 million in 1998. The increase in 2000 reflects lower earnings of an insurance subsidiary and higher compensation and related costs. In 1999, earnings from the insurance subsidiary included dividends from reinsurers, which exceeded dividends received in 2000. Interest: After-tax interest expense increased slightly in 2000 compared with 1999. The increase was due to higher interest rates and lower amounts capitalized, partially offset by reduced average borrowings. Consolidated Operating Revenues: Sales and other operating revenues increased by 70% in 2000 principally reflecting significantly higher worldwide crude oil, natural gas and refined product selling prices. Sales volumes of foreign crude oil and natural gas also increased, as well as sales of refined products and purchased natural gas in the United States. Sales and other operating revenues increased by approximately 18% in 1999, excluding third party sales of the St. Croix refinery in 1998. The increase in the Corporation’s revenues in 1999 was principally due to higher crude oil and refined product selling prices and increased crude oil and natural gas sales volumes. 21
Slide 24: Special Items After-tax special items in 2000, 1999 and 1998 are summarized below: Millions of dollars Total Exploration and Production Refining, Marketing and Shipping Corporate 2000 Gain on termination of acquisition Costs associated with research and development venture Total 1999 Gain on asset sales Income tax benefits Impairment of assets and operating leases Total 1998 Gain (loss) on asset sales Impairment of assets and operating leases Severance Total Asset impairments in 1999 included $34 million for the Corporation’s crude oil storage terminal in St. Lucia as a result of a storage contract that was not renewed. The carrying value of the terminal had been partially impaired in 1998 reflecting the reduced crude oil storage requirements of the HOVENSA joint venture. Net charges of $38 million were also recorded in 1999 for the write-down in book value of the Corporation’s interest in the Trans Alaska Pipeline System. The Corporation also recorded a 1999 net charge of $27 million for the additional decline in value of a drilling service fixed-price contract, due to lower market rates. The Corporation had previously impaired drilling service contracts in 1998 by recording a charge of $77 million. Payments on the drilling service contracts were completed by December 31, 2000 and the remaining reserve of $14 million was reversed to income. Liquidity and Capital Resources Net cash provided by operating activities, including changes in operating assets and liabilities amounted to $1,843 million in 2000, $770 million in 1999 and $519 million in 1998. The increases in 2000 and 1999 reflect improved earnings and changes in operating assets and liabilities. Excluding balance sheet changes, operating cash flow was $1,948 million in 2000, $1,116 million in 1999 and $521 million in 1998. In 1999 and 1998, the Corporation generated additional cash of $395 million and $468 million, respectively, from the proceeds of asset sales. The amount of the Corporation’s cash and cash equivalents increased to $312 million at December 31, 2000. Total debt was $2,050 million at December 31, 2000 compared with $2,310 million at December 31, 1999. The debt to capitalization ratio decreased to 35% at December 31, 2000 from 43% at year-end 1999. At December 31, 2000, substantially all of the Corporation’s outstanding debt was fixed-rate debt. The Corporation had $2 billion of additional borrowing capacity available under its revolving credit agreements and unused lines of credit under uncommitted arrangements with banks of $216 million at December 31, 2000. In January 2001, the Corporation replaced its existing revolving credit facilities with two new committed facilities totalling $3 billion. These facilities provide $1.5 billion of short-term borrowing capacity and $1.5 billion of five-year revolving credit. $ 60 $ — $ — $60 (24) $ 36 $ 176 54 (99) $ 131 $ — — (24) $ (24) $ 146 — (34) $ 112 — $60 $— — — $— $ 30 54 (65) $ 19 $ (50) (198) (15) $(263) $ 56 (154) (15) $(113) $(106) (44) — $(150) $— — — $— The 2000 gain on termination of the proposed acquisition of another oil company principally reflects foreign currency gains on pound sterling contracts which were purchased in anticipation of the acquisition. These contracts were sold in the fourth quarter resulting in an after-tax gain of $53 million. Also included in this special item is income from a fee on termination of the acquisition, partially offset by transaction costs. The charge of $24 million reflects costs associated with an alternative fuel research and development venture. The gain on asset sales of $146 million in 1999 reflects the sale of the Corporation’s Gulf Coast and Southeast pipeline terminals and certain retail sites. The Corporation also sold natural gas properties in California, resulting in an after-tax gain of $30 million. Special income tax benefits of $54 million represent the United States tax impact of certain prior year foreign exploration activities and the recognition of capital losses. 22
Slide 25: The Corporation’s Board of Directors approved a $300 million stock repurchase program in March 2000. Through December 31, 2000, 3,444,000 shares have been repurchased for $220 million. The Corporation conducts foreign exploration and production activities in the United Kingdom, Norway, Denmark, Gabon, Indonesia, Thailand, Azerbaijan, Algeria and in other countries. The Corporation also has a refining joint venture with a Venezuelan company. Therefore, the Corporation is subject to the risks associated with foreign operations. These exposures may include political risk, credit risk and currency risk. There have not been any material adverse effects on the Corporation’s results of operations or financial condition as a result of its dealings with foreign entities. Capital Expenditures The following table summarizes the Corporation’s capital expenditures in 2000, 1999 and 1998: 2000 $167 536 80 783 Refining, marketing and shipping Operations Acquisitions 109 46 155 Total $938 1999 $101 626 — 727 70 — 70 $797 1998 $ 242 915 150 1,307 132 — 132 $1,439 During 2000, the Corporation agreed with the Algerian National Oil Company to acquire a 49% interest in three producing Algerian oil fields. The Corporation paid $55 million in 2000 for the redevelopment project and will invest up to $500 million over the next five years for new wells, workovers of existing wells and water injection and gas compression facilities. A significant portion of the future expenditures will be funded by the cash flows from these fields. The Corporation also purchased an additional 1.04% interest in three fields in Azerbaijan. The total purchase price was approximately $70 million, of which $45 million is payable over the next two years. The Corporation now owns a 2.72% interest in these fields. During 2000, the Corporation acquired the remaining outstanding stock of the Meadville Corporation for $168 million in cash, deferred payments and preferred stock. The purchase included 178 Merit retail gasoline stations located in the northeastern United States. During the year, the Corporation also purchased certain energy marketing operations. The decrease in capital expenditures in 1999 compared with 1998, reflects the completion of several major development projects and the reduced 1999 exploration program. Although not included in capital expenditures above, the Corporation increased its investment in Premier Oil plc, an equity affiliate, by $59 million in 1999. Acquisitions in 1998 included $100 million for exploration and production interests in Azerbaijan. Capital expenditures in 2001 are currently expected to be approximately $1,050 million, excluding the acquisitions referred to below. It is anticipated that these expenditures will be financed by internally generated funds. Millions of dollars Exploration and production Exploration Production and development Acquisitions 23
Slide 26: The Corporation has announced several acquisitions which, if completed as anticipated, will involve additional capital expenditures in 2001. These expenditures will be financed primarily with internally generated funds supplemented by borrowings to the extent necessary. The Corporation reached agreement to purchase substantially all of the assets of a privately held exploration and production company for approximately $750 million, after expected closing adjustments. The properties acquired are located on the Gulf of Mexico shelf and onshore Louisiana. Production currently is averaging approximately 200,000 Mcf of natural gas equivalent per day and is expected to rise to 250,000 Mcf of natural gas equivalent per day in 2003. The Corporation also has agreed to purchase three natural gas properties in the Gulf of Mexico for approximately $95 million, which will add natural gas production of approximately 30,000 Mcf per day. In addition, the Corporation will invest approximately $90 million in a 50% owned joint venture which will operate 120 gasoline stations and 21 travel centers. The Corporation will also acquire a chain of 53 retail outlets that will be financed with operating leases. Derivative Instruments The Corporation is exposed to market risks related to volatility in the selling prices of crude oil, natural gas and refined products, as well as to changes in interest rates and foreign currency values. Derivative instruments are used to reduce these price and rate fluctuations. The Corporation has guidelines for, and controls over, the use of derivative instruments. The Corporation uses futures, forwards, options and swaps to reduce the effects of changes in the selling prices of crude oil, natural gas and refined products. These instruments fix the selling prices of a portion of the Corporation’s products and the related gains or losses are an integral part of the Corporation’s selling prices. In the fourth quarter of 2000, the Corporation hedged an increased percentage of its crude oil production in anticipation of the proposed acquisition of another oil company. As a result, at December 31 the Corporation had open hedge positions equal to 65% of its estimated 2001 worldwide crude oil production and 25% of its 2002 production. The Corporation also has hedges covering 15% of its 2001 United States natural gas production. The Corporation also uses derivatives in its energy marketing activities to fix the purchase prices of energy products sold under fixed-price contracts. As market conditions change, the Corporation will adjust its hedge positions. The Corporation owns an interest in a partnership that trades energy commodities and energy derivatives. The accounts of the partnership are consolidated with those of the Corporation. The Corporation also takes trading positions for its own account. The Corporation uses value at risk to estimate the potential effects of changes in fair values of derivatives and other instruments used in hedging activities and derivatives and commodities used in trading activities. This method determines the potential one-day change in fair value with 95% confidence. The analysis is based on historical simulation and other assumptions. The value at risk is summarized below: Millions of dollars Hedging Activities Trading Activities 2000 At December 31 Average for the year High during the year Low during the year 1999 At December 31 Average for the year High during the year Low during the year $36 25 36 17 $ 13 6 13 2 $16 15 18 9 $6 7 10 5 The Corporation may use interest-rate swaps to balance exposure to interest rates. At December 31, 2000, the Corporation has substantially all fixed-rate debt and no interest-rate swaps. At December 31, 1999, the Corporation had $400 million of notional value, interest-rate swaps that decreased its percentage of floating-rate debt to 24%. The Corporation’s outstanding debt of $2,050 million has a fair value of $2,149 million at December 31, 2000 ($2,299 at December 31, 1999). A 10% change in interest rates would change the fair value of debt at December 31, 2000 by $110 million. The impact of a 10% change in interest rates on debt and related interest rate swaps at December 31, 1999 was $120 million. 24
Slide 27: The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates, principally the pound sterling. At December 31, 2000, the Corporation has $438 million of notional value foreign exchange contracts ($865 million at December 31, 1999). Generally, the Corporation uses these foreign exchange contracts to fix the exchange rate on net monetary liabilities of its North Sea operations. The change in fair value of the foreign exchange contracts from a 10% change in the exchange rate is estimated to be $40 million at December 31, 2000 ($90 million at December 31, 1999). During the fourth quarter of 2000, the Corporation purchased significant amounts of sterling foreign exchange contracts in anticipation of the proposed acquisition of another oil company. As discussed earlier, these contracts were sold before the end of the year, resulting in a special, after-tax gain of $53 million. Environment and Safety Improvement in environmental and safety performance continues to be a goal of the Corporation. The Corporation’s awareness of its environmental responsibilities and environmental regulations at the federal, state and local levels have led to programs on energy conservation, pollution control and waste minimization and treatment. To ensure that the Corporation meets its goals and the requirements of regulatory authorities, the Corporation also has programs for compliance evaluation, facility auditing and employee training to monitor operational activities. The trend toward environmental performance improvement raises the Corporation’s operating costs and requires increased capital investments. The Port Reading refining facility and the HOVENSA refinery presently produce gasolines that meet or exceed the current United States requirements for conventional and reformulated gasolines, including the requirements for reformulated gasolines that took effect in 2000 which further mandated decreases in emissions of volatile and toxic organic compounds. In addition, the HOVENSA refinery has desulfurization capabilities enabling it to produce lowsulfur diesel fuel. However, regulatory changes already made or anticipated in the United States will alter the composition and emissions characteristics of motor fuels. The regulation of motor fuels in the United States and elsewhere continues to be an area of considerable change and will require large capital expenditures in future years. In December 1999, the United States Environmental Protection Agency (“EPA”) adopted rules that phase in limitations on the sulfur content of gasoline beginning in 2004. In December 2000, EPA adopted regulations to substantially reduce the allowable sulfur content of diesel fuel by 2006. EPA is also considering restrictions or a prohibition on the use of MTBE, a gasoline additive that is produced by Port Reading and HOVENSA and is used primarily to meet United States regulations requiring oxygenation of reformulated gasolines. California and several other states have already adopted a ban on MTBE use beginning in 2003. The Corporation and HOVENSA are reviewing options to determine the most cost effective compliance strategies for these fuel regulations. The costs to comply will depend on a variety of factors, including the availability of suitable technology and contractors, the outcome of anticipated litigation regarding the diesel sulfur rule and whether the minimum oxygen content requirement for reformulated gasoline remains in place if MTBE is banned. Other fuel regulations are also under consideration which could result in additional capital expenditures. Future capital expenditures necessary to comply with these regulations may be substantial. Corporate programs and improved equipment and technologies have reduced the number and size of spills requiring remediation. However, the Corporation expects continuing expenditures for environmental assessment and remediation related primarily to existing conditions. Sites where corrective action may be necessary include gasoline stations, terminals, onshore exploration and production facilities, refineries (including solid waste management units under permits issued pursuant to the Resource Conservation and Recovery Act) and, although not significant, “Superfund” sites where the Corporation has been named a potentially responsible party. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. The Corporation expended $7 million in 2000, $8 million in 1999 and $9 million in 1998 for remediation. In addition, capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, were $5 million in 2000, $2 million in 1999 and $4 million in 1998. 25
Slide 28: The Corporation strives to provide a safe working environment for its employees, contractors, customers and the public. To achieve this goal, the Corporation sets performance objectives and targets for continual improvement. Programs are in place to enhance safety awareness and knowledge of safety policies. Inspections and audits are used to monitor performance. Forward Looking Information Certain sections of the Financial Review, including references to the Corporation’s future results of operations and financial position, capital expenditures, derivative disclosures and environmental sections, represent forward looking information. Forward looking disclosures are based on the Corporation’s current understanding and assessment of these activities and reasonable assumptions about the future. Actual results may differ from these disclosures because of changes in market conditions, government actions and other factors. Dividends Cash dividends on common stock totaled $.60 per share ($.15 per quarter) during 2000 and 1999. In March 2001, the Corporation increased its quarterly dividend to $.30 per share. Stock Market Information The common stock of Amerada Hess Corporation is traded principally on the New York Stock Exchange (ticker symbol: AHC). High and low sales prices in 2000 and 1999 were as follows: 2000 Quarter Ended March 31 June 30 September 30 December 31 High 65 ⁄4 701⁄8 7415⁄16 761⁄4 3 Quarterly Financial Data Quarterly results of operations for the years ended December 31, 2000 and 1999 follow: Millions of dollars, except per share data Sales and other operating revenues Operating earnings Special items Net income Net income per share (diluted) 2000 First Second Third Fourth Total 1999 First Second Third Fourth Total $ 2,831 2,644 2,833 3,685 $11,993 $ 1,539 1,430 1,801 2,269 7,039 $224 202 257 304 $987 $ 41 37 53 176 $ 307 $ — $ 224 — 202 — 257 36(a) 340 $ 36 $1,023 71 77 159 131 438 $2.47 2.24 2.86 3.83 $ 30(b) $ 40(b) 106(b) (45)(c) $131 $ $ .79 .86 1.75 1.45 $ (a) Includes a net gain of $60 million on termination of acquisition, partially offset by a charge of $24 million for costs associated with a research and development venture. (b) Represents after-tax gains on asset sales. (c) Includes special income tax benefits of $54 million, offset by impairment of assets and operating leases of $99 million. The results of operations for the periods reported herein should not be considered as indicative of future operating results. 1999 Low High 53 ⁄4 653⁄8 665⁄16 631⁄16 1 Low 433⁄4 4715⁄16 563⁄4 531⁄2 47 ⁄16 611⁄16 571⁄4 581⁄8 13 26
Slide 29: S TAT E M E N T O F C O N S O L I D AT E D I N C O M E Amerada Hess Corporation and Consolidated Subsidiaries For the Years Ended December 31 Millions of dollars, except per share data 2000 1999 1998 Revenues Sales (excluding excise taxes) and other operating revenues Non-operating income Gain (loss) on asset sales Equity in income (loss) of HOVENSA L.L.C. Other Total revenues Costs and Expenses Cost of products sold Production expenses Marketing expenses Exploration expenses, including dry holes and lease impairment Other operating expenses General and administrative expenses Interest expense Depreciation, depletion and amortization Impairment of assets and operating leases Total costs and expenses Income (loss) before income taxes Provision (benefit) for income taxes Net Income (Loss) Net Income (Loss) Per Share Basic Diluted $11,993 — 121 163 12,277 $7,039 273 7 142 7,461 $6,580 (26) (16) 83 6,621 7,883 557 542 289 234 224 162 714 — 10,605 1,672 649 $ 1,023 4,240 487 387 261 217 232 158 649 128 6,759 702 264 $ 438 4,373 518 379 349 224 271 153 662 206 7,135 (514) (55) $ (459) $ 11.48 11.38 $ 4.88 4.85 $ (5.12) (5.12) S TAT E M E N T O F C O N S O L I D AT E D R E TA I N E D E A R N I N G S For the Years Ended December 31 Millions of dollars, except per share data 2000 $ 2,287 1,023 (54) (187) $ 3,069 1999 $1,904 438 (55) — $2,287 1998 $2,463 (459) (55) (45) $1,904 Balance at Beginning of Year Net income (loss) Dividends declared — common stock ($.60 per share in 2000, 1999 and 1998) Common stock acquired and retired Balance at End of Year See accompanying notes to consolidated financial statements. 27
Slide 30: C O N S O L I D AT E D B A L A N C E S H E E T Amerada Hess Corporation and Consolidated Subsidiaries At December 31 Millions of dollars; thousands of shares 2000 1999 Assets Current Assets Cash and cash equivalents Accounts receivable Trade Other Inventories Other current assets Total current assets $ 312 2,949 47 401 406 4,115 $ 41 1,112 63 373 239 1,828 Investments and Advances HOVENSA L.L.C. Other Total investments and advances 831 219 1,050 710 282 992 Property, Plant and Equipment Exploration and production Refining, marketing and shipping Total — at cost Less reserves for depreciation, depletion, amortization and lease impairment Property, plant and equipment — net 10,499 1,399 11,898 7,575 4,323 9,974 1,091 11,065 7,013 4,052 Note Receivable 443 539 Deferred Income Taxes and Other Assets 343 317 Total Assets $10,274 $ 7,728 28
Slide 31: At December 31 2000 1999 Liabilities and Stockholders’ Equity Current Liabilities Accounts payable — trade Accrued liabilities Taxes payable Notes payable Current maturities of long-term debt Total current liabilities Long-Term Debt Deferred Liabilities and Credits Deferred income taxes Other Total deferred liabilities and credits Stockholders’ Equity Preferred stock, par value $1.00, 20,000 shares authorized 3% cumulative convertible series Authorized — 330 shares Issued — 327 shares in 2000 ($16 million liquidation preference) Common stock, par value $1.00 Authorized — 200,000 shares Issued — 88,744 shares in 2000; 90,676 shares in 1999 Capital in excess of par value Retained earnings Accumulated other comprehensive income Total stockholders’ equity Total Liabilities and Stockholders’ Equity 89 864 3,069 (139) 3,883 $10,274 91 782 2,287 (122) 3,038 $7,728 — — 510 358 868 442 382 824 $ 1,875 1,158 440 7 58 3,538 1,985 $ 772 625 159 18 5 1,579 2,287 The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and producing activities. See accompanying notes to consolidated financial statements. 29
Slide 32: S TAT E M E N T O F C O N S O L I D AT E D C A S H F L O W S Amerada Hess Corporation and Consolidated Subsidiaries For the Years Ended December 31 Millions of dollars 2000 1999 1998 Cash Flows From Operating Activities Net income (loss) Adjustments to reconcile net income (loss) to net cash provided by operating activities Depreciation, depletion and amortization Impairment of assets and operating leases Exploratory dry hole costs Lease impairment (Gain) loss on asset sales Provision (benefit) for deferred income taxes Undistributed earnings of affiliates Changes in other operating assets and liabilities (Increase) decrease in accounts receivable (Increase) decrease in inventories Increase (decrease) in accounts payable, accrued liabilities and deferred revenue Increase (decrease) in taxes payable Changes in prepaid expenses and other Net cash provided by operating activities Cash Flows From Investing Activities Capital expenditures Exploration and production Refining, marketing and shipping Total capital expenditures Investment in affiliates Proceeds from asset sales and other Net cash used in investing activities Cash Flows From Financing Activities Issuance (repayment) of notes Long-term borrowings Repayment of long-term debt Cash dividends paid Common stock acquired Stock options exercised Net cash provided by (used in) financing activities Effect of Exchange Rate Changes on Cash Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year See accompanying notes to consolidated financial statements. $ 1,023 $ 438 $ (459) 714 — 133 33 — 164 (119) 1,948 (1,792) (23) 1,617 272 (179) 1,843 649 128 69 36 (273) 62 7 1,116 (155) 80 (175) 53 (149) 770 662 206 160 31 26 (138) 33 521 6 122 186 (87) (229) 519 (783) (155) (938) (38) 27 (949) (727) (70) (797) (59) 432 (424) (1,307) (132) (1,439) — 503 (936) (11) — (396) (54) (220) 59 (622) (1) 271 41 $ 312 15 990 (1,348) (54) — 18 (379) — (33) 74 $ 41 $ (14) 848 (317) (55) (59) — 403 (3) (17) 91 74 30
Slide 33: S TAT E M E N T O F C O N S O L I D AT E D C H A N G E S I N P R E F E R R E D S T O C K , C O M M O N S T O C K A N D C A P I TA L I N E X C E S S O F PA R VA L U E Amerada Hess Corporation and Consolidated Subsidiaries Preferred Stock Number of shares — — — — — — — — — — — 327 327 $ Common stock Number of shares 91,451 (26) (1,071) 3 90,357 (3) 322 90,676 461 (3,475) 1,082 — 88,744 Capital in excess of par value $ 775 (2) (9) — 764 — 18 782 28 (31) 69 16 $864 Millions of dollars; thousands of shares Amount $ — — — — — — — — — — — — — Amount $ 91 — (1) — 90 — 1 91 — (3) 1 — $89 Balance at January 1, 1998 Cancellations of nonvested common stock awards (net) Common stock acquired and retired Employee stock options exercised Balance at December 31, 1998 Cancellations of nonvested common stock awards (net) Employee stock options exercised Balance at December 31, 1999 Distributions to trustee of nonvested common stock awards (net) Common stock acquired and retired Employee stock options exercised Issuance of preferred stock Balance at December 31, 2000 S TAT E M E N T O F C O N S O L I D AT E D C O M P R E H E N S I V E I N C O M E For the Years Ended December 31 Millions of dollars 2000 1999 1998 Components of Comprehensive Income (Loss) Net income (loss) Change in foreign currency translation adjustment Comprehensive Income (Loss) See accompanying notes to consolidated financial statements. $1,023 (17) $1,006 $438 (7) $431 $(459) (2) $(461) 31
Slide 34: N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S Amerada Hess Corporation and Consolidated Subsidiaries 1. Summary of Significant Accounting Policies Nature of Business: Amerada Hess Corporation and subsidiaries (the “Corporation”) engage in the exploration for and the production, purchase, transportation and sale of crude oil and natural gas. These activities are conducted primarily in the United States, United Kingdom, Norway, Denmark and Gabon. The Corporation also has oil and gas activities in Algeria, Azerbaijan, Indonesia, Thailand, Brazil and other countries. In addition, the Corporation manufactures, purchases, transports, trades and markets refined petroleum and other energy products. The Corporation owns 50% of HOVENSA L.L.C., a refinery joint venture in the United States Virgin Islands. An additional refining facility, terminals and retail gasoline stations are located on the East Coast of the United States. In preparing financial statements, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and revenues and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are: oil and gas reserves, asset valuations and depreciable lives, pension liabilities, environmental obligations, dismantlement costs and income taxes. Principles of Consolidation: The consolidated financial statements include the accounts of Amerada Hess Corporation and subsidiaries. The Corporation’s interests in oil and gas exploration and production ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned, including HOVENSA, the Corporation’s refining joint venture, are stated at cost of acquisition plus the Corporation’s equity in undistributed net income since acquisition, except as stated below. The change in the equity in net income of these companies is included in nonoperating income in the income statement. The Corporation consolidates a trading partnership in which it owns a 50% voting interest and over which it exercises control. Intercompany transactions and accounts are eliminated in consolidation. Revenue Recognition: The Corporation recognizes revenues from the sale of crude oil, natural gas, petroleum products and other merchandise when title passes to the customer. The Corporation recognizes revenues from the production of natural gas properties in which it has an interest based on sales to customers. Differences between natural gas volumes sold and the Corporation’s share of natural gas production are not material. Cash and Cash Equivalents: Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less. Inventories: Crude oil and refined product inventories are valued at the lower of cost or market, except for inventories held for trading purposes which are marked to market. For inventories valued at cost, the Corporation uses principally the last-in, first-out inventory method. Inventories of materials and supplies are valued at or below cost. Exploration and Development Costs: Oil and gas exploration and production activities are accounted for using the successful efforts method. Costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. The Corporation does not carry the capitalized costs of exploratory wells as assets for more than one year, unless oil and gas reserves are found and classified as proved, or additional exploration is underway or planned. If exploratory wells do not meet these conditions, the costs are charged to expense. 32
Slide 35: Depreciation, Depletion and Amortization: Depreciation, depletion and amortization of oil and gas production equipment, properties and wells are determined on the unit-of-production method based on estimated recoverable oil and gas reserves. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives. The estimated costs of dismantlement, restoration and abandonment, less estimated salvage values, of offshore oil and gas production platforms and certain other facilities are taken into account in determining depreciation. Retirement of Property, Plant and Equipment: Costs of property, plant and equipment retired or otherwise disposed of, less accumulated reserves, are reflected in net income. Impairment of Long-Lived Assets: The Corporation reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted future cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. The net present value of future cash flows is based on the Corporation’s estimates, including future oil and gas prices applied to projected production profiles, discounted at a rate commensurate with the risks involved. Oil and gas prices used for determining asset impairments may differ from those used at year-end in the standardized measure of discounted future net cash flows. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Maintenance and Repairs: The estimated costs of major maintenance, including turnarounds at the Port Reading refining facility, are accrued. Other expenditures for maintenance and repairs are charged against income as incurred. Renewals and improvements are treated as additions to property, plant and equipment, and items replaced are treated as retirements. Environmental Expenditures: The Corporation capitalizes environmental expenditures that increase the life or efficiency of property or that reduce or prevent environmental contamination. The Corporation accrues for environmental expenses resulting from existing conditions related to past operations when the future costs are probable and reasonably estimable. Employee Stock Options and Nonvested Common Stock Awards: The Corporation uses the intrinsic value method to account for employee stock options. Because the exercise prices of employee stock options equal or exceed the market price of the stock on the date of grant, the Corporation does not recognize compensation expense. The Corporation records compensation expense for nonvested common stock awards ratably over the vesting period. Foreign Currency Translation: The U.S. dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. For these operations, adjustments resulting from translating foreign currency assets and liabilities into U.S. dollars are recorded in income. For operations that use the local currency as the functional currency, adjustments resulting from translating foreign functional currency assets and liabilities into U.S. dollars are recorded in a separate component of stockholders’ equity entitled “Accumulated other comprehensive income.” Gains or losses resulting from transactions in other than the functional currency are reflected in net income. Hedging: The Corporation uses futures, forwards, options and swaps to hedge the effects of fluctuations in the prices of crude oil, natural gas and refined products and changes in interest rates and foreign currency values. These transactions meet the requirements for hedge accounting, including designation and correlation. The resulting gains or losses, measured by quoted market prices, termination values or other methods, are accounted for as part of the transactions being hedged, except that losses not expected to be recovered upon the completion of hedged transactions are expensed. On the balance sheet, deferred gains and losses are included in current assets and liabilities. Trading: Energy trading activities are marked to market, with gains and losses recorded in operating revenue. 33
Slide 36: 2. Special Items 2000: The Corporation recorded a gain of $97 million ($60 million after income taxes) from the termination of its proposed acquisition of another oil company. The income principally reflects foreign currency gains on pound sterling contracts which were purchased in anticipation of the acquisition. These contracts were subsequently liquidated at an after-tax gain of $53 million. The Corporation also recorded income from a termination payment which was received from the other company, partially offset by transaction costs. The combined results of this transaction were recorded as a special item in the Corporate segment. Refining and marketing results include a charge of $38 million ($24 million after income taxes) for costs associated with an alternative fuel research and development venture. Both of the special items are reflected in non-operating income in the income statement. 1999: The Corporation recorded a gain of $274 million ($176 million after income taxes) from the sale of its Gulf Coast and Southeast pipeline terminals, natural gas properties in California and certain retail sites. Exploration and production results included special income tax benefits of $54 million, reflecting the timing of deductions for certain prior year foreign drilling costs and capital losses. Exploration and production earnings also included an impairment of $59 million ($38 million after income taxes) for the Corporation’s interest in the Trans Alaska Pipeline System. The Corporation has no crude oil production in Alaska and there has been a significant reduction in crude oil volumes shipped through the Corporation’s share of the pipeline. Refining and marketing results included an asset impairment of $34 million (with no income tax benefit) for the Corporation’s crude oil storage terminal in St. Lucia, due to the nonrenewal of a major third party storage contract. The terminal had been partially impaired in 1998 as a result of the reduced crude oil storage requirements of the HOVENSA joint venture. The Corporation also accrued $35 million ($27 million after income taxes) for a further decline in the value of a drilling service fixed-price contract due to lower market rates. During 2000, $41 million of drilling contract payments were charged against the reserve and the remaining balance of $14 million was reversed to income. Gains on asset sales are included on a separate line in non-operating income in the income statement. The impairment of carrying values of the Alaska pipeline and the crude oil storage terminal and the loss on the drilling service contract are reflected in a separate impairment line in the income statement. 1998: The Corporation recorded a loss of $106 million in connection with the sale of the 50% interest in the fixed assets of its Virgin Islands refinery. The Corporation also recorded an additional charge of $44 million for the reduction in carrying value of its crude oil storage terminal in St. Lucia that was used less as a result of the joint venture. No income tax benefit was recorded on either charge. Exploration and production results included a charge of $90 million ($77 million after income taxes) for the reduction in market value of drilling service fixedprice contracts. A charge of $54 million ($35 million after income taxes) was also recorded for the impairment of capitalized costs related to a North Sea oil discovery that was uneconomic. The Corporation expensed $29 million for its share of asset impairment of an equity affiliate and $13 million for the reduction in carrying value of developed and undeveloped properties in the United States and United Kingdom. In addition, the Corporation recorded gains of $80 million ($56 million after income taxes) on the sale of oil and gas assets in the United States and Norway. The Corporation also recorded pre-tax charges of $23 million ($15 million after income taxes) for severance and related exit costs. 34
Slide 37: 3. Accounting Changes The Corporation adopted FAS No. 133, Accounting for Derivative Instruments and Hedging Activities, on January 1, 2001. This statement requires that the Corporation recognize all derivatives on the balance sheet at fair value. For derivatives that hedge changes in the fair value of assets, liabilities or firm commitments, the gains or losses are recognized in earnings together with the offsetting losses or gains on the hedged items. For derivatives that hedge cash flows of forecasted transactions, the gains or losses are recognized in other comprehensive income until the hedged items are recognized in income. For derivatives that are not hedges, the change in fair value must be recognized in income. The Corporation estimates that the transition adjustment resulting from applying the new rules will be a cumulative after-tax increase in other comprehensive income of approximately $100 million. The after-tax effect on net income is not expected to be material. The transition adjustment will be recognized in the first quarter of 2001. The accounting change will also affect assets and liabilities recorded on the Corporation’s balance sheet. On January 1, 1999, the Corporation adopted the last-in, first-out (LIFO) inventory method for valuing its refining and marketing inventories. The change to LIFO decreased net income by $97 million for the year ended December 31, 1999 ($1.08 per share basic and diluted). 4. Inventories Inventories at December 31 are as follows: 2000 $ 103 502 (281) 324 77 $ 401 1999 $ 67 393 (149) 311 62 $ 373 5. Refining Joint Venture In 1998, the Corporation formed HOVENSA L.L.C., a 50% joint venture with Petroleos de Venezuela, S.A. (PDVSA). HOVENSA owns and operates the Virgin Islands refinery, previously wholly-owned by the Corporation. The Corporation’s investment in the joint venture is accounted for using the equity method. Summarized financial information for HOVENSA as of December 31, 2000, 1999 and 1998 and for the years 2000 and 1999 and two months of 1998 since inception follows: 2000 1999 1998 Millions of dollars Summarized Balance Sheet Information At December 31 Current assets $ 523 $ 433 Net fixed assets 1,595 1,328 Other assets 37 27 Current liabilities (425) (282) Long-term debt (131) (150) Deferred liabilities and credits (22) (26) Partners’ equity $ 1,577 $ 1,330 $ 352 1,344 28 (134) (250) (28) $1,312 Summarized Income Statement Information For the periods ended December 31 Total revenues $ 5,243 $ 3,082 Costs and expenses (4,996) (3,064) Net income (loss)(a) $ 247 $ 18 $ 345 (376)(b) $ (31) Millions of dollars Crude oil and other charge stocks Refined and other finished products Less: LIFO adjustment Materials and supplies Total (a) The Corporation’s share of HOVENSA’s income was $121 million in 2000 and $7 million in 1999 and its share of the 1998 loss was $16 million. (b) 1998 results include an inventory writedown of $32 million, which reduced costs of products sold in 1999. 35
Slide 38: The Corporation purchased refined products from HOVENSA at a cost of approximately $2,080 million during 2000, $1,196 million during 1999 and $151 million during the two months ended December 31, 1998. The Corporation sold crude oil to HOVENSA at a cost of approximately $98 million during 2000, $81 million during 1999 and $7 million during the two months ended December 31, 1998. As part of the formation of the joint venture, PDVSA, V .I., a wholly-owned subsidiary of PDVSA, purchased a 50% interest in the fixed assets of the Corporation’s Virgin Islands refinery for $63 million in cash and a 10-year note from PDVSA V for $563 million bearing interest at 8.46% .I. per annum and requiring principal payments over its term. At December 31, 2000 and December 31, 1999, the principal balance of the note was $491 million and $539 million, respectively. In addition, there is a $125 million, 10-year, contingent note, also bearing interest at 8.46% per annum. The contingent note was not valued for accounting purposes. PDVSA V .I.’s payment obligations under both notes are guaranteed by PDVSA and secured by a pledge of PDVSA V .I.’s interest in the joint venture. In February 2000, HOVENSA reached agreement on a $600 million bank financing for the construction of a 58 thousand barrel per day delayed coking unit and related facilities at its refinery and for general working capital requirements. In connection with the financing, the Corporation and PDVSA V agreed to amend the note .I. received by the Corporation at the formation of the joint venture. PDVSA V deferred principal payments on the .I. note and the interest rate was increased to 9.46%. However, in October 2000, PDVSA V exercised its option to .I. repay principal in accordance with the original amortization schedule and the interest rate was reduced to the original rate of 8.46%. Principal payments are due ratably until maturity on February 14, 2009. 6. Short-Term Notes and Related Lines of Credit Short-term notes payable to banks amounted to $7 million at December 31, 2000 and $18 million at December 31, 1999. The weighted average interest rates on these borrowings were 6.8% and 6.3% at December 31, 2000 and 1999, respectively. At December 31, 2000, the Corporation has uncommitted arrangements with banks for unused lines of credit aggregating $216 million. 7. Long-Term Debt Long-term debt at December 31 consists of the following: 2000 990 1999 $ 990 Millions of dollars 7 ⁄8% and 7 ⁄8% Debentures, due in 2009 and 2029 $ 6.1% Marine Terminal Revenue Bonds — Series 1994 — City of Valdez, Alaska, due 2024 Pollution Control Revenue Bonds, weighted average rate 6.6%, due through 2022 Fixed rate notes, payable principally to insurance companies, weighted average rate 8.5%, due through 2014 Global Revolving Credit Facility with banks Project lease financing, weighted average rate 5.1%, due through 2014 Notes payable on asset purchases, weighted average rate 6.6%, due through 2003 Capitalized lease obligations, weighted average rate 6.9%, due through 2009 Other loans, weighted average rate 8.0%, due through 2007 Less amount included in current maturities Total 3 7 20 20 53 53 645 — 915 120 178 183 147 — 7 3 8 3 2,292 5 $2,287 2,043 58 $1,985 36
Slide 39: The aggregate long-term debt maturing during the next five years is as follows (in millions): 2001 — $58 (included in current liabilities); 2002 — $272; 2003 — $28; 2004 — $10 and 2005 — $25. The Corporation’s long-term debt agreements contain various restrictions and conditions, including working capital requirements and limitations on total borrowings and cash dividends. At December 31, 2000, the Corporation exceeded the required working capital ratio. Under the agreements, the Corporation is permitted to borrow an additional $3.7 billion for the construction or acquisition of assets. In addition, at December 31, 2000 it has $1.5 billion of retained earnings free of dividend restrictions. At December 31, 2000, the Corporation had an undrawn $2 billion Global Revolving Credit Facility, which was due to expire in 2002. In January 2001, this facility was replaced with two new committed revolving credit facilities (the “Facilities”). The first, provides for $1.5 billion of short-term revolving credit through January 2002. The second, is for $1.5 billion of five-year revolving credit which expires in January 2006. Borrowings under the Facilities bear interest at .525% and .50%, respectively, above the London Interbank Offered Rate. Facility fees of .10% and .125% per annum are payable on the amount of the credit lines. The Corporation has the option to extend up to $500 million of debt outstanding under the short-term revolving credit facility for an additional 364 days. In 1999, the Corporation issued $1 billion of public debentures, of which $300 million bears interest at 73⁄8% and is due in 2009 and the remainder bears interest at 77⁄8% and is due in 2029. The unamortized discount at December 31, 2000 totals $10 million. In 2000, 1999 and 1998, the Corporation capitalized interest of $3 million, $16 million and $24 million, respectively, on major development projects. The total amount of interest paid (net of amounts capitalized), principally on short-term and long-term debt, in 2000, 1999 and 1998 was $173 million, $145 million and $154 million, respectively. 8. Stock Based Compensation Plans The Corporation has outstanding stock options and nonvested common stock under its 1995 Long-Term Incentive Plan (as amended) and its Executive Long-Term Incentive Compensation and Stock Ownership Plan (which expired in 1997). Generally, stock options vest one year from the date of grant and the exercise price equals or exceeds the market price on the date of grant. Nonvested common stock vests three or five years from the date of grant, depending on the terms of the award. The Corporation’s stock option activity in 2000, 1999 and 1998 consisted of the following: Weightedaverage Options exercise price (thousands) per share Outstanding at January 1, 1998 Granted Exercised Forfeited Outstanding at December 31, 1998 Granted Exercised Forfeited Outstanding at December 31, 1999 Granted Exercised Outstanding at December 31, 2000 Exercisable at December 31, 1998 Exercisable at December 31, 1999 Exercisable at December 31, 2000 2,248 873 (3) (23) 3,095 1,804 (322) (70) 4,507 870 (1,082) 4,295 2,230 2,702 3,425 $ 57.43 53.05 49.75 56.22 56.21 55.66 53.22 58.08 56.18 60.39 54.41 $57.47 $ 57.44 56.52 56.73 Exercise prices for employee stock options at December 31, 2000 ranged from $49.00 to $65.94 per share. The weighted-average remaining contractual life of employee stock options is 7 years. .9 37
Slide 40: The Corporation uses the Black-Scholes model to estimate the fair value of employee stock options for pro forma disclosure of the effects on net income and earnings per share. The Corporation used the following weightedaverage assumptions in the Black-Scholes model for 2000, 1999 and 1998, respectively: risk-free interest rates of 5.4%, 5.9% and 5.6%; expected stock price volatility of .225, .207 and .218; dividend yield of 1.0%, 1.1% and 1.1%; and an expected life of seven years. The Corporation’s net income would have been reduced by approximately $17 million in 2000, $6 million in 1999 and $19 million in 1998 ($.19 per share in 2000, $.07 per share in 1999 and $.21 per share in 1998, diluted) if option expense were recorded using the fair value method. The weighted-average fair values of options granted for which the exercise price equaled the market price on the date of grant were $20.04 in 2000, $18.45 in 1999 and $17 in 1998. .50 Total compensation expense for nonvested common stock was $7 million in 2000, $10 million in 1999 and $16 million in 1998. Awards of nonvested common stock were as follows: Shares of nonvested common stock awarded (thousands) At December 31, 2000, the number of common shares reserved for issuance is as follows (in thousands): 1995 Long-Term Incentive Plan Future awards Stock options outstanding Stock appreciation rights Warrants* Total 2,549 4,295 31 1,061 7,936 *Issued in connection with an insurance company financing, exercisable through June 27, 2001 at $64.08 per share. In February 2001, the parties agreed that upon exercise, the warrants will be settled in cash with no shares issued. 9. Foreign Currency Translation Worldwide foreign currency gains amounted to $45 million, after income taxes, including the $53 million gain related to the special item on termination of the proposed acquisition. After-tax foreign currency gains in 1999 and 1998 amounted to $17 million and $3 million, respectively. Effective January 1, 1999, the Corporation changed the functional currency of its United Kingdom operations from the British pound sterling to the U.S. dollar. Weightedaverage price on date of grant Granted in 1998 Granted in 1999 Granted in 2000 18 24 519 $ 53.08 56.07 59.65 38
Slide 41: 10. Pension Plans The Corporation has defined benefit pension plans for substantially all of its employees. The following table reconciles the benefit obligation and fair value of plan assets and shows the funded status: 2000 1999 $543 22 34 (72) — (26) 501 477 63 20 — (26) 534 33 8 (92) $ (51) Pension expense consisted of the following: 2000 $ 18 37 (45) 2 (1) $ 11 1999 $ 22 34 (41) 1 — $ 16 1998 $ 19 33 (36) 1 — $ 17 Millions of dollars Millions of dollars Reconciliation of pension benefit obligation Benefit obligation at January 1 $501 Service cost 18 Interest cost 37 Actuarial (gain) loss 34 Acquisition of business 25 Benefit payments (26) Pension benefit obligation at December 31 Reconciliation of fair value of plan assets Fair value of plan assets at January 1 Actual return on plan assets Employer contributions Acquisition of business Benefit payments Fair value of plan assets at December 31 Funded status at December 31 Funded status Unrecognized prior service cost Unrecognized gain Accrued pension liability 589 534 (13) 14 34 (26) 543 (46) 6 (5) $ (45) Service cost Interest cost Expected return on plan assets Amortization of prior service cost Amortization of net gain Pension expense Prior service costs and gains and losses in excess of 10% of the greater of the benefit obligation and the market value of assets are amortized over the average remaining service period of active employees. The weighted-average actuarial assumptions used by the Corporation’s pension plans at December 31 were as follows: 2000 Discount rate Expected long-term rate of return on plan assets Rate of compensation increases 7.0% 8.7% 4.5% 1999 7.3% 8.7% 4.5% The Corporation also has a nonqualified supplemental pension plan covering certain employees. The supplemental pension plan provides for incremental pension payments from the Corporation’s funds so that total pension payments equal amounts that would have been payable from the Corporation’s principal pension plan were it not for limitations imposed by income tax regulations. The benefit obligation related to this unfunded plan totaled $47 million at December 31, 2000 and $38 million at December 31, 1999. Pension expense for the plan was $7 million in 2000 and 1999 and $6 million in 1998. The Corporation has accrued $35 million for this plan at December 31, 2000 and $29 million at December 31, 1999. The trust established to fund the supplemental plan held assets valued at $19 million at December 31, 2000 and $14 million at December 31, 1999. 39
Slide 42: 11. Provision for Income Taxes The provision (benefit) for income taxes consisted of: 2000 $ 92 62 22 176 Foreign Current Deferred 371 102 473 Adjustment of deferred tax liability for foreign income tax rate change Total 1999 $6 82 6 94 189 (15) 174 1998 $9 (68) 2 (57) 71 (66) 5 Millions of dollars Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. A summary of the components of deferred tax liabilities and assets at December 31 follows: 2000 $ 350 202 97 649 99 171 122 28 420 (111) 309 $ 340 1999 $ 320 225 56 601 98 300 138 79 615 (182) 433 $ 168 United States Federal Current Deferred State Millions of dollars Deferred tax liabilities Fixed assets and investments Foreign petroleum taxes Other Total deferred tax liabilities Deferred tax assets Accrued liabilities Net operating and capital loss carryforwards Tax credit carryforwards Other Total deferred tax assets Valuation allowance Net deferred tax assets — $649 (4) $264* (3) $(55) *Includes a benefit of $54 million representing deductions for certain prior year foreign drilling costs and capital losses. Income (loss) before income taxes consisted of the following: 2000 $ 497 1,175 $1,672 1999 $397 305 $702 1998 $(205) (309) $(514) Net deferred tax liabilities Millions of dollars United States Foreign* Total The difference between the Corporation’s effective income tax rate and the United States statutory rate is reconciled below: 2000 United States statutory rate Effect of foreign operations, including foreign tax credits State income taxes, net of Federal income tax benefit Prior year adjustments Other Total 35.0% 3.5 .8 (.6) .1 38.8% 1999 35.0% 3.0 .6 (.8) (.2) 37.6% 1998 (35.0)% 24.2 .2 (.3) .2 (10.7)% *Foreign income includes the Corporation’s Virgin Islands, shipping and other operations located outside of the United States. 40
Slide 43: The Corporation has not recorded deferred income taxes applicable to undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations. Undistributed earnings amounted to approximately $1.3 billion at December 31, 2000, excluding amounts which, if remitted, generally would not result in any additional U.S. income taxes because of available foreign tax credits. If the earnings of such foreign subsidiaries were not indefinitely reinvested, a deferred tax liability of approximately $135 million would have been required. For income tax reporting at December 31, 2000, the Corporation has general business credit carryforwards of $17 million. In addition, the Corporation has alternative minimum tax credit carryforwards of approximately $105 million, which can be carried forward indefinitely. At December 31, 2000, a net operating loss carryforward of approximately $750 million is also available to offset income of the HOVENSA joint venture partners. Income taxes paid (net of refunds) in 2000, 1999 and 1998 amounted to $249 million, $141 million and $140 million, respectively. 12. Net Income Per Share The weighted average number of common shares used in the basic and diluted earnings per share computations are summarized below: 2000 89,063 358 339 118 89,878 1999 89,692 436 152 — 90,280 1998 89,585 — — — 89,585 Diluted common shares include shares that would be outstanding assuming the fulfillment of restrictions on nonvested shares, the exercise of stock options and the conversion of preferred stock. In 1998, the above table excludes the antidilutive effect of 666,000 nonvested common shares and 78,000 stock options. The table also excludes the effect of out-of-the-money options on 1,063,000 shares, 1,609,000 shares and 1,626,000 shares in 2000, 1999 and 1998, respectively. 13. Leased Assets The Corporation and certain of its subsidiaries lease floating production systems, drilling rigs, tankers, gasoline stations, office space and other assets for varying periods. Capital leases are not material. At December 31, 2000, future minimum rental payments applicable to noncancelable operating leases with remaining terms of one year or more (other than oil and gas leases) are as follows: Operating Leases Millions of dollars 2001 2002 2003 2004 2005 Remaining years Total minimum lease payments Less income from subleases Net minimum lease payments $153 93 78 69 44 501 938 12 $926 Thousands of shares Common shares — basic Effect of dilutive securities Nonvested common stock Stock options Convertible preferred stock Common shares — diluted Rental expense for all operating leases, other than rentals applicable to oil and gas leases, was as follows: 2000 $199 86 $113 1999 $156 51 $105 1998 $179 30 $149 Millions of dollars Total rental expense Less income from subleases Net rental expense 41
Slide 44: 14. Financial Instruments, Hedging and Trading Activities The Corporation uses futures, forwards, options and swaps, individually or in combination, to reduce the effects of fluctuations in crude oil, natural gas and refined product prices and in fixed-price sales contracts. Foreign currency contracts are used to protect the Corporation from fluctuations in exchange rates. In addition, the Corporation may use interest-rate swaps to adjust the interest rates on a portion of its long-term debt. Commodity Hedging: At December 31, 2000, the Corporation’s hedging activities included commodity future, option and swap contracts, maturing mainly in 2001 and 2002 and covering 88 million barrels of crude oil (31 million barrels of crude oil and refined products in 1999). The Corporation also hedged 20 million Mcf of natural gas at December 31, 2000, maturing in 2001. The Corporation produced 96 million barrels of crude oil and natural gas liquids and 249 million Mcf of natural gas in 2000, and had approximately 16 million barrels of crude oil and refined products in its refining and marketing inventories at December 31, 2000. Since the contracts described above are designated as hedges and correlate to price movements of crude oil, natural gas and refined products, any gains or losses resulting from market changes will be offset by losses or gains on the Corporation’s hedged inventory or production. At December 31, 2000, after-tax deferred gains from the Corporation’s hedging contracts expiring through 2002 were approximately $100 million, of which $131 million were unrealized net gains and $31 million were realized net losses. There was $41 million of losses at December 31, 1999, including $32 million of unrealized losses. Financial Instruments: The Corporation has $438 million of notional value foreign currency forward and purchased option contracts maturing generally in 2001 ($865 million at December 31, 1999) and $365 million in letters of credit outstanding ($145 million at December 31, 1999). At December 31, 2000, the Corporation has no interest-rate swaps outstanding ($400 million at December 31, 1999). Notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts. Fair Value Disclosure: The carrying amounts of cash and cash equivalents, short-term debt and long-term, variablerate debt approximate fair value. The Corporation estimates the fair value of its long-term, fixed-rate note receivable and debt generally using discounted cash flow analysis based on current interest rates for instruments with similar maturities. Interest-rate swaps and foreign currency exchange contracts are valued based on current termination values or quoted market prices of comparable contracts. The Corporation’s valuation of commodity contracts considers quoted market prices, time value, volatility of the underlying commodities and other factors. The carrying amounts of the Corporation’s financial instruments and commodity contracts, including those used in the Corporation’s hedging and trading activities, generally approximate their fair values at December 31, 2000, except as follows: 2000 Millions of dollars, asset (liability) 1999 Fair Value Balance Sheet Amount Fair Value Balance Sheet Amount Long-term, fixed-rate note receivable Fixed-rate debt Interest-rate swaps $ 491 $ 467 $ 539 $ 493 (1,991) (2,090) (2,163) (2,141) — — — (11) Market and Credit Risks: The Corporation’s financial instruments expose it to market and credit risks and may at times be concentrated with certain counterparties or groups of counterparties. The credit worthiness of counterparties is subject to continuing review and full performance is anticipated. Commodity Trading: The Corporation, principally through a consolidated partnership, trades energy commodities, including futures, forwards, options and swaps, based on expectations of future market conditions. The Corporation’s results from trading activities, including its share of the earnings of the trading partnership which has been profitable in each year, amounted to net income of $22 million in 2000, $19 million in 1999 and a net loss of $26 million in 1998. 42
Slide 45: The following table presents the year-end fair values of energy commodities and derivative instruments used in trading activities and the average aggregate fair values during the year: Fair Value At Dec. 31, Average for At Dec. 31, Average for 15. Segment Information The information which follows is required by FAS No. 131, Disclosures about Segments of an Enterprise and Related Information, and includes financial information by geographic area and operating segment. Financial information by major geographic area for each of the three years ended December 31, 2000 follows: United States* Consolidated Millions of dollars, asset (liability) 2000 2000 1999 $ 69 225 (233) 178 (192) 546 (549) 1999 $ 85 143 (148) 67 (76) 356 (342) Millions of dollars Europe Other Commodities $ 6$ 17 Futures and forwards Assets 223 468 Liabilities (379) (490) Options Held 1,086 475 Written (1,043) (617) Swaps Assets 1,377 1,081 Liabilities (1,372) (1,077) 2000 Operating revenues Property, plant and equipment (net) 1999 Operating revenues Property, plant and equipment (net) 1998 Operating revenues Property, plant and equipment (net) $8,953 $2,825 1,558 2,269 $215 $11,993 496 $ 147 $ 367 $ 60 $ 384 4,323 7,039 4,052 6,580 4,192 $ 4,948 $ 1,944 1,289 2,396 $ 5,046 $ 1,474 1,457 2,351 Notional amounts of commodities and derivatives relating to trading activities follow: At December 31, Millions of barrels of oil equivalent *Includes U.S. Virgin Islands and shipping operations. 2000 — 69 (74) 2,115 (2,173) 878 (858) 1999 3 177 (168) 343 (318) 304 (329) Commodities Futures and forwards Long Short Options Held Written Swaps* Held Written The Corporation operates principally in the petroleum industry and its operating segments are (1) exploration and production and (2) refining, marketing and shipping. Exploration and production operations include the exploration for and the production, purchase, transportation and sale of crude oil and natural gas. Refining, marketing and shipping operations include the manufacture, purchase, transportation, trading and marketing of petroleum and other energy products. *Includes 50 million barrels long and 33 million barrels short related to basis swaps at December 31, 2000 (41 million barrels long and 53 million barrels short in 1999). 43
Slide 46: 15. Segment Information (Continued) The following table presents financial data by operating segment for each of the three years ended December 31, 2000: Millions of dollars Exploration and Production Refining, Marketing and Shipping Corporate Consolidated* 2000 Operating revenues Total operating revenues Less: Transfers between affiliates Operating revenues from unaffiliated customers Operating earnings (loss) Special items Net income (loss) Earnings of equity affiliates Interest income Interest expense Depreciation, depletion, amortization and lease impairment Provision (benefit) for income taxes Investments in equity affiliates Identifiable assets Capital employed Capital expenditures 1999 Operating revenues Total operating revenues Less: Transfers between affiliates Operating revenues from unaffiliated customers Operating earnings (loss) Special items Net income (loss) Earnings of equity affiliates Interest income Interest expense Depreciation, depletion, amortization and lease impairment Provision (benefit) for income taxes Investments in equity affiliates Identifiable assets Capital employed Capital expenditures 1998 Operating revenues Total operating revenues Less: Transfers between affiliates Operating revenues from unaffiliated customers Operating earnings (loss) Special items Net income (loss) Earnings of equity affiliates Interest income Interest expense Depreciation, depletion, amortization and lease impairment Provision (benefit) for income taxes Investments in equity affiliates Identifiable assets Capital employed Capital expenditures $3,970 792 $3,178 $ 868 — $ 868 $ 1 7 — 667 612 147 4,688 2,817 783 $8,813 — $8,813 $ 288 (24) $ 264 $ 121 59 — 39 50 894 4,976 2,747 154 2 — $ 2 $(169) 60 $(109) $ 6 11 162 8 (13) — 610 369 1 $ $11,993 $ 987 36 $ 1,023 $ 128 77 162 714 649 1,041 10,274 5,933 938 $ 2,947 450 $ 2,497 $ 324 19 $ 343 $ (9) 12 — 641 184 148 4,396 3,137 727 $ 4,541 — $ 4,541 $ 133 112 $ 245 $ 11 50 — 42 118 778 2,993 1,974 68 $ $ $ $ $ 1 — 1 (150) — (150) 7 1 158 2 (38) 61 339 237 2 $ $ $ $ 7,039 307 131 438 9 63 158 685 264 987 7,728 5,348 797 $ 2,176 314 $ 1,862 $ (18) (113) $ (131) $ (22) 11 — 566 7 96 4,286 3,231 1,307 $ 4,717 — $ 4,717 $ (18) (150) $ (168) $ (13) 11 — 125 (38) 781 3,126 1,969 129 $ $ $ $ $ 1 — 1 (160) — (160) 5 1 153 2 (24) 56 471 96 3 $ $ $ $ 6,580 (196) (263) (459) (30) 23 153 693 (55) 933 7,883 5,296 1,439 *After elimination of transactions between affiliates, which are valued at approximate market prices. 44
Slide 47: REPORT OF MANAG EM ENT Amerada Hess Corporation and Consolidated Subsidiaries The consolidated financial statements of Amerada Hess Corporation and consolidated subsidiaries were prepared by and are the responsibility of management. These financial statements conform with generally accepted accounting principles and are, in part, based on estimates and judgements of management. Other information included in this Annual Report is consistent with that in the consolidated financial statements. The Corporation maintains a system of internal controls designed to provide reasonable assurance that assets are safeguarded and that transactions are properly executed and recorded. Judgements are required to balance the relative costs and benefits of this system of internal controls. The Corporation’s consolidated financial statements have been audited by Ernst & Young LLP, independent auditors, who have been selected by the Audit Committee and the Board of Directors and approved by the stockholders. Ernst & Young LLP assesses the Corporation’s system of internal controls and performs tests and procedures that they consider necessary to arrive at an opinion on the fairness of the consolidated financial statements. The Audit Committee of the Board of Directors consists solely of independent directors. The Audit Committee meets periodically with the independent auditors, internal auditors and management to review and discuss the annual audit scope and plans, the adequacy of staffing, the system of internal controls and the results of examinations. At least annually, the Audit Committee meets with the independent auditors and with the internal auditors without management present. The Audit Committee also reviews the Corporation’s financial statements with management and the independent auditors. This review includes a discussion of accounting principles, significant judgements inherent in the financial statements, disclosures and such other matters required by generally accepted auditing standards. Ernst & Young LLP and the Corporation’s internal auditors have unrestricted access to the Audit Committee. John B. Hess Chairman of the Board and Chief Executive Officer John Y. Schreyer Executive Vice President and Chief Financial Officer 45
Slide 48: R E P O R T O F E R N S T & Y O U N G L L P, I N D E P E N D E N T A U D I TO R S The Board of Directors and Stockholders Amerada Hess Corporation We have audited the accompanying consolidated balance sheet of Amerada Hess Corporation and consolidated subsidiaries as of December 31, 2000 and 1999 and the related consolidated statements of income, retained earnings, cash flows, changes in preferred stock, common stock and capital in excess of par value and comprehensive income for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Amerada Hess Corporation and consolidated subsidiaries at December 31, 2000 and 1999 and the consolidated results of their operations and their consolidated 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. As discussed in Note 3 to the consolidated financial statements, in 1999 the Corporation adopted the last-in, first-out (LIFO) inventory method for valuing its refining and marketing inventories. New York, NY February 21, 2001 46
Slide 49: S U P P L E M E N TA RY O I L A N D G A S D ATA Amerada Hess Corporation and Consolidated Subsidiaries The supplementary oil and gas data that follows is presented in accordance with Statement of Financial Accounting Standards (FAS) No. 69, Disclosures about Oil and Gas Producing Activities, and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing activities, (2) net proved oil and gas reserves, and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves, including a reconciliation of changes therein. The Corporation produces crude oil and/or natural gas in the United States, Europe, Gabon, Indonesia, Thailand, Azerbaijan and Algeria. Exploration activities are also conducted, or are planned, in additional countries. The Corporation also owns a 25% interest in an oil and gas exploration company that it accounts for on the equity method. Costs Incurred in Oil and Gas Producing Activities For the Years Ended December 31 (Millions of dollars) Total United States Europe Africa, Asia and other 2000 Property acquisitions Exploration Development Share of equity investee’s costs incurred 1999 Property acquisitions Exploration Development Share of equity investee’s costs incurred 1998 Property acquisitions Exploration Development Share of equity investee’s costs incurred $118 252 536 49 $ 24 232 626 38 $ 203 319 915 70 $ 22 119 155 — $ 7 72 137 — $ 8 49 321 9 — 76 451 11 7 145 650 13 $ 88 84 60 40 $ 17 84 38 27 $155 68 83 57 $ $ 41 106 182 — $ Capitalized Costs Relating to Oil and Gas Producing Activities At December 31 (Millions of dollars) 2000 $ 321 1,736 8,442 1999 $ 369 1,551 8,054 9,974 6,464 $3,510 $ 233 Unproved properties Proved properties Wells, equipment and related facilities Total costs Less: Reserve for depreciation, depletion, amortization and lease impairment Net capitalized costs Share of equity investee’s capitalized costs 10,499 7,006 $ 3,493 $ 196 47
Slide 50: The results of operations for oil and gas producing activities shown below exclude sales of purchased natural gas, non-operating income (including gains on sales of oil and gas properties), interest expense and gains and losses resulting from foreign currency exchange transactions. Results of Operations for Oil and Gas Producing Activities For the Years Ended December 31 (Millions of dollars) Therefore, these results are on a different basis than the net income from exploration and production operations reported in management’s discussion and analysis of results of operations and in Note 15 to the financial statements. Total United States Europe Africa, Asia and other 2000 Sales and other operating revenues Unaffiliated customers Inter-company Total revenues Costs and expenses Production expenses, including related taxes Exploration expenses, including dry holes and lease impairment Other operating expenses Depreciation, depletion and amortization Total costs and expenses Results of operations before income taxes Provision (benefit) for income taxes Results of operations Share of equity investee’s results of operations 1999 Sales and other operating revenues Unaffiliated customers Inter-company Total revenues Costs and expenses Production expenses, including related taxes Exploration expenses, including dry holes and lease impairment Other operating expenses Depreciation, depletion and amortization Impairment of assets and operating leases Total costs and expenses Results of operations before income taxes Provision (benefit) for income taxes Results of operations Share of equity investee’s results of operations 1998 Sales and other operating revenues Unaffiliated customers Inter-company Total revenues Costs and expenses Production expenses, including related taxes Exploration expenses, including dry holes and lease impairment Other operating expenses Depreciation, depletion and amortization Impairment of assets and operating leases Total costs and expenses Results of operations before income taxes Provision (benefit) for income taxes Results of operations Share of equity investee’s results of operations *Includes severance and related costs of approximately $32 million. $2,153 944 3,097 557 289 86 667 1,599 1,498 613 $ 885 $ 2 $146 792 938 147 141 44 175 507 431 158 $273 $ — $1,813 152 1,965 361 51 20 450 882 1,083 442 $ 641 $ (3) $194 — 194 49 97 22 42 210 (16) 13 $ (29) $ 5 $ 1,548 450 1,998 487 261 101 604 94 1,547 451 152 $ $ 299 (6) $ 192 450 642 126 96 47 194 59 522 120 43 $ 77 $ — $ 1,242 — 1,242 336 91 34 385 — 846 396 160 $ $ 236 (11) $ 114 — 114 25 74 20 25 35 179 (65) (51) $ (14) $ 5 $ 1,182 314 1,496 518 349 151* 534 162 1,714 (218) (38) $ (180) $ (31) $ 174 254 428 129 133 67 154 7 490 (62) (22) $ (40) $ — $ 975 — 975 357 135 68 351 104 1,015 (40) (22) $ 33 60 93 32 81 16 29 51 209 (116) 6 $(122) $ (6) $ $ (18) (25) 48
Slide 51: The Corporation’s net oil and gas reserves have been estimated by DeGolyer and MacNaughton, independent consultants. The reserves in the tabulation below include proved undeveloped crude oil and natural gas reserves Oil and Gas Reserves that will require substantial future development expenditures. The estimates of the Corporation’s proved reserves of crude oil and natural gas (after deducting royalties and operating interests owned by others) follow: Crude Oil, Condensate and Natural Gas Liquids (Millions of barrels) United States Africa, Asia and other(a) Natural Gas (Millions of Mcf) United States Africa, Asia and other(a) Total Europe Total Europe Net Proved Developed and Undeveloped Reserves At January 1, 1998 Revisions of previous estimates Extensions, discoveries and other additions Purchases of minerals in-place Sales of minerals in-place Production At December 31, 1998 Revisions of previous estimates Extensions, discoveries and other additions Purchases of minerals in-place Sales of minerals in-place Production At December 31, 1999 Revisions of previous estimates Extensions, discoveries and other additions Purchases of minerals in-place Sales of minerals in-place Production At December 31, 2000 Share of equity investee’s reserves(c) At December 31, 1999 At December 31, 2000 Net Proved Developed Reserves At January 1, 1998 At December 31, 1998 At December 31, 1999 At December 31, 2000 Share of equity investee’s reserves(c) At December 31, 1999 At December 31, 2000 595 80 55 45 (5) (75) 695 21 68 4 (5) (85) 698 45 27 88 (7) (96) 755 174 6 6 — — (17) 169 13 5 — — (24) 163 9 7 1 — (24) 156 395 72 22 2 (5) (52) 434 10 49 — — (55) 438 31 16 4 (5) (65) 419 26 2 27 43 — (6) 92 (2) 14 4 (5) (6) 97 5 4 83 (2) (7) 180 1,935 147 227 3 (47) (210) 2,055 34 94 4 (48) (235) 1,904 42 104 10 (4) (249) 1,807 809 35 80 1 (38) (107) 780 (32) 25 4 (48) (124) 605 2 43 8 — (106) 552(b) 951 113 54 2 (9) (102) 1,009 35 60 — — (106) 998 33 47 2 (4) (131) 945 175 (1) 93 — — (1) 266 31 9 — — (5) 301 7 14 — — (12) 310 14 11 — — 9 7 5 4 277 320 — — 2 4 275 316 420 452 513 573 10 9 123 132 136 140 — — 280 293 351 353 8 5 17 27 26 80 2 4 1,342 1,330 1,437 1,429 87 199 497 525 477 476 — — 796 753 841 842 2 2 49 52 119 111 85 197 (a) Includes estimates of reserves under production sharing contracts. (b) Excludes 449 million Mcf of carbon dioxide gas for sale or use in company operations. (c) Reserves for 1998 are not available on a comparable basis. 49
Slide 52: The standardized measure of discounted future net cash flows relating to proved oil and gas reserves required to be disclosed by FAS No. 69 is based on assumptions and judgements. As a result, the future net cash flow estimates are highly subjective and could be materially different if other assumptions were used. Therefore, caution should be exercised in the use of the data presented below. Future net cash flows are calculated by applying yearend oil and gas selling prices (adjusted for price changes provided by contractual arrangements, including hedges) to estimated future production of proved oil and gas Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves At December 31 (Millions of dollars) reserves, less estimated future development and production costs and future income tax expenses. Future net cash flows are discounted at the prescribed rate of 10%. No recognition is given in the discounted future net cash flow estimates to depreciation, depletion, amortization and lease impairment, exploration expenses, interest expense, general and administrative expenses and changes in future prices and costs. The selling prices of crude oil and natural gas have increased significantly and are highly volatile. The year-end prices which are required to be used for the discounted future net cash flows may not be representative of future selling prices. Total United States Europe Africa, Asia and other 2000 Future revenues Less: Future development and production costs Future income tax expenses $25,986 8,672 6,750 15,422 $9,290 1,551 2,565 4,116 5,174 1,923 $3,251 $ — $12,537 4,808 3,597 8,405 4,132 1,132 $ 3,000 $ 44 $4,159 2,313 588 2,901 1,258 614 $ 644 $ 261 $ 1,915 620 537 1,157 758 346 $ $ 412 166 Future net cash flows Less: Discount at 10% annual rate Standardized measure of discounted future net cash flows Share of equity investee’s standardized measure 1999 Future revenues Less: Future development and production costs Future income tax expenses 10,564 3,669 $ 6,895 $ 305 $ 19,858 6,500 5,457 11,957 $ 5,133 1,396 1,167 2,563 2,570 1,027 $ 1,543 $ — $ 12,810 4,484 3,753 8,237 4,573 1,441 $ $ $ 3,132 71 6,457 4,183 795 4,978 1,479 326 $ 1,153 Future net cash flows Less: Discount at 10% annual rate Standardized measure of discounted future net cash flows Share of equity investee’s standardized measure 1998 Future revenues Less: Future development and production costs Future income tax expenses $ $ 7,901 2,814 5,087 237 $ 10,826 6,412 1,411 7,823 $ 2,866 1,479 374 1,853 1,013 403 $ 610 $ 1,503 750 242 992 511 251 $ 260 Future net cash flows Less: Discount at 10% annual rate Standardized measure of discounted future net cash flows $ 3,003 980 2,023 50
Slide 53: Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves For the years ended December 31 (Millions of dollars) 2000 $ 5,087 1999 $ 2,023 1998 $ 2,417 Standardized measure of discounted future net cash flows at beginning of year Changes during the year Sales and transfers of oil and gas produced during year, net of production costs Development costs incurred during year Net changes in prices and production costs applicable to future production Net change in estimated future development costs Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs Revisions of previous oil and gas reserve estimates Purchases (sales) of minerals in-place, net Accretion of discount Net change in income taxes Revision in rate or timing of future production and other changes Total Standardized measure of discounted future net cash flows at end of year (2,540) 536 3,349 (931) 551 396 230 832 (840) 225 1,808 $ 6,895 (1,511) 626 5,002 28 678 244 (112) 288 (2,289) 110 3,064 $ 5,087 (978) 915 (2,215) (273) 220 233 126 435 1,036 107 (394) $ 2,023 51
Slide 54: T E N -Y E A R S U M M A RY O F F I N A N C I A L D ATA Amerada Hess Corporation and Consolidated Subsidiaries Millions of dollars, except per share data 2000 1999(b) 1998 Statement of Consolidated Income Revenues Sales (excluding excise taxes) and other operating revenues Crude oil (including sales of purchased oil) Natural gas (including sales of purchased gas) Petroleum products Other operating revenues Total Non-operating income Gain (loss) on asset sales Equity in income (loss) of HOVENSA L.L.C. Other Total revenues Costs and expenses Cost of products sold Production expenses Marketing expenses Exploration expenses, including dry holes and lease impairment Other operating expenses General and administrative expenses Interest expense Depreciation, depletion and amortization Impairment of assets and operating leases Total costs and expenses Income (loss) before income taxes Provision (benefit) for income taxes Net income (loss) Net income (loss) per share Basic Diluted Dividends Per Share of Common Stock Weighted Average Diluted Shares Outstanding (thousands) $ 2,177 3,470 5,394 952 11,993 — 121 163 12,277 7,883 557 542 289 234 224 162 714 — 10,605 1,672 649 $ 1,023(a) $ 11.48 11.38 $ .60 $1,407 1,856 3,003 773 7,039 273 7 142 7,461 4,240 487 387 261 217 232 158 649 128 6,759 702 264 $ 438(c) $ 4.88 4.85 $ .60 90,280 $ 894 1,711 3,464 511 6,580 (26) (16) 83 6,621 4,373 518 379 349 224 271 153 662 206 7,135 (514) (55) $ (459)(d) $ (5.12) (5.12) $ .60 89,585 89,878 (a) Includes an after-tax gain of $60 million on termination of acquisition, partially offset by a $24 million charge for costs associated with a research and development venture. (b) On January 1, 1999, the Corporation adopted the last-in, first-out (LIFO) inventory method for refining and marketing inventories. (c) Includes after-tax gains on asset sales of $176 million and special tax benefits of $54 million, partially offset by impairment of assets and operating leases of $99 million (after income taxes). (d) Reflects after-tax special charges aggregating $263 million representing impairments of assets and operating leases, a net loss on asset sales and accrued severance. (e) After income taxes, the net gain was $421 million. (f) After income taxes, the net charge was $416 million. See accompanying notes to consolidated financial statements. 52
Slide 55: 1997 1996 1995 1994 1993 1992 1991 $ 1,436 1,414 4,961 413 8,224 16 — 120 8,360 5,578 557 329 422 232 236 136 663 80 8,233 127 119 $ $ $ 8 .08 .08 .60 $ 1,528 1,365 5,081 296 8,270 529(e) — 125 8,924 5,386 621 264 384 129 238 166 722 — 7,910 1,014 354 $ 660 $ 1,565 1,120 4,311 303 7,299 96 — 125 7,520 4,501 611 259 382 186 263 247 840 584(f) 7,873 (353) 41 $ (394) $ (4.26) (4.26) $ .60 $ 1,228 1,063 3,981 328 6,600 42 — 49 6,691 3,795 601 261 331 124 230 245 868 — 6,455 236 162 $ $ $ 74 .80 .79 .60 $ 1,220 1,021 3,349 290 5,880 — — 17 5,897 3,509 626 247 351 242 229 157 759 — 6,120 (223) 45 $ (268) $ (2.91) (2.91) $ .60 $ 1,362 788 3,429 279 5,858 — — 100 5,958 3,214 684 229 324 234 238 147 765 — 5,835 123 115 $ $ $ 8 .09 .09 .60 $ 1,449 574 3,898 346 6,267 — — 151 6,418 3,686 619 263 397 177 223 178 759 — 6,302 116 32 $ 84 $ 7.13 7.09 $ .60 $ 1.05 1.04 $ .60 91,733 93,110 92,509 92,968 92,213 87,286 81,087 53
Slide 56: T E N -Y E A R S U M M A RY O F F I N A N C I A L D ATA Amerada Hess Corporation and Consolidated Subsidiaries Millions of dollars, except per share data 2000 1999 1998 Selected Balance Sheet Data at Year-End Cash and cash equivalents Working capital Property, plant and equipment Exploration and production Refining, marketing and shipping Total — at cost Less reserves Property, plant and equipment — net Total assets Total debt Stockholders’ equity Stockholders’ equity per common share Summarized Statement of Cash Flows Net cash provided by operating activities Cash flows from investing activities Capital expenditures Exploration and production Refining, marketing and other Total capital expenditures Proceeds from sales of property, plant and equipment and other Net cash provided by (used in) investing activities Cash flows from financing activities Issuance (repayment) of notes Long-term borrowings Repayment of long-term debt Issuance of common stock Cash dividends paid Common stock acquired Stock options exercised Net cash provided by (used in) financing activities Effect of exchange rate changes on cash Net increase (decrease) in cash and cash equivalents Stockholder Data at Year-End Number of common shares outstanding (thousands) Number of stockholders (based on number of holders of record) Market price of common stock $ 312 577 $ 41 249 $ 74 90 $10,499 1,399 11,898 7,575 $ 4,323 $10,274 2,050 3,883 $ 43.58 $ 1,843 $ 9,974 1,091 11,065 7,013 $ 4,052 $ 7,728 2,310 3,038 $ 33.51 $ 770 $ 9,718 1,309 11,027 6,835 $ 4,192 $ 7,883 2,652 2,643 $ 29.26 $ 519 (783) (155) (938) (11) (949) (11) — (396) — (54) (220) 59 (622) (1) $ 271 $ (727) (70) (797) 373 (424) 15 990 (1,348) — (54) — 18 (379) — (33) $ (1,307) (132) (1,439) 503 (936) (14) 848 (317) — (55) (59) — 403 (3) (17) 88,744 7,709 $ 73.06 90,676 7,416 $ 56.75 90,357 8,959 $ 49.75 54
Slide 57: 1997 1996 1995 1994 1993 1992 1991 $ 91 464 $ 113 690 $ 56 358 $ 53 520 $ 80 245 $ 141 551 $ 120 625 $ 8,780 3,842 12,622 7,431 $ 5,191 $ 7,935 2,127 3,216 $ 35.16 $ 1,250 $ 8,233 3,669 11,902 6,995 $ 4,907 $ 7,784 1,939 3,384 $ 36.35 $ 808 $ 9,392 3,672 13,064 7,694 $ 5,370 $ 7,756 2,718 2,660 $ 28.60 $ 1,241 $ 9,791 4,514 14,305 7,939 $ 6,366 $ 8,338 3,340 3,100 $ 33.33 $ 957 $ 9,361 4,426 13,787 7,052 $ 6,735 $ 8,642 3,688 3,029 $ 32.71 $ 819 $ 9,204 3,887 13,091 6,647 $ 6,444 $ 8,722 3,186 3,388 $ 36.59 $ 1,138 $ 9,307 3,223 12,530 6,339 $ 6,191 $ 8,841 3,266 3,132 $ 38.63 $ 1,364 (1,158) (188) (1,346) 63 (1,283) 2 398 (209) — (55) (122) — 14 (2) $ (21) $ (788) (73) (861) 1,037 176 (72) — (795) — (56) (8) — (931) 3 56 $ (626) (66) (692) 146 (546) 26 25 (689) — (56) — — (694) 2 3 $ (532) (64) (596) 73 (523) (54) 290 (642) — (56) — — (462) 1 (27) $ (755) (593) (1,348) 12 (1,336) 118 548 (168) — (42) — — 456 — (61) $ (917) (641) (1,558) 26 (1,532) (160) 675 (524) 497 (64) — — 424 (9) 21 $ (1,295) (417) (1,712) 37 (1,675) (183) 786 (269) — (37) — — 297 4 (10) 91,451 9,591 $ 54.88 93,073 10,153 $ 57.88 93,011 11,294 $ 53.00 92,996 11,506 $ 45.63 92,587 12,000 $ 45.13 92,584 13,088 $ 46.00 81,068 13,732 $ 47.50 55
Slide 58: T E N -Y E A R S U M M A RY O F O P E R AT I N G D ATA Amerada Hess Corporation and Consolidated Subsidiaries 2000 Production Per Day (net) Crude oil (thousands of barrels) United States United Kingdom Norway Denmark Gabon Indonesia Azerbaijan Algeria Canada and Abu Dhabi Total Natural gas liquids (thousands of barrels) United States United Kingdom Norway Thailand Canada Total Natural gas (thousands of Mcf) United States United Kingdom Norway Denmark Indonesia Thailand Canada Total Well Completions (net) Oil wells Gas wells Dry holes Productive Wells at Year-End (net) Oil wells Gas wells Total Undeveloped Net Acreage at Year-End (thousands) United States Foreign(a) Total Shipping Vessels owned or under charter at year-end Total deadweight tons (thousands) Refining (thousands of barrels per day) Amerada Hess Corporation HOVENSA L.L.C.(c) Petroleum Products Sold (thousands of barrels per day) Gasoline, distillates and other light products Residual fuel oils Total Storage Capacity at Year-End (thousands of barrels) Number of Employees (average) (a) Includes acreage held under production sharing contracts. (b) Through ten months of 1998. (c) Reflects 50% of HOVENSA refinery crude runs from November 1, 1998. (d) Includes approximately 5,400 employees of retail operations. 1999 1998 55 119 25 25 7 4 3 2 — 240 12 6 2 1 — 21 288 297 24 37 10 23 — 679 29 11 18 774 188 962 616 14,419 15,035 8 884 — 211 304 62 366 37,487 9,891(d) 55 112 25 7 10 3 2 — — 214 10 5 2 1 — 18 338 258 31 3 5 8 — 643 28 11 9 735 161 896 678 15,858 16,536 8 884 — 209 284 60 344 38,343 8,485 37 109 27 — 14 3 — — — 190 8 6 2 — — 16 294 251 28 — 3 — — 576 28 20 25 721 252 973 748 16,927 17,675 9 952 419(b) 217 411 71 482 56,070 9,777 56
Slide 59: 1997 1996 1995 1994 1993 1992 1991 35 126 30 — 10 1 — — — 202 8 6 2 — — 16 312 226 30 — 1 — — 569 42 11 24 860 447 1,307 915 10,180 11,095 14 1,602 411 — 436 73 509 87,000 9,216 41 135 28 — 9 — — — 6 219 9 7 2 — — 18 338 254 30 — — — 63 685 39 25 40 854 455 1,309 891 7,455 8,346 13 1,236 396 — 412 83 495 86,986 9,085 52 135 26 — 10 — — — 17 240 11 7 1 — 2 21 402 239 28 — — — 215 884 33 41 50 2,154 1,160 3,314 1,440 5,871 7,311 16 2,010 377 — 401 86 487 89,165 9,574 56 122 24 — 9 — — — 18 229 12 7 1 — 2 22 427 209 24 — — — 186 846 28 44 24 2,160 1,146 3,306 1,685 4,570 6,255 17 2,265 388 — 375 93 468 94,597 9,858 60 80 26 — 8 — — — 22 196 12 4 1 — 2 19 502 188 29 — — — 168 887 48 49 37 2,189 1,115 3,304 1,854 4,310 6,164 15 2,398 351 — 291 95 386 94,380 10,173 62 86 30 — 7 — — — 23 208 11 1 2 — 2 16 602 153 32 — — — 138 925 33 20 22 2,082 966 3,048 1,819 3,168 4,987 21 3,223 335 — 275 102 377 95,199 10,263 66 60 28 — 9 — — — 22 185 10 1 2 — 2 15 584 128 27 — — — 104 843 45 41 36 2,103 927 3,030 1,802 3,480 5,282 21 2,825 320 — 285 128 413 94,879 10,317 57
Slide 60: Amerada Hess Corporation Amerada Hess Corporation and Consolidated Subsidiaries BOARD OF DIRECTORS John B. Hess (1) Chairman of the Board and Chief Executive Officer Nicholas F. Brady (1) (3) (5) Chairman, Darby Overseas Investments, Ltd.; Former Secretary of the United States Department of the Treasury; Former Chairman, Dillon, Read & Co., Inc. J. Barclay Collins II Executive Vice President and General Counsel Peter S. Hadley (3) (4) Former Senior Vice President Metropolitan Life Insurance Company Edith E. Holiday (2) (4) (5) Attorney; Former Assistant to the President and Secretary of the Cabinet; Former General Counsel United States Department of the Treasury William R. Johnson Chairman, President and Chief Executive Officer H.J. Heinz Company Thomas H. Kean (1) (2) (4) (5) President, Drew University; Former Governor State of New Jersey W. S. H. Laidlaw (1) President and Chief Operating Officer Frank A. Olson Chairman of the Board The Hertz Corporation Roger B. Oresman (4) Consulting Partner Milbank, Tweed, Hadley & McCloy John Y. Schreyer (1) Executive Vice President and Chief Financial Officer William I. Spencer (1) (2) (3) (4) Former President and Chief Administrative Officer Citicorp and Citibank, N.A. Robert N. Wilson (2) (3) Vice Chairman of the Board of Directors, Johnson & Johnson Robert F. Wright (1) Former President and Chief Operating Officer Amerada Hess Corporation DIRECTOR EMERITUS H. W. McCollum Former Chairman of the Executive Committee (1) Member of Executive Committee (2) Member of Audit Committee (3) Member of Compensation Committee (4) Member of Employee Benefits and Pension Committee (5) Member of Directors and Board Affairs Committee OFFICERS John B. Hess Chairman of the Board and Chief Executive Officer W. S. H. Laidlaw President and Chief Operating Officer J. B. Collins II Executive Vice President and General Counsel J. Y. Schreyer Executive Vice President and Chief Financial Officer Senior Vice Presidents A. A. Bernstein F. L. Clark J. A. Gartman N. Gelfand G. A. Jamin Treasurer L. H. Ornstein R. P. Strode F. B. Walker Vice Presidents S. J. Austin G. C. Barry R. J. Bartzokas L. L. Chan E. C. Crouch M. L. Eisenhower D. E. Friedman J. P. Gehegan R. E. Guerry S. E. Hankin W. R. Hanna J. S. Harvey L. J. Kupfer E. J. Kutcher R. J. Lawlor D. C. Lutken, Jr. J. J. Lynett W. D. Marshall L. S. Massaro R. K. May R. S. C. Phillips J. P. Rielly Controller R. B. Ross H. I. Small J. J. Steed D. G. Stevenson C. T. Tursi Secretary S. A. Villas Assistant Controllers K. G. Daley D. B. Douty M. W. Johnson D. M. Steffens S. J. Steigerwald J. T. Wilders Assistant Corporate Secretary T. B. Garcia Assistant Treasurers R. Birkenholz R. B. Kirby A. D. Lopena Associate General Counsel N. P. Brountas C. S. Colman 58
Slide 61: COMMON STOCK Transfer Agents The Bank of New York Shareholder Relations Department-11E P.O. Box 11258 Church Street Station New York, New York 10286 1-800-524-4458 e-mail: shareowner-svcs@bankofny.com First Union National Bank Corporate Trust Department Shareholder Administration Group 1525 West W. T. Harris Boulevard Charlotte, North Carolina 28288 Registrar The Bank of New York Shareholder Relations Department-11E P.O. Box 11258 New York, New York 10286 1-800-524-4458 Listed New York Stock Exchange (ticker symbol: AHC) CORPORATE HEADQUARTERS Amerada Hess Corporation 1185 Avenue of the Americas New York, New York 10036 (212) 997-8500 OPERATING OFFICES Exploration and Production Amerada Hess Corporation One Allen Center 500 Dallas Street Houston, Texas 77002 Amerada Hess Limited 33 Grosvenor Place London SW1X 7HY England Amerada Hess Norge A/S Langkaien 1, N-0150 Oslo, Norway Amerada Hess ApS Ostergade 26B DK-1100 Copenhagen K Denmark Amerada Hess Production Gabon P.O. Box 20316 Libreville, Gabon Refining and Marketing Amerada Hess Corporation 1 Hess Plaza Woodbridge, New Jersey 07095 FORM 10-K A copy of the Corporation’s 2000 Annual Report on Form 10-K to the Securities and Exchange Commission will be made available to interested stockholders upon written request to the Corporate Secretary, Amerada Hess Corporation, 1185 Avenue of the Americas, New York, New York 10036. e-mail: investorrelations@hess.com ANNUAL MEETING The Annual Meeting of Stockholders will be held on Wednesday, May 2, 2001 at 2:00 P.M., 1 Hess Plaza, Woodbridge, New Jersey 07095. DIVIDEND REINVESTMENT PLAN Information concerning the Dividend Reinvestment Plan available to holders of Amerada Hess Corporation Common Stock may be obtained by writing to The Bank of New York Dividend Reinvestment Department, P.O. Box 1958, Newark, New Jersey 07101 Amerada Hess Internet Home Page www.hess.com Design: Inc Design, incdesign.com © 2001 Amerada Hess Corporation Printed on Recycled Paper 3
Slide 62: A M E R A DA H E S S C O R P O R AT I O N 1185 Avenue of the Americas New York, New York 10036 http://www.hess.com 4