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Slide 1: Amerada Hess Corporation 1185 Avenue of the Americas New York, New York 10036 AMERADA HESS ANNUAL REPORT 1999 199 9 ANNUAL REPORT
Slide 2: THE CONTENTS 2. A Tribute to Leon Hess 4. Letter to Stockholders 8. Exploration and Production 16. Refining and Marketing 19. Index to Financial Information 58. Directors and Officers 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 CIBC Mellon Trust Company 393 University Avenue 5th Floor Toronto, Ontario M5G 2M7 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 A/S 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 1999 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 3, 2000 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 © 2000 Amerada Hess Corporation Cover Photo: SOUTH ARNE, DENMARK Printed on Recycled Paper
Slide 3: Financial and Operating Highlights Amerada Hess Corporation and Consolidated Subsidiaries Dollar amounts in thousands, except per share data 1999 1998 Financial — For The Year Sales and other operating revenues Operating earnings (loss) Net income (loss) Net income (loss) per share (diluted) 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—barrels per day United States Foreign $7,039,138 $ 306,511 $ 437,616(a) $4.85(a) $ .60 $ 796,657 90,280 $6,579,892 $ (196,051) $ (458,893)(b) $(5.12)(b) $ .60 $1,438,678 89,585 $7,727,712 $2,309,681 $3,038,192 $7,882,983 $2,652,465 $2,643,412 64,605 167,802 232,407 44,920 161,069 205,989 Total Natural gas—Mcf per day United States Foreign Total Refining and marketing—barrels per day Refining crude runs Amerada Hess Corporation HOVENSA L.L.C.(d) Refined products sold 338,044 304,500 642,544 293,849 282,628 576,477 — 209,000 344,000 419,000(c) 217,000 482,000 (a) Includes after-tax gains on asset sales of $176,000 ($1.95 per share) offset by other after-tax special charges of $44,900 ($.50 per share). (b) Includes after-tax special charges aggregating $262,800 ($2.93 per share) representing impairments of assets and operating leases, a net loss on asset sales and accrued severance. (c) Through ten months of 1998. (d) Reflects the Corporation’s 50% share of HOVENSA’s crude runs. See Management’s Discussion and Analysis of Results of Operations beginning on page 20. 1
Slide 4: A TRIBUTE TO L EON H ESS A builder, a dreamer, a driven and determined leader. A self made man with incredible vision, tireless energy and great wisdom. A true patriot, with a strong sense of the American dream. A religious man. Above all, a family man. When he was young his mother taught him that a good name was the greatest asset a man could have. He lived by that important lesson. Of all the praise he received, perhaps that which best characterized Leon Hess was that “His word was his bond.” A handshake was all that was necessary with Leon Hess. Leon Hess was born in Asbury Park, New Jersey, on March 14, 1914. His family was of modest means. He grew up during the Depression, and his family could not afford to send him to college. In 1933, he started a fuel oil busi1914-1999 ness, often working seven days a week delivering fuel oil in five gallon cans to homes in New Jersey from a second hand, 615 gallon delivery truck. In 1938, Leon Hess purchased land in Perth Amboy, New Jersey where he built his first oil storage terminal, the initial step in constructing the largest oil storage network on the East Coast of the United States. His customers could always rely on him for supply. From 1942 to 1945, he served as head of transportation logistics for General Patton. He fueled Patton’s “Red Ball Express” as the Third Army raced across Europe. For this he was promoted to Lieutenant Colonel. It was one of many proud moments in his life. After his return from World War II, he married Norma Wilentz, daughter of the prominent lawyer and former New Jersey Attorney General, David Wilentz. Mr. Wilentz had kindly offered to keep an eye on Leon’s terminal property while he was away at war. David Wilentz became Leon’s father-in-law, advisor and close personal friend. Leon Hess had an endless passion for the oil industry. He learned and knew every detail of the business. He traveled the globe for over 50 years developing relationships in countries such as Venezuela, Abu Dhabi, Saudi Arabia, Iran, Algeria, Libya, Gabon, the United Kingdom and Norway. Wherever he went he left his mark. The business leaders, ministers and heads of state he met were charmed by the magic, sincerity, honesty and eloquence of Leon Hess. Inevitably, he earned their deep respect. 2
Slide 5: In 1958, Leon Hess built a refinery in Port Reading, New Jersey. In 1960, he built his first HESS gasoline station and in 1964 began the legendary HESS toy truck holiday tradition. In 1965, he began his proudest achievement in business – the biggest project he ever undertook – the building of one of the world’s largest refineries in St. Croix, U.S. Virgin Islands. He was proud, not only of its enormous size, but also of the economic benefits it provided people in the Virgin Islands. The facility has trained over 4,000 Virgin Islanders. It is the Virgin Islands’ largest private employer, providing jobs to over 2,000 workers. Leon Hess was as proud of the jobs he created as he was of the facilities he built. Leon Hess had a special love for his football team, the New York Jets. A proud moment in his life was the team’s 1969 Super Bowl victory. He derived tremendous pleasure from watching the team over the years along with the loyal Jets fans. Leon Hess felt a great responsibility to care for others. He treated his employees, colleagues, friends and football players as if they were members of his family. When any of them was ill or injured, he was quick to offer his help. When Jets’ player Dennis Byrd suffered a serious injury that initially left him totally paralyzed, Leon Hess not only arranged for medical care, but also visited him at the hospital every day. Fortunately, Dennis had a miraculous recovery. He was a major contributor to educational institutions, medical schools, hospitals and cultural institutions. Throughout his life, he modestly and quietly contributed to his communities. So serious was his sense of social responsibility that when Hurricane Allen devastated Saint Lucia, where Amerada Hess has an oil storage terminal, and destroyed most of the island’s schools, he set up a fund to rebuild the schools. Over 70 schools were rebuilt, providing education for 30,000 children. Yet even this large undertaking he completed without fanfare, rewarded by the fact that these children would continue their education. Leon Hess’ greatest single love in life was Norma, his wife of 51 years. No two people were more devoted and loving. His greatest joy was his family, his three children and seven grandchildren. His son John, now Chairman and Chief Executive Officer of Amerada Hess, gave this tribute to his father at his memorial service on May 10, 1999, “No one had higher standards of ethics and values, nor was more modest, nor had more goodness to share than my father. Leon Hess was an angel in our midst. While his journey on earth has come to an end, his proud legacy will long live on through our family and the memory of all he stood for will endure.” Leon Hess is deeply missed by his family, his friends, his colleagues at Amerada Hess and by all who knew him. He will never be forgotten. 3
Slide 6: TO OUR STOCKHOLDERS We entered the year 2000 with increasing momentum toward achieving our goal of providing superior financial returns. We continue to increase our crude oil and natural gas production and expand our retail marketing business. We have made substantial progress in implementing the business plan adopted in 1995 to reshape the Company’s asset base to improve financial performance. That business plan resulted in the sale of over $2 billion of mature, low return assets and investments in higher return projects, including 15 crude oil and natural gas field developments. 1999 began with oil prices near an historical low of $12.34 per barrel. By year-end, prices had reached $25.90 and have continued to strengthen. Refining margins remained under severe pressure throughout the year and into 2000, but have improved recently. During 1999 we: • • Increased production to 339,000 barrels of oil equivalent per day from 302,000 barrels per day in 1998. Reduced operating costs by about $100 million, split nearly equally between exploration and production and refining and marketing. • Sold $340 million of terminal and retail marketing assets and $55 million of onshore California natural gas properties. • Reduced debt by $343 million and improved our total debt to capitalization ratio to 43% from 50% at year-end 1998. Throughout the year, we maintained financial discipline and significantly strengthened our balance sheet. We completed development of seven new oil and gas fields, reduced capital expenditures by $642 million to $797 million, reduced exploration expenses by $88 million to $261 million and continued to expand and upgrade our HESS retail network. We face both significant challenges and great opportunities as we begin a new century. E X P L O R AT I O N A N D P R O D U C T I O N We now have onstream 12 of the new oil and gas fields in which we invested to replace the mature properties sold as part of our restructuring. These new fields have superior financial returns and contributed strongly to the Company’s exploration and production earnings of $174 million in the fourth quarter of 1999. Our total unit cost per barrel of oil equivalent production dropped to $11.75 in 1999 from $13.80 in 1998 and $14.50 in 1997. 4
Slide 7: Exploration and production continues to be the primary vehicle for future income and growth. We expect to increase production in 2000 by about 10% over 1999 levels on a crude oil equivalent basis. Our challenge in exploration and production is to continue to provide long-term, profitable growth. Our exploration and production strategy will be balanced among exploration, reserve development and reserve acquisitions. In 2000: • • • We have a focused exploration program comprising 35 wells. We are pursuing field redevelopment and reserve development opportunities. We will seek reserve acquisition opportunities that offer low cost production and volumetric upside in strategic areas. Our goal is to increase to one third the portion of our oil and gas reserves that are outside the United States and the North Sea. Currently, 14% of our reserves are outside those areas. We have initiatives under way in our focus areas of Brazil, North and West Africa and Central and Southeast Asia. We are increasing our exposure to less mature areas that offer the potential for high-impact, longlife reserves to balance our portfolio, which currently is weighted toward the high net present value, but shorter life reserves generally found in the Gulf of Mexico and the North Sea. Attractive opportunities are available as countries that previously excluded foreign investment now actively seek it. Consolidation in the petroleum industry and the high debt levels of certain companies will result in assets becoming available. Our strong financial position permits us to pursue transactions that meet our strategic goals and financial return objectives. The results of our 1999 exploration program fell short of our targets, in part due to a severely reduced program. However, we did replace about 90% of our production excluding purchases and sales. Probable reserves increased slightly. At year-end 1999, we had over one billion barrels of proved reserves and more than seven hundred million barrels of probable reserves, on a barrel of oil equivalent basis. Two thirds of our proved reserves are crude oil and one third is natural gas. REFINING AND MARKETING The Company’s refining and marketing operations improved in 1999 despite one of the weakest years in history for refining margins and modest retail margins. The Company reported profitable operations in each quarter of 1999. Our challenge in refining and marketing is to achieve double-digit returns on 5
Slide 8: capital employed in a business that has traditionally suffered from low margins and relatively poor financial performance. Refining and marketing will be a smaller portion of the Company’s portfolio of assets with less exposure to refining, but more to marketing. We will selectively invest to expand our HESS retail marketing business along the East Coast of the United States and pursue opportunities to expand our energy marketing business with our industrial and commercial customers in the northeast United States. Early this year HOVENSA, the joint venture refinery company owned by Amerada Hess and Petroleos de Venezuela S.A., began constructing a 58,000 barrel per day delayed coking unit and related facilities that will further enhance financial returns for the St. Croix refinery. The $535 million construction project, being financed by HOVENSA, will take approximately two years. Currently, HOVENSA is processing approximately 155,000 barrels per day of Venezuelan crude oil. Upon completion of construction of the coker, 115,000 barrels per day of less expensive, heavy Venezuelan crude oil also will be processed at the refinery. With the addition of the coker and favorable crude oil supply arrangements, we envision the St. Croix refinery being the preeminent merchant refinery in the world. Financial returns from our expanding retail marketing business showed considerable improvement in 1999. Our retail marketing initiatives emphasize: • • • Building new HESS EXPRESS stores to provide one-stop shopping, quality and convenience. Adding convenience stores to all retail locations. Acquisitions in select markets along the East Coast of the United States. We continued to reshape our retail marketing asset base by selling 40 outlets in areas where our gasoline margins have been weak and purchasing 60 retail outlets in Pennsylvania and Florida which are higher margin markets for us. In the second quarter, we will purchase 178 Merit retail sites that will be converted to the HESS brand. We expect to have about 950 HESS retail outlets by the end of 2000, compared with 548 at the end of 1995. In energy marketing, our strategy is to be a total energy provider to our industrial and commercial customers in the northeastern United States. We have reached agreement to purchase the energy marketing business of Statoil Energy Services, a transaction that will more than double the Company’s sales of natural gas to end users and supplement its fuel oil business. The transaction also adds to our Company a well managed, highly professional organization and operation and provides a customer base for expansion of high value electricity sales. 6
Slide 9: S H A R E H O L D E R VA L U E Our corporate challenge is to increase current returns to shareholders and shareholder value while continuing to grow our business and maintain a strong balance sheet. Given the successful restructuring of our asset base, the Company’s earnings outlook and strong financial position and the conviction that our Common Stock is an excellent investment, your Board of Directors has authorized spending up to $300 million to repurchase shares of Common Stock. R E S U LT S O F O P E R AT I O N S Amerada Hess had operating earnings of $307 million in 1999 compared with an operating loss of $196 million in 1998. Excluding special items, exploration and production earned $324 million in 1999 compared with a loss of $18 million in 1998. Refining and marketing operations posted a profit of $133 million versus a loss of $18 million in 1998. Interest expense and other corporate charges were $150 million in 1999 compared with $160 million in 1998. Results including special items amounted to net income of $438 million ($4.85 per share) versus a loss of $459 million in 1998 ($5.12 per share). Details of results of operations appear under Management’s Discussion and Analysis of Results of Operations and Financial Condition beginning on page 20 of this Annual Report. We thank our employees for their hard work and dedication in helping us through the financial challenges that we faced in 1998 and early in 1999 and for their many contributions in successfully reshaping the Company’s asset base to improve financial performance. We express our deep appreciation to our Directors for their continued wise guidance and advice. We thank our stockholders for their support and confidence. We are excited about the Company’s future and the initiatives we have under way to continue the Company’s profitable growth. JOHN B. HESS Chairman of the Board and Chief Executive Officer March 1, 2000 7 W.S.H. LAIDLAW President and Chief Operating Officer
Slide 10: EXPLORATION AND PRODUCTION U N I T E D S TAT E S Crude oil and natural gas liquids production in the United States increased to 64,600 barrels per day in 1999 from 44,900 barrels per day in 1998. Natural gas production increased to 338,000 Mcf per day from 294,000 Mcf per day in 1998. The increased production was primarily due to a full year of peak production from the Baldpate Field on Garden Banks Blocks 259 and 260. The Corporation’s net production from Baldpate reached peak levels of 26,800 barrels of crude oil and natural gas liquids per day and 77,000 Mcf of natural gas per day during the year. Amerada Hess is the operator of the Baldpate Field with a 50% interest. Northwest of the Baldpate Field, Amerada Hess is developing the Conger Field (AHC 37.50%) on Garden Banks Block 215. The third development well was successfully drilled in 1999 and installation of high-pressure, subsea trees and related facilities is scheduled to begin during the summer of 2000. Three subsea wells will be tied back to the Garden Banks Block 172 “B” Platform which is located on the Enchilada Field. Initial production from the Conger Field is scheduled for late 2000 with the Corporation’s share of production expected to reach 7,000 barrels of oil per day and 35,000 Mcf of natural gas per day in 2001. Amerada Hess drilled a successful appraisal well on the Northwestern Field on Garden Banks Block 200 in 1999. The Corporation is in the final stages of engineering the development of the Northwestern Field, which is located in 1,750 feet of water. Production is expected to begin late in 2000 and the Corporation’s share of production is expected to peak at about 35,000 Mcf of natural gas per day in 2001. Amerada Hess has a 50% interest in the Northwestern Field. On the South Pass Block 89 Field (AHC 33.33%) five successful development wells in 1999 increased the Corporation’s average production to 16,000 Mcf of natural gas per day and 3,000 barrels of oil per day from a previous level of 8,000 Mcf of natural gas per day and 1,500 barrels of oil per day. On Galveston Block 210 (AHC 55%), the Corporation drilled a successful development well that currently is producing at a gross rate of 12,000 Mcf of natural gas per day. Onshore, Amerada Hess produces 33,000 barrels of crude oil and natural gas liquids and 147,000 Mcf of natural gas per day. About 40% of this production is in North Dakota where the Corporation drilled 14 horizontal wells on fields in which it has, on average, 89% interests. Infill and extension drilling is ongoing in the area. 8
Slide 11: GULF OF MEXICO
Slide 12: NORTH SEA
Slide 13: UNITED KINGDOM Production in the United Kingdom North Sea increased to 117,800 barrels of crude oil and natural gas liquids per day and 257,800 Mcf of natural gas per day from 115,450 barrels per day and 251,000 Mcf per day in 1998. Five new fields were brought onstream in 1999, development of the Bittern Field was nearly completed and older fields maintained good production rates. The Renee (AHL 14%) and Rubie (AHL 19.20%) Fields began producing crude oil in February 1999 through the Ivanhoe/Rob Roy facilities operated by Amerada Hess Limited, the Corporation’s British subsidiary. Amerada Hess Limited’s share of production from those fields is averaging 4,000 barrels of oil per day. Production began from the Neptune and Mercury Fields as part of phase one of the development of the Easington Catchment Area of the southern North Sea. Amerada Hess Limited’s share of production from these fields, in which it has approximately 23% interests, will average about 40,000 Mcf of natural gas per day in 2000. The Buckland Field (AHL 14.07%) came onstream in August 1999. Production for Amerada Hess Limited currently is averaging about 4,000 barrels of oil per day and 7,000 Mcf of natural gas per day. The Triton floating production, storage and offloading vessel for the Bittern Field has sailed to location. Production from the Bittern Field is expected to commence early in the second quarter and Amerada Hess Limited’s share of production will peak at 15,000 barrels of oil per day late in 2000. Amerada Hess Limited manages the joint team that will operate the production facilities and has a 29.12% interest in the field. The Skene Field (AHL 9.07%) is expected to be sanctioned for development in the second quarter of 2000. Amerada Hess Limited’s share of production is expected to peak at 24,000 Mcf of natural gas per day late in 2001. Approval for development of the Cook Field (AHL 28.46%) located on Block 21/20a in the central North Sea has been received. The field is expected to come onstream late in the second quarter of 2000 and net production is expected to peak at 4,000 barrels of oil per day in 2002. An appraisal program is in progress for the natural gas discoveries on Blocks 13/30a (AHL 90%), 14/26a (AHL 20%) and 20/4b (AHL 55%). Development decisions are likely to be made during 2000. 11
Slide 14: DENMARK Amerada Hess A/S, the Corporation’s Danish subsidiary, brought the South Arne Field onstream in the third quarter of 1999. Amerada Hess A/S developed the field with a concrete gravity base and integrated top sides. Net production is expected to average 30,000 barrels of oil per day and 40,000 Mcf of natural gas per day for Amerada Hess A/S in 2000. Further development wells, including water injectors, are being drilled to enhance future recovery. Amerada Hess A/S is the operator of the South Arne Field and has a 57.48% interest in the field. N O R W AY Amerada Hess Norge A/S, the Corporation’s Norwegian subsidiary, and its partners continue to evaluate the large enhanced-recovery, waterflood project for the Valhall Field, in which Amerada Hess Norge has a 28.09% interest. Early in 2000, the Norwegian Government provided royalty relief for fields on the Norwegian Continental Shelf. That decision is expected to accelerate the decision making process for the waterflood project and increase Amerada Hess Norge’s share of production from the Valhall Field by about 2,000 barrels of oil per day. Production for Amerada Hess Norge averaged 27,009 barrels of crude oil and natural gas liquids per day and 30,600 Mcf of natural gas per day in 1999. GABON Amerada Hess Production Gabon, in which Amerada Hess has a 77.50% interest, has a 40% interest in the Atora Field which is being developed. Production is expected to begin late in 2000 and to peak at a rate of 4,000 barrels of oil per day for Amerada Hess. By year-end 2000, the Corporation’s Gabonese production is expected to reach 11,000 barrels of oil per day compared with the current level of 7,000 barrels per day. Current production is primarily from the Rabi Kounga Field, in which Amerada Hess Production Gabon has a 10% interest. Amerada Hess Production Gabon plans to participate in the drilling of three exploration wells in Gabon in 2000. 12
Slide 15: BRAZIL Seismic was shot over 4,000 square kilometers on Block BS-2 on the Santos Basin and BC-8 in the Campos Basin. Amerada Hess is the operator of these blocks with a 32% interest and exploration drilling is planned on both blocks in 2000. During 1999, Amerada Hess acquired a 45% interest and operatorship of Block BMS-3 in the Santos Basin, on which acquisition of seismic is planned for 2000. Early in 2000, Amerada Hess acquired a 16% interest in Block BCE-2 in the Ceara Basin. Amerada Hess now has 1,427,700 net acres in Brazil. INDONESIA On the Jabung Production Sharing Contract (PSC) in which Amerada Hess holds a 30% interest, the North and Northeast Betara Fields and the Gemah discovery have been successfully appraised. The first phase of oil production is expected to begin late in 2000 and negotiations for sale of natural gas from the fields are nearly complete. The Corporation’s share of production from the producing fields on the Jabung PSC, North Geragai and Makmur, is averaging about 3,000 barrels of oil per day. On the Jambi Merang License (AHC 25%), the Corporation’s share of production from the Gelam Field has averaged 5,700 Mcf of natural gas per day and 100 barrels of condensate per day since the interest was acquired in August 1999. On an adjacent discovery, the Pulau Gading Field, two successful appraisal wells were drilled in 1999 with gross flow rates of up to 17,000 Mcf of natural gas per day. Various options for developing the Pulau Gading Field are being assessed. On the Lematang PSC, which Amerada Hess operates with a 70% interest, a successful natural gas discovery well was drilled on the Singa Field in 1999. Possible development scenarios for the development of this discovery are being analyzed. Emphasis is being placed on the sale of this natural gas to local markets. Further appraisal drilling is planned in 2000 on the Pangkah PSC, in which the Corporation has a 36% interest. An oil and gas discovery was made on this concession in 1998. In Indonesia, Amerada Hess has interests in five Production Sharing Contracts covering 3,300,000 net acres and plans to drill a total of six exploration wells in 2000. 13
Slide 16: THAILAND Amerada Hess has a 15% interest in the Pailin Field that came onstream in August 1999. The Corporation’s share of production is currently averaging 25,000 Mcf of natural gas per day and 1,500 barrels of condensate per day. Natural gas production is expected to increase to 50,000 Mcf of natural gas per day as demand justifies bringing the phase two development onstream. The Pailin Field is offshore Thailand and its production is sold in the Thailand gas market. M A L AY S I A Amerada Hess expects to drill one well each on SK-306 (AHC 80%) and PM-304 (AHC 70%) in 2000. There are oil and gas discoveries on these blocks and the Corporation will evaluate the commercial potential of the hydrocarbons on these blocks. VIETNAM Amerada Hess acquired a 24.50% interest in Block 16-1 in the Mekong Basin, offshore Vietnam, in 1999. Seismic work is planned in 2000. AZERBAIJAN Amerada Hess has a 1.68% equity interest in the Azeri, Chirag and Guneshli Fields being developed in the Caspian Sea by the AIOC consortium. Current net production is 1,500 barrels of oil per day and is expected to peak in 2008 at about 14,000 barrels of oil per day, assuming pipeline capacity is increased. Amerada Hess has acquired an interest in the Kursanga and Karabagly Fields onshore Azerbaijan and plans for the rehabilitation of these fields have been approved. The Corporation’s share of production from these fields is expected to rise from approximately 1,300 barrels of oil per day in 2000 to a peak of 7,000 barrels of oil per day in 2005. 14
Slide 17: PAILIN FIELD, THAILAND
Slide 18: ORLANDO, FLORIDA
Slide 19: REFINING AND MARKETING REFINING The past year was the first full year of operation for HOVENSA L.L.C., the joint venture between Amerada Hess and Petroleos de Venezuela, S.A. that owns and operates the St. Croix refinery. Despite some of the worst refining margins in history, HOVENSA was profitable for the year. HOVENSA supplies refined petroleum products to both joint venture partners for markets primarily on the East Coast and Gulf Coast of the United States as well as to third parties in the Caribbean. Capitalizing on its strategic location and operational capabilities to maximize profitability, HOVENSA shipped 16 cargoes of gasoline and distillates to California in 1999 during periods of shortages caused by refinery outages on the West Coast of the United States. Early in 2000, HOVENSA secured financing for the construction of a 58,000 barrel per day delayed coking unit. The coking unit will enable the refinery to process lower cost, heavy crude oil that will enhance financial returns and make the refinery one of the most sophisticated in the world. The refinery currently is processing 155,000 barrels per day of Venezuelan Mesa crude oil. Upon completion of construction of the coking unit, the refinery will also process 115,000 barrels per day of lower cost, Venezuelan Merey crude oil. Construction of the delayed coking unit and related facilities is expected to take about two years. Refinery runs at HOVENSA averaged 418,000 barrels per day in 1999. The refinery’s fluid catalytic cracking unit operated at rates that reached 140,000 barrels per day at times during 1999, making it one of the largest fluid catalytic cracking units in the world. The Corporation’s Port Reading fluid catalytic cracking unit ran at a rate of approximately 60,000 barrels per day in 1999 processing vacuum gas oil and residual fuel oil to manufacture primarily high quality gasoline for markets in the northeast. 17
Slide 20: MARKETING Amerada Hess is building high-volume HESS EXPRESS convenience retail sites, upgrading existing gasoline stations and convenience stores, making acquisitions in key geographic areas and increasing the number of independent HESS branded retailers. The number of HESS retail outlets increased to 701 at year-end 1999 from 637 at year-end 1998. It is anticipated that by the end of 2000 there will be approximately 950 HESS retail outlets. During 1999, 21 new HESS EXPRESS stores were opened, and construction began on 10 others. Twenty-three retail sites were upgraded by adding convenience stores or rebuilding existing facilities. The Corporation acquired 50 retail sites in central Pennsylvania and 10 retail sites in Florida. Early in 2000, Amerada Hess reached agreement to purchase 178 Merit retail gasoline stations located in the northeast. All of the stations will be rebranded HESS. This acquisition greatly strengthens the HESS brand in the New York City, Boston and Philadelphia metropolitan areas and is expected to close early in May. The reshaping of the Corporation’s downstream asset base for increased profitability continued in 1999 with the sale of 12 terminals with approximately 19 million barrels of storage capacity and 40 retail sites in Atlanta, Georgia and Greenville, South Carolina where fuel margins for the Corporation were lower than in its other markets. Proceeds from these sales aggregated $340 million. Early in 2000, the Corporation strengthened its energy marketing position on the East Coast of the United States when it reached agreement to purchase the energy marketing business of Statoil Energy Services. That company sells natural gas and electricity to industrial and commercial customers primarily in New York, Pennsylvania, Maryland, Virginia and Washington, D.C. The acquisition expands the HESS customer base, which previously was concentrated in the New York metropolitan area, and more than doubles sales of natural gas to end users. The transaction expands the Corporation’s energy marketing and operating capabilities and is scheduled to close in the second quarter of 2000. 18
Slide 21: Index to Financial Information Amerada Hess Corporation and Consolidated Subsidiaries 20. 27. Financial Review Statement of Consolidated Income; Statement of Consolidated Retained Earnings Consolidated Balance Sheet Statement of Consolidated Cash Flows Statement of Consolidated Changes in Common Stock and Capital in Excess of Par Value; Statement of Consolidated Comprehensive Income Notes to Consolidated Financial Statements Report of Management Report of Ernst & Young LLP , Independent Auditors Supplementary Oil and Gas Data Ten-Year Summary of Financial Data Ten-Year Summary of Operating Data 28. 30. 31. 32. 45. 46. 47. 52. 56. 19
Slide 22: Financial Review Amerada Hess Corporation and Consolidated Subsidiaries Management’s Discussion and Analysis of Results of Operations and Financial Condition Consolidated Results of Operations The Corporation’s net daily worldwide production was as follows: 1999 Crude oil and natural gas liquids (barrels per day) United States Foreign Total Natural gas (Mcf per day) United States Foreign Total Barrels of oil equivalent (per day) 1998 1997 Operating earnings (income excluding special items) for 1999 amounted to $307 million compared with a loss of $196 million in 1998 and income of $14 million in 1997 . The after-tax results by major operating activity for 1999, 1998 and 1997 are summarized below (in millions): 1999 Exploration and production Refining, marketing and shipping Corporate Interest Operating earnings (loss) Special items Net income (loss) Net income (loss) per share (diluted) $ 324 133 (31) (119) 307 131 $ 438 $4.85 1998 $ (18) (18) (37) (123) (196) (263) $ (459) $(5.12) $ 1997 $ 258 (110) (16) (118) 14 (6) 8 64,605 167,802 232,407 338,044 304,500 642,544 339,498 44,920 161,069 205,989 293,849 282,628 576,477 302,069 43,950 174,622 218,572 311,915 257,339 569,254 313,448 $ .08 Comparison of Results Exploration and Production: Operating earnings from exploration and production activities increased by $342 million in 1999, primarily due to significantly higher worldwide crude oil selling prices, increased crude oil and natural gas sales volumes and reduced exploration expenses in connection with a refocused exploration program. Exploration and production earnings decreased by $276 million in 1998 compared with 1997 principally reflecting lower crude oil selling prices. , The Corporation’s average selling prices, including the effects of hedging, were as follows: The 1999 increases in United States crude oil and natural gas production were primarily due to new production from deepwater Gulf of Mexico fields which came onstream in late 1998. Increased foreign crude oil production was largely due to new production in 1999 from a field in the Danish sector of the North Sea. The 1999 increase in foreign natural gas production reflected increases in the North Sea, Indonesia and Thailand. In 1998, United States crude oil production was comparable to 1997 and foreign crude oil production declined, largely due to maintenance related interruptions at three United Kingdom fields. United States natural gas production was lower in 1998, principally reflecting asset sales and natural decline. Foreign natural gas production increased in 1998 due to higher demand in the United Kingdom. 1999 Crude oil and natural gas liquids (per barrel) United States Foreign Natural gas (per Mcf) United States Foreign 1998 1997 $16.23 17.90 2.14 1.79 $12.02 13.05 2.08 2.26 $18.43 19.16 2.42 2.46 20
Slide 23: Depreciation, depletion, and amortization charges relating to exploration and production activities were higher in 1999 reflecting increased crude oil and natural gas production volumes. However, on a barrel of oil equivalent produced, depreciation and related charges were comparable in 1999 and 1998, and lower than in 1997 Production expenses were lower in . 1999, reflecting lower costs of new fields. Exploration expenses were also lower in 1999, principally in the United States and United Kingdom, as a result of a reduced drilling program. Production and exploration expenses were also lower in 1998 than in 1997 General and administrative . expenses in 1999 were somewhat lower than in 1998, reflecting cost reduction initiatives in the United States and United Kingdom. Excluding special charges, the total cost per barrel of depreciation, production, exploration and administrative expenses was $11.75 in 1999, $13.80 in 1998 and $14.50 in 1997 . Operating earnings from exploration and production activities in 1999 included net nonrecurring charges of $9 million, principally reflecting buyouts and renegotiations of drilling rig contracts and services, partially offset by $18 million in foreign currency exchange gains and related tax benefits. Pre-tax foreign currency gains or losses are included in other non-operating income in the income statement. The effective income tax rate on exploration and production earnings in 1999 was 44%. Generally, this rate exceeds the U.S. statutory rate because of special petroleum taxes in the United Kingdom and Norway and exploration expenses in certain foreign areas for which income tax benefits are not available. The 1999 effective rate was lower than in 1998 because of the use of a net operating loss carryforward in Denmark and the reduced impact of international drilling outside of the North Sea. The Corporation anticipates that its effective income tax rate on exploration and production earnings will continue to exceed the U.S. statutory rate. The selling price of crude oil has increased significantly from the low levels experienced in late 1998 and early 1999, however, there can be no assurance that the current higher selling prices will continue. Refining, Marketing and Shipping: Operating earnings for refining, marketing and shipping activities increased to $133 million in 1999 compared with a loss of $18 million in 1998 and a loss of $110 million in 1997 The Corporation’s down. stream operations include HOVENSA L.L.C. (HOVENSA), a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA), formed in October 1998. The joint venture is 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, shipping and trading. HOVENSA: The Corporation’s share of HOVENSA’s income was $7 million in 1999 compared with income of $24 million in 1998 when the refinery was wholly-owned for the first ten months of the year. Margins for all refined products continued to be weak during 1999 as the cost of crude oil increased significantly. Income taxes or benefits are not recorded on HOVENSA results due to available loss carryforwards. Operating earnings from refining, marketing and shipping activities in 1999 also include $47 million of interest income on the note received from PDVSA in connection with the formation of the joint venture. In 1998, $8 million of interest was recorded on the note. Interest is reflected in non-operating income in the income statement. Because HOVENSA is accounted for on the equity method, revenues and expenses of the refinery are no longer included in each caption in the Corporation’s income statement. Prior to the formation of HOVENSA, refinery results were fully consolidated. In 1998 and 1997 the amounts shown below for , the refinery were included in the income statement captions indicated (in millions): 1998 Sales and other operating revenues Cost of products sold Other operating expenses Depreciation and amortization $622 439 83 70 1997 $928 874 122 78 Refinery runs in 1999 and 1998 were 418,000 and 421,000 barrels per day, respectively. In February 2000, HOVENSA reached agreement on a $600 million bank financing for the construction of a 58,000 barrel per day delayed coking unit and related facilities at its refinery. The financing also provides for general working capital requirements. 21
Slide 24: Refining and marketing operations: Operating earnings from the Corporation’s catalytic cracking facility in New Jersey improved in 1999 as a result of its use of relatively low cost feedstocks. Earnings from retail operations were higher in 1999, reflecting higher volumes and slightly improved margins. However, results of energy marketing activities were lower, due to extremely competitive industry conditions. Earnings in 1999 were determined on the LIFO inventory method of accounting. During the year, the cost of inventory increased significantly. As a result, cost of products sold determined using LIFO was $149 million higher than it would have been using the average cost method. Sales volumes decreased to 126 million barrels in 1999 compared with 144 million barrels in 1998, excluding previously consolidated sales of the St. Croix refinery. The decrease primarily reflects lower spot sales. Operating expenses, excluding amounts related to the refinery, increased in 1999 due to expanded third party shipping activities. Revenue from shipping operations is included in operating revenue in the income statement. The Corporation has a 50% voting interest in a consolidated partnership which trades energy commodities. The Corporation also periodically takes forward positions on energy contracts in addition to its hedging program. The combined results of trading activities were gains of $19 million in 1999 compared with losses of $26 million in 1998 and gains of $4 million in 1997 Expenses of the trading partnership are . included in marketing expenses and have increased in 1999. Refining, marketing and shipping operations had losses in 1998 and 1997 reflecting weak refining margins and an inventory write-down at the end of 1997 The results in both . years were impacted by relatively mild winter weather and extremely competitive market conditions. The Corporation is expanding its retail operations by purchasing and constructing gasoline stations. The Corporation is also expanding its energy marketing activities. The costs of operating the retail and energy marketing businesses are included in marketing expenses. Refined product margins improved somewhat in early 2000 as a result of tight supplies for heating oil caused by cold weather in the Corporation’s marketing areas. However, future results 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 $31 million in 1999, $37 million in 1998 and $16 million in 1997 . The decrease in 1999 reflects lower administrative expenses and increased dividends from insurers. The Corporation does not expect these dividends to continue at 1999 levels. The change in 1998 compared with 1997 principally reflects Corporate income tax adjustments. Interest: After-tax interest expense decreased in 1999 compared with an increase in 1998. The decrease in 1999 reflects lower average interest rates and increased tax benefits resulting from borrowings in different tax jurisdictions. This change was partially offset by, and the increase in pre-tax interest was primarily due to, lower amounts capitalized. The increase in interest in 1998 was due to higher average borrowings than in 1997. Assuming interest rates comparable to 1999, interest expense in 2000 is anticipated to be somewhat lower than in 1999, reflecting a lower average outstanding debt balance. Consolidated Operating Revenues: Sales and other operating revenues increased by approximately 18% in 1999, excluding third party sales of the St. Croix refinery in 1998. The HOVENSA joint venture is accounted for on the equity method, and therefore, its revenues are not included in the Corporation’s 1999 revenues. The increase in the Corporation’s revenues in 1999 is principally due to higher crude oil and refined product selling prices and increased crude oil and natural gas sales volumes, partially offset by lower refined product sales volumes. Sales and other operating revenues decreased by 20% in 1998 compared with 1997 primarily due to lower crude oil and refined product selling prices. 22
Slide 25: Special Items After-tax special items in 1999, 1998 and 1997 are summarized below (in millions): Refining, Marketing and Shipping Total Exploration and Production 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 1997 Asset impairment Foreign tax refund Gain on asset sale Total $ 176 54 (99) $ 131 $ (50) (198) (15) $(263) $ (55) 38 11 $ (6) $ 30 54 (65) $ 19 $ 56 (154) (15) $(113) $ (55) 38 11 $ (6) $ 146 — (34) $ 112 $(106) (44) — $(150) $ — — — — $ 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 a gain of $30 million. Special income tax benefits of $54 million reflect actions taken in 1999 to realize the United States tax impact of certain prior year foreign exploration activities and capital losses. Asset impairments in 1999 include $34 million for the Corporation’s crude oil storage terminal in St. Lucia as a result of the nonrenewal of a storage contract. The carrying value of the terminal had been impaired by $44 million 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. This impairment is due to a significant reduction of crude oil volumes shipped through the Corporation’s share of the pipeline. The Corporation has no crude oil production in Alaska. It is estimated that asset impairments recorded in 1999 and 1998 will reduce future depreciation expense (after income tax effect) by approximately $14 million per year in 2000 and 2001. 23 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. The Corporation’s accrual for drilling service contracts, including the remainder of amounts provided in 1998, relates to payments that will be made in 2000 of approximately $45 million (after income tax effect). The 1998 special items also included a loss of $106 million on the sale of 50% of the St. Croix refinery and formation of the HOVENSA joint venture. The Corporation had a gain of $56 million on the sale of oil and gas assets in the United States and Norway. Asset impairment in 1998 included $35 million for impairment of a North Sea oil discovery and $13 million for other oil and gas assets in the United States and United Kingdom. The Corporation also recorded a $29 million charge for its share of asset impairment of Premier Oil plc, an equity affiliate. Severance costs of $15 million were also recorded in 1998. The 1997 special items included an after-tax charge of $55 million for the reduction in carrying values and provision for future costs of two United Kingdom North Sea oil fields. These fields ceased production in 1999. Other 1997 special items included income of $38 million from a refund of United Kingdom Petroleum Revenue Taxes and a gain of $11 million on the sale of a United States natural gas field. Liquidity and Capital Resources Net cash provided by operating activities, including changes in operating assets and liabilities amounted to $770 million in 1999, $519 million in 1998 and $1,250 million in 1997 The . increase in 1999 was primarily due to improved operating results, partially offset by a reduction in deferred revenues of $249 million from the advance sale of crude oil production in 1998. There was no comparable transaction in 1999. The variance between 1998 and 1997 was also due to the results of operations and changes in working capital, including inventory. Cash flow from operations, before changes in operating assets and liabilities, amounted to $1,116 million in 1999, $521 million in 1998 and $854 million in 1997 .
Slide 26: The Corporation generated additional cash for capital expenditures and debt reduction by selling non-core assets in 1999 and 1998. The gross proceeds from asset sales amounted to $395 million in 1999 and $468 million in 1998. Total debt was $2,310 million at December 31, 1999 compared with $2,652 million at December 31, 1998. The debt to capitalization ratio decreased to 43% at December 31, 1999 from 50% at year-end 1998. At December 31, 1999, floating rate debt amounted to 24% of total debt, including the effect of interest rate conversion (swap) agreements. At December 31, 1999, the Corporation had $1,880 million of additional borrowing capacity available under its revolving credit agreements and unused lines of credit under uncommitted arrangements with banks of $376 million. On October 1, 1999, the Corporation issued $1 billion of public debentures. The proceeds of the issuance were used to repay revolving credit and other debt. Of the $1 billion, $300 million bears interest at 73⁄8% and is due in 2009 and $700 million bears interest at 77⁄8% and is due in 2029. The Corporation conducts foreign exploration and production activities in the United Kingdom, Norway, Denmark, Gabon, Indonesia, Thailand, Azerbaijan 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 decrease in capital expenditures in 1999 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 reflect $100 million for exploration and production interests in Azerbaijan and $50 million for an increased interest in a consolidated subsidiary with proved crude oil reserves and exploration licenses in Gabon. Acquisitions in 1997 principally represent purchases of developed and undeveloped oil and gas properties in the United Kingdom. Refining and marketing expenditures in 1997 include the purchase of a chain of retail marketing properties in Florida. Capital expenditures in 2000, excluding acquisitions, are currently expected to be approximately $750 million. These expenditures will be financed principally by internally generated funds. On February 14, 2000, the Corporation announced that it entered into an agreement with the Meadville Corporation to acquire the 51% of Meadville’s outstanding stock that it does not already own for approximately $168 million in cash and deferred payments, preferred stock or a combination of both as selected by the Meadville stockholders. The purchase includes 178 Merit retail gasoline stations located in the Northeast. The transaction is expected to close in early May. Derivative Financial Instruments The following table summarizes the Corporation’s capital expenditures in 1999, 1998 and 1997 (in millions): 1999 Exploration and production Exploration $101 Production and development 626 Acquisitions — 727 Refining, marketing and shipping Total 70 $797 1998 $ 242 915 150 1,307 132 $1,439 1997 $ 286 679 193 1,158 188 $1,346 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. At December 31, the Corporation had open hedge positions equal to 30% of its estimated 2000 worldwide crude oil production and 3% of its 2001 production. In addition, the Corporation had hedges covering 10% of its refining and marketing inventories. As market conditions change, the Corporation will adjust its hedge positions. 24
Slide 27: 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 engages in trading 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 Corporation estimates that at December 31, 1999, the value at risk related to hedging activities, excluding the physical inventory hedged, was $13 million ($1 million at December 31, 1998). During 1999, the average value at risk for hedging activities was $6 million, the high was $13 million and the low was $2 million. During 1998, the average value at risk for hedging activities was $4 million, the high was $5 million and the low was $1 million. At December 31, 1999, the value at risk on trading activities, predominantly partnership trading, was $6 million ($4 million at December 31, 1998). During 1999, the average value at risk for trading activities was $7 million, the high was $10 million and the low was $5 million. During 1998, the average value at risk for trading activities was $5 million, the high was $6 million and the low was $3 million. The Corporation also uses interest-rate conversion agreements to balance exposure to interest rates. At December 31, 1999, the Corporation has substantially all fixed-rate debt and has $400 million of notional value, interest-rate conversion agreements that increased its percentage of floating-rate debt to 24%. At December 31, 1998, the Corporation had $400 million of notional value, interest-rate conversion agreements that decreased its percentage of floating-rate debt to 32%. The Corporation’s outstanding debt of $2,310 million, which together with the interest-rate swaps, has a fair value of $2,299 million at December 31, 1999. A 10% change in interest rates would change the fair values of debt and related swaps by $120 million ($64 million at December 31, 1998). The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates, principally the Pound Sterling. At December 31, 1999, the Corporation has $865 million ($97 million at December 31, 1998) of notional value foreign exchange contracts. Generally, the Corporation uses 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 $90 million at December 31, 1999 ($10 million at December 31, 1998). Environment, Health and Safety The Corporation’s awareness of its environmental responsibilities and environmental regulations at the federal, state and local levels have led to programs requiring higher operating costs and capital investments by the Corporation. The Corporation continues to focus on energy conservation, pollution control and waste minimization and treatment. There are also programs for compliance evaluation, facility auditing and employee training to monitor operational activities and to prevent conditions that might threaten the environment. The Corporation produces gasolines that meet the current requirements for oxygenated and reformulated gasolines of the Clean Air Act of 1990, including the requirements for reformulated gasolines that began in 2000. Reformulated gasolines decrease emissions of volatile and toxic organic compounds. The Corporation’s production of reformulated gasolines from its Port Reading facility and HOVENSA can meet its marketing requirements. In addition, the HOVENSA refinery has desulfurization capabilities enabling it to produce low-sulfur diesel fuel that meets the requirements of the Clean Air Act. HOVENSA can currently produce gasolines that meet the requirements of the California Air Resources Board. In December 1999, the United States Environmental Protection Agency (“EPA”) adopted rules which phase in limitations on the sulfur content of gasoline beginning in 2004. The rules will require Port Reading and HOVENSA to take steps to be in compliance and, increased capital expenditures are likely at one or both facilities. The Corporation is reviewing options to determine the most cost effective compliance strategy. EPA is also expected to propose reductions in the allowable sulfur content of diesel fuel which, if ultimately required, would result in additional capital expenditures. The EPA is 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 the Federal regulations requiring oxygenation of reformulated gasolines. California has already adopted a ban on MTBE use beginning in 2003. If MTBE is banned in other areas and the minimum oxygen content requirements for gasoline remain in place, the effect on the Corporation will depend on the specific regulations and the cost of alternative oxygenates. 25
Slide 28: The Corporation expects continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include gasoline stations, terminals, 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 under the Superfund legislation. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs of assessing and remediating known sites. The Corporation expended $8 million in 1999, $9 million in 1998 and $12 million in 1997 for remediation. In addition, capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, were $2 million in 1999, $4 million in 1998 and $5 million in 1997 . Year 2000 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 1999 and 1998 were as follows: 1999 Quarter Ended High Low High 1998 Low 3 March 31 June 30 September 30 December 31 53 ⁄4 653⁄8 665⁄16 631⁄16 1 43 ⁄4 4715⁄16 563⁄4 531⁄2 61 ⁄16 591⁄8 595⁄8 591⁄8 1 485⁄16 505⁄16 46 48 Quarterly Financial Data Quarterly results of operations for the years ended December 31, 1999 and 1998 follow (millions of dollars, except per share data): Net income (loss) per share (diluted) The Corporation has completed its program to address the year 2000 problem and has experienced only a few minor interruptions in its embedded computer systems, internal software and transactions with third parties. The total cost of the year 2000 remediation program was $12 million. The Corporation will continue to monitor systems during the year and will address any remaining year 2000 issues should they arise. Forward Looking Information Quarter Sales and other Operating operating earnings revenues (loss) Special items Net income (loss) 1999 First Second Third Fourth Total 1998 First Second Third Fourth Total $1,539 1,430 1,801 2,269 $7,039 $1,826 1,608 1,529 1,617 $6,580 $ 41 37 53 176 $ 307 $ (69) (22) (6) (99) $(196) $ 30(a) $ 40(a) 106(a) (45)(b) $ 131 71 77 159 131 $ .79 .86 1.75 1.45 $ 438 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 $ 56(a) $ (13) $ (.14) — (22) (.24) — (6) (.07) (319)(c) (418) (4.70) $(263) $(459) (a) Represents after-tax gains on asset sales. (b) Includes special income tax benefits of $54 million, offset by impairment of assets and operating leases of $99 million. (c) Includes a loss of $106 million on the formation of the refining joint venture, impairment of assets and operating leases of $198 million and accrued severance costs of $15 million. Cash dividends on common stock totaled $.60 per share ($.15 per quarter) during 1999 and 1998. The results of operations for the periods reported herein should not be considered as indicative of future operating results. 26
Slide 29: Statement of Consolidated Income Amerada Hess Corporation and Consolidated Subsidiaries For the Years Ended December 31 Thousands of dollars, except per share data 1999 1998 1997 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 $7,039,138 273,441 6,988 141,787 7,461,354 $6,579,892 (25,679) (15,848) 82,740 6,621,105 $8,223,582 16,463 — 120,435 8,360,480 Total revenues Costs and Expenses Cost of products sold Production expenses Marketing expenses Other operating expenses Exploration expenses, including dry holes and lease impairment General and administrative expenses Interest expense Depreciation, depletion and amortization Impairment of assets and operating leases 4,240,910 487,219 387,298 216,651 261,038 231,546 158,222 648,663 127,998 6,759,545 701,809 264,193 $ 437,616 $4.88 $4.85 4,373,616 517,828 378,506 224,433 348,951 270,668 152,934 661,802 206,478 7,135,216 (514,111) (55,218) $ (458,893) $(5.12) $(5.12) 5,577,924 557,025 328,975 231,791 421,863 236,269 136,149 663,297 80,602 8,233,895 126,585 119,085 $ 7,500 $.08 $.08 Total costs and expenses Income (loss) before income taxes Provision (benefit) for income taxes Net Income (Loss) Net Income (Loss) Per Share Basic Diluted Statement of Consolidated Retained Earnings For the Years Ended December 31 Thousands of dollars, except per share data 1999 1998 1997 Balance at Beginning of Year Net income (loss) Dividends declared—common stock ($.60 per share in 1999, 1998 and 1997) Common stock acquired and retired Balance at End of Year See accompanying notes to consolidated financial statements. $1,904,066 437,616 (54,311) — $2,287,371 27 $2,463,005 (458,893) (54,520) (45,526) $1,904,066 $2,613,920 7,500 (55,090) (103,325) $2,463,005
Slide 30: Consolidated Balance Sheet Amerada Hess Corporation and Consolidated Subsidiaries At December 31 Thousands of dollars 1999 1998 Assets Current Assets Cash and cash equivalents Accounts receivable Trade Other Inventories Current portion of deferred income taxes Other current assets $ 40,926 1,112,114 62,930 372,713 67,418 171,469 1,827,570 $ 73,791 954,353 58,831 482,182 114,194 203,355 1,886,706 Total current assets Investments and Advances HOVENSA L.L.C. Other 709,569 282,599 992,168 702,581 232,826 935,407 Total investments and advances Property, Plant and Equipment Exploration and production Refining and marketing Shipping 9,974,117 980,806 109,962 11,064,885 7,013,233 4,051,652 538,500 317,822 $ 7,727,712 9,718,424 1,193,353 115,462 11,027,239 6,835,301 4,191,938 538,500 330,432 $ 7,882,983 Total—at cost Less reserves for depreciation, depletion, amortization and lease impairment Property, plant and equipment—net Note Receivable Deferred Income Taxes and Other Assets Total Assets 28
Slide 31: At December 31 1999 1998 Liabilities and Stockholders’ Equity Current Liabilities Accounts payable—trade Accrued liabilities Deferred revenue Taxes payable Notes payable Current maturities of long-term debt $ 771,797 621,334 3,846 158,852 17,912 5,109 1,578,850 2,286,660 $ 713,831 554,632 251,328 100,686 3,500 172,820 1,796,797 2,476,145 Total current liabilities Long-Term Debt Deferred Liabilities and Credits Deferred income taxes Other 442,172 381,838 824,010 483,843 482,786 966,629 Total deferred liabilities and credits Stockholders’ Equity Preferred stock, par value $1.00 Authorized—20,000,000 shares for issuance in series Common stock, par value $1.00 Authorized—200,000,000 shares Issued—90,676,405 shares in 1999; 90,356,705 shares in 1998 Capital in excess of par value Retained earnings Accumulated other comprehensive income — — 90,676 782,271 2,287,371 (122,126) 3,038,192 $7,727,712 90,357 764,412 1,904,066 (115,423) 2,643,412 $7,882,983 Total stockholders’ equity Total Liabilities and Stockholders’ Equity 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: Statement of Consolidated Cash Flows Amerada Hess Corporation and Consolidated Subsidiaries For the Years Ended December 31 Thousands of dollars 1999 1998 1997 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 $ 437,616 $ (458,893) $ 7,500 648,663 127,998 69,346 36,790 (273,441) 62,419 7,102 1,116,493 (155,525) 79,648 (175,227) 53,256 (148,640) 770,005 661,802 206,478 159,435 31,191 25,679 (137,922) 33,430 521,200 6,335 122,204 185,403 (87,118) (229,236) 518,788 663,297 80,602 191,351 37,185 (16,463) (80,208) (29,439) 853,825 (148,488) 333,477 198,596 (46,626) 59,223 1,250,007 Changes in other operating assets and liabilities (Increase) decrease in accounts receivable 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 affiliate 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 (727,086) (69,571) (796,657) (59,171) 431,818 (424,010) (1,306,438) (132,240) (1,438,678) — 502,854 (935,824) (1,157,938) (187,652) (1,345,590) — 63,017 (1,282,573) 14,412 990,125 (1,347,745) (54,262) — 18,283 Net cash provided by (used in) financing activities (379,187) Effect of Exchange Rate Changes on Cash 327 Net Decrease in Cash and Cash Equivalents (32,865) Cash and Cash Equivalents at Beginning of Year 73,791 Cash and Cash Equivalents at End of Year $ 40,926 See accompanying notes to consolidated financial statements. (14,342) 848,320 (317,144) (54,647) (59,167) — 403,020 (3,347) (17,363) 91,154 $ 73,791 1,982 398,391 (209,000) (55,373) (122,283) — 13,717 (2,519) (21,368) 112,522 $ 91,154 30
Slide 33: Statement of Consolidated Changes in Common Stock and Capital in Excess of Par Value Amerada Hess Corporation and Consolidated Subsidiaries Common stock Number of shares Capital in excess of par value Thousands of dollars Amount Balance at January 1, 1997 Awards of nonvested common stock to employees (net) Common stock acquired and retired Employee stock options exercised Balance at December 31, 1997 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 93,073,305 719,000 (2,368,100) 27,000 91,451,205 (26,000) (1,071,500) 3,000 90,356,705 (2,500) 322,200 90,676,405 $93,073 719 (2,368) 27 91,451 (26) (1,071) 3 90,357 (3) 322 $90,676 $754,559 38,145 (19,419) 1,346 774,631 (1,292) (9,073) 146 764,412 (102) 17,961 $782,271 Statement of Consolidated Comprehensive Income For the Years Ended December 31 Thousands of dollars 1999 1998 1997 Components of Comprehensive Income (Loss) Net income (loss) Change in foreign currency translation adjustment Comprehensive Income (Loss) See accompanying notes to consolidated financial statements. $437,616 (6,703) $430,913 $(458,893) (2,035) $(460,928) $ 7,500 (35,467) $(27,967) 31
Slide 34: Notes to Consolidated Financial Statements Amerada Hess Corporation and Consolidated Subsidiaries 1. Summary of Significant Accounting Policies Nature of Business: Amerada Hess Corporation and sub- Revenue Recognition: The Corporation recognizes revenues sidiaries (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 Azerbaijan, Brazil, Indonesia, Thailand and other countries. In addition, the Corporation manufactures, purchases, transports and markets refined petroleum and other energy products. The Corporation owns 50% of 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 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 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 L.L.C., 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 non-operating 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. Certain amounts in prior years’ financial statements have been reclassified to conform with current year presentation. 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 an asset 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 prop- 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 erty, plant and equipment retired or otherwise disposed of, less accumulated reserves, are reflected in net income. Impairment of Long-Lived Assets: The Corporation reviews 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 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 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: Commodity trading activities are marked to market, 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. with gains and losses recorded in operating revenue. 33
Slide 36: 2. Special Items 1999: The Corporation recorded a gain of $274,100,000 1998: The Corporation recorded a loss of $106,000,000 in con- ($176,000,000 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 include special income tax benefits of $54,600,000, reflecting actions taken in 1999 to realize the United States tax impact of certain prior year exploration activities and capital losses. Exploration and production earnings also include an impairment of $58,700,000 ($38,200,000 after income taxes) for the Corporation’s interest in the Trans Alaska Pipeline System. The Corporation currently 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 include an asset impairment of $34,000,000 (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 $35,300,000 ($27 ,300,000 after income taxes) for a further decline in the value of a drilling service fixed-price contract due to lower market rates. At December 31, 1999, the Corporation’s reserve for drilling service contracts was $54,600,000, including amounts provided in 1998. During the year, $70,700,000 of contract payments were charged against the reserve. Gains on asset sales are included on a separate line in nonoperating 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. nection with the sale of the 50% interest in the fixed assets of its Virgin Islands refinery. The Corporation also recorded an additional charge of $44,000,000 for the reduction in carrying value of its crude oil storage terminal in St. Lucia that is being 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 $90,000,000 ($77 ,000,000 after income taxes) for the reduction in market value of drilling service fixed-price contracts due to the decline in worldwide crude oil prices. A charge of $54,000,000 ($35,000,000 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 $29,000,000 for its share of asset impairment of an equity affiliate and $13,000,000 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 $80,300,000 ($56,200,000 after income taxes) on the sale of oil and gas assets in the United States and Norway. In 1998, the Corporation recorded pre-tax charges of $23,000,000 ($15,000,000 after income taxes) for severance costs. The severance costs covered approximately 400 exploration and production employees (of which approximately 200 had been terminated at December 31, 1998). Approximately $2,000,000 of severance was paid in 1998 and the remainder was paid in 1999. The Corporation also recorded $8,000,000 of exit costs (accrued office lease costs). Approximately $3,400,000 of this reserve was used in 1999 and the remainder was reversed to income as a result of current plans for use of the office space. 1997: The Corporation recorded a charge of $80,600,000 ($55,000,000 after income taxes) for impairment of long-lived assets and a long-term operating lease, as a result of reserve revisions on two oil fields in the United Kingdom North Sea. The Corporation also recorded income of $38,200,000 from a refund of United Kingdom Petroleum Revenue Taxes. In 1997 , the Corporation sold its interest in a United States natural gas field resulting in an after-tax gain of $10,700,000. 34
Slide 37: 3. Accounting Changes 5. Refining Joint Venture Effective January 1, 1999, the Corporation adopted the last-in, first-out (LIFO) inventory method for valuing its refining and marketing inventories. The Corporation believes that the LIFO method more closely matches current costs and revenues and will improve comparability with other oil companies. The change to LIFO decreased net income by $97 ,051,000 for the year ended December 31, 1999 ($1.08 per share basic and diluted). There is no cumulative effect adjustment as of the beginning of the year for this type of accounting change. On January 1, 1998, the Corporation began capitalizing the cost of internal use software in accordance with AICPA Statement of Position 98-1. This accounting change increased net income for 1998 by $13,867 ,000 ($.15 per share). In June 1998, the Financial Accounting Standards Board issued FAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The Corporation must adopt FAS No. 133 by January 1, 2001. This statement requires that the Corporation recognize all derivatives on the balance sheet at fair value. For derivatives that are not hedges, the change in fair value must be recognized in income. 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. The Corporation has not yet determined what the effect of FAS No. 133 will be on its income and financial position. 4. Inventories In 1998, the Corporation formed HOVENSA L.L.C. (HOVENSA), a joint venture with Petroleos de Venezuela, S.A. (PDVSA). The Corporation’s Virgin Islands subsidiary and PDVSA, V.I., Inc. (PDVSA V.I.), a wholly-owned subsidiary of PDVSA, contributed their 50% interests in the fixed assets of the Virgin Islands refinery, previously wholly-owned by the Corporation, to HOVENSA. HOVENSA is 50% owned by a subsidiary of the Corporation and 50% owned by PDVSA V.I. and operates the refinery. The Corporation purchased refined products from HOVENSA at a cost of approximately $1,196,000,000 during 1999 and $151,000,000 during the two months ended December 31, 1998. The Corporation sold crude oil to HOVENSA at a cost of approximately $81,000,000 during 1999 and $7 ,000,000 during the two months ended December 31, 1998. The Corporation’s investment in the joint venture is accounted for using the equity method. Summarized financial information for HOVENSA as of December 31, 1999 and for the year then ended and as of December 31, 1998 and for the two months since inception follows: Thousands of dollars 1999 1998 Summarized Balance Sheet Information At December 31 Current assets $ 432,877 Net fixed assets 1,328,407 Other assets 27,094 Current liabilities (282,312) Long-term debt (150,000) Deferred liabilities and credits (25,750) Partners’ equity $ 1,330,316 Summarized Income Statement Information For the periods ended December 31 Total revenues $ 3,081,969 Costs and expenses (3,064,075) Net income (loss)* $ 17,894 $ 352,171 1,343,712 27,711 (133,454) (250,000) (27,718) $1,312,422 Inventories at December 31 are as follows: Thousands of dollars 1999 1998 Crude oil and other charge stocks Refined and other finished products Less: LIFO adjustment Materials and supplies Total $ 67,539 $ 35,818 393,064 386,917 (149,309) — 311,294 61,419 $ 372,713 422,735 59,447 $482,182 $ 344,896 (375,903)** $ (31,007) * The Corporation’s share of HOVENSA’s income in 1999 was $6,988 and its share of the 1998 loss was $15,848. ** 1998 results include an inventory writedown of $31,999, which reduced costs of products sold in 1999. 35
Slide 38: As part of the formation of the joint venture, PDVSA, V.I. purchased a 50% interest in the fixed assets of the Corporation’s Virgin Islands refinery for $62,500,000 in cash and a 10-year note from PDVSA V.I. for $562,500,000 bearing interest at 8.46% per annum and requiring principal payments over its term. At December 31, 1999, the principal balance of the note was $538,500,000. In addition, there was a $125,000,000, 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 $600,000,000 bank financing for the construction of a 58,000 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.I. agreed to amend the note received by the Corporation at the formation of the joint venture. PDVSA V.I. will defer principal payments on the note until after completion of coker construction but not later than February 14, 2003. Principal payments are due ratably until maturity on February 14, 2011. The interest rate on the note has been increased to 9.46%. PDVSA V.I. has the option to reduce the interest rate to the original rate of 8.46% by repaying principal in accordance with the original amortization schedule. 6. Short-Term Notes and Related Lines of Credit Short-term notes payable to banks amounted to $17 ,912,000 at December 31, 1999 and $3,500,000 at December 31, 1998. The weighted average interest rates on these borrowings were 6.3% and 8.8% at December 31, 1999 and 1998, respectively. At December 31, 1999, the Corporation has uncommitted arrangements with banks for unused lines of credit aggregating $376,000,000. 7. Long-Term Debt Long-term debt at December 31 consists of the following: Thousands of dollars 1999 990,026 $ 1998 — 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 8.0%*, due through 2014 Global Revolving Credit Facility with banks, weighted average rate 6.5%, due 2002 Project lease financing, weighted average rate 5.1%, due through 2014 Capitalized lease obligations, weighted average rate 5.3%, due through 2009 Other loans, weighted average rate 8.0%, due through 2007 Less amount included in current maturities Total 3 7 20,000 20,000 52,623 52,607 915,000 1,154,285 120,000 1,195,000 182,588 185,513 8,332 3,200 2,291,769 5,109 35,960 5,600 2,648,965 172,820 $2,476,145 $2,286,660 *Includes effect of interest rate conversion agreements. The aggregate long-term debt maturing during the next five years is as follows (in thousands): 2000—$5,109 (included in current liabilities); 2001—$25,411; 2002— $320,695; 2003—$80,990 and 2004—$159,794. 36
Slide 39: 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, 1999, the Corporation meets the required working capital ratio of 1 to 1. Under the agreements, the Corporation is permitted to borrow an additional $2,225,000,000 for the construction or acquisition of assets. In addition, at December 31, 1999 it has $638,000,000 of retained earnings free of dividend restrictions. In 1999, the Corporation issued $1,000,000,000 of public debentures, of which $300,000,000 bears interest at 73⁄8% and is due in 2009 and the remainder bears interest at 77⁄8% and is due in 2029. After discount and the effect of interest rate conversion agreements, the effective borrowing rates are 6.48% and 7 .97%, respectively. The Corporation has a $2,000,000,000 Global Revolving Credit Facility (the “Facility”), of which $120,000,000 is outstanding at December 31, 1999. Borrowings bear interest at a margin above the London Interbank Offered Rate (“LIBOR”) based on the Corporation’s capitalization ratio. The borrowing rate at December 31, 1999 is .20% above LIBOR. Facility fees of .125% per annum are payable on the amount of the credit line. In 1998, the Corporation entered into the sale and leaseback of its interests in the production platforms and related facilities of two Gulf of Mexico producing properties. These transactions were accounted for as financings. At December 31, 1999, the outstanding obligations amount to $182,588,000, maturing through 2014. The Corporation sold a portion of its subsequent year crude oil production in 1998 and used the proceeds to repay revolving credit debt. Accordingly, at December 31, 1998, $249,325,000 is included in deferred revenue on the balance sheet. There was no comparable transaction in 1999. At December 31, 1999, the Corporation has interest rate conversion agreements, accounted for by the accrual method, that effectively convert fixed rate debt to floating rate debt, increasing the percentage of its floating rate debt to 24%. In 1999, 1998 and 1997 the Corporation capitalized inter, est of $15,754,000, $23,559,000 and $10,284,000 on major development projects. The total amount of interest paid (net of amounts capitalized), principally on short-term and longterm debt, in 1999, 1998 and 1997 was $145,366,000, $154,419,000 and $146,795,000, 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, subject to stockholder approval) 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 1999, 1998 and 1997 consisted of the following: Weightedaverage Options exercise price (thousands) per share Outstanding at January 1, 1997 Granted Exercised Forfeited Outstanding at December 31, 1997 Granted Exercised Forfeited Outstanding at December 31, 1998 Granted* Exercised Forfeited Outstanding at December 31, 1999 Exercisable at December 31, 1997 Exercisable at December 31, 1998 Exercisable at December 31, 1999 1,421 873 (27) (19) 2,248 873 (3) (23) 3,095 1,804 (322) (70) 4,507 1,376 2,230 2,702 $58.99 54.75 50.86 59.52 57.43 53.05 49.75 56.22 56.21 55.66 53.22 58.08 $56.18 $59.14 57.44 56.52 *1,118 stock options with an exercise price of $58.13 per share were granted in December 1999 subject to approval of stockholders in 2000. Exercise prices for employee stock options at December 31, 1999 ranged from $49.00 to $65.94 per share. The weighted-average remaining contractual life of employee stock options is 8.2 years. 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 weighted-average assumptions in the Black-Scholes model for 1999, 1998 and 1997 , respectively: risk-free interest rates of 5.9%, 5.6% and 5.9%; expected stock price volatility of .207 .218 and .220; a , dividend yield of 1.1%; and an expected life of seven years. The Corporation’s net income would have been reduced by approximately $6,000,000 in 1999, $19,100,000 in 1998 and $7 ,600,000 in 1997 ($.07 per share in 1999, $.21 per share in 1998 and $.08 per share in 1997 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 $18.45 in 1999, $17 in 1998 and $18.69 .50 in 1997 . Total compensation expense for nonvested common stock was $9,831,000 in 1999, $15,975,000 in 1998 and $11,553,000 in 1997 Awards of nonvested common stock were . as follows: Shares of nonvested common stock awarded (thousands) 9. Foreign Currency Translation Worldwide currency translation gains amounted to $17 ,000 (including $7 ,577 ,688,000 of income tax benefits) in 1999. Foreign currency gains totaled $2,511,000 in 1998 and $5,073,000 in 1997 after income tax effects. 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. 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: Thousands of dollars 1999 1998 Reconciliation of pension benefit obligation Benefit obligation at January 1 $542,704 $464,728 Service cost 21,639 19,280 Interest cost 34,333 32,841 Actuarial (gain) loss (71,262) 48,855 Benefit payments (26,306) (23,000) 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 Employee contributions Benefit payments Fair value of plan assets at December 31 Funded status at December 31 Funded status Unrecognized prior service cost Unrecognized (gain) loss Accrued pension liability 501,108 476,849 63,375 19,678 — (26,306) 533,596 32,488 7,761 (91,629) 542,704 427,912 54,311 16,833 793 (23,000) 476,849 (65,855) 9,041 2,861 Weightedaverage price on date of grant Granted in 1997 Granted in 1998 Granted in 1999 746 18 24 $53.94 53.08 56.07 At December 31, 1999, 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 3,882* 4,507* 52 1,055 9,496 $ (51,380) $ (53,953) * Includes 3,882 shares reserved for future awards and 1,118 stock options outstanding which are subject to approval of stockholders in 2000. ** Issued in connection with an insurance company financing, exercisable through June 27, 2001 at $64.46 per share. 38
Slide 41: Pension expense consisted of the following: Thousands of dollars 11. Provision for Income Taxes The provision (benefit) for income taxes consisted of: 1999 $ 21,639 34,333 (41,072) 255 1,280 — $ 16,435 1998 $ 19,280 32,841 (36,221) (72) 1,280 (22) $ 17,086 1997 $ 19,109 33,162 (32,390) (3,052) 1,280 (1,692) $ 16,417 Thousands of dollars Service cost Interest cost Expected return on plan assets Amortization of transition asset (obligation) Amortization of prior service cost Amortization of net gain Pension expense 1999 $ 6,093 81,657 6,483 94,233 1998 1997 United States Federal Current Deferred State Foreign Current Deferred Adjustment of deferred tax liability for foreign income tax rate change Total $ 9,510 $ 16,210 (68,203) (27,254) 1,702 1,418 (56,991) 71,492 (66,310) 5,182 (9,626) 181,665(b) (41,599) 140,066 189,198 (15,058) 174,140 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: 1999 Discount rate Expected long-term rate of return on plan assets Rate of compensation increases 7.3% 8.7% 4.5% 1998 6.4% 8.3% 4.9% (4,180) (3,409) (11,355) $264,193(a) $(55,218) $119,085 (a) Includes a benefit of $54,600 representing actions taken in 1999 to realize the United States tax impact of certain prior year exploration activities and capital losses. (b) Includes income tax refund of $38,180. Income (loss) before income taxes consisted of the following: Thousands of dollars 1999 $397,237 304,572 $701,809 1998 $(205,522) (308,589) $(514,111) 1997 $ 3,533 123,052 $126,585 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 $38,358,000 at December 31, 1999 and $41,802,000 at December 31, 1998. Pension expense for the plan was $6,743,000 in 1999, $6,271,000 in 1998 and $5,098,000 in 1997 The Corporation has . accrued $29,310,000 for this plan at December 31, 1999 and $25,205,000 at December 31, 1998. The trust established to fund the supplemental plan held assets valued at $13,586,000 at December 31, 1999 and $6,209,000 at December 31, 1998. United States Foreign* Total *Foreign income includes the Corporation’s Virgin Islands, shipping and other operations located outside of the United States. 39
Slide 42: 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: Thousands of dollars 1999 1998 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 Net deferred tax liabilities $ 320,324 $ 272,461 224,359 238,568 55,917 58,251 600,600 98,510 299,962 137,598 78,691 614,761 (182,253) 432,508 569,280 194,109 224,765 126,590 41,592 587,056 (141,113) 445,943 $ 168,092 $ 123,337 The difference between the Corporation’s effective income tax rate and the United States statutory rate is reconciled below: 1999 United States statutory rate Effect of foreign operations, including foreign tax credits Effect of capital and other loss carryforwards State income taxes, net of Federal income tax benefit Prior year adjustments Tax credits Other Total 35.0% 3.0 — .6 (.8) — (.2) 37.6% 1998 (35.0)% 24.2 (.2) .2 (.3) — .4 (10.7)% 1997 35.0% 72.3 (8.3) .7 (3.5) (.8) (1.3) 94.1% 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 $950 million at December 31, 1999, 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 $120 million would have been required. For income tax reporting at December 31, 1999, the Corporation has general business credit carryforwards of approximately $30 million, principally expiring in 2000 and 2001. In addition, the Corporation has alternative minimum tax credit carryforwards of approximately $110 million, which can be carried forward indefinitely. At December 31, 1999, a net operating loss carryforward of approximately $1 billion is also available to offset income of the HOVENSA joint venture partners. Net operating loss carryforwards relating to several foreign exploration and production areas amount to approximately $190 million at December 31, 1999. Income taxes paid (net of refunds) in 1999, 1998 and 1997 amounted to $141,465,000, $140,470,000 and $259,767 ,000, respectively. 40
Slide 43: 12. Net Income Per Share 13. Leased Assets The weighted average number of common shares used in the basic and diluted earnings per share computations are summarized below: Thousands of shares 1999 89,692 436 152 90,280 1998 89,585 — — 89,585 1997 91,254 428 51 91,733 Common shares—basic Effect of dilutive securities Nonvested common stock Stock options Common shares—diluted The Corporation and certain of its subsidiaries lease floating production systems, drilling rigs, tankers, gasoline stations, office space and other assets for varying periods. At December 31, 1999, future minimum rental payments applicable to capital and noncancelable operating leases with remaining terms of one year or more (other than oil and gas leases) are as follows: Operating Leases Capital Leases Thousands of dollars Diluted common shares include shares that would be outstanding assuming the fulfillment of restrictions on nonvested shares and the exercise of stock options. 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 1,609,000 shares, 1,626,000 shares and 867 ,000 shares in 1999, 1998 and 1997 respectively. , 2000 2001 2002 2003 2004 Remaining years Total minimum lease payments Less: Imputed interest Income from subleases Net minimum lease payments Capitalized lease obligations— Current Long-term Total $ 274,551 172,149 106,186 90,570 86,727 403,651 1,133,834 — 17,263 $1,116,571* $ 1,156 1,156 1,156 1,156 1,156 5,781 11,561 3,229 — $ 8,332 $ 531 7,801 $ 8,332 *Of the total future minimum payments under operating leases, $79,590 has been accrued at December 31, 1999. Rental expense for all operating leases, other than rentals applicable to oil and gas leases, was as follows: Thousands of dollars 1999 1998 $178,560 29,979 $148,581 1997 $195,246 11,792 $183,454 Total rental expense $156,362 Less income from subleases 51,418 Net rental expense $104,944 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. In addition, the Corporation uses interest-rate conversion agreements to adjust the interest rates on a portion of its long-term, fixed-rate debt. Foreign currency contracts are used to protect the Corporation from fluctuations in exchange rates. Commodity Hedging: At December 31, 1999, the Corporation’s hedging activities included commodity and financial contracts, maturing mainly in 2000, covering 29,700,000 barrels of crude oil and 1,400,000 barrels of refined products (3,000,000 net barrels of crude oil and refined products in 1998). The Corporation also hedged 4,500,000 net Mcf of natural gas in 1998. The Corporation produced 85,000,000 barrels of crude oil and natural gas liquids and 235,000,000 Mcf of natural gas in 1999, and had approximately 14,000,000 barrels of crude oil and refined products in its refining and marketing inventories at December 31, 1999. 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. Net deferred losses from the Corporation’s hedging activities were $61,200,000 at December 31, 1999, including $47 ,600,000 of unrealized losses ($5,000,000 of gains at December 31, 1998, including $2,000,000 of unrealized gains). Financial Instruments: At December 31, 1999, the Corpora- Fair Value Disclosure: The carrying amounts of cash and cash equivalents, short-term debt and long-term, variable-rate 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. Interestrate conversion agreements 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, 1999, except as follows: 1999 Millions of dollars, asset (liability) Balance Sheet Amount Fair Value 1998 Balance Sheet Amount Fair Value Long-term, fixed-rate note receivable $ 539 $ 493 $ 563 $ 563 Long-term, fixed-rate debt (2,163) (2,141) (1,418) (1,477) Interest-rate conversion agreements — (11) — (24) Market and Credit Risks: The Corporation’s financial instru- tion has $400,000,000 in interest-rate conversion agreements outstanding ($400,000,000 at December 31, 1998). The Corporation also has $865,000,000 of notional value foreign currency forward and purchased option contracts maturing generally in 2000 ($97,000,000 at December 31, 1998) and $145,300,000 in letters of credit outstanding ($137,900,000 at December 31, 1998). 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. ments 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 1999, 1998 and 1997 amounted to net income of $19,000,000 , in 1999, a net loss of $26,000,000 in 1998 and net income of $4,000,000 in 1997 . 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 Millions of dollars, asset (liability) 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, 1999 follows: United States* Consolidated 1999 $ 69 225 (233) 178 (192) 546 (549) 1999 $ 85 143 (148) 67 (76) 356 (342) 1998 $ 98 29 (29) (7) 8 110 (117) 1998 $ 75 43 (39) (3) 5 59 (60) Millions of dollars Europe Other Commodities Futures and forwards Assets Liabilities Options Held Written Swaps Assets Liabilities 1999 Operating revenues Property, plant and equipment (net) 1998 Operating revenues Property, plant and equipment (net) 1997 Operating revenues Property, plant and equipment (net) $4,948 $1,944 1,289 2,396 $147 $7,039 367 4,052 $5,046 $1,474 1,457 2,351 $ 60 $6,580 384 4,192 Notional amounts of commodities and derivatives relating to trading activities follow: At December 31, Millions of barrels of oil equivalent $6,552 $1,614 2,872 2,106 $ 58 $8,224 213 5,191 1999 3 177 (168) 343 (318) 304 (329) 1998 7 39 (51) 20 (21) 83 (81) *Includes U.S. Virgin Islands and shipping operations. 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, marketing and trading of petroleum and other energy products. *Includes 41 million barrels long and 53 million barrels short related to basis swaps at December 31, 1999 (18 million barrels long and 20 million barrels short in 1998). 43
Slide 46: 15. Segment Information (Continued) The following table presents financial data by major operating segment for each of the three years ended December 31, 1999: Millions of dollars Exploration and Production Refining, Marketing and Shipping Corporate Consolidated * 1999 Operating revenues Total operating revenues Less: Transfers between affiliates Operating revenues from unaffiliated customers Operating earnings (loss) Special items $2,719 222 $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 2,211 68 $ $ 1 — 1 $7,039 $ 307 131 $ 438 $ 9 63 158 685 264 987 7,728 5,348 797 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 $(150) — $(150) $ 7 1 158 2 (38) 61 339 — 2 Operating revenues from unaffiliated customers Operating earnings (loss) Special items $1,980 118 $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 2,065 129 $ $ $ 1 — 1 $6,580 $ (196) (263) $ (459) $ (30) 23 153 693 (55) 933 7,883 5,296 1,439 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 1997 Operating revenues Total operating revenues Less: Transfers between affiliates $(160) — $(160) $ 5 1 153 2 (24) 56 471 — 3 Operating revenues from unaffiliated customers Operating earnings (loss) Special items $3,086 142 $2,944 $ 258 (6) $ 252 $ 21 14 — 580 164 114 3,727 2,468 1,158 $5,280 1 $5,279 $ (110) — $ (110) $ 6 3 — 118 — 77 3,713 2,875 183 $ $ 1 — 1 $8,224 $ $ $ 14 (6) 8 32 18 136 700 119 244 7,935 5,343 1,346 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 $(134) — $(134) $ 5 1 136 2 (45) 53 495 — 5 *After elimination of transactions between affiliates, which are valued at approximate market prices. 44
Slide 47: Report of Management 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 of 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, which consists solely of independent directors, meets periodically with the independent auditors, internal auditors and management to review and discuss the Corporation’s financial statements, the system of internal controls and the results of internal and external audits. Ernst & Young LLP and the Corporation’s internal auditors have unrestricted access to the Audit Committee to discuss audit findings and other financial matters. John B. Hess Chairman of the Board and Chief Executive Officer John Y. Schreyer Executive Vice President and Chief Financial Officer 45
Slide 48: Report of Ernst & Young LLP, Independent Auditors 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, 1999 and 1998 and the related consolidated statements of income, retained earnings, cash flows, changes in common stock and capital in excess of par value and comprehensive income for each of the three years in the period ended December 31, 1999. 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, 1999 and 1998 and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 1999, 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, and in 1998 the Corporation adopted AICPA Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. New York, NY February 24, 2000 46
Slide 49: Supplementary Oil and Gas Data 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 and Azerbaijan. 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 United States Africa, Asia and other For the Years Ended December 31 (Millions of dollars) Total Europe 1999 Property acquisitions Exploration Development Share of equity investee’s costs incurred 1998 Property acquisitions Exploration Development Share of equity investee’s costs incurred 1997 Property acquisitions Exploration Development Share of equity investee’s costs incurred $ 24 232 626 38 $203 319 915 70 $237 383 679 45 $ 7 72 137 — $— 76 451 11 $7 145 650 13 $193 215 408 9 $ 17 84 38 27 $155 68 83 57 $ 5 37 40 36 $ 41 106 182 — $ 39 131 231 — Capitalized Costs Relating to Oil and Gas Producing Activities At December 31 (Millions of dollars) 1999 $ 369 1,551 8,054 9,974 6,464 $3,510 $ 233 1998 $ 434 1,596 7,688 9,718 6,131 $3,587 $ 211 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 47
Slide 50: The results of operations for oil and gas producing activities shown below exclude sales of purchased natural gas, nonoperating income (including gains on sales of oil and gas properties), interest expense and gains and losses resulting from foreign currency exchange transactions. Therefore, these Results of Operations for Oil and Gas Producing Activities 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. For the Years Ended December 31 (Millions of dollars) Total United States Europe Africa, Asia and other 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 1997 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 for income taxes Results of operations Share of equity investee’s results of operations *Includes severance and related costs of approximately $32 million. $1,776 222 1,998 487 261 101 604 94 1,547 451 152 $ 299 $ (6) $420 222 642 126 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 $1,352 144 1,496 518 349 151* 534 162 1,714 (218) (38) $ (180) $ (31) $344 84 428 129 133 67 154 7 490 (62) (22) $ (40) $— $ 975 — 975 357 135 68 351 104 1,015 (40) (22) $ $ (18) (25) $ 33 60 93 32 81 16 29 51 209 (116) 6 $(122) $ (6) $1,973 134 2,107 557 421 136 544 81 1,739 368 143 $ 225 $ 26 $506 76 582 143 142 87 124 — 496 86 30 $ 56 $— $1,437 — 1,437 408 216 36 402 81 1,143 294 107 $ 187 $ 17 $ 30 58 88 6 63 13 18 — 100 (12) 6 $ (18) $ 9 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 that will Oil and Gas Reserves 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: Total Net Proved Developed and Undeveloped Reserves Crude Oil, Including Condensate and Natural Gas Liquids (Millions of barrels) United States Europe Africa, Asia and other At January 1, 1997 Revisions of previous estimates Extensions, discoveries and other additions Purchases of minerals in-place Sales of minerals in-place Production At December 31, 1997 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 Share of equity investee’s crude oil reserves** 578 47 39 14 (3) (80) 595 80 55 45 (5) (75) 695 21 68 4 (5) (85) 698 14 1,866 78 195 44 (41) (207) 1,935 147 227 3 (47) (210) 2,055 34 94 4 (48) (235) 1,904 277 171 7 12 1 (1) (16) 174 6 6 — — (17) 169 13 5 — — (24) 163 — 847 16 68 — (8) (114) 809 35 80 1 (38) (107) 780 (32) 25 4 (48) (124) 605* — 383 40 21 13 (2) (60) 395 72 22 2 (5) (52) 434 10 49 — — (55) 438 9 931 54 48 44 (33) (93) 951 113 54 2 (9) (102) 1,009 35 60 — — (106) 998 2 24 — 6 — — (4) 26 2 27 43 — (6) 92 (2) 14 4 (5) (6) 97 5 88 8 79 — — — 175 (1) 93 — — (1) 266 31 9 — — (5) 301 275 Natural Gas (Millions of Mcf) At January 1, 1997 Revisions of previous estimates Extensions, discoveries and other additions Purchases of minerals in-place Sales of minerals in-place Production At December 31, 1997 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 Share of equity investee’s natural gas reserves** Net Proved Developed Reserves Crude Oil, Including Condensate and Natural Gas Liquids (Millions of barrels) At January 1, 1997 At December 31, 1997 At December 31, 1998 At December 31, 1999 Share of equity investee’s crude oil reserves** Natural Gas (Millions of Mcf) At January 1, 1997 At December 31, 1997 At December 31, 1998 At December 31, 1999 Share of equity investee’s natural gas reserves** *Excludes 373 million Mcf of carbon dioxide gas for sale or use in company operations. **Prior year reserves are not available on a comparable basis. 412 420 452 513 10 1,368 1,342 1,330 1,437 87 121 123 132 136 — 553 497 525 477 — 280 280 293 351 8 815 796 753 841 2 11 17 27 26 2 — 49 52 119 85 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 year-end oil and gas selling prices (adjusted for price changes provided by contractual arrangements, including hedges) to estimated Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves future production of proved oil and gas 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 during 1999 and are highly volatile. At December 31 (Millions of dollars) Total United States Europe Africa, Asia and other 1999 Future revenues Less: Future development and production costs Future income tax expenses 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 Future net cash flows Less: Discount at 10% annual rate Standardized measure of discounted future net cash flows 1997 Future revenues Less: Future development and production costs Future income tax expenses Future net cash flows Less: Discount at 10% annual rate Standardized measure of discounted future net cash flows $19,858 6,500 5,457 11,957 7,901 2,814 $ 5,087 $ 237 $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 $1,915 620 537 1,157 758 346 $ 412 $ 166 $1,503 750 242 992 511 251 $ 260 $ 716 257 223 480 236 84 $ 152 $10,826 6,412 1,411 7,823 3,003 980 $ 2,023 $13,001 6,033 3,127 9,160 3,841 1,424 $ 2,417 $2,866 1,479 374 1,853 1,013 403 $ 610 $4,078 1,533 831 2,364 1,714 692 $1,022 $ 6,457 4,183 795 4,978 1,479 326 $ 1,153 $ 8,207 4,243 2,073 6,316 1,891 648 $ 1,243 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) 1999 $ 2,023 1998 $ 2,417 1997 $ 4,184 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 (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 (1,550) 679 (3,304) (392) 140 271 90 769 1,355 175 (1,767) $ 2,417 51
Slide 54: Ten-Year Summary of Financial Data Amerada Hess Corporation and Consolidated Subsidiaries Thousands of dollars, except per share data 1999(a) 1998 1997 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 $1,406,987 1,856,179 3,003,280 772,692 7,039,138 273,441 6,988 141,787 7,461,354 4,240,910 487,219 387,298 216,651 261,038 231,546 158,222 648,663 127,998 6,759,545 701,809 264,193 $ 437,616(b) $4.88 4.85 $ .60 90,280 $ 893,921 1,710,743 3,464,229 510,999 6,579,892 (25,679) (15,848) 82,740 6,621,105 4,373,616 517,828 378,506 224,433 348,951 270,668 152,934 661,802 206,478 7,135,216 (514,111) (55,218) $ (458,893)(c) $(5.12) (5.12) $ .60 89,585 $1,435,848 1,414,314 4,960,986 412,434 8,223,582 16,463 — 120,435 8,360,480 5,577,924 557,025 328,975 231,791 421,863 236,269 136,149 663,297 80,602 8,233,895 126,585 119,085 $ 7,500 $.08 .08 $.60 91,733 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 Other operating expenses Exploration expenses, including dry holes and lease impairment 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 Number of Shares Outstanding (diluted) —in thousands (a) On January 1, 1999, the Corporation adopted the last-in, first-out (LIFO) inventory method for refining and marketing inventories. (b) Includes after-tax gains on asset sales of $176,000 and special tax benefits of $54,600, partially offset by impairment of assets and operating leases (after income taxes) of $99,500. (c) Reflects after-tax special charges aggregating $262,800 representing impairments of assets and operating leases, a net loss on asset sales and accrued severance. (d) After income taxes, the net gain was $421,150. (e) After income taxes, the net charge was $415,542. See accompanying notes to consolidated financial statements. 52
Slide 55: 1996 1995 1994 1993 1992 1991 1990 $1,528,692 1,364,833 5,080,790 295,871 8,270,186 529,271(d) — 124,276 8,923,733 5,386,316 620,533 264,295 129,454 384,324 237,868 165,501 721,498 — 7,909,789 1,013,944 353,845 $ 660,099 $7.13 7.09 $ .60 93,110 $1,565,310 1,120,450 4,311,082 302,465 7,299,307 96,010 — 124,571 7,519,888 4,501,053 610,457 259,214 185,477 381,758 262,950 247,465 840,002 584,161(e) 7,872,537 (352,649) 41,764 $ (394,413) $(4.26) (4.26) $ .60 92,509 $1,228,045 1,063,560 3,980,563 327,816 6,599,984 41,657 — 49,226 6,690,867 3,795,094 600,501 260,552 124,258 331,216 230,110 245,149 868,175 — 6,455,055 235,812 162,098 $ 73,714 $.80 .79 $.60 92,968 $1,219,750 1,020,563 3,348,900 290,308 5,879,521 — — 17,068 5,896,589 3,508,295 626,377 247,029 242,266 350,859 229,218 156,615 759,406 — 6,120,065 (223,476) 44,727 $ (268,203) $(2.91) (2.91) $ .60 92,213 $1,362,118 787,996 3,428,702 279,541 5,858,357 — — 99,866 5,958,223 3,213,748 684,292 228,953 233,989 323,942 238,032 147,099 764,683 — 5,834,738 123,485 115,940 $ 7,545 $.09 .09 $.60 87,286 $1,448,793 574,004 3,897,748 346,300 6,266,845 — — 151,419 6,418,264 3,686,227 619,482 262,728 176,879 397,267 222,585 177,850 759,084 — 6,302,102 116,162 31,854 $ 84,308 $1.05 1.04 $ .60 81,087 $1,248,193 458,615 4,587,646 653,051 6,947,505 — — 138,854 7,086,359 4,003,747 503,579 268,222 231,942 360,168 196,588 224,200 682,412 — 6,470,858 615,501 132,788 $ 482,713 $5.99 5.96 $ .60 81,023 53
Slide 56: Ten-Year Summary of Financial Data Amerada Hess Corporation and Consolidated Subsidiaries Thousands of dollars, except per share data 1999 1998 1997 Selected Balance Sheet Data at Year-End Cash and cash equivalents Working capital Property, plant and equipment Exploration and production Refining, marketing and other $ 40,926 248,720 $ 73,791 89,909 $ 91,154 463,781 $ 9,974,117 1,090,768 11,064,885 7,013,233 $ 4,051,652 $ 7,727,712 2,309,681 3,038,192 $33.51 $ 770,005 $ 9,718,424 1,308,815 11,027,239 6,835,301 $ 4,191,938 $ 7,882,983 2,652,465 2,643,412 $29.26 $ 518,788 $ 8,779,807 3,841,828 12,621,635 7,430,841 $ 5,190,794 $ 7,934,619 2,127,288 3,215,699 $35.16 $ 1,250,007 Total—at cost Less reserves Property, plant and equipment—net Total assets Total debt Stockholders’ equity Stockholders’ equity per 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 (727,086) (69,571) (796,657) 372,647 (424,010) 14,412 990,125 (1,347,745) — (54,262) — 18,283 (379,187) 327 $ (32,865) 90,676 7,416 $56.75 $ (1,306,438) (132,240) (1,438,678) 502,854 (935,824) (14,342) 848,320 (317,144) — (54,647) (59,167) — 403,020 (3,347) (17,363) 90,357 8,959 $49.75 $ (1,157,938) (187,652) (1,345,590) 63,017 (1,282,573) 1,982 398,391 (209,000) — (55,373) (122,283) — 13,717 (2,519) (21,368) 91,451 9,591 $54.88 Net increase (decrease) in cash and cash equivalents Stockholder Data at Year-End Number of common shares outstanding (in thousands) Number of stockholders (based on number of holders of record) Market price of common stock 54
Slide 57: 1996 1995 1994 1993 1992 1991 1990 $ 112,522 689,864 $ 56,071 357,964 $ 53,135 520,247 $ 79,635 245,026 $ 141,014 551,459 $ 120,170 625,370 $ 129,914 603,244 $ 8,233,445 3,668,974 11,902,419 6,995,136 $ 4,907,283 $ 7,784,481 1,939,288 3,383,631 $36.35 $ 807,721 $ 9,392,184 3,672,028 13,064,212 7,694,496 $ 5,369,716 $ 7,756,370 2,717,866 2,660,396 $28.60 $ 1,241,007 $ 9,790,468 4,514,358 14,304,826 7,938,824 $ 6,366,002 $ 8,337,940 3,339,788 3,099,629 $33.33 $ 957,018 $ 9,360,871 4,426,369 13,787,240 7,052,328 $ 6,734,912 $ 8,641,546 3,687,922 3,028,911 $32.71 $ 819,423 $ 9,203,951 3,886,814 13,090,765 6,646,801 $ 6,443,964 $ 8,721,756 3,186,199 3,387,599 $36.59 $ 1,137,707 $ 9,306,435 3,223,397 12,529,832 6,339,232 $ 6,190,600 $ 8,841,435 3,266,195 3,131,982 $38.63 $ 1,364,268 $ 8,340,951 2,817,032 11,157,983 5,594,399 $ 5,563,584 $ 9,056,636 2,925,285 3,106,029 $38.34 $ 1,326,444 (788,286) (72,339) (860,625) 1,037,073 176,448 (72,046) — (794,527) — (55,746) (8,236) — (930,555) 2,837 $ 56,451 93,073 10,153 $57.88 $ (626,518) (65,593) (692,111) 145,792 (546,319) 26,247 25,000 (689,355) — (55,788) — — (693,896) 2,144 2,936 93,011 11,294 $53.00 $ (532,189) (64,095) (596,284) 72,804 (523,480) (54,153) 289,843 (642,112) — (55,711) — — (462,133) 2,095 (26,500) 92,996 11,506 $45.63 $ (755,419) (592,622) (1,348,041) 12,436 (1,335,605) 117,791 547,704 (167,769) — (41,603) — — 456,123 (1,320) (61,379) 92,587 12,000 $45.13 $ (916,536) (641,258) (1,557,794) 25,423 (1,532,371) (159,756) 675,016 (524,384) 497,360 (64,194) — — 424,042 (8,534) 20,844 92,584 13,088 $46.00 $ (1,295,039) (417,276) (1,712,315) 37,788 (1,674,527) (183,351) 786,280 (269,414) — (36,468) — — 297,047 3,468 (9,744) 81,068 13,732 $47.50 $ (1,267,506) (193,921) (1,461,427) (12,012) (1,473,439) 46,744 461,413 (287,531) — (60,681) (6,213) — 153,732 2,877 9,614 81,019 14,669 $46.38 55
Slide 58: Ten-Year Summary of Operating Data Amerada Hess Corporation and Consolidated Subsidiaries 1999 Production Per Day (net) Crude oil (barrels) United States United Kingdom Norway Denmark Gabon Indonesia and Azerbaijan Canada and Abu Dhabi 1998 1997 Total Natural gas liquids (barrels) United States United Kingdom Norway Thailand Canada Total Natural gas (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 (held at end of year) United States Foreign(a) Total Shipping Vessels owned or under charter at year-end Total deadweight tons Refining (barrels daily) Amerada Hess Corporation HOVENSA L.L.C.(c) Petroleum Products Sold (barrels daily) Gasoline, distillates and other light products Residual fuel oils Total Storage Capacity at Year-End (barrels) Number of Employees (average) (a) (b) (c) (d) Includes acreage held under production sharing contracts. Through ten months of 1998. Reflects 50% of HOVENSA refinery crude runs from November 1, 1998. Includes approximately 4,200 employees of retail operations. 54,772 112,129 25,326 7,547 10,226 4,662 — 214,662 9,833 5,670 1,683 559 — 17,745 338,044 257,800 30,600 2,900 5,400 7,800 — 642,544 28 11 9 735 161 896 678,000 15,858,000 16,536,000 8 884,000 — 209,000 284,000 60,000 344,000 38,343,000 8,485(d) 36,784 109,463 26,943 — 14,345 2,949 — 190,484 8,136 5,990 1,379 — — 15,505 293,849 251,000 27,828 — 3,800 — — 576,477 28 20 25 721 252 973 748,000 16,927,000 17,675,000 9 952,000 419,000(b) 217,000 411,000 71,000 482,000 56,070,000 9,777 35,707 126,427 29,516 — 10,127 531 — 202,308 8,243 6,364 1,657 — — 16,264 311,915 225,804 30,312 — 1,223 — — 569,254 42 11 24 860 447 1,307 915,000 10,180,000 11,095,000 14 1,602,000 411,000 — 436,000 73,000 509,000 87,000,000 9,216 56
Slide 59: 1996 1995 1994 1993 1992 1991 1990 41,020 134,726 27,603 — 9,725 — 5,929 219,003 9,105 6,628 1,585 — 476 17,794 337,653 253,983 30,445 — — — 62,585 684,666 39 25 40 854 455 1,309 891,000 7,455,000 8,346,000 13 1,236,000 396,000 — 412,000 83,000 495,000 86,986,000 9,085 52,284 135,429 25,576 — 9,512 — 16,976 239,777 10,722 6,900 1,414 — 1,647 20,683 401,581 239,307 27,743 — — — 215,500 884,131 33 41 50 2,154 1,160 3,314 1,440,000 5,871,000 7,311,000 16 2,010,000 377,000 — 401,000 86,000 487,000 89,165,000 9,574 55,638 122,043 24,279 — 8,857 — 17,854 228,671 11,964 6,756 1,320 — 1,809 21,849 427,103 208,742 24,417 — — — 185,856 846,118 28 44 24 2,160 1,146 3,306 1,685,000 4,570,000 6,255,000 17 2,265,000 388,000 — 375,000 93,000 468,000 94,597,000 9,858 60,173 80,019 26,388 — 8,301 — 21,540 196,421 11,798 3,783 1,432 — 1,956 18,969 502,459 188,024 28,987 — — — 167,839 887,309 48 49 37 2,189 1,115 3,304 1,854,000 4,310,000 6,164,000 15 2,398,000 351,000 — 291,000 95,000 386,000 94,380,000 10,173 62,517 86,265 29,598 — 6,910 — 22,678 207,968 11,063 1,468 1,707 — 1,981 16,219 601,824 153,599 31,858 — — — 137,680 924,961 33 20 22 2,082 966 3,048 1,819,000 3,168,000 4,987,000 21 3,223,000 335,000 — 275,000 102,000 377,000 95,199,000 10,263 66,063 59,979 28,619 — 8,952 — 21,832 185,445 10,047 766 1,752 — 1,997 14,562 583,740 128,014 26,947 — — — 104,151 842,852 45 41 36 2,103 927 3,030 1,802,000 3,480,000 5,282,000 21 2,825,000 320,000 — 285,000 128,000 413,000 94,879,000 10,317 62,434 56,027 24,351 — — — 17,969 160,781 9,436 805 2,004 — 1,704 13,949 457,042 145,921 25,656 — — — 76,768 705,387 17 33 38 2,111 905 3,016 1,716,000 3,329,000 5,045,000 23 3,012,000 383,000 — 296,000 132,000 428,000 93,867,000 9,645 57
Slide 60: Amerada Hess Corporation BOARD OF DIRECTORS John B. Hess (1) (5) 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 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) (2) (3) (4) Member of Executive Committee Member of Audit Committee Member of Compensation Committee 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 F B. Walker . Vice Presidents S. J. Austin G. C. Barry R. J. Bartzokas L. L. Chan E. C. Crouch R. T. Ehrlich D. E. Friedman J. P. Gehegan R. E. Guerry W. R. Hanna J. S. Harvey H. A. Hoo S. E. Hankin L. J. Kupfer E. J. Kutcher D. C. Lutken, Jr. J. J. Lynett L. S. Massaro R. K. May R. S. C. Phillips Controller R. B. Ross R. W. Schofield H. I. Small J. J. Steed D. G. Stevenson C. T. Tursi Secretary S. A. Villas Assistant Controllers D. B. Douty M. W. Johnson D. M. Steffens S. J. Steigerwald Assistant Corporate Secretary T. B. Garcia Assistant Treasurers R. Birkenholz R. B. Kirby A. D. Lopena 58