Hess - 10-K annual report

      Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes þ          No o

      Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).     Yes þ          No o

      The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $6,163,000,000 as of June 30, 2004.

      At December 31, 2004, 91,715,180 shares of Common Stock were outstanding.

      Part III is incorporated by reference from the Proxy Statement for the annual meeting of stockholders to be held on May 4, 2005.

      Amerada Hess Corporation (the Registrant) is a Delaware corporation, incorporated in 1920. The Registrant and its subsidiaries (collectively referred to as the “Corporation”) explore for, produce, purchase, transport and sell crude oil and natural gas. These exploration and production activities take place in the United States, United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Gabon, Indonesia, Thailand, Azerbaijan, Malaysia and other countries. The Corporation also manufactures, purchases, trades and markets refined petroleum and other energy products. The Corporation owns 50% of a refinery joint venture in the United States Virgin Islands, and another refining facility, terminals and retail gasoline stations located on the East Coast of the United States.

      At December 31, 2004, the Corporation had 646 million barrels of proved crude oil and natural gas liquids reserves, the same as at the end of 2003. Proved natural gas reserves were 2,400 million Mcf at December 31, 2004 compared with 2,332 million Mcf at December 31, 2003. Proved reserves at December 31, 2004 include 37% and 52%, respectively, of crude oil and natural gas reserves held under production sharing contracts. Of the total proved reserves (on a barrel of oil equivalent basis), 17% are located in the United States, 39% are located in the United Kingdom, Norwegian and Danish sectors of the North Sea, 17% are located in Africa and the remainder are located in Indonesia, Thailand, Malaysia and Azerbaijan. On a barrel of oil equivalent basis, 38% of the Corporation’s December 31, 2004 worldwide proved reserves are undeveloped (32% in 2003). Most of the proved undeveloped reserves relate to properties being developed in Africa and Asia.

      Worldwide crude oil and natural gas liquids production amounted to 246,000 barrels per day in 2004 compared with 259,000 barrels per day in 2003. Worldwide natural gas production was 575,000 Mcf per day in 2004 compared with 683,000 Mcf per day in 2003. On a barrel of oil equivalent basis, production from continuing operations was 342,000 barrels per day in 2004 compared with 360,000 barrels per day in 2003. The Corporation presently estimates that its 2005 barrel of oil equivalent production will be approximately 350,000 barrels per day. The Corporation is developing a number of oil and gas fields and has an inventory of domestic and foreign exploration prospects.

      Worldwide crude oil and natural gas production was as follows:

    United States. Amerada Hess Corporation operates mainly offshore in the Gulf of Mexico and onshore in Texas, Louisiana and North Dakota. During 2004, 23% of the Corporation’s crude oil and natural gas liquids production and 30% of its natural gas production were from United States operations.

      The table below sets forth the Corporation’s average daily net production by area in the United States:

      The Llano Field on Garden Banks Blocks 385 and 386 in the Gulf of Mexico commenced production in April and the Corporation’s 50% interest is currently averaging approximately 20,000 barrels of oil equivalent per day. Additional appraisal drilling is planned for the Shenzi prospect (AHC 28%) on Green Canyon

      At December 31, 2004, the Corporation has interests in approximately 376 exploration blocks in the Gulf of Mexico of which it operates 260. The Corporation has 1,341,000 net undeveloped acres in the Gulf of Mexico.

     United Kingdom. The Corporation’s activities in the United Kingdom are conducted by its wholly-owned subsidiary, Amerada Hess Limited. During 2004, 30% of the Corporation’s crude oil and natural gas liquids production and 47% of its natural gas production were from United Kingdom operations.

      The table below sets forth the Corporation’s average daily net production in the United Kingdom by field and the Corporation’s interest in each at December 31, 2004:

      Production from the Clair Field (AHC 9.29%) commenced in early 2005. The Atlantic (AHC 25%) and Cromarty (AHC 90%) natural gas fields are also being developed. These fields are expected to produce at an annualized rate of approximately 25,000 barrels of oil equivalent per day when they are onstream in 2006.

      During 2003, the Corporation exchanged 14% interests in the Scott and Telford fields for an additional 22.5% interest in the Llano Field in the Gulf of Mexico. In addition, Amerada Hess Limited exchanged its 25% shareholding interest in Premier Oil plc, for a 23% interest in Natuna Sea Block A in Indonesia.

     Norway. The Corporation’s activities in Norway are conducted through its wholly-owned Norwegian subsidiary, Amerada Hess Norge A/ S. Norwegian operations accounted for crude oil and natural gas liquids production of 28,000 barrels per day in 2004 and 25,000 barrels per day in 2003. Natural gas production averaged 27,000 Mcf per day in 2004 and 26,000 Mcf per day in 2003. Substantially all of the Norwegian

     Denmark. Amerada Hess ApS, the Corporation’s wholly-owned Danish subsidiary, operates the South Arne Field. Net crude oil production from the Corporation’s 57.48% interest in the South Arne Field was 22,000 barrels of crude oil per day in 2004 and 24,000 barrels of crude oil per day in 2003. Natural gas production was 24,000 Mcf and 29,000 Mcf per day in 2004 and 2003, respectively.

     Equatorial Guinea. The Corporation has interests in production sharing contracts covering three offshore blocks. Net crude oil production from the Corporation’s 85% interest in the Ceiba Field averaged 26,000 barrels of crude oil per day in 2004 and 22,000 barrels per day in 2003. The development plan for the Okume Complex, formerly referred to as Northern Block G, received government approval during 2004. Most of the major contracts for construction have been authorized and development drilling will begin in 2006. First production from the Okume Complex is expected in early 2007.

     Malaysia — Thailand. In 2003, the Corporation exchanged its oil and gas assets in Colombia for an additional 25% interest in long-lived natural gas reserves in the joint development area of Malaysia and Thailand (JDA), bringing the Corporation’s interest to 50%. In 2004, the Corporation negotiated additional gas sales covering Block A-18 in the JDA, which will result in production growth in the future. First production from the field under the original gas sales agreement commenced in early 2005.

     Algeria. The Corporation has a 49% interest in a venture with the Algerian national oil company that is redeveloping three oil fields. The Corporation’s share of production averaged 23,000 and 19,000 barrels of crude oil per day in 2004 and 2003, respectively. During 2004, the second phase of the project to redevelop these fields was approved, resulting in an increased investment commitment of approximately $400 million.

     Gabon. Amerada Hess Production Gabon, the Corporation’s 77.5% owned Gabonese subsidiary, has a 10% interest in the Rabi Kounga Field and interests in two other Gabonese fields. The Corporation’s share of production averaged 12,000 net barrels of crude oil per day in 2004 and 11,000 barrels per day in 2003.

     Indonesia. During 2003, the Corporation acquired a 23% interest in the Natuna Sea Block A production sharing contract in exchange for its shares of Premier Oil plc. Natural gas production in Indonesia increased to 32,000 Mcf per day in 2004 from 11,000 Mcf per day in 2003. In December 2004, the Ujung Pangkah gas sales agreement was approved and gas sales are expected to commence by early 2007.

     Thailand. The Corporation has a 15% interest in the Pailin gas field offshore Thailand. Net production from the Corporation’s interest averaged 53,000 Mcf and 52,000 Mcf of natural gas per day in 2004 and 2003, respectively. An onshore discovery on Phu Horm Block E5N (AHC 35%) has been successfully appraised and is now in the permitting process. It is expected that this project will be approved in 2005 with first production in 2007.

     Azerbaijan. The Corporation has a 2.72% interest in the AIOC Consortium in the Caspian Sea. Net production from its interest averaged 2,000 barrels of crude oil per day in 2004 and 2003. Phase three of the development of the Azeri, Chirag and Guneshli Fields was approved in 2004 and will result in increased production in the future. The Corporation also holds a 2.36% interest in the BTC Pipeline.

     Refining. The Corporation owns a 50% interest in the HOVENSA refining joint venture in the United States Virgin Islands with a subsidiary of Petroleos de Venezuela S.A. (PDVSA). In addition, it owns and operates a refining facility in Port Reading, New Jersey.

     HOVENSA. HOVENSA’s total crude runs amounted to 484,000 barrels per day in 2004 and 440,000 barrels per day in 2003. The fluid catalytic cracking unit at HOVENSA operated at the rates of 139,000 and 142,000 barrels per day in 2004 and 2003, respectively. The coking unit at HOVENSA operated at the rate of 55,000 barrels per day in 2004 and 53,000 barrels per day in 2003. The coker permits HOVENSA to run lower-cost heavy crude oil. HOVENSA has a long-term supply contract with PDVSA to purchase 115,000 barrels per day of Venezuelan Merey heavy crude oil. PDVSA also supplies 155,000 barrels

     Port Reading Facility. The Corporation owns and operates a fluid catalytic cracking facility in Port Reading, New Jersey. This facility processes vacuum gas oil and residual fuel oil and operated at a rate of approximately 52,000 barrels per day in 2004 and 54,000 barrels per day in 2003. Substantially all of Port Reading’s production is gasoline and heating oil.

     Marketing. The Corporation markets refined petroleum products on the East Coast of the United States to the motoring public, wholesale distributors, industrial and commercial users, other petroleum companies, governmental agencies and public utilities. It also markets natural gas to utilities and other industrial and commercial customers. The Corporation’s energy marketing activities include the sale of electricity. The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and derivatives. The Corporation also takes trading positions for its own account.

      The Corporation has 1,254 HESS® gasoline stations at December 31, 2004, of which approximately 67% are company operated. The Corporation has 941 convenience stores at its gasoline stations. In early 2004, a 50% owned joint venture acquired a chain of gasoline stations, adding approximately 50 HESS® retail outlets. Most of the Corporation’s gasoline stations are in New York, New Jersey, Pennsylvania, Florida, Massachusetts and North and South Carolina. The Corporation owns approximately 50% of the properties on which the stations are located.

      The Corporation has 22 terminals with an aggregate storage capacity of 21 million barrels in its East Coast marketing areas.

      Refined product sales averaged 428,000 barrels per day in 2004 and 419,000 barrels per day in 2003. Of total refined products sold in 2004, approximately 54% was obtained from HOVENSA and Port Reading. The Corporation purchased the balance from others under short-term supply contracts and by spot purchases from various sources.

      In June 2004, the Corporation formed a 50% owned joint venture, Hess LNG, which will pursue investments in liquefied natural gas (LNG) terminals and related supply, trading and marketing opportunities. The joint venture is pursuing development of an LNG terminal project located in Fall River, Massachusetts.

      The Corporation has a wholly-owned subsidiary that provides distributed electricity generating equipment to industrial and commercial customers as an alternative to purchasing electricity from local utilities. The Corporation also has invested in long-term technology to develop fuel cells for electricity generation through a venture with other parties.

      The petroleum industry is highly competitive. The Corporation encounters competition from numerous companies in each of its activities, particularly in acquiring rights to explore for crude oil and natural gas and in the purchasing and marketing of refined products and natural gas. Many competitors are larger and have substantially greater resources than the Corporation. The Corporation is also in competition with producers and marketers of other forms of energy.

      The petroleum business involves large-scale capital expenditures and risk-taking. In the search for new oil and gas reserves, long lead times are often required from successful exploration to subsequent production. Operations in the petroleum industry are dependent upon a depleting natural resource. The number of areas where it can be expected that hydrocarbons will be discovered in commercial quantities is constantly diminishing and exploration risks are high. Areas where hydrocarbons may be found are often in remote locations or offshore where exploration and development activities are capital intensive and operating costs are high.

      The major foreign oil producing countries, including members of the Organization of Petroleum Exporting Countries (OPEC), exert considerable influence over the supply and price of crude oil and refined petroleum products. Their ability or inability to agree on a common policy on rates of production and other matters has a significant impact on oil markets and the Corporation. The derivatives markets are also important in influencing the selling prices of crude oil, natural gas and refined products. The Corporation cannot predict the extent to which future market conditions may be affected by foreign oil producing countries, the derivatives markets or other external influences.

      Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, expropriation of property, cancellation of contract rights, and changes in import regulations, as well as other political developments may affect the Corporation’s operations. The Corporation has been affected by certain of these events in various countries in which it operates. The Corporation markets motor fuels through lessee-dealers and wholesalers in certain states where legislation prohibits producers or refiners of crude oil from directly engaging in retail marketing of motor fuels. Similar legislation has been periodically proposed in the U.S. Congress and in various other states. The Corporation, at this time, cannot predict the effect of any of the foregoing on its future operations.

      Compliance with various existing environmental and pollution control regulations imposed by federal, state and local governments is not expected to have a material adverse effect on the Corporation’s earnings and competitive position within the industry. The Corporation spent $12 million in 2004 for environmental remediation, with a comparable amount anticipated for 2005. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, were $1 million in 2004 and the Corporation anticipates approximately $35 million in 2005. Regulatory changes already made or anticipated in the United States will alter the composition and emissions characteristics of motor fuels. Future capital expenditures necessary to comply with these regulations will be substantial. The Environmental Protection Agency has adopted rules that limit the amount of sulfur in gasoline and diesel fuel. Capital expenditures necessary to comply with the low-sulfur gasoline requirements at Port Reading are estimated to be approximately $70 million over the next two years. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are currently expected to be approximately $400 million over the next two years, $50 million of which has already been spent. HOVENSA expects to finance these capital expenditures through cash flow and, if necessary, future borrowings.

      The number of persons employed by the Corporation averaged 11,119 in 2004 and 11,481 in 2003.

      The Corporation’s Internet address is www.hess.com. On its website, the Corporation makes available free of charge its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after the Corporation electronically files with or furnishes such material to the Securities and Exchange Commission. Copies of the Corporation’s Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the charters of the Audit Committee, the Compensation and Management Development Committee and the Corporate Governance and Nominating Committee of the Board of Directors are available on the Corporation’s website and are also available free of charge upon request to the Secretary of the Corporation at its principal executive offices. The Corporation has also filed with the New York Stock Exchange (NYSE) its annual certification that the Corporation’s chief executive officer is unaware of any violation of the NYSE’s corporate governance standards.

      The Corporation’s net proved oil and gas reserves at the end of 2004, 2003 and 2002 are presented under Supplementary Oil and Gas Data in the accompanying financial statements.

      During 2004, the Corporation provided oil and gas reserve estimates for 2003 to the Department of Energy. Such estimates are compatible with the information furnished to the SEC on Form 10-K, although

      The Corporation has no contracts or agreements to sell fixed quantities of its crude oil production, although derivative instruments are used to reduce the effects of changes in selling prices. In the United States, natural gas is sold to local distribution companies, and commercial, industrial and other purchasers, on a spot basis and under contracts for varying periods. The Corporation’s United States production is expected to approximate 55% of its 2005 sales commitments under long-term contracts that total approximately 275,000 Mcf per day. Natural gas sales commitments for 2006 are expected to be comparable. The Corporation attempts to minimize price and supply risks associated with its United States natural gas supply commitments by entering into purchase contracts with third parties having adequate sources of supply, on terms substantially similar to those under its commitments.

     The foregoing tabulation does not include substantial costs and charges applicable to finding and developing proved oil and gas reserves, nor does it reflect the costs of related general and administrative expenses, interest expense and income taxes.

      Purported class actions consolidated under the complaint captioned In re Amerada Hess Corporation Securities Litigation are pending in the United States District Court for the District of New Jersey, against certain executive officers and former executive officers of the Registrant alleging that these individuals sold shares of Registrant’s common stock in advance of Registrant’s acquisition of Triton Energy Limited (Triton) in 2001 in violation of federal securities laws. In April 2003, the Registrant and the other defendants filed a motion to dismiss for failure to state a claim and failure to plead fraud with particularity. On March 31, 2004, the court granted the defendants’ motion to dismiss the complaint. The plaintiffs were granted leave to file an amended complaint. Plaintiffs filed an amended complaint in June 2004. In August 2004, defendant moved to dismiss the plaintiffs amended complaint. This motion is currently pending with the District Court. Two other purported class actions, based in large part on the same factual background, were commenced in May and August 2003 and were consolidated under a complaint captioned Falk et. al. v. Amerada Hess Corporation, et. al. in the United States District Court for the District of New Jersey against certain named executive officers, certain directors and former directors and certain employees of Registrant on behalf of participants in the

      Registrant has been served with a complaint from the New York State Department of Environmental Conservation (DEC) relating to alleged violations at its petroleum terminal in Brooklyn, New York. The complaint, which seeks an order to shut down the terminal and penalties in unspecified amounts, alleges violations involving the structural integrity of certain tanks, the erosion of shorelines and bulkheads, petroleum discharges and improper certification of tank repairs. DEC is also seeking relief relating to remediation of certain gasoline stations in the New York metropolitan area. Registrant believes that many of the allegations are factually inaccurate or based on an incorrect interpretation of applicable law. Registrant has already addressed the primary conditions discussed in the complaint. Registrant intends to vigorously contest the complaint, but is involved in settlement discussions with DEC.

      Over the last several years, many refiners have entered into consent agreements to resolve EPA’s assertions that refining facilities were modified or expanded without complying with New Source Review regulations that require permits and new emission controls in certain circumstances and other regulations that impose emissions control requirements. These consent agreements, which arise out of an EPA enforcement initiative focusing on petroleum refiners and utilities, have typically imposed substantial civil fines and penalties and required significant capital expenditures to install emissions control equipment. EPA contacted Registrant and HOVENSA L.L.C. (HOVENSA), its 50% owned joint venture with Petroleos de Venezuela, regarding the petroleum refinery initiative in August 2003 and held an initial meeting in October 2003. While EPA has not made any specific assertions that the Registrant or HOVENSA violated the New Source Review regulations, the Registrant and HOVENSA expect to have further discussions with EPA regarding the petroleum refining initiative.

      In June 2001, the Corporation voluntarily investigated and disclosed to the New Jersey Department of Environmental Protection (NJDEP) that there was a calculation error in the program code of the Port Reading refining facility’s Wet Gas Scrubber (WGS) Continuous Emissions Monitoring System (CEM). The error in the code resulted in the CEM system under calculating CO, NOx and SO₂ emissions from the WGS beginning in late 1998 and some exceedances of the permit limits for NOx. After discovery, the code error was promptly corrected. In November 2003, the Corporation received a notice of violation from the NJDEP relating to the CEM coding error that proposes a fine of $649,600, subsequently revised to $319,600. The Corporation is engaging in settlement discussions with NJDEP to resolve this matter, particularly as regards to a reduction in the revised penalty to reflect the voluntary self-disclosure of the issue.

      The Registrant, along with other companies engaged in refining and marketing of gasoline, has been a party to lawsuits and claims related to the use of the methyl tertiary butyl ether (MTBE) in gasoline. A series of substantially identical lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produce gasoline containing MTBE, including Registrant. These cases have been consolidated in the Southern District of New York. The principal allegation is that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. Additional property damage and personal injury lawsuits and claims related to the use of MTBE are expected. Prior class action product liability based litigation involving MTBE in gasoline has been resolved without a material effect on the Registrant. While the damages claimed in these actions are substantial, Registrant has no reason to believe, based on factual and legal circumstances currently known to the Registrant, that these actions will have a material adverse effect on its financial condition. However, these actions are in their preliminary stages, and the factual and legal circumstances may change.

      In April 2003, HOVENSA received a notice of violation from the Virgin Islands Department of Planning and Natural Resources (DPNR), relating to certain alleged wastewater permit exceedances occurring in 2001 and 2002 at HOVENSA. The notice proposes a fine of $219,000 and requires corrective actions to address the alleged violations. HOVENSA is engaging in settlement discussions with DPNR to resolve this matter.

      The Registrant periodically receives notices from EPA that it is a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties are jointly and severally liable. For certain sites, EPA’s claims or assertions of liability against the Corporation relating to these sites have not been fully developed. With respect to the remaining sites, EPA’s claims have been settled, or a proposed settlement is under consideration, in all cases for amounts that are not material. The ultimate impact of these proceedings, and of any related proceedings by private parties, on the business or accounts of the Corporation cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates, but is not expected to be material.

      Registrant is one of approximately 40 companies that have received a directive from the New Jersey Department of Environmental Protection to remediate contamination in the sediments of the lower Passaic River and NJDEP is also seeking natural resource damages. The directive, insofar as it affects Registrant, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey now owned by Registrant. EPA has also issued an order relating to the same contamination. The costs of remediation of the Passaic River are preliminary, but NJDEP has estimated them at approximately $900 million. Based on currently known facts and circumstances, Registrant does not believe that this matter will result in material liability because its terminal could not have contributed contamination along most of the river’s length and did not store or use contaminants which are of the greatest concern in the river sediments, and because there are numerous other parties who will likely share in the cost of remediation and damages.

      On or about July 15, 2004, Hess Oil Virgin Islands Corp. (HOVIC), a wholly owned subsidiary of Registrant, and HOVENSA L.L.C., in which Registrant owns a 50% interest, each received a letter from the Commissioner of the Virgin Islands Department of Planning and Natural Resources and Natural Resources Trustees, advising of the Trustee’s intention to bring suit against HOVIC and HOVENSA under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The letter alleges that HOVIC and HOVENSA are potentially responsible for damages to natural resources arising from releases of hazardous substances from the “HOVENSA Oil Refinery.” HOVENSA currently owns and operates a petroleum refinery on the south shore of St. Croix, United States Virgin Islands, which had been operated by HOVIC until October 1998. The letter does not specify the basis for the claim or a claimed damages amount. If an action is brought, Registrant and HOVENSA intend to vigorously defend it.

      The Corporation is from time to time involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. Although the ultimate outcome of these proceedings cannot be ascertained at this time and some of them may be resolved adversely to the Corporation, no such proceeding is required to be disclosed under applicable rules of the Securities and Exchange Commission. In management’s opinion, based upon currently known facts and circumstances, such proceedings in the aggregate will not have a material adverse effect on the financial condition of the Corporation.

      During the fourth quarter of 2004, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise.

      The following table presents information as of February 1, 2005 regarding executive officers of the Registrant:

     Except for Messrs. O’Connor, Bohling, Paver, Rielly, Sandison, Scelfo and Strode, each of the above officers has been employed by the Registrant or its subsidiaries in various managerial and executive capacities for more than five years. Mr. O’Connor had served in senior executive positions at Texaco Inc. and BHP Petroleum prior to his employment with the Registrant in October 2001. Mr. Bohling was employed in senior human resource positions with American Standard Corporation and CDI Corporation before joining the Registrant in 2004. Mr. Paver had served in a senior executive position at BHP Petroleum prior to his employment with a subsidiary of Registrant in October 2002. Prior to his employment with the Registrant in April 2001, Mr. Rielly had been a partner of Ernst & Young LLP. Mr. Scelfo was chief financial officer of Sirius Satellite Radio and a division of Dell Computer before his employment by the Registrant in 2003. Mr. Sandison served in senior executive positions in the area of global drilling with Texaco, Inc. before he was employed by the Registrant in 2003. Prior to his employment with the Registrant in April 2000, Mr. Strode had served in senior executive positions in the area of exploration at Vastar Resources, Inc. and Atlantic Richfield Company.

      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 2004 and 2003 were as follows:

      The high and low sales prices of the Corporation’s 7% cumulative mandatory convertible preferred stock (traded on the New York Stock Exchange, ticker symbol: AHCPR) since issuance in the fourth quarter of 2003 were as follows:

      At December 31, 2004, 6,450 stockholders (based on number of holders of record) owned 91,715,180 shares of common stock.

      Cash dividends on common stock totaled $1.20 per share ($.30 per quarter) during 2004 and 2003. Annual dividends on the 7% cumulative mandatory convertible preferred stock totaled $3.50 per share ($.875 per quarter) in 2004. See Note 8 on Long-Term Debt in the financial statements for a discussion of restrictions on dividends.

      Following is information on the Registrant’s equity compensation plans at December 31, 2004:

     See Note 9 on Stock-Based Compensation Plans in the financial statements for further discussion of the Corporation’s equity compensation plans.

      A five-year summary of selected financial data follows:

      Proved reserves increased to 1.046 billion barrels of oil equivalent at year-end 2004 from 1.035 billion barrels of oil equivalent at the end of 2003. The Corporation’s reserves included in this Form 10-K are calculated by an independent third party reserve engineer. See further discussion of management’s governance over the estimation of oil and gas reserves in the Supplementary Oil and Gas Data on page 73.

      The strategic goals for R&M are to maximize returns from existing assets and generate free cash flow. The Corporation may grow the retail and energy marketing businesses opportunistically. During 2004 and 2003, the R&M segment’s results improved significantly, primarily due to higher refining margins. The HOVENSA and Port Reading refineries operated near maximum capacity for most of the year, enabling them to take full advantage of the strong margins. HOVENSA’s capacity to process lower cost heavy crude oil enhanced profitability in 2004, due to a significant price differential between light and heavy crude oil. In 2004, the Corporation received a cash distribution of $88 million from HOVENSA. The HOVENSA fluid catalytic cracking unit was shutdown for approximately 30 days of planned maintenance in the first quarter of 2005. Planned maintenance of the fluid catalytic cracking unit at the Port Reading facility is underway and expected to last for approximately 30 days.

      The Corporation’s liquidity and financial position have improved significantly since year-end 2002. At December 31, 2002, the Corporation’s debt was $5 billion and its debt to capitalization ratio was 54%. As of December 31, 2004, the Corporation’s debt has been reduced to $3.8 billion and the debt to capitalization ratio was 40.7%. Aggregate debt maturities through 2006 are $128 million. The Corporation’s cash balance at December 31, 2004 was $877 million.

      Capital expenditures were $1.5 billion in 2004, $1.4 billion in 2003 and $1.5 billion in 2002. Capital expenditures for 2005 are forecast to be $2.1 billion, with $2.0 billion dedicated to the exploration and production segment. This higher spending reflects the Corporation’s portfolio of organic growth projects and attractive investment opportunities. The Corporation has hedged approximately 60% of its 2005 worldwide crude oil production to underpin its cash flows to fund development projects. See further discussion on hedging starting on page 34.

      Net income in 2004 was $977 million compared with net income of $643 million in 2003 and a net loss of $218 million in 2002, including impairments. Included in these amounts was income from discontinued operations of $7 million in 2004, $169 million in 2003 and $27 million in 2002. See the following page for a table of items affecting the comparability of earnings between periods.

      The after-tax results by major operating activity for 2004, 2003 and 2002 are summarized below:

      In the discussion that follows, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the appropriate income tax rate in each tax jurisdiction to pre-tax amounts.

      The following items, on an after-tax basis, are included in income from continuing operations for the years 2004, 2003 and 2002:

      The items in the table above are explained on pages 21 through 24. The pre-tax amounts are shown on pages 21, 23 and 24.

     Exploration and Production: After considering the exploration and production items in the preceding table, the remaining changes in exploration and production earnings are primarily attributable to changes in selling prices, production volumes and operating costs and exploration expenses, as discussed below.

     Selling prices: Higher average selling prices of crude oil, natural gas liquids and natural gas increased exploration and production revenues from continuing operations by approximately $400 million in 2004 compared with 2003. In 2003, the change in average selling prices increased revenues by approximately $170 million compared with 2002. The Corporation’s average selling prices from continuing operations, including the effects of hedging, were as follows:

      The after-tax impacts of crude oil and U.S. natural gas hedges reduced earnings by $583 million ($935 million before income taxes) in 2004 and $260 million ($418 million before income taxes) in 2003 compared with an increase of $48 million ($82 million before income taxes) in 2002.

      The Corporation has after-tax, deferred hedge losses of $875 million recorded in accumulated other comprehensive income at December 31, 2004. Of this amount, $680 million is unrealized and relates to open hedge positions. The remaining $195 million deferred loss is realized and relates to closed hedge positions. The deferred realized loss will be recognized in earnings as the underlying barrels are sold in 2005.

      The Corporation has open hedge positions equal to 60% of its estimated worldwide crude oil production for 2005. The average price per barrel for open United States crude oil hedges is $33.06. The average price for open foreign crude oil hedges is $31.17. Approximately 20% of the Corporation’s hedges are WTI related and the remainder are Brent. In addition to the gains or losses on these open hedge positions, approximately $52 million of the $195 million deferred realized loss will reduce first quarter 2005 earnings and the remaining deferred realized loss will be recognized in earnings over the balance of the year. The Corporation also has approximately 24,000 barrels per day of Brent related production hedged from 2006 to 2012. The average price of these hedge positions is $26.20 per barrel. There were no natural gas hedges outstanding at December 31, 2004.

     Production and sales volumes: The Corporation’s crude oil and natural gas production, on a barrel of oil equivalent basis, was 342,000 barrels per day in 2004, 373,000 barrels per day in 2003 and 451,000 barrels per day in 2002. Approximately 50% of the production declines in 2004 and 2003 resulted from sales and exchanges of oil and gas producing properties. The remainder resulted principally from natural decline, and in 2003 compared with 2002, disappointing results from fields acquired in the United States in 2001 and reduced production from the Ceiba Field in Equatorial Guinea. The Corporation anticipates that its 2005 production, including anticipated production from Libya, will be approximately 350,000 barrels of oil equivalent per day. See page 27 for the current status of the discussions on the Corporation’s return to Libya. The Corporation’s net daily worldwide production was as follows:

     Decreased sales volumes resulted in lower revenue from continuing operations of approximately $75 million in 2004 compared with 2003 and lower revenue of approximately $425 million in 2003 compared with 2002.

     Operating costs and exploration expenses:Operating costs and exploration expenses from continuing operations decreased by approximately $115 million in 2004 compared with 2003 and increased by $70 million in 2003 compared with 2002. Depreciation, depletion and amortization charges were lower in 2004 and 2003 principally reflecting decreased production volumes. Exploration expenses were lower in 2004 as a result of lower dry hole costs. Exploration expenses were higher in 2003, reflecting increased activity in the United States and Equatorial Guinea, as well as additional lease cost amortization. Production expenses increased in 2004 and 2003 primarily due to the weakening of the U.S. dollar which increased costs incurred in foreign currencies. In addition, higher selling prices of crude oil and natural gas increased the costs of production taxes, transportation, maintenance and fuel. Unit costs per barrel totaled $17.26 in 2004, $17.32 in 2003 and $15.11 in 2002. Unit cost per barrel includes production expense, depreciation, depletion and amortization, exploration expense and administrative costs.

     Other: After-tax foreign currency gains amounted to $6 million ($29 million before income taxes) in 2004, compared with a loss of $22 million ($4 million before income taxes) in 2003 and income of $6 million ($26 million before income taxes) in 2002.

      Excluding items in the following table, the effective income tax rate for exploration and production operations in 2004 was 46%. This includes income taxes paid in jurisdictions with rates in excess of the United States statutory rate, such as the United Kingdom and Norway. It also reflects an income tax deduction for the Corporation’s hedging results at the U.S. statutory rate. Each of these factors increases the Corporation’s overall exploration and production effective income tax rate. The effective income tax rate for exploration and production operations in 2005 is expected to be in the range of 45% to 49%. Assuming agreements are finalized and the Corporation returns to Libya, the exploration and production effective income tax rate will exceed the range above.

      Exploration and production earnings from continuing operations include the following items:

     2004: The Corporation recognized gains on the sales of an office building in Aberdeen, Scotland, a non-producing property in Malaysia and two mature Gulf of Mexico properties. It also recorded foreign income tax benefits resulting from a change in tax law and a tax settlement. The Corporation accrued an additional amount for severance and costs for vacated office space during 2004. Additional accruals for vacated office space of approximately $35 million before income taxes are anticipated in 2005.

     2003: The Corporation recorded an after-tax charge of $32 million for accrued severance in the United States and United Kingdom and a reduction of leased office space in London. The pre-tax amount of this charge was $53 million, of which $32 million relates to vacated office space. The remainder of $21 million relates to severance for positions that were eliminated in London, Aberdeen and Houston.

      The Corporation recorded an income tax benefit reflecting the recognition for United States income tax purposes of certain prior year foreign exploration expenses. The gain from asset sale in 2003 reflects the sale of the Corporation’s 1.5% interest in the Trans Alaska Pipeline System.

     2002: Exploration and production earnings included after-tax asset impairments of $737 million, $530 million of which related to the Ceiba Field in Equatorial Guinea. The pre-tax amount of the Ceiba Field impairment was $706 million. The charge resulted from a 12% reduction in the estimated total field reserves that will ultimately be produced from the field, as well as higher anticipated development costs needed to produce the remaining reserves at lower production rates over a longer period. The reduction in estimated recoverable reserves was attributable to disappointing 2002 year-end drilling results on the western flank of the field. The reduction in probable reserves and higher estimated future development costs resulted in an asset impairment because projected cash flows were less than the book value of the field, which includes allocated purchase price from the Triton acquisition.

      The Corporation also recorded an after-tax impairment charge of $207 million to reduce the carrying value of oil and gas properties located primarily in the Main Pass/ Breton Sound area of the Gulf of Mexico. Most of these properties were obtained in the 2001 LLOG acquisition and consisted of producing oil and gas fields with proved and probable reserves and exploration acreage. This charge principally reflects reduced reserve estimates on these fields resulting from unfavorable production performance. The fair values of producing properties were determined by using discounted cash flows. Exploration properties were evaluated by using results of drilling and production data from nearby fields and seismic data for these and other properties in the area.

      During 2002, the United Kingdom government enacted a 10% supplementary tax on profits from oil and gas production. A one-time charge of $43 million was recorded to increase the existing United Kingdom deferred tax liability on the balance sheet.

      The gain on asset sales in 2002 reflected the disposal of oil and gas producing properties in the United States, United Kingdom and Azerbaijan, and the Corporation’s energy marketing business in the United Kingdom.

      The Corporation’s future exploration and production earnings may be impacted by external factors, such as volatility in the selling prices of crude oil and natural gas, reserve and production changes and changes in tax rates.

     Refining and Marketing: Earnings from refining and marketing activities amounted to $451 million in 2004, $327 million in 2003 and $85 million in 2002. The Corporation’s downstream operations include HOVENSA L.L.C. (HOVENSA), a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA) that is accounted for using the equity method. Additional refining and marketing activities include a fluid catalytic cracking facility in Port Reading, New Jersey, as well as retail gasoline stations, energy marketing and trading operations. In 2004, the Corporation invested in a 50% joint venture, Hess LNG L.L.C., to pursue investments in liquified natural gas terminals and related supply, trading and marketing opportunities.

     HOVENSA: The Corporation’s share of HOVENSA’s income was $244 million in 2004, compared with income of $117 million in 2003 and a loss of $47 million in 2002. The increases in 2004 and 2003 were

      Earnings from refining and marketing activities also include interest income on the note received from PDVSA at the formation of the joint venture. Interest on the PDVSA note amounted to $25 million in 2004, $30 million in 2003 and $35 million in 2002. Interest income is reflected in non-operating income in the income statement. In 2004, the Corporation recorded deferred income tax expense of $32 million in refining and marketing results relating to HOVENSA’s earnings and interest on the PDVSA note. In 2005, the Corporation expects that deferred income taxes will be recorded at the Virgin Islands statutory rate of 38.5%. At December 31, 2004, the Corporation has approximately $190 million of net operating loss carryforwards available to offset its share of future HOVENSA taxable income.

     Retail, Energy Marketing and Other: Retail gasoline operations in 2004 were profitable but less so than in 2003, reflecting lower margins. Earnings from retail gasoline operations were higher in 2003 compared with 2002, reflecting higher margins. Energy marketing earnings were lower in 2004 compared with 2003 because of lower margins. Energy marketing activities had higher earnings in 2003, reflecting increased margins and sales volumes in the early part of the year resulting from the cold winter. Results of the Port Reading refining facility improved in 2004 reflecting higher margins than in 2003, which was also an improvement over 2002 results. Total refined product sales volumes were 428,000 barrels per day in 2004, 419,000 barrels per day in 2003 and 383,000 barrels per day in 2002. Planned maintenance at the Port Reading fluid catalytic cracking unit is underway in the first quarter of 2005.

      The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions for its own account. The Corporation’s after-tax results from trading activities, including its share of the earnings of the trading partnership amounted to income of $37 million in 2004, $17 million in 2003 and $3 million in 2002. Before income taxes, the trading income was $72 million in 2004, $30 million in 2003 and $6 million in 2002.

      Marketing expenses increased in 2004 compared with 2003 reflecting higher expenses from retail operations and the trading partnership.

      Refining and marketing earnings include the following items:

      In 2004, refining and marketing results include income of $12 million from the liquidation of LIFO inventories. In 2003, refining and marketing earnings were reduced by a loss from the sale of the Corporation’s interest in a shipping joint venture. In 2002, the Corporation completed the sale of six United States flag vessels for $161 million in cash and a note for $29 million. The sale resulted in a net gain of $67 million. In connection with this sale, the Corporation agreed to support the buyer’s charter rate on these vessels for up to five years. The support agreement requires that if the actual contracted rate for the charter of a vessel is less than the stipulated support rate in the agreement, the Corporation will pay to the buyer the difference between the contracted rate and the stipulated rate. At January 1, 2004, the charter support reserve was $32 million. During 2004, the Corporation made net payments of $4 million for charter support. Based on contractual long-term charters and estimates of future charter rates, the Corporation lowered the estimated charter support reserve by $18 million in 2004. The balance in this reserve at December 31, 2004 was $10 million. In 2002, the Corporation recorded a charge for the write-off of intangible assets in its U.S. energy marketing business. In addition, severance was recorded for cost reduction initiatives in refining and marketing, principally energy marketing.

      Refining and marketing earnings will likely continue to be volatile reflecting competitive industry conditions and supply and demand factors, including the effects of weather.

     Corporate: After-tax corporate expenses amounted to $85 million in 2004, $101 million in 2003 and $63 million in 2002. The 2004 corporate expenses include $13 million ($20 million before income taxes) of insurance costs related to retrospective premium increases. In addition, corporate results include an income tax benefit of $13 million from the settlement of a federal tax audit. The 2003 amount includes expenses of $34 million for premiums paid on the repurchase of bonds compared with $6 million in 2002. The pre-tax amounts of the bond repurchase premiums were $58 million in 2003 and $15 million in 2002 and are recorded in non-operating income (expense) in the income statement. Recurring after-tax corporate expenses for 2005 are estimated to be in the range of $90 to $100 million.

     Interest: After-tax interest expense in 2004, 2003 and 2002 was as follows:

      Interest incurred decreased in 2004 and 2003 reflecting lower average outstanding debt. After-tax interest expense in 2005 is anticipated to be lower than the 2004 level because of higher estimated capitalized interest.

     Discontinued Operations: In 2003, the Corporation exchanged its crude oil producing properties in Colombia (acquired in 2001 as part of the Triton acquisition), plus $10 million in cash, for an additional 25% interest in Block A-18 in the joint development area of Malaysia and Thailand (JDA). The exchange resulted

      In 2003, the Corporation also sold Gulf of Mexico shelf properties, the Jabung Field in Indonesia and several small United Kingdom fields for $445 million. The after-tax gain from these asset sales of $176 million ($248 million before income taxes) was included in discontinued operations. Discontinued operations in 2003 also included $40 million of income from operations prior to the sales of these assets.

     Change in Accounting Principle: The Corporation adopted FAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. A net after-tax gain of $7 million resulting from the cumulative effect of this accounting change was recorded at the beginning of 2003. At the date of adoption, a liability of $556 million representing the estimated fair value of the Corporation’s required dismantlement obligations was recorded on the balance sheet. In addition, a dismantlement asset of $311 million was recorded, as well as accumulated depreciation of $203 million.

     Sales and Other Operating Revenues: In 2004, sales and other operating revenues totaled $16,733 million, an increase of 17% compared with 2003. This increase principally reflects higher selling prices and sales volumes of refined products, partially offset by decreased sales of purchased natural gas in energy marketing. Sales and other operating revenues increased by 24% in 2003 compared with 2002, reflecting increased sales volumes and selling prices of refined products and the higher selling price of purchased natural gas in energy marketing activities. The change in cost of goods sold in each year reflects the change in sales volumes and prices of refined products and purchased natural gas.

     Overview: Cash flows from operating activities, including changes in operating assets and liabilities, totaled $1,903 million in 2004. During the year, the Corporation repaid $106 million of debt, which decreased its debt to capitalization ratio to 40.7% at December 31, 2004 from 42.5% at December 31, 2003. Total debt was $3,835 million at December 31, 2004 and $3,941 million at December 31, 2003. The Corporation has debt maturities of $128 million during the next two years. In 2004, the Corporation entered into a new $2.5 billion revolving credit facility, expiring in 2009. Cash and cash equivalents at the end of 2004 totaled $877 million, an increase of $359 million for the year.

     Cash Flows from Operating Activities: Net cash provided by operating activities, including changes in operating assets and liabilities, totaled $1,903 million in 2004, $1,581 million in 2003 and $1,965 million in 2002. The increased cash flows in 2004 resulted primarily from higher earnings and the timing of cash flows associated with changes in operating assets and liabilities. In 2004, the Corporation also received a cash distribution of $88 million from HOVENSA. Lower cash flows in 2003 were primarily due to reduced exploration and production sales volumes. Changes in operating assets and liabilities increased cash flow by $230 million in 2004 and decreased cash flow by $120 million in 2003.

     Cash Flows from Investing Activities: The following table summarizes the Corporation’s capital expenditures in 2004, 2003 and 2002:

      Proceeds from asset sales in 2004 totaled $57 million. In 2003, the Corporation sold certain producing properties in the Gulf of Mexico Shelf, the Jabung Field in Indonesia, several small United Kingdom fields and an interest in a shipping joint venture. Proceeds from asset sales totaled $545 million in 2003. In addition, the Corporation completed several asset exchanges. The Corporation swapped mature, high-cost assets in Colombia for an additional 25% interest in long-lived natural gas reserves in Block A-18 in the joint development area of Malaysia and Thailand, bringing the Corporation’s interest in the area to 50%. The Corporation exchanged its 25% equity investment in Premier Oil plc for a 23% interest in Natuna Sea Block A in Indonesia, plus approximately $10 million in cash. In the fourth quarter of 2003, the Corporation exchanged 14% interests in the Scott and Telford fields in the United Kingdom for an additional 22.5% interest in the Llano Field in the Gulf of Mexico and $17 million in cash. This exchange increased the Corporation’s working interest in the Llano Field to 50% and decreased its interest in the Scott Field to 21% and the Telford Field to 17%. The net production from fields sold or exchanged in 2003 at the time of disposition was approximately 50,000 barrels of oil equivalent per day.

      In 2002, the Corporation sold six United States Flag vessels, its energy marketing business in the United Kingdom and several small oil and gas fields for net proceeds of $412 million.

     Cash Flows from Financing Activities: The Corporation reduced debt by $106 million in 2004, $1,051 million in 2003 and $673 million in 2002. The debt reduction in 2004 was due to cash flow from operations. In 2003, debt was reduced by proceeds from the issuance of preferred stock and from asset sales, as well as cash flow from operations. In 2003, the Corporation issued 13,500,000 shares of mandatory convertible preferred stock for net proceeds of $653 million. In 2004, the Corporation received proceeds from the exercise of stock options totaling $90 million. Dividends paid were $157 million in 2004, $108 million in 2003 and $107 million in 2002. The increase in 2004 was due to dividends on the 7% preferred stock issued in the fourth quarter of 2003.

     Future Capital Requirements and Resources: Capital expenditures in 2005 are expected to be approximately $2.1 billion, including an estimated amount for re-entering Libya. The Corporation anticipates that these expenditures will be funded by available cash and cash flow from operations, however, revolving credit facilities are available, if necessary.

      With higher crude oil prices, the Corporation’s collateral requirements under certain contracts with hedging and trading counterparties have increased. Outstanding letters of credit were $1,487 million at December 31, 2004, including $570 million drawn against the Corporation’s $2.5 billion syndicated, revolving credit facility, compared with outstanding letters of credit of $229 million at December 31, 2003. At December 31, 2004, the Corporation has $1,930 million available under its committed revolving credit

     Repatriation Provisions of the American Jobs Creation Act of 2004: On October 22, 2004, the President signed the American Jobs Creation Act (the Act) that effectively provides for a one-time reduction of the income tax rate to 5.25% on eligible dividends from foreign subsidiaries to a U.S. parent. Subsequent to December 31, 2004, the Corporation decided to repatriate approximately $1.3 billion of unremitted foreign earnings. As a result, the Corporation expects to record a tax provision of approximately $41 million in the first quarter of 2005. Had the additional taxes been recorded at the end of 2004, net income would have been $936 million ($9.93 per share basic and $9.17 per share diluted). The Corporation is reviewing the possibility of additional repatriations during 2005. The maximum additional amount that the Corporation could repatriate under the Act is approximately $600 million. The Corporation estimates that an additional tax provision of up to $32 million would be recorded, depending on the incremental amount distributed, if any.

     In the preceding table, the Corporation’s supply commitments include its estimated purchases of 50% of HOVENSA’s production of refined products, after anticipated sales by HOVENSA to unaffiliated parties. Also included are normal term purchase agreements at market prices for additional gasoline necessary to supply the Corporation’s retail marketing system and feedstocks for the Port Reading refining facility. In addition, the Corporation has commitments to purchase natural gas for use in supplying contracted customers in its energy marketing business. These commitments were computed based on year-end market prices.

      The table also reflects that portion of the Corporation’s planned capital expenditures that are contractually committed at December 31. The Corporation’s 2005 capital expenditures are estimated to be approximately $2.1 billion. Obligations for operating expenses include commitments for transportation, seismic purchases, oil and gas production expenses and other normal business expenses. Other long-term liabilities reflect contractually committed obligations on the balance sheet at December 31, including minimum pension plan funding requirements.

      In connection with the sale of six vessels in 2002, the Corporation agreed to support the buyer’s charter rate on these vessels for up to five years. The support agreement requires that if the actual contracted rate for the charter of a vessel is less than the stipulated support rate in the agreement, the Corporation will pay to the buyer the difference between the contracted rate and the stipulated rate. The balance in the charter support reserve at December 31, 2004 was $10 million.

      The Corporation has a contingent purchase obligation to acquire the remaining 50% interest in a retail marketing and gasoline station joint venture for approximately $90 million.

      The Corporation guarantees the payment of up to 50% of HOVENSA’s crude oil purchases from suppliers other than PDVSA. The amount of the Corporation’s guarantee fluctuates based on the volume of crude oil purchased and related prices and at December 31, 2004 amounted to $97 million. In addition, the Corporation has agreed to provide funding up to a maximum of $40 million to the extent HOVENSA does not have funds to meet its senior debt obligations.

      At December 31, the Corporation has $1,415 million of letters of credit principally relating to accrued liabilities with hedging and trading counterparties recorded on its balance sheet. In addition, the Corporation is contingently liable under letters of credit and under guarantees of the debt of other entities directly related to its business, as follows:

    Off-Balance Sheet Arrangements: The Corporation has leveraged lease financings not included in its balance sheet, primarily related to retail gasoline stations that the Corporation operates. The net present value of these financings is $467 million at December 31, 2004 compared with $462 million at December 31, 2003. The Corporation’s December 31, 2004 debt to capitalization ratio would increase from 40.7% to 43.5% if the lease financings were included as debt.

      See also “Contractual Obligations and Contingencies” above, Note 5, “Refining Joint Venture,” and Note 16, “Guarantees and Contingencies,” in the financial statements.

     Foreign Operations: The Corporation conducts exploration and production activities in many foreign countries, including the United Kingdom, Norway, Denmark, Gabon, Indonesia, Thailand, Azerbaijan, Algeria, Malaysia and Equatorial Guinea. Therefore, the Corporation is subject to the risks associated with foreign operations. These exposures include political risk (including tax law changes) and currency risk. The effects of these events are accounted for when they occur and generally have not been material to the Corporation’s liquidity or financial position.

      HOVENSA L.L.C., owned 50% by the Corporation and 50% by Petroleos de Venezuela, S.A. (PDVSA), owns and operates a refinery in the Virgin Islands. Although there have in the past been political disruptions in Venezuela that reduced the availability of Venezuelan crude oil used in refining operations, these disruptions did not have a material adverse effect on the Corporation’s financial position. The Corporation also has a note receivable of $273 million at December 31, 2004 from a subsidiary of PDVSA. The Corporation anticipates collection of the remaining balance.

      Accounting policies and estimates affect the recognition of assets and liabilities on the Corporation’s balance sheet and revenues and expenses on the income statement. The accounting methods used can affect net income, stockholders’ equity and various financial statement ratios. However, the Corporation’s accounting policies generally do not change cash flows or liquidity.

     Accounting for Exploration and Development Costs:Oil and gas exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.

      The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. In an area requiring a major capital expenditure before production can begin, an exploration well is carried as an asset if sufficient reserves are discovered to justify its completion as a production well, and additional exploration drilling is underway or firmly planned. The Corporation does not capitalize the cost of other exploratory wells for more than one year unless proved reserves are found.

     Crude Oil and Natural Gas Reserves: The determination of estimated proved reserves is a significant element in arriving at the results of operations of exploration and production activities. The estimates of proved reserves affect well capitalizations, undeveloped leasehold impairments and the unit of production depreciation rates of proved properties, wells and equipment. Reductions in reserve estimates may result in the need for increased depreciation or impairments of proved properties and related assets.

      The Corporation’s oil and gas reserves are calculated in accordance with SEC regulations and interpretations and the requirements of the Financial Accounting Standards Board. For reserves to be booked as proved they must be commercially producible, government approvals must be obtained and depending on the amount of the project cost, senior management or the board of directors must commit to fund the project. The Corporation’s oil and gas reserve estimation and reporting process involves an annual independent third party reserve determination as well as internal technical appraisals of reserves. The Corporation maintains its own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. The Corporation’s technical staff updates reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management reviews the estimates.

      The oil and gas reserve estimates reported in the Supplementary Oil and Gas Data in accordance with FAS No. 69 are determined independently by the consulting firm of DeGolyer and MacNaughton (D&M) and are consistent with internal estimates. Annually, the Corporation provides D&M with engineering, geological and geophysical data, actual production histories and other information necessary for the reserve

     Impairment of Long-Lived Assets and Goodwill: As explained below there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing. The Corporation reviews long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived assets are tested at the lowest level for which cash flows are identifiable and are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by undiscounted future net cash flow estimates, 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.

      In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of actual prices on the last day of the year.

      The Corporation’s impairment tests of long-lived exploration and production producing assets are based on its best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs and the timing of future production, which are updated each time an impairment test is performed. In 2002, the Corporation recorded impairments of the Ceiba Field and LLOG properties that were required primarily because of reduced estimates of oil and gas production volumes and, in the case of Ceiba, anticipated additional development costs. The impairment charges did not result from changes in the other factors. The change in the estimated timing of production on the Ceiba Field did not significantly affect the undiscounted future cash flows, but did significantly reduce the fair value of the field determined by discounted cash flows. The Corporation could have additional impairments if the projected production volumes from oil and gas fields were reduced. Significant extended declines in crude oil and natural gas selling prices could also result in asset impairments.

      The Corporation recorded $977 million of goodwill in connection with the purchase of Triton Energy Limited in 2001. Factors contributing to the recognition of goodwill included the strategic value of expanding global operations to access new growth areas outside of the United States and the North Sea, obtaining critical mass in Africa and Southeast Asia, and synergies, including cost savings, improved processes and portfolio high grading opportunities. In accordance with FAS No. 142, goodwill is no longer amortized but must be tested for impairment annually. FAS No. 142 requires that goodwill be tested for impairment at a reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment. A component is a reporting unit if the component constitutes a business for which discrete financial information is available and segment management regularly reviews the operating results of that component. However, two or more components of an operating segment shall be aggregated and deemed a single reporting unit if the components have similar economic characteristics. An operating segment shall be deemed a reporting unit if all of its components are economically similar.

      Within the Corporation’s exploration and production operating segment there are currently two components: (1) Americas and West Africa and (2) Europe, North Africa and Asia. Each component has a manager who reports to the segment manager. The Corporation has determined the components have similar economic characteristics and, therefore, has aggregated the components into a single reporting unit — the exploration and production operating segment. As a result, goodwill has been assigned to the exploration and production operating segment. If the Corporation reorganized its exploration and production business such

      The Corporation expects that the benefits of goodwill will be recovered through the operation of the exploration and production segment as a whole and it evaluated the following characteristics in determining that the components are economically similar:

      The Corporation’s fair value estimate of the exploration and production segment is the sum of: (1) the discounted anticipated cash flows of producing assets and known developments, (2) the expected risked present value of exploration assets, and (3) an estimated market premium to reflect the market price an acquirer would pay for potential synergies including cost savings, access to new business opportunities, enterprise control, improved processes and increased market share. The Corporation also considers the relative market valuation of similar exploration and production companies.

      The determination of the fair value of the exploration and production operating segment depends on estimates about oil and gas reserves, future prices, timing of future net cash flows and market premiums. Significant extended declines in crude oil and natural gas prices or reduced reserve estimates could lead to a decrease in the fair value of the exploration and production operating segment that could result in an impairment of goodwill. In addition, changes in management structure or sales or dispositions of a portion of the exploration and production segment may result in goodwill impairment.

      Because there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing, there may be impairments of individual assets that would not cause an impairment of the $977 million of goodwill assigned to the exploration and production segment. In 2002, the Corporation recognized asset impairments because reduced estimates of oil and gas production volumes caused the expected undiscounted cash flows of the assets to be lower than the asset carrying amounts. No impairment of goodwill existed because the fair value of the overall exploration and production operating segment continued to exceed its recorded book value.

     Segments: The Corporation has two operating segments, exploration and production, and refining and marketing. Management has determined that these are its operating segments because, in accordance with FAS No. 131, these are the segments of the Corporation (i) that engage in business activities from which revenues are earned and expenses are incurred, (ii) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance and (iii) for which discrete financial information is available. The Chairman of the Board and Chief Executive Officer of the Corporation, is the chief operating decision maker (CODM) as defined in FAS No. 131, because he is responsible for performing the functions within the Corporation of allocating resources to, and assessing the performance of, the Corporation’s operating segments. The CODM uses only the operating results of each segment as a whole to make decisions about resources to be allocated to each segment and to assess the segment performance. The CODM manages each segment globally and does not regularly review the operating results of any component (e.g., geographic area) or asset within each

     Hedging: The Corporation may use futures, forwards, options and swaps, individually or in combination, to reduce the effects of fluctuations in crude oil, natural gas and refined product selling prices. Related hedge gains or losses are an integral part of the selling or purchase prices. Generally, these derivatives are designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), and the changes in fair value are recorded in accumulated other comprehensive income. These transactions meet the requirements for hedge accounting, including correlation. The Corporation reclassifies hedging gains and losses included in accumulated other comprehensive income to earnings at the time the hedged transactions are recognized. The ineffective portion of hedges is included in current earnings. The Corporation’s remaining derivatives, including foreign currency contracts, are not designated as hedges and the change in fair value is included in income currently. At December 31, 2004, the Corporation has $875 million of deferred exploration and production hedging losses, after income taxes, included in accumulated other comprehensive income.

     Income Taxes: Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements. The Corporation has net operating loss carryforwards in several jurisdictions, including the United States, and has recorded deferred tax assets for those losses. Additionally, the Corporation has deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that will be realized. In evaluating realizability of deferred tax assets, the Corporation refers to the reversal periods for temporary differences, available carryforward periods for net operating losses, estimates of future taxable income, the availability of tax planning strategies, the existence of appreciated assets and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves and selling prices that are consistent with the Corporation’s internal business forecasts.

      The Corporation has implemented a values-based, socially-responsible strategy focused on improving environment, health and safety performance and making a positive impact on communities. The strategy is supported by the Corporation’s environment, health, safety and social responsibility policies and by environment and safety management systems that help protect the Corporation’s workforce, customers and local communities. The Corporation’s management systems are based on international standards and are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS performance. Improved performance may increase the Corporation’s operating costs and could also require increased capital expenditures to reduce potential risks to assets, reputation and license to operate. While overall governance is the responsibility of senior management, the Corporation has programs in place to evaluate regulatory compliance, audit facilities, train employees and to generally meet corporate EHS goals.

      The Port Reading refining facility and the HOVENSA refinery manufacture conventional and reformulated gasolines that are cleaner burning than that required under current U.S. regulations. The production of motor and other fuels in the United States and elsewhere has faced increasing regulatory pressures to reduce sulfur content in recent years. In 2004, new regulations went into effect that significantly reduced gasoline sulfur content and additional rules to reduce the allowable sulfur content in diesel fuel will go into effect in 2006. Fuels production will likely continue to be subject to more stringent regulation in future years and as such may require additional large capital expenditures.

      The Corporation and HOVENSA continue to evaluate options to determine the most cost effective compliance strategies for known fuel regulations. Estimated capital expenditures necessary to comply with low-sulfur gasoline requirements at Port Reading are approximately $70 million over the next two years. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are presently expected to be approximately $400 million in total, $50 million of which has already been spent. Remaining capital expenditures are projected to be $350 million over the next two years. HOVENSA plans to finance these capital expenditures through cash flow from operations. If it becomes necessary to finance a portion of the capital expenditures, HOVENSA has $400 million of available revolving credit capacity.

      Federal legislation to restrict or ban the use of MTBE, a gasoline oxygenate, and to require the use of ‘renewable’ fuels was considered by the United States Congress in 2004 and will likely be reconsidered in 2005. The Corporation and HOVENSA both manufacture and use MTBE, where permitted, to meet the federal requirement for oxygen in reformulated gasoline. In states within the Corporation’s marketing area where MTBE bans have been enacted, such as Connecticut and New York, the Corporation markets reformulated gasoline without oxygenates and ethanol is added to the gasoline downstream from the refineries to meet regulatory requirements. If Congress bans MTBE nationally or if additional state bans take effect, or if an obligation to use ethanol or other renewable fuels is imposed, the effect on the Corporation and HOVENSA could be significant. Whether the effect is significant will depend on several factors, including the extent and timing of any such bans of MTBE or obligations to use ethanol, requirements for maintenance of certain air emission reductions if MTBE is banned, the cost and availability of alternative oxygenates or credits and whether the minimum oxygen content standard for reformulated gasoline remains in effect. The Corporation will continue to review various options to market and produce reformulated gasolines if additional MTBE bans take effect.

      As described in Item 3 “Legal Proceedings” in 2003, the Corporation and HOVENSA began discussions with the U.S. EPA regarding the EPA’s Petroleum Refining Initiative (PRI). The PRI is an ongoing program that is designed to reduce certain air emissions at all U.S. refineries. Since 2000, EPA has entered into settlements addressing these emissions with petroleum refining companies that control over 50% of the nation’s refining capacity in 26 states and negotiations continue with many refiners. Depending on the outcome of these discussions, the Corporation and HOVENSA may experience increased capital and operating expenses related to air emissions controls. The PRI allows for controls to be phased in over several years.

      The Corporation recognizes the worldwide concern about the environmental and social impact of air emissions. On a global scale, climate change is an issue that has prompted much public debate and has a potential impact on future economic growth and development. The Corporation has undertaken a program to assess, monitor and reduce the emission of “greenhouse gases,” including carbon dioxide and methane. The challenges associated with this program may be significant, not only from the standpoint of technical feasibility, but also from the perspective of adequately measuring the Corporation’s entire greenhouse gas inventory.

      The Corporation expects continuing expenditures for environmental assessment and remediation related primarily to existing conditions. Sites where corrective action may be necessary include gasoline stations, terminals, onshore exploration and production facilities, refineries (including solid waste management units under permits issued pursuant to the Resource Conservation and Recovery Act) and, although not currently significant, “Superfund” sites where the Corporation has been named a potentially responsible party.

      The Corporation accrues for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. At year-end 2004, the Corporation’s reserve for its estimated environmental liability was approximately $81 million. The Corporation does not discount its environmental liability. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. Remediation spending was $12 million in 2004 and 2003 and $9 million in 2002. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, were $1 million in 2004, $7 million in 2003 and $5 million in 2002.

      Certain sections of Management’s Discussion and Analysis of Results of Operations and Financial Condition and Quantitative and Qualitative Disclosures about Market Risk, including references to the Corporation’s future results of operations and financial position, liquidity and capital resources, capital expenditures, oil and gas production, tax rates, debt repayment, hedging, derivative, market risk and environmental disclosures, off-balance sheet arrangements and contractual obligations and contingencies include 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.

      In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the price of crude oil, natural gas, refined products and electricity, as well as to changes in interest rates and foreign currency values. In the disclosures that follow, these operations are referred to as non-trading activities. The Corporation also has trading operations, principally through a 50% voting interest in a trading partnership. These activities are also exposed to commodity risks primarily related to the prices of crude oil, natural gas and refined products. The following describes how these risks are controlled and managed.

     Controls: The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value-at-risk limits. In addition, the chief risk officer must approve the use of new instruments or commodities. Risk limits are monitored daily and exceptions are reported to business units and to senior management. The Corporation’s risk management department also performs independent verifications of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s non-trading and trading activities, including the consolidated trading partnership. The Corporation’s treasury department administers foreign exchange rate and interest rate hedging programs.

     Instruments: The Corporation primarily uses forward commodity contracts, foreign exchange forward contracts, futures, swaps, options and energy commodity linked securities in its non-trading and trading activities. These contracts are widely traded instruments mainly with standardized terms. The following describes these instruments and how the Corporation uses them:

     Quantitative Measures: The Corporation uses value-at-risk to monitor and control commodity risk within its trading and non-trading activities. The value-at-risk model uses historical simulation and the results represent the potential loss in fair value over one day at a 95% confidence level. The model captures both first and second order sensitivities for options. The potential change in fair value based on commodity price risk is presented in the non-trading and trading sections below.

      For foreign exchange rate risk, the impact of a 10% change in foreign exchange rates on the value of the Corporation’s portfolio of foreign currency forward contracts is presented in the non-trading section. Similarly, the impact of a 15% change in interest rates on the fair value of the Corporation’s debt is also presented in the non-trading section. A 10% change in foreign exchange rates and a 15% change in the rate of interest over one year are considered reasonable possibilities for providing sensitivity disclosures.

     Non-Trading: The Corporation’s non-trading activities include hedging of crude oil and natural gas production. Futures and swaps are used to fix the selling prices of a portion of the Corporation’s future production and the related gains or losses are an integral part of the Corporation’s selling prices. As of December 31, the Corporation has open hedge positions equal to 60% of its estimated 2005 worldwide crude oil production. The average price for West Texas Intermediate crude oil (WTI) related open hedge positions is $33.06. The average price for Brent crude oil related open hedge positions is $31.17. Approximately 20% of the Corporation’s hedges is WTI related and the remainder is Brent. In addition, the Corporation has approximately 24,000 barrels per day of Brent related crude oil production hedged from 2006 through 2012 at an average price of $26.20 per barrel. There were no hedges of natural gas production at year end. As market conditions change, the Corporation may adjust its hedge percentages.

      Because the selling price of crude oil has increased during 2004, accumulated other comprehensive income (loss) at December 31, 2004 includes after-tax deferred losses of $875 million ($195 million of realized losses and $680 million of unrealized losses) related to crude oil contracts used as hedges of exploration and production sales. Realized losses in accumulated other comprehensive income represent losses on closed contracts that are deferred until the underlying barrels are sold. In addition to the impact of the open hedge positions described above, approximately $52 million of the realized losses will reduce earnings in the first quarter of 2005 and the remainder will reduce earnings during the balance of 2005. The pre-tax amount of all deferred hedge losses is reflected in accounts payable and the related income tax benefits are recorded as deferred tax assets on the balance sheet.

      The Corporation also markets energy commodities including refined petroleum products, natural gas and electricity. The Corporation uses futures and swaps to fix the purchase prices of commodities to be sold under fixed-price sales contracts.

      The following table summarizes the value-at-risk results of commodity related derivatives that are settled in cash and used in non-trading activities. The results may vary from time to time as hedge levels change.

      The increase in the value at risk in 2004 principally reflects additional hedge positions on Brent related production for the years 2006 through 2012.

      The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates by entering into forward purchase contracts for both the British pound sterling and the Danish kroner. At December 31, 2004, the Corporation has $476 million of notional value foreign exchange contracts maturing in 2005 ($384 million at December 31, 2003). The fair value of foreign exchange contracts recorded as assets was $49 million at December 31, 2004 ($40 million at December 31, 2003). The change in fair value of the foreign exchange contracts from a 10% change in exchange rates is estimated to be $53 million at December 31, 2004 ($43 million at December 31, 2003).

      At December 31, 2004, the interest rate on substantially all of the Corporation’s debt was fixed and there were no interest rate swaps. The Corporation’s outstanding debt of $3,835 million has a fair value of $4,327 million at December 31, 2004 (debt of $3,941 million at December 31, 2003 had a fair value of $4,440 million). A 15% change in the rate of interest would change the fair value of debt by approximately $260 million at December 31, 2004 and by approximately $270 million at December 31, 2003.

     Trading: The trading partnership in which the Corporation has a 50% voting interest trades energy commodities and derivatives. The accounts of the partnership are consolidated with those of the Corporation. The Corporation also takes trading positions for its own account. These strategies include proprietary position management and trading to enhance the potential return on assets. The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts.

      In trading activities, the Corporation is exposed to changes in crude oil, natural gas and refined product prices, primarily in North America and Europe. Trading positions include futures, forwards, swaps and options. In some cases, physical purchase and sale contracts are used as trading instruments and are included in the trading results.

      Gains or losses from sales of physical products are recorded at the time of sale. Derivative trading transactions are marked-to-market and are reflected in income currently. Total realized gains for the year amounted to $79 million. The following table provides an assessment of the factors affecting the changes in fair value of trading activities and represents 100% of the trading partnership and other trading activities.