AMERADA HESS CORPORATION
Table of Contents



UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549


Form 10-K

  x  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)  
  OF THE SECURITIES EXCHANGE ACT OF 1934  
For the fiscal year ended December 31, 2003
or
  o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)  
  OF THE SECURITIES EXCHANGE ACT OF 1934  
  For the transition period from                  to                   

Commission File Number 1-1204


Amerada Hess Corporation

(Exact name of Registrant as specified in its charter)

DELAWARE

(State or other jurisdiction of incorporation or organization)
13-4921002
(I.R.S. Employer Identification Number)
     
1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y.
(Address of principal executive offices)
  10036
(Zip Code)

(Registrant’s telephone number, including area code, is (212) 997-8500)


Securities registered pursuant to Section 12(b) of the Act:

     
Name of Each Exchange
Title of Each Class on which Registered


Common Stock (par value $1.00)   New York Stock Exchange
7% Mandatory Convertible Preferred Stock   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

      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  ü  No    

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
      Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).  Yes  ü  No    
      The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $3,771,000,000 as of June 30, 2003.
      At January 31, 2004, 89,856,630 shares of Common Stock were outstanding.
      Certain items in Parts I and II incorporate information by reference from the 2003 Annual Report to Stockholders and Part III is incorporated by reference from the Proxy Statement for the annual meeting of stockholders to be held on May 5, 2004.



TABLE OF CONTENTS

PART I
Item 1.Business
Item 2.Properties
Item 3.Legal Proceedings
Item 4.Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant
PART II
Item 5. Market for the Registrant’s Common Stock and Related Stockholder Matters
Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions
Item 14. Principal Accounting Fees and Services
PART IV
Item 15.Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SIGNATURES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
AMENDMENT TO STOCK AWARD PROGRAM
2003 ANNUAL REPORT TO STOCKHOLDERS
SUBSIDIARIES
SECTION 306 CERTIFCATION
SECTION 306 CERTIFICATION
SECTION 906 CERTIFCATION
SECTION 906 CERTIFCATION


Table of Contents

AMERADA HESS CORPORATION

Form 10-K

TABLE OF CONTENTS
                 
Item No. Page


PART I
  1.     Business     2  
  2.     Properties     7  
  3.     Legal Proceedings     9  
  4.     Submission of Matters to a Vote of Security Holders     11  
        Executive Officers of the Registrant     12  
PART II
  5.     Market for the Registrant’s Common Stock and Related Stockholder Matters     13  
  6.     Selected Financial Data     13  
  7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations     13  
  7A.     Quantitative and Qualitative Disclosures About Market Risk     13  
  8.     Financial Statements and Supplementary Data     13  
  9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     13  
  9A.     Controls and Procedures     13  
PART III
  10.     Directors and Executive Officers of the Registrant     13  
  11.     Executive Compensation     13  
  12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     14  
  13.     Certain Relationships and Related Transactions     14  
  14.     Principal Accounting Fees and Services     14  
PART IV
  15.     Exhibits, Financial Statement Schedules, and Reports on Form 8-K     15  
        Signatures     19  
        Index to Financial Statements and Schedules     F-1  
        HOVENSA L.L.C. Financial Statements as of December 31, 2003     H-1  

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PART I

 
Item 1. Business

      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.

Exploration and Production

      At December 31, 2003, the Corporation had 646 million barrels of proved crude oil and natural gas liquids reserves compared with 782 million barrels at the end of 2002. Proved natural gas reserves were 2,332 million Mcf at December 31, 2003 compared with 2,477 million Mcf at December 31, 2002. These crude oil and natural gas reserves included the Corporation’s proportionate share of the reserves of equity investees in prior years. The decrease in proved reserves resulted from asset sales and production. Proved reserves at December 31, 2003 include 32% and 43%, respectively, of crude oil and natural gas held under production sharing contracts. Of the total proved reserves (on a barrel of oil equivalent basis), 18% are located in the United States, 42% are located in the United Kingdom, Norwegian and Danish sectors of the North Sea and the remainder are located in Algeria, Azerbaijan, Equatorial Guinea, Gabon, Indonesia, Thailand and Malaysia. On a barrel of oil equivalent basis, 32% of the Corporation’s December 31, 2003 worldwide proved reserves are undeveloped (33% in 2002).

      Worldwide crude oil and natural gas liquids production amounted to 259,000 barrels per day in 2003 compared with 325,000 barrels per day in 2002. Worldwide natural gas production was 683,000 Mcf per day in 2003 compared with 754,000 Mcf per day in 2002. The Corporation presently estimates that its 2004 barrel of oil equivalent production will be approximately 13% less than 2003. The Corporation is developing a number of oil and gas fields and also has an inventory of domestic and foreign drillable prospects.

      United States.  Amerada Hess Corporation operates mainly offshore in the Gulf of Mexico and onshore in Texas, Louisiana and North Dakota. During 2003, 21% of the Corporation’s crude oil and natural gas liquids production and 37% 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:

                     
2003 2002


Crude Oil, Including Condensate and
Natural Gas Liquids (thousands of barrels per day)
               
 
Gulf of Mexico
    23       31  
 
North Dakota
    13       14  
 
Texas
    11       12  
 
Louisiana
    5       6  
 
New Mexico
    3       3  
     
     
 
   
Total
    55       66  
     
     
 

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2003 2002


Natural Gas (thousands of Mcf per day)
               
 
Gulf of Mexico
    117       208  
 
Louisiana
    58       84  
 
North Dakota
    58       57  
 
Texas
    11       14  
 
New Mexico
    9       10  
     
     
 
   
Total
    253       373  
     
     
 
Barrels of Oil Equivalent* (thousands of barrels per day)
    97       128  
     
     
 

Reflects natural gas production converted on the basis of relative energy content (six Mcf equals one barrel).

      The Llano Field (AHC 50%) on Garden Banks Blocks 385 and 386 in the Gulf of Mexico is currently being developed with initial net production expected in mid-2004 at an average rate of 12,000 barrels of oil equivalent per day. Additional appraisal drilling is planned for the Shenzi prospect (AHC 28%) on Green Canyon Block 654 in the deepwater Gulf of Mexico. Further appraisal drilling is also planned for the Tubular Bells discovery (AHC 20%) on Mississippi Canyon Block 725, also in the deepwater Gulf of Mexico.

      At December 31, 2003, the Corporation has interests in approximately 290 exploration blocks in the Gulf of Mexico of which it operates 202. The Corporation has 910,000 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 2003, 37% of the Corporation’s crude oil and natural gas liquids production and 46% 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, 2003:

                             
Interest 2003 2002
 Producing Field


Crude Oil, Including Condensate and Natural Gas Liquids (thousands of barrels per day)
                       
 
Beryl/Ness/Nevis/Buckland/Skene
    22.22/22.22/37.35/14.07/9.07%       19       20  
 
Schiehallion
    15.67       16       15  
 
Bittern
    28.28       15       15  
 
Scott/Telford
    20.95/17.42       14       21  
 
Fife/Fergus/Flora/Angus
    85.00/65.00/85.00/85.00       14       19  
 
Ivanhoe/Rob Roy/Hamish
    76.56       5       8  
 
Hudson
    28.00       4       4  
 
Other
    Various       8       16  
             
     
 
   
Total
            95       118  
             
     
 

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Interest 2003 2002
 Producing Field


Natural Gas (thousands of Mcf per day)
                       
 
Easington Catchment Area
    23.84%       84       47  
 
Everest/Lomond
    18.67/16.67       61       59  
 
Beryl/Ness/Nevis/Buckland
    22.22/22.22/37.35/14.07       52       54  
 
Indefatigable/Leman
    23.08/21.74       47       46  
 
Davy/Bessemer
    27.78/23.08       31       27  
 
Scott/Telford
    20.95/17.42       18       20  
 
Other
    Various       19       24  
             
     
 
   
Total
            312       277  
             
     
 
Barrels of Oil Equivalent (thousands of barrels per day)
            147       164  
             
     
 


      Development of the Clair Field (AHC 9.29%) is proceeding and it is expected to begin production in 2005. The Atlantic (AHC 25%) and Cromarty (AHC 90%) natural gas fields are also being developed. These fields are expected to have combined net production of approximately 25,000 barrels of oil equivalent per day in 2006.

      During 2003, 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 25,000 barrels per day in both 2003 and 2002. Natural gas production averaged 26,000 Mcf per day in 2003 and 25,000 Mcf per day in 2002. Substantially all of the Norwegian production is from the Corporation’s 28.09% interest in the Valhall Field. An enhanced-recovery waterflood project for the Valhall Field has commenced with water injection starting in the first quarter of 2004.

      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 24,000 barrels of crude oil per day in 2003 compared to 23,000 barrels of oil per day in 2002. Natural gas production was 29,000 Mcf and 37,000 Mcf of natural gas per day in 2003 and 2002, respectively.

      Equatorial Guinea. The Corporation has interests in production sharing contracts covering three offshore blocks, acquired in August 2001. Net crude oil production from the Corporation’s 85% interest in the Ceiba Field averaged 22,000 barrels of crude oil per day in 2003 and 37,000 barrels per day in 2002. The results of an appraisal drilling program are being incorporated into the development plan for Northern Block G discoveries (AHC 85%). It is anticipated that the development plan will be submitted for government approval in the second quarter of 2004.

      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, bringing the Corporation’s interest to 50%. This production sharing contract has a gas sales agreement for the sale of the first phase of gas production. Construction of the buyer’s pipeline commenced in the second half of 2003. First production from the field is expected in mid-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 19,000 and 15,000 barrels of crude oil per day in 2003 and 2002, respectively. A seismic program is underway and appraisal drilling is planned on a 2003 discovery on an exploration block in Algeria.

      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 11,000 net barrels of crude oil per day in 2003 and 9,000 barrels per day in 2002.

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      Indonesia. Reflecting the sale of the Jabung production sharing contract, net production in Indonesia amounted to 1,000 barrels of crude oil per day in 2003 compared with 4,000 barrels per day in 2002. 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. Consequently, natural gas production in Indonesia increased to 11,000 Mcf per day in 2003 from 6,000 Mcf per day in 2002. A natural gas discovery in the Pangkah production sharing contract area is being developed.

      Thailand. The Corporation has a 15% interest in the Pailin gas field offshore Thailand. Net production from the Corporation’s interest averaged 52,000 Mcf and 35,000 Mcf of natural gas per day in 2003 and 2002, respectively. Additional appraisal drilling is planned in 2004 on an onshore discovery on Phu Horm Block E5N (AHC 35%).

      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 2003 and 4,000 barrels per day in 2002. Development of the Azeri, Chirag and Guneshli fields is continuing.

Refining and Marketing

      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 440,000 barrels per day in 2003 and 361,000 barrels per day in 2002. The fluid catalytic cracking unit at HOVENSA operated at the rates of 142,000 and 116,000 barrels per day in 2003 and 2002, respectively. The coking unit at HOVENSA commenced production in August 2002. The unit operated at the rate of 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 per day of Venezuelan Mesa crude oil to HOVENSA under a long-term crude oil supply contract. The remaining crude oil requirements are purchased mainly under contracts of one year or less from third parties and through spot purchases on the open market. After sales of refined products by HOVENSA to third parties, the Corporation purchases 50% of HOVENSA’s remaining production at market prices.

      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. During 2003, the facility operated at a rate of approximately 54,000 barrels per day and substantially all of its production was 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 1,195 HESS® gasoline stations at December 31, 2003, of which approximately 68% are company operated. 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 concentrated in densely populated areas, principally in New York, New Jersey, Pennsylvania, Florida, Massachusetts and North and South Carolina, and 856 gasoline stations have convenience stores. 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 419,000 barrels per day in 2003 and 383,000 barrels per day in 2002. Of total refined products sold in 2003, approximately 50% was obtained from HOVENSA and Port Reading. The

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Corporation purchased the balance from others under short-term supply contracts and by spot purchases from various sources.

      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.

Competition and Market Conditions

      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 depend on 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.

Other Items

      The Corporation’s operations may be affected by 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. 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 2003 for environmental remediation, with a comparable amount anticipated for 2004. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, were $7 million in 2003 and the Corporation anticipates approximately $10 million in 2004. 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. These rules phase in beginning in 2004. Capital expenditures necessary to comply with the low-sulfur gasoline requirements at Port Reading are estimated to be approximately $70 million over the next several years. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are currently expected to be approximately $450 million over the next three years. HOVENSA expects to finance these capital expenditures through cash flow and, if necessary, future borrowings.

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      The number of persons employed by the Corporation averaged 11,481 in 2003 and 11,662 in 2002.

      Additional operating and financial information relating to the business and properties of the Corporation appears in the text on pages 10 and 11 under the heading “Exploration & Production,” on pages 12 and 13 under the heading “Refining & Marketing,” on pages 15 through 33 under the heading “Financial Review” and on pages 34 through 69 of the accompanying 2003 Annual Report to Stockholders, which information is incorporated herein by reference.*

      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.

Item 2. Properties

      Reference is made to Item 1 and the operating and financial information relating to the business and properties of the Corporation which is incorporated in Item 1 by reference.

      Additional information relating to the Corporation’s oil and gas operations follows:

1. Oil and gas reserves

      The Corporation’s net proved oil and gas reserves at the end of 2003, 2002 and 2001 are presented under Supplementary Oil and Gas Data in the accompanying 2003 Annual Report to Stockholders, which has been incorporated herein by reference.

      During 2003, the Corporation provided oil and gas reserve estimates for 2002 to the Department of Energy. Such estimates are compatible with the information furnished to the SEC on Form 10-K, although not necessarily directly comparable due to the requirements of the individual requests. There were no differences in excess of 5%.

      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 45% of its 2004 sales commitments under long-term contracts which total approximately 355,000 Mcf per day. Natural gas sales commitments for 2005 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.


Except as to information specifically incorporated herein by reference under Items 1, 2, 5, 6, 7, 7A and 8, no other information or data appearing in the 2003 Annual Report to Stockholders is deemed to be filed with the Securities and Exchange Commission (SEC) as part of this Annual Report on Form 10-K, or otherwise subject to the SEC’s regulations or the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

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2. Average selling prices and average production costs

                             
2003 2002 2001

Average selling prices (Note A)
                       
 
Crude oil, including condensate and natural gas liquids (per barrel)
                       
   
United States
  $ 24.13     $ 22.48     $ 22.50  
   
Europe
    24.58       24.84       24.51  
   
Africa, Asia and other
    25.68       23.65       22.87  
 
   
Average
    24.73       24.07       23.77  
 
 
Natural gas (per Mcf)
                       
   
United States
  $ 4.02     $ 3.72     $ 4.02  
   
Europe
    3.00       2.15       2.51  
   
Africa, Asia and other
    3.10       3.15       2.98  
 
   
Average
    3.34       2.88       3.21  

Average production (lifting) costs per barrel of oil equivalent produced (Note B)
                       
   
United States
  $ 5.90     $ 5.19     $ 4.04  
   
Europe
    5.49       4.88       4.31  
   
Africa, Asia and other (Note C)
    7.99       5.28       7.65  
 
   
Average
    6.06       5.04       4.54  

      Note A: Includes inter-company transfers valued at approximate market prices and the effect of the Corporation’s hedging activities.

      Note B: Production (lifting) costs consist of amounts incurred to operate and maintain the Corporation’s producing oil and gas wells, related equipment and facilities (including lease costs of floating production and storage facilities) and production and severance taxes. The average production costs per barrel of oil equivalent reflect the crude oil equivalent of natural gas production converted on the basis of relative energy content (six Mcf equals one barrel).

      Note C: Variations in production costs reflect changes in the mix of the Corporation’s producing fields in Africa and Asia, including fields held under production sharing contracts.

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

3. Gross and net undeveloped acreage at December 31, 2003

           
Undeveloped acreage (Note A)
(in thousands)

Gross Net

United States
  1,405   940
Europe
  3,285   1,276
Africa, Asia and other
  17,138   6,867
   
 
 
Total (Note B)
  21,828   9,083
   
 

      Note A: Includes acreage held under production sharing contracts.

      Note B: Approximately one-half of net undeveloped acreage held at December 31, 2003 will expire during the next three years.

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4. Gross and net developed acreage and productive wells at December 31, 2003

                               
Productive wells (Note A)
Developed acreage
applicable to
productive wells Oil Gas
(in thousands)


Gross Net Gross Net Gross Net







United States
  1,561   421   2,868   678     206     169
Europe
  734   204   301   72     173     36
Africa, Asia and other
  2,430   684   177   45     202     31
   
 
 
 
   
   
 
Total
  4,725   1,309   3,346   795     581     236
   
 
 
 
   
   

      Note A: Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 99 gross wells and 30 net wells.

5. Number of net exploratory and development wells drilled

                                                     
Net exploratory wells Net development wells


2003 2002 2001 2003 2002 2001






Productive wells
                                               
 
United States
    2       11       7       19       26       46  
 
Europe
          2       3       7       5       6  
 
Africa, Asia and other
    3       8       4       12       25       15  
     
     
     
     
     
     
 
   
Total
    5       21       14       38       56       67  
     
     
     
     
     
     
 
Dry holes
                                               
 
United States
    3       3       7       1       4       2  
 
Europe
    2       1       2       1              
 
Africa, Asia and other
    4       7       4       2       1        
     
     
     
     
     
     
 
   
Total
    9       11       13       4       5       2  
     
     
     
     
     
     
 
Total
    14       32       27       42       61       69  
     
     
     
     
     
     
 

6. Number of wells in process of drilling at December 31, 2003

                   
Gross Net
wells wells

United States
    3       2  
Europe
    6       2  
Africa, Asia and other
    6       3  
     
     
 
 
Total
    15       7  
     
     
 

 
7.  Number of waterfloods and pressure maintenance projects in process of installation at December 31, 2003 — 3 


 
Item 3. Legal Proceedings

      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 addition, derivative actions seeking damages on behalf of the Registrant and consolidated under a complaint captioned In re Amerada Hess Derivative Action are pending in the Superior Court of the State of New Jersey against certain executive officers and former executive officers of the Registrant, some of whom are also directors, alleging, among other things, that the

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officers breached their fiduciary duties by misusing material non-public information of the Registrant to personally profit from the sale of the Registrant’s common stock in connection with the Triton acquisition. 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’s savings and stock bonus plan, alleging that the defendants breached their fiduciary duties under the Employee Retirement Income Security Act, resulting in losses to participants in the plan who held shares of the Registrant’s common stock. The Registrant believes that these actions are without merit and is advancing expenses to these individuals in accordance with its By-Laws to defend these actions. Based on current legal and factual circumstances, Registrant does not believe these actions will have a material adverse effect on its financial condition.

      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 undertaken efforts to address certain conditions discussed in the complaint. Registrant intends to vigorously contest the complaint, but is involved in settlement discussions with DEC.

      Over the last five 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 which 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 (CEMS). 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 which proposes a fine of $649,600. The Corporation is engaging in settlement discussions with NJDEP to resolve this matter, particularly as regards to a reduction in the penalty to reflect the voluntary self disclosure of 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, have been recently filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produce gasoline containing MTBE, including Registrant. 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

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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 which 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, but has not named Registrant. 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.

      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.

Item 4. Submission of Matters to a Vote of Security Holders

      During the fourth quarter of 2003, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise.

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Executive Officers of the Registrant

      The following table presents information as of February 1, 2004 regarding executive officers of the Registrant:

                     
Year
individual
became an
Name Age Office Held* executive officer

John B. Hess
    49    
Chairman of the Board, Chief Executive Officer and Director
    1983  
J. Barclay Collins II
    59    
Executive Vice President, General Counsel and Director
    1986  
John J. O’Connor
    57    
Executive Vice President, President of Worldwide Exploration and Production and Director
    2001  
John Y. Schreyer
    64    
Executive Vice President, Chief Financial Officer and Director
    1990  
F. Borden Walker
    50    
Executive Vice President and President of Refining and Marketing
    1996  
E. Clyde Crouch
    55    
Senior Vice President
    2003  
John A. Gartman
    56    
Senior Vice President
    1997  
Neal Gelfand
    59    
Senior Vice President
    1980  
Gerald A. Jamin
    62    
Senior Vice President and Treasurer
    1985  
Lawrence H. Ornstein
    52    
Senior Vice President
    1995  
Howard Paver
    53    
Senior Vice President
    2002  
John P. Rielly
    41    
Vice President and Controller
    2002  
George F. Sandison
    47    
Senior Vice President
    2003  
Robert P. Strode
    47    
Senior Vice President
    2000  

All officers referred to herein hold office in accordance with the By-Laws until the first meeting of the Directors following the annual meeting of stockholders of the Registrant and until their successors shall have been duly chosen and qualified. Each of said officers was elected to the office set forth opposite his name on May 7, 2003. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 5, 2004.

      Except for Messrs. O’Connor, Paver, Rielly, Sandison 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. Paver had served in a senior executive position at BHP Petroleum prior to his employment with a subsidiary of Registrant in October 2002. Mr. Rielly had been a partner of Ernst & Young LLP prior to his employment with the Registrant in April 2001. Mr. Sandison served in senior executive positions in the area of global drilling with Texaco, Inc. prior to his employment with a subsidiary of Registrant in 2002. 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.

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PART II

 
Item  5.    Market for the Registrant’s Common Stock and Related Stockholder Matters

      Information pertaining to the market for the Registrant’s Common Stock, high and low sales prices of the Common Stock in 2003 and 2002, dividend payments and restrictions thereon and the number of holders of Common Stock is presented on page 32 (Financial Review), page 47 (Long-Term Debt) and on page 66 (Ten-Year Summary of Financial Data) of the accompanying 2003 Annual Report to Stockholders, which information is incorporated herein by reference.

 
Item 6.  Selected Financial Data

      A Ten-Year Summary of Financial Data is presented on pages 64 through 67 of the accompanying 2003 Annual Report to Stockholders, which summary is incorporated herein by reference.

 
Item  7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

      The information required by this item is presented on pages 15 through 33 of the accompanying 2003 Annual Report to Stockholders, which information is incorporated herein by reference.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

      The information required by this item is presented under “Market Risk Disclosure” on pages 25 through 28 and in Note 17 on pages 53 through 55 of the accompanying 2003 Annual Report to Stockholders, which information is incorporated herein by reference.

 
Item 8.  Financial Statements and Supplementary Data

      The consolidated financial statements, including the Report of Ernst & Young LLP, Independent Auditors, the Supplementary Oil and Gas Data (unaudited) and the Quarterly Financial Data (unaudited) are presented on pages 33 through 63 of the accompanying 2003 Annual Report to Stockholders, which financial statements, Report and Data are incorporated herein by reference.

 
Item  9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

      None.

 
Item  9A.  Controls and Procedures

      Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2003, John B. Hess, Chief Executive Officer, and John Y. Schreyer, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of December 31, 2003.

      There have been no significant changes in the Corporation’s internal controls or in other factors that could significantly affect internal controls after December 31, 2003.


 
PART III
 
Item 10.  Directors and Executive Officers of the Registrant

      Information relating to Directors is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2004.

      Information regarding executive officers is included in Part I hereof.

 
Item 11.  Executive Compensation

      Information relating to executive compensation is incorporated herein by reference to “Election of Directors–Executive Compensation and Other Information,” other than information under “Compensation Committee Report on Executive Compensation” and “Performance Graph” included therein, from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2004.

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Item  12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

      Information pertaining to security ownership of certain beneficial owners and management is incorporated herein by reference to “Election of Directors–Ownership of Voting Securities by Certain Beneficial Owners” and “Election of Directors–Ownership of Equity Securities by Management” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2004.

      Following is information on the Registrant’s equity compensation plans at December 31, 2003:

                         
Number of
securities
remaining
Number of available for
securities to be Weighted future issuance
issued upon average under equity
exercise of exercise price compensation
outstanding of outstanding plans (excluding
options, options, securities
warrants and warrants and reflected in
rights rights column (a))
Plan category (a) (b) (c)




Equity compensation plans approved by security holders
    4,160,900     $ 58.54       479,000*  
Equity compensation plans not approved by security holders**
                 

*   These securities may be awarded as stock options, restricted stock or other awards permitted under the Registrant’s equity compensation plan.
 
**  Registrant has a Stock Award Program adopted in 1997 pursuant to which each non-employee director receives 500 shares of Registrant’s common stock each year. These awards are made from treasury shares purchased by the Company in the open market. This equity compensation plan was not approved by stockholders.
 
Item 13.  Certain Relationships and Related Transactions

      Information relating to this item is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2004.

 
Item 14.  Principal Accounting Fees and Services

      Information relating to this item is incorporated by reference to “Ratification of Selection of Independent Auditors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 5, 2004.

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PART IV

 
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

      (a) 1. and 2. Financial statements and financial statement schedules

        The financial statements filed as part of this Annual Report on Form 10-K are listed in the accompanying index to financial statements and schedules.

               3. Exhibits

             
       3 (1)  
 –Restated Certificate of Incorporation of Registrant incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1988.
       3 (2)  
 –By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002.
       4 (1)  
 –Certificate of designations, preferences and rights of 3% cumulative convertible preferred stock of Registrant incorporated by reference to Exhibit 4 of Form 10-Q of Registrant for the three months ended June 30, 2000.
       4 (2)  
 –Certificate of designation, preferences and relative, optional and other special rights and qualifications, limitations and restrictions of 7% mandatory convertible preferred stock of Registrant, incorporated by reference to Exhibit 3 of Form 8-K of Registrant dated November 19, 2003.
       4 (3)  
 –Third Amended and Restated Credit Agreement (“Facility B”) dated as of January 23, 2001 among Amerada Hess Corporation, the lenders party thereto and JP Morgan Chase Bank (formerly, The Chase Manhattan Bank, N.A.), as Administrative Agent, incorporated by reference to Exhibit 4(2) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
       4 (4)  
 –Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.
       4 (5)  
 –First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 7 3/8% Notes due 2009 and 7 7/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.
       4 (6)  
 –Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.
       4 (7)  
 –Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002.
           
 –Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
      10 (1)  
 –Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981.

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               3. Exhibits (continued)
             
      10 (2)  
 –Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990.
      10 (3)  
 –Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993.
      10 (4)  
 –Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998.
      10 (5)*  
 –Incentive Compensation Award Plan for Key Employees of Amerada Hess Corporation and its subsidiaries incorporated by reference to Exhibit 10(2) of Form 10-K of Registrant for the fiscal year ended December 31, 1980.
      10 (6)*  
 –Financial Counseling Program description incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1980.
      10 (7)*  
 –Amerada Hess Corporation Savings and Stock Bonus Plan, incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
      10 (8)*  
 –Amerada Hess Corporation Savings and Stock Bonus Plan for Retail Operations Employees, incorporated by reference to Exhibit 10(8) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
      10 (9)*  
 –Amerada Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
      10 (10)*  
 –Letter Agreement dated August 8, 1990 between Registrant and Mr. John Y. Schreyer relating to Mr. Schreyer’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for the fiscal year ended December 31, 1991.
      10 (11)*  
 –Amended and Restated 1995 Long-Term Incentive Plan incorporated by reference to Form 10-Q of Registrant for the three months ended June 30, 2000. On May 2, 2001, the Board of Directors approved an increase in the shares to be awarded to non-employee directors from 200 to 500 shares per year. All other provisions of the program remain in effect.
      10 (12)*  
 –Stock Award Program for non-employee directors dated August 6, 1997 incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for the fiscal year ended December 31, 1997.
      10 (13)*  
 –Amendment to Stock Award Program for Non-Employee Directors dated August 6, 1997.
      10 (14)*  
 –Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and J. Barclay Collins, John J. O’Connor, John Y. Schreyer and F. Borden Walker.

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               3. Exhibits (continued)
             
      10 (15)*  
 –Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (other than the named executive officers referred to in Exhibit 10(13)).
      10 (16)*  
 –Letter Agreement dated March 18, 2002 between Registrant and John J. O’Connor relating to Mr. O’Connor’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(15) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
      10 (17)*  
 –Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
      10 (18)*  
 –Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
      10 (19)*  
 –Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Amerada Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
      10 (20)  
 –Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998.
      10 (21)  
 –Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998.
      13    
 –2003 Annual Report to Stockholders of Registrant.
      21    
 –Subsidiaries of Registrant.
      23    
 –Consent of Ernst & Young LLP, Independent Auditors, dated March 11, 2004, to the incorporation by reference in Registrant’s Registration Statements (Form S-8, Nos. 333-94851, 333-43569 and 333-43571, and Form S-3, No. 333-110294), of its report relating to Registrant’s financial statements, which consent appears on page F-2 herein.
      31 (1)  
 –Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
      31 (2)  
 –Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
      32 (1)  
 –Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
      32 (2)  
 –Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).

* These exhibits relate to executive compensation plans and arrangements.

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          (b) Reports on Form 8-K

      During the three months ended December 31, 2003, Registrant filed or furnished the following reports on Form 8-K: i) report on October 29, 2003 furnishing under Item 7 a news release dated October 29, 2003 reporting results for the third quarter of 2003 and under Items 7 and 9 the prepared remarks of John B. Hess, Chairman of the Board of Directors and Chief Executive Officer of the Corporation, in a public conference call; ii) a filing on November 6, 2003 updating certain financial information reported in the Corporation’s 2002 Form 10-K to conform with the presentation used in 2003 for an asset exchange and certain asset sales that were accounted for as discontinued operations; and iii) a filing on November 19, 2003 reporting under Items 5 and 7 the terms of mandatory convertible preferred stock.

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SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 11th day of March 2004.

  AMERADA HESS CORPORATION
              (Registrant)

  By        /s/ JOHN Y. SCHREYER       
 
  (John Y. Schreyer)
  Executive Vice President and
  Chief Financial Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

         
Signature Title Date

 /s/ JOHN B. HESS  

(John B. Hess)
  Director, Chairman of
the Board and
Chief Executive Officer
(Principal Executive Officer)
  March 11, 2004
 
 /s/ NICHOLAS F. BRADY  

(Nicholas F. Brady)
  Director   March 11, 2004
 
/s/ J. BARCLAY COLLINS II

(J. Barclay Collins II)
  Director   March 11, 2004
 
 /s/ EDITH E. HOLIDAY  

(Edith E. Holiday)
  Director   March 11, 2004
 
 /s/ THOMAS H. KEAN

(Thomas H. Kean)
  Director   March 11, 2004
 
 /s/ CRAIG G. MATTHEWS  

(Craig G. Matthews)
  Director   March 11, 2004
 
 /s/ JOHN J. O’CONNOR  

(John J. O’Connor)
  Director   March 11, 2004
 
 /s/ FRANK A. OLSON  

(Frank A. Olson)
  Director   March 11, 2004
 
/s/ JOHN P. RIELLY

(John P. Rielly)
  Vice President and Controller
(Principal Accounting Officer)
  March 11, 2004
 
/s/ JOHN Y. SCHREYER

(John Y. Schreyer)
  Director, Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
  March 11, 2004
 
 /s/ ERNST H. VON METZSCH  

(Ernst H. von Metzsch)
  Director   March 11, 2004
 
/s/ ROBERT N. WILSON

(Robert N. Wilson)
  Director   March 11, 2004

19


Table of Contents

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

 
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
     
Page
number

Statement of Consolidated Income for each of the three years in the period ended December 31, 2003
  *
Statement of Consolidated Retained Earnings for each of the three years in the period ended December 31, 2003
  *
Consolidated Balance Sheet at December 31, 2003 and 2002
  *
Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2003
  *
Statement of Consolidated Changes in Preferred Stock, Common Stock and Capital in Excess of Par Value for each of the three years in the period ended December 31, 2003
  *
Statement of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2003
  *
Notes to Consolidated Financial Statements
  *
Report of Ernst & Young LLP, Independent Auditors
  *
Quarterly Financial Data
  *
Supplementary Oil and Gas Data
  *
Consent of Independent Auditors
  F-2
Schedules**
II — Valuation and Qualifying Accounts
  F-3
HOVENSA L.L.C. Financial Statements as of December 31, 2003
  H-1

  *  The financial statements and notes thereto together with the Report of Ernst & Young LLP, Independent Auditors, on pages 34 through 58, the Quarterly Financial Data (unaudited) on page 33, and the Supplementary Oil and Gas Data (unaudited) on pages 59 through 63 of the accompanying 2003 Annual Report to Stockholders are incorporated herein by reference.

**  Schedules other than Schedule II have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto.

F-1


Table of Contents

CONSENT OF INDEPENDENT AUDITORS

      We consent to the incorporation by reference in this Annual Report (Form 10-K) of Amerada Hess Corporation of our report dated February 20, 2004, included in the 2003 Annual Report to Stockholders of Amerada Hess Corporation.

      Our audits also included the financial statement schedule of Amerada Hess Corporation listed in Item 15(a). This schedule is the responsibility of the Corporation’s management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

      We also consent to the incorporation by reference in Registration Statements (Form S-8, Nos. 333-94851, 333-43569 and 333-43571, and Form S-3, No. 333-110294) pertaining to the Amerada Hess Corporation Employees’ Savings and Stock Bonus Plan, Amerada Hess Corporation Savings and Stock Bonus Plan for Retail Operations Employees, Amended and Restated 1995 Long-Term Incentive Plan and the Amerada Hess Corporation Registration Statement of our report dated February 20, 2004, with respect to the consolidated financial statements of Amerada Hess Corporation incorporated by reference in the Annual Report (Form 10-K), and the financial statement schedule included in the Annual Report (Form 10-K), for the year ended December 31, 2003, and our report dated January 27, 2004 with respect to the financial statements of HOVENSA L.L.C. included in the Amerada Hess Corporation Annual Report (Form 10-K) for the year ended December 31, 2003.

  Ernst & Young Signature

New York, NY

March 11, 2004

F-2


Table of Contents

Schedule II

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2003, 2002 and 2001

(in millions)

                                           
Additions

Charged
to costs Charged Deductions
Balance and to other from Balance
Description January 1 expenses accounts reserves December 31

2003
                                       
 
Losses on receivables
  $ 13     $ 7     $     $ 2     $ 18  
     
     
     
     
     
 
 
Deferred income tax valuation
  $ 95     $     $     $ 2     $ 93  
     
     
     
     
     
 
 
Major maintenance
  $ 20     $ 11     $     $ 8     $ 23  
     
     
     
     
     
 
2002
                                       
 
Losses on receivables
  $ 15     $ 7     $ 4     $ 13     $ 13  
     
     
     
     
     
 
 
Deferred income tax valuation
  $ 93     $ 2     $     $     $ 95  
     
     
     
     
     
 
 
Major maintenance
  $ 19     $ 19     $     $ 18     $ 20  
     
     
     
     
     
 
2001
                                       
 
Losses on receivables
  $ 34     $ 10     $ 3     $ 32 (A)   $ 15  
     
     
     
     
     
 
 
Deferred income tax valuation
  $ 111     $     $     $ 18     $ 93  
     
     
     
     
     
 
 
Major maintenance
  $ 19     $ 16     $     $ 16     $ 19  
     
     
     
     
     
 

(A)  Reflects write-off of uncollectible accounts.

F-3


Table of Contents

EXHIBIT INDEX

         
Exhibit
Number Description


3(1)
 
 –Restated Certificate of Incorporation of Registrant incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1988.
   
3(2)
 
 –By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002.
   
4(1)
 
 –Certificate of designations, preferences and rights of 3% cumulative convertible preferred stock of Registrant incorporated by reference to Exhibit 4 of Form 10-Q of Registrant for the three months ended June 30, 2000.
   
4(2)
 
 –Certificate of designation, preferences and relative, optional and other special rights and qualifications, limitations and restrictions of 7% mandatory convertible preferred stock of Registrant, incorporated by reference to Exhibit 3 of Form 8-K of Registrant dated November 19, 2003.
   
4(3)
 
 –Third Amended and Restated Credit Agreement (“Facility B”) dated as of January 23, 2001 among Amerada Hess Corporation, the lenders party thereto and JP Morgan Chase Bank (formerly, The Chase Manhattan Bank, N.A.), as Administrative Agent, incorporated by reference to Exhibit 4(2) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
   
4(4)
 
 –Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.
   
4(5)
 
 –First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 7 3/8% Notes due 2009 and 7 7/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.
   
4(6)
 
 –Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.
   
4(7)
 
 –Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002.
   
   
 –Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
   
10(1)
 
 –Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981.
   


Table of Contents

         
Exhibit
Number Description


10(2)
 
 –Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990.
   
10(3)
 
 –Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993.
   
10(4)
 
 –Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998.
   
10(5)*
 
 –Incentive Compensation Award Plan for Key Employees of Amerada Hess Corporation and its subsidiaries incorporated by reference to Exhibit 10(2) of Form 10-K of Registrant for the fiscal year ended December 31, 1980.
   
10(6)*
 
 –Financial Counseling Program description incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1980.
   
10(7)*
 
 –Amerada Hess Corporation Savings and Stock Bonus Plan, incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
   
10(8)*
 
 –Amerada Hess Corporation Savings and Stock Bonus Plan for Retail Operations Employees, incorporated by reference to Exhibit 10(8) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
   
10(9)*
 
 –Amerada Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
   
10(10)*
 
 –Letter Agreement dated August 8, 1990 between Registrant and Mr. John Y. Schreyer relating to Mr. Schreyer’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for the fiscal year ended December 31, 1991.
   
10(11)*
 
 –Amended and Restated 1995 Long-Term Incentive Plan incorporated by reference to Form 10-Q of Registrant for the three months ended June 30, 2000. On May 2, 2001, the Board of Directors approved an increase in the shares to be awarded to non-employee directors from 200 to 500 shares per year. All other provisions of the program remain in effect.
   
10(12)*
 
 –Stock Award Program for non-employee directors dated August 6, 1997 incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for the fiscal year ended December 31, 1997.
   
10(13)*
 
 –Amendment to Stock Award Program for Non-Employee Directors dated August 6, 1997.
   


Table of Contents

         
Exhibit
Number Description


10(14)*
 
 –Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and J. Barclay Collins, John J. O’Connor, John Y. Schreyer and F. Borden Walker.
   
10(15)*
 
 –Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (other than the named executive officers referred to in Exhibit 10(13)).
   
10(16)*
 
 –Letter Agreement dated March 18, 2002 between Registrant and John J. O’Connor relating to Mr. O’Connor’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(15) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
   
10(17)*
 
 –Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
   
10(18)*
 
 –Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
   
10(19)*
 
 –Letter Agreement dated May 17, 2001 between Registrant and J.P. Rielly relating to Mr. Rielly’s participation in the Amerada Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
   
10(20)
 
 –Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998.
   
10(21)
 
 –Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998.
   
13
 
 –2003 Annual Report to Stockholders of Registrant.
   
21
 
 –Subsidiaries of Registrant.
   
23
 
 –Consent of Ernst & Young LLP, Independent Auditors, dated March 11, 2004, to the incorporation by reference in Registrant’s Registration Statements (Form S-8, Nos. 333-94851, 333-43569 and 333-43571, and Form S-3, No. 333-110294), of its report relating to Registrant’s financial statements, which consent appears on page F-2 herein.
   


Table of Contents

         
Exhibit
Number Description


31(1)
 
 –Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
   
31(2)
 
 –Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
   
32(1)
 
 –Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
   
32(2)
 
 –Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
   

These exhibits relate to executive compensation plans and arrangements.

EXHIBIT 10(13) Amendment To Stock Award Program for Non-Employee Directors August 6, 1997 On May 2, 2001, the Board of Directors approved an increase in the shares to be awarded to non-employee directors from 200 to 500 shares per year. All other provisions of the program remain in effect.

2003 ANNUAL REPORT TO STOCKHOLDERS
 

Our Exploration and Production efforts are focused on creating value for shareholders by advancing our current development projects, appraising our recent discoveries and growing our proved reserve base.

EXPLORATION & PRODUCTION

PRODUCTION

In 2003, Amerada Hess produced 373,000 barrels of oil equivalent per day. Production is expected to average 325,000 barrels of oil equivalent per day in 2004, reflecting asset sales and swaps transacted in 2003.

In the Garden Banks area of the deepwater Gulf of Mexico, total production exceeded 33,000 barrels of oil equivalent per day in 2003. Conger (AHC 37.5%) and Baldpate (AHC 50%) are key operated assets in the area.

Onshore, Amerada Hess is the leading oil producer in North Dakota. Through a combination of horizontal and infill drilling and stimulation technology, production levels have been maintained at approximately 22,000 barrels of oil equivalent per day, for the last five years.

In the Seminole San Andres unit in West Texas, Amerada Hess is an industry leader in using carbon dioxide injection technology to increase oil recovery. The carbon dioxide tertiary recovery project that commenced in 1983 is one of the most successful recovery projects in the region.

In the North Sea, Amerada Hess has a large production base including the Valhall Field (AHC 28.09%) in Norway, the South Arne Field (AHC 57.48%) in Denmark, and the Beryl (AHC 22.22%) and the Schiehallion (AHC 15.67%) fields in the United Kingdom. In 2003, 55% of global oil and gas production was from the North Sea.

The Ceiba Field (AHC 85%), located in Block G in Equatorial Guinea, is responding favorably to water injection and is expected to produce approximately 25,000 net barrels per day in 2004 compared to 22,000 barrels per day in 2003.

DEVELOPMENT

Amerada Hess is developing 12 new oil and gas fields with new production starting over the next three years. These developments are expected to add more than 100,000 barrels of oil equivalent production per day by 2006.

First production from the Llano Field (AHC 50%) on Garden Banks Blocks 385 and 386 in the Gulf of Mexico is scheduled for mid-2004, with initial net production expected to reach12,000 barrels of oil equivalent per day by year end.

In Block A-18 (AHC 50%) of the Joint Development Area between Malaysia and Thailand, final approval of the buyer’s pipeline and gas plant was secured and construction commenced in the second half of 2003. First production from the field is expected during the second half of 2005.

In Algeria, net production from the Gassi El Agreb redevelopment project operated by SonaHess, a joint operating company between Amerada Hess and Sonatrach, was approximately 20,000 barrels per day in 2003, an increase of more than 30% from 2002.

10


 

(PHOTO)

In the United Kingdom, first production from the Clair Field (AHC 9.29%) is expected in 2005 and from the Atlantic (AHC 25%) and Cromarty (AHC 90%) gas fields in 2006. Combined net production from these three fields is expected to exceed 25,000 barrels of oil equivalent per day in 2006.

In the Norwegian North Sea, enhanced recovery from the Valhall field (AHC 28.09%) has begun with flank development wells coming onstream in 2003 and water injection commencing in the first quarter of 2004. The Snohvit project (AHC 3.26%), in the Barents Sea offshore Norway, will be Europe’s first LNG export facility when gas production and liquefaction begin by 2006.

In Equatorial Guinea, the results of an extended appraisal drilling program are being incorporated into the development plan for the Northern Block G discoveries (AHC 85%). It is anticipated that the development plan will be submitted for government approval in the second quarter of 2004.

Development of the giant Azeri, Chirag and Guneshli fields (AHC 2.72%), in Azerbaijan, is on schedule. Net production is currently 2,000 barrels of oil equivalent per day, and is expected to increase to over 25,000 barrels per day by 2009.

EXPLORATION

Exploration is a key component of future growth. Amerada Hess has a strong position in the deep-water Gulf of Mexico, with leasehold interests in 291 blocks and over 4,000 blocks of 3D seismic coverage. In 2003, two key discoveries were made in this area:

  Successful appraisal drilling was conducted at the 2002 Shenzi discovery (AHC 28%), on Green Canyon Block 654. The Shenzi-2 well, located in 4,238 feet of water, encountered about 500 feet of net pay. Further appraisal drilling is planned in 2004.
 
  The Tubular Bells discovery well (AHC 20%) in Mississippi Canyon Block 725, located in 4,300 feet of water, was drilled to a depth of 31,131 feet. The well encountered 190 feet of net oil pay. Further appraisal drilling is planned in late 2004.

In northeastern Thailand, a successful appraisal well was drilled on Phu Horm Block E5N (AHC 35%). A flow test was completed with a stabilized gas rate of 31.5 million cubic feet per day. Additional appraisal drilling is planned in 2004.

Amerada Hess made a new discovery on Block 401c (AHC 60%), in Algeria. An extensive seismic program is underway, with more drilling scheduled for the second half of 2004.

11


 

Refining and marketing continues to be an important profit and cash generator for the Corporation, with growth opportunities in both retail and energy marketing. In 2003, refining and marketing achieved its best financial performance in 10 years.

REFINING & MARKETING

REFINING

The HOVENSA refinery in the United States Virgin Islands is jointly owned by the Corporation and Petroleos de Venezuela (PDVSA). It is one of the largest refineries in the world. The facility is strategically located in the Caribbean, allowing for short crude supply lines from Venezuela, as well as easy access to U.S. Gulf and East Coast product markets.

In 2003, the refinery successfully completed the first year of operation of a 58,000 barrel per day coking unit. Gross crude runs at the refinery averaged 440,000 barrels per day for 2003, which, combined with improved refining margins, resulted in a significant improvement in financial performance versus 2002.

The Corporation’s fluid catalytic cracking unit in Port Reading, New Jersey produces high-quality, clean-burning gasoline for northeast markets.

The facility averaged feedstock runs of 54,000 barrels per day and realized a significant improvement in gasoline margins over 2002.

Both refining facilities continue to produce gasoline with specifications that result in emissions well below the U.S. national average.

MARKETING

Retail

The HESS retail network has become the leading independent gasoline convenience store marketer on the East Coast. In 2003, four new locations were built, while 10 existing sites were upgraded with the addition of HESS EXPRESS convenience stores. HESS EXPRESS stores generally feature several fast food offerings and proprietary coffee/fountain programs and are major destinations for take-home bulk beverages. HESS EXPRESS gasoline volumes and convenience store sales are significantly higher than industry averages.

12


 

(PHOTO)

In early 2004, WilcoHess, LLC, the joint venture between Amerada Hess and A.T. Williams Oil Company, completed the acquisition of 50 retail facilities from Service Distributing Company, significantly strengthening our brand position in the growing North Carolina market. With that purchase, the total number of Hess branded retail facilities increased to approximately 1,250.

Energy Marketing

In energy marketing, the Corporation is a major supplier of natural gas, fuel oil and electricity, with more than 24,000 commercial and industrial customer locations primarily on the East Coast. Cold weather in the first quarter of 2003 resulted in strong margins and demand for fuel oil and natural gas, significantly improving financial results over 2002.

Supply & Terminals

The Corporation operates a network of twenty-two strategically located petroleum terminals on the East Coast of the United States. In addition to supply from our refining assets, a well-balanced combination of term and spot supply contracts provides the flexibility to manage product inventories effectively across the network. In 2003, the Corporation was able to leverage our network to provide customers superior reliability of supply during the unusually cold winter weather.

13


 

FINANCIAL REVIEW
Amerada Hess Corporation and Consolidated Subsidiaries

Management’s Discussion and Analysis of Results of Operations and Financial Condition

Executive Overview

The Corporation is a global integrated energy company that operates in two segments, exploration and production (E&P) and refining and marketing (R&M). The E&P segment explores for, produces and sells crude oil and natural gas. The R&M segment manufactures, trades and markets refined petroleum and other energy products.

The Corporation’s long-term goal for the E&P segment is to generate profitable and sustainable growth by transitioning the asset portfolio to longer life, lower cost fields, bringing new field developments onstream and pursuing a focused, high impact exploration program. During the past three years the Corporation has reshaped its E&P asset portfolio by:

  Acquiring exploration, development and production assets in West Africa and Southeast Asia.

  Selling higher cost properties predominantly in the shallow water Gulf of Mexico and the North Sea.

  Exchanging interests in mature producing assets for increased interests in development stage assets in the joint development area of Malaysia and Thailand and deepwater Gulf of Mexico.

The asset sales and exchanges have reduced near-term production which increased unit operating costs. Production declined from 451,000 barrels of oil equivalent per day in 2002 to 373,000 barrels of oil equivalent per day in 2003. Over 60% of the reduction resulted from the absence of production from assets sold or exchanged. The remainder of the decrease was due to natural declines and poorer than expected performance of certain fields in the United States and Equatorial Guinea. Production is expected to decline in 2004 by approximately 13% due to the 2003 asset sales and swaps and natural declines in our remaining fields.

The Corporation is currently funding twelve development projects that are expected to provide over 100,000 barrels of oil equivalent per day of new production in 2006, offsetting natural declines in existing fields and providing net overall production growth. In addition, since 2002, the Corporation has participated in two deepwater Gulf of Mexico discoveries that may provide additional production beyond 2006. As a result of the development projects, the Corporation presently estimates that production will be slightly higher in 2005 than in 2004 and production will increase further in 2006. While the Corporation expects these developments to be completed as currently scheduled, development projects may be subject to unforeseen events, such as technical complexities, delays in governmental sanction and political instability.

The lower production in 2004 is not expected to result in higher 2004 unit operating costs due to cost reduction initiatives begun in 2003 and the portfolio rationalization. The Corporation believes these factors, plus increasing production from new developments, will reduce unit costs in the future.

The portfolio reshaping has reduced near-term cash flows from operations. In response, the Corporation has hedged approximately 70% and 45% of its 2004 and 2005 worldwide crude oil production to provide secure cash flow to fund the development projects. Upon completion of the projects, the Corporation expects the percentage of hedged volumes to decrease.

The R&M segment’s financial results improved significantly in 2003, principally reflecting higher margins and increased sales volumes. The Corporation’s strategic goals for R&M are to maximize financial returns from existing assets and to generate free cash flow. The Corporation may opportunistically add retail marketing sites in its East Coast marketing area.

The Corporation’s liquidity and financial position were significantly improved in 2003. At December 31, 2002, the Corporation’s debt was $5 billion and its debt to capitalization ratio was 54%. During 2003, the Corporation generated cash flow of $545 million from asset sales and $653 million from the issuance of mandatory convertible preferred stock. These actions, combined with additional free cash flow from profitable operations after funding capital expenditures, resulted in debt reduction of $1.1 billion. Year-end debt was $3.9 billion and the debt to capitalization ratio improved to 42.5%. The Corporation has $221 million of debt maturities over the next three years, and had $518 million of cash on hand at December 31, 2003.

15


 

Consolidated Results of Operations

     Income from continuing operations was $467 million in 2003 compared with a loss of $245 million, including impairments, in 2002 and income of $816 million in 2001. Including income from discontinued operations, net income for 2003 was $643 million, compared with a net loss of $218 million in 2002 and net income of $914 million in 2001.

     The after-tax results by major operating activity for 2003, 2002 and 2001 are summarized below:

                         
Millions of dollars, except per share data
  2003
  2002
  2001
Exploration and production
  $ 414     $ (102 )   $ 796  
Refining and marketing
    327       85       233  
Corporate
    (101 )     (63 )     (78 )
Interest expense
    (173 )     (165 )     (135 )
 
   
 
     
 
     
 
 
Income (loss) from continuing operations
    467       (245 )     816  
Discontinued operations
                       
Net gains from asset sales
    116              
Income from operations
    53       27       98  
Income from cumulative effect of accounting change
    7              
 
   
 
     
 
     
 
 
Net income (loss)
  $ 643     $ (218 )   $ 914  
 
   
 
     
 
     
 
 
Income (loss) per share from continuing operations — diluted
  $ 5.17     $ (2.78 )   $ 9.15  
 
   
 
     
 
     
 
 
Net income (loss) per share — diluted
  $ 7.11     $ (2.48 )   $ 10.25  
 
   
 
     
 
     
 
 

In the discussion which 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 2003, 2002 and 2001:

                         
Millions of dollars
  2003
  2002
  2001
Premiums on bond repurchases
  $ (34 )   $ (6 )   $  
Accrued severance and London office lease costs
    (32 )           (10 )
United States income tax benefit
    30              
Net gains from asset sales
    11       100        
Asset impairments
          (737 )      
Charge for increase in United Kingdom income tax rate
          (43 )      
Reduction in carrying value of refining and marketing intangible assets and severance
          (22 )     (2 )
Charge related to Enron bankruptcy
                (19 )
 
   
 
     
 
     
 
 
 
  $ (25 )   $ (708 )   $ (31 )
 
   
 
     
 
     
 
 

The items in the table above are explained on pages 18, 19 and 20. The pre-tax amounts are shown on pages 18 and 20.

Comparison of Results

Exploration and Production: After considering the exploration and production items in the preceding table (described on page 18), 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 $170 million in 2003 compared with 2002. In 2002, the change in average selling prices did not significantly affect revenues compared with 2001. The Corporation’s average selling prices from continuing operations, including the effects of hedging, were as follows:

                         
    2003
  2002
  2001
Crude oil (per barrel)
                       
United States
  $ 24.23     $ 24.04     $ 23.38  
Foreign
    24.93       24.69       24.50  
Natural gas liquids (per barrel)
                       
United States
    23.74       16.12       18.76  
Foreign
    24.09       19.09       18.99  
Natural gas (per Mcf)
                       
United States
    4.02       3.72       4.02  
Foreign
    3.01       2.26       2.55  

16


 

     Production volumes: Lower crude oil and natural gas production volumes reduced exploration and production revenues from continuing operations in 2003 compared with 2002 by $425 million. In 2002, crude oil production was higher than in 2001 and natural gas production was lower. The net effect of these volume changes was an increase in revenues of $100 million. The Corporation’s net daily worldwide production was as follows:

                         
    2003
  2002
  2001
Crude oil
                       
(thousands of barrels per day)
                       
United States
    44       54       63  
Foreign
    195       250       212  
 
   
 
     
 
     
 
 
Total
    239       304       275  
 
   
 
     
 
     
 
 
Natural gas liquids
                       
(thousands of barrels per day)
                       
United States
    11       12       14  
Foreign
    9       9       9  
 
   
 
     
 
     
 
 
Total
    20       21       23  
 
   
 
     
 
     
 
 
Natural gas
                       
(thousands of Mcf per day)
                       
United States
    253       373       424  
Foreign
    430       381       388  
 
   
 
     
 
     
 
 
Total
    683       754       812  
 
   
 
     
 
     
 
 
Barrels of oil equivalent*
                       
(thousands of barrels per day)
    373       451       433  
 
   
 
     
 
     
 
 
Barrel of oil equivalent production related to discontinued operations
    13       51       45  
 
   
 
     
 
     
 
 

*   Reflects natural gas production converted on the basis of relative energy content (six Mcf equals one barrel).

The Corporation’s oil and gas production, on a barrel of oil equivalent basis, decreased to 373,000 barrels per day in 2003 from 451,000 barrels per day in 2002. Approximately 60% of this decline was due to asset sales and exchanges. The remainder was principally due to natural decline, 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 2004 production will be approximately 13% below 2003 production of 373,000 barrels of oil equivalent per day. Approximately 16,000 barrels per day of the expected decrease is due to asset sales and exchanges in 2003 and the remainder is principally due to natural decline.

     Operating costs and exploration expenses: Operating costs and exploration expenses from continuing operations increased by approximately $70 million and $330 million in 2003 and 2002 compared with the corresponding amounts in the prior years.

Production expenses increased in 2003 primarily due to the weakening of the U.S. dollar, which increased costs incurred in foreign currencies and resulted in higher expenses than in prior years. Production expenses in 2003 also reflect higher employee benefit, transportation and maintenance costs. Production expenses in 2002 were higher than in 2001 due to increased production from higher cost fields, workovers and other maintenance, and higher production volumes. Depreciation, depletion and amortization charges were lower in 2003 than in 2002, reflecting decreased production volumes and lower depreciable costs resulting from impairments in 2002. Depreciation and related charges were higher in 2002 compared to 2001, due to higher unit costs from amortization of the purchase prices of fields in Equatorial Guinea, Colombia and the United States and increased production volumes. Exploration expense was higher in 2003, reflecting increased activity in the United States and Equatorial Guinea, as well as additional lease cost amortization. Exploration expense decreased in 2002 compared with 2001, principally reflecting improved drilling results.

The Corporation’s total unit cost per barrel of oil equivalent produced increased in 2003 and 2002 compared with 2001. Unit cost per barrel includes production expense, depreciation, depletion and amortization, exploration expense and administrative costs. Unit costs per barrel totaled $17.32 in 2003, $15.11 in 2002 and $13.11 in 2001. The Corporation estimates that its 2004 unit costs will approximate the 2003 amount.

     Other: After-tax foreign currency losses amounted to $22 million ($4 million before income taxes) in 2003 compared with income of $6 million ($26 million before income taxes) in 2002 and a loss of $17 million ($21 million before income taxes) in 2001.

17


 

The effective income tax rate for exploration and production operations in 2003 was 51%. This includes income taxes paid in jurisdictions with rates in excess of the United States statutory rate in several producing areas, 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. In addition, certain expenses in foreign jurisdictions are benefited at rates equal to or below the U.S. statutory rate. Each of these factors increases the Corporation’s overall exploration and production effective income tax rate. During 2002, the United Kingdom government enacted a 10% supplementary tax on profits from oil and gas production. The effect of this supplementary tax was an increase in exploration and production income taxes of approximately $60 million in 2003 and $37 million in 2002. The effective income tax rate for exploration and production operations in 2004 is expected to be in the range of 47% to 51%.

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

                         
    After Income Taxes
Millions of dollars
  2003
  2002
  2001
Accrued severance and London office lease costs
  $ (32 )   $     $ (10 )
United States income tax benefit
    30              
Gains from asset sales
    31       34        
Asset impairments
          (737 )      
Charge for increase in United Kingdom income tax rate
          (43 )      
Charge related to Enron bankruptcy
                (19 )
 
   
 
     
 
     
 
 
 
  $ 29     $ (746 )   $ (29 )
 
   
 
     
 
     
 
 
                         
    Before Income Taxes
Millions of dollars
  2003
  2002
  2001
Accrued severance and London office lease costs
  $ (53 )   $     $ (15 )
Gains from asset sales
    47       41        
Asset impairments
          (1,024 )      
Charge related to Enron bankruptcy
                (29 )
 
   
 
     
 
     
 
 
 
  $ (6 )   $ (983 )   $ (44 )
 
   
 
     
 
     
 
 

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 leased office space. The remainder of $21 million relates to severance for positions that were eliminated in London, Aberdeen and Houston. Over 700 employee and contractor positions have been or will be eliminated. Approximately 240 employees are receiving severance, $15 million of which has been paid through year-end. The remainder is expected to be paid in 2004. Additional accruals for severance and lease costs of approximately $15 million before income taxes are anticipated in the first half of 2004. The annual savings from this cost reduction initiative is estimated to be approximately $50 million before income taxes. The Corporation anticipates realizing approximately sixty percent of these savings in 2004 and the full amount in 2005.

The Corporation recorded an income tax benefit of $30 million reflecting the recognition for United States income tax purposes of certain prior year foreign exploration expenses. Gains from asset sales in 2003 reflect $31 million ($47 million before income taxes) from 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 ($1,024 million before income taxes), $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 time frame.

The amount of Ceiba Field proved reserves was about the same at the end of 2002 as the amount at the beginning of the year (excluding 2002 production) and, therefore, the 12% reduction in total field reserves resulted from a decrease in probable reserves. The net proved reserves did not change in 2002 as a result of the recognition of a more efficient primary recovery factor than previously estimated, and to a lesser extent the positive impact of the initiation of water injection operations in February 2002 to maintain reservoir pressure, and additional drilling.

18


 

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 discounted 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 ($318 million before income taxes) 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.

A net gain of $34 million ($41 million before income taxes) was recorded during 2002 from sales 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.

2001: The Corporation recorded an after-tax charge of $19 million ($29 million before income taxes) for estimated losses due to the bankruptcy of certain subsidiaries of Enron Corporation. In addition, the Corporation recorded a net charge of $10 million ($15 million before income taxes) for severance expenses resulting from cost reduction initiatives.

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

Refining and Marketing: Earnings from refining and marketing activities amounted to $327 million in 2003, $85 million in 2002 and $233 million in 2001. The Corporation’s downstream operations include HOVENSA L.L.C. (HOVENSA), a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA), accounted for on the equity method. Additional refining and marketing activities include a fluid catalytic cracking facility in Port Reading, New Jersey, as well as retail gasoline stations, energy marketing and trading operations.

     HOVENSA: The Corporation’s share of HOVENSA’s income was $117 million in 2003, compared with a loss of $47 million in 2002 and income of $58 million in 2001. The increase in 2003 was due to higher refining margins and sales volumes compared with 2002. Crude runs were reduced in 2002 as a result of low refining margins and the shutdown of the fluid catalytic cracking unit for approximately two months. Income taxes on the Corporation’s share of HOVENSA’s results were offset by available loss carryforwards.

HOVENSA’s total crude runs amounted to 440,000 barrels per day in 2003, 361,000 barrels per day in 2002 and 403,000 barrels per day in 2001. In late 2002 and very early 2003, crude oil deliveries to HOVENSA were interrupted due to political disturbances in Venezuela. For the remainder of 2003, HOVENSA received contracted quantities of crude oil from PDVSA. The fluid catalytic cracking unit at HOVENSA operated at 142,000, 116,000 and 123,000 barrels per day in 2003, 2002 and 2001, respectively. The coking unit at HOVENSA commenced production in August 2002. The unit operated at the rate of 53,000 barrels per day in 2003.

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 $30 million in 2003, $35 million in 2002 and $39 million in 2001. Interest income is reflected in non-operating income in the income statement.

19


 

     Retail, Energy Marketing and Other: Earnings from retail gasoline operations were higher in 2003 compared with 2002, reflecting increased margins and sales volumes. Retail gasoline operations in 2002 were profitable but less so than in 2001, reflecting lower margins. Energy marketing activities had increased earnings in 2003, reflecting increased margins and sales volumes in the early part of the year resulting from the cold winter. Energy marketing activities were profitable in 2002 compared with a loss in 2001. Results of the Port Reading refining facility improved in 2003 reflecting higher margins than in 2002. Total refined product sales volumes were 153 million barrels in 2003, 140 million barrels in 2002 and 141 million barrels in 2001.

The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions in addition to its hedging program. The Corporation’s after-tax results from trading activities, including its share of the earnings of the trading partnership amounted to income of $17 million in 2003, $3 million in 2002 and $45 million in 2001. Before income taxes, the trading income was $30 million in 2003, $6 million in 2002 and $72 million in 2001.

Refining and marketing earnings include the following items:

                         
    After Income Taxes
Millions of dollars
  2003
  2002
  2001
Gain (loss) from asset sales
  $ (20 )   $ 67     $  
Reduction in carrying value of intangible assets
          (14 )      
Severance accrual
          (8 )     (2 )
 
   
 
     
 
     
 
 
 
  $ (20 )   $ 45     $ (2 )
 
   
 
     
 
     
 
 
 
    Before Income Taxes
Millions of dollars
  2003
  2002
  2001
Gain (loss) from asset sales
  $ (9 )   $ 102     $  
Reduction in carrying value of intangible assets
          (22 )      
Severance accrual
          (13 )     (3 )
 
   
 
     
 
     
 
 
 
  $ (9 )   $ 67     $ (3 )
 
   
 
     
 
     
 
 

In 2003, refining and marketing earnings include a net loss of $20 million (loss of $9 million before income taxes) 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 ($102 million before income taxes). 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, 2003, the charter support reserve was $48 million. During 2003, the Corporation paid $5 million of charter support. Based on contractual long-term charters entered into in 2003, and estimates of future charter rates, the Corporation lowered the estimated charter support reserve by $11 million. The balance in this reserve at December 31, 2003 was $32 million.

The Corporation recorded an after-tax charge of $14 million ($22 million before income taxes) in 2002 for the write-off of intangible assets in its U.S. energy marketing business. In addition, after-tax accrued severance of $8 million ($13 million before income taxes) 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 $101 million in 2003, $63 million in 2002 and $78 million in 2001. 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. Corporate administrative expenses, before income taxes, increased slightly in 2003 and were comparable in 2002 and 2001. The decrease in after-tax expenses in 2002 reflects lower United States taxes on foreign source income. After-tax corporate expenses for 2004 are estimated to be in the range of $60 to $70 million.

20


 

Interest: After-tax interest was $173 million in 2003, $165 million in 2002 and $135 million in 2001. The corresponding amounts before income taxes were $293 million, $256 million and $194 million in 2003, 2002 and 2001, respectively. Interest incurred in 2003 was lower than in 2002 because of debt reduction; however, the reduction in interest incurred was more than offset by lower capitalized interest in 2003. Capitalized interest in 2003, 2002 and 2001 was $41 million, $101 million and $44 million, respectively. Interest expense was higher in 2002 compared with 2001 reflecting increased borrowings related to acquisitions. After-tax interest expense in 2004 is anticipated to be approximately 20% below the 2003 level.

Discontinued Operations: In the first quarter of 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 an after-tax charge to income of $47 million ($51 million before income taxes). The after-tax loss on this exchange included a $43 million adjustment of the book value of the Colombian assets to fair value. The loss also included $17 million from the recognition in earnings of the value of related hedge contracts at the time of the exchange. These items were partially offset by after-tax earnings in Colombia prior to the exchange of $13 million. The JDA production facilities are complete, but production will not commence until the purchasers of the gas complete the construction of a natural gas pipeline. The Corporation anticipates that production will begin in the second half of 2005.

In the second quarter of 2003, the Corporation 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 $175 million ($248 million before income taxes) was included in discontinued operations. Discontinued operations in 2003 also includes $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 the year. 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 2003, sales and other operating revenues increased by 24% compared with 2002. This increase principally reflects increased sales volumes and selling prices of refined products and the higher selling price of purchased natural gas in energy marketing activities. Sales and other operating revenues decreased by 12% in 2002 compared with 2001, due to the sale of the United Kingdom energy marketing business, and lower sales volumes of refined products and purchased natural gas related to U.S. energy marketing. These decreases were partially offset by higher production of crude oil and natural gas. The change in cost of goods sold in each year reflects the change in sales of refined products and purchased natural gas.

Liquidity and Capital Resources

     Overview: Cash flows from operating activities, including changes in operating assets and liabilities, totaled $1,581 million in 2003. During the year, the Corporation strengthened its financial position through sales of assets and the issuance of preferred stock. At December 31, 2003, the Corporation’s debt to capitalization ratio was 42.5% compared to 54.0% at December 31, 2002. Total debt was $3,941 million at December 31, 2003 and $4,992 million at December 31, 2002. Cash and cash equivalents at the end of 2003 totaled $518 million, an increase of $321 million for the year. Long-term debt totaling $221 million matures over the next three years.

The Corporation has hedged the selling prices of a significant portion of its crude oil and natural gas production in 2004 and 2005 to help generate a level of cash flow that will meet operating and capital commitments.

21


 

     Cash Flows from Operating Activities: Net cash provided by operating activities, including changes in operating assets and liabilities, totaled $1,581 million in 2003, $1,965 million in 2002 and $1,960 million in 2001. Lower cash flows in 2003 were primarily due to reduced exploration and production sales volumes.

     Cash Flows from Investing Activities: The following table summarizes the Corporation’s capital expenditures in 2003, 2002 and 2001:

                         
Millions of dollars
  2003
  2002
  2001
Exploration and production
                       
Exploration
  $ 196     $ 239     $ 171  
Production and development
    1,067       1,095       1,250  
Acquisitions
    23       70       3,640  
 
   
 
     
 
     
 
 
 
    1,286       1,404       5,061  
 
   
 
     
 
     
 
 
Refining and marketing
                       
Operations
    72       83       110  
Acquisitions
          47       50  
 
   
 
     
 
     
 
 
 
    72       130       160  
 
   
 
     
 
     
 
 
Total
  $ 1,358     $ 1,534     $ 5,221  
 
   
 
     
 
     
 
 

Capital expenditures in 2001 included $2,720 million for the Triton acquisition, excluding the assumption of debt. In addition, the Corporation purchased crude oil and natural gas reserves in the Gulf of Mexico and onshore Louisiana for $920 million. The amounts shown for acquisitions in 2002 principally represent final installment payments on prior year acquisitions.

In 2003, the Corporation took initiatives to reshape its portfolio of producing assets to reduce future costs, increase its reserve to production ratio, and provide capital for investment in new fields and funds to reduce debt. 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 during 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%. Production from the Corporation’s 50% interest in the Llano Field is scheduled to commence in mid-2004.

The net production from fields sold or exchanged at the time of disposition was approximately 50,000 barrels of oil equivalent per day. The Corporation believes the overall impact of its program of asset exchanges and sales of properties has not reduced its liquidity in the short-term or over the next five years.

In 2002, the Corporation sold 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: In the fourth quarter of 2003, the Corporation issued 13,500,000 shares of mandatory convertible preferred stock for net proceeds of $653 million. Cash flows from operations, asset sales and the issuance of preferred stock enabled the Corporation to reduce debt by $1,051 million during 2003. Debt repayment in 2002, net of new borrowings, was $673 million.

22


 

     Future Capital Requirements and Resources: Capital expenditures in 2004 are expected to be approximately $1.5 billion. The Corporation anticipates that these expenditures will be funded by available cash and cash flow from operations. Lines of credit are available, if necessary. At December 31, 2003, the Corporation has an undrawn facility of $1.5 billion under its committed revolving credit agreement and has additional unused lines of credit of $206 million under uncommitted arrangements with banks. The Corporation’s revolving credit agreement expires in 2006 and the Corporation expects it will be able to arrange a new committed facility at that time, if required. The Corporation also has a shelf registration under which it may issue $825 million of additional debt securities, warrants, common stock or preferred stock.

     Loan agreement covenants allow the Corporation to borrow an additional $5 billion for the construction or acquisition of assets at December 31, 2003. At year end, the amount that can be borrowed under the loan agreements for the payment of dividends is $1.9 billion.

     The Corporation’s aggregate maturities of long-term debt total $221 million over the next three years. Based on current estimates of production, capital expenditures and other factors, and assuming West Texas Intermediate oil prices average $24 per barrel and United States natural gas prices average $4.25 per Mcf, the Corporation anticipates it will fund its future operations, including capital expenditures, dividends and required debt repayment, with existing cash on-hand, cash flow from operations and, when necessary, borrowings under its credit facilities and the issuance of securities under its shelf registration.

     Prior to June 30, 1986, the Corporation had extensive exploration and production operations in Libya, however, it was required to suspend participation in these operations as a result of U.S. government sanctions. If U.S. sanctions on Libya are removed, and if the Corporation and its partners successfully negotiate with the government of Libya to resume participation in the group’s former operations, management anticipates capital expenditures will likely increase over the current plan. Production and reserves would also increase. On February 24, 2004, the Corporation received U.S. Government authorization to negotiate and enter into an executory agreement with the government of Libya that would define the terms for resuming active participation in the Libyan properties. The Corporation’s performance under this agreement will be contingent on obtaining future U.S. Government authorizations. The Corporation cannot predict the outcome or timing of these events.

     Credit Ratings: While the Corporation maintains investment grade ratings from two rating agencies, one credit rating agency downgraded its rating of the Corporation’s debt to non-investment grade in February 2004. Cash margin or collateral is required under certain contracts with hedging and trading counterparties and certain lenders. The amount of such cash margin or collateral would have increased at December 31, 2003 by approximately $230 million as a result of the downgrade. The downgrade is expected to increase annual pre-tax financing costs by less than $10 million.

     Contractual Obligations and Contingencies: Following is a table showing aggregated information about certain contractual obligations at December 31, 2003:

                                         
    Payments Due by Period
                    2005 and   2007 and    
Millions of dollars
  Total
  2004
  2006
  2008
  Thereafter
Long-term debt
  $ 3,893     $ 63     $ 126     $ 327     $ 3,377  
Capital leases
    48       10       22       14       2  
Operating leases
    1,303       95       142       142       924  
Purchase obligations
Supply commitments
    14,706       5,233       4,847       4,626       *  
Capital expenditures
    799       433       296       70        
Operating expenses
    266       170       44       31       21  
Other long-term liabilities
    235       110       56       32       37  


    *The Corporation intends to continue purchasing its refined product supply from HOVENSA. Current purchases amount to approximately $2 billion annually.

23


 

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 2004 capital expenditures are estimated to be approximately $1.5 billion, including approximately $900 million for oil and gas developments. 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, 2003 was $32 million.

The Corporation has a contingent purchase obligation to acquire the remaining 50% interest in a retail marketing and gasoline station joint venture for $88 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, 2003 amounted to $134 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 is contingently liable under letters of credit and under guarantees of the debt of other entities directly related to its business, as follows:

         
Millions of dollars
  Total
Letters of credit
  $ 7  
Guarantees
    92 *
 
   
 
 
 
  $ 99  
 
   
 
 


    *Includes $40 million HOVENSA debt guarantee discussed above. The remainder relates principally to a loan guarantee for a natural gas pipeline in which the Corporation owns a 5% interest.

     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 $462 million at December 31, 2003, using interest rates inherent in the leases. The Corporation’s December 31, 2003 debt to capitalization ratio would increase from 42.5% to 45.2% if the lease financings were included.

See also “Contractual Obligations and Contingencies” above, Note No. 7, “Refining Joint Venture,” and Note No. 18, “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.

24


 

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 $334 million at December 31, 2003 from a subsidiary of PDVSA. The Corporation anticipates collection of the remaining balance.

Market Risk Disclosure

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 which 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 uses forward commodity contracts, foreign exchange forward contracts, futures, swaps and options in the Corporation’s 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:


 

  Forward Commodity Contracts: The forward purchase and sale of commodities is performed as part of the Corporation’s normal activities. At title date, the notional value of the contract is exchanged for physical delivery of the commodity. Forward contracts that are designated as normal purchase and sale contracts under FAS No. 133 are excluded from the quantitative market risk disclosures.

  Forward Foreign Exchange Contracts: Forward contracts include forward purchase contracts for both the British pound sterling and the Danish kroner. These foreign currency contracts commit the Corporation to purchase a fixed amount of pound sterling and kroner at a predetermined exchange rate on a certain date.

  Futures: The Corporation uses exchange traded futures contracts on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and are subject to exchange position limits.

  Swaps: The Corporation uses financially settled swap contracts with third parties as part of its hedging and trading activities. Cash flows from swap contracts are determined based on underlying commodity prices and are typically settled over the life of the contract.

  Options: Options on various underlying energy commodities include exchange traded and third party contracts and have various exercise periods. As a seller of options, the Corporation receives a premium at the outset and bears the risk of unfavorable changes in the price of the commodity underlying the option. As a purchaser of options, the Corporation pays a premium at the outset and has the right to participate in the favorable price movements in the underlying commodities.

     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.

25


 

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 the purpose of 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 70% of its estimated 2004 worldwide crude oil production and 45% of its estimated 2005 worldwide crude oil production. The average price for West Texas Intermediate crude oil (WTI) related open hedge positions is $26.24 in 2004 and $25.83 in 2005. The average price for Brent crude oil related open hedge positions is $24.51 in 2004 and $24.41 in 2005. Approximately 18% of the Corporation’s hedges are WTI related and the remainder are Brent. The Corporation also has hedged 30% of its 2004 United States natural gas production at an average price of $5.10 per Mcf. As market conditions change, the Corporation may adjust its hedge percentages.

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.

         
    Non-Trading
Millions of dollars
  Activities
2003
       
At December 31
  $ 44  
Average for the year
    43  
High during the year
    47  
Low during the year
    40  
 
   
 
 
2002
       
At December 31
  $ 50  
Average for the year
    49  
High during the year
    62  
Low during the year
    34  
 
   
 
 

The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates. To counteract these foreign exchange exposures, the Corporation enters into forward purchase contracts for both the British pound sterling and the Danish kroner. At December 31, 2003, the Corporation has $384 million of notional value foreign exchange contracts maturing in 2004 and 2005 ($307 million at December 31, 2002). The fair value of foreign exchange contracts recorded as assets was $40 million at December 31, 2003 ($18 million at December 31, 2002). The change in fair value of the foreign exchange contracts from a 10% change in exchange rates is estimated to be $43 million at December 31, 2003 ($33 million at December 31, 2002).

At December 31, 2003, the interest rate on substantially all of the Corporation’s debt is fixed and there are no interest rate swaps. The Corporation’s outstanding debt of $3,941 million has a fair value of $4,440 million at December 31, 2003 (debt of $4,992 million at December 31, 2002 had a fair value of $5,569 million). A 15% change in the rate of interest would change the fair value of debt at December 31, 2003 and 2002 by approximately $270 million.

26


 

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, 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 $50 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.

                 
Millions of dollars
  2003
  2002
Fair value of contracts outstanding at the beginning of the year
  $ 36     $ (58 )
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of year
    36       (14 )
Reversal of fair value for contracts closed during the year
    (26 )     75  
Fair value of contracts entered into during the year and still outstanding
    21       33  
 
   
 
     
 
 
Fair value of contracts outstanding at the end of the year
  $ 67     $ 36  
 
   
 
     
 
 

The Corporation uses observable market values for determining the fair value of its trading instruments. The majority of valuations are based on actively quoted market values. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. Internal estimates are based on internal models incorporating underlying market information such as commodity volatilities and correlations. The Corporation’s risk management department regularly compares valuations to independent sources and models.

                                 
Millions of dollars
  Total
  2004
  2005
  2006
Source of fair value
Prices actively quoted
  $ 69     $ 33     $ 36     $  
Other external sources
    5       (8 )     7       6  
Internal estimates
    (7 )     (4 )     (3 )      
 
   
 
     
 
     
 
     
 
 
Total
  $ 67     $ 21     $ 40     $ 6  
 
   
 
     
 
     
 
     
 
 

The following table summarizes the value-at-risk results for all trading activities. The results may change from time to time as strategies change to capture potential market rate movements.

         
    Trading
Millions of dollars
  Activities
2003
       
At December 31
  $ 7  
Average for the year
    9  
High during the year
    12  
Low during the year
    7  
 
   
 
 
2002
At December 31
  $ 6  
Average for the year
    10  
High during the year
    12  
Low during the year
    6  
 
   
 
 

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The following table summarizes the fair values of net receivables relating to the Corporation’s trading activities and the credit rating of counterparties at December 31:

                 
Millions of dollars
  2003
  2002
Investment grade determined by outside sources
  $ 246     $ 309  
Investment grade determined internally*
    89       70  
Less than investment grade
    16       61  
Not determined
          2  
 
   
 
     
 
 
 
  $ 351     $ 442  
 
   
 
     
 
 


    *Based on information provided by counterparties and other available sources.

Critical Accounting Policies and Estimates

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: The Corporation uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire or lease unproved and proved oil and gas properties are capitalized. Costs incurred in connection with the drilling and equipping of successful exploratory wells are also capitalized. If proved reserves are not found, these costs are charged to expense. Other exploration costs, including seismic, are charged to expense as incurred. Development costs, which include the costs of drilling and equipping development wells, are capitalized. Depreciation, depletion and amortization of capitalized costs of proved oil and gas properties are computed on the unit-of-production method based on estimates of proved reserves on a field basis.

The determination of estimated proved reserves is a significant element in arriving at the results of operations of exploration and production activities. The Corporation uses independent reservoir engineers to estimate all of its oil and gas reserves. The estimates of proved reserves impact well capitalizations, undeveloped lease impairments and the depreciation rates of proved properties, wells and equipment. Reduction in reserve estimates may result in the need for impairments of proved properties and related assets.

     Hedging: Hedging contracts correlate to the selling prices of crude oil or natural gas and the Corporation has designated these contracts as hedges. Therefore, the Corporation records gains or losses on these instruments in income in the period in which the production is sold. At December 31, 2003, the Corporation has $229 million of deferred hedging losses, after income taxes, included in other comprehensive income.

     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 undis-counted 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.

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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 has recorded $977 million of goodwill in connection with the purchase of Triton. 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 which 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 to be 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 that there was more than one operating segment, or its components were no longer economically similar, goodwill would be assigned to two or more reporting units. The goodwill would be allocated to any new reporting units using a relative fair value approach in accordance with FAS No. 142. Goodwill impairment testing for lower level reporting units could result in the recognition of an impairment that would not otherwise be recognized at the current higher level of aggregation.

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 operates its exploration and production segment as a single, global business.
 
  Each component produces oil and gas.
 
  The exploration and production processes are similar in each component.
 
  The methods used by each component to market and distribute oil and gas are similar.
 
  Customers of each component are similar.
 
  The components share resources and are supported by a worldwide exploration team and a shared services organization.

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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. The effect of synergies is embedded in the value of producing assets, known developments and exploration assets. Significant extended declines in crude oil and natural gas prices, reduced reserve estimates or failure to realize synergies 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 which 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. Mr. John B. Hess, 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. Mr. Hess 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 segment or any such information by geographical location, oil and gas property or project, subsidiary or division, to make decisions about resources to be allocated or to assess performance. While the CODM does review and approve initial corporate funding for a new project using information about the project, he does not review subsequent operating results by project after the initial funding. Each operating segment has one manager. The segment managers are responsible for allocating resources within the segments, reviewing financial results of components within the segments, and assessing the performance of the components. The CODM evaluates the performance of the segment managers based on performance metrics related to each manager’s operating segment as a whole. The Board of Directors of the Corporation does not receive more detailed information than that used by the CODM to operate and manage the Corporation.

30


 

     Oil and Gas Mineral Rights: The oil and gas industry is currently discussing the appropriate balance sheet classification of oil and gas mineral rights held by lease or contract. The Corporation classifies these assets as property, plant and equipment in accordance with its interpretation of FAS No. 19 and common industry practice. There is also a view that these mineral rights are intangible assets as defined in FAS No. 141, Business Combinations, and, therefore, should be classified separately on the balance sheet as intangible assets. If the accounting for mineral rights held by lease or contract is ultimately changed, the Corporation believes that any such reclassification of mineral rights could amount to approximately $2.3 billion at December 31, 2003 and $2.2 billion at December 31, 2002, if the Corporation is required to include the purchase price allocated to hydrocarbon reserves obtained in acquisitions of oil and gas properties. The determination of this amount is based on the Corporation’s current understanding of this evolving issue and how the provisions of FAS No. 141 might be applied to oil and gas mineral rights. If mineral rights are reclassified to intangible assets, FAS No. 142, Goodwill and Other Intangible Assets, will require additional disclosures in the financial statement notes. This potential balance sheet reclassification would not affect results of operations or cash flows.

Environment, Health and Safety

The Corporation has implemented a values-based, social-responsibility strategy focused on improved environment, health, and safety performance and making a positive impact on communities and the environment. The strategy is supported by the Corporation’s environment, health, safety and social responsibility policies and management systems that help protect the Corporation’s workforce, customers and local communities. Overall governance is the responsibility of senior management. To ensure that the Corporation meets its goals and regulatory requirements, the Corporation has programs in place for compliance evaluation, facility auditing and employee training. Environment and safety management systems, based on international standards, are used throughout the Corporation to ensure consistency and adherence to policy objectives. Improved performance in environment, health and safety may raise the Corporation’s operating costs and require increased capital expenditures while reducing potential risks to corporate assets, reputation and ability to operate.

The Port Reading refining facility and the HOVENSA refinery manufacture conventional and reformulated gasolines that are cleaner burning than required under U.S. regulations currently in effect. In addition, the benzene and sulfur content in the Corporation’s gasoline is approximately one-half of the national average (excluding California), resulting in significantly lower toxic emissions than the industry average.

The regulation of motor fuels in the United States and elsewhere continues to be an area of considerable change and will likely require large capital expenditures in future years. In December 1999, the United States Environmental Protection Agency (“EPA”) adopted rules that phase in limitations on the sulfur content of gasoline beginning in 2004. In December 2000, the EPA adopted regulations to substantially reduce the allowable sulfur content of diesel fuel by 2006.

The Corporation and HOVENSA continue to review options to determine the most cost effective compliance strategies for these fuel regulations. The costs to comply will depend on a variety of factors, including the availability of suitable technology and contractors and the credit trading programs. The estimated capital expenditures necessary to comply with the low-sulfur gasoline requirements at Port Reading are approximately $70 million over the next several years. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are presently expected to be $450 million over the next three years. HOVENSA expects to finance these capital expenditures through cash flow and, if necessary, future borrowings.

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 2002 and will likely be reconsidered. The Corporation and HOVENSA both manufacture and use MTBE primarily to meet the federal requirement for oxygen in reformulated gasoline, and do not presently use ethanol. Several states in the Corporation’s market area have enacted bans on MTBE use, including Connecticut and New York (effective January 2004), and other states are considering them. If Congress bans MTBE 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 or obligations, requirements for maintenance of certain air

31


 

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 is reviewing various options to market and produce reformulated gasolines if additional MTBE bans take effect.

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. Presently over 40% of U.S. refining capacity is operating under PRI controls and an additional 37% of refining capacity will be included in early 2004. Depending on the outcome of these discussions, which will not likely be concluded until 2005, 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 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 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 is working to establish an internal greenhouse gas reporting protocol that will provide a common set of principles and guidelines for reporting data from operated facilities and from assets operated by the Corporation’s partners.

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

The Corporation accrues for environmental expenses when the future costs are probable and reasonably estimable. At year end 2003, the Corporation’s reserve for its estimated environmental liability was approximately $85 million. Remediation spending was $12 million in 2003, $9 million in 2002, and $8 million in 2001. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, were $7 million in 2003, $5 million in 2002, and $6 million in 2001. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites.

Dividends

Cash dividends on common stock totaled $1.20 per share ($.30 per quarter) during 2003 and 2002. Dividends on the 7% cumulative mandatory convertible preferred stock will total $3.50 per share ($.875 per quarter).

Stock Market Information

The common stock of Amerada Hess Corporation is traded principally on the New York Stock Exchange (ticker symbol: AHC). High and low sales prices in 2003 and 2002 were as follows:

                                 
    2003
  2002
Quarter Ended
  High
  Low
  High
  Low
March 31
  $ 57.20     $ 41.14     $ 80.15     $ 57.60  
June 30
    51.50       43.51       84.70       74.61  
September 30
    50.90       45.04       83.00       61.36  
December 31
    55.25       46.09       71.48       49.40  

     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 to December 31 were $55.43 and $49.50, respectively.

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Quarterly Financial Data

Quarterly results of operations for the years ended December 31, 2003 and 2002 follow:

                                 
    Sales                
Millions of   and other           Net   Net
dollars, except   operating   Gross   income   income (loss)
per share data
  revenues
  profit (a)
  (loss)(b)
  per share
2003
                               
First
  $ 4,254     $ 477     $ 177 (c)   $ 1.98  
Second
    3,199       382       252 (d)     2.83  
Third
    3,230       361       146 (e)     1.64  
Fourth
    3,628       394       68 (d)(f)     .71  
2002
                               
First
  $ 2,926     $ 368     $ 140 (g)   $ 1.58  
Second
    2,694       385       149 (h)     1.66  
Third
    2,724       419       (136 )(i)     (1.54 )
Fourth
    3,207       431       (371 )(j)     (4.20 )


(a)   Gross profit represents sales and other operating revenues, less cost of products sold, production expenses, marketing expenses, other operating expenses and depreciation, depletion and amortization.
 
(b)   Includes net income (loss) from discontinued operations, as follows:
                 
Quarter
  2003
  2002
First
  $ (20 )   $ 9  
Second
    189       20  
Third
          (31 )
Fourth
          29  

(c)   Includes income of $7 million from the cumulative effect of the adoption of FAS No. 143, Accounting for Asset Retirement Obligations. Also includes income of $31 million ($47 million before income taxes) from asset sales.
 
(d)   Includes after-tax charges of $23 million ($38 million before income taxes) in the second quarter and $9 million ($15 million before income taxes) in the fourth quarter for accrued severance and a reduction in leased office space in London. Also includes a net loss in the second quarter of $20 million ($9 million before income taxes) from the sale of a shipping joint venture.
 
(e)   Includes a U.S. income tax benefit of $30 million for the recognition of certain prior year foreign exploration expenses.
 
(f)   Includes $19 million after-tax ($31 million before income taxes) for premiums paid on repurchase of bonds.
 
(g)   Reflects a net gain from asset sales of $42 million ($62 million before income taxes).
 
(h)   Includes charges of $14 million ($22 million before income taxes) for the reduction in carrying value of intangible assets related to energy marketing activities and $8 million ($13 million before income taxes) for a severance accrual.
 
(i)   Reflects a net charge of $207 million ($318 million before income taxes) for impairment of U.S. producing properties and exploration acreage. Also includes a net gain from asset sales of $45 million ($68 million before income taxes) and a deferred tax charge of $43 million for an increase in the United Kingdom income tax rate.
 
(j)   Includes a net charge of $530 million ($706 million before income taxes) for impairment of the Ceiba Field. Also includes a net gain from an asset sale of $13 million.

The results of operations for the periods reported herein should not be considered as indicative of future operating results.

Forward Looking Information

Certain sections of Management’s Discussion and Analysis of Results of Operations and Financial Condition, 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.

33


 

CONSOLIDATED BALANCE SHEET
Amerada Hess Corporation and Consolidated Subsidiaries

                 
    At December 31
Millions of dollars; thousands of shares
  2003
  2002
ASSETS
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 518     $ 197  
Accounts receivable
               
Trade
    1,717       1,785  
Other
    185       187  
Inventories
    579       492  
Other current assets
    187       95  
 
   
 
     
 
 
Total current assets
    3,186       2,756  
 
   
 
     
 
 
INVESTMENTS AND ADVANCES
               
HOVENSA L.L.C.
    960       842  
Other
    135       780  
 
   
 
     
 
 
Total investments and advances
    1,095       1,622  
 
   
 
     
 
 
PROPERTY, PLANT AND EQUIPMENT
               
Exploration and production
    14,614       14,699  
Refining and marketing
    1,486       1,450  
 
   
 
     
 
 
Total—at cost
    16,100       16,149  
Less reserves for depreciation, depletion, amortization and lease impairment
    8,122       9,117  
 
   
 
     
 
 
Property, plant and equipment—net
    7,978       7,032  
 
   
 
     
 
 
NOTES RECEIVABLE
    302       363  
 
   
 
     
 
 
GOODWILL
    977       977  
 
   
 
     
 
 
DEFERRED INCOME TAXES AND OTHER ASSETS
    445       512  
 
   
 
     
 
 
TOTAL ASSETS
  $ 13,983     $ 13,262  
 
   
 
     
 
 

34


 

                 
    At December 31
    2003
  2002
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
CURRENT LIABILITIES
               
Accounts payable—trade
  $ 1,542     $ 1,401  
Accrued liabilities
    855       830  
Taxes payable
    199       306  
Notes payable
          2  
Current maturities of long-term debt
    73       14  
 
   
 
     
 
 
Total current liabilities
    2,669       2,553  
 
   
 
     
 
 
LONG-TERM DEBT
    3,868       4,976  
 
   
 
     
 
 
DEFERRED LIABILITIES AND CREDITS
               
Deferred income taxes
    1,144       1,044  
Asset retirement obligations
    462        
Other
    500       440  
 
   
 
     
 
 
Total deferred liabilities and credits
    2,106       1,484  
 
   
 
     
 
 
STOCKHOLDERS’ EQUITY
               
Preferred stock, par value $1.00, 20,000 shares authorized
7% cumulative mandatory convertible series
               
Authorized—13,500 shares
Issued—13,500 shares in 2003 ($675 liquidation preference)
    14        
3% cumulative convertible series
Authorized—330 shares
Issued—327 shares in 2003 and 2002 ($16 liquidation preference)
           
Common stock, par value $1.00
Authorized—200,000 shares
Issued—89,868 shares in 2003; 89,193 shares in 2002
    90       89  
Capital in excess of par value
    1,603       932  
Retained earnings
    4,011       3,482  
Accumulated other comprehensive income (loss)
    (350 )     (254 )
Deferred compensation
    (28 )      
 
   
 
     
 
 
Total stockholders’ equity
    5,340       4,249  
 
   
 
     
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 13,983     $ 13,262  
 
   
 
     
 
 

The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.
See accompanying notes to consolidated financial statements.

35


 

STATEMENT OF CONSOLIDATED INCOME
Amerada Hess Corporation and Consolidated Subsidiaries

                         
    For the Years Ended December 31
Millions of dollars, except per share data
  2003
  2002
  2001
REVENUES AND NON-OPERATING INCOME
                       
Sales (excluding excise taxes) and other operating revenues
  $ 14,311     $ 11,551     $ 13,052  
Non-operating income (expense)
                 
Gain on asset sales
    39       143        
Equity in income (loss) of HOVENSA L.L.C.
    117       (47 )     58  
Other
    13       85       150  
 
   
 
     
 
     
 
 
Total revenues and non-operating income
    14,480       11,732       13,260  
 
   
 
     
 
     
 
 
COSTS AND EXPENSES
                       
Cost of products sold
    9,947       7,226       8,739  
Production expenses
    796       736       642  
Marketing expenses
    709       703       663  
Exploration expenses, including dry holes and lease impairment
    369       316       347  
Other operating expenses
    192       165       213  
General and administrative expenses
    340       253       311  
Interest expense
    293       256       194  
Depreciation, depletion and amortization
    1,053       1,118       833  
Asset impairments
          1,024        
 
   
 
     
 
     
 
 
Total costs and expenses
    13,699       11,797       11,942  
 
   
 
     
 
     
 
 
Income (loss) from continuing operations before income taxes
    781       (65 )     1,318  
Provision for income taxes
    314       180       502  
 
   
 
     
 
     
 
 
Income (loss) from continuing operations
    467       (245 )     816  
Discontinued operations
                       
Net gain from asset sales
    116              
Income from operations
    53       27       98  
Cumulative effect of change in accounting principle
    7              
 
   
 
     
 
     
 
 
NET INCOME (LOSS)
  $ 643     $ (218 )   $ 914  
 
   
 
     
 
     
 
 
Less preferred stock dividends
    5              
 
   
 
     
 
     
 
 
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS
  $ 638     $ (218 )   $ 914  
 
   
 
     
 
     
 
 
BASIC EARNINGS (LOSS) PER SHARE
         
Continuing operations
  $ 5.21     $ (2.78 )   $ 9.26  
Net income (loss)
    7.19       (2.48 )     10.38  
 
   
 
     
 
     
 
 
DILUTED EARNINGS (LOSS) PER SHARE
         
Continuing operations
  $ 5.17     $ (2.78 )   $ 9.15  
Net income (loss)
    7.11       (2.48 )     10.25  
 
   
 
     
 
     
 
 

See accompanying notes to consolidated financial statements.

36


 

STATEMENT OF CONSOLIDATED RETAINED EARNINGS
Amerada Hess Corporation and Consolidated Subsidiaries

                         
    For the Years Ended December 31
Millions of dollars, except per share data
  2003
  2002
  2001
BALANCE AT BEGINNING OF YEAR
  $ 3,482     $ 3,807     $ 3,069  
Net income (loss)
    643       (218 )     914  
Dividends declared—common stock ($1.20 per share in 2003, 2002 and 2001)
    (109 )     (107 )     (107 )
Dividends on preferred stock ($.34 per share in 2003)
    (5 )            
Common stock acquired and retired
                (69 )
 
   
 
     
 
     
 
 
BALANCE AT END OF YEAR
  $ 4,011     $ 3,482     $ 3,807  
 
   
 
     
 
     
 
 

See accompanying notes to consolidated financial statements.

37


 

STATEMENT OF CONSOLIDATED CASH FLOWS
Amerada Hess Corporation and Consolidated Subsidiaries

                         
    For the Years Ended December 31
Millions of dollars
  2003
  2002
  2001
CASH FLOWS FROM OPERATING ACTIVITIES
                       
Net income (loss)
  $ 643     $ (218 )   $ 914  
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization
    1,053       1,118       833  
Asset impairments
          1,024        
Exploratory dry hole costs
    162       157       185  
Lease impairment
    65       41       38  
Pre-tax gain on asset sales
    (245 )     (117 )      
Provision (benefit) for deferred income taxes
    107       (258 )     64  
Undistributed earnings of affiliates
    (130 )     47       (52 )
Non-cash effect of discontinued operations
    46       280       153  
Changes in other operating assets and liabilities
(Increase) decrease in accounts receivable
    47       (104 )     650  
(Increase) decrease in inventories
    (107 )     51       (131 )
Increase (decrease) in accounts payable and accrued liabilities
    18       (217 )     (553 )
Increase (decrease) in taxes payable
    (39 )     50       (185 )
Changes in prepaid expenses and other
    (39 )     111       44  
 
   
 
     
 
     
 
 
Net cash provided by operating activities
    1,581       1,965       1,960  
 
   
 
     
 
     
 
 
CASH FLOWS FROM INVESTING ACTIVITIES
                       
Capital expenditures
Exploration and production
    (1,286 )     (1,404 )     (2,341 )
Refining and marketing
    (72 )     (130 )     (160 )
 
   
 
     
 
     
 
 
Total capital expenditures
    (1,358 )     (1,534 )     (2,501 )
Acquisition of Triton Energy Limited, net of cash acquired
                (2,720 )
Proceeds from asset sales
    545       412       67  
Payment received on note receivable
    61       48       48  
Other
    (25 )     (22 )     (99 )
 
   
 
     
 
     
 
 
Net cash used in investing activities
    (777 )     (1,096 )     (5,205 )
 
   
 
     
 
     
 
 
CASH FLOWS FROM FINANCING ACTIVITIES
                       
Debt with maturities of 90 days or less — increase (decrease)
    (2 )     (581 )     564  
Debt with maturities of greater than 90 days
Borrowings
          637       2,595  
Repayments
    (1,026 )     (686 )     (54 )
Proceeds from issuance of preferred stock
    653              
Cash dividends paid
    (108 )     (107 )     (94 )
Common stock and warrants acquired
                (100 )
Stock options exercised
          28       59  
 
   
 
     
 
     
 
 
Net cash provided by (used in) financing activities
    (483 )     (709 )     2,970  
 
   
 
     
 
     
 
 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    321       160       (275 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    197       37       312  
 
   
 
     
 
     
 
 
CASH AND CASH EQUIVALENTS AT END OF YEAR
  $ 518     $ 197     $ 37  
 
   
 
     
 
     
 
 

See accompanying notes to consolidated financial statements.

38


 

STATEMENT OF CONSOLIDATED CHANGES IN PREFERRED STOCK, COMMON STOCK AND CAPITAL IN EXCESS OF PAR VALUE
Amerada Hess Corporation and Consolidated Subsidiaries

                                         
    Preferred Stock
  Common Stock
   
                                    Capital in
    Number of           Number of           excess of
Millions of dollars; thousands of shares
  shares
  Amount
  shares
  Amount
  par value
BALANCE AT JANUARY 1, 2001
    327     $       88,744     $ 89     $ 864  
Distributions to trustee of nonvested common stock awards (net)
                38             1  
Common stock acquired and retired
                (1,078 )     (1 )     (11 )
Employee stock options exercised
                1,053       1       69  
Warrants purchased
                            (20 )
 
   
 
     
 
     
 
     
 
     
 
 
BALANCE AT DECEMBER 31, 2001
    327             88,757       89       903  
Cancellations of nonvested common stock awards (net)
                (55 )           (3 )
Employee stock options exercised
                491             32  
 
   
 
     
 
     
 
     
 
     
 
 
BALANCE AT DECEMBER 31, 2002
    327             89,193       89       932  
Issuance of preferred stock
    13,500       14                   639  
Distributions to trustee of nonvested common stock awards (net)
                675       1       32  
 
   
 
     
 
     
 
     
 
     
 
 
BALANCE AT DECEMBER 31, 2003
    13,827     $ 14       89,868     $ 90     $ 1,603  
 
   
 
     
 
     
 
     
 
     
 
 

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

                         
    For the Years Ended December 31
Millions of dollars
  2003
  2002
  2001
COMPONENTS OF COMPREHENSIVE INCOME (LOSS)
                       
Net income (loss)
  $ 643     $ (218 )   $ 914  
Change in foreign currency translation adjustment
    13       34       (2 )
Additional minimum pension liability, after tax
    (1 )     (71 )      
Deferred gains (losses) on oil and gas cash flow hedges, after tax
                       
FAS 133 transition adjustment
                100  
Reclassification of deferred hedging to income
    203       (56 )     (74 )
Net change in fair value of cash flow hedges
    (311 )     (269 )     223  
 
   
 
     
 
     
 
 
COMPREHENSIVE INCOME (LOSS)
  $ 547     $ (580 )   $ 1,161  
 
   
 
     
 
     
 
 

See accompanying notes to consolidated financial statements.

39


 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amerada Hess Corporation and Consolidated Subsidiaries

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business: Amerada Hess Corporation and subsidiaries (the “Corporation”) engage in the exploration for and the production, purchase, transportation and sale of crude oil and natural gas. These activities are conducted primarily in the United States, United Kingdom, Norway, Denmark, Equatorial Guinea and Algeria. The Corporation also has oil and gas activities in Azerbaijan, Gabon, Indonesia, Malaysia, Thailand and other countries. In addition, the Corporation manufactures, purchases, transports, trades and markets refined petroleum and other energy products. The Corporation owns 50% of HOVENSA L.L.C., a refinery joint venture in the United States Virgin Islands. An additional refining facility, terminals and retail gasoline stations are located on the East Coast of the United States.

In preparing financial statements, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the balance sheet and revenues and expenses in the income statement. Actual results could differ from those estimates. Among the estimates made by management are: oil and gas reserves, asset valuations, depreciable lives, pension liabilities, environmental obligations, dismantlement costs and income taxes.

Certain information in the financial statements and notes has been reclassified to conform with current period presentation.

Principles of Consolidation: The consolidated financial statements include the accounts of Amerada Hess Corporation and entities in which the Corporation owns more than a 50% voting interest or entities that the Corporation controls. The Corporation’s undivided interests in unincorporated oil and gas exploration and production ventures are proportionately consolidated.

Investments in affiliated companies, 20% to 50% owned, including HOVENSA but excluding a trading partnership, are stated at cost of acquisition plus the Corporation’s equity in undistributed net income since acquisition. The change in the equity in net income of these companies is included in non-operating income in the income statement. The Corporation consolidates the trading partnership in which it owns a 50% voting interest and over which it exercises control.

Intercompany transactions and accounts are eliminated in consolidation.

Revenue Recognition: The Corporation recognizes revenues from the sale of crude oil, natural gas, petroleum products and other merchandise when title passes to the customer.

The Corporation recognizes revenues from the production of natural gas properties in which it has an interest based on sales to customers. Differences between natural gas volumes sold and the Corporation’s share of natural gas production are not material.

Cash and Cash Equivalents: Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired.

Inventories: Crude oil and refined product inventories are valued at the lower of average cost or market. For inventories valued at cost, the Corporation uses principally the last-in, first-out (LIFO) inventory method.

Inventories of materials and supplies are valued at the lower of average cost or market.

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 and exploration expenses, including geological and geophysical 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

40


 

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.

Depreciation, Depletion and Amortization: The Corporation calculates depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production equipment and wells is calculated using the units of production method over proved developed oil and gas reserves. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives.

Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors.

Asset Retirement Obligations: The Corporation recognizes a liability for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement obligations are incurred. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets.

Retirement of Property, Plant and Equipment: Costs of property, plant and equipment retired or otherwise disposed of, less accumulated reserves, are reflected in non-operating income.

Impairment of Long-Lived Assets: The Corporation reviews long-lived assets, including oil and gas properties at a field level, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted future cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. In the case of oil and gas fields, the net present value of future 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 at year-end in the standardized measure of discounted future net cash flows.

Impairment of Equity Investees: The Corporation reviews equity method investments for impairment whenever events or changes in circumstances indicate that an other than temporary decline in value has occurred. The amount of the impairment is based on quoted market prices, where available, or other valuation techniques, including discounted cash flows.

Impairment of Goodwill: In accordance with FAS No. 142, Goodwill and Other Intangible Assets, goodwill cannot be amortized; however, it must be tested annually for impairment. This impairment test is calculated at the reporting unit level, which is the exploration and production segment for the Corporation’s goodwill. The Corporation identifies potential impairments by comparing the fair value of the reporting unit to its book value, including goodwill. If the fair value of the reporting unit exceeds the carrying amount, goodwill is not impaired. If the carrying value exceeds the fair value, the Corporation calculates the possible impairment loss by comparing the implied fair value of goodwill with the carrying amount. If the implied fair value of goodwill is less than the carrying amount, an impairment would be recorded.

Maintenance and Repairs: The estimated costs of major maintenance, including turnarounds at the Port Reading refining facility, are accrued. Other expenditures for maintenance and repairs are charged against income as incurred. Renewals and improvements are treated as additions to property, plant and equipment, and items replaced are treated as retirements.

Environmental Expenditures: The Corporation capitalizes environmental expenditures that increase the life or efficiency of property or that reduce or prevent environmental contamination. The Corporation accrues for environmental expenses resulting from existing conditions related to past operations when the future costs are probable and reasonably estimable.

41


 

Employee Stock Options and Nonvested Common Stock (Restricted Stock) Awards: The Corporation uses the intrinsic value method to account for employee stock options. Because the exercise prices of employee stock options equal or exceed the market price of the stock on the date of grant, the Corporation does not recognize compensation expense. The following pro forma financial information presents the effect on net income and earnings per share as if the Corporation used the fair value method. The Corporation records compensation expense for non-vested common stock awards ratably over the vesting period.

                         
Millions of dollars, except per share data
  2003
  2002
  2001
Net income (loss)
  $ 643     $ (218 )   $ 914  
Add stock-based employee compensation expense included in net income, net of taxes
    7       5       8  
Less total stock-based employee compensation expense determined using the fair value method, net of taxes
    (8 )     (19 )     (22 )
 
   
 
     
 
     
 
 
Pro forma net income (loss)
  $ 642     $ (232 )   $ 900  
 
   
 
     
 
     
 
 
Net income (loss) per share as reported
                       
Basic
  $ 7.19     $ (2.48 )   $ 10.38  
Diluted
    7.11       (2.48 )     10.25  
Pro forma net income (loss) per share
                       
Basic
  $ 7.19     $ (2.63 )   $ 10.23  
Diluted
    7.11       (2.63 )     10.10  

Foreign Currency Translation: The U.S. dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. For these operations, adjustments resulting from translating foreign currency assets and liabilities into U.S. dollars are recorded in income. For operations that use the local currency as the functional currency, adjustments resulting from translating foreign functional currency assets and liabilities into U.S. dollars are recorded in a separate component of stockholders’ equity entitled accumulated other comprehensive income. Gains or losses resulting from transactions in other than the functional currency are reflected in net income.

Hedging: The Corporation uses futures, forwards, options and swaps, individually or in combination, to reduce the effects of fluctuations in crude oil, natural gas and refined product selling prices. The Corporation also uses derivatives in its energy marketing activities to fix the purchase prices of commodities to be sold under fixed-price contracts. 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.

Trading: Derivatives (futures, forwards, options and swaps) used in energy trading activities are marked to market, with net gains and losses recorded in operating revenue. Gains or losses from the sale of physical products are recorded at the time of sale.

2. ITEMS AFFECTING INCOME FROM CONTINUING OPERATIONS

2003: The Corporation recorded a pre-tax charge of $58 million for premiums paid on the repurchase of bonds. This amount included premiums on bonds repurchased with proceeds of the fourth quarter preferred stock offering. The repurchased bonds included notes due in 2005 and 2007 assumed from Triton Energy at the time of the acquisition. This charge is reflected in non-operating income (expense) in the income statement.

The Corporation recorded expense of $53 million, before income taxes, for accrued severance and London office lease costs in exploration and production operations. Of this amount, $32 million relates to leased office space and the remainder relates to severance for positions that were eliminated in London, Aberdeen and Houston. Over 700 employee and contractor positions have been or will be eliminated or transferred to other operators. Approximately 240 employees are receiving severance, $15 million of which has been paid. The remainder is expected to be paid in 2004. The estimated annual savings from this cost reduction initiative is approximately $50 million before income taxes. The Corporation anticipates realizing

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approximately sixty percent of the savings in 2004 and the full amount in 2005 and beyond. The 2003 expense is reflected principally in general and administrative expense in the income statement.

Exploration and production earnings in 2003 include income tax benefits of $30 million reflecting the recognition of certain prior year foreign exploration expenses for United States income tax purposes. In addition, the Corporation recorded a pre-tax gain of $47 million from the sale of its 1.5% interest in the Trans-Alaska Pipeline System. A pre-tax loss of $9 million was recorded in refining and marketing earnings as a result of the sale of a shipping joint venture. Gains and losses on asset sales are reflected in non-operating income (expense) in the income statement.

2002: The Corporation recorded a pre-tax impairment charge of $706 million relating to the Ceiba field in Equatorial Guinea. The charge resulted from a reduction in probable reserves of approximately 12% of total field reserves, as well as the additional development costs of producing these reserves over a longer field life. Fair value was determined by discounting anticipated future net cash flows. Discounted cash flows were less than the book value of the field, which included allocated purchase price from the Triton acquisition. The Corporation also recorded a pre-tax impairment charge of $318 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. The pre-tax amounts of these charges were recorded in the caption asset impairments in the income statement.

During 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 pre-tax gain of $102 million. The Corporation has agreed to support the buyer’s charter rate for these vessels for up to five years. A pre-tax gain of $50 million was deferred as part of the sale transaction to reflect potential obligations of the support agreement. The support agreement requires that, if the actual contracted rate for the charter of a vessel is less than the stipulated charter rate in the agreement, the Corporation pays to the buyer the difference between the contracted rate and the stipulated rate. If the actual contracted rate exceeds the stipulated rate, the buyer must apply such amount to reimburse the Corporation for any payments made by the Corporation up to that date. At January 1, 2003, the charter support reserve was $48 million. During 2003, the Corporation paid $5 million of charter support. Based on contractual long-term charter rates and estimates of future charter rates, the Corporation lowered the estimated charter support reserve by $11 million. While the Corporation’s eventual obligations under the support agreement could exceed the amount of the deferred gain, based on current estimates, the remaining amount recorded at December 31, 2003, $32 million, is appropriate.

Pre-tax net gains of $41 million were recorded during 2002 from sales 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 sale of the six United States flag vessels related to the refining and marketing segment and the remaining 2002 asset sales related to exploration and production activities. The pre-tax amounts of these asset sales are recorded in non-operating income in the income statement.

The United Kingdom government enacted a 10% supplementary tax on profits from oil and gas production in 2002. As a result of this tax law change, the Corporation recorded a one-time provision for deferred taxes of $43 million to increase the deferred tax liability on its balance sheet.

In 2002, the Corporation recorded a pre-tax charge of $22 million for the write-off of intangible assets in its U.S. energy marketing business. In addition, accrued severance of $13 million was recorded for cost reduction initiatives in refining and marketing, principally in energy marketing. Approximately 165 positions were eliminated and an office was closed. The estimated annual savings from the staff reduction is $15 million before tax. The accrued severance was paid prior to December 31, 2003.

2001: The Corporation recorded a pre-tax charge of $29 million for estimated losses due to the bankruptcy of certain subsidiaries of Enron Corporation. The charge

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reflected losses on less than 10% of the Corporation’s crude oil and natural gas hedges.

The Corporation recorded a pre-tax charge of $18 million for severance expenses resulting from cost reduction initiatives, all of which has been paid. The cost reduction program reflected the elimination of approximately 150 positions, principally in exploration and production operations. Substantially all of the pre-tax cost of these items are reflected in general and administrative expense in the income statement.

3. DISCONTINUED OPERATIONS

In 2003, the Corporation took initiatives to reshape its portfolio of exploration and production assets to reduce costs, lengthen reserve lives, provide capital for investment and reduce debt.

In the first quarter of 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 natural gas reserves in the joint development area of Malaysia and Thailand. The exchange resulted in a charge to income of $51 million before income taxes, which the Corporation reported as a loss from discontinued operations in the first quarter of 2003. The loss on this exchange included a $43 million pre-tax adjustment of the book value of the Colombian assets to fair value resulting primarily from a revision in crude oil reserves. The loss also included a $26 million charge from the recognition in earnings of the value of related hedge contracts at the time of the exchange. These items were partially offset by pre-tax earnings of $18 million in Colombia prior to the exchange.

In this exchange transaction, the Corporation acquired the 50% interest in a corporate joint venture that it did not already own. Prior to the exchange, the Corporation accounted for its 50% interest in the corporate joint venture using the equity method. Because of the exchange, the joint venture became a wholly owned subsidiary. Consequently, the Corporation has consolidated this subsidiary, which holds a 50% interest in a production sharing contract with natural gas reserves in the joint development area of Malaysia and Thailand. At the time of the exchange, the exploration and production segment included the net book value of fixed assets in Colombia of $670 million ($685 million at December 31, 2002) and a related deferred income tax liability of $142 million ($145 million at December 31, 2002).

In the second quarter of 2003, the Corporation sold producing properties in the Gulf of Mexico shelf, the Jabung Field in Indonesia and several small United Kingdom fields. The aggregate proceeds from these sales were $445 million and the pre-tax gain from disposition was $248 million. With respect to the assets sold in the second quarter of 2003, the net book value of fixed assets at the time of sale was approximately $295 million ($275 million at December 31, 2002) and the related dismantlement and deferred tax liabilities were approximately $160 million ($170 million at December 31, 2002).

Sales and other operating revenues (net of intercompany sales) from discontinued operations were $97 million in 2003, $381 million in 2002 and $361 million in 2001. Pretax operating profit for the same periods was $82 million, $14 million and $120 million, respectively. Income tax expense (benefit) was $29 million, $(13) million and $22 million for the same periods. The net production from fields accounted for as discontinued operations in 2003 at the time of disposition was approximately 45,000 barrels of oil equivalent per day.

4. ACCOUNTING CHANGE

On January 1, 2003, the Corporation changed its method of accounting for asset retirement obligations as required by FAS No. 143, Accounting for Asset Retirement Obligations. Previously, the Corporation had accrued the estimated costs of dismantlement, restoration and abandonment, less estimated salvage values, of offshore oil and gas production platforms and pipelines using the units-of-production method. This cost was reported as a component of depreciation expense and accumulated depreciation. Using the new accounting method required by FAS No. 143, the Corporation now recognizes a liability for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement obligations are incurred. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets.

The cumulative effect of this change on prior years resulted in a credit to income of $7 million or $.07 per share, basic and diluted. The cumulative effect is included in income for the year ended December 31, 2003. The effect of the change on the year 2003 was to increase income before the cumulative effect of the accounting change by $3 million, after-

44


 

tax ($.03 per share diluted). Assuming the accounting change had been applied retroactively to January 1, 2001 (rather than January 1, 2003), there would not have been a material change in income from continuing operations and net income in 2002 and 2001.

The following table describes changes to the Corporation’s asset retirement obligations:

         
Millions of dollars
  2003
Asset retirement obligations at
       
January 1
  $ 556  
Liabilities incurred
    15  
Liabilities settled or disposed of
    (173 )
Accretion expense
    28  
Revisions
    25  
Foreign currency translation
    11  
 
   
 
 
Asset retirement obligations at
       
December 31
  $ 462  
 
   
 
 

If FAS No. 143 had been applied beginning January 1, 2002 (rather than at January 1, 2003), the pro forma liability for asset retirement obligations at that date would have been $537 million.

The Corporation has adopted Emerging Issues Task Force abstract 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. In accordance with EITF 02-3, the Corporation began accounting for trading inventory purchased after October 25, 2002 at the lower of cost or market. Inventory purchased prior to this date was marked-to-market with changes reflected in income currently. Beginning January 1, 2003, the Corporation accounted for all trading inventory at the lower of cost or market. This accounting change did not have a material effect on the Corporation’s income or financial position.

The oil and gas industry is currently discussing the appropriate balance sheet classification of oil and gas mineral rights held by lease or contract. The Corporation classifies these assets as property, plant and equipment in accordance with its interpretation of FAS No. 19 and common industry practice. There is also a view that these mineral rights are intangible assets as defined in FAS No. 141, Business Combinations, and, therefore, should be classified separately on the balance sheet as intangible assets. If the accounting for mineral rights held by lease or contract is ultimately changed, the Corporation believes that any such reclassification of mineral rights could amount to approximately $2.3 billion at December 31, 2003, and $2.2 billion at December 31, 2002, if the Corporation is required to include the purchase price allocated to hydrocarbon reserves obtained in acquisitions of oil and gas properties. The determination of this amount is based on the Corporation’s current understanding of this evolving issue and how the provisions of FAS No. 141 might be applied to oil and gas mineral rights. If mineral rights are reclassified to intangible assets, FAS No. 142, Goodwill and Other Intangible Assets, will require additional disclosures in the financial statement footnotes. This potential balance sheet reclassification would not affect results of operations or cash flows.

5. ACQUISITION OF TRITON ENERGY LIMITED

In 2001, the Corporation acquired 100% of the outstanding ordinary shares of Triton Energy Limited, an international oil and gas exploration and production company. The Corporation’s consolidated financial statements include Triton’s results of operations from August 14, 2001. The purchase price resulted in the recognition of goodwill of $977 million. 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. The goodwill is assigned to the exploration and production reporting unit and is not deductible for income tax purposes.

The following 2001 pro forma results of operations present information as if the Triton acquisition occurred at the beginning of 2001:

         
Millions of dollars, except per share data
       
Pro forma revenue
  $ 13,936  
Pro forma income
  $ 914  
Pro forma earnings per share
       
Basic
  $ 10.38  
Diluted
  $ 10.25  

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6. INVENTORIES

Inventories at December 31 are as follows:

                 
Millions of dollars
  2003
  2002
Crude oil and other charge stocks
  $ 138     $ 99  
Refined and other finished products
    567       497  
Less: LIFO adjustment
    (293 )     (261 )
 
   
 
     
 
 
 
    412       335  
Materials and supplies
    167       157  
 
   
 
     
 
 
Total
  $ 579     $ 492  
 
   
 
     
 
 

7. REFINING JOINT VENTURE

The Corporation has an investment in HOVENSA L.L.C., a 50% joint venture with Petroleos de Venezuela, S.A. (PDVSA). HOVENSA owns and operates a refinery in the Virgin Islands, previously wholly-owned by the Corporation.

The Corporation accounts for its investment in HOVENSA using the equity method. Summarized financial information for HOVENSA as of December 31, 2003, 2002 and 2001 and for the years then ended follows:

                         
Millions of dollars
  2003
  2002
  2001
Summarized Balance Sheet
                       
At December 31
                       
Cash and cash equivalents
  $ 341     $ 11     $ 25  
Other current assets
    541       509       466  
Net fixed assets
    1,818       1,895       1,846  
Other assets
    37       40       35  
Current liabilities
    (441 )     (335 )     (294 )
Long-term debt
    (392 )     (467 )     (365 )
Deferred liabilities and credits
    (56 )     (45 )     (23 )
 
   
 
     
 
     
 
 
Partners’ equity
  $ 1,848     $ 1,608     $ 1,690  
 
   
 
     
 
     
 
 
Summarized Income Statement
                       
For the years ended December 31
                       
Total revenues
  $ 5,451     $ 3,783     $ 4,209  
Costs and expenses
    (5,212 )     (3,872 )     (4,089 )
 
   
 
     
 
     
 
 
Net income (loss)*
  $ 239     $ (89 )   $ 120  
 
   
 
     
 
     
 
 

*The Corporation’s share of HOVENSA’s income was $117 million in 2003 and $58 million in 2001. The Corporation’s share of the 2002 loss was $47 million. The Corporation’s share of HOVENSA’s undistributed income aggregated $240 million at December 31, 2003.

The Corporation has agreed to purchase 50% of HOVENSA’s production of refined products at market prices, after sales by HOVENSA to unaffiliated parties. Such purchases amounted to approximately $2,040 million during 2003, $1,280 million during 2002 and $1,500 million during 2001. The Corporation sold crude oil to HOVENSA for approximately $410 million during 2003, $80 million during 2002 and $110 million during 2001. In addition, the Corporation billed HOVENSA freight charter costs of $59 million during 2003, $20 million during 2002 and $55 million during 2001.

The Corporation guarantees the payment of up to 50% of the value of HOVENSA’s crude oil purchases from suppliers other than PDVSA. At December 31, 2003, this amount was $134 million. This amount fluctuates based on the volume of crude oil purchased and the related crude oil prices. In addition, the Corporation has agreed to provide funding to the extent HOVENSA does not have funds to meet its senior debt obligations up to a maximum of $40 million.

At formation of the joint venture, PDVSA V.I., a wholly-owned subsidiary of PDVSA, purchased a 50% interest in the fixed assets of the Corporation’s Virgin Islands refinery for $62.5 million in cash and a 10-year note from PDVSA V.I. for $562.5 million bearing interest at 8.46% per annum and requiring principal payments over its term. At December 31, 2003 and December 31, 2002, the principal balance of the note was $334 million and $395 million, respectively.

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consists of the following:

                 
Millions of dollars
  2003
  2002
Exploration and production
               
Unproved properties
  $ 950     $ 1,020  
Proved properties
    2,634       2,843  
Wells, equipment and related facilities
    11,030       10,836  
Refining and marketing
    1,486       1,450  
 
   
 
     
 
 
Total — at cost
    16,100       16,149  
Less reserves for depreciation, depletion, amortization and lease impairment
    8,122       9,117  
 
   
 
     
 
 
Property, plant and equipment, net
  $ 7,978     $ 7,032  
 
   
 
     
 
 

During 2003, the Corporation recorded non-cash additions to fixed assets of $1,340 million. Of this total, $485 million related to assets that were previously accounted for as an equity investment in a company that holds natural gas

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reserves in Malaysia and Thailand. The remaining $855 million resulted from asset exchanges. The Corporation also recorded deferred income tax liabilities of $105 million related to the asset exchanges. The assets and liabilities relinquished in these exchanges included fixed assets of approximately $770 million, an additional equity investment of $145 million and deferred income tax liabilities of $145 million.

9. SHORT-TERM NOTES AND RELATED LINES OF CREDIT

The Corporation has no short-term notes at December 31, 2003. Short-term notes payable to banks at December 31, 2002 amounted to $2 million, bearing interest at a weighted average rate of 1.4%. At December 31, 2003, the Corporation has uncommitted arrangements with banks for unused lines of credit aggregating $206 million.

10. LONG-TERM DEBT

Long-term debt at December 31 consists of the following:

                 
Millions of dollars
  2003
  2002
Fixed rate debentures, weighted average rate 7.2%, due through 2033
  $ 3,222     $ 4,237  
Pollution Control Revenue Bonds, weighted average rate 6.5%, due through 2032
    53       53  
Fixed rate notes, payable principally to insurance companies, weighted average rate 8.4%, due through 2014
    450       450  
Project lease financing, weighted average rate 5.1%, due through 2014
    164       169  
Capitalized lease obligations, weighted average rate 6.4%, due through 2009
    48       56  
6.1% Marine Terminal Revenue Bonds—Series 1994— City of Valdez, Alaska
          20  
Other loans, weighted average rate 9.3%, due through 2019
    4       5  
 
   
 
     
 
 
 
    3,941       4,990  
Less amount included in current maturities
    73       14  
 
   
 
     
 
 
Total
  $ 3,868     $ 4,976  
 
   
 
     
 
 

The aggregate long-term debt maturing during the next five years is as follows (in millions): 2004—$73 (included in current liabilities); 2005—$60; 2006—$88; 2007—$212 and 2008—$129.

The Corporation’s long-term debt agreements contain restrictions on the amount of total borrowings and cash dividends allowed. At December 31, 2003, the Corporation is permitted to borrow an additional $5 billion for the construction or acquisition of assets. At year-end, the amount that can be borrowed for the payment of dividends is $1.9 billion.

During 2003, the Corporation repurchased $1,015 million of fixed rate debentures consisting of most of the Corporation’s 5.3% and 5.9% notes due in 2004 and 2006, respectively, as well as notes due in 2005 and 2007 assumed from Triton at the time of the acquisition. At December 31, 2003, the Corporation’s public fixed rate debentures have a face value of $3,237 million ($3,222 million net of unamortized discount). Borrowings are due commencing in 2004 and extend through 2033. Interest rates on the debentures range from 5.3% to 7.9% and have a weighted average rate of 7.2%.

In connection with the sale of the Corporation’s interest in the Trans Alaska Pipeline in January 2003, $20 million of Marine Terminal Revenue Bonds were assumed by the purchaser.

The Corporation has a $1.5 billion revolving credit agreement, which was unutilized at December 31, 2003 and expires in January 2006. Because of a credit downgrade in February 2004, borrowings under the facility currently would bear interest at 1.125% above the London Interbank Offered Rate. A facility fee of .375% per annum is currently payable on the amount of the credit line. At December 31, 2003, the interest rate was .725% above the London Interbank Offered Rate and the facility fee was .15%.

In 2003, 2002 and 2001, the Corporation capitalized interest of $41 million, $101 million and $44 million, respectively, on major development projects. The total amount of interest paid (net of amounts capitalized), principally on short-term and long-term debt, in 2003, 2002 and 2001 was $313 million, $274 million and $121 million, respectively.

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11. STOCK BASED COMPENSATION PLANS

The Corporation has outstanding stock options and non-vested common stock (restricted stock) under its Amended and Restated 1995 Long-Term Incentive Plan. Generally, stock options vest one year from the date of grant and the exercise price equals or exceeds the market price on the date of grant. Outstanding nonvested common stock generally vests five years from the date of grant.

The Corporation’s stock option activity in 2003, 2002 and 2001 consisted of the following:

                 
            Weighted-
            average
    Options   exercise price
    (thousands)
  per share
Outstanding at January 1, 2001
    4,295     $ 57.47  
Granted
    1,674       60.91  
Exercised
    (1,053 )     56.28  
Forfeited
    (42 )     61.79  
 
   
 
     
 
 
Outstanding at December 31, 2001
    4,874       58.87  
Granted
    46       66.45  
Exercised
    (492 )     57.81  
Forfeited
    (53 )     59.79  
 
   
 
     
 
 
Outstanding at December 31, 2002
    4,375       59.06  
Granted
    65       47.07  
Forfeited
    (283 )     64.08  
 
   
 
     
 
 
Outstanding at December 31, 2003
    4,157     $ 58.54  
 
   
 
     
 
 
Exercisable at December 31, 2001
    3,216     $ 57.85  
Exercisable at December 31, 2002
    4,329       58.99  
Exercisable at December 31, 2003
    4,092       58.72  
 
   
 
     
 
 

Exercise prices for employee stock options at December 31, 2003 ranged from $45.76 to $84.61 per share. The weighted-average remaining contractual life of employee stock options is 6 years.

The Corporation uses the Black-Scholes model to estimate the fair value of employee stock options for pro forma disclosure of the effects on net income and earnings per share. The Corporation used the following weighted-average assumptions in the Black-Scholes model for 2003, 2002 and 2001, respectively: risk-free interest rates of 3.6%, 4.2% and 4.1%; expected stock price volatility of .288, .262 and .244; dividend yield of 2.6%, 1.9% and 2.0%; and an expected life of seven years. The Corporation’s net income would have been reduced by approximately $1 million in 2003 and $14 million in 2002 and 2001 if option expenses were recorded using the fair value method.

The weighted-average fair value per share of options granted for which the exercise price equaled the market price on the date of grant were $12.60 in 2003, $19.63 in 2002 and $16.20 in 2001.

Total compensation expense for nonvested common stock was $11 million in 2003, $7 million in 2002 and $12 million in 2001. Awards of nonvested common stock were as follows:

                 
    Shares of    
    nonvested   Weighted-
    common stock   average
    awarded   price on date
    (thousands)
  of grant
Granted in 2001
    108     $ 67.25  
Granted in 2002
    21       66.29  
Granted in 2003
    765       46.73  
 
   
 
     
 
 

At December 31, 2003, the number of common shares reserved for issuance under the 1995 Long-Term Incentive Plan is as follows (in thousands):

         
Future awards
    479  
Stock options outstanding
    4,157  
Stock appreciation rights
    4  
 
   
 
 
Total
    4,640  
 
   
 
 

12. FOREIGN CURRENCY TRANSLATION

Foreign currency gains (losses) from continuing operations before income taxes amounted to $(6) million in 2003, $26 million in 2002 and $(22) million in 2001.

The balances in accumulated other comprehensive income related to foreign currency translation were reductions in stockholders’ equity of $94 million at December 31, 2003 and $107 million at December 31, 2002.

13. PENSION PLANS

The Corporation has funded noncontributory defined benefit pension plans for substantially all of its employees. In addition, the Corporation has an unfunded supplemental pension plan covering certain employees. The unfunded supplemental pension plan provides for incremental

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pension payments from the Corporation’s funds so that total pension payments equal amounts that would have been payable from the Corporation’s principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary. The Corporation uses December 31 as the measurement date for its plans.

The following table reconciles the projected benefit obligation and the fair value of plan assets and shows the funded status of the pension plans:

                                 
    Funded   Unfunded
    Pension Benefits
  Pension Benefits
Millions of dollars
  2003
  2002
  2003
  2002
Reconciliation of projected benefit obligation
                               
Balance at January 1
  $ 721     $ 623     $ 61     $ 59  
Service cost
    24       23       3       2  
Interest cost
    47       44       4       4  
Amendments
                      4  
Actuarial loss
    57       60       3       1  
Benefit payments
    (32 )     (29 )     (6 )     (9 )
 
   
 
     
 
     
 
     
 
 
Balance at December 31
    817       721       65       61  
 
   
 
     
 
     
 
     
 
 
Reconciliation of fair value of plan assets
                               
Balance at January 1
    487       495              
Actual return on plan assets
    104       (42 )            
Employer contributions
    67       63       6       9  
Benefit payments
    (32 )     (29 )     (6 )     (9 )
 
   
 
     
 
     
 
     
 
 
Balance at December 31
    626       487              
 
   
 
     
 
     
 
     
 
 
Funded status (plan assets less than benefit obligations)
    (191 )     (234 )     (65) *     (61) *
Unrecognized net actuarial loss
    190       214       18       15  
Unrecognized prior service cost
    3       5       3       3  
 
   
 
     
 
     
 
     
 
 
Net amount recognized
  $ 2     $ (15 )   $ (44 )   $ (43 )
 
   
 
     
 
     
 
     
 
 

*The trust established by the Corporation to fund the supplemental plan held assets valued at $40 million at December 31, 2003 and $26 million at December 31, 2002.

Amounts recognized in the consolidated balance sheet at December 31 consist of the following:

                                 
    Funded   Unfunded
    Pension Benefits
  Pension Benefits
Millions of dollars
  2003
  2002
  2003
  2002
Accrued benefit liability
  $ (106 )   $ (130 )   $ (53 )   $ (44 )
Intangible assets
    3       5       3       1  
Accumulated other comprehensive income*
    105       110       6        
 
   
 
     
 
     
 
     
 
 
Net amount recognized
  $ 2     $ (15 )   $ (44 )   $ (43 )
 
   
 
     
 
     
 
     
 
 

*Amount included in other comprehensive income after income taxes was $73 million at December 31, 2003 and $72 million at December 31, 2002.

The accumulated benefit obligation for the funded defined benefit pension plans was $733 million at December 31, 2003 and $639 million at December 31, 2002. The accumulated benefit obligation for the unfunded defined benefit pension plan was $53 million at December 31, 2003 and $44 million at December 31, 2002.

All pension plans had accumulated benefit obligations in excess of plan assets at December 31, 2003 and 2002.

Components of funded and unfunded pension expense consisted of the following:

                         
Millions of dollars
  2003
  2002
  2001
Service cost
  $ 27     $ 25     $ 21  
Interest cost
    51       49       45  
Expected return on plan assets
    (44 )     (44 )     (48 )
Amortization of prior service cost
    2       2       3  
Amortization of net loss
    19       5       1  
 
   
 
     
 
     
 
 
Net periodic benefit cost
  $ 55     $ 37     $ 22  
 
   
 
     
 
     
 
 
Increase in minimum liability included in other comprehensive income
  $ 1     $ 110     $  
 
   
 
     
 
     
 
 

49


 

Prior service costs and gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees.

The weighted-average actuarial assumptions used by the Corporation’s funded and unfunded pension plans were as follows:

                         
    2003
  2002
  2001
Weighted-average assumptions used to determine benefit obligations at December 31
                       
Discount rate
    6.2 %     6.6 %     7.0 %
Rate of compensation increase
    4.5       4.4       4.5  
Weighted-average assumptions used to determine net cost for years ended December 31
                       
Discount rate
    6.6 %     7.0 %     7.0 %
Expected return on plan assets
    8.5       9.0       9.0  
Rate of compensation increase
    4.4       4.5       4.5  
 
   
 
     
 
     
 
 

The assumed long-term rate of return on assets is based on historical, long-term returns of the plan, adjusted downward to reflect lower prevailing interest rates. The assumed long-term rate of return is less than the actual return for the year ended December 31, 2003.

The Corporation’s funded pension plan assets by asset category are as follows:

                 
    At December 31
Asset Category
  2003
  2002
Equity securities
    57 %     57 %
Debt securities
    43       43  
 
   
 
     
 
 
Total
    100 %     100 %
 
   
 
     
 
 

The target investment allocations for the plan assets are 55% equity securities and 45% debt securities. Asset allocations are rebalanced on a regular basis throughout the year to bring assets to within a 2—3% range of target levels. Target allocations take into account analyses performed to optimize long term risk and return relationships. All assets are highly liquid and can be readily adjusted to provide liquidity for current benefit payment requirements.

The Corporation has budgeted contributions of $82 million to its funded pension plans in 2004. The Corporation also has budgeted contributions of $20 million to the trust established for the unfunded plan.

Estimated future pension benefit payments for the funded and unfunded plans, which reflect expected future service, are as follows:

         
Millions of dollars
       
2004
  $ 43  
2005
    38  
2006
    39  
2007
    41  
2008
    43  
Years 2009 to 2013
    258  
 
   
 
 

50


 

14. PROVISION FOR INCOME TAXES

The provision for income taxes on income from continuing operations consisted of:

                         
Millions of dollars
  2003
  2002
  2001
United States Federal
                       
Current
  $ (180 )   $ 30     $ 57  
Deferred
    78       (158 )     50  
State
    (13 )     5       27  
 
   
 
     
 
     
 
 
 
    (115 )     (123 )     134  
 
   
 
     
 
     
 
 
Foreign
                       
Current
    431       401       355  
Deferred
    (2 )     (141 )     13  
 
   
 
     
 
     
 
 
 
    429       260       368  
 
   
 
     
 
     
 
 
Adjustment of deferred tax liability for foreign income tax rate change
          43        
 
   
 
     
 
     
 
 
Total provision for income taxes on continuing operations
  $ 314 (a)   $ 180     $ 502 (b)
 
   
 
     
 
     
 
 


(a)   Includes benefit of $30 million relating to certain prior year foreign exploration expenses.
 
(b)   Includes benefit of $48 million relating to prior year refunds of United Kingdom Advance Corporation Taxes and deductions for exploratory drilling.

Income (loss) from continuing operations before income taxes consisted of the following:

                         
Millions of dollars
  2003
  2002
  2001
United States
  $ (245 )(a)   $ (378 )   $ 330  
Foreign(b)
    1,026       313       988  
 
   
 
     
 
     
 
 
Total income from continuing operations
  $ 781     $ (65 )   $ 1,318  
 
   
 
     
 
     
 
 


(a)   Includes substantially all of the Corporation’s interest expense and the results of hedging activities.
 
(b)   Foreign income includes the Corporation’s Virgin Islands, shipping and other operations located outside of the United States.

Deferred income taxes arise from temporary differences between the tax bases of assets and liabilities and their recorded amounts in the financial statements. A summary of the components of deferred tax liabilities and assets at December 31 follows:

                 
Millions of dollars
  2003
  2002
Deferred tax liabilities
               
Fixed assets and investments
  $ 1,391     $ 943  
Foreign petroleum taxes
    281       256  
Other
    226       138  
 
   
 
     
 
 
Total deferred tax liabilities
    1,898       1,337  
 
   
 
     
 
 
Deferred tax assets
               
Accrued liabilities
    209       124  
Dismantlement liability
    169        
Net operating loss carryforwards
    551       543  
Tax credit carryforwards
    155       61  
Other
    64       33  
 
   
 
     
 
 
Total deferred tax assets
    1,148       761  
Valuation allowance
    (93 )     (95 )
 
   
 
     
 
 
Net deferred tax assets
    1,055       666  
 
   
 
     
 
 
Net deferred tax liabilities
  $ 843     $ 671  
 
   
 
     
 
 

The difference between the Corporation’s effective income tax rate and the United States statutory rate is reconciled below:

                         
    2003
  2002
  2001
United States statutory rate
    35.0 %     (35.0 )%     35.0 %
Effect of foreign operations, including foreign tax credits
    4.6       321.5 *     2.8  
Loss on repurchase of bonds
    (.6 )     (15.4 )      
State income taxes, net of Federal income tax benefit
    (1.1 )     8.1       1.3  
Prior year adjustments
    2.8       (1.5 )     (1.5 )
Other
    (.4 )     (.1 )     .5  
 
   
 
     
 
     
 
 
Total
    40.3 %     277.6 %     38.1 %
 
   
 
     
 
     
 
 

*Reflects high effective tax rates in certain foreign jurisdictions, including special taxes in the United Kingdom and Norway, and losses in other jurisdictions which were benefited at lower rates.

51


 

The Corporation has not recorded deferred income taxes applicable to undistributed earnings of foreign subsidiaries that are expected to be indefinitely reinvested in foreign operations. Undistributed earnings amounted to approximately $2.6 billion at December 31, 2003 and include amounts which, if remitted, would result in U.S. income taxes at less than the statutory rate, because of available foreign tax credits. If the earnings of such foreign subsidiaries were not indefinitely reinvested, a deferred tax liability of approximately $100 million would have been required.

For income tax reporting at December 31, 2003, the Corporation has alternative minimum tax credit carryforwards of approximately $120 million, which can be carried forward indefinitely. The Corporation also has approximately $35 million of general business credits. At December 31, 2003, the Corporation has a net operating loss carryforward in the United States of approximately $450 million. At December 31, 2003, a net operating loss carryforward of approximately $500 million is also available to offset the Corporation’s share of HOVENSA joint venture income and to reduce taxes on interest from the PDVSA note. In addition, a foreign exploration and production subsidiary has a net operating loss carryforward of approximately $550 million.

Income taxes paid (net of refunds) in 2003, 2002 and 2001 amounted to $361 million, $410 million and $605 million, respectively.

15. STOCKHOLDERS’ EQUITY AND NET INCOME PER SHARE

The weighted average number of common shares used in the basic and diluted earnings per share computations for each year are summarized below:

                         
Thousands of shares
  2003
  2002
  2001
Common shares—basic
    88,618       88,187       88,031  
Effect of dilutive securities
                       
Convertible preferred stock
    1,425             205  
Nonvested common stock
    290             425  
Stock options
    9             468  
 
   
 
     
 
     
 
 
Common shares—diluted
    90,342       88,187       89,129  
 
   
 
     
 
     
 
 

The table above excludes the effect of out-of-the-money options on 4,170,000 shares, 633,000 shares and 139,000 shares in 2003, 2002 and 2001, respectively. In 2002, the table also excludes the antidilutive effect of 461,000 non-vested common shares, 424,000 stock options and 205,000 shares of convertible preferred stock.

Earnings per share are as follows:

                         
    2003
  2002
  2001
Basic
                       
Continuing operations
  $ 5.21     $ (2.78 )   $ 9.26  
Discontinued operations
    1.91       .30       1.12  
Cumulative effect of change in accounting
    .07              
 
   
 
     
 
     
 
 
Net income (loss)
  $ 7.19     $ (2.48 )   $ 10.38  
 
   
 
     
 
     
 
 
Diluted
                       
Continuing operations
  $ 5.17     $ (2.78 )   $ 9.15  
Discontinued operations
    1.87       .30       1.10  
Cumulative effect of change in accounting
    .07              
 
   
 
     
 
     
 
 
Net income (loss)
  $ 7.11     $ (2.48 )   $ 10.25  
 
   
 
     
 
     
 
 

In 2003, the Corporation issued 13,500,000 shares of 7% cumulative mandatory convertible preferred stock. Dividends are payable on March 1, June 1, September 1 and December 1 of each year. The cumulative mandatory convertible preferred shares have a liquidation preference of $675 million ($50 per share). Each cumulative mandatory convertible preferred share will automatically convert on December 1, 2006 into .8305 to 1.0299 shares of common stock, depending on the average closing price of the Corporation’s common stock over a 20-day period before conversion. The Corporation has reserved 13,903,650 shares of common stock for the conversion of these preferred shares. Holders of the cumulative mandatory convertible preferred stock have the right to convert their shares at any time prior to December 1, 2006 at the rate of .8305 share of common stock for each preferred share converted. The cumulative mandatory convertible preferred shares do not have voting rights, except in certain limited circumstances.

52


 

16. LEASED ASSETS

The Corporation and certain of its subsidiaries lease gasoline stations, tankers, floating production systems, drilling rigs, office space and other assets for varying periods. At December 31, 2003, future minimum rental payments applicable to noncancelable leases with remaining terms of one year or more (other than oil and gas property leases) are as follows:

                 
    Operating   Capital
Millions of dollars
  Leases
  Leases
2004
  $ 95     $ 13  
2005
    71       13  
2006
    71       13  
2007
    71       13  
2008
    71       2  
Remaining years
    924       1  
 
   
 
     
 
 
Total minimum lease payments
    1,303       55  
Less: Imputed interest
          7  
Income from subleases
    36        
 
   
 
     
 
 
Net minimum lease payments
  $ 1,267     $ 48  
 
   
 
     
 
 
Capitalized lease obligations
               
Current
          $ 10  
Long-term
            38  
 
           
 
 
Total
          $ 48  
 
           
 
 

Certain operating leases provide an option to purchase the related property at fixed prices.

Rental expense for all operating leases, other than rentals applicable to oil and gas property leases, was as follows:

                         
Millions of dollars
  2003
  2002
  2001
Total rental expense
  $ 190     $ 160     $ 206  
Less income from subleases
    52       34       63  
 
   
 
     
 
     
 
 
Net rental expense
  $ 138     $ 126     $ 143  
 
   
 
     
 
     
 
 

17. FINANCIAL INSTRUMENTS, NON-TRADING AND TRADING ACTIVITIES

On January 1, 2001, the Corporation adopted FAS No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement requires that the Corporation recognize all derivatives on the balance sheet at fair value and establishes criteria for using derivatives as hedges.

The January 1, 2001 transition adjustment resulting from adopting FAS No. 133 was a cumulative increase in other comprehensive income of $100 million after income taxes ($145 million before income taxes). Substantially all of the transition adjustment resulted from crude oil and natural gas cash flow hedges. The transition adjustment did not have a material effect on net income or retained earnings.

Non-Trading: The Corporation uses futures, forwards, options and swaps, individually or in combination, to reduce the effects of fluctuations in crude oil, natural gas and refined product selling prices. The Corporation also uses derivatives in its energy marketing activities to fix the purchase prices of commodities to be sold under fixed-price contracts. 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 other comprehensive income until the hedged transactions are recognized. The Corporation’s use of fair value hedges is not material.

The Corporation reclassifies hedging gains and losses from accumulated other comprehensive income to earnings at the time the hedged transactions are recognized. Hedging decreased exploration and production results by $418 million before income taxes in 2003. Hedging increased exploration and production results before income taxes by $82 million in 2002 and $106 million in 2001 (including $82 million associated with the transition adjustment at the beginning of 2001). The ineffective portion of hedges is included in current earnings in cost of products sold. The amount of hedge ineffectiveness was not material during the years ended December 31, 2003, 2002 and 2001.

53


 

The Corporation produced 95 million barrels of crude oil and natural gas liquids and 249 million Mcf of natural gas in 2003. The Corporation’s crude oil and natural gas hedging activities included commodity futures and swap contracts. At December 31, 2003, crude oil hedges maturing in 2004 and 2005 cover 93 million barrels of crude oil production (91 million barrels of crude oil at December 31, 2002). The Corporation has natural gas hedges maturing in 2004 covering 18 million Mcf of natural gas production in the United States at December 31, 2003 (35 million Mcf of natural gas at December 31, 2002).

Since the contracts described above are designated as hedges and correlate to price movements of crude oil and natural gas, any gains or losses resulting from market changes will be offset by losses or gains on the Corporation’s production. At December 31, 2003, net after tax deferred losses in accumulated other comprehensive income from the Corporation’s crude oil and natural gas hedging contracts expiring through 2005 were $229 million ($352 million before income taxes), including $196 million of unrealized losses. Of the net after tax deferred loss, $185 million matures during 2004. At December 31, 2002, net after-tax deferred losses were $91 million ($141 million before income taxes), including $71 million of unrealized losses.

In its energy marketing business, the Corporation has entered into cash flow hedges to fix the purchase prices of natural gas, heating oil, residual fuel oil and electricity. At December 31, 2003, the net after tax deferred gains in accumulated other comprehensive income from these contracts, expiring through 2007, were $45 million ($70 million before income taxes). Substantially all of the deferred gains will be recognized in 2004.

Commodity Trading: The Corporation, principally through a consolidated partnership, trades energy commodities, including futures, forwards, options and swaps, based on expectations of future market conditions. The Corporation’s income before income taxes from trading activities, including its share of the earnings of the trading partnership amounted to $30 million in 2003, $6 million in 2002 and $72 million in 2001.

Other Financial Instruments: Foreign currency contracts are used to protect the Corporation from fluctuations in exchange rates. The Corporation enters into foreign currency contracts, which are not designated as hedges, and the change in fair value is included in income currently. The Corporation has $384 million of notional value foreign currency forward contracts maturing in 2004 and 2005 ($307 million at December 31, 2002). Notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts. The fair values of the foreign currency forward contracts recorded by the Corporation were receivables of $40 million at December 31, 2003 and $18 million at December 31, 2002.

The Corporation also has $229 million in letters of credit outstanding at December 31, 2003 ($149 million at December 31, 2002). Of the total letters of credit outstanding at December 31, 2003, $7 million represents contingent liabilities; the remaining $222 million relates to liabilities recorded on the balance sheet.

Fair Value Disclosure: The Corporation estimates the fair value of its fixed-rate notes receivable and debt generally using discounted cash flow analysis based on current interest rates for instruments with similar maturities. Foreign currency exchange contracts are valued based on current termination values or quoted market prices of comparable contracts. The Corporation’s valuation of commodity contracts considers quoted market prices where applicable. In the absence of quoted market prices, the Corporation values contracts at fair value considering time value, volatility of the underlying commodities and other factors.

The following table presents the year-end fair values of energy commodities and derivative financial instruments used in non-trading and trading activities:

                 
    Fair Value
    At Dec. 31
Millions of dollars,        
asset (liability)
  2003
  2002
Commodities
  $     $ 27  
Futures and forwards
               
Assets
    219       370  
Liabilities
    (218 )     (378 )
Options
               
Held
    975       65  
Written
    (948 )     (27 )
Swaps
               
Assets
    1,157       1,323  
Liabilities
    (1,384 )     (1,394 )
 
   
 
     
 
 

54


 

The carrying amounts of the Corporation’s financial instruments and commodity contracts, including those used in the Corporation’s non-trading and trading activities, generally approximate their fair values at December 31, 2003 and 2002, except as follows:

                                 
    2003
  2002
    Balance           Balance    
Millions of dollars,   Sheet   Fair   Sheet   Fair
asset (liability)
  Amount
  Value
  Amount
  Value
Fixed-rate notes receivable
  $ 363     $ 355     $ 424     $ 364  
Fixed-rate debt
    (3,935 )     (4,434 )     (4,984 )     (5,561 )
 
   
 
     
 
     
 
     
 
 

Credit Risks: The Corporation’s financial instruments expose it to credit risks and may at times be concentrated with certain counterparties or groups of counterparties. The credit worthiness of counterparties is subject to continuing review and full performance is anticipated. The Corporation reduces its risk related to certain counterparties by using master netting agreements and requiring collateral, generally cash.

In its trading activities the Corporation has net receivables of $351 million at December 31, 2003, which are concentrated with counterparties as follows: domestic and foreign trading companies — 25%, gas and power companies — 25%, banks and major financial institutions — 22%, government entities —15% and integrated energy companies — 7%.

18. GUARANTEES AND CONTINGENCIES

In the normal course of business, the Corporation provides guarantees principally for investees of the Corporation. These guarantees are contingent commitments that ensure performance for repayment of borrowings and other arrangements. The maximum potential amount of future payments that the Corporation could be required to make under its guarantees at December 31, 2003 is $99 million ($358 million at December 31, 2002). This amount includes the Corporation’s guarantee of $40 million of the senior debt obligation of HOVENSA (see note 7). The remainder relates generally to a loan guarantee of a natural gas pipeline in which the Corporation owns a 5% interest. The amount of this guarantee declines over its term.

The Corporation is subject to contingent liabilities with respect to existing or potential claims, lawsuits and other proceedings. The Corporation considers these routine and incidental to its business and not material to its financial position or results of operations. The Corporation accrues liabilities when the future costs are probable and reasonably estimable.

19. SEGMENT INFORMATION

Financial information by major geographic area for each of the three years ended December 31, 2003 follows:

                                 
    United           Africa, Asia   Consoli-
Millions of dollars
  States
  Europe
  and other
  dated
2003
                               
Operating revenues
  $ 12,019     $ 1,694     $ 598     $ 14,311  
Property, plant and equipment (net)
    1,705       2,538       3,735       7,978  
 
   
 
     
 
     
 
     
 
 
2002
                               
Operating revenues
  $ 8,684     $ 2,185     $ 682     $ 11,551  
Property, plant and equipment (net)
    1,770       2,327       2,935       7,032  
 
   
 
     
 
     
 
     
 
 
2001
                               
Operating revenues
  $ 9,663     $ 3,081     $ 308     $ 13,052  
Property, plant and equipment (net)
    2,469       2,322       3,374       8,165  
 
   
 
     
 
     
 
     
 
 

The Corporation has two operating segments that comprise the structure used by senior management to make key operating decisions and assess performance. These are (1) exploration and production and (2) refining and marketing. Operating segments have not been aggregated. Exploration and production operations include the exploration for and the production, purchase, transportation and sale of crude oil and natural gas. Refining and marketing operations include the manufacture, purchase, transportation, trading and marketing of petroleum and other energy products.

55


 

19. SEGMENT INFORMATION (CONTINUED)

The following table presents financial data by operating segment for each of the three years ended December 31, 2003:

                                 
    Exploration and   Refining and   Corporate and    
Millions of dollars
  Production
  Marketing
  Interest
  Consolidated*
2003
                               
Operating revenues
                               
Total operating revenues
  $ 3,153     $ 11,473     $ 1          
Less: Transfers between affiliates
    316                      
 
   
 
     
 
     
 
     
 
 
Operating revenues from unaffiliated customers
  $ 2,837     $ 11,473     $ 1     $ 14,311  
 
   
 
     
 
     
 
     
 
 
Income (loss) from continuing operations
  $ 414     $ 327     $ (274 )   $ 467  
Discontinued operations
    170             (1 )     169  
Income from cumulative effect of accounting change
    7                   7  
 
   
 
     
 
     
 
     
 
 
Net income (loss)
  $ 591     $ 327     $ (275 )   $ 643  
 
   
 
     
 
     
 
     
 
 
Earnings of equity affiliates
  $ 13     $ 125     $     $ 138  
Interest income
    10       34       2       46  
Interest expense
                293       293  
Depreciation, depletion, amortization and lease impairment
    1,063       54       1       1,118  
Provision (benefit) for income taxes
    363       126       (175 )     314  
Investments in equity affiliates
          1,055             1,055  
Identifiable assets
    9,149       4,267       567       13,983  
Capital employed
    6,270       2,820       191       9,281  
Capital expenditures
    1,286       66       6       1,358  
 
   
 
     
 
     
 
     
 
 
2002
                               
Operating revenues
                               
Total operating revenues
  $ 3,735     $ 8,351     $ 1          
Less: Transfers between affiliates
    536                      
 
   
 
     
 
     
 
     
 
 
Operating revenues from unaffiliated customers
  $ 3,199     $ 8,351     $ 1     $ 11,551  
 
   
 
     
 
     
 
     
 
 
Income (loss) from continuing operations
  $ (102 )   $ 85     $ (228 )   $ (245 )
Discontinued operations
    40             (13 )     27  
 
   
 
     
 
     
 
     
 
 
Net income (loss)
  $ (62 )   $ 85     $ (241 )   $ (218 )
 
   
 
     
 
     
 
     
 
 
Earnings of equity affiliates
  $ (4 )   $ (38 )   $     $ (42 )
Interest income
    5       38       1       44  
Interest expense
                256       256  
Depreciation, depletion, amortization and lease impairment
    1,103       55       1       1,159  
Asset impairments
    1,024                   1,024  
Provision (benefit) for income taxes
    265       47       (132 )     180  
Investments in equity affiliates
    617       1,001             1,618  
Identifiable assets
    8,392       4,218       652       13,262  
Capital employed
    6,657       2,465       118       9,240  
Capital expenditures
    1,404       123       7       1,534  
 
   
 
     
 
     
 
     
 
 
2001
                               
Operating revenues
                               
Total operating revenues
  $ 4,451     $ 9,454     $ 2          
Less: Transfers between affiliates
    855                      
 
   
 
     
 
     
 
     
 
 
Operating revenues from unaffiliated customers
  $ 3,596     $ 9,454     $ 2     $ 13,052  
 
   
 
     
 
     
 
     
 
 
Income (loss) from continuing operations
  $ 796     $ 233     $ (213 )   $ 816  
Discontinued operations
    98                   98  
 
   
 
     
 
     
 
     
 
 
Net income (loss)
  $ 894     $ 233     $ (213 )   $ 914  
 
   
 
     
 
     
 
     
 
 
Earnings of equity affiliates
  $ (2 )   $ 54     $     $ 52  
Interest income
    6       45       8       59  
Interest expense
                194       194  
Depreciation, depletion, amortization and lease impairment
    818       51       2       871  
Provision (benefit) for income taxes
    506       65       (69 )     502  
Investments in equity affiliates
    580       1,052             1,632  
Identifiable assets
    10,412       4,797       160       15,369  
Capital employed
    7,534       2,999       39       10,572  
Capital expenditures
    5,061       155       5       5,221  
 
   
 
     
 
     
 
     
 
 

* After elimination of transactions between affiliates, which are valued at approximate market prices.

56


 

REPORT OF MANAGEMENT
Amerada Hess Corporation and Consolidated Subsidiaries

The consolidated financial statements of Amerada Hess Corporation and consolidated subsidiaries were prepared by and are the responsibility of management. These financial statements conform with generally accepted accounting principles and are, in part, based on estimates and judgements of management. Other information included in this Annual Report is consistent with that in the consolidated financial statements.

The Corporation maintains a system of internal controls designed to provide reasonable assurance that assets are safeguarded and that transactions are properly executed and recorded. Judgements are required to balance the relative costs and benefits of this system of internal controls.

The Corporation’s consolidated financial statements have been audited by Ernst & Young LLP, independent auditors, who have been appointed by the Audit Committee of the Board of Directors and approved by the stockholders. Ernst & Young LLP assesses the Corporation’s system of internal controls and performs tests and procedures that they consider necessary to arrive at an opinion on the fairness of the consolidated financial statements.

The Audit Committee of the Board of Directors consists solely of independent directors. The Audit Committee meets periodically with the independent auditors, internal auditors and management to review and discuss the annual audit scope and plans, the adequacy of staffing, the system of internal controls and the results of examinations. In 2003, the Audit Committee met three times with the independent auditors and three times with the internal auditors without management present. The Audit Committee also reviews the Corporation’s financial statements with management and the independent auditors. This review includes a discussion of accounting principles, significant judgements inherent in the financial statements, disclosures and such other matters required by generally accepted auditing standards. Ernst & Young LLP and the Corporation’s internal auditors have unrestricted access to the Audit Committee.

(-s-JOHN B. HESS)

John B. Hess
Chairman of the Board and Chief Executive Officer

(-s-JOHN Y. SCHREYER)

John Y. Schreyer
Executive Vice President and Chief Financial Officer

57


 

REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS

The Board of Directors and Stockholders
Amerada Hess Corporation

We have audited the accompanying consolidated balance sheet of Amerada Hess Corporation and consolidated subsidiaries as of December 31, 2003 and 2002 and the related consolidated statements of income, retained earnings, cash flows, changes in preferred stock, common stock and capital in excess of par value and comprehensive income for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Amerada Hess Corporation and consolidated subsidiaries at December 31, 2003 and 2002 and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States.

As discussed in Notes 4 and 17 to the consolidated financial statements, the Corporation adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003, and Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, effective January 1, 2001.

(ERNEST AND YOUNG SIGNATURE)

New York, NY
February 20, 2004

58


 

SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
Amerada Hess Corporation and Consolidated Subsidiaries

The supplementary oil and gas data that follows is presented in accordance with Statement of Financial Accounting Standards (FAS) No. 69, Disclosures about Oil and Gas Producing Activities, and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing activities, (2) net proved oil and gas reserves, and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves, including a reconciliation of changes therein.

The Corporation produces crude oil and/or natural gas in the United States, Europe, Equatorial Guinea, Algeria, Gabon, Indonesia, Thailand and Azerbaijan. Exploration activities are also conducted, or are planned, in additional countries.

In 2001 and 2002, the Corporation had two equity investees and reported its proportionate share of their oil and gas data in the following tables. As a result of transactions in 2003, one of these equity investees was consolidated and the other was exchanged for other oil and gas interests. Previously, the Corporation owned a 25% interest in certain oil and gas fields in the joint development area of Malaysia and Thailand (JDA) through a 50% investment in a joint venture that was accounted for as an equity investment. In 2003, the Corporation exchanged producing properties in Colombia for the remaining 50% of the JDA joint venture. As a result of this exchange, the Corporation has consolidated its oil and gas interests in the JDA. In 2003, the Corporation exchanged its 25% equity investment in Premier Oil plc for an interest in a producing field in Indonesia.

During 2003, the Corporation exchanged its interests in producing oil and gas fields in the United Kingdom for an increased interest in a Gulf of Mexico field under development. The Corporation sold producing properties in the Gulf of Mexico Shelf, the Jabung Field in Indonesia and several small United Kingdom fields in 2003.

COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES

                                 
            United           Africa, Asia
For the Years Ended December 31 (Millions of dollars)
  Total
  States
  Europe
  and other
2003
                               
Property acquisitions
                               
Unproved
  $ 16     $ 16     $     $  
Proved
    23                   23  
Exploration
    321       143       49       129  
Production and development*
    1,082       118       501       463  
 
   
 
     
 
     
 
     
 
 
2002
                               
Property acquisitions
                               
Unproved
  $ 23     $ 22     $     $ 1  
Proved
    70                   70  
Exploration
    335       120       53       162  
Production and development
    1,095       146       509       440  
Share of equity investees’ costs incurred
    39             25       14  
 
   
 
     
 
     
 
     
 
 
2001
                               
Property acquisitions
                               
Unproved
  $ 820     $ 121     $ 1     $ 698  
Proved
    2,772       831             1,941  
Exploration
    297       107       87       103  
Production and development
    1,182       322       516       344  
Share of equity investees’ costs incurred
    14             9       5  
 
   
 
     
 
     
 
     
 
 

*   Includes $15 million that the Corporation has capitalized related to asset retirement obligations accrued during 2003. Also see Note 4 to the financial statements entitled Accounting Change.

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

                 
At December 31 (Millions of dollars)
  2003
  2002
Unproved properties
  $ 950     $ 1,020  
Proved properties
    2,634       2,843  
Wells, equipment and related facilities
    11,030       10,836  
 
   
 
     
 
 
Total costs
    14,614       14,699  
Less: Reserve for depreciation, depletion, amortization and lease impairment
    7,512       8,539  
 
   
 
     
 
 
Net capitalized costs
  $ 7,102 *   $ 6,160  
 
   
 
     
 
 
Share of equity investees’ capitalized costs
  $     $ 704  
 
   
 
     
 
 

*   Includes amounts related to asset retirement obligations.

59


 

The results of operations for oil and gas producing activities shown below exclude sales of purchased natural gas, non-operating income (including gains on sales of oil and gas properties), interest expense and gains and losses resulting from foreign exchange transactions. Therefore, these results are on a different basis than the net income from exploration and production operations reported in management’s discussion and analysis of results of operations and in Note 19 to the financial statements.

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

                                 
            United           Africa, Asia
For the Years Ended December 31 (Millions of dollars)
  Total
  States
  Europe
  and other
2003
                               
Sales and other operating revenues
                               
Unaffiliated customers
  $ 2,771     $ 469     $ 1,716     $ 586  
Inter-company
    316       316              
 
   
 
     
 
     
 
     
 
 
Total revenues
    3,087       785       1,716       586  
 
   
 
     
 
     
 
     
 
 
Costs and expenses
                               
Production expenses, including related taxes
    796       194       408       194  
Exploration expenses, including dry holes and lease impairment
    369       147       60       162  
General, administrative and other expenses
    168 *     65       63       40  
Depreciation, depletion and amortization
    998       260       553       185  
 
   
 
     
 
     
 
     
 
 
Total costs and expenses
    2,331       666       1,084       581  
 
   
 
     
 
     
 
     
 
 
Results of continuing operations before income taxes
    756       119       632       5  
Provision for income taxes
    358       42       291       25  
 
   
 
     
 
     
 
     
 
 
Results of continuing operations
    398       77       341       (20 )
Discontinued operations
    42       25       4       13  
 
   
 
     
 
     
 
     
 
 
Results of operations
  $ 440     $ 102     $ 345     $ (7 )
 
   
 
     
 
     
 
     
 
 
2002
                               
Sales and other operating revenues
                               
Unaffiliated customers
  $ 2,766     $ 365     $ 1,768     $ 633  
Inter-company
    568       536       32        
 
   
 
     
 
     
 
     
 
 
Total revenues
    3,334       901       1,800       633  
 
   
 
     
 
     
 
     
 
 
Costs and expenses
                               
Production expenses, including related taxes
    736       208       387       141  
Exploration expenses, including dry holes and lease impairment
    316       85       94       137  
General, administrative and other expenses
    105       45       16       44  
Depreciation, depletion and amortization
    1,061       345       518       198  
Asset impairments
    1,024       318             706  
 
   
 
     
 
     
 
     
 
 
Total costs and expenses
    3,242       1,001       1,015       1,226  
 
   
 
     
 
     
 
     
 
 
Results of continuing operations before income taxes
    92       (100 )     785       (593 )
Provision for income taxes
    225       (33 )     376       (118 )
 
   
 
     
 
     
 
     
 
 
Results of continuing operations
    (133 )     (67 )     409       (475 )
Discontinued operations
    52       (51 )     14       89  
 
   
 
     
 
     
 
     
 
 
Results of operations
  $ (81 )   $ (118 )   $ 423     $ (386 )
 
   
 
     
 
     
 
     
 
 
Share of equity investees’ results of operations
  $ 8     $     $ (3 )   $ 11  
 
   
 
     
 
     
 
     
 
 
2001
                               
Sales and other operating revenues
                               
Unaffiliated customers
  $ 2,154     $ 216     $ 1,650     $ 288  
Inter-company
    1,032       856       176        
 
   
 
     
 
     
 
     
 
 
Total revenues
    3,186       1,072       1,826       288  
 
   
 
     
 
     
 
     
 
 
Costs and expenses
                               
Production expenses, including related taxes
    642       190       350       102  
Exploration expenses, including dry holes and lease impairment
    347       138       103       106  
General, administrative and other expenses
    139       78       25       36  
Depreciation, depletion and amortization
    780       292       437       51  
 
   
 
     
 
     
 
     
 
 
Total costs and expenses
    1,908       698       915       295  
 
   
 
     
 
     
 
     
 
 
Results of continuing operations before income taxes
    1,278       374       911       (7 )
Provision for income taxes
    490       128       313       49  
 
   
 
     
 
     
 
     
 
 
Results of continuing operations
    788       246       598       (56 )
Discontinued operations
    95       28       16       51  
 
   
 
     
 
     
 
     
 
 
Results of operations
  $ 883     $ 274     $ 614     $ (5 )
 
   
 
     
 
     
 
     
 
 
Share of equity investees’ results of operations
  $ 17     $     $ 12     $ 5  
 
   
 
     
 
     
 
     
 
 

*   Includes accrued severance and London office lease costs of approximately $40 million.

60


 

The Corporation’s net oil and gas reserves have been estimated by independent consultants DeGolyer and MacNaughton. The reserves in the tabulation below include proved undeveloped crude oil and natural gas reserves that will require substantial future development expenditures. On a barrel of oil equivalent basis, 32% of the Corporation’s December 31, 2003 worldwide proved reserves are undeveloped. The estimates of the Corporation’s proved reserves of crude oil and natural gas (after deducting royalties and operating interests owned by others) follow:

OIL AND GAS RESERVES

                                                                                                 
    Crude Oil, Condensate and    
    Natural Gas Liquids   Natural Gas
    (Millions of barrels)
  (Millions of Mcf)
                    Africa,                                           Africa,                
    United           Asia and           Equity   World-   United           Asia and           Equity   World-
    States
  Europe
  other
  Total
  Investees
  wide
  States
  Europe
  other
  Total
  Investees
  wide
Net Proved Developed and Undeveloped Reserves
                                                                                               
At January 1, 2001
    156       419       180       755       11       766       552       945       310       1,807       320       2,127  
Revisions of previous estimates
    3       (1 )     4       6       (1 )     5       31       (25 )     (17 )     (11 )     46       35  
Improved recovery
          34             34             34             27             27             27  
Extensions, discoveries and other additions
    9       18       8       35             35       62       196       33       291             291  
Purchases of minerals in-place
    22       1       190       213       13       226       227             10       237       493       730  
Sales of minerals in-place
                                              (1 )           (1 )     (25 )     (26 )
Production
    (28 )     (63 )     (18 )     (109 )     (2 )     (111 )     (155 )     (131 )     (10 )     (296 )     (7 )     (303 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
At December 31, 2001
    162       408       364       934       21       955       717       1,011       326       2,054       827       2,881  
Revisions of previous estimates(a)
    (10 )     7       (73 )     (76 )     (5 )     (81 )     (82 )     (16 )     8       (90 )     (81 )     (171 )
Extensions, discoveries and other additions
    13       11       15       39             39       69       24       31       124       3       127  
Sales of minerals in-place
    (3 )     (1 )     (6 )     (10 )           (10 )     (29 )     (43 )           (72 )           (72 )
Production
    (24 )     (61 )     (34 )     (119 )     (2 )     (121 )     (136 )     (124 )     (15 )     (275 )     (13 )     (288 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
At December 31, 2002
    138       364       266       768       14       782       539       852       350       1,741       736       2,477  
Revisions of previous estimates(a)
    8       8       33       49             49       (8 )     14       (25 )     (19 )           (19 )
Extensions, discoveries and other additions
    1       6       4       11             11       3       81       4       88             88  
Purchases of minerals in-place(c)
    8             14 (b)     22       (6) (b)     16       21             1,023 (b)     1,044       (405) (b)     639  
Sales of minerals in-place(c)
    (8 )     (20 )     (81 )     (109 )     (7 )     (116 )     (103 )     (13 )     (157 )     (273 )     (316 )     (589 )
Production
    (20 )     (53 )     (22 )     (95 )     (1 )     (96 )     (92 )     (134 )     (23 )     (249 )     (15 )     (264 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
At December 31, 2003
    127       305       214       646             646 (d)     360 (e)     800       1,172       2,332             2,332 (d)
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Net Proved Developed Reserves
                                                                                               
At January 1, 2001
    140       353       80       573       9       582       476       842       111       1,429       199       1,628  
At December 31, 2001
    144       318       196       658       7       665       580       709       111       1,400       220       1,620  
At December 31, 2002
    113       294       140       547       8       555       450       631       154       1,235       221       1,456  
At December 31, 2003
    105       249       111       465             465       297       518       633       1,448             1,448  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 

(a)   Includes the impact of changes in selling prices on production sharing contracts with cost recovery provisions and stipulated rates of return. In 2003 such revisions were immaterial. In 2002 revisions included reductions of approximately 44 million barrels of crude oil and 26 million Mcf of natural gas relating to higher selling prices. In 2002 revisions also reflected reductions in reserves on fields acquired in the LLOG and Triton acquisitions.

(b)   Includes the reclassification of reserves to “Africa, Asia and other” from “Equity Investees” as a result of the consolidation of the Corporation’s interest in the JDA.

(c)   Includes additions and reductions to reserves from asset exchanges.

(d)   Includes 32% of crude oil reserves and 43% of natural gas reserves held under production sharing contracts. These reserves are located outside of the United States and are subject to different political and economic risks.

(e)   Excludes 443 million Mcf of carbon dioxide gas for sale or use in company operations.

61


 

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves required to be disclosed by FAS No. 69 is based on assumptions and judgements. As a result, the future net cash flow estimates are highly subjective and could be materially different if other assumptions were used. Therefore, caution should be exercised in the use of the data presented below.

Future net cash flows are calculated by applying year-end oil and gas selling prices (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future development and production costs, which are based on year-end costs and existing economic assumptions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the pre-tax net cash flows relating to the Corporation’s proved oil and gas reserves. Future net cash flows are discounted at the prescribed rate of 10%. No recognition is given in the discounted future net cash flow estimates to depreciation, depletion, amortization and lease impairment, exploration expenses, interest expense, corporate general and administrative expenses and changes in future prices and costs. The selling prices of crude oil and natural gas are highly volatile. The year-end prices, which are required to be used for the discounted future net cash flows and do not include the effects of hedges, may not be representative of future selling prices.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

                                 
            United           Africa, Asia
At December 31 (Millions of dollars)
  Total
  States
  Europe
  and other
2003
                               
Future revenues
  $ 27,649     $ 5,742     $ 12,417     $ 9,490  
 
   
 
     
 
     
 
     
 
 
Less:
                               
Future development and production costs
    10,065       1,546       5,181       3,338  
Future income tax expenses
    5,848       1,299       3,496       1,053  
 
   
 
     
 
     
 
     
 
 
 
    15,913       2,845       8,677       4,391  
 
   
 
     
 
     
 
     
 
 
Future net cash flows
    11,736       2,897       3,740       5,099  
Less: Discount at 10% annual rate
    4,719       1,062       1,333       2,324  
 
   
 
     
 
     
 
     
 
 
Standardized measure of discounted future net cash flows
  $ 7,017     $ 1,835     $ 2,407     $ 2,775  
 
   
 
     
 
     
 
     
 
 
2002
                               
Future revenues
  $ 27,994     $ 6,219     $ 13,203     $ 8,572  
 
   
 
     
 
     
 
     
 
 
Less:
                               
Future development and production costs
    10,133       1,843       4,863       3,427  
Future income tax expenses
    6,661       1,228       4,042       1,391  
 
   
 
     
 
     
 
     
 
 
 
    16,794       3,071       8,905       4,818  
 
   
 
     
 
     
 
     
 
 
Future net cash flows
    11,200       3,148       4,298       3,754  
Less: Discount at 10% annual rate
    4,115       1,178       1,441       1,496  
 
   
 
     
 
     
 
     
 
 
Standardized measure of discounted future net cash flows
  $ 7,085     $ 1,970     $ 2,857     $ 2,258  
 
   
 
     
 
     
 
     
 
 
Share of equity investees’ standardized measure
  $ 587     $     $ 23     $ 564  
 
   
 
     
 
     
 
     
 
 
2001
                               
Future revenues
  $ 22,666     $ 4,884     $ 10,569     $ 7,213  
 
   
 
     
 
     
 
     
 
 
Less:
                               
Future development and production costs
    10,335       1,817       4,889       3,629  
Future income tax expenses
    3,989       686       2,495       808  
 
   
 
     
 
     
 
     
 
 
 
    14,324       2,503       7,384       4,437  
 
   
 
     
 
     
 
     
 
 
Future net cash flows
    8,342       2,381       3,185       2,776  
Less: Discount at 10% annual rate
    3,286       809       1,132       1,345  
 
   
 
     
 
     
 
     
 
 
Standardized measure of discounted future net cash flows
  $ 5,056     $ 1,572     $ 2,053     $ 1,431  
 
   
 
     
 
     
 
     
 
 
Share of equity investees’ standardized measure
  $ 543     $     $ 28     $ 515  
 
   
 
     
 
     
 
     
 
 

62


 

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

                         
For the years ended December 31 (Millions of dollars)
  2003
  2002
  2001
Standardized measure of discounted future net cash flows at beginning of year
  $ 7,085     $ 5,056     $ 6,828  
 
   
 
     
 
     
 
 
Changes during the year
                       
Sales and transfers of oil and gas produced during year, net of production costs
    (2,291 )     (2,964 )     (2,840 )
Development costs incurred during year
    1,082       1,095       1,182  
Net changes in prices and production costs applicable to future production
    796       5,767       (4,346 )
Net change in estimated future development costs
    (726 )     (546 )     (838 )
Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs
    261       287       521  
Revisions of previous oil and gas reserve estimates
    622       (939 )     231  
Purchases (sales) of minerals in-place, net
    (469 )     (247 )     1,186  
Accretion of discount
    945       796       1,087  
Net change in income taxes
    72       (1,701 )     1,943  
Revision in rate or timing of future production and other changes
    (360 )     481       102  
 
   
 
     
 
     
 
 
Total
    (68 )     2,029       (1,772 )
 
   
 
     
 
     
 
 
Standardized measure of discounted future net cash flows at end of year
  $ 7,017     $ 7,085     $ 5,056  
 
   
 
     
 
     
 
 

63


 

TEN-YEAR SUMMARY OF FINANCIAL DATA
Amerada Hess Corporation and Consolidated Subsidiaries

                         
Millions of dollars, except per share data
  2003
  2002
  2001
STATEMENT OF CONSOLIDATED INCOME
                       
Revenues and Non-operating Income
                       
Sales (excluding excise taxes) and other operating revenues
           
Crude oil (including sales of purchased oil)
  $ 2,032     $ 2,471     $ 2,099  
Natural gas (including sales of purchased gas)
    4,522       3,078       4,503  
Petroleum products
    6,513       4,865       5,303  
Other operating revenues
    1,244       1,137       1,147  
 
   
 
     
 
     
 
 
Total
    14,311       11,551       13,052  
Non-operating income
                       
Gain on asset sales
    39       143        
Equity in income (loss) of HOVENSA L.L.C.
    117       (47 )     58  
Other
    13       85       150  
 
   
 
     
 
     
 
 
Total revenues and non-operating income
    14,480       11,732       13,260  
 
   
 
     
 
     
 
 
Costs and expenses
                       
Cost of products sold
    9,947       7,226       8,739  
Production expenses
    796       736       642  
Marketing expenses
    709       703       663  
Exploration expenses, including dry holes and lease impairment
    369       316       347  
Other operating expenses
    192       165       213  
General and administrative expenses
    340       253       311  
Interest expense
    293       256       194  
Depreciation, depletion and amortization
    1,053       1,118       833  
Impairment of assets and operating leases
          1,024        
 
   
 
     
 
     
 
 
Total costs and expenses
    13,699       11,797       11,942  
 
   
 
     
 
     
 
 
Income (loss) from continuing operations before income taxes
    781       (65 )     1,318  
Provision (benefit) for income taxes
    314       180       502  
 
   
 
     
 
     
 
 
Income (loss) from continuing operations
    467       (245 )(b)     816 (d)
Discontinued operations
    169 (a)     27       98  
Cumulative effect of change in accounting principle
    7              
 
   
 
     
 
     
 
 
NET INCOME (LOSS)
  $ 643     $ (218 )   $ 914  
 
   
 
     
 
     
 
 
Less preferred stock dividends
    5              
 
   
 
     
 
     
 
 
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS
  $ 638     $ (218 )   $ 914  
 
   
 
     
 
     
 
 
Basic earnings (loss) per share
                       
Continuing operations
  $ 5.21     $ (2.78 )   $ 9.26  
Net income (loss)
    7.19       (2.48 )     10.38  
Diluted earnings (loss) per share
                       
Continuing operations
  $ 5.17     $ (2.78 )   $ 9.15  
Net income (loss)
    7.11       (2.48 )     10.25  
 
   
 
     
 
     
 
 
DIVIDENDS PER SHARE OF COMMON STOCK
  $ 1.20     $ 1.20     $ 1.20  
WEIGHTED AVERAGE DILUTED SHARES OUTSTANDING (THOUSANDS)
    90,342       88,187 (c)     89,129  
 
   
 
     
 
     
 
 

(a)   Reflects net gains from asset sales of $116 million and income from operations prior to sale of $53 million.

(b)   Includes net after-tax charges aggregating $708 million ($931 million before income taxes), principally resulting from asset impairments. See Note 2 to consolidated financial statements.

(c)   Represents basic shares.

(d)   Includes after-tax charges aggregating $31 million ($47 million before income taxes) for losses related to the bankruptcy of certain subsidiaries of Enron and accrued severance.

(e)   Includes an after-tax gain of $60 million ($97 million before income taxes) on termination of an acquisition, partially offset by a $24 million ($38 million before income taxes) charge for costs associated with a research and development venture.

(f)   On January 1, 1999, the Corporation adopted the last-in, first-out (LIFO) inventory method for refining and marketing inventories.

(g)   Includes after-tax gains on asset sales of $176 million ($273 million before income taxes) and tax benefits of $54 million, partially offset by impairment of assets and operating leases of $99 million ($128 million before income taxes).

See accompanying notes to consolidated financial statements, including Note 5 on Acquisition of Triton Energy Limited in August of 2001.

64


 

                                                                 
    2000
  1999(f)
  1998
  1997
  1996
  1995
  1994
       
 
  $ 2,022     $ 1,322     $ 836     $ 1,338     $ 1,426     $ 1,480     $ 1,178          
 
    3,239       1,800       1,645       1,306       1,241       1,005       901          
 
    5,539       3,003       3,464       4,958       5,081       4,311       3,981          
 
    947       770       509       413       296       303       328          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
    11,747       6,895       6,454       8,015       8,044       7,099       6,388          
 
          273       (26 )     16       529       96       42          
 
    121       7       (16 )                                
 
    165       140       83       120       125       125       49          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
    12,033       7,315       6,495       8,151       8,698       7,320       6,479          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
    7,885       4,239       4,373       5,577       5,387       4,501       3,795          
 
    522       453       478       513       573       561       550          
 
    542       387       379       329       264       259       261          
 
    282       260       350       422       382       382       331          
 
    234       217       224       232       129       186       124          
 
    222       232       271       235       237       263       230          
 
    162       158       153       136       166       247       245          
 
    676       610       598       595       644       693       741          
 
          128       206       80             584                
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
    10,525       6,684       7,032       8,119       7,782       7,676       6,277          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
    1,508       631       (537 )     32       916       (356 )     202          
 
    591       240       (62 )     85       319       37       138          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
    917 (e)     391 (g)     (475 )     (53 )     597       (393 )     64          
 
    106       47       16       61       63       (1 )     10          
 
                                                 
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
  $ 1,023     $ 438     $ (459 )   $ 8     $ 660     $ (394 )   $ 74          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
                                                 
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
  $ 1,023     $ 438     $ (459 )   $ 8     $ 660     $ (394 )   $ 74          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
  $ 10.29     $ 4.36     $ (5.30 )   $ (.58 )   $ 6.45     $ (4.25 )   $ .69          
 
    11.48       4.88       (5.12 )     .08       7.13       (4.26 )     .80          
 
  $ 10.20     $ 4.33     $ (5.30 )   $ (.58 )   $ 6.41     $ (4.25 )   $ .69          
 
    11.38       4.85       (5.12 )     .08       7.09       (4.26 )     .79          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         
 
  $ .60     $ .60     $ .60     $ .60     $ .60     $ .60     $ .60          
 
    89,878       90,280       89,585 (c)     91,733       93,110       92,509 (c)     92,968          
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
         

65


 

TEN-YEAR SUMMARY OF FINANCIAL DATA
Amerada Hess Corporation and Consolidated Subsidiaries

                         
Millions of dollars, except per share data
  2003
  2002
  2001
SELECTED BALANCE SHEET DATA AT YEAR-END
                       
Cash and cash equivalents
  $ 518     $ 197     $ 37  
Working capital
    517       203       228  
Property, plant and equipment
           
Exploration and production
  $ 14,614     $ 14,699     $ 15,194  
Refining and marketing
    1,486       1,450       1,433  
 
   
 
     
 
     
 
 
Total—at cost
    16,100       16,149       16,627  
Less reserves
    8,122       9,117       8,462  
 
   
 
     
 
     
 
 
Property, plant and equipment—net
  $ 7,978     $ 7,032     $ 8,165  
 
   
 
     
 
     
 
 
Total assets
  $ 13,983     $ 13,262     $ 15,369  
Total debt
    3,941       4,992       5,665  
Stockholders’ equity
    5,340       4,249       4,907  
Stockholders’ equity per share, assuming conversion of preferred stock
  $ 51.50     $ 47.45     $ 55.11  
 
   
 
     
 
     
 
 
SUMMARIZED STATEMENT OF CASH FLOWS
                       
Net cash provided by operating activities
  $ 1,581     $ 1,965     $ 1,960  
 
   
 
     
 
     
 
 
Cash flows from investing activities
           
Capital expenditures
           
Exploration and production
    (1,286 )     (1,404 )     (5,061 )
Refining and marketing
    (72 )     (130 )     (160 )
 
   
 
     
 
     
 
 
Total capital expenditures
    (1,358 )     (1,534 )     (5,221 )
Proceeds from sales of property, plant and equipment and other
    581       438       16  
 
   
 
     
 
     
 
 
Net cash provided by (used in) investing activities
    (777 )     (1,096 )     (5,205 )
 
   
 
     
 
     
 
 
Cash flows from financing activities
           
Debt with maturities of 90 days or less—increase (decrease)
    (2 )     (581 )     564  
Debt with maturities of greater than 90 days
           
Borrowings
          637       2,595  
Repayments
    (1,026 )     (686 )     (54 )
Proceeds from issuance of preferred stock
    653              
Cash dividends paid
    (108 )     (107 )     (94 )
Common stock acquired
                (100 )
Stock options exercised
          28       59  
 
   
 
     
 
     
 
 
Net cash provided by (used in) financing activities
    (483 )     (709 )     2,970  
 
   
 
     
 
     
 
 
Net increase (decrease) in cash and cash equivalents
  $ 321     $ 160     $ (275 )
 
   
 
     
 
     
 
 
STOCKHOLDER DATA AT YEAR-END
                       
Number of common shares outstanding (thousands)
    89,868       89,193       88,757  
Number of stockholders (based on number of holders of record)
    6,983       7,272       6,481  
Market price of common stock
  $ 53.17     $ 55.05     $ 62.50  
 
   
 
     
 
     
 
 

66


 

                                                         
    2000
  1999
  1998
  1997
  1996
  1995
  1994
 
  $ 312     $ 41     $ 74     $ 91     $ 113     $ 56     $ 53  
 
    577       249       90       464       690       358       520  
 
  $ 10,499     $ 9,974     $ 9,718     $ 8,780     $ 8,233     $ 9,392     $ 9,791  
 
    1,399       1,091       1,309       3,842       3,669       3,672       4,514  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    11,898       11,065       11,027       12,622       11,902       13,064       14,305  
 
    7,575       7,013       6,835       7,431       6,995       7,694       7,939  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 4,323     $ 4,052     $ 4,192     $ 5,191     $ 4,907     $ 5,370     $ 6,366  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 10,274     $ 7,728     $ 7,883     $ 7,935     $ 7,784     $ 7,756     $ 8,338  
 
    2,050       2,310       2,652       2,127       1,939       2,718       3,340  
 
    3,883       3,038       2,643       3,216       3,384       2,660       3,100  
 
  $ 43.58     $ 33.51     $ 29.26     $ 35.16     $ 36.35     $ 28.60     $ 33.33  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 1,795     $ 746     $ 519     $ 1,250     $ 808     $ 1,241     $ 957  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    (783 )     (727 )     (1,307 )     (1,158 )     (788 )     (626 )     (532 )
 
    (155 )     (70 )     (132 )     (188 )     (73 )     (66 )     (64 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    (938 )     (797 )     (1,439 )     (1,346 )     (861 )     (692 )     (596 )
 
    36       397       500       61       1,040       148       74  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    (902 )     (400 )     (939 )     (1,285 )     179       (544 )     (522 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    (131 )     (1,060 )     213       398       (825 )     (352 )     (575 )
 
    20       990       441       2             25       290  
 
    (296 )     (273 )     (137 )     (209 )     (42 )     (311 )     (121 )
 
                                         
 
    (54 )     (54 )     (55 )     (55 )     (56 )     (56 )     (56 )
 
    (220 )           (59 )     (122 )     (8 )            
 
    59       18                                
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    (622 )     (379 )     403       14       (931 )     (694 )     (462 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
  $ 271     $ (33 )   $ (17 )   $ (21 )   $ 56     $ 3     $ (27 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    88,744       90,676       90,357       91,451       93,073       93,011       92,996  
 
    7,709       7,416       8,959       9,591       10,153       11,294       11,506  
 
  $ 73.06     $ 56.75     $ 49.75     $ 54.88     $ 57.88     $ 53.00     $ 45.63  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 

67


 

TEN-YEAR SUMMARY OF OPERATING DATA
Amerada Hess Corporation and Consolidated Subsidiaries

                         
    2003
  2002
  2001
PRODUCTION PER DAY (NET)
                       
Crude oil (thousands of barrels)
                       
United States
    44       54       63  
United Kingdom
    89       112       119  
Norway
    24       24       25  
Denmark
    24       23       20  
Equatorial Guinea
    22       37       6  
Algeria
    19       15       13  
Gabon
    11       9       9  
Indonesia
    1       4       6  
Azerbaijan
    2       4       4  
Colombia
    3       22       10  
Other
                 
 
   
 
     
 
     
 
 
Total
    239       304       275  
 
   
 
     
 
     
 
 
Natural gas liquids (thousands of barrels)
                       
United States
    11       12       14  
United Kingdom
    6       6       7  
Norway
    1       1       1  
Thailand
    2       2       1  
Other
                 
 
   
 
     
 
     
 
 
Total
    20       21       23  
 
   
 
     
 
     
 
 
Natural gas (thousands of Mcf )
                       
United States
    253       373       424  
United Kingdom
    312       277       291  
Thailand
    52       35       20  
Denmark
    29       37       43  
Norway
    26       25       25  
Indonesia
    11       6       8  
Other
          1       1  
 
   
 
     
 
     
 
 
Total
    683       754       812  
 
   
 
     
 
     
 
 
Barrels of oil equivalent (thousands of barrels per day)(e)
    373       451       433  
 
   
 
     
 
     
 
 
WELL COMPLETIONS (NET)
                       
Oil wells
    30       38       50  
Gas wells
    13       39       31  
Dry holes
    13       16       15  
PRODUCTIVE WELLS AT YEAR-END (NET)
                       
Oil wells
    795       760       858  
Gas wells
    236       237       257  
 
   
 
     
 
     
 
 
Total
    1,031       997       1,115  
 
   
 
     
 
     
 
 
UNDEVELOPED NET ACREAGE AT YEAR-END (THOUSANDS)
                       
United States
    940       743       625  
Foreign(a)
    8,143       12,224       15,999  
 
   
 
     
 
     
 
 
Total
    9,083       12,967       16,624  
 
   
 
     
 
     
 
 
REFINING (THOUSANDS OF BARRELS PER DAY)
                       
Amerada Hess Corporation
                 
HOVENSA L.L.C.(c)
    220       181       202  
PETROLEUM PRODUCTS SOLD (THOUSANDS OF BARRELS PER DAY)
                       
Gasoline, distillates and other light products
    351       329       322  
Residual fuel oils
    68       54       65  
 
   
 
     
 
     
 
 
Total
    419       383       387  
 
   
 
     
 
     
 
 
STORAGE CAPACITY AT YEAR-END (THOUSANDS OF BARRELS)
    36,028       36,140       36,298  
NUMBER OF EMPLOYEES (AVERAGE)
    11,481 (d)     11,662       10,838  
 
   
 
     
 
     
 
 

(a)   Includes acreage held under production sharing contracts.

(b)   Through ten months of 1998.

(c)   Reflects 50% of HOVENSA refinery crude runs from November 1, 1998.

(d)   Includes approximately 7,100 employees of retail operations.

(e)   Includes barrels of oil equivalent production per day (in thousands) of 13 in 2003, 51 in 2002, 45 in 2001, 26 in 2000, 27 in 1999 and 25 in 1998 related to operations discontinued in 2003.

68


 

                                                         
    2000
  1999
  1998
  1997
  1996
  1995
  1994
 
    55       55       37       35       41       52       56  
 
    119       112       109       126       135       135       122  
 
    25       25       27       30       28       26       24  
 
    25       7                                
 
                                         
 
    2                                      
 
    7       10       14       10       9       10       9  
 
    4       3       3       1                    
 
    3       2                                
 
                                         
 
                            6       17       18  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    240       214       190       202       219       240       229  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    12       10       8       8       9       11       12  
 
    6       5       6       6       7       7       7  
 
    2       2       2       2       2       1       1  
 
    1       1                                
 
                                  2       2  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    21       18       16       16       18       21       22  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    288       338       294       312       338       402       427  
 
    297       258       251       226       254       239       209  
 
    23       8                                
 
    37       3                                
 
    24       31       28       30       30       28       24  
 
    10       5       3       1                    
 
                            63       215       186  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    679       643       576       569       685       884       846  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    374       339       302       313       351       408       392  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    29       28       28       42       39       33       28  
 
    11       11       20       11       25       41       44  
 
    18       9       25       24       40       50       24  
 
 
    774       735       721       860       854       2,154       2,160  
 
    188       161       252       447       455       1,160       1,146  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    962       896       973       1,307       1,309       3,314       3,306  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    616       678       748       915       891       1,440       1,685  
 
    14,419       15,858       16,927       10,180       7,455       5,871       4,570  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    15,035       16,536       17,675       11,095       8,346       7,311       6,255  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
                419 (b)     411       396       377       388  
 
    211       209       217                          
 
 
    304       284       411       436       412       401       375  
 
    62       60       71       73       83       86       93  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    366       344       482       509       495       487       468  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 
 
    37,487       38,343       56,070       87,000       86,986       89,165       94,597  
 
    9,891       8,485       9,777       9,216       9,085       9,574       9,858  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
 

69

EXHIBIT 21 PAGE 1 OF 2 AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES ------------------------------------------------------ SUBSIDIARIES OF THE REGISTRANT ------------------------------ Organized under Name of Subsidiary the laws of ------------------ ----------- Triton Energy Limited .................................. Cayman Islands and Delaware Amerada Hess Limited ................................... United Kingdom Hess Oil Virgin Islands Corp. .......................... U.S. Virgin Islands Amerada Hess Norge A/S ................................. Norway Hess Energy Trading Company, LLC ....................... Delaware Amerada Hess (Denmark) ApS ............................. Denmark Amerada Hess Oil and Gas Holdings, Inc. ................ Cayman Islands Amerada Hess Production Gabon .......................... Gabon Amerada Hess (GEA) Limited ............................. Cayman Islands Amerada Hess (Thailand) Limited ........................ United Kingdom Amerada Hess Pipeline Corporation ...................... Delaware Tioga Gas Plant, Inc. .................................. Delaware Other subsidiaries (names omitted because such unnamed subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary) Each of the foregoing subsidiaries conducts business under the name listed, and is 100% owned by the Registrant, except for Hess Energy Trading Company, LLC, which is a trading company that is a joint venture between the Registrant and unrelated parties.

EXHIBIT 21 PAGE 2 OF 2 AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES SUBSIDIARIES OF THE REGISTRANT Name of Affiliate ----------------- HOVENSA L.L.C. (50% owned) ............................. U.S. Virgin Islands Summarized Financial Information of HOVENSA L.L.C. is included in the Registrant's 2003 Annual Report to Stockholders.

SECTION 306 CERTIFICATION
 

Exhibit 31(1)

I, John B. Hess, certify that:

      1. I have reviewed this annual report on Form 10-K of Amerada Hess Corporation;

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

      3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

      4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

        (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
        (b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
        (c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

      5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

        (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
        (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

  By        /s/ JOHN B. HESS       
  ....................................................
  John B. Hess
  Chairman of the Board and
  Chief Executive Officer

Date: March 11, 2004

SECTION 306 CERTIFICATION
 

Exhibit 31(2)

I, John Y. Schreyer, certify that:

      1. I have reviewed this annual report on Form 10-K of Amerada Hess Corporation;

      2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

      3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

      4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

        (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
        (b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
        (c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

      5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

        (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
        (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

  By        /s/ JOHN Y. SCHREYER       
  ....................................................
  John Y. Schreyer
  Executive Vice President and
  Chief Financial Officer

Date: March 11, 2004

SECTION 906 CERTIFICATION
 

Exhibit 32(1)

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

      In connection with the Annual Report of Amerada Hess Corporation (the “Corporation”) on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John B. Hess, Chairman of the Board and Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section  906 of the Sarbanes-Oxley Act of 2002, that:

        (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
 
        (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

  By        /s/ JOHN B. HESS       
  ....................................................
  John B. Hess
  Chairman of the Board and
  Chief Executive Officer

Date:     March 11, 2004

SECTION 906 CERTIFICATION
 

Exhibit 32(2)

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

      In connection with the Annual Report of Amerada Hess Corporation (the “Corporation”) on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Y. Schreyer, Executive Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section  906 of the Sarbanes-Oxley Act of 2002, that:

        (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
 
        (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

  By        /s/ JOHN Y. SCHREYER       
  ....................................................
  John Y. Schreyer
  Executive Vice President and
  Chief Financial Officer

Date:     March 11, 2004