10-K
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Form 10-K
 
     
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006
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
 
 
 
 
Hess Corporation
(Exact name of Registrant as specified in its charter)
 
     
DELAWARE
  13-4921002
(State or other jurisdiction of
incorporation or organization)
  (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:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock (par value $1.00)
  New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark 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.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  Large accelerated filer þ     Accelerated filer  o     Non-accelerated filer  o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $12,765,000,000 as of June 30, 2006.
 
At December 31, 2006, there were 315,017,951 shares of Common Stock outstanding.
 
Part III is incorporated by reference from the Proxy Statement for the annual meeting of stockholders to be held on May 2, 2007.
 


 

 
HESS CORPORATION
 
Form 10-K
 
TABLE OF CONTENTS
 
             
Item No.
      Page
 
  Business and Properties   2
1A.
  Risk Factors Related to Our Business and Operations   10
3.
  Legal Proceedings   12
4.
  Submission of Matters to a Vote of Security Holders   15
    Executive Officers of the Registrant   15
 
5.
  Market for the Registrant’s Common Stock and Related Stockholder Matters   16
6.
  Selected Financial Data   19
7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations   20
7A.
  Quantitative and Qualitative Disclosures About Market Risk   38
8.
  Financial Statements and Supplementary Data   42
9.
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   85
9A.
  Controls and Procedures   85
9B.
  Other Information   85
 
10.
  Directors, Executive Officers and Corporate Governance of the Registrant   85
11.
  Executive Compensation   85
12.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   85
13.
  Certain Relationships and Related Transactions, and Director Independence   85
14.
  Principal Accounting Fees and Services   86
 
15.
  Exhibits, Financial Statement Schedules, and Reports on Form 8-K   86
    Signatures   89
 EX-10.7: SAVINGS AND STOCK BONUS PLAN
 EX-10.10: AMENDED PENSION RESTORATION PLAN
 EX-21: SUBSIDIARIES
 EX-31.1: CERTIFICATION
 EX-31.2: CERTIFICATION
 EX-32.1: CERTIFICATION
 EX-32.2: CERTIFICATION


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PART I
 
Items 1 and 2.  Business and Properties
 
Hess Corporation (formerly Amerada Hess Corporation) (the Registrant) is a Delaware corporation, incorporated in 1920. On May 3, 2006, Amerada Hess Corporation changed its name to Hess Corporation. The Registrant and its subsidiaries (collectively referred to as the “Corporation” or “Hess”) is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. These exploration and production activities take place in the United States, United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Malaysia, Thailand, Russia, Gabon, Azerbaijan, Indonesia, Libya, Egypt, and other countries. The M&R segment manufactures, purchases, transports, trades and markets refined petroleum products, natural gas and electricity. The Corporation owns 50% of a refinery joint venture in the United States Virgin Islands, and another refining facility, terminals and retail gasoline stations, most of which include convenience stores, located on the East Coast of the United States.
 
Exploration and Production
 
The Corporation’s total proved reserves at December 31 were as follows:
 
                 
    2006     2005  
 
Crude oil and natural gas liquids (millions of barrels)
    832       692  
Natural gas (millions of mcf)
    2,466       2,406  
Total barrels of oil equivalent* (millions of barrels)
    1,243       1,093  
 
 
* Reflects natural gas reserves converted on the basis of relative energy content (six mcf equals one barrel).
 
Of the total proved reserves (on a barrel of oil equivalent basis), 14% are located in the United States, 36% are located in Europe (consisting of reserves in the North Sea and Russia), 25% are located in Africa and the remainder are located in Indonesia, Thailand, Malaysia, and Azerbaijan. On a barrel of oil equivalent basis, 40% of the Corporation’s December 31, 2006 worldwide proved reserves are undeveloped (42% in 2005). Proved reserves at December 31, 2006 include 26% and 56%, respectively, of crude oil and natural gas reserves held under production sharing contracts.
 
Worldwide crude oil and natural gas liquids production amounted to 257,000 barrels per day in 2006 compared with 244,000 barrels per day in 2005. Worldwide natural gas production was 612,000 mcf per day in 2006 compared with 544,000 mcf per day in 2005. On a barrel of oil equivalent basis, production was 359,000 barrels per day in 2006 compared with 335,000 barrels per day in 2005.
 
Worldwide crude oil, natural gas liquids and natural gas production was as follows:
 
                 
    2006     2005  
 
Crude oil (thousands of barrels per day)
               
United States
               
Onshore
    15       21  
Offshore
    21       23  
                 
      36       44  
                 
Europe
               
United Kingdom
    50       54  
Norway
    22       26  
Denmark
    19       24  
Russia
    18       6  
                 
      109       110  
                 


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    2006     2005  
 
Africa
               
Equatorial Guinea
    28       30  
Algeria
    22       25  
Gabon
    12       12  
Libya
    23        
                 
      85       67  
                 
Asia and other
               
Azerbaijan
    7       4  
Other
    5       3  
                 
      12       7  
                 
Total
    242       228  
                 
Natural gas liquids (thousands of barrels per day)
               
United States
               
Onshore
    7       8  
Offshore
    3       4  
                 
      10       12  
                 
Europe
               
United Kingdom
    4       3  
Norway
    1       1  
                 
      5       4  
                 
Total
    15       16  
                 
Natural gas (thousands of mcf per day)
               
United States
               
Onshore
    54       74  
Offshore
    56       63  
                 
      110       137  
                 
Europe
               
United Kingdom
    244       222  
Norway
    22       28  
Denmark
    17       24  
                 
      283       274  
                 
Asia and other
               
Joint Development Area of Malaysia and Thailand
    131       51  
Thailand
    60       57  
Indonesia
    26       25  
Other
    2        —  
                 
      219       133  
                 
Total
    612       544  
                 
Barrels of oil equivalent*
    359       335  
                 
 
 
* Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel).
 
The Corporation presently estimates that its 2007 barrel of oil equivalent production will be approximately 370,000 to 380,000 barrels per day. The Corporation is developing a number of oil and gas fields and has an inventory of domestic and foreign exploration prospects.

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United States
 
During 2006, 18% of the Corporation’s crude oil and natural gas liquids production and 18% of its natural gas production were from United States operations. The Corporation operates mainly offshore in the Gulf of Mexico and onshore in Texas and North Dakota. During 2006, the Corporation completed the sale of its interests in certain producing properties in the Permian Basin in Texas and New Mexico and certain U.S. Gulf Coast oil and gas producing assets. Total net production from assets sold was approximately 8,000 barrels of oil equivalent per day at the time of sale.
 
In the second quarter of 2006, the Shenzi development (Hess 28%) in the Green Canyon Block area of the deepwater Gulf of Mexico was sanctioned by the operator and first oil is expected in the second half of 2009. Plans for the Shenzi development in 2007 include the drilling of development wells and continued construction of platform components and subsea equipment installation. In February 2007, the Corporation acquired a 28% interest in the Genghis Khan oil and gas development located in the deepwater Gulf of Mexico on Green Canyon Blocks 652 and 608 for $371 million. The Genghis Khan development is part of the same geologic structure as the Shenzi development and first production from this development is expected in the second half of 2007.
 
In 2006, an exploration well on the Corporation’s Pony prospect (Hess 100%) on Green Canyon Block 468 in the deepwater Gulf of Mexico encountered 475 feet of oil saturated sandstone in Miocene age reservoirs. Drilling of an appraisal sidetrack well on the Pony Prospect was completed in January 2007 which encountered 280 feet of oil saturated sandstone in Miocene age reservoirs after penetrating sixty percent of its geological objective. Drilling of the sidetrack well was stopped for mechanical reasons after successfully recovering 450 feet of conventional core. The Corporation is currently drilling an appraisal well about 7,400 feet northwest of the discovery well.
 
In 2006, on the Tubular Bells prospect (Hess 20%) in the Mississippi Canyon area of the deepwater Gulf of Mexico a successful appraisal well encountered hydrocarbons approximately 5 miles from the initial discovery well. The operator intends to drill two sidetrack wells in 2007 which will further delineate the field.
 
The Corporation has an interest in the Seminole-San Andres Unit (Hess 34.3%) in the Permian Basin. A residual oil zone development at the Seminole-San Andres Unit is expected to commence in 2007 and it is anticipated that production from this development will begin in 2009. The Corporation intends to use carbon dioxide gas from its interests in the West Bravo Dome and Bravo Dome fields in New Mexico for the enhanced recovery effort in this residual oil zone development.
 
At December 31, 2006, the Corporation has interests in over 400 exploration blocks in the Gulf of Mexico. The Corporation has 1,525,304 net undeveloped acres in the Gulf of Mexico.
 
  Europe
 
During 2006, 44% of the Corporation’s crude oil and natural gas liquids production and 46% of its natural gas production were from European operations.
 
United Kingdom:  Production of crude oil and natural gas liquids from the United Kingdom North Sea was 54,000 barrels per day in 2006 compared with 57,000 barrels per day in 2005, principally from the Corporation’s non-operated interests in the Beryl (Hess 22.2%), Bittern (Hess 28.3%), Schiehallion (Hess 15.7%) and Clair (Hess 9.3%) fields. Natural gas production from the United Kingdom in 2006 was 244,000 mcf of natural gas per day compared with 222,000 mcf per day in 2005, primarily from gas fields in the Easington Catchment Area (Hess 28.8%), as well as Everest (Hess 18.7%), Lomond (Hess 16.7%) and Beryl (Hess 22.2%). In addition, production from the Atlantic (Hess 25%) and Cromarty (Hess 90%) fields commenced in June of 2006 and the fields produced at a combined rate of approximately 95,000 mcf per day net to Hess in the second half of 2006.
 
In the first half of 2007, the Corporation expects to complete the sale of its interests in the Scott and Telford fields with an effective date of January 1, 2007 for approximately $100 million. The Corporation’s share of net production from these fields was 9,000 barrels of oil equivalent per day at the end of 2006.
 
Norway:  Crude oil and natural gas liquids production was 23,000 barrels per day in 2006 and 27,000 barrels per day in 2005. Natural gas production averaged 22,000 mcf per day in 2006 and 28,000 mcf per day in 2005. Substantially all of the Norwegian production is from the Corporation’s interest in the Valhall field (Hess 28.1%).


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Denmark:  Net production from the Corporation’s interest in the South Arne field (Hess 57.5%) was 19,000 barrels of crude oil per day in 2006 and 24,000 barrels of crude oil per day in 2005. Natural gas production was 17,000 mcf per day in 2006 and 24,000 mcf per day in 2005.
 
Russia:  The Corporation’s activities in Russia are conducted through its 80%-owned interest in a corporate joint venture operating in the Volga-Urals region of Russia. Production averaged 18,000 barrels of crude oil per day in 2006 compared to 6,000 barrels per day in 2005. The Corporation’s initial interest in its Russian joint venture was acquired during 2005.
 
  Africa
 
During 2006, 33% of the Corporation’s crude oil and natural gas liquids production was from African operations.
 
Equatorial Guinea:  The Corporation is the operator and owns an interest in Block G (Hess 85%) which contains the Ceiba field and Okume Complex. Net production from the Ceiba field averaged 28,000 barrels of crude oil per day in 2006 and 30,000 barrels per day in 2005. Production of crude oil from the Okume Complex commenced in December 2006. The Corporation estimates that its net share of 2007 production from the Okume Complex will average approximately 20,000 barrels of oil per day. In 2007, the Corporation plans to complete the construction of offshore production facilities and to drill additional development wells at the Okume Complex.
 
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 22,000 and 25,000 barrels of crude oil per day in 2006 and 2005, respectively. The Corporation has also submitted a plan of development for a small oil discovery on Block 401C, which is currently awaiting government approval.
 
Libya:  In January 2006, the Corporation, in conjunction with its Oasis Group partners, re-entered its former oil and gas production operations in the Waha concessions in Libya (Hess 8.16%). The re-entry terms included a 25-year extension of the concessions and payments by the Corporation to the Libyan National Oil Corporation of $359 million. The Corporation’s net share of 2006 production from Libya averaged 23,000 barrels of oil per day. The Corporation also owns a 100% interest in offshore exploration Area 54.
 
Gabon:  Through its 77.5% owned Gabonese subsidiary, the Corporation has interests in the Rabi Kounga, Toucan and Atora fields. The Corporation’s share of production averaged 12,000 barrels of crude oil per day in 2006 and 2005.
 
Egypt:  In January 2006, the Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a 25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities.
 
  Asia and Other
 
During 2006, 5% of the Corporation’s crude oil and natural gas liquids production and 36% of its natural gas production were from Asian operations.
 
Joint Development Area of Malaysia and Thailand:  The Corporation owns an interest in the production sharing agreement covering Block A-18 of the Joint Development Area (JDA) (Hess 50%) in the Gulf of Thailand. Net production averaged 131,000 mcf of natural gas and 2,000 barrels of crude oil per day in 2006 compared to 51,000 mcf of natural gas and 1,000 barrels of crude oil per day in 2005. In 2007, the Corporation’s capital investments in the JDA will be primarily focused on facilities expansion and development drilling associated with the additional contracted gas sales of 400,000 mcf per day (gross) in 2008. It is anticipated that production associated with these additional gas sales will begin ramping up in the fourth quarter of 2007.
 
Thailand:  The Corporation has an interest in the Pailin gas field (Hess 15%) offshore Thailand. Net production from the Corporation’s interest averaged 60,000 mcf and 57,000 mcf of natural gas per day in 2006 and 2005, respectively. The Corporation is the operator and owns an interest in the onshore natural gas project in the Phu


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Horm Block (Hess 35%) which commenced production in November 2006. The Corporation estimates its net share of 2007 production from Phu Horm will average approximately 30,000 mcf of natural gas per day.
 
Indonesia:  The Corporation’s net share of natural gas production from Indonesia averaged 26,000 mcf per day in 2006 and 25,000 mcf per day in 2005 primarily from its interest in the Natuna A gas field (Hess 23%). The Ujung Pangkah project (Hess 75%), where the Corporation is the operator, is expected to commence gas sales by mid 2007 under an existing gas sales agreement for 440 million mcf (gross) over a 20 year period with an expected plateau rate of 100,000 mcf per day (gross). The Corporation’s plans for Ujung Pangkah in 2007 include drilling additional development wells, the completion of onshore and offshore gas facilities and the commencement of a crude oil development project. The Corporation also owns an interest in the Jambi Merang natural gas project (Hess 25%).
 
Azerbaijan:  The Corporation has an interest in the Azeri-Chirag-Gunashli (ACG) fields (Hess 2.72%) in the Caspian Sea. Net production from its interest averaged 7,000 barrels of crude oil per day in 2006 and 4,000 barrels per day in 2005. Phase 2 production from the ACG fields commenced during 2006. The Corporation also holds an interest in the Baku-Tbilisi-Ceyhan (BTC) Pipeline (Hess 2.36%), which started operation in the second quarter of 2006.
 
Oil and Gas Reserves
 
The Corporation’s net proved oil and gas reserves at the end of 2006, 2005 and 2004 are presented under Supplementary Oil and Gas Data on pages 80 and 81 in the accompanying financial statements.
 
During 2006, the Corporation provided oil and gas reserve estimates for 2005 to the United States Department of Energy. Such estimates are compatible with the information furnished to the SEC on Form 10-K for the year ended December 31, 2005, 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. In the United States, natural gas is sold on a spot basis and under contracts for varying periods to local distribution companies, and commercial, industrial and other purchasers. The Corporation’s United States natural gas production is expected to approximate 20% of its 2007 sales commitments under long-term contracts. 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 and by leasing storage facilities. In international markets, the Corporation generally sells its natural gas production under long-term sales contracts. In the United Kingdom, the Corporation also sells a portion of its natural gas production on a spot basis.
 
Average selling prices and average production costs
 
                         
    2006     2005     2004  
 
Average selling prices (including the effects of hedging) (Note A)
                       
Crude oil, including condensate and natural gas liquids (per barrel)
                       
United States
  $ 57.41     $ 33.86     $ 27.87  
Europe
    55.80       33.30       26.24  
Africa
    51.18       32.10       26.35  
Asia and other
    61.52       54.69       38.36  
Worldwide
    54.81       33.69       26.86  
Natural gas (per mcf)
                       
United States
  $ 6.59     $ 7.93     $ 5.18  
Europe
    6.20       5.29       3.96  
Asia and other
    4.05       4.02       3.90  
Worldwide
    5.50       5.65       4.31  
 


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    2006     2005     2004  
 
Average production (lifting) costs per barrel of oil equivalent produced (Note B)
                       
United States
  $ 9.54     $  7.46     $  6.42  
Europe
    10.73       8.13       6.35  
Africa
    9.03       7.99       7.72  
Asia and other
    6.54       7.29       6.05  
Worldwide
    9.55       7.91       6.59  
 
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. Production costs in 2005 exclude Gulf of Mexico hurricane related expenses. The average production costs per barrel of oil equivalent reflect the crude oil equivalent of natural gas production converted based on the basis of relative energy content (six mcf equals one barrel).
 
The table above does not include costs of finding and developing proved oil and gas reserves, or the costs of related general and administrative expenses, interest expense and income taxes.
 
Gross and net undeveloped acreage at December 31, 2006
 
                 
    Undeveloped
 
    Acreage (Note A)  
    Gross     Net  
    (In thousands)  
 
United States
    2,199       1,672  
Europe
    2,893       984  
Africa
    13,527       9,572  
Asia and other
    16,486       10,016  
                 
Total (Note B)
    35,105       22,244  
                 
 
Note A:  Includes acreage held under production sharing contracts.
 
Note B:  Approximately 5% of net undeveloped acreage held at December 31, 2006 will expire during the next three years.
 
Gross and net developed acreage and productive wells at December 31, 2006
 
                                                 
    Developed
             
    Acreage
             
    Applicable to
    Productive Wells (Note A)  
    Productive Wells     Oil     Gas  
    Gross     Net     Gross     Net     Gross     Net  
    (In thousands)                          
United States
    450       385       708       396       74       59  
Europe
    1,183       587       283       98       163       37  
Africa
    9,919       958       844       105       3        
Asia and other
    2,185       624       40       3       320       60  
                                                 
Total
    13,737       2,554       1,875       602       560       156  
                                                 
 
Note A:  Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 301 gross wells and 62 net wells.

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Number of net exploratory and development wells drilled
 
                                                 
    Net Exploratory
    Net Development
 
    Wells     Wells  
    2006     2005     2004     2006     2005     2004  
 
Productive wells
                                               
United States
    1        –       4       24       28       32  
Europe
    1        3             20       6       5  
Africa
           1       1       17       12       12  
Asia and other
    6        1       1       11       8       2  
                                                 
Total
    8        5       6       72       54       51  
                                                 
Dry holes
                                               
United States
    4        2       1             2        
Europe
          1        1                   1  
Africa
           1       2             1       1  
Asia and other
           –       1                   1  
                                                 
Total
    4        4       5             3       3  
                                                 
Total
    12        9       11       72       57       54  
                                                 
 
Number of wells in process of drilling at December 31, 2006
 
                 
    Gross
    Net
 
    Wells     Wells  
 
United States
    12       7  
Europe
    13       6  
Africa
    21       8  
Asia and other
    19       4  
                 
Total
    65       25  
                 
 
Number of waterfloods and pressure maintenance projects in process of installation at December 31, 2006 — 2
 
Marketing and Refining
 
Refined product sales of the M&R businesses were as follows:
 
                 
    2006     2005  
    (Thousands of barrels per day)  
 
Gasoline
    218       213  
Distillates
    144       136  
Residuals
    60       64  
Other
    37       43  
                 
Total
    459       456  
                 
 
Refining:  The Corporation owns a 50% interest in HOVENSA L.L.C. (HOVENSA), a 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.


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HOVENSA:  Refining operations at HOVENSA consist of crude units, a fluid catalytic cracking unit and a delayed coker unit. The following table summarizes capacity and utilization rates for HOVENSA:
 
                 
    Refinery
    Refinery Utilization
    Capacity     2006   2005
    (Thousands of
         
    barrels per day)          
 
Crude
    500       89.7%       92.2%  
Fluid catalytic cracker
    150     84.3%   81.9%
Coker
    58     84.3%   92.8%
 
The fluid catalytic cracking unit at HOVENSA was shut down for approximately 22 days of unscheduled maintenance in 2006.
 
The delayed coker unit 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 medium gravity 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 unrelated 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, with a capacity of 65,000 barrels per day. This facility processes residual fuel oil and vacuum gas oil and operated at a rate of approximately 63,000 barrels per day in 2006 and 55,000 barrels per day in 2005. Substantially all of Port Reading’s production is gasoline and heating oil.
 
Marketing:  The Corporation markets refined petroleum products on the East Coast of the United States to the motoring public, wholesale distributors, industrial and commercial users, other petroleum companies, governmental agencies and public utilities. It also markets natural gas and electricity to utilities and other industrial and commercial customers. During 2006 and 2005, the Corporation selectively expanded its energy marketing business by acquiring natural gas and electricity customer accounts.
 
The Corporation has 1,350 HESS® gasoline stations at December 31, 2006, including stations owned by the WilcoHess joint venture (Hess 44%). Approximately 88% of the gasoline stations are operated by the Company or WilcoHess. Of the operated stations, 92% have convenience stores on the sites. Most of the Corporation’s gasoline stations are in New York, New Jersey, Pennsylvania, Florida, Massachusetts, North Carolina and South Carolina.
 
Refined product sales averaged 459,000 barrels per day in 2006 and 456,000 barrels per day in 2005. Of total refined products sold in 2006, approximately 50% was obtained from HOVENSA and Port Reading. The Corporation purchased the balance from others under short-term supply contracts and by spot purchases from various sources.
 
The Corporation has 22 terminals with an aggregate storage capacity of 22 million barrels in its East Coast marketing areas.
 
The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and derivatives. The Corporation also takes energy commodity and derivative trading positions for its own account.
 
The Corporation also has a 50% interest in a joint venture, Hess LNG, which is pursuing investments in liquefied natural gas (LNG) terminals and related supply, trading and marketing opportunities. The joint venture is pursuing the development of LNG terminal projects located in Fall River, Massachusetts and Shannon, Ireland.
 
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.


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Competition and Market Conditions
 
See Item 1A, Risk Factors Related to Our Business and Operations, for a discussion of competition and market conditions.
 
Other Items
 
Compliance with various existing environmental and pollution control regulations imposed by federal, state, local and foreign governments is not expected to have a material adverse effect on the Corporation’s earnings and competitive position within the industry. The Corporation spent $15 million in 2006 for environmental remediation. The United States Environmental Protection Agency (EPA) has adopted rules that limit the amount of sulfur in gasoline and diesel fuel. Capital expenditures necessary to comply with the low-sulfur gasoline requirements at Port Reading were $72 million, of which $23 million was spent in 2005 and the remainder was spent in 2006. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are expected to be approximately $420 million, of which $360 million has been spent to date and the remainder will be spent in 2007. HOVENSA expects to finance these capital expenditures through cash flow from operations.
 
The number of persons employed by the Corporation at year end was approximately 13,700 in 2006 and 12,800 in 2005.
 
The Corporation’s Internet address is www.hess.com. On its website, the Corporation makes available free of charge its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after the Corporation electronically files with or furnishes such material to the Securities and Exchange Commission. Copies of the Corporation’s Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the charters of the Audit Committee, the Compensation and Management Development Committee and the Corporate Governance and Nominating Committee of the Board of Directors are available on the Corporation’s website and are also available free of charge upon request to the Secretary of the Corporation at its principal executive offices. The Corporation has also filed with the New York Stock Exchange (NYSE) its annual certification that the Corporation’s chief executive officer is unaware of any violation of the NYSE’s corporate governance standards.
 
Item 1A.   Risk Factors Related to Our Business and Operations
 
Our business activities and the value of our securities are subject to significant risk factors, including those described below. The risk factors described below could negatively affect our operations, financial condition, liquidity and results of operations, and as a result holders and purchasers of our securities could lose part or all of their investments. It is possible additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.
 
Commodity Price Risk:  Our estimated proved reserves, revenue, operating cash flows, operating margins, future earnings and trading operations are highly dependent on the prices of crude oil, natural gas and refined petroleum products, which are influenced by numerous factors beyond our control. Historically these prices have been very volatile. 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 the oil markets. The derivatives markets may also influence the selling prices of crude oil, natural gas and refined petroleum products. A significant downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow and could result in a reduction in the carrying value of our oil and gas assets, goodwill and proved oil and gas reserves. To the extent that we engage in hedging activities to mitigate commodity price volatility, we will not realize the benefit of price increases above the hedged price.
 
Technical Risk:  We own or have access to a finite amount of oil and gas reserves which will be depleted over time. Replacement of oil and gas reserves is subject to successful exploration drilling, development activities, and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding


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and developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks include adverse unexpected conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions. Future developments may be affected by unforeseen reservoir conditions which negatively affect recovery factors or flow rates. The costs of drilling and development activities have also been increasing, which could negatively affect expected economic returns. Although due diligence is used in evaluating acquired oil and gas properties, similar uncertainties may be encountered in the production of oil and gas on properties acquired from others.
 
Oil and Gas Reserves and Discounted Future Net Cash Flow Risks:  Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, geologic success and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities and future net revenues of our proved reserves. In addition, reserve estimates may be subject to downward or upward revisions based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices, production sharing contracts which may decrease reserves as crude oil and natural gas prices increase, and other factors.
 
Political Risk:  Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, expropriation of property, cancellation of contract rights, and changes in import regulations, as well as other political developments may affect our operations. For example, during 2006, the governments of the United Kingdom and Algeria increased taxation on our crude oil and natural gas revenues in response to higher crude oil and natural gas prices. Some of the international areas in which we operate may be politically less stable than our domestic operations. In addition, the increasing threat of terrorism around the world poses additional risks to the operations of the oil and gas industry. In our M&R segment, we market 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.
 
Environmental Risk:  Our oil and gas operations, like those of the industry, are subject to environmental hazards such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. Our operations are also subject to numerous United States federal, state, local and foreign environmental laws and regulations. Non-compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups and natural resource damages or other liabilities. In addition, increasingly stringent environmental regulations, particularly relating to the production of motor and other fuels, has resulted, and will likely continue to result, in higher capital expenditures and operating expenses for us and the oil and gas industry generally.
 
Competitive Risk:  The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies in each of our 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, including national oil companies, are larger and have substantially greater resources. We are also in competition with producers and marketers of other forms of energy. Increased competition for worldwide oil and gas assets has significantly increased the cost of acquisitions. In addition, competition for drilling services and equipment has affected the availability of drilling rigs and increased capital and operating costs.
 
Catastrophic Risk:  Although we maintain an appropriate level of insurance coverage against property and casualty losses, our oil and gas operations are subject to unforeseen occurrences which may damage or destroy assets or interrupt operations. Examples of catastrophic risks include hurricanes, fires, explosions and blowouts. These occurrences have affected us from time to time. During 2005, our annual Gulf of Mexico production of crude oil and natural gas was reduced by 7,000 barrels of oil equivalent per day (boepd) due to the impact of Hurricanes Katrina and Rita.


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Item 3.   Legal Proceedings
 
Purported class actions consolidated under a complaint captioned: In re Amerada Hess Securities Litigation were filed in United States District Court for the District of New Jersey against the Registrant and certain executive officers and former executive officers of the Registrant alleging that these individuals sold shares of the Registrant’s common stock in advance of the Registrant’s acquisition of Triton Energy Limited (Triton) in 2001 in violation of federal securities laws. In April 2003, the Registrant and the other defendants filed a motion to dismiss for failure to state a claim and failure to plead fraud with particularity. On March 31, 2004, the court granted the defendants’ motion to dismiss the complaint. The plaintiffs were granted leave to file an amended complaint. Plaintiffs filed an amended complaint in June 2004. Defendants moved to dismiss the amended complaint. In June 2005, this motion was denied. On January 30, 2007, the District Court issued an order preliminarily approving settlement of this action and providing for notice to members of the class of plaintiffs. While continuing to deny the allegations of the complaint and all charges of wrongdoing or liability arising in connection with the subject matter of the action, the defendants agreed with plaintiffs to settle the action on the terms set forth in the stipulation of settlement in order to avoid the cost, inconvenience and uncertainty of continued protracted litigation. Under the terms of the settlement, defendants have caused to be deposited into an escrow account the sum of $9 million, which after payment of certain administrative expenses and plaintiffs’ attorney fees, will be distributed according to a plan of allocation to class members who submit valid and timely proof of claim and release forms. All of the amount deposited was paid by the defendants’ insurer. The settlement is subject to final approval of the district court and certain other conditions, including that not more than 5% of shares owned by class members eligible to participate in the settlement elect to opt out of the settlement.
 
The Registrant, along with many other companies engaged in refining and marketing of gasoline, has been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. A series of substantially identical lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produce gasoline containing MTBE, including the Registrant. These cases have been consolidated in the Southern District of New York and the Registrant is named as a defendant in 43 of the 69 cases pending. The principal allegation in all cases 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. In some cases, punitive damages are also sought. In April 2005, the District Court denied the primary legal aspects of the defendants’ motion to dismiss these actions. While the damages claimed in these actions are substantial, only limited information is available to evaluate the factual and legal merits of those claims. The Corporation also believes that significant legal uncertainty remains regarding the validity of causes of action asserted and availability of the relief sought by plaintiffs. Accordingly, based on the information currently available, there is insufficient information on which to evaluate the Corporation’s exposure in these cases.
 
Over the last several years, many refiners have entered into consent agreements to resolve the EPA’s assertions that refining facilities were modified or expanded without complying with New Source Review regulations that require permits and new emission controls in certain circumstances and other regulations that impose emissions control requirements. These consent agreements, which arise out of an EPA enforcement initiative focusing on petroleum refiners and utilities, have typically imposed substantial civil fines and penalties and required (i) significant capital expenditures to install emissions control equipment over a three to eight year time period and (ii) changes to operations which resulted in increased operating costs. Settlements under Petroleum Refining Initiative consent agreements to date have averaged $335 per barrel per day of refining capacity. However the capital expenditures, penalties and supplemental environmental projects for individual refineries covered by the settlements can vary significantly, depending on the size and configuration of the refinery, the circumstances of the alleged modifications and whether the refinery has previously installed more advanced pollution controls. EPA initially 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 discussions resumed in August 2005. The Registrant and HOVENSA have had and expect to have further discussions with the EPA regarding the Petroleum Refining Initiative, although both the Registrant and HOVENSA have already installed many of the pollution controls required of other refiners under the consent agreements and the EPA has not made any specific


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assertions that either Registrant or HOVENSA violated either New Source Review or other regulations which would require additional controls. While the effect on the Corporation of the Petroleum Refining Initiative cannot be estimated at this time, additional future capital expenditures and operating expenses may be incurred. The amount of penalties, if any, is not expected to be material to the Corporation.
 
In December 2006, HOVENSA received a Notice of Violation (NOV) from the EPA alleging non-compliance with emissions limits in a permit issued by the Virgin Islands Department of Planning and Natural Resources (DPNR) for the two process heaters in the delayed coking unit. The NOV was issued in response to a voluntary investigation and submission by HOVENSA regarding potential non-compliance with the permit emissions limits for two pollutants. Any exceedances were minor from the perspective of the amount of pollutants emitted in excess of the limits. HOVENSA intends to work with the appropriate governmental agency to reach resolution of this matter and does not believe that it will result in material liability.
 
Registrant is one of over 60 companies that have received a directive from the New Jersey Department of Environmental Protection (NJDEP) 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 the Registrant. EPA has also issued an Administrative Order on Consent relating to the same contamination. While NJDEP has suggested a remedial cost of over $900 million, the costs of remediation of the Passaic River sediments are the subject of a remedial investigation and feasibility study currently being conducted on a portion of the river by the EPA under an agreement with Registrant and over 40 other companies. Thus, remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, the Registrant does not believe that this matter will result in material liability because its terminal could not have contributed contamination along most of the river’s length and did not store or use contaminants which are of the greatest concern in the river sediments, and because there are numerous other parties who will likely share in the cost of remediation and damages.
 
On or about July 15, 2004, Hess Oil Virgin Islands Corp. (HOVIC), a wholly owned subsidiary of the Registrant, and HOVENSA, in which Registrant owns a 50% interest, each received a letter from the Commissioner of the Virgin Islands Department of Planning and Natural Resources and Natural Resources Trustees, advising of the Trustee’s intention to bring suit against HOVIC and HOVENSA under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The letter alleges that HOVIC and HOVENSA are potentially responsible for damages to natural resources arising from releases of hazardous substances from the “HOVENSA Oil Refinery.” HOVENSA currently owns and operates a petroleum refinery on the south shore of St. Croix, United States Virgin Islands, which had been operated by HOVIC until October 1998. An action was filed on May 5, 2005 in the District Court of the Virgin Islands against HOVENSA, HOVIC and other companies that operated industrial facilities on the south shore of St. Croix asserting that the defendants are liable under CERCLA and territorial statutory and common law for damages to natural resources. HOVIC and HOVENSA do not believe that this matter will result in a material liability as they believe that they have strong defenses to this complaint, and they intend to vigorously defend this matter.
 
The Securities and Exchange Commission (SEC) has notified the Registrant that on July 21, 2005, it commenced a private investigation into payments made to the government of Equatorial Guinea or to officials and persons affiliated with officials of the government of Equatorial Guinea. The staff of the SEC has requested documents and information from the Registrant and other oil and gas companies that have operations or interests in Equatorial Guinea. The staff of the SEC had previously been conducting an informal inquiry into such matters. The Registrant has been cooperating and continues to cooperate with the SEC investigation.
 
Registrant has been served with a complaint from the New York State Department of Environmental Conservation (DEC) relating to alleged violations at its petroleum terminal in Brooklyn, New York. The complaint, which seeks an order to shut down the terminal and penalties in unspecified amounts, alleges violations involving the structural integrity of certain tanks, the erosion of shorelines and bulkheads, petroleum discharges and improper certification of tank repairs. DEC is also seeking relief relating to remediation of certain gasoline stations in the New York metropolitan area. Registrant believes that many of the allegations are factually inaccurate or based on an incorrect interpretation of applicable law. Registrant has already addressed the primary conditions discussed in the


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


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Item 4.   Submission of Matters to a Vote of Security Holders
 
During the fourth quarter of 2006, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise.
 
Executive Officers of the Registrant
 
The following table presents information as of February 1, 2007 regarding executive officers of the Registrant:
 
                     
            Year Individual
            Became an
            Executive
Name
 
Age
  Office Held*  
Officer
 
John B. Hess
  52   Chairman of the Board, Chief Executive Officer and Director   1983
J. Barclay Collins II
  62   Executive Vice President, General Counsel and Director   1986
John J. O’Connor
  60   Executive Vice President, President of Worldwide Exploration and Production and Director   2001
F. Borden Walker
  53   Executive Vice President and President of Marketing and Refining and Director   1996
Brian J. Bohling
  46   Senior Vice President   2004
E. Clyde Crouch
  58   Senior Vice President   2003
John A. Gartman
  59   Senior Vice President   1997
Scott Heck
  49   Senior Vice President   2005
Lawrence H. Ornstein
  55   Senior Vice President   1995
Howard Paver
  56   Senior Vice President   2002
John P. Rielly
  44   Senior Vice President and Chief Financial Officer   2002
George F. Sandison
  50   Senior Vice President   2003
John J. Scelfo
  49   Senior Vice President   2004
Robert P. Strode
  50   Senior Vice President   2000
Robert J. Vogel
  47   Vice President & Treasurer   2004
 
 
* 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 3, 2006. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 2, 2007.
 
Except for Messrs. Bohling, Sandison and Scelfo, 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. Bohling was employed in senior human resource positions with American Standard Corporation and CDI Corporation before joining the Registrant in 2004. Mr. Scelfo was chief financial officer of Sirius Satellite Radio and a division of Dell Computer before his employment by the Registrant in 2003. Mr. Sandison served in senior executive positions in the area of global drilling with Texaco, Inc. before he was employed by the Registrant in 2003.


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PART II
 
Item 5.   Market for the Registrant’s Common Stock and Related Stockholder Matters
 
Stock Market Information
 
The common stock of Hess Corporation is traded principally on the New York Stock Exchange (ticker symbol: HES). High and low sales prices were as follows:
 
                                 
    2006     2005  
Quarter Ended*
  High     Low     High     Low  
 
March 31
  $  52.00     $  42.83     $  34.65     $  25.94  
June 30
    53.46       43.23       37.39       28.75  
September 30
    56.45       38.30       47.50       35.53  
December 31
    52.70       37.62       46.33       36.67  
 
 
* Prices for all periods reflect the impact of a 3-for-1 stock split on May 31, 2006.
 
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: HESPR) were as follows**:
 
                                 
    2006     2005  
Quarter Ended
  High     Low     High     Low  
 
March 31
  $ 130.65     $ 111.11     $  90.33     $  70.47  
June 30
    133.65       109.90       95.75       74.75  
September 30
    140.20       98.61       120.17       91.32  
December 31**
    124.94       95.00       117.56       95.33  
 
 
** On December 1, 2006, each share of the Corporation’s 7% Mandatory Convertible Preferred Stock was converted into 2.4915 shares of its common stock.


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Performance Graph
 
Set forth below is a line graph comparing the cumulative total shareholder return, assuming reinvestment of dividends, on the Corporation’s common stock with the cumulative total return, assuming reinvestment of dividends, of:
 
  •  Standard & Poor’s 500 Stock Index, which includes the Corporation, and
 
  •  AMEX Oil Index, which is comprised of companies involved in various phases of the oil industry including the Corporation.
 
As of each December 31, over a five-year period commencing on December 31, 2001 and ending on December 31, 2006:
 
Total Shareholder Returns
(Dividends Reinvested)
Years Ended December 31
 
PERFORMANCE GRAPH
 
As a result of consolidations in the oil and gas industry, the Corporation believes that the peer group it had used previously had too few participants and has selected the AMEX Oil Index, a published industry index that includes the Corporation and 12 additional oil and gas companies, for purposes of the performance graph shown above.
 
Holders
 
At December 31, 2006, there were 5,572 stockholders (based on number of holders of record) who owned a total of 315,017,951 shares of common stock.
 
Dividends
 
Cash dividends on common stock totaled $.40 per share ($.10 per quarter) during 2006 and 2005 on a split adjusted basis. Dividends on the 7% cumulative mandatory convertible preferred stock totaled $3.21 per share in 2006 prior to conversion on December 1, 2006 and $3.50 per share ($.875 per quarter) in 2005. See note 8, “Long-Term Debt,” in the notes to the financial statements for a discussion of restrictions on dividends.


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Equity Compensation Plans
 
Following is information on the Registrant’s equity compensation plans at December 31, 2006:
 
                         
                Number of
 
                Securities
 
                Remaining
 
                Available for
 
    Number of
          Future Issuance
 
    Securities to
    Weighted
    Under Equity
 
    be Issued
    Average
    Compensation
 
    Upon Exercise
    Exercise Price
    Plans
 
    of Outstanding
    of Outstanding
    (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
    12,923,000     $ 29.68       11,698,000 *
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 pursuant to which each non-employee director receives $150,000 in value of Registrant’s common stock each year. These awards are made from shares purchased by the Company in the open market. Stockholders did not approve this equity compensation plan.
 
See note 9, “Share-Based Compensation,” in the notes to the financial statements for further discussion of the Corporation’s equity compensation plans.


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Item 6.   Selected Financial Data
 
A five-year summary of selected financial data follows:
 
                                         
    2006     2005     2004     2003     2002  
    (Millions of dollars, except per share amounts)  
 
Sales and other operating revenues
                                       
Crude oil and natural gas liquids
  $ 5,307     $ 3,219     $ 2,594     $ 2,295     $ 2,702  
Natural gas (including sales of purchased gas)
    6,826       6,423       4,638       4,522       3,077  
Petroleum and other energy products
    14,411       11,690       8,125       6,250       4,635  
Convenience store sales and other operating revenues
    1,523       1,415       1,376       1,244       1,137  
                                         
Total
  $ 28,067     $ 22,747     $ 16,733     $ 14,311     $ 11,551  
                                         
Income (loss) from continuing operations
  $ 1,916 (a)   $ 1,242 (b)   $ 970 (c)   $ 467 (d)   $ (245 )(e)
Discontinued operations
     —        —       7       169       27  
Cumulative effect of change in accounting principle
                      7        
                                         
Net income (loss)
  $ 1,916     $ 1,242     $ 977     $ 643     $ (218 )
                                         
Less preferred stock dividends
    44       48       48       5        
                                         
Net income (loss) applicable to common shareholders
  $ 1,872     $ 1,194     $ 929     $ 638     $ (218 )
                                         
Basic earnings (loss) per share *
                                       
Continuing operations
  $ 6.73     $ 4.38     $ 3.43     $ 1.74     $ (.93 )
Net income (loss)
    6.73       4.38       3.46       2.40       (.83 )
Diluted earnings (loss) per share *
                                       
Continuing operations
  $ 6.07     $ 3.98     $ 3.17     $ 1.72     $ (.93 )
Net income (loss)
    6.07       3.98       3.19       2.37       (.83 )
Total assets
  $ 22,404     $ 19,115     $ 16,312     $ 13,983     $ 13,262  
Total debt
    3,772       3,785       3,835       3,941       4,992  
Stockholders’ equity
    8,111       6,286       5,597       5,340       4,249  
Dividends per share of common stock *
  $ .40     $ .40     $ .40     $ .40     $ .40  
 
 
* Per share amounts in all periods reflect the impact of a 3-for-1 stock split on May 31, 2006.
 
(a) Includes net after-tax income of $173 million primarily from sales of assets, partially offset by income tax adjustments and accrued leased office closing costs.
 
(b) Includes after-tax expenses of $37 million primarily relating to income taxes on repatriated earnings, premiums on bond repurchases and hurricane related expenses, partially offset by gains from asset sales and a LIFO inventory liquidation.
 
(c) Includes net after-tax income of $76 million primarily from sales of assets and income tax adjustments.
 
(d) Includes net after-tax expenses of $25 million, principally from premiums on bond repurchases and accrued severance and leased office closing costs, partially offset by income tax adjustments and asset sales.
 
(e) Includes net after-tax expenses aggregating $708 million, principally resulting from asset impairments.


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview
 
The Corporation is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. The M&R segment manufactures, purchases, transports, trades and markets refined petroleum products, natural gas and electricity.
 
Net income in 2006 was $1,916 million compared with $1,242 million in 2005 and $977 million in 2004. Diluted earnings per share were $6.07 in 2006 compared with $3.98 in 2005 and $3.19 in 2004.
 
Exploration and Production
 
The Corporation’s strategy for the E&P segment is to profitably grow reserves and production in a sustainable and financially disciplined manner. At December 31, 2006 and 2005, the Corporation’s total proved reserves were 1,243 million and 1,093 million barrels of oil equivalent. The following table summarizes the components of proved reserves as of December 31:
 
                                 
    2006     2005  
 
Crude oil and condensate (millions of barrels)
                               
U.S. 
    138       17 %     124       18 %
International
    694       83       568       82  
                                 
Total
    832       100 %     692       100 %
                                 
Natural gas (millions of mcf)
                               
U.S. 
    236       10 %     282       12 %
International
    2,230       90       2,124       88  
                                 
Total
    2,466       100 %     2,406       100 %
                                 
 
 
E&P net income was $1,763 million in 2006, $1,058 million in 2005 and $762 million in 2004. The improved results were primarily driven by higher average crude oil selling prices during the reporting period and lower hedged crude oil volumes in 2006. See further discussion in Comparison of Results on page 24.
 
Production totaled 359,000 barrels of oil equivalent per day (boepd) in 2006, 335,000 boepd in 2005 and 342,000 boepd in 2004. The Corporation estimates that production will be approximately 370,000 boepd to 380,000 boepd in 2007.
 
During 2006, the Corporation commenced production from four new field developments:
 
  •  The Atlantic (Hess 25%) and Cromarty (Hess 90%) natural gas fields in the United Kingdom came onstream in June 2006 and produced at a combined net rate of approximately 95,000 mcf per day in the second half of the year.
 
  •  The Okume Complex development (Hess 85%) in Equatorial Guinea commenced production in December. Additional development activities are planned throughout 2007. The Corporation estimates that its net share of 2007 production will average approximately 20,000 boepd.
 
  •  First production from the Phu Horm onshore gas project (Hess 35%) in Thailand commenced in November. The Corporation estimates that its net share of 2007 production will average approximately 30,000 mcf per day.
 
  •  Phase 2 production from the ACG fields (Hess 2.7%) in Azerbaijan also commenced during 2006.
 
The Corporation has several additional development projects that will also increase production in the future:
 
  •  Development of the Shenzi field (Hess 28%) in the deepwater Gulf of Mexico was sanctioned and first production is anticipated in the second half of 2009.


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  •  The Genghis Khan field (Hess 28%) was acquired by the Shenzi partners in February 2007. The field is part of the same geologic structure as the Shenzi development and first production is anticipated in the second half of 2007.
 
  •  The Ujung Pangkah field (Hess 75%) in Indonesia is scheduled to commence production of natural gas by mid 2007 under an existing gas sales agreement for 440 million mcf (gross) over a 20 year period with an expected plateau rate of 100,000 mcf per day (gross). The Corporation’s plans for Ujung Pangkah in 2007 also include drilling additional development wells and the commencement of a crude oil development project.
 
  •  Capital investments in the JDA (Hess 50%) will be made during 2007 which will be primarily focused on facilities expansion and development drilling associated with the anticipated commencement of additional contracted gas sales of 400,000 mcf per day (gross) in 2008. It is anticipated that production associated with these additional gas sales will begin ramping up in the fourth quarter of 2007.
 
  •  Development of the residual oil zone at the Seminole - San Andres Unit (Hess 34.3%) in the Permian Basin is expected to commence in 2007 and production is anticipated to begin in 2009.
 
During 2006, the Corporation’s exploration program had several successes, particularly in the deepwater Gulf of Mexico:
 
  •  An exploration well on the Corporation’s Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico encountered 475 feet of oil saturated sandstone in Miocene age reservoirs. Drilling of an appraisal sidetrack well on the Pony Prospect was completed in January 2007 which encountered 280 feet of oil saturated sandstone in Miocene age reservoirs after penetrating 60% of its geological objective. Drilling of the sidetrack well was stopped for mechanical reasons after successfully recovering 450 feet of conventional core. The Corporation is currently drilling an appraisal well about 7,400 feet northwest of the discovery well.
 
  •  On the Tubular Bells prospect (Hess 20%) in the Mississippi Canyon area of the deepwater Gulf of Mexico a successful appraisal well encountered hydrocarbons approximately 5 miles from the initial discovery well. The operator intends to drill two sidetrack wells in 2007 which will further delineate the field.
 
In addition, during 2006, the Corporation made the following acquisitions and also disposed of several producing properties:
 
  •  In January 2006, the Corporation, in conjunction with its Oasis Group partners, re-entered its former oil and gas production operations in the Waha concessions (Hess 8.16%) in Libya. The re-entry terms include a 25-year extension of the concessions and payments by the Corporation to the Libyan National Oil Corporation of $359 million. The Corporation’s net share of 2006 production from Libya averaged 23,000 barrels of oil per day.
 
  •  The Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a 25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities.
 
  •  During 2006, the Corporation completed the sale of its interests in certain producing properties in the Permian Basin in Texas and New Mexico and certain U.S. Gulf Coast oil and gas producing assets. These asset sales generated total proceeds of $444 million after closing adjustments and an aggregate after-tax gain of $236 million ($369 million before income taxes). Total net production from assets sold was approximately 8,000 boepd at the time of sale.
 
Marketing and Refining
 
The Corporation’s strategy for the M&R segment is to deliver consistent financial performance and generate free cash flow. M&R net income was $390 million in 2006, $515 million in 2005 and $451 million in 2004. Total Marketing and Refining earnings decreased in 2006 due to lower margins on refined product sales. Refining


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operations contributed net income of $236 million in 2006, $346 million in 2005 and $302 million in 2004. Profitability in 2006 was adversely affected by lower refined product margins. Refining facilities at the HOVENSA joint venture and at Port Reading performed reliably in 2006 with the exception of 22 days of unplanned downtime at HOVENSA early in the year. The Corporation received cash distributions from HOVENSA totaling $400 million in 2006 and $275 million in 2005.
 
In 2006, the Corporation’s Port Reading facility completed its $72 million program for complying with low-sulfur gasoline requirements. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are estimated to be approximately $420 million, of which $360 million has been incurred through the end of 2006 with the remainder to be spent in 2007.
 
Marketing earnings were $108 million in 2006, $136 million in 2005 and $112 million in 2004. During 2006 and 2005, the Corporation selectively expanded its energy marketing business by acquiring natural gas and electricity customer accounts.
 
Liquidity and Capital and Exploratory Expenditures
 
Net cash provided by operating activities was $3,491 million in 2006 compared with $1,840 million in 2005. At December 31, 2006, cash and cash equivalents totaled $383 million compared with $315 million at December 31, 2005. Total debt was $3,772 million at December 31, 2006 compared with $3,785 million at December 31, 2005. The Corporation’s debt to capitalization ratio at December 31, 2006 was 31.7% compared with 37.6% at the end of 2005. The Corporation has debt maturities of $27 million in 2007 and $28 million in 2008.
 
Capital and exploratory expenditures were as follows for the years ended December 31:
 
                 
    2006     2005  
    (Millions of dollars)  
 
Exploration and Production
               
United States
  $ 908     $ 353  
International
    2,979       2,031  
                 
Total Exploration and Production
    3,887       2,384  
Marketing, Refining and Corporate
    169       106  
                 
Total Capital and Exploratory Expenditures
  $ 4,056     $ 2,490  
                 
Exploration expenses charged to income included above:
               
United States
  $ 110     $ 89  
International
    102       60  
                 
    $ 212     $ 149  
                 
 
 
The Corporation anticipates $4.0 billion in capital and exploratory expenditures in 2007, of which $3.9 billion relates to E&P operations. These expenditures include $371 million for the acquisition of a 28% interest in the Genghis Khan development in the deepwater Gulf of Mexico.


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Consolidated Results of Operations
 
The after-tax results by major operating activity are summarized below:
 
                         
    2006     2005     2004  
    (Millions of dollars, except per share data)  
 
Exploration and Production
  $ 1,763     $ 1,058     $ 755  
Marketing and Refining
    390       515       451  
Corporate
    (110 )     (191 )     (85 )
Interest expense
    (127 )     (140 )     (151 )
                         
Income from continuing operations
    1,916       1,242       970  
Discontinued operations
     —        —       7  
                         
Net income
  $ 1,916     $ 1,242     $ 977  
                         
Income per share from continuing operations — diluted*
  $ 6.07     $ 3.98     $ 3.17  
                         
Net income per share — diluted*
  $ 6.07     $ 3.98     $ 3.19  
                         
 
 
* Per share amounts in all periods reflect the impact of a 3-for-1 stock split on May 31, 2006.
 
In the discussion that follows, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the appropriate income tax rate in each tax jurisdiction to pre-tax amounts.
 
The following items of income (expense), on an after-tax basis, are included in net income:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Exploration and Production
                       
Gains from asset sales
  $ 236     $ 41     $ 54  
Income tax adjustments
    (45 )     11       19  
Accrued office closing costs
    (18 )      —       (9 )
Hurricane related costs
          (26 )      
Legal settlement
          11        
Marketing and Refining
                       
LIFO inventory liquidation
          32       12  
Charge related to customer bankruptcy
          (8 )      
Corporate
                       
Tax on repatriated earnings
          (72 )      
Premiums on bond repurchases
          (26 )      
Income tax adjustments
           —       13  
Insurance accrual
           —       (13 )
                         
    $ 173     $ (37 )   $ 76  
                         
 
The items in the table above are explained, and the pre-tax amounts are shown, on pages 26 through 29.


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Comparison of Results
 
Exploration and Production
 
Following is a summarized income statement of the Corporation’s Exploration and Production operations:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Sales and other operating revenues
  $ 6,524     $ 4,210     $ 3,416  
Non-operating income
    428       94       90  
                         
Total revenues
    6,952       4,304       3,506  
                         
Costs and expenses
                       
Production expenses, including related taxes
    1,250       1,007       825  
Exploration expenses, including dry holes and lease impairment
    552       397       287  
General, administrative and other expenses
    209       140       150  
Depreciation, depletion and amortization
    1,159       965       918  
                         
Total costs and expenses
    3,170       2,509       2,180  
                         
Results of operations from continuing operations before income taxes
    3,782       1,795       1,326  
Provision for income taxes
    2,019       737       571  
                         
Results from continuing operations
    1,763       1,058       755  
Discontinued operations
     —        —       7  
                         
Results of operations
  $ 1,763     $ 1,058     $ 762  
                         
 
After considering the Exploration and Production items in the table on page 23, the remaining changes in Exploration and Production earnings are primarily attributable to changes in selling prices, production volumes, operating costs, exploration expenses and income taxes, as discussed below.
 
Selling prices:  Higher average crude oil selling prices and reduced hedge positions increased Exploration and Production revenues by approximately $1,900 million in 2006 compared with 2005. In 2005, the change in average selling prices increased revenues by approximately $870 million compared with 2004.
 
The Corporation’s average selling prices were as follows:
 
                         
    2006     2005     2004  
 
Crude oil-per barrel (including hedging)
                       
United States
  $ 60.45     $ 32.64     $ 27.42  
Europe
    56.19       33.13       26.18  
Africa
    51.18       32.10       26.35  
Asia and other
    61.52       54.71       38.36  
Worldwide
    55.31       33.38       26.70  
Crude oil-per barrel (excluding hedging)
                       
United States
  $ 60.45     $ 51.16     $ 38.56  
Europe
    58.46       52.22       37.57  
Africa
    62.80       51.70       37.07  
Asia and other
    61.52       54.71       38.36  
Worldwide
    60.41       51.94       37.64  


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Table of Contents

                         
    2006     2005     2004  
 
Natural gas liquids-per barrel
                       
United States
  $ 46.22     $ 38.50     $ 29.50  
Europe
    47.30       37.13       27.44  
Worldwide
    46.59       38.08       28.81  
Natural gas-per mcf
                       
United States
  $ 6.59     $ 7.93     $ 5.18  
Europe
    6.20       5.29       3.96  
Asia and other
    4.05       4.02       3.90  
Worldwide
    5.50       5.65       4.31  
 
The after-tax impacts of hedging reduced earnings by $285 million ($449 million before income taxes) in 2006, $989 million ($1,582 million before income taxes) in 2005 and $583 million ($935 million before income taxes) in 2004.
 
Production and sales volumes:  The Corporation’s crude oil and natural gas production was 359,000 boepd in 2006, 335,000 boepd in 2005 and 342,000 boepd in 2004. The Corporation anticipates that its 2007 production will average between 370,000 and 380,000 boepd. The Corporation’s net daily worldwide production was as follows:
 
                         
    2006     2005     2004  
 
Crude oil (thousands of barrels per day)
                       
United States
    36       44       44  
Europe
    109       110       119  
Africa
    85       67       61  
Asia and other
    12       7       4  
                         
Total
    242       228       228  
                         
Natural gas liquids (thousands of barrels per day)
                       
United States
    10       12       12  
Europe
    5       4       6  
                         
Total
    15       16       18  
                         
Natural gas (thousands of mcf per day)
                       
United States
    110       137       171  
Europe
    283       274       319  
Asia and other
    219       133       85  
                         
Total
    612       544       575  
                         
Barrels of oil equivalent* (thousands of barrels per day)
    359       335       342  
                         
 
 
* Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel).
 
Crude oil and natural gas production in the United States was lower in 2006 due to asset sales and natural decline. Production in Europe was comparable in 2006 and 2005, reflecting increased production from Russia and new production from the Atlantic and Cromarty natural gas fields in the United Kingdom, which offset lower production due to maintenance and natural decline. Increased crude oil production in Africa in 2006 was primarily due to production from Libya. Natural gas production in Asia was higher in 2006 due to increased production from the JDA.

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Higher sales volumes increased revenue by approximately $400 million in 2006 compared with 2005. Decreased sales volumes resulted in lower revenue of approximately $80 million in 2005 compared with 2004.
 
Operating costs and depreciation, depletion and amortization:  Cash operating costs, consisting of production expenses and general and administrative expenses, increased by $322 million in 2006 and $147 million in 2005 compared with the corresponding amounts in prior years, excluding the charges for vacated leased office space and hurricane related costs discussed below. Production expenses increased in 2006 and 2005, principally reflecting higher maintenance expenses, increased costs of services, materials and fuel and higher production taxes resulting from higher oil prices. Production expenses also increased in 2006 due to the re-entry into Libya and continued expansion of operations in Russia and the JDA. Depreciation, depletion and amortization charges were higher in 2006, principally reflecting increased production volumes and higher per barrel rates, due to new production from the Atlantic and Cromarty fields and higher asset retirement obligations. Depreciation, depletion and amortization charges were higher in 2005 versus 2004, principally due to higher per barrel rates.
 
Cash operating costs per barrel of oil equivalent were $10.92 in 2006, $9.07 in 2005 and $7.67 in 2004. Cash operating costs for 2007 are estimated to be in the range of $12.00 to $13.00 per barrel, reflecting industry-wide cost increases and the timing of achieving peak production from new fields. Depreciation, depletion and amortization costs per barrel of oil equivalent were $8.85 in 2006, $7.88 in 2005 and $7.34 in 2004. Depreciation, depletion and related costs for 2007 are expected to be in the range of $10.00 to $11.00 per barrel. The anticipated increase is due to new fields, including the Okume Complex, which has allocated acquisition cost in its depreciable base.
 
Exploration expenses:  Exploration expenses were higher in 2006, primarily reflecting higher dry hole costs. Exploration expenses were higher in 2005 compared with 2004 as a result of increased drilling and seismic activity.
 
Income Taxes:  The effective income tax rate for Exploration and Production operations was 53% in 2006, 41% in 2005 and 43% in 2004. After considering the items in the table below, the effective income tax rates were 54% in 2006, 42% in 2005 and 46% in 2004. The increase in the 2006 effective income tax rate was primarily due to taxes on Libyan operations and the increase in the supplementary tax on petroleum operations in the United Kingdom from 10% to 20%. During 2006, the Algerian government amended its hydrocarbon tax laws effective August 1, 2006 and the Corporation recorded a net charge of $6 million for the estimated impact of the tax. The effective income tax rate for E&P operations in 2007 is expected to be in the range of 52% to 56%.
 
Other:  After-tax foreign currency gains were $10 million ($21 million before income taxes) in 2006, $20 million ($3 million loss before income taxes) in 2005, and $6 million ($29 million before income taxes) in 2004.
 
Reported Exploration and Production earnings include the following items of income (expense) before and after income taxes:
 
                                                 
    Before Income Taxes     After Income Taxes  
    2006     2005     2004     2006     2005     2004  
    (Millions of dollars)  
 
Gains from asset sales
  $  369     $ 48     $ 55     $  236     $ 41     $  54  
Income tax adjustments
     —                   (45 )     11       19  
Accrued office closing costs
    (30 )      —       (15 )     (18 )      —       (9 )
Hurricane related costs
     —       (40 )            —       (26 )      
Legal settlement
     —       19              —       11        
                                                 
    $ 339     $ 27     $ 40     $ 173     $ 37     $ 64  
                                                 
 
2006:  The gains from asset sales relate to the sale of certain United States oil and gas producing properties located in the Permian Basin in Texas and New Mexico and onshore Gulf Coast. The accrued office closing cost relates to vacated leased office space in the United Kingdom. The income tax adjustment represents a one-time adjustment to the Corporation’s deferred tax liability resulting from an increase in the supplementary tax on petroleum operations in the United Kingdom from 10% to 20%.


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2005:  The gains from asset sales represent the disposal of non-producing properties in the United Kingdom and the exchange of a mature North Sea asset for an increased interest in the Pangkah development in Indonesia. The Corporation incurred incremental expenses in 2005, principally repair costs and higher insurance premiums, as a result of hurricane damage in the Gulf of Mexico that are included in production expenses in the income statement. The income tax adjustment reflects the effect on deferred income taxes of a reduction in the income tax rate in Denmark and a tax settlement in the United Kingdom. The legal settlement reflects the favorable resolution of contingencies on a prior year asset sale, which is reflected in non-operating income in the income statement.
 
2004:  The Corporation recognized gains from the sales of an office building in Scotland, a non-producing property in Malaysia and two mature Gulf of Mexico properties. It also recorded foreign income tax benefits resulting from a change in tax law and a tax settlement. The Corporation recorded an after-tax charge for vacated leased office space in the United Kingdom and severance costs, which is reflected in general and administrative expenses in the income statement.
 
The Corporation’s future Exploration and Production earnings may be impacted by external factors, such as political risk, volatility in the selling prices of crude oil and natural gas, reserve and production changes, industry cost inflation, exploration expenses, the effects of weather and changes in foreign exchange and income tax rates.
 
Marketing and Refining
 
Earnings from Marketing and Refining activities amounted to $390 million in 2006, $515 million in 2005 and $451 million in 2004. After considering the Marketing and Refining items in the table on page 23, the earnings amounted to $390 million in 2006, $491 million in 2005 and $439 million in 2004 and are discussed in the paragraphs below. The Corporation’s downstream operations include HOVENSA, a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA) that is accounted for using the equity method. Additional Marketing and Refining activities include a fluid catalytic cracking facility in Port Reading, New Jersey, as well as retail gasoline stations, energy marketing and trading operations.
 
Refining:  Refining earnings, which consist of the Corporation’s share of HOVENSA’s results, Port Reading earnings, interest income on a note receivable from PDVSA and other miscellaneous items were $236 million in 2006, $346 million in 2005 and $302 million in 2004.
 
The Corporation’s share of HOVENSA’s net income was $125 million ($203 million before income taxes) in 2006 and $231 million ($376 million before income taxes) in 2005 and $216 million ($244 million before income taxes) in 2004. The lower earnings in 2006 were principally due to lower refined product margins. Refined product margins were higher in 2005 compared with 2004. In 2006 and 2005, the Corporation provided income taxes at the Virgin Islands statutory rate of 38.5% on HOVENSA’s income and the interest income on the note receivable from PDVSA. In 2004, income taxes on HOVENSA’s earnings were partially offset by available loss carryforwards. In 2006, the fluid catalytic cracking unit was shutdown for approximately 22 days of unscheduled maintenance. During 2005, a crude unit and the fluid catalytic cracking unit at HOVENSA were each shutdown for approximately 30 days of scheduled maintenance. Cash distributions from HOVENSA were $400 million in 2006, $275 million in 2005 and $88 million in 2004.
 
Pre-tax interest on the PDVSA note was $15 million, $20 million and $25 million in 2006, 2005 and 2004, respectively. Interest income is reflected in non-operating income in the income statement. At December 31, 2006, the remaining balance of the PDVSA note was $137 million, which is scheduled to be fully repaid by February 2009.
 
Port Reading’s after-tax earnings were $99 million in 2006, $100 million in 2005 and $60 million in 2004. Higher refined product sales volumes were offset by lower margins in 2006 compared with 2005. Refined product margins were higher in 2005 compared with 2004. In 2005, the Port Reading facility was shutdown for 36 days of planned maintenance.


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The following table summarizes refinery utilization rates:
 
                                 
    Refinery
    Refinery Utilization  
    Capacity     2006     2005     2004  
    (Thousands of
                   
    barrels per day)                    
 
HOVENSA
                               
Crude
    500       89.7%       92.2%       96.7%  
Fluid catalytic cracker
    150       84.3%       81.9%       92.9%  
Coker
    58       84.3%       92.8%       94.5%  
Port Reading
    65       97.4%       85.3%       83.4%  
 
Marketing:  Marketing operations, which consist principally of retail gasoline and energy marketing activities, generated income of $108 million in 2006, $112 million in 2005 and $100 million in 2004, excluding the income from liquidation of LIFO inventories and the charge related to a customer bankruptcy described below. The decrease in 2006 primarily reflects lower margins on refined product sales. The increase in 2005 was primarily due to higher margins and increased sales volumes compared with 2004. Total refined product sales volumes were 459,000 barrels per day in 2006, 456,000 barrels per day in 2005 and 428,000 barrels per day in 2004.
 
The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions for its own account. The Corporation’s after-tax results from trading activities, including its share of the earnings of the trading partnership, amounted to income of $46 million in 2006, $33 million in 2005 and $37 million in 2004. Before income taxes, the trading income amounted to $83 million in 2006, $60 million in 2005 and $72 million in 2004 and is included in operating revenues in the income statement.
 
Marketing expenses increased due to higher expenses resulting from an increased number of retail convenience stores, growth in energy marketing operations, and higher utility and compensation related costs.
 
Reported Marketing and Refining earnings include the following items of income (expense) before and after income taxes:
 
                                                 
    Before Income Taxes     After Income Taxes  
    2006     2005     2004     2006     2005     2004  
    (Millions of dollars)  
 
LIFO inventory liquidation
  $     $ 51     $ 20     $     $ 32     $ 12  
Charge related to customer bankruptcy
          (13 )                 (8 )      
                                                 
    $     $ 38     $ 20     $     $ 24     $ 12  
                                                 
 
In 2005 and 2004, Marketing and Refining earnings include income from the liquidation of prior year LIFO inventories. In 2005, earnings include a charge resulting from the bankruptcy of a customer in the utility industry, which is included in marketing expenses.
 
The Corporation’s future Marketing and Refining earnings may be impacted by volatility in Marketing and Refining margins, competitive industry conditions, government regulatory changes, credit risk and supply and demand factors, including the effects of weather.


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Corporate
 
The following table summarizes corporate expenses:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Corporate expenses (excluding the items listed below)
  $ 156     $ 119     $ 116  
Income taxes (benefits) on the above
    (46 )     (26 )     (31 )
                         
      110       93       85  
Items affecting comparability between periods, after tax
                       
Tax on repatriated earnings
          72        
Premiums on bond repurchases
          26        
Income tax adjustments
           —       (13 )
Insurance accrual
           —       13  
                         
Net corporate expenses
  $ 110     $ 191     $ 85  
                         
 
Excluding the items affecting comparability between periods, the increase in corporate expenses in 2006 compared to 2005 primarily reflects the expensing of stock options commencing January 1, 2006 and increases in insurance costs. Recurring after-tax corporate expenses in 2007 are estimated to be in the range of $115 to $125 million.
 
In 2005, the American Jobs Creation Act provided for a one-time reduction in the income tax rate to 5.25% on the remittance of eligible dividends from foreign subsidiaries to a United States parent. The Corporation repatriated $1.9 billion of previously unremitted foreign earnings resulting in the recognition of an income tax provision of $72 million. The pre-tax amount of bond repurchase premiums in 2005 was $39 million and is reflected in non-operating income in the income statement. The pre-tax amount of the 2004 corporate insurance accrual was $20 million and is reflected in non-operating income.
 
Interest
 
After-tax interest expense was as follows:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Total interest incurred
  $ 301     $ 304     $ 295  
Less capitalized interest
    100       80       54  
                         
Interest expense before income taxes
    201       224       241  
Less income taxes
    74       84       90  
                         
After-tax interest expense
  $ 127     $ 140     $ 151  
                         
 
After-tax interest expense in 2007 is expected to be in the range of $170 to $180 million, principally reflecting an anticipated decrease in capitalized interest due to the achievement of first production from several development projects.
 
Sales and Other Operating Revenues
 
Sales and other operating revenues totaled $28,067 million in 2006, an increase of 23% compared with 2005. The increase reflects higher selling prices of crude oil, higher sales volumes and reduced crude oil hedge positions in Exploration and Production activities and higher selling prices and sales volumes in marketing activities. In 2005, sales and other operating revenues totaled $22,747 million, an increase of 36% compared with 2004. This increase principally reflects higher selling prices of crude oil and natural gas in Exploration and Production and higher


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selling prices and sales volumes in marketing activities. The change in cost of goods sold in each year reflects the change in sales volumes and prices of refined products and purchased natural gas.
 
Liquidity and Capital Resources
 
The following table sets forth certain relevant measures of the Corporation’s liquidity and capital resources as of December 31:
 
                 
    2006     2005  
    (Millions of dollars)  
 
Cash and cash equivalents
  $ 383     $ 315  
Current portion of long-term debt
  $ 27     $ 26  
Total debt
  $ 3,772     $ 3,785  
Stockholders’ equity
  $ 8,111     $ 6,286  
Debt to capitalization ratio*
    31.7 %     37.6 %
 
 
* Total debt as a percentage of the sum of total debt plus stockholders’ equity.
 
  Cash Flows
 
The following table sets forth a summary of the Corporation’s cash flows:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Net cash provided by (used in):
                       
Operating activities
  $ 3,491     $ 1,840     $ 1,903  
Investing activities
    (3,289 )     (2,255 )     (1,371 )
Financing activities
    (134 )     (147 )     (173 )
                         
Net increase (decrease) in cash and cash equivalents
  $ 68     $ (562 )   $ 359  
                         
 
Operating Activities:  In 2006, net cash provided by operating activities, including changes in operating assets and liabilities, was $3,491 million, an increase of $1,651 million from 2005, principally reflecting higher earnings, changes in working capital accounts and increased distributions from HOVENSA. Net cash provided by operating activities was $1,840 million in 2005 compared with $1,903 million in 2004. The change was due to higher earnings in 2005, offset by a decrease from changes in operating assets and liabilities, principally working capital, of $408 million. The Corporation received cash distributions from HOVENSA of $400 million in 2006, $275 million in 2005 and $88 million in 2004.
 
Investing Activities:  The following table summarizes the Corporation’s capital expenditures:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Exploration and Production
                       
Exploration
  $ 590     $ 229     $ 168  
Production and development
    2,164       1,598       1,204  
Acquisitions (including leasehold)
    921       408       62  
                         
      3,675       2,235       1,434  
Marketing, Refining and Corporate
    169       106       87  
                         
Total
  $ 3,844     $ 2,341     $ 1,521  
                         
 
Capital expenditures in 2006 include payments of $359 million to acquire the Corporation’s former oil and gas production operations in the Waha concessions in Libya and $413 million to acquire a 55% working interest in the West Med Block in Egypt.


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Proceeds from asset sales in 2006 totaled $444 million, including the sale of the Corporation’s interests in certain producing properties in the Permian Basin and onshore U.S. Gulf Coast. Proceeds from asset sales were $74 million and $57 million in 2005 and 2004, respectively, principally from the sale of non-producing properties.
 
Financing Activities:  The Corporation reduced debt by $13 million in 2006, $50 million in 2005 and $106 million in 2004. The net reductions in debt in 2006, 2005 and 2004 were funded by available cash and cash flow from operations. In 2005, bond repurchases of $600 million were funded by borrowings on the revolving credit facility in connection with the repatriation of foreign earnings to the United States.
 
Dividends paid were $161 million in 2006, $159 million in 2005 and $157 million in 2004. The Corporation received proceeds from the exercise of stock options totaling $40 million, $62 million and $90 million in 2006, 2005 and 2004, respectively.
 
Future Capital Requirements and Resources
 
The Corporation anticipates $4.0 billion in capital and exploratory expenditures in 2007, of which $3.9 billion relates to Exploration and Production operations. The Corporation has maturities of long-term debt of $27 million in 2007 and $28 million in 2008. The Corporation anticipates that it can fund its 2007 operations, including capital expenditures, dividends, pension contributions and required debt repayments, with existing cash on-hand, cash flow from operations and its available credit facilities.
 
During 2006, the Corporation amended and restated its existing syndicated, revolving credit facility (the facility) to increase the credit line to $3.0 billion from $2.5 billion and extend the term to May 2011 from December 2009. The facility can be used for borrowings and letters of credit. At December 31, 2006, the Corporation has $2.7 billion available under this facility.
 
The Corporation has a 364-day asset-backed credit facility securitized by certain accounts receivable from its Marketing and Refining operations, which are sold to a wholly-owned subsidiary. Under the terms of this financing arrangement, the Corporation has the ability to borrow up to $800 million, subject to the availability of sufficient levels of eligible receivables. At December 31, 2006, the Corporation has $318 million in outstanding borrowings under this facility which was collateralized by approximately $1,100 million of receivables. These receivables are not available to pay the general obligations of the Corporation before repayment of outstanding borrowings under the asset-backed facility.
 
The Corporation has additional unused lines of credit of approximately $370 million, primarily for letters of credit, under uncommitted arrangements with banks. The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.
 
Outstanding letters of credit at December 31, were as follows:
 
                 
    2006     2005  
    (Millions of dollars)  
 
Lines of Credit
               
Revolving credit facility
  $ 1     $ 28  
Committed short-term letter of credit facilities
    1,875       1,675  
Uncommitted lines
    1,603       982  
                 
    $ 3,479     $ 2,685  
                 
 
Loan agreement covenants allow the Corporation to borrow up to an additional $9.7 billion for the construction or acquisition of assets at December 31, 2006. The Corporation has the ability to borrow up to an additional $2.2 billion of secured debt at December 31, 2006 under the loan agreement covenants. At December 31, 2006, the maximum amount of dividends or stock repurchases that can be paid from borrowings under the loan agreement covenants is $3.7 billion.


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Credit Ratings
 
There are three major credit rating agencies that rate the Corporation’s debt. Two credit agencies have assigned an investment grade rating to the Corporation’s debt and one agency has rated it below investment grade. The interest rate and facility fee are subject to adjustment if the Corporation’s credit rating changes. In addition, if any one of the three rating agencies were to reduce their rating on the Corporation’s senior unsecured debt, margin requirements with non-trading and trading counterparties at December 31, 2006 would increase by up to approximately $140 million.
 
Contractual Obligations and Contingencies
 
Following is a table showing aggregated information about certain contractual obligations at December 31, 2006:
 
                                         
          Payments Due by Period  
                2008 and
    2010 and
       
    Total     2007     2009     2011     Thereafter  
    (Millions of dollars)  
 
Long-term debt(a)
  $ 3,772     $ 27     $ 171     $  1,340     $  2,234  
Operating leases
    2,471       630       567       198       1,076  
Purchase obligations
                                       
Supply commitments
     25,800        8,381      8,990       8,429       (b )
Capital expenditures
    1,109       809       263       37        
Operating expenses
    794       477       187       89       41  
Other long-term liabilities
    1,316       65       285       220       746  
 
 
(a) At December 31, 2006, the Corporation’s debt bears interest at a weighted average rate of 7.0%.
 
(b) The Corporation intends to continue purchasing refined product supply from HOVENSA. Estimated future purchases amount to approximately $4.2 billion annually using year-end 2006 prices.
 
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. The value of future supply commitments will fluctuate based on prevailing market prices at the time of purchase, the actual output from HOVENSA, and the level of sales to unaffiliated parties. Also included are 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 refined products, natural gas and electricity 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 $4 billion capital investment program for 2007 that is contractually committed at December 31, 2006. 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 asset retirement obligations and pension plan funding requirements.
 
At December 31, 2006, the Corporation had a remaining accrual of $49 million for vacated leased office space costs. In 2006, the Corporation recorded an additional $30 million charge for vacated leased office space ($18 million after income taxes) and made payments of $12 million. At December 31, 2005, the accrual was $31 million after reduction for payments of $8 million during 2005.
 
The Corporation has a contingent purchase obligation, expiring in April 2010, to acquire the remaining interest in WilcoHess, a retail gasoline station joint venture, for approximately $140 million as of December 31, 2006.
 
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, 2006, amounted to $229 million. In addition, the Corporation has


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agreed to provide funding up to a maximum of $15 million to the extent HOVENSA does not have funds to meet its senior debt obligations.
 
At December 31, 2006, the Corporation has $3,427 million of letters of credit principally relating to accrued liabilities with hedging and trading counterparties recorded on its balance sheet. In addition, the Corporation is contingently liable under letters of credit and under guarantees of the debt of other entities directly related to its business, as follows:
 
         
    Total  
    (Millions of
 
    dollars)  
 
Letters of credit
  $ 52  
Guarantees
    301 *
         
    $ 353  
         
 
 
* Includes $15 million HOVENSA debt and $229 million crude oil purchase guarantees discussed above. The remainder relates to a loan guarantee of $57 million for an oil pipeline in which the Corporation owns a 2.36% interest.
 
Off-Balance Sheet Arrangements
 
The Corporation has leveraged leases not included in its balance sheet, primarily related to retail gasoline stations that the Corporation operates. The net present value of these leases is $490 million at December 31, 2006 compared with $480 million at December 31, 2005. The Corporation’s December 31, 2006 debt to capitalization ratio would increase from 31.7% to 34.4% if these leases were included as debt.
 
See also “Contractual Obligations and Contingencies” above, note 5, “Refining Joint Venture,” and note 16, “Guarantees and Contingencies,” in the notes to the financial statements.
 
Stock Split
 
On May 3, 2006, the Corporation’s shareholders voted to increase the number of authorized common shares from 200 million to 600 million and the board of directors declared a three-for-one stock split. The stock split was completed in the form of a stock dividend that was issued on May 31, 2006 to shareholders of record on May 17, 2006. The common share par value remained at $1.00 per share. All common share and per share amounts in the financial statements and notes and management’s discussion and analysis are on an after-split basis for all periods presented.
 
Foreign Operations
 
The Corporation conducts exploration and production activities in the United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Malaysia, Thailand, Russia, Gabon, Azerbaijan, Indonesia, Libya, Egypt and other countries. Therefore, the Corporation is subject to the risks associated with foreign operations. These exposures include political risk (including tax law changes) and currency risk.
 
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 United States Virgin Islands. In the past, there have been political disruptions in Venezuela that reduced the availability of Venezuelan crude oil used in refining operations; however, these disruptions did not have a material adverse effect on the Corporation’s financial position. The Corporation has a note receivable of $137 million at December 31, 2006 from a subsidiary of PDVSA. All payments are current and the Corporation anticipates collection of the remaining balance.
 
Subsequent Events
 
In February 2007, the Corporation completed the acquisition of a 28% interest in the Genghis Khan oil and gas development located in the deepwater Gulf of Mexico on Green Canyon Blocks 652 and 608 for $371 million. The Genghis Khan development is part of the same geologic structure as the Shenzi development (Hess 28%) and first production from this development is expected in the second half of 2007.


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Accounting Policies
 
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:  Exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
 
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.
 
Crude Oil and Natural Gas Reserves:  The determination of estimated proved reserves is a significant element in arriving at the results of operations of exploration and production activities. The estimates of proved reserves affect well capitalizations, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets and goodwill.
 
The Corporation’s oil and gas reserves are calculated in accordance with SEC regulations and interpretations and the requirements of the Financial Accounting Standards Board. For reserves to be booked as proved they must be commercially producible, government and project operator approvals must be obtained and depending on the amount of the project cost, senior management or the board of directors, must commit to fund the project. The Corporation’s oil and gas reserve estimation and reporting process involves an annual independent third party reserve determination as well as internal technical appraisals of reserves. The Corporation maintains its own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. The Corporation’s technical staff updates reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management reviews the estimates.
 
The oil and gas reserve estimates reported in the Supplementary Oil and Gas Data in accordance with Statement of Financial Accounting Standards (FAS) No. 69 Disclosures about Oil and Gas Producing Activities (FAS No. 69) are determined independently by the consulting firm of DeGolyer and MacNaughton (D&M) and are consistent with internal estimates. Annually, the Corporation provides D&M with engineering, geological and geophysical data, actual production histories and other information necessary for the reserve determination. The Corporation’s and D&M’s technical staffs meet to review and discuss the information provided. Senior management and the Board of Directors review the final reserve estimates issued by D&M.
 
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 based on identifiable cash flows (the field level for oil and gas assets) and are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by undiscounted future net cash flow


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estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.
 
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of actual prices on the last day of the year.
 
The Corporation’s impairment tests of long-lived Exploration and Production producing assets are based on its best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs and the timing of future production, which are updated each time an impairment test is performed. The Corporation could have 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.
 
In accordance with FAS No. 142 Goodwill and Other Intangible Assets (FAS No. 142), the Corporation’s goodwill is not amortized, but is tested for impairment annually in the fourth quarter 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. The Corporation’s goodwill is assigned to the Exploration and Production operating segment and it expects that the benefits of goodwill will be recovered through the operation of that segment.
 
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 estimated risk adjusted present value of exploration assets, and (3) an estimated market premium to reflect the market price an acquirer would pay for potential synergies including cost savings, access to new business opportunities, enterprise control, improved processes and increased market share. The Corporation also considers the relative market valuation of similar Exploration and Production companies.
 
The determination of the fair value of the Exploration and Production operating segment depends on estimates about oil and gas reserves, future prices, timing of future net cash flows and market premiums. Significant extended declines in crude oil and natural gas prices or reduced reserve estimates could lead to a decrease in the fair value of the Exploration and Production operating segment that could result in an impairment of goodwill.
 
Because there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing, there may be impairments of individual assets that would not cause an impairment of the goodwill assigned to the Exploration and Production segment.
 
Segments:  The Corporation has two operating segments, Exploration and Production and Marketing and Refining. Management has determined that these are its operating segments because, in accordance with FAS No. 131 Disclosures about Segments of an Enterprise and Related Information (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 (CODM) to make decisions about resources to be allocated to the segment and assess its performance and (iii) for which discrete financial information is available. The Chairman of the Board and Chief Executive Officer of the Corporation, is the 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.
 
Derivatives:  The Corporation utilizes derivative instruments for both non-trading and trading activities. In non-trading activities, the Corporation uses futures, forwards, options and swaps, individually or in combination to mitigate its exposure to fluctuations in the prices of crude oil, natural gas, refined products and electricity, and changes in foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated


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partnership, trades energy commodities derivatives, including futures, forwards, options and swaps, based on expectations of future market conditions.
 
All derivative instruments are recorded at fair value in the Corporation’s balance sheet. The Corporation’s policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges under FAS No. 133 are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.
 
Derivatives that are designated as either cash flow or fair value hedges are tested for effectiveness prospectively before they are executed and both prospectively and retrospectively on an on-going basis to determine whether they continue to qualify for hedge accounting. The prospective and retrospective effectiveness calculations are performed using either historical simulation or other statistical models, which utilize historical observable market data consisting of futures curves and spot prices.
 
Income Taxes:  Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements. The Corporation has net operating loss carryforwards in several jurisdictions, including the United States, and has recorded deferred tax assets for those losses. Additionally, the Corporation has deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. In evaluating realizability of deferred tax assets, the Corporation refers to the reversal periods for temporary differences, available carryforward periods for net operating losses, estimates of future taxable income, the availability of tax planning strategies, the existence of appreciated assets and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves and selling prices that are consistent with the Corporation’s internal business forecasts.
 
Changes in Accounting Policies
 
Effective January 1, 2006, the Corporation adopted the provisions of FAS No. 123R, Share-Based Payment (FAS No. 123R). FAS No. 123R requires that the fair value of all stock-based compensation to employees, including grants of stock options, be expensed over the vesting period. Through December 31, 2005, the Corporation used the intrinsic value method to account for employee stock options. Because the exercise prices of employee stock options equaled or exceeded the market price of the stock on the date of grant, the Corporation did not recognize compensation expense under the intrinsic value method. See note 9, “Share-Based Compensation,” in the notes to the consolidated financial statements.
 
In September 2006, the Financial Accounting Standards Board (FASB) issued FAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (FAS No. 158). FAS No. 158 requires recognition on the balance sheet of the overfunded or underfunded status of a defined benefit postretirement plan measured as the difference between the fair value of plan assets and the benefit obligation. As required, the Corporation prospectively adopted the provisions of FAS No. 158 on December 31, 2006. See note 11, “Retirement Plans,” in the notes to the consolidated financial statements.
 
Recently Issued Accounting Standards
 
In September 2006, the FASB issued Staff Position (FSP) AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP eliminates the previously acceptable accrue-in-advance method of accounting for planned major maintenance. As a result, the Corporation will retrospectively change its method of accounting for


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refinery turnarounds on January 1, 2007, the effective date of this pronouncement, to recognize expenses associated with refinery turnarounds when such costs are incurred. Under the retrospective method of adoption, the Corporation expects to increase 2006 earnings by approximately $4 million, reduce 2005 earnings by approximately $16 million and increase retained earnings as of January 1, 2005 by approximately $66 million.
 
In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 prescribes the financial statement recognition and measurement criteria for a tax position taken or expected to be taken in a tax return. FIN 48 also requires additional disclosures related to uncertain income tax positions. As required, the Corporation will adopt the provisions of FIN 48 effective January 1, 2007. The Corporation has not concluded its evaluation of the impact of adopting FIN 48 on its results of operations, financial position or cash flows.
 
In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS No. 157). FAS No. 157 establishes a fair value hierarchy, which applies broadly to financial and non-financial assets and liabilities measured at fair value under other authoritative accounting pronouncements. Additionally, the standard requires increased disclosure of the methods of determining fair value. The Corporation is currently evaluating the impact of adoption on its financial statements and, as required, the Corporation will adopt the provisions of FAS No. 157 effective January 1, 2008.
 
Environment, Health and Safety
 
The Corporation has implemented a values-based, socially-responsible strategy focused on improving environment, health and safety performance and making a positive impact on communities. The strategy is supported by the Corporation’s environment, health, safety and social responsibility (EHS & SR) policies and by environment and safety management systems that help protect the Corporation’s workforce, customers and local communities. The Corporation’s management systems are designed to uphold or exceed international standards and are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short-term, increase the Corporation’s operating costs and could also require increased capital expenditures to reduce potential risks to assets, reputation and license to operate. In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be captured as collateral benefits from investments in EHS & SR. The Corporation has programs in place to evaluate regulatory compliance, audit facilities, train employees and to generally meet corporate EHS & SR goals.
 
The production of motor and other fuels in the United States and elsewhere has faced increasing regulatory pressures in recent years. In 2004, new regulations went into effect that have already significantly reduced gasoline sulfur content and additional regulations to reduce the allowable sulfur content in diesel fuel went into effect in 2006. Additional reductions in gasoline and fuel oil sulfur content are under consideration. Fuels production will likely continue to be subject to more stringent regulation in future years and as such may require additional capital expenditures.
 
Capital expenditures necessary to comply with low-sulfur gasoline requirements at Port Reading were $72 million, of which $23 million was spent in 2005 and the remainder was spent in 2006. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are presently expected to be approximately $420 million in total, $360 million of which has already been spent and the remainder is expected to be spent in 2007. HOVENSA has and continues to plan to finance these capital expenditures through cash flow from operations.
 
The Energy Policy Act of 2005 eliminated the Clean Air Act’s mandatory oxygen content requirement for reformulated gasoline and imposes on refiners a requirement to use specific quantities of renewable content in gasoline. Many states have also enacted bans on the use of MTBE in gasoline, many of which will take effect between 2007 and 2009. As a result, several companies have announced their intention to cease using MTBE, since it will no longer be needed in reformulated gasoline to comply with the Clean Air Act and does not meet the new renewable content requirement. In response to these changes in the gasoline marketplace, the Corporation and HOVENSA phased out the use of ether based oxygenates during 2006. Both companies are reviewing the most cost effective means to replace ether unit processing capabilities, which may necessitate additional capital investments.


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As described in Item 3 “Legal Proceedings,” in 2003 the Corporation and HOVENSA began discussions with the U.S. EPA regarding the EPA’s Petroleum Refining Initiative (PRI). The PRI is an ongoing program that is designed to reduce certain air emissions at all U.S. refineries. Since 2000, the EPA has entered into settlements addressing these emissions with petroleum refining companies that control over 77% of the domestic refining capacity. Negotiations with the EPA are continuing and depending on the outcome of these discussions, the Corporation and HOVENSA may experience increased capital expenditures and operating expenses related to air emissions controls. Settlements with other refiners allow for controls to be phased in over several years.
 
HOVENSA is constructing a new wastewater treatment system at the refinery. This project will significantly enhance the refinery’s ability to treat wastewater and better protect the marine environment of St. Croix. The cost to complete the project is approximately $120 million, of which $55 million has already been incurred.
 
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 are significant, not only from the standpoint of technical feasibility, but also from the perspective of adequately measuring the Corporation’s greenhouse gas inventory. The Corporation has completed a revised monitoring protocol which will allow for better measurement of “greenhouse gases” and is conducting an independently verified audit of its emissions. Once completed, the monitoring protocol will allow for better control of these emissions and assist the Corporation in complying with any future regulatory restrictions.
 
The Corporation expects continuing expenditures for environmental assessment and remediation related primarily to existing conditions. Sites where corrective action may be necessary include gasoline stations, terminals, onshore exploration and production facilities, refineries (including solid waste management units under permits issued pursuant to the Resource Conservation and Recovery Act) and, although not currently significant, “Superfund” sites where the Corporation has been named a potentially responsible party.
 
The Corporation accrues for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. At year-end 2006, the Corporation’s reserve for its estimated environmental liability was approximately $75 million. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. The Corporation’s remediation spending was $15 million in 2006 and 2005 and $12 million in 2004. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, other than for low sulfur projects discussed above, were $22 million in 2006, $3 million in 2005 and $1 million in 2004.
 
Forward-Looking Information
 
Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, including references to the Corporation’s future results of operations and financial position, liquidity and capital resources, capital expenditures, oil and gas production, tax rates, debt repayment, hedging, derivative, market risk and environmental disclosures, off-balance sheet arrangements and contractual obligations and contingencies include forward-looking information. Forward-looking disclosures are based on the Corporation’s current understanding and assessment of these activities and reasonable assumptions about the future. Actual results may differ from these disclosures because of changes in market conditions, government actions and other factors.
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
In the normal course of its business, the Corporation is exposed to commodity risks related to changes in the price of crude oil, natural gas, refined products and electricity, as well as to changes in interest rates and foreign currency values. In the disclosures that follow, these operations are referred to as non-trading activities. The Corporation also has trading operations, principally through a 50% voting interest in a trading partnership. These activities are also exposed to commodity risks primarily related to the prices of crude oil, natural gas and refined products. The following describes how these risks are controlled and managed.
 
Controls:  The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include


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volumetric, term and value-at-risk limits. In addition, the chief risk officer must approve the use of new instruments or commodities. Risk limits are monitored daily and exceptions are reported to business units and to senior management. The Corporation’s risk management department also performs independent verifications of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s non-trading and trading activities, including the consolidated trading partnership. The Corporation’s treasury department administers foreign exchange rate and interest rate hedging programs.
 
Instruments:  The Corporation primarily uses forward commodity contracts, foreign exchange forward contracts, futures, swaps, options and energy commodity based securities in its non-trading and trading activities. These contracts are generally widely traded instruments 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 settlement 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.
 
  •  Exchange Traded Contracts:  The Corporation uses exchange traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be 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. These premiums are a component of the fair value of the options.
 
  •  Energy Securities:  Energy securities include energy related equity or debt securities issued by a company or government or related derivatives on these securities.
 
Value-at-Risk:  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 following table summarizes the value-at-risk results for trading and non-trading activities. These


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results may vary from time to time as strategies change in trading activities or hedging levels change in non-trading activities.
 
                 
    Trading
    Non-Trading
 
    Activities     Activities  
    (Millions of dollars)  
 
2006
               
At December 31
  $  17     $ 62  
Average for the year
    20       75  
High during the year
    22       86  
Low during the year
    17       62  
2005
               
At December 31
  $  18     $ 93  
Average for the year
    11       111  
High during the year
    18       127  
Low during the year
    7       93  
 
 
Non-Trading:  The Corporation’s non-trading activities may 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. Following is a summary of the Corporation’s outstanding crude oil hedges at December 31, 2006:
 
                 
    Brent Crude Oil  
    Average
    Thousands of
 
Maturity
  Selling Price     Barrels per Day  
 
2007
  $  25.85       24  
2008
    25.56       24  
2009
    25.54       24  
2010
    25.78       24  
2011
    26.37       24  
2012
    26.90       24  
 
 
There were no hedges of WTI crude oil or natural gas production at December 31, 2006. 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 manage the risk in its marketing activities.
 
Accumulated other comprehensive income (loss) at December 31, 2006 includes after-tax unrealized deferred losses of $1,338 million primarily related to crude oil contracts used as hedges of exploration and production sales. The pre-tax amount of deferred hedge losses is reflected in accounts payable and the related income tax benefits are recorded as deferred tax assets on the balance sheet.
 
The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates by entering into forward purchase contracts for both the British pound sterling and the Danish kroner. At December 31, 2006, the Corporation had $729 million of notional value foreign exchange contracts maturing in 2007. The fair value of the foreign exchange contracts was a receivable of $51 million at December 31, 2006. The change in fair value of the foreign exchange contracts from a 10% change in exchange rates is estimated to be approximately $80 million at December 31, 2006.
 
The Corporation’s outstanding debt of $3,772 million has a fair value of $4,105 million at December 31, 2006. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $300 million at December 31, 2006.
 
Trading:  In trading activities, the Corporation is exposed to changes in crude oil, natural gas and refined product prices. The trading partnership in which the Corporation has a 50% voting interest trades energy


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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. The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts.
 
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 $721 million ($297 million of realized losses for 2005). 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.
 
                 
    2006     2005  
    (Millions of dollars)  
 
Fair value of contracts outstanding at the beginning of the year
  $ 1,109     $ 184  
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of year
    (82 )     6  
Reversal of fair value for contracts closed during the year
    (547 )     (23 )
Fair value of contracts entered into during the year and still outstanding
    (115 )     942  
                 
Fair value of contracts outstanding at the end of the year
  $ 365     $ 1,109  
                 
 
 
The Corporation uses observable market values for determining the fair value of its trading instruments. 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.
 
The following table summarizes the sources of fair values of derivatives used in the Corporation’s trading activities at December 31:
 
                                         
                            2010 and
 
    Total     2007     2008     2009     Beyond  
    (Millions of dollars)  
 
Source of fair value
                                       
Prices actively quoted
  $ 357     $ 198     $ 62     $ 65     $ 32  
Other external sources
    24       30       (12 )      —       6  
Internal estimates
    (16 )     (16 )      —        —        —  
                                         
Total
  $ 365     $ 212     $ 50     $ 65     $ 38  
                                         
 
 
The following table summarizes the fair values of net receivables relating to the Corporation’s trading activities and the credit ratings of counterparties at December 31:
 
                 
    2006     2005  
    (Millions of dollars)  
 
Investment grade determined by outside sources
  $ 347     $ 353  
Investment grade determined internally*
    59       139  
Less than investment grade
    41       70  
                 
Fair value of net receivables outstanding at the end of the year
  $ 447     $ 562  
                 
 
 
* Based on information provided by counterparties and other available sources.


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Item 8.   Financial Statements and Supplementary Data
 
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
INDEX TO FINANCIAL STATEMENTS AND SCHEDULE
 
         
    Page
    Number
 
  43
  44
  46
  47
  48
  49
  50
  51
  78
  84
  90
  91
 
 
* 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.


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Management’s Report on Internal Control over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2006.
 
Our management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.
 
             
By
 
/s/  John P. Rielly

John P. Rielly
Senior Vice President and
Chief Financial Officer
  By  
/s/  John B. Hess

John B. Hess
Chairman of the Board and
Chief Executive Officer
 
February 23, 2007


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Hess Corporation
 
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Hess Corporation (formerly, Amerada Hess Corporation) and consolidated subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Hess Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, management’s assessment that Hess Corporation and consolidated subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Hess Corporation and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheet of Hess Corporation and consolidated subsidiaries as of December 31, 2006 and 2005, and the related statements of consolidated income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2006, and our report dated February 23, 2007 expressed an unqualified opinion on these statements.
 
(ERNST & YOUNG)
 
New York, NY
February 23, 2007


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Hess Corporation
 
We have audited the accompanying consolidated balance sheet of Hess Corporation (formerly, Amerada Hess Corporation) and consolidated subsidiaries as of December 31, 2006 and 2005, and the related statements of consolidated income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2006. Our audits also included the Financial Statement Schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 Hess Corporation and consolidated subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related Financial Statement Schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
 
As discussed in Note 1 to the consolidated financial statements, the Corporation adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment, effective January 1, 2006. Also as discussed in Note 11 to the consolidated financial statements, the Corporation adopted the provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Hess Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2007 expressed an unqualified opinion thereon.
 
(ERNST & YOUNG)
 
New York, NY
February 23, 2007


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEET
 
                 
    At December 31  
    2006     2005  
    (Millions of dollars; thousands of shares)  
ASSETS
CURRENT ASSETS
               
Cash and cash equivalents
  $ 383     $ 315  
Accounts receivable
               
Trade
    3,659       3,517  
Other
    214       138  
Inventories
    1,005       855  
Other current assets
    587       465  
                 
Total current assets
    5,848       5,290  
                 
INVESTMENTS IN AFFILIATES
               
HOVENSA L.L.C. 
    1,012       1,217  
Other
    188       172  
                 
Total investments in affiliates
    1,200       1,389  
                 
PROPERTY, PLANT AND EQUIPMENT
               
Exploration and Production
    20,199       17,836  
Marketing and Refining
    1,781       1,628  
                 
Total — at cost
    21,980       19,464  
Less reserves for depreciation, depletion, amortization and lease impairment
    9,672       9,952  
                 
Property, plant and equipment — net
    12,308       9,512  
                 
GOODWILL
    1,253       977  
DEFERRED INCOME TAXES
    1,435       1,544  
OTHER ASSETS
    360       403  
                 
TOTAL ASSETS
  $  22,404     $  19,115  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
               
Accounts payable
  $ 4,803     $ 4,995  
Accrued liabilities
    1,477       1,029  
Taxes payable
    432       397  
Current maturities of long-term debt
    27       26  
                 
Total current liabilities
    6,739       6,447  
                 
LONG-TERM DEBT
    3,745       3,759  
DEFERRED INCOME TAXES
    2,099       1,401  
ASSET RETIREMENT OBLIGATIONS
    824       564  
OTHER LIABILITIES AND DEFERRED CREDITS
    886       658  
                 
Total Liabilities
    14,293       12,829  
                 
STOCKHOLDERS’ EQUITY
               
Preferred stock, par value $1.00, 20,000 shares authorized
               
7% cumulative mandatory convertible series
Authorized — 0 shares in 2006; 13,500 shares in 2005
Issued — 0 shares in 2006; 13,500 shares in 2005
          14  
3% cumulative convertible series
Authorized — 330 shares
Issued — 324 shares in 2006 and 2005 ($16 million liquidation preference)
           
Common stock*, par value $1.00
               
Authorized — 600,000 shares
               
Issued — 315,018 shares in 2006; 279,197 shares in 2005
    315       279  
Capital in excess of par value*
    1,689       1,656  
Retained earnings
    7,671       5,914  
Accumulated other comprehensive income (loss)
    (1,564 )     (1,526 )
Deferred compensation
          (51 )
                 
Total stockholders’ equity
    8,111       6,286  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 22,404     $ 19,115  
                 
 
 
Common stock and Capital in excess of par value as of December 31, 2005 are restated to reflect the impact of a 3-for-1 stock split on May 31, 2006.
 
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.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED INCOME
 
                         
    For the Years Ended
 
    December 31  
    2006     2005     2004  
    (In millions, except per share data)  
 
REVENUES AND NON-OPERATING INCOME
                       
Sales (excluding excise taxes) and other operating revenues
  $ 28,067     $ 22,747     $ 16,733  
Non-operating income
                       
Equity in income of HOVENSA L.L.C. 
    203       376       244  
Gain on asset sales
    369       48       55  
Other, net
    81       84       94  
                         
Total revenues and non-operating income
    28,720       23,255       17,126  
                         
COSTS AND EXPENSES
                       
Cost of products sold (excluding items shown separately below)
    19,912       17,041       11,971  
Production expenses
    1,250       1,007       825  
Marketing expenses
    940       842       737  
Exploration expenses, including dry holes and lease impairment
    552       397       287  
Other operating expenses
    130       136       195  
General and administrative expenses
    471       357       342  
Interest expense
    201       224       241  
Depreciation, depletion and amortization
    1,224       1,025       970  
                         
Total costs and expenses
    24,680       21,029       15,568  
                         
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    4,040       2,226       1,558  
Provision for income taxes
    2,124       984       588  
                         
INCOME FROM CONTINUING OPERATIONS
    1,916       1,242       970  
DISCONTINUED OPERATIONS
     —        —       7  
                         
NET INCOME
  $ 1,916     $ 1,242     $ 977  
                         
Less preferred stock dividends
    44       48       48  
                         
NET INCOME APPLICABLE TO COMMON SHAREHOLDERS
  $ 1,872     $ 1,194     $ 929  
                         
BASIC EARNINGS PER SHARE*
                       
Continuing operations
  $ 6.73     $ 4.38     $ 3.43  
Net income
    6.73       4.38       3.46  
DILUTED EARNINGS PER SHARE*
                       
Continuing operations
  $ 6.07     $ 3.98     $ 3.17  
Net income
    6.07       3.98       3.19  
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (DILUTED)*
    315.7       312.1       306.3  
 
 
Weighted average number of shares and per-share amounts in all periods reflect the impact of a 3-for-1 stock split on May 31, 2006.
 
See accompanying notes to consolidated financial statements.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED CASH FLOWS
 
                         
    For the Years Ended
 
    December 31  
    2006     2005     2004  
    (Millions of dollars)
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
                       
Net income
  $ 1,916     $ 1,242     $ 977  
Adjustments to reconcile net income to net cash provided by operating activities
                       
Depreciation, depletion and amortization
    1,224       1,025       970  
Exploratory dry hole costs
    241       170       81  
Lease impairment
    99       78       77  
Pre-tax gain on asset sales
    (369 )     (48 )     (55 )
Provision (benefit) for deferred income taxes
    279       (118 )     (211 )
Distributed (undistributed) earnings of HOVENSA L.L.C., net
    197       (101 )     (156 )
Non-cash effect of discontinued operations
     —        —       (7 )
Changes in other operating assets and liabilities:
                       
Increase in accounts receivable
    (179 )     (1,042 )     (705 )
Increase in inventories
    (152 )     (270 )     (16 )
Increase (decrease) in accounts payable and accrued liabilities
    (44 )     877       783  
Increase (decrease) in taxes payable
    47       (111 )     131  
Changes in other assets and liabilities
    232       138       34  
                         
Net cash provided by operating activities
    3,491       1,840       1,903  
                         
CASH FLOWS FROM INVESTING ACTIVITIES
                       
Capital expenditures
                       
Exploration and Production
    (3,675 )     (2,235 )     (1,434 )
Marketing and Refining
    (169 )     (106 )     (87 )
                         
Total capital expenditures
    (3,844 )     (2,341 )     (1,521 )
Proceeds from asset sales
    444       74       57  
Payments received on notes receivable
    76       60       90  
Other
    35       (48 )     3  
                         
Net cash used in investing activities
    (3,289 )     (2,255 )     (1,371 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES
                       
Debt with maturities of greater than 90 days
                       
Borrowings
    320       600       25  
Repayments
    (333 )     (650 )     (131 )
Cash dividends paid
    (161 )     (159 )     (157 )
Employee stock options exercised
    40       62       90  
                         
Net cash used in financing activities
    (134 )     (147 )     (173 )
                         
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    68       (562 )     359  
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    315       877       518  
                         
CASH AND CASH EQUIVALENTS AT END OF YEAR
  $ 383     $ 315     $ 877  
                         
 
See accompanying notes to consolidated financial statements.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED STOCKHOLDERS’ EQUITY
 
                                                 
    2006     2005     2004  
    Shares     Amount     Shares     Amount     Shares     Amount  
          (Millions of dollars; thousands of shares)        
 
PREFERRED STOCK
                                               
Balance at January 1
    13,824     $ 14       13,827     $ 14       13,827     $ 14  
Conversion of preferred stock to common stock
    (13,500 )     (14 )     (3 )                  
                                                 
Balance at December 31
    324        —       13,824       14       13,827       14  
                                                 
COMMON STOCK*
                                               
Balance at January 1
    279,197       279       275,145       275       269,604       270  
Activity related to restricted common stock awards, net
    903       1       948       1       927       1  
Employee stock options exercised
    1,283       1       3,098       3       4,614       4  
Conversion of preferred stock to common stock
    33,635       34       6                    
                                                 
Balance at December 31
    315,018       315       279,197       279       275,145       275  
                                                 
CAPITAL IN EXCESS OF PAR VALUE*
                                               
Balance at January 1
            1,656               1,544               1,423  
Activity related to restricted common stock awards, net
            36               37               23  
Employee stock options exercised
            68               75               98  
Conversion of preferred stock to common stock
            (20 )                            
Reclassification resulting from adoption of FAS 123R
            (51 )              —                
                                                 
Balance at December 31
            1,689               1,656               1,544  
                                                 
RETAINED EARNINGS
                                               
Balance at January 1
            5,914               4,831               4,011  
Net income
            1,916               1,242               977  
Dividends declared on common stock
            (115 )             (111 )             (109 )
Dividends on preferred stock
            (44 )             (48 )             (48 )
                                                 
Balance at December 31
            7,671               5,914               4,831  
                                                 
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
                                               
Balance at January 1
            (1,526 )             (1,024 )             (350 )
Net other comprehensive income (loss)
            104               (502 )             (674 )
Cumulative effect of adoption of FAS 158
            (142 )                            
                                                 
Balance at December 31
            (1,564 )             (1,526 )             (1,024 )
                                                 
DEFERRED COMPENSATION
                                               
Balance at January 1
            (51 )             (43 )             (28 )
Change in unearned compensation
                          (8 )             (15 )
Reclassification resulting from adoption of FAS 123R
            51                              
                                                 
Balance at December 31
                          (51 )             (43 )
                                                 
TOTAL STOCKHOLDERS’ EQUITY at December 31
          $ 8,111             $ 6,286             $ 5,597  
                                                 
 
Common stock and Capital in excess of par value as of January 1, 2004, December 31, 2004 and December 31, 2005 are restated to reflect the impact of a 3-for-1 stock split on May 31, 2006.
 
See accompanying notes to consolidated financial statements.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
 
                         
    For the Years Ended
 
    December 31  
    2006     2005     2004  
    (Millions of dollars)  
 
COMPONENTS OF COMPREHENSIVE INCOME
                       
Net income
  $  1,916     $ 1,242     $ 977  
                         
Other comprehensive income (loss):
                       
Deferred gains (losses) on cash flow hedges, after tax:
                       
Effect of hedge losses recognized in income
    345       946       511  
Net change in fair value of cash flow hedges
    (379 )     (1,381 )     (1,196 )
Change in minimum postretirement plan liabilities, after tax
    90       (33 )     (25 )
Change in foreign currency translation adjustment and other
    48       (34 )     36  
                         
Net other comprehensive income (loss)
    104       (502 )     (674 )
                         
COMPREHENSIVE INCOME
  $  2,020     $ 740     $ 303  
                         
 
See accompanying notes to consolidated financial statements.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.   Summary of Significant Accounting Policies
 
Nature of Business:  On May 3, 2006, Amerada Hess Corporation changed its name to Hess Corporation. Hess Corporation and subsidiaries (the Corporation) engage in the exploration for and the development, production, purchase, transportation and sale of crude oil and natural gas. These activities are conducted in the United States, United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Malaysia, Thailand, Russia, Gabon, Azerbaijan, Indonesia, Libya, Egypt 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. (HOVENSA), a refinery joint venture in the United States Virgin Islands. An additional refining facility, terminals and retail gasoline stations, most of which include convenience stores, 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, legal and environmental obligations, asset retirement obligations and income taxes.
 
Principles of Consolidation:  The consolidated financial statements include the accounts of 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, are stated at cost of acquisition plus the Corporation’s equity in undistributed net income since acquisition. The Corporation’s 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. Sales are reported net of excise and similar taxes in the consolidated statement of income. The Corporation recognizes revenues from the production of natural gas properties based on sales to customers. Differences between natural gas volumes sold and the Corporation’s share of natural gas production are not material. Revenues from natural gas and electricity sales by the Corporation’s marketing operations are recognized based on meter readings and estimated deliveries to customers since the last meter reading.
 
In its exploration and production activities, the Corporation enters into crude oil purchase and sale transactions with the same counterparty that are entered into in contemplation of one another for the primary purpose of changing location or quality. Similarly, in its marketing activities, the Corporation also enters into refined product purchase and sale transactions with the same counterparty. These arrangements are reported net in sales and other operating revenue in the consolidated statement of income.
 
Derivatives:  The Corporation utilizes derivative instruments for both non-trading and trading activities. In non-trading activities, the Corporation uses futures, forwards, options and swaps, individually or in combination, to mitigate its exposure to fluctuations in prices of crude oil, natural gas, refined products and electricity, and changes in foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated partnership, trades energy commodities derivatives, including futures, forwards, options and swaps based on expectations of future market conditions.
 
All derivative instruments are recorded at fair value in the Corporation’s balance sheet. The Corporation’s policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges under FAS No. 133 are recognized currently in


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.
 
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 cost or market. For inventories valued at cost, the Corporation uses principally the last-in, first-out (LIFO) inventory method. Inventories of merchandise, materials and supplies are valued at the lower of average cost or market.
 
Exploration and Development Costs:  Exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
 
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. In accordance with Financial Accounting Standards Board (FASB) Staff Position 19-1, Accounting for Suspended Well Costs, which amended FAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (FAS No. 19), exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.
 
Depreciation, Depletion and Amortization:  The Corporation records 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. Retail gas stations and equipment related to a leased property, are depreciated over the estimated useful lives not to exceed the remaining lease period. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors.
 
Capitalized Interest:  Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying assets.
 
Asset Retirement Obligations:  The Corporation accounts for asset retirement obligations as required by FAS No. 143, Accounting for Asset Retirement Obligations and FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations. Under these standards, a liability is recognized for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

obligations are incurred. In addition, the fair value of any legally required conditional asset retirement obligations is recorded if the liability can be reasonably estimated. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets.
 
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 the year-end prices used 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.
 
Impairment of Goodwill:  In accordance with FAS No. 142, Goodwill and Other Intangible Assets, goodwill cannot be amortized; however, it is tested for impairment annually in the fourth quarter. 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:  Maintenance and repairs are expensed as incurred. The estimated costs of refinery turnarounds are accrued. Capital improvements are recorded as additions in property, plant and equipment.
 
Environmental Expenditures:  The Corporation accrues and expenses environmental costs to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. The Corporation capitalizes environmental expenditures that increase the life or efficiency of property or that reduce or prevent future environmental contamination.
 
Share-Based Compensation:  Effective January 1, 2006, the Corporation adopted FAS No. 123R, Share-Based Payment (FAS No. 123R) which requires that compensation expense be recorded for all share based payments to employees. The Corporation used the modified prospective application method for its adoption of FAS No. 123R, which requires that compensation cost be recorded for restricted stock, previously awarded unvested stock options outstanding at January 1, 2006 based on the grant date fair-values used for disclosure purposes under previous accounting requirements, and stock options awarded subsequent to January 1, 2006 determined under the provisions of FAS No. 123R. The cumulative effect on prior years of this change in accounting was immaterial. Prior to adoption of FAS No. 123R, the Corporation recorded compensation expense for restricted common stock awards and used the intrinsic value method to account for employee stock options. Because the exercise prices of employee stock options equaled or exceeded the market price of the stock on the date of grant, compensation expense was not recorded under this method. All share-based compensation expense is recognized on a straight-line basis over the vesting period of the awards.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

 
Income Taxes:  Deferred income taxes are determined using the liability method. The Corporation regularly assesses the realizability of deferred tax assets, based on estimates of future taxable income, the availability of tax planning strategies, the existence of appreciated assets, the available carryforward periods for net operating losses and other factors. The Corporation does not provide for deferred U.S. income taxes applicable to undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations.
 
Foreign Currency Translation:  The U.S. dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. Adjustments resulting from translating monetary assets and liabilities that are denominated in a nonfunctional currency into the functional currency are recorded in other non-operating income. For operations that do not use the U.S. dollar as the functional currency, adjustments resulting from translating foreign currency assets and liabilities into U.S. dollars are recorded in a separate component of stockholders’ equity entitled accumulated other comprehensive income (loss).
 
Recently Issued Accounting Standards:  In September 2006, the FASB issued Staff Position (FSP) AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP eliminates the previously acceptable accrue-in-advance method of accounting for planned major maintenance. As a result, the Corporation will retrospectively change its method of accounting for refinery turnarounds on January 1, 2007, the effective date of this pronouncement, to recognize expenses associated with refinery turnarounds when such costs are incurred. Under the retrospective method of adoption, the Corporation expects to increase 2006 earnings by approximately $4 million, reduce 2005 earnings by approximately $16 million and increase retained earnings as of January 1, 2005 by approximately $66 million.
 
In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 prescribes the financial statement recognition and measurement criteria for a tax position taken or expected to be taken in a tax return. FIN 48 also requires additional disclosures related to uncertain income tax positions. As required, the Corporation will adopt the provisions of FIN 48 effective January 1, 2007. The Corporation has not concluded its evaluation of the impact of adopting of FIN 48 on its results of operations, financial position or cash flows.
 
In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS No. 157). FAS No. 157 establishes a fair value hierarchy, which applies broadly to financial and non-financial assets and liabilities measured at fair value under other authoritative accounting pronouncements. Additionally, the standard requires increased disclosure of the methods of determining fair value. The Corporation is currently evaluating the impact of adoption on its financial statements and, as required, will adopt the provisions of FAS No. 157 effective January 1, 2008.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

 
2.   Items Affecting the Comparability of Income
 
The following table reflects items affecting comparability of income between periods:
 
                                                 
    Before Taxes     After Taxes  
    2006     2005     2004     2006     2005     2004  
    (Millions of dollars, income (expense))  
 
Exploration and Production
                                               
Gains from asset sales
  $ 369     $ 48     $ 55     $ 236     $ 41     $ 54  
Income tax adjustments
                      (45 )     11       19  
Accrued office closing costs
    (30 )           (15 )     (18 )           (9 )
Hurricane related costs
          (40 )                 (26 )      
Legal settlement
          19                   11        
Marketing and Refining
                                               
LIFO inventory liquidation
          51       20             32       12  
Charge related to customer bankruptcy
          (13 )                 (8 )      
Corporate
                                               
Tax on repatriated earnings
                            (72 )      
Premiums on bond repurchases
          (39 )                 (26 )      
Income tax adjustments
                                  13  
Insurance accrual
                (20 )                 (13 )
                                                 
    $ 339     $ 26     $ 40     $ 173     $ (37 )   $ 76  
                                                 
 
Exploration and Production:  In the first quarter of 2006, the Corporation completed the sale of its interests in certain oil and gas producing properties located in the Permian Basin in Texas and New Mexico for $358 million. This asset sale resulted in an after-tax gain of $186 million ($289 million before income taxes). These assets were producing at a combined net rate of approximately 5,500 barrels of oil equivalent per day at the time of sale. In June 2006, the Corporation also completed the sale of certain U.S. Gulf Coast onshore oil and gas producing assets for $86 million, resulting in an after-tax gain of $50 million ($80 million before income taxes). These assets were producing at a combined net rate of approximately 2,600 barrels of oil equivalent per day at the time of sale. In 2005, the Corporation sold non-producing properties in the United Kingdom and exchanged a mature North Sea asset for an increased interest in the Pangkah development in Indonesia. In 2004, the Corporation sold an office building in Scotland, a non-producing property in Malaysia and two mature Gulf of Mexico properties.
 
The Corporation accrued $30 million in 2006 and $15 million in 2004 for vacated leased office space in the United Kingdom. These expenses are reflected principally in general and administrative expense in the income statement. The remaining accrual balance was $49 million at December 31, 2006 and $31 million at December 31, 2005 after payments of $12 million in 2006 and $8 million in 2005.
 
During 2006, the United Kingdom increased the supplementary tax on petroleum operations from 10% to 20%. As a result, the Corporation recorded a $45 million adjustment to its United Kingdom deferred tax liability. The Exploration and Production income tax adjustments in 2005 reflect the effect on deferred income taxes of a reduction in the income tax rate in Denmark and a tax settlement in the United Kingdom. In 2004, the foreign income tax benefits resulted from a tax law change and a tax settlement.
 
In 2005, the Corporation incurred incremental expenses, principally repair costs and higher insurance premiums, as a result of hurricane damage in the Gulf of Mexico that are included in production expenses in


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

the income statement. The legal settlement in 2005 resulted from the favorable resolution of contingencies on a prior year asset sale that is reflected in non-operating income in the income statement.
 
Marketing and Refining:  Earnings include income from the liquidation of prior year LIFO inventories in 2005 and 2004. In 2005, earnings included a charge resulting from the bankruptcy of a customer in the utility industry that is included in marketing expenses in the income statement.
 
Corporate:  In 2005, expenses include charges for premiums on bond repurchases, which are reflected in non-operating income (expense) in the income statement. In 2004, the Corporation recorded $20 million of insurance costs related to retrospective premium increases and a $13 million income tax benefit arising from the settlement of a federal tax audit.
 
3.   Acquisitions
 
2006 Acquisitions:  In January 2006, the Corporation, in conjunction with its Oasis Group partners, re-entered its former oil and gas production operations in the Waha concessions in Libya, in which the Corporation holds an 8.16% interest. The re-entry terms included a 25-year extension of the concessions and payments by the Corporation to the Libyan National Oil Corporation of $359 million. This transaction was accounted for as a business combination.
 
The following table summarizes the allocation of the purchase price to assets and liabilities acquired (in millions):
 
         
Property, plant and equipment
  $ 362  
Goodwill
    236  
         
Total assets acquired
    598  
Current liabilities
    (3 )
Deferred tax liabilities
    (236 )
         
Net assets acquired
  $ 359  
         
 
The goodwill recorded in this transaction relates to the deferred tax liability recorded for the difference in book and tax bases of the assets acquired. The goodwill is not expected to be deductible for income tax purposes. The primary reason for the Libyan investment was to acquire long-lived crude oil reserves. The Corporation’s share of production from Libya averaged 23,000 barrels of oil equivalent per day in 2006.
 
The Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a 25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities. This transaction was accounted for as an acquisition of assets.
 
2005 Acquisitions:  The Corporation spent approximately $400 million during 2005 to acquire a controlling interest in a corporate joint venture, additional licenses and other assets in the Volga-Urals region of Russia. The primary reason for the Russian investments was to acquire long-lived crude oil reserves. Substantially all of the acquisition cost was allocated to unproved and proved properties.


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

 
4.   Inventories
 
Inventories at December 31 are as follows:
 
                 
    2006     2005  
    (Millions of dollars)  
 
Crude oil and other charge stocks
  $ 202     $ 161  
Refined products and natural gas
    1,185       1,149  
Less: LIFO adjustment
    (676 )     (656 )
                 
      711       654  
Merchandise, materials and supplies
    294       201  
                 
Total
  $ 1,005     $ 855  
                 
 
The percentage of LIFO inventory to total crude oil, refined products and natural gas inventories was 66% and 68% at December 31, 2006 and 2005, respectively. During 2005 and 2004, the Corporation reduced LIFO inventories, which are carried at lower costs than current inventory costs. The effect of the LIFO inventory liquidations was to decrease cost of products sold by approximately $51 million in 2005 and $20 million in 2004.
 
5.   Refining Joint Venture
 
The Corporation has an investment in HOVENSA L.L.C., a 50% joint venture with Petroleos de Venezuela, S.A. (PDVSA), which is accounted for using the equity method. HOVENSA owns and operates a refinery in the U.S. Virgin Islands. Summarized financial information for HOVENSA as of December 31 and for the years then ended follows:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Summarized Balance Sheet, at December 31
                       
Cash and cash equivalents
  $ 290     $ 612     $ 518  
Short-term investments
          263       39  
Other current assets
    943       814       636  
Net fixed assets
    2,123       1,950       1,843  
Other assets
    32       39       36  
Current liabilities
    (1,060 )     (996 )     (606 )
Long-term debt
    (252 )     (252 )     (252 )
Deferred liabilities and credits
    (108 )     (57 )     (48 )
                         
Partners’ equity
  $ 1,968     $ 2,373     $ 2,166  
                         
Summarized Income Statement, for the Years Ended December 31
                       
Total revenues
  $ 11,788     $ 10,439     $ 7,776  
Costs and expenses
    (11,377 )     (9,682 )     (7,282 )
                         
Net income
  $ 411     $ 757     $ 494  
                         
Hess Corporation’s share*
  $ 203     $ 376     $ 244  
                         


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

                         
    2006     2005     2004  
    (Millions of dollars)  
 
Summarized Cash Flow Statement, for the Years Ended December 31
                       
Net cash provided by (used in):
                       
Operating activities
  $ 484     $ 1,070     $ 656  
Investing activities
    (10 )     (426 )     (167 )
Financing activities
    (796 )     (550 )     (312 )
                         
Net increase (decrease) in cash and cash equivalents
  $ (322 )   $ 94     $ 177  
                         
 
 
* Before Virgin Islands income taxes, which were recorded in the Corporation’s income tax provision.
 
The Corporation received cash distributions from HOVENSA of $400 million, $275 million and $88 million during 2006, 2005 and 2004, respectively. The Corporation’s share of HOVENSA’s undistributed income aggregated $302 million at December 31, 2006.
 
The Corporation guarantees the payment of up to 50% of the value of HOVENSA’s crude oil purchases from suppliers other than PDVSA. The guarantee amounted to $229 million at December 31, 2006. 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 up to a current maximum of $15 million to the extent HOVENSA does not have funds to meet its senior debt obligations.
 
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. The principal balance of the note was $137 million and $212 million at December 31, 2006 and 2005, respectively, which is due to be fully repaid by February 2009.
 
6.   Property, Plant and Equipment
 
Property, plant and equipment at December 31 consists of the following:
 
                 
    2006     2005  
    (Millions of dollars)  
 
Exploration and Production
               
Unproved properties
  $ 1,231     $ 629  
Proved properties
    3,298       3,490  
Wells, equipment and related facilities
    15,670       13,717  
Marketing and Refining
    1,781       1,628  
                 
Total — at cost
    21,980       19,464  
Less reserves for depreciation, depletion, amortization and lease impairment
    9,672       9,952  
                 
Property, plant and equipment - net
  $ 12,308     $ 9,512  
                 

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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 

The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31, and the changes therein during the respective years:
 
                         
    2006     2005     2004  
    (Millions of dollars)  
 
Beginning balance at January 1
  $ 244     $ 220     $ 225  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    299       97       150  
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
    (144 )     (12 )     (149 )
Capitalized exploratory well costs charged to expense
          (61 )     (6 )
                         
Ending balance at December 31
  $ 399     $ 244     $ 220  
                         
Number of wells at end of year
    28       16       15  
                         
 
The preceding table excludes exploratory dry hole costs of $241 million, $109 million and $75 million in 2006, 2005 and 2004, respectively, relating to wells that were drilled and expensed in the same year.
 
At December 31, 2006, expenditures related to exploratory drilling costs in excess of one year old were capitalized as follows (in millions):
 
         
2003
  $ 46  
2004
    8  
2005
    17  
         
    $ 71  
         
 
The capitalized well costs in excess of one year relate to 5 projects which meet the requirements of FASB Staff Position 19-1. Approximately 75% of the costs relates to two projects for which additional drilling is firmly planned in 2007. The remainder of the costs relate to projects where development approvals or sales contracts are being pursued.
 
7.   Asset Retirement Obligations
 
The following table describes changes to the Corporation’s asset retirement obligations:
 
                 
    2006     2005  
    (Millions of dollars)  
 
Asset retirement obligations at January 1
  $ 564     $ 511  
Liabilities incurred
    16       8  
Liabilities settled or disposed of
    (118 )     (26 )
Accretion expense </