FORM 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, 2007
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.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer  þ Accelerated filer  o Non-accelerated filer  o Smaller reporting company  o
(Do not check if a smaller reporting company)
 
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 $16,463,000,000 as of June 30, 2007.
 
At December 31, 2007, there were 320,599,585 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 7, 2008.
 


 

 
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     11  
4.
  Submission of Matters to a Vote of Security Holders     14  
    Executive Officers of the Registrant     14  
 
PART II
5.
  Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities     15  
6.
  Selected Financial Data     17  
7.
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     18  
7A.
  Quantitative and Qualitative Disclosures About Market Risk     36  
8.
  Financial Statements and Supplementary Data     40  
9.
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     81  
9A.
  Controls and Procedures     81  
9B.
  Other Information     81  
 
PART III
10.
  Directors, Executive Officers and Corporate Governance     81  
11.
  Executive Compensation     81  
12.
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     81  
13.
  Certain Relationships and Related Transactions, and Director Independence     82  
14.
  Principal Accounting Fees and Services     82  
 
PART IV
15.
  Exhibits, Financial Statement Schedules     82  
  Signatures     85  
 EX-21: SUBSIDIARIES
 EX-31.1: CERTIFICATION
 EX-31.2: CERTIFICATION
 EX-32.1: CERTIFICATION
 EX-32.2: CERTIFICATION


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Table of Contents

 
PART I
 
Items 1 and 2.  Business and Properties
 
Hess Corporation (the Registrant) is a Delaware corporation, incorporated in 1920. 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 principally in Algeria, Australia, Azerbaijan, Brazil, Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Libya, Malaysia, Norway, Russia, Thailand, the United Kingdom and the United States. 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:
 
                                                 
    Crude Oil and
          Total Barrels of Oil
 
    Natural Gas Liquids     Natural Gas     Equivalent (BOE)*  
    2007     2006     2007     2006     2007     2006  
    (Millions of barrels)     (Millions of mcf)     (Millions of barrels)  
 
United States
    204       138       270       236       249       178  
Europe
    329       340       656       677       438       453  
Africa
    285       304       87             300       304  
Asia and other
    67       50       1,655       1,553       343       308  
                                                 
      885       832       2,668       2,466       1,330       1,243  
                                                 
 
 
* Reflects natural gas reserves converted on the basis of relative energy content (six mcf equals one barrel).
 
On a barrel of oil equivalent (boe) basis, 44% of the Corporation’s worldwide proved reserves are undeveloped at December 31, 2007 (40% at December 31, 2006). Proved reserves held under production sharing contracts at December 31, 2007 totaled 25% of crude oil and natural gas liquids and 57% of natural gas reserves.
 
Worldwide crude oil, natural gas liquids and natural gas production was as follows:
 
                         
    2007     2006     2005  
 
Crude oil (thousands of barrels per day)
                       
United States
                       
Onshore
    15       15       21  
Offshore
    16       21       23  
                         
      31       36       44  
                         
Europe
                       
United Kingdom
    38       50       54  
Norway
    19       22       26  
Denmark
    12       19       24  
Russia
    24       18       6  
                         
      93       109       110  
                         


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    2007     2006     2005  
 
Africa
                       
Equatorial Guinea
    56       28       30  
Algeria
    22       22       25  
Gabon
    14       12       12  
Libya
    23       23        
                         
      115       85       67  
                         
Asia and other
                       
Azerbaijan
    16       7       4  
Other
    5       5       3  
                         
      21       12       7  
                         
Total
    260       242       228  
                         
Natural gas liquids (thousands of barrels per day)
                       
United States
    10       10       12  
Europe
                       
United Kingdom
    4       4       3  
Norway
    1       1       1  
                         
      5       5       4  
                         
Total
    15       15       16  
                         
Natural gas (thousands of mcf per day)
                       
United States
                       
Onshore
    42       54       74  
Offshore
    46       56       63  
                         
      88       110       137  
                         
Europe
                       
United Kingdom
    231       244       222  
Norway
    18       22       28  
Denmark
    10       17       24  
                         
      259       283       274  
                         
Asia and other
                       
Joint Development Area of Malaysia and Thailand (JDA)
    115       131       51  
Thailand
    90       60       57  
Indonesia
    59       26       25  
Other
    2       2        
                         
      266       219       133  
                         
Total
    613       612       544  
                         
Barrels of oil equivalent*
    377       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 2008 production will be approximately 380,000 to 390,000 barrels of oil equivalent per day (boepd). 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
 
At December 31, 2007, 19% of the Corporation’s total proved reserves were located in the United States. During 2007, 15% of the Corporation’s crude oil and natural gas liquids production and 14% of its natural gas production were from United States operations. The Corporation’s production in the United States was principally from properties offshore in the Gulf of Mexico, which include the Llano (Hess 50%), Conger (Hess 37.5%), Baldpate (Hess 50%), Hack Wilson (Hess 33.3%) and Penn State (Hess 50%) fields, onshore in North Dakota including interests in the Bakken Play and Williston Basin and the Seminole-San Andres Unit (Hess 34.3%) onshore Texas in the Permian Basin.
 
The Shenzi development (Hess 28%) in the Green Canyon area of the deepwater Gulf of Mexico was sanctioned by the operator in 2006 and progressed in 2007 with installation of the tension leg platform tendon piles and hull fabrication. First production from Shenzi is expected to commence in mid-2009. 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. The Genghis Khan development is part of the same geological structure as the Shenzi development. These fields were unitized in 2007. Crude oil production from the Genghis Khan Field commenced in October 2007.
 
Development of a residual oil zone at the Seminole-San Andres Unit commenced in the fourth quarter of 2007 and it is anticipated that production from this development will begin in 2009. The Corporation intends to inject carbon dioxide gas supplied from its interests in the West Bravo Dome and Bravo Dome fields in New Mexico into the residual oil zone to enhance recovery of crude oil.
 
At the Corporation’s Tubular Bells prospect (Hess 20%) located in the Mississippi Canyon area of the deepwater Gulf of Mexico a successful sidetrack to the second Tubular Bells well was completed during the first quarter of 2007 and the drilling of a third well commenced in October 2007. On the Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico a sidetrack from the original discovery well was successfully completed in the first quarter of 2007 and a second appraisal well is being drilled about 1.5 miles northwest of the original discovery well.
 
At December 31, 2007, the Corporation has interests in more than 370 exploration blocks in the Gulf of Mexico, which include 1,372,529 net undeveloped acres.
 
Europe
 
At December 31, 2007, 33% of the Corporation’s total proved reserves were located in Europe (United Kingdom 11%, Norway 14%, Denmark 3% and Russia 5%). During 2007, 36% of the Corporation’s crude oil and natural gas liquids production and 42% 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 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 2007 was primarily from fields in the Easington Catchment Area (Hess 28.8%), as well as the Everest (Hess 18.7%), Lomond (Hess 16.7%), Beryl (Hess 22.2%), Atlantic (Hess 25%) and Cromarty (Hess 90%) fields.
 
In 2007, the Corporation completed the sale of its interests in the Scott and Telford fields located offshore United Kingdom.
 
Norway:  Substantially all of the 2007 and 2006 Norwegian production was from the Corporation’s interest in the Valhall Field (Hess 28.1%). A field redevelopment for Valhall was sanctioned during 2007. In September 2007, gas production commenced at the Snohvit Field (Hess 3.26%) located offshore Norway.
 
Denmark:  Crude oil and natural gas production comes from the Corporation’s interest in the South Arne Field (Hess 57.5%).
 
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.


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Africa
 
At December 31, 2007, 22% of the Corporation’s total proved reserves were located in Africa (Equatorial Guinea 9%, Algeria 2%, Libya 10% and Gabon 1%). During 2007, 42% 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.
 
Algeria:  The Corporation has a 49% interest in a venture with the Algerian national oil company that is redeveloping three oil fields.
 
Libya:  The Corporation, in conjunction with its Oasis Group partners, has oil and gas production operations in the Waha concessions in Libya (Hess 8.16%). The Corporation also owns a 100% interest in offshore exploration Area 54, where drilling of an exploration well is planned for 2008.
 
Gabon:  The Corporation’s activities in Gabon are conducted through its 77.5% owned Gabonese subsidiary, where the Corporation has interests in the Rabi Kounga, Toucan and Atora fields.
 
Egypt:  The Corporation has a 25-year development lease for the West Med Block 1 concession (West Med Block) (Hess 55%), which contains four existing natural gas discoveries and additional exploration opportunities. During 2007, the Corporation commenced front-end engineering and seismic studies.
 
Ghana:  The Corporation holds an interest in the Cape Three Points South Block (Hess 100%) located offshore Ghana where drilling of an exploration well is planned during 2008.
 
Asia and Other
 
At December 31, 2007, 26% of the Corporation’s total proved reserves were located in the Asia and other region (JDA 14%, Indonesia 7%, Thailand 3% and Azerbaijan 2%). During 2007, 7% of the Corporation’s crude oil and natural gas liquids production and 44% of its natural gas production were from Asia and other operations.
 
Joint Development Area of Malaysia and Thailand:  The Corporation owns an interest in the JDA (Hess 50%) in the Gulf of Thailand. In the fourth quarter of 2007, the Corporation completed the expansion of offshore facilities and installation of wellhead platforms at the JDA. Full Phase 2 production is expected in the second half of 2008.
 
Indonesia:  The Corporation’s natural gas production in Indonesia primarily comes from its interests offshore in the Ujung Pangkah project (Hess 75%) and the Natuna A gas Field (Hess 23%). Natural gas production from the Ujung Pangkah project commenced in April 2007. In addition, during 2007 a crude oil development project commenced at Ujung Pangkah. Production from this Phase 2 oil project is expected to commence in 2009. The Corporation also owns an interest in the onshore Jambi Merang natural gas project (Hess 25%), which was sanctioned for development in 2007.
 
Thailand:  The Corporation has an interest in the Pailin gas Field (Hess 15%) offshore Thailand. The Corporation is the operator and owns an interest in the onshore natural gas project in the Sinphuhorm Block (formerly the Phu Horm Block) (Hess 35%) which commenced production in the fourth quarter of 2006.
 
Azerbaijan:  The Corporation has an interest in the Azeri-Chirag-Gunashli (ACG) fields (Hess 2.72%) in the Caspian Sea. The Corporation also holds an interest in the Baku-Tbilisi-Ceyhan (BTC) Pipeline (Hess 2.36%).
 
Australia:  In 2007, the Corporation acquired a 100% interest in an exploration license covering 780,000 acres in the Carnarvon basin offshore Western Australia (Block 390-P). During 2008, the Corporation plans to drill four wells of a 16 well commitment on the block. During 2007, the Corporation also acquired a 50% interest in Block 404-P located offshore Western Australia, which covers a total area of 680,000 acres.
 
Brazil:  The Corporation has interests in two blocks located offshore Brazil, the BMS-22 Block (Hess 40%) in the Santos Basin, where drilling of an exploration well is planned in 2008, and the BM-ES-30 Block (Hess 60%) in the Espirito Santo Basin.


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Oil and Gas Reserves
 
The Corporation’s net proved oil and gas reserves at the end of 2007, 2006 and 2005 are presented under Supplementary Oil and Gas Data on pages 76 through 78 in the accompanying financial statements.
 
During 2007, the Corporation provided oil and gas reserve estimates for 2006 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, 2006, although not necessarily directly comparable due to the requirements of the individual requests. There were no differences in excess of 5%.
 
Sales commitments:  The Corporation has no contracts or agreements to sell fixed quantities of its crude oil production. In the United States, natural gas is marketed 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 30% of its 2008 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 reliable 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 with prices that are periodically adjusted due to changes in the commodity prices or other indices. In the United Kingdom, the Corporation sells the majority of its natural gas production on a spot basis.
 
Average selling prices and average production costs
 
                         
    2007     2006     2005  
 
Average selling prices (including the effects of hedging) (Note A)
                       
Crude oil, including condensate and natural gas liquids (per barrel)
                       
United States
  $ 64.96     $ 57.41     $ 33.86  
Europe
    60.76       55.80       33.30  
Africa
    62.04       51.18       32.10  
Asia and other
    72.17       61.52       54.69  
Worldwide
    62.87       54.81       33.69  
Natural gas (per mcf)
                       
United States
  $ 6.67     $ 6.59     $ 7.93  
Europe
    6.13       6.20       5.29  
Asia and other
    4.71       4.05       4.02  
Worldwide
    5.60       5.50       5.65  
Average production (lifting) costs per barrel of oil equivalent produced (Note B)
                       
United States
  $ 13.56     $ 9.54     $ 7.46  
Europe
    14.06       10.73       8.13  
Africa
    9.09       9.03       7.99  
Asia and other
    8.41       6.54       7.29  
Worldwide
    11.50       9.55       7.91  
 
 
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), transportation costs 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 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.


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Gross and net undeveloped acreage at December 31, 2007
 
                 
    Undeveloped
 
    Acreage (Note A)  
    Gross     Net  
    (In thousands)  
 
United States
    2,497       1,701  
Europe
    3,862       1,356  
Africa
    12,357       8,850  
Asia and other
    15,496       10,798  
                 
Total (Note B)
    34,212       22,705  
                 
 
 
Note A:  Includes acreage held under production sharing contracts.
 
Note B:  Licenses covering approximately 32% of the Corporation’s net undeveloped acreage held at December 31, 2007 are scheduled to expire during the next three years pending the results of exploration activities. These scheduled expirations are largely in Libya (offshore exploration Area 54), Algeria and Peru.
 
Gross and net developed acreage and productive wells at December 31, 2007
 
                                                 
    Developed
             
    Acreage
             
    Applicable to
    Productive Wells (Note A)  
    Productive Wells     Oil     Gas  
    Gross     Net     Gross     Net     Gross     Net  
    (In thousands)                          
 
United States
    471       400       731       420       64       50  
Europe
    1,618       814       244       86       151       33  
Africa
    9,919       958       944       142              
Asia and other
    2,185       624       48       3       235       49  
                                                 
Total
    14,193       2,796       1,967       651       450       132  
                                                 
 
 
Note A:  Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 200 gross wells and 39 net wells.
 
Number of net exploratory and development wells drilled
 
                                                 
    Net Exploratory
    Net Development
 
    Wells     Wells  
    2007     2006     2005     2007     2006     2005  
 
Productive wells
                                               
United States
      1         1         —         54         24         28  
Europe
    3       1       3       14       20       6  
Africa
    1             1       23       17       12  
Asia and other
    3       6       1       15       11       8  
                                                 
Total
    8       8       5       106       72       54  
                                                 
Dry holes
                                               
United States
    1       4       2                   2  
Europe
    1             1                    
Africa
    1             1                   1  
Asia and other
                                   
                                                 
Total
    3       4       4                   3  
                                                 
Total
    11       12       9       106       72       57  
                                                 


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Number of wells in process of drilling at December 31, 2007
 
                 
    Gross
    Net
 
    Wells     Wells  
 
United States
    14       7  
Europe
    6       4  
Africa
    13       6  
Asia and other
    7       1  
                 
Total
    40       18  
                 
 
 
Number of net waterfloods and pressure maintenance projects in process of installation at December 31, 2007 — 1
 
 
 
Marketing and Refining
 
Total M&R product sales were as follows:
 
                         
    2007*     2006*     2005*  
    (Thousands of
 
    barrels per day)  
 
Gasoline
    210       218       213  
Distillates
    147       144       136  
Residuals
    62       60       64  
Other
    32       37       43  
                         
Total
    451       459       456  
                         
 
 
* Of total refined products sold in 2007, 2006 and 2005 approximately 50% was obtained from HOVENSA and Port Reading. The Corporation purchased the balance from third parties under short-term supply contracts and spot purchases.
 
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.
 
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   2007   2006   2005
    (Thousands of
           
    barrels per day)            
 
Crude
  500   90.8%   89.7%   92.2%
Fluid catalytic cracker
  150   87.1%   84.3%   81.9%
Coker
   58   83.4%   84.3%   92.8%
 
 
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 third parties, the Corporation purchases 50% of HOVENSA’s remaining production at market prices.


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Gross crude runs at HOVENSA averaged 454,000 barrels per day in 2007 compared with 448,000 barrels per day in 2006 and 461,000 barrels per day in 2005. During the second quarter of 2007, the coker unit at HOVENSA was shut down for approximately 30 days for a scheduled turnaround. The fluid catalytic cracking unit at HOVENSA was shut down for approximately 22 days of unscheduled maintenance in 2006.
 
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, which processes residual fuel oil and vacuum gas oil, operated at a rate of approximately 61,000 barrels per day in 2007 compared with 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.
 
The Corporation has 1,371 HESS® gasoline stations at December 31, 2007, including stations owned by the WilcoHess joint venture (Hess 44%). Approximately 90% of the gasoline stations are operated by the Company or WilcoHess. Of the operated stations, 93% 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 451,000 barrels per day in 2007 compared with 459,000 barrels per day in 2006 and 456,000 barrels in 2005. Total energy marketing natural gas sales volumes, including utility and spot sales, were approximately 1.9 million mcf per day in 2007, 1.8 million mcf per day in 2006 and 1.7 million mcf per day in 2005. In addition, energy marketing sold electricity volumes at the rate of 2,800, 1,400 and 500 megawatts (round the clock) in 2007, 2006 and 2005, respectively.
 
The Corporation owns 22 terminals with an aggregate storage capacity of 22 million barrels in its East Coast marketing areas. The Corporation also owns a terminal in St. Lucia with a storage capacity of 10 million barrels, which is used for third party storage.
 
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 92.5% interest in 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 also has invested in a venture to develop fuel cells for electricity generation.
 
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 $23 million in 2007 for environmental remediation.
 
The number of persons employed by the Corporation at year end was approximately 13,300 in 2007 and 13,700 in 2006.
 
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


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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 commodities trading 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 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, mandatory government participation, cancellation or amendment of contract rights, and changes in import regulations, as well as other political developments may affect our operations. 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


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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 and the potential for controls on greenhouse gas emissions, have resulted, and will likely continue to result, in higher capital expenditures and operating expenses for us and the oil and gas industry in general.
 
Competitive Risk:  The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies in each of our activities, including acquiring rights to explore for crude oil and natural gas, and in 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, technical expertise and equipment has affected the availability of technical personnel and drilling rigs and has increased capital and operating costs.
 
Catastrophic Risk:  Although we maintain a level of insurance coverage consistent with industry practices 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.
 
Item 3.   Legal Proceedings
 
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, as of the end of 2007, the Registrant is named as a defendant in 51 of approximately 80 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. The damages claimed in these actions are substantial and 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. As a result of Court-ordered mediation, the Registrant anticipates that settlement will be reached in a number of the pending cases, the number and terms of which are currently being negotiated and are subject to a confidentiality agreement. In the fourth quarter 2007, the Registrant recorded a pre-tax charge of $40 million related to MTBE litigation.
 
Over the last several years, many refiners have entered into consent agreements to resolve the United States Environmental Protection Agency’s (EPA) 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. The capital expenditures, penalties and supplemental environmental projects for individual


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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, which owns and operates a refinery in the U.S. Virgin Islands, 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. 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. Negotiations with EPA are continuing and substantial progress has been made toward resolving this matter.
 
On September 13, 2007, HOVENSA received a Notice Of Violation (NOV) pursuant to section 113(a)(i) of the Clean Air Act (Act) from the United States Environmental Protection Agency (EPA) finding that HOVENSA failed to obtain proper permitting for the construction and operation of its delayed coking unit in accordance with applicable law and regulations. HOVENSA believes it properly obtained all necessary permits for this project. The NOV states that EPA has authority to issue an administrative order assessing penalties for violation of the Act. However, HOVENSA intends to enter into discussions with the EPA to reach resolution of this matter. Registrant does not believe that this matter will result in material liability to HOVENSA or Registrant.
 
In December 2006, HOVENSA received a 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. Registrant and over 40 companies entered into an Administrative Order on Consent with EPA to study the same contamination. In June 2007, EPA issued a draft study which evaluated six alternatives for early action, with costs ranging from $900 million to $2.3 billion. Based on adverse comments from Registrant and others, EPA is reevaluating its alternatives. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given the ongoing studies, 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.
 
In July 2004, Hess Oil Virgin Islands Corp. (HOVIC), a wholly owned subsidiary of the Registrant, and HOVENSA, 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.


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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 and DEC have reached a settlement in principle, which is expected to be finalized in early 2008. 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 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.
 
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 2007, 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, 2008 regarding executive officers of the Registrant:
 
                     
            Year Individual
            Became an
            Executive
Name
 
Age
  Office Held*  
Officer
 
John B. Hess
    53     Chairman of the Board, Chief Executive Officer and Director     1983  
J. Barclay Collins II
    63     Executive Vice President, General Counsel and Director     1986  
John J. O’Connor
    61     Executive Vice President, President of Worldwide Exploration and Production and Director     2001  
F. Borden Walker
    54     Executive Vice President and President of Marketing and Refining and Director     1996  
Brian J. Bohling
    47     Senior Vice President     2004  
William T. Drennen
    57     Senior Vice President     2007  
John A. Gartman
    60     Senior Vice President     1997  
Scott Heck
    50     Senior Vice President     2005  
Lawrence H. Ornstein
    56     Senior Vice President     1995  
Howard Paver
    57     Senior Vice President     2002  
John P. Rielly
    45     Senior Vice President and Chief Financial Officer     2002  
George F. Sandison
    51     Senior Vice President     2003  
John J. Scelfo
    50     Senior Vice President     2004  
Gordon Shearer
    53     Senior Vice President     2007  
John V. Simon
    54     Senior Vice President     2007  
Robert J. Vogel
    48     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 2, 2007, except for Mr. Drennen, who was elected on July 2, 2007. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 7, 2008.
 
Except for Messrs. Bohling, Drennen, Sandison, Scelfo and Shearer, 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. Drennen served in senior executive positions in exploration and technology at ExxonMobil and its subsidiaries prior to joining the company in 2007. Mr. Scelfo was chief financial officer of Sirius Satellite Radio and a division of Dell Computer before his employment by the Registrant in 2003. Mr. Sandison served in senior executive positions in the area of global drilling with Texaco, Inc. before he was employed by the Registrant in 2003. Prior to joining Hess LNG, a joint venture subsidiary of the company, in 2004, Mr. Shearer was a consultant at Poten Partners, and held other senior positions in the liquefied natural gas industry.


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PART II
 
Item 5.   Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
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:
 
                                 
    2007     2006  
Quarter Ended
  High     Low     High     Low  
March 31
  $ 58.00     $  45.96     $  52.00     $  42.83  
June 30
    61.48       54.55       53.46       43.23  
September 30
    69.87       53.12       56.45       38.30  
December 31
    105.85       63.58       52.70       37.62  
                                 
 
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, 2002 and ending on December 31, 2007:
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
 
(PERFORMANCE GRAPH)
 
Holders
 
At December 31, 2007, there were 5,673 stockholders (based on number of holders of record) who owned a total of 320,599,585 shares of common stock.


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Dividends
 
Cash dividends on common stock totaled $.40 per share ($.10 per quarter) during 2007 and 2006 on a split adjusted basis.
 
Equity Compensation Plans
 
Following is information on the Registrant’s equity compensation plans at December 31, 2007:
 
                         
                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
    11,292,000     $ 38.31       7,821,000 *
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 8, “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*:
 
                                         
    2007     2006     2005     2004     2003  
    (Millions of dollars, except per share amounts)  
 
Sales and other operating revenues
                                       
Crude oil and natural gas liquids
  $ 6,303     $ 5,307     $ 3,219     $ 2,594     $ 2,295  
Natural gas (including sales of purchased gas)
    6,877       6,826       6,423       4,638       4,522  
Refined and other energy products
    17,063       14,411       11,690       8,125       6,250  
Convenience store sales and other operating revenues
    1,404       1,523       1,415       1,376       1,244  
                                         
Total
  $ 31,647     $ 28,067     $ 22,747     $ 16,733     $ 14,311  
                                         
Income from continuing operations
  $ 1,832 (a)   $ 1,920 (b)   $ 1,226 (c)   $ 970 (d)   $ 467 (e)
Discontinued operations
                      7       169  
Cumulative effect of change in accounting principle
                            7  
                                         
Net income
  $ 1,832     $ 1,920     $ 1,226     $ 977     $ 643  
                                         
Less preferred stock dividends
          44       48       48       5  
                                         
Net income applicable to common shareholders
  $ 1,832     $ 1,876     $ 1,178     $ 929     $ 638  
                                         
Basic earnings per share**
                                       
Continuing operations
  $ 5.86     $ 6.75     $ 4.32     $ 3.43     $ 1.74  
Net income
    5.86       6.75       4.32       3.46       2.40  
Diluted earnings per share**
                                       
Continuing operations
  $ 5.74     $ 6.08     $ 3.93     $ 3.17     $ 1.72  
Net income
    5.74       6.08       3.93       3.19       2.37  
Total assets
  $ 26,131     $ 22,442     $ 19,158     $ 16,312     $ 13,983  
Total debt
    3,980       3,772       3,785       3,835       3,941  
Stockholders’ equity
    9,774       8,147       6,318       5,597       5,340  
Dividends per share of common stock**
  $ .40     $ .40     $ .40     $ .40     $ .40  
 
 
* The financial results for 2007, 2006 and 2005 reflect the impact of FASB Staff Position AUG AIR-1,“Accounting for Planned Major Maintenance Activities” which was retrospectively adopted from January 1, 2005. If the Corporation had adopted this standard on January 1, 2003, after-tax net income would have decreased by $8 million in 2004 and increased by $18 million in 2003.
 
** Per share amounts in all periods reflect the 3-for-1 stock split on May 31, 2006.
 
(a) Includes net after-tax expenses of $75 million primarily relating to asset impairments, estimated production imbalance settlements and a charge for MTBE litigation, partially offset by income from LIFO inventory liquidations and gains from asset sales.
 
(b) 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.
 
(c) 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.
 
(d) Includes net after-tax income of $76 million primarily from sales of assets and income tax adjustments.
 
(e) 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.


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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 2007 was $1,832 million compared with $1,920 million in 2006 and $1,226 million in 2005. Diluted earnings per share were $5.74 in 2007 compared with $6.08 in 2006 and $3.93 in 2005. A table of items affecting comparability between periods is shown on page 21.
 
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. The Corporation’s total proved reserves were 1,330 million barrels of oil equivalent (boe) at December 31, 2007 compared with 1,243 million boe at December 31, 2006 and 1,093 million boe at December 31, 2005. Total proved reserves at year end 2007 increased 87 million boe or 7% from the end of 2006.
 
E&P net income was $1,842 million in 2007, $1,763 million in 2006 and $1,058 million in 2005. The improved results in 2007 as compared to 2006 were primarily driven by higher average crude oil selling prices and increased crude oil and natural gas production. See further discussion in Comparison of Results on page 21.
 
Production averaged 377,000 barrels of oil equivalent per day (boepd) in 2007 compared with 359,000 boepd in 2006 and 335,000 boepd in 2005. Production in 2007 increased 18,000 boepd or 5% from 2006 reflecting the following developments:
 
  •  The Okume Complex in Equatorial Guinea (Hess 85%), which commenced production in December 2006, exhibited strong reservoir performance and facilities uptime during the year. In January 2008, production reached design capacity of 60,000 boepd, gross (approximately 40,000 boepd, net).
 
  •  The Ujung Pangkah Field (Hess 75%) in Indonesia commenced natural gas production in April 2007. The Corporation’s net share of production from the field ramped up to an average of 69,000 mcf per day in the fourth quarter of 2007.
 
  •  The Atlantic (Hess 25%) and Cromarty (Hess 90%) natural gas fields in the United Kingdom North Sea, which came onstream in June 2006, contributed to the Corporation’s year-over-year production growth. Production from the Cromarty Field was shut in during the summer when natural gas prices were seasonally lower and then full production re-commenced in October at higher prices.
 
  •  The Corporation benefited from a full year of natural gas production from Sinphuhorm (Hess 35%) located onshore Thailand, which commenced production in the fourth quarter of 2006, and from production growth in Azerbaijan and Russia.
 
  •  The Snohvit Field located offshore Norway (Hess 3.26%) commenced natural gas production in September 2007 and the Genghis Khan Field in the Gulf of Mexico (Hess 28%) started crude oil production in October 2007.
 
In 2008, the Corporation expects total worldwide production of approximately 380,000 boepd to 390,000 boepd.
 
During the year, the Corporation progressed development projects that will add to its production in future years:
 
  •  The expansion of offshore facilities and installation of wellhead platforms was completed in the fourth quarter at Block A-18 of the Joint Development Area of Malaysia and Thailand (JDA) (Hess 50%). Full Phase 2 production is expected in the second half of 2008.


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  •  The Shenzi development (Hess 28%) in the deepwater Gulf of Mexico progressed with the installation of tension leg platform tendon piles and hull fabrication. First production is expected to commence in mid-2009.
 
  •  Development of the residual oil zone at the Seminole-San Andres Unit (Hess 34.3%) in the Permian Basin commenced and is advancing as planned. Production is expected to start up in 2009.
 
  •  Development of the Ujung Pangkah crude oil project commenced and facilities engineering and construction continue on schedule. Production from this Phase 2 oil project is expected to commence in 2009.
 
  •  The Jambi Merang natural gas project (Hess 25%) in Indonesia was sanctioned during the year.
 
During 2007, the Corporation’s exploration activities included:
 
  •  The Corporation gained access to new exploration acreage including two offshore blocks on the Australian Northwest Shelf, licenses WA-390-P (Hess 100%) and nearby WA-404-P (Hess 50%) with total gross acreage of approximately 1.5 million acres. Additionally, more than 125,000 net undeveloped acres were added in the Bakken trend of North Dakota.
 
  •  On the Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico a sidetrack from the original discovery well was successfully completed in the first quarter and a second appraisal well is being drilled about 1.5 miles northwest of the original discovery well.
 
  •  At the Tubular Bells discovery (Hess 20%) on Mississippi Canyon Block 682 in the deepwater Gulf of Mexico a successful sidetrack well was completed during the first quarter of 2007 and a further appraisal well was spud in October 2007.
 
During 2007, the Corporation completed the following acquisition and divestiture transactions:
 
  •  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, which is part of the same geological structure as the Shenzi development.
 
  •  In the second quarter, interests in the Scott-Telford fields located offshore United Kingdom were sold for $93 million resulting in an after-tax gain of $15 million ($21 million before income taxes). The Corporation’s share of production from the Scott-Telford fields was approximately 6,500 boepd at the time of sale.
 
Marketing and Refining
 
The Corporation’s strategy for the M&R segment is to deliver consistent operating performance and generate free cash flow. M&R net income was $300 million in 2007, $394 million in 2006 and $499 million in 2005. Profitability in 2007 and 2006 was adversely affected by lower average margins.
 
Refining operations contributed net income of $193 million in 2007, $240 million in 2006 and $330 million in 2005. The Corporation received cash distributions from HOVENSA, a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA), totaling $300 million in 2007, $400 million in 2006 and $275 million in 2005. Gross crude runs at HOVENSA averaged 454,000 barrels per day in 2007 compared with 448,000 barrels per day in 2006 and 461,000 barrels per day in 2005. In 2007, HOVENSA successfully completed the first turnaround of its delayed coking unit. The Port Reading refinery operated at an average of 61,000 barrels per day in 2007 versus 63,000 barrels per day in 2006 and 55,000 barrels per day in 2005. Marketing earnings were $83 million in 2007, $108 million in 2006 and $136 million in 2005. Total refined product sales volumes averaged 451,000 barrels per day in 2007 compared with 459,000 barrels per day in 2006 and 456,000 barrels per day in 2005.
 
Liquidity and Capital and Exploratory Expenditures
 
Net cash provided by operating activities was $3,507 million in 2007, $3,491 million in 2006 and $1,840 million in 2005, principally reflecting increasing earnings. At December 31, 2007, cash and cash equivalents totaled $607 million compared with $383 million at December 31, 2006. Total debt was


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$3,980 million at December 31, 2007 compared with $3,772 million at December 31, 2006. The Corporation’s debt to capitalization ratio at December 31, 2007 was 28.9% compared with 31.6% at the end of 2006. The Corporation has debt maturities of $62 million in 2008 and $143 million in 2009.
 
Capital and exploratory expenditures were as follows for the years ended December 31:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Exploration and Production
               
United States
  $ 1,603     $ 908  
International
    2,183       2,979  
                 
Total Exploration and Production
    3,786       3,887  
Marketing, Refining and Corporate
    140       169  
                 
Total Capital and Exploratory Expenditures
  $ 3,926     $ 4,056  
                 
Exploration expenses charged to income included above:
               
United States
  $ 192     $ 110  
International
    156       102  
                 
Total exploration expenses charged to income included above
  $ 348     $ 212  
                 
 
The Corporation anticipates $4.4 billion in capital and exploratory expenditures in 2008, of which $4.3 billion relates to E&P operations.
 
Consolidated Results of Operations
 
The after-tax results by major operating activity are summarized below:
 
                         
    2007     2006     2005  
    (Millions of dollars,
 
    except per share data)  
 
Exploration and Production
  $ 1,842     $ 1,763     $ 1,058  
Marketing and Refining
    300       394       499  
Corporate
    (150 )     (110 )     (191 )
Interest expense
    (160 )     (127 )     (140 )
                         
Net income
  $ 1,832     $ 1,920     $ 1,226  
                         
Net income per share — diluted
  $ 5.74     $ 6.08     $ 3.93  
                         
 
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 income tax rate in each tax jurisdiction to pre-tax amounts.


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The following items of income (expense), on an after-tax basis, are included in net income:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Exploration and Production
                       
Gains from asset sales
  $ 15     $ 236     $ 41  
Asset impairments
    (56 )            
Estimated production imbalance settlements
    (33 )            
Income tax adjustments
          (45 )     11  
Accrued office closing costs
          (18 )      
Hurricane related costs
                (26 )
Legal settlement
                11  
Marketing and Refining
                       
LIFO inventory liquidations
    24             32  
Charge related to customer bankruptcy
                (8 )
Corporate
                       
Estimated MTBE litigation
    (25 )            
Tax on repatriated earnings
                (72 )
Premiums on bond repurchases
                (26 )
                         
    $ (75 )   $ 173     $ (37 )
                         
 
 
The items in the table above are explained, and the pre-tax amounts are shown, on pages 24 through 27.
 
Comparison of Results
 
Exploration and Production
 
Following is a summarized income statement of the Corporation’s Exploration and Production operations:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Sales and other operating revenues*
  $ 7,498     $ 6,524     $ 4,210  
Other income
    65       428       94  
                         
Total revenues
    7,563       6,952       4,304  
                         
Costs and expenses
                       
Production expenses, including related taxes
    1,581       1,250       1,007  
Exploration expenses, including dry holes and lease impairment
    515       552       397  
General, administrative and other expenses
    257       209       140  
Depreciation, depletion and amortization
    1,503       1,159       965  
                         
Total costs and expenses
    3,856       3,170       2,509  
                         
Results of operations from continuing operations before income taxes
    3,707       3,782       1,795  
Provision for income taxes
    1,865       2,019       737  
                         
Results of operations
  $ 1,842     $ 1,763     $ 1,058  
                         
 
 
 
* Amounts differ from E&P operating revenues in Note 16 “ Segment Information” primarily due to the exclusion of sales of hydrocarbons purchased from third parties.


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After considering the Exploration and Production items in the table on page 21, 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 selling prices, primarily crude oil, increased Exploration and Production revenues by approximately $740 million in 2007 compared with 2006. In 2006, the increase in average crude oil selling prices and reduced hedge positions increased revenues by approximately $1,900 million compared with 2005.
 
The Corporation’s average selling prices were as follows:
 
                         
    2007     2006     2005  
 
Crude oil-per barrel (including hedging)
                       
United States
  $ 69.23     $ 60.45     $ 32.64  
Europe
    60.99       56.19       33.13  
Africa
    62.04       51.18       32.10  
Asia and other
    72.17       61.52       54.71  
Worldwide
    63.44       55.31       33.38  
Crude oil-per barrel (excluding hedging)
                       
United States
  $ 69.23     $ 60.45     $ 51.16  
Europe
    60.99       58.46       52.22  
Africa
    71.71       62.80       51.70  
Asia and other
    72.17       61.52       54.71  
Worldwide
    67.79       60.41       51.94  
Natural gas liquids-per barrel
                       
United States
  $ 51.89     $ 46.22     $ 38.50  
Europe
    57.20       47.30       37.13  
Worldwide
    53.72       46.59       38.08  
Natural gas-per mcf
                       
United States
  $ 6.67     $ 6.59     $ 7.93  
Europe
    6.13       6.20       5.29  
Asia and other
    4.71       4.05       4.02  
Worldwide
    5.60       5.50       5.65  
 
 
The after-tax impacts of hedging reduced earnings by $244 million ($399 million before income taxes) in 2007, $285 million ($449 million before income taxes) in 2006 and $989 million ($1,582 million before income taxes) in 2005.
 
Production and sales volumes:  The Corporation’s crude oil and natural gas production was 377,000 boepd in 2007 compared with 359,000 boepd in 2006 and 335,000 boepd in 2005. The Corporation anticipates that its 2008 production will average between 380,000 and 390,000 boepd.


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The Corporation’s net daily worldwide production was as follows:
 
                         
    2007     2006     2005  
 
Crude oil (thousands of barrels per day)
                       
United States
    31       36       44  
Europe
    93       109       110  
Africa
    115       85       67  
Asia and other
    21       12       7  
                         
Total
    260       242       228  
                         
Natural gas liquids (thousands of barrels per day)
                       
United States
    10       10       12  
Europe
    5       5       4  
                         
Total
    15       15       16  
                         
Natural gas (thousands of mcf per day)
                       
United States
    88       110       137  
Europe
    259       283       274  
Asia and other
    266       219       133  
                         
Total
    613       612       544  
                         
Barrels of oil equivalent* (thousands of barrels per day)
    377       359       335  
                         
 
 
* Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel).
 
United States:  Crude oil and natural gas production was lower in 2007 compared with 2006 and 2005, principally due to natural decline and asset sales.
 
Europe:  Crude oil production in 2007 was lower than in 2006, reflecting natural decline, facilities work on three North Sea fields, and the sale of the Corporation’s interests in the Scott and Telford fields in the United Kingdom. These decreases were partially offset by increased production in Russia. Decreased natural gas production in 2007 compared with 2006 was principally due to lower nominations related to the shut-down of a non-operated pipeline in the North Sea and natural decline, partially offset by higher production from the Atlantic and Cromarty natural gas fields in the United Kingdom which commenced in June 2006. Production in Europe was comparable in 2006 and 2005, reflecting increased production from Russia and new production from the Atlantic and Cromarty fields, which offset lower production due to maintenance and natural decline.
 
Africa:  Crude oil production increased in 2007 compared with 2006 primarily due to the start-up of the Okume Complex in Equatorial Guinea in December 2006. Production in 2006 was higher than 2005 levels, principally due to production from Libya, which the Corporation re-entered in January 2006.
 
Asia and other:  Crude oil production increased in 2007 versus 2006, reflecting a combination of an increased entitlement and higher production in Azerbaijan. Higher natural gas production in 2007 compared with 2006 was principally due to new production from the Sinphuhorm onshore gas project in Thailand which commenced in November 2006 and new production from the Ujung Pangkah Field in Indonesia which commenced in April 2007. These increases were partially offset by the planned shut-down of the JDA to install facilities required for Phase 2 gas sales. Natural gas production was higher in 2006 compared with 2005 due to increased production from the JDA.
 
Sales volumes:  Higher sales volumes increased revenue by approximately $240 million in 2007 compared with 2006 and $400 million in 2006 compared with 2005.
 
Operating costs and depreciation, depletion and amortization:  Cash operating costs, consisting of production expenses and general and administrative expenses, increased by $409 million in 2007 and $322 million in 2006 compared with the corresponding amounts in prior years (excluding the charges for


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vacated leased office space and hurricane related costs in 2006). The increases in 2007 and 2006 were primarily due to higher production volumes, increased costs of services and materials, higher employee costs and increased production taxes. Cash operating costs per barrel of oil equivalent were $13.36 in 2007, $10.92 in 2006 and $9.07 in 2005. Cash operating costs in 2008 are estimated to be in the range of $14.00 to $15.00 per barrel of oil equivalent.
 
Excluding the pre-tax amount of the 2007 asset impairments, depreciation, depletion and amortization charges increased by $232 million and $194 million in 2007 and 2006, respectively. The increases were primarily due to higher production volumes and per barrel costs. Depreciation, depletion and amortization costs per barrel of oil equivalent were $10.11 in 2007, $8.85 in 2006 and $7.88 in 2005. Depreciation, depletion and amortization costs for 2008 are expected to be in the range of $12.50 to $13.50 per barrel.
 
Exploration expenses:  Exploration expenses were lower in 2007 compared with 2006, primarily reflecting lower dry hole costs, partially offset by increased costs related to seismic studies. Exploration expenses were higher in 2006 compared with 2005, principally reflecting higher dry hole costs.
 
Income taxes:  The effective income tax rate for Exploration and Production operations was 50% in 2007, 53% in 2006 and 41% in 2005. After considering the items in the table below, the effective income tax rates were 50% in 2007, 54% in 2006 and 42% in 2005. The effective income tax rate increased beginning in 2006 due to the Corporation’s re-entry into Libya and the increase in the supplementary tax on petroleum operations in the United Kingdom from 10% to 20%. The effective income tax rate for E&P operations in 2008 is expected to be in the range of 47% to 51%.
 
Other:  The after-tax foreign currency loss was $7 million in 2007, compared with a gain of $10 million in 2006 and $20 million in 2005.
 
Reported Exploration and Production earnings include the following items of income (expense) before and after income taxes:
 
                                                 
    Before Income Taxes     After Income Taxes  
    2007     2006     2005     2007     2006     2005  
    (Millions of dollars)  
 
Gains from asset sales
  $ 21     $ 369     $ 48     $ 15     $ 236     $ 41  
Asset impairments
    (112 )                 (56 )            
Estimated production imbalance settlements
    (64 )                 (33 )            
Income tax adjustments
                            (45 )     11  
Accrued office closing costs
          (30 )                 (18 )      
Hurricane related costs
                (40 )                 (26 )
Legal settlement
                19                   11  
                                                 
    $ (155 )   $ 339     $ 27     $ (74 )   $ 173     $ 37  
                                                 
 
2007:  The gain from asset sales relates to the sale of the Corporation’s interests in the Scott and Telford fields located in the United Kingdom North Sea. The charge for asset impairments relates to two mature fields in the United Kingdom North Sea. The pre-tax amount of this charge is reflected in depreciation, depletion and amortization. The estimated production imbalance settlements represent a charge for adjustments to prior meter readings at two offshore fields, which are recorded as a reduction of sales and other operating revenues.
 
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 related expenses are reflected principally in general and administrative expenses. 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%.
 
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 Ujung Pangkah Field in Indonesia. The Corporation recorded incremental production expenses in 2005, principally repair costs and higher insurance


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premiums, as a result of hurricane damage in the Gulf of Mexico. 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 recorded in other income 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 $300 million in 2007, $394 million in 2006 and $499 million in 2005. After considering the Marketing and Refining items in the table on page 21, the earnings amounted to $276 million in 2007, $394 million in 2006 and $475 million in 2005 and are discussed in the paragraphs below. The Corporation’s downstream operations include its 50% interest in HOVENSA, which 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 results of other miscellaneous operating activities were $193 million in 2007, $240 million in 2006 and $330 million in 2005.
 
The Corporation’s share of HOVENSA’s net income was $108 million ($176 million before income taxes) in 2007, $124 million ($201 million before income taxes) in 2006 and $227 million ($370 million before income taxes) in 2005. The lower earnings in 2007 and 2006 compared to the respective prior years were principally due to lower refining margins. During 2007, the coker unit at HOVENSA was shutdown for approximately 30 days for a scheduled turnaround. Certain related processing units were also included in this turnaround. In 2006, the fluid catalytic cracking unit at HOVENSA 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 $300 million in 2007, $400 million in 2006 and $275 million in 2005.
 
Pre-tax interest income on the PDVSA note was $9 million, $15 million and $20 million in 2007, 2006 and 2005, respectively. Interest income is reflected in other income in the income statement. At December 31, 2007, the remaining balance of the PDVSA note was $76 million, which is scheduled to be fully repaid by February 2009.
 
Port Reading’s after-tax earnings were $75 million in 2007, $104 million in 2006 and $88 million in 2005. Refined product margins were lower in 2007 compared with 2006. Higher refined product sales volumes were offset by lower margins in 2006 compared with 2005. In 2005, the Port Reading facility was shutdown for 36 days of planned maintenance.
 
The following table summarizes refinery utilization rates:
 
                                 
    Refinery
    Refinery Utilization  
    Capacity     2007     2006     2005  
    (Thousands of
                   
    barrels per day)                    
 
HOVENSA
                               
Crude
    500       90.8%       89.7%       92.2%  
Fluid catalytic cracker
    150       87.1%       84.3%       81.9%  
Coker
    58       83.4%       84.3%       92.8%  
Port Reading
    65       93.2%       97.4%       85.3%  
 
Marketing:  Marketing operations, which consist principally of retail gasoline and energy marketing activities, generated income of $59 million in 2007, $108 million in 2006 and $112 million in 2005, excluding income from liquidations of LIFO inventories and the charge related to a customer bankruptcy described on page 26.


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The decreases in 2007 and 2006 primarily reflect lower margins on refined product sales. Total refined product sales volumes were 451,000 barrels per day in 2007, 459,000 barrels per day in 2006 and 456,000 barrels per day in 2005. Total energy marketing natural gas sales volumes, including utility and spot sales, were approximately 1.9 million mcf per day in 2007, 1.8 million mcf per day in 2006 and 1.7 million mcf per day in 2005. In addition, energy marketing sold electricity volumes at the rate of 2,800, 1,400 and 500 megawatts (round the clock) in 2007, 2006 and 2005, respectively.
 
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 $24 million in 2007, $46 million in 2006 and $33 million in 2005.
 
Marketing expenses were comparable in 2007 and 2006, but increased in 2006 compared with 2005, due to higher expenses from an increased number of retail convenience stores, growth in energy marketing operations and increased 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  
    2007     2006     2005     2007     2006     2005  
    (Millions of dollars)  
 
LIFO inventory liquidations
  $   38     $   —     $   51     $   24     $   —     $   32  
Charge related to customer bankruptcy
                (13 )                 (8 )
                                                 
    $ 38     $     $ 38     $ 24     $     $ 24  
                                                 
 
In 2007 and 2005, Marketing and Refining earnings include income from the liquidation of prior year LIFO inventories. In 2005, Marketing and Refining earnings also 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 margins, competitive industry conditions, government regulatory changes, credit risk and supply and demand factors, including the effects of weather.
 
Corporate
 
The following table summarizes corporate expenses:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Corporate expenses (excluding the items listed below)
  $ 187     $ 156     $ 119  
Income taxes (benefits) on the above
    (62 )     (46 )     (26 )
                         
      125       110       93  
Items affecting comparability between periods, after tax
                       
Estimated MTBE litigation
    25              
Tax on repatriated earnings
                72  
Premiums on bond repurchases
                26  
                         
Net corporate expenses
  $ 150     $ 110     $ 191  
                         
 
Excluding the items affecting comparability between periods, the increase in corporate expenses in 2007 compared with 2006 primarily reflects higher employee related costs, including stock-based compensation. The increase in corporate expenses in 2006 compared with 2005 principally reflects the expensing of stock options


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commencing January 1, 2006 and increases in insurance costs. Recurring after-tax corporate expenses in 2008 are estimated to be in the range of $130 to $140 million.
 
In 2007, Corporate expenses include a charge of $25 million ($40 million before income taxes) related to MTBE litigation. The pre-tax amount of this charge is recorded in general and administrative expenses. 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, which was recorded in other income in the income statement.
 
Interest
 
After-tax interest expense was as follows:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Total interest incurred
  $ 306     $ 301     $ 304  
Less capitalized interest
    50       100       80  
                         
Interest expense before income taxes
    256       201       224  
Less income taxes
    96       74       84  
                         
After-tax interest expense
  $ 160     $ 127     $ 140  
                         
 
The decrease in capitalized interest in 2007 reflects the completion of several development projects in 2007 and the latter portion of 2006. After-tax interest expense in 2008 is expected to be in the range of $165 to $175 million, principally reflecting lower capitalized interest.
 
Sales and Other Operating Revenues
 
Sales and other operating revenues totaled $31,647 million in 2007, an increase of 13% compared with 2006. The increase reflects higher selling prices and sales volumes of crude oil, higher refined product selling prices and increased sales volumes in electricity. In 2006, sales and other operating revenues totaled $28,067 million, 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.
 
The change in cost of goods sold in each year principally reflects the change in sales volumes and prices of refined products and purchased natural gas and electricity.
 
Liquidity and Capital Resources
 
The following table sets forth certain relevant measures of the Corporation’s liquidity and capital resources as of December 31:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Cash and cash equivalents
  $ 607     $ 383  
Current portion of long-term debt
  $ 62     $ 27  
Total debt
  $ 3,980     $ 3,772  
Stockholders’ equity
  $ 9,774     $ 8,147  
Debt to capitalization ratio*
    28.9 %     31.6 %
 
 
* Total debt as a percentage of the sum of total debt plus stockholders’ equity.


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Cash Flows
 
The following table sets forth a summary of the Corporation’s cash flows:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Net cash provided by (used in):
                       
Operating activities
  $ 3,507     $ 3,491     $ 1,840  
Investing activities
    (3,474 )     (3,289 )     (2,255 )
Financing activities
    191       (134 )     (147 )
                         
Net increase (decrease) in cash and cash equivalents
  $ 224     $ 68     $ (562 )
                         
 
Operating Activities:  Net cash provided by operating activities, including changes in operating assets and liabilities, was comparable in 2007 and 2006. Net cash provided by operating activities increased to $3,491 million in 2006 from $1,840 million in 2005, principally reflecting higher earnings, changes in working capital accounts and increased distributions from HOVENSA. The Corporation received cash distributions from HOVENSA of $300 million in 2007, $400 million in 2006 and $275 million in 2005.
 
Investing Activities:  The following table summarizes the Corporation’s capital expenditures:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Exploration and Production
                       
Exploration
  $ 371     $ 590     $ 229  
Production and development
    2,605       2,164       1,598  
Acquisitions (including leaseholds)
    462       921       408  
                         
      3,438       3,675       2,235  
Marketing, Refining and Corporate
    140       169       106  
                         
Total
  $ 3,578     $ 3,844     $ 2,341  
                         
 
Capital expenditures in 2007 include the acquisition of a 28% interest in the Genghis Khan Field in the deepwater Gulf of Mexico for $371 million. In 2006, capital expenditures included payments of $359 million to re-enter 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.
 
In 2007 the Corporation received proceeds of $93 million for the sale of its interests in the Scott and Telford fields located in the United Kingdom. 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 in 2005, principally from the sale of non-producing properties.
 
Financing Activities:  During 2007, net borrowings were $208 million. The Corporation reduced debt by $13 million in 2006 and $50 million in 2005. 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.
 
Common stock dividends paid were $127 million in 2007. Total common and preferred stock dividends paid were $161 million in 2006 and $159 million in 2005. The Corporation received net proceeds from the exercise of stock options totaling $110 million, $40 million and $62 million in 2007, 2006 and 2005, respectively.
 
Future Capital Requirements and Resources
 
The Corporation anticipates $4.4 billion in capital and exploratory expenditures in 2008, of which $4.3 billion relates to Exploration and Production operations. The Corporation has maturities of long-term debt of $62 million in 2008 and $143 million in 2009. The Corporation anticipates that it can fund its 2008 operations, including capital


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expenditures, dividends, pension contributions and required debt repayments, with existing cash on-hand, projected cash flow from operations and its available credit facilities.
 
The Corporation maintains a $3.0 billion syndicated, revolving credit facility (the facility), substantially all of which is committed through May 2012. The facility can be used for borrowings and letters of credit. At December 31, 2007, outstanding borrowings under the facility were $220 million and additional available borrowing capacity under the facility was $2,780 million.
 
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, 2007, the Corporation had $250 million in outstanding borrowings and outstanding letters of credit of $534 million which were collateralized by $1,336 million of Marketing and Refining accounts receivable. These receivables are not available to pay the general obligations of the Corporation before repayment of outstanding borrowings under the asset-backed facility.
 
At December 31, 2007, $600 million of outstanding borrowings under short-term credit facilities are classified as long term based on the Corporation’s available capacity under the committed revolving credit facility. These borrowings consist of the $250 million under the asset-backed credit facility described above, $300 million under a short-term committed facility and $50 million under uncommitted lines at December 31, 2007. 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:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Revolving credit facility
  $     $ 1  
Asset-backed credit facility
    534        
Committed short-term letter of credit facilities
    995       1,875  
Uncommitted lines
    1,510       1,603  
                 
    $ 3,039     $ 3,479  
                 
 
A loan agreement covenant based on the Corporation’s debt to equity ratio allows the Corporation to borrow up to an additional $12.3 billion for the construction or acquisition of assets at December 31, 2007. The Corporation has the ability to borrow up to an additional $2.6 billion of secured debt at December 31, 2007 under the loan agreement covenants.
 
Credit Ratings
 
There are three major credit rating agencies that rate the Corporation’s debt. All three agencies have currently assigned an investment grade rating to the Corporation’s debt. The interest rates and facility fees charged on the Corporation’s borrowing arrangements and margin requirements from non-trading and trading counterparties are subject to adjustment if the Corporation’s credit rating changes.


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Contractual Obligations and Contingencies
 
Following is a table showing aggregated information about certain contractual obligations at December 31, 2007:
 
                                         
          Payments Due by Period  
                2009 and
    2011 and
       
    Total     2008     2010     2012     Thereafter  
    (Millions of dollars)  
 
Long-term debt(a)
  $ 3,980     $ 62     $ 172     $ 1,543     $ 2,203  
Operating leases
    3,233       382       849       588       1,414  
Purchase obligations
                                       
Supply commitments
    38,548       9,805       14,560       14,058       125 (b)
Capital expenditures
    1,951       1,118       833              
Operating expenses
    977       537       230       105       105  
Other long-term liabilities
    1,579       98       481       222       778  
 
 
(a) At December 31, 2007, 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 $7.0 billion annually using year-end 2007 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 future capital expenditures, including a portion of the Corporation’s planned $4.4 billion capital investment program for 2008, that is contractually committed at December 31, 2007. 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, 2007, including asset retirement obligations, pension plan funding requirements and anticipated obligations for uncertain income tax positions.
 
The Corporation and certain of its subsidiaries lease gasoline stations, drilling rigs, tankers, office space and other assets for varying periods under leases accounted for as operating leases. During 2007, the Corporation entered into a lease agreement for a new drillship and related support services for use in its global deepwater exploration and development activities beginning in the middle of 2009. The total payments under this five year contract will approximate $950 million.
 
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 $150 million as of December 31, 2007.
 
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, 2007 amounted to $277 million. In addition, the Corporation has 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, 2007, the Corporation has issued $2,978 million of letters of credit principally relating to accrued liabilities with hedging and trading counterparties recorded on its balance sheet. In addition, the


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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
  $ 61  
Guarantees
    292 *
         
    $ 353  
         
 
* Includes $277 million for the HOVENSA crude oil purchases guarantee and the $15 million guarantee on HOVENSA’s debt which are discussed on page 30.
 
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 $493 million at December 31, 2007 compared with $490 million at December 31, 2006. The Corporation’s December 31, 2007 debt to capitalization ratio would increase from 28.9% to 31.4% if these leases were included as debt.
 
See also “Contractual Obligations and Contingencies” on page 30, Note 4, “Refining Joint Venture,” and Note 15, “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. 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 principally in Algeria, Australia, Azerbaijan, Brazil, Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Libya, Malaysia, Norway, Russia, Thailand, the United Kingdom and the United States. 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 owns and operates a refinery in the United States Virgin Islands. In 2002, there was a political disruption in Venezuela that reduced the availability of Venezuelan crude oil used in refining operations; however, this disruption did not have a material adverse effect on the Corporation’s financial position. The Corporation has a note receivable of $76 million at December 31, 2007 from a subsidiary of PDVSA. All payments are current and the Corporation anticipates collection of the remaining balance.
 
See also Item 1A. Risk Factors Related to Our Business and Operations.
 
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


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


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The Corporation’s impairment tests of long-lived Exploration and Production producing assets are based on its best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, 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 decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly.
 
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, which is an operating segment or one level below an operating segment. 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.
 
Asset Retirement Obligations:  The Corporation has material legal obligations to remove and dismantle long lived assets and to restore land or seabed at certain exploration and production locations. In accordance with generally accepted accounting principles, the Corporation recognizes a liability for the fair value of required asset retirement obligations. 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 such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In order to measure these obligations, the Corporation estimates the fair value of the obligations by discounting the future payments that will be required to satisfy the obligations. In determining these estimates, the Corporation is required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate. In addition, there are other external factors which could significantly affect the ultimate settlement costs for these obligations including: changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates and advances in technology. As a result, the Corporation’s estimates of asset retirement obligations are subject to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values.
 
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 partnership, trades energy commodities and 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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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. These judgements include the requirement to only recognize the financial statement effect of a tax position when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination.
 
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. 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.
 
Changes in Accounting Policies
 
Effective January 1, 2007, the Corporation adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP eliminated the previously acceptable accrue-in-advance method of accounting for planned major maintenance. As a result, the Corporation retrospectively changed its method of accounting to recognize expenses associated with refinery turnarounds when such costs are incurred. The impact of adopting this FSP increased previously reported 2006 earnings by $4 million ($.01 per diluted share). In addition, previously reported 2005 net income decreased by $16 million ($.05 per diluted share) and retained earnings as of January 1, 2005 increased by approximately $48 million. All 2007, 2006 and 2005 financial information reflects this retrospective accounting change.
 
Effective January 1, 2007, the Corporation adopted the provisions of FASB 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. See Note 11, “Income Taxes” for further information.
 
Recently Issued Accounting Standard
 
In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS No. 157). FAS No. 157 establishes a framework for measuring fair value and requires disclosure of a fair value hierarchy, which applies to financial assets and liabilities measured at fair value under other authoritative accounting pronouncements. The standard also requires additional disclosure about the methods of determining fair value. The Corporation as


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required, will prospectively adopt the provisions of FAS No. 157 effective January 1, 2008. The Corporation believes that the impact of adopting FAS No. 157 on net income will not be material. In addition, the Corporation expects to record a reduction in the after-tax charge reflected in accumulated other comprehensive income relating to the crude oil hedging program of approximately $160 million, after income taxes.
 
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 realized as collateral benefits from investments in EHS & SR. The Corporation has programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies 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 2006, additional regulations to reduce the allowable sulfur content in diesel fuel went into effect. 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. The Energy Policy Act of 2005 imposes on refiners a requirement to use specific quantities of renewable content in gasoline. The 2007 Energy Policy Act expanded requirements on the use of renewable content and included several technology forcing provisions. Many states have also enacted or are considering biofuels mandates, which, in combination with national legislation may affect the Registrant’s markets for fuels.
 
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 80% 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.
 
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 has completed an independently verified audit of its emissions. The monitoring protocol in conjunction with the Corporation’s recently formulated Climate Change Network will allow for better control of these emissions and assist the Corporation in developing policies and programs to reduce these emissions and comply 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 2007, the Corporation’s reserve for estimated environmental liabilities was approximately $60 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


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was $23 million in 2007 and $15 million in 2006 and 2005. Capital expenditures incurred over several years to comply with low sulfur gasoline and diesel fuel requirements totaled approximately $400 million at HOVENSA and approximately $70 million at Port Reading. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, other than for the low sulfur requirements, were $22 million in 2007 and 2006 and $3 million in 2005.
 
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 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 is responsible for administering 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 Corporation enters into contracts for the forward purchase and sale of commodities. 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.


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  •  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 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)  
 
2007
               
At December 31
  $ 10     $ 72  
Average
    12       63  
High
    13       72  
Low
    10       54  
2006
               
At December 31
  $ 17     $ 62  
Average
    20       75  
High
    22       86  
Low
    17       62  
 
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, 2007:
 
                 
    Brent Crude Oil  
    Average
    Thousands of
 
Maturity
  Selling Price     Barrels per Day  
 
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, 2007. 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, swaps and options to manage the risk in its marketing activities.
 
Accumulated other comprehensive income (loss) at December 31, 2007 includes after-tax unrealized deferred losses of $1,672 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.


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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, 2007, the Corporation had $977 million of notional value foreign exchange contracts maturing in 2008. The fair value of the foreign exchange contracts was a payable of $1 million at December 31, 2007. The change in fair value of the foreign exchange contracts from a 10% change in exchange rates is estimated to be approximately $100 million at December 31, 2007.
 
The Corporation’s outstanding debt of $3,980 million has a fair value of $4,263 million at December 31, 2007. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $200 million at December 31, 2007.
 
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 commodities, securities 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. Total realized gains on trading activities for 2007 amounted to $303 million ($721 million in 2006). Derivative trading transactions are marked-to-market and unrealized gains or losses are reflected in income currently. 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.
 
                 
    2007     2006  
    (Millions of dollars)  
 
Fair value of contracts outstanding at the beginning of the year
  $ 365     $ 1,109  
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of year
    193       (82 )
Reversal of fair value for contracts closed during the year
    (230 )     (547 )
Fair value of contracts entered into during the year and still outstanding
    (174 )     (115 )
                 
Fair value of contracts outstanding at the end of the year
  $ 154     $ 365  
                 
 
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, 2007:
 
                                         
                            2011 and
 
    Total     2008     2009     2010     Beyond  
          (Millions of dollars)        
 
Source of fair value
                                       
Prices actively quoted
  $ 119     $ 45     $ 53     $ 42     $ (21 )
Other external sources
    36       24       10             2  
Internal estimates
    (1 )     (1 )                  
                                         
Total
  $ 154     $ 68     $ 63     $ 42     $ (19 )
                                         


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The following table summarizes the net receivables relating to the Corporation’s trading activities and the credit ratings of counterparties at December 31:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Investment grade determined by outside sources
  $ 364     $ 347  
Investment grade determined internally*
    173       59  
Less than investment grade
    55       41  
                 
Fair value of net receivables outstanding at the end of the year
  $ 592     $ 447  
                 
 
 
* 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  
 
    41  
    42  
    44  
    45  
    46  
    47  
    48  
    49  
    74  
    80  
    86  
    87  
 
 
* 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, 2007.
 
The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2007, 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 22, 2008


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
Hess Corporation
 
We have audited Hess Corporation’s internal control over financial reporting as of December 31, 2007, 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 included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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, Hess Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007 based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Hess Corporation and consolidated subsidiaries as of December 31, 2007 and 2006, and the related statements of consolidated income, cash flows, stockholders’ equity and comprehensive income of Hess Corporation and consolidated subsidiaries for each of the three years in the period ended December 31, 2007, and our report dated February 22, 2008 expressed an unqualified opinion thereon.
 
(ERNST <DATA,ampersand> YOUNG)
 
February 22, 2008
New York, New York


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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 and consolidated subsidiaries as of December 31, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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 FASB Staff Position (FSP) AUG AIR-1, Accounting for Planned Major Maintenance Activities, and FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, effective January 1, 2007. As discussed in Note 10 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. Also, 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.
 
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, 2007, 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 22, 2008 expressed an unqualified opinion thereon.
 
(ERNST <DATA,ampersand> YOUNG)
 
February 22, 2008
New York, New York


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEET
 
                 
    For the Years Ended
 
    December 31  
    2007     2006  
    (Millions of dollars;
 
    thousands of shares)  
 
ASSETS
CURRENT ASSETS
               
Cash and cash equivalents
  $ 607     $ 383  
Accounts receivable
               
Trade
    4,527       3,659  
Other
    181       214  
Inventories
    1,250       1,005  
Other current assets
    361       587  
                 
Total current assets
    6,926       5,848  
                 
INVESTMENTS IN AFFILIATES
               
HOVENSA L.L.C. 
    933       1,055  
Other
    184       188  
                 
Total investments in affiliates
    1,117       1,243  
                 
PROPERTY, PLANT AND EQUIPMENT
               
Exploration and Production
    22,903       20,199  
Marketing, Refining and Corporate
    1,928       1,781  
                 
Total — at cost
    24,831       21,980  
Less reserves for depreciation, depletion, amortization and lease impairment
    10,197       9,672  
                 
Property, plant and equipment — net
    14,634       12,308  
                 
GOODWILL
    1,225       1,253  
DEFERRED INCOME TAXES
    1,873       1,430  
OTHER ASSETS
    356       360  
                 
TOTAL ASSETS
  $ 26,131     $ 22,442  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
               
Accounts payable
  $ 5,741     $ 4,803  
Accrued liabilities
    1,638       1,477  
Taxes payable
    583       432  
Current maturities of long-term debt
    62       27  
                 
Total current liabilities
    8,024       6,739  
LONG-TERM DEBT
    3,918       3,745  
DEFERRED INCOME TAXES
    2,362       2,116  
ASSET RETIREMENT OBLIGATIONS
    1,016       824  
OTHER LIABILITIES AND DEFERRED CREDITS
    1,037       871  
                 
Total liabilities
    16,357       14,295  
                 
STOCKHOLDERS’ EQUITY
               
Preferred stock, par value $1.00, 20,000 shares authorized
               
3% cumulative convertible series
               
Authorized — 330 shares
               
Issued — 284 shares in 2007 ($14 million liquidation preference) and 324 shares in 2006
           
Common stock, par value $1.00
               
Authorized — 600,000 shares
               
Issued — 320,600 shares in 2007; 315,018 shares in 2006
    321       315  
Capital in excess of par value
    1,882       1,689  
Retained earnings
    9,412       7,707  
Accumulated other comprehensive income (loss)
    (1,841 )     (1,564 )
                 
Total stockholders’ equity
    9,774       8,147  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 26,131     $ 22,442  
                 
 
 
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  
    2007     2006     2005  
    (In millions, except per share data)  
 
REVENUES AND NON-OPERATING INCOME
                       
Sales (excluding excise taxes) and other operating revenues
  $ 31,647     $ 28,067     $ 22,747  
Equity in income of HOVENSA L.L.C. 
    176       201       370  
Gain on asset sales
    21       369       48  
Other income, net
    80       81       84  
                         
Total revenues and non-operating income
    31,924       28,718       23,249  
                         
COSTS AND EXPENSES
                       
Cost of products sold (excluding items shown separately below)
    22,573       19,912       17,041  
Production expenses
    1,581       1,250       1,007  
Marketing expenses
    944       940       842  
Exploration expenses, including dry holes and lease impairment
    515       552       397  
Other operating expenses
    161       122       155  
General and administrative expenses
    614       471       357  
Interest expense
    256       201       224  
Depreciation, depletion and amortization
    1,576       1,224       1,025  
                         
Total costs and expenses
    28,220       24,672       21,048  
                         
INCOME BEFORE INCOME TAXES
    3,704       4,046       2,201  
Provision for income taxes
    1,872       2,126       975  
                         
NET INCOME
  $ 1,832     $ 1,920     $ 1,226  
                         
Less preferred stock dividends
          44       48  
                         
NET INCOME APPLICABLE TO COMMON SHAREHOLDERS
  $ 1,832     $ 1,876     $ 1,178  
                         
BASIC NET INCOME PER SHARE
  $ 5.86     $ 6.75     $ 4.32  
DILUTED NET INCOME PER SHARE
  $ 5.74     $ 6.08     $ 3.93  
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)
    319.3       315.7       312.1  
 
 
 
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  
    2007     2006     2005  
    (Millions of dollars)  
 
CASH FLOWS FROM OPERATING ACTIVITIES
                       
Net income
  $ 1,832     $ 1,920     $ 1,226  
Adjustments to reconcile net income to net cash provided by operating activities
                       
Depreciation, depletion and amortization
    1,576       1,224       1,025  
Exploratory dry hole costs
    65       241       170  
Lease impairment
    102       99       78  
Pre-tax gain on asset sales
    (21 )     (369 )     (48 )
Provision (benefit) for deferred income taxes
    (33 )     281       (98 )
Distributed (undistributed) earnings of HOVENSA L.L.C., net
    124       199       (114 )
Changes in other operating assets and liabilities:
                       
Increase in accounts receivable
    (783 )     (179 )     (1,042 )
Increase in inventories
    (254 )     (152 )     (270 )
Increase (decrease) in accounts payable and accrued liabilities
    597       (44 )     877  
Increase (decrease) in taxes payable
    134       47       (111 )
Changes in other assets and liabilities
    168       224       147  
                         
Net cash provided by operating activities
    3,507       3,491       1,840  
                         
CASH FLOWS FROM INVESTING ACTIVITIES
                       
Capital expenditures
    (3,578 )     (3,844 )     (2,341 )
Proceeds from asset sales
    93       444       74  
Payments received on notes receivable
    61       76       60  
Other
    (50 )     35       (48 )
                         
Net cash used in investing activities
    (3,474 )     (3,289 )     (2,255 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES
                       
Debt with maturities of greater than 90 days
                       
Borrowings
    1,094       320       600  
Repayments
    (886 )     (333 )     (650 )
Cash dividends paid
    (127 )     (161 )     (159 )
Employee stock options exercised
    110       40       62  
                         
Net cash provided by (used in) financing activities
    191       (134 )     (147 )
                         
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    224       68       (562 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    383       315       877  
                         
CASH AND CASH EQUIVALENTS AT END OF YEAR
  $ 607     $ 383     $ 315  
                         
 
 
 
See accompanying notes to consolidated financial statements.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED STOCKHOLDERS’ EQUITY
 
                                                 
    2007     2006     2005  
    Shares     Amount     Shares     Amount     Shares     Amount  
    (Millions of dollars; thousands of shares)  
 
PREFERRED STOCK
                                               
Balance at January 1
    324     $       13,824     $ 14       13,827     $ 14  
Conversion of preferred stock to common stock
    (40 )           (13,500 )     (14 )     (3 )      
                                                 
Balance at December 31
    284             324             13,824       14  
                                                 
COMMON STOCK
                                               
Balance at January 1
    315,018       315       279,197       279       275,145       275  
Activity related to restricted common stock awards, net
    941       1       903       1       948       1  
Employee stock options exercised
    4,566       5       1,283       1       3,098       3  
Conversion of preferred stock to common stock
    75             33,635       34       6        
                                                 
Balance at December 31
    320,600       321       315,018       315       279,197       279  
                                                 
CAPITAL IN EXCESS OF PAR VALUE
                                               
Balance at January 1
            1,689               1,656               1,544  
Activity related to restricted common stock awards, net
            50               36               37  
Employee stock options exercised, including income tax benefits
            143               68               75  
Conversion of preferred stock to common stock
                          (20 )              
Reclassification resulting from adoption of FAS 123R
                          (51 )              
                                                 
Balance at December 31
            1,882               1,689               1,656  
                                                 
RETAINED EARNINGS
                                               
Balance at January 1
            7,707               5,946               4,879  
Net income
            1,832               1,920               1,226  
Dividends declared on common stock
            (127 )             (115 )             (111 )
Dividends on preferred stock
                          (44 )             (48 )
                                                 
Balance at December 31
            9,412               7,707               5,946  
                                                 
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
                                               
Balance at January 1
            (1,564 )             (1,526 )             (1,024 )
Net other comprehensive income (loss)
            (277 )             104               (502 )
Cumulative effect of adoption of FAS 158
                          (142 )              
                                                 
Balance at December 31
            (1,841 )             (1,564 )             (1,526 )
                                                 
DEFERRED COMPENSATION
                                               
Balance at January 1
                          (51 )             (43 )
Change in unearned compensation
                                        (8 )
Reclassification resulting from adoption of FAS 123R
                          51                
                                                 
Balance at December 31
                                        (51 )
                                                 
TOTAL STOCKHOLDERS’ EQUITY at December 31
          $ 9,774             $ 8,147             $ 6,318  
                                                 
 
 
 
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  
    2007     2006     2005  
    (Millions of dollars)  
 
COMPONENTS OF COMPREHENSIVE INCOME
                       
Net income
  $ 1,832     $ 1,920     $ 1,226  
                         
Other comprehensive income (loss):
                       
Deferred gains (losses) on cash flow hedges, after tax:
                       
Effect of hedge losses recognized in income
    325       345       946  
Net change in fair value of cash flow hedges
    (659 )     (379 )     (1,381 )
Change in minimum postretirement plan liabilities, after tax
    17       90       (33 )
Change in foreign currency translation adjustment and other
    40       48       (34 )
                         
Net other comprehensive income (loss)
    (277 )     104       (502 )
                         
COMPREHENSIVE INCOME
  $ 1,555     $ 2,024     $ 724  
                         
 
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:  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 principally in Algeria, Australia, Azerbaijan, Brazil, Denmark, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Libya, Malaysia, Norway, Russia, Thailand, the United Kingdom and the United States. 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 in conformity with U.S. generally accepted accounting principles (GAAP), 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 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 revenues 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 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


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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:  Inventories are valued at the lower of cost or market. For refined product inventories valued at cost, the Corporation uses principally the last-in, first-out (LIFO) inventory method. For the remaining inventories, cost is generally determined using average actual costs.
 
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 has material legal obligations to remove and dismantle long lived assets and to restore land or seabed at certain exploration and production locations. 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 obligations are incurred. In addition, the fair value of any legally required conditional


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 generally 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 is not 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 operating 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, including costs of refinery turnarounds. Capital improvements are recorded as additions in property, plant and equipment.
 
Effective January 1, 2007, the Corporation adopted Financial Accounting Standards Board (FASB) Staff Position (FSP) AUG AIR-1, Accounting for Planned Major Maintenance Activities. This FSP eliminated the previously acceptable accrue-in-advance method of accounting for planned major maintenance. As required, the Corporation retrospectively applied the provisions of this FSP which resulted in a change of its method of accounting to recognize expenses associated with refinery turnarounds when such costs are incurred. The impact of adopting this FSP increased previously reported 2006 earnings by $4 million ($.01 per diluted share). In addition, previously reported 2005 net income decreased by $16 million ($.05 per diluted share) and retained earnings as of January 1, 2005 increased by approximately $48 million. All prior period amounts in the consolidated financial statements and accompanying notes reflect this retrospective accounting change.
 
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 adverse impacts to the environment.
 
Share-Based Compensation:  All share-based compensation is expensed and recognized on a straight-line basis over the vesting period of the awards. Prior to the adoption of FAS No. 123R, Share-Based Payment, on January 1, 2006, the Corporation recorded compensation expense for restricted common stock awards and used the intrinsic value method to account for employee stock options. The Corporation used the modified prospective application method for its adoption of FAS No. 123R, which requires that compensation cost be recorded for


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.
 
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 adopted the provisions of FASB Interpretation No. 48 (FIN-48) on January 1, 2007. The impact of adoption was not material to the Corporation’s financial position, results of operations or cash flows. A deferred tax asset of $28 million related to an acquired net operating loss carryforward was recorded in accordance with FIN 48 and goodwill was reduced. In addition, effective with its adoption of FIN-48, the Corporation recognizes the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. 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. The Corporation classifies interest and penalties associated with uncertain tax positions as income tax expense.
 
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 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 titled accumulated other comprehensive income (loss).
 
Recently Issued Accounting Standard:  In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS No. 157). FAS No. 157 establishes a framework for measuring fair value and requires disclosure of a fair value hierarchy, which applies to financial assets and liabilities measured at fair value under other authoritative accounting pronouncements. The standard also requires additional disclosure about the methods of determining fair value. The Corporation as required, will prospectively adopt the provisions of FAS No. 157 effective January 1, 2008. The Corporation believes that the impact of adopting FAS No. 157 on net income will not be material. In addition, the Corporation expects to record a reduction in the charge reflected in accumulated other comprehensive income relating to the Corporation’s crude oil hedging program of approximately $160 million, after income taxes.
 
2.   Acquisitions and Divestitures
 
2007:  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, of which $342 million was allocated to proved and unproved properties and the remainder to wells and equipment. The Genghis Khan development is part of the same geologic structure as the Shenzi development. This transaction was accounted for as an acquisition of assets.
 
During the second quarter of 2007, the Corporation completed the sale of its interests in the Scott and Telford fields located in the United Kingdom for $93 million and recorded a gain of $21 million ($15 million after income taxes). At the time of sale, these two fields were producing at a combined net rate of 6,500 barrels of oil per day.
 
2006:  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.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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 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.
 
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.
 
3.   Inventories
 
Inventories at December 31 are as follows:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Crude oil and other charge stocks
  $ 338     $ 202  
Refined products and natural gas
    1,577       1,185  
Less: LIFO adjustment
    (1,029 )     (676 )
                 
      886       711  
Merchandise, materials and supplies
    364       294  
                 
Total
  $ 1,250     $ 1,005  
                 
 
 
The percentage of LIFO inventory to total crude oil, refined products and natural gas inventories was 69% and 66% at December 31, 2007 and 2006, respectively. During 2007 and 2005 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 $38 million in 2007 ($24 million after income taxes) and $51 million in 2005 ($32 million after income taxes).


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
4.   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:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Summarized Balance Sheet, at December 31
                       
Cash and cash equivalents
  $ 279     $ 290     $ 612  
Short-term investments
                263  
Other current assets
    1,183       943       814  
Net fixed assets
    2,181       2,123       1,950  
Other assets
    62       32       39  
Current liabilities
    (1,459 )     (1,013 )     (919 )
Long-term debt
    (356 )     (252 )     (252 )
Deferred liabilities and credits
    (75 )     (70 )     (44 )
                         
Partners’ equity
  $ 1,815     $ 2,053     $ 2,463  
                         
Summarized Income Statement, for the Years Ended December 31
                       
Total revenues
  $ 13,396     $ 11,788     $ 10,439  
Costs and expenses
    (13,039 )     (11,381 )     (9,694 )
                         
Net income
  $ 357     $ 407     $ 745  
                         
Hess Corporation’s share*
  $ 176     $ 201     $ 370  
                         
Summarized Cash Flow Statement, for the Years Ended December 31
                       
Net cash provided by (used in):
                       
Operating activities
  $ 654     $ 484     $ 1,070  
Investing activities
    (165 )     (10 )     (426 )
Financing activities
    (500 )     (796 )     (550 )
                         
Net increase (decrease) in cash and cash equivalents
  $ (11 )   $ (322 )   $ 94  
                         
 
 
* Before Virgin Islands income taxes, which were recorded in the Corporation’s income tax provision.
 
The Corporation received cash distributions from HOVENSA of $300 million, $400 million and $275 million during 2007, 2006 and 2005, respectively. The Corporation’s share of HOVENSA’s undistributed income aggregated $220 million at December 31, 2007.
 
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 $277 million at December 31, 2007. 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 in 1999, 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


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
over its term. The principal balance of the note, which is due to be fully repaid by February 2009, was $76 million and $137 million at December 31, 2007 and 2006, respectively.
 
5.   Property, Plant and Equipment
 
Property, plant and equipment at December 31 consists of the following:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Exploration and Production
               
Unproved properties
  $ 1,688     $ 1,231  
Proved properties
    3,350       3,298  
Wells, equipment and related facilities
    17,865       15,670  
                 
      22,903       20,199  
Marketing, Refining and Corporate
    1,928       1,781  
                 
Total — at cost
    24,831       21,980  
Less reserves for depreciation, depletion, amortization and lease impairment
    10,197       9,672  
                 
Property, plant and equipment — net
  $ 14,634     $ 12,308  
                 
 
 
In the fourth quarter of 2007 the Corporation recorded asset impairments at two mature fields in the United Kingdom North Sea. The pre-tax amount of this charge was $112 million ($56 million after income taxes) and is reflected in depreciation, depletion and amortization.
 
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:
 
                         
    2007     2006     2005  
    (Millions of dollars)  
 
Beginning balance at January 1
  $ 399     $ 244     $ 220  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    229       299       97  
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves
    (20 )     (144 )     (12 )
Capitalized exploratory well costs charged to expense
                (61 )
                         
Ending balance at December 31
  $ 608     $ 399     $ 244  
                         
Number of wells at end of year
    30       28       16  
                         
 
 
The preceding table excludes exploratory dry hole costs of $65 million, $241 million and $109 million in 2007, 2006 and 2005, respectively, which were incurred and subsequently expensed in the same year.
 
At December 31, 2007, expenditures related to exploratory drilling costs in excess of one year old were capitalized as follows (in millions):
 
         
2003
  $ 46  
2004
    8  
2005
    17  
2006
    233  
         
    $ 304  
         
 
 
The capitalized well costs in excess of one year relate to 11 projects. Approximately 70% of the costs relates to two projects in the deepwater Gulf of Mexico where appraisal wells were being drilled at December 31, 2007. The


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
remainder of the costs relate to projects where appraisal and development activities are ongoing or natural gas sales contracts are being actively pursued.
 
6.   Asset Retirement Obligations
 
The following table describes changes to the Corporation’s asset retirement obligations:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Asset retirement obligations at January 1
  $ 882     $ 564  
Liabilities incurred
    62       16  
Liabilities settled or disposed of
    (51 )     (60 )
Accretion expense
    50       44  
Revisions
    84       282  
Foreign currency translation
    28       36  
                 
Asset retirement obligations at December 31
    1,055       882  
Less: current obligations
    39       58  
                 
Long-term obligations at December 31
  $ 1,016     $ 824  
                 
 
 
Revisions are primarily attributable to higher service and equipment costs in the oil and gas industry.
 
7.   Long-Term Debt
 
Long-term debt at December 31 consists of the following:
 
                 
    2007     2006  
    (Millions of dollars)  
 
Revolving credit facility, weighted average rate 6.3%
  $ 220     $ 300  
Asset-backed credit facility, weighted average rate 5.6%
    250       318  
Short-term credit facilities, weighted average rate 5.5%
    350        
Fixed rate debentures:
               
7.4% due 2009
    103       103  
6.7% due 2011
    662       662  
7.9% due 2029
    694       693  
7.3% due 2031
    745       745  
7.1% due 2033
    598       598  
                 
Total fixed rate debentures
    2,802       2,801  
Fixed rate notes, payable principally to insurance companies, weighted average rate 9.1%, due through 2014
    126       145  
Project lease financing, weighted average rate 5.1%, due through 2014
    140       148  
Pollution control revenue bonds, weighted average rate 5.9%, due through 2034
    53       53  
Other loans, weighted average rate 7.7%, due through 2019
    39       7  
                 
      3,980       3,772  
Less: amount included in current maturities
    62       27  
                 
Total
  $ 3,918     $ 3,745  
                 
 
 
The aggregate long-term debt maturing during the next five years is as follows (in millions): 2008 — $62 (included in current liabilities); 2009 — $143; 2010 — $29; 2011 — $698 and 2012 — $845.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
At December 31, 2007, the Corporation’s fixed rate debentures have a principal amount of $2,816 million ($2,802 million net of unamortized discount). Interest rates on the outstanding fixed rate debentures have a weighted average rate of 7.3%.
 
The Corporation has a $3.0 billion syndicated revolving credit facility (the facility), which can be used for borrowings and letters of credit, substantially all of which is committed through May 2012. At December 31, 2007, the Corporation has available capacity on the facility of $2,780 million. Current borrowings under the facility bear interest at 0.525% above the London Interbank Offered Rate and a facility fee of 0.125% per annum is payable on the amount of the credit line. The interest rate and facility fee are subject to adjustment if the Corporation’s credit rating changes.
 
The Corporation has a 364-day asset-backed credit facility securitized by certain accounts receivable from its marketing operations, which are sold to a wholly-owned subsidiary. This asset-backed funding arrangement allows the Corporation to borrow up to $800 million subject to sufficient levels of eligible receivables. The credit line matures in October 2008. Borrowings under the asset-backed credit facility represent floating rate debt for which the weighted average interest rate was 5.6% for 2007. At December 31, 2007, total collateralized accounts receivable of $1,336 million are serviced by the Corporation and recorded on its balance sheet but are not available to pay the general obligations of the Corporation before repayment of outstanding borrowings under the asset-backed facility.
 
At December 31, 2007, the Corporation classified an aggregate of $600 million of borrowings under short-term credit facilities as long term debt, based on the available capacity under the $3.0 billion syndicated revolving credit facility. These borrowings consist of $300 million under a short-term committed facility, $250 million under the asset-backed credit facility and $50 million under uncommitted lines at December 31, 2007.
 
The Corporation’s long-term debt agreements contain a financial covenant that restricts the amount of total borrowings and secured debt. At December 31, 2007, the Corporation is permitted to borrow up to an additional $12.3 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $2.6 billion of secured debt at December 31, 2007.
 
The total amount of interest paid (net of amounts capitalized), principally on short-term and long-term debt, was $257 million, $200 million and $245 million in 2007, 2006 and 2005, respectively. The Corporation capitalized interest of $50 million, $100 million and $80 million in 2007, 2006 and 2005, respectively. In 2005, the Corporation recorded charges of $39 million ($26 million after income taxes) for premiums on bond repurchases, which are reflected in other income in the income statement.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
8.   Share-Based Compensation
 
The Corporation awards restricted common stock and stock options under its Amended and Restated 1995 Long-Term Incentive Plan. Generally, stock options vest in one to three years from the date of grant, have a 10-year option life, and the exercise price equals or exceeds the market price on the date of grant. Outstanding restricted common stock generally vests in three years from the date of grant.
 
Share-based compensation expense consists of the following:
 
                                 
    Before Taxes     After Taxes  
    2007     2006     2007     2006  
    (Millions of dollars)  
 
Stock options
  $ 36     $ 30     $ 23     $ 19  
Restricted stock
    51       38       31       23  
                                 
Total
  $ 87     $ 68     $ 54     $ 42  
                                 
 
 
Total pre-tax compensation expense for restricted common stock was $28 million in 2005. The following pro forma financial information for the year ended December 31, 2005 presents the effect on net income and earnings per share as if the Corporation commenced expensing of stock options on January 1, 2005 instead of on January 1, 2006 (millions of dollars, except per share data).
 
         
Net income
  $ 1,226  
Add: stock-based employee compensation expense included in net income, net of taxes
    18  
Less: total stock-based employee compensation expense determined using the fair value method, net of taxes
    (37 )
         
Pro forma net income
  $ 1,207  
         
Net income per share as reported
       
Basic
  $ 4.32  
Diluted
    3.93  
Pro forma net income per share
       
Basic
  $ 4.25  
Diluted
    3.87  
 
 
Based on restricted stock and stock option awards outstanding at December 31, 2007, unearned compensation expense, before income taxes, will be recognized in future years as follows (in millions): 2008 — $68, 2009 — $39 and 2010 — $5.


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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Corporation’s stock option and restricted stock activity consisted of the following:
 
                                 
    Stock Options     Restricted Stock  
          Weighted-
    Shares of
    Weighted-
 
          Average
    Restricted
    Average
 
          Exercise Price
    Common
    Price on Date
 
    Options     per Share     Stock     of Grant  
    (Thousands)           (Thousands)        
 
Outstanding at January 1, 2005
    11,361     $ 21.00       4,404     $ 19.52  
Granted
    3,282       30.91       1,121       30.79  
Exercised
    (3,099 )     19.96              
Vested
                (989 )     19.89  
Forfeited
    (93 )     24.85       (173 )     19.67  
                                 
Outstanding at December 31, 2005
    11,451       24.09       4,363       22.32  
Granted
    2,853       49.46       984       50.40  
Exercised
    (1,283 )     22.96              
Vested
                (237 )     22.78  
Forfeited
    (98 )     40.07       (66 )     30.24  
                                 
Outstanding at December 31, 2006
    12,923       29.68       5,044       27.68  
Granted
    3,066       53.82       1,032       53.92  
Exercised
    (4,566 )     24.07              
Vested
                (1,184 )     24.53  
Forfeited
    (131 )     46.41       (91 )     36.40  
                                 
Outstanding at December 31, 2007
    11,292       38.31       4,801       33.93  
                                 
Exercisable at December 31, 2005
    8,181     $ 21.36                  
Exercisable at December 31, 2006
    6,832       22.08                  
Exercisable at December 31, 2007
    5,408       27.34                  
 
 
The table below summarizes information regarding the outstanding and exercisable stock options as of December 31, 2007:
 
                                         
          Outstanding Options     Exercisable Options  
          Weighted-
                   
          Average
    Weighted-
          Weighted-
 
          Remaining
    Average
          Average
 
Range of
        Contractual
    Exercise Price
          Exercise Price
 
Exercise Prices
  Options     Life     per