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, 2008	
or	
o	 	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to           	
 
Commission File Number 1-1204

 
 
Hess Corporation
(Exact name of Registrant as specified in its charter)

DELAWARE	 	13-4921002	
(State or other jurisdiction of
incorporation or organization)	 	(I.R.S. Employer
Identification Number)	
1185 AVENUE OF THE AMERICAS,
NEW YORK, N.Y.
(Address of principal executive offices)	 	10036
(Zip Code)	
 
(Registrant’s telephone number, including area code, is (212) 997-8500)

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

Title of Each Class	 	Name of Each Exchange on Which Registered	
 	 	 	
Common Stock (par value $1.00)	 	New York Stock Exchange	
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  þ      No  o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes  o      No  þ
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ      No  o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 $36,438,000,000 computed using the outstanding common shares and closing market price on June 30, 2008.
 
At December 31, 2008, there were 326,132,740 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 6, 2009.

 
 
HESS CORPORATION

Form 10-K

TABLE OF CONTENTS

Item No.	 	 	 	Page	 	 	
 	 	 	 	 	 	 	 	 	
PART I	 	 	
1. and 2.	 	Business and Properties	 	 	2	 	 	 	
1A.	 	Risk Factors Related to Our Business and Operations	 	 	11	 	 	 	
3.	 	Legal Proceedings	 	 	12	 	 	 	
4.	 	Submission of Matters to a Vote of Security Holders	 	 	15	 	 	 	
 	 	Executive Officers of the Registrant	 	 	15	 	 	 	
 	 	 	
PART II	 	 	
5.	 	Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities	 	 	16	 	 	 	
6.	 	Selected Financial Data	 	 	18	 	 	 	
7.	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	19	 	 	 	
7A.	 	Quantitative and Qualitative Disclosures About Market Risk	 	 	38	 	 	 	
8.	 	Financial Statements and Supplementary Data	 	 	41	 	 	 	
9.	 	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	 	 	83	 	 	 	
9A.	 	Controls and Procedures	 	 	83	 	 	 	
9B.	 	Other Information	 	 	83	 	 	 	
 	 	 	
PART III	 	 	
10.	 	Directors, Executive Officers and Corporate Governance	 	 	83	 	 	 	
11.	 	Executive Compensation	 	 	83	 	 	 	
12.	 	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	 	83	 	 	 	
13.	 	Certain Relationships and Related Transactions, and Director Independence	 	 	84	 	 	 	
14.	 	Principal Accounting Fees and Services	 	 	84	 	 	 	
 	 	 	
PART IV	 	 	
15.	 	Exhibits, Financial Statement Schedules	 	 	84	 	 	 	
 	 	Signatures	 	 	87	 	 	 	
 EX-21: SUBSIDIARIES	
 EX-31.1: CERTIFICATION	
 EX-31.2: CERTIFICATION	
 EX-32.1: CERTIFICATION	
 EX-32.2: CERTIFICATION	

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PART I
 
Items 1 and 2.  Business and Properties
 
Hess Corporation (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, Peru, 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
	 	 	 	Total Barrels of
	
 	 	and
	 	 	 	Oil
	
 	 	Natural Gas
	 	 	 	Equivalent
	
 	 	Liquids	 	Natural Gas	 	(BOE)*	
 	 	2008	 	2007	 	2008	 	2007	 	2008	 	2007	
 	 	(Millions of barrels)	 	(Millions of mcf)	 	(Millions of barrels)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	227	 	 	 	204	 	 	 	276	 	 	 	270	 	 	 	273	 	 	 	249	 	
Europe	 	 	332	 	 	 	329	 	 	 	639	 	 	 	656	 	 	 	438	 	 	 	438	 	
Africa	 	 	324	 	 	 	285	 	 	 	69	 	 	 	87	 	 	 	336	 	 	 	300	 	
Asia and other	 	 	87	 	 	 	67	 	 	 	1,789	 	 	 	1,655	 	 	 	385	 	 	 	343	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	970	 	 	 	885	 	 	 	2,773	 	 	 	2,668	 	 	 	1,432	 	 	 	1,330	 	

 
 	 	 	
*	 	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, 43% of the Corporation’s worldwide proved reserves are undeveloped at December 31, 2008 (44% at December 31, 2007). Proved reserves held under production sharing contracts at December 31, 2008 totaled 28% of crude oil and natural gas liquids and 58% of natural gas reserves (25% and 57% respectively, at December 31, 2007).
 
Worldwide crude oil, natural gas liquids and natural gas production was as follows:

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude oil (thousands of barrels per day)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Onshore	 	 	17	 	 	 	15	 	 	 	15	 	
Offshore	 	 	15	 	 	 	16	 	 	 	21	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	32	 	 	 	31	 	 	 	36	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Europe	 	 	 	 	 	 	 	 	 	 	 	 	
United Kingdom	 	 	29	 	 	 	38	 	 	 	50	 	
Norway	 	 	16	 	 	 	19	 	 	 	22	 	
Denmark	 	 	11	 	 	 	12	 	 	 	19	 	
Russia	 	 	27	 	 	 	24	 	 	 	18	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	83	 	 	 	93	 	 	 	109	 	

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 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Africa	 	 	 	 	 	 	 	 	 	 	 	 	
Equatorial Guinea	 	 	72	 	 	 	56	 	 	 	28	 	
Algeria	 	 	15	 	 	 	22	 	 	 	22	 	
Gabon	 	 	14	 	 	 	14	 	 	 	12	 	
Libya	 	 	23	 	 	 	23	 	 	 	23	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	124	 	 	 	115	 	 	 	85	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Asia and other	 	 	 	 	 	 	 	 	 	 	 	 	
Azerbaijan	 	 	7	 	 	 	16	 	 	 	7	 	
Other	 	 	6	 	 	 	5	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	13	 	 	 	21	 	 	 	12	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	252	 	 	 	260	 	 	 	242	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas liquids (thousands of barrels per day)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Onshore	 	 	7	 	 	 	7	 	 	 	7	 	
Offshore	 	 	3	 	 	 	3	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	10	 	 	 	10	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Europe	 	 	 	 	 	 	 	 	 	 	 	 	
United Kingdom	 	 	3	 	 	 	4	 	 	 	4	 	
Norway	 	 	1	 	 	 	1	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	4	 	 	 	5	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	14	 	 	 	15	 	 	 	15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas (thousands of mcf per day)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	 	 	 	 	 	 	 	 	 	 	
Onshore	 	 	41	 	 	 	42	 	 	 	54	 	
Offshore	 	 	37	 	 	 	46	 	 	 	56	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	78	 	 	 	88	 	 	 	110	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Europe	 	 	 	 	 	 	 	 	 	 	 	 	
United Kingdom	 	 	223	 	 	 	231	 	 	 	244	 	
Norway	 	 	22	 	 	 	18	 	 	 	22	 	
Denmark	 	 	10	 	 	 	10	 	 	 	17	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	255	 	 	 	259	 	 	 	283	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Asia and other	 	 	 	 	 	 	 	 	 	 	 	 	
Joint Development Area of Malaysia and Thailand (JDA)	 	 	185	 	 	 	115	 	 	 	131	 	
Thailand	 	 	87	 	 	 	90	 	 	 	60	 	
Indonesia	 	 	82	 	 	 	59	 	 	 	26	 	
Other	 	 	2	 	 	 	2	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	356	 	 	 	266	 	 	 	219	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	689	 	 	 	613	 	 	 	612	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Barrels of oil equivalent*	 	 	381	 	 	 	377	 	 	 	359	 	

 
 	 	 	
*	 	Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel).	
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The Corporation presently estimates that its 2009 production will be approximately 380,000 to 390,000 barrels of oil equivalent per day (boepd).
 
A description of our significant E&P operations follows:
 
United States
 
At December 31, 2008, 19% of the Corporation’s total proved reserves were located in the United States. During 2008, 16% of the Corporation’s crude oil and natural gas liquids production and 11% 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 38%), Baldpate (Hess 50%), Hack Wilson (Hess 25%) and Penn State (Hess 50%) fields, as well as onshore properties in North Dakota and in the Permian Basin of Texas.
 
In the deepwater Gulf of Mexico, development of the Shenzi Field (Hess 28%) progressed in 2008. Tension leg platform tendons, hull and topsides were installed and flowlines were laid and tested. First production is expected in the second quarter of 2009.
 
In the Williston Basin of North Dakota, the Corporation holds a net acreage position in the Bakken Play of approximately 570,000 acres. In 2009, the Corporation plans to drill additional production wells and expand production facilities.
 
The Corporation is developing a residual oil zone at the Seminole-San Andres Unit (Hess 34%) in Texas where carbon dioxide gas supplied from its interests in the West Bravo Dome and Bravo Dome fields in New Mexico will be injected to enhance recovery of crude oil.
 
In the Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico, the Corporation successfully completed drilling an appraisal well in June 2008. The Corporation is evaluating development options for Pony.
 
At the Corporation’s Tubular Bells prospect (Hess 20%) located in the Mississippi Canyon area of the deepwater Gulf of Mexico, a third well was successfully drilled during 2008. The operator is evaluating development options for Tubular Bells.
 
At December 31, 2008, the Corporation had interests in more than 400 exploration blocks in the Gulf of Mexico, which included 1,442,020 net undeveloped acres.
 
Europe
 
At December 31, 2008, 31% of the Corporation’s total proved reserves were located in Europe (United Kingdom 9%, Norway 13%, Denmark 3% and Russia 6%). During 2008, 33% of the Corporation’s crude oil and natural gas liquids production and 37% 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 Nevis (Hess 39%), Schiehallion (Hess 16%), Clair (Hess 9%), Bittern (Hess 28%) and Beryl (Hess 22%) fields. Natural gas production from the United Kingdom was primarily from the Atlantic (Hess 25%) and Cromarty (Hess 90%), Easington Catchment Area (Hess 32%), Bacton area (Hess 23%), Beryl (Hess 22%), Everest (Hess 19%), Lomond (Hess 17%) and Nevis (Hess 39%) fields.
 
Norway:  Substantially all of the 2008 and 2007 Norwegian production was from the Corporation’s interest in the Valhall Field (Hess 28%). A field redevelopment for Valhall commenced in 2008 and is expected to be completed in 2010. The Corporation also holds an interest in the Snohvit Field (Hess 3%) located offshore Norway.
 
Denmark:  Crude oil and natural gas production comes from the Corporation’s interest in the South Arne Field (Hess 58%).
 
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, 2008, 23% of the Corporation’s total proved reserves were located in Africa (Equatorial Guinea 8%, Algeria 4%, Libya 10% and Gabon 1%). During 2008, 46% 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%). The Corporation also owns a 100% interest in offshore exploration Area 54, where a successful exploration well was drilled in 2008. The Corporation intends to obtain 3D seismic in Area 54 and further drilling is planned.
 
Gabon:  The Corporation’s activities in Gabon are conducted through its Gabonese subsidiary, where the Corporation has interests in the Rabi Kounga, Toucan and Atora fields. In the third quarter of 2008, the Corporation acquired the remaining 22.5% interest in the Gabonese subsidiary.
 
Egypt:  The Corporation has a 25-year development lease for the West Mediterranean Block 1 concession (West Med Block) (Hess 55%), which contains four existing natural gas discoveries and additional exploration opportunities. During 2008, the Corporation drilled a successful exploration well on the block, which encountered natural gas and crude oil. The Corporation is currently conducting engineering studies and further exploratory drilling is planned.
 
Ghana:  The Corporation holds a 100% interest in the Cape Three Points South Block located offshore Ghana. The Corporation is currently acquiring new 3D seismic in the unexplored western half of the license area.
 
Asia and Other
 
At December 31, 2008, 27% of the Corporation’s total proved reserves were located in the Asia and other region (JDA 13%, Indonesia 9%, Thailand 3% and Azerbaijan 2%). During 2008, 5% of the Corporation’s crude oil and natural gas liquids production and 52% of its natural gas production were from Asia and other operations.
 
Joint Development Area of Malaysia and Thailand:  The Corporation owns an interest in Block A-18 of the JDA (Hess 50%) in the Gulf of Thailand. Phase 2 gas sales commenced in November of 2008 upon commissioning of a third-party gas export pipeline to Thailand.
 
Indonesia:  The Corporation’s natural gas production in Indonesia primarily comes from its interests offshore in the Ujung Pangkah project (Hess 75%), which commenced in 2007, and the Natuna A Field (Hess 23%). Additional production from a Phase 2 oil project at Ujung Pangkah is expected in mid 2009. The Corporation also owns an interest in the onshore Jambi Merang natural gas project (Hess 25%), which was sanctioned for development in 2007. In the fourth quarter of 2008, the Corporation acquired a 100% working interest in the offshore Semai V exploration block.
 
Thailand:  The Corporation’s natural gas production in Thailand primarily comes from the offshore Pailin Field (Hess 15%) and the onshore Sinphuhorm Block (Hess 35%).
 
Azerbaijan:  The Corporation has an interest in the Azeri-Chirag-Gunashli (ACG) fields (Hess 3%) in the Caspian Sea. The Corporation also holds an interest in the Baku-Tbilisi-Ceyhan (BTC) Pipeline (Hess 2%).
 
Australia:  The Corporation holds a 100% interest in an exploration license covering 780,000 acres in the Carnarvon basin offshore Western Australia (WA-Block 390-P). During 2008, the Corporation completed drilling its initial four exploration wells of a 16 well commitment on the block. Three of the four wells discovered natural gas and the Corporation plans to drill five additional exploration wells in 2009. The Corporation also holds a 50% interest in WA-Block 404-P located offshore Western Australia, which covers a total area of 680,000 acres. The operator plans to drill three wells on this block in 2009.
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Brazil:  The Corporation has interests in two blocks located offshore Brazil, the BM-S-22 Block (Hess 40%) in the Santos Basin and the BM-ES-30 Block (Hess 60%) in the Espirito Santo Basin. The operator commenced drilling of the Azulao exploration well on BM-S-22 in 2008 and filed a Notice of Discovery with the regulators on January 16, 2009. The operator plans to drill another well on BM-S-22 in 2009.
 
Oil and Gas Reserves
 
The Corporation’s net proved oil and gas reserves at the end of 2008, 2007 and 2006 are presented under Supplementary Oil and Gas Data on pages 75 through 81 in the accompanying financial statements.
 
During 2008, the Corporation provided oil and gas reserve estimates for 2007 to the United States Department of Energy. Such estimates are consistent with the information furnished to the SEC on Form 10-K for the year ended December 31, 2007, 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 by the M&R segment on a spot basis and under contracts for varying periods to local distribution companies, and commercial, industrial and other purchasers. The Corporation’s United States natural gas production is expected to approximate 20% of its 2009 sales commitments under long-term contracts. The Corporation attempts to minimize 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.
 
Outside of the United States, the Corporation generally sells its natural gas production under long-term sales contracts at prices that are periodically adjusted due to changes in commodity prices or other indices. In the United Kingdom, the Corporation sells the majority of its natural gas production on a spot basis.
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Average selling prices and average production costs

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Average selling prices*	 	 	 	 	 	 	 	 	 	 	 	 	
Crude oil (per barrel)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	96.82	 	 	$	69.23	 	 	$	60.45	 	
Europe	 	 	78.75	 	 	 	60.99	 	 	 	56.19	 	
Africa	 	 	78.72	 	 	 	62.04	 	 	 	51.18	 	
Asia and other	 	 	97.07	 	 	 	72.17	 	 	 	61.52	 	
Worldwide	 	 	82.04	 	 	 	63.44	 	 	 	55.31	 	
Natural gas liquids (per barrel)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	64.98	 	 	$	51.89	 	 	$	46.22	 	
Europe	 	 	74.63	 	 	 	57.20	 	 	 	47.30	 	
Worldwide	 	 	67.61	 	 	 	53.72	 	 	 	46.59	 	
Natural gas (per mcf)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	8.61	 	 	$	6.67	 	 	$	6.59	 	
Europe	 	 	9.44	 	 	 	6.13	 	 	 	6.20	 	
Asia and other	 	 	5.24	 	 	 	4.71	 	 	 	4.05	 	
Worldwide	 	 	7.17	 	 	 	5.60	 	 	 	5.50	 	
Average production (lifting) costs per barrel of oil equivalent produced**	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	18.46	 	 	$	13.56	 	 	$	9.54	 	
Europe	 	 	17.12	 	 	 	14.06	 	 	 	10.73	 	
Africa	 	 	10.22	 	 	 	9.09	 	 	 	9.03	 	
Asia and other	 	 	8.48	 	 	 	8.41	 	 	 	6.54	 	
Worldwide	 	 	13.43	 	 	 	11.50	 	 	 	9.55	 	

 	 	 	
* 	 	Includes inter-company transfers valued at approximate market prices and the effect of the Corporation’s hedging activities.	
 	 	 	
**	 	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. 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.
 
Gross and net undeveloped acreage at December 31, 2008

 	 	Undeveloped
	
 	 	Acreage*	
 	 	Gross	 	Net	
 	 	(In thousands)	
 	 	 	 	 	 	 	 	 	
United States	 	 	2,919	 	 	 	1,971	 	
Europe	 	 	2,099	 	 	 	673	 	
Africa	 	 	9,979	 	 	 	6,464	 	
Asia and other	 	 	8,849	 	 	 	4,323	 	
 	 	 	 	 	 	 	 	 	
Total**	 	 	23,846	 	 	 	13,431	 	

 
 	 	 	
*	 	Includes acreage held under production sharing contracts.	
 	 	 	
**	 	Licenses covering approximately 33% of the Corporation’s net undeveloped acreage held at December 31, 2008 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), U.S. and Egypt.	

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Gross and net developed acreage and productive wells at December 31, 2008

 	 	Developed
	 	 	 	 	
 	 	Acreage
	 	 	 	 	
 	 	Applicable to
	 	Productive Wells*	
 	 	Productive Wells	 	Oil	 	Gas	
 	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	
 	 	(In thousands)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	529	 	 	 	455	 	 	 	774	 	 	 	431	 	 	 	59	 	 	 	45	 	
Europe	 	 	1,362	 	 	 	758	 	 	 	269	 	 	 	105	 	 	 	145	 	 	 	32	 	
Africa	 	 	9,919	 	 	 	958	 	 	 	987	 	 	 	154	 	 	 	—	 	 	 	—	 	
Asia and other	 	 	2,185	 	 	 	624	 	 	 	64	 	 	 	7	 	 	 	385	 	 	 	85	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	13,995	 	 	 	2,795	 	 	 	2,094	 	 	 	697	 	 	 	589	 	 	 	162	 	

 
 	 	 	
*	 	Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 312 gross wells and 54 net wells.	
 
Number of net exploratory and development wells drilled

 	 	Net Exploratory
	 	Net Development
	
 	 	Wells	 	Wells	
 	 	2008	 	2007	 	2006	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Productive wells	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	2	 	 	 	1	 	 	 	1	 	 	 	50	 	 	 	54	 	 	 	24	 	
Europe	 	 	11	 	 	 	3	 	 	 	1	 	 	 	11	 	 	 	14	 	 	 	20	 	
Africa	 	 	1	 	 	 	1	 	 	 	—	 	 	 	23	 	 	 	23	 	 	 	17	 	
Asia and other	 	 	5	 	 	 	3	 	 	 	6	 	 	 	25	 	 	 	15	 	 	 	11	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	19	 	 	 	8	 	 	 	8	 	 	 	109	 	 	 	106	 	 	 	72	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Dry holes	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	—	 	 	 	1	 	 	 	4	 	 	 	1	 	 	 	—	 	 	 	—	 	
Europe	 	 	3	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Africa	 	 	2	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Asia and other	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	6	 	 	 	3	 	 	 	4	 	 	 	1	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	25	 	 	 	11	 	 	 	12	 	 	 	110	 	 	 	106	 	 	 	72	 	

 
Number of wells in process of drilling at December 31, 2008

 	 	Gross
	 	Net
	
 	 	Wells	 	Wells	
 	 	 	 	 	 	 	 	 	
United States	 	 	37	 	 	 	13	 	
Europe	 	 	12	 	 	 	7	 	
Africa	 	 	8	 	 	 	2	 	
Asia and other	 	 	7	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	
Total	 	 	64	 	 	 	24	 	

 
Number of net waterfloods and pressure maintenance projects in process of installation at December 31, 2008 — 1
 
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Marketing and Refining
 
Total refined product sales were as follows:

 	 	2008*	 	2007*	 	2006*	
 	 	(Thousands of barrels per day)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Gasoline	 	 	234	 	 	 	210	 	 	 	218	 	
Distillates	 	 	143	 	 	 	147	 	 	 	144	 	
Residuals	 	 	56	 	 	 	62	 	 	 	60	 	
Other	 	 	39	 	 	 	32	 	 	 	37	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	472	 	 	 	451	 	 	 	459	 	

 
 	 	 	
*	 	Of total refined products sold in 2008, 2007 and 2006 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	 	2008	 	2007	 	2006	
 	 	(Thousands of
	 	 	 	 	 	 	
 	 	barrels per day)	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude	 	 	500	 	 	 	88.2%	 	 	 	90.8%	 	 	 	89.7%	 	
Fluid catalytic cracker	 	 	150	 	 	 	72.7%	 	 	 	87.1%	 	 	 	84.3%	 	
Coker	 	 	58	 	 	 	92.4%	 	 	 	83.4%	 	 	 	84.3%	 	

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.
 
Gross crude runs at HOVENSA averaged 441,000 barrels per day in 2008 compared with 454,000 barrels per day in 2007 and 448,000 barrels per day in 2006. The 2008 utilization rate for the fluid catalytic cracking unit at HOVENSA reflects lower utilization due to weak refining margins, planned and unplanned maintenance of certain units, and a refinery wide shut down for Hurricane Omar. 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 unplanned 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 70,000 barrels per day. This facility, which processes residual fuel oil and vacuum gas oil, operated at a rate of approximately 64,000 barrels per day in 2008 compared with 61,000 barrels per day in 2007 and 63,000 barrels per day in 2006. Substantially all of Port Reading’s production is gasoline and heating oil.
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Marketing
 
The Corporation markets refined petroleum products, natural gas and electricity 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.
 
The Corporation had 1,366 HESS® gasoline stations at December 31, 2008, including stations owned by its WilcoHess joint venture (Hess 44%). Approximately 90% of the gasoline stations are operated by the Corporation 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 472,000 barrels per day in 2008 compared with 451,000 barrels per day in 2007 and 459,000 barrels in 2006. Total energy marketing natural gas sales volumes, including utility and spot sales, were approximately 2.0 million mcf per day in 2008, 1.9 million mcf per day in 2007 and 1.8 million mcf per day in 2006. In addition, energy marketing sold electricity volumes at the rate of 3,200, 2,800 and 1,400 megawatts (round the clock) in 2008, 2007 and 2006, respectively. The increases reflect the impact of acquisitions and organic growth.
 
The Corporation owns 21 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 operated 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. In addition, a wholly-owned subsidiary of the Corporation is exploring the development of fuel cell technology.
 
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 financial condition or results of operations. The Corporation spent $23 million in 2008 for environmental remediation.
 
The number of persons employed by the Corporation at year end was approximately 13,500 in 2008 and 13,300 in 2007.
 
The Corporation’s Internet address is www.hess.com. On its website, the Corporation makes available free of charge its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after the Corporation electronically files with or furnishes such material to the Securities and Exchange Commission. Copies of the Corporation’s Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the charters of the Audit Committee, the Compensation and Management Development Committee and the Corporate Governance and Nominating Committee of the Board of Directors are available on the Corporation’s website and are also available free of charge upon request to the Secretary of the Corporation at its principal executive offices. The Corporation has also filed with the New York Stock Exchange (NYSE) its annual certification that the Corporation’s chief executive officer is unaware of any violation of the NYSE’s corporate governance standards.
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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 and most recently have been adversely affected by falling demand caused by the global economic downturn. 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. If crude oil and natural gas prices remain at year-end 2008 levels, our revenues, profitability and cash flow will be lower in 2009 compared with 2008. In addition, if crude oil and natural gas prices decline further from year-end 2008 levels, it could result in a reduction in the carrying value of our oil and gas assets, proved oil and gas reserves, deferred tax assets and goodwill. To the extent that we engage in hedging activities to mitigate commodity price volatility, we may not realize the benefit of price increases above the hedged price. Changes in commodity prices can also have a material impact on margin requirements under our derivative contracts.
 
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. Reserve replacement can also be achieved through acquisition. 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 unexpected adverse 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 increased in recent years 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 or nationalization of property, mandatory government participation, cancellation or amendment of contract rights, and changes in import regulations, limitations on access to exploration and development opportunities, as well as other political developments may affect our operations. Some of the international areas in which we operate are politically less stable than our domestic operations. In addition, the threat of terrorism around the world poses additional risks to the operations of the oil and gas industry. In our M&R segment, we market motor fuels through lessee-dealers and wholesalers in certain states where legislation prohibits producers or refiners of crude oil from directly engaging in retail marketing of motor fuels. Similar legislation has been periodically proposed in the U.S. Congress and in various other states.
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Environmental Risk:  Our oil and gas operations, like those of the industry, are subject to environmental risk 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 2008, our annual Gulf of Mexico production of crude oil and natural gas was reduced by an estimated 7,000 boepd due to the impact of Hurricanes Ike and Gustav.

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 similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including the Registrant. While the majority of the cases were settled in 2008, the Registrant remains a defendant in approximately 20 cases. These cases have been consolidated for pre-trial purposes in the Southern District of New York as part of a multi-district litigation proceeding, with the exception of an action brought in state court by the State of New Hampshire. 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 almost all cases, punitive damages are also sought. In the fourth quarter 2007, the Corporation recorded a pre-tax charge of $40 million related to MTBE litigation, including amounts for the cases settled in 2008.
 
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 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 regarding the Petroleum Refinery Initiative in August 2003. Negotiations with EPA and the relevant states and the Virgin Islands are continuing and substantial progress has been made toward resolving this matter for both the Corporation and HOVENSA. While
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the effect on the Corporation of the Petroleum Refining Initiative cannot be estimated until a final settlement is reached and entered by a court, additional future capital expenditures and operating expenses will likely be incurred over a number of years. The amount of penalties, if any, is not expected to be material to the Corporation.
 
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 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. HOVENSA has entered 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 has entered into discussions with the appropriate governmental agencies to reach resolution of this matter and does not believe that it will result in material liability to HOVENSA or the Corporation.
 
Registrant 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 70 companies entered into an Administrative Order on Consent with EPA to study the same contamination. NJDEP has also sued several other companies linked to a facility considered by the State to be the largest contributor to river contamination. In January 2009, these companies added third party defendants, including the Registrant, to that case. 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.
 
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
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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) 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 SEC has requested documents and information from the Registrant and other oil and gas companies that have operations or interests in Equatorial Guinea. Registrant has provided the documents and information requested.
 
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 SEC. 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 2008, 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, 2009 regarding executive officers of the Registrant:

 	 	 	 	 	 	Year Individual
	
 	 	 	 	 	 	Became an
	
 	 	 	 	 	 	Executive
	
Name	 	Age	 	Office Held*	 	Officer	
 	 	 	 	 	 	 	 	 	 	 	
John B. Hess	 	 	54	 	 	Chairman of the Board, Chief Executive Officer and Director	 	 	1983	 	
J. Barclay Collins II	 	 	64	 	 	Executive Vice President and Director	 	 	1986	 	
Gregory P. Hill	 	 	47	 	 	Executive Vice President and President of Worldwide Exploration and Production	 	 	2009	 	
John J. O’Connor	 	 	62	 	 	Executive Vice President and Director	 	 	2001	 	
F. Borden Walker	 	 	55	 	 	Executive Vice President and President of Marketing and Refining and Director	 	 	1996	 	
Brian J. Bohling	 	 	48	 	 	Senior Vice President	 	 	2004	 	
William T. Drennen	 	 	58	 	 	Senior Vice President	 	 	2007	 	
John A. Gartman	 	 	61	 	 	Senior Vice President	 	 	1997	 	
Timothy B. Goodell	 	 	51	 	 	Senior Vice President and General Counsel	 	 	2009	 	
Scott Heck	 	 	51	 	 	Senior Vice President	 	 	2005	 	
Lawrence H. Ornstein	 	 	57	 	 	Senior Vice President	 	 	1995	 	
Howard Paver	 	 	58	 	 	Senior Vice President	 	 	2002	 	
John P. Rielly	 	 	46	 	 	Senior Vice President and Chief Financial Officer	 	 	2002	 	
Lori J. Ryerkerk	 	 	46	 	 	Senior Vice President	 	 	2008	 	
George F. Sandison	 	 	52	 	 	Senior Vice President	 	 	2003	 	
John J. Scelfo	 	 	51	 	 	Senior Vice President	 	 	2004	 	
Gordon Shearer	 	 	54	 	 	Senior Vice President	 	 	2007	 	
John V. Simon	 	 	55	 	 	Senior Vice President	 	 	2007	 	
Sachin Mehra	 	 	38	 	 	Vice President and Treasurer	 	 	2008	 	

 	 	 	
*	 	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 opposite his or her name on May 7, 2008, except for Messrs. Hill and Goodell and Ms. Ryerkerk, who were elected effective January 1, 2009, January 5, 2009 and November 5, 2008, respectively. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 6, 2009.	
 
Except for Messrs. Hill, Bohling, Drennen, Goodell, Mehra, Shearer and Ms. Ryerkerk, 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. Prior to joining the Corporation, Mr. Hill served in senior executive positions in exploration and production operations of Royal Dutch Shell and its subsidiaries for 25 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 Corporation in 2007. Before joining the Corporation in 2009, Mr. Goodell
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was a partner in the law firm of White & Case LLP. Ms. Ryerkerk was employed in senior managerial positions principally in the refining and marketing operations of ExxonMobil prior to joining the Corporation in 2008. Mr. Mehra was employed in treasury and financial functions at General Motors before joining the Corporation in 2007. Prior to joining Hess LNG, a joint venture subsidiary of the Corporation, in 2004, Mr. Shearer was a consultant at Poten Partners, and held other senior positions in the liquefied natural gas industry.
 
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:

 	 	2008	 	2007	
Quarter Ended	 	High	 	Low	 	High	 	Low	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
March 31	 	$	101.65	 	 	$	76.67	 	 	$	58.00	 	 	$	45.96	 	
June 30	 	 	137.00	 	 	 	88.20	 	 	 	61.48	 	 	 	54.55	 	
September 30	 	 	129.00	 	 	 	71.16	 	 	 	69.87	 	 	 	53.12	 	
December 31	 	 	82.03	 	 	 	35.50	 	 	 	105.85	 	 	 	63.58	 	

Performance Graph
 
Set forth below is a line graph comparing the Corporation’s cumulative total shareholder return for five years, assuming reinvestment of dividends on common stock, with the cumulative total return 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.	
Comparison of Five-Year Shareholder Returns
Years Ended December 31,

 
Holders
 
At December 31, 2008, there were 5,909 stockholders (based on number of holders of record) who owned a total of 326,132,740 shares of common stock.
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Dividends
 
Cash dividends on common stock totaled $.40 per share ($.10 per quarter) during 2008 and 2007.
 
Equity Compensation Plans
 
Following is information on the Registrant’s equity compensation plans at December 31, 2008:

 	 	 	 	 	 	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	 	 	9,700,000	 	 	$	52.73	 	 	 	12,804,000	*	
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 Corporation 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:

 	 	2008	 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	
 	 	(Millions of dollars, except per share amounts)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Sales and other operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude oil and natural gas liquids	 	$	7,764	 	 	$	6,303	 	 	$	5,307	 	 	$	3,219	 	 	$	2,594	 	
Natural gas (including sales of purchased gas)	 	 	8,800	 	 	 	6,877	 	 	 	6,826	 	 	 	6,423	 	 	 	4,638	 	
Refined petroleum products	 	 	19,765	 	 	 	14,741	 	 	 	13,339	 	 	 	11,317	 	 	 	7,907	 	
Electricity	 	 	2,926	 	 	 	2,322	 	 	 	1,064	 	 	 	363	 	 	 	207	 	
Convenience store sales and other operating revenues	 	 	1,910	 	 	 	1,404	 	 	 	1,531	 	 	 	1,425	 	 	 	1,387	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	41,165	 	 	$	31,647	 	 	$	28,067	 	 	$	22,747	 	 	$	16,733	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	2,360	(a)	 	$	1,832	(b)	 	$	1,920	(c)	 	$	1,226	(d)	 	$	970	(e)	
Discontinued operations	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	2,360	 	 	$	1,832	 	 	$	1,920	 	 	$	1,226	 	 	$	977	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Less preferred stock dividends	 	 	—	 	 	 	—	 	 	 	44	 	 	 	48	 	 	 	48	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income applicable to common shareholders	 	$	2,360	 	 	$	1,832	 	 	$	1,876	 	 	$	1,178	 	 	$	929	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings per share*	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing operations	 	$	7.35	 	 	$	5.86	 	 	$	6.75	 	 	$	4.32	 	 	$	3.43	 	
Net income	 	 	7.35	 	 	 	5.86	 	 	 	6.75	 	 	 	4.32	 	 	 	3.46	 	
Diluted earnings per share*	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing operations	 	$	7.24	 	 	$	5.74	 	 	$	6.08	 	 	$	3.93	 	 	$	3.17	 	
Net income	 	 	7.24	 	 	 	5.74	 	 	 	6.08	 	 	 	3.93	 	 	 	3.19	 	
Total assets	 	$	28,589	 	 	$	26,131	 	 	$	22,442	 	 	$	19,158	 	 	$	16,312	 	
Total debt	 	 	3,955	 	 	 	3,980	 	 	 	3,772	 	 	 	3,785	 	 	 	3,835	 	
Stockholders’ equity	 	 	12,307	 	 	 	9,774	 	 	 	8,147	 	 	 	6,318	 	 	 	5,597	 	
Dividends per share of common stock*	 	$	.40	 	 	$	.40	 	 	$	.40	 	 	$	.40	 	 	$	.40	 	

 	 	 	
*	 	Per share amounts in all periods reflect the 3-for-1 stock split on May 31, 2006.	
 	 	 	
(a)	 	Includes net after-tax expenses of $26 million primarily relating to asset impairments and hurricanes in the Gulf of Mexico.	
 	 	 	
(b)	 	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.	
 	 	 	
(c)	 	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.	
 	 	 	
(d)	 	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.	
 	 	 	
(e)	 	Includes net after-tax income of $76 million primarily from sales of assets and income tax adjustments.	

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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 2008 was $2,360 million compared with $1,832 million in 2007 and $1,920 million in 2006. Diluted earnings per share were $7.24 in 2008 compared with $5.74 in 2007 and $6.08 in 2006. 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 1,432 million barrels of oil equivalent (boe) at December 31, 2008 compared with 1,330 million boe at December 31, 2007 and 1,243 million boe at December 31, 2006. Total proved reserves at year end 2008 increased 102 million boe or 8% from the end of 2007.
 
E&P net income was $2,423 million in 2008, $1,842 million in 2007 and $1,763 million in 2006. The improved results in 2008 as compared to 2007 were primarily driven by higher average crude oil selling prices. At December 31, 2008, crude oil selling prices were significantly below the average prices in 2008.
 
Production averaged 381,000 barrels of oil equivalent per day (boepd) in 2008 compared with 377,000 boepd in 2007 and 359,000 boepd in 2006. Production in 2008 increased 4,000 boepd or 1% from 2007. In 2009, the Corporation currently estimates total worldwide production to be approximately 380,000 boepd to 390,000 boepd.
 
During 2008, the Corporation progressed the following development projects that will add to its production in future years:

 	• 	In November 2008, upon the commissioning of a third-party gas export pipeline to Thailand, Phase 2 gas sales commenced at Block A-18 of the Joint Development Area of Malaysia and Thailand (JDA) (Hess 50%).	
 	 	 	
 	• 	In the deepwater Gulf of Mexico, development of the Shenzi Field (Hess 28%) progressed. Tension leg platform tendons, hull and topsides were installed and flowlines were laid and tested. First production is expected in the second quarter of 2009.	
 	 	 	
 	• 	Additional production from a Phase 2 oil project at the Ujung Pangkah Field (Hess 75%) in Indonesia is expected in mid 2009.	
 	 	 	
 	• 	Development of a residual oil zone advanced at the Seminole-San Andres Unit (Hess 34%) with the installation of facilities and equipment.	
 
During 2008, the Corporation’s exploration activities included:

 	• 	In the Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico, the Corporation successfully completed drilling an appraisal well. The Corporation is evaluating development options for Pony.	
 	 	 	
 	• 	At the Corporation’s Tubular Bells prospect (Hess 20%) located in the Mississippi Canyon area of the deepwater Gulf of Mexico, a third well was successfully drilled during 2008. The operator is evaluating development options for Tubular Bells.	
 	 	 	
 	• 	The Corporation completed drilling its initial four exploration wells of a 16 well commitment on the WA-Block-390-P offshore Western Australia (Hess 100%). Three of the four wells discovered natural gas and the Corporation plans to drill five additional exploration wells in 2009. The operator of the WA-Block 404-P (Hess 50%) offshore Western Australia plans to drill three exploration wells in 2009.	

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 	• 	The Corporation drilled a successful exploration well in Area 54 offshore Libya (Hess 100%). The Corporation intends to obtain 3D seismic in Area 54 and further drilling is planned.	
 	 	 	
 	• 	The Corporation drilled a successful exploration well on the West Med Block (Hess 55%) in Egypt, which encountered natural gas and crude oil. The Corporation is currently conducting engineering studies and further exploratory drilling is planned.	
 	 	 	
 	• 	The operator commenced drilling of an exploration well on the BM-S-22 Block (Hess 40%) in the Santos Basin offshore Brazil and filed a Notice of Discovery with the regulators on January 16, 2009.	
 	 	 	
 	• 	The Corporation was successful in acquiring new deepwater blocks in the Central and Western Gulf of Mexico and the offshore Semai V exploration block in Indonesia.	
 
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 $277 million in 2008, $300 million in 2007 and $394 million in 2006. Earnings in 2008 and 2007 reflect lower average margins compared to the prior periods.
 
Refining operations contributed net income of $73 million in 2008, $193 million in 2007 and $240 million in 2006. The Corporation received cash distributions from HOVENSA totaling $50 million in 2008, $300 million in 2007 and $400 million in 2006. Gross crude runs at HOVENSA averaged 441,000 barrels per day in 2008 compared with 454,000 barrels per day in 2007 and 448,000 barrels per day in 2006. In 2007, HOVENSA successfully completed the first turnaround of its delayed coker unit. The Port Reading refinery operated at an average of 64,000 barrels per day in 2008 versus 61,000 barrels per day in 2007 and 63,000 barrels per day in 2006. Marketing earnings were $240 million in 2008, $83 million in 2007 and $108 million in 2006. Total refined product sales volumes averaged 472,000 barrels per day in 2008 compared with 451,000 barrels per day in 2007 and 459,000 barrels per day in 2006.
 
Liquidity and Capital and Exploratory Expenditures
 
Net cash provided by operating activities was $4,567 million in 2008, $3,507 million in 2007 and $3,491 million in 2006, principally reflecting increased earnings. At December 31, 2008, cash and cash equivalents totaled $908 million compared with $607 million at December 31, 2007. Total debt was $3,955 million at December 31, 2008 compared with $3,980 million at December 31, 2007. The Corporation’s debt to capitalization ratio at December 31, 2008 was 24.3% compared with 28.9% at the end of 2007. The Corporation has debt maturities of $143 million in 2009 and $31 million in 2010. In February 2009, the Corporation issued $250 million of 5 year notes with a coupon of 7% and $1 billion of 10 year notes with a coupon of 8.125%.
 
Capital and exploratory expenditures were as follows for the years ended December 31:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Exploration and Production	 	 	 	 	 	 	 	 	
United States	 	$	2,164	 	 	$	1,603	 	
International	 	 	2,477	 	 	 	2,183	 	
 	 	 	 	 	 	 	 	 	
Total Exploration and Production	 	 	4,641	 	 	 	3,786	 	
Marketing, Refining and Corporate	 	 	187	 	 	 	140	 	
 	 	 	 	 	 	 	 	 	
Total Capital and Exploratory Expenditures	 	$	4,828	 	 	$	3,926	 	
 	 	 	 	 	 	 	 	 	
Exploration expenses charged to income included above:	 	 	 	 	 	 	 	 	
United States	 	$	211	 	 	$	192	 	
International	 	 	179	 	 	 	156	 	
 	 	 	 	 	 	 	 	 	
Total exploration expenses charged to income included above	 	$	390	 	 	$	348	 	

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The Corporation anticipates $3.2 billion in capital and exploratory expenditures in 2009, of which $3.1 billion relates to E&P operations.
 
Consolidated Results of Operations
 
The after-tax results by major operating activity are summarized below:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars,
	 	
 	 	except per share data)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exploration and Production	 	$	2,423	 	 	$	1,842	 	 	$	1,763	 	
Marketing and Refining	 	 	277	 	 	 	300	 	 	 	394	 	
Corporate	 	 	(173	)	 	 	(150	)	 	 	(110	)	
Interest expense	 	 	(167	)	 	 	(160	)	 	 	(127	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	2,360	 	 	$	1,832	 	 	$	1,920	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income per share — diluted	 	$	7.24	 	 	$	5.74	 	 	$	6.08	 	

 
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.
 
The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income and affect comparability between periods. The items in the table below are explained, and the pre-tax amounts are shown, on pages 25 through 27.

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exploration and Production	 	$	(26	)	 	$	(74	)	 	$	173	 	
Marketing and Refining	 	 	—	 	 	 	24	 	 	 	—	 	
Corporate	 	 	—	 	 	 	(25	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	(26	)	 	$	(75	)	 	$	173	 	

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Comparison of Results
 
Exploration and Production
 
Following is a summarized income statement of the Corporation’s Exploration and Production operations:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Sales and other operating revenues*	 	$	9,806	 	 	$	7,498	 	 	$	6,524	 	
Other, net	 	 	(167	)	 	 	65	 	 	 	428	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues and non operating income	 	 	9,639	 	 	 	7,563	 	 	 	6,952	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses, including related taxes	 	 	1,872	 	 	 	1,581	 	 	 	1,250	 	
Exploration expenses, including dry holes and lease impairment	 	 	725	 	 	 	515	 	 	 	552	 	
General, administrative and other expenses	 	 	302	 	 	 	257	 	 	 	209	 	
Depreciation, depletion and amortization	 	 	1,952	 	 	 	1,503	 	 	 	1,159	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	4,851	 	 	 	3,856	 	 	 	3,170	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations from continuing operations before income taxes	 	 	4,788	 	 	 	3,707	 	 	 	3,782	 	
Provision for income taxes	 	 	2,365	 	 	 	1,865	 	 	 	2,019	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	 	$	2,423	 	 	$	1,842	 	 	$	1,763	 	

 

*	 	Amounts differ from E&P operating revenues in Note 17 “Segment Information” primarily due to the exclusion of sales of hydrocarbons purchased from third parties.	
 
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, foreign exchange, and income taxes, as discussed below.
 
Selling prices:  Higher average selling prices increased Exploration and Production revenues by approximately $2,100 million in 2008 compared with 2007. At December 31, 2008, the selling prices of crude oil and natural gas had decreased significantly from the average 2008 selling prices indicated below. In 2007, an increase in average crude oil selling prices and reduced hedge positions compared with 2006 increased revenues by approximately $740 million.
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The Corporation’s average selling prices were as follows:

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude oil-per barrel (including hedging)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	96.82	 	 	$	69.23	 	 	$	60.45	 	
Europe	 	 	78.75	 	 	 	60.99	 	 	 	56.19	 	
Africa	 	 	78.72	 	 	 	62.04	 	 	 	51.18	 	
Asia and other	 	 	97.07	 	 	 	72.17	 	 	 	61.52	 	
Worldwide	 	 	82.04	 	 	 	63.44	 	 	 	55.31	 	
Crude oil-per barrel (excluding hedging)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	96.82	 	 	$	69.23	 	 	$	60.45	 	
Europe	 	 	78.75	 	 	 	60.99	 	 	 	58.46	 	
Africa	 	 	93.57	 	 	 	71.71	 	 	 	62.80	 	
Asia and other	 	 	97.07	 	 	 	72.17	 	 	 	61.52	 	
Worldwide	 	 	89.23	 	 	 	67.79	 	 	 	60.41	 	
Natural gas liquids-per barrel	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	64.98	 	 	$	51.89	 	 	$	46.22	 	
Europe	 	 	74.63	 	 	 	57.20	 	 	 	47.30	 	
Worldwide	 	 	67.61	 	 	 	53.72	 	 	 	46.59	 	
Natural gas-per mcf (including hedging)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	8.61	 	 	$	6.67	 	 	$	6.59	 	
Europe	 	 	9.44	 	 	 	6.13	 	 	 	6.20	 	
Asia and other	 	 	5.24	 	 	 	4.71	 	 	 	4.05	 	
Worldwide	 	 	7.17	 	 	 	5.60	 	 	 	5.50	 	
Natural gas-per mcf (excluding hedging)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	$	8.61	 	 	$	6.67	 	 	$	6.59	 	
Europe	 	 	9.79	 	 	 	6.13	 	 	 	6.20	 	
Asia and other	 	 	5.24	 	 	 	4.71	 	 	 	4.05	 	
Worldwide	 	 	7.30	 	 	 	5.60	 	 	 	5.50	 	

The after-tax impacts of hedging reduced earnings by $423 million ($685 million before income taxes) in 2008, $244 million ($399 million before income taxes) in 2007 and $285 million ($449 million before income taxes) in 2006. In October 2008, the Corporation closed its Brent crude oil hedge positions by entering into offsetting contracts with the same counterparty covering 24,000 barrels per day from 2009 through 2012 at a per barrel price of $86.95 each year. The deferred after-tax loss as of the date the hedge positions were closed will be recorded in earnings as the contracts mature. The estimated annual after-tax loss from the closed positions will be approximately $335 million from 2009 through 2012. The pretax amounts will continue to be recorded as a reduction of revenue and allocated to the selling prices of the Corporation’s African production.
 
Production and sales volumes:  The Corporation’s crude oil and natural gas production was 381,000 boepd in 2008 compared with 377,000 boepd in 2007 and 359,000 boepd in 2006. The Corporation currently estimates that its 2009 production will average between 380,000 and 390,000 boepd.
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The Corporation’s net daily worldwide production was as follows:

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude oil (thousands of barrels per day)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	32	 	 	 	31	 	 	 	36	 	
Europe	 	 	83	 	 	 	93	 	 	 	109	 	
Africa	 	 	124	 	 	 	115	 	 	 	85	 	
Asia and other	 	 	13	 	 	 	21	 	 	 	12	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	252	 	 	 	260	 	 	 	242	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas liquids (thousands of barrels per day)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	10	 	 	 	10	 	 	 	10	 	
Europe	 	 	4	 	 	 	5	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	14	 	 	 	15	 	 	 	15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas (thousands of mcf per day)	 	 	 	 	 	 	 	 	 	 	 	 	
United States	 	 	78	 	 	 	88	 	 	 	110	 	
Europe	 	 	255	 	 	 	259	 	 	 	283	 	
Asia and other	 	 	356	 	 	 	266	 	 	 	219	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	689	 	 	 	613	 	 	 	612	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Barrels of oil equivalent* (thousands of barrels per day)	 	 	381	 	 	 	377	 	 	 	359	 	

 
 	 	 	
*	 	Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel).	
 
United States:  Crude oil production in the United States was higher in 2008 compared with 2007, principally due to production from new wells in North Dakota and the deepwater Gulf of Mexico. This increased production was partially offset by the impact of hurricanes in the Gulf of Mexico. Natural gas production was lower in 2008, primarily reflecting hurricane downtime and natural decline. Hurricane impacts reduced full year 2008 production by an estimated 7,000 boepd. At December 31, 2008, approximately 15,000 boepd remained shut-in from the hurricanes and this production is expected to be brought back on line by the end of the first quarter of 2009. Crude oil and natural gas production in 2007 decreased compared with 2006 principally due to natural decline and asset sales.
 
Europe:  Crude oil production in 2008 was lower than in 2007, due to temporary shut-ins at three North Sea fields, cessation of production at the mature Fife, Fergus, Flora and Angus Fields, and natural decline. These decreases were partially offset by increased production in Russia. 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, partially offset by higher Russian production. Natural gas production was comparable in 2008 and 2007, but decreased in 2007 compared with 2006 principally due to lower nominations related to the shut-down of a non-operated pipeline and natural decline. The decreases were partially offset by higher natural gas production from the Atlantic and Cromarty Fields in the United Kingdom which commenced in June 2006.
 
Africa:  Crude oil production increased in 2008 compared with 2007, primarily due to higher production at the Okume Complex in Equatorial Guinea, partially offset by a lower entitlement to Algerian production. Crude oil production increased in 2007 compared with 2006 primarily due to the start-up of the Okume Complex in December 2006.
 
Asia and other:  The change in crude oil production from 2006 through 2008 principally reflects changes to the Corporation’s entitlement to production in Azerbaijan. The increase in 2007 compared with 2006 also reflects increased gross production from the fields in Azerbaijan. Natural gas production increased in 2008 compared with 2007 due to increased production from Block A-18 in the Joint Development Area of Malaysia and Thailand (JDA) and a full year of production from the Ujung Pangkah Field in Indonesia. Higher natural gas
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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 production from the Ujung Pangkah Field 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.
 
Sales volumes:  Higher sales volumes and other operating revenues increased revenue by approximately $200 million in 2008 compared with 2007 and $240 million in 2007 compared with 2006.
 
Operating costs and depreciation, depletion and amortization:   Cash operating costs, consisting of production expenses and general and administrative expenses, increased by $321 million in 2008 and $409 million in 2007 compared with the corresponding amounts in prior years (excluding the charges for hurricane related costs in 2008 and vacated leased office space in 2006 that are discussed below). The increases in 2008 and 2007 were primarily due to higher production volumes, increased production taxes (due to higher realized selling prices), increased costs of services and materials and higher employee costs. Cash operating costs per barrel of oil equivalent were $15.49 in 2008, $13.36 in 2007 and $10.92 in 2006. Cash operating costs in 2009 are estimated to be in the range of $15.00 to $16.00 per barrel of oil equivalent.
 
Excluding the pre-tax amount of asset impairments, depreciation, depletion and amortization charges increased by $531 million and $232 million in 2008 and 2007, 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 $13.79 in 2008, $10.11 in 2007 and $8.85 in 2006. Depreciation, depletion and amortization costs for 2009 are estimated to be in the range of $13.00 to $14.00 per barrel.
 
Exploration expenses:  Exploration expenses were higher in 2008 compared with 2007, principally due to higher dry hole costs. Exploration expenses were lower in 2007 compared with 2006, primarily reflecting lower dry hole costs, partially offset by increased seismic studies.
 
Income taxes:  After considering the items in the table below, the effective income tax rates for Exploration and Production operations were 49% in 2008, 50% in 2007 and 54% in 2006. The effective income tax rate for E&P operations in 2009 is estimated to be in the range of 57% to 61%. The increase from the 2008 effective rate largely reflects the impact of Libyan taxes in a lower commodity price environment.
 
Foreign Exchange:  The after-tax foreign currency loss was $84 million in 2008, compared with a loss of $7 million in 2007 and a gain of $10 million in 2006. The increased foreign currency loss reflects the effect of significant exchange rate movements in the fourth quarter of 2008 on the remeasurement of assets, liabilities and foreign currency forward contracts by certain foreign businesses.
 
Reported Exploration and Production earnings include the following items of income (expense) before and after income taxes:

 	 	Before Income Taxes	 	 	After Income Taxes	 	
 	 	2008	 	 	2007	 	 	2006	 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gains from asset sales	 	$	—	 	 	$	21	 	 	$	369	 	 	$	—	 	 	$	15	 	 	$	236	 	
Asset impairments	 	 	(30	)	 	 	(112	)	 	 	—	 	 	 	(17	)	 	 	(56	)	 	 	—	 	
Hurricane related costs	 	 	(15	)	 	 	—	 	 	 	—	 	 	 	(9	)	 	 	—	 	 	 	—	 	
Estimated production imbalance settlements	 	 	—	 	 	 	(64	)	 	 	—	 	 	 	—	 	 	 	(33	)	 	 	—	 	
Accrued office closing costs	 	 	—	 	 	 	—	 	 	 	(30	)	 	 	—	 	 	 	—	 	 	 	(18	)	
Income tax adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(45	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	(45	)	 	$	(155	)	 	$	339	 	 	$	(26	)	 	$	(74	)	 	$	173	 	

 
2008:  The charge for asset impairments relates to mature fields in the United States and the United Kingdom North Sea. The pre-tax amount of this charge is reflected in depreciation, depletion and amortization. The hurricane costs relate to expenses associated with Hurricanes Gustav and Ike in the Gulf of Mexico and are recorded in production expenses.
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2007:  The gain from asset sales relates to the sale of the Corporation’s interests in the Scott and Telford fields in the United Kingdom North Sea. The charge for asset impairments relates to two mature fields also in the United Kingdom North Sea. 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%.
 
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 $277 million in 2008, $300 million in 2007 and $394 million in 2006. After considering the liquidation of LIFO inventories reflected in the table on page 21 and discussed below, the earnings were $277 million, $276 million and $394 million, respectively.
 
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 $73 million in 2008, $193 million in 2007, and $240 million in 2006.
 
The Corporation’s share of HOVENSA’s net income was $27 million ($44 million before income taxes) in 2008, $108 million ($176 million before income taxes) in 2007 and $124 million ($201 million before income taxes) in 2006. The lower earnings in 2008 and 2007, compared with the respective prior years, were principally due to lower refining margins. The 2008 utilization rate for the fluid catalytic cracking unit at HOVENSA reflects lower utilization due to weak refining margins, planned and unplanned maintenance of certain units, and a refinery wide shut down for Hurricane Omar. In 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. Cash distributions received by the Corporation from HOVENSA were $50 million in 2008, $300 million in 2007 and $400 million in 2006.
 
Pre-tax interest income on the PDVSA note was $4 million, $9 million and $15 million in 2008, 2007 and 2006, respectively. Interest income is reflected in other income in the income statement. At December 31, 2008, the remaining balance of the PDVSA note was $15 million, which was fully repaid in February 2009.
 
Port Reading and other after-tax refining earnings were $43 million in 2008, $79 million in 2007 and $107 million in 2006, also reflecting lower refining margins.
 
The following table summarizes refinery utilization rates:

 	 	Refinery
	 	Refinery Utilization	
 	 	Capacity	 	2008	 	2007	 	2006	
 	 	(Thousands of
	 	 	 	 	 	 	
 	 	barrels per day)	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
HOVENSA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude	 	 	500	 	 	 	88.2%	 	 	 	90.8%	 	 	 	89.7%	 	
Fluid catalytic cracker	 	 	150	 	 	 	72.7%	 	 	 	87.1%	 	 	 	84.3%	 	
Coker	 	 	58	 	 	 	92.4%	 	 	 	83.4%	 	 	 	84.3%	 	
Port Reading	 	 	70	*	 	 	90.7%	 	 	 	93.2%	 	 	 	97.4%	 	

 
 	 	 	
*	 	Refinery utilization in 2007 and 2006 is based on capacity of 65 thousand barrels per day.	

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Marketing:  Marketing operations, which consist principally of retail gasoline and energy marketing activities, generated income of $240 million in 2008, $59 million in 2007 and $108 million in 2006, excluding income from the liquidation of LIFO inventories in 2007 totaling $38 million before income taxes ($24 million after income taxes).
 
The increase in 2008 primarily reflects higher margins on refined product sales, including sales of retail gasoline operations. Refined product margins were lower in 2007 compared with 2006. Total refined product sales volumes were 472,000 barrels per day in 2008, 451,000 barrels per day in 2007 and 459,000 barrels per day in 2006. Total energy marketing natural gas sales volumes, including utility and spot sales, were approximately 2.0 million mcf per day in 2008, 1.9 million mcf per day in 2007 and 1.8 million mcf per day in 2006. In addition, energy marketing sold electricity volumes at the rate of 3,200, 2,800 and 1,400 megawatts (round the clock) in 2008, 2007 and 2006, 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 a loss of $36 million in 2008, compared with earnings of $24 million in 2007 and $46 million in 2006.
 
Marketing expenses increased in 2008, principally reflecting growth in energy marketing activities, higher credit card fees in retail gasoline operations, and increased transportation costs.
 
The Corporation’s future Marketing and Refining earnings may be impacted by external factors, including volatility in margins, competitive industry conditions, government regulations, credit risk, and supply and demand factors, including the effects of weather.
 
Corporate
 
The following table summarizes corporate expenses:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Corporate expenses (excluding the item described below)	 	$	260	 	 	$	187	 	 	$	156	 	
Income taxes (benefits) on the above	 	 	(87	)	 	 	(62	)	 	 	(46	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	173	 	 	 	125	 	 	 	110	 	
Item affecting comparability between periods, after tax	 	 	 	 	 	 	 	 	 	 	 	 	
Estimated MTBE litigation	 	 	—	 	 	 	25	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net corporate expenses	 	$	173	 	 	$	150	 	 	$	110	 	

 
Excluding the item affecting comparability between periods, the increase in corporate expenses in 2008 compared with 2007 primarily reflects losses on pension related investments, higher employee costs, and higher professional fees. The increase in net corporate expenses in 2007 compared with 2006 principally reflects higher employee costs, including stock based compensation. Recurring after-tax corporate expenses in 2009 are estimated to be in the range of $165 to $175 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.
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Interest
 
After-tax interest expense was as follows:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total interest incurred	 	$	274	 	 	$	306	 	 	$	301	 	
Less capitalized interest	 	 	7	 	 	 	50	 	 	 	100	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense before income taxes	 	 	267	 	 	 	256	 	 	 	201	 	
Less income taxes	 	 	100	 	 	 	96	 	 	 	74	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
After-tax interest expense	 	$	167	 	 	$	160	 	 	$	127	 	

 
The decrease in interest incurred in 2008 principally reflects lower average debt. The decrease in capitalized interest in 2008 reflects the completion of several development projects in 2007 and 2006. Interest expense in each period includes the cost of letters of credit primarily issued to counterparties in hedging and trading activities. After-tax interest expense in 2009 is expected to be in the range of $230 to $240 million. See Future Capital Requirements and Resources for discussion of a $1,250 million note issuance in the first quarter of 2009.
 
Sales and Other Operating Revenues
 
Sales and other operating revenues totaled $41,165 million in 2008, an increase of 30% compared with 2007. In 2007, sales and other operating revenues totaled $31,647 million, an increase of 13% compared with 2006. The increase in each year reflects higher selling prices and sales volumes of crude oil, higher refined product selling prices and increased sales volumes of electricity.
 
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:

 	 	2008	 	2007	
 	 	(Millions of dollars)	
 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	908	 	 	$	607	 	
Current portion of long-term debt	 	$	143	 	 	$	62	 	
Total debt	 	$	3,955	 	 	$	3,980	 	
Stockholders’ equity	 	$	12,307	 	 	$	9,774	 	
Debt to capitalization ratio*	 	 	24.3	%	 	 	28.9	%	

 
 	 	 	
*	 	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:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	4,567	 	 	$	3,507	 	 	$	3,491	 	
Investing activities	 	 	(4,444	)	 	 	(3,474	)	 	 	(3,289	)	
Financing activities	 	 	178	 	 	 	191	 	 	 	(134	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net increase in cash and cash equivalents	 	$	301	 	 	$	224	 	 	$	68	 	

 
Operating Activities:  Net cash provided by operating activities, including changes in operating assets and liabilities, increased to $4,567 million in 2008 from $3,507 million in 2007, reflecting increased earnings. Operating cash flow was comparable in 2007 and 2006. The Corporation received cash distributions from HOVENSA of $50 million in 2008, $300 million in 2007 and $400 million in 2006.
 
Investing Activities:  The following table summarizes the Corporation’s capital expenditures:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exploration and Production	 	 	 	 	 	 	 	 	 	 	 	 	
Exploration	 	$	744	 	 	$	371	 	 	$	590	 	
Production and development	 	 	2,523	 	 	 	2,605	 	 	 	2,164	 	
Acquisitions (including leaseholds)	 	 	984	 	 	 	462	 	 	 	921	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	4,251	 	 	 	3,438	 	 	 	3,675	 	
Marketing, Refining and Corporate	 	 	187	 	 	 	140	 	 	 	169	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	4,438	 	 	$	3,578	 	 	$	3,844	 	

 
Capital expenditures in 2008 include leasehold acquisitions in the United States of $600 million and $210 million for the acquisition of the remaining 22.5% interest in the Corporation’s Gabonese subsidiary. In 2008, the Corporation also selectively expanded its energy marketing business by acquiring fuel oil, natural gas, and electricity customer accounts, and a terminal and related assets, for an aggregate of approximately $100 million. In 2007, capital expenditures 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.
 
Financing Activities:  During 2008, net repayments of debt were $32 million compared with net borrowings of $208 million in 2007. In 2006, the Corporation reduced debt by $13 million.
 
Total common and preferred stock dividends paid were $130 million, $127 million and $161 million in 2008, 2007 and 2006, respectively. The Corporation received net proceeds from the exercise of stock options, including related income tax benefits, of $340 million, $110 million and $40 million in 2008, 2007 and 2006, respectively.
 
Future Capital Requirements and Resources
 
The Corporation anticipates $3.2 billion in capital and exploratory expenditures in 2009, of which $3.1 billion relates to Exploration and Production operations. Of the total E&P amount, $1.4 billion is for production and $900 million is for developments, with the remainder for exploration. The anticipated 2009 capital program
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represents a decrease of approximately $1.6 billion from 2008, primarily as a result of lower crude oil selling prices. The Corporation also has maturities of long-term debt of $143 million in 2009. The Corporation anticipates that it can fund its 2009 operations, including planned capital expenditures, dividends, pension contributions and required debt repayments, with existing cash on-hand, projected cash flow from operations and available credit facilities. Crude oil and natural gas prices are volatile and difficult to predict in the near term as a result of the recent global economic recession. In addition, unplanned increases in the Corporation’s capital expenditure program could occur. The Corporation will take steps as necessary to protect its financial flexibility, and may pursue other sources of liquidity, including the issuance of debt or equity securities, or asset sales.
 
The table below summarizes the capacity, usage, and remaining availability of the Corporation’s borrowing and letter of credit facilities at December 31, 2008 (in millions):

 	 	Expiration
	 	 	 	 	 	 	 	Letters of
	 	 	 	 	 	Remaining
	 	
 	 	Date	 	Capacity	 	 	Borrowings	 	 	Credit Issued	 	 	Total Used	 	 	Capacity	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revolving credit facility	 	May 2012*	 	$	3,000	 	 	$	350	 	 	$	176	 	 	$	526	 	 	$	2,474	 	
Asset backed credit facility	 	October 2009	 	 	500	 	 	 	500	 	 	 	—	 	 	 	500	 	 	 	—	 	
Committed lines	 	Various**	 	 	1,993	 	 	 	—	 	 	 	1,973	 	 	 	1,973	 	 	 	20	 	
Uncommitted lines	 	Various	 	 	1,686	 	 	 	—	 	 	 	1,686	 	 	 	1,686	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	$	7,179	 	 	$	850	 	 	$	3,835	 	 	$	4,685	 	 	$	2,494	 	

 
 	 	 	
*	 	$75 million of capacity expires in May 2011.	
 	 	 	
**	 	Committed lines have expiration dates ranging from 2009 through 2011.	
 
The Corporation maintains a $3.0 billion syndicated, revolving credit facility (the facility), of which $2,925 million is committed through May 2012. The facility can be used for borrowings and letters of credit. At December 31, 2008, additional available capacity under the facility was $2,474 million.
 
The Corporation has a 364-day asset-backed credit facility securitized by certain accounts receivable from its Marketing and Refining operations. Under the terms of this financing arrangement, the Corporation has the ability to borrow or issue letters of credit up to $500 million, subject to the availability of sufficient levels of eligible receivables. At December 31, 2008, outstanding borrowings under this facility were collateralized by $1,249 million of accounts receivable, which are held by a wholly-owned subsidiary. 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, 2008, $500 million of outstanding borrowings under the asset-backed credit facility are classified as long-term based on the Corporation’s available capacity under the committed revolving credit facility.
 
In February 2009, the Corporation issued $250 million of 5 year senior unsecured notes with a coupon of 7% and $1 billion of 10 year senior unsecured notes with a coupon of 8.125%. The majority of the proceeds were used to repay revolving credit debt and outstanding borrowings on other credit facilities. The remainder of the proceeds is available for working capital and other corporate purposes.
 
The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.
 
A loan agreement covenant based on the Corporation’s debt to equity ratio allows the Corporation to borrow up to an additional $16.6 billion for the construction or acquisition of assets at December 31, 2008. The Corporation has the ability to borrow up to an additional $2.8 billion of secured debt at December 31, 2008 under the loan agreement covenants.
 
In order to reduce credit risk, the Corporation has agreements with counterparties to exchange collateral which is determined based on the fair values of positions held under these agreements. The Corporation’s $3.8 billion of letters of credit outstanding at December 31, 2008 were primarily issued to satisfy collateral requirements. Additionally, the Corporation has posted cash collateral of approximately $394 million and has received cash
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collateral of approximately $705 million from its hedging and trading counterparties. Changes in commodity prices can have a material impact on collateral requirements under these agreements.
 
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 credit facilities, as well as margin requirements from non-trading and trading counterparties, are subject to adjustment if the Corporation’s credit rating changes.
 
Contractual Obligations and Contingencies
 
Following is a table showing aggregated information about certain contractual obligations at December 31, 2008:

 	 	 	 	Payments Due by Period	
 	 	 	 	 	 	2010 and
	 	2012 and
	 	 	
 	 	Total	 	2009	 	2011	 	2013	 	Thereafter	
 	 	(Millions of dollars)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt*	 	$	3,955	 	 	$	143	 	 	$	733	 	 	$	907	 	 	$	2,172	 	
Operating leases	 	 	3,561	 	 	 	551	 	 	 	725	 	 	 	638	 	 	 	1,647	 	
Purchase obligations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Supply commitments	 	 	24,252	 	 	 	8,602	 	 	 	8,204	 	 	 	7,344	 	 	 	102	**	
Capital expenditures	 	 	1,356	 	 	 	929	 	 	 	427	 	 	 	—	 	 	 	—	 	
Operating expenses	 	 	1,011	 	 	 	486	 	 	 	321	 	 	 	77	 	 	 	127	 	
Other long-term liabilities	 	 	2,011	 	 	 	134	 	 	 	474	 	 	 	93	 	 	 	1,310	 	

 	 	 	
*	 	At December 31, 2008, the Corporation’s debt bears interest at a weighted average rate of 6.7%.	
 	 	 	
**	 	The Corporation intends to continue purchasing refined product supply from HOVENSA. Estimated future purchases amount to approximately $4.0 billion annually using year-end 2008 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 to supply 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 $3.2 billion capital investment program for 2009 that is contractually committed at December 31, 2008. 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, 2008, including asset retirement obligations, pension plan liabilities 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 are expected to be approximately $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 $175 million as of December 31, 2008.
 
The Corporation guarantees the payment of up to 50% of HOVENSA’s crude oil purchases from certain suppliers other than PDVSA. The amount of the Corporation’s guarantee fluctuates based on the volume of crude oil
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purchased and related prices and at December 31, 2008 amounted to $78 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.
 
The Corporation is contingently liable under letters of credit and under guarantees of the debt of other entities directly related to its business, as follows:

 	 	Total	 	
 	 	(Millions of
	 	
 	 	dollars)	 	
 	 	 	 	 	
Letters of credit	 	$	126	 	
Guarantees	 	 	93	 	
 	 	 	 	 	
 	 	$	219	 	

 
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 $491 million at December 31, 2008 compared with $493 million at December 31, 2007. The Corporation’s December 31, 2008 debt to capitalization ratio would increase from 24.3% to 26.5% if these leases were included as debt.
 
See also Note 4, “Refining Joint Venture,” and Note 16, “Guarantees and Contingencies,” in the notes to the financial statements.
 
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, Peru, Russia, Thailand, the United Kingdom and the United States. Therefore, the Corporation is subject to the risks associated with foreign operations, including political risk, 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.
 
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 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
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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 review.
 
The oil and gas reserve estimates reported in the Supplementary Oil and Gas Data in accordance with Statement of Financial Accounting Standards (FAS) 69  Disclosures about Oil and Gas Producing Activities  (FAS 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.
 
On December 31, 2008, the Securities and Exchange Commission published a final rule which revises its oil and gas reserve estimation and disclosure requirements. The revisions are effective for filings on Form 10-K for fiscal years ending December 31, 2009. The Corporation is evaluating the impact of these requirements on its oil and gas reserve estimates and disclosures.
 
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 that 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 and discounted at a risk-adjusted rate, The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of actual prices on the last day of the year.
 
The Corporation’s impairment tests of long-lived Exploration and Production producing assets are based on its best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed. The
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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 142, Goodwill and Other Intangible Assets, the Corporation’s goodwill is not amortized, but is tested for impairment at a reporting unit level, which is an operating segment or one level below an operating segment. The impairment test is conducted annually in the fourth quarter or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. 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 133,  Accounting for Derivative Instruments and Hedging Activities , 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
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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.
 
Fair Value Measurements:  The Corporation’s derivative instruments and supplemental pension plan investments are carried at fair value, with changes in fair value recognized in earnings or other comprehensive income each period. In determining fair value, the Corporation uses various valuation approaches, including the market and income approaches. The Corporation’s fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and the Corporation’s credit is considered for accrued liabilities.
 
The Corporation adopted the provisions of FAS 157, Fair Value Measurements (FAS 157), effective January 1, 2008. FAS 157 establishes a hierarchy for the inputs used to measure fair value based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value for each financial asset or liability is based on the lowest significant input level within this fair value hierarchy. Details on the methods and assumptions used to determine the fair values of the financial assets and liabilities are as follows :
 
Fair value measurements based on Level 1 inputs:
 
Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. The fair value of certain of the Corporation’s exchange traded futures and options are considered Level 1. In addition, fair values for the majority of the Corporation’s supplemental pension plan investments are considered Level 1, since they are determined using quotations from national securities exchanges.
 
Fair value measurements based on Level 2 inputs:
 
Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Corporation utilizes fair value measurements based on Level 2 inputs for certain forwards, swaps and options. The liability related to the Corporation’s crude oil hedges is classified as Level 2.
 
Fair value measurements based on Level 3 inputs:
 
Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. For example, in its energy marketing business, the Corporation sells natural gas and electricity to customers and offsets the price exposure by purchasing forward contracts. The fair value of these sales and purchases may be based on specific prices at less liquid delivered locations, which are classified as Level 3.
 
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.
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The Corporation has net operating loss carryforwards or credit carryforwards in several jurisdictions, including the United States, and has recorded deferred tax assets for those losses and credits. 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 and credit carryforwards, 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.
 
Retirement Plans:  The Corporation has funded non-contributory defined benefit pension plans and an unfunded supplemental pension plan. In accordance with FAS 158,  Employer’s Accounting For Defined Benefit Pension and Other Postretirement Plans  (FAS 158), the Corporation recognizes on the balance sheet the net change in the funded status of the projected benefit obligation for these plans.
 
The determination of the obligations and expenses related to these plans are based on several actuarial assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; and rate of future increases in compensation levels. These assumptions represent estimates made by the Corporation, some of which can be affected by external factors. For example, the discount rate used to estimate the Corporation’s projected benefit obligation is based on a portfolio of high-quality, fixed-income debt instruments with maturities that approximate the expected payment of plan obligations, while the expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category. Changes in these assumptions can have a material impact on the amounts reported in the Corporation’s financial statements.
 
Changes in Accounting Policies
 
As discussed on page 35, the Corporation adopted FAS 157 effective January 1, 2008. The impact of adopting FAS 157 was not material to the Corporation’s results of operations. Upon adoption, the Corporation recorded a reduction in the net deferred hedge losses reflected in accumulated other comprehensive income, which increased stockholders’ equity by $193 million, after income taxes.
 
Effective December 31, 2008, the Corporation applied the provisions of Emerging Issues Task Force 08-5 , Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement  (EITF 08-5). Upon adoption, the Corporation revalued certain derivative liabilities collateralized by letters of credit to reflect the Corporation’s credit rating rather than the credit rating of the issuing bank. The adoption resulted in an increase in sales and other operating revenues of approximately $13 million and an increase in other comprehensive income of approximately $78 million, with a corresponding decrease in derivative liabilities recorded within accounts payable.
 
Recently Issued Accounting Standard
 
In December 2007, the FASB issued FAS 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51  (FAS 160). FAS 160 changes the accounting for and reporting of noncontrolling interests in a subsidiary. The Corporation will adopt the provisions of FAS 160 effective January 1, 2009 and estimates that adoption will result in a decrease in other long term liabilities and an increase in stockholders’ equity of approximately $85 million.
 
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
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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 Corporation and HOVENSA produce and the Corporation distributes fuel oils in the United States. Proposals by state regulatory agencies and legislatures have been made that would require a lower sulfur content of fuel oils. If adopted, these proposals could require capital expenditures by the Registrant and HOVENSA to meet the required sulfur content standards.
 
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 nearly 90% of the domestic refining capacity. Negotiations with the EPA are continuing and substantial progress has been made toward resolving this matter for both the Corporation and HOVENSA. While the effect on the Corporation of the Petroleum Refining Initiative cannot be estimated until a final settlement is reached and entered by a court, additional future capital expenditures and operating expenses will likely be incurred over a number of years. The amount of penalties, if any, is not expected to be material to the Corporation.
 
The Corporation has undertaken a program to assess, monitor and reduce the emission of “greenhouse gases,” including carbon dioxide and methane. The Corporation recognizes that climate change is a global environmental concern with potentially significant consequences for society and the energy industry. The Corporation is committed to the responsible management of greenhouse gas emissions from our existing assets and future developments and is developing and implementing a strategy to control our carbon emissions.
 
The Corporation will have continuing expenditures for environmental assessment and remediation. 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 2008, the Corporation’s reserve for estimated environmental liabilities was approximately $61 million. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. The Corporation’s remediation spending was $23 million in 2008, $23 million in 2007 and $15 million in 2006. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, other than for the low sulfur requirements, were $15 million in 2008 and $22 million in 2007 and 2006.
 
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.
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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 consolidated partnership that trades energy commodities. 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 133 are excluded from the quantitative market risk disclosures.	
 	 	 	
 	• 	Forward Foreign Exchange Contracts:  The Corporation enters into forward contracts primarily for the British pound, the Norwegian krone, and the Danish krone, which commit the Corporation to buy or sell a fixed amount of these currencies at a predetermined exchange rate on a future date.	
 	 	 	
 	• 	Exchange Traded Contracts:  The Corporation uses exchange traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.	
 	 	 	
 	• 	Swaps:  The Corporation uses financially settled swap contracts with third parties as part of its hedging and trading activities. Cash flows from swap contracts are determined based on underlying commodity prices and are typically settled over the life of the contract.	
 	 	 	
 	• 	Options:  Options on various underlying energy commodities include exchange traded and third party contracts and have various exercise periods. As a seller of options, the Corporation receives a premium at the outset and bears the risk of unfavorable changes in the price of the commodity underlying the option. As a purchaser of options, the Corporation pays a premium at the outset and has the right to participate in the favorable price movements in the underlying commodities. These premiums are a component of the fair value of the options.	
 	 	 	
 	• 	Energy Securities:  Energy securities include energy related equity or debt securities issued by a company or government or related derivatives on these securities.	

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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)	
 	 	 	 	 	 	 	 	 	
2008	 	 	 	 	 	 	 	 	
At December 31	 	$	17	 	 	$	13	 	
Average	 	 	13	 	 	 	90	 	
High	 	 	17	 	 	 	140	 	
Low	 	 	11	 	 	 	13	 	
2007	 	 	 	 	 	 	 	 	
At December 31	 	$	10	 	 	$	72	 	
Average	 	 	12	 	 	 	63	 	
High	 	 	13	 	 	 	72	 	
Low	 	 	10	 	 	 	54	 	

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. In October 2008, the Corporation closed its Brent crude oil hedge positions by entering into offsetting contracts with the same counterparty covering 24,000 barrels per day from 2009 through 2012 at a per barrel price of $86.95 each year. The after-tax deferred losses related to closed crude oil contracts will be recorded in earnings as the contracts mature.
 
There were no hedges of WTI crude oil or natural gas production at December 31, 2008. 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, 2008 includes after-tax deferred losses of $1,478 million primarily related to closed crude oil contracts that were used as hedges of exploration and production sales.
 
The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates by entering into forward contracts for various currencies including the British pound, the Norwegian krone and the Danish krone. At December 31, 2008, the Corporation had $896 million of notional value foreign exchange contracts maturing in 2009. The fair value of the foreign exchange contracts was a payable of $75 million at December 31, 2008. The change in fair value of the foreign exchange contracts from a 20% change in exchange rates is estimated to be approximately $165 million at December 31, 2008.
 
The Corporation’s outstanding debt of $3,955 million has a fair value of $3,883 million at December 31, 2008. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $85 million at December 31, 2008.
 
Trading:  In trading activities, the Corporation is primarily 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.
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Gains or losses from sales of physical products are recorded at the time of sale. Total realized gains (losses) on trading activities amounted to $(317) million in 2008 and $303 million in 2007. 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.

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Fair value of contracts outstanding at the beginning of the year	 	$	154	 	 	$	365	 	
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of year	 	 	(257	)	 	 	193	 	
Reversal of fair value for contracts closed during the year	 	 	42	 	 	 	(230	)	
Fair value of contracts entered into during the year and still outstanding	 	 	925	 	 	 	(174	)	
 	 	 	 	 	 	 	 	 	
Fair value of contracts outstanding at the end of the year	 	$	864	 	 	$	154	 	

 
The Corporation measures fair value and summarizes the sources of fair value for derivatives in accordance with the provisions of FAS 157. See the discussion on page 35 for more details on how the Corporation measures fair value.
 
The following table summarizes the sources of fair values of derivatives used in the Corporation’s trading activities at December 31, 2008:

 	 	 	 	 	 	 	 	 	 	 	 	 	 	2012 and
	 	
 	 	Total	 	 	2009	 	 	2010	 	 	2011	 	 	Beyond	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Source of fair value	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Level 1	 	$	35	 	 	$	(22	)	 	$	63	 	 	$	2	 	 	$	(8	)	
Level 2	 	 	885	 	 	 	564	 	 	 	180	 	 	 	82	 	 	 	59	 	
Level 3	 	 	(56	)	 	 	(42	)	 	 	(12	)	 	 	(1	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	864	 	 	$	500	 	 	$	231	 	 	$	83	 	 	$	50	 	

 
The following table summarizes the receivables net of cash margin and letters of credit relating to the Corporation’s trading activities and the credit ratings of counterparties at December 31:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Investment grade determined by outside sources	 	$	263	 	 	$	364	 	
Investment grade determined internally*	 	 	133	 	 	 	173	 	
Less than investment grade	 	 	58	 	 	 	55	 	
 	 	 	 	 	 	 	 	 	
Fair value of net receivables outstanding at the end of the year	 	$	454	 	 	$	592	 	

 

*	 	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	 	
 	 	 	 	 	
Management’s Report on Internal Control over Financial Reporting	 	 	42	 	
Reports of Independent Registered Public Accounting Firm	 	 	43	 	
Consolidated Balance Sheet at December 31, 2008 and 2007	 	 	45	 	
Statement of Consolidated Income for each of the three years in the period ended December 31, 2008	 	 	46	 	
Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2008	 	 	47	 	
Statement of Consolidated Stockholders’ Equity for each of the three years in the period ended December 31, 2008	 	 	48	 	
Statement of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2008	 	 	49	 	
Notes to Consolidated Financial Statements	 	 	50	 	
Supplementary Oil and Gas Data	 	 	75	 	
Quarterly Financial Data	 	 	82	 	
Consent of Independent Registered Public Accounting Firm	 	 	88	 	
Schedule* II — Valuation and Qualifying Accounts	 	 	89	 	

 
 	 	 	
*	 	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, 2008.
 
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, 2008, 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 20, 2009
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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, 2008, 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 Corporation’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, 2008 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, 2008 and 2007, 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, 2008, and our report dated February 20, 2009 expressed an unqualified opinion thereon.

 
February 20, 2009
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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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 Interpretation No. 48, Accounting for Uncertainty in Income Taxes, effective January 1, 2007.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hess Corporation’s internal control over financial reporting as of December 31, 2008, 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 20, 2009 expressed an unqualified opinion thereon.

 
February 20, 2009
New York, New York
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

 	 	December 31,	 	
 	 	2008	 	 	2007	 	
 	 	(Millions of dollars; thousands of shares)	 	
 	 	 	 	 	 	 	 	 	
ASSETS	
CURRENT ASSETS	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	908	 	 	$	607	 	
Accounts receivable	 	 	 	 	 	 	 	 	
Trade	 	 	4,059	 	 	 	4,527	 	
Other	 	 	238	 	 	 	181	 	
Inventories	 	 	1,308	 	 	 	1,250	 	
Other current assets	 	 	819	 	 	 	361	 	
 	 	 	 	 	 	 	 	 	
Total current assets	 	 	7,332	 	 	 	6,926	 	
 	 	 	 	 	 	 	 	 	
INVESTMENTS IN AFFILIATES	 	 	 	 	 	 	 	 	
HOVENSA L.L.C. 	 	 	919	 	 	 	933	 	
Other	 	 	208	 	 	 	184	 	
 	 	 	 	 	 	 	 	 	
Total investments in affiliates	 	 	1,127	 	 	 	1,117	 	
 	 	 	 	 	 	 	 	 	
PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	 	
Exploration and Production	 	 	25,332	 	 	 	22,903	 	
Marketing, Refining and Corporate	 	 	2,105	 	 	 	1,928	 	
 	 	 	 	 	 	 	 	 	
Total — at cost	 	 	27,437	 	 	 	24,831	 	
Less reserves for depreciation, depletion, amortization and lease impairment	 	 	11,166	 	 	 	10,197	 	
 	 	 	 	 	 	 	 	 	
Property, plant and equipment — net	 	 	16,271	 	 	 	14,634	 	
 	 	 	 	 	 	 	 	 	
GOODWILL	 	 	1,225	 	 	 	1,225	 	
DEFERRED INCOME TAXES	 	 	2,292	 	 	 	1,873	 	
OTHER ASSETS	 	 	342	 	 	 	356	 	
 	 	 	 	 	 	 	 	 	
TOTAL ASSETS	 	$	28,589	 	 	$	26,131	 	

LIABILITIES AND STOCKHOLDERS’ EQUITY	
CURRENT LIABILITIES	 	 	 	 	 	 	 	 	
Accounts payable	 	$	5,045	 	 	$	5,741	 	
Accrued liabilities	 	 	1,905	 	 	 	1,638	 	
Taxes payable	 	 	637	 	 	 	583	 	
Current maturities of long-term debt	 	 	143	 	 	 	62	 	
 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	7,730	 	 	 	8,024	 	
 	 	 	 	 	 	 	 	 	
LONG-TERM DEBT	 	 	3,812	 	 	 	3,918	 	
DEFERRED INCOME TAXES	 	 	2,241	 	 	 	2,362	 	
ASSET RETIREMENT OBLIGATIONS	 	 	1,164	 	 	 	1,016	 	
OTHER LIABILITIES AND DEFERRED CREDITS	 	 	1,335	 	 	 	1,037	 	
 	 	 	 	 	 	 	 	 	
Total liabilities	 	 	16,282	 	 	 	16,357	 	
 	 	 	 	 	 	 	 	 	
STOCKHOLDERS’ EQUITY	 	 	 	 	 	 	 	 	
Preferred stock, par value $1.00, 20,000 shares authorized	 	 	 	 	 	 	 	 	
3% cumulative convertible series	 	 	 	 	 	 	 	 	
Authorized: 330 shares	 	 	 	 	 	 	 	 	
Issued: 2008 — 0 shares; 2007 — 284 shares	 	 	—	 	 	 	—	 	
Common stock, par value $1.00	 	 	 	 	 	 	 	 	
Authorized: 600,000 shares	 	 	 	 	 	 	 	 	
Issued: 2008 — 326,133 shares; 2007 — 320,600 shares	 	 	326	 	 	 	321	 	
Capital in excess of par value	 	 	2,347	 	 	 	1,882	 	
Retained earnings	 	 	11,642	 	 	 	9,412	 	
Accumulated other comprehensive income (loss)	 	 	(2,008	)	 	 	(1,841	)	
 	 	 	 	 	 	 	 	 	
Total stockholders’ equity	 	 	12,307	 	 	 	9,774	 	
 	 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	 	$	28,589	 	 	$	26,131	 	

 
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

 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
 	 	(In millions, except per share data)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
REVENUES AND NON-OPERATING INCOME	 	 	 	 	 	 	 	 	 	 	 	 	
Sales (excluding excise taxes) and other operating revenues	 	$	41,165	 	 	$	31,647	 	 	$	28,067	 	
Equity in income of HOVENSA L.L.C. 	 	 	44	 	 	 	176	 	 	 	201	 	
Gain on asset sales	 	 	—	 	 	 	21	 	 	 	369	 	
Other, net	 	 	(115	)	 	 	80	 	 	 	81	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues and non-operating income	 	 	41,094	 	 	 	31,924	 	 	 	28,718	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
COSTS AND EXPENSES	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of products sold (excluding items shown separately below)	 	 	29,595	 	 	 	22,573	 	 	 	19,912	 	
Production expenses	 	 	1,872	 	 	 	1,581	 	 	 	1,250	 	
Marketing expenses	 	 	1,025	 	 	 	944	 	 	 	940	 	
Exploration expenses, including dry holes and lease impairment	 	 	725	 	 	 	515	 	 	 	552	 	
Other operating expenses	 	 	209	 	 	 	161	 	 	 	122	 	
General and administrative expenses	 	 	672	 	 	 	614	 	 	 	471	 	
Interest expense	 	 	267	 	 	 	256	 	 	 	201	 	
Depreciation, depletion and amortization	 	 	2,029	 	 	 	1,576	 	 	 	1,224	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	36,394	 	 	 	28,220	 	 	 	24,672	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
INCOME BEFORE INCOME TAXES	 	 	4,700	 	 	 	3,704	 	 	 	4,046	 	
Provision for income taxes	 	 	2,340	 	 	 	1,872	 	 	 	2,126	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	$	2,360	 	 	$	1,832	 	 	$	1,920	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Less preferred stock dividends	 	 	—	 	 	 	—	 	 	 	44	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
NET INCOME APPLICABLE TO COMMON SHAREHOLDERS	 	$	2,360	 	 	$	1,832	 	 	$	1,876	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
BASIC NET INCOME PER SHARE	 	$	7.35	 	 	$	5.86	 	 	$	6.75	 	
DILUTED NET INCOME PER SHARE	 	$	7.24	 	 	$	5.74	 	 	$	6.08	 	
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)	 	 	325.8	 	 	 	319.3	 	 	 	315.7	 	

 
See accompanying notes to consolidated financial statements.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED CASH FLOWS

 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
CASH FLOWS FROM OPERATING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	2,360	 	 	$	1,832	 	 	$	1,920	 	
Adjustments to reconcile net income to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization	 	 	2,029	 	 	 	1,576	 	 	 	1,224	 	
Exploratory dry hole costs	 	 	210	 	 	 	65	 	 	 	241	 	
Lease impairment	 	 	125	 	 	 	102	 	 	 	99	 	
Pre-tax gain on asset sales	 	 	—	 	 	 	(21	)	 	 	(369	)	
Provision (benefit) for deferred income taxes	 	 	(57	)	 	 	(33	)	 	 	281	 	
Distributed earnings of HOVENSA L.L.C., net	 	 	6	 	 	 	124	 	 	 	199	 	
Changes in other operating assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
(Increase) decrease in accounts receivable	 	 	357	 	 	 	(783	)	 	 	(179	)	
Increase in inventories	 	 	(56	)	 	 	(254	)	 	 	(152	)	
Increase (decrease) in accounts payable and accrued liabilities	 	 	(252	)	 	 	597	 	 	 	(44	)	
Increase in taxes payable	 	 	61	 	 	 	134	 	 	 	47	 	
Changes in other assets and liabilities	 	 	(216	)	 	 	168	 	 	 	224	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	 	 	4,567	 	 	 	3,507	 	 	 	3,491	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
CASH FLOWS FROM INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(4,438	)	 	 	(3,578	)	 	 	(3,844	)	
Proceeds from asset sales	 	 	—	 	 	 	93	 	 	 	444	 	
Payments received on notes receivable	 	 	61	 	 	 	61	 	 	 	76	 	
Other, net	 	 	(67	)	 	 	(50	)	 	 	35	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(4,444	)	 	 	(3,474	)	 	 	(3,289	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
CASH FLOWS FROM FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Debt with maturities of greater than 90 days	 	 	 	 	 	 	 	 	 	 	 	 	
Borrowings	 	 	380	 	 	 	1,094	 	 	 	320	 	
Repayments	 	 	(412	)	 	 	(886	)	 	 	(333	)	
Cash dividends paid	 	 	(130	)	 	 	(127	)	 	 	(161	)	
Employee stock options exercised, including income tax benefits	 	 	340	 	 	 	110	 	 	 	40	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in) financing activities	 	 	178	 	 	 	191	 	 	 	(134	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
NET INCREASE IN CASH AND CASH EQUIVALENTS	 	 	301	 	 	 	224	 	 	 	68	 	
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	 	 	607	 	 	 	383	 	 	 	315	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
CASH AND CASH EQUIVALENTS AT END OF YEAR	 	$	908	 	 	$	607	 	 	$	383	 	

 
 
See accompanying notes to consolidated financial statements.
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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED STOCKHOLDERS’ EQUITY

 	 	2008	 	 	2007	 	 	2006	 	
 	 	Shares	 	 	Amount	 	 	Shares	 	 	Amount	 	 	Shares	 	 	Amount	 	
 	 	(Millions of dollars; thousands of shares)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
PREFERRED STOCK	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	 	284	 	 	$	—	 	 	 	324	 	 	$	—	 	 	 	13,824	 	 	$	14	 	
Conversion of preferred stock to common stock	 	 	(284	)	 	 	—	 	 	 	(40	)	 	 	—	 	 	 	(13,500	)	 	 	(14	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	—	 	 	 	—	 	 	 	284	 	 	 	—	 	 	 	324	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
COMMON STOCK	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	 	320,600	 	 	 	321	 	 	 	315,018	 	 	 	315	 	 	 	279,197	 	 	 	279	 	
Activity related to restricted common stock awards, net	 	 	1,148	 	 	 	1	 	 	 	941	 	 	 	1	 	 	 	903	 	 	 	1	 	
Employee stock options exercised	 	 	3,852	 	 	 	4	 	 	 	4,566	 	 	 	5	 	 	 	1,283	 	 	 	1	 	
Conversion of preferred stock to common stock	 	 	533	 	 	 	—	 	 	 	75	 	 	 	—	 	 	 	33,635	 	 	 	34	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	326,133	 	 	 	326	 	 	 	320,600	 	 	 	321	 	 	 	315,018	 	 	 	315	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
CAPITAL IN EXCESS OF PAR VALUE	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	 	 	 	 	 	1,882	 	 	 	 	 	 	 	1,689	 	 	 	 	 	 	 	1,656	 	
Activity related to restricted common stock awards, net	 	 	 	 	 	 	145	 	 	 	 	 	 	 	50	 	 	 	 	 	 	 	36	 	
Employee stock options, including income tax benefits	 	 	 	 	 	 	320	 	 	 	 	 	 	 	143	 	 	 	 	 	 	 	68	 	
Conversion of preferred stock to common stock	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	 	 	 	 	 	 	(20	)	
Reclassification resulting from adoption of FAS 123R	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	 	 	 	 	 	 	(51	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	 	 	 	 	2,347	 	 	 	 	 	 	 	1,882	 	 	 	 	 	 	 	1,689	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
RETAINED EARNINGS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	 	 	 	 	 	9,412	 	 	 	 	 	 	 	7,707	 	 	 	 	 	 	 	5,946	 	
Net income	 	 	 	 	 	 	2,360	 	 	 	 	 	 	 	1,832	 	 	 	 	 	 	 	1,920	 	
Dividends declared on common stock	 	 	 	 	 	 	(130	)	 	 	 	 	 	 	(127	)	 	 	 	 	 	 	(115	)	
Dividends on preferred stock	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	 	 	 	 	 	 	(44	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	 	 	 	 	11,642	 	 	 	 	 	 	 	9,412	 	 	 	 	 	 	 	7,707	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	 	 	 	 	 	(1,841	)	 	 	 	 	 	 	(1,564	)	 	 	 	 	 	 	(1,526	)	
Net other comprehensive income (loss)	 	 	 	 	 	 	(167	)	 	 	 	 	 	 	(277	)	 	 	 	 	 	 	104	 	
Cumulative effect of adoption of FAS 158	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	 	 	 	 	 	 	(142	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	 	 	 	 	(2,008	)	 	 	 	 	 	 	(1,841	)	 	 	 	 	 	 	(1,564	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
DEFERRED COMPENSATION	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	 	 	 	 	 	 	(51	)	
Reclassification resulting from adoption of FAS 123R	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	 	 	 	 	 	 	51	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	 	 	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
TOTAL STOCKHOLDERS’ EQUITY at December 31	 	 	 	 	 	$	12,307	 	 	 	 	 	 	$	9,774	 	 	 	 	 	 	$	8,147	 	

 
 
See accompanying notes to consolidated financial statements.
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STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

 	 	Years Ended December 31,	 	
 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPONENTS OF COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	2,360	 	 	$	1,832	 	 	$	1,920	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Other comprehensive income (loss):	 	 	 	 	 	 	 	 	 	 	 	 	
Deferred gains (losses) on cash flow hedges, after tax:	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of hedge losses recognized in income	 	 	342	 	 	 	325	 	 	 	345	 	
Net change in fair value of cash flow hedges	 	 	(341	)	 	 	(659	)	 	 	(379	)	
Effect of adoption of FAS 157	 	 	193	 	 	 	—	 	 	 	—	 	
Change in retirement plan liabilities, after tax	 	 	(241	)	 	 	17	 	 	 	90	 	
Change in foreign currency translation adjustment and other	 	 	(120	)	 	 	40	 	 	 	48	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net other comprehensive income (loss)	 	 	(167	)	 	 	(277	)	 	 	104	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
COMPREHENSIVE INCOME	 	$	2,193	 	 	$	1,555	 	 	$	2,024	 	

 
See accompanying notes to consolidated financial statements.
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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, Peru, 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 133,  Accounting for Derivative Instruments and Hedging Activities,  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
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value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.
 
Cash and Cash Equivalents:  Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired.
 
Inventories:  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 19,  Financial Accounting and Reporting by Oil and Gas Producing Companies  (FAS 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 143,  Accounting for Asset Retirement Obligations  and FASB Interpretation 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
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required conditional asset retirement obligations is recorded if the liability can be reasonably estimated. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets.
 
Impairment of Long-Lived Assets:  The Corporation reviews long-lived assets 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 and discounted at a risk-adjusted rate. 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 142, Goodwill and Other Intangible Assets, goodwill is not amortized; however, it is tested for impairment annually in the fourth quarter or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. This impairment test is calculated at the reporting unit level, which for the Corporation’s goodwill is the Exploration and Production operating segment. 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). 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:  The fair value of all share-based compensation is expensed and recognized on a straight-line basis over the vesting period of the awards in accordance with FAS 123R, Share-Based Payment , which was adopted on January 1, 2006.
 
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
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planning strategies, the existence of appreciated assets, the available carryforward periods for net operating losses and other factors. 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 expected to be realized.
 
The Corporation adopted the provisions of FASB Interpretation 48, Accounting for Uncertainty in Income Taxes , (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 non-functional 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).
 
Fair Value Measurements:  The Corporation adopted the provisions of FAS 157, Fair Value Measurements  (FAS 157), effective January 1, 2008. FAS 157 establishes a hierarchy for the inputs used to measure fair value based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value for each financial asset or liability is based on the lowest significant input level within this fair value hierarchy. See Note 15, “Fair Value Measurements”, for more details on the methods and assumptions used to determine the fair values of the financial assets and liabilities.
 
The impact of adopting FAS 157 was not material to the Corporation’s results of operations. Upon adoption, the Corporation recorded a reduction in the net deferred hedge losses reflected in accumulated other comprehensive income, which increased stockholders’ equity by $193 million, after income taxes.
 
Effective December 31, 2008, the Corporation applied the provisions of Emerging Issues Task Force 08-5 , Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement  (EITF 08-5). Upon adoption, the Corporation revalued certain derivative liabilities collateralized by letters of credit to reflect the Corporation’s credit rating rather than the credit rating of the issuing bank. The adoption resulted in an increase in sales and other operating revenues of approximately $13 million and an increase in accumulated other comprehensive income of approximately $78 million, with a corresponding decrease in derivative liabilities recorded within accounts payable.
 
Retirement Plans:  Effective December 31, 2006, the Corporation adopted FAS 158, Employer’s Accounting For Defined Benefit Pension and Other Postretirement Plans , which required the recognition of the underfunded status of defined benefit postretirement plans on the balance sheet. For the Corporation’s pension plans, the underfunded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. For the Corporation’s postretirement medical plan, the underfunded status represents the difference between the fair value of plan assets and the accumulated postretirement benefit obligation. The Corporation recognizes the net changes in the funded status of these plans in the year in which such changes occur.
 
Recently Issued Accounting Standard:  In December 2007, the FASB issued FAS 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 51 (FAS 160). FAS 160 changes the accounting for and reporting of noncontrolling interests in a subsidiary. The Corporation will adopt the provisions
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of FAS 160 effective January 1, 2009 and estimates that the impact of adoption will result in a decrease to other long term liabilities and an increase to stockholders’ equity of approximately $85 million.

2.  	Acquisitions and Divestitures	
 
2008:  In the third quarter of 2008, the Corporation acquired the remaining 22.5% interest in its Gabonese subsidiary for $285 million, of which $210 million was allocated to proved properties. The Corporation expanded its energy marketing business by acquiring fuel oil, natural gas, and electricity customer accounts, and a terminal and related assets, for an aggregate of approximately $100 million.
 
2007:  In the first quarter of 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. This transaction was accounted for as an asset acquisition. Genghis Khan has been unitized with the Shenzi development.
 
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.

3.  	Inventories	
 
Inventories at December 31 are as follows:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Crude oil and other charge stocks	 	$	383	 	 	$	338	 	
Refined products and natural gas	 	 	988	 	 	 	1,577	 	
Less: LIFO adjustment	 	 	(500	)	 	 	(1,029	)	
 	 	 	 	 	 	 	 	 	
 	 	 	871	 	 	 	886	 	
Merchandise, materials and supplies	 	 	437	 	 	 	364	 	
 	 	 	 	 	 	 	 	 	
Total	 	$	1,308	 	 	$	1,250	 	

 
The percentage of LIFO inventory to total crude oil, refined products and natural gas inventories was 60% and 69% at December 31, 2008 and 2007, respectively. During 2007 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 ($24 million after income taxes).
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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:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Summarized Balance Sheet, at December 31	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	75	 	 	$	279	 	 	$	290	 	
Other current assets	 	 	664	 	 	 	1,183	 	 	 	943	 	
Net fixed assets	 	 	2,136	 	 	 	2,181	 	 	 	2,123	 	
Other assets	 	 	58	 	 	 	62	 	 	 	32	 	
Current liabilities	 	 	(679	)	 	 	(1,459	)	 	 	(1,013	)	
Long-term debt	 	 	(356	)	 	 	(356	)	 	 	(252	)	
Deferred liabilities and credits	 	 	(104	)	 	 	(75	)	 	 	(70	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Partners’ equity	 	$	1,794	 	 	$	1,815	 	 	$	2,053	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Summarized Income Statement, for the years ended December 31	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	$	17,480	 	 	$	13,396	 	 	$	11,788	 	
Costs and expenses	 	 	(17,385	)	 	 	(13,039	)	 	 	(11,381	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	95	 	 	$	357	 	 	$	407	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Hess Corporation’s share*	 	$	44	 	 	$	176	 	 	$	201	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Summarized Cash Flow Statement, for the years ended December 31	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	(20	)	 	$	654	 	 	$	484	 	
Investing activities	 	 	(85	)	 	 	(165	)	 	 	(10	)	
Financing activities	 	 	(99	)	 	 	(500	)	 	 	(796	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net decrease in cash and cash equivalents	 	$	(204	)	 	$	(11	)	 	$	(322	)	

 
 	 	 	
*	 	Before Virgin Islands income taxes, which were recorded in the Corporation’s income tax provision.	
 
The Corporation received cash distributions from HOVENSA of $50 million, $300 million and $400 million during 2008, 2007 and 2006, respectively. The Corporation’s share of HOVENSA’s undistributed income aggregated $206 million at December 31, 2008.
 
The Corporation guarantees the payment of up to 50% of the value of HOVENSA’s crude oil purchases from certain suppliers other than PDVSA. The guarantee amounted to $78 million at December 31, 2008. 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 $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 over its term. The principal balance of the note was $15 million and $76 million at December 31, 2008 and 2007, respectively, which was fully repaid in February 2009.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.  	Property, Plant and Equipment	
 
Property, plant and equipment at December 31 consists of the following:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Exploration and Production	 	 	 	 	 	 	 	 	
Unproved properties	 	$	2,265	 	 	$	1,688	 	
Proved properties	 	 	3,009	 	 	 	3,350	 	
Wells, equipment and related facilities	 	 	20,058	 	 	 	17,865	 	
 	 	 	 	 	 	 	 	 	
 	 	 	25,332	 	 	 	22,903	 	
Marketing, Refining and Corporate	 	 	2,105	 	 	 	1,928	 	
 	 	 	 	 	 	 	 	 	
Total — at cost	 	 	27,437	 	 	 	24,831	 	
Less: reserves for depreciation, depletion, amortization and lease impairment	 	 	11,166	 	 	 	10,197	 	
 	 	 	 	 	 	 	 	 	
Property, plant and equipment — net	 	$	16,271	 	 	$	14,634	 	

 
In 2008, the Corporation recorded asset impairments at fields located in the United States and U.K. North Sea totaling $30 million ($17 million after income taxes). In 2007 the Corporation recorded asset impairments at two mature fields in the U.K. North Sea totaling $112 million ($56 million after income taxes). These impairments are reflected in depreciation, depletion and amortization.
 
At December 31, 2008, the Corporation has classified its Gabonese assets as held for sale. As a result, the net book value of $452 million at December 31, 2008 was reclassified to other current assets. In addition, $169 million of asset retirement obligations and deferred income taxes were reclassified to accrued liabilities.
 
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:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning balance at January 1	 	$	608	 	 	$	399	 	 	$	244	 	
Additions to capitalized exploratory well costs pending the determination of proved reserves	 	 	560	 	 	 	229	 	 	 	299	 	
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves	 	 	(67	)	 	 	(20	)	 	 	(144	)	
Capitalized exploratory well costs charged to expense	 	 	(7	)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance at December 31	 	$	1,094	 	 	$	608	 	 	$	399	 	

Number of wells at end of year	 	 	45	 	 	 	30	 	 	 	28	 	

 
The preceding table excludes exploratory dry hole costs of $203 million, $65 million and $241 million in 2008, 2007 and 2006, respectively, which were incurred and subsequently expensed in the same year.
 
At December 31, 2008, exploratory drilling costs capitalized in excess of one year past completion of drilling were as follows (in millions):

2007	 	$	109	 	
2006	 	 	216	 	
2003 to 2005	 	 	56	 	
 	 	 	 	 	
 	 	$	381	 	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The capitalized well costs in excess of one year relate to 10 projects. Approximately 80% of the costs relates to the Pony and Tubular Bells projects in the deepwater Gulf of Mexico where development options are being evaluated at December 31, 2008. The remainder of the costs relate to projects where further drilling is planned or development planning activities are ongoing.

6.  	Asset Retirement Obligations	
 
The following table describes changes to the Corporation’s asset retirement obligations:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Asset retirement obligations at January 1	 	$	1,055	 	 	$	882	 	
Liabilities incurred	 	 	35	 	 	 	62	 	
Liabilities settled or disposed of	 	 	(56	)	 	 	(51	)	
Accretion expense	 	 	67	 	 	 	50	 	
Revisions	 	 	309	 	 	 	84	 	
Foreign currency translation	 	 	(196	)	 	 	28	 	
 	 	 	 	 	 	 	 	 	
Asset retirement obligations at December 31	 	 	1,214	 	 	 	1,055	 	
Less: current obligations	 	 	50	 	 	 	39	 	
 	 	 	 	 	 	 	 	 	
Long-term obligations at December 31	 	$	1,164	 	 	$	1,016	 	

 
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:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Revolving credit facility, weighted average rate 2.2%	 	$	350	 	 	$	220	 	
Asset-backed credit facility, weighted average rate 2.8%	 	 	500	 	 	 	250	 	
Short-term credit facilities	 	 	—	 	 	 	350	 	
Fixed rate debentures:	 	 	 	 	 	 	 	 	
7.4% due 2009	 	 	104	 	 	 	103	 	
6.7% due 2011	 	 	662	 	 	 	662	 	
7.9% due 2029	 	 	694	 	 	 	694	 	
7.3% due 2031	 	 	745	 	 	 	745	 	
7.1% due 2033	 	 	598	 	 	 	598	 	
 	 	 	 	 	 	 	 	 	
Total fixed rate debentures	 	 	2,803	 	 	 	2,802	 	
Fixed rate notes, payable principally to insurance companies, weighted average rate 9.1%, due through 2014	 	 	108	 	 	 	126	 	
Project lease financing, weighted average rate 5.1%, due through 2014	 	 	132	 	 	 	140	 	
Pollution control revenue bonds, weighted average rate 5.9%, due through 2034	 	 	53	 	 	 	53	 	
Other loans, weighted average rate 7.5%, due through 2019	 	 	9	 	 	 	39	 	
 	 	 	 	 	 	 	 	 	
 	 	 	3,955	 	 	 	3,980	 	
Less: amount included in current maturities	 	 	143	 	 	 	62	 	
 	 	 	 	 	 	 	 	 	
Total	 	$	3,812	 	 	$	3,918	 	

 
The aggregate long-term debt maturing during the next five years is as follows (in millions): 2009 — $143 (included in current liabilities); 2010 — $31; 2011 — $702; 2012 — $874 and 2013 — $33.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
At December 31, 2008, the Corporation’s fixed rate debentures have a principal amount of $2,816 million ($2,803 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, 2008, the Corporation has available capacity on the facility of $2,474 million. Current borrowings under the facility bear interest at 0.4% above the London Interbank Offered Rate and a facility fee of 0.1% 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 and Refining operations. Under the terms of this financing arrangement, the Corporation has the ability to borrow or issue letters of credit up to $500 million, subject to the availability of sufficient levels of eligible receivables. At December 31, 2008, outstanding borrowings under this facility were collateralized by $1,249 million of accounts receivable, which are held by a wholly-owned subsidiary. 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, 2008, $500 million of outstanding borrowings under the asset-backed credit facility are classified as long-term based on the Corporation’s available capacity under the committed revolving credit facility.
 
The Corporation’s long-term debt agreements contain a financial covenant that restricts the amount of total borrowings and secured debt. At December 31, 2008, the Corporation is permitted to borrow up to an additional $16.6 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $2.8 billion of secured debt at December 31, 2008.
 
Outstanding letters of credit at December 31 were as follows:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Revolving credit facility	 	$	176	 	 	$	—	 	
Asset-backed credit facility	 	 	—	 	 	 	534	 	
Committed lines*	 	 	1,973	 	 	 	995	 	
Uncommitted short-term lines	 	 	1,686	 	 	 	1,510	 	
 	 	 	 	 	 	 	 	 	
Total	 	$	3,835	 	 	$	3,039	 	

 
 	 	 	
*	 	Committed lines have expiration dates ranging from 2009 through 2011.	
 
Of the total letters of credit outstanding at December 31, 2008, $126 million relates to contingent liabilities and the remaining $3,709 million relates to liabilities recorded on the balance sheet.
 
The total amount of interest paid (net of amounts capitalized) was $266 million, $257 million and $200 million in 2008, 2007 and 2006, respectively. The Corporation capitalized interest of $7 million, $50 million and $100 million in 2008, 2007, and 2006, respectively.

8.  	Share-Based Compensation	
 
The Corporation awards restricted common stock and stock options under its 2008 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Share-based compensation expense consists of the following:

 	 	Before Taxes	 	 	After Taxes	 	
 	 	2008	 	 	2007	 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Stock options	 	$	51	 	 	$	36	 	 	$	31	 	 	$	23	 	
Restricted stock	 	 	68	 	 	 	51	 	 	 	43	 	 	 	31	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	119	 	 	$	87	 	 	$	74	 	 	$	54	 	

 
Based on restricted stock and stock option awards outstanding at December 31, 2008, unearned compensation expense, before income taxes, will be recognized in future years as follows (in millions): 2009 — $92, 2010 — $56 and 2011 — $6.
 
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, 2006	 	 	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	 	
Granted	 	 	2,473	 	 	 	82.55	 	 	 	1,289	 	 	 	84.45	 	
Exercised	 	 	(3,852	)	 	 	29.17	 	 	 	—	 	 	 	—	 	
Vested	 	 	—	 	 	 	—	 	 	 	(2,787	)	 	 	21.40	 	
Forfeited	 	 	(213	)	 	 	60.61	 	 	 	(142	)	 	 	58.60	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Outstanding at December 31, 2008	 	 	9,700	 	 	 	52.73	 	 	 	3,161	 	 	 	64.47	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercisable at December 31, 2006	 	 	6,832	 	 	$	22.08	 	 	 	 	 	 	 	 	 	
Exercisable at December 31, 2007	 	 	5,408	 	 	 	27.34	 	 	 	 	 	 	 	 	 	
Exercisable at December 31, 2008	 	 	4,522	 	 	 	36.95	 	 	 	 	 	 	 	 	 	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The table below summarizes information regarding the outstanding and exercisable stock options as of December 31, 2008:

 	 	 	 	Outstanding Options	 	Exercisable Options	
 	 	 	 	Weighted-
	 	 	 	 	 	 	
 	 	 	 	Average
	 	Weighted-
	 	 	 	Weighted-
	
 	 	 	 	Remaining
	 	Average
	 	 	 	Average
	
Range of
	 	 	 	Contractual
	 	Exercise Price
	 	 	 	Exercise Price
	
Exercise Prices	 	Options	 	Life	 	per Share	 	Options	 	per Share	
 	 	(Thousands)	 	(Years)	 	 	 	(Thousands)	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
$10.00 – $40.00	 	 	2,514	 	 	 	5	 	 	$	25.78	 	 	 	2,512	 	 	$	25.77	 	
$40.01 – $70.00	 	 	4,749	 	 	 	8	 	 	 	51.65	 	 	 	1,996	 	 	 	50.77	 	
$70.01 – $120.00	 	 	2,437	 	 	 	9	 	 	 	82.62	 	 	 	14	 	 	 	73.06	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	9,700	 	 	 	7	 	 	 	52.73	 	 	 	4,522	 	 	 	36.95	 	

 
The intrinsic value (or the amount by which the market price of the Corporation’s Common Stock exceeds the exercise price of an option) for outstanding options and exercisable options at December 31, 2008 was $80 million and $76 million, respectively. At December 31, 2008, assuming forfeitures of 2% per year, 9,500,000 outstanding options are expected to vest at a weighted average exercise price of $52.45 per share. At December 31, 2008 the weighted average remaining term of exercisable options was 6 years.
 
The Corporation uses the Black-Scholes model to estimate the fair value of employee stock options. The following weighted average assumptions were utilized for stock options awarded:

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Risk free interest rate	 	 	2.70	%	 	 	4.70	%	 	 	4.50	%	
Stock price volatility	 	 	.294	 	 	 	.316	 	 	 	.321	 	
Dividend yield	 	 	.50	%	 	 	.75	%	 	 	.80	%	
Expected term in years	 	 	5	 	 	 	5	 	 	 	5	 	
Weighted average fair value per option granted	 	$	24.09	 	 	$	18.07	 	 	$	16.50	 	

The assumption above for the risk free interest rate is based on the expected terms of the options and is obtained from published sources. The stock price volatility is determined from historical experience using the same period as the expected terms of the options. The expected stock option term is based on historical exercise patterns and the expected future holding period.
 
In May 2008, shareholders approved the 2008 Long-Term Incentive Plan. The Corporation also has stock options outstanding under a former plan. At December 31, 2008, the number of common shares reserved for issuance under the 2008 Long-Term Incentive Plan is as follows (in thousands):

Total common shares reserved for issuance	 	 	12,884	 	
Less: stock options outstanding	 	 	80	 	
 	 	 	 	 	
Available for future awards of restricted stock and stock options	 	 	12,804	 	

 
 	 	
9.  	Foreign Currency Translation	
 
Foreign currency gains (losses) before income taxes amounted to $(212) million in 2008, $17 million in 2007 and $21 million in 2006. The foreign currency loss in 2008 reflects the effect of significant exchange rate movements in the fourth quarter of 2008 on the remeasurement of assets, liabilities and foreign currency forward contracts by certain foreign businesses. The balances in accumulated other comprehensive income (loss) related to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
foreign currency translation were reductions in stockholders’ equity of $123 million at December 31, 2008 and $3 million at December 31, 2007.

10.  	Retirement Plans	
 
The Corporation has funded noncontributory defined benefit pension plans for a significant portion of its employees. In addition, the Corporation has an unfunded supplemental pension plan covering certain employees. The unfunded supplemental pension plan provides for incremental pension payments from the Corporation so that total pension payments equal amounts that would have been payable from the Corporation’s principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary. Additionally, the Corporation maintains an unfunded postretirement medical plan that provides health benefits to certain qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31. The following table summarizes the Corporation’s benefit obligations and the fair value of plan assets and shows the funded status of the pension and postretirement medical plans:

 	 	Funded
	 	 	Unfunded
	 	 	Postretirement
	 	
 	 	Pension Plans	 	 	Pension Plan	 	 	Medical Plan	 	
 	 	2008	 	 	2007	 	 	2008	 	 	2007	 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in benefit obligation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	$	1,136	 	 	$	1,098	 	 	$	147	 	 	$	114	 	 	$	86	 	 	$	89	 	
Service cost	 	 	36	 	 	 	36	 	 	 	6	 	 	 	5	 	 	 	3	 	 	 	3	 	
Interest cost	 	 	71	 	 	 	65	 	 	 	9	 	 	 	8	 	 	 	4	 	 	 	4	 	
Actuarial (gain) loss	 	 	19	 	 	 	(31	)	 	 	11	 	 	 	30	 	 	 	(13	)	 	 	(5	)	
Benefit payments	 	 	(42	)	 	 	(37	)	 	 	(8	)	 	 	(10	)	 	 	(3	)	 	 	(5	)	
Foreign currency exchange rate changes	 	 	(95	)	 	 	5	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	1,125	 	 	 	1,136	 	 	 	165	 	 	 	147	 	 	 	77	 	 	 	86	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in fair value of plan assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at January 1	 	 	1,075	 	 	 	961	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Actual return on plan assets	 	 	(280	)	 	 	70	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Employer contributions	 	 	70	 	 	 	77	 	 	 	8	 	 	 	10	 	 	 	3	 	 	 	5	 	
Benefit payments	 	 	(42	)	 	 	(37	)	 	 	(8	)	 	 	(10	)	 	 	(3	)	 	 	(5	)	
Foreign currency exchange rate changes	 	 	(78	)	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31	 	 	745	 	 	 	1,075	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded status (plan assets less than benefit obligations) at December 31	 	 	(380	)	 	 	(61	)	 	 	(165	)*	 	 	(147	)*	 	 	(77	)	 	 	(86	)	
Unrecognized net actuarial losses	 	 	513	 	 	 	162	 	 	 	77	 	 	 	75	 	 	 	13	 	 	 	27	 	
Unrecognized prior service cost	 	 	—	 	 	 	—	 	 	 	1	 	 	 	2	 	 	 	—	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net amount recognized	 	$	133	 	 	$	101	 	 	$	(87	)	 	$	(70	)	 	$	(64	)	 	$	(60	)	

 
 	 	 	
*	 	The trust established by the Corporation for the supplemental plan held assets valued at $65 million at December 31, 2008 and $88 million at December 31, 2007.	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

 	 	Funded
	 	 	Unfunded
	 	 	Postretirement
	 	
 	 	Pension Plans	 	 	Pension Plan	 	 	Medical Plan	 	
 	 	2008	 	 	2007	 	 	2008	 	 	2007	 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accrued benefit liability	 	$	(380	)	 	$	(61	)	 	$	(165	)	 	$	(147	)	 	$	(77	)	 	$	(86	)	
Accumulated other comprehensive loss*	 	 	513	 	 	 	162	 	 	 	78	 	 	 	77	 	 	 	13	 	 	 	26	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net amount recognized	 	$	133	 	 	$	101	 	 	$	(87	)	 	$	(70	)	 	$	(64	)	 	$	(60	)	

 
 	 	 	
*	 	The after-tax reduction to stockholders’ equity recorded in Accumulated other comprehensive income (loss) was $407 million at December 31, 2008 and $166 million at December 31, 2007.	
 
The accumulated benefit obligation for the funded defined benefit pension plans was $1,032 million at December 31, 2008 and $1,019 million at December 31, 2007. The accumulated benefit obligation for the unfunded defined benefit pension plan was $149 million at December 31, 2008 and $120 million at December 31, 2007.
 
Components of net periodic benefit cost for funded and unfunded pension plans and the postretirement medical plan consisted of the following:

 	 	Pension Plans	 	 	Postretirement Medical Plan	 	
 	 	2008	 	 	2007	 	 	2006	 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Service cost	 	$	42	 	 	$	41	 	 	$	34	 	 	$	3	 	 	$	3	 	 	$	3	 	
Interest cost	 	 	80	 	 	 	73	 	 	 	63	 	 	 	4	 	 	 	4	 	 	 	5	 	
Expected return on plan assets	 	 	(80	)	 	 	(74	)	 	 	(63	)	 	 	—	 	 	 	—	 	 	 	—	 	
Amortization of prior service cost	 	 	1	 	 	 	1	 	 	 	1	 	 	 	(1	)	 	 	(1	)	 	 	(1	)	
Amortization of unrecognized net actuarial loss	 	 	18	 	 	 	22	 	 	 	30	 	 	 	1	 	 	 	—	 	 	 	—	 	
Settlement loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net periodic benefit cost	 	$	61	 	 	$	63	 	 	$	65	 	 	$	7	 	 	$	8	 	 	$	10	 	

 
Prior service costs and actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees.
 
The Corporation’s 2009 pension and postretirement medical expense is estimated to be approximately $125 million, of which approximately $57 million relates to the amortization of unrecognized net actuarial losses.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The weighted-average actuarial assumptions used by the Corporation’s funded and unfunded pension plans were as follows:

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted-average assumptions used to determine benefit obligations at December 31	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	6.3	%	 	 	6.3	%	 	 	5.8	%	
Rate of compensation increase	 	 	4.4	 	 	 	4.4	 	 	 	4.4	 	
Weighted-average assumptions used to determine net benefit cost for years ended December 31	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	6.3	 	 	 	5.8	 	 	 	5.5	 	
Expected return on plan assets	 	 	7.5	 	 	 	7.5	 	 	 	7.5	 	
Rate of compensation increase	 	 	4.4	 	 	 	4.4	 	 	 	4.3	 	

The actuarial assumptions used by the Corporation’s postretirement medical plan were as follows:

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Assumptions used to determine benefit obligations at December 31	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate	 	 	6.3	%	 	 	6.3	%	 	 	5.8	%	
Initial health care trend rate	 	 	9.0	%	 	 	9.0	%	 	 	8.0	%	
Ultimate trend rate	 	 	4.5	%	 	 	4.5	%	 	 	4.5	%	
Year in which ultimate trend rate is reached	 	 	2013	 	 	 	2013	 	 	 	2011	 	

The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year-end. The net periodic benefit cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is developed based on a portfolio of high-quality, fixed-income debt instruments with maturities that approximate the expected payment of plan obligations. The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category.
 
The Corporation’s investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by the Corporation’s investment committee and include domestic and foreign equities, fixed income securities, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by the Corporation unless indirectly held as part of an index strategy. The majority of plan assets are highly liquid, providing ample liquidity for benefit payment requirements.
 
The Corporation’s funded pension plan assets by asset category are as follows:

 	 	Target
	 	December 31,	
Asset Category	 	Allocation	 	2008	 	2007	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity securities	 	 	50	%	 	 	48	%	 	 	57	%	
Debt securities	 	 	25	 	 	 	27	 	 	 	29	 	
Other investments	 	 	25	 	 	 	25	 	 	 	14	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	100	%	 	 	100	%	 	 	100	%	

 
Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Corporation has budgeted contributions ranging from approximately $110 million to $150 million to its funded pension plans in 2009. The Corporation has not budgeted any contributions to the trust established for the unfunded plan.
 
Estimated future benefit payments for the funded and unfunded pension plans and the postretirement medical plan, which reflect expected future service, are as follows:

 	 	(Millions of dollars)	
 	 	 	 	 	
2009	 	$	63	 	
2010	 	 	73	 	
2011	 	 	90	 	
2012	 	 	76	 	
2013	 	 	83	 	
Years 2014 to 2018	 	 	492	 	

The Corporation also contributes to several defined contribution plans for eligible employees. Employees may contribute a portion of their compensation to the plans and the Corporation matches a portion of the employee contributions. The Corporation recorded expense of $22 million in 2008, $19 million in 2007 and $16 million in 2006 for contributions to these plans.

11.  	Income Taxes	
 
The provision for (benefit from) income taxes consisted of:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
United States Federal	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	$	10	 	 	$	2	 	 	$	4	 	
Deferred	 	 	(140	)	 	 	62	 	 	 	96	 	
State	 	 	10	 	 	 	(149	)	 	 	19	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	(120	)	 	 	(85	)*	 	 	119	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	 	2,377	 	 	 	1,898	 	 	 	1,836	 	
Deferred	 	 	87	 	 	 	64	 	 	 	142	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	2,464	 	 	 	1,962	 	 	 	1,978	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjustment of deferred tax liability for foreign income tax rate change	 	 	(4	)	 	 	(5	)	 	 	29	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total provision for income taxes	 	$	2,340	 	 	$	1,872	 	 	$	2,126	 	

 
 	 	 	
*	 	Includes a provision for an increase in the valuation allowance for foreign tax credit carryforwards of $81 million and a benefit from a decrease in the valuation allowance for state net operating loss carryforwards of $96 million..	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
United States*	 	$	(318	)	 	$	(228	)	 	$	406	 	
Foreign**	 	 	5,018	 	 	 	3,932	 	 	 	3,640	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income before income taxes	 	$	4,700	 	 	$	3,704	 	 	$	4,046	 	

 
 	 	 	
*	 	Includes substantially all of the Corporation’s interest expense and the results of hedging activities.	
 	 	 	
**	 	Foreign income includes the Corporation’s Virgin Islands and other operations located outside of the United States.	
 
Deferred income taxes arise from temporary differences between the tax bases of assets and liabilities and their recorded amounts in the financial statements. A summary of the components of deferred tax liabilities and assets at December 31 follows:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Deferred tax liabilities	 	 	 	 	 	 	 	 	
Fixed assets and investments	 	$	2,918	 	 	$	3,048	 	
Other	 	 	114	 	 	 	70	 	
 	 	 	 	 	 	 	 	 	
Total deferred tax liabilities	 	 	3,032	 	 	 	3,118	 	
 	 	 	 	 	 	 	 	 	
Deferred tax assets	 	 	 	 	 	 	 	 	
Net operating loss carryforwards	 	 	1,832	 	 	 	1,884	 	
Tax credit carryforwards	 	 	458	 	 	 	285	 	
Accrued liabilities	 	 	415	 	 	 	390	 	
Asset retirement obligations	 	 	406	 	 	 	430	 	
Other	 	 	227	 	 	 	48	 	
 	 	 	 	 	 	 	 	 	
Total deferred tax assets	 	 	3,338	 	 	 	3,037	 	
Valuation allowance	 	 	(266	)	 	 	(224	)	
 	 	 	 	 	 	 	 	 	
Net deferred tax assets	 	 	3,072	 	 	 	2,813	 	
 	 	 	 	 	 	 	 	 	
Net deferred tax assets (liabilities)	 	$	40	 	 	$	(305	)	

 
At December 31, 2008, the Corporation has net operating loss carryforwards in the United States of approximately $4.0 billion, substantially all of which expire in 2024 through 2027. At December 31, 2008, the Corporation has alternative minimum tax credit carryforwards of approximately $165 million, which can be carried forward indefinitely. Foreign tax credit carryforwards, which expire in 2017 and 2018, total $248 million. The Corporation also has approximately $45 million of general business credits, substantially all of which expire between 2012 and 2025.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
In the consolidated balance sheet at December 31 deferred tax assets and liabilities from the preceding table are netted by taxing jurisdiction and are recorded in the following captions:

 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Other current assets	 	$	188	 	 	$	211	 	
Deferred income taxes (long-term asset)	 	 	2,292	 	 	 	1,873	 	
Accrued liabilities	 	 	(199	)	 	 	(27	)	
Deferred income taxes (long-term liability)	 	 	(2,241	)	 	 	(2,362	)	
 	 	 	 	 	 	 	 	 	
Net deferred tax assets (liabilities)	 	$	40	 	 	$	(305	)	

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

 	 	2008	 	2007	 	2006	
 	 	 	 	 	 	 	 	 	 	 	 	 	
United States statutory rate	 	 	35.0	%	 	 	35.0	%	 	 	35.0	%	
Effect of foreign operations	 	 	13.0	 	 	 	15.6	 	 	 	17.5	 	
State income taxes, net of Federal income tax	 	 	0.1	 	 	 	(2.6	)	 	 	0.3	 	
Other	 	 	1.7	 	 	 	2.5	 	 	 	(0.3	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	49.8	%	 	 	50.5	%	 	 	52.5	%	

 
Below is a reconciliation of the beginning and ending amount of unrecognized tax benefits (millions of dollars):

 	 	2008	 	 	2007	 	
 	 	 	 	 	 	 	 	 	
Balance at January 1	 	$	165	 	 	$	142	 	
Additions based on tax positions taken in the current year	 	 	16	 	 	 	38	 	
Additions based on tax positions of prior years	 	 	11	 	 	 	5	 	
Reductions based on tax positions of prior years	 	 	(15	)	 	 	—	 	
Reductions due to settlements with taxing authorities	 	 	(2	)	 	 	(20	)	
 	 	 	 	 	 	 	 	 	
Balance at December 31	 	$	175	 	 	$	165	 	

 
At December 31, 2008, the unrecognized tax benefits include $145 million which, if recognized, would affect the Corporation’s effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease by up to $30 million due to settlements with taxing authorities.
 
The Corporation has not recorded deferred income taxes applicable to undistributed earnings of foreign subsidiaries that are expected to be indefinitely reinvested in foreign operations. The Corporation had undistributed earnings from foreign subsidiaries of approximately $7.1 billion at December 31, 2008. If the earnings of foreign subsidiaries were not indefinitely reinvested, a deferred tax liability of approximately $2.5 billion would be required, excluding the potential use of foreign tax credits in the United States.
 
The Corporation and its subsidiaries file income tax returns in the United States and various foreign jurisdictions. The Corporation is no longer subject to examinations by income tax authorities in most jurisdictions for years prior to 2003.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Income taxes paid (net of refunds) in 2008, 2007, and 2006 amounted to $2,420 million, $1,826 million and $1,799 million, respectively. As of December 31, 2008, the Corporation had approximately $6 million of accrued interest and penalties.

12.  	Stockholders’ Equity and Net Income Per Share	
 
The weighted average number of common shares used in the basic and diluted earnings per share computations for each year is summarized below:

 	 	2008	 	2007	 	2006	
 	 	(Thousands of shares)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Common shares — basic	 	 	320,803	 	 	 	312,736	 	 	 	278,100	 	
Effect of dilutive securities	 	 	 	 	 	 	 	 	 	 	 	 	
Stock options	 	 	2,870	 	 	 	2,925	 	 	 	3,135	 	
Restricted common stock	 	 	1,815	 	 	 	3,066	 	 	 	2,776	 	
Convertible preferred stock	 	 	359	 	 	 	585	 	 	 	31,656	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Common shares — diluted	 	 	325,847	 	 	 	319,312	 	 	 	315,667	 	

 
The table above excludes the effect of out-of-the-money options on 425,000 shares, 715,000 shares, and 2,080,000 shares in 2008, 2007 and 2006, respectively.
 
During the third quarter of 2008, the Corporation’s remaining 284,139 outstanding shares of 3% cumulative convertible preferred shares were converted into common stock at a conversion rate of 1.8783 shares of common stock for each preferred share. The Corporation issued 533,697 shares of common stock for the conversion of these preferred shares and fractional shares were settled by cash payments.
 
On December 1, 2006, all of the Corporation’s 13,500,000 outstanding shares of 7% cumulative mandatory convertible preferred shares were converted into common stock at a conversion rate of 2.4915 shares of common stock for each preferred share. The Corporation issued 33,635,191 shares of common stock for the conversion of its 7% cumulative mandatory convertible preferred shares. Fractional shares were settled by cash payments.

13.  	Leased Assets	
 
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. Certain operating leases provide an option to purchase the related property at fixed prices. At December 31, 2008, future minimum rental payments applicable to non-cancelable operating leases with remaining terms of one year or more (other than oil and gas property leases) are as follows:

 	 	(Millions of dollars)	 	
 	 	 	 	 	
2009	 	$	551	 	
2010	 	 	422	 	
2011	 	 	303	 	
2012	 	 	316	 	
2013	 	 	322	 	
Remaining years	 	 	1,647	 	
 	 	 	 	 	
Total minimum lease payments	 	 	3,561	 	
Less: income from subleases	 	 	60	 	
 	 	 	 	 	
Net minimum lease payments	 	$	3,501	 	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Operating lease expenses for drilling rigs used to drill development wells and successful exploration wells are capitalized.
 
Rental expense was as follows:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total rental expense	 	$	270	 	 	$	266	 	 	$	198	 	
Less: income from subleases	 	 	12	 	 	 	13	 	 	 	15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net rental expense	 	$	258	 	 	$	253	 	 	$	183	 	

 
The Corporation accrued $30 million in 2006 for vacated leased office space in the United Kingdom. The related expenses are reflected principally in general and administrative expense in the income statement. The accrual balance was $16 million at December 31, 2008 and $31 million at December 31, 2007. Payments were $15 million in 2008 and $15 million in 2007.

14.  	Financial Instruments, Non-trading and Trading Activities	
 
Non-trading:  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. Hedging activities decreased Exploration and Production revenues by $685 million in 2008, $399 million in 2007 and $449 million in 2006. The amount of hedge ineffectiveness gains (losses) reflected in revenue in 2008, 2007 and 2006 was $(13) million, $6 million and $(5) million respectively.
 
In October 2008, the Corporation closed its Brent crude oil hedge positions by entering into offsetting contracts with the same counterparty covering 24,000 barrels per day from 2009 through 2012 at a per barrel price of $86.95 each year. The deferred after-tax losses related to the closed crude oil contracts will be recorded in earnings as the contracts mature. The estimated annual after-tax loss from the closed positions will be approximately $355 million from 2009 through 2012.
 
Accumulated other comprehensive income (loss) at December 31, 2008 includes after-tax deferred losses of $1,478 million ($1,672 at December 31, 2007) related to closed crude oil contracts and certain energy marketing contracts. Approximately $515 million of after-tax deferred losses is expected to be reclassified into earnings in 2009. 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.
 
Commodity Trading:  The Corporation, principally through a consolidated partnership, trades energy commodities, securities and derivatives including futures, forwards, options and swaps, based on expectations of future market conditions. The Corporation’s income (loss) before income taxes from trading activities, including its share of the earnings of the trading partnership, amounted to $(57) million in 2008, $49 million in 2007 and $83 million in 2006.
 
Other Financial Instruments:  At December 31, 2008, the Corporation has $896 million of notional value foreign currency forward contracts maturing through 2009 ($977 million at December 31, 2007). Notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts. The fair value of the foreign currency forward contracts recorded by the Corporation were payables of $75 million and $1 million at December 31, 2008 and December 31, 2007, respectively.
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The following table presents the fair values at December 31 of financial instruments and derivatives used in non-trading and trading activities:

 	 	2008	 	2007	
 	 	(Millions of dollars, asset (liability))	
 	 	 	 	 	 	 	 	 	
Futures and forwards	 	 	 	 	 	 	 	 	
Assets	 	$	1,047	 	 	$	431	 	
Liabilities	 	 	(314	)	 	 	(215	)	
Options	 	 	 	 	 	 	 	 	
Held	 	 	518	 	 	 	508	 	
Written	 	 	(637	)	 	 	(277	)	
Swaps	 	 	 	 	 	 	 	 	
Assets	 	 	1,488	 	 	 	473	 	
Liabilities (including hedging contracts)	 	 	(3,528	)	 	 	(3,377	)	

The carrying amounts of the Corporation’s financial instruments and derivatives, including those used in the Corporation’s non-trading and trading activities, generally approximate their fair values at December 31, 2008 and 2007, except fixed rate long-term debt which had a carrying value of $3,103 million and a fair value of $3,031 million at December 31, 2008 and a carrying value of $3,124 million and a fair value of $3,407 million at December 31, 2007.
 
The Corporation offsets cash collateral received or paid against the fair value of its derivative instruments executed with the same counterparty. At December 31, 2008 and 2007, the Corporation is holding cash from counterparties of approximately $705 million and $393 million, respectively. The Corporation has posted cash to counterparties at December 31, 2008 and 2007 of approximately $394 million and $380 million, respectively.
 
Credit Risks:  The Corporation’s financial instruments expose it to credit risks and may at times be concentrated with certain counterparties or groups of counterparties. Trade receivables in the Exploration and Production and Marketing and Refining businesses are generated from a diverse domestic and international customer base. The Corporation continuously monitors counterparty concentration and credit risk. The Corporation reduces its risk related to certain counterparties by using master netting agreements and requiring collateral, generally cash or letters of credit.

15.  	Fair Value Measurements	
 
The Corporation adopted the provisions of FAS 157 effective January 1, 2008 (see Note 1, “Summary of Significant Accounting Policies”). FAS 157 establishes a hierarchy for the inputs used to measure fair value based on the source of the input, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3). Multiple inputs may be used to measure fair value, however, the level of fair value for each financial asset or liability presented below is based on the lowest significant input level within this fair value hierarchy. The following table provides the fair value hierarchy of the Corporation’s financial assets and (liabilities) as of December 31, 2008 (in millions):

 	 	 	 	 	 	 	 	Collateral and
	 	 	
 	 	 	 	 	 	 	 	Counterparty
	 	 	
 	 	Level 1	 	Level 2	 	Level 3	 	Netting	 	Total	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Supplemental pension plan investments	 	$	55	 	 	$	—	 	 	$	10	 	 	$	—	 	 	$	65	 	
Derivative contracts	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets	 	 	449	 	 	 	1,795	 	 	 	695	 	 	 	(1,023	)	 	 	1,916	 	
Liabilities	 	 	(397	)	 	 	(3,413	)	 	 	(555	)	 	 	712	 	 	 	(3,653	)	
 
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Details on the methods and assumptions used to determine the fair values of the financial assets and liabilities are as follows:
 
Fair value measurements based on Level 1 inputs:  Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. The fair value of certain of the Corporation’s exchange traded futures and options are considered Level 1. In addition, fair values for the majority of the pension investments are considered Level 1, since they are determined using quotations from national securities exchanges.
 
Fair value measurements based on Level 2 inputs:  Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. The Corporation utilizes fair value measurements based on Level 2 inputs for certain forwards, swaps and options. The liability related to the Corporation’s crude oil hedges is classified as Level 2.
 
Fair value measurements based on Level 3 inputs:  Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. For example, in its energy marketing business, the Corporation sells natural gas and electricity to customers and offsets the price exposure by purchasing forward contracts. The fair value of these sales and purchases may be based on specific prices at less liquid delivered locations, which are classified as Level 3. There may be offsets to these positions that are priced based on more liquid markets, which are, therefore, classified as Level 1 or Level 2.
 
The following table provides changes in financial assets and liabilities that are measured at fair value based on Level 3 inputs (in millions):

 	 	Year Ended
	 	
 	 	December 31,
	 	
 	 	2008	 	
 	 	 	 	 	
Balance at January 1	 	$	(4	)	
Unrealized gains (losses)	 	 	 	 	
Included in earnings(*)	 	 	634	 	
Included in other comprehensive income	 	 	(351	)	
Purchases, sales or other settlements during the period	 	 	(37	)	
Net transfers in to (out of) Level 3	 	 	(93	)	
 	 	 	 	 	
Balance at December 31	 	$	149	 	

 
 	 	 	
* 	 	Reflected in Sales and other operating revenue	

16.  	Guarantees and Contingencies	
 
At December 31, 2008, the Corporation’s guarantees include $78 million of HOVENSA’s crude oil purchases and $15 million of HOVENSA’s senior debt obligations. In addition, the Corporation has $126 million in letters of credit for which it is contingently liable. As a result, the maximum potential amount of future payments that the Corporation could be required to make under its guarantees is $219 million at December 31, 2008 ($353 million at December 31, 2007). The Corporation also has a contingent purchase obligation expiring in April 2010, to acquire
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the remaining interest in WilcoHess, a retail gasoline station joint venture. As of December 31, 2008, the estimated value of the purchase obligation is approximately $175 million.
 
The Corporation is subject to loss contingencies with respect to various lawsuits, claims and other proceedings, including environmental matters. A liability is recognized in the Corporation’s consolidated financial statements when it is probable a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, the Corporation discloses the nature of those contingencies in accordance with FAS 5,  Accounting for Contingencies.
 
The Corporation, 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 similar 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 Corporation. While the majority of the cases were settled in 2008, the Corporation remains a defendant in approximately 20 cases. These cases have been consolidated for pre-trial purposes in the Southern District of New York as part of a multi-district litigation proceeding, with the exception of an action brought in state court by the State of New Hampshire. 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 almost all cases, punitive damages are also sought. In the fourth quarter 2007, the Corporation recorded a pre-tax charge of $40 million related to MTBE litigation, including amounts for the cases settled in 2008.
 
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 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 the Corporation and HOVENSA regarding the Petroleum Refinery Initiative in August 2003. Negotiations with EPA and the relevant states and the Virgin Islands are continuing and substantial progress has been made toward resolving this matter for both the Corporation and HOVENSA. While the effect on the Corporation of the Petroleum Refining Initiative cannot be estimated until a final settlement is reached and entered by a court, additional future capital expenditures and operating expenses will likely be incurred over a number of years. The amount of penalties, if any, is not expected to be material to the Corporation.
 
The United States Deep Water Royalty Relief Act of 1995 (the act) implemented a royalty relief program that relieves eligible leases issued between November 28, 1995 and November 28, 2000 from paying royalties on deep-water production in Federal Outer Continental Shelf lands. Some of the Corporation’s leases in the Gulf of Mexico qualify for royalty relief under the act. The act is silent on satisfying any price thresholds in order to qualify for the royalty relief. The U.S. Minerals Management Service (MMS) created regulations that included pricing requirements to qualify for the royalty relief provided in the act. The legality of the thresholds determined by the MMS has been challenged in federal courts. On January 12, 2009, the U.S. 5th Circuit Court of Appeals ruled against the MMS, which has until March 30, 2009 to seek a rehearing by the 5th Circuit Court and until April to seek
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leave to bring the matter before the U.S. Supreme Court. At December 31, 2008, the Corporation has accrued $114 million in liabilities and paid $15 million relating to these royalties.
 
The Corporation is also currently subject to certain other existing claims, lawsuits and proceedings, which it considers routine and incidental to its business. The Corporation believes that there is only a remote likelihood that future costs related to any of these other known contingent liability exposures would have a material adverse impact on its financial position or results of operations.

17.  	Segment Information	
 
The Corporation has two operating segments that comprise the structure used by senior management to make key operating decisions and assess performance. These are (1) Exploration and Production and (2) Marketing and Refining. Exploration and Production operations include the exploration for and the development, production, purchase, transportation and sale of crude oil and natural gas. Marketing and Refining operations include the manufacture, purchase, transportation, trading and marketing of refined petroleum products, natural gas and electricity.
 
The following table presents financial data by operating segment for each of the three years ended December 31, 2008:

 	 	Exploration
	 	 	Marketing
	 	 	Corporate
	 	 	 	 	
 	 	and Production	 	 	and Refining	 	 	and Interest	 	 	Consolidated(a)	 	
 	 	(Millions of dollars)	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues(b)	 	$	10,095	 	 	$	31,304	 	 	$	3	 	 	 	 	 	
Less: Transfers between affiliates	 	 	237	 	 	 	—	 	 	 	—	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues from unaffiliated customers	 	$	9,858	 	 	$	31,304	 	 	$	3	 	 	$	41,165	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	2,423	 	 	$	277	 	 	$	(340	)	 	$	2,360	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in income of HOVENSA L.L.C. 	 	$	—	 	 	$	44	 	 	$	—	 	 	$	44	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	267	 	 	 	267	 	
Depreciation, depletion and amortization	 	 	1,952	 	 	 	74	 	 	 	3	 	 	 	2,029	 	
Provision (benefit) for income taxes	 	 	2,365	 	 	 	162	 	 	 	(187	)	 	 	2,340	 	
Investments in affiliates	 	 	57	 	 	 	1,070	 	 	 	—	 	 	 	1,127	 	
Identifiable assets	 	 	19,506	 	 	 	6,680	 	 	 	2,403	 	 	 	28,589	 	
Capital employed(c)	 	 	12,936	 	 	 	3,103	 	 	 	223	 	 	 	16,262	 	
Capital expenditures	 	 	4,251	 	 	 	149	 	 	 	38	 	 	 	4,438	 	

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 	 	Exploration
	 	 	Marketing
	 	 	Corporate
	 	 	 	 	
 	 	and Production	 	 	and Refining	 	 	and Interest	 	 	Consolidated(a)	 	
 	 	(Millions of dollars)	 	
2007	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues(b)	 	$	7,933	 	 	$	23,913	 	 	$	2	 	 	 	 	 	
Less: Transfers between affiliates	 	 	201	 	 	 	—	 	 	 	—	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues from unaffiliated customers	 	$	7,732	 	 	$	23,913	 	 	$	2	 	 	$	31,647	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	1,842	 	 	$	300	 	 	$	(310	)	 	$	1,832	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in income of HOVENSA L.L.C. 	 	$	—	 	 	$	176	 	 	$	—	 	 	$	176	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	256	 	 	 	256	 	
Depreciation, depletion and amortization	 	 	1,503	 	 	 	68	 	 	 	5	 	 	 	1,576	 	
Provision (benefit) for income taxes	 	 	1,865	 	 	 	181	 	 	 	(174	)	 	 	1,872	 	
Investments in affiliates	 	 	57	 	 	 	1,060	 	 	 	—	 	 	 	1,117	 	
Identifiable assets	 	 	17,008	 	 	 	6,667	 	 	 	2,456	 	 	 	26,131	 	
Capital employed(c)	 	 	11,274	 	 	 	2,979	 	 	 	(499	)	 	 	13,754	 	
Capital expenditures	 	 	3,438	 	 	 	118	 	 	 	22	 	 	 	3,578	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues(b)	 	$	6,860	 	 	$	21,480	 	 	$	2	 	 	 	 	 	
Less: Transfers between affiliates	 	 	275	 	 	 	—	 	 	 	—	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues from unaffiliated customers	 	$	6,585	 	 	$	21,480	 	 	$	2	 	 	$	28,067	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	1,763	 	 	$	394	 	 	$	(237	)	 	$	1,920	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in income of HOVENSA L.L.C. 	 	$	—	 	 	$	201	 	 	$	—	 	 	$	201	 	
Interest expense	 	 	—	 	 	 	—	 	 	 	201	 	 	 	201	 	
Depreciation, depletion and amortization	 	 	1,159	 	 	 	61	 	 	 	4	 	 	 	1,224	 	
Provision (benefit) for income taxes	 	 	2,019	 	 	 	226	 	 	 	(119	)	 	 	2,126	 	
Investments in affiliates	 	 	57	 	 	 	1,186	 	 	 	—	 	 	 	1,243	 	
Identifiable assets	 	 	14,397	 	 	 	6,228	 	 	 	1,817	 	 	 	22,442	 	
Capital employed(c)	 	 	9,397	 	 	 	2,955	 	 	 	(433	)	 	 	11,919	 	
Capital expenditures	 	 	3,675	 	 	 	158	 	 	 	11	 	 	 	3,844	 	

 	 	 	
(a)	 	After elimination of transactions between affiliates, which are valued at approximate market prices.	
 	 	 	
(b)	 	Sales and operating revenues are reported net of excise and similar taxes in the consolidated statement of income, which amounted to approximately $2,200 million, $2,000 million and $1,900 million in 2008, 2007 and 2006, respectively.	
 	 	 	
(c)	 	Calculated as equity plus debt.	
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Financial information by major geographic area for each of the three years ended December 31, 2008:

 	 	 	 	 	 	 	 	 	 	 	Asia and
	 	 	 	 	
 	 	United States	 	 	Europe	 	 	Africa	 	 	Other	 	 	Consolidated	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	33,233	 	 	$	3,488	 	 	$	3,173	 	 	$	1,271	 	 	$	41,165	 	
Property, plant and equipment (net)	 	 	5,319	 	 	 	3,674	 	 	 	4,139	 	 	 	3,139	 	 	 	16,271	 	
2007	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	25,450	 	 	$	2,647	 	 	$	2,443	 	 	$	1,107	 	 	$	31,647	 	
Property, plant and equipment (net)	 	 	3,611	 	 	 	3,749	 	 	 	4,599	 	 	 	2,675	 	 	 	14,634	 	
2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues	 	$	22,599	 	 	$	3,108	 	 	$	1,677	 	 	$	683	 	 	$	28,067	 	
Property, plant and equipment (net)	 	 	2,402	 	 	 	3,255	 	 	 	4,495	 	 	 	2,156	 	 	 	12,308	 	

 	 	
18.  	Related Party Transactions	
 
Related party transactions for the year-ended December 31:

 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Purchases of petroleum products:	 	 	 	 	 	 	 	 	 	 	 	 	
HOVENSA*	 	$	6,589	 	 	$	5,238	 	 	$	4,694	 	
Sales of petroleum products and crude oil:	 	 	 	 	 	 	 	 	 	 	 	 	
WilcoHess	 	 	2,590	 	 	 	2,014	 	 	 	1,664	 	
HOVENSA	 	 	701	 	 	 	213	 	 	 	179	 	

 	 	 	
*	 	The Corporation has agreed to purchase 50% of HOVENSA’s production of refined products at market prices, after sales by HOVENSA to unaffiliated parties.	

19.  	Subsequent Event	
 
In February 2009, the Corporation issued $250 million of 5 year senior unsecured notes with a coupon of 7% and $1 billion of 10 year senior unsecured notes with a coupon of 8.125%. The majority of the proceeds were used to repay revolving credit debt and outstanding borrowings on other credit facilities. The remainder of the proceeds is available for working capital and other corporate purposes.
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SUPPLEMENTARY OIL AND GAS DATA
(Unaudited)
 
The supplementary oil and gas data that follows is presented in accordance with FAS 69, Disclosures about Oil and Gas Producing Activities , and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing activities, (2) net proved oil and gas reserves, and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves, including a reconciliation of changes therein.
 
The Corporation produces crude oil, natural gas liquids and/or natural gas principally in Algeria, Azerbaijan, Denmark, Equatorial Guinea, Gabon, Indonesia, Libya, Malaysia, Norway, Russia, Thailand, the United Kingdom and the United States. Exploration activities are also conducted, or are planned, in additional countries.
 
Costs Incurred in Oil and Gas Producing Activities

 	 	 	 	United
	 	 	 	 	 	Asia and
	
For the Years Ended December 31	 	Total	 	States	 	Europe	 	Africa	 	Other	
 	 	(Millions of dollars)	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property acquisitions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	684	 	 	$	642	 	 	$	—	 	 	$	—	 	 	$	42	 	
Proved*	 	 	300	 	 	 	87	 	 	 	—	 	 	 	210	 	 	 	3	 	
Exploration	 	 	1,134	 	 	 	408	 	 	 	121	 	 	 	275	 	 	 	330	 	
Production and development capital expenditures**	 	 	2,867	 	 	 	1,042	 	 	 	881	 	 	 	451	 	 	 	493	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2007	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property acquisitions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	325	 	 	$	316	 	 	$	—	 	 	$	1	 	 	$	8	 	
Proved*	 	 	137	 	 	 	137	 	 	 	—	 	 	 	—	 	 	 	—	 	
Exploration	 	 	719	 	 	 	421	 	 	 	65	 	 	 	77	 	 	 	156	 	
Production and development capital expenditures**	 	 	2,751	 	 	 	690	 	 	 	764	 	 	 	698	 	 	 	599	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property acquisitions	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	607	 	 	$	86	 	 	$	32	 	 	$	483	 	 	$	6	 	
Proved*	 	 	314	 	 	 	—	 	 	 	8	 	 	 	306	 	 	 	—	 	
Exploration	 	 	802	 	 	 	544	 	 	 	92	 	 	 	57	 	 	 	109	 	
Production and development capital expenditures**	 	 	2,462	 	 	 	329	 	 	 	644	 	 	 	1,080	 	 	 	409	 	

 	 	 	
*	 	Includes wells, equipment and facilities acquired with proved reserves.	
 	 	 	
**	 	Also includes $344 million, $146 million and $298 million in 2008, 2007 and 2006, respectively, related to the accruals for asset retirement obligations.	

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Capitalized Costs Relating to Oil and Gas Producing Activities

 	 	At December 31	 	
 	 	2008	 	 	2007	 	
 	 	(Millions of dollars)	 	
 	 	 	 	 	 	 	 	 	
Unproved properties	 	$	2,265	 	 	$	1,688	 	
Proved properties	 	 	3,009	 	 	 	3,350	 	
Wells, equipment and related facilities	 	 	20,058	 	 	 	17,865	 	
 	 	 	 	 	 	 	 	 	
Total costs	 	 	25,332	 	 	 	22,903	 	
Less: reserve for depreciation, depletion, amortization and lease impairment	 	 	10,269	 	 	 	9,373	 	
 	 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	15,063	 	 	$	13,530	 	

 
Results of Operations for Oil and Gas Producing Activities
 
The results of operations shown below exclude non-oil and gas producing activities, primarily gains on sales of oil and gas properties, interest expense and gains and losses resulting from foreign exchange transactions. Therefore, these results are on a different basis than the net income from Exploration and Production operations reported in management’s discussion and analysis of results of operations and in Note 17, “Segment Information,” in the notes to the financial statements.

 	 	 	 	 	United
	 	 	 	 	 	 	 	 	Asia and
	 	
For the Years Ended December 31	 	Total	 	 	States	 	 	Europe	 	 	Africa	 	 	Other	 	
 	 	(Millions of dollars)	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Sales and other operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unaffiliated customers	 	$	9,569	 	 	$	1,415	 	 	$	3,435	 	 	$	3,580	 	 	$	1,139	 	
Inter-company	 	 	237	 	 	 	237	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	9,806	 	 	 	1,652	 	 	 	3,435	 	 	 	3,580	 	 	 	1,139	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses, including related taxes(a)	 	 	1,872	 	 	 	373	 	 	 	811	 	 	 	465	 	 	 	223	 	
Exploration expenses, including dry holes and lease impairment	 	 	725	 	 	 	305	 	 	 	45	 	 	 	186	 	 	 	189	 	
General, administrative and other expenses	 	 	302	 	 	 	159	 	 	 	86	 	 	 	19	 	 	 	38	 	
Depreciation, depletion, amortization(b)	 	 	1,952	 	 	 	238	 	 	 	591	 	 	 	888	 	 	 	235	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	4,851	 	 	 	1,075	 	 	 	1,533	 	 	 	1,558	 	 	 	685	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations before income taxes	 	 	4,955	 	 	 	577	 	 	 	1,902	 	 	 	2,022	 	 	 	454	 	
Provision for income taxes	 	 	2,490	 	 	 	223	 	 	 	920	 	 	 	1,181	 	 	 	166	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	 	$	2,465	 	 	$	354	 	 	$	982	 	 	$	841	 	 	$	288	 	

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 	 	 	 	 	United
	 	 	 	 	 	 	 	 	Asia and
	 	
For the Years Ended December 31	 	Total	 	 	States	 	 	Europe	 	 	Africa	 	 	Other	 	
 	 	(Millions of dollars)	 	
2007	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Sales and other operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unaffiliated customers	 	$	7,297	 	 	$	1,010	 	 	$	2,670	 	 	$	2,609	 	 	$	1,008	 	
Inter-company	 	 	201	 	 	 	201	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	7,498	 	 	 	1,211	 	 	 	2,670	 	 	 	2,609	 	 	 	1,008	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses, including related taxes	 	 	1,581	 	 	 	280	 	 	 	723	 	 	 	381	 	 	 	197	 	
Exploration expenses, including dry holes and lease impairment	 	 	515	 	 	 	302	 	 	 	43	 	 	 	90	 	 	 	80	 	
General, administrative and other expenses	 	 	257	 	 	 	130	 	 	 	73	 	 	 	17	 	 	 	37	 	
Depreciation, depletion and amortization(c)	 	 	1,503	 	 	 	187	 	 	 	548	 	 	 	593	 	 	 	175	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	3,856	 	 	 	899	 	 	 	1,387	 	 	 	1,081	 	 	 	489	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations before income taxes	 	 	3,642	 	 	 	312	 	 	 	1,283	 	 	 	1,528	 	 	 	519	 	
Provision for income taxes	 	 	1,817	 	 	 	121	 	 	 	661	 	 	 	911	 	 	 	124	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	 	$	1,825	 	 	$	191	 	 	$	622	 	 	$	617	 	 	$	395	 	

2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Sales and other operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unaffiliated customers	 	$	6,249	 	 	$	957	 	 	$	3,052	 	 	$	1,637	 	 	$	603	 	
Inter-company	 	 	275	 	 	 	275	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	6,524	 	 	 	1,232	 	 	 	3,052	 	 	 	1,637	 	 	 	603	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses, including related taxes	 	 	1,250	 	 	 	221	 	 	 	631	 	 	 	284	 	 	 	114	 	
Exploration expenses, including dry holes and lease impairment	 	 	552	 	 	 	353	 	 	 	39	 	 	 	117	 	 	 	43	 	
General, administrative and other expenses(d)	 	 	209	 	 	 	95	 	 	 	74	 	 	 	15	 	 	 	25	 	
Depreciation, depletion and amortization	 	 	1,159	 	 	 	127	 	 	 	490	 	 	 	401	 	 	 	141	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	3,170	 	 	 	796	 	 	 	1,234	 	 	 	817	 	 	 	323	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations before income taxes	 	 	3,354	 	 	 	436	 	 	 	1,818	 	 	 	820	 	 	 	280	 	
Provision for income taxes	 	 	1,870	 	 	 	161	 	 	 	1,009	 	 	 	609	 	 	 	91	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	 	$	1,484	 	 	$	275	 	 	$	809	 	 	$	211	 	 	$	189	 	

 
 	 	 	
(a)	 	Includes $15 million ($9 million after income taxes) of Gulf of Mexico hurricane related costs.	
 	 	 	
(b)	 	Includes asset impairment charges of $30 million ($17 million after income taxes).	
 	 	 	
(c)	 	Includes asset impairment charges of $112 million ($56 million after income taxes).	
 	 	 	
(d)	 	Includes accrued costs for vacated office space of approximately $30 million ($18 million after income taxes).	
 
Oil and Gas Reserves
 
The Corporation’s oil and gas reserves are calculated in accordance with SEC regulations and interpretations and the requirements of the FASB. For reserves to be booked as proved they must be commercially producible; government approvals must be obtained and depending on the amount of the project cost, senior management or the board of directors, must commit to fund the project. The Corporation’s oil and gas reserve estimation and reporting process involves an annual independent third party reserve determination as well as internal technical appraisals of
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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 review.
 
On December 31, 2008, the Securities and Exchange Commission published a final rule which revises its oil and gas reserve estimation and disclosure requirements. The revisions are effective for filings on Form 10-K for fiscal year ending December 31, 2009. The Corporation is evaluating the impact of these requirements on its oil and gas reserve estimates and disclosures.
 
The oil and gas reserve estimates reported below are determined independently by the consulting firm of DeGolyer and MacNaughton (D&M) and are consistent with internal estimates. The Corporation provided 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 met to review and discuss the information provided. Senior management and the Board of Directors reviewed the final reserve estimates issued by D&M.

 	 	Crude Oil, Condensate and Natural Gas Liquids	 	Natural Gas	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Africa,
	 	 	
 	 	United
	 	 	 	 	 	Asia and
	 	 	 	United
	 	 	 	Asia and
	 	 	
 	 	States	 	Europe	 	Africa	 	Other	 	Total	 	States	 	Europe	 	Other	 	Total	
 	 	(Millions of barrels)	 	(Millions of mcf)	
Net Proved Developed and Undeveloped Reserves	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
At January 1, 2006	 	 	124	 	 	 	348	 	 	 	165	 	 	 	55	 	 	 	692	(c)	 	 	282	(d)	 	 	715	 	 	 	1,409	 	 	 	2,406	 	
Revisions of previous estimates(a)	 	 	7	 	 	 	21	 	 	 	39	 	 	 	(3	)	 	 	64	 	 	 	2	 	 	 	63	 	 	 	45	 	 	 	110	 	
Extensions, discoveries and other additions	 	 	45	 	 	 	11	 	 	 	6	 	 	 	2	 	 	 	64	 	 	 	32	 	 	 	11	 	 	 	168	 	 	 	211	 	
Improved recovery	 	 	—	 	 	 	—	 	 	 	4	 	 	 	—	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Purchases of minerals in place	 	 	—	 	 	 	2	 	 	 	121	 	 	 	—	 	 	 	123	 	 	 	—	 	 	 	—	 	 	 	15	 	 	 	15	 	
Sales of minerals in place	 	 	(21	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(21	)	 	 	(37	)	 	 	—	 	 	 	—	 	 	 	(37	)	
Production	 	 	(17	)	 	 	(42	)	 	 	(31	)	 	 	(4	)	 	 	(94	)	 	 	(43	)	 	 	(112	)	 	 	(84	)	 	 	(239	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
At December 31, 2006	 	 	138	 	 	 	340	 	 	 	304	 	 	 	50	 	 	 	832	(c)	 	 	236	(d)	 	 	677	 	 	 	1,553	 	 	 	2,466	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revisions of previous estimates(a)	 	 	37	 	 	 	17	 	 	 	17	 	 	 	1	 	 	 	72	 	 	 	32	 	 	 	73	 	 	 	143	 	 	 	248	 	
Extensions, discoveries and other additions	 	 	17	 	 	 	14	 	 	 	6	 	 	 	23	 	 	 	60	 	 	 	26	 	 	 	11	 	 	 	148	 	 	 	185	 	
Improved recovery	 	 	22	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	22	 	 	 	13	 	 	 	—	 	 	 	—	 	 	 	13	 	
Purchases of minerals in place	 	 	5	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	5	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	1	 	
Sales of minerals in place	 	 	—	 	 	 	(6	)	 	 	—	 	 	 	—	 	 	 	(6	)	 	 	—	 	 	 	(4	)	 	 	—	 	 	 	(4	)	
Production	 	 	(15	)	 	 	(36	)	 	 	(42	)	 	 	(7	)	 	 	(100	)	 	 	(38	)	 	 	(101	)	 	 	(102	)	 	 	(241	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
At December 31, 2007	 	 	204	 	 	 	329	 	 	 	285	 	 	 	67	 	 	 	885	(c)	 	 	270	(d)	 	 	656	 	 	 	1,742	 	 	 	2,668	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revisions of previous estimates(a)	 	 	9	 	 	 	30	 	 	 	83	 	 	 	25	 	 	 	147	 	 	 	22	 	 	 	84	 	 	 	188	 	 	 	294	 	
Extensions, discoveries and other additions	 	 	26	 	 	 	5	 	 	 	1	 	 	 	—	 	 	 	32	 	 	 	18	 	 	 	—	 	 	 	65	 	 	 	83	 	
Improved recovery	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Purchases of minerals in place	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Sales of minerals in place	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Production	 	 	(15	)	 	 	(32	)	 	 	(45	)	 	 	(5	)	 	 	(97	)	 	 	(34	)	 	 	(101	)	 	 	(137	)	 	 	(272	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
At December 31, 2008(b)	 	 	227	 	 	 	332	 	 	 	324	 	 	 	87	 	 	 	970	(c)	 	 	276	(d)	 	 	639	 	 	 	1,858	 	 	 	2,773	 	

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 	 	Crude Oil, Condensate and Natural Gas Liquids	 	Natural Gas	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Africa,
	 	 	
 	 	United
	 	 	 	 	 	Asia and
	 	 	 	United
	 	 	 	Asia and
	 	 	
 	 	States	 	Europe	 	Africa	 	Other	 	Total	 	States	 	Europe	 	Other	 	Total	
 	 	(Millions of barrels)	 	(Millions of mcf)	
Net Proved Developed Reserves	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
At January 1, 2006	 	 	108	 	 	 	233	 	 	 	67	 	 	 	13	 	 	 	421	 	 	 	251	 	 	 	559	 	 	 	496	 	 	 	1,306	 	
At December 31, 2006	 	 	90	 	 	 	223	 	 	 	194	 	 	 	19	 	 	 	526	 	 	 	195	 	 	 	517	 	 	 	585	 	 	 	1,297	 	
At December 31, 2007	 	 	101	 	 	 	201	 	 	 	201	 	 	 	15	 	 	 	518	 	 	 	199	 	 	 	519	 	 	 	654	 	 	 	1,372	 	
At December 31, 2008	 	 	119	 	 	 	192	 	 	 	237	 	 	 	23	 	 	 	571	 	 	 	202	 	 	 	502	 	 	 	727	 	 	 	1,431	 	

 	 	 	
(a)	 	Includes the impact of changes in selling prices on production sharing contracts with cost recovery provisions and stipulated rates of return. In 2008, revisions included increases of approximately 59 million barrels of crude oil and 104 million mcf of natural gas, relating to lower selling prices. In 2007 revisions included reductions of approximately 29 million barrels of crude oil and 104 million mcf of natural gas, relating to higher selling prices. In 2006 this amount was immaterial for both oil and natural gas	
 	 	 	
(b)	 	Includes 28% of crude oil reserves and 58% of natural gas reserves held under production sharing contracts. These reserves are located outside of the United States and are subject to different political and economic risks.	
 	 	 	
(c)	 	Includes 16 million barrels in 2008, 20 million barrels in 2007 and 23 million barrels in 2006 of crude oil reserves relating to minority interest owners of corporate joint ventures.	
 	 	 	
(d)	 	Excludes approximately 400 million mcf of carbon dioxide gas for sale or use in company operations.	
 
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
Future net cash flows are calculated by applying year-end oil and gas selling prices (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future development and production costs, which are based on year-end costs and existing economic assumptions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the pre-tax net cash flows relating to the Corporation’s proved oil and gas reserves. Future net cash flows are discounted at the prescribed rate of 10%. The discounted future net cash flow estimates required by FAS 69 do not include exploration expenses, interest expense or corporate general and administrative expenses. The selling prices of crude oil and natural gas are highly volatile. The year-end prices, which are required to be used for the discounted future net cash flows, do not include the effects of hedges and may not be representative of future selling prices. The future net cash flow estimates could be materially different if other assumptions were used.

 	 	 	 	 	United
	 	 	 	 	 	 	 	 	Asia and
	 	
At December 31	 	Total	 	 	States	 	 	Europe	 	 	Africa	 	 	Other	 	
 	 	(Millions of dollars)	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future revenues	 	$	46,846	 	 	$	9,801	 	 	$	15,757	 	 	$	12,332	 	 	$	8,956	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Less:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future production costs	 	 	15,884	 	 	 	3,422	 	 	 	5,998	 	 	 	3,763	 	 	 	2,701	 	
Future development costs	 	 	10,649	 	 	 	1,983	 	 	 	4,014	 	 	 	1,781	 	 	 	2,871	 	
Future income tax expenses	 	 	9,299	 	 	 	1,467	 	 	 	2,741	 	 	 	4,440	 	 	 	651	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	35,832	 	 	 	6,872	 	 	 	12,753	 	 	 	9,984	 	 	 	6,223	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flows	 	 	11,014	 	 	 	2,929	 	 	 	3,004	 	 	 	2,348	 	 	 	2,733	 	
Less: discount at 10% annual rate	 	 	4,050	 	 	 	1,602	 	 	 	984	 	 	 	493	 	 	 	971	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	6,964	 	 	$	1,327	 	 	$	2,020	 	 	$	1,855	 	 	$	1,762	 	

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 	 	 	 	 	United
	 	 	 	 	 	 	 	 	Asia and
	 	
At December 31	 	Total	 	 	States	 	 	Europe	 	 	Africa	 	 	Other	 	
 	 	(Millions of dollars)	 	
2007	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future revenues	 	$	94,955	 	 	$	18,876	 	 	$	32,778	 	 	$	28,960	 	 	$	14,341	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Less:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future production costs	 	 	17,862	 	 	 	2,733	 	 	 	7,569	 	 	 	4,770	 	 	 	2,790	 	
Future development costs	 	 	10,118	 	 	 	1,472	 	 	 	4,329	 	 	 	1,640	 	 	 	2,677	 	
Future income tax expenses	 	 	33,833	 	 	 	5,291	 	 	 	12,083	 	 	 	14,309	 	 	 	2,150	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	61,813	 	 	 	9,496	 	 	 	23,981	 	 	 	20,719	 	 	 	7,617	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flows	 	 	33,142	 	 	 	9,380	 	 	 	8,797	 	 	 	8,241	 	 	 	6,724	 	
Less: discount at 10% annual rate	 	 	11,237	 	 	 	3,792	 	 	 	2,826	 	 	 	2,155	 	 	 	2,464	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	21,905	 	 	$	5,588	 	 	$	5,971	 	 	$	6,086	 	 	$	4,260	 	

2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future revenues	 	$	55,252	 	 	$	8,686	 	 	$	19,751	 	 	$	18,480	 	 	$	8,335	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Less:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future production costs	 	 	13,312	 	 	 	1,376	 	 	 	6,482	 	 	 	3,783	 	 	 	1,671	 	
Future development costs	 	 	7,043	 	 	 	722	 	 	 	2,916	 	 	 	1,846	 	 	 	1,559	 	
Future income tax expenses	 	 	16,765	 	 	 	2,331	 	 	 	5,625	 	 	 	7,908	 	 	 	901	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	37,120	 	 	 	4,429	 	 	 	15,023	 	 	 	13,537	 	 	 	4,131	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flows	 	 	18,132	 	 	 	4,257	 	 	 	4,728	 	 	 	4,943	 	 	 	4,204	 	
Less: discount at 10% annual rate	 	 	5,771	 	 	 	1,423	 	 	 	1,358	 	 	 	1,322	 	 	 	1,668	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows	 	$	12,361	 	 	$	2,834	 	 	$	3,370	 	 	$	3,621	 	 	$	2,536	 	

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

For the Years Ended December 31	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions of dollars)	 	
Standardized measure of discounted future net cash flows at beginning of year	 	$	21,905	 	 	$	12,361	 	 	$	14,489	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Changes during the year	 	 	 	 	 	 	 	 	 	 	 	 	
Sales and transfers of oil and gas produced during year, net of production costs	 	 	(7,934	)	 	 	(5,917	)	 	 	(5,274	)	
Development costs incurred during year	 	 	2,523	 	 	 	2,605	 	 	 	2,164	 	
Net changes in prices and production costs applicable to future production	 	 	(28,627	)	 	 	18,646	 	 	 	(4,329	)	
Net change in estimated future development costs	 	 	(1,056	)	 	 	(2,554	)	 	 	(2,402	)	
Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs	 	 	334	 	 	 	3,173	 	 	 	1,937	 	
Revisions of previous oil and gas reserve estimates	 	 	1,730	 	 	 	4,036	 	 	 	1,235	 	
Net purchases (sales) of minerals in place, before income taxes	 	 	18	 	 	 	(50	)	 	 	2,937	 	
Accretion of discount	 	 	4,109	 	 	 	2,233	 	 	 	2,308	 	
Net change in income taxes	 	 	13,859	 	 	 	(9,259	)	 	 	(1,381	)	
Revision in rate or timing of future production and other changes	 	 	103	 	 	 	(3,369	)	 	 	677	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	(14,941	)	 	 	9,544	 	 	 	(2,128	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows at end of year	 	$	6,964	 	 	$	21,905	 	 	$	12,361	 	

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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
 
QUARTERLY FINANCIAL DATA
(Unaudited)
 
Quarterly results of operations for the years ended December 31:

 	 	Sales and
	 	 	 	 	 	 	
 	 	Other
	 	 	 	 	 	Diluted Net
	
 	 	Operating
	 	Gross
	 	Net
	 	Income (Loss)
	
 	 	Revenues	 	Profit(a)	 	Income (Loss)	 	per Share	
 	 	(Million of dollars, except per share data)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First	 	$	10,667	 	 	$	1,795	 	 	$	759	 	 	$	2.34	 	
Second	 	 	11,717	 	 	 	2,073	 	 	 	900	 	 	 	2.76	 	
Third	 	 	11,398	 	 	 	1,905	 	 	 	775	 	 	 	2.37	 	
Fourth	 	 	7,383	 	 	 	662	 	 	 	(74	)(b)	 	 	(.23	)	
2007	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First	 	$	7,319	 	 	$	980	 	 	$	370	 	 	$	1.17	 	
Second	 	 	7,421	 	 	 	1,222	 	 	 	557	(c)	 	 	1.75	 	
Third	 	 	7,451	 	 	 	1,087	 	 	 	395	(d)	 	 	1.23	 	
Fourth	 	 	9,456	 	 	 	1,523	 	 	 	510	(e)	 	 	1.59	 	

 	 	 	
(a)	 	Gross profit represents sales and other operating revenues, less cost of products sold, production expenses, marketing expenses, other operating expenses and depreciation, depletion and amortization.	
 	 	 	
(b)	 	Includes after-tax charges of $17 million related to asset impairments in the United States and United Kingdom North Sea and $9 million associated with Hurricanes Gustav and Ike in the Gulf of Mexico.	
 	 	 	
(c)	 	Includes after-tax income of $15 million from asset sales in the United Kingdom North Sea.	
 	 	 	
(d)	 	Includes after-tax charges of $33 million from estimated production imbalance settlements at two offshore fields.	
 	 	 	
(e)	 	Includes net after-tax expense of $57 million related to asset impairments at two mature fields in the United Kingdom North Sea and a charge related to MTBE litigation, partially offset by income due to the liquidation of prior year LIFO inventories.	
 
The results of operations for the periods reported herein should not be considered as indicative of future operating results.
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Item 9.  	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	
 
None.

Item 9A.  	Controls and Procedures	
 
Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2008, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of December 31, 2008.
 
There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect, internal controls over financial reporting.
 
Management’s report on internal control over financial reporting and the attestation report on management’s assessment are included in Item 8 of this annual report on Form 10-K.

Item 9B.  	Other Information	
 
None.
 
PART III

Item 10.  	Directors, Executive Officers and Corporate Governance	
 
Information relating to Directors is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 6, 2009.
 
Information regarding executive officers is included in Part I hereof.
 
The Corporation has adopted a Code of Business Conduct and Ethics applicable to the Corporation’s directors, officers (including the Corporation’s principal executive officer and principal financial officer) and employees. The Code of Business Conduct and Ethics is available on the Corporation’s website. In the event that we amend or waive any of the provisions of the Code of Business Conduct and Ethics that relate to any element of the code of ethics definition enumerated in Item 406(b) of Regulation S-K, we intend to disclose the same on the Corporation’s website at www.hess.com.
 
Information relating to the audit committee is incorporated herein by reference to “Election of Directors” from the registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 6, 2009.

Item 11.  	Executive Compensation	
 
Information relating to executive compensation is incorporated herein by reference to “Election of Directors — Executive Compensation and Other Information,” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 6, 2009.

Item 12.  	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	
 
Information pertaining to security ownership of certain beneficial owners and management is incorporated herein by reference to “Election of Directors — Ownership of Voting Securities by Certain Beneficial Owners” and “Election of Directors — Ownership of Equity Securities by Management” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 6, 2009.
 
See “Equity Compensation Plans” in Item 5 for information pertaining to securities authorized for issuance under equity compensation plans.
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Item 13.  	Certain Relationships and Related Transactions, and Director Independence	
 
Information relating to this item is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 6, 2009.

Item 14.  	Principal Accounting Fees and Services	
 
Information relating to this item is incorporated by reference to “Ratification of Selection of Independent Auditors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 6, 2009.
 
PART IV

Item 15.  	Exhibits, Financial Statement Schedules	

(a)  	1. and 2. Financial statements and financial statement schedules	
 
The financial statements filed as part of this Annual Report on Form 10-K are listed in the accompanying index to financial statements and schedules in Item 8, “Financial Statements and Supplementary Data.”

3.  	Exhibits	

 	3(1)	 	 	Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 2006 incorporated by reference to Exhibit 3 of Registrant’s Form 10-Q for the three months ended June 30, 2006.	
 	3(2)	 	 	By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002.	
 	4(1)	 	 	Certificate of designations, preferences and rights of 3% cumulative convertible preferred stock of Registrant incorporated by reference to Exhibit 4 of Form 10-Q of Registrant for the three months ended June 30, 2000.	
 	4(2)	 	 	Five-Year Credit Agreement dated as of December 10, 2004, as amended and restated as of May 12, 2006, among Registrant, certain subsidiaries of Registrant, J.P. Morgan Chase Bank, N.A. as lender and administrative agent, and the other lenders party thereto, incorporated by reference to Exhibit(4) of Form 10-Q of Registrant for the three months ended June 30, 2006.	
 	4(3)	 	 	Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.	
 	4(4)	 	 	First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.	
 	4(5)	 	 	Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.	
 	4(6)	 	 	Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.	
 	4(7)	 	 	Indenture dated as of March 1, 2006 between Registrant and The Bank of New York Mellon as successor to JP Morgan Chase, as Trustee, including form of Note. Incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed with the Securities and Exchange Commission on March 1, 2006.	

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 	4(8)	 	 	Form of 2014 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase as Trustee. Incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.	
 	4(9)	 	 	Form of 2019 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase, as Trustee. Incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.	
 	10(1)	 	 	Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981.	
 	10(2)	 	 	Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990.	
 	10(3)	 	 	Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993.	
 	10(4)	 	 	Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998.	
 	10(5)	*	 	Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on February 10, 2009.	
 	10(6)	*	 	Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.	
 	10(7)	*	 	Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006.	
 	10(8)	*	 	Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) of Form 10-Q of Registrant for the three months ended June 30, 2006.	
 	10(9)	*	 	Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.	
 	10(10)	*	 	Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006.	
 	10(11)	*	 	Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.	
 	10(12)	*	 	Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.	
 	10(13)	*	 	2008 Long Term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008.	
 	10(14)	*	 	Forms of Awards under Registrant’s 2008 Long Term Incentive Plan, incorporated by reference to Exhibit 10(2) of Form 10-Q of Registrant for three months ended June 30, 2008.	
 	10(15)	*	 	Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2007.	
 	10(16)	*	 	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and J. Barclay Collins, John J. O’Connor and F. Borden Walker.	
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 	10(17)	*	 	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (other than the named executive officers referred to in Exhibit 10(15)).	
 	10(18)	*	 	Letter Agreement dated March 18, 2002 between Registrant and John J. O’Connor relating to Mr. O’Connor’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(15) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.	
 	10(19)	*	 	Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.	
 	10(20)	*	 	Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Form 8-K of Registrant filed January 7, 2009.	
 	10(21)	*	 	Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.	
 	10(22)	 	 	Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998.	
 	10(23)	 	 	Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998.	
 	21	 	 	Subsidiaries of Registrant.	
 	23	 	 	Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 20, 2009, to the incorporation by reference in Registrant’s Registration Statements (Form S-3 No. 333-132145, and Form S-8 Nos. 333-43569, 333-94851, 333-115844 and 333-150992), of its reports relating to Registrant’s financial statements, which consent appears on page 88 herein.	
 	31(1)	 	 	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a)
(17 CFR 240.15d-14(a)).	
 	31(2)	 	 	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).	
 	32(1)	 	 	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b)
(17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code
(18 U.S.C. 1350).	
 	32(2)	 	 	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b)
(17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code
(18 U.S.C. 1350).	

 	 	 	
*	 	These exhibits relate to executive compensation plans and arrangements.	

(b)  	Reports on Form 8-K	
 
During the three months ended December 31, 2008, Registrant filed or furnished the following report on Form 8-K:
 
1. Filing dated October 29, 2008 reporting under Items 2.02 and 9.01, a news release dated October 29, 2008 reporting results for the third quarter of 2008.
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SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 23rd day of February 2009.
 
HESS CORPORATION
     (Registrant)

 	By 	/s/  JOHN P. RIELLY	
(John P. Rielly)
Senior Vice President and
Chief Financial Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	 	Title	 	Date	
 	 	 	 	 	 	 	
/s/  JOHN B. HESS

John B. Hess	 	Director, Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)	 	February 23, 2009	
 	 	 	 	 	
/s/  NICHOLAS F. BRADY

Nicholas F. Brady	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  J. BARCLAY COLLINS II

J. Barclay Collins II	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  EDITH E. HOLIDAY

Edith E. Holiday	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  THOMAS H. KEAN

Thomas H. Kean	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  DR. RISA LAVIZZO-MOUREY

Dr. Risa Lavizzo-Mourey	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  CRAIG G. MATTHEWS

Craig G. Matthews	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  JOHN H. MULLIN

John H. Mullin	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  JOHN J. O’CONNOR

John J. O’Connor	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  FRANK A. OLSON

Frank A. Olson	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  JOHN P. RIELLY

John P. Rielly	 	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	 	February 23, 2009	
 	 	 	 	 	
/s/  ERNST H. VON METZSCH

Ernst H. von Metzsch	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  F. BORDEN WALKER

F. Borden Walker	 	Director	 	February 23, 2009	
 	 	 	 	 	
/s/  ROBERT N. WILSON

Robert N. Wilson	 	Director	 	February 23, 2009	

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Consent of Independent Registered Public Accounting Firm
 
We consent to the incorporation by reference in the following Registration Statements:
 
(1) Registration Statement (Form S-3 No. 333-132145) of Hess Corporation,
 
(2) Registration Statement (Form S-8 No. 333-43569) pertaining to the Hess Corporation Employees’ Savings Plan,
 
(3) Registration Statement (Form S-8 No. 333-94851), pertaining to the Hess Corporation Amended and Restated 1995 Long-Term Incentive Plan
 
(4) Registration Statement (Form S-8 No. 333-115844) pertaining to the Hess Corporation Second Amended and Restated 1995 Long-Term Incentive Plan, and
 
(5) Registration Statement (Form S-8 No. 333-150992) pertaining to the Hess Corporation 2008 Long-Term Incentive Plan;
 
of our reports dated February 20, 2009, with respect to the consolidated financial statements and schedule of Hess Corporation and consolidated subsidiaries and with respect to the effectiveness of internal control over financial reporting of Hess Corporation, included in this Annual Report (Form 10-K) for the year ended December 31, 2008.

 
New York, New York
February 20, 2009
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Schedule II
 
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS
 
For the Years Ended December 31, 2008, 2007 and 2006

 	 	 	 	 	Additions	 	 	 	 	 	 	 	
 	 	 	 	 	Charged
	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	to Costs
	 	 	Charged
	 	 	Deductions
	 	 	 	 	
 	 	Balance
	 	 	and
	 	 	to Other
	 	 	from
	 	 	Balance
	 	
Description	 	January 1	 	 	Expenses	 	 	Accounts	 	 	Reserves	 	 	December 31	 	
 	 	(In millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Losses on receivables	 	$	41	 	 	$	9	 	 	$	—	 	 	$	4	 	 	$	46	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2007	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Losses on receivables	 	$	39	 	 	$	5	 	 	$	—	 	 	$	3	 	 	$	41	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Losses on receivables	 	$	30	 	 	$	14	 	 	$	—	 	 	$	5	 	 	$	39	 	

89

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EXHIBIT INDEX

 	3(1)	 	 	Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 2006 incorporated by reference to Exhibit(3) of Registrant’s Form 10-Q for the three months ended June 30, 2006.	
 	3(2)	 	 	By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002.	
 	4(1)	 	 	Certificate of designations, preferences and rights of 3% cumulative convertible preferred stock of Registrant incorporated by reference to Exhibit 4 of Form 10-Q of Registrant for the three months ended June 30, 2000.	
 	4(2)	 	 	Five-Year Credit Agreement dated as of December 10, 2004, as amended and restated as of May 12, 2006, among Registrant, certain subsidiaries of Registrant, J.P. Morgan Chase Bank, N.A. as lender and administrative agent, and the other lenders party thereto, incorporated by reference to Exhibit(4) of Form 10-Q of Registrant for the three months ended June 30, 2006.	
 	4(3)	 	 	Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.	
 	4(4)	 	 	First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 7 3 / 8 % Notes due 2009 and 7 7 / 8 % Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.	
 	4(5)	 	 	Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.	
 	4(6)	 	 	Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002.	
 	 	 	 	Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.	
 	4(7)	 	 	Indenture dated as of March 1, 2006 between Registrant and The Bank of New York Mellon as successor to JP Morgan Chase, as Trustee, including form of Note. Incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed with the Securities and Exchange Commission on March 1, 2006.	
 	4(8)	 	 	Form of 2014 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase as Trustee. Incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.	
 	4(9)	 	 	Form of 2019 Note issued pursuant to Indenture, dated as of March 1, 2006, among Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase, as Trustee. Incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed with the Securities and Exchange Commission on February 4, 2009.	
 	10(1)	 	 	Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981.	
 	10(2)	 	 	Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990.	
 	10(3)	 	 	Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993.	

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 	10(4)	 	 	Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998.	
 	10(5)	*	 	Incentive Cash Bonus Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on February 10, 2009.	
 	10(6)	*	 	Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.	
 	10(7)	*	 	Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for fiscal year ended December 31, 2006.	
 	10(8)	*	 	Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) of Form 10-Q of Registrant for the three months ended June 30, 2006.	
 	10(9)	*	 	Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.	
 	10(10)	*	 	Amendment dated December 31, 2006 to Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(10) of Form 10-K of Registrant for fiscal year ended December 31, 2006.	
 	10(11)	*	 	Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.	
 	10(12)	*	 	Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.	
 	10(13)	*	 	2008 Long Term Incentive Plan, incorporated by reference to Annex B to Registrant’s definitive proxy statement filed on March 27, 2008.	
 	10(14)	*	 	Forms of Awards under Registrant’s 2008 Long Term Incentive Plan, incorporated by reference to Exhibit 10(2) of Form 10-Q of Registrant for three months ended June 30, 2008.	
 	10(15)	*	 	Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2007.	
 	10(16)	*	 	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and J. Barclay Collins, John J. O’Connor and F. Borden Walker.	
 	10(17)	*	 	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (other than the named executive officers referred to in Exhibit 10(15)).	
 	10(18)	*	 	Letter Agreement dated March 18, 2002 between Registrant and John J. O’Connor relating to Mr. O’Connor’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(15) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.	
 	10(19)	*	 	Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.	
 	10(20)	*	 	Agreement between Registrant and Gregory P. Hill relating to his compensation and other terms of employment, incorporated by reference to Form 8-K of Registrant filed January 7, 2009.	
 	10(21)	*	 	Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.	
 	10(22)	 	 	Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998.	
 	10(23)	 	 	Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998.	

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 	21	 	 	Subsidiaries of Registrant.	
 	23	 	 	Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 20, 2009, to the incorporation by reference in Registrant’s Registration Statements (Form S-3 No. 333-132145, and Form S-8 Nos. 333-43569, 333-94851, 333-115844 and 333-150992), of its reports relating to Registrant’s financial statements, which consent appears on page 88 herein.	
 	31(1)	 	 	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a)
(17 CFR 240.15d-14(a)).	
 	31(2)	 	 	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a)
(17 CFR 240.15d-14(a)).	
 	32(1)	 	 	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b)
(17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code
(18 U.S.C. 1350).	
 	32(2)	 	 	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b)
(17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code
(18 U.S.C. 1350).	

 	 	 	
*	 	These exhibits relate to executive compensation plans and arrangements.	

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

Exhibit 31(1)
 
I, John B. Hess, certify that:
 
1. I have reviewed this annual report on Form 10-K of Hess Corporation;
 
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
 
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 	By 	/s/  John B. Hess

John B. Hess
Chairman of the Board and
Chief Executive Officer	
 
Date: February 20, 2009

Exhibit 31(2)
 
I, John P. Rielly, certify that:
 
1. I have reviewed this annual report on Form 10-K of Hess Corporation;
 
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
 
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
 
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 	By 	/s/  John P. Rielly	
John P. Rielly
Senior Vice President and
Chief Financial Officer
 
Date: February 20, 2009

Exhibit 32(1)
 
CERTIFICATION PURSUANT TO
 
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Annual Report of Hess Corporation (the Corporation) on Form 10-K for the period ending December 31, 2008 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, John B. Hess, Chairman of the Board and Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
 
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
 
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

 	By 	/s/  John B. Hess	
John B. Hess
Chairman of the Board and
Chief Executive Officer
 
Date: February 20, 2009

Exhibit 32(2)
 
CERTIFICATION PURSUANT TO
 
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Annual Report of Hess Corporation (the Corporation) on Form 10-K for the period ending December 31, 2008 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, John P. Rielly, Senior Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
 
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
 
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

 	By 	/s/  John P. Rielly	
John P. Rielly
Senior Vice President and
Chief Financial Officer
 
Date: February 20, 2009