Hess 10K 2006 Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2006
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to

Commission File Number 1-1204

Hess Corporation

(Exact name of Registrant as specified in its charter)


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

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

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


Title of Each Class		Name of Each Exchange on Which Registered

Common Stock (par value $1.00)		New York Stock Exchange

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation 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 thisForm 10-K or any amendment to thisForm 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 12b-2 of the Exchange Act. Large accelerated filerþ Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $12,765,000,000 as of June 30, 2006.

At December 31, 2006, there were 315,017,951 shares of Common Stock outstanding.

Part III is incorporated by reference from the Proxy Statement for the annual meeting of stockholders to be held on May 2, 2007.

HESS CORPORATION

Form 10-K

TABLE OF CONTENTS


Item No.		Page

PART I
1. and 2.	Business and Properties		2
1A.	Risk Factors Related to Our Business and Operations		10
3.	Legal Proceedings		12
4.	Submission of Matters to a Vote of Security Holders		15
	Executive Officers of the Registrant		15

PART II
5.	Market for the Registrant’s Common Stock and Related Stockholder Matters		16
6.	Selected Financial Data		19
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
7A.	Quantitative and Qualitative Disclosures About Market Risk		38
8.	Financial Statements and Supplementary Data		42
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		85
9A.	Controls and Procedures		85
9B.	Other Information		85

PART III
10.	Directors, Executive Officers and Corporate Governance of the Registrant		85
11.	Executive Compensation		85
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		85
13.	Certain Relationships and Related Transactions, and Director Independence		85
14.	Principal Accounting Fees and Services		86

PART IV
15.	Exhibits, Financial Statement Schedules, and Reports onForm 8-K		86
	Signatures		89
EX-10.7: SAVINGS AND STOCK BONUS PLAN
EX-10.10: AMENDED PENSION RESTORATION PLAN
EX-21: SUBSIDIARIES
EX-31.1: CERTIFICATION
EX-31.2: CERTIFICATION
EX-32.1: CERTIFICATION
EX-32.2: CERTIFICATION

PART I

Items 1 and 2. Business and Properties

Hess Corporation (formerly Amerada Hess Corporation) (the Registrant) is a Delaware corporation, incorporated in 1920. On May 3, 2006, Amerada Hess Corporation changed its name to Hess Corporation. The Registrant and its subsidiaries (collectively referred to as the “Corporation” or “Hess”) is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. These exploration and production activities take place in the United States, United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Malaysia, Thailand, Russia, Gabon, Azerbaijan, Indonesia, Libya, Egypt, and other countries. The M&R segment manufactures, purchases, transports, trades and markets refined petroleum products, natural gas and electricity. The Corporation owns 50% of a refinery joint venture in the United States Virgin Islands, and another refining facility, terminals and retail gasoline stations, most of which include convenience stores, located on the East Coast of the United States.

Exploration and Production

The Corporation’s total proved reserves at December 31 were as follows:


	2006		2005

Crude oil and natural gas liquids (millions of barrels)		832		692
Natural gas (millions of mcf)		2,466		2,406
Total barrels of oil equivalent* (millions of barrels)		1,243		1,093


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

Of the total proved reserves (on a barrel of oil equivalent basis), 14% are located in the United States, 36% are located in Europe (consisting of reserves in the North Sea and Russia), 25% are located in Africa and the remainder are located in Indonesia, Thailand, Malaysia, and Azerbaijan. On a barrel of oil equivalent basis, 40% of the Corporation’s December 31, 2006 worldwide proved reserves are undeveloped (42% in 2005). Proved reserves at December 31, 2006 include 26% and 56%, respectively, of crude oil and natural gas reserves held under production sharing contracts.

Worldwide crude oil and natural gas liquids production amounted to 257,000 barrels per day in 2006 compared with 244,000 barrels per day in 2005. Worldwide natural gas production was 612,000 mcf per day in 2006 compared with 544,000 mcf per day in 2005. On a barrel of oil equivalent basis, production was 359,000 barrels per day in 2006 compared with 335,000 barrels per day in 2005.

Worldwide crude oil, natural gas liquids and natural gas production was as follows:


	2006		2005

Crude oil (thousands of barrels per day)
United States
Onshore		15		21
Offshore		21		23

		36		44

Europe
United Kingdom		50		54
Norway		22		26
Denmark		19		24
Russia		18		6

		109		110


	2006		2005

Africa
Equatorial Guinea		28		30
Algeria		22		25
Gabon		12		12
Libya		23		—

		85		67

Asia and other
Azerbaijan		7		4
Other		5		3

		12		7

Total		242		228

Natural gas liquids (thousands of barrels per day)
United States
Onshore		7		8
Offshore		3		4

		10		12

Europe
United Kingdom		4		3
Norway		1		1

		5		4

Total		15		16

Natural gas (thousands of mcf per day)
United States
Onshore		54		74
Offshore		56		63

		110		137

Europe
United Kingdom		244		222
Norway		22		28
Denmark		17		24

		283		274

Asia and other
Joint Development Area of Malaysia and Thailand		131		51
Thailand		60		57
Indonesia		26		25
Other		2		—

		219		133

Total		612		544

Barrels of oil equivalent*		359		335


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

The Corporation presently estimates that its 2007 barrel of oil equivalent production will be approximately 370,000 to 380,000 barrels per day. The Corporation is developing a number of oil and gas fields and has an inventory of domestic and foreign exploration prospects.

United States

During 2006, 18% of the Corporation’s crude oil and natural gas liquids production and 18% of its natural gas production were from United States operations. The Corporation operates mainly offshore in the Gulf of Mexico and onshore in Texas and North Dakota. During 2006, the Corporation completed the sale of its interests in certain producing properties in the Permian Basin in Texas and New Mexico and certain U.S. Gulf Coast oil and gas producing assets. Total net production from assets sold was approximately 8,000 barrels of oil equivalent per day at the time of sale.

In the second quarter of 2006, the Shenzi development (Hess 28%) in the Green Canyon Block area of the deepwater Gulf of Mexico was sanctioned by the operator and first oil is expected in the second half of 2009. Plans for the Shenzi development in 2007 include the drilling of development wells and continued construction of platform components and subsea equipment installation. In February 2007, the Corporation acquired a 28% interest in the Genghis Khan oil and gas development located in the deepwater Gulf of Mexico on Green Canyon Blocks 652 and 608 for $371 million. The Genghis Khan development is part of the same geologic structure as the Shenzi development and first production from this development is expected in the second half of 2007.

In 2006, an exploration well on the Corporation’s Pony prospect (Hess 100%) on Green Canyon Block 468 in the deepwater Gulf of Mexico encountered 475 feet of oil saturated sandstone in Miocene age reservoirs. Drilling of an appraisal sidetrack well on the Pony Prospect was completed in January 2007 which encountered 280 feet of oil saturated sandstone in Miocene age reservoirs after penetrating sixty percent of its geological objective. Drilling of the sidetrack well was stopped for mechanical reasons after successfully recovering 450 feet of conventional core. The Corporation is currently drilling an appraisal well about 7,400 feet northwest of the discovery well.

In 2006, on the Tubular Bells prospect (Hess 20%) in the Mississippi Canyon area of the deepwater Gulf of Mexico a successful appraisal well encountered hydrocarbons approximately 5 miles from the initial discovery well. The operator intends to drill two sidetrack wells in 2007 which will further delineate the field.

The Corporation has an interest in the Seminole-San Andres Unit (Hess 34.3%) in the Permian Basin. A residual oil zone development at the Seminole-San Andres Unit is expected to commence in 2007 and it is anticipated that production from this development will begin in 2009. The Corporation intends to use carbon dioxide gas from its interests in the West Bravo Dome and Bravo Dome fields in New Mexico for the enhanced recovery effort in this residual oil zone development.

At December 31, 2006, the Corporation has interests in over 400 exploration blocks in the Gulf of Mexico. The Corporation has 1,525,304 net undeveloped acres in the Gulf of Mexico.

Europe

During 2006, 44% of the Corporation’s crude oil and natural gas liquids production and 46% of its natural gas production were from European operations.

United Kingdom: Production of crude oil and natural gas liquids from the United Kingdom North Sea was 54,000 barrels per day in 2006 compared with 57,000 barrels per day in 2005, principally from the Corporation’s non-operated interests in the Beryl (Hess 22.2%), Bittern (Hess 28.3%), Schiehallion (Hess 15.7%) and Clair (Hess 9.3%) fields. Natural gas production from the United Kingdom in 2006 was 244,000 mcf of natural gas per day compared with 222,000 mcf per day in 2005, primarily from gas fields in the Easington Catchment Area (Hess 28.8%), as well as Everest (Hess 18.7%), Lomond (Hess 16.7%) and Beryl (Hess 22.2%). In addition, production from the Atlantic (Hess 25%) and Cromarty (Hess 90%) fields commenced in June of 2006 and the fields produced at a combined rate of approximately 95,000 mcf per day net to Hess in the second half of 2006.

In the first half of 2007, the Corporation expects to complete the sale of its interests in the Scott and Telford fields with an effective date of January 1, 2007 for approximately $100 million. The Corporation’s share of net production from these fields was 9,000 barrels of oil equivalent per day at the end of 2006.

Norway: Crude oil and natural gas liquids production was 23,000 barrels per day in 2006 and 27,000 barrels per day in 2005. Natural gas production averaged 22,000 mcf per day in 2006 and 28,000 mcf per day in 2005. Substantially all of the Norwegian production is from the Corporation’s interest in the Valhall field (Hess 28.1%).

Denmark: Net production from the Corporation’s interest in the South Arne field (Hess 57.5%) was 19,000 barrels of crude oil per day in 2006 and 24,000 barrels of crude oil per day in 2005. Natural gas production was 17,000 mcf per day in 2006 and 24,000 mcf per day in 2005.

Russia: The Corporation’s activities in Russia are conducted through its 80%-owned interest in a corporate joint venture operating in the Volga-Urals region of Russia. Production averaged 18,000 barrels of crude oil per day in 2006 compared to 6,000 barrels per day in 2005. The Corporation’s initial interest in its Russian joint venture was acquired during 2005.

Africa

During 2006, 33% of the Corporation’s crude oil and natural gas liquids production was from African operations.

Equatorial Guinea: The Corporation is the operator and owns an interest in Block G (Hess 85%) which contains the Ceiba field and Okume Complex. Net production from the Ceiba field averaged 28,000 barrels of crude oil per day in 2006 and 30,000 barrels per day in 2005. Production of crude oil from the Okume Complex commenced in December 2006. The Corporation estimates that its net share of 2007 production from the Okume Complex will average approximately 20,000 barrels of oil per day. In 2007, the Corporation plans to complete the construction of offshore production facilities and to drill additional development wells at the Okume Complex.

Algeria: The Corporation has a 49% interest in a venture with the Algerian national oil company that is redeveloping three oil fields. The Corporation’s share of production averaged 22,000 and 25,000 barrels of crude oil per day in 2006 and 2005, respectively. The Corporation has also submitted a plan of development for a small oil discovery on Block 401C, which is currently awaiting government approval.

Libya: In January 2006, the Corporation, in conjunction with its Oasis Group partners, re-entered its former oil and gas production operations in the Waha concessions in Libya (Hess 8.16%). The re-entry terms included a25-year extension of the concessions and payments by the Corporation to the Libyan National Oil Corporation of $359 million. The Corporation’s net share of 2006 production from Libya averaged 23,000 barrels of oil per day. The Corporation also owns a 100% interest in offshore exploration Area 54.

Gabon: Through its 77.5% owned Gabonese subsidiary, the Corporation has interests in the Rabi Kounga, Toucan and Atora fields. The Corporation’s share of production averaged 12,000 barrels of crude oil per day in 2006 and 2005.

Egypt: In January 2006, the Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities.

Asia and Other

During 2006, 5% of the Corporation’s crude oil and natural gas liquids production and 36% of its natural gas production were from Asian operations.

Joint Development Area of Malaysia and Thailand: The Corporation owns an interest in the production sharing agreement covering BlockA-18 of the Joint Development Area (JDA) (Hess 50%) in the Gulf of Thailand. Net production averaged 131,000 mcf of natural gas and 2,000 barrels of crude oil per day in 2006 compared to 51,000 mcf of natural gas and 1,000 barrels of crude oil per day in 2005. In 2007, the Corporation’s capital investments in the JDA will be primarily focused on facilities expansion and development drilling associated with the additional contracted gas sales of 400,000 mcf per day (gross) in 2008. It is anticipated that production associated with these additional gas sales will begin ramping up in the fourth quarter of 2007.

Thailand: The Corporation has an interest in the Pailin gas field (Hess 15%) offshore Thailand. Net production from the Corporation’s interest averaged 60,000 mcf and 57,000 mcf of natural gas per day in 2006 and 2005, respectively. The Corporation is the operator and owns an interest in the onshore natural gas project in the Phu

Horm Block (Hess 35%) which commenced production in November 2006. The Corporation estimates its net share of 2007 production from Phu Horm will average approximately 30,000 mcf of natural gas per day.

Indonesia: The Corporation’s net share of natural gas production from Indonesia averaged 26,000 mcf per day in 2006 and 25,000 mcf per day in 2005 primarily from its interest in the Natuna A gas field (Hess 23%). The Ujung Pangkah project (Hess 75%), where the Corporation is the operator, is expected to commence gas sales by mid 2007 under an existing gas sales agreement for 440 million mcf (gross) over a 20 year period with an expected plateau rate of 100,000 mcf per day (gross). The Corporation’s plans for Ujung Pangkah in 2007 include drilling additional development wells, the completion of onshore and offshore gas facilities and the commencement of a crude oil development project. The Corporation also owns an interest in the Jambi Merang natural gas project (Hess 25%).

Azerbaijan: The Corporation has an interest in the Azeri-Chirag-Gunashli (ACG) fields (Hess 2.72%) in the Caspian Sea. Net production from its interest averaged 7,000 barrels of crude oil per day in 2006 and 4,000 barrels per day in 2005. Phase 2 production from the ACG fields commenced during 2006. The Corporation also holds an interest in the Baku-Tbilisi-Ceyhan (BTC) Pipeline (Hess 2.36%), which started operation in the second quarter of 2006.

Oil and Gas Reserves

The Corporation’s net proved oil and gas reserves at the end of 2006, 2005 and 2004 are presented under Supplementary Oil and Gas Data on pages 80 and 81 in the accompanying financial statements.

During 2006, the Corporation provided oil and gas reserve estimates for 2005 to the United States Department of Energy. Such estimates are compatible with the information furnished to the SEC onForm 10-K for the year ended December 31, 2005, although not necessarily directly comparable due to the requirements of the individual requests. There were no differences in excess of 5%.

The Corporation has no contracts or agreements to sell fixed quantities of its crude oil production. In the United States, natural gas is sold on a spot basis and under contracts for varying periods to local distribution companies, and commercial, industrial and other purchasers. The Corporation’s United States natural gas production is expected to approximate 20% of its 2007 sales commitments under long-term contracts. The Corporation attempts to minimize price and supply risks associated with its United States natural gas supply commitments by entering into purchase contracts with third parties having adequate sources of supply, on terms substantially similar to those under its commitments and by leasing storage facilities. In international markets, the Corporation generally sells its natural gas production under long-term sales contracts. In the United Kingdom, the Corporation also sells a portion of its natural gas production on a spot basis.

Average selling prices and average production costs


	2006		2005		2004

Average selling prices (including the effects of hedging) (Note A)
Crude oil, including condensate and natural gas liquids (per barrel)
United States	$	57.41	$	33.86	$	27.87
Europe		55.80		33.30		26.24
Africa		51.18		32.10		26.35
Asia and other		61.52		54.69		38.36
Worldwide		54.81		33.69		26.86
Natural gas (per mcf)
United States	$	6.59	$	7.93	$	5.18
Europe		6.20		5.29		3.96
Asia and other		4.05		4.02		3.90
Worldwide		5.50		5.65		4.31


	2006		2005		2004

Average production (lifting) costs per barrel of oil equivalent produced (Note B)
United States	$	9.54	$	7.46	$	6.42
Europe		10.73		8.13		6.35
Africa		9.03		7.99		7.72
Asia and other		6.54		7.29		6.05
Worldwide		9.55		7.91		6.59

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

Note B: Production (lifting) costs consist of amounts incurred to operate and maintain the Corporation’s producing oil and gas wells, related equipment and facilities (including lease costs of floating production and storage facilities) and production and severance taxes. Production costs in 2005 exclude Gulf of Mexico hurricane related expenses. The average production costs per barrel of oil equivalent reflect the crude oil equivalent of natural gas production converted based on the basis of relative energy content (six mcf equals one barrel).

The table above does not include costs of finding and developing proved oil and gas reserves, or the costs of related general and administrative expenses, interest expense and income taxes.

Gross and net undeveloped acreage at December 31, 2006


	Undeveloped
	Acreage (Note A)
	Gross		Net
	(In thousands)

United States		2,199		1,672
Europe		2,893		984
Africa		13,527		9,572
Asia and other		16,486		10,016

Total (Note B)		35,105		22,244

Note A: Includes acreage held under production sharing contracts.

Note B: Approximately 5% of net undeveloped acreage held at December 31, 2006 will expire during the next three years.

Gross and net developed acreage and productive wells at December 31, 2006


	Developed
	Acreage
	Applicable to				Productive Wells (Note A)
	Productive Wells				Oil				Gas
	Gross		Net		Gross		Net		Gross		Net
	(In thousands)
United States		450		385		708		396		74		59
Europe		1,183		587		283		98		163		37
Africa		9,919		958		844		105		3		—
Asia and other		2,185		624		40		3		320		60

Total		13,737		2,554		1,875		602		560		156

Note A: Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 301 gross wells and 62 net wells.

Number of net exploratory and development wells drilled


	Net Exploratory						Net Development
	Wells						Wells
	2006		2005		2004		2006		2005		2004

Productive wells
United States		1		–		4		24		28		32
Europe		1		3		–		20		6		5
Africa		–		1		1		17		12		12
Asia and other		6		1		1		11		8		2

Total		8		5		6		72		54		51

Dry holes
United States		4		2		1		–		2		–
Europe		–		1		1		–		–		1
Africa		–		1		2		–		1		1
Asia and other		–		–		1		–		–		1

Total		4		4		5		–		3		3

Total		12		9		11		72		57		54

Number of wells in process of drilling at December 31, 2006


	Gross		Net
	Wells		Wells

United States		12		7
Europe		13		6
Africa		21		8
Asia and other		19		4

Total		65		25

Number of waterfloods and pressure maintenance projects in process of installation at December 31, 2006 — 2

Marketing and Refining

Refined product sales of the M&R businesses were as follows:


	2006		2005
	(Thousands of barrels per day)

Gasoline		218		213
Distillates		144		136
Residuals		60		64
Other		37		43

Total		459		456

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

HOVENSA: Refining operations at HOVENSA consist of crude units, a fluid catalytic cracking unit and a delayed coker unit. The following table summarizes capacity and utilization rates for HOVENSA:


	Refinery		Refinery Utilization
	Capacity		2006	2005
	(Thousands of
	barrels per day)

Crude		500	89.7%	92.2%
Fluid catalytic cracker		150	84.3%	81.9%
Coker		58	84.3%	92.8%

The fluid catalytic cracking unit at HOVENSA was shut down for approximately 22 days of unscheduled maintenance in 2006.

The delayed coker unit permits HOVENSA to run lower-cost heavy crude oil. HOVENSA has a long-term supply contract with PDVSA to purchase 115,000 barrels per day of Venezuelan Merey heavy crude oil. PDVSA also supplies 155,000 barrels per day of Venezuelan Mesa medium gravity crude oil to HOVENSA under a long-term crude oil supply contract. The remaining crude oil requirements are purchased mainly under contracts of one year or less from third parties and through spot purchases on the open market. After sales of refined products by HOVENSA to unrelated third parties, the Corporation purchases 50% of HOVENSA’s remaining production at market prices.

Port Reading Facility: The Corporation owns and operates a fluid catalytic cracking facility in Port Reading, New Jersey, with a capacity of 65,000 barrels per day. This facility processes residual fuel oil and vacuum gas oil and operated at a rate of approximately 63,000 barrels per day in 2006 and 55,000 barrels per day in 2005. Substantially all of Port Reading’s production is gasoline and heating oil.

Marketing: The Corporation markets refined petroleum products on the East Coast of the United States to the motoring public, wholesale distributors, industrial and commercial users, other petroleum companies, governmental agencies and public utilities. It also markets natural gas and electricity to utilities and other industrial and commercial customers. During 2006 and 2005, the Corporation selectively expanded its energy marketing business by acquiring natural gas and electricity customer accounts.

The Corporation has 1,350 HESS^® gasoline stations at December 31, 2006, including stations owned by the WilcoHess joint venture (Hess 44%). Approximately 88% of the gasoline stations are operated by the Company or WilcoHess. Of the operated stations, 92% have convenience stores on the sites. Most of the Corporation’s gasoline stations are in New York, New Jersey, Pennsylvania, Florida, Massachusetts, North Carolina and South Carolina.

Refined product sales averaged 459,000 barrels per day in 2006 and 456,000 barrels per day in 2005. Of total refined products sold in 2006, approximately 50% was obtained from HOVENSA and Port Reading. The Corporation purchased the balance from others under short-term supply contracts and by spot purchases from various sources.

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

The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and derivatives. The Corporation also takes energy commodity and derivative trading positions for its own account.

The Corporation also has a 50% interest in a joint venture, Hess LNG, which is pursuing investments in liquefied natural gas (LNG) terminals and related supply, trading and marketing opportunities. The joint venture is pursuing the development of LNG terminal projects located in Fall River, Massachusetts and Shannon, Ireland.

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

Competition and Market Conditions

See Item 1A, Risk Factors Related to Our Business and Operations, for a discussion of competition and market conditions.

Other Items

Compliance with various existing environmental and pollution control regulations imposed by federal, state, local and foreign governments is not expected to have a material adverse effect on the Corporation’s earnings and competitive position within the industry. The Corporation spent $15 million in 2006 for environmental remediation. The United States Environmental Protection Agency (EPA) has adopted rules that limit the amount of sulfur in gasoline and diesel fuel. Capital expenditures necessary to comply with the low-sulfur gasoline requirements at Port Reading were $72 million, of which $23 million was spent in 2005 and the remainder was spent in 2006. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are expected to be approximately $420 million, of which $360 million has been spent to date and the remainder will be spent in 2007. HOVENSA expects to finance these capital expenditures through cash flow from operations.

The number of persons employed by the Corporation at year end was approximately 13,700 in 2006 and 12,800 in 2005.

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


Item 1A.	*Risk Factors Related to Our Business and Operations*

Our business activities and the value of our securities are subject to significant risk factors, including those described below. The risk factors described below could negatively affect our operations, financial condition, liquidity and results of operations, and as a result holders and purchasers of our securities could lose part or all of their investments. It is possible additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.

Commodity Price Risk: Our estimated proved reserves, revenue, operating cash flows, operating margins, future earnings and trading operations are highly dependent on the prices of crude oil, natural gas and refined petroleum products, which are influenced by numerous factors beyond our control. Historically these prices have been very volatile. The major foreign oil producing countries, including members of the Organization of Petroleum Exporting Countries (OPEC), exert considerable influence over the supply and price of crude oil and refined petroleum products. Their ability or inability to agree on a common policy on rates of production and other matters has a significant impact on the oil markets. The derivatives markets may also influence the selling prices of crude oil, natural gas and refined petroleum products. A significant downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow and could result in a reduction in the carrying value of our oil and gas assets, goodwill and proved oil and gas reserves. To the extent that we engage in hedging activities to mitigate commodity price volatility, we will not realize the benefit of price increases above the hedged price.

Technical Risk: We own or have access to a finite amount of oil and gas reserves which will be depleted over time. Replacement of oil and gas reserves is subject to successful exploration drilling, development activities, and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding

and developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks include adverse unexpected conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions. Future developments may be affected by unforeseen reservoir conditions which negatively affect recovery factors or flow rates. The costs of drilling and development activities have also been increasing, which could negatively affect expected economic returns. Although due diligence is used in evaluating acquired oil and gas properties, similar uncertainties may be encountered in the production of oil and gas on properties acquired from others.

Oil and Gas Reserves and Discounted Future Net Cash Flow Risks: Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, geologic success and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities and future net revenues of our proved reserves. In addition, reserve estimates may be subject to downward or upward revisions based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices, production sharing contracts which may decrease reserves as crude oil and natural gas prices increase, and other factors.

Political Risk: Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, expropriation of property, cancellation of contract rights, and changes in import regulations, as well as other political developments may affect our operations. For example, during 2006, the governments of the United Kingdom and Algeria increased taxation on our crude oil and natural gas revenues in response to higher crude oil and natural gas prices. Some of the international areas in which we operate may be politically less stable than our domestic operations. In addition, the increasing threat of terrorism around the world poses additional risks to the operations of the oil and gas industry. In our M&R segment, we market motor fuels through lessee-dealers and wholesalers in certain states where legislation prohibits producers or refiners of crude oil from directly engaging in retail marketing of motor fuels. Similar legislation has been periodically proposed in the U.S. Congress and in various other states.

Environmental Risk: Our oil and gas operations, like those of the industry, are subject to environmental hazards such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. Our operations are also subject to numerous United States federal, state, local and foreign environmental laws and regulations. Non-compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedialclean-ups and natural resource damages or other liabilities. In addition, increasingly stringent environmental regulations, particularly relating to the production of motor and other fuels, has resulted, and will likely continue to result, in higher capital expenditures and operating expenses for us and the oil and gas industry generally.

Competitive Risk: The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies in each of our activities, particularly in acquiring rights to explore for crude oil and natural gas and in the purchasing and marketing of refined products and natural gas. Many competitors, including national oil companies, are larger and have substantially greater resources. We are also in competition with producers and marketers of other forms of energy. Increased competition for worldwide oil and gas assets has significantly increased the cost of acquisitions. In addition, competition for drilling services and equipment has affected the availability of drilling rigs and increased capital and operating costs.

Catastrophic Risk: Although we maintain an appropriate level of insurance coverage against property and casualty losses, our oil and gas operations are subject to unforeseen occurrences which may damage or destroy assets or interrupt operations. Examples of catastrophic risks include hurricanes, fires, explosions and blowouts. These occurrences have affected us from time to time. During 2005, our annual Gulf of Mexico production of crude oil and natural gas was reduced by 7,000 barrels of oil equivalent per day (boepd) due to the impact of Hurricanes Katrina and Rita.


Item 3.	*Legal Proceedings*

Purported class actions consolidated under a complaint captioned:In re Amerada Hess SecuritiesLitigation were filed in United States District Court for the District of New Jersey against the Registrant and certain executive officers and former executive officers of the Registrant alleging that these individuals sold shares of the Registrant’s common stock in advance of the Registrant’s acquisition of Triton Energy Limited (Triton) in 2001 in violation of federal securities laws. In April 2003, the Registrant and the other defendants filed a motion to dismiss for failure to state a claim and failure to plead fraud with particularity. On March 31, 2004, the court granted the defendants’ motion to dismiss the complaint. The plaintiffs were granted leave to file an amended complaint. Plaintiffs filed an amended complaint in June 2004. Defendants moved to dismiss the amended complaint. In June 2005, this motion was denied. On January 30, 2007, the District Court issued an order preliminarily approving settlement of this action and providing for notice to members of the class of plaintiffs. While continuing to deny the allegations of the complaint and all charges of wrongdoing or liability arising in connection with the subject matter of the action, the defendants agreed with plaintiffs to settle the action on the terms set forth in the stipulation of settlement in order to avoid the cost, inconvenience and uncertainty of continued protracted litigation. Under the terms of the settlement, defendants have caused to be deposited into an escrow account the sum of $9 million, which after payment of certain administrative expenses and plaintiffs’ attorney fees, will be distributed according to a plan of allocation to class members who submit valid and timely proof of claim and release forms. All of the amount deposited was paid by the defendants’ insurer. The settlement is subject to final approval of the district court and certain other conditions, including that not more than 5% of shares owned by class members eligible to participate in the settlement elect to opt out of the settlement.

The Registrant, along with many other companies engaged in refining and marketing of gasoline, has been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. A series of substantially identical lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produce gasoline containing MTBE, including the Registrant. These cases have been consolidated in the Southern District of New York and the Registrant is named as a defendant in 43 of the 69 cases pending. The principal allegation in all cases is that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. In some cases, punitive damages are also sought. In April 2005, the District Court denied the primary legal aspects of the defendants’ motion to dismiss these actions. While the damages claimed in these actions are substantial, only limited information is available to evaluate the factual and legal merits of those claims. The Corporation also believes that significant legal uncertainty remains regarding the validity of causes of action asserted and availability of the relief sought by plaintiffs. Accordingly, based on the information currently available, there is insufficient information on which to evaluate the Corporation’s exposure in these cases.

Over the last several years, many refiners have entered into consent agreements to resolve the EPA’s assertions that refining facilities were modified or expanded without complying with New Source Review regulations that require permits and new emission controls in certain circumstances and other regulations that impose emissions control requirements. These consent agreements, which arise out of an EPA enforcement initiative focusing on petroleum refiners and utilities, have typically imposed substantial civil fines and penalties and required (i) significant capital expenditures to install emissions control equipment over a three to eight year time period and (ii) changes to operations which resulted in increased operating costs. Settlements under Petroleum Refining Initiative consent agreements to date have averaged $335 per barrel per day of refining capacity. However the capital expenditures, penalties and supplemental environmental projects for individual refineries covered by the settlements can vary significantly, depending on the size and configuration of the refinery, the circumstances of the alleged modifications and whether the refinery has previously installed more advanced pollution controls. EPA initially contacted Registrant and HOVENSA L.L.C. (HOVENSA), its 50% owned joint venture with Petroleos de Venezuela, regarding the Petroleum Refinery Initiative in August 2003 and discussions resumed in August 2005. The Registrant and HOVENSA have had and expect to have further discussions with the EPA regarding the Petroleum Refining Initiative, although both the Registrant and HOVENSA have already installed many of the pollution controls required of other refiners under the consent agreements and the EPA has not made any specific

assertions that either Registrant or HOVENSA violated either New Source Review or other regulations which would require additional controls. While the effect on the Corporation of the Petroleum Refining Initiative cannot be estimated at this time, additional future capital expenditures and operating expenses may be incurred. The amount of penalties, if any, is not expected to be material to the Corporation.

In December 2006, HOVENSA received a Notice of Violation (NOV) from the EPA alleging non-compliance with emissions limits in a permit issued by the Virgin Islands Department of Planning and Natural Resources (DPNR) for the two process heaters in the delayed coking unit. The NOV was issued in response to a voluntary investigation and submission by HOVENSA regarding potential non-compliance with the permit emissions limits for two pollutants. Any exceedances were minor from the perspective of the amount of pollutants emitted in excess of the limits. HOVENSA intends to work with the appropriate governmental agency to reach resolution of this matter and does not believe that it will result in material liability.

Registrant is one of over 60 companies that have received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the lower Passaic River and NJDEP is also seeking natural resource damages. The directive, insofar as it affects Registrant, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey now owned by the Registrant. EPA has also issued an Administrative Order on Consent relating to the same contamination. While NJDEP has suggested a remedial cost of over $900 million, the costs of remediation of the Passaic River sediments are the subject of a remedial investigation and feasibility study currently being conducted on a portion of the river by the EPA under an agreement with Registrant and over 40 other companies. Thus, remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, the Registrant does not believe that this matter will result in material liability because its terminal could not have contributed contamination along most of the river’s length and did not store or use contaminants which are of the greatest concern in the river sediments, and because there are numerous other parties who will likely share in the cost of remediation and damages.

On or about July 15, 2004, Hess Oil Virgin Islands Corp. (HOVIC), a wholly owned subsidiary of the Registrant, and HOVENSA, in which Registrant owns a 50% interest, each received a letter from the Commissioner of the Virgin Islands Department of Planning and Natural Resources and Natural Resources Trustees, advising of the Trustee’s intention to bring suit against HOVIC and HOVENSA under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The letter alleges that HOVIC and HOVENSA are potentially responsible for damages to natural resources arising from releases of hazardous substances from the “HOVENSA Oil Refinery.” HOVENSA currently owns and operates a petroleum refinery on the south shore of St. Croix, United States Virgin Islands, which had been operated by HOVIC until October 1998. An action was filed on May 5, 2005 in the District Court of the Virgin Islands against HOVENSA, HOVIC and other companies that operated industrial facilities on the south shore of St. Croix asserting that the defendants are liable under CERCLA and territorial statutory and common law for damages to natural resources. HOVIC and HOVENSA do not believe that this matter will result in a material liability as they believe that they have strong defenses to this complaint, and they intend to vigorously defend this matter.

The Securities and Exchange Commission (SEC) has notified the Registrant that on July 21, 2005, it commenced a private investigation into payments made to the government of Equatorial Guinea or to officials and persons affiliated with officials of the government of Equatorial Guinea. The staff of the SEC has requested documents and information from the Registrant and other oil and gas companies that have operations or interests in Equatorial Guinea. The staff of the SEC had previously been conducting an informal inquiry into such matters. The Registrant has been cooperating and continues to cooperate with the SEC investigation.

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

complaint. Registrant intends to vigorously contest the complaint, but is involved in settlement discussions with DEC. Any settlement is not expected to be material to the Corporation.

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

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


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

During the fourth quarter of 2006, no matter was submitted to a vote of security holders through the solicitation of proxies or otherwise.

Executive Officers of the Registrant

The following table presents information as of February 1, 2007 regarding executive officers of the Registrant:


				Year Individual
				Became an
				Executive
Name	Age		Office Held*	Officer

John B. Hess		52	Chairman of the Board, Chief Executive Officer and Director		1983
J. Barclay Collins II		62	Executive Vice President, General Counsel and Director		1986
John J. O’Connor		60	Executive Vice President, President of Worldwide Exploration and Production and Director		2001
F. Borden Walker		53	Executive Vice President and President of Marketing and Refining and Director		1996
Brian J. Bohling		46	Senior Vice President		2004
E. Clyde Crouch		58	Senior Vice President		2003
John A. Gartman		59	Senior Vice President		1997
Scott Heck		49	Senior Vice President		2005
Lawrence H. Ornstein		55	Senior Vice President		1995
Howard Paver		56	Senior Vice President		2002
John P. Rielly		44	Senior Vice President and Chief Financial Officer		2002
George F. Sandison		50	Senior Vice President		2003
John J. Scelfo		49	Senior Vice President		2004
Robert P. Strode		50	Senior Vice President		2000
Robert J. Vogel		47	Vice President & Treasurer		2004


*		All officers referred to herein hold office in accordance with the By-Laws until the first meeting of the Directors following the annual meeting of stockholders of the Registrant and until their successors shall have been duly chosen and qualified. Each of said officers was elected to the office set forth opposite his name on May 3, 2006. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 2, 2007.

Except for Messrs. Bohling, Sandison and Scelfo, each of the above officers has been employed by the Registrant or its subsidiaries in various managerial and executive capacities for more than five years. Mr. Bohling was employed in senior human resource positions with American Standard Corporation and CDI Corporation before joining the Registrant in 2004. Mr. Scelfo was chief financial officer of Sirius Satellite Radio and a division of Dell Computer before his employment by the Registrant in 2003. Mr. Sandison served in senior executive positions in the area of global drilling with Texaco, Inc. before he was employed by the Registrant in 2003.

PART II


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

Stock Market Information

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

2006

2005

Quarter Ended*

High

Low

High

Low

March 31

52.00

42.83

34.65

25.94

June 30

53.46

43.23

37.39

28.75

September 30

56.45

38.30

47.50

35.53

December 31

52.70

37.62

46.33

36.67


*		Prices for all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

The high and low sales prices of the Corporation’s 7% cumulative mandatory convertible preferred stock (traded on the New York Stock Exchange, ticker symbol: HESPR) were as follows**:

2006

2005

Quarter Ended

High

Low

High

Low

March 31

130.65

111.11

90.33

70.47

June 30

133.65

109.90

95.75

74.75

September 30

140.20

98.61

120.17

91.32

December 31**

124.94

95.00

117.56

95.33


**		On December 1, 2006, each share of the Corporation’s 7% Mandatory Convertible Preferred Stock was converted into 2.4915 shares of its common stock.

Performance Graph

Set forth below is a line graph comparing the cumulative total shareholder return, assuming reinvestment of dividends, on the Corporation’s common stock with the cumulative total return, assuming reinvestment of dividends, of:


	•	Standard & Poor’s 500 Stock Index, which includes the Corporation, and

	•	AMEX Oil Index, which is comprised of companies involved in various phases of the oil industry including the Corporation.

As of each December 31, over a five-year period commencing on December 31, 2001 and ending on December 31, 2006:

Total Shareholder Returns

(Dividends Reinvested)

Years Ended December 31

As a result of consolidations in the oil and gas industry, the Corporation believes that the peer group it had used previously had too few participants and has selected the AMEX Oil Index, a published industry index that includes the Corporation and 12 additional oil and gas companies, for purposes of the performance graph shown above.

Holders

At December 31, 2006, there were 5,572 stockholders (based on number of holders of record) who owned a total of 315,017,951 shares of common stock.

Dividends

Cash dividends on common stock totaled $.40 per share ($.10 per quarter) during 2006 and 2005 on a split adjusted basis. Dividends on the 7% cumulative mandatory convertible preferred stock totaled $3.21 per share in 2006 prior to conversion on December 1, 2006 and $3.50 per share ($.875 per quarter) in 2005. See note 8, “Long-Term Debt,” in the notes to the financial statements for a discussion of restrictions on dividends.

Equity Compensation Plans

Following is information on the Registrant’s equity compensation plans at December 31, 2006:

Number of

Securities

Remaining

Available for

Number of

Future Issuance

Securities to

Weighted

Under Equity

be Issued

Average

Compensation

Upon Exercise

Exercise Price

Plans

of Outstanding

(Excluding

Options,

Securities

Warrants and

Reflected in

Rights

Column (a))

Plan Category

(a)

(b)

(c)

Equity compensation plans approved by security holders

12,923,000

29.68

11,698,000

Equity compensation plans not approved by security holders**

—


*		These securities may be awarded as stock options, restricted stock or other awards permitted under the Registrant’s equity compensation plan.

**		Registrant has a Stock Award Program pursuant to which each non-employee director receives $150,000 in value of Registrant’s common stock each year. These awards are made from shares purchased by the Company in the open market. Stockholders did not approve this equity compensation plan.

See note 9, “Share-Based Compensation,” in the notes to the financial statements for further discussion of the Corporation’s equity compensation plans.


Item 6.	*Selected Financial Data*

A five-year summary of selected financial data follows:


	2006			2005			2004			2003			2002
	(Millions of dollars, except per share amounts)

Sales and other operating revenues
Crude oil and natural gas liquids	$	5,307		$	3,219		$	2,594		$	2,295		$	2,702
Natural gas (including sales of purchased gas)		6,826			6,423			4,638			4,522			3,077
Petroleum and other energy products		14,411			11,690			8,125			6,250			4,635
Convenience store sales and other operating revenues		1,523			1,415			1,376			1,244			1,137

Total	$	28,067		$	22,747		$	16,733		$	14,311		$	11,551

Income (loss) from continuing operations	$	1,916	(a)	$	1,242	(b)	$	970	(c)	$	467	(d)	$	(245	)(e)
Discontinued operations		—			—			7			169			27
Cumulative effect of change in accounting principle		—			—			—			7			—

Net income (loss)	$	1,916		$	1,242		$	977		$	643		$	(218	)

Less preferred stock dividends		44			48			48			5			—

Net income (loss) applicable to common shareholders	$	1,872		$	1,194		$	929		$	638		$	(218	)

Basic earnings (loss) per share *
Continuing operations	$	6.73		$	4.38		$	3.43		$	1.74		$	(.93	)
Net income (loss)		6.73			4.38			3.46			2.40			(.83	)
Diluted earnings (loss) per share *
Continuing operations	$	6.07		$	3.98		$	3.17		$	1.72		$	(.93	)
Net income (loss)		6.07			3.98			3.19			2.37			(.83	)
Total assets	$	22,404		$	19,115		$	16,312		$	13,983		$	13,262
Total debt		3,772			3,785			3,835			3,941			4,992
Stockholders’ equity		8,111			6,286			5,597			5,340			4,249
Dividends per share of common stock *	$	.40		$	.40		$	.40		$	.40		$	.40


*		Per share amounts in all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

(a)		Includes net after-tax income of $173 million primarily from sales of assets, partially offset by income tax adjustments and accrued leased office closing costs.

(b)		Includes after-tax expenses of $37 million primarily relating to income taxes on repatriated earnings, premiums on bond repurchases and hurricane related expenses, partially offset by gains from asset sales and a LIFO inventory liquidation.

(c)		Includes net after-tax income of $76 million primarily from sales of assets and income tax adjustments.

(d)		Includes net after-tax expenses of $25 million, principally from premiums on bond repurchases and accrued severance and leased office closing costs, partially offset by income tax adjustments and asset sales.

(e)		Includes net after-tax expenses aggregating $708 million, principally resulting from asset impairments.


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

Overview

The Corporation is a global integrated energy company that operates in two segments, Exploration and Production (E&P) and Marketing and Refining (M&R). The E&P segment explores for, develops, produces, purchases, transports and sells crude oil and natural gas. The M&R segment manufactures, purchases, transports, trades and markets refined petroleum products, natural gas and electricity.

Net income in 2006 was $1,916 million compared with $1,242 million in 2005 and $977 million in 2004. Diluted earnings per share were $6.07 in 2006 compared with $3.98 in 2005 and $3.19 in 2004.

Exploration and Production

The Corporation’s strategy for the E&P segment is to profitably grow reserves and production in a sustainable and financially disciplined manner. At December 31, 2006 and 2005, the Corporation’s total proved reserves were 1,243 million and 1,093 million barrels of oil equivalent. The following table summarizes the components of proved reserves as of December 31:


	2006				2005

Crude oil and condensate (millions of barrels)
U.S.		138	17	%		124	18	%
International		694	83			568	82

Total		832	100	%		692	100	%

Natural gas (millions of mcf)
U.S.		236	10	%		282	12	%
International		2,230	90			2,124	88

Total		2,466	100	%		2,406	100	%

E&P net income was $1,763 million in 2006, $1,058 million in 2005 and $762 million in 2004. The improved results were primarily driven by higher average crude oil selling prices during the reporting period and lower hedged crude oil volumes in 2006. See further discussion in Comparison of Results on page 24.

Production totaled 359,000 barrels of oil equivalent per day (boepd) in 2006, 335,000 boepd in 2005 and 342,000 boepd in 2004. The Corporation estimates that production will be approximately 370,000 boepd to 380,000 boepd in 2007.

During 2006, the Corporation commenced production from four new field developments:


	•	The Atlantic (Hess 25%) and Cromarty (Hess 90%) natural gas fields in the United Kingdom came onstream in June 2006 and produced at a combined net rate of approximately 95,000 mcf per day in the second half of the year.

	•	The Okume Complex development (Hess 85%) in Equatorial Guinea commenced production in December. Additional development activities are planned throughout 2007. The Corporation estimates that its net share of 2007 production will average approximately 20,000 boepd.

	•	First production from the Phu Horm onshore gas project (Hess 35%) in Thailand commenced in November. The Corporation estimates that its net share of 2007 production will average approximately 30,000 mcf per day.

	•	Phase 2 production from the ACG fields (Hess 2.7%) in Azerbaijan also commenced during 2006.

The Corporation has several additional development projects that will also increase production in the future:


	•	Development of the Shenzi field (Hess 28%) in the deepwater Gulf of Mexico was sanctioned and first production is anticipated in the second half of 2009.


	•	The Genghis Khan field (Hess 28%) was acquired by the Shenzi partners in February 2007. The field is part of the same geologic structure as the Shenzi development and first production is anticipated in the second half of 2007.

	•	The Ujung Pangkah field (Hess 75%) in Indonesia is scheduled to commence production of natural gas by mid 2007 under an existing gas sales agreement for 440 million mcf (gross) over a 20 year period with an expected plateau rate of 100,000 mcf per day (gross). The Corporation’s plans for Ujung Pangkah in 2007 also include drilling additional development wells and the commencement of a crude oil development project.

	•	Capital investments in the JDA (Hess 50%) will be made during 2007 which will be primarily focused on facilities expansion and development drilling associated with the anticipated commencement of additional contracted gas sales of 400,000 mcf per day (gross) in 2008. It is anticipated that production associated with these additional gas sales will begin ramping up in the fourth quarter of 2007.

	•	Development of the residual oil zone at the Seminole - San Andres Unit (Hess 34.3%) in the Permian Basin is expected to commence in 2007 and production is anticipated to begin in 2009.

During 2006, the Corporation’s exploration program had several successes, particularly in the deepwater Gulf of Mexico:


	•	An exploration well on the Corporation’s Pony prospect on Green Canyon Block 468 (Hess 100%) in the deepwater Gulf of Mexico encountered 475 feet of oil saturated sandstone in Miocene age reservoirs. Drilling of an appraisal sidetrack well on the Pony Prospect was completed in January 2007 which encountered 280 feet of oil saturated sandstone in Miocene age reservoirs after penetrating 60% of its geological objective. Drilling of the sidetrack well was stopped for mechanical reasons after successfully recovering 450 feet of conventional core. The Corporation is currently drilling an appraisal well about 7,400 feet northwest of the discovery well.

	•	On the Tubular Bells prospect (Hess 20%) in the Mississippi Canyon area of the deepwater Gulf of Mexico a successful appraisal well encountered hydrocarbons approximately 5 miles from the initial discovery well. The operator intends to drill two sidetrack wells in 2007 which will further delineate the field.

In addition, during 2006, the Corporation made the following acquisitions and also disposed of several producing properties:


	•	In January 2006, the Corporation, in conjunction with its Oasis Group partners, re-entered its former oil and gas production operations in the Waha concessions (Hess 8.16%) in Libya. The re-entry terms include a25-year extension of the concessions and payments by the Corporation to the Libyan National Oil Corporation of $359 million. The Corporation’s net share of 2006 production from Libya averaged 23,000 barrels of oil per day.

	•	The Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities.

	•	During 2006, the Corporation completed the sale of its interests in certain producing properties in the Permian Basin in Texas and New Mexico and certain U.S. Gulf Coast oil and gas producing assets. These asset sales generated total proceeds of $444 million after closing adjustments and an aggregate after-tax gain of $236 million ($369 million before income taxes). Total net production from assets sold was approximately 8,000 boepd at the time of sale.

Marketing and Refining

The Corporation’s strategy for the M&R segment is to deliver consistent financial performance and generate free cash flow. M&R net income was $390 million in 2006, $515 million in 2005 and $451 million in 2004. Total Marketing and Refining earnings decreased in 2006 due to lower margins on refined product sales. Refining

operations contributed net income of $236 million in 2006, $346 million in 2005 and $302 million in 2004. Profitability in 2006 was adversely affected by lower refined product margins. Refining facilities at the HOVENSA joint venture and at Port Reading performed reliably in 2006 with the exception of 22 days of unplanned downtime at HOVENSA early in the year. The Corporation received cash distributions from HOVENSA totaling $400 million in 2006 and $275 million in 2005.

In 2006, the Corporation’s Port Reading facility completed its $72 million program for complying with low-sulfur gasoline requirements. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are estimated to be approximately $420 million, of which $360 million has been incurred through the end of 2006 with the remainder to be spent in 2007.

Marketing earnings were $108 million in 2006, $136 million in 2005 and $112 million in 2004. During 2006 and 2005, the Corporation selectively expanded its energy marketing business by acquiring natural gas and electricity customer accounts.

Liquidity and Capital and Exploratory Expenditures

Net cash provided by operating activities was $3,491 million in 2006 compared with $1,840 million in 2005. At December 31, 2006, cash and cash equivalents totaled $383 million compared with $315 million at December 31, 2005. Total debt was $3,772 million at December 31, 2006 compared with $3,785 million at December 31, 2005. The Corporation’s debt to capitalization ratio at December 31, 2006 was 31.7% compared with 37.6% at the end of 2005. The Corporation has debt maturities of $27 million in 2007 and $28 million in 2008.

Capital and exploratory expenditures were as follows for the years ended December 31:


	2006		2005
	(Millions of dollars)

Exploration and Production
United States	$	908	$	353
International		2,979		2,031

Total Exploration and Production		3,887		2,384
Marketing, Refining and Corporate		169		106

Total Capital and Exploratory Expenditures	$	4,056	$	2,490

Exploration expenses charged to income included above:
United States	$	110	$	89
International		102		60

	$	212	$	149

The Corporation anticipates $4.0 billion in capital and exploratory expenditures in 2007, of which $3.9 billion relates to E&P operations. These expenditures include $371 million for the acquisition of a 28% interest in the Genghis Khan development in the deepwater Gulf of Mexico.

Consolidated Results of Operations

The after-tax results by major operating activity are summarized below:


	2006			2005			2004
	(Millions of dollars, except per share data)

Exploration and Production	$	1,763		$	1,058		$	755
Marketing and Refining		390			515			451
Corporate		(110	)		(191	)		(85	)
Interest expense		(127	)		(140	)		(151	)

Income from continuing operations		1,916			1,242			970
Discontinued operations		—			—			7

Net income	$	1,916		$	1,242		$	977

Income per share from continuing operations — diluted*	$	6.07		$	3.98		$	3.17

Net income per share — diluted*	$	6.07		$	3.98		$	3.19


*		Per share amounts in all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

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

The following items of income (expense), on an after-tax basis, are included in net income:


	2006			2005			2004
	(Millions of dollars)

Exploration and Production
Gains from asset sales	$	236		$	41		$	54
Income tax adjustments		(45	)		11			19
Accrued office closing costs		(18	)		—			(9	)
Hurricane related costs		—			(26	)		—
Legal settlement		—			11			—
Marketing and Refining
LIFO inventory liquidation		—			32			12
Charge related to customer bankruptcy		—			(8	)		—
Corporate
Tax on repatriated earnings		—			(72	)		—
Premiums on bond repurchases		—			(26	)		—
Income tax adjustments		—			—			13
Insurance accrual		—			—			(13	)

	$	173		$	(37	)	$	76

The items in the table above are explained, and the pre-tax amounts are shown, on pages 26 through 29.

Comparison of Results

Exploration and Production

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


	2006		2005		2004
	(Millions of dollars)

Sales and other operating revenues	$	6,524	$	4,210	$	3,416
Non-operating income		428		94		90

Total revenues		6,952		4,304		3,506

Costs and expenses
Production expenses, including related taxes		1,250		1,007		825
Exploration expenses, including dry holes and lease impairment		552		397		287
General, administrative and other expenses		209		140		150
Depreciation, depletion and amortization		1,159		965		918

Total costs and expenses		3,170		2,509		2,180

Results of operations from continuing operations before income taxes		3,782		1,795		1,326
Provision for income taxes		2,019		737		571

Results from continuing operations		1,763		1,058		755
Discontinued operations		—		—		7

Results of operations	$	1,763	$	1,058	$	762

After considering the Exploration and Production items in the table on page 23, the remaining changes in Exploration and Production earnings are primarily attributable to changes in selling prices, production volumes, operating costs, exploration expenses and income taxes, as discussed below.

Selling prices: Higher average crude oil selling prices and reduced hedge positions increased Exploration and Production revenues by approximately $1,900 million in 2006 compared with 2005. In 2005, the change in average selling prices increased revenues by approximately $870 million compared with 2004.

The Corporation’s average selling prices were as follows:


	2006		2005		2004

Crude oil-per barrel (including hedging)
United States	$	60.45	$	32.64	$	27.42
Europe		56.19		33.13		26.18
Africa		51.18		32.10		26.35
Asia and other		61.52		54.71		38.36
Worldwide		55.31		33.38		26.70
Crude oil-per barrel (excluding hedging)
United States	$	60.45	$	51.16	$	38.56
Europe		58.46		52.22		37.57
Africa		62.80		51.70		37.07
Asia and other		61.52		54.71		38.36
Worldwide		60.41		51.94		37.64


	2006		2005		2004

Natural gas liquids-per barrel
United States	$	46.22	$	38.50	$	29.50
Europe		47.30		37.13		27.44
Worldwide		46.59		38.08		28.81
Natural gas-per mcf
United States	$	6.59	$	7.93	$	5.18
Europe		6.20		5.29		3.96
Asia and other		4.05		4.02		3.90
Worldwide		5.50		5.65		4.31

The after-tax impacts of hedging reduced earnings by $285 million ($449 million before income taxes) in 2006, $989 million ($1,582 million before income taxes) in 2005 and $583 million ($935 million before income taxes) in 2004.

Production and sales volumes: The Corporation’s crude oil and natural gas production was 359,000 boepd in 2006, 335,000 boepd in 2005 and 342,000 boepd in 2004. The Corporation anticipates that its 2007 production will average between 370,000 and 380,000 boepd. The Corporation’s net daily worldwide production was as follows:


	2006		2005		2004

Crude oil (thousands of barrels per day)
United States		36		44		44
Europe		109		110		119
Africa		85		67		61
Asia and other		12		7		4

Total		242		228		228

Natural gas liquids (thousands of barrels per day)
United States		10		12		12
Europe		5		4		6

Total		15		16		18

Natural gas (thousands of mcf per day)
United States		110		137		171
Europe		283		274		319
Asia and other		219		133		85

Total		612		544		575

Barrels of oil equivalent* (thousands of barrels per day)		359		335		342


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

Crude oil and natural gas production in the United States was lower in 2006 due to asset sales and natural decline. Production in Europe was comparable in 2006 and 2005, reflecting increased production from Russia and new production from the Atlantic and Cromarty natural gas fields in the United Kingdom, which offset lower production due to maintenance and natural decline. Increased crude oil production in Africa in 2006 was primarily due to production from Libya. Natural gas production in Asia was higher in 2006 due to increased production from the JDA.

Higher sales volumes increased revenue by approximately $400 million in 2006 compared with 2005. Decreased sales volumes resulted in lower revenue of approximately $80 million in 2005 compared with 2004.

Operating costs and depreciation, depletion and amortization: Cash operating costs, consisting of production expenses and general and administrative expenses, increased by $322 million in 2006 and $147 million in 2005 compared with the corresponding amounts in prior years, excluding the charges for vacated leased office space and hurricane related costs discussed below. Production expenses increased in 2006 and 2005, principally reflecting higher maintenance expenses, increased costs of services, materials and fuel and higher production taxes resulting from higher oil prices. Production expenses also increased in 2006 due to the re-entry into Libya and continued expansion of operations in Russia and the JDA. Depreciation, depletion and amortization charges were higher in 2006, principally reflecting increased production volumes and higher per barrel rates, due to new production from the Atlantic and Cromarty fields and higher asset retirement obligations. Depreciation, depletion and amortization charges were higher in 2005 versus 2004, principally due to higher per barrel rates.

Cash operating costs per barrel of oil equivalent were $10.92 in 2006, $9.07 in 2005 and $7.67 in 2004. Cash operating costs for 2007 are estimated to be in the range of $12.00 to $13.00 per barrel, reflecting industry-wide cost increases and the timing of achieving peak production from new fields. Depreciation, depletion and amortization costs per barrel of oil equivalent were $8.85 in 2006, $7.88 in 2005 and $7.34 in 2004. Depreciation, depletion and related costs for 2007 are expected to be in the range of $10.00 to $11.00 per barrel. The anticipated increase is due to new fields, including the Okume Complex, which has allocated acquisition cost in its depreciable base.

Exploration expenses: Exploration expenses were higher in 2006, primarily reflecting higher dry hole costs. Exploration expenses were higher in 2005 compared with 2004 as a result of increased drilling and seismic activity.

Income Taxes: The effective income tax rate for Exploration and Production operations was 53% in 2006, 41% in 2005 and 43% in 2004. After considering the items in the table below, the effective income tax rates were 54% in 2006, 42% in 2005 and 46% in 2004. The increase in the 2006 effective income tax rate was primarily due to taxes on Libyan operations and the increase in the supplementary tax on petroleum operations in the United Kingdom from 10% to 20%. During 2006, the Algerian government amended its hydrocarbon tax laws effective August 1, 2006 and the Corporation recorded a net charge of $6 million for the estimated impact of the tax. The effective income tax rate for E&P operations in 2007 is expected to be in the range of 52% to 56%.

Other: After-tax foreign currency gains were $10 million ($21 million before income taxes) in 2006, $20 million ($3 million loss before income taxes) in 2005, and $6 million ($29 million before income taxes) in 2004.

Reported Exploration and Production earnings include the following items of income (expense) before and after income taxes:


	Before Income Taxes									After Income Taxes
	2006			2005			2004			2006			2005			2004
	(Millions of dollars)

Gains from asset sales	$	369		$	48		$	55		$	236		$	41		$	54
Income tax adjustments		—			—			—			(45	)		11			19
Accrued office closing costs		(30	)		—			(15	)		(18	)		—			(9	)
Hurricane related costs		—			(40	)		—			—			(26	)		—
Legal settlement		—			19			—			—			11			—

	$	339		$	27		$	40		$	173		$	37		$	64

2006: The gains from asset sales relate to the sale of certain United States oil and gas producing properties located in the Permian Basin in Texas and New Mexico and onshore Gulf Coast. The accrued office closing cost relates to vacated leased office space in the United Kingdom. The income tax adjustment represents a one-time adjustment to the Corporation’s deferred tax liability resulting from an increase in the supplementary tax on petroleum operations in the United Kingdom from 10% to 20%.

2005: The gains from asset sales represent the disposal of non-producing properties in the United Kingdom and the exchange of a mature North Sea asset for an increased interest in the Pangkah development in Indonesia. The Corporation incurred incremental expenses in 2005, principally repair costs and higher insurance premiums, as a result of hurricane damage in the Gulf of Mexico that are included in production expenses in the income statement. The income tax adjustment reflects the effect on deferred income taxes of a reduction in the income tax rate in Denmark and a tax settlement in the United Kingdom. The legal settlement reflects the favorable resolution of contingencies on a prior year asset sale, which is reflected in non-operating income in the income statement.

2004: The Corporation recognized gains from the sales of an office building in Scotland, a non-producing property in Malaysia and two mature Gulf of Mexico properties. It also recorded foreign income tax benefits resulting from a change in tax law and a tax settlement. The Corporation recorded an after-tax charge for vacated leased office space in the United Kingdom and severance costs, which is reflected in general and administrative expenses in the income statement.

The Corporation’s future Exploration and Production earnings may be impacted by external factors, such as political risk, volatility in the selling prices of crude oil and natural gas, reserve and production changes, industry cost inflation, exploration expenses, the effects of weather and changes in foreign exchange and income tax rates.

Marketing and Refining

Earnings from Marketing and Refining activities amounted to $390 million in 2006, $515 million in 2005 and $451 million in 2004. After considering the Marketing and Refining items in the table on page 23, the earnings amounted to $390 million in 2006, $491 million in 2005 and $439 million in 2004 and are discussed in the paragraphs below. The Corporation’s downstream operations include HOVENSA, a 50% owned refining joint venture with a subsidiary of Petroleos de Venezuela S.A. (PDVSA) that is accounted for using the equity method. Additional Marketing and Refining activities include a fluid catalytic cracking facility in Port Reading, New Jersey, as well as retail gasoline stations, energy marketing and trading operations.

Refining: Refining earnings, which consist of the Corporation’s share of HOVENSA’s results, Port Reading earnings, interest income on a note receivable from PDVSA and other miscellaneous items were $236 million in 2006, $346 million in 2005 and $302 million in 2004.

The Corporation’s share of HOVENSA’s net income was $125 million ($203 million before income taxes) in 2006 and $231 million ($376 million before income taxes) in 2005 and $216 million ($244 million before income taxes) in 2004. The lower earnings in 2006 were principally due to lower refined product margins. Refined product margins were higher in 2005 compared with 2004. In 2006 and 2005, the Corporation provided income taxes at the Virgin Islands statutory rate of 38.5% on HOVENSA’s income and the interest income on the note receivable from PDVSA. In 2004, income taxes on HOVENSA’s earnings were partially offset by available loss carryforwards. In 2006, the fluid catalytic cracking unit was shutdown for approximately 22 days of unscheduled maintenance. During 2005, a crude unit and the fluid catalytic cracking unit at HOVENSA were each shutdown for approximately 30 days of scheduled maintenance. Cash distributions from HOVENSA were $400 million in 2006, $275 million in 2005 and $88 million in 2004.

Pre-tax interest on the PDVSA note was $15 million, $20 million and $25 million in 2006, 2005 and 2004, respectively. Interest income is reflected in non-operating income in the income statement. At December 31, 2006, the remaining balance of the PDVSA note was $137 million, which is scheduled to be fully repaid by February 2009.

Port Reading’s after-tax earnings were $99 million in 2006, $100 million in 2005 and $60 million in 2004. Higher refined product sales volumes were offset by lower margins in 2006 compared with 2005. Refined product margins were higher in 2005 compared with 2004. In 2005, the Port Reading facility was shutdown for 36 days of planned maintenance.

The following table summarizes refinery utilization rates:


	Refinery		Refinery Utilization
	Capacity		2006		2005		2004
	(Thousands of
	barrels per day)

HOVENSA
Crude		500		89.7%		92.2%		96.7%
Fluid catalytic cracker		150		84.3%		81.9%		92.9%
Coker		58		84.3%		92.8%		94.5%
Port Reading		65		97.4%		85.3%		83.4%

Marketing: Marketing operations, which consist principally of retail gasoline and energy marketing activities, generated income of $108 million in 2006, $112 million in 2005 and $100 million in 2004, excluding the income from liquidation of LIFO inventories and the charge related to a customer bankruptcy described below. The decrease in 2006 primarily reflects lower margins on refined product sales. The increase in 2005 was primarily due to higher margins and increased sales volumes compared with 2004. Total refined product sales volumes were 459,000 barrels per day in 2006, 456,000 barrels per day in 2005 and 428,000 barrels per day in 2004.

The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions for its own account. The Corporation’s after-tax results from trading activities, including its share of the earnings of the trading partnership, amounted to income of $46 million in 2006, $33 million in 2005 and $37 million in 2004. Before income taxes, the trading income amounted to $83 million in 2006, $60 million in 2005 and $72 million in 2004 and is included in operating revenues in the income statement.

Marketing expenses increased due to higher expenses resulting from an increased number of retail convenience stores, growth in energy marketing operations, and higher utility and compensation related costs.

Reported Marketing and Refining earnings include the following items of income (expense) before and after income taxes:


	Before Income Taxes							After Income Taxes
	2006		2005			2004		2006		2005			2004
	(Millions of dollars)

LIFO inventory liquidation	$	—	$	51		$	20	$	—	$	32		$	12
Charge related to customer bankruptcy		—		(13	)		—		—		(8	)		—

	$	—	$	38		$	20	$	—	$	24		$	12

In 2005 and 2004, Marketing and Refining earnings include income from the liquidation of prior year LIFO inventories. In 2005, earnings include a charge resulting from the bankruptcy of a customer in the utility industry, which is included in marketing expenses.

The Corporation’s future Marketing and Refining earnings may be impacted by volatility in Marketing and Refining margins, competitive industry conditions, government regulatory changes, credit risk and supply and demand factors, including the effects of weather.

Corporate

The following table summarizes corporate expenses:


	2006			2005			2004
	(Millions of dollars)

Corporate expenses (excluding the items listed below)	$	156		$	119		$	116
Income taxes (benefits) on the above		(46	)		(26	)		(31	)

		110			93			85
Items affecting comparability between periods, after tax
Tax on repatriated earnings		—			72			—
Premiums on bond repurchases		—			26			—
Income tax adjustments		—			—			(13	)
Insurance accrual		—			—			13

Net corporate expenses	$	110		$	191		$	85

Excluding the items affecting comparability between periods, the increase in corporate expenses in 2006 compared to 2005 primarily reflects the expensing of stock options commencing January 1, 2006 and increases in insurance costs. Recurring after-tax corporate expenses in 2007 are estimated to be in the range of $115 to $125 million.

In 2005, the American Jobs Creation Act provided for a one-time reduction in the income tax rate to 5.25% on the remittance of eligible dividends from foreign subsidiaries to a United States parent. The Corporation repatriated $1.9 billion of previously unremitted foreign earnings resulting in the recognition of an income tax provision of $72 million. The pre-tax amount of bond repurchase premiums in 2005 was $39 million and is reflected in non-operating income in the income statement. The pre-tax amount of the 2004 corporate insurance accrual was $20 million and is reflected in non-operating income.

Interest

After-tax interest expense was as follows:


	2006		2005		2004
	(Millions of dollars)

Total interest incurred	$	301	$	304	$	295
Less capitalized interest		100		80		54

Interest expense before income taxes		201		224		241
Less income taxes		74		84		90

After-tax interest expense	$	127	$	140	$	151

After-tax interest expense in 2007 is expected to be in the range of $170 to $180 million, principally reflecting an anticipated decrease in capitalized interest due to the achievement of first production from several development projects.

Sales and Other Operating Revenues

Sales and other operating revenues totaled $28,067 million in 2006, an increase of 23% compared with 2005. The increase reflects higher selling prices of crude oil, higher sales volumes and reduced crude oil hedge positions in Exploration and Production activities and higher selling prices and sales volumes in marketing activities. In 2005, sales and other operating revenues totaled $22,747 million, an increase of 36% compared with 2004. This increase principally reflects higher selling prices of crude oil and natural gas in Exploration and Production and higher

selling prices and sales volumes in marketing activities. The change in cost of goods sold in each year reflects the change in sales volumes and prices of refined products and purchased natural gas.

Liquidity and Capital Resources

The following table sets forth certain relevant measures of the Corporation’s liquidity and capital resources as of December 31:


	2006			2005
	(Millions of dollars)

Cash and cash equivalents	$	383		$	315
Current portion of long-term debt	$	27		$	26
Total debt	$	3,772		$	3,785
Stockholders’ equity	$	8,111		$	6,286
Debt to capitalization ratio*		31.7	%		37.6	%


*		Total debt as a percentage of the sum of total debt plus stockholders’ equity.

Cash Flows

The following table sets forth a summary of the Corporation’s cash flows:


	2006			2005			2004
	(Millions of dollars)

Net cash provided by (used in):
Operating activities	$	3,491		$	1,840		$	1,903
Investing activities		(3,289	)		(2,255	)		(1,371	)
Financing activities		(134	)		(147	)		(173	)

Net increase (decrease) in cash and cash equivalents	$	68		$	(562	)	$	359

Operating Activities: In 2006, net cash provided by operating activities, including changes in operating assets and liabilities, was $3,491 million, an increase of $1,651 million from 2005, principally reflecting higher earnings, changes in working capital accounts and increased distributions from HOVENSA. Net cash provided by operating activities was $1,840 million in 2005 compared with $1,903 million in 2004. The change was due to higher earnings in 2005, offset by a decrease from changes in operating assets and liabilities, principally working capital, of $408 million. The Corporation received cash distributions from HOVENSA of $400 million in 2006, $275 million in 2005 and $88 million in 2004.

Investing Activities: The following table summarizes the Corporation’s capital expenditures:


	2006		2005		2004
	(Millions of dollars)

Exploration and Production
Exploration	$	590	$	229	$	168
Production and development		2,164		1,598		1,204
Acquisitions (including leasehold)		921		408		62

		3,675		2,235		1,434
Marketing, Refining and Corporate		169		106		87

Total	$	3,844	$	2,341	$	1,521

Capital expenditures in 2006 include payments of $359 million to acquire the Corporation’s former oil and gas production operations in the Waha concessions in Libya and $413 million to acquire a 55% working interest in the West Med Block in Egypt.

Proceeds from asset sales in 2006 totaled $444 million, including the sale of the Corporation’s interests in certain producing properties in the Permian Basin and onshore U.S. Gulf Coast. Proceeds from asset sales were $74 million and $57 million in 2005 and 2004, respectively, principally from the sale of non-producing properties.

Financing Activities: The Corporation reduced debt by $13 million in 2006, $50 million in 2005 and $106 million in 2004. The net reductions in debt in 2006, 2005 and 2004 were funded by available cash and cash flow from operations. In 2005, bond repurchases of $600 million were funded by borrowings on the revolving credit facility in connection with the repatriation of foreign earnings to the United States.

Dividends paid were $161 million in 2006, $159 million in 2005 and $157 million in 2004. The Corporation received proceeds from the exercise of stock options totaling $40 million, $62 million and $90 million in 2006, 2005 and 2004, respectively.

Future Capital Requirements and Resources

The Corporation anticipates $4.0 billion in capital and exploratory expenditures in 2007, of which $3.9 billion relates to Exploration and Production operations. The Corporation has maturities of long-term debt of $27 million in 2007 and $28 million in 2008. The Corporation anticipates that it can fund its 2007 operations, including capital expenditures, dividends, pension contributions and required debt repayments, with existing cash on-hand, cash flow from operations and its available credit facilities.

During 2006, the Corporation amended and restated its existing syndicated, revolving credit facility (the facility) to increase the credit line to $3.0 billion from $2.5 billion and extend the term to May 2011 from December 2009. The facility can be used for borrowings and letters of credit. At December 31, 2006, the Corporation has $2.7 billion available under this facility.

The Corporation has a364-day asset-backed credit facility securitized by certain accounts receivable from its Marketing and Refining operations, which are sold to a wholly-owned subsidiary. Under the terms of this financing arrangement, the Corporation has the ability to borrow up to $800 million, subject to the availability of sufficient levels of eligible receivables. At December 31, 2006, the Corporation has $318 million in outstanding borrowings under this facility which was collateralized by approximately $1,100 million of receivables. These receivables are not available to pay the general obligations of the Corporation before repayment of outstanding borrowings under theasset-backed facility.

The Corporation has additional unused lines of credit of approximately $370 million, primarily for letters of credit, under uncommitted arrangements with banks. The Corporation also has a shelf registration under which it may issue additional debt securities, warrants, common stock or preferred stock.

Outstanding letters of credit at December 31, were as follows:


	2006		2005
	(Millions of dollars)

Lines of Credit
Revolving credit facility	$	1	$	28
Committed short-term letter of credit facilities		1,875		1,675
Uncommitted lines		1,603		982

	$	3,479	$	2,685

Loan agreement covenants allow the Corporation to borrow up to an additional $9.7 billion for the construction or acquisition of assets at December 31, 2006. The Corporation has the ability to borrow up to an additional $2.2 billion of secured debt at December 31, 2006 under the loan agreement covenants. At December 31, 2006, the maximum amount of dividends or stock repurchases that can be paid from borrowings under the loan agreement covenants is $3.7 billion.

Credit Ratings

There are three major credit rating agencies that rate the Corporation’s debt. Two credit agencies have assigned an investment grade rating to the Corporation’s debt and one agency has rated it below investment grade. The interest rate and facility fee are subject to adjustment if the Corporation’s credit rating changes. In addition, if any one of the three rating agencies were to reduce their rating on the Corporation’s senior unsecured debt, margin requirements with non-trading and trading counterparties at December 31, 2006 would increase by up to approximately $140 million.

Contractual Obligations and Contingencies

Following is a table showing aggregated information about certain contractual obligations at December 31, 2006:


			Payments Due by Period
					2008 and		2010 and
	Total		2007		2009		2011		Thereafter
	(Millions of dollars)

Long-term debt(a)	$	3,772	$	27	$	171	$	1,340	$	2,234
Operating leases		2,471		630		567		198		1,076
Purchase obligations
Supply commitments		25,800		8,381		8,990		8,429		(b	)
Capital expenditures		1,109		809		263		37		—
Operating expenses		794		477		187		89		41
Other long-term liabilities		1,316		65		285		220		746


(a)		At December 31, 2006, the Corporation’s debt bears interest at a weighted average rate of 7.0%.

(b)		The Corporation intends to continue purchasing refined product supply from HOVENSA. Estimated future purchases amount to approximately $4.2 billion annually using year-end 2006 prices.

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

The table also reflects that portion of the Corporation’s planned $4 billion capital investment program for 2007 that is contractually committed at December 31, 2006. Obligations for operating expenses include commitments for transportation, seismic purchases, oil and gas production expenses and other normal business expenses. Other long-term liabilities reflect contractually committed obligations on the balance sheet at December 31, including asset retirement obligations and pension plan funding requirements.

At December 31, 2006, the Corporation had a remaining accrual of $49 million for vacated leased office space costs. In 2006, the Corporation recorded an additional $30 million charge for vacated leased office space ($18 million after income taxes) and made payments of $12 million. At December 31, 2005, the accrual was $31 million after reduction for payments of $8 million during 2005.

The Corporation has a contingent purchase obligation, expiring in April 2010, to acquire the remaining interest in WilcoHess, a retail gasoline station joint venture, for approximately $140 million as of December 31, 2006.

The Corporation guarantees the payment of up to 50% of HOVENSA’s crude oil purchases from suppliers other than PDVSA. The amount of the Corporation’s guarantee fluctuates based on the volume of crude oil purchased and related prices and at December 31, 2006, amounted to $229 million. In addition, the Corporation has

agreed to provide funding up to a maximum of $15 million to the extent HOVENSA does not have funds to meet its senior debt obligations.

At December 31, 2006, the Corporation has $3,427 million of letters of credit principally relating to accrued liabilities with hedging and trading counterparties recorded on its balance sheet. In addition, the Corporation is contingently liable under letters of credit and under guarantees of the debt of other entities directly related to its business, as follows:


	Total
	(Millions of
	dollars)

Letters of credit	$	52
Guarantees		301	*

	$	353


*		Includes $15 million HOVENSA debt and $229 million crude oil purchase guarantees discussed above. The remainder relates to a loan guarantee of $57 million for an oil pipeline in which the Corporation owns a 2.36% interest.

Off-Balance Sheet Arrangements

The Corporation has leveraged leases not included in its balance sheet, primarily related to retail gasoline stations that the Corporation operates. The net present value of these leases is $490 million at December 31, 2006 compared with $480 million at December 31, 2005. The Corporation’s December 31, 2006 debt to capitalization ratio would increase from 31.7% to 34.4% if these leases were included as debt.

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

Stock Split

On May 3, 2006, the Corporation’s shareholders voted to increase the number of authorized common shares from 200 million to 600 million and the board of directors declared athree-for-one stock split. The stock split was completed in the form of a stock dividend that was issued on May 31, 2006 to shareholders of record on May 17, 2006. The common share par value remained at $1.00 per share. All common share and per share amounts in the financial statements and notes and management’s discussion and analysis are on an after-split basis for all periods presented.

Foreign Operations

The Corporation conducts exploration and production activities in the United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Malaysia, Thailand, Russia, Gabon, Azerbaijan, Indonesia, Libya, Egypt and other countries. Therefore, the Corporation is subject to the risks associated with foreign operations. These exposures include political risk (including tax law changes) and currency risk.

HOVENSA L.L.C., owned 50% by the Corporation and 50% by Petroleos de Venezuela, S.A. (PDVSA), owns and operates a refinery in the United States Virgin Islands. In the past, there have been political disruptions in Venezuela that reduced the availability of Venezuelan crude oil used in refining operations; however, these disruptions did not have a material adverse effect on the Corporation’s financial position. The Corporation has a note receivable of $137 million at December 31, 2006 from a subsidiary of PDVSA. All payments are current and the Corporation anticipates collection of the remaining balance.

Subsequent Events

In February 2007, the Corporation completed the acquisition of a 28% interest in the Genghis Khan oil and gas development located in the deepwater Gulf of Mexico on Green Canyon Blocks 652 and 608 for $371 million. The Genghis Khan development is part of the same geologic structure as the Shenzi development (Hess 28%) and first production from this development is expected in the second half of 2007.

Accounting Policies

Critical Accounting Policies and Estimates

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

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

The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.

Crude Oil and Natural Gas Reserves: The determination of estimated proved reserves is a significant element in arriving at the results of operations of exploration and production activities. The estimates of proved reserves affect well capitalizations, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets and goodwill.

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

The oil and gas reserve estimates reported in the Supplementary Oil and Gas Data in accordance with Statement of Financial Accounting Standards (FAS) No. 69Disclosures about Oil and Gas Producing Activities(FAS No. 69) are determined independently by the consulting firm of DeGolyer and MacNaughton (D&M) and are consistent with internal estimates. Annually, the Corporation provides D&M with engineering, geological and geophysical data, actual production histories and other information necessary for the reserve determination. The Corporation’s and D&M’s technical staffs meet to review and discuss the information provided. Senior management and the Board of Directors review the final reserve estimates issued by D&M.

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

estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

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

The Corporation’s impairment tests of long-lived Exploration and Production producing assets are based on its best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs and the timing of future production, which are updated each time an impairment test is performed. The Corporation could have impairments if the projected production volumes from oil and gas fields were reduced. Significant extended declines in crude oil and natural gas selling prices could also result in asset impairments.

In accordance with FAS No. 142Goodwill and Other Intangible Assets(FAS No. 142), the Corporation’s goodwill is not amortized, but is tested for impairment annually in the fourth quarter at a reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. The Corporation’s goodwill is assigned to the Exploration and Production operating segment and it expects that the benefits of goodwill will be recovered through the operation of that segment.

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

The determination of the fair value of the Exploration and Production operating segment depends on estimates about oil and gas reserves, future prices, timing of future net cash flows and market premiums. Significant extended declines in crude oil and natural gas prices or reduced reserve estimates could lead to a decrease in the fair value of the Exploration and Production operating segment that could result in an impairment of goodwill.

Because there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing, there may be impairments of individual assets that would not cause an impairment of the goodwill assigned to the Exploration and Production segment.

Segments: The Corporation has two operating segments, Exploration and Production and Marketing and Refining. Management has determined that these are its operating segments because, in accordance with FAS No. 131Disclosures about Segments of an Enterprise and Related Information(FAS No. 131), these are the segments of the Corporation (i) that engage in business activities from which revenues are earned and expenses are incurred, (ii) whose operating results are regularly reviewed by the Corporation’s chief operating decision maker (CODM) to make decisions about resources to be allocated to the segment and assess its performance and (iii) for which discrete financial information is available. The Chairman of the Board and Chief Executive Officer of the Corporation, is the CODM as defined in FAS No. 131, because he is responsible for performing the functions within the Corporation of allocating resources to, and assessing the performance of, the Corporation’s operating segments.

Derivatives: The Corporation utilizes derivative instruments for both non-trading and trading activities. In non-trading activities, the Corporation uses futures, forwards, options and swaps, individually or in combination to mitigate its exposure to fluctuations in the prices of crude oil, natural gas, refined products and electricity, and changes in foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated

partnership, trades energy commodities derivatives, including futures, forwards, options and swaps, based on expectations of future market conditions.

All derivative instruments are recorded at fair value in the Corporation’s balance sheet. The Corporation’s policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges under FAS No. 133 are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.

Derivatives that are designated as either cash flow or fair value hedges are tested for effectiveness prospectively before they are executed and both prospectively and retrospectively on an on-going basis to determine whether they continue to qualify for hedge accounting. The prospective and retrospective effectiveness calculations are performed using either historical simulation or other statistical models, which utilize historical observable market data consisting of futures curves and spot prices.

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

Changes in Accounting Policies

Effective January 1, 2006, the Corporation adopted the provisions of FAS No. 123R,Share-Based Payment(FAS No. 123R). FAS No. 123R requires that the fair value of all stock-based compensation to employees, including grants of stock options, be expensed over the vesting period. Through December 31, 2005, the Corporation used the intrinsic value method to account for employee stock options. Because the exercise prices of employee stock options equaled or exceeded the market price of the stock on the date of grant, the Corporation did not recognize compensation expense under the intrinsic value method. See note 9, “Share-Based Compensation,” in the notes to the consolidated financial statements.

In September 2006, the Financial Accounting Standards Board (FASB) issued FAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans(FAS No. 158). FAS No. 158 requires recognition on the balance sheet of the overfunded or underfunded status of a defined benefit postretirement plan measured as the difference between the fair value of plan assets and the benefit obligation. As required, the Corporation prospectively adopted the provisions of FAS No. 158 on December 31, 2006. See note 11, “Retirement Plans,” in the notes to the consolidated financial statements.

Recently Issued Accounting Standards

In September 2006, the FASB issued Staff Position (FSP) AUG AIR-1,Accounting for Planned Major Maintenance Activities. This FSP eliminates the previously acceptableaccrue-in-advance method of accounting for planned major maintenance. As a result, the Corporation will retrospectively change its method of accounting for

refinery turnarounds on January 1, 2007, the effective date of this pronouncement, to recognize expenses associated with refinery turnarounds when such costs are incurred. Under the retrospective method of adoption, the Corporation expects to increase 2006 earnings by approximately $4 million, reduce 2005 earnings by approximately $16 million and increase retained earnings as of January 1, 2005 by approximately $66 million.

In July 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes(FIN 48). FIN 48 prescribes the financial statement recognition and measurement criteria for a tax position taken or expected to be taken in a tax return. FIN 48 also requires additional disclosures related to uncertain income tax positions. As required, the Corporation will adopt the provisions of FIN 48 effective January 1, 2007. The Corporation has not concluded its evaluation of the impact of adopting FIN 48 on its results of operations, financial position or cash flows.

In September 2006, the FASB issued FAS No. 157,Fair Value Measurements (FAS No. 157). FAS No. 157 establishes a fair value hierarchy, which applies broadly to financial and non-financial assets and liabilities measured at fair value under other authoritative accounting pronouncements. Additionally, the standard requires increased disclosure of the methods of determining fair value. The Corporation is currently evaluating the impact of adoption on its financial statements and, as required, the Corporation will adopt the provisions of FAS No. 157 effective January 1, 2008.

Environment, Health and Safety

The Corporation has implemented a values-based, socially-responsible strategy focused on improving environment, health and safety performance and making a positive impact on communities. The strategy is supported by the Corporation’s environment, health, safety and social responsibility (EHS & SR) policies and by environment and safety management systems that help protect the Corporation’s workforce, customers and local communities. The Corporation’s management systems are designed to uphold or exceed international standards and are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short-term, increase the Corporation’s operating costs and could also require increased capital expenditures to reduce potential risks to assets, reputation and license to operate. In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be captured as collateral benefits from investments in EHS & SR. The Corporation has programs in place to evaluate regulatory compliance, audit facilities, train employees and to generally meet corporate EHS & SR goals.

The production of motor and other fuels in the United States and elsewhere has faced increasing regulatory pressures in recent years. In 2004, new regulations went into effect that have already significantly reduced gasoline sulfur content and additional regulations to reduce the allowable sulfur content in diesel fuel went into effect in 2006. Additional reductions in gasoline and fuel oil sulfur content are under consideration. Fuels production will likely continue to be subject to more stringent regulation in future years and as such may require additional capital expenditures.

Capital expenditures necessary to comply with low-sulfur gasoline requirements at Port Reading were $72 million, of which $23 million was spent in 2005 and the remainder was spent in 2006. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are presently expected to be approximately $420 million in total, $360 million of which has already been spent and the remainder is expected to be spent in 2007. HOVENSA has and continues to plan to finance these capital expenditures through cash flow from operations.

The Energy Policy Act of 2005 eliminated the Clean Air Act’s mandatory oxygen content requirement for reformulated gasoline and imposes on refiners a requirement to use specific quantities of renewable content in gasoline. Many states have also enacted bans on the use of MTBE in gasoline, many of which will take effect between 2007 and 2009. As a result, several companies have announced their intention to cease using MTBE, since it will no longer be needed in reformulated gasoline to comply with the Clean Air Act and does not meet the new renewable content requirement. In response to these changes in the gasoline marketplace, the Corporation and HOVENSA phased out the use of ether based oxygenates during 2006. Both companies are reviewing the most cost effective means to replace ether unit processing capabilities, which may necessitate additional capital investments.

As described in Item 3 “Legal Proceedings,” in 2003 the Corporation and HOVENSA began discussions with the U.S. EPA regarding the EPA’s Petroleum Refining Initiative (PRI). The PRI is an ongoing program that is designed to reduce certain air emissions at all U.S. refineries. Since 2000, the EPA has entered into settlements addressing these emissions with petroleum refining companies that control over 77% of the domestic refining capacity. Negotiations with the EPA are continuing and depending on the outcome of these discussions, the Corporation and HOVENSA may experience increased capital expenditures and operating expenses related to air emissions controls. Settlements with other refiners allow for controls to be phased in over several years.

HOVENSA is constructing a new wastewater treatment system at the refinery. This project will significantly enhance the refinery’s ability to treat wastewater and better protect the marine environment of St. Croix. The cost to complete the project is approximately $120 million, of which $55 million has already been incurred.

The Corporation has undertaken a program to assess, monitor and reduce the emission of “greenhouse gases,” including carbon dioxide and methane. The challenges associated with this program are significant, not only from the standpoint of technical feasibility, but also from the perspective of adequately measuring the Corporation’s greenhouse gas inventory. The Corporation has completed a revised monitoring protocol which will allow for better measurement of “greenhouse gases” and is conducting an independently verified audit of its emissions. Once completed, the monitoring protocol will allow for better control of these emissions and assist the Corporation in complying with any future regulatory restrictions.

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

The Corporation accrues for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. At year-end 2006, the Corporation’s reserve for its estimated environmental liability was approximately $75 million. The Corporation expects that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. The Corporation’s remediation spending was $15 million in 2006 and 2005 and $12 million in 2004. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, other than for low sulfur projects discussed above, were $22 million in 2006, $3 million in 2005 and $1 million in 2004.

Forward-Looking Information

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, including references to the Corporation’s future results of operations and financial position, liquidity and capital resources, capital expenditures, oil and gas production, tax rates, debt repayment, hedging, derivative, market risk and environmental disclosures, off-balance sheet arrangements and contractual obligations and contingencies include forward-looking information. Forward-looking disclosures are based on the Corporation’s current understanding and assessment of these activities and reasonable assumptions about the future. Actual results may differ from these disclosures because of changes in market conditions, government actions and other factors.


Item 7A.	*Quantitative and Qualitative Disclosures About Market Risk*

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

Controls: The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include

volumetric, term andvalue-at-risk limits. In addition, the chief risk officer must approve the use of new instruments or commodities. Risk limits are monitored daily and exceptions are reported to business units and to senior management. The Corporation’s risk management department also performs independent verifications of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s non-trading and trading activities, including the consolidated trading partnership. The Corporation’s treasury department administers foreign exchange rate and interest rate hedging programs.

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


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

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

	•	Exchange Traded Contracts: The Corporation uses exchange traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.

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

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

	•	Energy Securities: Energy securities include energy related equity or debt securities issued by a company or government or related derivatives on these securities.

Value-at-Risk: The Corporation usesvalue-at-risk to monitor and control commodity risk within its trading and non-trading activities. Thevalue-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 thevalue-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)

2006
At December 31	$	17	$	62
Average for the year		20		75
High during the year		22		86
Low during the year		17		62
2005
At December 31	$	18	$	93
Average for the year		11		111
High during the year		18		127
Low during the year		7		93

Non-Trading: The Corporation’s non-trading activities may include hedging of crude oil and natural gas production. Futures and swaps are used to fix the selling prices of a portion of the Corporation’s future production and the related gains or losses are an integral part of the Corporation’s selling prices. Following is a summary of the Corporation’s outstanding crude oil hedges at December 31, 2006:


	Brent Crude Oil
	Average		Thousands of
Maturity	Selling Price		Barrels per Day

2007	$	25.85		24
2008		25.56		24
2009		25.54		24
2010		25.78		24
2011		26.37		24
2012		26.90		24

There were no hedges of WTI crude oil or natural gas production at December 31, 2006. As market conditions change, the Corporation may adjust its hedge percentages. The Corporation also markets energy commodities including refined petroleum products, natural gas and electricity. The Corporation uses futures and swaps to manage the risk in its marketing activities.

Accumulated other comprehensive income (loss) at December 31, 2006 includes after-tax unrealized deferred losses of $1,338 million primarily related to crude oil contracts used as hedges of exploration and production sales. The pre-tax amount of deferred hedge losses is reflected in accounts payable and the related income tax benefits are recorded as deferred tax assets on the balance sheet.

The Corporation uses foreign exchange contracts to reduce its exposure to fluctuating foreign exchange rates by entering into forward purchase contracts for both the British pound sterling and the Danish kroner. At December 31, 2006, the Corporation had $729 million of notional value foreign exchange contracts maturing in 2007. The fair value of the foreign exchange contracts was a receivable of $51 million at December 31, 2006. The change in fair value of the foreign exchange contracts from a 10% change in exchange rates is estimated to be approximately $80 million at December 31, 2006.

The Corporation’s outstanding debt of $3,772 million has a fair value of $4,105 million at December 31, 2006. A 15% decrease in the rate of interest would increase the fair value of debt by approximately $300 million at December 31, 2006.

Trading: In trading activities, the Corporation is exposed to changes in crude oil, natural gas and refined product prices. The trading partnership in which the Corporation has a 50% voting interest trades energy

commodities and derivatives. The accounts of the partnership are consolidated with those of the Corporation. The Corporation also takes trading positions for its own account. The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts.

Gains or losses from sales of physical products are recorded at the time of sale. Derivative trading transactions aremarked-to-market and are reflected in income currently. Total realized gains for the year amounted to $721 million ($297 million of realized losses for 2005). The following table provides an assessment of the factors affecting the changes in fair value of trading activities and represents 100% of the trading partnership and other trading activities.


	2006			2005
	(Millions of dollars)

Fair value of contracts outstanding at the beginning of the year	$	1,109		$	184
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of year		(82	)		6
Reversal of fair value for contracts closed during the year		(547	)		(23	)
Fair value of contracts entered into during the year and still outstanding		(115	)		942

Fair value of contracts outstanding at the end of the year	$	365		$	1,109

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

The following table summarizes the sources of fair values of derivatives used in the Corporation’s trading activities at December 31:


												2010 and
	Total			2007			2008			2009		Beyond
	(Millions of dollars)

Source of fair value
Prices actively quoted	$	357		$	198		$	62		$	65	$	32
Other external sources		24			30			(12	)		—		6
Internal estimates		(16	)		(16	)		—			—		—

Total	$	365		$	212		$	50		$	65	$	38

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


	2006		2005
	(Millions of dollars)

Investment grade determined by outside sources	$	347	$	353
Investment grade determined internally*		59		139
Less than investment grade		41		70

Fair value of net receivables outstanding at the end of the year	$	447	$	562


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


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		43
Reports of Independent Registered Public Accounting Firm		44
Consolidated Balance Sheet at December 31, 2006 and 2005		46
Statement of Consolidated Income for each of the three years in the period ended December 31, 2006		47
Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2006		48
Statement of Consolidated Stockholders’ Equity for each of the three years in the period ended December 31, 2006		49
Statement of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2006		50
Notes to Consolidated Financial Statements		51
Supplementary Oil and Gas Data		78
Quarterly Financial Data		84
Consent of Independent Registered Public Accounting Firm		90
Schedule* II — Valuation and Qualifying Accounts		91


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

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 ActRules 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 inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2006.

Our management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.


By		/s/ John P. Rielly John P. Rielly Senior Vice President and Chief Financial Officer		By		/s/ John B. Hess John B. Hess Chairman of the Board and Chief Executive Officer

February 23, 2007

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Hess Corporation

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Hess Corporation (formerly, Amerada Hess Corporation) and consolidated subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Hess Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Hess Corporation and consolidated subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Hess Corporation and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheet of Hess Corporation and consolidated subsidiaries as of December 31, 2006 and 2005, and the related statements of consolidated income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2006, and our report dated February 23, 2007 expressed an unqualified opinion on these statements.

New York, NY
February 23, 2007

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Hess Corporation

We have audited the accompanying consolidated balance sheet of Hess Corporation (formerly, Amerada Hess Corporation) and consolidated subsidiaries as of December 31, 2006 and 2005, and the related statements of consolidated income, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2006. Our audits also included the Financial Statement Schedule listed in the Index at Item 8. These financial statements and schedule are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Hess Corporation and consolidated subsidiaries at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related Financial Statement Schedule, when considered in relation to the consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Corporation adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment, effective January 1, 2006. Also as discussed in Note 11 to the consolidated financial statements, the Corporation adopted the provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Hess Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2007 expressed an unqualified opinion thereon.

New York, NY
February 23, 2007

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	At December 31
	2006			2005
	(Millions of dollars; thousands of shares)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	383		$	315
Accounts receivable
Trade		3,659			3,517
Other		214			138
Inventories		1,005			855
Other current assets		587			465

Total current assets		5,848			5,290

INVESTMENTS IN AFFILIATES
HOVENSA L.L.C.		1,012			1,217
Other		188			172

Total investments in affiliates		1,200			1,389

PROPERTY, PLANT AND EQUIPMENT
Exploration and Production		20,199			17,836
Marketing and Refining		1,781			1,628

Total — at cost		21,980			19,464
Less reserves for depreciation, depletion, amortization and lease impairment		9,672			9,952

Property, plant and equipment — net		12,308			9,512

GOODWILL		1,253			977
DEFERRED INCOME TAXES		1,435			1,544
OTHER ASSETS		360			403

TOTAL ASSETS	$	22,404		$	19,115

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	4,803		$	4,995
Accrued liabilities		1,477			1,029
Taxes payable		432			397
Current maturities of long-term debt		27			26

Total current liabilities		6,739			6,447

LONG-TERM DEBT		3,745			3,759
DEFERRED INCOME TAXES		2,099			1,401
ASSET RETIREMENT OBLIGATIONS		824			564
OTHER LIABILITIES AND DEFERRED CREDITS		886			658

Total Liabilities		14,293			12,829

STOCKHOLDERS’ EQUITY
Preferred stock, par value $1.00, 20,000 shares authorized
7% cumulative mandatory convertible series Authorized — 0 shares in 2006; 13,500 shares in 2005 Issued — 0 shares in 2006; 13,500 shares in 2005		—			14
3% cumulative convertible series Authorized — 330 shares Issued — 324 shares in 2006 and 2005 ($16 million liquidation preference)		—			—
Common stock*, par value $1.00
Authorized — 600,000 shares
Issued — 315,018 shares in 2006; 279,197 shares in 2005		315			279
Capital in excess of par value*		1,689			1,656
Retained earnings		7,671			5,914
Accumulated other comprehensive income (loss)		(1,564	)		(1,526	)
Deferred compensation		—			(51	)

Total stockholders’ equity		8,111			6,286

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	22,404		$	19,115


*	Common stock and Capital in excess of par value as of December 31, 2005 are restated to reflect the impact of a3-for-1 stock split on May 31, 2006.

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

See accompanying notes to consolidated financial statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME


	For the Years Ended
	December 31
	2006		2005		2004
	(In millions, except per share data)

REVENUES AND NON-OPERATING INCOME
Sales (excluding excise taxes) and other operating revenues	$	28,067	$	22,747	$	16,733
Non-operating income
Equity in income of HOVENSA L.L.C.		203		376		244
Gain on asset sales		369		48		55
Other, net		81		84		94

Total revenues and non-operating income		28,720		23,255		17,126

COSTS AND EXPENSES
Cost of products sold (excluding items shown separately below)		19,912		17,041		11,971
Production expenses		1,250		1,007		825
Marketing expenses		940		842		737
Exploration expenses, including dry holes and lease impairment		552		397		287
Other operating expenses		130		136		195
General and administrative expenses		471		357		342
Interest expense		201		224		241
Depreciation, depletion and amortization		1,224		1,025		970

Total costs and expenses		24,680		21,029		15,568

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		4,040		2,226		1,558
Provision for income taxes		2,124		984		588

INCOME FROM CONTINUING OPERATIONS		1,916		1,242		970
DISCONTINUED OPERATIONS		—		—		7

NET INCOME	$	1,916	$	1,242	$	977

Less preferred stock dividends		44		48		48

NET INCOME APPLICABLE TO COMMON SHAREHOLDERS	$	1,872	$	1,194	$	929

BASIC EARNINGS PER SHARE*
Continuing operations	$	6.73	$	4.38	$	3.43
Net income		6.73		4.38		3.46
DILUTED EARNINGS PER SHARE*
Continuing operations	$	6.07	$	3.98	$	3.17
Net income		6.07		3.98		3.19
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)*		315.7		312.1		306.3


*		Weighted average number of shares and per-share amounts in all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

See accompanying notes to consolidated financial statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS


	For the Years Ended
	December 31
	2006			2005			2004
	(Millions of dollars)

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,916		$	1,242		$	977
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		1,224			1,025			970
Exploratory dry hole costs		241			170			81
Lease impairment		99			78			77
Pre-tax gain on asset sales		(369	)		(48	)		(55	)
Provision (benefit) for deferred income taxes		279			(118	)		(211	)
Distributed (undistributed) earnings of HOVENSA L.L.C., net		197			(101	)		(156	)
Non-cash effect of discontinued operations		—			—			(7	)
Changes in other operating assets and liabilities:
Increase in accounts receivable		(179	)		(1,042	)		(705	)
Increase in inventories		(152	)		(270	)		(16	)
Increase (decrease) in accounts payable and accrued liabilities		(44	)		877			783
Increase (decrease) in taxes payable		47			(111	)		131
Changes in other assets and liabilities		232			138			34

Net cash provided by operating activities		3,491			1,840			1,903

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures
Exploration and Production		(3,675	)		(2,235	)		(1,434	)
Marketing and Refining		(169	)		(106	)		(87	)

Total capital expenditures		(3,844	)		(2,341	)		(1,521	)
Proceeds from asset sales		444			74			57
Payments received on notes receivable		76			60			90
Other		35			(48	)		3

Net cash used in investing activities		(3,289	)		(2,255	)		(1,371	)

CASH FLOWS FROM FINANCING ACTIVITIES
Debt with maturities of greater than 90 days
Borrowings		320			600			25
Repayments		(333	)		(650	)		(131	)
Cash dividends paid		(161	)		(159	)		(157	)
Employee stock options exercised		40			62			90

Net cash used in financing activities		(134	)		(147	)		(173	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		68			(562	)		359
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		315			877			518

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	383		$	315		$	877

See accompanying notes to consolidated financial statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED STOCKHOLDERS’ EQUITY

						��
	2006						2005						2004
	Shares			Amount			Shares			Amount			Shares		Amount
				(Millions of dollars; thousands of shares)

PREFERRED STOCK
Balance at January 1		13,824		$	14			13,827		$	14			13,827	$	14
Conversion of preferred stock to common stock		(13,500	)		(14	)		(3	)		—			—		—

Balance at December 31		324			—			13,824			14			13,827		14

COMMON STOCK*
Balance at January 1		279,197			279			275,145			275			269,604		270
Activity related to restricted common stock awards, net		903			1			948			1			927		1
Employee stock options exercised		1,283			1			3,098			3			4,614		4
Conversion of preferred stock to common stock		33,635			34			6			—			—		—

Balance at December 31		315,018			315			279,197			279			275,145		275

CAPITAL IN EXCESS OF PAR VALUE*
Balance at January 1					1,656						1,544					1,423
Activity related to restricted common stock awards, net					36						37					23
Employee stock options exercised					68						75					98
Conversion of preferred stock to common stock					(20	)					—					—
Reclassification resulting from adoption of FAS 123R					(51	)					—					—

Balance at December 31					1,689						1,656					1,544

RETAINED EARNINGS
Balance at January 1					5,914						4,831					4,011
Net income					1,916						1,242					977
Dividends declared on common stock					(115	)					(111	)				(109	)
Dividends on preferred stock					(44	)					(48	)				(48	)

Balance at December 31					7,671						5,914					4,831

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at January 1					(1,526	)					(1,024	)				(350	)
Net other comprehensive income (loss)					104						(502	)				(674	)
Cumulative effect of adoption of FAS 158					(142	)					—					—

Balance at December 31					(1,564	)					(1,526	)				(1,024	)

DEFERRED COMPENSATION
Balance at January 1					(51	)					(43	)				(28	)
Change in unearned compensation					—						(8	)				(15	)
Reclassification resulting from adoption of FAS 123R					51						—					—

Balance at December 31					—						(51	)				(43	)

TOTAL STOCKHOLDERS’ EQUITY at December 31				$	8,111					$	6,286				$	5,597


*	Common stock and Capital in excess of par value as of January 1, 2004, December 31, 2004 and December 31, 2005 are restated to reflect the impact of a3-for-1 stock split on May 31, 2006.

See accompanying notes to consolidated financial statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME


	For the Years Ended
	December 31
	2006			2005			2004
	(Millions of dollars)

COMPONENTS OF COMPREHENSIVE INCOME
Net income	$	1,916		$	1,242		$	977

Other comprehensive income (loss):
Deferred gains (losses) on cash flow hedges, after tax:
Effect of hedge losses recognized in income		345			946			511
Net change in fair value of cash flow hedges		(379	)		(1,381	)		(1,196	)
Change in minimum postretirement plan liabilities, after tax		90			(33	)		(25	)
Change in foreign currency translation adjustment and other		48			(34	)		36

Net other comprehensive income (loss)		104			(502	)		(674	)

COMPREHENSIVE INCOME	$	2,020		$	740		$	303

See accompanying notes to consolidated financial statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Summary of Significant Accounting Policies

Nature of Business: On May 3, 2006, Amerada Hess Corporation changed its name to Hess Corporation. Hess Corporation and subsidiaries (the Corporation) engage in the exploration for and the development, production, purchase, transportation and sale of crude oil and natural gas. These activities are conducted in the United States, United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Malaysia, Thailand, Russia, Gabon, Azerbaijan, Indonesia, Libya, Egypt and other countries. In addition, the Corporation manufactures, purchases, transports, trades and markets refined petroleum and other energy products. The Corporation owns 50% of HOVENSA L.L.C. (HOVENSA), a refinery joint venture in the United States Virgin Islands. An additional refining facility, terminals and retail gasoline stations, most of which include convenience stores, are located on the East Coast of the United States.

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

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

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

Intercompany transactions and accounts are eliminated in consolidation.

Revenue Recognition: The Corporation recognizes revenues from the sale of crude oil, natural gas, petroleum products and other merchandise when title passes to the customer. Sales are reported net of excise and similar taxes in the consolidated statement of income. The Corporation recognizes revenues from the production of natural gas properties based on sales to customers. Differences between natural gas volumes sold and the Corporation’s share of natural gas production are not material. Revenues from natural gas and electricity sales by the Corporation’s marketing operations are recognized based on meter readings and estimated deliveries to customers since the last meter reading.

In its exploration and production activities, the Corporation enters into crude oil purchase and sale transactions with the same counterparty that are entered into in contemplation of one another for the primary purpose of changing location or quality. Similarly, in its marketing activities, the Corporation also enters into refined product purchase and sale transactions with the same counterparty. These arrangements are reported net in sales and other operating revenue in the consolidated statement of income.

Derivatives: The Corporation utilizes derivative instruments for both non-trading and trading activities. In non-trading activities, the Corporation uses futures, forwards, options and swaps, individually or in combination, to mitigate its exposure to fluctuations in prices of crude oil, natural gas, refined products and electricity, and changes in foreign currency exchange rates. In trading activities, the Corporation, principally through a consolidated partnership, trades energy commodities derivatives, including futures, forwards, options and swaps based on expectations of future market conditions.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges) or hedges of firm commitments (fair value hedges). The effective portion of changes in fair value of derivatives that are designated as cash flow hedges is recorded as a component of other comprehensive income (loss). Amounts included in accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. The ineffective portion of changes in fair value of derivatives designated as cash flow hedges is recorded currently in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.

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

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

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

The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. In accordance with Financial Accounting Standards Board (FASB) Staff Position19-1,Accounting for Suspended Well Costs, which amended FAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies(FAS No. 19), exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.

Depreciation, Depletion and Amortization: The Corporation records depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production equipment and wells is calculated using the units of production method over proved developed oil and gas reserves. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives. Retail gas stations and equipment related to a leased property, are depreciated over the estimated useful lives not to exceed the remaining lease period. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors.

Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying assets.

Asset Retirement Obligations: The Corporation accounts for asset retirement obligations as required by FAS No. 143,Accounting for Asset Retirement Obligationsand FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations. Under these standards, a liability is recognized for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligations are incurred. In addition, the fair value of any legally required conditional asset retirement obligations is recorded if the liability can be reasonably estimated. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets.

Impairment of Long-Lived Assets: The Corporation reviews long-lived assets, including oil and gas properties at a field level, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted future cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. In the case of oil and gas fields, the net present value of future cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from the year-end prices used in the standardized measure of discounted future net cash flows.

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

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

Maintenance and Repairs: Maintenance and repairs are expensed as incurred. The estimated costs of refinery turnarounds are accrued. Capital improvements are recorded as additions in property, plant and equipment.

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

Share-Based Compensation: Effective January 1, 2006, the Corporation adopted FAS No. 123R,Share-Based Payment (FAS No. 123R) which requires that compensation expense be recorded for all share based payments to employees. The Corporation used the modified prospective application method for its adoption of FAS No. 123R, which requires that compensation cost be recorded for restricted stock, previously awarded unvested stock options outstanding at January 1, 2006 based on the grant date fair-values used for disclosure purposes under previous accounting requirements, and stock options awarded subsequent to January 1, 2006 determined under the provisions of FAS No. 123R. The cumulative effect on prior years of this change in accounting was immaterial. Prior to adoption of FAS No. 123R, the Corporation recorded compensation expense for restricted common stock awards and used the intrinsic value method to account for employee stock options. Because the exercise prices of employee stock options equaled or exceeded the market price of the stock on the date of grant, compensation expense was not recorded under this method. All share-based compensation expense is recognized on a straight-line basis over the vesting period of the awards.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income Taxes: Deferred income taxes are determined using the liability method. The Corporation regularly assesses the realizability of deferred tax assets, based on estimates of future taxable income, the availability of tax planning strategies, the existence of appreciated assets, the available carryforward periods for net operating losses and other factors. The Corporation does not provide for deferred U.S. income taxes applicable to undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations.

Foreign Currency Translation: The U.S. dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. Adjustments resulting from translating monetary assets and liabilities that are denominated in a nonfunctional currency into the functional currency are recorded in other non-operating income. For operations that do not use the U.S. dollar as the functional currency, adjustments resulting from translating foreign currency assets and liabilities into U.S. dollars are recorded in a separate component of stockholders’ equity entitled accumulated other comprehensive income (loss).

Recently Issued Accounting Standards: In September 2006, the FASB issued Staff Position (FSP) AUG AIR-1,Accounting for Planned Major Maintenance Activities. This FSP eliminates the previously acceptableaccrue-in-advance method of accounting for planned major maintenance. As a result, the Corporation will retrospectively change its method of accounting for refinery turnarounds on January 1, 2007, the effective date of this pronouncement, to recognize expenses associated with refinery turnarounds when such costs are incurred. Under the retrospective method of adoption, the Corporation expects to increase 2006 earnings by approximately $4 million, reduce 2005 earnings by approximately $16 million and increase retained earnings as of January 1, 2005 by approximately $66 million.

In July 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes(FIN 48). FIN 48 prescribes the financial statement recognition and measurement criteria for a tax position taken or expected to be taken in a tax return. FIN 48 also requires additional disclosures related to uncertain income tax positions. As required, the Corporation will adopt the provisions of FIN 48 effective January 1, 2007. The Corporation has not concluded its evaluation of the impact of adopting of FIN 48 on its results of operations, financial position or cash flows.

In September 2006, the FASB issued FAS No. 157,Fair Value Measurements (FAS No. 157). FAS No. 157 establishes a fair value hierarchy, which applies broadly to financial and non-financial assets and liabilities measured at fair value under other authoritative accounting pronouncements. Additionally, the standard requires increased disclosure of the methods of determining fair value. The Corporation is currently evaluating the impact of adoption on its financial statements and, as required, will adopt the provisions of FAS No. 157 effective January 1, 2008.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


2.	Items Affecting the Comparability of Income

The following table reflects items affecting comparability of income between periods:


	Before Taxes									After Taxes
	2006			2005			2004			2006			2005			2004
	(Millions of dollars, income (expense))

Exploration and Production
Gains from asset sales	$	369		$	48		$	55		$	236		$	41		$	54
Income tax adjustments		—			—			—			(45	)		11			19
Accrued office closing costs		(30	)		—			(15	)		(18	)		—			(9	)
Hurricane related costs		—			(40	)		—			—			(26	)		—
Legal settlement		—			19			—			—			11			—
Marketing and Refining
LIFO inventory liquidation		—			51			20			—			32			12
Charge related to customer bankruptcy		—			(13	)		—			—			(8	)		—
Corporate
Tax on repatriated earnings		—			—			—			—			(72	)		—
Premiums on bond repurchases		—			(39	)		—			—			(26	)		—
Income tax adjustments		—			—			—			—			—			13
Insurance accrual		—			—			(20	)		—			—			(13	)

	$	339		$	26		$	40		$	173		$	(37	)	$	76

Exploration and Production: In the first quarter of 2006, the Corporation completed the sale of its interests in certain oil and gas producing properties located in the Permian Basin in Texas and New Mexico for $358 million. This asset sale resulted in an after-tax gain of $186 million ($289 million before income taxes). These assets were producing at a combined net rate of approximately 5,500 barrels of oil equivalent per day at the time of sale. In June 2006, the Corporation also completed the sale of certain U.S. Gulf Coast onshore oil and gas producing assets for $86 million, resulting in an after-tax gain of $50 million ($80 million before income taxes). These assets were producing at a combined net rate of approximately 2,600 barrels of oil equivalent per day at the time of sale. In 2005, the Corporation sold non-producing properties in the United Kingdom and exchanged a mature North Sea asset for an increased interest in the Pangkah development in Indonesia. In 2004, the Corporation sold an office building in Scotland, a non-producing property in Malaysia and two mature Gulf of Mexico properties.

The Corporation accrued $30 million in 2006 and $15 million in 2004 for vacated leased office space in the United Kingdom. These expenses are reflected principally in general and administrative expense in the income statement. The remaining accrual balance was $49 million at December 31, 2006 and $31 million at December 31, 2005 after payments of $12 million in 2006 and $8 million in 2005.

During 2006, the United Kingdom increased the supplementary tax on petroleum operations from 10% to 20%. As a result, the Corporation recorded a $45 million adjustment to its United Kingdom deferred tax liability. The Exploration and Production income tax adjustments in 2005 reflect the effect on deferred income taxes of a reduction in the income tax rate in Denmark and a tax settlement in the United Kingdom. In 2004, the foreign income tax benefits resulted from a tax law change and a tax settlement.

In 2005, the Corporation incurred incremental expenses, principally repair costs and higher insurance premiums, as a result of hurricane damage in the Gulf of Mexico that are included in production expenses in

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the income statement. The legal settlement in 2005 resulted from the favorable resolution of contingencies on a prior year asset sale that is reflected in non-operating income in the income statement.

Marketing and Refining: Earnings include income from the liquidation of prior year LIFO inventories in 2005 and 2004. In 2005, earnings included a charge resulting from the bankruptcy of a customer in the utility industry that is included in marketing expenses in the income statement.

Corporate: In 2005, expenses include charges for premiums on bond repurchases, which are reflected in non-operating income (expense) in the income statement. In 2004, the Corporation recorded $20 million of insurance costs related to retrospective premium increases and a $13 million income tax benefit arising from the settlement of a federal tax audit.


3.	Acquisitions

2006 Acquisitions: In January 2006, the Corporation, in conjunction with its Oasis Group partners, re-entered its former oil and gas production operations in the Waha concessions in Libya, in which the Corporation holds an 8.16% interest. The re-entry terms included a25-year extension of the concessions and payments by the Corporation to the Libyan National Oil Corporation of $359 million. This transaction was accounted for as a business combination.

The following table summarizes the allocation of the purchase price to assets and liabilities acquired (in millions):


Property, plant and equipment	$	362
Goodwill		236

Total assets acquired		598
Current liabilities		(3	)
Deferred tax liabilities		(236	)

Net assets acquired	$	359

The goodwill recorded in this transaction relates to the deferred tax liability recorded for the difference in book and tax bases of the assets acquired. The goodwill is not expected to be deductible for income tax purposes. The primary reason for the Libyan investment was to acquire long-lived crude oil reserves. The Corporation’s share of production from Libya averaged 23,000 barrels of oil equivalent per day in 2006.

The Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities. This transaction was accounted for as an acquisition of assets.

2005 Acquisitions: The Corporation spent approximately $400 million during 2005 to acquire a controlling interest in a corporate joint venture, additional licenses and other assets in the Volga-Urals region of Russia. The primary reason for the Russian investments was to acquire long-lived crude oil reserves. Substantially all of the acquisition cost was allocated to unproved and proved properties.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


4.	Inventories

Inventories at December 31 are as follows:


	2006			2005
	(Millions of dollars)

Crude oil and other charge stocks	$	202		$	161
Refined products and natural gas		1,185			1,149
Less: LIFO adjustment		(676	)		(656	)

		711			654
Merchandise, materials and supplies		294			201

Total	$	1,005		$	855

The percentage of LIFO inventory to total crude oil, refined products and natural gas inventories was 66% and 68% at December 31, 2006 and 2005, respectively. During 2005 and 2004, the Corporation reduced LIFO inventories, which are carried at lower costs than current inventory costs. The effect of the LIFO inventory liquidations was to decrease cost of products sold by approximately $51 million in 2005 and $20 million in 2004.


5.	Refining Joint Venture

The Corporation has an investment in HOVENSA L.L.C., a 50% joint venture with Petroleos de Venezuela, S.A. (PDVSA), which is accounted for using the equity method. HOVENSA owns and operates a refinery in the U.S. Virgin Islands. Summarized financial information for HOVENSA as of December 31 and for the years then ended follows:


	2006			2005			2004
	(Millions of dollars)

Summarized Balance Sheet, at December 31
Cash and cash equivalents	$	290		$	612		$	518
Short-term investments		—			263			39
Other current assets		943			814			636
Net fixed assets		2,123			1,950			1,843
Other assets		32			39			36
Current liabilities		(1,060	)		(996	)		(606	)
Long-term debt		(252	)		(252	)		(252	)
Deferred liabilities and credits		(108	)		(57	)		(48	)

Partners’ equity	$	1,968		$	2,373		$	2,166

Summarized Income Statement, for the Years Ended December 31
Total revenues	$	11,788		$	10,439		$	7,776
Costs and expenses		(11,377	)		(9,682	)		(7,282	)

Net income	$	411		$	757		$	494

Hess Corporation’s share*	$	203		$	376		$	244

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	2006			2005			2004
	(Millions of dollars)

Summarized Cash Flow Statement, for the Years Ended December 31
Net cash provided by (used in):
Operating activities	$	484		$	1,070		$	656
Investing activities		(10	)		(426	)		(167	)
Financing activities		(796	)		(550	)		(312	)

Net increase (decrease) in cash and cash equivalents	$	(322	)	$	94		$	177


*		Before Virgin Islands income taxes, which were recorded in the Corporation’s income tax provision.

The Corporation received cash distributions from HOVENSA of $400 million, $275 million and $88 million during 2006, 2005 and 2004, respectively. The Corporation’s share of HOVENSA’s undistributed income aggregated $302 million at December 31, 2006.

The Corporation guarantees the payment of up to 50% of the value of HOVENSA’s crude oil purchases from suppliers other than PDVSA. The guarantee amounted to $229 million at December 31, 2006. This amount fluctuates based on the volume of crude oil purchased and the related crude oil prices. In addition, the Corporation has agreed to provide funding up to a current maximum of $15 million to the extent HOVENSA does not have funds to meet its senior debt obligations.

At formation of the joint venture, PDVSA V.I., a wholly-owned subsidiary of PDVSA, purchased a 50% interest in the fixed assets of the Corporation’s Virgin Islands refinery for $62.5 million in cash and a10-year note from PDVSA V.I. for $562.5 million bearing interest at 8.46% per annum and requiring principal payments over its term. The principal balance of the note was $137 million and $212 million at December 31, 2006 and 2005, respectively, which is due to be fully repaid by February 2009.


6.	Property, Plant and Equipment

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


	2006		2005
	(Millions of dollars)

Exploration and Production
Unproved properties	$	1,231	$	629
Proved properties		3,298		3,490
Wells, equipment and related facilities		15,670		13,717
Marketing and Refining		1,781		1,628

Total — at cost		21,980		19,464
Less reserves for depreciation, depletion, amortization and lease impairment		9,672		9,952

Property, plant and equipment - net	$	12,308	$	9,512

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31, and the changes therein during the respective years:


	2006			2005			2004
	(Millions of dollars)

Beginning balance at January 1	$	244		$	220		$	225
Additions to capitalized exploratory well costs pending the determination of proved reserves		299			97			150
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(144	)		(12	)		(149	)
Capitalized exploratory well costs charged to expense		—			(61	)		(6	)

Ending balance at December 31	$	399		$	244		$	220

Number of wells at end of year		28			16			15

The preceding table excludes exploratory dry hole costs of $241 million, $109 million and $75 million in 2006, 2005 and 2004, respectively, relating to wells that were drilled and expensed in the same year.

At December 31, 2006, expenditures related to exploratory drilling costs in excess of one year old were capitalized as follows (in millions):


2003	$	46
2004		8
2005		17

	$	71

The capitalized well costs in excess of one year relate to 5 projects which meet the requirements of FASB Staff Position19-1. Approximately 75% of the costs relates to two projects for which additional drilling is firmly planned in 2007. The remainder of the costs relate to projects where development approvals or sales contracts are being pursued.


7.	Asset Retirement Obligations

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


	2006			2005
	(Millions of dollars)

Asset retirement obligations at January 1	$	564		$	511
Liabilities incurred		16			8
Liabilities settled or disposed of		(118	)		(26	)
Accretion expense		44			33
Revisions		282			62
Foreign currency translation		36			(24	)

Asset retirement obligations at December 31	$	824		$	564

The increase in revisions in 2006 is primarily attributable to higher service and equipment costs in the oil and gas industry.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


8.	Long-Term Debt

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


	2006		2005
	(Millions of dollars)

Revolving credit facility, weighted average rate 6.2%	$	300	$	600
Asset-backed credit facility, weighted average rate 5.5%		318		—
Fixed rate debentures:
7.4% due 2009		103		103
6.7% due 2011		662		662
7.9% due 2029		693		693
7.3% due 2031		745		745
7.1% due 2033		598		598

Total fixed rate debentures		2,801		2,801
Fixed rate notes, payable principally to insurance companies, weighted average rate 9.1%, due through 2014		145		163
Project lease financing, weighted average rate 5.1%, due through 2014		148		161
Pollution control revenue bonds, weighted average rate 5.9%, due through 2034		53		52
Other loans, weighted average rate 7.0%, due through 2019		7		8

		3,772		3,785
Less: amount included in current maturities		27		26

Total	$	3,745	$	3,759

The aggregate long-term debt maturing during the next five years is as follows (in millions): 2007 – $27 (included in current liabilities); 2008 – $28; 2009 – $143; 2010 – $30 and 2011 – $1,310.

At December 31, 2006, the Corporation’s fixed rate debentures have a principal amount of $2,816 million ($2,801 million net of unamortized discount). Interest rates on the outstanding fixed rate debentures have a weighted average rate of 7.3%.

During 2006, the Corporation amended and restated its existing syndicated revolving credit facility (the revolving credit facility) to increase the credit line to $3.0 billion from $2.5 billion and extend the term to May 2011 from December 2009. The facility can be used for borrowings and letters of credit. At December 31, 2006, the Corporation has available capacity on the facility of $2.7 billion. Current borrowings under the facility bear interest at 0.525% above the London Interbank Offered Rate and a facility fee of 0.125% per annum is payable on the amount of the credit line. The interest rate and facility fee are subject to adjustment if the Corporation’s credit rating changes.

The Corporation has an asset-backed credit facility securitized by certain accounts receivable from its marketing operations, which are sold to a wholly-owned subsidiary. This asset-backed funding arrangement allows the Corporation to borrow up to $800 million subject to sufficient levels of eligible receivables. The credit line has a364-day maturity. Borrowings under the asset-backed credit facility represent floating rate debt for which the weighted average interest rate was 5.5% for 2006. Outstanding borrowings of $318 million at December 31, 2006 are classified as long term based on the Corporation’s available capacity under the committed revolving credit facility. At December 31, 2006, total collateralized accounts receivable of approximately $1,100 million are serviced by the Corporation and recorded on its balance sheet but are not available to pay the general obligations of the Corporation before repayment of outstanding borrowings under the asset-backed facility.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Corporation’s long-term debt agreements contain a financial covenant that restricts the amount of total borrowings, secured debt and cash dividends. At December 31, 2006, the Corporation is permitted to borrow up to an additional $9.7 billion for the construction or acquisition of assets. The Corporation has the ability to borrow up to an additional $2.2 billion of secured debt at December 31, 2006. At year-end, the amount that can be borrowed for the payment of dividends or stock repurchases is $3.7 billion.

The total amount of interest paid (net of amounts capitalized), principally on short-term and long-term debt, was $200 million, $245 million and $243 million in 2006, 2005 and 2004, respectively. The Corporation capitalized interest of $100 million, $80 million and $54 million in 2006, 2005 and 2004, respectively.


9.	Share-Based Compensation

The Corporation awards restricted common stock and stock options under its Amended and Restated 1995 Long-Term Incentive Plan. Generally, stock options vest from one to three years from the date of grant, have a10-year option life, and the exercise price equals or exceeds the market price on the date of grant. Outstanding restricted common stock generally vests three to five years from the date of grant.

Share-based compensation expense was $68 million ($42 million after income taxes) for the year ended December 31, 2006, of which $30 million ($19 million after income taxes) related to stock options and the remainder related to restricted stock. Stock option expense recorded in the year 2006 reduced basic and diluted earnings per share by $.07 and $.06, respectively. Total pre-tax compensation expense for restricted common stock was $28 million in 2005 and $17 million in 2004.

The following pro forma financial information presents the effect on net income and earnings per share as if the Corporation commenced expensing of stock options on January 1, 2004 instead of on January 1, 2006.


	2005			2004
	(Millions of dollars, except per share data)

Net income	$	1,242		$	977
Add: stock-based employee compensation expense included in net income, net of taxes		18			11
Less: total stock-based employee compensation expense determined using the fair value method, net of taxes		(37	)		(18	)

Pro forma net income	$	1,223		$	970

Net income per share as reported*
Basic	$	4.38		$	3.46
Diluted		3.98			3.19
Pro forma net income per share*
Basic	$	4.31		$	3.44
Diluted		3.92			3.17


*		Per share amounts in both periods reflect the impact of a3-for-1 stock split on May 31, 2006.

Based on restricted stock and stock option awards outstanding at December 31, 2006, unearned compensation expense, before income taxes, will be recognized in future years as follows: 2007 — $56 million, 2008 — $34 million and 2009 — $4 million.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Corporation’s stock option and restricted stock activity consisted of the following:


	Stock Options					Restricted Stock
				Weighted-		Shares of			Weighted-
				Average		Restricted			Average
				Exercise Price		Common			Price on Date
	Options*			per Share*		Stock*			of Grant*
	(Thousands)					(Thousands)

Outstanding at January 1, 2004		12,471		$	19.51		3,729		$	17.55
Granted		3,594			24.26		1,268			24.32
Exercised		(4,614	)		19.51		—			—
Vested		—			—		(253	)		16.99
Forfeited		(90	)		21.98		(340	)		17.73

Outstanding at December 31, 2004		11,361			21.00		4,404			19.52
Granted		3,282			30.91		1,121			30.79
Exercised		(3,099	)		19.96		—			—
Vested		—			—		(989	)		19.89
Forfeited		(93	)		24.85		(173	)		19.67

Outstanding at December 31, 2005		11,451			24.09		4,363			22.32
Granted		2,853			49.46		984			50.40
Exercised		(1,283	)		22.96		—			—
Vested		—			—		(237	)		22.78
Forfeited		(98	)		40.07		(66	)		30.24

Outstanding at December 31, 2006		12,923			29.68		5,044			27.68

Exercisable at December 31, 2004		7,821		$	19.52
Exercisable at December 31, 2005		8,181			21.36
Exercisable at December 31, 2006		6,832			22.08


*		Stock options, restricted stock and weighted average exercise prices per share in all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

The table below summarizes information regarding the Company’s outstanding and exercisable stock options as of December 31, 2006:


			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)						(Thousands)

$10.01 – $20.00		3,413		4	$	18.89		3,413	$	18.89
$20.01 – $40.00		6,528		7		26.39		3,358		24.91
$40.01 – $60.00		2,982		9		49.23		61		45.41

		12,923		7		29.68		6,832		22.08


*		Stock options and weighted average exercise prices per share reflect the impact of a3-for-1 stock split on May 31, 2006.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2006 was $257 million and $188 million, respectively. At December 31, 2006, assuming forfeitures of 2% per year, the number of outstanding options that are expected to vest is 12,736,000 shares with a weighted average exercise price of $29.53 per share. At December 31, 2006 the weighted average remaining term of exercisable options was 5 years and the remaining term of all outstanding options was 7 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:


	2006			2005			2004

Risk free interest rate		4.50	%		3.90	%		4.30	%
Stock price volatility		.321			.300			.293
Dividend yield		.80	%		1.30	%		1.70	%
Expected term in years		5			7			7
Weighted average fair value per option granted	$	16.50		$	10.51		$	7.92

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.

At December 31, 2006, the number of common shares reserved for issuance under the 1995 Long-Term Incentive Plan is as follows (in thousands):


Total common shares reserved for issuance			24,621
Less: stock options outstanding			12,923

Available for future awards of restricted stock and stock options			11,698


10.	Foreign Currency Translation

Foreign currency gains (losses) before income taxes amounted to $21 million in 2006, $(5) million in 2005 and $29 million in 2004. The balances in accumulated other comprehensive income (loss) related to foreign currency translation were reductions in stockholders’ equity of $61 million at December 31, 2006 and $92 million at December 31, 2005.


11.	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’s funds so that total pension payments equal amounts that would have been payable from the Corporation’s principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary. Additionally, the Corporation maintains a postretirement medical plan that provides health benefits to certain qualified retirees from ages 55 through 65. The Corporation uses December 31 as the measurement date for all of these retirement plans.

Effective December 31, 2006, the Corporation prospectively adopted FAS No. 158,Employer’s Accounting For Defined Benefit Pension and Other Postretirement Plans(FAS No. 158), which requires recognition on the balance sheet of the underfunded status of a defined benefit postretirement plan measured as the difference between

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the fair value of plan assets and the benefit obligation. The benefit obligation is defined as the projected benefit obligation for pension plans and the accumulated postretirement obligation for postretirement medical plans. The Corporation recognizes on the balance sheet all changes in the funded status of its defined benefit postretirement plans in the year in which such changes occur. As a result of adopting FAS 158, the Corporation recorded an after-tax decrease in stockholders’ equity of $142 million ($225 million before-tax) by increasing accumulated other comprehensive income (loss). The following table reflects the impact of adopting FAS No. 158 effective December 31, 2006:


	(Millions of dollars)

Decrease in prepaid benefit cost(a)	$	78
Decrease in intangible assets(a)		2
Increase in accrued benefit liability(b)		145
Charge to accumulated other comprehensive income (loss)		225


(a)		Included within Other assets on the Corporation’s balance sheet
(b)		Included within Other liabilities and deferred credits on the Corporation’s balance sheet

The following table reconciles the benefit obligation 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
	2006			2005			2006			2005			2006			2005
	(Millions of dollars)

Change in benefit obligation
Balance at January 1	$	1,030		$	925		$	105		$	77		$	73		$	71
Service cost		31			26			4			4			3			2
Interest cost		57			53			6			5			5			4
Actuarial loss		16			60			4			24			11			—
Benefit payments		(36	)		(34	)		(5	)		(5	)		(3	)		(4	)

Balance at December 31		1,098			1,030			114			105			89			73

Change in fair value of plan assets
Balance at January 1		826			750			—			—			—			—
Actual return on plan assets		126			42			—			—			—			—
Employer contributions		45			68			5			5			3			4
Benefit payments		(36	)		(34	)		(5	)		(5	)		(3	)		(4	)

Balance at December 31		961			826			—			—			—			—

Funded status (plan assets less than benefit obligations) at December 31		(137	)		(204	)		(114	)*		(105	)*		(89	)		(73	)
Unrecognized net actuarial loss		205			278			51			53			34			26
Unrecognized prior service cost		—			1			3			3			(2	)		(3	)

Net amount recognized	$	68		$	75		$	(60	)	$	(49	)	$	(57	)	$	(50	)


*		The trust established by the Corporation to fund the supplemental plan held assets valued at $76 million at December 31, 2006 and $53 million at December 31, 2005.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

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
	2006			2005			2006			2005			2006			2005
	(Millions of dollars)

Accrued benefit liability	$	(137	)	$	(93	)	$	(114	)	$	(83	)	$	(89	)	$	(50	)
Intangible assets		—			1			—			3			—			—
Accumulated other comprehensive income (loss)*		205			167			54			31			32			—

Net amount recognized	$	68		$	75		$	(60	)	$	(49	)	$	(57	)	$	(50	)


*		The amount included in accumulated other comprehensive income (loss) after income taxes was $183 million at December 31, 2006 and $131 million at December 31, 2005.

The accumulated benefit obligation for the funded defined benefit pension plans was $996 million at December 31, 2006 and $919 million at December 31, 2005. The accumulated benefit obligation for the unfunded defined benefit pension plan was $96 million at December 31, 2006 and $83 million at December 31, 2005.

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
	2006			2005			2004			2006			2005			2004
	(Millions of dollars)

Service cost	$	34		$	30		$	26		$	3		$	3		$	2
Interest cost		63			58			54			5			4			4
Expected return on plan assets		(63	)		(56	)		(56	)		—			—			—
Amortization of prior service cost		1			2			2			(1	)		(1	)		(1	)
Amortization of net loss		30			24			16			—			—			—
Settlement loss		—			—			6			3			1			1

Net periodic benefit cost	$	65		$	58		$	48		$	10		$	7		$	6

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

The Corporation’s 2007 pension and postretirement medical expense is estimated to be approximately $70 million, of which $25 million relates to the amortization of estimated actuarial losses.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	2006			2005			2004

Weighted-average assumptions used to determine benefit obligations at December 31
Discount rate		5.8	%		5.5	%		5.8	%
Rate of compensation increase		4.4			4.3			4.5
Weighted-average assumptions used to determine net benefit cost for years ended December 31
Discount rate		5.5			5.8			6.2
Expected return on plan assets		7.5			7.5			8.5
Rate of compensation increase		4.3			4.5			4.5

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


	2006			2005			2004

Assumptions used to determine benefit obligations at December 31
Discount rate		5.8	%		5.5	%		5.8	%
Initial health care trend rate		8.0	%		9.0	%		10.0	%
Ultimate trend rate		4.5	%		4.5	%		4.5	%
Year in which ultimate trend rate is reached		2011			2011			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 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 engages an independent investment consultant to assist in the development of these expected returns.

The Corporation’s investment strategy is to maximize 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 Company’s investment committee and include domestic and foreign equities, fixed income securities, and other investments, including hedge funds 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:


				At
	Target			December 31
Asset Category	Allocation			2006			2005

Equity securities		55	%		61	%		61	%
Debt securities		35			34			35
Other		10			5			4

Total		100	%		100	%		100	%

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels.

The Corporation has budgeted contributions of approximately $65 million to its funded pension plans in 2007. The Corporation also has budgeted contributions of approximately $15 million to the trust established for the unfunded plan.

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


	(Millions of dollars)

2007	$	52
2008		55
2009		59
2010		67
2011		79
Years 2012 to 2016		420

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 $16 million in 2006, $14 million in 2005 and $13 million in 2004 for contributions to these plans.


12.	Income Taxes

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


	2006		2005			2004
	(Millions of dollars)

United States Federal
Current	$	4	$	50		$	—
Deferred		93		(314	)		(162	)
State		19		(14	)		(23	)

		116		(278	)		(185	)

Foreign
Current		1,836		1,047			801
Deferred		143		220			(28	)

		1,979		1,267			773

Adjustment of deferred tax liability for foreign income tax rate change		29		(5	)		—

Total provision for income taxes on continuing operations*	$	2,124	$	984		$	588


*		See note 2 for items affecting comparability of income taxes between years.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	2006		2005			2004
	(Millions of dollars)

United States(a)	$	398	$	(941	)	$	(411	)
Foreign(b)		3,642		3,167			1,969

Total income from continuing operations before income taxes	$	4,040	$	2,226		$	1,558


(a)		Includes substantially all of the Corporation’s interest expense and the results of hedging activities.

(b)		Foreign income includes the Corporation’s Virgin Islands 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:


	2006			2005
	(Millions of dollars)

Deferred tax liabilities
Fixed assets and investments	$	2,473		$	1,657
Foreign petroleum taxes		347			324
Other		179			97

Total deferred tax liabilities		2,999			2,078

Deferred tax assets
Net operating loss carryforwards		1,470			1,578
Accrued liabilities		372			314
Asset retirement obligations		316			189
Tax credit carryforwards		182			197
Other		260			140

Total deferred tax assets		2,600			2,418
Valuation allowance		(164	)		(76	)

Net deferred tax assets		2,436			2,342

Net deferred tax assets (liabilities)	$	(563	)	$	264

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:


	2006			2005
	(Millions of dollars)

Other current assets	$	152		$	121
Deferred income taxes (long-term asset)		1,435			1,544
Accrued liabilities		(51	)		—
Deferred income taxes (long-term liability)		(2,099	)		(1,401	)

Net deferred tax assets (liabilities)	$	(563	)	$	264

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	2006			2005			2004

United States statutory rate		35.0	%		35.0	%		35.0	%
Effect of foreign operations		17.5			7.5			5.0
State income taxes, net of Federal income tax		0.3			(0.4	)		(0.9	)
Tax on repatriation		—			3.3			—
Other		(0.2	)		(1.2	)		(1.3	)

Total		52.6	%		44.2	%		37.8	%

The increase in the 2006 effective income tax rate was primarily due to taxes on Libyan operations and the increase in the supplementary tax on petroleum operations in the United Kingdom from 10% to 20%. During 2006, the Algerian government amended its hydrocarbon tax laws effective August 1, 2006 and the Corporation recorded a net charge of $6 million for the estimated impact of the tax.

The American Jobs Creation Act (the Act) provided for a one-time reduction in the income tax rate to 5.25% on the remittance of eligible dividends from foreign subsidiaries to a U.S. parent. During 2005, the Corporation repatriated $1.9 billion of foreign dividends under the Act and recorded a related income tax provision of approximately $72 million.

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 $5.4 billion at December 31, 2006. If the earnings of foreign subsidiaries were not indefinitely reinvested, a deferred tax liability of approximately $1.9 billion would be required, excluding the potential use of foreign tax credits in the United States.

At December 31, 2006, the Corporation has net operating loss carryforwards in the United States of approximately $3.2 billion, substantially all of which expire in 2022 through 2025. In addition, a foreign Exploration and Production subsidiary has a net operating loss carryforward of approximately $500 million, which can be carried forward indefinitely. For income tax reporting at December 31, 2006, the Corporation has alternative minimum tax credit carryforwards of approximately $135 million, which can be carried forward indefinitely. The Corporation also has approximately $45 million of general business credits, substantially all of which expire between 2011 and 2025.

Income taxes paid (net of refunds) in 2006, 2005 and 2004 amounted to $1,799 million, $1,139 million and $632 million, respectively.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


13.	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*:


	2006		2005		2004
	(Thousands of shares)

Common shares — basic		278,100		272,700		268,355
Effect of dilutive securities
Convertible preferred stock		31,656		34,247		34,976
Stock options		3,135		2,507		1,110
Restricted common stock		2,776		2,651		1,817

Common shares — diluted		315,667		312,105		306,258


*		Weighted average number of shares in all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

The table above excludes the effect ofout-of-the-money options on 2,080,000 shares, 61,000 shares and 2,582,000 shares in 2006, 2005 and 2004, respectively.

Earnings per share are as follows*:


	2006		2005		2004

Basic
Continuing operations	$	6.73	$	4.38	$	3.43
Discontinued operations		—		—		.03

Net income	$	6.73	$	4.38	$	3.46

Diluted
Continuing operations	$	6.07	$	3.98	$	3.17
Discontinued operations		—		—		.02

Net income	$	6.07	$	3.98	$	3.19


*		Per share amounts in all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

On May 3, 2006, the Corporation’s shareholders voted to increase the number of authorized common shares from 200 million to 600 million and the board of directors declared athree-for-one stock split. The stock split was completed in the form of a stock dividend that was issued on May 31, 2006 to shareholders of record on May 17, 2006. The common share par value remained at $1.00 per share. All common share and per share amounts in these financial statements and notes are on an after-split basis for all periods presented.

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. Based on the Corporation’s average closing common stock price over the20-day period before conversion, the conversion rate was 2.4915 shares of common stock for each share of preferred. 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.

At December 31, 2006, the Corporation has outstanding 323,715 shares of 3% cumulative convertible preferred stock which have a total liquidation value of $16 million ($50 per share). Each share of the 3% cumulative convertible preferred stock is convertible at the option of the holder into 1.8783 shares of common stock. Holders of

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the cumulative convertible preferred stock have no voting rights except in certain limited circumstances involving non-payment of dividends.


14.	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, 2006, future minimum rental payments applicable to noncancelable operating leases with remaining terms of one year or more (other than oil and gas property leases) are as follows:


	(Millions of dollars)

2007	$	630
2008		343
2009		224
2010		105
2011		93
Remaining years		1,076

Total minimum lease payments		2,471
Less: Income from subleases		88

Net minimum lease payments	$	2,383

Operating lease expenses for drilling rigs used to drill development wells and successful exploration wells are capitalized.

Rental expense was as follows:


	2006		2005		2004
	(Millions of dollars)

Total rental expense	$	198	$	201	$	238
Less: Income from subleases		15		14		58

Net rental expense	$	183	$	187	$	180


15.	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 $449 million in 2006, $1,582 million in 2005 and $935 million in 2004. The amount of hedge ineffectiveness losses reflected in revenue in 2006 and 2005 was $5 million and $17 million, respectively, and was not material during the year ended December 31, 2004.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Corporation’s crude oil hedging activities included the use of commodity futures and swap contracts. At December 31, 2006, the Corporation’s outstanding hedge positions were as follows:


	Brent Crude Oil
	Average		Thousands of
Maturity	Selling Price		Barrels per Day

2007	$	25.85		24
2008		25.56		24
2009		25.54		24
2010		25.78		24
2011		26.37		24
2012		26.90		24

The Corporation had no WTI crude oil or natural gas hedges at year-end 2006. The Corporation also markets energy commodities including refined petroleum products, natural gas and electricity. The Corporation uses futures and swaps to manage the underlying risk in its marketing activities. At December 31, 2006, net after tax deferred losses in accumulated other comprehensive income (loss) from the Corporation’s hedging contracts were $1,338 million ($2,101 million before income taxes). At December 31, 2005, net after-tax deferred losses were $1,304 million ($2,063 million before income taxes). The pre-tax amount of all deferred hedge losses is reflected in accounts payable and the related income tax benefits are recorded as deferred tax assets on the balance sheet.

Commodity Trading: The Corporation, principally through a consolidated partnership, trades energy commodities and securities and derivatives including futures, forwards, options and swaps, based on expectations of future market conditions. The Corporation’s income before income taxes from trading activities, including its share of the earnings of the trading partnership amounted to $83 million in 2006, $60 million in 2005 and $72 million in 2004.

Other Financial Instruments: The Corporation has $729 million of notional value foreign currency forward contracts maturing through 2007, ($677 million at December 31, 2005). 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 was a receivable of $51 million at December 31, 2006 and a liability of $31 million at December 31, 2005.

The Corporation has $3,479 million in letters of credit outstanding at December 31, 2006 ($2,685 million at December 31, 2005). Of the total letters of credit outstanding at December 31, 2006, $52 million relates to contingent liabilities and the remaining $3,427 million relates to liabilities recorded on the balance sheet.

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

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the fair values at December 31 of financial instruments and derivatives used in non-trading and trading activities:


	2006			2005
	(Millions of dollars, asset (liability))

Futures and forwards
Assets	$	632		$	199
Liabilities		(273	)		(115	)
Options
Held		252			963
Written		(265	)		(265	)
Swaps
Assets		620			763
Liabilities (including hedging contracts)		(2,711	)		(2,512	)

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, 2006 and 2005, except fixed rate long-term debt which had a carrying value of $3,149 million and a fair value of $3,482 million at December 31, 2006 and a carrying value of $3,174 million and a fair value of $3,675 million at December 31, 2005.

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.


16.	Guarantees and Contingencies

The Corporation’s guarantees include $15 million of HOVENSA’s senior debt obligations and $229 million of HOVENSA’s crude oil purchases, see note 5, “Refining Joint Venture.” The remainder relates to a loan guarantee of $57 million for an oil pipeline in which the Corporation owns a 2.36% interest. In addition, the Corporation has $52 million in letters of credit for which it is contingently liable. The maximum potential amount of future payments that the Corporation could be required to make under its guarantees at December 31, 2006 is $353 million ($306 million at December 31, 2005). The Corporation has a contingent purchase obligation expiring in April 2010, to acquire the remaining interest in WilcoHess, a retail gasoline station joint venture, for approximately $140 million as of December 31, 2006.

The Corporation 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 No. 5,Accounting for Contingencies.

The Corporation, along with many other companies engaged in refining and marketing of gasoline, is a party to numerous lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. These cases have been consolidated in the Southern District of New York. The principal allegation in all cases is that gasoline

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. In some cases, punitive damages are also sought. In April 2005, the District Court denied the primary legal aspects of the defendants’ motion to dismiss these actions. While the damages claimed in these actions are substantial, and it is reasonably possible that a liability may have been incurred, only limited information is available to evaluate the factual and legal merits of these claims. The Corporation also believes that significant legal uncertainty remains regarding the validity of causes of action asserted and availability of the relief sought by plaintiffs. Accordingly, based on the information currently available, there is insufficient information on which to evaluate the Corporation’s exposure in these cases.

Over the last several years, many refiners have entered into consent agreements to resolve assertions by the Environmental Protection Agency (EPA) that refining facilities were modified or expanded without complying with New Source Review regulations that require permits and new emission controls in certain circumstances and other regulations that impose emissions control requirements. These consent agreements, which arise out of an EPA enforcement initiative focusing on petroleum refiners and utilities, have typically imposed substantial civil fines and penalties and required significant capital expenditures to install emissions control equipment over a three to eight year time period. The penalties assessed and the capital expenditures required vary considerably between refineries. The EPA initially contacted the Corporation and HOVENSA regarding the petroleum refinery initiative in August 2003 and the Corporation and HOVENSA expect to have further discussions with EPA regarding the initiative. While it is reasonably possible additional capital expenditures and operating expenses may be incurred in the future, the amounts cannot be estimated at this time. The amount of penalties, if any, is not expected to be material to the financial position or results of operations of the Corporation.

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.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents financial data by operating segment for each of the three years ended December 31, 2006:


	Exploration		Marketing		Corporate
	and Production		and Refining		and Interest			Consolidated(a)
	(Millions of dollars)

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	$	390	$	(237	)	$	1,916

Equity in income of HOVENSA L.L.C.	$	—	$	203	$	—		$	203
Interest expense		—		—		201			201
Depreciation, depletion and amortization		1,159		61		4			1,224
Provision (benefit) for income taxes		2,019		224		(119	)		2,124
Investments in affiliates		57		1,143		—			1,200
Identifiable assets		14,397		6,190		1,817			22,404
Capital employed(c)		9,397		2,919		(433	)		11,883
Capital expenditures		3,675		158		11			3,844

2005
Operating revenues
Total operating revenues(b)	$	4,428	$	18,673	$	2
Less: Transfers between affiliates		356		—		—

Operating revenues from unaffiliated customers	$	4,072	$	18,673	$	2		$	22,747

Net income (loss)	$	1,058	$	515	$	(331	)	$	1,242

Equity in income of HOVENSA L.L.C.	$	—	$	376	$	—		$	376
Interest expense		—		—		224			224
Depreciation, depletion and amortization		965		58		2			1,025
Provision (benefit) for income taxes		737		298		(51	)		984
Investments in affiliates		43		1,346		—			1,389
Identifiable assets		10,961		6,337		1,817			19,115
Capital employed(c)		7,832		3,074		(835	)		10,071
Capital expenditures		2,235		101		5			2,341

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Exploration		Marketing		Corporate
	and Production		and Refining		and Interest			Consolidated(a)
	(Millions of dollars)

2004
Operating revenues
Total operating revenues(b)	$	3,586	$	13,448	$	1
Less: Transfers between affiliates		302		—		—

Operating revenues from unaffiliated customers	$	3,284	$	13,448	$	1		$	16,733

Income (loss) from continuing operations	$	755	$	451	$	(236	)	$	970
Discontinued operations		7		—		—			7

Net income (loss)	$	762	$	451	$	(236	)	$	977

Equity in income of HOVENSA L.L.C.	$	—	$	244	$	—		$	244
Interest expense		—		—		241			241
Depreciation, depletion and amortization		918		50		2			970
Provision (benefit) for income taxes		571		158		(141	)		588
Investments in affiliates		28		1,226		—			1,254
Identifiable assets		10,407		4,850		1,055			16,312
Capital employed(c)		7,603		2,519		(690	)		9,432
Capital expenditures		1,434		85		2			1,521


(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 $1,800 million in each year.

(c)	Calculated as equity plus debt.

Financial information by major geographic area for each of the three years ended December 31, 2006:


							Asia and
	United States		Europe		Africa		Other		Consolidated
	(Millions of dollars)

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
2005
Operating revenues	$	19,496	$	2,016	$	827	$	408	$	22,747
Property, plant and equipment (net)		1,836		3,080		2,791		1,805		9,512
2004
Operating revenues	$	14,254	$	1,705	$	548	$	226	$	16,733
Property, plant and equipment (net)		1,880		2,591		2,293		1,741		8,505

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


18.	Related Party Transactions

Related party transactions for the year-ended December 31:


	2006		2005
	(Millions of dollars)

Purchases of petroleum products:
HOVENSA*	$	4,694	$	3,991
Sales of petroleum products and crude oil:
WilcoHess		1,664		1,244
HOVENSA		179		98


*	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 Events

In February 2007, the Corporation completed the acquisition of a 28% interest in the Genghis Khan oil and gas development located in the deepwater Gulf of Mexico on Green Canyon Blocks 652 and 608 for $371 million. The Genghis Khan development is part of the same geologic structure as the Shenzi development and first production from this development is expected in the second half of 2007.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

SUPPLEMENTARY OIL AND GAS DATA

(Unaudited)

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

The Corporation produces crude oiland/or natural gas in the United States, United Kingdom, Norway, Denmark, Equatorial Guinea, Algeria, Malaysia, Thailand, Russia, Gabon, Azerbaijan, Indonesia and Libya. 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)

2006
Property acquisitions
Unproved	$	607	$	86	$	32	$	483	$	6
Proved		314		—		8		306		—
Exploration		802		544		92		57		109
Production and development*		2,462		329		644		1,080		409

2005
Property acquisitions
Unproved	$	193	$	14	$	173	$	6	$	—
Proved		215		—		215		—		—
Exploration		378		197		60		43		78
Production and development*		1,668		162		522		857		127

2004
Property acquisitions
Unproved	$	62	$	62	$	—	$	—	$	—
Exploration		297		194		22		35		46
Production and development*		1,255		200		459		506		90


*	Includes $298 million, $70 million and $51 million in 2006, 2005 and 2004, respectively, related to the accruals for asset retirement obligations.

Capitalized Costs Relating to Oil and Gas Producing Activities


	At December 31
	2006		2005
	(Millions of dollars)

Unproved properties	$	1,231	$	629
Proved properties		3,298		3,490
Wells, equipment and related facilities		15,670		13,717

Total costs		20,199		17,836
Less: Reserve for depreciation, depletion, amortization and lease impairment		8,910		9,243

Net capitalized costs	$	11,289	$	8,593

Results of Operations for Oil and Gas Producing Activities

The results of operations shown below exclude non-oil and gas producing activities, including gains on sales of oil and gas properties, interest expense and gains and losses resulting from foreign exchange transactions. Therefore, these results are on a different basis than the net income from Exploration and Production operations reported in management’s discussion and analysis of results of operations and in note 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)

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**		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


2005
Sales and other operating revenues
Unaffiliated customers	$	3,854	$	741	$	2,004	$	769	$	340
Inter-company		356		356		��		—		—

Total revenues		4,210		1,097		2,004		769		340

Costs and expenses
Production expenses, including related taxes*		1,007		253		478		198		78
Exploration expenses, including dry holes and lease impairment		397		233		26		97		41
General, administrative and other expenses		140		74		39		11		16
Depreciation, depletion and amortization		965		145		408		301		111

Total costs and expenses		2,509		705		951		607		246

Results of operations before income taxes		1,701		392		1,053		162		94
Provision for income taxes		709		141		500		29		39

Results of operations	$	992	$	251	$	553	$	133	$	55


			United						Asia and
For the Years Ended December 31	Total		States		Europe		Africa		Other
	(Millions of dollars)

2004
Sales and other operating revenues
Unaffiliated customers	$	3,114	$	607	$	1,753	$	568	$	186
Inter-company		302		302		—		—		—

Total revenues		3,416		909		1,753		568		186

Costs and expenses
Production expenses, including related taxes		825		198		415		171		41
Exploration expenses, including dry holes and lease impairment		287		135		28		78		46
General, administrative and other expenses**		150		57		31		25		37
Depreciation, depletion and amortization		918		147		497		215		59

Total costs and expenses		2,180		537		971		489		183

Results of continuing operations before income taxes		1,236		372		782		79		3
Provision for income taxes		543		132		381		36		(6	)

Results of continuing operations		693		240		401		43		9
Discontinued operations		7		—		—		—		7

Results of operations	$	700	$	240	$	401	$	43	$	16


*		Includes $40 million of Gulf of Mexico hurricane related costs.

**		Includes accrued severance and costs for vacated office space of approximately $30 million and $15 million in 2006 and 2004, respectively.

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 reserves. The Corporation maintains its own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. The Corporation’s technical staff updates reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management reviews the estimates.

The oil and gas reserve estimates reported on the following page 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.


	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, 2004		127			305			135			79			646			360			800			1,172			2,332
Revisions of previous estimates(a)		15			20			8			(14	)		29			(1	)		75			(76	)		(2	)
Extensions, discoveries and other additions		3			3			53			3			62			13			2			287			302
Purchases of minerals in place		—			—			—			—			—			1			—			—			1
Sales of minerals in place		(1	)		—			—			—			(1	)		(6	)		—			—			(6	)
Production		(20	)		(46	)		(22	)		(2	)		(90	)		(67	)		(126	)		(34	)		(227	)

At December 31, 2004		124			282			174			66			646	(c)		300	(d)		751			1,349			2,400

Revisions of previous estimates(a)		16			23			4			(10	)		33			21			70			(99	)		(8	)
Extensions, discoveries and other additions		3			2			11			2			18			13			2			190			205
Improved recovery		1			—			—			—			1			—			—			—			—
Purchases of minerals in place		—			87			—			—			87			1			—			22			23
Sales of minerals in place		—			(4	)		—			—			(4	)		—			—			—			—
Production		(20	)		(42	)		(24	)		(3	)		(89	)		(53	)		(108	)		(53	)		(214	)

At December 31, 2005		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(b)		138			340			304			50			832	(c)		236	(d)		677			1,553			2,466


Net Proved Developed Reserves
At January 1, 2004		105			249			95			16			465			297			518			633			1,448
At December 31, 2004		110			234			80			12			436			260			528			471			1,259
At December 31, 2005		108			233			67			13			421			251			559			496			1,306
At December 31, 2006		90			223			194			19			526			195			517			585			1,297


(a)		Includes the impact of changes in selling prices on production sharing contracts with cost recovery provisions and stipulated rates of return. In 2006 this amount was immaterial for both oil and natural gas. In 2005 and 2004, revisions included reductions of approximately 23 million barrels of crude oil in each year and 63 million and 52 million mcf of natural gas, respectively, relating to higher selling prices.

(b)		Includes 26% of crude oil reserves and 56% 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 23 million barrels in 2006 and 2005, and 3 million barrels in 2004 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 No. 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 and do not include the effects of hedges, 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)

2006
Future revenues	$	55,252	$	8,686	$	19,751	$	18,480	$	8,335

Less:
Future development and production costs		20,355		2,098		9,398		5,629		3,230
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


2005
Future revenues	$	50,273	$	9,449	$	23,534	$	8,827	$	8,463

Less:
Future development and production costs		14,822		1,622		6,976		3,391		2,833
Future income tax expenses		13,666		2,764		8,703		1,037		1,162

		28,488		4,386		15,679		4,428		3,995

Future net cash flows		21,785		5,063		7,855		4,399		4,468
Less: Discount at 10% annual rate		7,296		1,892		2,448		1,168		1,788

Standardized measure of discounted future net cash flows	$	14,489	$	3,171	$	5,407	$	3,231	$	2,680


2004
Future revenues	$	34,425	$	6,542	$	14,743	$	6,161	$	6,979

Less:
Future development and production costs		11,989		1,623		5,007		2,939		2,420
Future income tax expenses		8,168		1,641		5,190		485		852

		20,157		3,264		10,197		3,424		3,272

Future net cash flows		14,268		3,278		4,546		2,737		3,707
Less: Discount at 10% annual rate		5,091		1,138		1,450		887		1,616

Standardized measure of discounted future net cash flows	$	9,177	$	2,140	$	3,096	$	1,850	$	2,091

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


For the Years Ended December 31	2006			2005			2004
	(Millions of dollars)

Standardized measure of discounted future net cash flows at beginning of year	$	14,489		$	9,177		$	7,017

Changes during the year
Sales and transfers of oil and gas produced during year, net of production costs		(5,274	)		(3,203	)		(2,591	)
Development costs incurred during year		2,164			1,598			1,204
Net changes in prices and production costs applicable to future production		(4,329	)		9,334			3,683
Net change in estimated future development costs		(2,402	)		(1,725	)		(1,564	)
Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs		1,937			865			997
Revisions of previous oil and gas reserve estimates		1,235			1,499			578
Net purchases (sales) of minerals in place, before income taxes		2,937			393			(29	)
Accretion of discount		2,308			1,424			1,057
Net change in income taxes		(1,381	)		(3,533	)		(1,463	)
Revision in rate or timing of future production and other changes		677			(1,340	)		288

Total		(2,128	)		5,312			2,160

Standardized measure of discounted future net cash flows at end of year	$	12,361		$	14,489		$	9,177

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

Revenues

Profit(a)

Income

per Share*

(Million of dollars, except per share data)

2006

First

7,159

1,138

695

(b)

2.21

Second

6,718

1,152

565

(c)

1.79

Third

7,035

1,225

297

(d)

.94

Fourth

7,155

1,096

359

1.13

2005

First

4,956

621

219

(e)

.71

Second

4,963

596

299

(f)

.96

Third

5,769

604

272

(g)

.87

Fourth

7,059

875

452

(h)

1.44


*		Per-share amounts in all periods reflect the impact of a3-for-1 stock split on May 31, 2006.

(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 income of $186 million from asset sales in the United States.

(c)		Includes net after-tax income of $32 million from asset sales, partially offset by accrued office closing costs.

(d)		Includes an after-tax expense of $105 million for income tax adjustments in the United Kingdom.

(e)		Includes net after-tax expenses of $12 million related to tax on repatriated earnings, partially offset by income related to an asset exchange, a favorable legal settlement and liquidation of prior year LIFO inventories.

(f)		Includes net after-tax income of $4 million resulting from a favorable foreign tax rate change, partially offset by premiums on repurchased bonds.

(g)		Includes after-tax expenses of $45 million due to hurricane related expenses and tax on repatriated earnings.

(h)		Includes net after-tax income of $16 million related to asset sales and liquidation of prior year LIFO inventories, partially offset by hurricane related expenses, premiums on bond repurchases and a charge related to a customer bankruptcy.

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


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 ActRules 13a-15(e) and15d-15(e)) as of December 31, 2006, 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, 2006.

There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) ofRules 13a-15 or15d-15 in the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, internal controls over financial reporting.


Item 9B.	*Other Information*

None.

PART III


Item 10.	*Directors, Executive Officers and Corporate Governance of the Registrant*

Information relating to Directors is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 2, 2007.

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) ofRegulation S-K, we intend to disclose the same on the Corporation’s website at www.hess.com.


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 2, 2007.


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 2, 2007.

See “Equity Compensation Plans” in Item 5.


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 2, 2007.


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 2, 2007.

PART IV


Item 15.	*Exhibits, Financial Statement Schedules, and Reports onForm 8-K*


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

The financial statements filed as part of this Annual Report onForm 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’sForm 10-Q for the three months ended June 30, 2006.
	3(2)			By-Laws of Registrant incorporated by reference to Exhibit 3 ofForm 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 ofForm 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) ofForm 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) ofForm 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) toForm 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.
	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) ofForm 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 ofForm 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) ofForm 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) ofForm 10-K of Registrant for the fiscal year ended December 31, 1998.
	10(5)	*	Incentive Cash Bonus Plan description incorporated by reference to Item 1.01 ofForm 8-K of Registrant dated February 7, 2007.
	10(6)	*	Financial Counseling Program description incorporated by reference to Exhibit 10(6) ofForm 10-K of Registrant for fiscal year ended December 31, 2004.
	10(7)	*	Hess Corporation Savings and Stock Bonus Plan.
	10(8)	*	Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) ofForm 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) ofForm 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.
	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) ofForm 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) ofForm 10-K of Registrant for fiscal year ended December 31, 2004.
	10(13)	*	Compensation program description for non-employee directors, incorporated by reference to Item 1.01 ofForm 8-K of Registrant dated January 1, 2007.
	10(14)	*	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) ofForm 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(15)	*	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) ofForm 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(16)	*	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) ofForm 10-K of Registrant for the fiscal year ended December 31, 2001.
��	10(17)	*	Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) ofForm 10-K of Registrant for the fiscal year ended December 31, 2001.
	10(18)	*	Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) ofForm 10-K of Registrant for the fiscal year ended December 31, 1999.
	10(19)		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 ofForm 8-K of Registrant dated October 30, 1998.
	10(20)		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 ofForm 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 23, 2007, to the incorporation by reference in Registrant’s Registration Statements(Form S-8Nos. 333-115844,333-94851 and333-43569, andForm S-3 Nos.333-110294 and333-132145), of its reports relating to Registrant’s financial statements, which consent appears onpage F-1 herein.
	31(1)			Certification required byRule 13a-14(a) (17 CFR240.13a-14(a)) orRule 15d-14(a)(17 CFR 240.15d-14(a)).
	31(2)			Certification required byRule 13a-14(a) (17 CFR240.13a-14(a)) orRule 15d-14(a) (17 CFR240.15d-14(a)).
	32(1)			Certification required byRule 13a-14(b) (17 CFR240.13a-14(b)) orRule 15d-14(b) (17 CFR240.15d-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 byRule 13a-14(b) (17 CFR240.13a-14(b)) orRule 15d-14(b) (17 CFR240.15d-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 onForm 8-K

During the three months ended December 31, 2006, Registrant filed or furnished the following report onForm 8-K:

1. Filing dated October 25, 2006 reporting under Items 2.02 and 9.01, a news release dated October 25, 2006 reporting results for the third quarter of 2006.

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 28th day of February 2007.

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 28, 2007

/s/ Nicholas F. Brady Nicholas F. Brady	Director	February 28, 2007

/s/ J. Barclay Collins II J. Barclay Collins II	Director	February 28, 2007

/s/ Edith E. Holiday Edith E. Holiday	Director	February 28, 2007

/s/ Thomas H. Kean Thomas H. Kean	Director	February 28, 2007

/s/ Dr. Risa Lavizzo-Mourey Dr. Risa Lavizzo-Mourey	Director	February 28, 2007

/s/ Craig G. Matthews Craig G. Matthews	Director	February 28, 2007

/s/ John H. Mullin John H. Mullin	Director	February 28, 2007

/s/ John J. O’Connor John J. O’Connor	Director	February 28, 2007

/s/ Frank A. Olson Frank A. Olson	Director	February 28, 2007

/s/ John P. Rielly John P. Rielly	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 28, 2007

/s/ Ernst H. von Metzsch Ernst H. von Metzsch	Director	February 28, 2007

/s/ F. Borden Walker F. Borden Walker	Director	February 28, 2007

/s/ Robert N. Wilson Robert N. Wilson	Director	February 28, 2007

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements(Form S-3 Nos.333-110294 and333-132145 andForm S-8 Nos.333-115844,333-94851 and333-43569 pertaining to the Second Amended and Restated 1995 Long-Term Incentive Plan, the Amended and Restated 1995 Long- Term Incentive Plan and the Hess Corporation Employees’ Savings and Stock Bonus Plan) of Hess Corporation of our reports dated February 23, 2007, with respect to the consolidated financial statements and schedule of Hess Corporation, Hess Corporation management’s assessment of the effectiveness of internal control over financial reporting, and 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, 2006.

New York, NY

February 23, 2007

Schedule II

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2006, 2005 and 2004


			Additions
			Charged
			to Costs		Charged		Deductions
	Balance		and		to Other		from		Balance
Description	January 1		Expenses		Accounts		Reserves		December 31
	(In millions)

2006
Losses on receivables	$	30	$	14	$	—	$	5	$	39

Deferred income tax valuation	$	76	$	24	$	66	$	2	$	164

2005
Losses on receivables	$	17	$	16	$	2	$	5	$	30

Deferred income tax valuation	$	77	$	10	$	2	$	13	$	76

2004
Losses on receivables	$	18	$	2	$	2	$	5	$	17

Deferred income tax valuation	$	126	$	9	$	13	$	71	$	77

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’sForm 10-Q for the three months ended June 30, 2006.
3(2)		By-Laws of Registrant incorporated by reference to Exhibit 3 ofForm 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 ofForm 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) ofForm 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) ofForm 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) toForm 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.
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) ofForm 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 ofForm 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) ofForm 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) ofForm 10-K of Registrant for the fiscal year ended December 31, 1998.
10(5)	*	Incentive Cash Bonus Plan description incorporated by reference to Item 1.01 ofForm 8-K of Registrant dated February 7, 2007.
10(6)	*	Financial Counseling Program description incorporated by reference to Exhibit 10(6) ofForm 10-K of Registrant for fiscal year ended December 31, 2004.
10(7)	*	Hess Corporation Savings and Stock Bonus Plan.
10(8)	*	Performance Incentive Plan for Senior Officers, incorporated by reference to Exhibit (10) ofForm 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) ofForm 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.
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) ofForm 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) ofForm 10-K of Registrant for fiscal year ended December 31, 2004.
10(13)	*	Compensation program description for non-employee directors, incorporated by reference to Item 1.01 ofForm 8-K of Registrant dated January 1, 2007.
10(14)	*	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) ofForm 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(15)	*	Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) ofForm 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(16)	*	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) ofForm 10-K of Registrant for the fiscal year ended December 31, 2001.
10(17)	*	Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) ofForm 10-K of Registrant for the fiscal year ended December 31, 2001.
10(18)	*	Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) ofForm 10-K of Registrant for the fiscal year ended December 31, 1999.
10(19)		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 ofForm 8-K of Registrant dated October 30, 1998.
10(20)		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 ofForm 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 23, 2007, to the incorporation by reference in Registrant’s Registration Statements(Form S-8 Nos.333-115844,333-94851 and333-43569, andForm S-3 Nos.333-110294 and333-132145), of its reports relating to Registrant’s financial statements, which consent appears onpage F-1 herein.
31(1)		Certification required byRule 13a-14(a) (17 CFR240.13a-14(a)) orRule 15d-14(a) (17 CFR240.15d-14(a)).
31(2)		Certification required byRule 13a-14(a) (17 CFR240.13a-14(a)) orRule 15d-14(a) (17 CFR240.15d-14(a)).
32(1)		Certification required byRule 13a-14(b) (17 CFR240.13a-14(b)) orRule 15d-14(b) (17 CFR240.15d-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 byRule 13a-14(b) (17 CFR240.13a-14(b)) orRule 15d-14(b) (17 CFR240.15d-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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Bad

Hess (HES) 10-K2006 FY Annual report

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