10-K

10-K 1 y17683e10vk.htm FORM 10-K 10-K

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, 2005
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission File Number 1-1204

Amerada Hess Corporation

(Exact name of Registrant as specified in its charter)


DELAWARE (State or other jurisdiction of incorporation or organization)		13-4921002 (I.R.S. Employer Identification Number)

1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y. (Address of principal executive offices)		10036 (Zip Code)

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

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


Title of Each Class		Name of Each Exchange on Which Registered

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

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

None

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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

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

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o

The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $8,436,000,000 as of June 30, 2005.

At December 31, 2005, there were 93,065,619 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 3, 2006.

AMERADA 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		17
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
7A.	Quantitative and Qualitative Disclosures About Market Risk		36
8.	Financial Statements and Supplementary Data		40
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		82
9A.	Controls and Procedures		82
9B.	Other Information		82

PART III
10.	Directors and Executive Officers of the Registrant		82
11.	Executive Compensation		82
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		82
13.	Certain Relationships and Related Transactions		82
14.	Principal Accounting Fees and Services		82

PART IV
15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K		83
	Signatures		86
EX-21: SUBSIDIARIES OF REGISTRANT
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*

Amerada Hess Corporation (the Registrant) is a Delaware corporation, incorporated in 1920. The Registrant and its subsidiaries (collectively referred to as the “Corporation”) explore for, develop, produce, purchase, transport and sell crude oil and natural gas. These exploration and production activities take place in the United States, United Kingdom, Norway, Denmark, Russia, Equatorial Guinea, Algeria, Gabon, Libya, Indonesia, Thailand, Azerbaijan, Malaysia and other countries. The Corporation also manufactures, purchases, trades and markets refined petroleum and other energy products. The Corporation owns 50% of a refinery joint venture in the United States Virgin Islands, and another refining facility, terminals and retail gasoline stations located on the East Coast of the United States.

Exploration and Production

At December 31, 2005, the Corporation had 692 million barrels of proved crude oil and natural gas liquids reserves compared with 646 million barrels at the end of 2004. Proved natural gas reserves were 2,406 million Mcf at December 31, 2005 compared with 2,400 million Mcf at December 31, 2004. Proved reserves at December 31, 2005 include 31% and 51%, respectively, of crude oil and natural gas reserves held under production sharing contracts. Of the total proved reserves (on a barrel of oil equivalent basis), 16% are located in the United States, 43% are located in Europe (consisting of reserves in the North Sea and Russia), 16% are located in Africa and the remainder are located in Indonesia, Thailand, Malaysia, and Azerbaijan. On a barrel of oil equivalent basis, 42% of the Corporation’s December 31, 2005 worldwide proved reserves are undeveloped (38% in 2004).

Worldwide crude oil and natural gas liquids production amounted to 244,000 barrels per day in 2005 compared with 246,000 barrels per day in 2004. Worldwide natural gas production was 544,000 Mcf per day in 2005 compared with 575,000 Mcf per day in 2004. On a barrel of oil equivalent basis, production was 335,000 barrels per day in 2005 compared with 342,000 barrels per day in 2004. The impact of Hurricanes Katrina and Rita reduced 2005 full year production by an average of 7,000 barrels of oil equivalent per day (boepd).

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


		2005		2004

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

			44		44

Europe
	United Kingdom		54		70
	Norway		26		27
	Denmark		24		22
	Russia		6		—

			110		119

Africa
	Equatorial Guinea		30		26
	Algeria		25		23
	Gabon		12		12

			67		61


			2005		2004

	Asia and other
		Azerbaijan		4		2
		Other		3		2

				7		4

		Total		228		228

	Natural gas liquids (thousands of barrels per day)
	United States
		Onshore		8		7
		Offshore		4		5

				12		12

	Europe
		United Kingdom		3		5
		Norway		1		1

				4		6

		Total		16		18

	Natural gas (thousands of Mcf per day)
	United States
		Onshore		74		91
		Offshore		63		80

				137		171

	Europe
		United Kingdom		222		268
		Norway		28		27
		Denmark		24		24

				274		319

	Asia and other
		Thailand		57		53
		Joint Development Area of Malaysia and Thailand		51		—
		Indonesia		25		32

				133		85

		Total		544		575

Barrels of oil equivalent*				335		342


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

The Corporation presently estimates that its 2006 barrel of oil equivalent production will be approximately 360,000 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 2005, 23% of the Corporation’s crude oil and natural gas liquids production and 25% of its natural gas production were from United States operations. The Corporation operates mainly offshore in the Gulf of Mexico and onshore in Texas, Louisiana and North Dakota. The Llano field in Garden Banks Blocks 385 and 386 in the Gulf of Mexico produced at the rate of 15,000 barrels of oil equivalent per day in 2005. In 2005, the Corporation acquired an additional 64,000 acres in the Bakken Shale resource play in the Williston Basin of North Dakota.

At December 31, 2005, the Corporation has interests in approximately 355 exploration blocks in the Gulf of Mexico, of which it operates 260. The Corporation has 1,391,000 net undeveloped acres in the Gulf of Mexico.

In 2006, the Corporation intends to drill approximately seven exploration wells in the deepwater Gulf of Mexico and an appraisal of the Tubular Bells discovery (AHC 20%) in Mississippi Canyon Block 725.

The Shenzi development (AHC 28%) in the deepwater Gulf of Mexico is expected to be approved in 2006. During the first quarter of 2006, the Corporation expects to complete the sale of its interests in certain producing properties in the Permian Basin in West Texas and New Mexico with a production rate of approximately 6,000 barrels per day at year-end 2005.

Europe

During 2005, 47% of the Corporation’s crude oil and natural gas liquids production and 50% of its natural gas production were from European operations.

United Kingdom: The Corporation’s activities in the United Kingdom are conducted by its wholly-owned subsidiary, Amerada Hess Limited. During 2005, 23% of the Corporation’s crude oil and natural gas liquids production and 41% of its natural gas production were from United Kingdom operations.

Production in 2005 of crude oil and natural gas liquids from the United Kingdom North Sea was 57,000 barrels per day compared with 75,000 barrels per day in 2004, principally from the Corporation’s non-operated interests in the Beryl (AHC 22.2%), Bittern (AHC 28.3%) and Schiehallion (AHC 15.7%) fields. In addition, production from the Clair field (AHC 9.3%) commenced in 2005. Natural gas production from the United Kingdom in 2005 was 222,000 Mcf of natural gas per day compared with 268,000 Mcf per day in 2004, primarily from gas fields in the Easington Catchment Area (AHC 28.8%), as well as Everest (AHC 18.7%), Lomond (AHC 16.7%) and Beryl (AHC 22.2%).

Development of the Atlantic and Cromarty natural gas fields is substantially complete. These fields are expected to commence production in the second quarter of 2006.

Norway: The Corporation’s activities in Norway are conducted through its wholly-owned Norwegian subsidiary, Amerada Hess Norge
A/ S. Norwegian operations accounted for crude oil and natural gas liquids production of 27,000 barrels per day in 2005 and 28,000 barrels per day in 2004. Natural gas production averaged 28,000 Mcf per day in 2005 and 27,000 Mcf per day in 2004. Substantially all of the Norwegian production is from the Corporation’s 28.1% interest in the Valhall field.

Denmark: Amerada Hess ApS, the Corporation’s wholly-owned Danish subsidiary, operates the South Arne field. Net production from the Corporation’s 57.5% interest in the South Arne field was 24,000 barrels of crude oil per day in 2005 and 22,000 barrels of crude oil per day in 2004. Natural gas production was 24,000 Mcf per day in 2005 and 2004.

Russia: During 2005, the Corporation acquired a controlling interest in a corporate joint venture operating in the Volga-Urals region of Russia. Subsequent to the acquisition, this venture acquired additional licenses and assets bringing the Corporation’s total investment in Russia to approximately $400 million. Production averaged 6,000 barrels per day in 2005 and is expected to average 12,000 to 15,000 barrels per day in 2006.

Africa

During 2005, 27% of the Corporation’s crude oil and natural gas liquids production were from African operations.

Equatorial Guinea: The Corporation currently has interests in production sharing contracts covering two offshore blocks. Block G contains the Okume Complex and Ceiba field where the Corporation is operator and owns an 85% interest. Net production from the Ceiba field averaged 30,000 barrels of crude oil per day in 2005 and 26,000 barrels per day in 2004. The development of the Okume Complex is on schedule and first production of crude oil is expected in early 2007.

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 25,000 and 23,000 barrels of crude oil per day in 2005 and 2004, respectively. The Corporation has also submitted a plan of development for a small oil discovery on Block 401C and is currently awaiting approval.

Gabon: Amerada Hess Production Gabon, the Corporation’s 77.5% owned Gabonese subsidiary, 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 2005 and 2004.

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. The re-entry terms include a 25-year extension of the concessions, in which the Corporation will hold an 8.16% interest, and a payment by the Corporation to the Libyan National Oil Corporation of $260 million. In addition, the Corporation will make a payment of $106 million related to certain investments in fixed assets made since 1986. The Corporation estimates its net share of 2006 production from Libya will average approximately 20,000 to 25,000 barrels of oil per day.

Egypt: In January 2006, the Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a 25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities.

Asia and Other

During 2005, 3% of the Corporation’s crude oil and natural gas liquids production and 24% of its natural gas production were from Asian operations.

Block A-18 of the Joint Development Area of Malaysia and Thailand (JDA): First production from Block A-18 of the JDA commenced in early 2005. Net production from the Corporation’s 50% interest averaged 51,000 Mcf of natural gas and 1,000 barrels of crude oil per day in 2005. Additional gas sales commencing in 2008 were negotiated with buyers during 2004. Development drilling will continue in 2006 to increase the production capacity of the field in preparation for the increased gas sales.

Thailand: The Corporation has a 15% interest in the Pailin gas field offshore Thailand. Net production from the Corporation’s interest averaged 57,000 Mcf and 53,000 Mcf of natural gas per day in 2005 and 2004, respectively. The onshore natural gas project in the Phu Horm Block (AHC 35%) was approved in 2005 and development work is underway. First production from the Phu Horm field is expected at the end of 2006.

Indonesia: Natural gas production in Indonesia averaged 25,000 Mcf per day in 2005 and 32,000 Mcf per day in 2004. The Ujung Pangkah gas sales agreement has been approved and gas sales are expected to commence by early 2007.

Azerbaijan: The Corporation has a 2.72% interest in the ACG fields in the Caspian Sea. Net production from its interest averaged 4,000 barrels of crude oil per day in 2005 and 2,000 barrels per day in 2004. The Corporation also holds a 2.36% interest in the BTC Pipeline, which is expected to be completed in the second quarter of 2006.

Oil and Gas Reserves

The Corporation’s net proved oil and gas reserves at the end of 2005, 2004 and 2003 are presented under Supplementary Oil and Gas Data in the accompanying financial statements.

During 2005, the Corporation provided oil and gas reserve estimates for 2004 to the Department of Energy. Such estimates are compatible with the information furnished to the SEC on Form 10-K, although not necessarily directly comparable due to the requirements of the individual requests. There were no differences in excess of 5%.

The Corporation has no contracts or agreements to sell fixed quantities of its crude oil production, although derivative instruments are used to reduce the effects of changes in selling prices. In the United States, natural gas is sold to local distribution companies, and commercial, industrial and other purchasers, on a spot basis and under contracts for varying periods. The Corporation’s United States production is expected to approximate 50% of its 2006 sales commitments under long-term contracts. Long-term natural gas sales commitments for 2007 are expected to be comparable. The Corporation attempts to minimize price and supply risks associated with its United States natural gas supply commitments by entering into purchase contracts with third parties having adequate sources of supply, on terms substantially similar to those under its commitments.

Average selling prices and average production costs


			2005		2004		2003

Average selling prices (including the effects of hedging) (Note A)
	Crude oil, including condensate and natural gas liquids (per barrel)
		United States	$	33.86	$	27.87	$	24.13
		Europe		33.30		26.24		24.58
		Africa		32.10		26.35		25.43
		Asia and other		54.69		38.36		28.49
		Average		33.69		26.86		24.73
	Natural gas (per Mcf)
		United States	$	7.93	$	5.18	$	4.02
		Europe		5.29		3.96		3.00
		Asia and other		4.02		3.90		3.10
		Average		5.65		4.31		3.34


		2005		2004		2003

Average production (lifting) costs per barrel of oil equivalent produced (Note B)
	United States	$	7.46	$	6.42	$	5.90
	Europe		8.13		6.35		5.49
	Africa		7.99		7.72		8.96
	Asia and other		7.29		6.05		4.54
	Average		7.91		6.59		6.06

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, 2005


		Undeveloped
		Acreage (Note A)

		Gross		Net

		(In thousands)
United States			2,012		1,460
Europe			2,596		951
Africa			7,385		5,825
Asia and other			9,743		2,937

	Total (Note B)		21,736		11,173

Note A: Includes acreage held under production sharing contracts.

Note B: Approximately one-sixth of net undeveloped acreage held at December 31, 2005 will expire during the next three years.

Gross and net developed acreage and productive wells at December 31, 2005


		Developed				Productive Wells (Note A)
		Acreage
		Applicable to
		Productive Wells				Oil				Gas

		Gross		Net		Gross		Net		Gross		Net

		(In thousands)
United States			1,582		438		2,770		619		235		179
Europe			1,163		555		275		83		160		36
Africa			354		177		154		48		—		—
Asia and other			2,465		833		30		3		282		51

	Total		5,564		2,003		3,229		753		677		266

Note A: Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 313 gross wells and 88 net wells.

Number of net exploratory and development wells drilled


			Net Exploratory						Net Development
			Wells						Wells

			2005		2004		2003		2005		2004		2003

Productive wells
	United States			—		4		2		28		32		19
	Europe			3		—		—		6		5		7
	Africa			1		1		2		12		12		7
	Asia and other			1		1		1		8		2		5

		Total		5		6		5		54		51		38

Dry holes
	United States			2		1		3		2		—		1
	Europe			1		1		2		—		1		1
	Africa			1		2		4		1		1		2
	Asia and other			—		1		—		—		1		—

		Total		4		5		9		3		3		4

		Total		9		11		14		57		54		42

Number of wells in process of drilling at December 31, 2005


		Gross		Net
		Wells		Wells

United States			5		4
Europe			7		3
Africa			4		2
Asia and other			12		3

	Total		28		12

Number of waterfloods and pressure maintenance projects in process of installation at December 31, 2005 — 3

Marketing and Refining

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: HOVENSA’s total crude runs amounted to 461,000 barrels per day in 2005 and 484,000 barrels per day in 2004. The fluid catalytic cracking unit at HOVENSA operated at the rates of 123,000 and 139,000 barrels per day in 2005 and 2004, respectively. The coking unit at HOVENSA operated at the rate of 54,000 barrels per day in 2005 and 55,000 barrels per day in 2004. The following table summarizes capacity and utilization rates for HOVENSA:

Refinery Utilization

Refinery

Capacity

2005

2004

(Thousands of

barrels per day)

Crude

500

92.2

96.7

Fluid catalytic cracker

150

81.9

92.9

Coker

92.8

94.5

A crude unit and the fluid catalytic cracking unit at HOVENSA were each shutdown for approximately 30 days of scheduled maintenance in 2005.

The coker permits HOVENSA to run lower-cost heavy crude oil. HOVENSA has a long-term supply contract with PDVSA to purchase 115,000 barrels per day of Venezuelan Merey heavy crude oil. PDVSA also supplies 155,000 barrels per day of Venezuelan Mesa 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 55,000 barrels per day in 2005 and 52,000 barrels per day in 2004. Substantially all of Port Reading’s production is gasoline and heating oil. In 2005, the Port Reading facility was shutdown for 36 days of planned maintenance.

Marketing: The Corporation markets refined petroleum products on the East Coast of the United States to the motoring public, wholesale distributors, industrial and commercial users, other petroleum companies, governmental agencies and public utilities. It also markets natural gas to utilities and other industrial and commercial customers. The Corporation’s energy marketing activities also include the sale of

electricity. In 2005, the Corporation acquired two natural gas marketing businesses, First Energy Solutions and EnLine Solutions.

The Corporation has 1,354 HESS^® gasoline stations at December 31, 2005, including stations owned by the WilcoHess joint venture, of which approximately 86% are company or WilcoHess operated. 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 and North and South Carolina. In June 2005, the WilcoHess joint venture acquired approximately 100 retail sites in North Carolina through the acquisition of Trade Oil Company.

Refined product sales averaged 456,000 barrels per day in 2005 and 428,000 barrels per day in 2004. Of total refined products sold in 2005, 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 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 development of an LNG terminal project located in Fall River, Massachusetts.

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.

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

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 and local governments is not expected to have a material adverse effect on the Corporation’s earnings and competitive position within the industry. The Corporation spent $15 million in 2005 for environmental remediation, with a comparable amount anticipated for 2006. Regulatory changes already made or anticipated in the United States will alter the composition and emissions characteristics of motor fuels. The Environmental Protection Agency 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 are estimated to be approximately $75 million. Of this amount, approximately $23 million was spent in 2005 and the remainder is principally expected to be spent in 2006. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are expected to be approximately $410 million, $160 million of which has already been spent. Approximately $200 million is expected to be spent in 2006. HOVENSA expects to finance these capital expenditures through cash flow from operations.

The number of persons employed by the Corporation averaged 11,610 in 2005 and 11,119 in 2004.

The Corporation’s Internet address is www.hess.com. On its website, the Corporation makes available free of charge its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after the Corporation electronically files with or furnishes such material to the Securities and Exchange Commission. Copies of the Corporation’s Code of Business Conduct and Ethics, its Corporate Governance Guidelines and the charters of the Audit Committee, the Compensation and

Management Development Committee and the Corporate Governance and Nominating Committee of the Board of Directors are available on the Corporation’s website and are also available free of charge upon request to the Secretary of the Corporation at its principal executive offices. The Corporation has also filed with the New York Stock Exchange (NYSE) its annual certification that the Corporation’s chief executive officer is unaware of any violation of the NYSE’s corporate governance standards.


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

Our business activities and the value of our securities are subject to significant risk factors, including those described below. The risk factors described below could negatively affect our operations, financial condition, liquidity and results of operations, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectus supplements for securities we issue in the future.

Crude Oil and Natural Gas Price Risk: Our estimated proved reserves, revenue, operating cash flows and future earnings are highly dependent on the prices of crude oil and natural gas, 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 are also important in influencing 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 quantities of proved 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, blow-outs 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 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. We have been affected by certain of these events in several countries in which we operate. Some of the international areas in which we operate may be politically less stable than our domestic operations. We market motor fuels through lessee-dealers and wholesalers in certain states where legislation prohibits producers or refiners of crude oil from directly engaging in retail marketing of motor fuels. Similar legislation has been periodically proposed in the U.S. Congress and in various other states.

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

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

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


Item 3.	*Legal Proceedings*

As disclosed in Registrant’s Form 10-K for the fiscal year ended December 31, 2004 (the Form 10-K), purported class actions consolidated under a complaint captioned: In re Amerada Hess Securities Litigation were pending in United States District Court for the District of New Jersey against 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 defendant’s 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. Defendants believe this action is without merit and will continue to defend this action vigorously.

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 the 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 Registrant. These cases have been consolidated in the Southern District of New York and Registrant is named as a defendant in 40 of the 70 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 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. 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. Registrant and HOVENSA expect to have further discussions with EPA regarding the petroleum refining initiative, although both Registrant and HOVENSA have already installed many of the pollution controls required of other refiners under the consent agreements and 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 refinery 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.

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 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 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, 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 Registrant, and HOVENSA L.L.C., 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.

In June 2001, the Corporation voluntarily investigated and disclosed to the New Jersey Department of Environmental Protection (NJDEP) that there was a calculation error in the program code of the Port Reading refining facility’s Wet Gas Scrubber (WGS) Continuous Emissions Monitoring System (CEM). The error in the code resulted in the CEM system under-calculating carbon monoxide, nitrous oxide (NOx) and sulfur dioxide emissions from the WGS beginning in late 1998 and some exceedances of the permit limits for NOx. After discovery, the code error was promptly corrected. In November 2003, the Corporation received a notice of violation from the NJDEP relating to the CEM coding error. This matter was resolved by payment of $114,000 in December 2005.

In April 2003, HOVENSA received a notice of violation from the Virgin Islands Department of Planning and Natural Resources (DPNR), relating to certain alleged wastewater permit exceedances occurring in 2001 and 2002 at HOVENSA. This matter was resolved by execution of Consent Order in December 2004, which required payment of penalty of $120,000 in January 2005.

The Registrant periodically receives notices from EPA that it is a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties are jointly and severally liable. For certain sites, EPA’s claims or assertions of liability

against the Corporation relating to these sites have not been fully developed. With respect to the remaining sites, EPA’s claims have been settled, or a proposed settlement is under consideration, in all cases for amounts that are not material. The ultimate impact of these proceedings, and of any related proceedings by private parties, on the business or accounts of the Corporation cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates, but is not expected to be material.

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


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

During the fourth quarter of 2005, 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, 2006 regarding executive officers of the Registrant:


				Year Individual
				Became an
				Executive
Name	Age		Office Held*	Officer

John B. Hess		51	Chairman of the Board, Chief Executive Officer and Director		1983
J. Barclay Collins II		61	Executive Vice President, General Counsel and Director		1986
John J. O’Connor		59	Executive Vice President, President of Worldwide Exploration and Production and Director		2001
F. Borden Walker		52	Executive Vice President and President of Marketing and Refining and Director		1996
Brian J. Bohling		45	Senior Vice President		2004
E. Clyde Crouch		57	Senior Vice President		2003
John A. Gartman		58	Senior Vice President		1997
Scott Heck		48	Senior Vice President		2005
Lawrence H. Ornstein		54	Senior Vice President		1995
Howard Paver		55	Senior Vice President		2002
John P. Rielly		43	Senior Vice President and Chief Financial Officer		2002
George F. Sandison		49	Senior Vice President		2003
John J. Scelfo		48	Senior Vice President		2004
Robert P. Strode		50	Senior Vice President		2000
Robert J. Vogel		46	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 4, 2005. The first meeting of Directors following the next annual meeting of stockholders of the Registrant is scheduled to be held May 3, 2006.

Except for Messrs. O’Connor, Bohling, Rielly, 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. O’Connor had served in senior executive positions at Texaco Inc. and BHP Petroleum prior to his employment with the Registrant in October 2001. Mr. Bohling was employed in senior human resource positions with American Standard Corporation and CDI Corporation before joining the Registrant in 2004. Prior to his employment with the Registrant in April 2001, Mr. Rielly had been a partner of Ernst & Young LLP. 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 Amerada Hess Corporation is traded principally on the New York Stock Exchange (ticker symbol: AHC). High and low sales prices were as follows:

2005

2004

Quarter Ended

High

Low

High

Low

March 31

103.96

77.83

67.48

53.24

June 30

112.17

86.25

79.49

62.05

September 30

142.50

106.60

89.73

75.81

December 31

138.99

110.00

93.89

76.13

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

2005

2004

Quarter Ended

High

Low

High

Low

March 31

90.33

70.47

64.75

54.90

June 30

95.75

74.75

72.45

60.71

September 30

120.17

91.32

80.05

68.93

December 31

117.56

95.33

83.65

68.70


	*Holders*

At December 31, 2005, 5,712 stockholders (based on number of holders of record) owned 93,065,619 shares of common stock.


	*Dividends*

Cash dividends on common stock totaled $1.20 per share ($.30 per quarter) during 2005 and 2004. Annual dividends on the 7% cumulative mandatory convertible preferred stock totaled $3.50 per share ($.875 per quarter) in 2005 and 2004. See note 8 on Long-Term Debt in 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, 2005:

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

3,817,000

72.27

5,124,000

Equity compensation plans not approved by security holders**

—


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


**	Registrant has a Stock Award Program adopted in 1997 pursuant to which each non-employee director receives 500 shares of Registrant’s common stock each year. These awards are made from treasury shares purchased by the Company in the open market. Stockholders did not approve this equity compensation plan.

See note 9 on Stock-Based Compensation Plans in 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:


			2005			2004			2003			2002			2001

			(Millions of dollars, except per share amounts)
Sales and other operating revenues
	Crude oil and natural gas liquids		$	3,219		$	2,594		$	2,295		$	2,702		$	2,317
	Natural gas (including sales of purchased gas)			6,423			4,638			4,522			3,077			4,501
	Petroleum and other energy products			11,690			8,125			6,250			4,635			5,087
	Convenience store sales and other operating revenues			1,415			1,376			1,244			1,137			1,147

		Total	$	22,747		$	16,733		$	14,311		$	11,551		$	13,052

Income (loss) from continuing operations			$	1,242	(a)	$	970	(b)	$	467	(c)	$	(245	)(d)	$	816	(e)
Discontinued operations				—			7			169			27			98
Cumulative effect of change in accounting principle				—			—			7			—			—

Net income (loss)			$	1,242		$	977		$	643		$	(218	)	$	914

Less preferred stock dividends				48			48			5			—			—

Net income (loss) applicable to common shareholders			$	1,194		$	929		$	638		$	(218	)	$	914

Basic earnings (loss) per share
	Continuing operations		$	13.14		$	10.30		$	5.21		$	(2.78	)	$	9.26
	Net income (loss)			13.14			10.38			7.19			(2.48	)		10.38
Diluted earnings (loss) per share
	Continuing operations		$	11.94		$	9.50		$	5.17		$	(2.78	)	$	9.15
	Net income (loss)			11.94			9.57			7.11			(2.48	)		10.25

Total assets			$	19,115		$	16,312		$	13,983		$	13,262		$	15,369
Total debt				3,785			3,835			3,941			4,992			5,665
Stockholders’ equity				6,286			5,597			5,340			4,249			4,907
Dividends per share of common stock			$	1.20		$	1.20		$	1.20		$	1.20		$	1.20


(a)		Includes after-tax charges 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.

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

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

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

(e)		Includes after-tax charges of $31 million for losses related to the bankruptcy of certain subsidiaries of Enron and accrued severance.


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. The E&P segment explores for, develops, produces and sells crude oil and natural gas. The marketing and refining segment manufactures, purchases, trades and markets refined petroleum products and other energy products.


	*Exploration & Production*

The Corporation’s strategy for the E&P segment is to grow reserves and production in a sustainable and financially disciplined manner. The Corporation has increased its reserve life in each of the last three years. At December 31, 2005 and 2004, the Corporation’s total proved reserves were 1,093 million and 1,046 million barrels of oil equivalent. The following table summarizes the components of proved reserves as of December 31:


		2005				2004

Crude oil and condensate (millions of barrels)
	U.S.		124	18	%		124	19	%
	International		568	82			522	81

Total			692	100	%		646	100	%

Natural Gas (millions of Mcf)
	U.S.		282	12	%		300	12	%
	International		2,124	88			2,100	88

Total			2,406	100	%		2,400	100	%

Income from continuing operations was $1,058 million in 2005, $755 million in 2004 and $414 million in 2003. The improved results were primarily driven by increasingly higher oil and gas prices during the reporting period. See further discussion in Comparison of Results on page 21.

Production totaled 335,000 barrels of oil equivalent per day (boepd) in 2005, 342,000 boepd in 2004 and 373,000 boepd in 2003. During 2005, first production was achieved from Block A-18 of the Malaysia-Thailand Joint Development Area (JDA), the Clair field in the North Sea and Phase 1 of the ACG fields in Azerbaijan. Damage caused by Hurricanes Katrina and Rita in the Gulf of Mexico caused production to be lower by 7,000 boepd in 2005. The Corporation estimates that production will be approximately 360,000 boepd to 380,000 boepd in 2006.

The Corporation has a number of development projects that are in various stages of completion that should begin production in 2006 and 2007. Development milestones achieved in 2005 include:


	•	Development of the Atlantic and Cromarty natural gas fields in the United Kingdom sector of the North Sea is substantially complete.

	•	The Phu Horm onshore gas project in Thailand was sanctioned. First production is scheduled at the end of 2006.

	•	The Okume Complex development in Equatorial Guinea is on schedule and on budget. First production of crude oil is scheduled for the beginning of 2007.

	•	Development of the Pangkah field in Indonesia also progressed and is on schedule. First gas is expected in the first half of 2007.

During 2005, the Corporation acquired a controlling interest in a corporate joint venture operating in the Volga-Urals region of Russia. Subsequent to the acquisition, this venture acquired additional licenses and

assets, bringing the Corporation’s total investment in Russia to approximately $400 million. Production averaged 6,000 boepd in 2005 and is expected to average 12,000 to 15,000 boepd in 2006.

In January 2006, the Corporation, in conjunction with its Oasis Group partners, re-entered its former oil and gas production operations in the Waha concessions in Libya. The re-entry terms include a 25-year extension of the concessions, in which the Corporation will hold an 8.16% interest, and a payment by the Corporation to the Libyan National Oil Corporation of $260 million. In addition, the Corporation will make a payment of $106 million related to certain investments in fixed assets made since 1986. The Corporation estimates its net share of 2006 production from Libya will average approximately 20,000 to 25,000 boepd.

In January 2006, the Corporation acquired a 55% working interest in the deepwater section of the West Mediterranean Block 1 Concession (the West Med Block) in Egypt for $413 million. The Corporation has a 25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities.

In 2006, the Corporation will complete the sale of its interests in certain producing properties located in the Permian Basin in West Texas and New Mexico for $404 million, before purchase price adjustments. The Corporation estimates that it will record an after-tax gain of $160 to $180 million in the first quarter on the sale of these assets.


	*Marketing & Refining*

The Corporation’s strategy is to deliver consistent financial performance from marketing and refining assets and generate free cash flow. Net income was $515 million in 2005, $451 million in 2004 and $327 million in 2003. Refining operations contributed net income of $346 million in 2005, $302 million in 2004 and $165 million in 2003. Marketing earnings were $136 million in 2005, $112 million in 2004 and $145 million in 2003. Total marketing and refining earnings improved due to increased margins and higher refined product sales volumes. The Corporation received cash distributions from HOVENSA totaling $275 million in 2005 and $88 million in 2004.

In 2005, the Corporation’s Port Reading facility commenced its approximately $75 million program for complying with low-sulfur gasoline requirements. Capital expenditures of $23 million were made in 2005 with the remainder of the expenditures anticipated in 2006. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are expected to approximate $410 million, of which $160 million has been spent. Anticipated capital expenditures in 2006 for the low-sulfur requirements are $200 million. HOVENSA plans to finance these capital expenditures through cash flow from operations.


	*Liquidity and Capital and Exploratory Expenditures*

Net cash provided by operating activities was $1,840 million in 2005 compared with $1,903 million in 2004. At December 31, 2005, cash and cash equivalents totaled $315 million compared with $877 million at December 31, 2004. The Corporation’s debt to capitalization ratio at December 31, 2005 was 37.6% compared with 40.7% at the end of 2004. Total debt was $3,785 million at December 31, 2005 and $3,835 million at December 31, 2004. The Corporation has debt maturities of $26 million in 2006.

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


		2005		2004

		(Millions of
		dollars)
Exploration and Production
	United States	$	353	$	446
	International		2,031		1,117

	Total Exploration and Production		2,384		1,563
Marketing and Refining			106		87

	Total Capital and Exploratory Expenditures	$	2,490	$	1,650

Exploration expenses charged to income included above:
	United States	$	89	$	89
	International		60		40

		$	149	$	129

The Corporation has approved a $4 billion capital and exploratory expenditure program for 2006, which includes a total of approximately $780 million for the acquisition of Egyptian assets and re-entry to the Waha concessions in Libya. Excluding acquisitions, $3.1 billion is targeted for Exploration and Production and $125 million for Marketing and Refining.

Consolidated Results of Operations

Net income from continuing operations in 2005 was $1,242 million compared with $970 million in 2004 and $467 million in 2003. See the following page for a table of items affecting the comparability of earnings between periods.

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


	2005			2004			2003

	(Millions of dollars, except per
	share data)
Exploration and Production	$	1,058		$	755		$	414
Marketing and Refining		515			451			327
Corporate		(191	)		(85	)		(101	)
Interest expense		(140	)		(151	)		(173	)

Income from continuing operations		1,242			970			467
Discontinued operations		—			7			169
Income from cumulative effect of accounting change		—			—			7

Net income	$	1,242		$	977		$	643

Income per share from continuing operations — diluted	$	11.94		$	9.50		$	5.17

Net income per share — diluted	$	11.94		$	9.57		$	7.11

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 income from continuing operations:


		2005			2004			2003

		(Millions of dollars)
Exploration and Production
	Net gains from asset sales	$	41		$	54		$	31
	Hurricane related costs		(26	)		—			—
	Income tax adjustments		11			19			30
	Legal settlement		11			—			—
	Accrued severance and office costs		—			(9	)		(32	)
Marketing and Refining
	LIFO inventory liquidation		32			12			—
	Charge related to customer bankruptcy		(8	)		—			—
	Net loss from asset sales		—			—			(20	)
Corporate
	Premiums on bond repurchases		(26	)		—			(34	)
	Tax on repatriated earnings		(72	)		—			—
	Income tax adjustments		—			13			—
	Insurance accrual		—			(13	)		—

		$	(37	)	$	76		$	(25	)

The items in the table above are explained, and the pre-tax amounts are shown, on pages 24 through 26.

Comparison of Results


	*Exploration and Production*

Following is a summarized income statement of the Corporation’s exploration and production operations:


			2005		2004		2003

			(Millions of dollars)
Sales and other operating revenues			$	4,210	$	3,416	$	3,087
Non-operating income				94		90		21

		Total revenues		4,304		3,506		3,108

Costs and expenses
	Production expenses, including related taxes			1,007		825		796
	Exploration expenses, including dry holes and lease impairment			397		287		369
	General, administrative and other expenses			140		150		168
	Depreciation, depletion and amortization			965		918		998

		Total costs and expenses		2,509		2,180		2,331

Results of operations from continuing operations before income taxes				1,795		1,326		777
Provision for income taxes				737		571		363

Results from continuing operations				1,058		755		414
Discontinued operations				—		7		170
Income from cumulative effect of accounting change				—		—		7

Results of operations			$	1,058	$	762	$	591

After considering the exploration and production items in the table on page 24, the remaining changes in exploration and production earnings are primarily attributable to changes in selling prices, production volumes and operating costs and exploration expenses, as discussed below.

Selling prices: Higher average selling prices of crude oil, natural gas liquids and natural gas increased exploration and production revenues from continuing operations by approximately $870 million, including the effect of hedging, in 2005 compared with 2004. In 2004, the change in average selling prices increased revenues by approximately $400 million compared with 2003.

The Corporation’s average selling prices, including the effects of hedging, were as follows:


		2005		2004		2003

Crude oil (per barrel)
	United States	$	32.64	$	27.42	$	24.23
	Europe		33.13		26.18		24.66
	Africa		32.10		26.35		25.43
	Asia and other		54.69		38.36		28.49
Natural gas liquids (per barrel)
	United States		38.50		29.50		23.74
	Europe		37.13		27.44		23.09
Natural gas (per Mcf)
	United States		7.93		5.18		4.02
	Europe		5.29		3.96		3.00
	Asia and other		4.02		3.90		3.10

The Corporation’s average selling prices, excluding the effects of hedging, were as follows:


		2005		2004		2003

Crude oil (per barrel)
	United States	$	51.16	$	38.56	$	29.43
	Europe		52.22		37.57		29.06
	Africa		51.70		37.07		28.10
	Asia and other		54.69		38.36		28.49
Natural gas liquids (per barrel)
	United States		38.50		29.50		23.74
	Europe		37.13		27.44		23.09
Natural gas (per Mcf)
	United States		7.93		5.53		5.08
	Europe		5.29		3.96		3.00
	Asia and other		4.02		3.90		3.10

The after-tax impacts of hedging reduced earnings by $989 million ($1,582 million before income taxes) in 2005, $583 million ($935 million before income taxes) in 2004 and $260 million ($418 million before income taxes) in 2003.

Production and sales volumes: The Corporation’s crude oil and natural gas production was 335,000 boepd in 2005, 342,000 boepd in 2004 and 373,000 boepd in 2003. Hurricane related interruptions in the Gulf of Mexico reduced 2005 production by approximately 7,000 boepd. The Corporation anticipates that

its 2006 production will average between 360,000 and 380,000 boepd, including 20,000 to 25,000 boepd from Libya. The Corporation’s net daily worldwide production was as follows:


			2005		2004		2003

Crude oil (thousands of barrels per day)
	United States			44		44		44
	Europe			110		119		137
	Africa			67		61		52
	Asia and other			7		4		8

		Total		228		228		241

Natural gas liquids (thousands of barrels per day)
	United States			12		12		11
	Europe			4		6		7

		Total		16		18		18

Natural gas (thousands of Mcf per day)
	United States			137		171		253
	Europe			274		319		367
	Asia and other			133		85		63

		Total		544		575		683

Barrels of oil equivalent* (thousands of barrels per day)				335		342		373

Barrels of oil equivalent production included above related to discontinued operations				—		—		13


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

Crude oil production in the United States in 2005 included increased production from the Llano field which offset natural decline and the effect of the hurricanes. Production in Europe was lower due to natural decline and increased maintenance, partially offset by new production from Russia. Increased crude oil production in Africa is principally due to improved performance from the Ceiba field in Equatorial Guinea. Natural gas production in Asia increased due to new production from the JDA.

Decreased sales volumes resulted in lower revenue of approximately $80 million in 2005 and $75 million in 2004.

Operating costs and depreciation, depletion and amortization: Cash operating costs, consisting of production expenses and general and administrative expenses, increased by $147 million in 2005 and $44 million in 2004 compared with the prior years, excluding the hurricane related costs and accrued severance and office lease costs discussed on page 24. Production expenses increased in 2005 and 2004, principally reflecting higher maintenance expenses, production taxes and fuel costs. Production expenses in 2005 also increased due to expanded operations in Russia and the JDA. Depreciation, depletion and amortization charges were higher in 2005, principally due to higher per barrel rates. Depreciation and related charges were lower in 2004 compared with 2003, reflecting decreased production volumes. Unit production costs per barrel of oil equivalent, comprised of production expense, administrative costs and depreciation, depletion and amortization totaled $16.88 in 2005, $14.96 in 2004 and $14.52 in 2003. Unit production costs in 2006 are estimated to be $17 to $19 per barrel of oil equivalent.

Exploration expenses: Exploration expenses were higher in 2005, reflecting increased drilling and seismic activity compared with 2004. Exploration expenses were lower in 2004 compared with 2003 as a result of lower dry hole costs.

Other: After-tax foreign currency gains were $20 million ($3 million loss before income taxes) in 2005 and $6 million ($29 million before income taxes) in 2004, compared with a loss of $22 million ($4 million before income taxes) in 2003.

The effective income tax rate for exploration and production operations was 41% in 2005, 43% in 2004 and 47% in 2003. After considering the items in the table below, the effective income tax rates were 42% in 2005, 46% in 2004 and 51% in 2003. The effective income tax rate for exploration and production operations in 2006 is expected to be in the range of 50% to 52%. The increase in the estimated 2006 effective income tax rate is due to an anticipated additional 10% supplementary tax on oil and gas earnings in the United Kingdom, and the estimated impact of Libyan operations, which commenced in 2006 and will be taxed at a rate higher than the current exploration and production effective rate. In addition, there will also be a one-time non-cash charge of approximately $40 to $50 million from the adjustment of deferred income tax liabilities when the anticipated United Kingdom tax is enacted, which is expected to be in the second or third quarter of 2006.

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


	Before Income Taxes									After Income Taxes

	2005			2004			2003			2005			2004			2003

	(Millions of dollars)
Gains from asset sales	$	48		$	55		$	47		$	41		$	54		$	31
Hurricane related costs		(40	)		—			—			(26	)		—			—
Income tax adjustments		—			—			—			11			19			30
Legal settlement		19			—			—			11			—			—
Accrued severance and office costs		—			(15	)		(53	)		—			(9	)		(32	)

	$	27		$	40		$	(6	)	$	37		$	64		$	29

2005: The gains from asset sales in 2005 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 natural gas development in Indonesia. The Corporation incurred incremental expenses, principally repair costs and higher insurance premiums in 2005, 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 on the sales of an office building in Aberdeen, 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 accrued an additional amount for severance and vacated office space during 2004, which is reflected in general and administrative expenses in the income statement.

2003: The Corporation recorded an after-tax charge for accrued severance in the United States and United Kingdom and a reduction of leased office space in London. The pre-tax amount of this charge was $53 million, of which $32 million relates to vacated office space. The remainder of $21 million relates to severance for positions that were eliminated in London, Aberdeen and Houston. These expenses are reflected principally in general and administrative expenses in the income statement.

The Corporation recorded an income tax benefit reflecting the recognition for United States income tax purposes of certain prior year foreign exploration expenses. The gain from asset sale in 2003 reflects the sale of the Corporation’s 1.5% interest in the Trans Alaska Pipeline System.

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 and changes in tax rates.


	*Marketing and Refining*

Earnings from marketing and refining activities amounted to $515 million in 2005, $451 million in 2004 and $327 million in 2003. After considering the marketing and refining items in the table on page 26, the earnings amounted to $491 million in 2005, $439 million in 2004 and $347 million in 2003 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 the note receivable from PDVSA and other miscellaneous items were $346 million in 2005, $302 million in 2004 and $165 million in 2003.

The Corporation’s share of HOVENSA’s income was $376 million ($231 million after income taxes) in 2005 and $244 million ($216 million after income taxes) in 2004. In 2003, HOVENSA’s earnings were $117 million, before and after income taxes. The increased earnings in 2005 were due to higher refining margins. In 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 PDVSA note. In 2004, income taxes on HOVENSA’s earnings were partially offset by available loss carryforwards. Cash distributions from HOVENSA were $275 million in 2005 and $88 million in 2004. A crude unit and the fluid catalytic cracking unit at HOVENSA were each shutdown for approximately 30 days of scheduled maintenance in 2005.

Pre-tax interest on the PDVSA note was $20 million, $25 million and $30 million in 2005, 2004 and 2003, respectively. Interest income is reflected in non-operating income in the income statement. At December 31, 2005, the remaining balance of the PDVSA note was $212 million, which is scheduled to be fully repaid by February 2009.

Port Reading’s after-tax earnings were $100 million in 2005, $60 million in 2004 and $27 million in 2003, reflecting higher margins in each period. In 2005, the Port Reading facility was shutdown for 36 days of planned maintenance.

The following table summarizes refinery utilization rates:

Refinery Utilization

Refinery

Capacity

2005

2004

2003

(Thousands of

barrels per day)

HOVENSA

Crude

500

92.2%

96.7%

88.0%

Fluid catalytic cracker

150

81.9%

92.9%

94.7%

Coker

92.8%

94.5%

91.4%

Port Reading

85.3%

83.4%

87.1%


	*	Reflects reduced utilization from scheduled maintenance.


**	Includes a storm-related interruption.

Marketing: Marketing operations, which consist principally of retail gasoline and energy marketing activities, generated income of $112 million in 2005, $100 million in 2004 and $165 million in 2003, excluding the income from liquidation of LIFO inventories and other items described on page 26. The increase in 2005 was primarily due to higher margins and increased sales volumes. The decrease in 2004 was principally due to lower margins. Total refined product sales volumes were 456,000 barrels per day in 2005, 428,000 barrels per day in 2004 and 419,000 barrels per day in 2003.

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 $33 million in 2005, $37 million in 2004 and $17 million in 2003. Before income taxes, the trading income amounted to $60 million in 2005, $72 million in 2004 and $30 million in 2003, which is included in operating revenues in the income statement.

Marketing expenses increased in 2005, 2004 and 2003 reflecting additional retail sites and higher costs of the trading partnership.

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


	Before Income Taxes								After Income Taxes

	2005			2004		2003			2005			2004		2003

	(Millions of dollars)
LIFO inventory liquidation	$	51		$	20	$	—		$	32		$	12	$	—
Loss from asset sales		—			—		(9	)		—			—		(20	)
Charge related to customer bankruptcy		(13	)		—		—			(8	)		—		—

	$	38		$	20	$	(9	)	$	24		$	12	$	(20	)

In 2005, marketing and refining earnings include income from the liquidation of prior year LIFO inventories and a charge resulting from the bankruptcy of a customer in the utility industry, which is included in marketing expenses. In 2004, marketing and refining results include income from the liquidation of LIFO inventories. In 2003, marketing and refining earnings were reduced by a loss from the sale of the Corporation’s interest in a shipping joint venture.

Marketing and refining earnings will likely continue to be volatile reflecting competitive industry conditions, government regulatory changes and supply and demand factors, including the effects of weather.


	*Corporate*

The following table summarizes corporate expenses:


			2005			2004			2003

			(Millions of dollars)
Corporate expenses (excluding the other items, after-tax listed below)			$	119		$	116		$	98
Income taxes (benefits) on the above				(26	)		(31	)		(31	)

				93			85			67
Other items, after-tax
	Tax on repatriation of foreign earnings			72			—			—
	Premiums on bond repurchases			26			—			34
	Corporate insurance accrual			—			13			—
	Adjustments relating to income tax audits			—			(13	)		—

		Net corporate expenses	$	191		$	85		$	101

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 U.S. parent. During 2005, 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 amounts of the bond repurchase premiums in 2005 and 2003 were $39 million and $58 million, respectively, which are reflected in non-operating income in the income statement. The pre-tax amount of the 2004 corporate insurance accrual was $20 million. Recurring after-tax corporate expenses in 2006 are estimated to be in the range of $105 to $115 million.


	*Interest*

After-tax interest expense was as follows:


	2005		2004		2003

	(Millions of dollars)
Total interest incurred	$	304	$	295	$	334
Less capitalized interest		80		54		41

Interest expense before income taxes		224		241		293
Less income taxes		84		90		120

After-tax interest expense	$	140	$	151	$	173

After-tax interest expense in 2006 is anticipated to be lower than the 2005 level because of higher estimated capitalized interest.


	*Discontinued Operations*

In 2003, the Corporation exchanged its crude oil producing properties in Colombia plus $10 million in cash, for an additional 25% interest in natural gas reserves in the JDA. In addition, the Corporation sold, for aggregate proceeds of $445 million, producing properties in the Gulf of Mexico shelf, the Jabung field in Indonesia and several small United Kingdom fields. These disposals resulted in a net gain from asset sales of $116 million and income from operations prior to sale was $53 million, after income taxes. Income from discontinued operations of $7 million in 2004 reflects the settlement of a previously accrued contingency relating to the exchanged Colombian assets.


	*Change in Accounting Principle*

The Corporation adopted Statement of Financial Accounting Standards (FAS) No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. A net after-tax gain of $7 million resulting from the cumulative effect of this accounting change was recorded at the beginning of 2003.


	*Sales and Other Operating Revenues*

Sales and other operating revenues totaled $22,747 million in 2005, an increase of 36% compared with 2004. The increase reflects higher selling prices of crude oil and natural gas in exploration and production activities and higher selling prices and sales volumes in marketing activities. In 2004, sales and other operating revenues totaled $16,733 million, an increase of 17% compared with 2003. This increase principally reflects higher selling prices and sales volumes of refined products, partially offset by decreased sales of purchased natural gas 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:


	2005			2004

	(Millions of dollars,
	except ratios)
Cash and cash equivalents	$	315		$	877
Current portion of long-term debt	$	26		$	50
Total debt	$	3,785		$	3,835
Stockholders’ equity	$	6,286		$	5,597
Debt to capitalization ratio*		37.6	%		40.7	%


*	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:


	2005			2004			2003

	(Millions of dollars)
Net cash provided by (used in):
Operating activities	$	1,840		$	1,903		$	1,581
Investing activities		(2,255	)		(1,371	)		(777	)
Financing activities		(147	)		(173	)		(483	)

Net increase (decrease) in cash and cash equivalents	$	(562	)	$	359		$	321

Operating Activities: In 2005, net cash provided by operating activities of $1,840 million was comparable to the prior year as higher earnings in 2005 were offset by a decrease from changes in operating assets and liabilities, principally working capital, of $408 million. Net cash provided by operating activities was $1,903 million in 2004, an increase of $322 million over 2003, resulting primarily from higher earnings and an increase from changes in operating assets and liabilities of $227 million. Net cash provided by operating activities was $1,581 million in 2003. The Corporation received cash distributions of $275 million in 2005 and $88 million in 2004 from HOVENSA.

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


			2005		2004		2003

			(Millions of dollars)
Exploration and production
	Exploration		$	229	$	168	$	180
	Production and development			1,598		1,204		1,067
	Acquisitions (including leasehold)			408		62		39

				2,235		1,434		1,286

Marketing and refining
	Operations			106		67		72
	Acquisitions			—		20		—

				106		87		72

		Total	$	2,341	$	1,521	$	1,358

Proceeds from asset sales in 2005 and 2004 were $74 million and $57 million, respectively, principally from the sale of non-producing properties. Proceeds from asset sales totaled $545 million in 2003.

Financing Activities: The Corporation reduced debt by $50 million in 2005, $106 million in 2004 and $1,051 million in 2003. 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. The net reduction in debt in 2005 and 2004 was funded by available cash and cash flow from operations. In 2003, debt was reduced by proceeds of $653 million from the issuance of 13,500,000 shares of mandatory convertible preferred stock and from asset sales, as well as cash flow from operations. In 2005 and 2004, the Corporation received proceeds from the exercise of stock options totaling $62 million and $90 million, respectively. Dividends paid were $159 million in 2005, $157 million in 2004 and $108 million in 2003. The increase in 2004 was due to dividends on the 7% preferred stock issued in the fourth quarter of 2003.

Future Capital Requirements and Resources: In January 2006, the Corporation announced a $4 billion capital and exploratory expenditure program for 2006, which includes approximately $780 million for the acquisition of Egyptian assets and payments for the Corporation’s re-entry into Libya. Excluding acquisitions, $3.1 billion relates to exploration and production, including $1,370 million for development, $1,130 million for production and $570 million for exploration. The program also includes $125 million for marketing and refining.

The Corporation’s aggregate maturities of long-term debt total $54 million over the next two years. The Corporation anticipates it will fund its 2006 operations, including capital expenditures, dividends, pension contributions and required debt repayments, with existing cash on-hand and cash flow from operations and, as necessary, additional borrowings on the revolving credit facility.

Outstanding letters of credit, principally relating to hedging activities at December 31, were as follows:


		2005		2004

		(Millions of dollars)
Lines of Credit
	Revolving credit facility	$	28	$	570
	Committed short-term letter of credit facilities		1,675		—
	Uncommitted lines		982		917

		$	2,685	$	1,487

At December 31, 2005, the Corporation has $1,872 million available under its $2.5 billion syndicated revolving credit facility and 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.

A loan agreement covenant allows the Corporation to borrow up to an additional $6.7 billion for the construction or acquisition of assets at December 31, 2005. At year end, the maximum amount of dividends or stock repurchases that can be paid from borrowings under this covenant is $2.5 billion.

Credit Ratings: Two credit rating agencies have rated the Corporation’s debt as investment grade and one rating agency’s rating is below investment grade. If another rating agency were to reduce its credit rating below investment grade, the Corporation would have to comply with a more stringent financial covenant contained in its revolving credit facility. In addition, margin requirements with non-trading and trading counterparties at December 31, 2005 would increase by approximately $30 million.

Contractual Obligations and Contingencies: Following is a table showing aggregated information about certain contractual obligations at December 31, 2005:


				Payments Due by Period

						2007 and		2009 and
		Total		2006		2008		2010		Thereafter

		(Millions of dollars)
Long-term debt*		$	3,785	$	26	$	58	$	775	$	2,926
Operating leases			2,384		345		719		283		1,037
Purchase obligations
	Supply commitments		29,070		9,905		9,961		9,204		**
	Capital expenditures		1,729		1,191		523		15		—
	Operating expenses		470		319		119		27		5
	Other long-term liabilities		306		72		91		78		65


	*	At December 31, 2005, the Corporation’s debt bears interest at a weighted average rate of 7.0%.


**	The Corporation intends to continue purchasing refined product supply from HOVENSA. Estimated future purchases amount to approximately $4.6 billion annually using year-end 2005 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 natural gas for use in supplying contracted customers in its energy marketing business. These commitments were computed based on year-end market prices.

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

At December 31, 2004, the Corporation had an accrual of $39 million for vacated office costs in London. During 2005, $8 million of payments were made reducing the accrual to $31 million at December 31, 2005. Additional accruals totaling approximately $30 million, before income taxes, are anticipated in 2006 for office space to be vacated.

In December 2005, the Minerals Management Service (MMS) issued an order to the Corporation to pay royalties on certain deep water exploration leases in the Gulf of Mexico held by the Corporation. In the Deep Water Royalty Relief Act of 1995 (the Act), Congress granted royalty relief in order to encourage deep water exploration in the Gulf of Mexico. With respect to exploration leases issued between November 28, 1995 and November 28, 2000, the Act granted royalty relief without regard to the market price of crude oil and natural gas at the time the royalty is payable. However, in regulations promulgated by MMS relating to these deep water leases, the MMS imposed a price threshold such that if the market price for crude oil or natural gas exceeded the threshold, royalty relief would not be granted. The Corporation has accrued $34 million for royalties relating to sales from these leases, which the Corporation believes is its full potential liability if the MMS regulations are determined to be valid.

The Corporation has a contingent purchase obligation, expiring in April 2010, to acquire the remaining interest in a retail marketing and gasoline station joint venture for approximately $140 million.

The Corporation guarantees the payment of up to 50% of HOVENSA’s crude oil purchases from suppliers other than PDVSA. The amount of the Corporation’s guarantee fluctuates based on the volume of crude oil purchased and related prices and at December 31, 2005 amounted to $135 million. In addition, the

Corporation has agreed to provide funding up to a maximum of $40 million to the extent HOVENSA does not have funds to meet its senior debt obligations.

At December 31, the Corporation has $2,612 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	$	73
Guarantees		233	*

	$	306


*	Includes $40 million HOVENSA debt and $135 million crude oil purchase guarantees discussed above. The remainder relates to a loan guarantee of $58 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 $480 million at December 31, 2005 compared with $467 million at December 31, 2004. The Corporation’s December 31, 2005 debt to capitalization ratio would increase from 37.6% to 40.4% 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 financial statements.

Foreign Operations: The Corporation conducts exploration and production activities in the United Kingdom, Norway, Denmark, Russia, Equatorial Guinea, Algeria, Azerbaijan, Gabon, Indonesia, Malaysia, Thailand, Libya 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 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 $212 million at December 31, 2005 from a subsidiary of PDVSA. All payments are current and the Corporation anticipates collection of the remaining balance.

Subsequent Events

In January 2006, the Corporation acquired a 55% working interest in the deepwater section of the West Med Block in Egypt for $413 million. The Corporation has a 25-year development lease for the West Med Block, which contains four existing natural gas discoveries and additional exploration opportunities.

In 2006, the Corporation will complete the sale of its interests in certain producing properties located in the Permian Basin in West Texas and New Mexico for $404 million, before purchase price adjustments. The net book value of these assets held for sale of approximately $70 million has been recorded in other current assets at December 31, 2005. The Corporation estimates that it will record an after-tax gain of $160 million to $180 million in the first quarter on the sale of these assets.

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.

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 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. 142, the Corporation’s goodwill is not amortized, but must be tested for impairment annually 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 risked present value of exploration assets, and (3) an estimated market premium to reflect the market price an acquirer would pay for potential synergies including cost savings, access to new business opportunities, enterprise control, improved processes and increased market share. The Corporation also considers the relative market valuation of similar exploration and production companies.

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

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

Segments: The Corporation has two operating segments, exploration and production and marketing and refining. Management has determined that these are its operating segments because, in accordance with FAS No. 131, 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.

value are recorded in accumulated other comprehensive income. These transactions meet the requirements for hedge accounting, including correlation. The Corporation’s hedges are tested prospectively before they are executed and both prospectively and retrospectively on an on-going basis to ensure they continue to qualify for hedge accounting. The prospective and retrospective effectiveness calculations are performed using a historical simulation model. The simulation utilizes historical observable market data consisting of futures curves and spot prices.

At December 31, 2005, the Corporation has $1,304 million of deferred hedging losses, after income taxes, included in accumulated other comprehensive income. The Corporation reclassifies hedging gains and losses included in accumulated other comprehensive income to earnings at the time the hedged transactions are recognized. The ineffective portion of hedges is included in current earnings. The Corporation’s remaining derivatives, including foreign currency contracts, are not designated as hedges and the change in fair value is included in income currently.

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.

New Accounting Standard: In 2004, the Financial Accounting Standards Board reissued Statement No. 123, Share-Based Payment (FAS 123R). This standard requires that compensation expense for all stock-based payments to employees, including grants of employee stock options, be recognized in the income statement based on fair values. The Corporation adopted FAS 123R as of January 1, 2006. The actual cost of expensing stock options in 2006 and future periods will be based on a number of factors, including the amount of options granted, the terms of such awards and the stock price at the time of grant. The Corporation estimates that the cost of unvested options at December 31, 2005 and the annual grant of employee stock options in February 2006, will increase compensation expense in 2006 by approximately $30 million, before income taxes. Awards of restricted common stock are expensed over the vesting period under existing accounting requirements and will continue to be expensed under FAS 123R.

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. While overall governance is the responsibility of senior management, 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.

Estimated capital expenditures necessary to comply with low-sulfur gasoline requirements at Port Reading will approximate $75 million, $23 million of which was spent in 2005. The remainder is expected to be spent in 2006. Capital expenditures to comply with low-sulfur gasoline and diesel fuel requirements at HOVENSA are presently expected to be approximately $410 million in total, $160 million of which has already been spent. Capital expenditures for low-sulfur requirements are expected to be $200 million in 2006, with the remainder in 2007. HOVENSA plans to finance these capital expenditures through cash flow from operations.

The Energy Policy Act of 2005 eliminates 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 in 2007-2009. 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 will phase out the use of ether based oxygenates in the spring of 2006. The phase out may adversely affect the amount and type of fuels produced at HOVENSA and Port Reading. Both companies are reviewing the most cost effective means to replace ether unit processing capabilities, which may necessitate additional capital investments. The Corporation and HOVENSA are preparing to meet the renewable content requirement for gasoline and do not anticipate that the impact of this requirement will be significant.

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 $32 million has already been incurred.

The Corporation recognizes the worldwide concern about the environmental and social impact of air emissions. On a global scale, climate change is an issue that has prompted much public debate and has a potential impact on future economic growth and development. The Corporation has undertaken a program to assess, monitor and reduce the emission of “greenhouse gases,” including carbon dioxide and methane. The challenges associated with this program may be significant, not only from the standpoint of technical feasibility, but also from the perspective of adequately measuring the Corporation’s greenhouse gas inventory. The Corporation has recently completed a revised monitoring protocol which will allow for better measurement and control of “greenhouse gases.”

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 2005, the Corporation’s reserve for its estimated environmental liability was approximately $77 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 2005, $12 million in 2004 and $12 million in 2003. Capital expenditures for facilities, primarily to comply with federal, state and local environmental standards, other than for low sulfur projects discussed above, were $3 million in 2005, $1 million in 2004 and $7 million in 2003.

Forward Looking Information

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

Controls: The Corporation maintains a control environment under the direction of its chief risk officer and through its corporate risk policy, which the Corporation’s senior management has approved. Controls include volumetric, term and value-at-risk limits. In addition, the chief risk officer must approve the use of new instruments or commodities. Risk limits are monitored daily and exceptions are reported to business units and to senior management. The Corporation’s risk management department also performs independent verifications of sources of fair values and validations of valuation models. These controls apply to all of the Corporation’s non-trading and trading activities, including the consolidated trading partnership. The Corporation’s treasury department 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 widely traded instruments mainly with standardized terms. The following describes these instruments and how the Corporation uses them:


	•	Forward Commodity Contracts: The forward purchase and sale of commodities is performed as part of the Corporation’s normal activities. At 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. In some cases, physical purchase and sale contracts are used as trading instruments and are included in trading results.

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


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

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

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

	•	Energy Commodity Based Securities: Securities where the price is based on the price of an underlying energy commodity. These securities may be issued by a company or government.

Value-at-Risk: The Corporation uses value-at-risk to monitor and control commodity risk within its trading and non-trading activities. The value-at-risk model uses historical simulation and the results represent the potential loss in fair value over one day at a 95% confidence level. The model captures both first and second order sensitivities for options. The following table summarizes the value-at-risk results for trading and non-trading activities. These results may vary from time to time as strategies change in trading activities or hedging levels change in non-trading activities.


		Trading		Non-Trading
		Activities		Activities

		(Millions of dollars)
2005
	At December 31	$	18	$	93
	Average for the year		11		111
	High during the year		18		127
	Low during the year		7		93
2004
	At December 31	$	17	$	108
	Average for the year		12		90
	High during the year		17		111
	Low during the year		7		52

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, 2005:


	Brent Crude Oil

	Average		Thousands of
Maturity	Selling Price		Barrels per Day

2006	$	28.10		30
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 year end. 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, 2005 includes after-tax unrealized deferred losses of $1,304 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, 2005, the Corporation has $677 million of notional value foreign exchange contracts maturing in 2006 and 2007 ($476 million at December 31, 2004). The fair value of the foreign exchange contracts was a liability of $31 million at December 31, 2005 (receivable of $49 million at December 31, 2004). The change in fair value of the foreign exchange contracts from a 10% change in exchange rates is estimated to be $64 million at December 31, 2005 ($53 million at December 31, 2004).

The Corporation’s outstanding debt of $3,785 million has a fair value of $4,286 million at December 31, 2005 (debt of $3,835 million at December 31, 2004 had a fair value of $4,327 million). A 15% change in the rate of interest would change the fair value of debt by approximately $250 million at December 31, 2005 and by approximately $260 million at December 31, 2004.

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 are marked-to-market and are reflected in income currently. Total realized losses for the year amounted to $297 million ($79 million of realized gains for 2004). 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.


	2005			2004

	(Millions of dollars)
Fair value of contracts outstanding at the beginning of the year	$	184		$	67
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at the end of year		6			13
Reversal of fair value for contracts closed during the year		(23	)		(10	)
Fair value of contracts entered into during the year and still outstanding		942			114

Fair value of contracts outstanding at the end of the year	$	1,109		$	184

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:


											2009 and
			Total		2006		2007		2008		Beyond

			(Millions of dollars)
Source of fair value
	Prices actively quoted		$	1,040	$	506	$	278	$	128	$	128
	Other external sources			51		4		11		4		32
	Internal estimates			18		10		5		3		—

		Total	$	1,109	$	520	$	294	$	135	$	160

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:


	2005		2004

	(Millions of
	dollars)
Investment grade determined by outside sources	$	353	$	307
Investment grade determined internally*		139		48
Less than investment grade		70		25

Fair value of net receivables outstanding at the end of the year	$	562	$	380


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


Item 8.	*Financial Statements and Supplementary Data*

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS AND SCHEDULE


	Page
	Number

Management’s Report on Internal Control over Financial Reporting		41
Reports of Independent Registered Public Accounting Firm		42
Consolidated Balance Sheet at December 31, 2005 and 2004		44
Statement of Consolidated Income for each of the three years in the period ended December 31, 2005		45
Statement of Consolidated Retained Earnings for each of the three years in the period ended December 31, 2005		46
Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2005		47
Statement of Consolidated Changes in Preferred Stock, Common Stock and Capital in Excess of Par Value for each of the three years in the period ended December 31, 2005		48
Statement of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 2005		48
Notes to Consolidated Financial Statements		49
Supplementary Oil and Gas Data		75
Quarterly Financial Data		81
Consent of Independent Registered Public Accounting Firm		F-1
Schedule* II — Valuation and Qualifying Accounts		F-2


*	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 Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2005.

Our management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, 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 24, 2006

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Amerada Hess Corporation

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Amerada Hess Corporation and consolidated subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Amerada 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 Amerada Hess Corporation and consolidated subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Amerada Hess Corporation and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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 Amerada Hess Corporation and consolidated subsidiaries as of December 31, 2005 and 2004, and the related statements of consolidated income, retained earnings, cash flows, changes in preferred stock, common stock and capital in excess of par value and comprehensive income for each of the three years in the period ended December 31, 2005, and our report dated February 24, 2006 expressed an unqualified opinion on these statements.

New York, NY

February 24, 2006

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Amerada Hess Corporation

We have audited the accompanying consolidated balance sheet of Amerada Hess Corporation and consolidated subsidiaries as of December 31, 2005 and 2004, and the related statements of consolidated income, retained earnings, cash flows, changes in preferred stock, common stock and capital in excess of par value and comprehensive income for each of the three years in the period ended December 31, 2005. 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 Amerada Hess Corporation and consolidated subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Amerada Hess Corporation’s internal control over financial reporting as of December 31, 2005, 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 24, 2006 expressed an unqualified opinion thereon.

New York, NY

February 24, 2006

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


				At December 31

				2005			2004

				(Millions of dollars;
				thousands of shares)
ASSETS
CURRENT ASSETS
	Cash and cash equivalents			$	315		$	877
	Accounts receivable
		Trade			3,517			2,372
		Other			138			182
	Inventories				855			596
	Other current assets				465			308

			Total current assets		5,290			4,335

INVESTMENTS AND ADVANCES
	HOVENSA L.L.C.				1,217			1,116
	Other				172			138

			Total investments and advances		1,389			1,254

PROPERTY, PLANT AND EQUIPMENT
	Exploration and production				17,836			16,095
	Marketing and refining				1,628			1,537

			Total — at cost		19,464			17,632
	Less reserves for depreciation, depletion, amortization and lease impairment				9,952			9,127

			Property, plant and equipment — net		9,512			8,505

NOTE RECEIVABLE					152			212
GOODWILL					977			977
DEFERRED INCOME TAXES					1,544			834
OTHER ASSETS					251			195

TOTAL ASSETS				$	19,115		$	16,312


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
	Accounts payable			$	4,995		$	3,280
	Accrued liabilities				1,029			920
	Taxes payable				397			447
	Current maturities of long-term debt				26			50

			Total current liabilities		6,447			4,697

LONG-TERM DEBT					3,759			3,785
DEFERRED INCOMES TAXES					1,401			1,184
ASSET RETIREMENT OBLIGATIONS					564			511
OTHER LIABILITIES AND DEFERRED CREDITS					658			538

			Total liabilities		12,829			10,715

STOCKHOLDERS’ EQUITY
	Preferred stock, par value $1.00, 20,000 shares authorized
		7% cumulative mandatory convertible series
			Authorized — 13,500 shares
			Issued — 13,500 shares in 2005 and 2004 ($675 million liquidation preference)		14			14
		3% cumulative convertible series
			Authorized — 330 shares
			Issued — 324 shares in 2005; 327 shares in 2004 ($16 million liquidation preference)		—			—
	Common stock, par value $1.00
			Authorized — 200,000 shares
			Issued — 93,066 shares in 2005; 91,715 shares in 2004		93			92
	Capital in excess of par value				1,842			1,727
	Retained earnings				5,914			4,831
	Accumulated other comprehensive income (loss)				(1,526	)		(1,024	)
	Deferred compensation				(51	)		(43	)

			Total stockholders’ equity		6,286			5,597

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY				$	19,115		$	16,312

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.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME


				For the Years Ended
				December 31

				2005		2004		2003

				(Millions of dollars,
				except per share data)
REVENUES AND NON-OPERATING INCOME
	Sales (excluding excise taxes) and other operating revenues			$	22,747	$	16,733	$	14,311
	Non-operating income
		Equity in income of HOVENSA L.L.C.			376		244		117
		Gain on asset sales			48		55		39
		Other, net			84		94		13

			Total revenues and non-operating income		23,255		17,126		14,480

COSTS AND EXPENSES
	Cost of products sold (excluding items shown separately below)				17,041		11,971		9,947
	Production expenses				1,007		825		796
	Marketing expenses				842		737		709
	Exploration expenses, including dry holes and lease impairment				397		287		369
	Other operating expenses				136		195		192
	General and administrative expenses				357		342		340
	Interest expense				224		241		293
	Depreciation, depletion and amortization				1,025		970		1,053

			Total costs and expenses		21,029		15,568		13,699

	Income from continuing operations before income taxes				2,226		1,558		781
	Provision for income taxes				984		588		314

	Income from continuing operations				1,242		970		467
	Discontinued operations				—		7		169
	Cumulative effect of change in accounting principle				—		—		7

NET INCOME				$	1,242	$	977	$	643

Less preferred stock dividends					48		48		5

NET INCOME APPLICABLE TO COMMON SHAREHOLDERS				$	1,194	$	929	$	638

BASIC EARNINGS PER SHARE
	Continuing operations			$	13.14	$	10.30	$	5.21
	Net income				13.14		10.38		7.19
DILUTED EARNINGS PER SHARE
	Continuing operations			$	11.94	$	9.50	$	5.17
	Net income				11.94		9.57		7.11
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (DILUTED)					104.0		102.1		90.3

See accompanying notes to consolidated financial statements.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED RETAINED EARNINGS


		For the Years Ended
		December 31

		2005			2004			2003

		(Millions of dollars)
BALANCE AT BEGINNING OF YEAR		$	4,831		$	4,011		$	3,482
	Net income		1,242			977			643
	Dividends declared — common stock ($1.20 per share in 2005, 2004 and 2003)		(111	)		(109	)		(109	)
	Dividends on preferred stock ($3.50 per share in 2005 and 2004; $.34 per share in 2003)		(48	)		(48	)		(5	)

BALANCE AT END OF YEAR		$	5,914		$	4,831		$	4,011

See accompanying notes to consolidated financial statements.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS


						For the Years Ended December 31

						2005			2004			2003

						(Millions of dollars)
CASH FLOWS FROM OPERATING ACTIVITIES
	Net income					$	1,242		$	977		$	643
	Adjustments to reconcile net income to net cash provided by operating activities
			Depreciation, depletion and amortization				1,025			970			1,053
			Exploratory dry hole costs				170			81			162
			Lease impairment				78			77			65
			Pre-tax gain on asset sales				(48	)		(55	)		(245	)
			Provision (benefit) for deferred income taxes				(118	)		(211	)		107
			Undistributed earnings of HOVENSA L.L.C.				(101	)		(156	)		(117	)
			Non-cash effect of discontinued operations				—			(7	)		46
			Changes in other operating assets and liabilities:
				(Increase) decrease in accounts receivable			(1,042	)		(705	)		47
				Increase in inventories			(270	)		(16	)		(107	)
				Increase in accounts payable and accrued liabilities			877			783			18
				Increase (decrease) in taxes payable			(111	)		131			(39	)
				Changes in other assets and liabilities			138			34			(52	)

					Net cash provided by operating activities		1,840			1,903			1,581

CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures
		Exploration and production					(2,235	)		(1,434	)		(1,286	)
		Marketing and refining					(106	)		(87	)		(72	)

					Total capital expenditures		(2,341	)		(1,521	)		(1,358	)
	Proceeds from asset sales						74			57			545
	Payment received on notes receivable						60			90			61
	Other						(48	)		3			(25	)

					Net cash used in investing activities		(2,255	)		(1,371	)		(777	)

CASH FLOWS FROM FINANCING ACTIVITIES
	Debt with maturities of greater than 90 days
		Borrowings					600			25			—
		Repayments					(650	)		(131	)		(1,026	)
	Decrease in debt with maturities of 90 days or less						—			—			(2	)
	Proceeds from issuance of preferred stock						—			—			653
	Cash dividends paid						(159	)		(157	)		(108	)
	Stock options exercised						62			90			—

					Net cash used in financing activities		(147	)		(173	)		(483	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS							(562	)		359			321
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR							877			518			197

CASH AND CASH EQUIVALENTS AT END OF YEAR						$	315		$	877		$	518

See accompanying notes to consolidated financial statements.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN PREFERRED

STOCK, COMMON STOCK AND CAPITAL IN EXCESS OF PAR VALUE


		Preferred Stock					Common Stock
											Capital in
		Number of					Number of				Excess of
		Shares			Amount		Shares		Amount		Par Value

		(Millions of dollars; thousands of shares)
BALANCE AT JANUARY 1, 2003			327		$	—		89,193	$	89	$	932
	Issuance of preferred stock		13,500			14		—		—		639
	Distributions to trustee of restricted common stock awards (net)		—			—		675		1		32

BALANCE AT DECEMBER 31, 2003			13,827			14		89,868		90		1,603
	Distributions to trustee of restricted common stock awards (net)		—			—		309		—		24
	Employee stock options exercised		—			—		1,538		2		100

BALANCE AT DECEMBER 31, 2004			13,827			14		91,715		92		1,727
	Conversion of 3% preferred to common stock		(3	)		—		2		—		—
	Distributions to trustee of restricted common stock awards (net)		—			—		316		—		38
	Employee stock options exercised		—			—		1,033		1		77

BALANCE AT DECEMBER 31, 2005			13,824		$	14		93,066	$	93	$	1,842

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME


			For the Years Ended December 31

			2005			2004			2003

			(Millions of dollars)
COMPONENTS OF COMPREHENSIVE INCOME
	Net income		$	1,242		$	977		$	643
	Change in foreign currency translation adjustment			(34	)		36			13
	Additional minimum pension liability, after tax			(33	)		(25	)		(1	)
	Deferred gains (losses) on cash flow hedges, after tax
		Effect of hedge losses recognized in income		946			511			203
		Net change in fair value of cash flow hedges		(1,381	)		(1,196	)		(311	)

COMPREHENSIVE INCOME			$	740		$	303		$	547

See accompanying notes to consolidated financial statements.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Summary of Significant Accounting Policies

Nature of Business: Amerada 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, Russia, Equatorial Guinea, Algeria, Azerbaijan, Gabon, Indonesia, Malaysia, Thailand, Libya 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 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, dismantlement costs and income taxes.

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

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

Investments in affiliated companies, 20% to 50% owned, including HOVENSA, 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. 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.

Sales are reported net of excise and similar taxes in the consolidated statement of income, which amounted to approximately $1,790 million, $1,650 million and $1,590 million in 2005, 2004 and 2003, respectively.

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 the consolidated statement of income.

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

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.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. In accordance with FASB Staff Position 19-1, Accounting for Suspended Well Costs, which amended Statement of Financial Accounting Standards (FAS) No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, 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 and firm plans for additional drilling and other factors.

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

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

Asset Retirement Obligations: The Corporation accounts for asset retirement obligations as required by FAS No. 143, Accounting for Asset Retirement Obligations and FIN 47, Accounting for Conditional Asset Retirement Obligations. Under these standards, a liability is recognized for the fair value of legally required asset retirement obligations associated with long-lived assets in the period in which the retirement obligations are incurred. In addition, the fair value of any legally required conditional 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. On January 1, 2003, the effective date of FAS No. 143, the cumulative effect of this accounting change on prior years resulted in a credit to income of $7 million or $.07 per share, basic and diluted.

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

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 must be tested annually for impairment. This impairment test is calculated at the reporting unit level, which is the exploration and production segment for the Corporation’s goodwill. The Corporation identifies potential impairments by comparing the fair value of the reporting unit to its book value, including goodwill. If the fair value of the reporting unit exceeds the carrying amount, goodwill is not impaired. If the carrying value exceeds the fair value, the Corporation calculates the possible impairment loss by comparing the implied fair value of goodwill with the carrying amount. If the implied fair value of goodwill is less than the carrying amount, an impairment would be recorded.

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

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

Stock-Based Compensation: The Corporation records compensation expense for restricted common stock awards ratably 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. Effective January 1, 2006, the Corporation adopted FAS No. 123R, Share-Based Payment, which requires that compensation expense be recorded for all stock based payments to employees,

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

including grants of stock options (see note 9). The following pro forma financial information presents the effect on net income and earnings per share as if the Corporation used the fair value method for stock options.


		2005			2004			2003

		(Millions of dollars, except
		per share data)
Net income		$	1,242		$	977		$	643
Add: stock-based employee compensation expense included in net income, net of taxes			18			11			7
Less: total stock-based employee compensation expense determined using the fair value method, net of taxes			(37	)		(18	)		(8	)

Pro forma net income		$	1,223		$	970		$	642

Net income per share as reported
	Basic	$	13.14		$	10.38		$	7.19
	Diluted		11.94			9.57			7.11
Pro forma net income per share
	Basic	$	12.93		$	10.31		$	7.19
	Diluted		11.76			9.50			7.11

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

Hedging: The Corporation may use futures, forwards, options and swaps, individually or in combination, to reduce the effects of fluctuations in crude oil, natural gas and refined product prices. Related hedge gains or losses are an integral part of the selling or purchase prices. Generally, these derivatives are designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), and the changes in fair value are recorded in accumulated other comprehensive income. These transactions meet the requirements for hedge accounting, including correlation. The Corporation’s hedges are tested prospectively before they are executed and both prospectively and retrospectively on an on-going basis to ensure they continue to qualify for hedge accounting. The prospective and retrospective effectiveness calculations are performed using a historical simulation model. The simulation utilizes historical observable market data consisting of futures curves and spot prices for the hedges.

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

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

applicable to undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations.


2.	Items Affecting Income from Operations

The following items of income (expense) are included in income:


		Items Affecting
		Income Before Taxes

		2005			2004			2003

		(Millions of dollars,
		income (expense))
Exploration and Production
	Net gains from asset sales	$	48		$	55		$	47
	Hurricane related costs		(40	)		—			—
	Legal settlement		19			—			—
	Accrued severance and office costs		—			(15	)		(53	)
Marketing and Refining
	LIFO inventory liquidation		51			20			—
	Charge related to customer bankruptcy		(13	)		—			—
	Net loss from asset sales		—			—			(9	)
Corporate
	Premiums on bond repurchases		(39	)		—			(58	)
	Insurance accrual		—			(20	)		—

		$	26		$	40		$	(73	)


		Items Affecting
		Income Taxes

		2005			2004		2003

Exploration and production
	Income tax adjustments	$	11		$	19	$	30
Corporate
	Tax on repatriated earnings		(72	)		—		—
	Income tax adjustments		—			13		—

		$	(61	)	$	32	$	30

Exploration and Production: 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 natural gas development in Indonesia. In 2004, the Corporation sold an office building in Aberdeen, Scotland, a non-producing property in Malaysia and two mature Gulf of Mexico properties. In 2003, the Corporation sold its 1.5% interest in the Trans-Alaska Pipeline System.

In 2005, the Corporation incurred incremental expenses, principally repair costs and insurance premiums, as a result of hurricane damage in the Gulf of Mexico that are included in production expenses in the income statement. The legal settlement resulted from the favorable resolution of contingencies on a prior year asset sale that is reflected in non-operating income in the income statement.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In 2003, the Corporation accrued severance and office costs of $53 million. Of this amount, $32 million relates to vacated leased office space in London and the remainder relates to severance for positions that were eliminated in London, Aberdeen and Houston. In 2004, the Corporation accrued an additional $15 million for severance and vacated lease costs in London. These expenses are reflected principally in general and administrative expense in the income statement. The Corporation has made total payments to date of approximately $37 million reducing the accrual to $31 million at December 31, 2005. The accrual was $39 million at December 31, 2004.

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, foreign income tax adjustments resulted from a tax law change and a tax settlement. In 2003, the Corporation recognized certain prior year foreign exploration expenses for United States income tax purposes.

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. In 2003, a loss was recorded on the sale of a shipping joint venture.

Corporate: In 2005 and 2003, 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.	Discontinued Operations

In 2003, the Corporation exchanged its crude oil producing properties in Colombia plus $10 million in cash, for an additional 25% interest in natural gas reserves in the Joint Development Area of Malaysia and Thailand. In addition, the Corporation sold, for aggregate proceeds of $445 million, producing properties in the Gulf of Mexico shelf, the Jabung field in Indonesia and several small United Kingdom fields. These disposals resulted in a net gain from asset sales of $116 million and income from operations prior to sale was $53 million. Income from discontinued operations of $7 million in 2004 reflects the settlement of a previously accrued contingency relating to the exchanged Colombian assets.


4.	Inventories

Inventories at December 31 are as follows:


	2005			2004

	(Millions of
	dollars)
Crude oil and other charge stocks	$	161		$	174
Refined and other finished products		1,149			700
Less: LIFO adjustment		(656	)		(446	)

		654			428
Merchandise, materials and supplies		201			168

Total	$	855		$	596

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 and $20 million in 2005 and 2004, respectively.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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:


			2005			2004			2003

			(Millions of dollars)
Summarized Balance Sheet
At December 31
	Cash and cash equivalents		$	612		$	518		$	341
	Short-term investments			263			39			—
	Other current assets			814			636			541
	Net fixed assets			1,950			1,843			1,818
	Other assets			39			36			37
	Current liabilities			(996	)		(606	)		(441	)
	Long-term debt			(252	)		(252	)		(392	)
	Deferred liabilities and credits			(57	)		(48	)		(56	)

		Partners’ equity	$	2,373		$	2,166		$	1,848

Summarized Income Statement
For the Years Ended December 31
	Total revenues		$	10,439		$	7,776		$	5,451
	Costs and expenses			(9,682	)		(7,282	)		(5,212	)

		Net income	$	757		$	494		$	239

		Amerada Hess Corporation’s share(a)	$	376		$	244		$	117

Summarized Cash Flow Statement
For the Years Ended December 31
	Net cash provided by (used in)
	Operating activities		$	1,070		$	656		$	430
	Investing activities			(426	)		(167	)		(22	)
	Financing activities			(550	)		(312	)		(78	)

Net increase in cash and cash equivalents			$	94		$	177		$	330


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

During 2005 and 2004, the Corporation received cash distributions from HOVENSA of $275 million and $88 million, respectively. The Corporation’s share of HOVENSA’s undistributed income at December 31, 2005 aggregated $499 million.

The Corporation guarantees the payment of up to 50% of the value of HOVENSA’s crude oil purchases from suppliers other than PDVSA. At December 31, 2005, the guarantee amounted to $135 million. This amount fluctuates based on the volume of crude oil purchased and the related crude oil prices. In addition, the Corporation has agreed to provide funding up to a maximum of $40 million to the extent HOVENSA does not have funds to meet its senior debt obligations.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At formation of the joint venture, PDVSA V.I., a wholly-owned subsidiary of PDVSA, purchased a 50% interest in the fixed assets of the Corporation’s Virgin Islands refinery for $62.5 million in cash and a 10-year note from PDVSA V.I. for $562.5 million bearing interest at 8.46% per annum and requiring principal payments over its term. At December 31, 2005 and 2004, the principal balance of the note was $212 million and $273 million, 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:


			2005		2004

			(Millions of dollars)
Exploration and production
	Unproved properties		$	629	$	450
	Proved properties			3,490		3,267
	Wells, equipment and related facilities			13,717		12,378
Marketing and refining				1,628		1,537

		Total — at cost		19,464		17,632
Less reserves for depreciation, depletion, amortization and lease impairment				9,952		9,127

		Property, plant and equipment, net	$	9,512	$	8,505

In 2005, the Corporation acquired a controlling interest in a corporate joint venture operating in the Volga-Urals region of Russia. Subsequent to the acquisition, this venture acquired additional licenses and assets bringing the Corporation’s total investment in Russia to approximately $400 million. The primary reason for the Russian investments was to acquire long-lived crude oil reserves. Production from the Russian subsidiary averaged 6,000 barrels per day in 2005. Substantially all of the acquisition cost was allocated to unproved and proved properties.

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:


		2005			2004			2003

		(Millions of dollars)
Beginning balance at January 1		$	220		$	225		$	211
	Additions to capitalized exploratory well costs pending the determination of proved reserves		97			150			78
	Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(12	)		(149	)		(1	)
	Capitalized exploratory well costs charged to expense		(61	)		(6	)		(41	)
	Sales, exchanges or disposals (includes discontinued operations)		—			—			(22	)

Ending balance at December 31		$	244		$	220		$	225

Number of wells at end of year			16			15			26

The preceding table excludes exploratory dry hole costs of $109 million, $75 million and $121 million in 2005, 2004 and 2003, respectively, relating to wells that were drilled and expensed in the same year.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2005, expenditures related to exploratory drilling costs in excess of one year old were capitalized as follows (in millions):


2002	$	40
2003		46
2004		64

	$	150

These costs relate to five projects which meet the requirements of FASB Staff Position 19-1. Approximately 68% of the capitalized well costs in excess of one year old relates to two projects where development approval is expected in 2006. Upon development approval, the reserves associated with these projects will be classified as proved. Approximately 27% of the costs relates to an oil discovery for which additional drilling is firmly planned in 2006. The remaining 5% relates to two small projects where the Corporation is undertaking commercial and exploration activities consistent with FASB Staff Position 19-1 that justify capitalization of the well costs at December 31, 2005.


7.	Asset Retirement Obligations

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


		2005			2004

		(Millions of
		dollars)
Asset retirement obligations at January 1		$	511		$	462
	Liabilities incurred		8			2
	Liabilities settled or disposed of		(26	)		(40	)
	Accretion expense		33			24
	Revisions		62			49
	Foreign currency translation		(24	)		14

Asset retirement obligations at December 31		$	564		$	511

AMERADA 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:


			2005		2004

			(Millions of
			dollars)
Revolving credit facility, weighted average rate 6.0%			$	600	$	—
Fixed rate debentures:
	5.9% due 2005			—		25
	5.9% due 2006			—		51
	7.4% due 2009			103		299
	6.7% due 2011			662		749
	7.9% due 2029			693		693
	7.3% due 2031			745		745
	7.1% due 2033			598		598

	Total fixed rate debentures			2,801		3,160
Fixed rate notes, payable principally to insurance companies, weighted average rate 9%, due through 2014				163		446
Project lease financing, weighted average rate 5.2%, due through 2014				161		166
Pollution control revenue bonds, weighted average rate 5.9%, due through 2034				52		53
Other loans, weighted average rate 7.0%, due through 2019				8		10

				3,785		3,835
Less amount included in current maturities				26		50

		Total	$	3,759	$	3,785

The aggregate long-term debt maturing during the next five years is as follows (in millions): 2006 – $26 (included in current liabilities); 2007 – $28; 2008 – $30; 2009 – $744 and 2010 – $31.

At December 31, 2005, 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 2005, the Corporation repurchased $600 million of fixed rate debentures and fixed rate notes at a premium of $39 million, before income taxes.

The Corporation has a $2.5 billion syndicated, revolving credit facility expiring in December 2009, which can be used for borrowings and letters of credit. At December 31, 2005, the Corporation has available capacity on the revolving credit facility of $1,872 million. Borrowings under the facility bear interest at .80% above the London Interbank Offered Rate. A facility fee of .20% 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’s long-term debt agreements contain a financial covenant that restricts the amount of total borrowings and cash dividends. At December 31, 2005, the Corporation is permitted to borrow up to an additional $6.7 billion for the construction or acquisition of assets. At year-end, the amount that can be borrowed for the payment of dividends or stock repurchases is $2.5 billion. Under the Corporation’s revolving credit agreement, if two stated credit rating agencies classify the Corporation’s public debt below investment grade, an additional covenant becomes effective requiring that the Corporation’s ratio of total consolidated debt to consolidated EBITDA, as defined, shall not exceed 3.5. The Corporation would have been in compliance with this covenant had it been in effect for the year ended December 31, 2005. This covenant shall

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

be deleted from the credit agreement if both credit rating agencies’ ratings are simultaneously investment grade.

The total amount of interest paid (net of amounts capitalized), principally on short-term and long-term debt, in 2005, 2004 and 2003 was $245 million, $243 million and $313 million, respectively. In 2005, 2004 and 2003, the Corporation capitalized interest of $80 million, $54 million and $41 million, respectively.


9.	Stock-Based Compensation Plans

The Corporation has outstanding 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 a 10-year option life, and the exercise price equals or exceeds the market price on the date of grant. Outstanding restricted common stock generally vests three to five years from the date of grant.

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


					Weighted-
					Average
					Exercise Price
		Options			per Share

		(Thousands)
Outstanding at January 1, 2003			4,375		$	59.06
	Granted		65			47.07
	Forfeited		(283	)		64.08

Outstanding at December 31, 2003			4,157			58.54
	Granted		1,198			72.79
	Exercised		(1,538	)		58.53
	Forfeited		(30	)		65.93

Outstanding at December 31, 2004			3,787			62.99
	Granted		1,094			92.74
	Exercised		(1,033	)		59.87
	Forfeited		(31	)		74.56

Outstanding at December 31, 2005			3,817		$	72.27

Exercisable at December 31, 2003			4,092		$	58.72
Exercisable at December 31, 2004			2,607			58.55
Exercisable at December 31, 2005			2,727			64.08

Exercise prices for employee stock options outstanding at December 31, 2005 ranged from $45.81 to $137.35 per share. The weighted-average remaining contractual life of employee stock options is 7 years.

The Corporation uses the Black-Scholes model to estimate the fair value of employee stock options for pro forma disclosure of the effects on net income and earnings per share. The Corporation used the following weighted-average assumptions in the Black-Scholes model for 2005, 2004 and 2003, respectively: risk-free interest rates of 3.9%, 4.3% and 3.6%; expected stock price volatility of .300, .293 and .288; dividend yield of 1.3%, 1.7% and 2.6%; and an expected life of seven years. The weighted-average fair values per share of options granted for which the exercise price equaled the market price on the date of grant were $31.53 in 2005, $23.75 in 2004 and $12.60 in 2003. The Corporation’s net income would have been reduced by approximately $19 million in 2005, $7 million in 2004 and $1 million in 2003 if option expenses were recorded using the fair value method.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Total pre-tax compensation expense for restricted common stock was $28 million in 2005, $17 million in 2004 and $11 million in 2003. Awards of restricted common stock were as follows:


	Shares of		Weighted-
	Restricted		Average
	Common		Price on
	Stock		Date of
	Awarded		Grant

	(Thousands)
Granted in 2003		765	$	46.73
Granted in 2004		423		72.97
Granted in 2005		374		92.36

At December 31, 2005, the number of common shares reserved for issuance under the 1995 Long-Term Incentive Plan is as follows (in thousands):


Future awards		5,124
Stock options outstanding		3,817

	Total	8,941

In 2004, the Financial Accounting Standards Board issued FAS No. 123R, Share-Based Payment (FAS 123R). This new standard requires that compensation expense for all stock-based payments to employees, including grants of employee stock options, be recognized in the income statement based on fair values. Had the Corporation adopted FAS 123R in prior periods, the impact would have approximated the additional expenses disclosed above and in the table under Stock-Based Compensation in note 1. The Corporation adopted FAS 123R as of January 1, 2006. The actual cost of expensing stock options in 2006 and future periods will be based on a number of factors, including the amount of options granted, the terms of such awards and the stock price at the time of grant. The Corporation estimates that the cost of unvested options at December 31, 2005 and the annual grant of employee stock options in February 2006 will increase compensation expense in 2006 by approximately $30 million, before income taxes.


10.	Foreign Currency Translation

Foreign currency gains (losses) from continuing operations before income taxes amounted to $(5) million in 2005, $29 million in 2004 and $(6) million in 2003. The balances in accumulated other comprehensive income related to foreign currency translation were reductions in stockholders’ equity of $92 million at December 31, 2005 and $58 million at December 31, 2004.


11.	Retirement Plans

The Corporation has funded noncontributory defined benefit pension plans for substantially all of its employees. In addition, the Corporation has an unfunded supplemental pension plan covering certain employees. The unfunded supplemental pension plan provides for incremental pension payments from the Corporation’s funds so that total pension payments equal amounts that would have been payable from the Corporation’s principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary. The Corporation uses December 31 as the measurement date for its plans.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


			Funded						Unfunded
			Pension Plans						Pension Plan

			2005			2004			2005			2004

			(Millions of dollars)
Reconciliation of projected benefit obligation
	Balance at January 1		$	925		$	817		$	77		$	65
	Service cost			26			23			4			3
	Interest cost			53			50			5			4
	Actuarial loss			60			67			24			25
	Benefit payments			(34	)		(32	)		(5	)		(20	)

		Balance at December 31		1,030			925			105			77

Reconciliation of fair value of plan assets
	Balance at January 1			750			626			—			—
	Actual return on plan assets			42			74			—			—
	Employer contributions			68			82			5			20
	Benefit payments			(34	)		(32	)		(5	)		(20	)

		Balance at December 31		826			750			—			—

Funded status (plan assets less than projected benefit obligations)				(204	)		(175	)		(105	)*		(77	)*
	Unrecognized net actuarial loss			278			230			53			34
	Unrecognized prior service cost			1			2			3			4

		Net amount recognized	$	75		$	57		$	(49	)	$	(39	)


*	The trust established by the Corporation to fund the supplemental plan held assets valued at $53 million at December 31, 2005 and $44 million at December 31, 2004.

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


	Funded						Unfunded
	Pension Plans						Pension Plan

	2005			2004			2005			2004

	(Millions of dollars)
Accrued benefit liability	$	(93	)	$	(80	)	$	(83	)	$	(61	)
Intangible assets		1			2			3			4
Accumulated other comprehensive income*		167			135			31			18

Net amount recognized	$	75		$	57		$	(49	)	$	(39	)


*	The amount included in accumulated other comprehensive income after income taxes was $131 million at December 31, 2005 and $98 million at December 31, 2004.

The accumulated benefit obligation for the funded defined benefit pension plans was $919 million at December 31, 2005 and $830 million at December 31, 2004. The accumulated benefit obligation for the unfunded defined benefit pension plan was $83 million at December 31, 2005 and $61 million at December 31, 2004.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

All pension plans had accumulated benefit obligations in excess of plan assets at December 31, 2005 and 2004.

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


	2005			2004			2003

	(Millions of dollars)
Service cost	$	30		$	26		$	27
Interest cost		58			54			51
Expected return on plan assets		(56	)		(56	)		(44	)
Amortization of prior service cost		2			2			2
Amortization of net loss		24			16			19
Settlement loss		—			6			—

Net periodic benefit cost	$	58		$	48		$	55

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

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


		2005			2004			2003

Weighted-average assumptions used to determine benefit obligations at December 31
	Discount rate		5.5	%		5.8	%		6.2	%
	Rate of compensation increase		4.3			4.5			4.5
Weighted-average assumptions used to determine net cost for years ended December 31
	Discount rate		5.8			6.2			6.6
	Expected return on plan assets		7.5			8.5			8.5
	Rate of compensation increase		4.5			4.5			4.4

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 projected 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 investments that matches the maturity of the plan obligations. The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the expected 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.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


					At
					December 31
		Target
Asset Category		Allocation			2005			2004

Equity securities			55	%		61	%		56	%
Debt securities			35			35			44
Other			10			4			—

	Total		100	%		100	%		100	%

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

The Corporation has budgeted contributions of approximately $40 million to its funded pension plans in 2006. The Corporation also has budgeted contributions of approximately $15 million to the trust established for the unfunded plan.

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


	(Millions of dollars)
2006	$	41
2007		45
2008		47
2009		50
2010		57
Years 2011 to 2015		340

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 $14 million in 2005, $13 million in 2004 and $12 million in 2003 for contributions to these plans.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


12.	Provision for Income Taxes

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


		2005			2004			2003

		(Millions of dollars)
United States Federal
	Current	$	50		$	—		$	(180	)
	Deferred		(314	)		(162	)		78
State			(14	)		(23	)		(13	)

			(278	)		(185	)		(115	)

Foreign
	Current		1,047			801			431
	Deferred		220			(28	)		(2	)

			1,267			773			429

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

Total provision for income taxes on continuing operations*		$	984		$	588		$	314

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

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


		2005			2004			2003

		(Millions of dollars)
United States(a)		$	(941	)	$	(411	)	$	(245	)
Foreign(b)			3,167			1,969			1,026

	Total income from continuing operations	$	2,226		$	1,558		$	781


(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.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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:


			2005			2004

			(Millions of dollars)
Deferred tax liabilities
	Fixed assets and investments		$	1,657		$	1,414
	Foreign petroleum taxes			324			311
	Other			97			198

		Total deferred tax liabilities		2,078			1,923

Deferred tax assets
	Net operating loss carryforwards			1,578			1,011
	Accrued liabilities			314			394
	Dismantlement liability			189			128
	Tax credit carryforwards			197			178
	Other			140			93

		Total deferred tax assets		2,418			1,804
	Valuation allowance			(76	)		(77	)

		Net deferred tax assets		2,342			1,727

		Net deferred tax assets (liabilities)	$	264		$	(196	)

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:


	2005			2004

	(Millions of dollars)
Other current assets	$	121		$	154
Deferred income taxes (long-term asset)		1,544			834
Deferred income taxes (long-term liability)		(1,401	)		(1,184	)

Net deferred tax assets (liabilities)	$	264		$	(196	)

AMERADA 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:


		2005			2004			2003

United States statutory rate			35.0	%		35.0	%		35.0	%
Effect of foreign operations			7.5			5.0			4.6
Tax on repatriation			3.3			—			—
Loss on repurchase of bonds			—			—			(0.6	)
State income taxes, net of Federal income tax			(0.4	)		(0.9	)		(1.1	)
Prior year adjustments			—			0.3			2.8
Federal audit settlement			—			(0.9	)		—
Other			(1.2	)		(0.7	)		(0.4	)

	Total		44.2	%		37.8	%		40.3	%

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 $3.6 billion at December 31, 2005. If the earnings of foreign subsidiaries were not indefinitely reinvested, a deferred tax liability of approximately $1.2 billion would be required, excluding the potential use of foreign tax credits.

At December 31, 2005, the Corporation has net operating loss carryforwards in the United States of approximately $3.6 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 $600 million, which can be carried forward indefinitely. For income tax reporting at December 31, 2005, the Corporation has minimum tax credit carryforwards of approximately $85 million, which can be carried forward indefinitely. The Corporation also has approximately $45 million of general business credits, substantially all of which expire between 2010 and 2025.

Income taxes paid (net of refunds) in 2005, 2004 and 2003 amounted to $1,139 million, $632 million and $361 million, respectively.

AMERADA 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:


		2005		2004		2003

		(Thousands of shares)
Common shares — basic			90,900		89,452		88,618
Effect of dilutive securities
	Convertible preferred stock		11,416		11,659		1,425
	Restricted common stock		883		605		290
	Stock options		836		370		9

Common shares — diluted			104,035		102,086		90,342

The table above excludes the effect of out-of-the-money options on 20,000 shares, 861,000 shares and 4,170,000 shares in 2005, 2004 and 2003, respectively.

Earnings per share are as follows:


		2005		2004		2003

Basic
	Continuing operations	$	13.14	$	10.30	$	5.21
	Discontinued operations		—		.08		1.91
	Cumulative effect of change in accounting		—		—		.07

	Net income	$	13.14	$	10.38	$	7.19

Diluted
	Continuing operations	$	11.94	$	9.50	$	5.17
	Discontinued operations		—		.07		1.87
	Cumulative effect of change in accounting		—		—		.07

	Net income	$	11.94	$	9.57	$	7.11

In 2003, the Corporation issued 13,500,000 shares of 7% cumulative mandatory convertible preferred stock. Dividends are payable on March 1, June 1, September 1 and December 1 of each year. The cumulative mandatory convertible preferred shares have a liquidation preference of $675 million ($50 per share). Each cumulative mandatory convertible preferred share will automatically convert on December 1, 2006 into .8305 to 1.0299 shares of common stock, depending on the average closing price of the Corporation’s common stock over a 20-day period before conversion. The conversion rate will be .8305 shares of common stock for each share of preferred, if the common stock price is $60.20 or greater, and 1.0299 shares of common stock for each share of preferred, if the common stock price is $48.55 or less. The conversion ratio will change ratably from .8305 to 1.0299 shares, if the average common stock price is between $60.20 and $48.55. The Corporation has reserved 13,903,650 shares of common stock for the conversion of these preferred shares. Holders of the cumulative mandatory convertible preferred stock have the right to convert their shares at any time prior to December 1, 2006 at the rate of .8305 share of common stock for each preferred share converted. The cumulative mandatory convertible preferred shares do not have voting rights, except in certain limited circumstances.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At December 31, 2005, the Corporation has outstanding 323,715 shares of 3% cumulative convertible preferred stock which carry a 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 .6261 shares of common stock. Holders of 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, floating production systems, 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, 2005, 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:


	Operating
	Leases

	(Millions of
	dollars)
2006	$	345
2007		421
2008		298
2009		196
2010		87
Remaining years		1,037

Total minimum lease payments		2,384
Less: Income from subleases		42

Net minimum lease payments	$	2,342

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

Rental expense was as follows:


		2005		2004		2003

		(Millions of dollars)
Total rental expense		$	201	$	238	$	190
Less: Income from subleases			14		58		52

	Net rental expense	$	187	$	180	$	138


15.	Financial Instruments, Non-trading and Trading Activities

Non-Trading: FAS No. 133, Accounting for Derivative Instruments and Hedging Activities, requires that the Corporation recognize all derivatives on the balance sheet at fair value and establishes criteria for using derivatives as hedges. The Corporation reclassifies hedging gains and losses from accumulated other comprehensive income to earnings at the time the hedged transactions are recognized. Hedging decreased exploration and production results by $1,582 million before income taxes in 2005, $935 million in 2004 and $418 million in 2003. The amount of hedge ineffectiveness reflected in income in 2005 was $17 million, before income taxes and was not material during the years ended December 31, 2004 and 2003.

AMERADA 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, 2005, the Corporation’s outstanding hedge positions were as follows:


	Brent Crude Oil

	Average		Thousands of
Maturity	Selling Price		Barrels per Day

2006	$	28.10		30
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. At December 31, 2005, net after tax deferred losses in accumulated other comprehensive income from the Corporation’s hedging contracts were $1,304 million ($2,063 million before income taxes). At December 31, 2004, net after-tax deferred losses were $869 million ($1,365 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, including futures, forwards, options, swaps and energy commodity based securities, 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 $60 million in 2005, $72 million in 2004 and $30 million in 2003.

Other Financial Instruments: Foreign currency contracts are used to protect the Corporation from fluctuations in exchange rates. The Corporation enters into foreign currency contracts, which are not designated as hedges, and the change in fair value is included in income currently. The Corporation has $677 million of notional value foreign currency forward contracts maturing through 2007, ($476 million at December 31, 2004). 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 liability of $31 million at December 31, 2005 and a receivable of $49 million at December 31, 2004.

The Corporation has $2,685 million in letters of credit outstanding at December 31, 2005 ($1,487 million at December 31, 2004). Of the total letters of credit outstanding at December 31, 2005, $73 million relates to contingent liabilities and the remaining $2,612 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.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


		Fair Value at
		December 31,

		2005			2004

		(Millions of dollars,
		asset (liability))
Futures and forwards
	Assets	$	199		$	110
	Liabilities		(115	)		(98	)
Options
	Held		963			393
	Written		(265	)		(490	)
Swaps
	Assets		763			871
	Liabilities (including hedging contracts)		(2,512	)		(2,027	)

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, 2005 and 2004, except as follows:

2005

2004

Balance

Sheet

Fair

Sheet

Fair

Amount

Value

Amount

Value

(Millions of dollars, asset (liability))

Fixed-rate debt

$(3,174)

$(3,675)

$(3,822)

$(4,314)

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

In its trading activities the Corporation has net receivables of $562 million at December 31, 2005, which are concentrated with counterparties as follows: domestic and foreign trading companies – 42%, banks and major financial institutions – 24% and gas and power companies – 12%.


16.	Guarantees and Contingencies

In the normal course of business, the Corporation provides guarantees for investees of the Corporation. These guarantees are contingent commitments that ensure performance for repayment of borrowings and other arrangements. The Corporation’s guarantees include $40 million of HOVENSA’s senior debt obligations and $135 million of HOVENSA’s crude oil purchases (see note 5). The remainder relates to a loan guarantee of $58 million for an oil pipeline in which the Corporation owns a 2.36% interest. The guarantee of the crude oil pipeline will be in place through the end of pipeline construction, which the Corporation expects to be in 2006. In addition, the Corporation has $73 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, 2005 is $306 million ($309 million at December 31, 2004). The Corporation has a contingent purchase obligation expiring in April 2010, to acquire the remaining interest in a retail marketing and gasoline station joint venture for approximately $140 million.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 discussions resumed in August 2005. 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 petroleum and other energy products.

AMERADA 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, 2005:


				Exploration		Marketing		Corporate
				and Production		and Refining		and Interest			Consolidated*

				(Millions of dollars)
2005
	Operating revenues
		Total operating revenues		$	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 income				21		9		6			36
	Interest expense				—		—		224			224
	Depreciation, depletion and amortization				965		58		2			1,025
	Provision (benefit) for income taxes				737		298		(51	)		984
	Investments in equity affiliates				—		1,346		—			1,346
	Identifiable assets				10,961		6,337		1,817			19,115
	Capital employed**				7,832		3,074		(835	)		10,071
	Capital expenditures				2,235		101		5			2,341

2004
	Operating revenues
		Total operating revenues		$	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 income				17		32		1			50
	Interest expense				—		—		241			241
	Depreciation, depletion and amortization				918		50		2			970
	Provision (benefit) for income taxes				571		158		(141	)		588
	Investments in equity affiliates				—		1,226		—			1,226
	Identifiable assets				10,407		4,850		1,055			16,312
	Capital employed**				7,603		2,519		(690	)		9,432
	Capital expenditures				1,434		85		2			1,521

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


				Exploration		Marketing		Corporate
				and Production		and Refining		and Interest			Consolidated*

				(Millions of dollars)
2003
	Operating revenues
		Total operating revenues		$	3,153	$	11,473	$	1
		Less: Transfers between affiliates			316		—		—

			Operating revenues from unaffiliated customers	$	2,837	$	11,473	$	1		$	14,311

	Income (loss) from continuing operations			$	414	$	327	$	(274	)	$	467
	Discontinued operations				170		—		(1	)		169
	Income from cumulative effect of accounting change				7		—		—			7

			Net income (loss)	$	591	$	327	$	(275	)	$	643

	Equity in income of HOVENSA L.L.C.			$	—	$	117	$	—		$	117
	Interest income				10		34		2			46
	Interest expense				—		—		293			293
	Depreciation, depletion and amortization				998		54		1			1,053
	Provision (benefit) for income taxes				363		126		(175	)		314
	Investments in equity affiliates				—		1,055		—			1,055
	Identifiable assets				9,149		4,267		567			13,983
	Capital employed**				6,689		2,626		(34	)		9,281
	Capital expenditures				1,286		66		6			1,358


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


**	Calculated as equity plus debt.

Financial information by major geographic area for each of the three years ended December 31, 2005 follows:


								Asia and
		United States		Europe		Africa		Other		Consolidated

		(Millions of dollars)
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
2003
	Operating revenues	$	12,019	$	1,694	$	450	$	148	$	14,311
	Property, plant and equipment (net)		1,705		2,538		2,043		1,692		7,978

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


18.	Related Party Transactions

The Corporation has agreed to purchase 50% of HOVENSA’s production of refined products at market prices, after sales by HOVENSA to unaffiliated parties. Such purchases amounted to approximately $3,991 million in 2005, $2,940 million in 2004 and $2,040 million in 2003. The Corporation sold crude oil to HOVENSA totaling approximately $100 million in 2005, $35 million in 2004 and $410 million in 2003. In addition, the Corporation billed HOVENSA freight charter costs of $8 million in 2005, $75 million in 2004 and $59 million in 2003.

The Corporation sold gasoline to a related retail marketing and gasoline station joint venture totaling $1,244 million in 2005, $764 million in 2004 and $489 million in 2003.


19.	Subsequent Events

In 2006, the Corporation will complete the sale of its interests in certain producing properties located in the Permian Basin in West Texas and New Mexico for $404 million, before purchase price adjustments. The net book value of these assets held for sale of approximately $70 million has been recorded in other current assets at December 31, 2005. The Corporation estimates that it will record an after-tax gain of $160 million to $180 million in the first quarter on the sale of these assets.

AMERADA 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 oil and/or natural gas in the United States, United Kingdom, Norway, Denmark, Russia, Equatorial Guinea, Algeria, Gabon, Indonesia, Malaysia, Thailand and Azerbaijan. 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)

2005

Property acquisitions

Unproved

193

173

—

Proved

215

—

215

—

Exploration

378

197

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


2003
	Property acquisitions
		Unproved	$	16	$	16	$	—	$	—	$	—
		Proved		23		—		—		—		23
	Exploration			321		143		49		96		33
	Production and development*			1,082		118		501		395		68


*	Includes $70 million, $51 million and $15 million in 2005, 2004 and 2003, respectively, related to the accrual for asset retirement obligations.

Capitalized Costs Relating to Oil and Gas Producing Activities


		At December 31

		2005		2004

		(Millions of dollars)
Unproved properties		$	629	$	450
Proved properties			3,490		3,267
Wells, equipment and related facilities			13,717		12,378

	Total costs		17,836		16,095
Less: Reserve for depreciation, depletion, amortization and lease impairment			9,243		8,469

	Net capitalized costs	$	8,593	$	7,626

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 to the financial statements.


						United						Asia and
For the Years Ended December 31				Total		States		Europe		Africa		Other

				(Millions of dollars)
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 continuing 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


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


						United							Asia and
For the Years Ended December 31				Total		States		Europe		Africa			Other

				(Millions of dollars)
2003
	Sales and other operating revenues
		Unaffiliated customers		$	2,771	$	469	$	1,716	$	469		$	117
		Inter-company			316		316		—		—			—

			Total revenues		3,087		785		1,716		469			117

	Costs and expenses
		Production expenses, including related taxes			796		194		408		170			24
		Exploration expenses, including dry holes and lease impairment			369		147		60		116			46
		General, administrative and other expenses**			168		65		63		13			27
		Depreciation, depletion and amortization			998		260		553		153			32

			Total costs and expenses		2,331		666		1,084		452			129

		Results of continuing operations before income taxes			756		119		632		17			(12	)
		Provision for income taxes			358		42		291		32			(7	)

	Results of continuing operations				398		77		341		(15	)		(5	)
	Discontinued operations				42		25		4		—			13

	Results of operations			$	440	$	102	$	345	$	(15	)	$	8


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


**	Includes accrued severance and costs for vacated office space of approximately $15 million and $40 million in 2004 and 2003, 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 Financial Accounting Standards Board. 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 below 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						Equity			United						Asia and						Equity
		States			Europe			Africa			Other			Total			Investees			States			Europe			Other			Total			Investees

		(Millions of barrels)																		(Millions of Mcf)
Net Proved Developed and Undeveloped Reserves
	At January 1, 2003		138			364			138			128			768			14			539			852			350			1,741			736
	Revisions of previous estimates(a)		8			8			12			21			49			—			(8	)		14			(25	)		(19	)		—
	Extensions, discoveries and other additions		1			6			4			—			11			—			3			81			4			88			—
	Purchases of minerals in place(c)		8			—			—			14			22			(6	)		21			—			1,023	(b)		1,044			(405	)(b)
	Sales of minerals in place(c)		(8	)		(20	)		—			(81	)		(109	)		(7	)		(103	)		(13	)		(157	)		(273	)		(316	)
	Production		(20	)		(53	)		(19	)		(3	)		(95	)		(1	)		(92	)		(134	)		(23	)		(249	)		(15	)

	At December 31, 2003		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			—			300			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(d)		124			348			165			55			692	(f)		—			282	(e)		715			1,409			2,406			—


Net Proved Developed Reserves
	At January 1, 2003		113			294			85			55			547			8			450			631			154			1,235			221
	At December 31, 2003		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			—


(a)		Includes the impact of changes in selling prices on production sharing contracts with cost recovery provisions and stipulated rates of return. 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. In 2003, such revisions were immaterial.

(b)		Includes the reclassification of reserves to Africa, Asia and Other from equity investees as a result of the consolidation of the Corporation’s interest in the JDA.

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

(d)		Includes 31% of crude oil reserves and 51% of natural gas reserves held under production sharing contracts. These reserves are located outside of the United States and are subject to different political and economic risks.

(e)		Excludes 438 million Mcf of carbon dioxide gas for sale or use in company operations.

(f)		Includes 23 million barrels of crude oil reserves relating to minority interest owners of corporate joint ventures.

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)
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


					United						Asia and
At December 31,			Total		States		Europe		Africa		Other

			(Millions of dollars)
2003
	Future revenues		$	27,823	$	5,742	$	12,417	$	3,922	$	5,742

	Less:
		Future development and production costs		10,065		1,546		5,181		1,697		1,641
		Future income tax expenses		6,022		1,299		3,496		370		857

				16,087		2,845		8,677		2,067		2,498

	Future net cash flows			11,736		2,897		3,740		1,855		3,244
	Less: Discount at 10% annual rate			4,719		1,062		1,333		553		1,771

	Standardized measure of discounted future net cash flows		$	7,017	$	1,835	$	2,407	$	1,302	$	1,473

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


For the Years Ended December 31,			2005			2004			2003

			(Millions of dollars)
Standardized measure of discounted future net cash flows at beginning of year			$	9,177		$	7,017		$	7,085

Changes during the year
	Sales and transfers of oil and gas produced during year, net of production costs			(3,203	)		(2,591	)		(2,291	)
	Development costs incurred during year			1,668			1,255			1,082
	Net changes in prices and production costs applicable to future production			9,334			3,683			774
	Net change in estimated future development costs			(1,725	)		(1,564	)		(726	)
	Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs			865			997			265
	Revisions of previous oil and gas reserve estimates			1,499			578			632
	Purchases (sales) of minerals in place, net			393			(29	)		(469	)
	Accretion of discount			1,424			1,057			960
	Net change in income taxes			(3,533	)		(1,463	)		112
	Revision in rate or timing of future production and other changes			(1,410	)		237			(407	)

		Total		5,312			2,160			(68	)

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

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

QUARTERLY FINANCIAL DATA

(Unaudited)

Quarterly results of operations for the years ended December 31:

Sales and

Other

Net

Operating

Gross

Net

Income

Revenues

Profit(a)

Income

per Share

(Million of dollars, except per share data)

2005

First

4,956

621

219

(b)

2.12

Second

4,963

596

299

(c)

2.89

Third

5,769

604

272

(d)

2.60

Fourth

7,059

875

452

(e)

4.31

2004

First

4,488

562

281

(f)

2.77

Second

3,803

528

288

(g)

2.84

Third

3,830

418

179

1.74

Fourth

4,612

527

229

(h)

2.22


(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 a gain of $11 million for an asset exchange, a gain of $11 million for a legal settlement and a gain of $7 million from a liquidation of prior year LIFO inventory. Also included is a charge of $41 million for tax on repatriated earnings.

(c)		Includes a gain of $11 million resulting from a foreign tax rate change and a charge of $7 million for premiums on repurchased bonds.

(d)		Includes a charge of $14 million due to hurricane related expenses and an additional tax of $31 million on repatriated earnings.

(e)		Includes a gain of $30 million on asset sales and a gain of $25 million from a liquidation of prior year LIFO inventories. Also included are charges of $12 million for additional hurricane expenses, $19 million for premiums on bond repurchases and $8 million related to a customer bankruptcy.

(f)		Includes a gain of $19 million from an asset sale and an income tax benefit of $13 million resulting from the completion of a prior year United States income tax audit.

(g)		Includes a gain of $15 million from the sale of a non-producing asset, partially offset by a charge of $6 million for accrued severance and costs of vacated office space. Additionally, there was income of $7 million from discontinued operations.

(h)		Includes a gain of $21 million resulting from the disposal of two Gulf of Mexico properties and tax benefits of $19 million from a change in tax law and a tax settlement. Also included is a gain of $12 million from a liquidation of prior year LIFO inventories, and a loss of $13 million from a Corporate insurance accrual.

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 Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2005, 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, 2005.

There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended December 31, 2005 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 and Executive Officers of the Registrant*

Information relating to Directors is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 3, 2006.

Information regarding executive officers is included in Part I hereof.


Item 11.	*Executive Compensation*

Information relating to executive compensation is incorporated herein by reference to “Election of Directors — Executive Compensation and Other Information,” other than information under “Compensation Committee Report on Executive Compensation” and “Performance Graph” included therein, from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 3, 2006.


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 3, 2006.

See “Equity Compensation Plans” in Item 5.


Item 13.	*Certain Relationships and Related Transactions*

Information relating to this item is incorporated herein by reference to “Election of Directors” from the Registrant’s definitive proxy statement for the annual meeting of stockholders to be held on May 3, 2006.


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 3, 2006.

PART IV


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


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

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


3.	Exhibits


3(1)		Restated Certificate of Incorporation of Registrant incorporated by reference to Exhibit 3.1 to Form S-3 (Registration No. 333-110244) filed on November 6, 2003.
3(2)		By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002.
4(1)		Certificate of designations, preferences and rights of 3% cumulative convertible preferred stock of Registrant incorporated by reference to Exhibit 4 of Form 10-Q of Registrant for the three months ended June 30, 2000.
4(2)		Certificate of designation, preferences and relative, optional and other special rights and qualifications, limitations and restrictions of 7% mandatory convertible preferred stock of Registrant, incorporated by reference to Exhibit 3 of Form 8-K of Registrant dated November 19, 2003.
4(3)		Revolving Credit Agreement dated as of December 10, 2004 among Amerada Hess Corporation, the lenders party thereto and JP Morgan Chase Bank (formerly, The Chase Manhattan Bank, N.A.), as Administrative Agent incorporated by reference to Exhibit 4(3) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
4(4)		Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.
4(5)		First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 7³/8% Notes due 2009 and 7⁷/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.
4(6)		Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.
4(7)		Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002.
		Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
10(1)		Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981.
10(2)		Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990.
10(3)		Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993.


10(4)		Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998.
10(5)*		Incentive Cash Bonus Plan description incorporated by reference to Item 1.01 of Form 8-K of Registrant dated February 1, 2006.
10(6)*		Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(7)*		Amerada Hess Corporation Savings and Stock Bonus Plan, incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(8)*		Amerada Hess Corporation Savings and Stock Bonus Plan for Retail Operations Employees, incorporated by reference to Exhibit 10(8) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(9)*		Amerada Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
10(10)*		Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Amerada Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(11)*		Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(12)*		Stock Award Program for non-employee directors dated August 6, 1997 incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for the fiscal year ended December 31, 1997.
10(13)*		Amendment to Stock Award Program for Non-Employee Directors dated August 6, 1997 incorporated by reference to Exhibit 10(13) of Form 10-K of Registrant for the fiscal year ended December 31, 2003.
10(14)*		Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2005.
10(15)*		Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and J. Barclay Collins, John J. O’Connor and F. Borden Walker.
10(16)*		Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (other than the named executive officers referred to in Exhibit 10(15)).
10(17)*		Letter Agreement dated March 18, 2002 between Registrant and John J. O’Connor relating to Mr. O’Connor’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(15) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
10(18)*		Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
10(19)*		Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
10(20)		Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998.


10(21)		Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998.
21		Subsidiaries of Registrant.
23		Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated March 8, 2006, to the incorporation by reference in Registrant’s Registration Statements (Form S-8 Nos. 333-115844, 333-94851, 333-43569 and 333-43571, and Form S-3 Nos. 333-110294 and 333-132145), of its reports relating to Registrant’s financial statements, which consent appears on page F-1 herein.
31(1)		Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
31(2)		Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
32(1)		Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32(2)		Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).


*	These exhibits relate to executive compensation plans and arrangements.

(b) Reports on Form 8-K

During the three months ended December 31, 2005, Registrant filed or furnished the following report on Form 8-K:


	1. Filing dated October 26, 2005 reporting under Items 2.02, 7.01 and 9.01, a news release dated October 26, 2005 reporting results for the third quarter of 2005.

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 9th day of March 2006.


	AMERADA 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)	March 9, 2006

/s/ Nicholas F. Brady Nicholas F. Brady	Director	March 9, 2006

/s/ J. Barclay Collins II J. Barclay Collins II	Director	March 9, 2006

/s/ Edith E. Holiday Edith E. Holiday	Director	March 9, 2006

/s/ Thomas H. Kean Thomas H. Kean	Director	March 9, 2006

/s/ Dr. Risa Lavizzo-Mourey Dr. Risa Lavizzo-Mourey	Director	March 9, 2006

/s/ Craig G. Matthews Craig G. Matthews	Director	March 9, 2006

/s/ John J. O’Connor John J. O’Connor	Director	March 9, 2006

/s/ Frank A. Olson Frank A. Olson	Director	March 9, 2006


Signature	Title	Date


/s/ John P. Rielly John P. Rielly	Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 9, 2006

/s/ Ernst H. von Metzsch Ernst H. von Metzsch	Director	March 9, 2006

/s/ F. Borden Walker F. Borden Walker	Director	March 9, 2006

/s/ Robert N. Wilson Robert N. Wilson	Director	March 9, 2006

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements (Form S-3 Nos. 333-110294 and 333-132145 and Form S-8 Nos. 333-115844, 333-94851, 333-43569 and 333-43571 pertaining to the Second Amended and Restated 1995 Long-Term Incentive Plan, the Amended and Restated 1995 Long-Term Incentive Plan, the Amerada Hess Corporation Employees’ Savings and Stock Bonus Plan and the Amerada Hess Corporation Savings and Stock Bonus Plan for Retail Operations Employees) of Amerada Hess Corporation of our reports dated February 24, 2006, with respect to the consolidated financial statements and schedule of Amerada Hess Corporation, Amerada Hess Corporation management’s assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of Amerada Hess Corporation, included in this Annual Report (Form 10-K) for the year ended December 31, 2005.

New York, NY

March 8, 2006

F-1

Schedule II

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2005, 2004 and 2003


				Additions

				Charged
				to Costs		Charged		Deductions
		Balance		and		to Other		from		Balance
Description		January 1		Expenses		Accounts		Reserves		December 31

		(In millions)
2005
	Losses on receivables	$	17	$	16	$	2	$	5	$	30

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

	Refinery maintenance	$	25	$	17	$	—	$	36	$	6

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

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

	Refinery maintenance	$	23	$	14	$	—	$	12	$	25

2003
	Losses on receivables	$	13	$	7	$	—	$	2	$	18

	Deferred income tax valuation	$	128	$	34	$	—	$	36	$	126

	Refinery maintenance	$	20	$	11	$	—	$	8	$	23

F-2

EXHIBIT INDEX


Exhibit
Number		Description

3(1)		Restated Certificate of Incorporation of Registrant incorporated by reference to Exhibit 3.1 to Form S-3 (Registration No. 333-110244) filed on November 6, 2003.
3(2)		By-Laws of Registrant incorporated by reference to Exhibit 3 of Form 10-Q of Registrant for the three months ended June 30, 2002.
4(1)		Certificate of designations, preferences and rights of 3% cumulative convertible preferred stock of Registrant incorporated by reference to Exhibit 4 of Form 10-Q of Registrant for the three months ended June 30, 2000.
4(2)		Certificate of designation, preferences and relative, optional and other special rights and qualifications, limitations and restrictions of 7% mandatory convertible preferred stock of Registrant, incorporated by reference to Exhibit 3 of Form 8-K of Registrant dated November 19, 2003.
4(3)		Revolving Credit Agreement dated as of December 10, 2004 among Amerada Hess Corporation, the lenders party thereto and JP Morgan Chase Bank (formerly, The Chase Manhattan Bank, N.A.), as Administrative Agent incorporated by reference to Exhibit 4(3) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
4(4)		Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.
4(5)		First Supplemental Indenture dated as of October 1, 1999 between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 7³/8% Notes due 2009 and 7⁷/8% Notes due 2029, incorporated by reference to Exhibit 4(2) to Form 10-Q of Registrant for the three months ended September 30, 1999.
4(6)		Prospectus Supplement dated August 8, 2001 to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on August 9, 2001.
4(7)		Prospectus Supplement dated February 28, 2002 to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933 on February 28, 2002. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10 percent of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
10(1)		Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(4) of Form 10-Q of Registrant for the three months ended June 30, 1981.
10(2)		Restated Second Extension and Amendment Agreement dated July 27, 1990 between Hess Oil Virgin Islands Corp. and the Government of the Virgin Islands incorporated by reference to Exhibit 19 of Form 10-Q of Registrant for the three months ended September 30, 1990.
10(3)		Technical Clarifying Amendment dated as of November 17, 1993 to Restated Second Extension and Amendment Agreement between the Government of the Virgin Islands and Hess Oil Virgin Islands Corp. incorporated by reference to Exhibit 10(3) of Form 10-K of Registrant for the fiscal year ended December 31, 1993.
10(4)		Third Extension and Amendment Agreement dated April 15, 1998 and effective October 30, 1998 among Hess Oil Virgin Islands Corp., PDVSA V.I., Inc., HOVENSA L.L.C. and the Government of the Virgin Islands incorporated by reference to Exhibit 10(4) of Form 10-K of Registrant for the fiscal year ended December 31, 1998.
10(5)*		Incentive Cash Bonus Plan description incorporated by reference to Item 1.01 of Form 8-K of Registrant dated February 1, 2006.


Exhibit
Number		Description

10(6)*		Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(7)*		Amerada Hess Corporation Savings and Stock Bonus Plan, incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(8)*		Amerada Hess Corporation Savings and Stock Bonus Plan for Retail Operations Employees, incorporated by reference to Exhibit 10(8) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(9)*		Amerada Hess Corporation Pension Restoration Plan dated January 19, 1990 incorporated by reference to Exhibit 10(9) of Form 10-K of Registrant for the fiscal year ended December 31, 1989.
10(10)*		Letter Agreement dated May 17, 2001 between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Amerada Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(11)*		Second Amended and Restated 1995 Long-Term Incentive Plan, including forms of awards thereunder incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for fiscal year ended December 31, 2004.
10(12)*		Stock Award Program for non-employee directors dated August 6, 1997 incorporated by reference to Exhibit 10(11) of Form 10-K of Registrant for the fiscal year ended December 31, 1997.
10(13)*		Amendment to Stock Award Program for Non-Employee Directors dated August 6, 1997 incorporated by reference to Exhibit 10(13) of Form 10-K of Registrant for the fiscal year ended December 31, 2003.
10(14)*		Compensation program description for non-employee directors, incorporated by reference to Item 1.01 of Form 8-K of Registrant dated January 1, 2005.
10(15)*		Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John B. Hess, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended September 30, 1999. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and J. Barclay Collins, John J. O’Connor and F. Borden Walker.
10(16)*		Change of Control Termination Benefits Agreement dated as of September 1, 1999 between Registrant and John A. Gartman incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2001. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (other than the named executive officers referred to in Exhibit 10(15)).
10(17)*		Letter Agreement dated March 18, 2002 between Registrant and John J. O’Connor relating to Mr. O’Connor’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(15) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
10(18)*		Letter Agreement dated March 18, 2002 between Registrant and F. Borden Walker relating to Mr. Walker’s participation in the Amerada Hess Corporation Pension Restoration Plan incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 2001.
10(19)*		Deferred Compensation Plan of Registrant dated December 1, 1999 incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
10(20)		Asset Purchase and Contribution Agreement dated as of October 26, 1998, among PDVSA V.I., Inc., Hess Oil Virgin Islands Corp. and HOVENSA L.L.C. (including Glossary of definitions) incorporated by reference to Exhibit 2.1 of Form 8-K of Registrant dated October 30, 1998.
10(21)		Amended and Restated Limited Liability Company Agreement of HOVENSA L.L.C. dated as of October 30, 1998 incorporated by reference to Exhibit 10.1 of Form 8-K of Registrant dated October 30, 1998.
21		Subsidiaries of Registrant.


Exhibit
Number		Description

23		Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated March 8, 2006, to the incorporation by reference in Registrant’s Registration Statements (Form S-8 Nos. 333-115844, 333-94851, 333-43569 and 333-43571, and Form S-3 Nos. 333-110294 and 333-132145), of its reports relating to Registrant’s financial statements, which consent appears on page F-1 herein.
31(1)		Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
31(2)		Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
32(1)		Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32(2)		Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).


*	These exhibits relate to executive compensation plans and arrangements.