AMERADA HESS CORP - 10-Q Quarterly Report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarter ended June 30, 2003

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		13-4921002
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)

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

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

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

At June 30, 2003, 89,940,930 shares of Common Stock were outstanding.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements.
	Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition.
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
PART II- OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security-Holders
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
CERTIFICATION OF CHIEF FINANCIAL OFFICER
SECTION 906 CERTIFICATION OF CEO
SECTION 906 CERTIFICATION OF CFO

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)
(in millions, except per share data)


					Three Months						Six months
					ended June 30						ended June 30

					2003			*2002()**			2003		*2002()**

REVENUES AND NON-OPERATING INCOME
	Sales (excluding excise taxes) and other operating revenues				$	3,199		$	2,694		$	7,453	$	5,620
	Non-operating income (expense)
		Gain (loss) on asset sales				(9	)		—			39		62
		Equity in income (loss) of HOVENSA L.L.C.				15			(18	)		65		(44	)
		Other				8			36			19		51

				Total revenues and non-operating income		3,213			2,712			7,576		5,689

COSTS AND EXPENSES
	Cost of products sold					2,140			1,586			5,228		3,523
	Production expenses					191			166			382		325
	Marketing expenses					167			197			337		357
	Exploration expenses, including dry holes and lease impairment					88			49			194		103
	Other operating expenses					49			41			100		83
	General and administrative expenses					106			60			183		122
	Interest expense					77			67			151		133
	Depreciation, depletion and amortization					270			319			546		580

				Total costs and expenses		3,088			2,485			7,121		5,226

	Income from continuing operations before income taxes					125			227			455		463
	Provision for income taxes					62			98			203		203

	Income from continuing operations					63			129			252		260
	Discontinued operations
			Net gain from asset sales			175			—			116		—
			Income from operations			14			20			53		29
	Cumulative effect of change in accounting principle					—			—			7		—

NET INCOME					$	252		$	149		$	428	$	289

BASIC EARNINGS PER SHARE
		Continuing operations			$	.71		$	1.46		$	2.85	$	2.95
		Net income				2.85			1.68			4.83		3.28
DILUTED EARNINGS PER SHARE
		Continuing operations			$	.71		$	1.44		$	2.84	$	2.92
		Net income				2.83			1.66			4.81		3.25

WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING						89.0			89.5			89.1		89.1

COMMON STOCK DIVIDENDS PER SHARE					$	.30		$	.30		$	.60	$	.60

(*) Reclassified to conform with current period presentation.

See accompanying notes to consolidated financial statements.

PART I — FINANCIAL INFORMATION (CONT’D.)

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(in millions of dollars, thousands of shares)


			June 30,
			2003			December 31,
			(Unaudited)			2002

ASSETS
CURRENT ASSETS
	Cash and cash equivalents		$	677		$	197
	Accounts receivable			1,720			1,972
	Inventories			449			492
	Other current assets			101			95

		Total current assets		2,947			2,756

INVESTMENTS AND ADVANCES
	HOVENSA L.L.C.			907			842
	Other			228			780

		Total investments and advances		1,135			1,622

PROPERTY, PLANT AND EQUIPMENT
	Total — at cost			15,827			16,149
	Less reserves for depreciation, depletion, amortization and lease impairment			8,172			9,117

		Property, plant and equipment — net		7,655			7,032

NOTES RECEIVABLE				332			363

GOODWILL				977			977

DEFERRED INCOME TAXES AND OTHER ASSETS				554			512

TOTAL ASSETS			$	13,600		$	13,262

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
	Accounts payable — trade		$	1,385		$	1,401
	Accrued liabilities			735			830
	Taxes payable			408			306
	Notes payable			—			2
	Current maturities of long-term debt			15			14

		Total current liabilities		2,543			2,553

LONG-TERM DEBT				4,627			4,976

DEFERRED LIABILITIES AND CREDITS
	Deferred income taxes			957			1,044
	Asset retirement obligations			425			—
	Other			475			440

		Total deferred liabilities and credits		1,857			1,484

STOCKHOLDERS’ EQUITY
	Preferred stock, par value $1.00, 20,000 shares authorized 3% cumulative convertible series Authorized - 330 shares Issued - 327 shares ($16 million liquidation preference)			—			—
	Common stock, par value $1.00 Authorized - 200,000 shares Issued - 89,941 shares at June 30, 2003; 89,193 shares at December 31, 2002			90			89
	Capital in excess of par value			966			932
	Deferred compensation			(32	)		—
	Retained earnings			3,856			3,482
	Accumulated other comprehensive loss			(307	)		(254	)

		Total stockholders’ equity		4,573			4,249

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY			$	13,600		$	13,262

See accompanying notes to consolidated financial statements.

PART I — FINANCIAL INFORMATION (CONT’D.)

AMERADA HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)
Six months ended June 30
(in millions)


					2003			*2002()**

CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$	428		$	289
	Adjustments to reconcile net income to net cash provided by operating activities
			Depreciation, depletion and amortization			546			580
			Exploratory dry hole costs			95			35
			Lease impairment			30			21
			Pre-tax gain on asset sales			(244	)		(41	)
			Provision (benefit) for deferred income taxes			68			(5	)
			Undistributed earnings of affiliates			(62	)		46
			Non-cash effect of discontinued operations			46			90
			Changes in operating assets and liabilities			152			(21	)

				Net cash provided by operating activities		1,059			994

CASH FLOWS FROM INVESTING ACTIVITIES
	Capital expenditures					(709	)		(863	)
	Payment received on note					31			24
	Proceeds from asset sales and other					508			221

				Net cash used in investing activities		(170	)		(618	)

CASH FLOWS FROM FINANCING ACTIVITIES
	Debt with maturities of 90 days or less — decrease					(2	)		(459	)
	Debt with maturities of greater than 90 days
		Borrowings				—			602
		Repayments				(326	)		(469	)
	Cash dividends paid					(81	)		(80	)
	Stock options exercised					—			28

				Net cash used in financing activities		(409	)		(378	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS						480			(2	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR						197			37

CASH AND CASH EQUIVALENTS AT END OF PERIOD					$	677		$	35

(*) Reclassified to conform with current period presentation.

See accompanying notes to consolidated financial statements.

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1-		The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of the Corporation’s consolidated financial position at June 30, 2003 and December 31, 2002, and the consolidated results of operations and the consolidated cash flows for the three- and six-month periods ended June 30, 2003 and 2002. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.

		Certain notes and other information have been condensed or omitted from these interim financial statements. These statements, therefore, should be read in conjunction with the consolidated financial statements and related notes included in the 2002 Annual Report to Stockholders, which have been incorporated by reference in the Corporation’s Form 10-K for the year ended December 31, 2002. Certain information in the financial statements and notes has been reclassified to conform with current period presentation.

Note 2-		Inventories consist of the following (in millions):


		At			At
		June 30,			December 31,
		2003			2002

Crude oil and other charge stocks		$	130		$	99
Refined and other finished products			412			497
Less: LIFO adjustment			(249	)		(261	)

			293			335
Materials and supplies			156			157

	Total inventories	$	449		$	492


Note 3-		The Corporation accounts for its investment in HOVENSA L.L.C. using the equity method. Summarized financial information for HOVENSA follows (in millions):


			At			At
			June 30,			December 31,
			2003			2002

Summarized balance sheet
	Current assets		$	681		$	520
	Net fixed assets			1,858			1,895
	Other assets			38			40
	Current liabilities			(374	)		(335	)
	Long-term debt			(399	)		(467	)
	Deferred liabilities and credits			(64	)		(45	)

		Partners’ equity	$	1,740		$	1,608

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


			Three months					Six months
			ended June 30					ended June 30

			2003		2002			2003		2002

Summarized income statement
	Total revenues		$	1,172	$	789		$	2,564	$	1,568
	Costs and expenses			1,142		824			2,432		1,655

		Net income (loss)	$	30	$	(35	)	$	132	$	(87	)

Amerada Hess Corporation’s share			$	15	$	(18	)	$	65	$	(44	)


Note 4-		During the three- and six-month periods ended June 30, 2003, the Corporation capitalized interest of $9 million and $21 million on major development projects ($24 million and $49 million during the corresponding periods of 2002).

Note 5-		The provision for income taxes consisted of the following (in millions):


		Three months					Six months
		ended June 30					ended June 30

		2003		2002			2003		2002

Current		$	19	$	109		$	133	$	209
Deferred			43		(11	)		70		(6	)

	Total	$	62	$	98		$	203	$	203


Note 6-		Foreign currency gains (losses), after income tax effects, amounted to the following (in millions):


	Three months					Six months
	ended June 30					ended June 30

	2003			2002		2003			2002

Foreign currency gains (losses)	$	(12	)	$	10	$	(13	)	$	4


Note 7-		The Corporation records compensation expense for nonvested common stock awards ratably over the vesting period, which is generally five years. The Corporation uses the intrinsic value method to account for employee stock options. Because the exercise prices of employee stock options equal or exceed the market price of the stock on the date of grant, the Corporation does not recognize compensation expense.

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		The Corporation uses the Black-Scholes model to estimate the fair value of employee stock options for pro forma disclosure. Using the fair value method, stock option expense would be recognized over the one-year vesting period. 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 granted during the previous year (in millions, except per share data):


		Three months						Six months
		ended June 30						ended June 30

		2003			2002			2003			2002

Net income		$	252		$	149		$	428		$	289
Add nonvested common stock compensation expense included in net income, net of taxes			2			2			4			4
Less total stock-based employee compen- sation expense, net of taxes (*)			(2	)		(6	)		(4	)		(12	)

	Pro forma net income	$	252		$	145		$	428		$	281

Net income per share as reported
	Basic	$	2.85		$	1.68		$	4.83		$	3.28

	Diluted	$	2.83		$	1.66		$	4.81		$	3.25

Pro forma net income per share
	Basic	$	2.85		$	1.64		$	4.83		$	3.19

	Diluted	$	2.83		$	1.61		$	4.81		$	3.15

(*)Includes nonvested common stock and stock option expense determined using the fair value method.

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 8-		The weighted average number of common shares used in the basic and diluted earnings per share computations are as follows (in thousands):


		Three months				Six months
		ended June 30				ended June 30

		2003		2002		2003		2002

Common shares — basic			88,614		88,202		88,614		88,025
Effect of dilutive securities (equivalent shares)
	Nonvested common stock		222		489		222		472
	Stock options		—		603		14		431
	Convertible preferred stock		205		205		205		205

Common shares — diluted			89,041		89,499		89,055		89,133

Earnings per share are as follows:


		Three months				Six months
		ended June 30				ended June 30

		2003		2002		2003		2002

Basic
	Continuing operations	$	.71	$	1.46	$	2.85	$	2.95
	Discontinued operations		2.14		.22		1.91		.33
	Cumulative effect of change in accounting principle		—		—		.07		—

	Net income	$	2.85	$	1.68	$	4.83	$	3.28

Diluted
	Continuing operations	$	.71	$	1.44	$	2.84	$	2.92
	Discontinued operations		2.12		.22		1.90		.33
	Cumulative effect of change in accounting principle		—		—		.07		—

	Net income	$	2.83	$	1.66	$	4.81	$	3.25

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 9-		Comprehensive income was as follows (in millions):


	Three months						Six months
	ended June 30						ended June 30

	2003			2002			2003			2002

Net income	$	252		$	149		$	428		$	289
Net change in cash flow hedging activities		(38	)		(10	)		(46	)		(252	)
Change in foreign currency translation adjustment		(2	)		17			(6	)		27

Comprehensive income	$	212		$	156		$	376		$	64


		The Corporation reclassifies hedging gains and losses included in other comprehensive income to earnings at the time the hedged transactions are recognized. Hedging decreased exploration and production results by $45 million ($72 million before income taxes) in the second quarter of 2003 and $147 million ($235 million before income taxes) in the first half of 2003. Hedging increased exploration and production results by $9 million ($14 million before income taxes) and $75 million ($115 million before income taxes) for the corresponding periods of 2002.

		At June 30, 2003, after-tax deferred losses from crude oil and natural gas contracts used as hedges and expiring through 2004 were approximately $141 million ($117 million of unrealized losses and $24 million of realized losses).

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 10-		The Corporation’s results by operating segment were as follows (in millions):


			Three months						Six months
			ended June 30						ended June 30

			2003			2002			2003			2002

Operating revenues
	Exploration and production (*)		$	770		$	801		$	1,586		$	1,955
	Refining and marketing			2,503			2,041			6,051			3,926

		Total	$	3,273		$	2,842		$	7,637		$	5,881

Net income
	Exploration and production		$	88		$	175		$	207		$	389
	Refining and marketing			46			17			183			(5	)
	Corporate, including interest			(71	)		(63	)		(138	)		(124	)

	Income from continuing operations			63			129			252			260
	Discontinued operations			189			20			169			29
	Income from cumulative effect of accounting change			—			—			7			—

		Total	$	252		$	149		$	428		$	289


(*)		Includes transfers to affiliates of $74 million and $184 million during the three- and six-months ended June 30, 2003, compared to $148 million and $261 million for the corresponding periods of 2002.

Identifiable assets by operating segment were as follows (in millions):


		At		At
		June 30,		December 31,
		2003		2002

Identifiable assets
	Exploration and production	$	8,869	$	8,392
	Refining and marketing		3,829		4,218
	Corporate		902		652

Total		$	13,600	$	13,262


Note 11-		In the second quarter of 2003, the Corporation sold producing properties in the Gulf of Mexico shelf, the Jabung Field in Indonesia and several small United Kingdom fields. The aggregate proceeds from these sales were $445 million and the net gain from discontinued operations was $175 million. Income from operations of these assets prior to sale amounted to $14 million in the second quarter and $40 million in the first half of 2003. In the first half of 2003, the Corporation also exchanged producing properties in Colombia for an increased interest in a non-producing property under development in the joint development area of Malaysia and Thailand. The net production from fields sold or exchanged at the time of disposition was approximately 45,000 barrels of oil equivalent per day.

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		With respect to the assets sold in the second quarter of 2003, the net book value of fixed assets at the time of sale was approximately $295 million ($275 million at December 31, 2002) and the related dismantlement and deferred tax liabilities were approximately $160 million ($170 million at December 31, 2002). Sales and other operating revenues were $37 million in the second quarter and $115 million in the first half of 2003 and $69 million and $115 million in the same periods of last year.

		The Corporation exchanged its crude oil producing properties in Colombia (acquired in 2001 as part of the Triton acquisition), plus $10 million in cash, for an additional 25% interest in natural gas reserves in the joint development area of Malaysia and Thailand. The exchange resulted in a net charge to income of $47 million, after-tax, which the Corporation reported as a loss from discontinued operations in the first quarter of 2003. The loss on this exchange included a $43 million adjustment of the book value of the Colombian assets to fair value resulting primarily from a revision in crude oil reserves. The loss also included $17 million from the recognition in earnings of the value of related hedge contracts at the time of the exchange. These items were partially offset by after-tax earnings in Colombia prior to the exchange of $13 million.

		In the Colombia exchange transaction, the Corporation acquired the 50% interest in a corporate joint venture that it did not already own. Prior to the exchange, the Corporation accounted for its 50% interest in the corporate joint venture using the equity method. Because of the exchange, the joint venture became a wholly owned subsidiary. Consequently, the Corporation has consolidated this subsidiary, which holds a 50% interest in a production sharing contract with natural gas reserves in the joint development area of Malaysia and Thailand. At the time of the exchange, the exploration and production segment included the net book value of fixed assets in Colombia of $670 million ($685 million at December 31, 2002) and a related deferred income tax liability of $142 million ($145 million at December 31, 2002). Sales and other operating revenues were $36 million in the first half of 2003 and $121 million for the same period of the prior year.

		The Corporation has reached agreement with another oil company to exchange 14% interests in the Scott and Telford fields in the United Kingdom for an additional 22.5% interest in the Llano Field in the Gulf of Mexico and $17 million in cash. The exchange increases the Corporation’s working interest in the Llano Field to 50% and decreases its interest in the Scott Field to 21%. This transaction is expected to close in the fourth quarter of 2003.

Note 12 -		On January 1, 2003, the Corporation changed its method of accounting for asset retirement obligations as required by FAS No. 143, Accounting for Asset Retirement Obligations. Previously, the Corporation had accrued the estimated costs of dismantlement, restoration and abandonment, less estimated salvage values, of offshore oil and gas production platforms and pipelines using the units-of-production method. This cost was reported as a component of depreciation expense and accumulated depreciation. Using the new accounting method required by FAS No.

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		143, the Corporation now recognizes as a liability legally required asset retirement obligations for oil and gas production facilities in the period in which they are incurred based on the estimated fair value. The Corporation capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived asset.

		The cumulative effect of this change on prior years resulted in a credit to income of $7 million (net of income taxes of $18 million) or $0.08 per share, basic and diluted. The cumulative effect is included in income for the six months ended June 30, 2003. The effect of the change on the six months ended June 30, 2003 was to increase income before the cumulative effect of the accounting change by $3 million, after-tax ($0.04 per share diluted). Assuming the accounting change had been applied retroactively to January 1, 2002 (rather than January 1, 2003), there would not have been a material change in income from continuing operations and net income.

		The following table describes changes to the Corporation’s asset retirement obligations (in millions):


Asset retirement obligations at January 1, 2003	$	556
Liabilities settled or disposed of		(147	)
Accretion expense		13
Foreign currency translation		3

Asset retirement obligations at June 30, 2003	$	425


		If FAS No. 143 had been applied beginning January 1, 2002 (rather than at January 1, 2003), the pro forma liability for asset retirement obligations at that date would have been $537 million.

		The Corporation has adopted Emerging Issues Task Force abstract 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. In accordance with EITF 02-3, the Corporation began accounting for trading inventory purchased after October 25, 2002 at the lower of cost or market. Inventory purchased prior to this date was marked-to-market and reflected in income currently. Beginning January 1, 2003, the Corporation accounted for all trading inventory at the lower of cost or market. This accounting change did not have a material effect on the Corporation’s income or financial position.

		In January 2003, the Financial Accounting Standards Board issued FIN 46, Consolidation of Variable Interest Entities, which is effective for third quarter reporting. The Corporation does not presently anticipate any material effect on its financial position or results of operations from this Interpretation.

PART I — FINANCIAL INFORMATION (CONT’D.)

Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition.

Results of Operations

Net income for the second quarter of 2003 amounted to $252 million, including gains on asset sales, compared with $149 million in the second quarter of 2002. Net income for the first half of 2003 was $428 million compared with $289 million in the first half of 2002. Income from continuing operations was $63 million and $252 million in the second quarter and first half of 2003, respectively. The after-tax results by major operating activity for the three- and six-months ended June 30, 2003 and 2002 were as follows (in millions, except per share data):


		Three months						Six months
		ended June 30						ended June 30

		2003			*2002()**			2003			*2002()**

Exploration and production		$	88		$	175		$	207		$	389
Refining and marketing			46			17			183			(5	)
Corporate			(27	)		(18	)		(47	)		(33	)
Interest expense			(44	)		(45	)		(91	)		(91	)

Income from continuing operations			63			129			252			260
Discontinued operations
	Net gains from asset sales		175			—			116			—
	Income from operations		14			20			53			29
Income from cumulative effect of accounting change			—			—			7			—

Net income		$	252		$	149		$	428		$	289

Income per share from continuing operations (diluted)		$	.71		$	1.44		$	2.84		$	2.92

Net income per share (diluted)		$	2.83		$	1.66		$	4.81		$	3.25

(*) Reclassified to conform with current period presentation.

Exploration and Production

Exploration and production earnings from continuing operations decreased by $87 million and $182 million in the second quarter and first half of 2003, respectively, compared with 2002. These results include an after-tax charge of $23 million in the second quarter of 2003 for accrued severance in the United States and United Kingdom and a reduction of leased office space in London. The remainder of the decrease in each period is primarily due to lower crude oil and natural gas sales volumes, higher exploration expenses, losses from foreign currency fluctuations in 2003 (compared with income in 2002) and a higher effective income tax rate. Exploration and production earnings include after-tax gains from asset sales of $31 million and $42 million in the first half of 2003 and 2002, respectively.

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

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


		Three months				Six months
		ended June 30				ended June 30

		2003		2002		2003		2002

Crude oil (per barrel)
	United States	$	23.12	$	25.51	$	23.79	$	23.58
	Foreign		24.31		24.10		24.82		23.84
Natural gas liquids (per barrel)
	United States	$	21.84	$	15.22	$	24.60	$	14.06
	Foreign		19.44		17.83		22.81		17.16
Natural gas (per Mcf)
	United States	$	4.09	$	3.56	$	4.27	$	3.58
	Foreign		2.58		1.94		2.81		2.17

The Corporation’s net daily worldwide production was as follows (in thousands):


			Three months				Six months
			ended June 30				ended June 30

			2003		2002		2003		2002

Crude oil (barrels per day)
	United States			45		57		47		58
	United Kingdom			96		115		99		113
	Equatorial Guinea			24		48		25		39
	Norway			24		24		24		23
	Denmark			23		21		24		22
	Algeria			15		14		18		13
	Gabon			10		9		10		9
	Indonesia			1		3		2		5
	Azerbaijan			2		4		2		4
	Colombia			—		21		6		23

		Total		240		316		257		309

Natural gas liquids (barrels per day)
	United States			9		13		10		13
	Foreign			11		8		10		9

		Total		20		21		20		22

Natural gas (Mcf per day)
	United States			264		422		291		408
	United Kingdom			327		272		324		299
	Denmark			28		36		31		39
	Norway			28		24		27		24
	Indonesia and Thailand			48		36		52		32

		Total		695		790		725		802

Barrels of oil equivalent (per day) () (*)				376		469		398		464

(*) Includes production related to discontinued operations				14		56		26		54

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

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

The Corporation’s oil and gas production, on a barrel-of-oil equivalent basis, decreased by 20% in the second quarter and 14% in the first half of 2003 compared with the corresponding periods of 2002. Approximately one-half of the decreases are due to asset sales and the Colombia/JDA exchange. Crude oil and natural gas production in the United States was lower due to asset sales and natural decline. United Kingdom crude oil production was also lower reflecting asset sales and temporary production interruptions. Production from the Ceiba field in Equatorial Guinea decreased in the second quarter and first half of 2003 due to reservoir characteristics.

In the second quarter of 2003, the Corporation sold Gulf of Mexico shelf properties, the Jabung Field in Indonesia and several small United Kingdom fields. In the first quarter of 2003, the Corporation exchanged its producing fields in Colombia for an increased interest in the joint development area of Malaysia and Thailand, which is not yet producing. Barrel of oil equivalent production from these fields at the time of sale or exchange was approximately 45,000 barrels per day. The Corporation has also agreed to exchange an interest in the Scott and Telford fields in the United Kingdom for an increased interest in the Llano Field in the Gulf of Mexico. Production from the Llano Field is scheduled to commence in the second quarter of 2004. This exchange of assets is scheduled to close in the fourth quarter. Production from the Scott/Telford interest expected to be exchanged is currently 10,000 barrels per day.

Production expenses increased in the second quarter and first half of 2003 compared with 2002, reflecting higher per barrel costs, including transportation, insurance and workovers. Depreciation, depletion and amortization charges were lower in the second quarter and first half of 2003 principally reflecting lower production volumes. General and administrative expenses relating to exploration and production activities were higher in the second quarter and first half of 2003 reflecting charges for accrued severance in London, Aberdeen and Houston and a reduction in leased office space in London. Exploration expense increased in the second quarter and first half of 2003 compared with the corresponding periods of 2002 when more of the exploration drilling program took place in the second half of the year.

After-tax foreign currency losses amounted to $12 million in the second quarter of 2003 and $13 million in the first half of 2003, compared with income of $10 million and $4 million in the corresponding periods of 2002. The pre-tax amounts of foreign currency gains or losses are included in non-operating income (expense) in the income statement.

The effective income tax rate for exploration and production operations in the first half of 2003 was approximately 49%. This rate is higher than the United States statutory rate, reflecting an increased proportion of E&P earnings from foreign jurisdictions with higher income tax rates, such as the United Kingdom and Norway, and a lesser percentage from United States sources. All of the Corporation’s hedging results are included in the United States tax return which reduced United States

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

taxable income in 2003. The full year 2003 effective E&P income tax rate is expected to be comparable to the first half rate.

The Corporation’s future exploration and production earnings may be impacted by volatility in the selling prices of crude oil and natural gas, reserve and production changes, fluctuations in foreign exchange rates and changes in tax rates.

Refining and Marketing

Refining and marketing income amounted to $46 million in the second quarter of 2003 compared with $17 million in the corresponding period of 2002. For the first half of 2003, refining and marketing earnings were $183 million compared with a loss of $5 million in 2002. Earnings in the second quarter of 2003 include a net loss of $20 million from the sale of the Corporation’s interest in a shipping joint venture. Refining and marketing earnings in the second quarter of 2002 included after-tax charges totaling $22 million for accrued severance and a reduction in the carrying value of intangible assets.

HOVENSA

The Corporation’s share of HOVENSA’s income was $15 million in the second quarter of 2003 compared with a loss of $18 million in the second quarter of 2002. The Corporation’s share of HOVENSA’s income in the first half of 2003 was $65 million compared with a loss of $44 million in the first half of 2002. The increase was due to higher refining margins in both periods compared to the prior year. Margins were particularly strong during the first quarter of 2003 reflecting colder weather and low industry inventories. Income taxes on the Corporation’s share of HOVENSA’s results are not recorded due to available loss carryforwards.

The Corporation’s share of HOVENSA’s crude runs amounted to 207,000 barrels per day in the first half of 2003 compared with 176,000 barrels per day in the first half of 2002. The fluid catalytic cracking unit at HOVENSA was shutdown for a portion of the first half of 2002. Crude runs were reduced in 2002 due to downtime at this unit and low refining margins. HOVENSA is currently receiving its contracted quantities of crude oil from PDVSA after political disturbances in Venezuela earlier in the year interrupted crude oil deliveries.

Refining and marketing earnings also included interest income of $16 million in the first half of 2003 and $18 million in the first half of 2002 on the note received from PDVSA V.I. in connection with the formation of the joint venture.

Retail, energy marketing and other

Retail gasoline operations were more profitable in the second quarter and first half of 2003 than in the corresponding periods of 2002, reflecting higher margins at gasoline stations. Earnings from energy marketing activities were also higher in the

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

second quarter and first half of 2003. Energy marketing earnings were particularly strong during the first quarter of 2003 reflecting higher sales volumes and margins from the colder winter. Results of the Port Reading refining facility in 2003 were slightly higher than in 2002.

Total refined product sales volumes increased by 11% to 78 million barrels in the first half of 2003 compared with the same period of 2002. The increase was largely due to higher demand for distillates and residual fuel oils.

The Corporation has a 50% voting interest in a consolidated partnership that trades energy commodities and energy derivatives. The Corporation also takes trading positions in addition to its hedging program. The Corporation’s after-tax results from trading activities, including its share of the earnings of the trading partnership, amounted to a loss of $6 million in the second quarter and a gain of $12 million in the first half of 2003. Trading activities recorded income of $17 million in both the second quarter and first half of 2002.

Refining and marketing earnings will likely continue to be volatile reflecting competitive industry conditions and supply and demand factors, including the effects of weather.

Corporate

Net corporate expenses were $27 million in the second quarter and $47 million in the first half of 2003, compared with $18 and $33 million in the same periods of 2002. Corporate expenses in 2003 include after-tax charges of $8 million in the second quarter and $11 million in the first half from early repayment of debt. The pre-tax amounts are recorded in other non-operating income (expense) in the income statement.

Interest

After-tax interest amounted to $44 million in the second quarter of 2003 compared with $45 million in the second quarter of 2002. In the first half of 2003, after-tax interest amounted to $91 million, the same as in 2002. Interest incurred in the second quarter and first half of 2003 is lower than in 2002 because of debt reduction, however, less interest has been capitalized in 2003. Pre-tax capitalized interest amounted to $21 million in the first half of 2003 compared with $49 million in the corresponding period of 2002.

Discontinued Operations

In the second quarter of 2003, the Corporation sold Gulf of Mexico Shelf properties, the Jabung Field in Indonesia and several small United Kingdom fields for $445 million. An after-tax gain from these asset sales of $175 million was included in discontinued operations in the second quarter. Discontinued operations in the

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

second quarter and first half of 2003 also include $14 million and $40 million, respectively, of income from operations prior to the sales of these assets.

In the first quarter of 2003, the Corporation exchanged its crude oil producing properties in Colombia, plus $10 million in cash, for an additional 25% interest in Block A-18 in the joint development area of Malaysia and Thailand. The exchange resulted in a charge to income of $47 million, after-tax, which the Corporation reported as a loss from discontinued operations. The loss on this exchange included a $43 million adjustment of the book value of the Colombian assets to fair value resulting primarily from a revision in crude oil reserves. The loss also included $17 million from the recognition in earnings of the value of related hedge contracts at the time of the exchange. These items were partially offset by after-tax earnings in Colombia prior to the exchange of $13 million.

Change in Accounting Principle

The Corporation adopted 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 the year. At the date of adoption, a liability of $556 million representing the estimated fair value of the Corporation’s required dismantlement obligations was recorded on the balance sheet. In addition, a dismantlement asset of $311 million was recorded, as well as accumulated depreciation of $203 million. For the full year of 2003, the depreciation of the dismantlement asset, plus accretion of the dismantlement liability, will be approximately $40 million, a decrease of approximately 20% from the dismantlement expense under the previous accounting policy, adjusted for discontinued operations.

Consolidated Operating Revenues

Sales and other operating revenues increased by 19% in the second quarter and 33% in the first half of 2003, compared with the corresponding periods of 2002. These increases principally reflect higher sales volumes of refined products and increased sales of purchased natural gas by Energy Marketing operations. In the first quarter of 2003 selling prices of distillates, residual fuel oils and natural gas were higher reflecting the colder winter.

Liquidity and Capital Resources

Net cash provided by operating activities, including changes in operating assets and liabilities, amounted to $1,059 million in the first half of 2003 compared with $994 million in the first half of 2002. The 2003 amount includes cash of $152 million from changes in working capital accounts including accounts receivable and inventories. Excluding the working capital changes, cash provided by operating activities decreased, reflecting lower cash operating earnings.

PART I — FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (Continued)

In the first half of 2003, the Corporation took initiatives to reshape its portfolio of producing assets to reduce future costs, lengthen its reserve to production ratio, and provide capital for investment in new fields and funds to reduce debt. The Corporation exchanged producing properties in Colombia for an increased interest in a non-producing property under development in the joint development area of Malaysia and Thailand. The Corporation’s Colombia properties (acquired in 2001 as part of the Triton acquisition), plus $10 million in cash, were exchanged for an additional 25% interest in natural gas reserves in the joint development area of Malaysia and Thailand (JDA). The JDA production facilities are complete, but production will not commence until the construction of a natural gas pipeline and gas plant is completed by the purchasers of the gas. It is anticipated that production will begin in 2005. The Corporation also sold certain producing properties in the Gulf of Mexico Shelf, the Jabung Field in Indonesia, several small United Kingdom fields and an interest in a shipping joint venture. The aggregate proceeds from these sales were $508 million. The net production from fields sold or exchanged at the time of disposition was approximately 45,000 barrels of oil equivalent per day.

The Corporation has reached agreement with another oil company to exchange 14% interests in the Scott and Telford fields in the United Kingdom for an additional 22.5% interest in the Llano Field in the Gulf of Mexico and $17 million in cash. This transaction is scheduled to close in the fourth quarter. Production from the United Kingdom interest being transferred was approximately 10,000 barrels per day in the first half of 2003. Production from the Corporation’s 50% interest in the Llano Field is scheduled to commence in the second quarter of 2004.

The asset sales accelerated cash flows into 2003 that would have been received over the productive lives of the assets. The proceeds from asset sales, as well as operating cash flow, will provide capital for the development of new fields, as well as funds to repay debt. The Corporation believes the overall impact of its program of asset sales and exchanges of properties has not reduced its liquidity in the short-term or over the next five years.

Based on current estimates of production, capital expenditures and other variables, and assuming quarter-end oil and gas prices, the Corporation anticipates it will fund its future operations, including capital expenditures and required debt repayment, with cash flow from operations, and, when necessary, available borrowing capacity under its presently undrawn committed revolving credit agreement totaling $1.5 billion. This agreement expires in 2006 and the Corporation expects it will be able to arrange a new committed facility at that time, if required. It is possible that there may be a modest increase in total debt over the next six quarters.

Total debt was $4,642 million at June 30, 2003 compared with $4,992 million at December 31, 2002. The Corporation’s debt to capitalization ratio was 50.4% at June 30, 2003 compared with 54.0% at December 31, 2002.

At June 30, 2003, loan agreement covenants allow the Corporation to borrow an additional $2.9 billion for the construction or acquisition of assets. The amount

PART I — FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (Continued)

that can be borrowed under the loan agreements for the payment of dividends is $1.1 billion. At June 30, 2003, the Corporation has $1.5 billion of additional borrowing capacity available under its revolving credit agreement and has additional unused lines of credit for $206 million under uncommitted arrangements with banks.

The Corporation has lease financings, a portion of which are leveraged lease financings not included in its balance sheet, primarily related to retail gasoline stations. The net present value of the financings is $462 million at June 30, 2003, using interest rates inherent in the leases. The Corporation’s June 30 debt to capitalization ratio would increase from 50.4% to 52.7% if the lease financings were included.

While the Corporation continues to maintain investment grade credit ratings, two rating agencies have reduced their ratings of the Corporation’s debt during 2003. The rating change did not result in the termination or reduction of any of the Corporation’s debt or leasing capacity, nor were principal or interest payments accelerated. The Corporation’s commercial paper ratings have also been reduced, which will restrict its ability to access the commercial paper market. However, it has $1.5 billion in unused revolving credit capacity available. Certain contracts with hedging and trading counterparties may require additional cash margin or collateral of up to approximately $70 million as a result of the downgrade. Assuming current conditions, the Corporation estimates the change in credit ratings will increase financing costs by less than $1 million annually.

If the Corporation’s credit rating were to be reduced below investment grade, the Corporation may be required to provide additional security under a lease with remaining payments of $39 million and to comply with more stringent financial covenants contained in debt instruments assumed in the Triton acquisition, unless it elects to defease these obligations. The Corporation would have been in compliance with such covenants as of the balance sheet date. In addition, the amount of cash margin or collateral required under contracts with hedging and trading counterparties at June 30, 2003 would increase to $157 million.

The Corporation and PDVSA equally guarantee the payment of the value 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 June 30, 2003 amounted to $117 million.

In addition, the Corporation has agreed to provide funding, in proportion to its 50% interest, to the extent HOVENSA does not have funds to meet its senior debt obligations prior to the completion of coker construction, as defined. At June 30, 2003, the Corporation’s pro-rata share of HOVENSA’s senior debt was $100 million after deducting HOVENSA funds available for debt service. After completion of the coker construction project, the maximum pro-rata share becomes $40 million until completion of construction required to meet final low sulfur fuel regulations, after which the amount reduces to $15 million.

PART I — FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (Continued)

In connection with the sale of six vessels in 2002, the Corporation agreed to support the buyer’s charter rate on these vessels for up to five years. The support agreement requires that, if the actual contracted rate for the charter of a vessel is less than the stipulated support rate in the agreement, the Corporation will pay to the buyer the difference between the contracted rate and the stipulated rate. At January 1, 2003, the charter support reserve was $48 million. During the first half of 2003, the Corporation paid $2 million of charter support, reducing the reserve to $46 million.

In the second quarter of 2003, the Corporation recorded an after-tax charge of $23 million for accrued severance and a reduction in leased office space in London. The pre-tax amount of this charge was $38 million, of which $21 million relates to leased office space. The remainder of $17 million relates to severance for positions which were eliminated in London, Aberdeen and Houston. A total of approximately 800 employee and contractor positions have been or will be eliminated or will be transferred to other operators. Approximately 280 employees will be receiving severance which will be paid principally in the second half of 2003 and 2004. Additional accruals for severance and lease costs of approximately $20 million, after-tax, are anticipated over the next several quarters. The estimated annual after-tax savings from this cost reduction initiative is approximately $30 million.

Capital expenditures in the first half of 2003 were $709 million of which $660 million related to exploration and production activities. Capital expenditures in the first half of 2002 were $863 million, including $778 million for exploration and production. Capital expenditures for the remainder of 2003 are currently estimated to be approximately $750 million. These expenditures are expected to be funded by available cash or cash flow from operations.

Market Risk Disclosure

In the normal course of business, the Corporation is exposed to commodity risks related to changes in the price of crude oil, natural gas, refined products and electricity. 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 principally related to the prices of crude oil, natural gas and refined products.

Instruments: The Corporation uses forward commodity contracts, foreign exchange forward contracts, futures, swaps and options in the Corporation’s non-trading and trading activities. These contracts are widely traded instruments with standardized terms.

PART I — FINANCIAL INFORMATION (CONT’D.)

Market Risk Disclosure (Continued)

Quantitative Measures: 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 potential change in fair value based on commodity price risk is presented in the non-trading and trading sections below.

Non-Trading: The Corporation’s non-trading activities 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. As of June 30, the Corporation has open hedge positions equal to 65% of its estimated 2003 worldwide crude oil production for the period July 1, 2003 to December 31, 2003 and 55% of its estimated 2004 worldwide crude oil production. The average price for West Texas Intermediate (WTI) related open hedge positions is $24.29 in 2003 and $24.33 in 2004. The average price for Brent related open hedge positions is $23.61 in 2003 and $23.30 in 2004. Of the Corporation’s outstanding hedges, approximately 20% is WTI related and the remainder is Brent. The Corporation has no open hedges of natural gas production at June 30, 2003. As market conditions change, the Corporation may adjust its hedge positions.

The Corporation also markets energy commodities including refined petroleum products, natural gas and electricity. The Corporation uses futures and swaps to fix the purchase prices of commodities to be sold under fixed-price sales contracts.

The Corporation estimates that at June 30, 2003, the value-at-risk for commodity related derivatives that are settled in cash and used in non-trading activities was $40 million ($50 million at December 31, 2002). The results may vary from time to time as hedge levels change.

Trading: 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. These strategies include proprietary position management and trading to enhance the potential return on assets. The information that follows represents 100% of the trading partnership and the Corporation’s proprietary trading accounts.

In trading activities, the Corporation is exposed to changes in crude oil, natural gas and refined product prices, primarily in North America and Europe. Trading positions include futures, swaps and options. In some cases, physical purchase and sale contracts are used as trading instruments and are included in the trading results.

Derivative trading transactions are marked-to-market and are reflected in income currently. Total net realized gains, before income taxes, for the first half of 2003 amounted to $16 million and net unrealized gains were $63 million. The following

PART I — FINANCIAL INFORMATION (CONT’D.)

Market Risk Disclosure (Continued)

table provides an assessment of the factors affecting the changes in fair value of trading activities in the first half of 2003 and represents 100% of the trading partnership and other trading activities (in millions):


Fair value of contracts outstanding at January 1, 2003	$	36
Change in fair value of contracts outstanding at the beginning of the year and still outstanding at June 30, 2003		65
Reversal of fair value for contracts closed during the period		(20	)
Fair value of contracts entered into during the period		18

Fair value of contracts outstanding at June 30, 2003	$	99

The Corporation uses observable market values for determining the fair value of its trading instruments. The majority of valuations are based on actively quoted market values. In cases where actively quoted prices are not available, other external sources or internal estimates are used. External sources incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. The Corporation’s risk management department compares valuations regularly to independent sources and models. The sources of fair value follow (in millions):


				Instruments Maturing

	Total			2003		2004			2005

Prices actively quoted	$	100		$	34	$	25		$	41
Other external sources		(1	)		—		(1	)		—

Total	$	99		$	34	$	24			41

The Corporation estimates that at June 30, 2003, the value-at-risk for trading activities, including commodities, was $8 million ($6 million at December 31, 2002). The results may change from time to time as strategies change to capture potential market rate movements.

The following table summarizes the fair values of net receivables, including option premiums, relating to the Corporation’s trading activities and the credit rating of counterparties at June 30, 2003 (in millions):


Investment grade determined by outside sources	$	227
Investment grade determined internally*		70
Less than investment grade		30
Not determined		9

Total	$	336

Based on information provided by counterparties and other available sources.

PART I — FINANCIAL INFORMATION (CONT’D.)

Critical Accounting Policies

Accounting policies 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.

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

In the case of oil and gas fields, the 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 on oil and gas fields were reduced. Significant extended declines in crude oil and natural gas selling prices could also result in asset impairments.

The Corporation has recorded $977 million of goodwill in connection with the purchase of Triton. Factors contributing to the recognition of goodwill included the strategic value of expanding global operations to access new growth areas outside of the United States and the North Sea, obtaining critical mass in Africa and Southeast Asia, and synergies, including cost savings, improved processes and portfolio high grading opportunities. In accordance with FAS No. 142, goodwill is no longer amortized but must be tested for

PART I — FINANCIAL INFORMATION (CONT’D.)

impairment annually. FAS No. 142 requires that goodwill be tested for impairment 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. A reporting unit is an operating segment or a component which is one level below an operating segment. A component is a reporting unit if the component constitutes a business for which discrete financial information is available and segment management regularly reviews the operating results of that component. However, two or more components of an operating segment shall be aggregated and deemed a single reporting unit if the components have similar economic characteristics. An operating segment shall be deemed to be a reporting unit if all of its components are economically similar.

The Corporation has two operating segments which are (1) exploration and production and (2) refining and marketing. Within the exploration and production operating segment there are currently two components: (1) Americas and West Africa and (2) Europe, North Africa and Asia. Each component has a manager who reports to the segment manager. The Corporation has determined the components have similar economic characteristics and, therefore, aggregates the components into a single reporting unit — the exploration and production operating segment. As a result, goodwill has been assigned to the exploration and production operating segment. If the Corporation reorganized its exploration and production business such that there was more than one operating segment, or its components were no longer economically similar, goodwill would be assigned to two or more reporting units. The goodwill would be allocated to any new reporting units using a relative fair value approach in accordance with FAS No. 142. Goodwill impairment testing for lower level reporting units could result in the recognition of an impairment that would not otherwise be recognized at the current higher level of aggregation.

The Corporation expects that the benefits of goodwill will be recovered through the operation of the exploration and production segment as a whole and it evaluated the following characteristics in determining that the components are economically similar:

• The Corporation operates its exploration and production segment as a single, global business.

• Each component produces oil and gas.

• The exploration and production processes are similar in each component.

• The methods used by each component to market and distribute oil and gas are similar.

• Customers of each component are similar, and

• The components share resources and are supported by a worldwide exploration team and a shared services organization.

The Corporation’s fair value estimate of the exploration and production segment is the sum of: (1) the discounted anticipated cash flows of producing

PART I — FINANCIAL INFORMATION (CONT’D.)

assets and known developments, (2) the expected 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 judgments about oil and gas reserves, future prices, timing of future net cash flows and market premiums. The effect of synergies is embedded in the value of producing assets, known developments and exploration assets. Significant extended declines in crude oil and natural gas prices, reduced reserve estimates or failure to recognize synergies could lead to a decrease in the fair value of the exploration and production operating segment that could result in an impairment of goodwill. In addition, changes in management structure or sales or dispositions of a portion of the exploration and production segment may result in goodwill impairment.

As explained above, there are significant differences in the way long-lived assets and goodwill are evaluated and measured for impairment testing. Consequently, there may be impairments of individual assets which would not cause an impairment of the $977 million of goodwill assigned to the exploration and production segment. In 2002, the Corporation recognized asset impairments because reduced estimates of oil and gas production volumes caused the expected undiscounted cash flows of the assets to be lower than the asset carrying amounts. No impairment of goodwill exists because the fair value of the overall exploration and production operating segment continues to exceed its recorded book value.

The Corporation has two operating segments, exploration and production, and refining and marketing. 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 to make decisions about resources to be allocated to the segment and assess its performance and (iii) for which discrete financial information is available. Mr. John B. Hess, Chairman of the Board and Chief Executive Officer of the Corporation, is the chief operating decision maker (“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. Mr. Hess uses only the operating results of each segment as a whole to make decisions about resources to be allocated to each segment and to assess the segment performance. The CODM manages each segment globally and does not regularly review the operating results of any component (e.g., geographic area) or asset within each segment or any information by geographical location, oil and gas property or project, subsidiary or division, to make decisions about resources to be allocated or to assess performance. While the CODM does review and approve initial corporate funding for a new project using information about the project, he does not review

PART I — FINANCIAL INFORMATION (CONT’D.)

subsequent operating results by project after the initial funding. Each operating segment has one manager. The segment managers are responsible for allocating resources within the segments, reviewing financial results of components within the segments, and assessing the performance of the components. The CODM evaluates the performance of the segment managers based on performance metrics related to each manager’s operating segment as a whole. The Board of Directors of the Corporation does not receive more detailed information than that used by the CODM to operate and manage the Corporation.

Other

As discussed in the Corporation’s 2002 Form 10-K and first quarter 2003 10-Q, as part of its initiative to monitor the public filings of Fortune 500 companies, the Staff of the Division of Corporation Finance of the Securities and Exchange Commission reviewed and commented on the Corporation’s Form 10-K for the year ended December 31, 2001 and certain quarterly and current reports on Forms 10-Q and 8-K filed or furnished thereafter and the 2002 Form 10-K. Almost all of these comments have been resolved. The Staff had questioned the Corporation’s determination that the exploration and production segment constitutes the reporting unit for its annual testing for impairment of goodwill, and considered whether components of the exploration and production segment should constitute reporting units for goodwill impairment testing. The Corporation has concluded discussions with the Staff on this issue. As requested by the Staff, the Corporation has made in this report and will continue to make in future reports additional disclosures in its Critical Accounting Policies regarding the impairment of goodwill, including the basis for its determination that the exploration and production segment is the reporting unit for testing goodwill and the circumstances in which goodwill could be impaired. The Staff is continuing to question the classification as proved reserves at December 31, 2002, of 38 million barrels of secondary recovery reserves associated with the waterflood program in the Ceiba Field. The Corporation and its independent reservoir engineer, DeGolyer and MacNaughton, believe the inclusion of the reserves in the proved category is appropriate. The Corporation is continuing its discussions with the Staff on this matter.

The oil and gas industry is currently discussing the appropriate balance sheet classification of oil and gas mineral rights held by lease or contract. The Corporation classifies these assets as property, plant and equipment in accordance with its interpretation of FAS No. 19 and common industry practice. There is also a view that these mineral rights are intangible assets as defined in FAS No. 141, Business Combinations, and, therefore, should be classified separately on the balance sheet as intangible assets. If the accounting for mineral rights held by lease or contract is ultimately changed, the Corporation believes that as of June 30, 2003 any such reclassification of mineral rights could amount to approximately $2.2 billion, if the Corporation is required to include the purchase price allocated to hydrocarbon reserves obtained in acquisitions of oil and gas properties. The determination of this amount is based on the Corporation’s current understanding of this evolving issue and how the provisions of FAS No. 141 might

PART I — FINANCIAL INFORMATION (CONT’D.)

be applied to oil and gas mineral rights. This potential balance sheet reclassification would not affect results of operations or cash flows.

Forward-Looking Information

Certain sections of Management’s Discussion and Analysis of Results of Operations and Financial Condition, including references to the Corporation’s future results of operations and financial position, liquidity and capital resources, capital expenditures, oil and gas production, debt repayment, income tax rates, hedging, and derivative disclosures, represent 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.

PART I — FINANCIAL INFORMATION (CONT’D.)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information required by this item is presented under Item 2, “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Market Risk Disclosure.”

Item 4. Controls and Procedures

Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a — 14(c) and 15d — 14(c)) as of June 30, 2003, John B. Hess, Chief Executive Officer, and John Y. Schreyer, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of June 30, 2003.

There have been no significant changes in the Corporation’s internal controls or in other factors that could significantly affect internal controls after June 30, 2003.

PART II- OTHER INFORMATION

Item 1. Legal Proceedings

A purported class action complaint was filed on May 27, 2003 in the United States District Court for the District of New Jersey by Martin Falk, an employee of the Registrant, on behalf of himself and other class members, against Amerada Hess Corporation, John B. Hess, John Y. Schreyer, members of Registrant’s Employee Benefit Plans Committee and other unnamed fiduciaries. The members of the purported class are participants in Registrant’s Savings and Stock Bonus Plan who maintained investments through the Plan in the Registrant’s common stock between February 9, 2001 and the present (the “Class Period”). The complaint alleges that the defendants breached their fiduciary duties under the Employment Retirement Income Security Act (“ERISA”) resulting in losses to plaintiff in Registrant’s common stock during the Class Period. Registrant believes this action is without merit.

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

The Annual Meeting of Stockholders of the Registrant was held on May 7, 2003. The Inspectors of Election reported that 79,180,610 shares of common stock of the Registrant were represented in person or by proxy at the meeting, constituting 88.06% of the votes entitled to be cast. At the meeting, stockholders voted upon the election of four nominees for the Board of Directors for the three-year term expiring in 2006, and the ratification of the selection by the Board of Directors of Ernst & Young LLP as the independent auditors of the Registrant for the fiscal year ended December 31, 2003.

With respect to the election of directors, the inspectors of election reported as follows:


	For		Withhold Authority to Vote
Name	Nominee Listed		For Nominee Listed

John B. Hess		77,585,110		1,595,500
Craig G. Matthews		78,422,519		758,091
John Y. Schreyer		78,379,351		801,259
Ernst H. von Metzsch		78,420,925		759,685

The inspectors reported that 75,702,356 votes were cast for the ratification of the selection of Ernst & Young LLP as independent auditors for the fiscal year ending December 31, 2003, 3,060,941 votes were cast against said ratification and holders of 417,313 votes abstained.

There were no broker non-votes with respect to the election of directors or the ratification of the selection of independent auditors.

PART II- OTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K

a. Exhibits


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)

b. Reports on Form 8-K

During the three months ended June 30, 2003, Registrant filed one report on Form 8-K dated April 29, 2003 furnishing under Items 9 and 12 the news release reporting its financial results for the first quarter of 2003.

SIGNATURES

Pursuant to the requirements 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.


		AMERADA HESS CORPORATION (REGISTRANT)

		By		/s/ John B. Hess

				JOHN B. HESS CHAIRMAN OF THE BOARD AND CHIEF EXECUTIVE OFFICER

		By		/s/ John Y. Schreyer

				JOHN Y. SCHREYER EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER

Date: August 12, 2003

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•		The Corporation operates its exploration and production segment as a single, global business.

•		Each component produces oil and gas.

•		The exploration and production processes are similar in each component.

•		The methods used by each component to market and distribute oil and gas are similar.

•		Customers of each component are similar, and

•		The components share resources and are supported by a worldwide exploration team and a shared services organization.

		The Annual Meeting of Stockholders of the Registrant was held on May 7, 2003. The Inspectors of Election reported that 79,180,610 shares of common stock of the Registrant were represented in person or by proxy at the meeting, constituting 88.06% of the votes entitled to be cast. At the meeting, stockholders voted upon the election of four nominees for the Board of Directors for the three-year term expiring in 2006, and the ratification of the selection by the Board of Directors of Ernst & Young LLP as the independent auditors of the Registrant for the fiscal year ended December 31, 2003.

		With respect to the election of directors, the inspectors of election reported as follows:

		The inspectors reported that 75,702,356 votes were cast for the ratification of the selection of Ernst & Young LLP as independent auditors for the fiscal year ending December 31, 2003, 3,060,941 votes were cast against said ratification and holders of 417,313 votes abstained.

		There were no broker non-votes with respect to the election of directors or the ratification of the selection of independent auditors.

	b.		Reports on Form 8-K

			During the three months ended June 30, 2003, Registrant filed one report on Form 8-K dated April 29, 2003 furnishing under Items 9 and 12 the news release reporting its financial results for the first quarter of 2003.