SEC Filing | Hess Corporation

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AMERADA HESS CORP.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended September 30, 2003


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)

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

At September 30, 2003, 89,876,430 shares of Common Stock were outstanding.

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements.
		STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)
		CONSOLIDATED BALANCE SHEET
		STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)
		NOTES TO CONSOLIDATED 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 6. Exhibits and Reports on Form 8-K
SIGNATURES
SECTION 302 CERTIFICATION OF CEO
SECTION 302 CERTIFICATION OF CFO
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					Nine months
	ended September 30					ended September 30
	2003		*2002()**			2003		*2002()**
REVENUES AND NON-OPERATING INCOME
Sales (excluding excise taxes) and other operating revenues	$	3,230	$	2,724		$	10,683	$	8,345
Non-operating income (expense)
Gain on asset sales		—		68			39		129
Equity in income (loss) of HOVENSA L.L.C		43		(6	)		108		(50	)
Other		23		12			42		62

Total revenues and non-operating income		3,296		2,798			10,872		8,486


COSTS AND EXPENSES
Cost of products sold		2,194		1,650			7,423		5,175
Production expenses		207		197			589		522
Marketing expenses		171		144			508		500
Exploration expenses, including dry holes and lease impairment		59		103			253		206
Other operating expenses		44		40			144		122
General and administrative expenses		70		70			252		192
Interest expense		73		61			224		194
Depreciation, depletion and amortization		253		274			799		853
Asset impairment		—		318			—		318


Total costs and expenses		3,071		2,857			10,192		8,082


Income (loss) from continuing operations before income taxes		225		(59	)		680		404
Provision for income taxes		79		46			282		249


Income (loss) from continuing operations		146		(105	)		398		155

Discontinued operations
Net gain from asset sales		—		—			116		—
Income (loss) from operations		—		(31	)		53		(2	)
Cumulative effect of change in accounting principle		—		—			7		—


NET INCOME (LOSS)	$	146	$	(136	)	$	574	$	153


BASIC EARNINGS PER SHARE
Continuing operations	$	1.65	$	(1.19	)	$	4.49	$	1.75
Net income (loss)		1.65		(1.54	)		6.48		1.74

DILUTED EARNINGS PER SHARE
Continuing operations	$	1.64	$	(1.19	)	$	4.47	$	1.73
Net income (loss)		1.64		(1.54	)		6.45		1.72

WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING		89.1		88.3			89.1		89.3

COMMON STOCK DIVIDENDS PER SHARE	$	.30	$	.30		$	.90	$	.90

(*)

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)


	September 30,
	2003			December 31,
	(Unaudited)			2002
A S S E T S
CURRENT ASSETS
Cash and cash equivalents	$	339		$	197
Accounts receivable		1,502			1,972
Inventories		560			492
Other current assets		137			95

Total current assets		2,538			2,756


INVESTMENTS AND ADVANCES
HOVENSA L.L.C.		950			842
Other		98			780

Total investments and advances		1,048			1,622


PROPERTY, PLANT AND EQUIPMENT
Total — at cost		16,384			16,149
Less reserves for depreciation, depletion, amortization and lease impairment		8,442			9,117

Property, plant and equipment — net		7,942			7,032


NOTES RECEIVABLE		302			363


GOODWILL		977			977


DEFERRED INCOME TAXES AND OTHER ASSETS		404			512


TOTAL ASSETS	$	13,211		$	13,262


L I A B I L I T I E S A N D S T O C K H O L D E R S ’ E Q U I T Y

CURRENT LIABILITIES
Accounts payable — trade	$	1,098		$	1,401
Accrued liabilities		679			830
Taxes payable		209			306
Notes payable		—			2
Current maturities of long-term debt		189			14

Total current liabilities		2,175			2,553


LONG-TERM DEBT		4,301			4,976


DEFERRED LIABILITIES AND CREDITS
Deferred income taxes		1,083			1,044
Asset retirement obligations		464			—
Other		474			440

Total deferred liabilities and credits		2,021			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 - 89,876 shares at September 30, 2003; 89,193 shares at December 31, 2002		90			89
Capital in excess of par value		963			932
Deferred compensation		(30	)		—
Retained earnings		3,975			3,482
Accumulated other comprehensive loss		(284	)		(254	)

Total stockholders’ equity		4,714			4,249


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	13,211		$	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)
Nine months ended September 30
(in millions)


	2003			*2002()**
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	574		$	153
Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization		799			853
Asset impairment		—			318
Exploratory dry hole costs		107			97
Lease impairment		47			33
Pre-tax gain on asset sales		(244	)		(103	)
Provision (benefit) for deferred income taxes		170			(70	)
Undistributed earnings of affiliates		(121	)		52
Non-cash effect of discontinued operations		46			236
Changes in operating assets and liabilities		(219	)		(142	)

Net cash provided by operating activities		1,159			1,427


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(1,015	)		(1,207	)
Payment received on note		61			48
Proceeds from asset sales and other		525			363

Net cash used in investing activities		(429	)		(796	)


CASH FLOWS FROM FINANCING ACTIVITIES
Debt with maturities of 90 days or less — decrease		(2	)		(574	)
Debt with maturities of greater than 90 days Borrowings		—			602
Repayments		(478	)		(569	)
Cash dividends paid		(108	)		(107	)
Stock options exercised		—			28

Net cash used in financing activities		(588	)		(620	)


NET INCREASE IN CASH AND CASH EQUIVALENTS		142			11

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		197			37


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	339		$	48

(*)

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 September 30, 2003 and December 31, 2002, and the consolidated results of operations for the three- and nine-month periods ended September 30, 2003 and 2002 and the consolidated cash flows for the nine-month periods ended September 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, as updated by Form 8-K filed on November 6, 2003. Certain information in the financial statements and notes has been reclassified to conform with current period presentation.

Note 2	-	In the first nine months of 2003, the Corporation took initiatives to reshape its portfolio of exploration and production segment assets to reduce costs, lengthen reserve lives, provide capital for investment and reduce debt.

		In the first quarter of 2003, 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 charge to income of $51 million before income taxes, 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 pre-tax 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 $26 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 pretax earnings in Colombia prior to the exchange of $18 million. At the time of the exchange, the exploration and production segment included the net book value of fixed assets in Colombia of $670 million and a related deferred income tax liability of $142 million.

		In this 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 and now is consolidated.

		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 pre-tax gain from disposition was $248 million. With respect to the assets sold in the second quarter of

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		2003, the net book value of fixed assets at the time of sale was approximately $295 million and the related dismantlement and deferred tax liabilities were approximately $160 million. Income from operations of these assets prior to sale amounted to $40 million in the first nine months of 2003.

		Sales and other operating revenues (net of intercompany sales) from discontinued operations were $97 million and $291 million in the first nine months of 2003 and 2002, respectively. The net production from fields sold or exchanged in 2003 at the time of disposition was approximately 45,000 barrels of oil equivalent per day.

		During the third quarter of 2003, the Corporation completed the exchange of its 25% equity investment in Premier Oil plc for a 23% interest in Natuna Sea, Block A, in Indonesia.

		On October 1, 2003, the Corporation exchanged 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% and the Telford Field to 17%

Note 3	-	Inventories consist of the following (in millions):


	At			At
	September 30,			December 31,
	2003			2002
Crude oil and other charge stocks	$	132		$	99
Refined and other finished products		512			497
Less: LIFO adjustment		(257	)		(261	)

		387			335
Materials and supplies		173			157

Total inventories	$	560		$	492

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 4		-		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
	September 30,			December 31,
	2003			2002
Summarized balance sheet
Current assets	$	732		$	520
Net fixed assets		1,835			1,895
Other assets		37			40
Current liabilities		(310	)		(335	)
Long-term debt		(399	)		(467	)
Deferred liabilities and credits		(68	)		(45	)

Partners’ equity	$	1,827		$	1,608


	Three months					Nine months
	ended September 30					ended September 30
	2003		2002			2003		2002
Summarized income statement
Total revenues	$	1,506	$	1,054		$	4,070	$	2,622
Costs and expenses		1,419		1,065			3,851		2,720

Net income (loss)	$	87	$	(11	)	$	219	$	(98	)

Amerada Hess Corporation’s share	$	43	$	(6	)	$	108	$	(50	)


Note 5	-	During the three- and nine-month periods ended September 30, 2003, the Corporation capitalized interest of $9 million and $31 million, respectively, on major development projects ($26 million and $75 million during the corresponding periods of 2002).

Note 6	-	The provision for income taxes from continuing operations consisted of the following (in millions):


	Three months					Nine months
	ended September 30					ended September 30
	2003		2002			2003		2002
Current	$	10	$	107		$	143	$	316
Deferred		69		(61	)		139		(67	)

Total	$	79	$	46		$	282	$	249

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 7		-		Foreign currency gains (losses) amounted to the following (in millions):


	Three months				Nine months
	ended September 30				ended September 30
	2003		2002		2003			2002
Pre-tax foreign currency gains (losses)	$	2	$	6	$	(15	)	$	25


Note 8	-	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.

		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						Nine months
	ended September 30						ended September 30
	2003			2002			2003			2002
Net income (loss)	$	146		$	(136	)	$	574		$	153
Add nonvested common stock compensation expense included in net income, net of taxes		1			—			5			4
Less total stock-based employee compensation expense, net of taxes (*)		(1	)		(4	)		(5	)		(16	)

Pro forma net income (loss)	$	146		$	(140	)	$	574		$	141

Net income (loss) per share as reported
Basic	$	1.65		$	(1.54	)	$	6.48		$	1.74

Diluted	$	1.64		$	(1.54	)	$	6.45		$	1.72

Pro forma net income (loss) per share
Basic	$	1.65		$	(1.59	)	$	6.47		$	1.59

Diluted	$	1.64		$	(1.59	)	$	6.44		$	1.58

(*)

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


	Three months				Nine months
	ended September 30				ended September 30
	2003		2002		2003		2002
Common shares — basic		88,617		88,328		88,615		88,116
Effect of dilutive securities (equivalent shares) Nonvested common stock		317		—		255		477
Stock options		1		—		11		491
Convertible preferred stock		205		—		205		205

Common shares — diluted		89,140		88,328		89,086		89,289


				Earnings per share are as follows:


	Three months					Nine months
	ended September 30					ended September 30
	2003		2002			2003		2002
Basic
Continuing operations	$	1.65	$	(1.19	)	$	4.49	$	1.75
Discontinued operations		—		(.35	)		1.91		(.01	)
Cumulative effect of change in accounting principle		—		—			.08		—

Net income (loss)	$	1.65	$	(1.54	)	$	6.48	$	1.74

Diluted
Continuing operations	$	1.64	$	(1.19	)	$	4.47	$	1.73
Discontinued operations		—		(.35	)		1.90		(.01	)
Cumulative effect of change in accounting principle		—		—			.08		—

Net income (loss)	$	1.64	$	(1.54	)	$	6.45	$	1.72


Note 10		-		Comprehensive income was as follows (in millions):


	Three months					Nine months
	ended September 30					ended September 30
	2003		2002			2003			2002
Net income (loss)	$	146	$	(136	)	$	574		$	153
Net change in cash flow hedging activities		13		(100	)		(33	)		(352	)
Change in foreign currency translation adjustment		9		(2	)		3			26

Comprehensive income (loss)	$	168	$	(238	)	$	544		$	(173	)

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		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 $87 million before income taxes in the third quarter of 2003 and $321 million before income taxes in the first nine months of 2003. Hedging results were breakeven in the third quarter of 2002 and increased exploration and production results by $115 million before income taxes in the first nine months of 2002.

		At September 30, 2003, after-tax deferred losses from crude oil and natural gas contracts used as hedges and expiring through 2005 were $109 million ($72 million of unrealized losses and $37 million of realized losses).

Note 11	-	The Corporation’s results by operating segment were as follows (in millions):


	Three months						Nine months
	ended September 30						ended September 30
	2003			2002			2003			2002
Operating revenues
Exploration and production (*)	$	748		$	897		$	2,333		$	2,852
Refining and marketing		2,548			1,962			8,600			5,889

Total	$	3,296		$	2,859		$	10,933		$	8,741

Net income (loss)
Exploration and production	$	124		$	(116	)	$	331		$	273
Refining and marketing		89			70			272			65
Corporate, including interest		(67	)		(59	)		(205	)		(183	)

Income (loss) from continuing operations		146			(105	)		398			155
Discontinued operations		—			(31	)		169			(2	)
Income from cumulative effect of accounting change		—			—			7			—

Total	$	146		$	(136	)	$	574		$	153

(*)

Includes transfers to affiliates of $66 million and $250 million during the three- and nine-months ended September 30, 2003, compared to $135 million and $396 million for the corresponding periods of 2002.


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


	At		At
	September 30,		December 31,
	2003		2002
Identifiable assets
Exploration and production	$	8,977	$	8,392
Refining and marketing		3,805		4,218
Corporate		429		652

Total	$	13,211	$	13,262

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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. 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 nine months ended September 30, 2003. The effect of the change on the results for the nine months ended September 30, 2003, compared with the previous accounting method, was to increase income before the cumulative effect of the accounting change by $4 million, after-tax ($0.05 per share diluted).

		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, net of additions		(115	)
Accretion expense		18
Foreign currency translation		5

Asset retirement obligations at September 30, 2003	$	464


				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. 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 or net income.

				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.

PART I — FINANCIAL INFORMATION (CONT’D.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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

				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 any such reclassification of mineral rights could amount to approximately $2.4 billion at September 30, 2003 and $2.2 billion at December 31, 2002, 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 be applied to oil and gas mineral rights. This potential balance sheet reclassification would not affect results of operations or cash flows.

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 third quarter of 2003 amounted to $146 million compared with a net loss of $136 million in the third quarter of 2002. Income in the third quarter of 2003 included an income tax benefit of $30 million reflecting the recognition for United States income tax purposes of certain prior year foreign exploration expenses. Results for the third quarter of 2002 included an after-tax impairment charge of $207 million ($318 million before income taxes). Net income for the first nine months of 2003 was $574 million compared with $153 million in the first nine months of 2002. The after-tax results by major operating activity for the three- and nine-months ended September 30, 2003 and 2002 were as follows (in millions, except per share data):


	Three months ended						Nine months ended
	September 30						September 30
	2003			2002(*)			2003			2002(*)
Exploration and production	$	124		$	(116	)	$	331		$	273
Refining and marketing		89			70			272			65
Corporate		(25	)		(23	)		(73	)		(56	)
Interest expense		(42	)		(36	)		(132	)		(127	)

Income (loss) from continuing operations		146			(105	)		398			155
Discontinued operations
Net gains from asset sales		—			—			116			—
Income (loss) from operations		—			(31	)		53			(2	)
Income from cumulative effect of accounting change		—			—			7			—

Net income (loss)	$	146		$	(136	)	$	574		$	153

Income (loss) per share from continuing operations (diluted)	$	1.64		$	(1.19	)	$	4.47		$	1.73

Net income (loss) per share (diluted)	$	1.64		$	(1.54	)	$	6.45		$	1.72

(*)

Reclassified to conform to current period presentation.

In the discussion which 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 explanation of variances in segment earnings. Such after-tax amounts may be considered to be non-GAAP financial measures. Management believes that they 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.

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

Exploration and Production

Exploration and production earnings from continuing operations include the following after-tax items in the third quarter and first nine months of 2003 and 2002 (in millions):


	Three months ended					Nine months ended
	September 30					September 30
	2003		2002			2003			2002
United States income tax benefit	$	30	$	—		$	30		$	—
Accrued severance and London office lease costs		—		—			(23	)		—
Asset impairment		—		(207	)		—			(207	)
Gains (losses) from asset sales		—		(22	)		31			20
Charge for increase in United Kingdom income tax rate		—		(43	)		—			(43	)

	$	30	$	(272	)	$	38		$	(230	)

The following table contains the pre-tax amounts of the items included above on an after-tax basis:


	Three months ended					Nine months ended
	September 30					September 30
	2003		2002			2003			2002
Accrued severance and London office lease costs	$	—	$	—		$	(38	)	$	—
Asset impairment		—		(318	)		—			(318	)
Gains (losses) from asset sales		—		(35	)		47			27

	$	—	$	(353	)	$	9		$	(291	)

After reflecting the after-tax variances in the table above, exploration and production earnings in the third quarter and first nine months of 2003 decreased by $62 million and $210 million compared with the corresponding periods of 2002. These decreases were primarily due to lower crude oil and natural gas sales volumes.

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 ended				Nine months ended
	September 30				September 30
	2003		2002		2003		2002
Crude oil (per barrel)
United States	$	24.33	$	26.19	$	23.97	$	24.41
Foreign		24.72		26.08		24.79		24.66

Natural gas liquids (per barrel)
United States	$	22.00	$	16.08	$	23.64	$	14.73
Foreign		23.33		19.73		22.95		18.05

Natural gas (per Mcf)
United States	$	3.53	$	3.47	$	4.03	$	3.54
Foreign		2.54		2.17		2.73		2.17

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


	Three months ended				Nine months ended
	September 30				September 30
	2003		2002		2003		2002
Crude oil (barrels per day)
United States		41		53		45		56
United Kingdom		78		112		92		113
Equatorial Guinea		21		39		24		39
Norway		22		26		23		24
Denmark		24		20		24		21
Algeria		23		15		19		14
Gabon		11		8		10		9
Indonesia		—		4		2		5
Azerbaijan		2		4		2		4
Colombia		—		21		4		22

Total		222		302		245		307

Natural gas liquids (barrels per day)
United States		12		12		11		13
Foreign		7		9		9		9

Total		19		21		20		22

Natural gas (Mcf per day)
United States		216		355		266		390
United Kingdom		262		227		303		275
Denmark		30		30		31		36
Norway		24		28		26		25
Indonesia and Thailand		59		63		54		42

Total		591		703		680		768

Barrels of oil equivalent (per day) () (*)		339		441		378		456

(*) Includes production related to discontinued operations		—		51		17		53


(**) Reflects natural gas production converted based on 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 23% in the third quarter and 17% in the first nine months 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. The remainder of the decreases are principally due to natural decline in the United States and North Sea and reduced production from the Ceiba Field in Equatorial Guinea.

In the third quarter of 2003, the Corporation exchanged its 25% equity investment in Premier Oil Plc for a 23% interest in the Indonesian Natuna A Field. In the fourth quarter, the Corporation has also exchanged 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, plus $17 million in cash. Production from the Llano Field is scheduled to commence mid-year 2004.

These transactions along with asset sales and the Colombia/JDA exchange in the first half of the year will contribute to a decline in production in 2004. Production in 2004 is expected to be approximately 12% below projected full year 2003 production of approximately 370 thousand barrels of oil equivalent per day. Approximately 40% of the decline is due to asset sales and exchanges and the remainder is due to natural decline.

Production expenses increased in the third quarter and first nine months of 2003 compared with 2002, reflecting higher per barrel costs, including increased transportation, insurance and workover costs. Depreciation, depletion and amortization charges were lower in the third quarter and first nine months of 2003 principally reflecting lower production volumes. General and administrative expenses relating to exploration and production activities were comparable in the third quarter of 2003 and 2002, but higher in the first nine months of 2003, largely due to 2003 charges for accrued severance in London, Aberdeen and Houston and costs of a reduction in leased office space in London. Exploration expense was lower in the third quarter of 2003 compared with 2002, reflecting the timing of exploration drilling and higher capitalization of drilling costs in the 2003 quarter.

After-tax foreign currency losses amounted to $3 million ($2 million gain before income taxes) in the third quarter of 2003 and $16 million ($15 million before income taxes) in the first nine months of 2003, compared with income of $11 million and $15 million ($6 million and $25 million before income taxes) in the corresponding periods of 2002. The pre-tax amounts of foreign currency gains and 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 nine months of 2003 was 52%. This rate includes income taxes in excess of the United States statutory rate in several producing areas, such as the United Kingdom and Norway. It also reflects the income tax deduction for the Corporation’s hedging results at only the U.S. statutory rate. In addition, certain expenses in foreign jurisdictions are not deductible for income tax purposes, or are benefited at rates equal to or below the U.S. statutory rate. Each of these factors

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

increases the Corporation’s overall exploration and production effective income tax rate. The full year 2003 exploration and production effective income tax rate is expected to be comparable to the rate for the first nine months of the year.

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 $89 million in the third quarter of 2003 compared with $70 million in the corresponding period of 2002. For the first nine months of 2003, refining and marketing earnings were $272 million compared with income of $65 million in 2002. Refining and marketing earnings include the following after-tax items in the third quarter and first nine months of 2003 and 2002 (in millions):


	Three months ended				Nine months ended
	September 30				September 30
	2003		2002		2003			2002
Gains (losses) from asset sales (1)	$	—	$	67	$	(20	)	$	67
Reduction in carrying value of intangible assets and accrued severance (2)		—		—		—			(22	)

	$	—	$	67	$	(20	)	$	45

(1)		The pre-tax amount of the 2002 asset sale was a gain of $102 million and the pre-tax loss related to the 2003 asset sale was $9 million.
(2)		The pre-tax amount of this charge was $35 million.

HOVENSA

The Corporation’s share of HOVENSA’s income was $43 million in the third quarter of 2003 compared with a loss of $6 million in the third quarter of 2002. The Corporation’s share of HOVENSA’s income in the first nine months of 2003 was $108 million compared with a loss of $50 million in the first nine months of 2002. The increase was due to higher refining margins and sales volumes in both periods compared to the prior year. 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 218,000 barrels per day in the first nine months of 2003 compared with 175,000 barrels per day in the first nine months 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

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

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 $23 million (before and after income taxes) in the first nine months of 2003 and $27 million in the first nine months 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 third quarter and first nine months of 2003 than in the corresponding periods of 2002, reflecting higher margins and increased sales volumes at gasoline stations. Earnings from energy marketing activities were also higher in the third quarter and first nine months of 2003. Energy marketing earnings were particularly strong during the early part of 2003 reflecting increased margins and sales volumes from the colder winter. Results of the Port Reading refining facility also improved in 2003 compared with 2002, reflecting improved refining margins.

Total refined product sales volumes increased by 11% to 114 million barrels in the first nine months 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 income of $3 million ($8 million before income taxes) in the third quarter of 2003 and income of $15 million ($26 million before income taxes) in the first nine months of 2003. Trading activities resulted in losses of $14 million ($20 million before income taxes) in the third quarter of 2002 and income of $4 million ($8 million before income taxes) in the first nine months 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 $25 million in the third quarter and $73 million in the first nine months of 2003, compared with $23 and $56 million in the same periods of 2002. Corporate expenses in the first nine months of 2003 include after-tax charges of $15 million ($27 million before income taxes) from early repayment of debt. The amount in the corresponding period of 2002 was $4 million ($10 million before income taxes). The pre-tax expense for early debt repayment is recorded in other non-operating income (expense) in the income statement.

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

Interest

After-tax interest expense amounted to $42 million in the third quarter of 2003 compared with $36 million in the third quarter of 2002 ($73 million and $61 million before income taxes, respectively). In the first nine months of 2003, after-tax interest expense amounted to $132 million compared with $127 million in the same period of 2002 ($224 million and $194 million before income taxes). Interest incurred in the third quarter and first nine months of 2003 was lower than in 2002 because of debt reduction, however, the reduction in interest incurred was more than offset by lower interest capitalized in 2003. Pre-tax capitalized interest amounted to $31 million in the first nine months of 2003 compared with $75 million in the corresponding period of 2002.

Discontinued Operations

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 an after-tax charge to income in the first quarter of 2003 of $47 million ($51 million before income taxes), 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. 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 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 ($248 million before income taxes) was included in discontinued operations in the second quarter of 2003. Discontinued operations in the first nine months of 2003 also includes $40 million of income from operations prior to the sales of these assets.

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.

PART I — FINANCIAL INFORMATION (CONT’D.)

Results of Operations (Continued)

Consolidated Operating Revenues

Sales and other operating revenues increased by 19% in the third quarter and 28% in the first nine months of 2003, compared with the corresponding periods of 2002. These increases principally reflect higher sales volumes of refined products and the increased selling price of purchased natural gas in energy marketing operations.

Liquidity and Capital Resources

Net cash provided by operating activities, including changes in operating assets and liabilities, amounted to $1,159 million in the first nine months of 2003 compared with $1,427 million in the first nine months of 2002.

In 2003, the Corporation has taken 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 late 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.

In the third quarter of 2003, the Corporation completed the exchange of its 25% equity investment in Premier Oil plc for a 23% interest in Natuna Sea Block A in Indonesia, plus approximately $10 million in cash (including closing adjustments). Current production from the Corporation’s 23% interest in Natuna is approximately 5,000 barrels of oil equivalent per day.

In October 2003, the Corporation exchanged 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% and the Telford Field to 17%. Production from the United Kingdom interests being transferred was approximately 10,000 barrels per day in the third quarter of 2003. Production from the Corporation’s 50% interest in the Llano Field is scheduled to commence in the second quarter of 2004.

PART I — FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (Continued)

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, and proceeds of issuances of securities under the shelf registration described below. The Corporation’s revolving credit 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 will be a modest increase in total debt over the next five quarters.

On November 6, 2003, the Corporation filed a shelf registration statement on Form S-3. This registration, when effective, will allow the Corporation to issue from time to time the following securities: debt securities, shares of common stock, shares of preferred stock and warrants to purchase common stock, preferred stock or debt securities. The aggregate initial offering price of all securities that could be issued by the Corporation under the registration statement will not exceed $1,500 million. The proceeds, if any, will be used for general corporate purposes, which may include working capital, capital expenditures, acquisitions and the reduction or refinancing of existing indebtedness.

Total debt decreased by $502 million at September 30, 2003 from $4,992 million at December 31, 2002. The Corporation’s debt to capitalization ratio was 48.8% at September 30, 2003 compared with 54.0% at December 31, 2002.

At September 30, 2003, loan agreement covenants allow the Corporation to borrow an additional $3.3 billion for the construction or acquisition of assets. The amount that can be borrowed under the loan agreements for the payment of dividends is $1.2 billion. At September 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 September 30, 2003, using interest rates inherent in the leases. The Corporation’s September 30 debt to capitalization ratio would increase from 48.8% to 51.2% if the lease financings were included.

PART I — FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (Continued)

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 changes 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 has restricted 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 require additional cash margin or collateral of up to approximately $43 million because of the downgrade. The Corporation estimates the change in credit ratings increased financing costs by less than $1 million annually.

In October 2003, one rating agency placed the Corporation’s long-term debt and commercial paper ratings under review for possible downgrade. If the Corporation’s credit rating were to be reduced by this agency 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 September 30, 2003 would increase by approximately $64 million. A downgrade below investment grade would increase annual financing costs by $5 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 September 30, 2003 amounted to $96 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 coker financial completion, as defined. At September 30, 2003, the Corporation’s pro-rata share of HOVENSA’s senior debt was $84 million after deducting HOVENSA funds available for debt service. In October 2003, coker financial completion was achieved and the maximum pro-rata share of funding became $40 million. After completion of construction required to meet final low sulfur fuel regulations, this amount reduces to $15 million.

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 nine months of 2003, the Corporation paid $3 million of charter support, reducing the reserve to $45 million.

PART I — FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (Continued)

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 that were eliminated in London, Aberdeen and Houston. Through September 30, approximately $4 million of the severance has been paid. Over 700 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 fourth quarter and 2004. Additional accruals for severance and lease costs of approximately $22 million before income taxes are anticipated over the next several quarters. The estimated annual savings from this cost reduction initiative is approximately $50 million before income taxes.

Capital expenditures in the first nine months of 2003 were $1,015 million of which $958 million related to exploration and production activities. Capital expenditures in the first nine months of 2002 were $1,207 million, including $1,101 million for exploration and production. Capital expenditures for the remainder of 2003 are currently estimated to be approximately $420 million. These expenditures are expected to be funded by available cash or cash flow from operations. Capital expenditures in 2004 excluding acquisitions, if any, are currently expected to be $1.5 billion.

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.

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

PART I — FINANCIAL INFORMATION (CONT’D.)

Market Risk Disclosure (Continued)

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 September 30, the Corporation has open hedge positions equal to 60% of its estimated 2003 worldwide crude oil production for the period October 1, 2003 to December 31, 2003, 60% of estimated 2004 worldwide crude oil production and 15% of estimated 2005 production. The average price for West Texas Intermediate (WTI) related open hedge positions is $26.38 in 2003, $24.62 in 2004 and $25.03 in 2005. The average price for Brent related open hedge positions is $24.34 in 2003, $23.74 in 2004 and $23.79 in 2005. Approximately 15% of the Corporation’s hedges are WTI related and the remainder are Brent. The Corporation has no open hedges of natural gas production at September 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 September 30, 2003, the value-at-risk for commodity related derivatives that are settled in cash and used in non-trading activities was $41 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 nine months of 2003 amounted to $35 million and net unrealized gains were $68 million. The following table provides a compilation of the factors affecting the changes in fair value of trading contracts in the first nine months of 2003 and represents 100% of the trading partnership and other trading activities (in millions):

PART I — FINANCIAL INFORMATION (CONT’D.)

Market Risk Disclosure (Continued)


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 September 30, 2003		32
Reversal of fair value for contracts closed during the period		(20	)
Fair value of contracts entered into during the period		56

Fair value of contracts outstanding at September 30, 2003	$	104

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 at September 30, 2003 follow (in millions):


			Instruments Maturing
	Total		2003		2004		2005		2006
Prices actively quoted	$	97	$	9	$	41	$	42	$	5
Other external sources		7		7		—		—		—

Total	$	104	$	16	$	41	$	42	$	5

The Corporation estimates that at September 30, 2003, the value-at-risk for trading activities, including commodities, was $9 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 September 30, 2003 (in millions):


Investment grade determined by outside sources	$	186
Investment grade determined internally*		48
Less than investment grade		28

Total	$	262

Based on information provided by counterparties and other available sources.

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.

PART I — FINANCIAL INFORMATION (CONT’D.)

Critical Accounting Policies (Continued)

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 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 that 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,

PART I — FINANCIAL INFORMATION (CONT’D.)

Critical Accounting Policies (Continued)

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.

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 if 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.

•

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 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

PART I — FINANCIAL INFORMATION (CONT’D.)

Critical Accounting Policies (Continued)

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 realize 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 that 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: (1) exploration and production and (2) 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 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.

PART I — FINANCIAL INFORMATION (CONT’D.)

Critical Accounting Policies (Continued)

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 any such reclassification of mineral rights could amount to approximately $2.4 billion at September 30, 2003 and $2.2 billion at December 31, 2002, 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 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, tax rates, debt repayment, hedging, derivative and environmental 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 September 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 September 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 September 30, 2003.

PART II — OTHER INFORMATION


Item 1.		Legal Proceedings

On August 11, 2003 a purported class action complaint was filed in the United States District Court for the District of New Jersey by Michael Kennedy, on behalf of himself and other class members, against Amerada Hess Corporation, John B. Hess, John Y. Schreyer, members of the 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. This complaint is substantially identical to an earlier purported class action complaint filed by Martin Falk in May 2003. Registrant believes these actions are without merit.

As reported in the Corporation’s Form 10-K annual report for 2002, over the last five years, many refiners have entered into consent agreements to resolve EPA’s assertions that these 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 which 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. EPA contacted the Corporation and HOVENSA regarding the petroleum refinery initiative in August, 2003. While EPA has not made any specific assertions that the Corporation or HOVENSA violated the New Source Review regulations, the Corporation and HOVENSA expect to have further discussions with EPA regarding the petroleum refining initiative.

The Corporation, along with 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, have been recently filed in jurisdictions across the United States against refiners and producers of MTBE. The principal allegation is that gasoline containing MTBE is a defective product and that these parties are strictly liable for damage to groundwater resources and required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. Additional property damage and personal injury lawsuits and claims related to the use of MTBE are expected. Prior product liability based litigation has been resolved without a material effect on the Corporation and the United States Congress is considering a limitation on product liability lawsuits for the use of MTBE in gasoline. While the damages claimed in these actions is substantial, Registrant believes, based on current factual and legal circumstances, that these actions will not have a material adverse effect on its financial condition.

PART II — OTHER INFORMATION (CONT’D.)


Item 6.		Exhibits and Reports on Form 8-K

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)

Reports on Form 8-K

During the three months ended September 30, 2003, Registrant filed one report on Form 8-K dated July 29, 2003 furnishing under Items 9 and 12 the news release reporting its financial results for the second 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: November 12, 2003

SECTION 302 CERTIFICATION OF CEO

Exhibit 31(1)

CERTIFICATIONS

I, John B. Hess, certify that:

I have reviewed this quarterly report on Form 10-Q of Amerada Hess Corporation;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

SECTION 302 CERTIFICATION OF CFO

Exhibit 31(2)

I, John Y. Schreyer, certify that:

I have reviewed this quarterly report on Form 10-Q of Amerada Hess Corporation;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

SECTION 906 CERTIFICATION OF CEO

Exhibit 32(1)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Amerada Hess Corporation (the “Corporation”) on Form 10-Q for the period ending September 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John B. Hess, Chairman of the Board and Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

A signed original of this written statement required by Section 906 has been provided to Amerada Hess Corporation and will be retained by Amerada Hess Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

SECTION 906 CERTIFICATION OF CFO

Exhibit 32(2)

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Amerada Hess Corporation (the “Corporation”) on Form 10-Q for the period ending September 30, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Y. Schreyer, Executive Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

/s/ John B. Hess

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

Date: November 12, 2003