Noble Energy (NBL) 8-K Financial Statements and Supplementary Data

EXHIBIT 99.1

Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Independent Auditors’ Report

To the Shareholders and Board of Directors of Noble Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2002 and December 31, 2001, and the related consolidated statements of operations, shareholders’ equity and other comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

	KPMG LLP
Houston, Texas
December 23, 2003

2

CONSOLIDATED BALANCE SHEETS

NOBLE ENERGY, INC. AND SUBSIDIARIES

	December 31,
(in thousands, except share amounts)	2002			2001
ASSETS
Current Assets:
Cash and short-term investments	$	15,442		$	73,237
Accounts receivable - trade	232,924			182,979
Oil and gas hedges receivable	10,271			33,424
Materials and supplies inventories	10,663			10,828
Other current assets	41,074			51,103
Total current assets	310,374			351,571
Property, Plant and Equipment, at Cost:
Oil and gas mineral interests, equipment and facilities (successful efforts method of accounting)	4,285,508			3,929,226
Other	48,507			45,528
	4,334,015			3,974,754
Accumulated depreciation, depletion and amortization	(2,194,230		)	(2,021,543		)
Total property, plant and equipment, net	2,139,785			1,953,211
Investment in Unconsolidated Subsidiary	234,668			242,142
Other Assets	45,188			57,331
Total Assets	$	2,730,015		$	2,604,255
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	351,856		$	270,091
Short-term note payable				25,000
Current installments of long-term debt	41,919			19,507
Oil and gas hedges payable	32,285			25,363
Other current liabilities	36,159			41,090
Income taxes - current	9,535
Total current liabilities	471,754			381,051
Deferred Income Taxes	201,939			176,259
Other Deferred Credits and Noncurrent Liabilities	69,820			75,629
Long-term Debt	977,116			961,118
Shareholders’ Equity:
Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
Common stock - par value $3.33 1/3; 100,000,000 shares authorized; 59,868,067 and 59,511,323 shares issued in 2002 and 2001, respectively	199,558			198,369
Capital in excess of par value	405,271			396,104
Accumulated other comprehensive income (loss)	(14,603		)	5,070
Retained earnings	458,490			449,985
	1,048,716			1,049,528
Less common stock in treasury at cost (December 31, 2002 and 2001, 2,505,522 shares)	(39,330		)	(39,330		)
Total shareholders’ equity	1,009,386			1,010,198
Total Liabilities and Shareholders’ Equity	$	2,730,015		$	2,604,255

See accompanying Notes to Consolidated Financial Statements.

3

CONSOLIDATED STATEMENTS OF OPERATIONS

NOBLE ENERGY, INC. AND SUBSIDIARIES

	Year ended December 31,
(in thousands, except per share amounts)	2002			2001			2000
Revenues:
Oil and gas sales and royalties	$	618,129		$	726,842		$	647,344
Gathering, marketing and processing	64,517			64,640			62,328
Electricity sales	18,257
Income from investment in unconsolidated subsidiary	9,532			6,981			13,544
Other income	1,246			953			7,441
Total Revenues	711,681			799,416			730,657
Costs and Expenses:
Oil and gas operations	107,734			107,631			95,994
Transportation	16,441			16,012			9,241
Oil and gas exploration	150,701			152,096			84,868
Gathering, marketing and processing	53,982			51,932			46,661
Electricity generation	15,946
Depreciation, depletion and amortization	239,325			236,111			187,316
Selling, general and administrative	47,664			44,164			47,291
Interest	64,040			53,960			50,023
Interest capitalized	(16,331		)	(15,953		)	(6,326		)
Total Costs and Expenses	679,502			645,953			515,068
Income Before Taxes	32,179			153,463			215,589
Income Tax Provision:
Current	3,978			6,694			45,253
Deferred	17,322			59,440			33,270
Total Tax Provision	21,300			66,134			78,523
Income From Continuing Operations	10,879			87,329			137,066
Discontinued Operations, Net of Tax	6,773			46,246			54,531
Net Income	$	17,652		$	133,575		$	191,597
Basic Earnings Per Share
Income From Continuing Operations	$	0.19		$	1.54		$	2.45
Discontinued Operations, Net of Tax	$	0.12		$	0.82		$	0.97
Net Income	$	0.31		$	2.36		$	3.42
Diluted Earnings Per Share
Income From Continuing Operations	$	0.19		$	1.52		$	2.42
Discontinued Operations, Net of Tax	$	0.12		$	0.81		$	0.96
Net Income	$	0.31		$	2.33		$	3.38
Weighted Average Shares Outstanding:
Basic	57,196			56,549			55,999
Diluted	57,763			57,303			56,755

See accompanying Notes to Consolidated Financial Statements.

4

CONSOLIDATED STATEMENTS OF CASH FLOWS

NOBLE ENERGY, INC. AND SUBSIDIARIES

	Year ended December 31,
(in thousands)	2002			2001			2000
Cash Flows from Operating Activities:
Net income	$	17,652		$	133,575		$	191,597
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas operations	239,325			236,111			187,316
Depreciation, depletion and amortization - electricity generation	8,458
Dry hole expense	81,396			99,684			38,463
Amortization of unproved leasehold costs, net	21,254			17,213			16,075
Non-cash effect of discontinued operations	45,961			47,905			43,484
Gain on disposal of assets	(106		)	(2,098		)	(3,799		)
Noncurrent deferred income taxes	18,192			59,212			33,973
Income from unconsolidated subsidiary	(9,532		)	(6,981		)	(13,544		)
Dividends received from unconsolidated subsidiary	17,696
Increase (decrease) in other deferred credits	(5,810		)	13,990			7,762
(Increase) decrease in other	10,942			(2,224		)	(3,747		)
Changes in operating assets and liabilities, not including cash:
(Increase) decrease in accounts receivable	(49,945		)	57,973			(137,049		)
(Increase) decrease in other current assets	21,972			(64,951		)	3,557
Increase (decrease) in accounts payable	81,764			(17,960		)	198,871
Increase (decrease) in other current liabilities	5,072			52,313			(4,644		)
Net Cash Provided by Operating Activities	504,291			623,762			558,315
Cash Flows from Investing Activities:
Capital expenditures	(595,739		)	(738,706		)	(536,901		)
Investment in unconsolidated subsidiary	(7,652		)	(36,641		)	(45,026		)
Proceeds from sale of property, plant and equipment	20,363			1,434			12,608
Distribution from unconsolidated subsidiary	5,500
Aspect acquisition				(107,078		)
Cash obtained in acquisition				9,286
Net Cash Used in Investing Activities	(577,528		)	(871,705		)	(569,319		)
Cash Flows from Financing Activities:
Exercise of stock options	10,356			16,675			13,717
Cash dividends paid	(9,147		)	(9,042		)	(8,958		)
Proceeds from bank debt	158,669			675,000			137,000
Repayment of bank debt	(124,929		)	(375,000		)	(57,000		)
Repayment of notes payable - unconsolidated subsidiary							(23,245		)
Repayment of note payable obtained in Aspect acquisition	(19,507		)	(9,605		)
Purchase of treasury stock							(30,283		)
Net Cash Provided by Financing Activities	15,442			298,028			31,231
Increase (Decrease) in Cash and Short-term Cash Investments	(57,795		)	50,085			20,227
Cash and Short-term Cash Investments at Beginning of Year	73,237			23,152			2,925
Cash and Short-term Cash Investments at End of Year	$	15,442		$	73,237		$	23,152
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized)	$	26,321		$	26,590		$	32,976
Income taxes paid (refunded)	$	(40,394	)	$	66,131		$	56,890
Non-cash financing and investing activities:
Issuance of treasury stock for acquisition				$	14,238
Debt assumed in acquisition				$	40,043

See accompanying Notes to Consolidated Financial Statements.

5

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME

NOBLE ENERGY, INC. AND SUBSIDIARIES

(in thousands)	Comprehensive Income (Loss)			Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock (At Cost)			Total Shareholders’ Equity
December 31, 1999				$	195,231	$	360,983	$	142,813					$	(15,418	)	$	683,609
Net Income								191,597									191,597
Purchase of treasury stock														(30,283		)	(30,283		)
Exercise of stock options				1,441		12,276											13,717
Cash dividends ($.16 per share)								(8,958		)							(8,958		)
December 31, 2000				$	196,672	$	373,259	$	325,452					$	(45,701	)	$	849,682
Net Income	$	133,575						133,575									133,575
Hedge derivatives marked to market	5,070										5,070						5,070
Treasury stock issued for acquisition						7,867								6,371			14,238
Exercise of stock options				1,697		14,978											16,675
Cash dividends ($.16 per share)								(9,042		)							(9,042		)
Total	$	138,645
December 31, 2001				$	198,369	$	396,104	$	449,985		$	5,070		$	(39,330	)	$	1,010,198
Net Income	$	17,652						17,652									17,652
Reclassification of unrealized gains on hedges to net income, net of $.5 income tax	1										1						1
Change in fair value of cash flow hedges, net of income tax	(19,674		)								(19,674		)				(19,674		)
Exercise of stock options				1,189		9,167											10,356
Cash dividends ($.16 per share)								(9,147		)							(9,147		)
Total	$	(2,021	)
December 31, 2002				$	199,558	$	405,271	$	458,490		$	(14,603	)	$	(39,330	)	$	1,009,386

See accompanying Notes to Consolidated Financial Statements.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in tables, unless otherwise indicated, are in thousands, except per share amounts)

Note 1 - Summary of Significant Accounting Policies

Basis of Presentation and Consolidation

Accounting policies used by Noble Energy, Inc. and subsidiaries reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such policies are briefly discussed below. The consolidated accounts include Noble Energy, Inc. (the “Company” or “Noble Energy”) and the consolidated accounts of its wholly-owned subsidiaries. Effective December 31, 2001, Energy Development Corporation (“EDC”), a previously wholly-owned subsidiary of Samedan Oil Corporation (“Samedan”), was merged into Samedan, another previously wholly-owned subsidiary. Effective December 31, 2002, Samedan was merged into Noble Energy, Inc. Also effective December 31, 2002, Noble Trading, Inc. (“NTI”) was merged into Noble Gas Marketing, Inc. (“NGM”) under the new name of Noble Energy Marketing, Inc. (“NEMI”). Listed below are consolidated entities at December 31, 2002. All significant intercompany balances and transactions have been eliminated upon consolidation.

NOBLE ENERGY, INC.

LaTex Resources Inc.

Noble Energy Marketing, Inc.

Noble Gas Pipeline, Inc.

NPM, Inc.

Samedan North Sea, Inc.

Samedan of North Africa, Inc.

Atlantic Methanol Capital Company (“AMCCO”)

EDC Ireland

Samedan International

Machalapower Cia. Ltda.

Samedan, Mediterranean Sea

Samedan Transfer Sub

Samedan Vietnam Limited

Samedan, Mediterranean Sea, Inc.

Samedan of Tunisia, Inc.

Samedan Oil of Canada, Inc.

Samedan Oil of Indonesia, Inc.

Samedan Pipe Line Corporation

Samedan Royalty Corporation

EDC Australia, Ltd.

EDC Ecuador Ltd.

EDC Ecuador Limited

EDC Portugal Ltd.

EDC (UK) Limited

EDC (Denmark) Inc.

EDC (Europe) Limited

EDC (ISE) Limited

EDC (Oilex) Limited

Brabant Oil Limited

Energy Development Corporation (Argentina), Inc.

Energy Development Corporation (China), Inc.

Energy Development Corporation (HIPS), Inc.

Gasdel Pipeline System Incorporated

HGC, Inc.

Producers Service, Inc.

7

Nature of Operations

The Company is an independent energy company engaged, directly or through its subsidiaries or various arrangements with other companies, in the exploration, development, production and marketing of crude oil and natural gas. The Company has exploration, exploitation and production operations domestically and internationally. The domestic areas consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana, New Mexico and Texas); the Mid-Continent Region (Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, North Dakota, Wyoming and California). The international areas of operations include Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea (Israel), the North Sea (Denmark, Netherlands and United Kingdom) and Vietnam. The Company also markets domestic crude oil and natural gas production through NEMI.

Use of Estimates

The preparation of the consolidated financial statements requires management of the Company to make a number of estimates and assumptions relating to the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s estimates of crude oil and natural gas reserves are the most significant. All of the reserve data in this Form 8-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment; valuation allowances for receivables, inventories and deferred income tax assets; environmental liabilities; valuation of derivative instruments; and assets and obligations related to employee benefits. Actual results could differ from those estimates.

Foreign Currency Translation

The U.S. dollar is considered the primary currency for each of the Company’s international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Transaction gains or losses were not material in any of the periods presented and are included in other income on the statement of operations.

Materials and Supplies Inventories

Materials and supplies inventories, consisting principally of tubular goods and production equipment, are stated at the lower of cost or market, with cost being determined by the first-in, first-out method.

Property, Plant and Equipment

The Company accounts for its crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-production method based on proved developed crude oil and natural gas reserves on a property-by-property basis as estimated by Company engineers. Through December 31, 2002, estimated future restoration and abandonment costs are recorded by charges to DD&A expense over the productive lives of the related properties. The Company has provided $84.1 million for such future costs classified with accumulated DD&A in the December 31, 2002 balance sheet. The total estimated future dismantlement and restoration costs of $206.6 million, which consists of $188.7 million for the United States and $17.9 million for the North Sea, are included in future production and development costs for purposes of estimating the future net revenues relating to the Company’s proved reserves. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

8

Individually significant unproved crude oil and natural gas properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized on a composite method based on the Company’s experience of successful drilling and average holding period. Geological and geophysical costs, delay rentals and costs to drill exploratory wells that do not find proved reserves are expensed. Repairs and maintenance are expensed as incurred.

Proved crude oil and natural gas properties and other long-lived assets are periodically assessed to determine if circumstances indicate that the carrying amount of an asset may not be recoverable. SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” was issued in August 2001. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This statement supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” This statement requires (a) recognition of an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and (b) measurement of an impairment loss as the difference between the carrying amount and fair value of the asset. The Company adopted the statement January 1, 2002 with no material impact on the Company’s results of operations or financial position. However, the Company has reclassified all years presented for the effect of discontinued operations arising from property sales in 2003 in accordance with provisions of SFAS No 144.

Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Capitalization of Interest

The Company capitalizes interest costs associated with the development and construction of significant properties or projects.

Statement of Cash Flows

For purposes of reporting cash flows, cash and short-term investments include cash on hand and investments purchased with original maturities of three months or less.

9

Basic Earnings Per Share and Diluted Earnings Per Share

Basic earnings per share (“EPS”) of common stock have been computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of common stock includes the effect of outstanding stock options. The following table summarizes the calculation of basic EPS and diluted EPS components as of December 31:

	2002					2001					2000
(in thousands except per share amounts)	Income (Numerator)				Shares (Denominator)	Income (Numerator)				Shares (Denominator)	Income (Numerator)				Shares (Denominator)
Net income/shares	$	17,652			57,196	$	133,575			56,549	$	191,597			55,999
Basic EPS			$	0.31				$	2.36				$	3.42
Net income/shares	$	17,652			57,196	$	133,575			56,549	$	191,597			55,999
Effect of Dilutive Securities
Stock options					567					754					756
Adjusted net income and shares	$	17,652			57,763	$	133,575			57,303	$	191,597			56,755
Diluted EPS			$	0.31				$	2.33				$	3.38

The table below reflects the amount of options not included in the EPS calculation above, as they were antidilutive.

	2002	2001	2000
Options excluded from dilution calculation	2,229,978	1,485,303	1,633,149
Range of exercise prices	$35.40 - $43.21	$38.88 - $43.21	$35.94 - $40.38
Weighted average exercise price	$39.77	$41.29	$38.39

Accounting for Employee Stock-Based Compensation

At December 31, 2002, the Company has two stock-based employee compensation plans, which are described more fully in “Note 5 - Common Stock, Stock Options and Stockholder Rights.” The Company accounts for those plans under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. At issuance, stock-based employee compensation cost was reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.

(in thousands except per share amounts)	2002			2001			2000
Net income, as reported	$	17,652		$	133,575		$	191,597
Add: Stock-based compensation cost recognized, net of related tax effects	392						477
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(6,394		)	(7,538		)	(8,170		)
Pro forma net income	$	11,650		$	126,037		$	183,904
Earnings per share:
Basic - as reported	$	.31		$	2.36		$	3.42
Basic - pro forma	$	.20		$	2.23		$	3.28
Diluted - as reported	$	.31		$	2.33		$	3.38
Diluted - pro forma	$	.20		$	2.20		$	3.24

10

Fair value estimates are based on several assumptions and should not be viewed as indicative of the operations of the Company in future periods. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2002, 2001 and 2000, respectively, as follows:

(amounts expressed in percentages)	2002	2001	2000
Interest rate	4.78	5.46	6.25
Dividend yield	.43	.40	.40
Expected volatility	40.26	38.19	51.67
Expected life	9.73	9.64	9.71

The weighted average fair value of options granted using the Black-Scholes option pricing model for 2002, 2001 and 2000, respectively, is as follows:

	2002		2001		2000
Black-Scholes model weighted average fair value option price	$	18.14	$	23.86	$	16.66

Revenue Recognition and Gas Imbalances

Noble Energy generally recognizes revenue when the product is delivered to a third-party purchaser.

NEMI records third-party sales, including derivative transactions, as gathering, marketing and processing revenues. NEMI records the amount paid to third parties as gathering, marketing and processing costs and expenses.

The Company follows the entitlements method of accounting for its natural gas imbalances. Natural gas imbalances occur when the Company sells more or less natural gas than it is entitled to under its ownership percentage of total natural gas production. Any excess amount received above the Company’s share is treated as a liability. If less than the Company’s entitlement is received, the underproduction is recorded as a receivable. The Company records the non-current liability in other deferred credits and non-current liabilities, and the current liability in other current liabilities. The Company’s natural gas imbalance liabilities were $15.4 million and $15.5 million for 2002 and 2001, respectively. The Company records the non-current receivable in other assets and the current receivable in other current assets. The Company’s natural gas imbalance receivables were $20.1 million and $20.9 million for 2002 and 2001, respectively, and are valued at the amount that is expected to be received.

Derivatives and Hedging Activities

The Company, directly or through its subsidiaries, from time to time, uses various hedging arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars and other contractual arrangements. Although these hedging arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties and believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company’s crude oil and natural gas production are recorded in oil and gas sales and royalties.

The FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” in June 1998. The Statement established accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders’ equity as other comprehensive income until the hedged item is recognized. Special accounting for qualifying hedges allows a

11

derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this statement did not have a material impact on the Company’s results of operations or financial position, as of the date of adoption. At December 31, 2002, the Company recorded crude oil and natural gas hedge liabilities of $22.5 million and other comprehensive loss, net of tax, of $14.6 million related to the Company’s hedging contracts.

Self-Insurance

The Company self-insures the medical and dental coverage provided to certain of its employees, certain workers’ compensation and the first $250,000 of its general liability coverage.

Liabilities are accrued for self-insured claims when sufficient information is available to reasonably estimate the amount of the loss.

Unconsolidated Subsidiary

The Company owns a 45 percent interest in AMPCO through its ownership in AMCCO. Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due December 15, 2004 to fund the remaining construction payments. The Company includes the $125 million series A-2 senior notes in its balance sheet. On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. The terms of the $125 million Series A-2 Notes remain unchanged. The Company accounts for its investment in unconsolidated subsidiary under the equity method of accounting. AMPCO is an integral component of the Company’s natural gas operations as AMPCO’s function is to convert a portion of the Company’s natural gas reserves to methanol for sale. For more information, see “Note 9 - Unconsolidated Subsidiary” of this Form 8-K.

Reclassification

Certain reclassifications have been made to the 2000 and 2001 consolidated financial statements to conform to the 2002 presentation. These reclassifications are not material to the Company’s financial position.

Recently Issued Pronouncements

SFAS No. 143, “Accounting for Asset Retirement Obligations,” was issued in June 2001. This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The Company adopted SFAS No. 143 on January 1, 2003 and recognized, as the fair value of asset retirement obligations, $99.7 million related to the United States and $10.0 million related to the North Sea. The Company’s accumulated provision for future retirement obligations was $84.1 million at December 31, 2002. The Company has not determined the cumulative effect of adoption of this standard. The expected future retirement obligation for the United States is $188.7 million and for the North Sea is $17.9 million. The difference between the expected future retirement obligation and the fair value of the retirement obligation will be expensed beginning in 2003 based on the credit-adjusted risk-free rate of 8.5 percent until the asset retirement date.

SFAS No. 148, “Accounting for Stock-Based Compensation,” was issued in December 2002. This statement amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide for alternative methods of transition for an

12

entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure provisions of that statement to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation.

The Company currently accounts for stock-based employee compensation plans under the recognition and measurement principles of the APB Opinion No. 25, “Accounting for Stock Issued to Employees.” The Company has not determined if it will adopt the fair value provisions of SFAS No. 123.

Adoption of EITF 02-03

In June 2002, the EITF reached a consensus on certain issues contained in Topic 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” While the Company does not engage in energy trading activities, the EITF has expanded its definition of energy trading activities to include the marketing activities in which the Company is engaged. The Company has reclassified its statement of operations for all periods to present its gathering, marketing and processing activities on a net rather than a gross basis. The adoption of EITF 02-03 resulted in a decrease in revenues and a decrease in operating expenses of $650 million, $656 million and $528 million for the years ended December 31, 2002, 2001 and 2000, respectively. The adoption of EITF 02-03 had no effect on operating income or cash flow.

Note 2 - Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between two willing parties.

Cash, Short-Term Investments, Accounts Receivable and Accounts Payable

The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.

Crude Oil and Natural Gas Price Hedge Agreements

The fair value of crude oil and natural gas price hedges is the estimated amount the Company would receive or pay to terminate the hedge agreements at the reporting date taking into account creditworthiness of the hedging parties.

Long-Term Debt

The fair value of the Company’s long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturities.

The carrying amounts and estimated fair values of the Company’s financial instruments, including current items, as of December 31, for each of the years are as follows:

	2002						2001
(in thousands)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Crude oil and natural gas price hedge agreements	$	(22,520	)	$	(22,520	)	$	16,032		$	16,032
Long-term debt	$	(1,025,246	)	$	(1,039,216	)	$	(986,015	)	$	(996,540	)

13

Note 3 - Debt

A summary of debt at December 31 follows:

		December 31, 2002			December 31, 2001
(in thousands)		Debt		Percentage Interest Rate	Debt		Percentage Interest Rate
$400 million Credit Agreement, maturity date November 2006		$	380,000	2.47	$	380,000	3.00
Note obtained in Aspect acquisition, due May 2004		11,508		6.25	31,015		6.25
7 1/4% Notes Due 2023		100,000		7.25	100,000		7.25
8% Senior Notes Due 2027		250,000		8.00	250,000		8.00
7 1/4% Senior Debentures Due 2097		100,000		7.25	100,000		7.25
AMCCO Note, due December 2004		125,000		8.95	125,000		8.95
Israel Note, due 2003 and 2004		58,738		2.18
Outstanding debt		1,025,246			986,015
Less:	unamortized discount	6,211			5,390
	current installment of long-term debt	41,919			19,507
Long-term debt		$	977,116		$	961,118

The Company’s total long-term debt, net of unamortized discount, at December 31, 2002, was $977 million compared to $961 million at December 31, 2001. The ratio of debt-to-book capital (defined as the Company’s total debt plus its equity) was 50 percent at December 31, 2002, and 50 percent at December 31, 2001.

The Company entered into a new $400 million five-year credit agreement on November 30, 2001, with certain commercial lending institutions, which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million borrowed against this credit agreement, which has a maturity date of November 30, 2006.

The Company also entered into a new $200 million 364-day credit agreement on November 27, 2002 with certain commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 62.5 to 150 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there were no amounts outstanding under this credit agreement. The agreement has a maturity date of November 26, 2003 for the revolving commitment and a maturity date of November 25, 2004 for the term commitment that includes any balance remaining after the revolving commitment matures.

Financial covenants on both the $400 million and $200 million credit facilities include the following: (a) the ratio of EBITDAX to total interest expense for any consecutive period of four fiscal quarters ending on the last day of a fiscal quarter may not be less than 4.0 to 1.0; (b) the total debt to capitalization ratio, expressed as a percentage, may not exceed 60 percent at any time; and (c) the total asset value of the Company’s restricted subsidiaries may not be less than $800 million at any time.

The Company had no short-term borrowings outstanding on December 31, 2002. The Company had a $25 million short-term note payable outstanding December 31, 2001, which was repaid January 28, 2002. The note was an uncommitted facility with an interest rate of 3.25 percent for the period December 28, 2001 to January 28, 2002.

14

Note 4 - Income Taxes 

The following table details the difference between the federal statutory tax rate and the effective tax rate for the years ended December 31:

(amounts expressed in percentages)	2002		2001	2000
Statutory rate (benefit)	35.0		35.0	35.0
Effect of:
State taxes, net of federal benefit	1.1		.3	.3
Difference between U.S. and foreign rates	32.1		7.4	.6
Other, net	(2.0	)	.4	.5
Effective rate	66.2		43.1	36.4

The net current deferred tax asset (liability) in the following table is classified as other current assets in the consolidated balance sheet. The tax effects of temporary differences that gave rise to deferred tax assets and liabilities as of December 31 were:

(in thousands)	2002			2001
U.S. and State Current Deferred Tax Assets (Liabilities):
Accrued expenses	$	980		$	15
Deferred income	387			626
Allowance for doubtful accounts	353			226
Marked to market - hedging contracts	7,864			(2,730		)
Other				(17		)
Net U.S. and State Current Deferred Tax Assets (Liabilities)	9,584			(1,880		)
U.S. and State Non-current Deferred Tax Assets (Liabilities):
Property, plant and equipment, principally due to differences in depreciation, amortization, lease impairment and abandonments	(183,338		)	(177,382		)
Accrued expenses	4,777			7,125
Deferred income	4,594			6,029
Allowance for doubtful accounts	5,935			5,767
Foreign and state income tax accruals	11,940			11,627
Post retirement benefits	9,668			2,489
Other	(245		)	(245		)
Net U.S. and State Non-current Deferred Tax Assets (Liabilities)	(146,669		)	(144,590		)
Total Net U.S. and State Deferred Tax Assets (Liabilities)	(137,085		)	(146,470		)
Foreign Non-current Deferred Tax Assets (Liabilities):
Property, plant and equipment of foreign operations	(55,270		)	(31,669		)
Foreign loss carryforward	4,416			2,745
Net Foreign Non-current Deferred Tax Assets (Liabilities)	(50,854		)	(28,924		)
Valuation allowance	(4,416		)	(2,745		)
Total Net Deferred Tax Assets (Liabilities)	$	(192,355	)	$	(178,139	)

The components of income (loss) from continuing operations before income taxes as of December 31 for each year are as follows:

(in thousands)	2002			2001			2000
Domestic	$	(7,353	)	$	170,332		$	184,595
Foreign	39,532			(16,869		)	30,994
Total	$	32,179		$	153,463		$	215,589

15

The income tax provision (benefit) relating to operations consists of the following for the years ended December 31:

(in thousands)	2002			2001		2000
U.S. current	$	(7,945	)	$	24,743	$	65,358
U.S. deferred	1,421			53,591		32,311
State current	895			652		917
State deferred	(212		)	359		334
Foreign current	14,675			6,200		8,341
Foreign deferred	16,113			5,490		625
Total provision	24,947			91,035		107,886
Income tax provision associated with discontinued operations	3,647			24,901		29,363
Income tax provision associated with continuing operations	$	21,300		$	66,134	$	78,523

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 2002. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

Note 5 - Common Stock, Stock Options and Stockholder Rights

The Company has two stock option plans, the 1992 Stock Option and Restricted Stock Plan (“1992 Plan”) and the 1988 Non-Employee Director Stock Option Plan (“1988 Plan”). The Company accounts for these plans under APB Opinion No. 25.

Under the Company’s 1992 Plan, the Board of Directors may grant stock options and award restricted stock. No restricted stock has been issued under the 1992 Plan. Since the adoption of the 1992 Plan, stock options have been issued at the market price on the date of grant. The earliest the granted options may be exercised is over a three year period at the rate of 33 1/3% each year commencing on the first anniversary of the grant date. The options expire ten years from the grant date. The 1992 Plan was amended in 2000, by a vote of the shareholders, to increase the maximum number of shares of common stock that may be issued under the 1992 Plan to 6,500,000 shares. At December 31, 2002, the Company had reserved 5,042,040 shares of common stock for issuance, including 1,079,604 shares available for grant, under its 1992 Plan.

The Company’s 1988 Plan allows stock options to be issued to certain non-employee directors at the market price on the date of grant. The options may be exercised one year after issue and expire ten years from the grant date. The 1988 Plan provides for the grant of options to purchase a maximum of 550,000 shares of the Company’s authorized but unissued common stock. The 1988 Plan was amended at the shareholders’ annual meeting on April 24, 2001 to provide for the granting of a consistent number of stock options to each non-employee director annually (10,000 stock options for the first year of service and 5,000 stock options for each year thereafter) and to change the annual grant date to February 1, commencing February 1, 2002. At December 31, 2002, the Company had reserved 321,571 shares of common stock for issuance, including 89,786 shares available for grant, under its 1988 Plan.

The Company adopted a stockholder rights plan on August 27, 1997, designed to assure that the Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers and other abusive takeover tactics to gain control of the Company without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, the Company declared a dividend of one right (“Right”) on each share of Noble Energy, Inc. common stock. Each Right will entitle the holder to

16

purchase one one-hundredth of a share of a new Series A Junior Participating Preferred Stock, par value $1.00 per share, at an exercise price of $150.00. The Rights are not currently exercisable and will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more of Noble Energy, Inc. common stock. The dividend distribution was made on September 8, 1997, to stockholders of record at the close of business on that date. The Rights will expire on September 8, 2007.

A summary of the status of Noble Energy’s stock option plans as of December 31, 2000, 2001 and 2002, and changes during each of the years then ended, is presented below.

	Options Outstanding				Options Exercisable
	Number Outstanding		Exercise Price		Number Exercisable	Weighted Average Exercise Price
Outstanding at December 31, 1999	3,484,938		$	29.98	2,203,146	$	31.14
Options granted	774,343		$	24.19
Options exercised	(432,199	)	$	24.43
Options canceled	(105,977	)	$	29.11
Outstanding at December 31, 2000	3,721,105		$	29.44	2,408,522	$	32.08
Options granted	723,400		$	42.77
Options exercised	(509,161	)	$	24.97
Options canceled	(81,267	)	$	33.11
Outstanding at December 31, 2001	3,854,077		$	32.46	2,530,285	$	32.10
Options granted	732,500		$	32.66
Options exercised	(356,744	)	$	21.56
Options canceled	(35,612	)	$	37.02
Outstanding at December 31, 2002	4,194,221		$	33.38	2,871,943	$	32.84

The following table summarizes information about Noble Energy’s stock options which were outstanding, and those which were exercisable, as of December 31, 2002.

Options Outstanding					Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Life	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$17.28 - $21.61	833,264	6.0 Years	$	20.06	678,310	$	20.06
$21.61 - $25.93	185,145	1.9 Years	$	24.52	185,145	$	24.52
$25.93 - $30.25	126,834	2.3 Years	$	27.41	126,834	$	27.41
$30.25 - $34.57	785,075	8.5 Years	$	32.32	79,958	$	31.27
$34.57 - $38.89	742,924	4.9 Years	$	36.34	702,924	$	36.24
$38.89 - $43.21	1,520,979	5.2 Years	$	41.36	1,098,772	$	40.69
	4,194,221	5.7 Years	$	33.38	2,871,943	$	32.84

Compensation expense totaling $643,170 and $781,275 was recognized in 2002 and 2000, respectively, due to the accelerated vesting of stock options as a result of the retirement of certain employees.

17

Note 6 - Employee Benefit Plans

Pension Plan and Other Postretirement Benefit Plans

The Company has a non-contributory defined benefit pension plan covering substantially all of its domestic employees. The benefits are based on an employee’s years of service and average earnings for the 60 consecutive calendar months of highest compensation. The Company also has an unfunded restoration plan to ensure payments of amounts for which employees are entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. The Company’s funding policy has been to make annual contributions equal to the actuarially computed liability to the extent such amounts are deductible for income tax purposes. Plan assets consist of equity securities and fixed income investments.

The Company sponsors other plans for the benefit of its employees and retirees. These plans include health care and life insurance benefits. The following table reflects the required disclosures on the Company’s pension and other postretirement benefit plans at December 31:

	Pension Benefits						Other Benefits
(in thousands)	2002			2001			2002			2001
Change in benefit obligation
Benefit obligation at beginning of year	$	89,587		$	76,623		$	2,688		$	2,718
Adjustment for contributions paid in 2000				(54		)
Service cost	4,986			3,790			346			220
Interest cost	7,071			6,218			314			193
Amendments	380
Plan participants’ contributions							90			71
Actuarial (gain) loss	8,439			6,882			2,849			(333		)
Benefits paid	(4,239		)	(3,872		)	(146		)	(181		)
Benefit obligation at year end	$	106,224		$	89,587		$	6,141		$	2,688
Change in plan assets
Fair value of plan assets at beginning of year	$	53,570		$	55,487		$			$
Actual return on plan assets	(3,471		)	(1,541		)
Employer contribution	10,800			3,497			146			180
Benefits paid	(4,239		)	(3,873		)	(146		)	(180		)
Fair value of plan at end of year	$	56,660		$	53,570		$			$
Fund status	$	(49,564	)	$	(36,017	)	$	(6,141	)	$	(2,688	)
Unrecognized net actuarial loss (gain)	23,366			6,826			2,472			(304		)
Unrecognized prior service cost	2,525			2,451			(244		)	(274		)
Unrecognized net transition obligation (assets)	1,167			1,191
Prepaid (accrued) benefit costs	$	(22,506	)	$	(25,549	)	$	(3,913	)	$	(3,266	)
Components of net periodic benefit cost
Service cost	$	4,986		$	3,790		$	346		$	220
Interest cost	7,071			6,218			314			193
Expected return on plan assets	(5,474		)	(4,899		)
Transition (assets) obligation recognition	24			24
Amortization of prior service cost	306			292			(30		)	(30		)
Recognized net actuarial loss (gain)	845			(66		)	73			(10		)
Net periodic benefit cost	$	7,758		$	5,359		$	703		$	373
Weighted-average assumptions as of December 31,
Discount rate	6.75		%	7.25		%	6.75		%	7.25		%
Expected return on plan assets	8.50		%	8.50		%
Rate of compensation increase	4.00		%	4.75		%	4.00		%	5.50		%

18

The following table reflects the aggregate pension obligation components for the defined benefit pension plan and the restoration benefit plan, which are aggregated in the previous tables, at December 31:

	Defined Benefit Pension Plan						Restoration Benefit Plan
(in thousands)	2002			2001			2002			2001
Aggregated pension benefits
Aggregate fair value of plan assets	$	56,660		$	53,570		$			$
Aggregate accumulated benefit obligation	68,476			58,266			13,081			10,095
Fund status of net periodic benefit assets (obligation)	$	(11,816	)	$	(4,696	)	$	(13,081	)	$	(10,095	)

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following results:

(in thousands)	1-Percentage- Point increase		1-Percentage- Point decrease
Total service and interest cost components	$	733	$	598
Total postretirement benefit obligation	$	6,766	$	5,591

Employee Savings Plan (“ESP”)

The Company has an ESP that is a defined contribution plan. Participation in the ESP is voluntary and all regular employees of the Company are eligible to participate. The Company may match up to 100 percent of the participant’s contribution not to exceed six percent of the employee’s base compensation. The following table indicates the Company’s contribution for the years ended December 31:

(in thousands)	2002		2001		2000
Employers’ plan contribution	$	2,302	$	2,145	$	1,858

Note 7 - Additional Balance Sheet and Statement of Operations Information

Included in accounts receivable-trade is an allowance for doubtful accounts at December 31:

(in thousands)	2002		2001
Allowance for doubtful accounts	$	1,510	$	638

Other current assets included the following at December 31:

(in thousands)	2002		2001
Deferred tax asset (liability)	$	9,584	$	(1,880	)
Prepaid federal income taxes			$	66,131

Other current liabilities included the following at December 31:

(in thousands)	2002		2001
Gas imbalance liabilities	$	1,090	$	1,593
Accrued interest payable	$	11,178	$	11,158
Louisiana workers compensation	$	7,611	$	6,433

19

Crude oil and natural gas exploration expense included the following for the years ended December 31:

(in thousands)	2002		2001		2000
Dry hole expense	$	81,396	$	99,684	$	38,463
Unproved lease amortization	21,254		17,213		16,075
Seismic	20,492		15,607		18,738
Other	27,559		19,592		11,592
Total exploration expense	$	150,701	$	152,096	$	84,868

During the past three years, there was no third-party purchaser that accounted for more than 10 percent of the annual total crude oil and natural gas sales and royalties.

Note 8 - Derivatives and Hedging Activities

During 2002, the Company entered into various natural gas costless collars, natural gas costless collar combinations and crude oil costless collar transactions related to its production. The table below depicts the various transactions for 2002.

Natural Gas		Crude Oil
Hedge MMBTUpd	170,274	Hedge Bpd	5,247
Floor price range	$2.00 - $3.50	Floor price range	$23.00 - $24.00
Ceiling price range	$2.45 - $5.10	Ceiling price range	$29.30 - $30.10
Percent of daily production	50%	Percent of daily production	17	%
Gain (loss) per Mcf	$.04	Gain (loss) per Bbl	$(.01	)

As of December 31, 2002, the Company had entered into costless collars related to its natural gas and crude oil production to support the Company’s investment program as follows:

Natural Gas			Crude Oil
Production Period	MMBTU Per Day	Price Per MMBTU Floor - Ceiling	Bbls Per Day	Price Per Bbl Floor - Ceiling
1Q 2003	185,000	$3.87 - $4.82	15,000	$23.00 - $28.63
2Q 2003	185,000	$3.43 - $4.57	15,000	$23.00 - $28.63
3Q 2003	185,000	$3.43 - $4.60	10,000	$23.00 - $27.95
4Q 2003	185,000	$3.43 - $4.84	10,000	$23.00 - $27.95

The contracts entitle the Company (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the last scheduled NYMEX trading day applicable for each calculation period is less than the floor price. The Company would pay the counterparty if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period is more than the ceiling price. The amount payable by the floating price payor, if the floating price is above the ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if the floating price is below the floor price, is the product of the notional quantity per calculation period and the excess, if any, of the floor price over the floating price in respect of each calculation period.

During 2001, the Company had natural gas costless collars for the fourth quarter of 2001 for 50,000 MMBTU of natural gas per day, with a floor price of $3.25 per MMBTU and a ceiling price of $4.60 per MMBTU. The net effect of this fourth quarter 2001 hedge was a $.03 per Mcf increase in the average natural gas price for the year 2001. Of the 50,000 MMBTU per day of costless collars, 25,000 MMBTU per day were terminated early, at a gain. As a result, the Company recognized an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas per day in 2001.

20

In addition to the hedging arrangements pertaining to the Company’s production as described above, NEMI employs various derivative arrangements in connection with its purchases and sales of third-party production to lock in profits or limit exposure to gas price risk. Most of the purchases made by NEMI are on an index basis; however, purchasers in the markets in which NEMI sells often require fixed or NYMEX related pricing. NEMI may use a derivative to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility. During 2002, NEMI had derivative transactions with broker-dealers that ranged from 986,000 MMBTU to 2,085,000 MMBTU of natural gas per day. At December 31, 2002, NEMI had in place derivatives ranging from approximately 20,000 MMBTU to 909,000 MMBTU of natural gas per day for January 2003 to May 2006 for future physical transactions.

In 2001, NGM had derivative transactions with broker-dealers that ranged from 1,157,000 MMBTU to 1,388,000 MMBTU of natural gas per day. During 2000, NGM had derivative transactions with broker-dealers that ranged from 423,000 MMBTU to 1,023,000 MMBTU of natural gas per day. NEMI records derivative gains or losses relating to fixed term sales as gathering, marketing and processing revenues in the periods in which the related contract is completed.

Note 9 - Unconsolidated Subsidiary

The Company owns a 45 percent interest in AMPCO through its ownership in AMCCO. Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due December 15, 2004 to fund the remaining construction payments. The Company includes the $125 million Series A-2 senior notes in its balance sheet. On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. The terms of the $125 million Series A-2 Notes remain unchanged.

The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. The total construction costs of the plant and supporting facilities as of December 31, 2002 were $417 million, with the Company responsible for $208.5 million. The plant is designed to produce 2,500 MTpd of methanol, which equates to approximately 20,000 Bpd. At this level of production, the plant would purchase approximately 125 MMcfpd from the 34 percent owned Alba field. The methanol plant has a 25-year contract to purchase natural gas from the Alba field.

AMPCO, AMPCO Marketing LLC, AMPCO Services LLC and Samedan Methanol are accounted for using the equity method.

21

The following are summarized financial statements for subsidiaries accounted for using the equity method as of December 31, 2002 and 2001 and for the years ended December 31, 2002, 2001 and 2000:

Consolidated Balance Sheet (Unaudited)

Equity Method Subsidiaries

(in thousands)	2002		2001
Assets
Current assets	$	74,832	$	86,213
Non-current assets	412,134		431,372
Total Assets	$	486,966	$	517,585
Liabilities, Minority Interest and Members’ Equity
Current liabilities	$	37,419	$	14,426
Non-current liabilities			147,406
Minority interest			41,210
Members’ equity	449,547		314,543
Total Liabilities, Minority Interest and Members’ Equity	$	486,966	$	517,585

Consolidated Statement of Operations (Unaudited)

Equity Method Subsidiaries

(in thousands)	2002		2001			2000
Revenue
Methanol sales	$	97,476	$	43,343		$
Other income	18,471		5,346			4,389
Total Revenue	$	115,947	$	48,689		$	4,389
Less cost of goods sold	71,687		28,548
Gross Margin	$	44,260	$	20,141		$	4,389
Expenses
DD&A	$	20,763	$	8,427		$
Other expenses			4,363
Interest (net of amount capitalized)			7,013			(11,050		)
Administrative	3,076		317			86
Total Expenses	$	23,839	$	20,120		$	(10,964	)
Net Income (Loss) Before Extraordinary Items	$	20,421	$	21		$	15,353
Extraordinary Items (1)	$		$	24,776		$
Net Income (Loss)	$	20,421	$	(24,755	)	$	15,353

(1)   During the year, a prepayment penalty was recorded in connection with the early retirement of Series A-1 Secured Notes in 2002. The charge for the extraordinary item has been allocated to the Company’s partner in AMCCO. Therefore, the Company has not recognized anything related to this loss in its financial statements.

22

Note 10 - Commitments and Contingencies

(a)   The Company and its subsidiaries are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the inherent uncertainties in any litigation. The Company is defending itself vigorously in all such matters and does not believe that the ultimate disposition of such proceedings will have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

(b)   On October 15, 2002, Noble Gas Marketing, Inc., Samedan Oil Corporation and Aspect Resources L.L.C., collectively referred to as the “Noble Defendants,” filed proofs of claim in the United States Bankruptcy Court for the Southern District of New York in response to bankruptcy filings by Enron Corporation and certain of its subsidiaries and affiliates, including Enron North America Corporation (“ENA”), under Chapter 11 of the U.S. Bankruptcy Code. The proofs of claim relate to certain natural gas sales agreements and aggregate approximately $18 million.

On December 13, 2002, ENA filed a complaint in which it objected to the Noble Defendants’ proofs of claim, sought recovery of approximately $60 million from the Noble Defendants under the natural gas sales agreements, sought declaratory relief in respect of the offset rights of the Noble Defendants and sought to invalidate the arbitration provisions contained in certain of the agreements in issue. The Noble Defendants intend to vigorously defend against ENA’s claims and do not believe that the ultimate disposition of the bankruptcy proceeding will have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity. See also Note 14 - “Subsequent Events”.

Note 11 - Geographical Data

The Company has operations throughout the world and manages its operations by country. The following information is grouped into five components that are all primarily in the business of natural gas and crude oil exploration and production: United States, North Sea, Israel, Equatorial Guinea, and Other International, Corporate and Marketing. Other International includes operations in Argentina, China, Ecuador and Vietnam.

Year Ended December 31, 2002

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	266,233	$	120,808	$	72,041	$			$	45,830	$	27,554
Gas Sales	351,896		332,240		19,497					3,052		(2,893		)
Gathering, Marketing and Processing	64,517											64,517
Electricity Sales	18,257											18,257
Income from Unconsolidated Subsidiaries	9,532									9,532
Other	1,246		100		389		(8		)			765
Total Revenues	711,681		453,148		91,927		(8		)	58,414		108,200
COSTS AND EXPENSES
Oil and Gas Operations	107,734		84,757		10,812					9,848		2,317
Transportation	16,441				9,618							6,823
Oil and Gas Exploration	150,701		120,695		5,210		2,625			1,341		20,830
Gathering, Marketing and Processing	53,982											53,982
Electricity Generation	15,946											15,946
DD&A	239,325		195,152		28,279		31			5,849		10,014
SG&A	47,664		27,768		630		10			2,045		17,211
Interest Expense (net)	47,709											47,709
Total Costs and Expenses	679,502		428,372		54,549		2,666			19,083		174,832
OPERATING INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS	32,179		24,776		37,378		(2,674		)	39,331		(66,632		)
DISCONTINUED OPERATIONS	10,420		10,420
OPERATING INCOME (LOSS) BEFORE TAX	$	42,599	$	35,196	$	37,378	$	(2,674	)	$	39,331	$	(66,632	)
LONG-LIVED ASSETS (PRIMARILY PROPERTY, PLANT AND EQUIPMENT, NET) As of December 31, 2002	$	2,139,784	$	1,225,501	$	89,316	$	180,267		$	154,231	$	490,469

23

Year Ended December 31, 2001

(Dollars in Thousands)

	Consolidated		United States			North Sea			Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	223,027	$	117,408		$	39,972		$			$	38,841	$	26,806
Gas Sales	503,815		480,394			22,850						2,201		(1,630		)
Gathering, Marketing and Processing	64,640													64,640
Electricity Sales
Income (Loss) from Unconsolidated Subsidiaries	6,981											6,981
Other	953		(267		)	1,299						183		(262		)
Total Revenues	799,416		597,535			64,121						48,206		89,554
COSTS AND EXPENSES
Oil and Gas Operations	107,631		90,924			6,075						6,775		3,857
Transportation	16,012					8,772								7,240
Oil and Gas Exploration	152,096		100,492			34,950			380			39		16,235
Gathering, Marketing and Processing	51,932													51,932
Electricity Generation
DD&A	236,111		205,327			16,537			23			3,889		10,335
SG&A	44,164		26,554			2,699			3			917		13,991
Interest Expense (net)	38,007													38,007
Total Costs and Expenses	645,953		423,297			69,033			406			11,620		141,597
OPERATING INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS	153,463		174,238			(4,912		)	(406		)	36,586		(52,043		)
DISCONTINUED OPERATIONS	71,147		71,147
OPERATING INCOME (LOSS) BEFORE TAX	$	224,610	$	245,385		$	(4,912	)	$	(406	)	$	36,586	$	(52,043	)
LONG-LIVED ASSETS (PRIMARILY PROPERTY, PLANT AND EQUIPMENT, NET) As of December 31, 2001	$	1,953,211	$	1,308,504		$	103,781		$	101,407		$	87,461	$	352,058

Year Ended December 31, 2000

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	186,638	$	116,279	$	16,964	$			$	25,501	$	27,894
Gas Sales	460,706		435,638		24,392					235		441
Gathering, Marketing and Processing	62,328											62,328
Electricity Sales
Income from Unconsolidated Subsidiaries	13,544									13,544
Other	7,441		1,144		273							6,024
Total Revenues	730,657		553,061		41,629					39,280		96,687
COSTS AND EXPENSES
Oil and Gas Operations	95,994		81,559		5,256					4,325		4,854
Transportation	9,241				6,072							3,169
Oil and Gas Exploration	84,868		80,367		1,396		581			62		2,462
Gathering, Marketing and Processing	46,661											46,661
Electricity Generation
DD&A	187,316		164,206		12,297					1,361		9,452
SG&A	47,291		36,781		2,049					1,107		7,354
Interest Expense (net)	43,697											43,697
Total Costs and Expenses	515,068		362,913		27,070		581			6,855		117,649
OPERATING INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS	215,589		190,148		14,559		(581		)	32,425		(20,962		)
DISCONTINUED OPERATIONS	83,894		83,894
OPERATING INCOME (LOSS) BEFORE TAX	$	299,483	$	274,042	$	14,559	$	(581	)	$	32,425	$	(20,962	)
LONG-LIVED ASSETS (PRIMARILY PROPERTY, PLANT AND EQUIPMENT, NET) As of December 31, 2000	$	1,485,123	$	1,047,750	$	90,231	$	69,726		$	76,898	$	200,518

24

Note 12 - Company Stock Repurchase Forward Program

The Company’s Board of Directors, in February 2000, authorized a repurchase of up to $50 million in the Company’s common stock. In the first quarter of 2000, the Company repurchased approximately $30 million of common stock. The 2000 repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded from the Company’s current cash flow. On September 17, 2001 the Company’s Board of Directors approved an expansion of the original repurchase program from $50 million to $100 million. During the fourth quarter of 2001, in conjunction with the expanded repurchase program, the Board approved a stock repurchase forward program. Under the stock repurchase forward program, one of the Company’s banks purchased approximately $35 million of the Company’s stock or 1,044,454 shares on the open market during the first quarter of 2002.

The program was scheduled to mature in January 2003 but has been extended to January 2004. Under the provisions of the agreement with the bank, the Company could choose to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price has decreased, pay the bank a net amount of cash to the extent that the share price has decreased, or receive from the bank a net amount of cash to the extent that the share price has increased. The bank has the right to terminate the agreement prior to the maturity date if the Company’s share price decreases by 50 percent (to $16.77 per share) or if the Company’s credit rating is downgraded below BBB- (S&P) or Baa3 (Moody’s). If either event occurs and the bank exercises its right to terminate, the Company still retains the right to settle in cash or additional shares. The agreement limits the number of shares to be issued by the Company to 14,000,000 additional shares. Amounts paid or received related to the change in share price will be an addition or reduction to the Company’s capital in excess of par value. As of December 31, 2002, the fair value of the Company’s obligation under the contract would be an obligation to pay approximately $36.1 million to the bank (and hold the shares as treasury stock), or the bank would return 81,946 shares of Company stock to the Company, or the bank would pay $3.1 million to the Company.

In June  2003, the Company and the bank amended the agreement to delete the provisions that allowed the Company to net settle the contract, and in December 2003, the Company paid the obligation in full. See also Note 14 – “Subsequent Events”.

Note 13 – Discontinued Operations

2003 PROPERTY SALES: During 2003, the Company identified five property packages for disposition. Bids have now been received on all five packages. Year-to-date, property sales have closed on four of the five packages, with the remaining property package expected to close during the first quarter of 2004. Total pretax proceeds on all five packages, before closing adjustments, are expected to be in excess of $110 million.

During the third quarter 2003, closed property sales resulted in a pretax gain of $9.9 million. Also during the third quarter 2003, certain properties in two packages were classified as held for sale, written down by $18.3 million to fair value, pretax, and reported in discontinued operations.

Subsequent to September 30, 2003, the remaining asset package met the criteria to be classified as held for sale. During the fourth quarter 2003, Noble Energy has closed sales on properties located in California, Oklahoma and Wyoming. A package of Gulf of Mexico properties is expected to close during the first quarter 2004. The transfer of the remaining property package to discontinued operations and the timing of completed sales will result in an expected non-cash, pretax write-down to fair value and realized loss of approximately $40 million ($26 million after tax) (unaudited). The total non-cash charge will appear in discontinued operations for the fourth quarter 2003.

25

Pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which replaced APB Opinion No. 30 for the disposal of segments of a business, the Company’s consolidated financial statements have been reclassified for all periods presented to reflect the operations and assets of the properties being sold as discontinued operations.  The net income from discontinued operations was classified on the consolidated statements of operations as “Discontinued operations, net of tax.” Summarized results of discontinued operations are as follows:

	Year ended December 31,
(dollars in thousands)	2002		2001		2000
Revenues:
Oil and gas sales and royalties	$	82,473	$	144,970	$	153,250
Costs and Expenses:
Oil and gas operations	26,092		25,918		25,872
Depreciation, depletion and amortization	45,961		47,905		43,484
	72,053		73,823		69,356
Income Before Income Taxes	10,420		71,147		83,894
Income Tax Provision	3,647		24,901		29,363
Income From Discontinued Operations	$	6,773	$	46,246	$	54,531

The long-term debt of the Company is recorded at the consolidated level and is not reflected by each segment. Thus, the Company has not allocated interest expense to the discontinued operations.

Note 14 - Subsequent Events

ACCOUNTING FOR COSTS ASSOCIATED WITH MINERAL RIGHTS: During 2003 a reporting issue arose regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, excluding amortization, the Company would be required to reclassify certain amounts out of oil and gas properties and into a separate intangible assets line item. The Company has not yet determined fully the impact of this change; however, it is expected to significantly impact the Company’s balance sheet. The Company’s cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules. Further, the Company does not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on compliance with covenants under the Company’s debt agreements.

CREDIT FACILITY: The Company entered into a new 364-day credit facility in the amount of $300 million effective November 3, 2003 that replaced the $200 million credit facility that would have expired November 26, 2003. The interest rate on the new credit facility is LIBOR plus a range of 62.5 to 150 basis points, depending upon the percentage of utilization.

ADOPTION OF SFAS NO. 150: During the second quarter of 2003, the Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” As a result, the Company recorded an additional 1.04 million shares of treasury stock at a cost of $36.6 million and an obligation of $36.6 million. During 2003 the Company paid the obligation of $36.6 million in full.

DIVIDEND PAYMENT: On October 28, 2003, the Company’s Board of Directors declared a quarterly cash dividend of five cents per common share payable November 24, 2003 to the shareholders of record on November 10, 2003. This payment represents an increase of one cent per share, or 25 percent, over the Company’s previous quarterly payment of four cents per share.

26

LEGAL UPDATE: On January 13, 2003, the Noble Defendants each filed an answer to ENA’s complaint. On January 29, 2003, the Noble Defendants filed the Motion of Noble Energy Marketing, Inc., as Successor to Noble Gas Marketing, Inc., Aspect Resources L.L.C., and Noble Energy, Inc., as Successor to Samedan Oil Corporation, to Compel Arbitration. On March 4, 2003, the Court issued its Order Governing Mediation of Trading Cases and Appointing the Honorable Allan L. Gropper as Mediator (the “Mediation Order”) which, among other things, abated this case and referred it to mediation along with other pending adversary proceedings in the Enron bankruptcy cases which involve disputes arising from or in connection with commodity trading contracts. Pursuant to the Mediation Order, the Honorable Allan L. Gropper (United States Bankruptcy Judge for the Southern District of New York) is acting as mediator for this case and the other trading cases which have been referred to him. The mediation for this case was held on December 17, 2003 and no resolution was reached.

27

Supplemental Oil and Gas Information

(Unaudited)

There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than Noble Energy’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The procedures and methods used to estimate approximately 80 percent of the Company’s proved reserves have been audited by a third party. This audit of procedures and methods included all of the Company’s major international properties, whose reserves were also estimated by third parties. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. China, Ecuador and Equatorial Guinea are subject to production sharing contracts.

Proved Gas Reserves (Unaudited)

The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in estimated quantities of proved gas reserves of the Company during each of the three years presented.

	Natural Gas and Casinghead Gas (MMcf)
	United States		Argentina		Ecuador		Equatorial Guinea		Israel	North Sea		Total
Proved reserves as of:
January 1, 2002	751,283		4,348		87,500		438,214		378,001	20,661		1,680,007
Revisions of previous estimates	(37,566	)	(37	)	281		(245	)		18		(37,549	)
Extensions, discoveries and other additions	42,806								72,306			115,112
Production	(119,664	)	(424	)	(2,788	)	(12,549	)		(6,201	)	(141,626	)
Sale of minerals in place	(20,290	)										(20,290	)
Purchase of minerals in place	5,147											5,147
December 31, 2002	621,716		3,887		84,993		425,420		450,307	14,478		1,600,801
Proved reserves as of:
January 1, 2001	752,387		4,544		87,500		383,292		218,154	28,752		1,474,629
Revisions of previous estimates	(46,886	)	36				(2,550	)	159,847	(1,583	)	108,864
Extensions, discoveries and other additions	129,172		371				66,410					195,953
Production	(134,507	)	(603	)			(8,938	)		(6,508	)	(150,556	)
Sale of minerals in place	(246	)										(246	)
Purchase of minerals in place	51,363											51,363
December 31, 2001	751,283		4,348		87,500		438,214		378,001	20,661		1,680,007
Proved reserves as of:
January 1, 2000	759,781		5,221		87,500		384,102			26,452		1,263,056
Revisions of previous estimates	(7,022	)	44				131			7,864		1,017
Extensions, discoveries and other additions	135,844								218,154	3,101		357,099
Production	(136,010	)	(721	)			(941	)		(8,665	)	(146,337	)
Sale of minerals in place	(4,840	)										(4,840	)
Purchase of minerals in place	4,634											4,634
December 31, 2000	752,387		4,544		87,500		383,292		218,154	28,752		1,474,629
Proved developed gas reserves as of:
January 1, 2003	576,378		3,664		34,436		425,419			14,478		1,054,375
January 1, 2002	721,926		3,996				438,213			20,662		1,184,797
January 1, 2001	690,301		4,544				383,292			25,652		1,103,789
January 1, 2000	703,166		5,221				11,687			26,452		746,526

28

Proved Oil Reserves (Unaudited)

The following reserve schedule was developed by the Company’s reserve engineers and sets forth the changes in estimated quantities of proved oil reserves of the Company during each of the three years presented.

	Crude Oil and Condensate (Bbls in thousands)
	United States		Argentina		China	Equatorial Guinea		North Sea		Total
Proved reserves as of:
January 1, 2002	71,672		10,277		9,768	79,790		11,114		182,621
Revisions of previous estimates	(5,331	)	36			(34	)	(27	)	(5,356	)
Extensions, discoveries and other additions	2,929				1,162	33,182				37,273
Production	(6,652	)	(1,030	)		(1,919	)	(2,864	)	(12,465	)
Sale of minerals in place	(732	)								(732	)
Purchase of minerals in place	137									137
December 31, 2002	62,023		9,283		10,930	111,019		8,223		201,478
Proved reserves as of:
January 1, 2001	69,700		9,437		9,768	47,446		12,418		148,769
Revisions of previous estimates	324		(6	)		(272	)	407		453
Extensions, discoveries and other additions	7,453		1,846			34,303				43,602
Production	(7,363	)	(1,000	)		(1,687	)	(1,711	)	(11,761	)
Sale of minerals in place	(37	)								(37	)
Purchase of minerals in place	1,595									1,595
December 31, 2001	71,672		10,277		9,768	79,790		11,114		182,621
Proved reserves as of:
January 1, 2000	65,523		10,285		9,768	30,684		5,786		122,046
Revisions of previous estimates	(1,493	)	68			185		(366	)	(1,606	)
Extensions, discoveries and other additions	12,788					17,491		5,731		36,010
Production	(7,309	)	(916	)		(914	)	(654	)	(9,793	)
Sale of minerals in place	(935	)						(229	)	(1,164	)
Purchase of minerals in place	1,126							2,150		3,276
December 31, 2000	69,700		9,437		9,768	47,446		12,418		148,769
Proved developed oil reserves as of:
January 1, 2003	52,847		8,331		10,930	78,746		8,223		159,077
January 1, 2002	64,534		8,866		9,768	61,897		11,114		156,179
January 1, 2001	58,903		9,437		9,768	47,446		5,728		131,282
January 1, 2000	60,618		10,285		9,768	14,743		3,986		99,400

Proved Reserves. Proved reserves are estimated quantities of crude oil, natural gas, natural gas liquids and condensate liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Developed Reserves. Proved developed reserves are proved reserves that are expected to be recovered through existing wells with existing equipment and operating methods.

29

Oil and Gas Operations (Unaudited)

Aggregate results of continuing operations for each period ended December 31, in connection with the Company’s crude oil and natural gas producing activities, are shown below.

(in thousands)	United States		Equatorial Guinea		Israel			North Sea			Other Int’l			Total
December 31, 2002
Revenues	$	453,224	$	45,830	$			$	91,538		$	27,537		$	618,129
Production costs	116,486		8,840		10			21,061			13,093			159,490
Exploration expenses	102,323		1,341		1,725			5,032			20,733			131,154
DD&A and valuation provision	212,349		5,835		909			28,350			9,606			257,049
Income (loss)	22,066		29,814		(2,644		)	37,095			(15,895		)	70,436
Income tax expense (benefit)	8,058		13,825					17,346			666			39,895
Result of continuing operations from producing activities (excluding corporate overhead and interest costs)	$	14,008	$	15,989	$	(2,644	)	$	19,749		$	(16,561	)	$	30,541
December 31, 2001
Revenues	$	597,939	$	38,841	$			$	54,051		$	19,999		$	710,830
Production costs	120,336		5,381		3			8,774			7,675			142,169
Exploration expenses	86,619		39		5			33,224			17,021			136,908
DD&A and valuation provision	218,900		3,830		382			18,171			8,679			249,962
Income (loss)	172,084		29,591		(390		)	(6,118		)	(13,376		)	181,791
Income tax expense (benefit)	60,597		14,429					(2,721		)	(700		)	71,605
Result of continuing operations from producing activities (excluding corporate overhead and interest costs)	$	111,487	$	15,162	$	(390	)	$	(3,397	)	$	(12,676	)	$	110,186
December 31, 2000
Revenues	$	552,020	$	25,501	$			$	35,284		$	25,298		$	638,103
Production costs	103,487		5,010					5,962			6,952			121,411
Exploration expenses	78,955		121		581			2,739			2,169			84,565
DD&A and valuation provision	178,677		1,355					12,231			8,292			200,555
Income (loss)	190,901		19,015		(581		)	14,352			7,885			231,572
Income tax expense (benefit)	67,312		8,978					4,316			5,033			85,639
Result of continuing operations from producing activities (excluding corporate overhead and interest costs)	$	123,589	$	10,037	$	(581	)	$	10,036		$	2,852		$	145,933

30

Costs Incurred in Oil and Gas Activities (Unaudited)

Costs incurred in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities for each of the years are shown below.

(in thousands)	United States		Equatorial Guinea		Israel		North Sea			Other Int’l		Total
December 31, 2002
Property acquisition costs
Proved	$	7,873	$		$		$	115		$		$	7,988
Unproved	28,023						(238		)	2,730		30,515
Total	$	35,896	$		$		$	(123	)	$	2,730	$	38,503
Exploration costs	$	153,437	$	1,351	$	1,725	$	5,062		$	20,935	$	182,510
Development costs	$	131,244	$	51,839	$	14,767	$	9,892		$	60,934	$	268,676
December 31, 2001
Property acquisition costs
Proved	$	91,251	$		$		$	6,318		$		$	97,569
Unproved	76,808						2,167			2,310		81,285
Total	$	168,059	$		$		$	8,485		$	2,310	$	178,854
Exploration costs	$	134,247	$	4,003	$	131	$	34,766		$	19,233	$	192,380
Development costs	$	279,297	$	10,364	$	11,163	$	17,338		$	75,910	$	394,072
December 31, 2000
Property acquisition costs
Proved	$	6,822	$		$	50,861	$	41,284		$		$	98,967
Unproved	12,559				1,927		2,218			858		17,562
Total	$	19,381	$		$	52,788	$	43,502		$	858	$	116,529
Exploration costs	$	115,728	$	62	$	11,387	$	1,396		$	2,135	$	130,708
Development costs	$	180,339	$	36,820	$	1,502	$	2,219		$	44,648	$	265,528

Aggregate Capitalized Costs (Unaudited)

Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, and related accumulated DD&A, as of December 31 are shown below:

	2002									2001
(in thousands)	U. S.			Int’l			Total			U. S.			Int’l			Total
Unproved oil and gas properties	$	138,319		$	16,532		$	154,851		$	142,232		$	14,041		$	156,273
Proved oil and gas properties	3,053,256			1,069,914			4,123,170			3,007,757			757,885			3,765,642
	3,191,575			1,086,446			4,278,021			3,149,989			771,926			3,921,915
Accumulated DD&A	(1,972,282		)	(189,540		)	(2,161,822		)	(1,855,352		)	(138,425		)	(1,993,777		)
Net capitalized costs	$	1,219,293		$	896,906		$	2,116,199		$	1,294,637		$	633,501		$	1,928,138

31

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2002, 2001 and 2000 in accordance with SFAS No. 69. The Standard requires the use of a 10 percent discount rate. This information is not the fair market value nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

	United States		Ecuador		Equatorial Guinea		Israel		North Sea		Other Int’l		Total
December 31, 2002
(in millions of dollars)
Future cash inflows	$	4,743	$	268	$	3,111	$	1,181	$	294	$	648	$	10,245
Future production and development costs	1,506		73		661		301		110		238		2,889
Future income tax expenses	985		33		860		263		68		111		2,320
Future net cash flows	2,252		162		1,590		617		116		299		5,036
10% annual discount for estimated timing of cash flows	877		59		953		301		21		93		2,304
Standardized measure of discounted future net cash flows	$	1,375	$	103	$	637	$	316	$	95	$	206	$	2,732
December 31, 2001
(in millions of dollars)
Future cash inflows	$	3,399	$	264	$	1,576	$	900	$	281	$	317	$	6,737
Future production and development costs	1,618		103		381		150		84		168		2,504
Future income tax expenses	437		26		598		193		49		24		1,327
Future net cash flows	1,344		135		597		557		148		125		2,906
10% annual discount for estimated timing of cash flows	562		56		406		364		25		65		1,478
Standardized measure of discounted future net cash flows	$	782	$	79	$	191	$	193	$	123	$	60	$	1,428
December 31, 2000
(in millions of dollars)
Future cash inflows	$	8,825	$	305	$	1,125	$	524	$	379	$	462	$	11,620
Future production and development costs	1,759		90		178		92		89		186		2,394
Future income tax expenses	1,909		58		256		117		78		74		2,492
Future net cash flows	5,157		157		691		315		212		202		6,734
10% annual discount for estimated timing of cash flows	2,037		62		273		124		84		80		2,660
Standardized measure of discounted future net cash flows	$	3,120	$	95	$	418	$	191	$	128	$	122	$	4,074

The future net cash inflows for 2002, 2001 and 2000 do not include cash flows relating to the Company’s anticipated future methanol or power sales.

Future cash inflows are computed by applying year-end prices (with a weighted average price of $29.48 per Bbl of crude oil and $3.95 per Mcf of natural gas, after adjusting for differentials on a property-by-property basis) to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end.

32

The Company estimates that a $1.00 per Bbl change or a $.10 per Mcf change in the average crude oil price or the average natural gas price, respectively, from the year-end price would change the discounted future net cash flows before income taxes by approximately $105 million or $64 million, respectively.

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to the Company’s proved crude oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations relating to the Company’s proved crude oil and natural gas reserves.

At December 31, 2002, the Company estimated natural gas imbalance receivables of $20.1 million and estimated natural gas imbalance liabilities of $15.4 million; at year-end 2001, $20.9 million in receivables and $15.5 million in liabilities; and at year-end 2000, $18.5 million in receivables and $14.2 million in liabilities. Neither the natural gas imbalance receivables nor natural gas imbalance liabilities have been included in the standardized measure of discounted future net cash flows as of each of the three years ended December 31, 2002, 2001 and 2000.

Sources of Changes in Discounted Future Net Cash Flows (Unaudited)

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by SFAS No. 69, at year-end are shown below.

(in millions)	2002			2001			2000
Standardized measure of discounted future net cash flows at the beginning of the year	$	1,428		$	4,074		$	1,493
Extensions, discoveries and improved recovery, less related costs	486			448			1,462
Revisions of previous quantity estimates	(158		)	114			(20		)
Changes in estimated future development costs	(243		)	(128		)	(52		)
Purchases (sales) of minerals in place	(13		)	108			69
Net changes in prices and production costs	1,636			(3,376		)	2,448
Accretion of discount	208			564			185
Sales of oil and gas produced, net of production costs	(553		)	(713		)	(662		)
Development costs incurred during the period	254			220			172
Net change in income taxes	(667		)	908			(1,207		)
Change in timing of estimated future production, and other	354			(791		)	186
Standardized measure of discounted future net cash flows at the end of the year	$	2,732		$	1,428		$	4,074

33

Supplemental Quarterly Financial Information (Unaudited)

Supplemental quarterly financial information for the years ended December 31, 2002 and 2001is as follows:

	Quarter Ended
(in thousands except per share amounts)	Mar. 31,			June 30,		Sept. 30,			Dec. 31,
2002
Revenues	$	145,509		$	170,187	$	181,838		$	214,147
Income (loss) from continuing operations before taxes	(19,037		)	23,508		(6,799		)	34,507
Income (loss) from continuing operations	(13,760		)	13,591		(3,703		)	14,751
Discontinued operations, net of tax	(1,338		)	3,528		2,513			2,070
Net income (loss)	$	(15,098	)	$	17,119	$	(1,190	)	$	16,821
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	(0.24	)	$	0.24	$	(0.06	)	$	0.26
Discontinued operations, net of tax	$	(0.02	)	$	0.06	$	0.04		$	0.03
Net income (loss)	$	(0.26	)	$	0.30	$	(0.02	)	$	0.29
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	(0.24	)	$	0.24	$	(0.06	)	$	0.26
Discontinued operations, net of tax	$	(0.02	)	$	0.06	$	0.04		$	0.03
Net income (loss)	$	(0.26	)	$	0.30	$	(0.02	)	$	0.29
2001
Revenues	$	303,458		$	214,888	$	157,128		$	123,942
Income (loss) from continuing operations before taxes	147,440			61,702		(10,407		)	(45,272		)
Income (loss) from continuing operations	94,508			39,804		(7,848		)	(39,135		)
Discontinued operations, net of tax	11,403			11,530		11,656			11,657
Net income (loss)	$	105,910		$	51,334	$	3,808		$	(27,477	)
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	1.68		$	0.71	$	(0.14	)	$	(0.69	)
Discontinued operations, net of tax	$	0.20		$	0.20	$	0.21		$	0.21
Net income (loss)	$	1.88		$	0.91	$	0.07		$	(0.48	)
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	1.64		$	0.69	$	(0.14	)	$	(0.69	)
Discontinued operations, net of tax	$	0.20		$	0.20	$	0.21		$	0.21
Net income (loss)	$	1.84		$	0.89	$	0.07		$	(0.48	)

34