UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period 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: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware		73-0785597
(State of incorporation)		(I.R.S. employer identification number)

100 Glenborough Drive, Suite 100 Houston, Texas		77067
(Address of principal executive offices)		(Zip Code)

(281) 872-3100
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes ý No o

Number of shares of common stock outstanding as of November 7, 2003: 56,751,851

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

	(Unaudited)
	September 30, 2003			December 31, 2002
ASSETS
Current Assets:
Cash and short-term investments	$	71,382		$	15,442
Accounts receivable - trade	260,668			232,924
Oil and gas hedges receivable	7,998			10,271
Materials and supplies inventories	11,618			10,663
Assets held for sale	62,873
Other current assets	62,282			41,074
Total Current Assets	476,821			310,374
Property, Plant and Equipment, at cost	4,054,927			4,334,015
Less: accumulated depreciation, depletion and amortization	(1,880,879		)	(2,194,230		)
Total property, plant and equipment, net	2,174,048			2,139,785
Investment in Unconsolidated Subsidiaries	229,383			234,668
Other Assets	48,762			45,188

Total Assets	$	2,929,014		$	2,730,015

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	344,453		$	351,856
Current installments of long-term debt	60,776			41,919
Oil and gas hedges payable	10,843			32,285
Other current liabilities	48,303			36,159
Income taxes - current	60,275			9,535
Total Current Liabilities	524,650			471,754
Deferred Income Taxes	192,888			201,939
Asset Retirement Obligation	98,038
Other Noncurrent Liabilities	82,981			69,820
Long-Term Debt	945,977			977,116

Total Liabilities	1,844,534			1,720,629

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; 60,086,048 and 59,868,067 shares issued at September 30, 2003 and December 31, 2002, respectively	200,285			199,558
Capital in excess of par value	411,004			405,271
Retained earnings	550,653			458,490
Accumulated other comprehensive loss	(1,506		)	(14,603		)
	1,160,436			1,048,716
Less: Common Stock in Treasury, at cost
(September 30, 2003, 3,549,976 shares and December 31, 2002, 2,505,522 shares, respectively)	(75,956		)	(39,330		)

Total Shareholders’ Equity	1,084,480			1,009,386

Total Liabilities and Shareholders’ Equity	$	2,929,014		$	2,730,015

See notes to consolidated condensed financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,
	2003			2002
REVENUES:
Oil and gas sales and royalties	$	205,650		$	156,548
Gathering, marketing and processing	16,877			18,940
Electricity sales	12,855			3,931
Income from unconsolidated subsidiaries	8,584			5,184
Other loss, net	(1,850		)	(1,901		)

	242,116			182,702
COSTS AND EXPENSES:
Oil and gas operations	37,508			31,289
Transportation	3,451			4,010
Oil and gas exploration	25,481			50,628
Gathering, marketing and processing	14,708			15,216
Electricity generation	12,818			3,117
Depreciation, depletion and amortization	73,155			60,076
Selling, general and administrative	12,495			14,835
Accretion of asset retirement obligation	2,401
Interest	15,405			14,979
Interest capitalized	(4,395		)	(4,649		)

	193,027			189,501

INCOME (LOSS) BEFORE TAXES	49,089			(6,799		)

INCOME TAX PROVISION (BENEFIT)	16,969			(3,096		)

INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS	32,120			(3,703		)

DISCONTINUED OPERATIONS, NET OF TAX	2,996			2,513

NET INCOME (LOSS)	$	35,116		$	(1,190	)

EARNINGS (LOSS) PER SHARE:
Basic -
Income (loss) before discontinued operations	$	0.57		$	(0.06	)
Discontinued operations, net of tax	0.05			0.04

Net income (loss)	$	0.62		$	(0.02	)

Diluted -
Income (loss) before discontinued operations	$	0.56		$	(0.06	)
Discontinued operations, net of tax	0.05			0.04

Net income (loss)	$	0.61		$	(0.02	)

Weighted average number of shares outstanding - Basic	56,494			57,287
Weighted average number of shares outstanding - Diluted	57,113			57,287

See notes to consolidated condensed financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Nine Months Ended September 30,
	2003			2002
REVENUES:
Oil and gas sales and royalties	$	632,192		$	443,758
Gathering, marketing and processing	54,657			47,597
Electricity sales	41,361			3,931
Income from unconsolidated subsidiaries	33,190			1,278
Other income (loss), net	(7,547		)	972

	753,853			497,536

COSTS AND EXPENSES:
Oil and gas operations	111,719			79,911
Transportation	10,570			13,227
Oil and gas exploration	95,559			107,266
Gathering, marketing and processing	48,690			40,151
Electricity generation	36,439			3,117
Depreciation, depletion and amortization	217,690			184,590
Selling, general and administrative	41,069			38,241
Accretion of asset retirement obligation	7,015
Interest	46,363			47,092
Interest capitalized	(9,578		)	(13,732		)

	605,536			499,863

INCOME (LOSS) BEFORE TAXES	148,317			(2,327		)

INCOME TAX PROVISION	56,790			1,545

INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE	91,527			(3,872		)

DISCONTINUED OPERATIONS, NET OF TAX	13,355			4,703

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX	(5,839		)

NET INCOME	$	99,043		$	831

EARNINGS (LOSS) PER SHARE:
Basic -
Income (loss) before discontinued operations and cumulative effect of change in accounting principle	$	1.61		$	(0.07	)
Discontinued operations, net of tax	0.23			0.08
Cumulative effect of change in accounting principle, net of tax	(0.10		)

Net income	$	1.74		$	0.01

Diluted -
Income (loss) before discontinued operations and cumulative effect of change in accounting principle	$	1.59		$	(0.07	)
Discontinued operations, net of tax	0.23			0.08
Cumulative effect of change in accounting principle, net of tax	(0.10		)

Net income	$	1.72		$	0.01

Weighted average number of shares outstanding - Basic	57,014			57,159
Weighted average number of shares outstanding - Diluted	57,546			57,727

See notes to consolidated condensed financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

AND SHAREHOLDERS’ EQUITY

(Dollars in Thousands)

(Unaudited)

	Comprehensive Income		Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Treasury Stock At Cost			Total Shareholders’ Equity

Balance at December 31, 2002			$	199,558	$	405,271	$	458,490		$	(14,603	)	$	(39,330	)	$	1,009,386
Net income	$	99,043					99,043									99,043
Change in fair value of cash flow hedges, net of income tax	13,097									13,097						13,097
Shares issued			727		5,733											6,460
Dividends declared ($0.12 per share)							(6,880		)							(6,880		)
Treasury stock purchase													(36,626		)	(36,626		)

Total	$	112,140

Balance at September 30, 2003			$	200,285	$	411,004	$	550,653		$	(1,506	)	$	(75,956	)	$	1,084,480

See notes to consolidated condensed financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2003			2002
Cash Flows from Operating Activities:
Net income	$	99,043		$	831
Adjustments to reconcile net income to net cash provided by operating activities:	217,690			183,023
Depreciation, depletion and amortization - oil and gas production
Depreciation, depletion and amortization - electricity generation	19,180			1,567
Dry hole expense	46,035			62,126
Amortization of unproved leasehold costs	18,420			15,510
Non-cash effect of discontinued operations	38,740			34,598
Cumulative effect of change in accounting principle, net of tax	5,839
Loss on disposal of assets	10,089			48
Deferred income taxes	(5,907		)	2,783
Accretion of asset retirement obligation	7,015
Income from unconsolidated subsidiaries	(33,190		)	(1,278		)
Dividends received from unconsolidated subsidiary	37,575			5,363
Increase (decrease) in noncurrent liabilities	13,161			(4,971		)
(Increase) decrease in other	(3,384		)	6,375
Changes in operating assets and liabilities, not including cash:
(Increase) in accounts receivable	(27,744		)	(9,852		)
(Increase) decrease in other current assets and inventories	(22,163		)	24,900
(Decrease) in accounts payable	(7,403		)	(19,877		)
Increase in other current liabilities	56,812			3,997

Net Cash Provided by Operating Activities	469,808			305,143

Cash Flows From Investing Activities:
Capital expenditures	(380,623		)	(427,587		)
Investment in unconsolidated subsidiary	900			(7,838		)
Proceeds from sale of property, plant and equipment	15,373			20,363
Distribution from unconsolidated subsidiary				5,500

Net Cash Used in Investing Activities	(364,350		)	(409,562		)

Cash Flows From Financing Activities:
Exercise of stock options	6,460			8,181
Cash dividends paid	(6,880		)	(6,855		)
Proceeds from bank debt	100,435			153,489
Repayment of bank debt	(146,373		)	(100,000		)
Repayment of note payable obtained in Aspect acquisition	(3,160		)	(17,226		)

Net Cash (Used in) Provided by Financing Activities	(49,518		)	37,589

Increase (Decrease) in Cash and Short-term Investments	55,940			(66,830		)

Cash and Short-term Investments at Beginning of Period	15,442			73,237

Cash and Short-term Investments at End of Period	$	71,382		$	6,407

Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during the period for:
Interest (net of amount capitalized)	$	21,115		$	13,914
Income taxes paid (refunded)	$	29,147		$	(40,394	)
Debt obtained from consolidation of AMCCO (net of discount)	$			$	122,655
Treasury stock purchase	$	36,626		$

See notes to consolidated condensed financial statements.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(Unaudited)

In the opinion of Noble Energy, Inc. (the “Company” or “Noble Energy”), the accompanying unaudited consolidated condensed financial statements contain all adjustments, consisting only of necessary and normal recurring adjustments, necessary to present fairly the Company’s financial position as of September 30, 2003; the results of operations for the three month and nine month periods ended September 30, 2003 and 2002; the statement of comprehensive income and shareholders’ equity for the nine month period ended September 30, 2003; and the cash flows for the nine month periods ended September 30, 2003 and 2002. These consolidated condensed financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2002.

(1) STOCK-BASED EMPLOYEE COMPENSATION

The Company currently accounts for stock-based employee compensation plans under the recognition and measurement principles of the Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.”

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.

For the three months ended September 30:

(in thousands except per share amounts)	2003			2002
Net income (loss), as reported	$	35,116		$	(1,190	)
Add: Stock-based compensation cost recognized, net of related tax effects	72
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2,543		)	(2,379		)
Pro forma net income (loss)	$	32,645		$	(3,569	)
Earnings (loss) per share:
Basic - as reported	$	0.62		$	(0.02	)
Basic - pro forma	$	0.58		$	(0.06	)
Diluted - as reported	$	0.61		$	(0.02	)
Diluted - pro forma	$	0.57		$	(0.06	)

For the nine months ended September 30:

(in thousands except per share amounts)	2003			2002
Net income, as reported	$	99,043		$	831
Add: Stock-based compensation cost recognized, net of related tax effects	143			349
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(7,645		)	(7,137		)
Pro forma net income (loss)	$	91,541		$	(5,957	)
Earnings (loss) per share:
Basic - as reported	$	1.74		$	0.01
Basic - pro forma	$	1.61		$	(0.10	)
Diluted - as reported	$	1.72		$	0.01
Diluted - pro forma	$	1.59		$	(0.10	)

(2) INCOME TAX PROVISION (BENEFIT)

For the three months ended September 30:

	(In thousands)
	2003			2002
Current	$	18,434		$	(1,603	)
Deferred	(1,465		)	(1,493		)

	$	16,969		$	(3,096	)

For the nine months ended September 30:

	(In thousands)
	2003			2002
Current	$	58,029		$	(1,238	)
Deferred	(1,239		)	2,783

	$	56,790		$	1,545

In assessing whether or not deferred tax assets are realizable, management considers whether it is more likely than not that some portion 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. During the second quarter of 2003, the Company achieved certain milestones on its Israel development project, which led management to conclude that the prior valuation allowance was no longer required for the deferred tax asset related to that project. This resulted in a decrease in tax expense of approximately $2.6 million for the nine-month period ending September 30, 2003.

The income tax provisions associated with discontinued operations were $7.2 million and $2.5 million for the nine-month periods ending September 30, 2003 and 2002, respectively. For the three-month periods ending September 30, 2003 and 2002, the tax provision were $1.6 million and $1.4 million, respectively.

(3) BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE

Basic earnings per share (“EPS”) of common stock was computed using the weighted average number of shares of common stock outstanding during each period. The diluted net income per share of common stock includes the effect of outstanding stock options.

The following table summarizes the calculation of basic and diluted EPS.

For the three months ended September 30:

	2003			2002
(in thousands, except per share)	Income (Numerator)		Shares (Denominator)	Income (Numerator)			Shares (Denominator)
Net income (loss)/shares	$	35,116	56,494	$	(1,190	)	57,287
Basic EPS	$	0.62		$	(0.02	)

Net income (loss)/shares	$	35,116	56,494	$	(1,190	)	57,287
Effect of Dilutive Securities Stock options			619
Adjusted net income (loss)/shares	$	35,116	57,113	$	(1,190	)	57,287
Diluted EPS	$	0.61		$	(0.02	)

For the nine months ended September 30:

	2003			2002
(in thousands, except per share)	Income (Numerator)		Shares (Denominator)	Income (Numerator)		Shares (Denominator)
Net income/shares	$	99,043	57,014	$	831	57,159
Basic EPS	$	1.74		$	0.01

Net income/shares	$	99,043	57,014	$	831	57,159
Effect of Dilutive Securities Stock options			532			568
Adjusted net income/shares	$	99,043	57,546	$	831	57,727
Diluted EPS	$	1.72		$	0.01

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

For the three months ended September 30:

(in thousands, except exercise prices)	2003	2002
Options excluded from dilution calculation	1,504	2,964
Range of exercise prices	$ 37.92 - $ 43.21	$ 32.54 - $ 43.21
Weighted average exercise price	$ 41.32	$ 37.38

For the nine months ended September 30:

(in thousands, except exercise prices)	2003	2002
Options excluded from dilution calculation	1,661	2,237
Range of exercise prices	$ 37.25 - $ 43.21	$ 35.40 - $ 43.21
Weighted average exercise price	$ 40.98	$ 39.79

(4) GEOGRAPHICAL DATA

The Company has operations throughout the world and generally manages its operations by country. The following information is grouped into five reporting segments that are all primarily in the business of natural gas and crude oil exploration and production: (1) United States, (2) North Sea, (3) Equatorial Guinea, (4) Israel, and (5) Other International, Corporate and Marketing. Other International includes operations in Argentina, China, Ecuador and Vietnam. The following segment data was prepared on the same basis as Noble Energy’s consolidated financial statements. The information does not include the effects of income taxes.

Oil & Gas Operations

Three Months Ended 9/30/2003

(Dollars in Thousands)

	Consolidated			United States			North Sea			Equatorial Guinea		Israel			Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	88,630		$	39,217		$	18,305		$	13,685	$			$	17,423
Gas Sales	117,020			112,224			3,914			860					22
Gathering, Marketing and Processing Revenue	16,877														16,877
Electricity Sales	12,855														12,855
Income from Unconsolidated Subsidiaries	8,584									8,584
Other	(1,850		)	(4,481		)	(473		)			(17		)	3,121
Total Revenues	242,116			146,960			21,746			23,129		(17		)	50,298

COSTS AND EXPENSES
Oil and Gas Operations	37,508			25,339			2,407			3,798					5,964
Transportation	3,451						1,837								1,614
Oil and Gas Exploration	25,481			21,596			764			1		1,651			1,469
Gathering, Marketing and Processing Costs	14,708														14,708
Electricity Generation	12,818														12,818
DD&A	73,155			59,007			7,087			1,286		10			5,765
SG&A	12,495			3,852						182					8,461
Accretion of Asset Retirement Obligation	2,401														2,401
Interest Expense (net)	11,010														11,010
Total Costs and Expenses	193,027			109,794			12,095			5,267		1,661			64,210

OPERATING INCOME (LOSS)	$	49,089		$	37,166		$	9,651		$	17,862	$	(1,678	)	$	(13,912	)
Discontinued Operations	4,609			4,609
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS	$	53,698		$	41,775		$	9,651		$	17,862	$	(1,678	)	$	(13,912	)

Three Months Ended 9/30/2002

(Dollars in Thousands)

	Consolidated			United States			North Sea		Equatorial Guinea		Israel			Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	72,928		$	35,078		$	18,041	$	11,483	$			$	8,326
Gas Sales	83,620			79,859			3,812		922					(973		)
Gathering, Marketing and
Processing Revenue	18,940													18,940
Electricity Sales	3,931													3,931
Income from Unconsolidated
Subsidiaries	5,184								5,184
Other	(1,901		)	(2,561		)	196				(9		)	473
Total Revenues	182,702			112,376			22,049		17,589		(9		)	30,697

COSTS AND EXPENSES
Oil and Gas Operations	31,289			23,816			2,522		2,466					2,485
Transportation	4,010						2,429							1,581
Oil and Gas Exploration	50,628			36,489			414		4		233			13,488
Gathering, Marketing and
Processing Costs	15,216													15,216
Electricity Generation	3,117													3,117
DD&A	60,076			50,328			5,986		1,781		9			1,972
SG&A	14,835			8,844			184		572		1			5,234
Interest Expense (net)	10,330													10,330
Total Costs and Expenses	189,501			119,477			11,535		4,823		243			53,423

OPERATING INCOME (LOSS)	$	(6,799	)	$	(7,101	)	$	10,514	$	12,766	$	(252	)	$	(22,726	)
Discontinued Operations	3,867			3,867
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS	$	(2,932	)	$	(3,234	)	$	10,514	$	12,766	$	(252	)	$	(22,726	)

Oil & Gas Operations

Nine Months Ended 9/30/2003

(Dollars in Thousands)

	Consolidated			United States			North Sea			Equatorial Guinea		Israel			Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	266,302		$	113,379		$	59,394		$	44,844	$			$	48,685
Gas Sales	365,890			349,403			13,558			2,841					88
Gathering, Marketing and Processing Revenue	54,657														54,657
Electricity Sales	41,361														41,361
Income from Unconsolidated Subsidiaries	33,190									33,190
Other	(7,547		)	(11,136		)	(294		)			(16		)	3,899
Total Revenues	753,853			451,646			72,658			80,875		(16		)	148,690

COSTS AND EXPENSES
Oil and Gas Operations	111,719			74,394			8,130			11,965					17,230
Transportation	10,570						6,420								4,150
Oil and Gas Exploration	95,559			64,500			8,216			51		7,106			15,686
Gathering, Marketing and Processing Costs	48,690														48,690
Electricity Generation	36,439														36,439
DD&A	217,690			175,036			22,228			4,892		30			15,504
SG&A	41,069			12,459						339					28,271
Accretion of Asset Retirement
Obligation	7,015														7,015
Interest Expense (net)	36,785														36,785
Total Costs and Expenses	605,536			326,389			44,994			17,247		7,136			209,770

OPERATING INCOME (LOSS)	$	148,317		$	125,257		$	27,664		$	63,628	$	(7,152	)	$	(61,080	)
Discontinued Operations	20,546			20,546
Cumulative Effect of SFAS 143	(8,983		)	(8,983		)
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS	$	159,880		$ 136,820			$	27,664		$	63,628	$	(7,152	)	$	(61,080	)

Nine Months Ended 9/30/2002

(Dollars in Thousands)

	Consolidated			United States			North Sea			Equatorial Guinea		Israel			Other Int’l, Corporate & Marketing
REVENUES
Oil Sales	$	196,942		$	90,355			$	52,510	$	31,540	$			$	22,537
Gas Sales	246,816			232,439				14,253		2,144					(2,020		)
Gathering, Marketing and Processing Revenue	47,597														47,597
Electricity Sales	3,931														3,931
Income from Unconsolidated Subsidiaries	1,278									1,278
Other	972			(411		)		197				(9		)	1,195
Total Revenues	497,536			322,383				66,960		34,962		(9		)	73,240

COSTS AND EXPENSES
Oil and Gas Operations	79,911			64,643				7,695		6,973					600
Transportation	13,227							7,167							6,060
Oil and Gas Exploration	107,266			83,941				3,594		3		1,903			17,825
Gathering, Marketing and Processing Costs	40,151														40,151
Electricity Generation	3,117														3,117
DD&A	184,590			152,829				19,827		3,852		22			8,060
SG&A	38,241			24,577				457		1,293		3			11,911
Interest Expense (net)	33,360														33,360
Total Costs and Expenses	499,863			325,990				38,740		12,121		1,928			121,084

OPERATING INCOME (LOSS)	$	(2,327	)	$	(3,607	)		$	28,220	$	22,841	$	(1,937	)	$	(47,844	)
Discontinued Operations	7,236			7,236
OPERATING INCOME (LOSS) AFTER DISCONTINUED OPERATIONS	$	4,909		$	3,629			$	28,220	$	22,841	$	(1,937	)	$	(47,844	)

LONG-LIVED ASSETS (PRIMARILY PROPERTY, PLANT AND EQUIPMENT, NET)
As of 9/30/03	$	2,174,048		$	1,098,281			$	80,165	$	309,940	$	238,866		$	446,796
As of 9/30/02	$	2,063,563		$	1,227,780			$	90,087	$	116,157	$	163,033		$	466,506

(5) DERIVATIVES AND HEDGING ACTIVITIES

The Company, directly or through its subsidiaries, from time to time, uses various derivative arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price swaps, costless collars and other contractual arrangements. Although these arrangements expose the Company to credit risk, the Company takes reasonable steps to protect itself from nonperformance by its counterparties including periodic assessment of necessary provisions for bad debt allowance; however, the Company is not able to predict sudden changes in its counterparties’ creditworthiness. The Company accounts for its derivative arrangements under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and has elected to designate its derivative arrangements as cash flow hedges. Gains and losses from such arrangements related to the Company’s crude oil and natural gas production and which qualify for hedge accounting treatment are recorded in oil and gas sales and royalties upon sale of the associated products.

The Company entered into various natural gas costless collars and crude oil costless collar transactions related to its production for the third quarter of 2003. The table below depicts the various transactions that settled for the third quarter.

Natural Gas

Hedge MMBTUpd	185,000
Floor price range	$ 3.25 - $3.80
Ceiling price range	$ 4.00 - $5.00
Percent of daily production	51	%
Realized loss per Mcf	$(0.21	)

Crude Oil

Hedge Bpd	15,000
Floor price range	$ 23.00 - $25.00
Ceiling price range	$ 27.20 - $32.70
Percent of daily production	39	%
Realized loss per Bbl	$(0.61	)

For the first nine months of 2003, the Company entered into various natural gas costless collars and crude oil costless collar transactions related to its production. The table below depicts the various transactions that settled for the first nine months.

Natural Gas

Hedge MMBTUpd	185,000
Floor price range	$ 3.25 - $3.80
Ceiling price range	$ 4.00 - $5.20
Percent of daily production	50	%
Realized loss per Mcf	$(0.50	)

Crude Oil

Hedge Bpd	15,000
Floor price range	$ 23.00 - $25.00
Ceiling price range	$ 27.20 - $32.70
Percent of daily production	39	%
Realized loss per Bbl	$(0.97	)

As of November 10, 2003, the Company had entered into future costless collar transactions related to its natural gas and crude oil production to support the Company’s investment program as follows:

	Natural Gas		Crude Oil
Production Period	Volumes Per Day	Average Price Per MMBTU Floor - Ceiling	Volumes Per Day	Average Price Per Bbl Floor - Ceiling
4Q2003	185,000	$3.43 - $4.84	18,000	$24.22 - $30.66
1Q2004	120,000	$4.81 - $7.73	15,000	$25.33 - $31.53
2Q2004	120,000	$4.06 - $5.95	10,000	$24.50 - $30.50
3Q2004	120,000	$4.19 - $5.99	5,000	$24.00 - $30.20
4Q2004	120,000	$4.19 - $6.42

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 were 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.

The Company entered into various natural gas costless collars and crude oil costless collar transactions related to its production for the third quarter of 2002. The table below depicts the various transactions that settled for the third quarter.

Natural Gas

Hedge MMBTUpd	195,000
Floor price range	$ 2.75 - $3.25
Ceiling price range	$ 3.50 - $5.10
Percent of daily production	51	%
Realized gain per Mcf	$0.05

Crude Oil

Hedge Bpd	10,000
Floor price range	$ 23.00 - $24.00
Ceiling price range	$ 29.30 - $30.00
Percent of daily production	29	%
Realized loss per Bbl	$(0.02	)

For the first nine months of 2002, the Company entered into various natural gas costless collars and crude oil costless collar transactions related to its production. The table below depicts the various transactions that settled for the first nine months.

Natural Gas

Hedge MMBTUpd	172,051
Floor price range	$ 2.00 - $3.25
Ceiling price range	$ 2.45 - $5.10
Percent of daily production	44	%
Realized gain per Mcf	$0.04

Crude Oil

Hedge Bpd	4,487
Floor price range	$ 23.00 - $24.00
Ceiling price range	$ 29.30 - $30.00
Percent of daily production	13	%
Realized loss per Bbl	$(0.01	)

Noble Energy Marketing, Inc. (“NEMI”), from time to time, 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.

NEMI records gains and losses on derivative arrangements using mark-to-market accounting. Under this accounting method, the change in the market value of outstanding financial instruments is recognized as gains or losses in the period of change. During the three months ended September 30, 2003 and 2002, NEMI recorded mark-to-market gains of $1.3 million and $0.4 million, respectively. During the nine months ended September 30, 2003 and 2002, NEMI recorded mark-to-market gains of $1.2 million and $0.5 million, respectively.

At September 30, 2003, the Company recorded crude oil and natural gas hedge receivables of $8.0 million, crude oil and natural gas hedge liabilities of $10.8 million and other comprehensive loss, net of tax, of $1.5 million related to the Company’s cash flow hedging contracts. The Company recorded net hedging losses of $9.1 million and $61.7 million for the three months and the nine months ended September 30, 2003, respectively.

During the three month and nine month periods ending September 30, 2003, the Company had contracts with Enron North America Corporation (“ENA”) that resulted in $0.3 million and $6.6 million of income, respectively, (net of allowance) recognized in earnings. In addition, as of September 30, 2003, the Company had NYMEX-related transactions with ENA totaling 183 contracts with a mark-to-market receivable value of $1.4 million compared to 208 contracts with a mark-to-market receivable value of $2.5 million in the second quarter of 2003. For additional discussion of ENA matters, see Note 10, “Commitments and Contingencies” of this Form 10-Q.

(6) ATLANTIC METHANOL PRODUCTION COMPANY (“AMPCO”) METHANOL OPERATIONS

The following are the results of operations for the Company’s unconsolidated subsidiaries as of September 30, 2003. Noble Energy owns a 45 percent interest in AMPCO.

	Three Months Ended September 30,
(dollars in thousands) (unaudited)	2003		2002

REVENUE:
Methanol sales	$	42,220	$	38,337
Other income	4,380		(1,663		)
Total Revenue	$	46,600	$	36,674
Less cost of goods sold	22,199		19,739
Gross Margin	$	24,401	$	16,935

EXPENSES:
DD&A	$	4,906	$	5,253
Administrative	860		703
Total Expenses	$	5,766	$	5,956

NET INCOME	$	18,635	$	10,979

	Nine Months Ended September 30,
(dollars in thousands) (unaudited)	2003		2002

REVENUE:
Methanol sales	$	146,433	$	75,623
Other income	10,770		10,445
Total Revenue	$	157,203	$	86,068
Less cost of goods sold	67,076		66,582
Gross Margin	$	90,127	$	19,486

EXPENSES:
DD&A	$	10,164	$	15,647
Administrative	2,710		2,243
Total Expenses	$	12,874	$	17,890

NET INCOME	$	77,253	$	1,596

(7) COMPANY STOCK REPURCHASE PLAN

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 1.4 million shares at an average cost of $21.84 per share was funded from the Company’s 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 1.04 million shares on the open market during the first quarter of 2002.

As of June 10, 2003, the Company and the bank amended the agreement to delete the provisions that allowed the Company to net settle the contract.

had increased. The bank had the right to terminate the agreement prior to the maturity date if the Company’s share price decreased by 50 percent (to $16.77 per share) or if the Company’s credit rating was downgraded below BBB- (S&P) or Baa3 (Moody’s).

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. On July 28, 2003, the Company paid $10.0 million on the obligation and plans to extinguish the remaining $26.6 million balance by year-end 2003.

(8) RECOGNITION AND REPORTING OF GAINS AND LOSSES ON ENERGY TRADING CONTRACTS

In June 2002, the Emerging Issues Task Force (“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 material energy trading activities, the EITF has expanded its definition of energy trading activities to include the marketing activities in which the Company is engaged. As of January 1, 2003, the Company presents, in its statements of operations for all periods, its marketing activities on a net rather than a gross basis. The change significantly decreased reported marketing sales and purchases, but had no effect on operating income or cash flow. Prior results have been reclassified to present the activity on a consistent basis.

(9) RECENTLY ISSUED PRONOUNCEMENTS

SFAS No. 143, “Accounting for Asset Retirement Obligations,” issued in June 2001, 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 $99.8 million related to the United States and $10.0 million related to the North Sea.

Below is a reconciliation of the beginning and ending aggregate carrying amount of the Company’s asset retirement obligations.

(Dollars in Thousands)	Nine Months Ended September 30, 2003
Beginning of the period	$
Initial adoption entry	109,821
Liabilities incurred in the current period	6,463
Liabilities settled in the current period	(25,261		)
Accretion expense	7,015
End of the period	$	98,038

The following table summarizes the pro forma net income and earnings per share, for the three months and nine months ended September 30, 2002, for the change in accounting had it been implemented on January 1, 2002 (in thousands, except per share amounts):

	Three Months Ended						Nine Months Ended
	As Reported			Pro Forma			As Reported		Pro Forma
Net income (loss)	$	(1,190	)	$	(3,508	)	$	831	$	(6,289	)
Net income (loss) per share, basic	$	(0.02	)	$	(0.06	)	$	0.01	$	(0.11	)
Net income (loss) per share, diluted	$	(0.02	)	$	(0.06	)	$	0.01	$	(0.11	)

In addition, on a pro forma basis as required by SFAS No. 143, if the Company had applied the provisions of SFAS No. 143 as of January 1, 2002, the amount of asset retirement obligations would have been $99.7 million.

(10) COMMITMENTS AND CONTINGENCIES

affiliates, including 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.

On January 13, 2003, the Noble Defendants each filed an answer to the 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 is currently anticipated to occur in the fourth quarter 2003.

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.

(11) ACCOUNTING FOR COSTS ASSOCIATED WITH MINERAL RIGHTS

A reporting issue has arisen 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.

(12) DISCONTINUED OPERATIONS

During 2003, Noble Energy identified five property packages for disposition, and bids have now been received on all five packages. Two of the property packages were classified as discontinued operations in the second quarter, two in the third quarter and one will be classified in the fourth quarter. During the third quarter, closed property sales resulted in a pre-tax 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, pre-tax, and reported in discontinued operations. The net loss for closed and written down properties totaled $8.4 million during the third quarter. Subsequent to September 30, 2003, the remaining asset package met the criteria to be classified as held for sale. For the full year, property sales are expected to generate over $110 million in pre-tax proceeds.

The remaining asset package relating to onshore California properties which has a carrying amount of $67.4 million (including asset retirement obligations of $0.3 million) is expected to close by year-end 2003.

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 assets of such properties have been classified as “Assets held for sale” on the September 30, 2003 consolidated balance sheet and consists of the following:

(dollars in thousands)	September 30, 2003
Property, plant and equipment, net	$	62,873

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:

	Three Months Ended September 30,				Nine Months Ended September 30,
(dollars in thousands)	2003		2002		2003		2002

REVENUES
Oil and gas sales and royalties	$	24,112	$	21,443	$	78,386	$	61,665

COSTS AND EXPENSES
Write down to fair value, net	$	8,422	$		$	13,336	$
Oil and gas operations	4,330		7,015		19,100		19,831
Depreciation, depletion and amortization	6,751		10,561		25,404		34,598
	$	19,503	$	17,576	$	57,840	$	54,429

INCOME BEFORE INCOME TAXES	$	4,609	$	3,867	$	20,546	$	7,236
INCOME TAX PROVISION	1,613		1,354		7,191		2,533
INCOME FROM DISCONTINUED OPERATIONS	$	2,996	$	2,513	$	13,355	$	4,703

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.

(13) RECLASSIFICATION

Certain reclassifications have been made to the 2002 consolidated financial statements to conform to the 2003 presentation. These reclassifications are not material to the Company’s financial position.

(14) SUBSEQUENT EVENT

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.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

General. Noble Energy is including the following discussion to generally inform its existing and potential security holders of some of the risks and uncertainties that can affect the Company and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, the Company’s management or persons acting on management’s behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include, but are not limited to, projections and estimates concerning the timing and success of specific projects and the Company’s future: (1) income, (2) crude oil and natural gas production, (3) crude oil and natural gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Sometimes the Company will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information

contained in this Form 10-Q, the matters discussed in this Form 10-Q are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.

Noble Energy believes the factors discussed below are important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made herein or elsewhere by the Company or on its behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. Noble Energy does not intend to update its description of important factors each time a potential important factor arises. The Company advises its stockholders that they should: (1) be aware that important factors not described below could affect the accuracy of its forward-looking statements, and (2) use caution and common sense when analyzing its forward-looking statements in this document or elsewhere. All of such forward-looking statements are qualified in their entirety by this cautionary statement.

Volatility and Level of Hydrocarbon Commodity Prices. Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market supply and demand fundamentals and changes in the political, regulatory and economic climates and other factors that affect commodities markets generally and are outside of Noble Energy’s control. Some of Noble Energy’s projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. The Company expects its assumptions may change over time and that actual prices in the future may differ from our estimates. Any substantial or extended change in the actual prices of natural gas and/or crude oil could have a material effect on: (1) the Company’s financial position and results of operations, (2) the quantities of natural gas and crude oil reserves that the Company can economically produce, (3) the quantity of estimated proved reserves that may be attributed to its properties, and (4) the Company’s ability to fund its capital program.

Production Rates and Reserve Replacement. Projecting future rates of crude oil and natural gas production is inherently imprecise. Producing crude oil and natural gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including geological, geophysical and engineering issues, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climates. Another factor affecting production rates is Noble Energy’s ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, the Company’s ability to replace reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price environment for natural gas and crude oil, Noble Energy’s finding and development costs may not justify the use of resources to explore for and develop such reserves.

Reserve Estimates. Noble Energy’s forward-looking statements are predicated, in part, on the Company’s estimates of its crude oil and natural gas reserves. All of the reserve data in this Form 10-Q or otherwise made by or on behalf of the Company 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. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond the Company’s control affect these estimates. In addition, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore, estimates made by different engineers may vary. The results of drilling, testing and production after the date of an estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

Laws and Regulations. Noble Energy’s forward-looking statements are generally based on the assumption that the legal and regulatory environments will remain stable. Changes in the legal and/or regulatory environments could have a material effect on the Company’s future results of operations and financial condition. Noble Energy’s ability to economically produce and sell crude oil, natural gas, methanol and power is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting: (1) crude oil and natural gas production, (2) taxes applicable to the Company and/or its production, (3) the amount of crude oil and natural gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities, and (5) the marketing of competitive fuels. The Company’s operations are also subject to extensive

federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Noble Energy’s forward-looking statements are generally based upon the expectation that the Company will not be required, in the near future, to expend cash to comply with environmental laws and regulations that are material in relation to its total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, the Company is unable to accurately predict the ultimate financial impact of compliance.

Drilling and Operating Risks. Noble Energy’s drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of crude oil, natural gas or well fluids. In addition, a substantial amount of the Company’s operations are currently offshore, domestically and internationally, and subject to the additional hazards of marine operations, such as loop currents, capsizing, collision, and damage or loss from severe weather. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions.

Competition. The Company’s forward-looking statements are generally based on a stable competitive environment. Competition in the industry is intense. Noble Energy actively competes for reserve acquisitions and exploration leases and licenses, for the labor and equipment required to operate and develop crude oil and natural gas properties and in the gathering and marketing of natural gas, crude oil, methanol and power. The Company’s competitors include the major integrated oil companies, independent crude oil and natural gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers, many of whom have greater financial resources than the Company.

Noble Energy believes that the location of its properties, its expertise in exploration, drilling and production operations, the experience of its management and the efforts and expertise of its marketing units generally enable it to compete effectively. In making projections with respect to numerous aspects of the Company’s business, Noble Energy generally assumes that there will be no material adverse change in competitive conditions.

LIQUIDITY AND CAPITAL RESOURCES

Net cash provided by operating activities increased $164.7 million to $469.8 million in the nine months ended September 30, 2003 from $305.1 million in the same period of 2002. Cash and short-term investments increased from $15.4 million at December 31, 2002 to $71.4 million at September 30, 2003. These increases are primarily a result of higher natural gas and liquids prices in 2003 versus the comparable period in 2002. In addition, as of September 30, 2003, the Company has received approximately $17 million and expects to receive approximately $110 million for the full year related to the ongoing divestiture program.

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 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.

cases which have been referred to him. The mediation for this case is currently anticipated to occur in the fourth quarter 2003.

During the first nine months of 2003, the Company repaid a net $45 million on its $400 million credit facility, which resulted in the September 30, 2003 balance of $335 million. The Company also had available a $200 million 364-day credit agreement with certain commercial lending institutions. At September 30, 2003, there was a net $40 million borrowed under the $200 million credit agreement. 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. Long-term debt at September 30, 2003 was $946.0 million compared with $977.1 million at December 31, 2002. At September 30, 2003, total debt was $1.007 billion, which was a $12 million decrease over $1.019 billion at December 31, 2002.

The Company set its 2003 capital expenditures budget at approximately $510 million. Through September 30, 2003, the Company has expended approximately $395 million of its 2003 capital expenditures budget. Such expenditures are planned to be funded principally through internally generated cash flows. The Company believes that it has the capital structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows or available lines of credit and other borrowing opportunities.

The Company follows the entitlements method of accounting for its natural gas imbalances. The Company’s estimated natural gas imbalance receivables were $22.6 million at September 30, 2003 and $20.1 million at December 31, 2002. Estimated natural gas imbalance liabilities were $17.5 million at September 30, 2003 and $15.4 million at December 31, 2002. These imbalances are valued at the amount that is expected to be received or paid to settle the imbalances. The settlement of the imbalances can occur either over the life, or at the end of the life, of a well, on a volume basis or by cash settlement. The Company does not expect that a significant portion of the settlements will occur in any one year. Thus, the Company believes the settlement of natural gas imbalances will not have a material impact on its liquidity.

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.

RESULTS OF OPERATIONS

For the third quarter of 2003, the Company recorded net income of $35.1 million, or $0.62 per basic share, compared with a net loss of $1.2 million, or ($0.02) per basic share, in the third quarter of 2002. The increase in net income primarily reflected higher commodity prices and lower exploration expense. In addition, income from the methanol operations increased 66 percent, compared to the third quarter of 2002, due to a $.15 per gallon increase in methanol prices. Natural gas prices increased 50 percent, crude oil prices increased five percent and methanol prices increased 31 percent, compared with the third quarter of 2002.

During the first nine months of 2003, the Company recorded net income of $99.0 million, or $1.74 per basic share, compared with $.8 million, or $0.01 per basic share, in the first nine months of 2002. The increased earnings through the first nine months of 2003 were a result of significantly higher commodity prices and increased production volumes. Natural gas prices increased 56 percent, while crude oil prices and daily crude oil production each increased 16 percent. Income from the methanol operations increased $31.9 million through the first nine months of 2003 due to a 76 percent increase in methanol prices and a 22 percent increase in methanol sales volumes.

Certain selected geographical oil and gas operating statistics follow:

	Consolidated				United States			North Sea			Equatorial Guinea			Other International (1)

Oil & Gas Operations for the Three Months Ended 9/30/2003

Before Discontinued Operations
Daily Production
Liquids (Bbl)	38,253				19,268			6,692			5,488			6,805
Natural Gas (Mcf)	365,146			(2)	293,445			12,483			37,622			21,596			(2)

Average Realized Price
Liquids per Bbl	$		27.53		$		26.79	$		29.73	$		27.10	$		27.83
Natural Gas per Mcf	$		4.17		$		4.74	$		3.41	$		0.25	$		0.68

After Discontinued Operations
Daily Production
Liquids (Bbl)	35,038				16,053			6,692			5,488			6,805
Natural Gas (Mcf)	331,188			(2)	259,487			12,483			37,622			21,596			(2)

Average Realized Price
Liquids per Bbl	$		27.49		$		26.55	$		29.73	$		27.10	$		27.83
Natural Gas per Mcf	$		4.10		$		4.70	$		3.41	$		0.25	$		0.68

Oil & Gas Operations for the Three Months Ended 9/30/2002

Before Discontinued Operations
Daily Production
Liquids (Bbl)	34,340				19,034			7,418			4,871			3,017
Natural Gas (Mcf)	383,082				320,517			14,310			40,968			7,287			(2)

Average Realized Price
Liquids per Bbl	$	25.93			$	25.16		$	26.44		$	25.62		$	29.72
Natural Gas per Mcf	$	2.80			$	3.13		$	2.90		$	0.24		$

After Discontinued Operations
Daily Production
Liquids (Bbl)	30,271				14,965			7,418			4,871			3,017
Natural Gas (Mcf)	339,215				276,650			14,310			40,968			7,287			(2)

Average Realized Price
Liquids per Bbl	$	26.19			$	25.48		$	26.44		$	25.62		$	29.72
Natural Gas per Mcf	$	2.73			$	3.14		$	2.90		$	0.24		$

	Consolidated			United States		North Sea		Equatorial Guinea		Other International (1)

Oil & Gas Operations for the Nine Months Ended 9/30/2003

Before Discontinued Operations
Daily Production
Liquids (Bbl)	39,035			19,601		7,238		5,978		6,218
Natural Gas (Mcf)	373,364		(2)	297,097		13,817		41,817		20,633		(2)

Average Realized Price
Liquids per Bbl	$	27.54		$	26.27	$	30.06	$	27.48	$	28.68
Natural Gas per Mcf	$	4.32		$	4.94	$	3.59	$	0.25	$	0.42

After Discontinued Operations
Daily Production
Liquids (Bbl)	35,436			16,002		7,238		5,978		6,218
Natural Gas (Mcf)	340,248		(2)	263,981		13,817		41,817		20,633		(2)

Average Realized Price
Liquids per Bbl	$	27.53		$	25.96	$	30.06	$	27.48	$	28.68
Natural Gas per Mcf	$	4.18		$	4.85	$	3.59	$	0.25	$	0.42

Oil & Gas Operations for the Nine Months Ended 9/30/2002

Before Discontinued Operations
Daily Production
Liquids (Bbl)	34,454			18,460		7,940		4,988		3,066
Natural Gas (Mcf)	388,549			336,002		17,291		32,045		3,211		(2)

Average Realized Price
Liquids per Bbl	$	23.35		$	22.45	$	24.22	$	23.16	$	26.78
Natural Gas per Mcf	$	2.73		$	2.96	$	3.02	$	0.25	$	0.94

After Discontinued Operations
Daily Production
Liquids (Bbl)	30,486			14,492		7,940		4,988		3,066
Natural Gas (Mcf)	339,564			287,017		17,291		32,045		3,211		(2)

Average Realized Price
Liquids per Bbl	$	23.66		$	22.84	$	24.22	$	23.16	$	26.78
Natural Gas per Mcf	$	2.68		$	2.97	$	3.02	$	0.25	$	0.94

Bbl - - barrel

Mcf - thousand cubic feet

(1) Other International includes operations in Argentina, China, Ecuador, Israel and Vietnam.

(2) Ecuador natural gas volumes are included in Other International and Consolidated production, but are not included in natural gas sales revenue for either. Because the gas-to-power project in Ecuador is 100 percent owned by Noble Energy, intercompany natural gas sales are eliminated for accounting purposes.

Natural gas sales for the Company, excluding third-party sales by NEMI, a wholly owned subsidiary of the Company, increased 40 percent for the three months ended September 30, 2003 compared with the same period in 2002. Natural gas sales increased due to a 50 percent increase in natural gas prices, offset with a two percent decrease in average daily natural gas production volumes. Domestically, natural gas sales increased 41 percent, primarily due to a 50 percent increase in natural gas prices, offset by a decrease of six percent in average daily natural gas production volumes.

During the first nine months of 2003, natural gas sales increased 48 percent compared with the same period in 2002. Natural gas sales increased due to a 56 percent increase in natural gas prices and a slight increase in average daily natural gas production volumes. Domestically, natural gas sales increased 50 percent, primarily due to a 63 percent increase in natural gas prices, offset by a decrease of eight percent in average daily natural gas production volumes. In Equatorial Guinea, natural gas sales increased 33 percent due to an increase of 30 percent in average daily natural gas sales volumes.

Crude oil sales for the Company, excluding third-party sales by NEMI, increased 22 percent for the three months ended September 30, 2003 compared with the same period in 2002. Crude oil sales increased due to a 16 percent increase in average daily crude oil production volumes coupled with a five percent increase in crude oil prices. Domestically, crude oil sales increased 12 percent, primarily due to a seven percent increase in average daily crude oil production coupled with a four percent increase in crude oil prices. In Equatorial Guinea, crude oil sales increased 19 percent, primarily due to a 13 percent increase in average daily crude oil production coupled with a six percent increase in crude oil prices. In Other International, Corporate and Marketing, crude oil sales increased 109 percent, primarily due to start-up operations in China, which commenced in the first quarter of 2003.

During the first nine months of 2003, crude oil sales increased 35 percent compared the same period in 2002. Crude oil sales increased due to a 16 percent increase in average daily crude oil production coupled with a 16 percent increase in crude oil prices. Domestically, crude oil sales increased 25 percent, primarily due to a 14 percent increase in crude oil prices coupled with a 10 percent increase in average daily crude oil production. In Equatorial Guinea, crude oil sales increased 42 percent, primarily due to a 19 percent increase in crude oil prices coupled with a 20 percent increase in average daily crude oil production. In Other International, Corporate and Marketing, crude oil sales increased 116 percent, primarily due to the start-up operations in China, which commenced in the first quarter of 2003.

NEMI markets the majority of the Company’s domestic natural gas, as well as certain third-party natural gas. NEMI sells natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power generators and local distribution companies. NEMI markets a portion of the Company’s domestic crude oil, as well as certain third-party crude oil. As of January 1, 2003, the Company presents, in its statements of operations for all periods, its marketing activities on a net rather than a gross basis. All other expenses are recorded as gathering, marketing and processing expenses. All intercompany sales and expenses have been eliminated in the Company’s consolidated financial statements.

For the third quarter of 2003, net revenues and expenses from NEMI third-party sales totaled $16.9 million and $14.7 million, respectively, for a combined gross margin of $2.2 million. In comparison, for the third quarter of 2002, NEMI third-party sales and expenses of $18.9 million and $15.2 million, respectively, resulted in a combined gross margin of $3.7 million. For the nine months ended September 30, 2003, net revenues and expenses from NEMI third-party sales totaled $54.7 million and $48.7 million, respectively, for a combined gross margin of $6.0 million. In comparison, for the first nine months of 2002, NEMI third-party sales and expenses of $47.6 million and $40.2 million, respectively, resulted in a combined gross margin of $7.4 million. The Company adopted EITF Topic 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts,” on January 1, 2003. The result of the adoption of EITF Topic 02-03 was to account for gathering, marketing and processing revenues and expenses related to derivative trading activities on a net basis. The adoption did not have an effect on the Company’s net results from operations for any periods.

During the three-month and nine-month periods ending September 30, 2003, the Company had contracts with ENA that resulted in $.3 million and $6.6 million of income, respectively, (net of allowance) recognized in earnings. In addition, as of September 30, 2003, the Company had NYMEX-related transactions with ENA totaling 183 contracts with a mark-to-market receivable value of $1.4 million compared to 208 contracts with a mark-to-market receivable value of $2.5 million in the second quarter of 2003. For additional discussion of ENA matters, see Note 10, “Commitments and Contingencies” of this Form 10-Q.

Crude oil and natural gas exploration expense decreased $25.1 million for the three months ended September 30, 2003, as compared with the same period in 2002. The third quarter 2003 decrease is primarily due to decreased dry hole expense, which was lower by $25.0 million compared to the same period in 2002. For the nine months ended September 30, 2003, exploration expense decreased $11.7 million, as compared with the same period in 2002. The decrease was due to a $16.1 million decrease in dry hole expense, offset by an increase in undeveloped lease amortization of $2.9 million. The decrease in exploration expense resulted primarily from decisioning several significant dry holes during the same periods in 2002. During the first nine months of 2003 and 2002, the Company drilled 39 exploratory wells and 61 exploratory wells, respectively.

Crude oil and natural gas operations expense increased $6.2 million for the three months ended September 30, 2003, as compared with the same period in 2002. The increase consists primarily of a $1.1 million increase in production taxes resulting from higher commodity prices and a $3.8 million increase in operating costs associated with the start-up of new international properties. For the nine months ended September 30, 2003, operations expense increased $31.8 million, as compared with the same period in 2002. The increase consists primarily of a $6.6 million increase in production taxes resulting from higher commodity prices and a $24.1 million increase in operating costs associated with the start-up of new international properties and additional deepwater production projects.

Depreciation, depletion and amortization (“DD&A”) expense increased $13.1 million for the three months ended September 30, 2003, as compared with the same period in 2002. The unit rate of DD&A per barrel of oil equivalent (“BOE”), converting gas to oil on the basis of six MCF per barrel, was $8.81 for the third quarter of 2003. The unit rate per barrel for the same period in 2002 was $7.52. For the nine months ended September 30, 2003, the unit rate per barrel was $8.65 compared with $7.76 for the same period in 2002. The increase was primarily due to higher finding costs in the Gulf of Mexico shallow shelf in prior years and the initial capital carry associated with the Company’s joint venture with Aspect Energy. The adoption of SFAS No. 143, as of January 1, 2003, which related to accounting for asset retirement costs, also contributed to higher DD&A.

Interest expense increased three percent for the three months ended September 30, 2003 as compared with the same period in 2002. The average interest rate on short-term loans for the three-month period ending September 30, 2003 was 2.32 percent compared to 2.62 percent for the same period in 2002. Short-term borrowings outstanding for the three-month period ending September 30, 2003 averaged $21.1 million compared to $14.8 million for the same period in 2002. For the nine months ended September 30, 2003, interest expense decreased two percent as compared with the same period in 2002. The average interest rate on short-term loans for the first nine months of 2003 was 2.27 percent compared to 2.66 percent for the same period in 2002. Short-term borrowings outstanding for the nine-month period ending September 30, 2003 averaged $17.4 million compared to $15.2 million for the same period in 2002.

The Company’s effective tax rate on income before discontinued operations and cumulative effect of change in accounting principle for the nine months ending September 30, 2003 was 38.3 percent. The difference between the effective rate and the federal statutory rate of 35 percent was due primarily to higher taxes on foreign income, the provision for state income taxes and a partially offsetting tax benefit for costs incurred on the Israel project.

On January 1, 2003, the Company adopted SFAS No. 143, which requires the accretion of interest for retirement obligations. This amount totaled $2.4 million and $7.0 million, respectively, for the three months and nine months ended September 30, 2003.

FUTURE TRENDS

In Israel, Noble Energy has completed all construction necessary to begin natural gas production. The Company expects to start production during the fourth quarter of 2003. In Equatorial Guinea, the phase 2A condensate expansion project is expected to start-up during the fourth quarter of 2003. Phase 2A is expected to add gross production of 6,000 Bpd upon start-up, which is expected to occur in the first week of December 2003. The Company expects crude oil and natural gas production to increase in 2004 compared to 2003. The increase in 2004 is expected primarily from the ramp-up of production from the Mari-B field, offshore Israel and the phase 2A expansion of the Alba field in Equatorial Guinea.

The Company set its 2003 capital expenditures budget at approximately $510 million. Such expenditures are planned to be funded principally through internally generated cash flows. The Company believes that it has the capital structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows or available lines of credit and other borrowing opportunities.

Management believes that the Company is well positioned with its balanced reserves of crude oil and natural gas and downstream projects. The uncertainty of commodity prices continues to affect the crude oil, natural gas and methanol industries. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.

COMPANY STOCK REPURCHASE PLAN

As of June 10, 2003, the Company and the bank amended the agreement to delete the provisions that allowed the Company to net settle the contract.

The program was scheduled to mature in January 2003 but had been extended to January 2004. Under the provisions of the agreement with the bank, the Company could have chosen to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price had decreased, pay the bank a net amount of cash to the extent that the share price had decreased, or receive from the bank a net amount of cash to the extent that the share price had increased. The bank had the right to terminate the agreement prior to the maturity date if the Company’s share price decreased by 50 percent (to $16.77 per share) or if the Company’s credit rating was downgraded below BBB- (S&P) or Baa3 (Moody’s).

ACCOUNTING FOR COSTS ASSOCIATED WITH MINERAL RIGHTS

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of crude oil and natural gas reserves to take advantage of future price increases

that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, the Company, from time to time, has used derivative hedging instruments and may do so in the future as a means of managing its exposure to price changes.

Natural Gas

Hedge MMBTUpd	185,000
Floor price range	$ 3.25 - $3.80
Ceiling price range	$ 4.00 - $5.00
Percent of daily production	51	%
Realized loss per Mcf	$(0.21	)

Crude Oil

Hedge Bpd	15,000
Floor price range	$ 23.00 - $25.00
Ceiling price range	$ 27.20 - $32.70
Percent of daily production	39	%
Realized loss per Bbl	$(0.61	)

Natural Gas

Hedge MMBTUpd	185,000
Floor price range	$ 3.25 - $3.80
Ceiling price range	$ 4.00 - $5.20
Percent of daily production	50	%
Realized loss per Mcf	$(0.50	)

Crude Oil

Hedge Bpd	15,000
Floor price range	$ 23.00 - $25.00
Ceiling price range	$ 27.20 - $32.70
Percent of daily production	39	%
Realized loss per Bbl	$(0.97	)

As of November 10, 2003, the Company had entered into future costless collar transactions related to its natural gas and crude oil production to support the Company’s investment program as follows:

	Natural Gas		Crude Oil
Production Period	Volumes Per Day	Average Price Per MMBTU Floor - Ceiling	Volumes Per Day	Average Price Per Bbl Floor - Ceiling
4Q2003	185,000	$3.43 - $4.84	18,000	$24.22 - $30.66
1Q2004	120,000	$4.81 - $7.73	15,000	$25.33 - $31.53
2Q2004	120,000	$4.06 - $5.95	10,000	$24.50 - $30.50
3Q2004	120,000	$4.19 - $5.99	5,000	$24.00 - $30.20
4Q2004	120,000	$4.19 - $6.42

Natural Gas

Hedge MMBTUpd	195,000
Floor price range	$ 2.75 - $3.25
Ceiling price range	$ 3.50 - $5.10
Percent of daily production	51	%
Realized gain per Mcf	$0.05

Crude Oil

Hedge Bpd	10,000
Floor price range	$ 23.00 - $24.00
Ceiling price range	$ 29.30 - $30.00
Percent of daily production	29	%
Realized loss per Bbl	$(0.02	)

Natural Gas

Hedge MMBTUpd	172,051
Floor price range	$ 2.00 - $3.25
Ceiling price range	$ 2.45 - $5.10
Percent of daily production	44	%
Realized gain per Mcf	$0.04

Crude Oil

Hedge Bpd	4,487
Floor price range	$ 23.00 - $24.00
Ceiling price range	$ 29.30 - $30.00
Percent of daily production	13	%
Realized loss per Bbl	$(0.01	)

NEMI, from time to time, employs derivative arrangements in connection with its purchases and sales of production. While most of NEMI’s purchases are made for an index-based price, NEMI’s customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NEMI may convert a fixed or NYMEX sale to an index-based sales price (such as purchasing a NYMEX futures contract at the Henry Hub with an adjoining basis swap at a physical location). Due to the size of such transactions and certain restraints imposed by contract and by Company guidelines, as of September 30, 2003, the Company believes it had no material market risk exposure from NEMI’s derivative arrangements. During the third quarter of 2003, NEMI had derivative arrangements with broker-dealers that represented approximately 890,000 MMBTU’s of natural gas per day. Arrangements for October 2003 through May 2006, which range from 20,000 MMBTU’s to 757,000 MMBTU’s of natural gas per day for future physical transactions, were not closed at September 30, 2003. During the third quarter of 2002, NEMI had derivative arrangements with broker-dealers that represented approximately 1,221,000 MMBTU’s of natural gas per day. For the nine months ended September 30, 2003, NEMI had hedging transactions that represented approximately 1,082,000 MMBTU’s of natural gas per day, compared with 1,388,000 MMBTU’s of natural gas per day for the same period in 2002.

The Company has a $400 million credit agreement, which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At September 30, 2003, the Company had $335 million outstanding on its $400 million credit facility, which has a maturity date of November 30, 2006. 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. The Company also had a $200 million 364-day credit agreement, which exposed the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate was 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 September 30, 2003, there was $40 million borrowed on this credit agreement, which was subsequently reduced to $20 million on October 27, 2003. On November 3, 2003, the Company entered into a new $300 million credit facility which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. This 364-day credit facility is based on LIBOR plus a range of 62.5 to 150 basis points, depending upon the percentage of utilization. Proceeds of $40 million from the new $300 million credit facility were used to pay the $20 million balance on the expiring $200 million credit facility and other corporate obligations. All other significant Company long-term debt is fixed-rate and, therefore, does not expose the Company to the risk of earnings or cash flow loss due to changes in market interest rates.

The Company does not enter into foreign currency derivatives. The U.S. dollar is considered the functional 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. Translation gains or losses were not material in any of the periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense on the statements of operations. However, certain sales transactions are concluded in foreign currencies and the Company therefore is exposed to potential risk of loss based on fluctuation in exchange rates from time to time.

ITEM 4. CONTROLS AND PROCEDURES

Based on the evaluation of the Company’s disclosure controls and procedures by Charles D. Davidson, the Company’s principal executive officer, and James L. McElvany, the Company’s principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that the Company’s disclosure controls and procedures are effective. There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) The information required by this Item 6(a) is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.

(b) The following reports on Form 8-K were filed by the Company:

(i) On July 25, 2003, Noble Energy furnished a current report on Form 8-K to report under Item 9 that it was filing a copy of its press release announcing its financial results for its second fiscal quarter ended June 30, 2003. The date of such report (the date of the earliest event reported) was July 23, 2003.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934 as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		NOBLE ENERGY, INC.
		(Registrant)


Date	November 12, 2003	/s/ JAMES L. McELVANY
		JAMES L. McELVANY Senior Vice President, Chief Financial Officer and Treasurer

INDEX TO EXHIBITS

Exhibit Number		Exhibit

31.1		Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

31.2		Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

32.1		Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

32.2		Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)