NOBLE ENERGY INC - 10-Q Quarterly Report

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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, 2004

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 October 29, 2004: 58,815,905

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

	(Unaudited) September 30, 2004			December 31, 2003
ASSETS
Current Assets:
Cash and cash equivalents	$	160,099		$	62,374
Accounts receivable - trade, net	315,100			303,822
Derivative financial instruments	21,947			56,058
Materials and supplies inventories	14,488			11,083
Assets held for sale				21,245
Deferred taxes	24,387			7,501
Prepaid expenses	42,910			13,793
Other current assets	20,208			2,511
Total Current Assets	599,139			478,387
Property, Plant and Equipment, at cost (successful efforts method of accounting)	4,208,321			3,924,987
Less:accumulated depreciation, depletion and amortization	(1,969,635		)	(1,825,246		)
Total property, plant and equipment, net	2,238,686			2,099,741
Investment in Unconsolidated Subsidiaries	222,065			227,669
Other Assets	40,176			36,852

Total Assets	$	3,100,066		$	2,842,649

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	350,329		$	388,428
Current installments of long-term debt				153,674
Derivative financial instruments	75,168			67,562
Other current liabilities	49,334			38,506
Income taxes - current	28,630			6,548
Total Current Liabilities	503,461			654,718
Deferred Income Taxes	207,592			163,146
Asset Retirement Obligation	100,473			102,827
Other Noncurrent Liabilities	76,384			72,364
Long-Term Debt	880,187			776,021

Total Liabilities	1,768,097			1,769,076

Commitments and Contingencies

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; 62,256,390 and 60,744,583 shares issued at September 30, 2004 and December 31, 2003, respectively	207,660			202,480
Capital in excess of par value	489,394			431,208
Retained earnings	759,288			526,727
Accumulated other comprehensive loss	(48,417		)	(10,886		)
	1,407,925			1,149,529
Less: Common Stock in Treasury (3,549,976 shares, at cost)	(75,956		)	(75,956		)

Total Shareholders’ Equity	1,331,969			1,073,573

Total Liabilities and Shareholders’ Equity	$	3,100,066		$	2,842,649

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30
	2004			2003			2004			2003
Revenues:
Oil and gas sales and royalties	$	288,910		$	203,095		$	853,406		$	624,275
Gathering, marketing and processing	10,175			16,877			37,295			54,657
Electricity sales	7,504			12,855			38,369			41,361
Income from unconsolidated subsidiaries	13,585			8,584			43,953			33,190
Other income, net	6,399			2,933			12,178			4,752

Total Revenues	326,573			244,344			985,201			758,235

Costs and Expenses:
Oil and gas operations	37,562			31,871			116,298			94,194
Production taxes	6,234			4,962			17,256			15,177
Transportation	3,975			3,451			11,818			10,570
Oil and gas exploration	26,588			25,481			82,100			95,559
Gathering, marketing and processing	8,642			14,708			29,992			48,690
Electricity generation	8,600			12,818			32,034			36,439
Depreciation, depletion and amortization	76,040			76,908			234,365			226,631
Selling, general and administrative	13,326			12,495			41,518			41,069
Accretion of asset retirement obligation	2,067			2,401			7,080			7,015
Interest	17,961			15,406			48,973			46,364
Interest capitalized	(3,013		)	(4,395		)	(9,655		)	(9,578		)

Total Costs and Expenses	197,982			196,106			611,779			612,130

Income Before Taxes	128,591			48,238			373,422			146,105

Income Tax Provision	47,620			16,671			146,511			56,016

Income From Continuing Operations	80,971			31,567			226,911			90,089

Discontinued Operations, Net of Tax	2,721			3,549			14,354			14,793

Cumulative Effect of Change in Accounting Principle, Net of Tax										(5,839		)

Net Income	$	83,692		$	35,116		$	241,265		$	99,043

Earnings Per Share:
Basic -
Income from continuing operations	$	1.38		$	0.56		$	3.90		$	1.58
Discontinued operations, net of tax	0.05			0.06			0.25			0.26
Cumulative effect of change in accounting principle, net of tax										(0.10		)

Net income	$	1.43		$	0.62		$	4.15		$	1.74

Diluted -
Income from continuing operations	$	1.36		$	0.55		$	3.85		$	1.56
Discontinued operations, net of tax	0.05			0.06			0.24			0.26
Cumulative effect of change in accounting principle, net of tax										(0.10		)

Net income	$	1.41		$	0.61		$	4.09		$	1.72

Weighted average number of shares outstanding - Basic	58,453			56,494			58,068			57,014
Weighted average number of shares outstanding - Diluted	59,487			57,113			59,002			57,546

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2004			2003		2004			2003
Comprehensive Income:
Net income	$	83,692		$	35,116	$	241,265		$	99,043
Other comprehensive income, net of tax:
Unrealized gain/(loss) on cash flow hedges:
Unrealized fair value gain/(loss) during period (1)	(39,472		)	8,585		(60,775		)	(27,428		)
Less: reclassification adjustment for amounts out of OCI (2)	11,815			6,256		23,079			40,437
	(27,657		)	14,841		(37,696		)	13,009
Change in additional minimum pension liability and other	999			49		165			88
Other comprehensive income/(loss)	(26,658		)	14,890		(37,531		)	13,097

Comprehensive income	$	57,034		$	50,006	$	203,734		$	112,140

(1) Net of income tax benefit/(expense):		$	21,254		$	(4,623	)	$	32,725		$	14,769
(2) Net of income tax benefit:		$	6,362		$	3,369		$	12,427		$	21,774

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2004			2003
Cash Flows from Operating Activities:
Net income	$	241,265		$	99,043
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	234,365			226,631
Depreciation, depletion and amortization - electricity generation	15,361			19,180
Dry hole expense	37,546			46,035
Amortization of unproved leasehold costs	15,406			18,420
Non-cash effect of discontinued operations	(14,179		)	42,097
Cumulative effect of change in accounting principle, net of tax				5,839
(Gain) loss on disposal of assets	(8,291		)	10,089
Deferred income taxes	44,446			(5,907		)
Accretion of asset retirement obligation	7,080			7,015
Income from unconsolidated subsidiaries	(43,953		)	(33,190		)
Dividends received from unconsolidated subsidiary	46,125			37,575
(Increase) decrease in other	(4,567		)	9,777
Changes in operating assets and liabilities, not including cash:
(Increase) decrease in accounts receivable	11,700			(27,744		)
(Increase) decrease in other current assets	(67,107		)	(22,163		)
Increase (decrease) in accounts payable	(38,099		)	(7,403		)
Increase (decrease) in other current liabilities	46,916			57,261

Net Cash Provided by Operating Activities	524,014			482,555

Cash Flows From Investing Activities:
Capital expenditures	(457,044		)	(392,921		)
Distribution from unconsolidated subsidiaries	3,432			900
Proceeds from sale of property, plant and equipment	36,160			15,373

Net Cash Used in Investing Activities	(417,452		)	(376,648		)

Cash Flows From Financing Activities:
Exercise of stock options	53,547			6,011
Cash dividends paid	(8,705		)	(6,880		)
Issuance of long-term debt	347,688
Payment on credit facilities, net	(244,822		)	100,435
Payment on long-term debt	(20,746		)	(146,373		)
Repayment of note payable obtained in Aspect acquisition	(7,928		)	(3,160		)
Repayment of AMCCO note	(127,871		)

Net Cash Used in Financing Activities	(8,837		)	(49,967		)

Increase in Cash and Cash Equivalents	97,725			55,940

Cash and Cash Equivalents at Beginning of Period	62,374			15,442

Cash and Cash Equivalents at End of Period	$	160,099		$	71,382

Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	14,212		$	21,115
Income taxes paid	$	90,450		$	29,147
Non-cash financing and investing activities:
Treasury stock and note obligation				$	36,626

See notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The consolidated financial statements of Noble Energy, Inc. (the “Company” or “Noble Energy”), a Delaware corporation, included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and, accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. In the opinion of Noble Energy, the accompanying unaudited consolidated 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, 2004 and December 31, 2003; the results of operations for the three month and nine month periods ended September 30, 2004 and 2003; the statements of comprehensive income/(loss) for the three month and nine month periods ended September 30, 2004 and 2003; and the cash flows for the nine month periods ended September 30, 2004 and 2003. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. These consolidated 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, 2003.

Note 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,” and related interpretations.

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.

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share amounts)	2004			2003			2004			2003

Net income, as reported	$	83,692		$	35,116		$	241,265		$	99,043
Add: Stock-based compensation cost recognized, net of related tax effects	212			72			434			143
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2,062		)	(2,543		)	(6,042		)	(7,645		)
Pro forma net income	$	81,842		$	32,645		$	235,657		$	91,541
Earnings per share:
Basic - as reported	$	1.43		$	0.62		$	4.15		$	1.74
Basic - pro forma	$	1.40		$	0.58		$	4.06		$	1.61
Diluted - as reported	$	1.41		$	0.61		$	4.09		$	1.72
Diluted - pro forma	$	1.38		$	0.57		$	3.99		$	1.59

Note 2 - Employee Benefit Plans

The Company has a non-contributory defined benefit pension plan covering substantially all of its domestic employees. The Company also sponsors an unfunded restoration plan, as well as other plans that provide for health care and life insurance benefits for its employees and retirees. The following table reflects the components of net periodic benefit cost recognized by the Company related to pension and other postretirement benefit plans.

For the three months ended September 30:

	Pension Benefits						Other Benefits
(in thousands)	2004			2003			2004			2003
Service cost	$	1,408		$	1,162		$	181		$	156
Interest cost	1,559			1,431			273			262
Expected return on plan assets	(1,666		)	(1,464		)
Transition obligation recognition	(54		)	(54		)	60			60
Amortization of prior service cost	102			98			(11		)	(18		)
Recognized net actuarial loss	95						51			39
Net periodic benefit cost	$	1,444		$	1,173		$	554		$	499

For the nine months ended September 30:

	Pension Benefits						Other Benefits
(in thousands)	2004			2003			2004			2003
Service cost	$	4,133		$	3,486		$	527		$	467
Interest cost	4,654			4,292			816			787
Expected return on plan assets	(5,078		)	(4,392		)
Transition obligation recognition	(162		)	(162		)	180			180
Amortization of prior service cost	302			295			(40		)	(55		)
Recognized net actuarial loss	261						153			118
Net periodic benefit cost	$	4,110		$	3,519		$	1,636		$	1,497

For 2004, the expected return assumption is 8.5 percent and the assumed discount rate is 6.25 percent.

As of October 15, 2004, the Company has contributed, during 2004, $3.2 million to its defined benefit pension plan.

Note 3 - Income Tax Provision

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2004		2003			2004			2003
Current	$	43,302	$	18,136		$		102,624	$	57,255
Deferred	4,318		(1,465		)	43,887			(1,239		)

Total Income Tax Provision	$	47,620	$	16,671		$	146,511		$	56,016

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 third quarter 2004, the Company recognized a deferred tax benefit of $9.5 million related to the elimination of a valuation allowance associated with the Company’s foreign loss carryforwards in China. Due to the positive results of recent drilling activities in China and projections of future taxable income, management now believes it is more likely than not that the deferred tax asset related to the China foreign loss carryforward will be realized. As of September 30, 2004, the Company has no valuation allowance related to its foreign loss carryforwards.

The income tax provisions associated with discontinued operations were $1.5 million and $1.9 million for the three-month periods ending September 30, 2004 and 2003, respectively, and $7.7 million and $8.0 million for the nine-month periods ending September 30, 2004 and 2003, respectively.

Note 4 - Basic Earnings Per Share and Diluted Earnings Per Share

Basic earnings per share (“EPS”) of common stock were computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of common stock include the effect of outstanding stock options. The following table summarizes the calculation of basic and diluted EPS.

For the three months ended September 30:

	2004					2003
(in thousands, except per share)	Income (Numerator)				Shares (Denominator)	Income (Numerator)				Shares (Denominator)
Net income/shares	$	83,692			58,453	$	35,116			56,494
Basic EPS			$	1.43				$	0.62

Net income/shares	$	83,692			58,453	$	35,116			56,494
Effect of Dilutive Securities Stock options					1,034					619
Adjusted net income/shares	$	83,692			59,487	$	35,116			57,113
Diluted EPS			$	1.41				$	0.61

For the nine months ended September 30:

	2004					2003
(in thousands, except per share)	Income (Numerator)				Shares (Denominator)	Income (Numerator)				Shares (Denominator)
Net income/shares	$	241,265			58,068	$	99,043			57,014
Basic EPS			$	4.15				$	1.74

Net income/shares	$	241,265			58,068	$	99,043			57,014
Effect of Dilutive Securities Stock options					934					532
Adjusted net income/shares	$	241,265			59,002	$	99,043			57,546
Diluted EPS			$	4.09				$	1.72

The table below reflects the number of options excluded from the EPS calculation above for 2003, as they were antidilutive. There were no antidilutive options for the first nine months of 2004 as the average market price of Company common stock for that period was in excess of the exercise price for all options outstanding.

	Three Months Ended September 30,	Nine Months Ended September 30,
(in thousands, except exercise prices)	2003	2003
Options excluded from dilution calculation	1,504	1,661
Range of exercise prices	$37.92 - $43.21	$37.25 - $43.21
Weighted average exercise price	$41.32	$40.98

Note 5 - 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 and Ecuador. The following 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 September 30, 2004

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel		Equatorial Guinea		Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	140,012	$	60,216	$	23,945	$		$	32,336	$	23,515
Gas Sales	148,898		125,686		3,828		18,318		1,056		10
Gathering, Marketing and Processing Revenue	10,175										10,175
Electricity Sales	7,504										7,504
Income from Unconsolidated Subsidiaries	13,585								13,585
Other	6,399		2,877		90		1,161		137		2,134
Total Revenues	326,573		188,779		27,863		19,479		47,114		43,338

Costs and Expenses
Oil and Gas Operations	37,562		23,338		2,729		2,126		5,576		3,793
Production Taxes	6,234		4,589								1,645
Transportation	3,975				2,034						1,941
Oil and Gas Exploration	26,588		21,419		3,843		135		22		1,169
Gathering, Marketing and Processing Costs	8,642										8,642
Electricity Generation	8,600										8,600
DD&A	76,040		58,328		3,985		3,013		3,819		6,895
SG&A	13,326		3,609						80		9,637
Accretion of Asset Retirement Obligation	2,067		1,754		264		49
Interest Expense (net)	14,948										14,948
Total Costs and Expenses	197,982		113,037		12,855		5,323		9,497		57,270

Operating Income from Continuing Operations	$	128,591	$	75,742	$	15,008	$	14,156	$	37,617	$	(13,932	)
Discontinued Operations	4,186		4,186

Income Before Taxes	$	132,777	$	79,928	$	15,008	$	14,156	$	37,617	$	(13,932	)

Oil & Gas Operations

Three Months Ended September 30, 2003

(Dollars in Thousands)

	Consolidated		United States			North Sea			Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	86,314	$	36,901		$	18,305		$			$	13,685	$	17,423
Gas Sales	116,781		111,985			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	2,933		(425		)	(473		)	(17		)			3,848
Total Revenues	244,344		148,461			21,746			(17		)	23,129		51,025

Costs and Expenses
Oil and Gas Operations	31,871		21,338			2,407						3,798		4,328
Production Taxes	4,962		3,326											1,636
Transportation	3,451					1,837								1,614
Oil and Gas Exploration	25,481		21,596			764			1,651			1		1,469
Gathering, Marketing and Processing Costs	14,708													14,708
Electricity Generation	12,818													12,818
DD&A	76,908		62,760			7,087			10			1,286		5,765
SG&A	12,495		3,852									182		8,461
Accretion of Asset Retirement Obligation	2,401		2,171			230
Interest Expense (net)	11,011													11,011
Total Costs and Expenses	196,106		115,043			12,325			1,661			5,267		61,810

Operating Income from Continuing Operations	$	48,238	$	33,418		$	9,421		$	(1,678	)	$	17,862	$	(10,785	)
Discontinued Operations	5,460		5,460

Income Before Taxes	$	53,698	$	38,878		$	9,421		$	(1,678	)	$	17,862	$	(10,785	)

Oil & Gas Operations

Nine Months Ended September 30, 2004

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel		Equatorial Guinea			Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	412,425	$	189,225	$	71,187	$		$	89,807		$	62,206
Gas Sales	440,981		390,368		13,913		33,498		3,116			86
Gathering, Marketing and Processing Revenue	37,295											37,295
Electricity Sales	38,369											38,369
Income from Unconsolidated Subsidiaries	43,953								43,953
Other	12,178		3,992		1,723		1,259		(317		)	5,521
Total Revenues	985,201		583,585		86,823		34,757		136,559			143,477

Costs and Expenses
Oil and Gas Operations	116,298		75,901		8,143		5,123		16,616			10,515
Production Taxes	17,256		13,591									3,665
Transportation	11,818				6,639							5,179
Oil and Gas Exploration	82,100		68,203		9,805		803		158			3,131
Gathering, Marketing and Processing Costs	29,992											29,992
Electricity Generation	32,034											32,034
DD&A	234,365		184,271		14,426		6,464		9,575			19,629
SG&A	41,518		10,464		1				228			30,825
Accretion of Asset Retirement Obligation	7,080		6,066		886		128
Interest Expense (net)	39,318											39,318
Total Costs and Expenses	611,779		358,496		39,900		12,518		26,577			174,288

Operating Income from Continuing Operations	$	373,422	$	225,089	$	46,923	$	22,239	$	109,982		$	(30,811	)
Discontinued Operations	22,083		22,083

Income Before Taxes	$	395,505	$	247,172	$	46,923	$	22,239	$	109,982		$	(30,811	)

Oil & Gas Operations

Nine Months Ended September 30, 2003

(Dollars in Thousands)

	Consolidated			United States			North Sea			Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	259,070		$	106,147		$	59,394		$			$	44,844	$	48,685
Gas Sales	365,205			348,718			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	4,752			1,163			(294		)	(16		)			3,899
Total Revenues	758,235			456,028			72,658			(16		)	80,875		148,690

Costs and Expenses
Oil and Gas Operations	94,194			61,013			8,130						11,965		13,086
Production Taxes	15,177			11,033											4,144
Transportation	10,570						6,420								4,150
Oil and Gas Exploration	95,559			64,500			8,216			7,106			51		15,686
Gathering, Marketing and Processing Costs	48,690														48,690
Electricity Generation	36,439														36,439
DD&A	226,631			183,977			22,228			30			4,892		15,504
SG&A	41,069			12,459									339		28,271
Accretion of Asset Retirement Obligation	7,015			6,362			653
Interest Expense (net)	36,786														36,786
Total Costs and Expenses	612,130			339,344			45,647			7,136			17,247		202,756

Operating Income from Continuing Operations	$	146,105		$	116,684		$	27,011		$	(7,152	)	$	63,628	$	(54,066	)
Discontinued Operations	22,758			22,758
Cumulative Effect of SFAS 143	(8,983		)	(8,983		)

Income Before Taxes	$	159,880		$	130,459		$	27,011		$	(7,152	)	$	63,628	$	(54,066	)

Long-Lived Assets, (Primarily Property, Plant and Equipment, Net)
As of 09/30/04	$	2,238,686		$	964,824		$	69,976		$	244,920		$	503,871	$	455,095
As of 12/31/03	$	2,099,741		$	977,583		$	77,293		$	253,482		$	370,430	$	420,953

Total Assets
As of 09/30/04	$	3,100,066		$	1,112,049		$	192,809		$	273,079		$	764,343	$	757,786
As of 12/31/03	$	2,842,649		$	1,037,106		$	163,381		$	267,915		$	620,663	$	753,584

Note 6 - Derivatives and Hedging Activities

Cash Flow Hedges – The Company, from time to time, uses various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such instruments include fixed price hedges, variable to fixed price swaps, costless collars and other contractual arrangements. Although these derivative instruments expose the Company to credit risk, the Company takes reasonable steps to protect itself from nonperformance by its counterparties and periodically assesses 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 instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and has elected to designate its derivative instruments as cash flow hedges. Derivative instruments designated as cash flow hedges are reflected at fair value on the Company’s consolidated balance sheets. Changes in fair value, to the extent the hedge is effective, are reported in accumulated other comprehensive income until the forecasted transaction occurs. Gains and losses from such derivative instruments 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 in the Company’s

consolidated statements of operations upon sale of the associated products. Hedge effectiveness is assessed at least quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other income.

The Company entered into various crude oil and natural gas costless collars related to its crude oil and natural gas production for the three months and nine months ended September 30, 2004 and 2003 as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
Natural Gas	2004	2003	2004	2003
Hedge MMBTUpd	120,000	185,000	120,379	185,000
Floor price range	$4.00 - $4.25	$3.25 - $3.80	$3.75 - $5.00	$3.25 - $3.80
Ceiling price range	$5.60 - $6.20	$4.00 - $5.00	$5.16 - $9.65	$4.00 - $5.20
Percent of daily production	32%	56%	33%	54%

	Three Months Ended September 30,		Nine Months Ended September 30,
Crude Oil	2004	2003	2004	2003
Hedge Bpd	15,000	15,000	15,006	15,000
Floor price range	$24.00 - $27.00	$23.00 - $25.00	$24.00 - $27.00	$23.00 - $25.00
Ceiling price range	$30.20 - $31.70	$27.20 - $32.70	$30.20 - $32.65	$27.20 - $32.70
Percent of daily production	35%	44%	33%	44%

The Company included losses of $18.0 million and $9.6 million related to cash flow hedges in oil and gas sales and royalties during third quarter 2004 and 2003, respectively. The Company recorded $3.7 million of ineffectiveness related to cash flow hedges during third quarter 2004 as an increase in revenues. No ineffectiveness was recorded in third quarter 2003.

The Company included losses of $35.2 million and $62.2 million related to cash flow hedges in oil and gas sales and royalties during the nine-month periods ended September 30, 2004 and 2003, respectively. The Company recorded $.8 million of ineffectiveness related to cash flow hedges during the nine-month period ended September 30, 2004 as a decrease in revenues. No ineffectiveness was recorded in the nine-month period ended September 30, 2003.

As of October 21, 2004, 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	MMBTUpd	Average Price Per MMBTU Floor - Ceiling	Bopd	Average Price Per Bbl Floor - Ceiling
4Q2004	120,000	$4.19 - $6.42	20,000	$29.38 - $39.66
1Q2005	95,000	$5.24 - $8.57	20,788	$32.32 - $42.88
2Q2005	75,000	$5.00 - $7.46	20,250	$31.12 - $43.28
3Q2005	75,000	$5.00 - $7.38	20,745	$31.65 - $44.69
4Q2005	75,000	$5.00 - $7.66	20,295	$31.12 - $43.99
1Q2006	15,000	$5.00 - $8.00	3,966	$29.00 - $35.50
2Q2006			3,558	$29.00 - $34.30

If commodity prices were to stay the same as they were at September 30, 2004, approximately $53.7 million of net deferred losses related to the fair values of the Company’s derivative financial instruments included in accumulated other comprehensive loss at September 30, 2004 would be reversed during the next twelve months as the forecasted transactions actually occur, and settlements would be recorded as a reduction in oil and gas sales and royalties. All forecasted transactions currently being hedged are expected to occur by June 30, 2006.

Other Derivative Financial Instruments – Noble Energy Marketing, Inc. (“NEMI”), from time to time, employs various derivative instruments in connection with its purchases and sales of third-party production to lock in profits or limit exposure to natural 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 instruments using mark-to-market accounting. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. During the three months ended September 30, 2004 and 2003, NEMI recorded gains of $.2 million and $1.3 million, respectively, related to derivative instruments. During the nine months ended September 30, 2004 and 2003, NEMI recorded gains of $.02 million and $1.2 million, respectively, related to derivative instruments.

During the nine-month period ending September 30, 2004, the Company had contracts with Enron North America Corporation (“ENA”) that resulted in $1.1 million of income (net of allowance) recognized in earnings. In addition, as of September 30, 2004, the Company had NYMEX-related transactions with ENA totaling 25 contracts with a mark-to-market receivable value of $0.5 million compared to 149 contracts with a mark-to-market receivable value of $1.8 million as of December 31, 2003. For additional discussion of ENA matters, see “Note 10 - Commitments and Contingencies” of this Form 10-Q.

Note 7 - Unconsolidated Subsidiaries

The Company has investments, at various percentages of ownership, in subsidiaries that are accounted for using the equity method of accounting. These subsidiaries include Atlantic Methanol Capital Company (“AMCCO”), through which the Company has an interest in a methanol plant in Equatorial Guinea. The following is a summarized, combined statement of operations information for subsidiaries accounted for using the equity method:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2004			2003			2004			2003

Revenues:
Methanol sales	$	55,219		$	42,220		$	163,284		$	146,433
Other income	11,003			4,380			23,025			10,770
Total Revenue	66,222			46,600			186,309			157,203

Expenses:
Cost of goods manufactured	30,941			22,199			72,735			67,076
DD&A	4,830			4,906			14,627			10,164
SG&A	798			860			2,694			2,710
Total Costs and Expenses	36,569			27,965			90,056			79,950

Net Income	$		29,653	$		18,635	$		96,253	$	77,253

Note 8 - Debt

In August 2004, the Company repaid the $125 million Series A-2 Notes that were due in December 2004. In connection with the repayment, the Company recognized a loss of $2.9 million, ($1.9 million after tax) which is included in interest expense in the Company’s consolidated statements of operations. The repayment of the Notes was funded with borrowings under the Company’s credit facility.

In October 2004, the Company replaced its $300 million 364-day credit agreement with a new $400 million five-year credit agreement due October 2009. The interest rate on the new credit agreement is based on a Eurodollar rate plus a range of 30 to 112.5 basis points depending on the percentage of utilization and credit rating. Proceeds of $85 million were drawn under the new $400 million credit agreement and used to repay the balance outstanding under the 364-day credit agreement.

The Company, from time to time, uses short-term loans to fund its operations. As of September 30, 2004, there were no short-term loans outstanding.

Note 9 - Asset Retirement Obligations

The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” 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. The Company also recognized a non-cash pre-tax charge of $9.0 million ($5.8 million, net of tax) as the cumulative effect of change in accounting principle due to adoption of this standard in the first quarter of 2003. The Company’s asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and gas properties.

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

	Nine Months Ended September 30,
(in thousands)	2004			2003
Beginning of the period	$	102,827		$
Initial adoption entry				109,821
Liabilities incurred in the current period	3,383			6,463
Liabilities settled in the current period	(12,817		)	(25,261		)
Accretion expense	7,080			7,015
End of the period	$	100,473		$	98,038

Note 10 - Commitments and Contingencies

On October 15, 2002, Noble Gas Marketing, Inc. and Samedan Oil Corporation, 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 $12 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 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. 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. Mediation sessions were held on December 17, 2003 and May 21, 2004, with no resolution being reached. The Company expects to continue mediation in the fourth quarter 2004.

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.

Note 11 – Impact of Hurricane Ivan

In mid-September 2004, Hurricane Ivan moved through the Gulf of Mexico resulting in infrastructure damage at Main Pass 293/305/306 (100 percent working interest). The net book value of assets destroyed totaled $24.0 million. The Company has written off this amount and has accrued a receivable of $23.0 million related to expected insurance recoveries, resulting in a net loss of $1 million, the amount equal to the insurance deductible. Shut-in production lowered production levels by approximately 2,900 Boepd during the third quarter.

Note 12 - Discontinued Operations

Pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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 in 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)	2004			2003		2004			2003
Revenues:
Oil and gas sales and royalties	$	10		$	26,667	$	12,468		$	86,303

Costs and Expenses:
Purchase price and accrual adjustments	(4,580		)			(14,179		)
Write down to market value and realized gain				8,422					13,336
Oil and gas operations	404			5,005		4,564			21,448
Depreciation, depletion and amortization				7,780					28,761
Total Costs and Expenses	(4,176		)	21,207		(9,615		)	63,545

Income Before Income Taxes	4,186			5,460		22,083			22,758
Income Tax Provision	1,465			1,911		7,729			7,965
Income From Discontinued Operations	$	2,721		$	3,549	$	14,354		$	14,793

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

Note 13 - Recently Issued Pronouncements and Emerging Issues

Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 — In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”) became law. The Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. In May 2004, the Financial Accounting Standards Board (“FASB”) issued FSP FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP FAS 106-2”). FSP FAS 106-2 provides guidance on accounting for the effects of the Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. It also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act. Guidance applies only to the sponsor of a single-employer defined benefit postretirement health care plan for which the employer has concluded that prescription drug benefits available under the plan to some or all participants for some or all future years are actuarially equivalent to Medicare Part D and thus qualify for the subsidy under the Act and the expected subsidy will offset or reduce the employer’s share of the cost of the underlying postretirement

prescription drug coverage on which the subsidy is based. At this time, the Company does not believe that FSP FAS 106-2 will have any impact on its financial position, results of operations or cash flows because the Company’s postretirement benefit plans, as currently structured, do not provide prescription drug benefits to some or all participants, for some or all future years, which are “actuarially equivalent” to Medicare Part D and thus qualify for the subsidy under the Act.

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 was whether SFAS No. 142 required registrants to classify the costs of mineral rights associated with extracting crude oil and natural gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. In September 2004, the FASB issued FSP FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil-and Gas-Producing Entities” (“FSP FAS 142-2”). FSP FAS 142-2 indicates that the scope exception in paragraph 8(b) of Statement 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil- and gas-producing entities that are within the scope of SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” The guidance in FSP FAS 142-2 is to be applied to the first reporting period beginning after September 2, 2004. Early application is permitted in periods for which financial statements have not yet been issued.

The adoption of FSP FAS 142-2 has no effect on the Company’s balance sheet, results of operations or cash flows. Historically, the Company has included the costs of mineral rights associated with extracting crude oil and natural gas as a component of oil and gas properties in accordance with SFAS No. 19.

Accounting for Suspended Well Costs – During 2004, an issue has arisen for companies using the successful efforts method of accounting for exploration and production activities regarding the application of certain guidance in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Paragraph 19 of SFAS No. 19 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the wells are expensed, net of any salvage value. Questions have arisen in practice about the application of this guidance due to changes in oil and gas exploration processes and life cycles. The issue is whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond one year other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. The Emerging Issues Task Force has requested that the Board consider an amendment to FASB Statement No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to address this issue. The Company believes it is currently in compliance with the provisions of SFAS No. 19 as related to accounting for suspended well costs. The Company has no capitalized exploratory well costs that have been suspended for more than one year.

American Jobs Creation Act of 2004 – In October 2004, the American Jobs Creation Act of 2004 (“the Jobs Creation Act”) became law. The Jobs Creation Act includes numerous provisions that may materially affect accounting for income taxes. Provisions include a repeal of an export tax benefit for U.S.-based manufacturing activities and grants a special deduction that, depending on the circumstances, could reduce the effective tax rate. The new law also allows domestic entities to repatriate foreign earnings at a reduced rate, subject to certain limitations. The Company is currently assessing the impact of the Jobs Creation Act on its financial position, results of operations and cash flows.

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

EXECUTIVE OVERVIEW

The Company’s strong operating and financial performance continued during third quarter 2004 despite weather-related shut-ins in the Gulf of Mexico and Gulf Coast areas and infrastructure damage caused by Hurricane Ivan. Financial performance was positively impacted by increasing production and by higher commodity prices, particularly record-high oil prices realized during third quarter 2004. Financial highlights included the following:

• Third quarter 2004 net income of $83.7 million, a 138 percent increase over third quarter 2003.

• Nine-month 2004 net income of $241.3 million, a 144 percent increase over the same period of 2003.

• Nine-month 2004 cash flows provided by operating activities of $524.0 million, a nine percent increase over the same period of 2003.

• Repayment of $125 million AMCCO Series A-2 Notes and expansion of borrowing capacity with a new $400 million credit facility.

Third quarter 2004 operational highlights as compared with third quarter 2003 included:

• A 17 percent increase in daily production, including a three percent domestic increase and a 44 percent international increase.

• Increases of 30 percent in the average realized crude oil price and 10 percent in the average realized natural gas price.

• Increasing international contributions reflecting continued ramp ups of natural gas sales in Israel and condensate production from Phase 2A in Equatorial Guinea.

• Acquisition of an interest in a Production Sharing Contract (“PSC”) with the Republic of Equatorial Guinea covering Block “I” offshore Bioko Island (40 percent working interest). Block “I” is immediately adjacent to Block “O”, which was awarded to Noble Energy in April 2004 (45 percent working interest).

• A 15 percent decrease in per unit depreciation, depletion and amortization (“DD&A”) expense.

Effects of Current Commodity Price Environment – During third quarter 2004, oil prices have risen to record levels. Crude oil for November delivery has recently traded over $50.00 per barrel on both the New York Mercantile Exchange and London’s International Petroleum Exchange. The rise in oil prices has been driven by concerns about supply in the face of increasing world demand for petroleum. The slow recovery of production that had been shut in due to hurricanes in the Gulf of Mexico and concerns about possible disruption of supplies from international producing locations, coupled with increasing demand from developing nations, are currently resulting in record high oil prices.

Effect of Hurricane Ivan – Due to Hurricane Ivan, Noble Energy temporarily suspended production operations in the Gulf of Mexico on September 14, 2004. Shut-in production lowered production levels by approximately 2,900 Boepd during the third quarter. Essentially all of Noble Energy’s production operations in the Gulf of Mexico have been resumed, with the exception of Main Pass 293/305/306. As a result of infrastructure damage incurred due to Hurricane Ivan, Main Pass 293/305/306 is expected to remain shut-in for the rest of 2004 pending the design and implementation of a plan to return the field to production. No date has been set for returning Main Pass 293/305/306 to production. Prior to Hurricane Ivan, net production at Main Pass 293/305/306 was approximately 3,400 Boepd. Costs related to clean-up and redevelopment of the area are not expected to have a significant effect on cash flows as the loss has been fully insured, subject to a deductible of $1 million.

LIQUIDITY AND CAPITAL RESOURCES

Overview

The Company’s primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of crude oil and natural gas properties, to repay outstanding borrowings or to pay other contractual commitments, for interest payments on debt, to pay cash dividends on common stock and to fund contributions to the Company’s pension and postretirement benefit plans. The Company’s traditional sources of liquidity are its cash on hand, cash flows from operations and available borrowing capacity under its credit facilities. Funds may also be generated from occasional sales of non-

strategic crude oil and natural gas properties. The Company’s current ratio (current assets divided by current liabilities) was 1.19:1 at September 30, 2004 compared with .73:1 at December 31, 2003. The improvement in the current ratio resulted primarily from a $97.7 million increase in the period-end balance of cash and cash equivalents and a $153.7 million decrease in current installments of long-term debt.

Cash Flows

Operating Activities – For the nine-month period ending September 30, 2004, the Company reported a $41.5 million increase in net cash provided by operating activities as compared with the same period of 2003. Net cash provided by operating activities totaled

$524.0 million for the first nine months of 2004 compared to $482.6 million for 2003. The 2004 increase resulted primarily from a 32 percent increase in crude oil production and a 20 percent increase in the average realized crude oil price. These factors, combined with an eight percent increase in natural gas production and an 11 percent increase in the average realized natural gas price, resulted in a $229.1 million increase in oil and gas sales and royalties.

Investing Activities – Net cash used in investing activities totaled $417.5 million and $376.7 million for the nine-month period ending September 30, 2004 and 2003, respectively, and related primarily to capital expenditures made for the exploration, development and acquisition of oil and gas properties. In addition, during the first nine months of 2004, the Company received $36.2 million in proceeds from the sales of non-strategic crude oil and natural gas properties.

Financing Activities – Net cash used in financing activities totaled $8.8 million and $50.0 million for the nine-month period ending September 30, 2004 and 2003, respectively. Financing activities consist primarily of proceeds from and repayments of bank or other long-term debt, repayment of notes currently due and payment of cash dividends on Company common stock. During the first nine months of 2004, the Company closed an offering of $200 million senior unsecured notes, receiving net proceeds of $197.7 million and repaid the $125 million Series A-2 AMCCO Notes. In addition, the Company received $53.5 million from the exercise of stock options.

Ecuador Receivables – Certain entities purchasing electricity from the Company in Ecuador have been slow to pay their receivables. While the Company does not consider these receivables to be material, it is pursuing various strategies to protect its interests.

Capital Expenditures

Capital expenditures consisted of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2004		2003		2004		2003
Oil and gas mineral interests, equipment and facilities	$	146,592	$	132,971	$	389,668	$	384,936
Property acquisition costs	2,050		864		85,253		818
Corporate and other	1,926		644		4,118		7,475
Total capital expenditures	$	150,568	$	134,479	$	479,039	$	393,229

Total capital expenditures in the table above include seismic, lease rentals and other miscellaneous expenditures that are expensed through the statements of operations and are not included in capital expenditures from investing activities. Capital expenditures from investing activities totaled $457.0 million and $392.9 million for the nine-month period ending September 30, 2004 and 2003, respectively. The Company has funded its 2004 capital expenditures primarily from cash flow from operations.

Total capital expenditures during the nine-month period ending September 30, 2004 increased $85.8 million or 22 percent from the same period of 2003. The increase was due to the capital requirements for the expansion and drilling activities for Phase 2A and Phase 2B in Equatorial Guinea, and additional acquisition and development activities in the deepwater Gulf of Mexico.

The Company expects 2004 capital expenditures to total approximately $750 million compared to the $600 million previously announced. The $150 million expected increase in the capital budget is associated with deepwater expenditures for the

Swordfish acquisition and development, as well as the accelerated appraisal and development of the Ticonderoga discovery, including the test of the Conquest prospect offsetting Ticonderoga. The Company expects that the expanded 2004 capital expenditures budget will be funded from a combination of cash flows from operations, increases in borrowings and proceeds from the asset disposition program.

Financing Activities

Debt – A summary of the Company’s debt follows:

	September 30, 2004			December 31, 2003
(in thousands)	Debt		Interest Rate (%)	Debt		Interest Rate (%)
$400 million Credit Agreement, due November 2006	$			$	140,000	2.19
$300 million Credit Agreement, due October 2004	85,000		2.48	190,000		2.09
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 Series A-2 Notes, due December 2004				125,000		8.95
Term Loans, due January 2009	150,000		2.48
5.25% Senior Notes, due 2014	200,000		5.25
Israel Note, due 2004				20,746		2.16
Note obtained in Aspect acquisition, due May 2004				7,928		6.25
Outstanding debt	885,000			933,674
Less: unamortized discount	4,813			3,979
current installments of long-term debt				153,674
Long-term debt	$	880,187		$	776,021

The Company’s credit agreements are with certain commercial lending institutions. The $400 million credit agreement due November 2006 bears interest based on a Eurodollar rate plus a range of 60 to 145 basis points depending on the percentage of utilization and credit rating, and the $300 million 364-day credit agreement bore interest based on a Eurodollar rate plus a range of 62.5 to 150 basis points depending on the percentage of utilization and credit rating. At September 30, 2004, $85 million was outstanding under the credit agreements, providing the Company $615 million in unused borrowing capacity. The Company’s credit agreements are supplemented by short-term borrowings under various uncommitted credit lines that may be offered by certain banks from time to time at then-quoted rates.

The $300 million 364-day credit agreement terminated in October 2004 and was replaced by a new $400 million five-year credit agreement due October 2009. The new $400 million credit agreement bears interest based on a Eurodollar rate plus a range of 30 to 112.5 basis points depending on the percentage of utilization and credit rating. Proceeds of $85 million were drawn under the new $400 million credit agreement and used to repay the balance outstanding under the 364-day credit agreement.

During April 2004, the Company closed an offering of $200 million senior unsecured notes receiving net proceeds of approximately $197.7 million, after deducting underwriting discounts and expenses. The notes mature April 15, 2014 and pay interest semi-annually at 5.25 percent. The net proceeds from the offering were used to repay amounts outstanding under the $300 million credit agreement and for general corporate purposes.

During first quarter 2004, a subsidiary of the Company, Noble Energy Mediterranean Ltd., entered into Term Loan agreements with several commercial lending institutions for a total of $150 million. The interest rate on the borrowings is LIBOR plus an effective range of 60 to 130 basis points depending on credit rating. The agreements expire in January 2009. Proceeds were used to reduce amounts outstanding under the $400 million credit agreement.

In addition to the above-mentioned transactions, the Company repaid the $7.9 million Aspect acquisition note and the $20.7 million Israel note during the first nine months of 2004.

As a result of these transactions, the Company has reduced total outstanding debt, less unamortized discount, by $49.5 million during the first nine months of 2004. The Company’s ratio of debt-to-book capital (defined as the Company’s total debt plus its equity) was 40 percent at September 30, 2004, compared to 46 percent at December 31, 2003.

Dividends – In January, April, July and October of 2004, the Company’s Board of Directors declared quarterly cash dividends of five cents per share of common stock. Quarterly payments of four cents per share of common stock were paid during each of the first three quarters of 2003. Dividend payments were increased to five cents per share of common stock for fourth quarter 2003.

Exercise of Stock Options – The Company received $53.5 million from the exercise of stock options during the first nine months of 2004, as compared to $6.0 million during the first nine months of 2003. Proceeds received by the Company from the exercise of stock options fluctuate primarily based on the price at which the Company’s common stock trades on the New York Stock Exchange in relation to the exercise price of the options issued. During the first nine months of 2004, the average market price of the Company’s common stock increased over the first nine months of 2003 average market pricing, resulting in the exercise of more options. This resulted in higher proceeds to the Company from the exercise of stock options.

RESULTS OF OPERATIONS

During the first nine months of 2004, the Company profited from increased production and higher commodity prices. Selected financial data is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except per share amounts)	2004		2003		2004		2003
Income from continuing operations	$	80,971	$	31,567	$	226,911	$	90,089
Income from discontinued operations, net of tax	2,721		3,549		14,354		14,793
Cumulative effect of change in accounting principle, net of tax							(5,839		)
Net income	$	83,692	$	35,116	$	241,265	$	99,043
Basic earnings per share	$	1.43	$	0.62	$	4.15	$	1.74
Diluted earnings per share	$	1.41	$	0.61	$	4.09	$	1.72

Natural Gas Information

Natural gas revenues increased 28 percent during third quarter 2004, compared with third quarter 2003, and 21 percent for the first nine months of 2004, compared with the first nine months of 2003.

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2004		2003		2004		2003
Natural gas sales	$	148,898	$	116,781	$	440,981	$	365,205

The table below includes average daily natural gas production volumes and prices from continuing operations:

	Three Months Ended September 30,
	2004			2003
	Mcfpd	Price		Mcfpd	Price
United States	231,990	$	5.89	259,049	$	4.70
North Sea	9,694	$	4.29	12,483	$	3.41
Equatorial Guinea (1)	45,364	$	0.25	37,622	$	0.25
Israel	71,619	$	2.78
Other International (2)	11,762	$	0.93	21,596	$	0.68
Total (3)	370,429	$	4.51	330,750	$	4.10

	Nine Months Ended September 30,
	2004			2003
	Mcfpd	Price		Mcfpd	Price
United States	246,334	$	5.78	263,577	$	4.85
North Sea	11,471	$	4.43	13,817	$	3.59
Equatorial Guinea (1)	45,097	$	0.25	41,817	$	0.25
Israel	43,976	$	2.78
Other International (2)	20,687	$	0.72	20,633	$	0.42
Total (3)	367,565	$	4.63	339,844	$	4.18

(1) Natural gas in Equatorial Guinea is under a contract through 2026 for $0.25 per MMBTU.

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

(3) Reflects reductions of $0.01 and $0.25 per Mcf for third quarter 2004 and 2003, respectively, and reductions of $0.03 and $0.56 per Mcf for the first nine months of 2004 and 2003, respectively, from hedging activities.

Natural gas production in the U.S. and in the North Sea has been decreasing as a result of natural decline rates for properties in the Gulf of Mexico and North Sea. Hurricane Ivan resulted in shut-in production of approximately 2.2 MMcfpd for third quarter 2004. Natural gas sales in Israel commenced on February 18, 2004 and averaged 12,235 Mcfpd for first quarter 2004, 47,769 Mcfpd for second quarter 2004 and 71,619 Mcfpd for third quarter 2004. The decrease in third quarter 2004 production from other international locations was due to lower natural gas production in Ecuador caused by normal seasonal weather variation and extended summer maintenance at the Machala power plant.

Crude Oil Information

Crude oil revenues increased 62 percent during third quarter 2004, compared with third quarter 2003, and 59 percent for the first nine months of 2004, compared with the first nine months of 2003.

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2004		2003		2004		2003
Crude oil sales	$	140,012	$	86,314	$	412,425	$	259,070

The table below includes average daily crude oil production volumes and prices from continuing operations:

	Three Months Ended September 30,
	2004			2003
	Bopd	Price		Bopd	Price
United States	21,219	$	30.85	15,177	$	26.43
North Sea	5,989	$	43.46	6,692	$	29.73
Equatorial Guinea	8,573	$	41.00	5,488	$	27.10
Other International (1)	6,948	$	36.78	6,805	$	27.83
Total (2)	42,729	$	35.62	34,162	$	27.46

	Nine Months Ended September 30,
	2004			2003
	Bopd	Price		Bopd	Price
United States	22,424	$	30.80	15,045	$	25.84
North Sea	6,919	$	37.55	7,238	$	30.06
Equatorial Guinea	9,223	$	35.54	5,978	$	27.48
Other International (1)	6,890	$	32.95	6,218	$	28.68
Total (2)	45,456	$	33.11	34,479	$	27.52

(1) Other International includes Argentina and China.

(2) Reflects reductions of $4.47 and $0.68 per Bbl for third quarter 2004 and 2003, respectively, and reductions of $2.59 and $1.09 for the first nine months of 2004 and 2003, respectively, from hedging in the United States.

Crude oil production volumes in the U.S. increased 40 percent quarter-over-quarter and 49 percent for the first nine months of 2004 as compared with 2003. The increase reflects new crude oil production from the Roaring Fork field (South Timbalier 315/316) in the Gulf of Mexico. Hurricane Ivan resulted in shut-in production of approximately 2,500 Bopd for third quarter 2004. The significant production increases in Equatorial Guinea reflect the ramp-up of Phase 2A expansion for the Alba field. Other international operating results include only a partial quarter of production for China during first quarter 2003.

Gathering, Marketing and Processing

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. All intercompany sales and expenses have been eliminated in the Company’s consolidated financial statements. The Company’s gross margin from gathering, marketing and processing (“GMP”) activities was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2004		2003		2004		2003
GMP revenues	$	10,175	$	16,877	$	37,295	$	54,657
GMP expenses	8,642		14,708		29,992		48,690
Gross margin	$	1,533	$	2,169	$	7,303	$	5,967

GMP gross proceeds for 2004 have declined primarily due to a decrease in natural gas volumes being marketed by NEMI. GMP expenses for 2004 have declined due to the decrease in transportation expense and decrease in natural gas volumes. GMP expenses included bad debt expense of $1.0 million and $4.7 million for the first nine months of 2004 and 2003, respectively, related to financial derivative contracts with one of the Company’s counterparties.

NEMI recorded gains of $.2 million and $1.3 million, related to derivative instruments during third quarter 2004 and 2003, respectively, and gains of $.02 million and $1.2 million during the first nine months of 2004 and 2003, respectively.

During the first nine months of 2004, the Company had contracts with ENA that resulted in $1.1 million of income (net of allowance) recognized in GMP proceeds. In addition, as of September 30, 2004, the Company had NYMEX-related transactions with ENA totaling 25 contracts with a mark-to-market receivable value of $0.5 million compared to 149 contracts with a mark-to-market receivable value of $1.8 million as of December 31, 2003. For additional discussion of ENA matters, see “Note 10 - Commitments and Contingencies” of this Form 10-Q.

Electricity Sales - Ecuador Integrated Power Project

The Company, through its subsidiaries, EDC Ecuador Ltd. and MachalaPower Cia. Ltda., has a 100 percent ownership interest in an integrated natural gas-to-power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies fuel to the Machala power plant. Power plant activities were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2004			2003		2004		2003
Electricity sales	$	7,504		$	12,855	$	38,369	$	41,361
Electricity generation	8,600			12,818		32,034		36,439
Operating income	$	(1,096	)	$	37	$	6,335	$	4,922

Power production (Total MW)	97,291			184,470		519,167		519,342
Average power price ($ per Kwh)	$	0.077		$	0.070	$	0.074	$	0.080
Natural gas production (Mcfpd)	11,645			21,235		20,247		19,856

The lower power production and natural gas sales at the Machala power plant during third quarter 2004 were due to normal seasonal weather variation and extended summer maintenance during third quarter 2004. Maintenance on one turbine has taken longer than expected after inspections uncovered damage that required repair work in the U.S. Full repairs are expected to be completed in early November.

Income from Unconsolidated Subsidiaries

Income from unconsolidated subsidiaries includes income from Atlantic Methanol Production Company (“AMPCO”), an unconsolidated subsidiary that owns a methanol plant in Equatorial Guinea. The Company owns a 45 percent interest in AMPCO. The Company’s share of results from methanol operations were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2004		2003		2004		2003
Income from unconsolidated subsidiaries	$	13,585	$	8,584	$	43,953	$	33,190

Company’s share of methanol sales volumes (gallons)	33,451		28,419		109,012		92,746
Average realized methanol prices ($ per gallon)	$	0.74	$	0.63	$	0.67	$	0.67

Methanol production has been increasing during 2004 as a result of improved plant efficiencies. Dividends from unconsolidated subsidiaries contributed $46.1 million and $37.6 million to the Company’s net cash provided by operating activities during the first nine months of 2004 and 2003, respectively.

Costs and Expenses

Production Expenses – Oil and gas operations expense, consisting of lease operating expense and workover expense, increased $5.7 million, or 18 percent, for third quarter 2004, as compared with third quarter 2003. For the first nine months of 2004, oil and gas operations expense increased $22.1 million, or 23 percent, as compared with the first nine months of 2003. The increase in oil and gas operations expense reflects increased workover activity in the Gulf of Mexico and higher lease operating expense.

The unit rate of oil and gas operations expense per barrel of oil equivalent (“BOE”), converting gas to oil on the basis of six Mcf per barrel, was $3.91 for third quarter 2004 as compared with $3.88 for third quarter 2003. The unit rate of oil and gas operations expense per BOE was $3.98 for the first nine months of 2004 as compared with $3.79 for the first nine months of 2003. The per unit rate increased primarily due to the higher workover activity in the Gulf of Mexico and higher lease operating expense.

Production taxes have increased 26 percent quarter-over-quarter and 14 percent year-over-year due to higher commodity prices.

The tables below include oil and gas operations expense and total production expense from continuing operations:

Three Months Ended September 30, (in thousands)

	Consolidated		United States		North Sea		Israel (2)		Equatorial Guinea		Other Int’l
2004
Lease operating (1)	$	34,603	$	20,379	$	2,729	$	2,126	$	5,576	$	3,793
Workover expense	2,959		2,959
Total operations expense	37,562		23,338		2,729		2,126		5,576		3,793
Production taxes	6,234		4,589								1,645
Transportation expense	3,975				2,034						1,941
Total production expense	$	47,771	$	27,927	$	4,763	$	2,126	$	5,576	$	7,379

2003
Lease operating (1)	$	30,371	$	19,838	$	2,407	$		$	3,798	$	4,328
Workover expense	1,500		1,500
Total operations expense	31,871		21,338		2,407				3,798		4,328
Production taxes	4,962		3,326								1,636
Transportation expense	3,451				1,837						1,614
Total production expense	$	40,284	$	24,664	$	4,244	$		$	3,798	$	7,578

Nine Months Ended September 30, (in thousands)

	Consolidated		United States		North Sea		Israel (2)		Equatorial Guinea		Other Int’l
2004
Lease operating (1)	$	104,031	$	63,634	$	8,143	$	5,123	$	16,616	$	10,515
Workover expense	12,267		12,267
Total operations expense	116,298		75,901		8,143		5,123		16,616		10,515
Production taxes	17,256		13,591								3,665
Transportation expense	11,818				6,639						5,179
Total production expense	$	145,372	$	89,492	$	14,782	$	5,123	$	16,616	$	19,359

2003
Lease operating (1)	$	89,805	$	56,624	$	8,130	$		$	11,965	$	13,086
Workover expense	4,389		4,389
Total operations expense	94,194		61,013		8,130				11,965		13,086
Production taxes	15,177		11,033								4,144
Transportation expense	10,570				6,420						4,150
Total production expense	$	119,941	$	72,046	$	14,550	$		$	11,965	$	21,380

(1) Lease operating expense includes labor, fuel, repairs, replacements, saltwater disposal, ad valorem taxes and other related lifting costs.

(2) Gas sales began in February 2004.

Oil and Gas Exploration Expense – Oil and gas exploration expense consists of dry hole expense, unproved lease amortization, seismic, staff expense and other miscellaneous exploration expense, including lease rentals. Oil and gas exploration expense was $26.6 million for third quarter 2004 as compared with $25.5 million for third quarter 2003.

Oil and gas exploration expense totaled $82.1 million and $95.6 million for the first nine months of 2004 and 2003, respectively. The decrease for 2004 was due to an $8.5 million period-over-period decrease in dry hole expense.

The Company drilled 29 exploratory wells and 39 exploratory wells during the first nine months of 2004 and 2003, respectively.

Depreciation, Depletion and Amortization – Depreciation, depletion and amortization (“DD&A”) expense was $76.0 million for third quarter 2004 compared with $76.9 million for third quarter 2003. The unit rate of DD&A per BOE decreased 15 percent to $7.91 per BOE for third quarter 2004 as compared with $9.36 per BOE for third quarter 2003.

For the first nine months of 2004, DD&A expense increased three percent, to $234.4 million, as compared with $226.6 million for the first nine months of 2003. The unit rate of DD&A per BOE was $8.02 for the first nine months of 2004 as compared with $9.11 for the first nine months of 2003.

The decreases in the unit rates noted above were primarily due to increased low-cost volumes in Equatorial Guinea, Israel and domestic onshore properties combined with declining production from higher unit rate domestic offshore properties.

Selling, General and Administrative Expense – Selling, general and administrative (“SG&A”) expense increased seven percent, to $13.3 million for third quarter 2004, as compared with $12.5 million for third quarter 2003. The per unit rate of SG&A declined nine percent to $1.39 per BOE for third quarter 2004 as compared with $1.52 per BOE for third quarter 2003 due to higher production volumes.

For the first nine months of 2004, SG&A expense remained flat at $41.5 million for 2004 and $41.1 million for 2003. The per unit rate of SG&A declined 14 percent to $1.42 per BOE for the first nine months of 2004 as compared with $1.65 per BOE for the first nine months of 2003.

Interest Expense – Interest expense (net of interest capitalized) increased $3.9 million, or 36 percent, to $14.9 million for third quarter 2004 as compared with $11.0 million for third quarter 2003. Capitalized interest was $3.0 million for third quarter 2004 compared with $4.4 million for third quarter 2003.

Interest expense (net of interest capitalized) increased $2.5 million, or seven percent, to $39.3 million for the nine months ended September 30, 2004 as compared to $36.8 million for the same period in 2003. Capitalized interest remained flat at $9.7 million for the first nine months of 2004 and $9.6 million for the first nine months of 2003.

Interest expense for the third quarter and first nine months of 2004 includes the $2.9 million loss incurred on the early extinguishment of the AMCCO debt. Increases in interest expense due to an increase in fixed-rate debt, with associated higher rates, versus variable rate debt were offset by a decrease in interest expense due to an overall declining debt level.

The Company had entered into an interest rate lock to protect against a rise in interest rates prior to the issuance of its $200 million senior unsecured notes. At the time of the debt offering in April 2004, the fair market value of the interest rate lock was a payable of $7.6 million. The amount of deferred loss included in accumulated other comprehensive income/(loss) was $4.7 million, net of tax, at September 30, 2004. This amount will be reclassified into earnings as adjustments to interest expense over the term of the unsecured notes.

Income Tax Provision – Income tax expense associated with continuing operations was $47.6 million and $16.7 million for third quarter 2004 and 2003, respectively. The increase was due primarily to the increase in income from continuing operations and an increase in the effective tax rate, offset by the elimination of the Company’s deferred tax asset valuation allowance related to China foreign loss carryforwards. During the third quarter 2004, the Company recognized a deferred tax benefit of $9.5 million related to the elimination of a valuation allowance associated with the Company’s foreign loss carryforwards in China. Due to the positive results of recent drilling activities in China and projections of future taxable income, management now believes it is more likely than not that the deferred tax asset related to the China foreign loss carryforward will be realized. As of September 30, 2004, the Company has no valuation allowance related to its foreign loss carryforwards. The Company’s effective tax rate on income from continuing operations was 37 percent for third quarter 2004 and 35 percent for third quarter 2003.

Income tax expense associated with continuing operations was $146.5 million and $56.0 million for the nine months ended September 30, 2004 and 2003, respectively. The effective tax rates on income from continuing operations were 39 percent and 38 percent for the first nine months of 2004 and 2003, respectively. During the first nine months of 2004, the Company made income tax payments of $90.5 million.

Discontinued Operations

During second quarter 2004, the Company announced that it had completed its asset disposition program first announced in July 2003. The sales price for the five packages of properties totaled approximately $130 million, before closing adjustments, ($115 million after closing adjustments). The asset disposition program was an important element in improving the performance of the Company’s domestic assets. The properties sold were non-core assets that, at this stage of their productive lives, were better suited to be managed by other companies.

Pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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:

	Three Months Ended September 30,					Nine Months Ended September 30,
(dollars in thousands)	2004			2003		2004			2003
Revenues:
Oil and gas sales and royalties	$	10		$	26,667	$	12,468		$	86,303

Costs and Expenses:
Purchase price and accrual adjustments	(4,580		)			(14,179		)
Write down to market value and realized gains				8,422					13,336
Oil and gas operations	404			5,005		4,564			21,448
Depreciation, depletion and amortization				7,780					28,761
Total Costs and Expenses	(4,176		)	21,207		(9,615		)	63,545

Income Before Income Taxes	4,186			5,460		22,083			22,758
Income Tax Provision	1,465			1,911		7,729			7,965
Income From Discontinued Operations	$	2,721		$	3,549	$	14,354		$	14,793

Key Statistics:
Daily Production
Liquids (Bbl)	(3		)	4,091		301			4,555
Natural Gas (Mcf)	(56		)	34,396		5,917			33,520
Average Realized Price
Liquids ($/Bbl)	$			$	28.11	$	33.96		$	27.68
Natural Gas ($/Mcf)	$			$	5.08	$	5.97		$	5.67

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

Cumulative Effect of Change in Accounting Principle, Net of Tax

The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” on January 1, 2003 and recognized a non-cash pre-tax charge of $9.0 million ($5.8 million, net of tax) as the cumulative effect of change in accounting principle due to adoption of this standard in the first quarter of 2003.

FUTURE TRENDS

With renewed focus on domestic operations and the continuing ramp-up of international projects, the Company expects to continue to deliver improved performance throughout the year.

The Company expects production from continuing operations in 2004 to increase compared to the full year 2003. Noble Energy’s production profile will be impacted by several factors, including:

• The timing of the production increases in Israel and Phase 2A in Equatorial Guinea during 2004;

• Seasonal variations in rainfall in Ecuador that affect the Company’s natural gas-to-power project; and

• Hurricane Ivan related shut-ins in the U.S. Gulf of Mexico.

Major international projects scheduled to contribute incremental production this year include:

• Initial natural gas sales offshore Israel. Production is projected, during the fourth quarter of 2004, to range between 50 MMcfpd and 65 MMcfpd, net to Noble Energy; and

• Phase 2A condensate expansion in Equatorial Guinea, which began late 2003 and continued to ramp up through 2004.

The Company expects 2004 capital expenditures to be approximately $750 million compared to the $600 million announced in May of this year. The $150 million expected increase in the capital budget is associated with deepwater expenditures for the Swordfish acquisition and development, as well as the accelerated appraisal and development of the Ticonderoga discovery. The Company plans to fund such expenditures 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 does not budget for acquisitions.

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.

Recently Issued Pronouncements and Emerging Issues

Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 – In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”) became law. The Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. In May 2004, the Financial Accounting Standards Board (“FASB”) issued FSP FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP FAS 106-2”). FSP FAS 106-2 provides guidance on accounting for the effects of the Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. It also requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Act. Guidance applies only to the sponsor of a single-employer defined benefit postretirement health care plan for which the employer has concluded that prescription drug benefits available under the plan to some or all participants for some or all future years are actuarially equivalent to Medicare Part D and thus qualify for the subsidy under the Act and the expected subsidy will offset or reduce the employer’s share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based. At this time, the Company does not believe that FSP FAS 106-2 will have any impact on its financial position, results of operations or cash flows because the Company’s postretirement benefit plans, as currently structured, do not provide prescription drug benefits to some or all participants, for some or all future years, which are “actuarially equivalent” to Medicare Part D and thus qualify for the subsidy under the Act.

balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. In September 2004, the FASB issued FSP FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil-and Gas-Producing Entities” (“FSP FAS 142-2”). FSP FAS 142-2 indicates that the scope exception in paragraph 8(b) of Statement 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil- and gas-producing entities that are within the scope of SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” The guidance in FSP FAS 142-2 is to be applied to the first reporting period beginning after September 2, 2004. Early application is permitted in periods for which financial statements have not yet been issued.

Accounting for Suspended Well Costs – During 2004, an issue has arisen for companies using the successful efforts method of accounting for exploration and production activities regarding the application of certain guidance in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” Paragraph 19 of SFAS No. 19 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If the well has found proved reserves, the capitalized costs become part of the entity’s wells, equipment and facilities; if, however, the well has not found proved reserves, the capitalized costs of drilling the well are expensed, net of any salvage value. Questions have arisen in practice about the application of this guidance due to changes in oil and gas exploration processes and life cycles. The issue is whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond one year other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. The Emerging Issues Task Force has requested that the Board consider an amendment to FASB Statement No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to address this issue. The Company believes it is currently in compliance with the provisions of SFAS No. 19 as related to accounting for suspended well costs. The Company has no capitalized exploratory well costs that have been suspended for more than one year.

Equatorial Guinea – The Company’s operator of existing production in Equatorial Guinea has disclosed in a public filing that, by letter dated July 15, 2004, the United States Securities and Exchange Commission (“SEC”) notified the operator that it was conducting an inquiry into payments made to the government of Equatorial Guinea, or to officials or persons affiliated with officials of the government of Equatorial Guinea; that this inquiry follows an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on Investigation, which reviewed the transactions of various foreign governments, including that of Equatorial Guinea, with Riggs Bank; that the investigation and hearing also reviewed the operations of U.S. oil companies, including the operator in Equatorial Guinea; that there was no finding in the Subcommittee’s report that the operator violated the U.S. Foreign Corrupt Practices Act or any other applicable laws or regulations; and that the operator is cooperating fully with the SEC inquiry. The Company’s interest in existing production is non-operated and the Company has received no notice of involvement in the Senate Subcommittee investigation and has received no correspondence in this regard from the SEC.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes – 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.

As of October 21, 2004, 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	MMBTUpd	Average Price Per MMBTU Floor - Ceiling	Bopd	Average Price Per Bbl Floor - Ceiling
4Q2004	120,000	$4.19 - $6.42	20,000	$29.38 - $39.66
1Q2005	95,000	$5.24 - $8.57	20,788	$32.32 - $42.88
2Q2005	75,000	$5.00 - $7.46	20,250	$31.12 - $43.28
3Q2005	75,000	$5.00 - $7.38	20,745	$31.65 - $44.69
4Q2005	75,000	$5.00 - $7.66	20,295	$31.12 - $43.99
1Q2006	15,000	$5.00 - $8.00	3,966	$29.00 - $35.50
2Q2006			3,558	$29.00 - $34.30

As of September 30, 2004, the Company had a net unrealized loss of $67.1 million related to crude oil and natural gas derivative financial instruments accounted for as cash flow hedges.

Derivative Instruments Held for Trading Purposes – NEMI, from time to time, employs derivative instruments 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, 2004, the Company believes it had no material market risk exposure from NEMI’s derivative instruments. As of September 30, 2004, NEMI had a net payable of less than $1 million on derivative instruments entered into for trading purposes.

Interest Rate Risk

The Company is exposed to interest rate risk related to its variable and fixed interest rate debt. As of September 30, 2004, the Company had $885 million of debt outstanding of which $650 million was fixed-rate debt. The Company believes that anticipated near term changes in interest rates would not have a material effect on the fair value of the Company’s fixed-rate debt and would not expose the Company to the risk of earnings or cash flow loss.

The remainder of the Company’s debt at September 30, 2004 was variable rate debt and therefore exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At September 30, 2004, $235 million of variable rate debt was outstanding. A 10 percent change in the floating interest rates applicable to the September 30, 2004 balance would result in a change in annual interest expense of less than $.6 million.

Foreign Currency Risk

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. Transaction 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 income, net on the statements 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 its 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. 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.

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. During the third quarter in connection with the testing of its internal controls for Sarbanes-Oxley 404 compliance, deficiencies in the Company’s internal control procedures and IT systems were identified. The assessed significant deficiencies in internal controls include: certain spreadsheet controls, input and approval controls, and segregation of duties and financial reporting controls. The Company is currently remediating these assessed significant deficiencies and will complete the testing of the newly implemented controls during the fourth quarter.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to “Note 10 - Commitments and Contingencies” to the consolidated condensed financial statements.

ITEM 6. EXHIBITS

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

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 8, 2004	/s/ JAMES L. McELVANY
		JAMES L. McELVANY
		Senior Vice President, Chief Financial Officer and Treasurer

INDEX TO EXHIBITS

Exhibit Number		Exhibit

10.1		Form of Change of Control Agreement entered into between the Company and each of the Company’s officers, with schedule setting forth differences in Change of Control Agreement.

12.1		Computation of ratio of earnings to fixed charges.

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).