NOBLE ENERGY INC - 10-Q Quarterly Report

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 June 30, 2004

		OR

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

For the transition period from to

Commission file number: 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 July 30, 2004: 58,423,069

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

	(Unaudited)
	June 30, 2004			December 31, 2003
ASSETS
Current Assets:
Cash and cash equivalents	$	173,312		$	62,374
Accounts receivable – trade, net	306,411			303,822
Derivative financial instruments	13,739			56,058
Materials and supplies inventories	14,802			11,083
Assets held for sale	531			21,245
Other current assets	22,806			23,805
Total Current Assets	531,601			478,387
Property, Plant and Equipment, at cost (successful efforts method of accounting)	4,182,404			3,924,987
Less: accumulated depreciation, depletion and amortization	(1,969,919		)	(1,825,246		)
Total property, plant and equipment, net	2,212,485			2,099,741
Investment in Unconsolidated Subsidiaries	222,487			227,669
Other Assets	35,076			36,852

Total Assets	$	3,001,649		$	2,842,649

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	354,635		$	388,428
Current installments of long-term debt	125,000			153,674
Derivative financial instruments	39,369			67,562
Other current liabilities	45,543			38,506
Income taxes - current	10,808			6,548
Total Current Liabilities	575,355			654,718
Deferred Income Taxes	207,701			163,146
Asset Retirement Obligation	102,610			102,827
Other Noncurrent Liabilities	61,980			72,364
Long-Term Debt	795,118			776,021

Total Liabilities	1,742,764			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; 61,811,732 and 60,744,583 shares issued at June 30, 2004 and December 31, 2003, respectively	206,037			202,480
Capital in excess of par value	472,045			431,208
Retained earnings	678,518			526,727
Accumulated other comprehensive loss	(21,759		)	(10,886		)
	1,334,841			1,149,529
Less: Common Stock in Treasury (3,549,976 shares, at cost)	(75,956		)	(75,956		)

Total Shareholders’ Equity	1,258,885			1,073,573

Total Liabilities and Shareholders’ Equity	$	3,001,649		$	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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Revenues:
Oil and gas sales and royalties	$	292,910		$	205,605		$	564,496		$	421,180
Gathering, marketing and processing	12,945			19,880			27,120			37,780
Electricity sales	11,746			9,181			30,865			28,506
Income from unconsolidated subsidiaries	17,632			11,874			30,368			24,606
Other income, net	3,969			1,650			5,779			1,819

Total Revenues	339,202			248,190			658,628			513,891

Costs and Expenses:
Oil and gas operations	49,123			35,496			89,758			72,538
Transportation	3,572			3,580			7,843			7,119
Oil and gas exploration	39,026			34,676			55,512			70,078
Gathering, marketing and processing	10,634			15,538			21,350			33,982
Electricity generation	10,410			10,035			23,434			23,621
Depreciation, depletion and amortization	80,643			79,760			158,325			149,723
Selling, general and administrative	13,133			14,945			28,192			28,574
Accretion of asset retirement obligation	2,352			2,281			5,013			4,614
Interest	16,854			15,501			31,012			30,958
Interest capitalized	(2,528		)	(3,253		)	(6,642		)	(5,183		)

Total Costs and Expenses	223,219			208,559			413,797			416,024

Income Before Taxes	115,983			39,631			244,831			97,867

Income Tax Provision	45,355			13,821			98,891			39,345

Income From Continuing Operations	70,628			25,810			145,940			58,522

Discontinued Operations, Net of Tax	1,399			3,260			11,633			11,244

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

Net Income	$	72,027		$	29,070		$	157,573		$	63,927

Earnings Per Share:
Basic -
Income from continuing operations	$	1.22		$	0.45		$	2.52		$	1.02
Discontinued operations, net of tax	0.02			0.06			0.20			0.20
Cumulative effect of change in accounting principle, net of tax										(0.10		)

Net income	$	1.24		$	0.51		$	2.72		$	1.12
Diluted -
Income from continuing operations	$	1.20		$	0.45		$	2.48		$	1.01
Discontinued operations, net of tax	0.02			0.05			0.20			0.20
Cumulative effect of change in accounting principle, net of tax										(0.10		)

Net income	$	1.22		$	0.50		$	2.68		$	1.11

Weighted average number of shares outstanding - Basic	58,084			57,181			57,874			57,278
Weighted average number of shares outstanding - Diluted	58,957			57,670			58,745			57,776

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Dollars in Thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Comprehensive Income:
Net income	$	72,027		$	29,070		$	157,573		$	63,927
Other comprehensive income, net of tax:
Unrealized gain/(loss) on cash flow hedges:
Unrealized fair value gain/(loss) during period (1)	415			(835		)	(14,649		)	(36,013		)
Less: reclassification adjustment for amounts out of OCI (2)	5,041			10,137			4,484			34,181
	5,456			9,302			(10,165		)	(1,832		)
Change in additional minimum pension liability and other	(83		)	168			(708		)	39
Other comprehensive income/(loss)	5,373			9,470			(10,873		)	(1,793		)

Comprehensive income	$	77,400		$	38,540		$	146,700		$	62,134

(1) Net of income tax benefit/(expense)		$	(223	)	$	450		$	7,820		$	19,392
(2) Net of income tax expense		$	(2,714	)	$	(5,458	)	$	(2,414	)	$	(18,405	)

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Six Months Ended June 30,
	2004			2003
Cash Flows from Operating Activities:
Net income	$	157,573		$	63,927
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	158,325			149,723
Depreciation, depletion and amortization - electricity generation	11,537			12,281
Dry hole expense	26,513			39,095
Amortization of unproved leasehold costs	10,403			11,305
Non-cash effect of discontinued operations	(9,599		)	16,583
Cumulative effect of change in accounting principle, net of tax				5,839
(Gain) loss on disposal of assets	(4,952		)	5,857
Deferred income taxes	44,555			226
Accretion of asset retirement obligation	5,013			4,614
Income from unconsolidated subsidiaries	(30,368		)	(24,606		)
Dividends received from unconsolidated subsidiary	33,075			28,125
Increase (decrease) in noncurrent liabilities	(15,614		)	2,746
(Increase) decrease in other	3,077			7,203
Changes in operating assets and liabilities, not including cash:
(Increase) decrease in accounts receivable	(2,590		)	15,362
(Increase) decrease in other current assets	(2,720		)	(29,454		)
Increase (decrease) in accounts payable	(31,584		)	(29,133		)
Increase (decrease) in other current liabilities	18,786			32,296

Net Cash Provided by Operating Activities	371,430			311,989

Cash Flows From Investing Activities:
Capital expenditures	(318,481		)	(248,659		)
Distribution from unconsolidated subsidiaries	2,475			227
Proceeds from sale of property, plant and equipment	34,223			101

Net Cash Used in Investing Activities	(281,783		)	(248,331		)

Cash Flows From Financing Activities:
Exercise of stock options	37,950			3,419
Cash dividends paid	(5,782		)	(4,592		)
Issuance of long-term debt	197,688
Proceeds from bank debt	150,000			60,314
Repayment of bank debt	(350,637		)	(86,999		)
Repayment of note payable obtained in Aspect acquisition	(7,928		)	(2,509		)

Net Cash Provided by (Used in) Financing Activities	21,291			(30,367		)

Increase in Cash and Cash Equivalents	110,938			33,291

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

Cash and Cash Equivalents at End of Period	$	173,312		$	48,733

Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	12,946		$	18,849
Income taxes paid	$	42,750		$	17,147
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 June 30, 2004 and December 31, 2003; the results of operations for the three month and six month periods ended June 30, 2004 and 2003; the statements of comprehensive income/(loss) for the three month and six month periods ended June 30, 2004 and 2003; and the cash flows for the six month periods ended June 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 June 30,						Six Months Ended June 30,
(in thousands, except per share amounts)	2004			2003			2004			2003

Net income, as reported	$	72,027		$	29,070		$	157,573		$	63,927
Add: Stock-based compensation cost recognized, net of related tax effects	117						223			71
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2,002		)	(2,542		)	(3,981		)	(5,155		)
Pro forma net income	$	70,142		$	26,528		$	153,815		$	58,843
Earnings per share:
Basic - as reported	$	1.24		$	0.51		$	2.72		$	1.12
Basic - pro forma	$	1.21		$	0.46		$	2.66		$	1.03
Diluted - as reported	$	1.22		$	0.50		$	2.68		$	1.11
Diluted - pro forma	$	1.19		$	0.46		$	2.62		$	1.02

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 June 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 six months ended June 30:

	Pension Benefits						Other Benefits
(in thousands)	2004			2003			2004			2003
Service cost	$	2,725		$	2,324		$	346		$	311
Interest cost	3,095			2,861			543			525
Expected return on plan assets	(3,412		)	(2,928		)
Transition obligation recognition	(108		)	(108		)	120			120
Amortization of prior service cost	200			197			(29		)	(37		)
Recognized net actuarial loss	166						102			79
Net periodic benefit cost	$	2,666		$	2,346		$	1,082		$	998

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

Note 3 - Income Tax Provision

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2004		2003			2004		2003

Current	$	28,962	$	18,720		$	59,321	$	39,119
Deferred	16,393		(4,899		)	39,570		226

Total Income Tax Provision	$	45,355	$	13,821		$	98,891	$	39,345

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.

The income tax provisions associated with discontinued operations were $.8 million and $1.8 million for the three-month periods ending June 30, 2004 and 2003, respectively, and $6.3 million and $6.1 million for the six-month periods ending June 30, 2004 and 2003, respectively.

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

Basic earnings per share (“EPS”) of common stock was computed using the weighted average number of shares of common stock outstanding during each period. The diluted 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 June 30:

	2004					2003
(in thousands, except per share)	Income (Numerator)				Shares (Denominator)	Income (Numerator)				Shares (Denominator)
Net income/shares	$	72,027			58,084	$	29,070			57,181
Basic EPS			$	1.24				$	0.51

Net income/shares	$	72,027			58,084	$	29,070			57,181
Effect of Dilutive Securities Stock options					873					489
Adjusted net income/shares	$	72,027			58,957	$	29,070			57,670
Diluted EPS			$	1.22				$	0.50

For the six months ended June 30:

	2004					2003
(in thousands, except per share)	Income (Numerator)				Shares (Denominator)	Income (Numerator)				Shares (Denominator)
Net income/shares	$	157,573			57,874	$	63,927			57,278
Basic EPS			$	2.72				$	1.12

Net income/shares	$	157,573			57,874	$	63,927			57,278
Effect of Dilutive Securities Stock options					871					498
Adjusted net income/shares	$	157,573			58,745	$	63,927			57,776
Diluted EPS			$	2.68				$	1.11

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 six 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.

(in thousands, except exercise prices)	Three Months Ended June 30, 2003	Six Months Ended June 30, 2003
Options excluded from dilution calculation	2,917,959	2,791,501
Range of exercise prices	$35.40 - $43.21	$35.40 - $43.21
Weighted average exercise price	$37.91	$39.63

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 June 30, 2004

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel		Equatorial Guinea			Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	135,715	$	63,927	$	23,641	$		$	28,958		$	19,189
Gas Sales	157,195		139,534		4,527		12,095		996			43
Gathering, Marketing and Processing Revenue	12,945											12,945
Electricity Sales	11,746											11,746
Income from Unconsolidated Subsidiaries	17,632								17,632
Other	3,969		317		111		65		(454		)	3,930
Total Revenues	339,202		203,778		28,279		12,160		47,132			47,853

Costs and Expenses
Oil and Gas Operations	49,123		34,479		2,540		1,833		5,891			4,380
Transportation	3,572				2,063							1,509
Oil and Gas Exploration	39,026		32,771		5,094		68		100			993
Gathering, Marketing and Processing Costs	10,634											10,634
Electricity Generation	10,410											10,410
DD&A	80,643		63,074		5,033		2,371		3,714			6,451
SG&A	13,133		3,176						113			9,844
Accretion of Asset Retirement Obligation	2,352		2,000		306		46
Interest Expense (net)	14,326											14,326
Total Costs and Expenses	223,219		135,500		15,036		4,318		9,818			58,547

Operating Income from Continuing Operations	$	115,983	$	68,278	$	13,243	$	7,842	$	37,314		$	(10,694	)
Discontinued Operations	2,153		2,153

Income Before Taxes	$	118,136	$	70,431	$	13,243	$	7,842	$	37,314		$	(10,694	)

Oil & Gas Operations

Three Months Ended June 30, 2003

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	85,678	$	37,994	$	17,490	$			$	14,259	$	15,935
Gas Sales	119,927		114,582		4,295					1,011		39
Gathering, Marketing and Processing Revenue	19,880											19,880
Electricity Sales	9,181											9,181
Income from Unconsolidated Subsidiaries	11,874									11,874
Other	1,650		2,617		202							(1,169		)
Total Revenues	248,190		155,193		21,987					27,144		43,866

Costs and Expenses
Oil and Gas Operations	35,496		23,724		2,788					3,882		5,102
Transportation	3,580				2,315							1,265
Oil and Gas Exploration	34,676		21,683		6,847		5,182			4		960
Gathering, Marketing and Processing Costs	15,538											15,538
Electricity Generation	10,035											10,035
DD&A	79,760		65,652		7,414		10			1,431		5,253
SG&A	14,945		4,419							97		10,429
Accretion of Asset Retirement Obligation	2,281		2,070		211
Interest Expense (net)	12,248											12,248
Total Costs and Expenses	208,559		117,548		19,575		5,192			5,414		60,830

Operating Income from Continuing Operations	$	39,631	$	37,645	$	2,412	$	(5,192	)	$	21,730	$	(16,964	)
Discontinued Operations	5,015		5,015

Income Before Taxes	$	44,646	$	42,660	$	2,412	$	(5,192	)	$	21,730	$	(16,964	)

Oil & Gas Operations

Six Months Ended June 30, 2004

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel		Equatorial Guinea			Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	272,413	$	129,009	$	47,242	$		$	57,471		$	38,691
Gas Sales	292,083		264,682		10,085		15,180		2,060			76
Gathering, Marketing and Processing Revenue	27,120											27,120
Electricity Sales	30,865											30,865
Income from Unconsolidated Subsidiaries	30,368								30,368
Other	5,779		1,115		1,633		98		(454		)	3,387
Total Revenues	658,628		394,806		58,960		15,278		89,445			100,139

Costs and Expenses
Oil and Gas Operations	89,758		61,565		5,414		2,997		11,040			8,742
Transportation	7,843				4,605							3,238
Oil and Gas Exploration	55,512		46,784		5,962		668		136			1,962
Gathering, Marketing and Processing Costs	21,350											21,350
Electricity Generation	23,434											23,434
DD&A	158,325		125,943		10,441		3,451		5,756			12,734
SG&A	28,192		6,855		1				148			21,188
Accretion of Asset Retirement Obligation	5,013		4,312		622		79
Interest Expense (net)	24,370											24,370
Total Costs and Expenses	413,797		245,459		27,045		7,195		17,080			117,018

Operating Income from Continuing Operations	$	244,831	$	149,347	$	31,915	$	8,083	$	72,365		$	(16,879	)
Discontinued Operations	17,897		17,897

Income Before Taxes	$	262,728	$	167,244	$	31,915	$	8,083	$	72,365		$	(16,879	)

Oil & Gas Operations

Six Months Ended June 30, 2003

(Dollars in Thousands)

	Consolidated			United States			North Sea		Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	172,756		$	69,246		$	41,089	$			$	31,159	$	31,262
Gas Sales	248,424			236,733			9,644					1,981		66
Gathering, Marketing and Processing Revenue	37,780													37,780
Electricity Sales	28,506													28,506
Income from Unconsolidated Subsidiaries	24,606											24,606
Other	1,819			1,588			179		1					51
Total Revenues	513,891			307,567			50,912		1			57,746		97,665

Costs and Expenses
Oil and Gas Operations	72,538			47,382			5,723					8,167		11,266
Transportation	7,119						4,583							2,536
Oil and Gas Exploration	70,078			42,904			7,452		5,455			50		14,217
Gathering, Marketing and Processing Costs	33,982													33,982
Electricity Generation	23,621													23,621
DD&A	149,723			121,217			15,141		20			3,606		9,739
SG&A	28,574			8,607								157		19,810
Accretion of Asset Retirement Obligation	4,614			4,191			423
Interest Expense (net)	25,775													25,775
Total Costs and Expenses	416,024			224,301			33,322		5,475			11,980		140,946

Operating Income from Continuing Operations	$	97,867		$	83,266		$	17,590	$	(5,474	)	$	45,766	$	(43,281	)
Discontinued Operations	17,298			17,298
Cumulative Effect of SFAS 143	(8,983		)	(8,983		)

Income Before Taxes	$	106,182		$	91,581		$	17,590	$	(5,474	)	$	45,766	$	(43,281	)

Long-Lived Assets, (Primarily Property, Plant and Equipment, Net)
As of 06/30/04	$	2,212,485		$	978,025		$	72,437	$	251,539		$	469,183	$	441,301
As of 12/31/03	$	2,099,741		$	977,583		$	77,293	$	253,482		$	370,430	$	420,953

Total Assets
As of 06/30/04	$	3,001,649		$	1,138,911		$	192,500	$	278,659		$	711,465	$	680,114
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 six months ended June 30, 2004 and 2003 as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
Natural Gas	2004		2003		2004		2003
Hedge MMBTUpd	120,000		185,000		120,570		185,000
Floor price range	$3.75 - $4.25		$3.25 - $3.80		$3.75 - $5.00		$3.25 - $3.80
Ceiling price range	$5.16 - $6.35		$4.00 - $5.00		$5.16 - $9.65		$4.00 - $5.20
Percent of daily production	31	%	54	%	33	%	54	%

	Three Months Ended June 30,				Six Months Ended June 30,
Crude Oil	2004		2003		2004		2003
Hedge Bpd	15,000		15,000		15,009		15,000
Floor price range	$24.00 - $25.50		$23.00		$24.00 - $26.00		$23.00
Ceiling price range	$30.50 - $32.65		$27.20 - $30.00		$30.25 - $32.65		$27.20 - $30.00
Percent of daily production	33	%	41	%	32	%	43	%

The Company included losses of $12.0 million and $15.6 million related to cash flow hedges in oil and gas sales and royalties during second quarter 2004 and 2003, respectively. The Company recorded $4.4 million of ineffectiveness related to cash flow hedges during second quarter 2004 as a decrease in revenues. No ineffectiveness was recorded in second quarter 2003.

The Company included losses of $17.5 million and $52.6 million related to cash flow hedges in oil and gas sales and royalties during the six-month periods ended June 30, 2004 and 2003, respectively. The Company recorded $4.0 million of ineffectiveness related to cash flow hedges during the six-month period ended June 30, 2004 as a decrease in revenues. No ineffectiveness was recorded in the six-month period ended June 30, 2003.

As of July 29, 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
3Q2004	120,000	$4.19 - $5.99	15,000	$25.00 - $31.13
4Q2004	120,000	$4.19 - $6.42	15,000	$26.67 - $34.88
1Q2005	95,000	$5.24 - $8.57	15,788	$30.68 - $40.47
2Q2005	75,000	$5.00 - $7.46	15,250	$30.67 - $38.95
3Q2005	75,000	$5.00 - $7.38	15,745	$31.38 - $42.11
4Q2005	75,000	$5.00 - $7.66	15,295	$30.67 - $42.18
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 June 30, 2004, approximately $15.3 million of net deferred losses related to the fair values of the Company’s derivative financial instruments included in accumulated other comprehensive loss at June 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 June 30, 2004 and 2003, NEMI recorded losses of $456 thousand and $1.1 million, respectively, related to derivative instruments. During the six months ended June 30, 2004 and 2003, NEMI recorded losses of $167 thousand and $160 thousand, respectively, related to derivative instruments.

During the six-month period ending June 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 June 30, 2004, the Company had NYMEX-related transactions with ENA totaling 56 contracts with a mark-to-market receivable value of $1.1 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 - Debt

On April 19, 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 proceeds were used to repay short-term borrowings. The notes mature April 15, 2014 and pay interest semi-annually at 5.25 percent.

The Company had entered into an interest rate lock to protect against a rise in interest rates prior to the issuance of the debt. At the time of the debt offering, 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 $4.8 million, net of tax, at June 30, 2004. This amount is being reclassified into earnings as adjustments to interest expense.

Note 8 - 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 June 30,				Six Months Ended June 30,
(in thousands)	2004		2003		2004		2003
Revenues:
Methanol sales	$	53,108	$	49,429	$	108,065	$	104,212
Other income	6,998		3,727		12,022		6,390
Total Revenue	60,106		53,156		120,087		110,602

Expenses:
Cost of goods manufactured	15,594		21,337		41,794		44,877
DD&A	4,860		5,043		9,797		10,164
SG&A	920		848		1,896		1,850
Total Costs and Expenses	21,374		27,228		53,487		56,891

Net Income	$	38,732	$	25,928	$	66,600	$	53,711

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.

	Six Months Ended June 30,
(in thousands)	2004			2003
Beginning of the period	$	102,827		$
Initial adoption entry				109,821
Liabilities incurred in the current period	3,615			1,316
Liabilities settled in the current period	(8,845		)	(222		)
Accretion expense	5,013			4,614
End of the period	$	102,610		$	115,529

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 third 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 - Accounting for Costs Associated With Mineral Rights

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-b would be applied to the first reporting period beginning after the date that the FSP is finalized. Until the FSP is finalized, further consideration of the issue could result in a change in how Noble Energy classifies these assets.

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. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting crude oil and natural gas as a separate intangible assets line item on the balance sheet, net of amortization, the Company most likely would be required to reclassify certain amounts out of oil and gas properties and into a separate intangible assets line item. The Company’s cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules.

If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting crude oil and natural gas as a separate intangible assets line item on the balance sheet, Noble Energy would be required to reclassify the estimated amounts as follows:

Intangible Assets (in thousands)	June 30, 2004			December 31, 2003
Proved leasehold acquisition costs	$	889,531		$	835,738
Unproved leasehold acquisition costs	128,669			127,194
Total leasehold acquisition costs	1,018,200			962,932
Less: accumulated depletion	(471,557		)	(496,227		)
Net leasehold acquisition costs	$	546,643		$	466,705

Further, the Company does not believe the classification of the costs of mineral rights associated with extracting crude oil and natural gas as intangible assets would have any impact on compliance with covenants under the Company’s debt agreements.

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 June 30,					Six Months Ended June 30,
(dollars in thousands)	2004			2003		2004			2003
Revenues:
Oil and gas sales and royalties	$	(265	)	$	26,716	$	12,457		$	59,636

Costs and Expenses:
Purchase price and accrual adjustments	(3,707		)			(9,599		)
Write down to market value				4,914					4,914
Oil and gas operations	1,290			8,119		4,160			16,443
Depreciation, depletion and amortization				8,668					20,981
Total Costs and Expenses	(2,417		)	21,701		(5,439		)	42,338

Income Before Income Taxes	2,152			5,015		17,896			17,298
Income Tax Provision	753			1,755		6,263			6,054
Income From Discontinued Operations	$	1,399		$	3,260	$	11,633		$	11,244

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

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 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.

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 second quarter 2004. Financial highlights included the following:

•		Second quarter 2004 net income of $72.0 million, a 148 percent increase over second quarter 2003.
•		Six-month 2004 net income of $157.6 million, a 146 percent increase over the same period of 2003.
•		Six-month 2004 cash flows provided by operating activities of $371.4 million, a 19 percent increase over the same period of 2003.
•		Issuance of $200 million senior notes.
•		Completion of asset disposition program first announced in July 2003.

Second quarter 2004 operational success resulted from growing domestic and international production and rising commodity prices. Operational highlights for second quarter 2004 as compared with second quarter 2003 included:

•		A 17 percent increase in daily production, including a seven percent domestic increase and a 36 percent international increase.
•		Increases of 27 percent in the average realized crude oil price and 19 percent in the average realized natural gas price.
•		Increasing international contribution reflecting Phase 2A expansion project in Equatorial Guinea and commencement of natural gas sales in Israel.
•		A 14 percent decrease in per unit depreciation, depletion and amortization (“DD&A”) expense.
•		Acquisition of additional interests in the deepwater Gulf of Mexico.

During second quarter 2004, the Company’s domestic division added three significant deepwater projects:

Swordfish – In May 2004, the Company announced the acquisition of an additional interest in the Swordfish development project (Viosca Knoll Blocks 917, 961 and 962) in the deepwater Gulf of Mexico, increasing its working interest from 10 percent to 60 percent. The development plan calls for three wells to be connected to existing infrastructure through subsea tieback. Initial production is expected to commence in second quarter 2005.

Lorien – In April 2004, the Company announced the acquisition of an additional interest in the Green Canyon Block 199 (Lorien) discovery well in the deepwater Gulf of Mexico. The acquisition increased the Company’s working interest in Lorien from 20 percent to 60 percent. An appraisal well at Lorien is planned for August 2004.

Ticonderoga – Also in April 2004, the Company announced successful results from the Green Canyon Block 768 #1 exploration well (Ticonderoga) in the Gulf of Mexico. The Company is currently drilling an exploration well near the Ticonderoga discovery, Green Canyon 767 #1 (Conquest). Noble Energy has a 50 percent working interest in the Ticonderoga discovery.

Production from the Company’s deepwater program has been increasing rapidly in recent years. The acquisition of Swordfish, combined with the recent discovery at Ticonderoga and the acquisition of a larger interest at Lorien, are expected to support continued strong growth in the deepwater program.

Noble Energy’s international operations are also positioned for continued long-term growth with the following second quarter 2004 highlights:

•		Continued expansion of the Alba field in Equatorial Guinea.
•		Signing of Production Sharing Contract (“PSC”) covering Block “O” offshore Bioko Island in Equatorial Guinea (45 percent working interest).
•		Increasing natural gas production in Israel.

The Company continues to focus on maintaining investment discipline and reducing costs while pursuing new exploration and production opportunities domestically and internationally.

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 .92:1 at June 30, 2004 compared with .73:1 at December 31, 2003. The improvement in the current ratio resulted primarily from a $110.9 million increase in the period-end balance of cash and cash equivalents.

Cash Flows

Operating Activities – For the six-month period ending June 30, 2004, the Company reported a $59.4 million increase in net cash provided by operating activities as compared with the same period of 2003. Net cash provided by operating activities totaled $371.4 million for the first six months of 2004 compared to $312.0 million for 2003. The 2004 increase resulted primarily from a 35 percent increase in crude oil production and from commodity price increases which, combined, resulted in a $143.3 million increase in oil and gas sales and royalties.

Investing Activities – Net cash used in investing activities totaled $281.8 million and $248.3 million for the six-month period ending June 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 six months of 2004, the Company received $34.2 million in proceeds from the sales of non-strategic crude oil and natural gas properties.

Financing Activities – Net cash provided by (used in) financing activities totaled $21.3 million and ($30.4) million for the six-month period ending June 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 six months of 2004, the Company closed an offering of $200 million senior unsecured notes, receiving net proceeds of $197.7 million. In addition, the Company received $38.0 million from the exercise of stock options.

Capital Expenditures

Capital expenditures consisted of the following:

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2004		2003			2004		2003
Oil and gas mineral interests, equipment and facilities	$	115,540	$	123,396		$	239,534	$	238,860
Property acquisition costs	85,251					85,251
Downstream projects	121		14,959			318		16,632
Corporate and other	949		(109		)	3,368		3,258
Total capital expenditures	$	201,861	$	138,246		$	328,471	$	258,750

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 $318.5 million and $248.7 million for the six-month period ending June 30, 2004 and 2003, respectively. The Company has funded its 2004 capital expenditures primarily from cash flow from operations.

Total capital expenditures during the six-month period ending June 30, 2004 increased $69.7 million or 27 percent from the same period of 2003. The increase was due to the capital requirements for the expansion and drilling activities 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:

		June 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 2005					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	125,000		8.95
Term Loan, due January 2009		150,000		2.02
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		925,000			933,674
Less:	unamortized discount	4,882			3,979
	current installments of long-term debt	125,000			153,674
Long-term debt		$	795,118		$	776,021

The Company’s credit agreements are with certain commercial lending institutions. The $400 million credit agreement 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 bears 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 June 30, 2004, there were no amounts outstanding under the credit agreements, providing the Company $700 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.

On April 14, 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 a Term Loan agreement with several commercial lending institutions for a total of $150 million. The interest rate on the borrowing is LIBOR plus an effective range of 60 to 130 basis points depending on credit rating. The Term Loan expires in January 2009. Proceeds were used to reduce amounts outstanding under the $400 million credit agreement.

In addition to the above-mentioned repayments of short-term bank borrowings, the Company repaid the $7.9 million Aspect acquisition note and the $20.7 million Israel note during the first six months of 2004.

As a result of these transactions, the Company has reduced total outstanding debt, less unamortized discount, by $9.6 million during the first six months of 2004. The Company’s ratio of debt-to-book capital (defined as the Company’s total debt plus its equity) was 42 percent at June 30, 2004, compared to 46 percent at December 31, 2003.

The Company’s $125 million Series A-2 Notes are due in December 2004. The Company expects to fund the repayment of the $125 million Notes from a combination of accumulated cash flows and draw downs of the credit facilities.

Dividends – In January, April and July of 2004, the Company’s Board of Directors declared quarterly cash dividends of five cents per common share. Each dividend payment represented an increase of one cent per share, or 25 percent, over the Company’s quarterly payments of four cents per share paid during the corresponding periods of 2003.

Exercise of Stock Options – The Company received $38.0 million from the exercise of stock options during the first six months of 2004, as compared to $3.4 million during the first six 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 six months of 2004, the average market price of the Company’s common stock increased over the first six 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 six months of 2004, the Company profited from increased production and higher commodity prices. Selected financial data is as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share amounts)	2004		2003		2004		2003
Income from continuing operations	$	70,628	$	25,810	$	145,940	$	58,522
Income from discontinued operations, net of tax	1,399		3,260		11,633		11,244
Cumulative effect of change in accounting principle, net of tax							(5,839		)
Net income	72,027		29,070		157,573		63,927
Basic earnings per share	$	1.24	$	0.51	$	2.72	$	1.12
Diluted earnings per share	$	1.22	$	0.50	$	2.68	$	1.11

Natural Gas Information

Natural gas revenues increased 31 percent during second quarter 2004, compared with second quarter 2003, and 18 percent for the first six months of 2004, compared with the first six months of 2003.

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2004		2003		2004		2003
Natural gas sales	$	157,195	$	119,927	$	292,083	$	248,424

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

	Three Months Ended June 30,
	2004			2003
	Mcfpd	Price		Mcfpd	Price
United States	257,121	$	5.96	269,841	$	4.67
North Sea	12,458	$	3.99	13,431	$	3.51
Equatorial Guinea (1)	43,500	$	0.25	44,455	$	0.25
Israel	47,769	$	2.78
Other International (2)	20,640	$	0.89	13,690	$	0.41
Total (3)	381,488	$	4.78	341,417	$	4.01

	Six Months Ended June 30,
	2004			2003
	Mcfpd	Price		Mcfpd	Price
United States	253,586	$	5.73	265,879	$	4.92
North Sea	12,370	$	4.48	14,495	$	3.68
Equatorial Guinea (1)	44,961	$	0.25	43,949	$	0.25
Israel	30,002	$	2.78
Other International (2)	25,199	$	0.69	20,143	$	0.37
Total (3)	366,118	$	4.70	344,466	$	4.22

(1) Natural gas in Equatorial Guinea is under a 25-year contract 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 $0.07 and $0.47 per Mcf for second quarter 2004 and 2003, respectively, and reductions of $0.04 and $0.71 per Mcf for the first six months of 2004 and 2003, respectively, from hedging in the United States.

Natural gas production in the U.S. and in the North Sea has been declining as a result of natural decline rates for properties in the Gulf of Mexico and North Sea. Natural gas sales in Israel commenced on February 18, 2004 and averaged 12,235 Mcfpd for first quarter 2004 and 47,769 Mcfpd for second quarter 2004. The increases in production from other international locations are due to higher natural gas production in Ecuador.

Crude Oil Information

Crude oil revenues increased 58 percent during second quarter 2004 and the first six months of 2004, compared with the same periods in 2003.

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2004		2003		2004		2003
Crude oil sales	$	135,715	$	85,678	$	272,413	$	172,756

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

	Three Months Ended June 30,
	2004			2003
	Bopd	Price		Bopd	Price
United States	22,676	$	30.98	16,273	$	25.66
North Sea	7,070	$	36.75	7,438	$	25.84
Equatorial Guinea	9,105	$	34.95	6,198	$	25.28
Other International (1)	6,664	$	31.64	6,457	$	27.12
Total (2)	45,515	$	32.77	36,366	$	25.89

	Six Months Ended June 30,
	2004			2003
	Bopd	Price		Bopd	Price
United States	23,036	$	30.77	14,979	$	25.54
North Sea	7,389	$	35.13	7,515	$	30.21
Equatorial Guinea	9,551	$	33.06	6,227	$	27.64
Other International (1)	6,860	$	30.99	5,921	$	29.17
Total (2)	46,836	$	31.96	34,642	$	27.55

(1) Other International includes Argentina and China.

(2) Reflects reductions of $2.35 and $0.33 per Bbl for second quarter 2004 and 2003, respectively, and reductions of $1.72 and $1.30 for the first six months of 2004 and 2003, respectively, from hedging in the United States.

Crude oil production volumes in the U.S. increased 39 percent quarter-over-quarter and 54 percent for the first six 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. 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 June 30,				Six Months Ended June 30,
(in thousands)	2004		2003		2004		2003
GMP revenues	$	12,945	$	19,880	$	27,120	$	37,780
GMP expenses	10,634		15,538		21,350		33,982
Gross margin	$	2,311	$	4,342	$	5,770	$	3,798

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

NEMI recorded losses of $456 thousand and $1.1 million, related to derivative instruments during second quarter 2004 and 2003, respectively, and losses of $167 thousand and $160 thousand during the first six months of 2004 and 2003, respectively.

During the first six 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 June 30, 2004, the Company had NYMEX-related transactions with ENA totaling 56 contracts with a mark-to-market receivable value of $1.1 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 June 30,					Six Months Ended June 30,
(in thousands)	2004		2003			2004		2003
Electricity sales	$	11,746	$	9,181		$	30,865	$	28,506
Electricity generation	10,411		10,035			23,434		23,621
Operating income	$	1,335	$	(854	)	$	7,431	$	4,885

Power production (Total MW)	168,815		111,666			421,876		334,872
Average power price ($ per Kwh)	$	0.070	$	0.083		$	0.073	$	0.085
Natural gas production (Mcfpd)	20,102		12,651			24,595		19,156

The volume of natural gas and MW produced in Ecuador is related to thermal electricity demand in that country and typically declines at the onset of the rainy season. During second quarter 2004, Ecuador had sufficient rainfall to allow hydroelectric power producers to provide base load power, while Noble Energy provided electricity to meet peak demand. As seasonal rains subside, the Company expects to experience increasing demand for thermal electricity.

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 June 30,				Six Months Ended June 30,
(in thousands)	2004		2003		2004		2003
Income from unconsolidated subsidiaries	$	17,632	$	11,874	$	30,368	$	24,606

Company’s share of methanol sales volumes (million gallons)	37.4		29.8		75.6		64.3
Average realized methanol prices ($ per gallon)	$	0.64	$	0.72	$	0.63	$	0.68

Methanol production has been increasing during 2004 as a result of increased demand. Dividends from unconsolidated subsidiaries contributed $33.1 million and $28.1 million to the Company’s net cash provided by operating activities during the first six months of 2004 and 2003, respectively.

Costs and Expenses

Oil and Gas Operations Expense and Transportation Expense – Oil and gas operations expense increased $13.6 million, or 38 percent, for second quarter 2004, as compared with second quarter 2003. For the first six months of 2004, oil and gas operations expense increased $17.2 million, or 24 percent, as compared with the first six months of 2003. The increases in oil and gas operations expense reflect increased workover activity in the Gulf of Mexico, higher production taxes resulting from higher commodity prices and higher lease operating expense resulting primarily from increased production volumes.

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 $4.95 for second quarter 2004 as compared with $4.18 for second quarter 2003. The unit rate of oil and gas operations expense per BOE was $4.57 for the first six months of 2004 as compared with $4.35 for the first six months of 2003. The per unit rates increased primarily due to the higher workover activity in the Gulf of Mexico and higher production taxes.

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

Three Months Ended June 30, (in thousands)

	Consolidated		United States		North Sea		Israel (2)		Equatorial Guinea		Other Int’l
2004
Lease operating (1)	$	35,575	$	21,952	$	2,540	$	1,833	$	5,891	$	3,359
Production taxes	6,027		5,006								1,021
Workover expense	7,521		7,521
Total operations expense	49,123		34,479		2,540		1,833		5,891		4,380
Transportation expense	3,572				2,063						1,509
Total production expense	$	52,695	$	34,479	$	4,603	$	1,833	$	5,891	$	5,889

2003
Lease operating (1)	$	29,823	$	18,823	$	2,788	$		$	3,882	$	4,330
Production taxes	4,296		3,524								772
Workover expense	1,377		1,377
Total operations expense	35,496		23,724		2,788				3,882		5,102
Transportation expense	3,580				2,315						1,265
Total production expense	$	39,076	$	23,724	$	5,103	$		$	3,882	$	6,367

Six Months Ended June 30, (in thousands)

	Consolidated		United States		North Sea		Israel (2)		Equatorial Guinea		Other Int’l
2004
Lease operating (1)	$	69,428	$	43,255	$	5,414	$	2,997	$	11,040	$	6,722
Production taxes	11,022		9,002								2,020
Workover expense	9,308		9,308
Total operations expense	89,758		61,565		5,414		2,997		11,040		8,742
Transportation expense	7,843				4,605						3,238
Total production expense	$	97,601	$	61,565	$	10,019	$	2,997	$	11,040	$	11,980

2003
Lease operating (1)	$	59,449	$	36,801	$	5,723	$		$	8,167	$	8,758
Production taxes	10,200		7,692								2,508
Workover expense	2,889		2,889
Total operations expense	72,538		47,382		5,723				8,167		11,266
Transportation expense	7,119				4,583						2,536
Total production expense	$	79,657	$	47,382	$	10,306	$		$	8,167	$	13,802

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

(2) Production 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 $39.0 million for second quarter 2004 as compared with $34.7 million for second quarter 2003. Domestic exploration expense for second quarter 2004 increased $11.1 million compared to second quarter 2003 primarily as a result of two unsuccessful exploration wells.

Oil and gas exploration expense totaled $55.5 million and $70.1 million for the first six months of 2004 and 2003, respectively. The decrease for 2004 was due to a $12.6 million period-over-period decrease in dry hole expense, of which $12.3 million was associated with a dry hole in China during 2003.

The Company drilled 13 exploratory wells and 28 exploratory wells during the first six months of 2004 and 2003, respectively.

Depreciation, Depletion and Amortization – Depreciation, depletion and amortization (“DD&A”) expense remained relatively flat quarter-to-quarter at $80.6 million for second quarter 2004 and $79.8 million for second quarter 2003. The unit rate of DD&A per BOE decreased 14 percent to $8.12 per BOE for second quarter 2004 as compared with $9.40 per BOE for second quarter 2003.

For the first six months of 2004, DD&A expense increased six percent, to $158.3 million, as compared with $149.7 million for the first six months of 2003. The increase was due to production increases primarily from the Roaring Fork field in the Gulf of Mexico. The unit rate of DD&A per BOE was $8.07 for the first six months of 2004 as compared with $8.99 for the first six months of 2003.

The decreases in the unit rates noted above reflect a greater contribution of production from lower cost fields.

Selling, General and Administrative Expense – Selling, general and administrative (“SG&A”) expense decreased 12 percent, to $13.1 million for second quarter 2004, as compared with $14.9 million for second quarter 2003. SG&A expense declined due to reduced personnel costs. The per unit rate of SG&A declined 25 percent to $1.32 per BOE for second quarter 2004 as compared with $1.76 per BOE for second quarter 2003 due to the overall reduction in costs plus the effect of higher production volumes.

For the first six months of 2004, SG&A expense was relatively flat at $28.2 million for 2004 and $28.6 million for 2003. The per unit rate of SG&A declined 16 percent to $1.44 per BOE for the first six months of 2004 as compared with $1.72 per BOE for the first six months of 2003.

Interest Expense – Interest expense (net of interest capitalized) increased $2.1 million, or 17 percent, to $14.3 million for second quarter 2004 as compared with $12.2 million for second quarter 2003. The increase was due to an increase in fixed debt versus variable debt and the associated interest rates for each. Capitalized interest was $2.5 million for second quarter 2004 compared with $3.3 million for second quarter 2003.

Interest expense (net of interest capitalized) decreased $1.4 million, or five percent, to $24.4 million for the six months ended June 30, 2004 as compared to $25.8 million for the same period in 2003. Capitalized interest increased $1.5 million period-over-period.

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 $4.8 million, net of tax, at June 30, 2004. This amount is being reclassified into earnings as adjustments to interest expense.

Income Tax Provision – Income tax expense associated with continuing operations was $45.4 million and $13.8 million for second 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. The Company’s effective tax rate on income from continuing operations was 39 percent for second quarter 2004 and 35 percent for second quarter 2003. During second quarter 2004, the Company made income tax payments of $43 million.

Income tax expense associated with continuing operations was $98.9 million and $39.3 million for the six months ended June 30, 2004 and 2003, respectively. The effective tax rate on income from continuing operations was 40 percent for the first six months of 2004 and 2003.

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 June 30,					Six Months Ended June 30,
(dollars in thousands)	2004			2003		2004			2003
Revenues:
Oil and gas sales and royalties	$	(265	)	$	26,716	$	12,457		$	59,636

Costs and Expenses:
Purchase price and accrual adjustments	(3,707		)			(9,599		)
Write down to market value				4,914					4,914
Oil and gas operations	1,290			8,119		4,160			16,443
Depreciation, depletion and amortization				8,668					20,981
Total Costs and Expenses	(2,417		)	21,701		(5,439		)	42,338

Income Before Income Taxes	2,152			5,015		17,896			17,298
Income Tax Provision	753			1,755		6,263			6,054
Income From Discontinued Operations	$	1,399		$	3,260	$	11,633		$	11,244

Key Statistics:
Daily Production
Liquids (Bbl)	(87		)	4,724		454			4,791
Natural Gas (Mcf)	(1,013		)	32,834		8,937			33,075
Average Realized Price
Liquids ($/Bbl)	$	26.33		$	25.39	$	34.07		$	27.49
Natural Gas ($/Mcf)	$	0.60		$	5.29	$	5.93		$	5.98

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

• Potential weather-related shut-ins in the U.S. Gulf of Mexico and Gulf Coast areas.

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

• Initial natural gas sales offshore Israel. Production is projected to continue to increase during the third quarter of 2004 and range between 50 MMcfpd and 80 MMcfpd, net to Noble Energy, during the second half of the year; and

• Phase 2A condensate expansion in Equatorial Guinea, which began during November 2003.

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, including the test of the Conquest prospect offsetting Ticonderoga. 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

Accounting for Costs Associated with Mineral Rights

During 2003, a reporting issue arose regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights associated with extracting 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 July 2004, the Financial Accounting Standards Board (“FASB”) issued a Proposed FASB Staff Position (“FSP”) on Statement 142, (“FSP FAS 142-b”). The Proposed FSP 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-b would be applied to the first reporting period beginning after the date that the FSP is finalized. Until the FSP is finalized, further consideration of the issue could result in a change in how Noble Energy classifies these assets.

Intangible Assets (in thousands)	June 30, 2004			December 31, 2003
Proved leasehold acquisition costs	$	889,531		$	835,738
Unproved leasehold acquisition costs	128,669			127,194
Total leasehold acquisition costs	1,018,200			962,932
Less: accumulated depletion	(471,557		)	(496,227		)
Net leasehold acquisition costs	$	546,643		$	466,705

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 July 29, 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
3Q2004	120,000	$4.19 - $5.99	15,000	$25.00 - $31.13
4Q2004	120,000	$4.19 - $6.42	15,000	$26.67 - $34.88
1Q2005	95,000	$5.24 - $8.57	15,788	$30.68 - $40.47
2Q2005	75,000	$5.00 - $7.46	15,250	$30.67 - $38.95
3Q2005	75,000	$5.00 - $7.38	15,745	$31.38 - $42.11
4Q2005	75,000	$5.00 - $7.66	15,295	$30.67 - $42.18
1Q2006	15,000	$5.00 - $8.00	3,966	$29.00 - $35.50
2Q2006			3,558	$29.00 - $34.30

As of June 30, 2004, the Company had a net unrealized loss of $28.1 million related to crude oil and natural gas derivative financial instruments entered into for non-trading purposes.

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 June 30, 2004, the Company

believes it had no material market risk exposure from NEMI’s derivative instruments. As of June 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 June 30, 2004, the Company had $925 million of debt outstanding of which $775 million was fixed-rate debt with fixed interest rates. 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 June 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 June 30, 2004, $150 million of variable rate debt was outstanding. A 10 percent change in the floating interest rates applicable to the June 30, 2004 balance would result in a change in annual interest expense of less than $500 thousand.

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. There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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

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

(i) On May 4, 2004, Noble Energy furnished a current report on Form 8-K reporting under Item 12, Results of Operations and Financial Condition, the filing of a press release announcing its financial results for the first quarter of fiscal year 2004. The date of the report (the date of earliest event reported) was May 4, 2004.

(ii) On May 10, 2004, Noble Energy filed a current report on Form 8-K reporting under Item 5, Other Events, that it had entered into certain financing arrangements aggregating $150 million due 2009. The date of the report (the date of earliest event reported) was January 30, 2004.

(iii) On May 25, 2004, Noble Energy furnished a current report on Form 8-K reporting under Item 9, Regulation FD Disclosure, the filing of a press release announcing its Annual Management Review to be held in New York. The date of the report (the date of earliest event reported) was May 13, 2004.

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	August 6, 2004	/s/ JAMES L. McELVANY
		JAMES L. McELVANY Senior Vice President, Chief Financial Officer and Treasurer

INDEX TO EXHIBITS

Exhibit Number		Exhibit

4.1		Third Indenture Supplement relating to $200 million of the Registrant’s 5.25% Notes due 2014 dated April 19, 2004 between the Company and the Bank of New York Trust Company, N.A., as successor trustee to U.S. Trust Company of Texas, N.A. (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-116092) and incorporated herein by reference).

10.1		Noble Energy, Inc. 2004 Long-Term Incentive Plan effective as of January 1, 2004.

10.2		1988 Nonqualified Stock Option Plan for Non-Employee Directors of the Registrant, as amended through April 27, 2004.

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).