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 March 31, 2004

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

For the transition period from to

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

(281) 872-3100

(Registrant’s telephone number, including area code)

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

Yes ý No o

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

Yes ý No o

Number of shares of common stock outstanding as of April 30, 2004: 58,046,495

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Share Amounts)

	(Unaudited)
	March 31, 2004			December 31, 2003
ASSETS
Current Assets:
Cash and cash equivalents	$	139,557		$	62,374
Accounts receivable – trade, net	313,971			303,822
Derivative financial instruments	26,460			56,058
Materials and supplies inventories	13,730			11,083
Assets held for sale	16,371			21,245
Other current assets	35,484			23,805
Total Current Assets	545,573			478,387
Property, Plant and Equipment, at cost (successful efforts method of accounting)	4,029,105			3,924,987
Less: accumulated depreciation, depletion and amortization	(1,902,700		)	(1,825,246		)
Total property, plant and equipment, net	2,126,405			2,099,741
Investment in Unconsolidated Subsidiaries	228,357			227,669
Other Assets	36,937			36,852

Total Assets	$	2,937,272		$	2,842,649

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	360,701		$	388,428
Current installments of long-term debt	140,098			153,674
Derivative financial instruments	51,213			67,562
Other current liabilities	58,580			38,506
Income taxes - current	39,460			6,548
Total Current Liabilities	650,052			654,718
Deferred Income Taxes	189,361			163,146
Asset Retirement Obligation	108,712			102,827
Other Noncurrent Liabilities	63,951			72,364
Long-Term Debt	746,065			776,021
Commitments and Contingencies

Total Liabilities	1,758,141			1,769,076

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; 61,515,186 and 60,744,583 shares issued at March 31, 2004 and December 31, 2003, respectively	205,049			202,480
Capital in excess of par value	461,120			431,208
Retained earnings	609,393			526,727
Accumulated other comprehensive loss	(20,475		)	(10,886		)
	1,255,087			1,149,529

Less: Common Stock in Treasury (3,549,976 shares, at cost)	(75,956		)	(75,956		)

Total Shareholders’ Equity	1,179,131			1,073,573

Total Liabilities and Shareholders’ Equity	$	2,937,272		$	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 March 31,
	2004			2003
Revenues:
Oil and gas sales and royalties	$	271,586		$	215,575
Gathering, marketing and processing	14,175			17,900
Electricity sales	19,119			19,325
Income from unconsolidated subsidiaries	12,736			12,732
Other income, net	1,810			169

Total Revenues	319,426			265,701

Costs and Expenses:
Oil and gas operations	40,635			37,042
Transportation	4,271			3,539
Oil and gas exploration	16,486			35,402
Gathering, marketing and processing	10,716			18,444
Electricity generation	13,024			13,586
Depreciation, depletion and amortization	77,682			69,963
Selling, general and administrative	15,059			13,629
Accretion of asset retirement obligation	2,661			2,333
Interest	14,158			15,457
Interest capitalized	(4,114		)	(1,930		)

Total Costs and Expenses	190,578			207,465

Income Before Taxes	128,848			58,236

Income Tax Provision	53,536			25,524

Income From Continuing Operations	75,312			32,712

Discontinued Operations, Net of Tax	10,234			7,984

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

Net Income	$	85,546		$	34,857

Earnings Per Share:
Basic -
Income from continuing operations	$	1.30		$	0.57
Discontinued operations, net of tax	0.18			0.14
Cumulative effect of change in accounting principle, net of tax				(0.10		)

Net income	$	1.48		$	0.61

Diluted -
Income from continuing operations	$	1.29		$	0.56
Discontinued operations, net of tax	0.17			0.14
Cumulative effect of change in accounting principle, net of tax				(0.10		)

Net income	$	1.46		$	0.60

Weighted average number of shares outstanding - Basic	57,663			57,376
Weighted average number of shares outstanding - Diluted	58,531			57,883

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2004			2003
Comprehensive Income:
Net income	$	85,546		$	34,857
Other comprehensive income, net of tax:
Unrealized loss on cash flow hedges:
Unrealized fair value losses during period	(12,325		)	(35,307		)
Less: reclassification adjustment for losses included in net income	3,361			24,044
	(8,964		)	(11,263		)
Change in additional minimum pension liability and other	(625		)
Other comprehensive income	(9,589		)	(11,263		)

Comprehensive Income	$	75,957		$	23,594

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)

	Three Months Ended March 31,
	2004			2003
Cash Flows from Operating Activities:
Net income	$	85,546		$	34,857
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	77,682			69,963
Depreciation, depletion and amortization - electricity generation	6,155			7,565
Dry hole expense	4,461			20,312
Amortization of unproved leasehold costs	5,294			5,804
Non-cash effect of discontinued operations	(5,892		)	12,313
Cumulative effect of change in accounting principle, net of tax				5,839
(Gain) loss on disposal of assets	(2,642		)	1,045
Deferred income taxes	26,215			5,242
Accretion of asset retirement obligation	2,661			2,333
Income from unconsolidated subsidiaries	(12,736		)	(12,732		)
Dividends received from unconsolidated subsidiary	11,250			12,375
Increase (decrease) in noncurrent liabilities	(5,189		)	7,496
(Increase) in other	(87		)	(7,181		)
Changes in operating assets and liabilities, not including cash:
(Increase) in accounts receivable	(10,149		)	(100,945		)
(Increase) decrease in other current assets	(14,326		)	8,573
Increase (decrease) in accounts payable	(27,727		)	66,991
Increase in other current liabilities	70,200			18,640

Net Cash Provided by Operating Activities	210,716			158,490

Cash Flows From Investing Activities:
Capital expenditures	(118,694		)	(119,733		)
Investment in unconsolidated subsidiary				(953		)
Distribution from unconsolidated subsidiaries	798
Proceeds from sale of property, plant and equipment	1,079

Net Cash Used in Investing Activities	(116,817		)	(120,686		)

Cash Flows From Financing Activities:
Exercise of stock options	29,695			752
Cash dividends paid	(2,879		)	(2,295		)
Proceeds from bank debt	195,000			70,200
Repayment of bank debt	(230,702		)	(87,011		)
Repayment of note payable obtained in Aspect acquisition	(7,830		)	(1,573		)

Net Cash Used in Financing Activities	(16,716		)	(19,927		)

Increase in Cash and Cash Equivalents	77,183			17,877

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

Cash and Cash Equivalents at End of Period	$	139,557		$	33,319

Supplemental Disclosures of Cash Flow Information:
Cash paid (received) during the period for:
Interest (net of amount capitalized)	$	5,324		$	5,147
Income taxes (refunded)	$			$	(4,353	)

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 March 31, 2004 and December 31, 2003; the results of operations for the three month periods ended March 31, 2004 and 2003; the statements of comprehensive income for the three month periods ended March 31, 2004 and 2003; and the cash flows for the three month periods ended March 31, 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.

For the three months ended March 31:

(in thousands except per share amounts)	2004			2003
Net income, as reported	$	85,546		$	34,857
Add: Stock-based compensation cost recognized, net of related tax effects	34			81
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(1,873		)	(2,467		)
Pro forma net income	$	83,707		$	32,471
Earnings per share:
Basic - as reported	$	1.48		$	0.61
Basic - pro forma	$	1.45		$	0.57
Diluted - as reported	$	1.46		$	0.60
Diluted - pro forma	$	1.43		$	0.56

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 March 31:

	Pension Benefits						Other Benefits
(in thousands)	2004			2003			2004			2003
Service cost	$	1,317		$	1,162		$	165		$	156
Interest cost	1,537			1,431			270			262
Expected return on plan assets	(1,746		)	(1,464		)
Transition obligation recognition	(54		)	(54		)	60			60
Amortization of prior service cost	98			98			(18		)	(18		)
Recognized net actuarial loss	71						51			39
Net periodic benefit cost	$	1,223		$	1,173		$	528		$	499

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

Note 3 - Income Tax Provision

For the three months ended March 31:

	(In thousands)
	2004		2003
Current	$	30,359	$	20,399
Deferred	23,177		5,125

	$	53,536	$	25,524

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 $5.5 million and $4.3 million for the three-month periods ending March 31, 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 March 31:

	2004							2003
(in thousands, except per share)	Income (Numerator)						Shares (Denominator)	Income (Numerator)						Shares (Denominator)
Net income/shares	$	85,546					57,663	$	34,857					57,376
Basic EPS				$		1.48					$		0.61

Net income/shares	$	85,546					57,663	$	34,857					57,376
Effect of Dilutive Securities Stock options							868							507
Adjusted net income/shares	$	85,546					58,531	$	34,857					57,883
Diluted EPS			$		1.46					$		0.60

The table below reflects the amount of options not included in the EPS calculation above for 2003, as they were antidilutive. There were no antidilutive options for the first quarter of 2004 as the average market price of Company common stock for first quarter 2004 was in excess of the exercise price for all options outstanding.

For the three months ended March 31:

(in thousands, except exercise prices)	2004	2003
Options excluded from dilution calculation		2,703,293
Range of exercise prices		$35.37 - $43.21
Weighted average exercise price		$41.53

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 March 31, 2004

(Dollars in Thousands)

	Consolidated		United States		North Sea		Israel		Equatorial Guinea		Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	136,698	$	65,082	$	23,601	$		$	28,513	$	19,502
Gas Sales	134,888		125,148		5,558		3,085		1,064		33
Gathering, Marketing and Processing Revenue	14,175										14,175
Electricity Sales	19,119										19,119
Income from Unconsolidated Subsidiaries	12,736								12,736
Other	1,810		798		1,522		33				(543		)
Total Revenues	319,426		191,028		30,681		3,118		42,313		52,286

Costs and Expenses
Oil and Gas Operations	40,635		27,086		2,874		1,164		5,149		4,362
Transportation	4,271				2,542						1,729
Oil and Gas Exploration	16,486		14,013		868		600		36		969
Gathering, Marketing and Processing Costs	10,716										10,716
Electricity Generation	13,024										13,024
DD&A	77,682		62,869		5,408		1,080		2,042		6,283
SG&A	15,059		3,679		1				35		11,344
Accretion of Asset Retirement Obligation	2,661		2,312		316		33
Interest Expense (net)	10,044										10,044
Total Costs and Expenses	190,578		109,959		12,009		2,877		7,262		58,471

Operating Income from Continuing Operations	$	128,848	$	81,069	$	18,672	$	241	$	35,051	$	(6,185	)
Discontinued Operations	15,744		15,744

Income Before Taxes	$	144,592	$	96,813	$	18,672	$	241	$	35,051	$	(6,185	)

Three Months Ended March 31, 2003

(Dollars in Thousands)

	Consolidated			United States			North Sea			Israel			Equatorial Guinea		Other Int’l, Corporate & Marketing
Revenues
Oil Sales	$	87,078		$	31,252		$	23,599		$			$	16,900	$	15,327
Gas Sales	128,497			122,151			5,349						970		27
Gathering, Marketing and Processing Revenue	17,900														17,900
Electricity Sales	19,325														19,325
Income from Unconsolidated Subsidiaries	12,732												12,732
Other	169			(1,029		)	(23		)	1					1,220
Total Revenues	265,701			152,374			28,925			1			30,602		53,799

Costs and Expenses
Oil and Gas Operations	37,042			23,658			2,935						4,285		6,164
Transportation	3,539						2,268								1,271
Oil and Gas Exploration	35,402			21,221			605			274			46		13,256
Gathering, Marketing and Processing Costs	18,444														18,444
Electricity Generation	13,586														13,586
DD&A	69,963			55,565			7,727			9			2,175		4,487
SG&A	13,629			4,188									60		9,381
Accretion of Asset Retirement Obligation	2,333			2,121			212
Interest Expense (net)	13,527														13,527
Total Costs and Expenses	207,465			106,753			13,747			283			6,566		80,116

Operating Income from Continuing Operations	$	58,236		$	45,621		$	15,178		$	(282	)	$	24,036	$	(26,317	)
Discontinued Operations	12,283			12,283
Cumulative Effect of SFAS 143	(8,983		)	(8,983		)

Income Before Taxes	$	61,536		$	48,921		$	15,178		$	(282	)	$	24,036	$	(26,317	)

Long-Lived Assets, (Primarily Property, Plant and Equipment, Net)
As of 03/31/04	$	2,126,405		$	946,873		$	78,446		$	251,845		$	423,292	$	425,949
As of 12/31/03	$	2,099,741		$	977,583		$	77,293		$	253,482		$	370,430	$	420,953

Total Assets
As of 03/31/04	$	2,937,272		$	1,073,310		$	184,108		$	274,705		$	675,380	$	729,769
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 first quarter of 2004 and 2003 as follows:

Natural Gas	2004		2003
Hedge MMBTUpd	121,140		188,000
Floor price range	$4.50 - $5.00		$3.25 - $3.75
Ceiling price range	$6.20 - $9.65		$4.00 - $5.20
Percent of daily production	35	%	54	%

Crude Oil	2004		2003
Hedge Bpd	15,018		15,000
Floor price range	$25.00 - $26.00		$23.00
Ceiling price range	$30.25 - $32.25		$27.20 - $30.00
Percent of daily production	31	%	46	%

The Company included losses of $5.2 million and $37.0 million related to cash flow hedges in oil and gas sales and royalties during first quarter 2004 and 2003, respectively. The Company recorded $2.0 million of ineffectiveness related to cash flow hedges during first quarter 2004 as a decrease in revenues. No ineffectiveness was recorded in first quarter 2003.

As of May 4, 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
2Q2004	120,000	$4.06 - $5.95	15,000	$24.83 - $31.22
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	50,000	$5.00 - $8.25	5,000	$29.00 - $39.40
2Q2005			5,000	$29.00 - $37.25

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

If commodity prices were to stay the same as they were at March 31, 2004, approximately $11.3 million of net deferred losses related to the fair values of the Company’s derivative financial instruments included in accumulated other comprehensive loss at March 31, 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 March 31, 2005.

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 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 March 31, 2004 and 2003, NEMI recorded gains of $0.3 million and $0.9 million, respectively, related to derivative instruments.

During the three-month period ending March 31, 2004, the Company had contracts with Enron North America Corporation (“ENA”) that resulted in $0.9 million of income (net of allowance) recognized in earnings. In addition, as of March 31, 2004, the Company had NYMEX-related transactions with ENA totaling 93 contracts with a mark-to-market receivable value of $1.5 million compared to 149 contracts with a mark-to-market receivable value of $1.8 million as of December 31, 2003. For additional discussion of ENA matters, see “Note 10 - Commitments and Contingencies” of this Form 10-Q.

Interest Rate Lock – The Company occasionally enters into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value, net of tax, of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in accumulated other comprehensive income, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At March 31, 2004, the Company’s consolidated balance sheet included a payable of $4.0 million related to an outstanding interest rate lock. The amount of deferred loss included in accumulated other comprehensive income was $2.5 million, net of tax. This amount will be reclassified into earnings as adjustments to interest expense related to the Company’s $200 million senior unsecured notes issued April 19, 2004 (discussed below).

Note 7 - Debt

During first quarter 2004, a subsidiary of the Company borrowed a total of $150 million from certain commercial lending institutions. The interest rate on the borrowing is LIBOR plus an effective range of 60 to 130 basis points depending on credit rating and the borrowing is for a term of five years. Proceeds were used to reduce amounts due under the $400 million credit agreement.

During first quarter 2004, the Company repaid $7.8 million on the Aspect acquisition note and $20.7 million of Israel debt.

Note 8 - Unconsolidated Subsidiaries

The following is summarized statement of operations information for subsidiaries accounted for using the equity method:

	Three Months Ended March 31,
(in thousands)	2004		2003
Revenues:
Methanol sales	$	54,957	$	54,783
Other income	5,024		2,662
Total Revenue	59,981		57,445

Expenses:
Cost of good manufactured	26,200		23,540
DD&A	4,937		5,121
SG&A	976		1,002
Total Costs and Expenses	32,113		29,663

Net Income	$	27,868	$	27,782

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.

For the three months ended March 31:

(in thousands)	2004			2003
Beginning of the period	$	102,827		$
Initial adoption entry				109,821
Liabilities incurred in the current period	4,599
Liabilities settled in the current period	(1,375		)
Accretion expense	2,661			2,333
End of the period	$	108,712		$	112,154

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. The mediation for this case was held on December 17, 2003 and no resolution was reached. The Company expects to continue mediation during second 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

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. The Emerging Issues Task Force (“EITF”) added the treatment of oil and gas mineral rights to its agenda. In March 2004, the EITF reached a consensus on EITF Issue No. 04-02, “Whether Mineral Rights are Tangible or Intangible Assets,” that mineral rights for mining companies are tangible assets. In April 2004, the Financial Accounting Standards Board (“FASB”) issued a FASB Staff Position on Statements 141 and 142 (“FSP FAS 141-1 and FAS 142-1”). The FSP amends SFAS No. 141 and 142 to resolve the perceived inconsistency between the characterization of mineral rights as tangible assets in the consensus and the characterization of mineral rights as intangible assets in SFAS No. 141 and SFAS No. 142. However, the EITF has not issued formal guidance for oil and gas companies, and further consideration of the issue may 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)	March 31, 2004			December 31, 2003
Proved leasehold acquisition costs	$	826,806		$	835,738
Unproved leasehold acquisition costs	132,465			127,194
Total leasehold acquisition costs	959,271			962,932
Less: accumulated depletion	(458,508		)	(496,227		)
Net leasehold acquisition costs	$	500,763		$	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.”

During 2003, Noble Energy identified five property packages in the United States for disposition. During 2003, property sales closed on four of the five packages, with the remaining property package expected to close during the first half of 2004. Total pre-tax proceeds on all five packages, before closing adjustments, are expected to be in excess of $110.0 million.

Summarized results of discontinued operations are as follows:

	Three Months Ended March 31,
(dollars in thousands)	2004			2003
Revenues:
Oil and gas sales and royalties	$	12,722		$	32,920

Costs and Expenses:
Purchase price and accrual adjustments	(5,892		)
Oil and gas operations	2,870			8,324
Depreciation, depletion and amortization				12,313
	(3,022		)	20,637

Income Before Income Taxes	15,744			12,283
Income Tax Provision	5,510			4,299
Income From Discontinued Operations	$	10,234		$	7,984

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.

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

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

During first quarter 2004, the Company achieved strong financial and operational performance as a result of increasing contributions from major international projects, strong domestic production growth and higher commodity prices. Financial highlights included the following:

• Net income of $85.5 million, a 145 percent increase over first quarter 2003.

• Cash flows provided by operating activities of $210.7 million, a 33 percent increase over first quarter 2003.

• A 5 percent reduction in year-end total debt balance.

Operational success was primarily due to the continuing ramp-up of international projects and strong domestic production growth, primarily as a result of Gulf of Mexico successes that came on production. First quarter 2004 operational highlights, as compared with first quarter 2003, included:

• Full quarter of production from the initial start-up period of the Phase 2A expansion project in Equatorial Guinea.

• Commencement of natural gas sales in Israel.

• A 46 percent increase in average daily crude oil production, including a 71 percent domestic increase.

• An 8 percent reduction in per unit oil and gas operations expense.

• Average realized commodity price increases of 6 percent for crude oil and 4 percent for natural gas.

The Company continues to focus on maintaining financial flexibility while pursuing new exploration and production opportunities.

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 .84:1 at March 31, 2004, compared with .73:1 at December 31, 2003. The improvement in the current ratio resulted primarily from a $77.2 million increase in the period-end balance of cash and cash equivalents, offset by an increase in current taxes payable.

Cash Flows

Operating Activities – The Company reported a $52.2 million quarter-over-quarter increase in cash flows from operating activities. Net cash provided by operating activities totaled $210.7 million for first quarter 2004 compared to $158.5 million for first quarter 2003. The 2004 increase resulted from a 46 percent increase in crude oil production and from modest increases in commodity prices which, combined, resulted in a $56.0 million increase in oil and gas sales and royalties.

Investing Activities – Net cash used in investing activities totaled $116.8 million and $120.7 million for first quarter 2004 and 2003, respectively, and related primarily to capital expenditures made for the exploration and development of oil and gas properties.

Financing Activities – Net cash used in financing activities totaled $16.7 million and $19.9 million for first quarter 2004 and 2003, respectively. Financing activities consist primarily of proceeds from and repayments of bank debt, repayment of notes currently due and payment of cash dividends on Company common stock. During first quarter 2004, debt repayments exceeded debt proceeds by $43.5 million. In addition, the Company received $29.7 million from the exercise of stock options during first quarter 2004.

Capital Expenditures

Capital expenditures consisted of the following for the three months ended March 31:

(in thousands)	2004		2003
Oil and gas mineral interests, equipment and facilities	$	123,994	$	115,464
Downstream projects	197		1,673
Corporate and other	2,419		3,367
Total capital expenditures	$	126,610	$	120,504

Total capital expenditures in the table above include seismic, dry hole 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 $118.7 million and $119.7 million for first quarter 2004 and 2003, respectively.

Total capital expenditures during first quarter 2004 increased $6.1 million or five percent from first quarter 2003. The increase in capital expenditures is due principally to the capital requirements for the expansion and drilling activities in Equatorial Guinea.

The Company expects 2004 capital expenditures to be $600 million, compared to the $460 million previously announced. Of the expected increase in the capital budget, approximately 60 percent is to pursue new exploration and development opportunities in the United States, the North Sea and Equatorial Guinea. The remaining 40 percent of the increase is for the completion of the Phase 2A and Phase 2B expansion in Equatorial Guinea. 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 sale of its offshore asset package expected to occur during the first half of 2004. The Company will evaluate its level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations and property acquisitions.

Financing Activities

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

		March 31, 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		150,000		2.52	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
Israel Note, due 2004					20,746		2.16
Note obtained in Aspect acquisition, due May 2004		98		6.25	7,928		6.25
$150 million Term Loan, due January 2009		150,000		1.97
Short Term Loans		15,000		2.04
Outstanding debt		890,098			933,674
Less:	unamortized discount	3,935			3,979
	current installments of long-term debt	140,098			153,674
Long-term debt		$	746,065		$	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.

During first quarter 2004, the Company repaid $7.8 million on the Aspect acquisition note and $20.7 million of Israel debt. The Company expects to fund the repayment of the $125 million Series A-2 Notes and the $15 million in short-term loans from a combination of accumulated cash flows and draw downs of the credit facilities.

Also during first quarter 2004, a subsidiary of the Company borrowed a total of $150 million from certain commercial lending institutions. The interest rate on the borrowing is LIBOR plus an effective range of 60 to 130 basis points depending on credit rating and the borrowing is for a term of five years. Proceeds were used to reduce amounts due under the $400 million credit agreement.

On April 19, 2004, the Company closed an offering of $200.0 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 offering was made pursuant to Rule 144A and the proceeds from the offering were used to repay short-term borrowings. 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 March 31, 2004, the Company’s consolidated balance sheet included a payable of $4.0 million related to the outstanding interest rate lock. The change in fair value of the interest rate lock, net of tax, was included in accumulated other comprehensive income at March 31, 2004, and will be reclassified into earnings as adjustments to interest expense.

The Company reduced total outstanding debt by $43.6 million during first quarter 2004. The Company’s ratio of debt-to-book capital (defined as the Company’s total debt plus its equity) was 43 percent at March 31, 2004, compared to 46 percent at December 31, 2003.

Dividends – On January 27, 2004, the Company’s Board of Directors declared a quarterly cash dividend of five cents per common share payable February 24, 2004 to the shareholders of record on February 10, 2004. This payment represents an increase of one cent per share, or 25 percent, over the Company’s quarterly payment of four cents per share paid during first quarter 2003.

Exercise of Stock Options – The Company received $29.7 million from the exercise of stock options during first quarter 2004, as compared to $0.8 million during first quarter 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 first quarter 2004, the average market price of the Company’s common stock increased over the first quarter 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

For first quarter 2004, the Company recorded net income of $85.5 million, or $1.48 per basic share, compared with net income of $34.9 million, or $0.61 per basic share, for first quarter 2003. The increase in net income resulted primarily from a significant increase in the Company’s crude oil production coupled with modest commodity price increases and a decrease in oil and gas exploration expense.

Natural Gas Information

Natural gas revenues increased five percent during first quarter 2004, compared with first quarter 2003, due to an overall four percent increase in natural gas prices and a one percent increase in daily natural gas production volumes. The table below includes average daily natural gas production volumes and prices from continuing operations for the three months ended March 31:

	2004			2003
	Mcfpd	Price		Mcfpd	Price
United States	250,052	$	5.50	261,874	$	5.18
North Sea	12,280	$	4.97	15,572	$	3.82
Equatorial Guinea (1)	46,424	$	.25	43,436	$	.25
Israel	12,235	$	2.77
Other International (2)	29,757	$	.54	26,668	$	.32
Total (3)	350,748	$	4.61	347,550	$	4.44

(1) Natural gas in Equatorial Guinea is under a long-term contract for $.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 for first quarter 2004 and 2003. Because the 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 $.01 and $.93 per Mcf for first quarter 2004 and 2003, respectively, from hedging in the United States.

Natural gas production declined in the U.S. and in the North Sea as a result of natural decline rates for properties in the Gulf of Mexico and North Sea. Natural gas production in Equatorial Guinea increased due to increased methanol production at the 45 percent owned methanol plant. Natural gas sales in Israel commenced on February 18, 2004 and averaged 12,235 Mcfpd for the first quarter 2004. Israel sales exceeded 40 MMcfpd, net to Noble Energy, by the end of first quarter 2004.

Crude Oil Information

Crude oil revenues increased 57 percent during first quarter 2004, compared with first quarter 2003, due to a 46 percent increase in daily crude oil production volumes and an overall six percent increase in crude oil prices. The table below includes average daily crude oil production volumes and prices from continuing operations for the three months ended March 31:

	2004			2003
	Bopd	Price		Bopd	Price
United States	23,394	$	30.57	13,669	$	25.40
North Sea	7,708	$	33.65	7,594	$	34.53
Equatorial Guinea	9,998	$	31.34	6,257	$	30.01
Other International (1)	7,057	$	30.37	5,378	$	31.66
Total (2)	48,157	$	31.19	32,898	$	29.41

(1) Other International includes Argentina and China.

(2) Reflects reductions of $1.14 and $2.36 per Bbl for first quarter 2004 and 2003, respectively, from hedging in the United States.

Crude oil production volumes in the U.S. increased 71 percent quarter-over-quarter. The increase was due primarily to production from Boris in the deepwater Gulf of Mexico and Roaring Fork in the deep shelf, which increased 9,175 Bopd from the same time period a year ago. Equatorial Guinea production increased due to the ramp-up of Phase 2A expansion for the Alba field. Other international is up due to a full quarter of production in China as compared to a partial quarter of production for the same time period last year.

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 $3.5 million for first quarter 2004 and ($0.5) million for first quarter 2003. GMP gross proceeds for first quarter 2004 decreased 21 percent, or $3.7 million, from first quarter 2003 primarily due to a decrease in third-party gas volumes being marketed by NEMI. GMP expenses for first quarter 2004 decreased 42 percent, or $7.7 million, from first quarter 2003 due to the decrease in third-party gas volumes being marketed by NEMI and to a decrease in bad debt expense. GMP expenses for first quarter 2003 had included bad debt expense of $4.7 million related to financial derivative contracts with one of the Company’s counterparties.

During first quarter 2004 and 2003, NEMI recorded gains of $0.3 million and $0.9 million, respectively, related to derivative instruments.

During first quarter 2004, the Company had contracts with ENA that resulted in $0.9 million of income (net of allowance) recognized in GMP proceeds. In addition, as of March 31, 2004, the Company had NYMEX-related transactions with ENA totaling 93 contracts with a mark-to-market receivable value of $1.5 million compared to 149 contracts with a mark-to-market receivable value of $1.8 million as of December 31, 2003. For additional discussion of ENA matters, see “Note 10 - Commitments and Contingencies” of this Form 10-Q.

Electricity Sales - Ecuador Integrated Power Project

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

During first quarter 2004, the combined project contributed $6.1 million of operating income from the generation of 253,061 MW of electricity. The average sales price was 6.7 cents per Kwh. During first quarter 2003, the combined project generated $5.7 million of operating income from the generation of 223,206 MW of electricity. The average sales price was 8.7 cents per Kwh.

Income from Unconsolidated Subsidiaries

Methanol operations produced $12.7 million, net to Noble Energy’s interest, for first quarter 2004 as well as for first quarter 2003. The Company’s share of production was 38,197 MGal and 34,486 MGal for first quarter 2004 and 2003, respectively. Average realized methanol prices were $.63 per gallon and $.66 per gallon for first quarter 2004 and 2003, respectively.

Costs and Expenses

Oil and Gas Operations Expense – Oil and gas operations expense increased $3.6 million, or 10 percent, to $40.6 million for first quarter 2004, as compared with $37.0 million for first quarter 2003. The increase was due to increased domestic production, the start-up of operations in Israel and the continuing ramp up of the Phase 2A in Equatorial Guinea. 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 $4.19 per BOE for first quarter 2004 as compared with $4.53 for first quarter 2003.

The table below includes crude oil and natural gas operations expense from continuing operations for the three months ended March 31:

(in thousands)

	Consolidated		United States		North Sea		Israel (2)		Equatorial Guinea		Other Int’l
2004
Lease operating (1)	$	33,853	$	21,303	$	2,874	$	1,164	$	5,149	$	3,363
Production taxes	4,995		3,996								999
Workover expense	1,787		1,787
Total operations expense	$	40,635	$	27,086	$	2,874	$	1,164	$	5,149	$	4,362

2003
Lease operating (1)	$	29,626	$	17,978	$	2,935	$		$	4,285	$	4,428
Production taxes	5,904		4,168								1,736
Workover expense	1,512		1,512
Total operations expense	$	37,042	$	23,658	$	2,935	$		$	4,285	$	6,164

(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.

Transportation Expense – The Company incurs transportation expense related to its oil and gas operations. Transportation expense totaled $4.3 million and $3.5 million for first quarter 2004 and 2003, respectively. The quarter-over-quarter increase was due primarily to higher oil production.

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 decreased $18.9 million to $16.5 million for first quarter 2004, as compared with $35.4 million for first quarter 2003. The decrease was due to a period-over-period decrease in dry hole expense of $15.8 million, of which $12.3 million was associated with a dry hole in China, and lower seismic expense of $2.0 million related to the United States.

The Company drilled 6 exploratory wells and 12 exploratory wells during first quarter 2004 and 2003, respectively.

Depreciation, Depletion and Amortization – Depreciation, depletion and amortization (“DD&A”) expense increased $7.7 million, or 11 percent, to $77.7 million for first quarter 2004, as compared with $70.0 million for first quarter 2003. The increase was due to the commencement of production from the Roaring Fork prospect in the deep shelf. The unit rate of DD&A per BOE was $8.01 for first quarter 2004 as compared with $8.56 for first quarter 2003. The decrease in the unit rate was due to the commencement of Israel production at a much lower unit rate than average and the impact of the asset impairment taken in the fourth quarter of 2003, which decreased the depletable sum for certain high unit rate properties.

Selling, General and Administrative Expense – Selling, general and administrative (“SG&A”) expense increased $1.4 million, or 10 percent, to $15.1 million for first quarter 2004, as compared with $13.6 million for first quarter 2003. The increase was due to higher rent expense and professional fees. The per unit rate of SG&A declined to $1.55 per BOE for first quarter 2004 as compared with $1.67 per BOE for first quarter 2003 due to the increase in production volumes.

Interest Expense – Interest expense (net of interest capitalized) decreased $3.5 million, or 26 percent, to $10.0 million for first quarter 2004, as compared with $13.5 million for first quarter 2003. The decrease was due to substantial debt reduction during first quarter 2004 and to an increase in the amount of interest capitalized. Capitalized interest was $4.1 million for first quarter 2004 compared with $1.9 million for first quarter 2003. Capitalized interest increased due to the continued expansion of the Phase 2A and Phase 2B projects in Equatorial Guinea.

Income Tax Provision – Income tax expense associated with continuing operations was $53.5 million and $25.5 million for first quarter 2004 and 2003, respectively. The increase was due primarily to the 121 percent increase in income before

taxes, partially offset by a decrease in the effective tax rate. The Company’s effective tax rate on income from continuing operations was 42 percent for first quarter 2004 and 44 percent for first quarter 2003.

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 on the consolidated statements of operations as “Discontinued Operations, Net of Tax.”

During 2003, the Company identified five property packages in the United States for disposition. During 2003, property sales closed on four of the five packages, with the remaining property package expected to close during the second quarter of 2004.

Summarized results of discontinued operations are as follows for the three months ended March 31:

(dollars in thousands)	2004			2003
Revenues:
Oil and gas sales and royalties	$	12,722		$	32,920

Costs and Expenses:
Purchase price and accrual adjustments	(5,892		)
Oil and gas operations	2,870			8,324
Depreciation, depletion and amortization				12,313
	(3,022		)	20,637

Income Before Income Taxes	15,744			12,283
Income Tax Provision	5,510			4,299
Income From Discontinued Operations	$	10,234		$	7,984

Key Statistics:
Daily Production
Liquids (Bbl)	996			4,859
Natural Gas (Mcf)	18,887			33,318

Average Realized Price
Liquids ($/Bbl)	$	33.39		$	29.56
Natural Gas ($/Mcf)	$	5.64		$	6.67

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

Cumulative Effect of Change in Accounting Principle, Net of Tax

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

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. The project was commissioned in the fourth quarter of 2003, and sales exceeded 40 MMcfpd, net to Noble Energy, by the end of the first quarter 2004. Production is projected to continue to increase throughout 2004, adding another 10 to 50 MMcfpd, net to Noble Energy; and

• Phase 2A condensate expansion in Equatorial Guinea, which began start-up during November 2003, is expected to add nearly 10,000 Boepd, net to Noble Energy, by the end of the second quarter 2004.

The Company expects its 2004 capital expenditures budget to be $600 million, compared to the $460 million previously announced. 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, electricity and methanol industries. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.

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. The Emerging Issues Task Force has added the treatment of oil and gas mineral rights to its agenda. In March 2004, the EITF reached a consensus on EITF Issue No. 04-02, “Whether Mineral Rights are Tangible or Intangible Assets,” that mineral rights for mining companies are tangible assets. In April 2004, the FASB issued a FASB Staff Position on Statements 141 and 142 (“FSP FAS 141-1 and FAS 142-1”). The FSP amends SFAS No. 141 and 142 to resolve the perceived inconsistency between the characterization of mineral rights as tangible assets in the consensus and the characterization of mineral rights as intangible assets in SFAS No. 141 and SFAS No. 142. However, the EITF has not issued formal guidance for oil and gas companies, and further consideration of the issue may result in a change in how Noble Energy classifies these assets.

Intangible Assets (in thousands)	March 31, 2004			December 31, 2003
Proved leasehold acquisition costs	$	826,806		$	835,738
Unproved leasehold acquisition costs	132,465			127,194
Total leasehold acquisition costs	959,271			962,932
Less: accumulated depletion	(458,508		)	(496,227		)
Net leasehold acquisition costs	$	500,763		$	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 May 4, 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
2Q2004	120,000	$4.06 - $5.95	15,000	$24.83 - $31.22
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	50,000	$5.00 - $8.25	5,000	$29.00 - $39.40
2Q2005			5,000	$29.00 - $37.25

As of March 31, 2004, the Company had a net unrealized loss of $25.3 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 pursuant to 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 March 31, 2004, the Company believes it had no material market risk exposure from NEMI’s derivative instruments. As of March 31, 2004, NEMI had a net receivable of $0.9 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 March 31, 2004, the Company had $890.1 million of debt outstanding of which approximately 65 percent was term 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 March 31, 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 March 31, 2004, $315 million of variable rate debt was outstanding. A 10 percent change in the floating interest rates applicable to the March 31, 2004 balance would result in a change in annual interest expense of less than $1 million.

The Company occasionally enters into forward contracts or swap agreements to hedge exposure to interest rate risk. At March 31, 2004, the Company’s consolidated balance sheet included a payable of $4.0 million related to an outstanding interest rate lock. The amount of deferred loss included in accumulated other comprehensive income was $2.5 million, net of tax. This amount will be reclassified into earnings as adjustments to interest expense related to the Company’s $200 million senior unsecured notes issued April 19, 2004.

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 (loss) 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 our estimates. Any substantial or extended change in the actual prices of natural gas and/or crude oil could have a material effect on: (1) the Company’s financial position and results of operations, (2) the quantities of natural gas and crude oil reserves that the Company can economically produce, (3) the quantity of estimated proved reserves that may be attributed to its properties, and (4) the Company’s ability to fund its capital program.

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

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

Laws and Regulations. Noble Energy’s forward-looking statements are generally based on the assumption that the legal and regulatory environments will remain stable. Changes in the legal and/or regulatory environments could have a material effect on the Company’s future results of operations and financial condition. Noble Energy’s ability to economically produce and sell crude oil, natural gas, methanol and power is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting: (1) crude oil and natural gas production, (2) taxes applicable to the Company and/or its production, (3) the amount of crude oil and natural gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities, and (5) the marketing of competitive fuels. The Company’s operations are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Noble Energy’s forward-looking statements are generally based upon the expectation that the Company will not be required, in the near future, to expend cash to comply with environmental laws and regulations that are material in relation to its total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, the Company is unable to accurately predict the ultimate financial impact of compliance.

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

Competition. 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a) The annual meeting of stockholders of the Company was held at 9:30 a.m., Central time, on Tuesday, April 27, 2004 in Ardmore, Oklahoma.

(b) Proxies were solicited by the Board of Directors of the Company pursuant to Regulation 14A under the Securities Exchange Act of 1934. There was no solicitation in opposition to the Board of Directors’ nominees as listed in the proxy statement and all such nominees were duly elected.

(c) Out of a total of 57,924,772 shares of common stock of the Company outstanding and entitled to vote, 51,463,528 shares were present in person or by proxy, representing approximately 89 percent.

	Number of Shares Voting FOR Election As Director	Number of Shares WITHHOLDING AUTHORITY To Vote for Election As Director

Michael A. Cawley	49,956,647	1,506,881
Edward F. Cox	49,910,967	1,552,561
Charles D. Davidson	49,807,599	1,655,929
Kirby L. Hedrick	50,298,867	1,164,661
Dale P. Jones	50,280,518	1,183,010
Bruce A. Smith	49,975,721	1,487,807

(d) The other matters voted on by the shareholders, as fully described in the proxy statement for the annual meeting, and the results of the voting are as follows:

Proposal II. Ratification of Appointment of KPMG LLP as Independent Auditors (For 50,692,311; Against 733,834; Abstaining 37,383)

Proposal III. Approval of Amendment to 1988 Nonqualified Stock Option Plan for Non-Employee Directors to increase the number of common stock authorized for issuance from 550,000 shares to 750,000 shares. (For 39,848,994; Against 7,102,279; Abstaining 50,882; Broker Non-Votes 4,461,373)

Proposal IV. Approval of Material Terms of Performance Goals under Noble Energy’s 2004 Long-Term Incentive Plan for Purposes of Section 162(m) of the Internal Revenue Code. (For 43,883,402; Against 2,938,422; Abstaining 180,331; Broker Non-Votes 4,461,373)

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 January 16, 2004, Noble Energy filed a current report on Form 8-K reporting under Item 5 the filing of 2002 financial statements which were reclassified in connection with the January 1, 2003 adoption of Emerging Issues Task Force EITF 02-03 “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” and as a result of the Company’s reporting discontinued operations for the sale of oil and gas properties during 2003. The date of the report (the date of earliest event reported) was January 16, 2004.

(ii) On February 9, 2004, Noble Energy furnished a current report on Form 8-K reporting under Item 12 that it was (a) filing a copy of its press release announcing its 2003 reserve replacement estimates and year-end reserve data and (b) filing a copy of its press release announcing its financial results for its full year and fourth quarter ended December 31, 2003. The date of the report (the date of earliest event reported) was February 2, 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	May 7, 2004	/s/ JAMES L. McELVANY
		JAMES L. McELVANY Senior Vice President, Chief Financial Officer and Treasurer

INDEX TO EXHIBITS

Exhibit Number		Exhibit

12.1		Computation of ratio of earnings to fixed charges.

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

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

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

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