NOBLE ENERGY INC - 10-Q Quarterly Report

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	(Unaudited) March 31, 2005			December 31, 2004
ASSETS
Current Assets:
Cash and cash equivalents	$	181,565		$	179,794
Accounts receivable - trade, net	385,593			407,349
Derivative instruments	10,527			28,733
Materials and supplies inventories	21,072			12,109
Deferred taxes	82,913			13,039
Prepaid expenses and other	46,431			28,278
Probable insurance claims	73,478			65,000
Total current assets	801,579			734,302
Property, Plant and Equipment, at Cost
Oil and gas mineral interests, equipment and facilities (successful efforts method of accounting)	4,367,393			4,292,561
Other	65,763			56,707
	4,433,156			4,349,268
Accumulated depreciation, depletion and amortization	(2,044,509		)	(2,016,318		)
Total property, plant and equipment, net	2,388,647			2,332,950
Investment in Unconsolidated Subsidiaries	229,549			231,795
Other Assets	127,848			144,124

Total Assets	$	3,547,623		$	3,443,171

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	404,012		$	431,521
Derivative instruments	236,601			50,304
Interest payable	18,568			11,439
Income taxes - current	62,165			64,852
Asset retirement obligations - current	88,046			79,568
Other current liabilities	26,700			27,320
Total Current Liabilities	836,092			665,004
Deferred Income Taxes	67,217			183,351
Asset Retirement Obligations	180,651			175,415
Derivative Instruments	370,838			9,678
Other Deferred Credits and Noncurrent Liabilities	76,507			69,479
Long-Term Debt	815,325			880,256

Total Liabilities	2,346,630			1,983,183

Commitments and Contingencies

Shareholders’ Equity:
Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
Common stock - par value $3.33 1/3; 100,000,000 shares authorized; 62,869,042 and 62,572,417 shares issued at March 31, 2005 and December 31, 2004, respectively	209,564			208,576
Capital in excess of par value	513,773			500,034
Deferred compensation	(4,064		)	(1,671		)
Accumulated other comprehensive loss	(393,133		)	(14,787		)
Retained earnings	950,809			843,792
	1,276,949			1,535,944
Less: common stock in treasury at cost (March 31, 2005 and December 31, 2004, 3,549,976 shares)	(75,956		)	(75,956		)

Total Shareholders’ Equity	1,200,993			1,459,988

Total Liabilities and Shareholders’ Equity	$	3,547,623		$	3,443,171

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended March 31,
	2005			2004
Revenues:
Oil and gas sales and royalties	$	315,551		$	271,586
Gathering, marketing and processing	11,483			14,175
Electricity sales	21,591			19,119
Income from investment in unconsolidated subsidiaries	16,609			12,736

Total Revenues	365,234			317,616

Costs and Expenses:
Oil and gas operations	37,077			33,982
Production and ad valorem taxes	9,220			6,653
Transportation	1,639			4,271
Oil and gas exploration	23,657			16,486
Gathering, marketing and processing	8,237			10,716
Electricity generation	11,439			13,024
Depreciation, depletion and amortization	70,467			77,682
Selling, general and administrative	15,168			15,059
Accretion of discount on asset retirement obligations	2,551			2,661
Interest	14,228			14,158
Interest capitalized	(4,861		)	(4,114		)
Other expense (income), net	1,859			(1,810		)

Total Costs and Expenses	190,681			188,768

Income Before Taxes	174,553			128,848

Income Tax Provision	64,585			53,536

Income From Continuing Operations	109,968			75,312

Discontinued Operations, Net of Tax	—			10,234

Net Income	$	109,968		$	85,546

Earnings Per Share:
Basic -
Income from continuing operations	$	1.86		$	1.30
Discontinued operations, net of tax	—			0.18
Net income	$	1.86		$	1.48

Diluted -
Income from continuing operations	$	1.83		$	1.29
Discontinued operations, net of tax	—			0.17
Net income	$	1.83		$	1.46

Weighted average number of shares outstanding - Basic	59,083			57,663
Weighted average number of shares outstanding - Diluted	60,139			58,531

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)

	Three Months Ended March 31,
	2005			2004
Comprehensive Income:
Net income	$	109,968		$	85,546
Other comprehensive income, net of tax:
Unrealized loss on cash flow hedges:
Unrealized fair value loss during period:
Oil and gas cash flow hedges (1)	(387,526		)	(12,325		)
Less: reclassification adjustment for amounts out of OCI:
Oil and gas cash flow hedges (2)	8,958			3,361
Interest rate lock cash flow hedge (3)	123			—
	(378,445		)	(8,964		)
Change in additional minimum pension liability and other (4)	99			(625		)
Other comprehensive loss	(378,346		)	(9,589		)

Comprehensive (loss) income	$	(268,378	)	$	75,957


(1) Income tax benefit	$	(208,668	)	$	(6,637	)
(2) Income tax provision	$	4,824		$	1,810
(3) Income tax provision	$	66		$	—
(4) Income tax provision (benefit)	$	53		$	(337	)

See notes to consolidated financial statements.

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Three Months Ended March 31,
	2005			2004
Cash Flows from Operating Activities:
Net income	$	109,968		$	85,546
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	70,467			77,682
Depreciation, depletion and amortization - electricity generation	4,308			6,155
Dry hole expense	8,862			4,461
Amortization of unproved leasehold costs	4,904			5,294
Non-cash effect of discontinued operations	—			(5,892		)
Gain on disposal of assets	(1,276		)	(2,642		)
Deferred income taxes	11,147			26,215
Accretion of discount on asset retirement obligations	2,551			2,661
Income from unconsolidated subsidiaries	(16,609		)	(12,736		)
Dividends received from unconsolidated subsidiary	17,550			11,250
Increase (decrease) in noncurrent liabilities	9,947			(5,189		)
Increase in other	(4,029		)	(87		)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	20,726			(10,149		)
Increase in other current assets	(29,618		)	(14,326		)
(Decrease) in accounts payable	(27,509		)	(27,727		)
Increase in other current liabilities	20,849			70,200

Net Cash Provided by Operating Activities	202,238			210,716

Cash Flows From Investing Activities:
Capital expenditures	(145,556		)	(118,694		)
Proceeds from sale of property, plant and equipment	320			1,079
Insurance recovery - involuntary conversion	2,287			—
Distribution from unconsolidated subsidiaries	1,305			798

Net Cash Used in Investing Activities	(141,644		)	(116,817		)

Cash Flows From Financing Activities:
Exercise of stock options	9,058			29,695
Cash dividends paid	(2,950		)	(2,879		)
Payment on credit facilities, net	(64,931		)	(164,956		)
Proceeds from term loan	—			150,000
Repayment of Israel note	—			(20,746		)
Repayment of note payable	—			(7,830		)

Net Cash Used in Financing Activities	(58,823		)	(16,716		)

Increase in Cash and Cash Equivalents	1,771			77,183

Cash and Cash Equivalents at Beginning of Period	179,794			62,374

Cash and Cash Equivalents at End of Period	$	181,565		$	139,557

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, 2005 and December 31, 2004; the results of operations for the three month periods ended March 31, 2005 and 2004; the statements of comprehensive income (loss) for the three month periods ended March 31, 2005 and 2004; and the cash flows for the three month periods ended March 31, 2005 and 2004. 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, 2004.

Note 1 - Pending Merger with Patina Oil & Gas Corporation

On December 15, 2004, the Boards of Directors of Noble Energy and Patina Oil & Gas Corporation (“Patina”) approved Noble Energy’s Merger Agreement with Patina. As a result of the proposed merger, Patina will merge into a wholly-owned subsidiary of Noble Energy, and Patina shareholders will receive aggregate consideration comprised of approximately 60 percent Noble Energy common stock and 40 percent cash. Total consideration for the outstanding shares of Patina is fixed at approximately $1.1 billion in cash and approximately 27 million Noble Energy shares, not including options and warrants exchanged in the transaction, and subject to adjustment as provided in the Merger Agreement. Under the terms of the Merger Agreement, Patina shareholders will have the right to elect to receive either cash or Noble Energy common stock, or a combination thereof, in exchange for their shares of Patina common stock, subject to an allocation mechanism if either the cash election or the stock election is oversubscribed. While the per share consideration was initially set in the Merger Agreement at $37.00 in cash or 0.6252 shares of Noble Energy common stock, the per share consideration is subject to adjustment upwards or downwards. This adjustment will reflect 37.5126 percent of the difference between $59.18 and the price of Noble Energy’s shares during a specified period prior to closing. In addition, the per share consideration is adjusted so that each Patina share receives consideration representing equal value regardless of whether it is converted into cash or Noble Energy common stock. The proposed merger is subject to certain approvals of the shareholders of Noble Energy and Patina and other customary conditions. Special meetings for the respective shareholders of Noble Energy and Patina have been scheduled for May 11, 2005 for this purpose.

In connection with the proposed merger with Patina, the Company has entered into a $1.3 billion credit facility with certain financial institutions. The new facility is a reducing revolver due 2010 with a five percent per quarter commitment reduction in each calendar quarter during year four and 20 percent per quarter reduction in year five. The facility incurs a 7.5 basis point “ticking” fee from the effective date, April 4, 2005, until the initial borrowing date under the facility. Commencing on the initial borrowing date, the Company will incur a facility fee of 10 to 25 basis points per annum depending upon the Company’s credit rating. The facility bears interest based upon a Eurodollar rate plus 30 to 100 basis points depending upon the Company’s credit rating. Financial covenants on the new facility are similar to those for the Company’s currently outstanding debt. In addition, the commitment will be reduced by the net proceeds from certain issuances of debt by the Company and by the amount of proceeds from certain asset sales in excess of $100 million received by the Company. The facility is available (a) to fund the acquisition of Patina, (b) to refinance existing indebtedness of the Company and Patina, and (c) for general corporate purposes.

Note 2 - 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 March 31,
(in thousands, except per share amounts)	2005			2004
Net income, as reported	$	109,968		$	85,546
Add: Stock-based compensation cost recognized, net of related tax effects	341			34
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(1,915		)	(1,873		)
Pro forma net income	$	108,394		$	83,707
Earnings per share:
Basic - as reported	$	1.86		$	1.48
Basic - pro forma	$	1.83		$	1.45
Diluted - as reported	$	1.83		$	1.46
Diluted - pro forma	$	1.80		$	1.43

Note 3 - Involuntary Conversion of Assets

In September 2004, Hurricane Ivan moved through the Gulf of Mexico resulting in infrastructure damage at Main Pass 293/305/306. Costs related to clean-up and redevelopment are insured to a limit that the Company believes will allow for restoration of production. The loss of production is not covered by business interruption insurance.

The Company plans to replace the assets that were destroyed by the hurricane and expects that the costs of replacing those assets will be recoverable from insurance proceeds, subject to a $1.0 million deductible. This amount was recognized as a loss on involuntary conversion of assets during 2004. The Company will adjust the total gain or loss attributable to the involuntary conversion in the period in which the contingencies related to the replacement costs and related insurance recoveries are resolved.

During the first quarter of 2005, Noble Energy received $2.3 million of insurance proceeds related to Main Pass 293/305/306 damage claims. In addition, the present value of the estimate for clean up and restoration costs was revised upward from $130.0 million at year-end 2004 to $147.0 million at March 31, 2005. The remediation work is scheduled to begin in the second quarter of 2005 and production could commence in the third quarter of 2005 from the undamaged platforms.

Assets (liabilities) included on the Company’s balance sheet consist of the following:

(in thousands)	March 31, 2005
Probable insurance claims - current	$				73,478
Other assets (long-term portion of probable insurance claims)	95,726
Total expected insurance recoveries	$			169,204

Asset retirement obligation - current	$		(73,478			)
Asset retirement obligation - long-term	(73,478					)
Total asset retirement obligation related to Main Pass assets	$	(146,956				)

As of March 31, 2005, the Company had received $9.0 million from insurance recoveries related to the Main Pass damage claims.

Note 4 - Capitalized Exploratory Well Costs

As of January 1, 2005, the Company adopted FASB Staff Position FAS 19-1, “Accounting for Suspended Well Costs.” For more information, see “Note 15 - Recently Issued Pronouncements” of this Form 10-Q. The following table reflects the net changes in capitalized exploratory well costs for the three months ended March 31, 2005 and does not include amounts that were capitalized and subsequently expensed in the same period.

(in thousands)	Three Months Ended March 31, 2005
Capitalized exploratory well costs at beginning of period	$	62,724
Additions to capitalized exploratory well costs pending the determination of proved reserves	11,336
Reclassified to property, plant and equipment based on the determination of proved reserves	(1,807		)
Capitalized exploratory well costs charged to expense	(1,496		)
Capitalized exploratory well costs at end of period	$	70,757

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

(in thousands)	March 31, 2005		December 31, 2004
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	52,972	$	44,986
Capitalized exploratory well costs that have been capitalized for a period of greater than one year	17,785		17,738
Balance at end of period	$	70,757	$	62,724

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	3		4

At March 31, 2005, the balance of property, plant and equipment included $70.8 million of suspended exploratory well costs, of which $17.8 million had been capitalized for a period greater than one year. Of the $17.8 million, $15.9 million is associated with Lorien (Green Canyon 199), a deepwater Gulf of Mexico project discovered in 2003. The Company increased its working interest from 20 percent to 60 percent in the second quarter of 2004. A successful appraisal sidetrack well was drilled in 2004 and a second appraisal well was drilled in the first quarter of 2005 to delineate the reservoir. Reserves are expected to be recorded in 2005, at which time the suspended well costs will be reclassified to property, plant and equipment.

Note 5 - 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.

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in thousands)	2005			2004			2005			2004
Service cost	$	1,514		$	1,317		$	184		$	165
Interest cost	1,666			1,537			282			270
Expected return on plan assets	(1,799		)	(1,746		)	—			—
Transition obligation recognition	(54		)	(54		)	60			60
Amortization of prior service cost	101			98			(13		)	(18		)
Recognized net actuarial loss	200			71			56			51
Net periodic benefit cost	$	1,628		$	1,223		$	569		$	528

For 2005, the expected return assumption is 8.25 percent and the assumed discount rate is 6.0 percent.

The Company contributed cash of $2.3 million to its pension plans in the first quarter 2005 relating to the 2004 plan year.

Note 6 - Income Tax Provision

The income tax provision consists of the following:

	Three Months Ended March 31,
(in thousands)	2005		2004
Current	$	53,438	$	30,359
Deferred	11,147		23,177
Total income tax provision	$	64,585	$	53,536

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 provision associated with discontinued operations was $5.5 million for the three-month period ending March 31, 2004.

On October 22, 2004, the American Jobs Creation Act (“AJCA”) became law. The AJCA included numerous provisions that may materially affect accounting for income taxes. Those provisions include a repeal of an export tax benefit for U.S.-based manufacturing activities and grants a special deduction that, depending on the circumstances, could reduce the effective tax rate. In addition, the AJCA created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing for an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. The deduction is subject to a number of limitations and, to date, uncertainty remains as to how to interpret some provisions of the AJCA.

In accordance with FSP FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the Company will account for any qualified production activities deduction as a special deduction in 2005. The Company believes that because of the phased-in nature of the deduction, it will not have a significant impact on its income tax provision or deferred tax assets or liabilities in 2005.

FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision with the American Jobs Creation Act of 2004” has allowed enterprises time beyond the financial reporting period of enactment of the AJCA to evaluate the effect of the Act on plans for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. The Company has begun an evaluation of the effects of the repatriation provision. However, due to uncertainty remaining as to how to interpret some provisions of the AJCA, the Company is not yet in a position to decide on whether, and to what extent, it might repatriate foreign earnings that have not yet been remitted to the U.S. The Company is currently evaluating the possibility of repatriating earnings of its Samedan Methanol subsidiary ranging in amount from $100 million to $118 million. Because the Company has provided U.S. tax on most of Samedan Methanol’s earnings at 35 percent through December 31, 2004, repatriation under the Act would result in a net tax benefit ranging from $29.8 million to $33.9 million. The Company expects to be in a position to finalize its assessment during the second quarter 2005. If management decides to repatriate a portion of its foreign earnings pursuant to the AJCA, the Company will reflect additional taxes (or tax benefit) on those earnings for the period in which that decision is made.

Note 7 - Basic Earnings Per Share and Diluted Earnings Per Share

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

	Three Months Ended March 31,
	2005					2004
(in thousands, except per share amounts)	Income (Numerator)				Shares (Denominator)	Income (Numerator)				Shares (Denominator)
Net income/shares	$	109,968			59,083	$	85,546			57,663
Basic EPS			$	1.86				$	1.48

Net income/shares	$	109,968			59,083	$	85,546			57,663
Effect of dilutive securities
Stock options					986					840
Restricted stock					70					28
Adjusted net income/shares	$	109,968			60,139	$	85,546			58,531
Diluted EPS			$	1.83				$	1.46

No options were excluded from the EPS calculations above. There were no antidilutive options for the first three months of 2005 or 2004 as the average market price of Company common stock for those periods was in excess of the exercise price for all options outstanding.

Note 8 - 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, Equatorial Guinea, North Sea, Israel, 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, 2005

(In Thousands)

	Consolidated		United States		Equatorial Guinea		North Sea		Israel		Other Int’l, Corporate & Marketing

Revenues from external customers	$	348,625	$	96,207	$	56,986	$	29,232	$	14,676	$	151,524
Intersegment revenues	—		90,369		—		—		—		(90,369		)
Income from unconsolidated subsidiaries	16,609		—		16,609		—		—		—
Total Revenues	$	365,234	$	186,576	$	73,595	$	29,232	$	14,676	$	61,155

DD&A	$	70,467	$	51,832	$	5,334	$	2,872	$	2,560	$	7,869
Accretion of discount on asset retirement obligation	$	2,551	$	2,174	$	9	$	279	$	55	$	34

Income from continuing operations before taxes	$	174,553	$	80,664	$	60,132	$	19,651	$	10,494	$	3,612

Total assets as of March 31, 2005	$	3,547,623	$	1,343,643	$	867,252	$	200,127	$	255,307	$	881,294

Oil & Gas Operations

Three Months Ended March 31, 2004

(In Thousands)

	Consolidated		United States		Equatorial Guinea		North Sea		Israel		Other Int’l, Corporate & Marketing

Revenues from external customers	$	304,880	$	43,984	$	29,577	$	29,159	$	3,085	$	199,075
Intersegment revenues	—		146,246		—		—		—		(146,246		)
Income from unconsolidated subsidiaries	12,736		—		12,736		—		—		—
Total Revenues	$	317,616	$	190,230	$	42,313	$	29,159	$	3,085	$	52,829

DD&A	$	77,682	$	62,869	$	2,042	$	5,408	$	1,080	$	6,283
Accretion of discount on asset retirement obligation	$	2,661	$	2,312	$	—	$	316	$	33	$	—

Income (loss) from continuing operations before taxes	$	128,848	$	81,069	$	35,051	$	18,672	$	241	$	(6,185	)

Total assets as of December 31, 2004	$	3,443,171	$	1,299,547	$	817,062	$	218,881	$	273,347	$	834,334

Note 9 - Derivative Instruments 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 on the Company’s consolidated statements of operations upon sale of the associated products. Hedge effectiveness is assessed 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 expense (income), net.

The Company entered into various natural gas and crude oil costless collars related to its natural gas and crude oil production as follows:

	Three Months Ended March 31,
Natural Gas	2005		2004
Hedge MMBTUpd	95,000		121,140
Floor price range	$5.00 - $5.75		$4.50 - $5.00
Ceiling price range	$7.80 - $9.50		$6.20 - $9.65
Percent of daily production	27	%	35	%

	Three Months Ended March 31,
Crude Oil	2005		2004
Hedge Bpd	20,788		15,018
Floor price range	$29.00 - $37.50		$25.00 - $26.00
Ceiling price range	$37.65 - $50.50		$30.25 - $32.25
Percent of daily production	45	%	31	%

The Company included losses of $13.8 million and $5.2 million related to cash flow hedges in oil and gas sales and royalties during first quarter 2005 and 2004, respectively. The Company recorded $2.6 million and $2.0 million of ineffectiveness related to cash flow hedges during first quarter 2005 and 2004, respectively, in other expense (income), net.

As of March 31, 2005, 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
		Average Price						Average Price
Production		Per MMBTU				Production		Per Bbl
Period	MMBTUpd	Floor		Ceiling		Period	Bopd	Floor		Ceiling
Apr-Dec 2005	75,000	$	5.00	$	7.50	Apr-Dec 2005	20,431	$	31.30	$	43.99
2006	3,699	$	5.00	$	8.00	2006	1,865	$	29.00	$	34.93

As of March 31, 2005, the Company had entered into future fixed price swap 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		Production Period	Bopd	Average Price Per Bbl
May-Dec 2005	130,000	$	6.76	May-Dec 2005	13,100	$	39.62
2006	170,000	$	6.48	2006	16,600	$	40.47
2007	170,000	$	6.03	2007	17,100	$	39.19
2008	170,000	$	5.67	2008	16,500	$	38.23

If commodity prices were to stay the same as they were at March 31, 2005, approximately $147.4 million of net deferred losses, net of taxes, related to the fair values of the Company’s derivative instruments included in accumulated other comprehensive loss at March 31, 2005 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 December 31, 2008.

The Company’s balance sheet includes the following assets (liabilities) related to derivative instruments:

(in thousands)	March 31, 2005			December 31, 2004
Derivative instruments (current asset)	$	10,527		$	28,733
Derivative instruments (long-term asset)	1,130			20,427
Derivative instruments (current liability)	(236,601		)	(50,304		)
Derivative instruments (long-term liability)	(370,838		)	(9,678		)

The increase in derivative liability balances reflects both record high crude oil prices and an increase in the percentage of production hedged at March 31, 2005.

Other Derivative Instruments – Noble Energy, 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 the Company are on an index basis; however, purchasers in the markets in which the Company sells often require fixed or NYMEX-related pricing. The Company may use a derivative instrument to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility.

The Company records gains and losses on these 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, 2005 and 2004, the Company recorded gains (losses) of $(0.7) million and $0.3 million, respectively, related to derivative instruments not accounted for as cash flow hedges.

Note 10 - Unconsolidated Subsidiaries

The Company has investments, at various percentages of ownership, in subsidiaries that are accounted for using the equity method of accounting. Through these subsidiaries, the Company has an interest in a methanol plant in Equatorial Guinea. The following is summarized, combined statement of operations information for subsidiaries accounted for using the equity method:

	Three Months Ended March 31,
(in thousands)	2005		2004
Revenues:
Methanol sales	$	75,933	$	54,957
Other income	2,851		5,024
Total Revenues	78,784		59,981
Less cost of goods sold	26,778		26,200
Gross Margin	52,006		33,781

Expenses:
DD&A	4,873		4,937
Administrative	948		976
Total Expenses	5,821		5,913

Income Before Taxes	46,185		27,868
Income tax provision	9,596		—

Net Income	$	36,589	$	27,868

Note 11 - Asset Retirement Obligations

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. The following table reflects the net changes in the Company’s asset retirement obligations.

(in thousands)	Three Months Ended March 31, 2005
Asset retirement obligations at beginning of period	$	254,983
Liabilities incurred in the current period	203
Liabilities settled in the current period	(1,063		)
Revisions	12,023
Accretion expense	2,551
Asset retirement obligations at end of period	$	268,697

The ending aggregate carrying amount includes $147.0 million, which will be reimbursed by insurance, related to Hurricane Ivan damage to the Main Pass assets in the Gulf of Mexico. The estimate for Main Pass was increased in the first quarter by approximately $14.5 million, discounted, due to revised estimates related to clean up and restoration costs.

Note 12 - Commitments and Contingencies

On October 15, 2002, the Company filed proofs of claim in the United States Bankruptcy Court 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 $12.0 million.

On December 13, 2002, ENA filed a complaint in which it objected to the Company’s proofs of claim, sought recovery of approximately $60.0 million from the Company under the natural gas sales agreements, sought declaratory relief in respect of

Note 15 - Recently Issued Pronouncements

Accounting for Stock Options – In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” This statement revised SFAS No. 123, “Accounting for Stock-Based Compensation,” and superseded APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and its related implementation guidance. SFAS No. 123(R) requires companies to recognize on the income statement the grant-date fair value of stock options and other equity-based compensation issued to employees. The SEC recently adopted a new rule that defers the effective date of SFAS No. 123(R) and allows companies to implement the provisions of the Statement at the beginning of their next fiscal year. As a result, the Company currently expects to adopt SFAS No. 123(R) as of January 1, 2006, using the modified prospective transition method. Under the modified prospective method, awards that are granted, modified or settled after January 1, 2006 will be measured in accordance with SFAS No. 123(R). Unvested equity-classified awards that were granted prior to January 1, 2006 will be accounted for in accordance with SFAS No. 123, except that the amounts will be recognized on the Company’s consolidated statements of operations. The Company is currently evaluating the impact of SFAS No. 123(R) and expects that it will recognize additional compensation expense during first quarter 2006.

Accounting for Suspended Well Costs – In April 2005, the FASB issued FASB Staff Position FAS 19-1, “Accounting for Suspended Well Costs” (“FSP FAS 19-1”). FSP FAS 19-1 amended SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” to provide for the continued capitalization of exploratory well costs beyond one year when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. The guidance in FSP FAS 19-1 is to be applied to the first reporting period beginning after April 4, 2005. Guidance is to be applied prospectively, and early application is permitted in periods for which financial statements have not yet been issued. The Company has applied the provisions of FSP FAS 19-1 for first quarter 2005 and its adoption had no effect on the Company’s balance sheet, results of operations or cash flows.

Accounting for Conditional Asset Retirement Obligations – In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS No. 143” (“FIN 47”). A conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 clarifies that an entity is required to recognize a liability in the period it is incurred for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability. The Company adopted FIN 47 in the first quarter 2005 and the adoption had no effect on the Company’s balance sheet, results of operations or cash flows.

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

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

The Company’s first quarter results reflect an ongoing trend of improving operating and financial performance that began in early 2004, continued through the first quarter of this year and is expected to continue for some time. Recent successes in the deepwater Gulf of Mexico have led to three significant projects that are expected to add new production through 2006, with the Swordfish development scheduled to begin producing at 10,000 Boepd, net, by mid-year 2005. The Phase 2A condensate expansion project in Equatorial Guinea is complete and near full production. The Phase 2B liquids expansion project is nearly complete, with production expected to commence late in the second quarter this year. Total unit costs declined compared to last year, driven primarily by lower unit depreciation, depletion and amortization (“DD&A”) rates from new international production. Deepwater developments and expansion in Equatorial Guinea are expected to add new production in the second half of 2005.

First quarter 2005 financial results, as compared with first quarter 2004, included:

• Net income of $110.0 million, or $1.86 per share, a 29 percent increase compared to $85.5 million, or $1.48 per share, reported first quarter 2004;

• Net cash provided by operating activities of $202.2 million, a four percent decrease compared to $210.7 million reported first quarter 2004;

• A $64.9 million, or seven percent, reduction in outstanding debt since December 31, 2004; and

• A new $1.3 billion credit facility to provide funding for the pending merger with Patina.

First quarter 2005 operational results, as compared with first quarter 2004, included:

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

• Successful high bids on eight lease blocks at the Central Gulf of Mexico Outer Continental Shelf Sale 194, including six blocks in the Mississippi Canyon area, one block in Green Canyon and one block in Viosca Knoll;

• A 30 percent increase in the average realized crude oil price and an eight percent increase in the average realized natural gas price;

• An overall production rate that remained steady at 105,051 Boepd for first quarter 2005 as compared with 106,615 Boepd for first quarter 2004;

• A 24 percent increase in international production volumes over first quarter 2004 from increasing production in Equatorial Guinea, Israel and China;

• An 18 percent decrease in domestic production volumes due primarily to natural field decline and effects of timing of production increases from deepwater developments; and

• A seven percent decrease in per unit DD&A expense.

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 and to pay cash dividends on common stock. 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.

Cash Flows

Operating Activities – For first quarter 2005, the Company reported net cash provided by operating activities of $202.2 million, an $8.5 million decrease as compared with $210.7 million for first quarter 2004.

Investing Activities – Net cash used in investing activities totaled $141.6 million and $116.8 million for first quarter 2005 and 2004, respectively, and related primarily to capital expenditures made for the exploration, development and acquisition of oil and gas properties.

Financing Activities – Net cash used in financing activities totaled $58.8 million and $16.7 million for first quarter 2005 and 2004, 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.

Ecuador Receivables – Certain entities purchasing electricity from the Company in Ecuador have been slow to pay their receivables. While the Company does not consider these receivables to be material, it is pursuing various strategies to protect its interests and has made adequate provisions to cover potentially uncollectible balances.

Capital Expenditures

Selected capital expenditure information is as follows:

	Three Months Ended March 31,
(in thousands)	2005		2004
Oil and gas mineral interests, equipment and facilities	$	130,714	$	111,980
Proved property acquisition costs	18		—
Unproved property acquisition costs	10,129		12,094
Downstream projects	59		197

The increase in expenditures for oil and gas mineral interests, equipment and facilities for first quarter 2005 over first quarter 2004 is due primarily to an increase of $41.8 million in the deepwater Gulf of Mexico for development of Lorien, Swordfish and Ticonderoga, offset by a decrease of $25.2 million for Phase 2A in Equatorial Guinea. The Company has funded its 2005 capital expenditures primarily from cash flow from operations.

Financing Activities

Debt – The Company had outstanding debt of $820 million ($815 million net of unamortized discount) at March 31, 2005, of which $650 million was fixed-rate debt due 2014 through 2097. The remainder of the outstanding debt, $170 million at March 31, 2005, represents variable-rate debt. The variable-rate debt consists of $150 million Israeli term loans due January 2009 and $20 million drawn under the Company’s two credit agreements that are with certain commercial lending institutions. The two credit agreements consist of a $400 million credit agreement due October 2009 that bears interest based on a Eurodollar rate plus a range of 30 to 112.5 basis points depending on the percentage of utilization and credit rating, and a $400 million credit agreement due November 2006 that 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. At March 31, 2005, the Company had $780 million in unused borrowing capacity under these credit facilities. The Company’s credit agreements are supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. The uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing.

During first quarter 2005, the Company reduced its total debt balance by $64.9 million. The Company’s ratio of debt-to-book capital (defined as the Company’s total debt divided by the sum of total debt plus equity) was 40 percent at March 31, 2005, compared to 38 percent at December 31, 2004.

Dividends – In January of 2005, the Company’s Board of Directors declared quarterly cash dividends of five cents per share of common stock.

Exercise of Stock Options – The Company received $9.1 million from the exercise of stock options during first quarter 2005, as compared to $29.7 million during first quarter 2004. Proceeds received by the Company from the exercise of stock options fluctuate primarily based on the number of outstanding options exercisable and 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. During first quarter 2005, fewer options were exercised than were exercised during first quarter 2004.

RESULTS OF OPERATIONS

First quarter selected financial data is as follows:

	Three Months Ended March 31,
(in thousands, except per share amounts)	2005		2004
Income from continuing operations	$	109,968	$	75,312
Income from discontinued operations, net of tax	—		10,234
Net income	$	109,968	$	85,546
Basic earnings per share	$	1.86	$	1.48
Diluted earnings per share	$	1.83	$	1.46

Natural Gas Information

Natural gas revenues increased eight percent during first quarter 2005, compared with first quarter 2004.

	Three Months Ended March 31,
(in thousands)	2005		2004
Natural gas sales	$	146,084	$	134,888

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

	Three Months Ended March 31,
	2005			2004
	Mcfpd	Price/Mcf		Mcfpd	Price/Mcf
United States	214,500	$	6.50	250,052	$	5.50
Equatorial Guinea (1)	43,833	$	0.25	46,424	$	0.25
North Sea	9,283	$	5.82	12,280	$	4.97
Israel	58,657	$	2.78	12,235	$	2.77
Other International (2)	24,534	$	—	29,757	$	0.54
Total (3)	350,807	$	4.97	350,748	$	4.61

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

(2) Other International for first quarter 2005 includes 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. Other International for first quarter 2004 includes Ecuador and Argentina.

(3) Reflects a reduction of $0.01 per Mcf for first quarter 2004 from hedging activities. There was no hedging impact on natural gas prices for first quarter 2005.

Variances in natural gas production were attributable to the following:

• Natural decline rates for properties in the Gulf of Mexico offset by increased production from the Gulf Coast region related to new wells;

• Natural decline rates for properties in the North Sea; and

• Ramp up of natural gas sales in Israel, which began in February 2004.

Crude Oil Information

Crude oil revenues increased 24 percent during first quarter 2005, compared with first quarter 2004.

	Three Months Ended March 31,
(in thousands)	2005		2004
Crude oil sales	$	169,467	$	136,698

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

	Three Months Ended March 31,
	2005			2004
	Bopd	Price/Bbl		Bopd	Price/Bbl
United States	17,927	$	37.82	23,394	$	30.57
Equatorial Guinea	14,129	$	44.03	9,998	$	31.34
North Sea	5,778	$	46.87	7,708	$	33.65
Other International (1)	8,749	$	35.66	7,057	$	30.37
Total (2)	46,583	$	40.42	48,157	$	31.19

(1) Other International includes Argentina and China.

(2) Reflects reductions of $3.29 and $1.14 per Bbl for first quarter 2005 and 2004, respectively, from hedging activities.

Variances in crude oil production were attributable to the following:

• Natural decline rates for properties in the Gulf of Mexico;

• Shut-in of Main Pass 293/305/306 due to Hurricane Ivan damage;

• Natural production declines in the North Sea;

• Ramp-up of the Phase 2A expansion project in the Alba field in Equatorial Guinea; and

• Increase in production from China.

Gathering, Marketing and Processing

Noble Energy markets the majority of its domestic natural gas, as well as certain third-party natural gas, and sells natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power generators and local distribution companies. The Company also markets a portion of its domestic crude oil, as well as certain third-party crude oil. The Company’s gross margin from gathering, marketing and processing (“GMP”) activities was as follows:

	Three Months Ended March 31,
(in thousands)	2005		2004
GMP revenues	$	11,483	$	14,175
GMP expenses	8,237		10,716
Gross margin	$	3,246	$	3,459

GMP gross proceeds for first quarter 2005 have declined primarily due to a decrease in crude oil trading margins. GMP expenses for first quarter 2005 have declined due to the decrease of $2.6 million in transportation expense.

The Company recorded mark-to-market gains (losses) of $(0.7) million and $0.3 million on derivative instruments related to its marketing activities during first quarter 2005 and 2004, respectively.

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 March 31,
(in thousands)	2005		2004
Electricity sales	$	21,591	$	19,119
Electricity generation expense	11,439		13,024
Operating income	$	10,152	$	6,095

Power production (Total MW)	208,771		253,061
Average power price ($ per Kwh)	$	0.103	$	0.076
Natural gas production (Mcfpd)	24,534		29,088
Average natural gas price	$	3.32	$	2.97

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 March 31,
	2005		2004
Income from unconsolidated subsidiaries (in thousands)	$	16,609	$	12,736

Methanol sales volumes (in thousands)	43,076		38,197
Average realized price (per gallon)	$	0.79	$	0.63

Methanol production has continued to increase during 2005 as a result of higher throughput and reduced downtime. Dividends from unconsolidated subsidiaries contributed $17.6 million and $11.3 million to the Company’s net cash provided by operating activities during first quarter 2005 and 2004, respectively.

Costs and Expenses

Production Expenses – Oil and gas operations expense, consisting of lease operating expense and workover expense, increased $3.1 million, or nine percent, for first quarter 2005, as compared with first quarter 2004. The increase in oil and gas operations expense primarily reflects increased workover activity in the Gulf of Mexico, higher condensate production in Equatorial Guinea and a full quarter of operations expense associated with the Mari-B field in Israel.

The unit rate of oil and gas operations expense per barrel of oil equivalent (“BOE”), converting gas to oil on the basis of six Mcf per barrel, was $3.92 for first quarter 2005 as compared with $3.50 for first quarter 2004. The per unit rate increased primarily due to the higher workover activity in the Gulf of Mexico and lower production volumes in the United States.

Production and ad valorem taxes have increased 39 percent quarter-over-quarter due to higher commodity prices.

The table below includes oil and gas operations expense and total production costs from continuing operations for the three months ended March 31:

(in thousands)	Consolidated		United States		Equatorial Guinea		North Sea		Israel(2)		Other Int’l
2005
Lease operating (1)	$	33,837	$	18,432	$	6,478	$	3,062	$	1,891	$	3,974
Workover expense	3,240		3,240		—		—		—		—
Total operations expense	37,077		21,672		6,478		3,062		1,891		3,974
Production and ad valorem taxes	9,220		6,144		—		—		—		3,076
Transportation costs	1,639		—		—		1,497		—		142
Total production costs	$	47,936	$	27,816	$	6,478	$	4,559	$	1,891	$	7,192

2004
Lease operating (1)	$	32,195	$	19,645	$	5,149	$	2,874	$	1,164	$	3,363
Workover expense	1,787		1,787		—		—		—		—
Total operations expense	33,982		21,432		5,149		2,874		1,164		3,363
Production and ad valorem taxes	6,653		5,654		—		—		—		999
Transportation costs	4,271		—		—		2,542		—		1,729
Total production costs	$	44,906	$	27,086	$	5,149	$	5,416	$	1,164	$	6,091

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

(2) Gas sales began in February 2004.

Selected expenses on a per BOE basis were as follows:

	Three Months Ended March 31,
	2005		2004
Lease operating	$	3.58	$	3.32
Workover expense	0.34		0.18
Total operations expense	$	3.92	$	3.50
Production and ad valorem taxes	0.98		0.69
Transportation costs	0.17		0.44
Total production costs	$	5.07	$	4.63

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 $23.7 million for first quarter 2005 as compared with $16.5 million for first quarter 2004. The increase for 2005 was due to a $4.4 million period-over-period increase in dry hole expense and a $2.5 million increase in seismic.

During first quarter 2005, the Company drilled five exploratory wells, three of which were dry holes. Of the two remaining wells, one is successful and one is being evaluated.

Depreciation, Depletion and Amortization – Depreciation, depletion and amortization (“DD&A”) expense was $70.5 million for first quarter 2005 compared with $77.7 million for first quarter 2004. The unit rate of DD&A per BOE decreased seven percent to $7.45 per BOE for first quarter 2005 as compared with $8.01 per BOE for first quarter 2004. The decrease in the unit rates was primarily due to increased low-cost volumes in Equatorial Guinea and Israel.

Selling, General and Administrative Expense – Selling, general and administrative (“SG&A”) expense remained constant at $15.2 million for first quarter 2005, as compared with $15.1 million for first quarter 2004. The per unit rate of SG&A increased three percent to $1.60 per BOE for first quarter 2005 as compared with $1.55 per BOE for first quarter 2004 due to slightly lower overall production volumes.

Interest Expense – Interest expense (net of interest capitalized) decreased $.6 million, or six percent, to $9.4 million for first quarter 2005 as compared with $10.0 million for first quarter 2004. Capitalized interest was $4.9 million for first quarter 2005 compared with $4.1 million for first quarter 2004.

Interest expense (net of interest capitalized) decreased slightly due to a decrease in total debt, offset by an increase in fixed-rate debt, with associated higher rates, as compared to the first quarter of 2004.

Income Tax Provision – Income tax expense associated with continuing operations was $64.6 million and $53.5 million for first quarter 2005 and 2004, respectively. The increase was due primarily to the increase in income from continuing operations, offset by a decrease in the effective tax rate. The Company’s effective tax rate on income from continuing operations was approximately 37 percent for first quarter 2005 and 42 percent for first quarter 2004.

Discontinued Operations

During 2004, the Company completed an asset disposition program that had first been announced in July 2003. The asset disposition program included five domestic property packages. The sales price for the five property packages totaled approximately $130 million before closing adjustments.

The Company’s consolidated financial statements have been reclassified to reflect the operations and assets of the properties 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:

(in thousands)	Three Months Ended March 31, 2004
Oil and gas sales and royalties	$	12,722
Realized gain	5,892
Income before income taxes	15,744

Key Statistics:
Daily Production
Liquids (Bbl)	996
Natural Gas (Mcf)	18,887
Average Realized Price
Liquids ($/Bbl)	$	33.39
Natural Gas ($/Mcf)	$	5.64

There was no discontinued operations activity in the first quarter of 2005.

FUTURE TRENDS

Pending Merger – On December 15, 2004, the Boards of Directors of Noble Energy and Patina approved Noble Energy’s Merger Agreement with Patina. As a result of the proposed merger, Patina will merge into a wholly-owned subsidiary of Noble Energy, and Patina shareholders will receive aggregate consideration comprised of approximately 60 percent Noble Energy common stock and 40 percent cash. Total consideration for the outstanding shares of Patina is fixed at approximately $1.1 billion in cash and approximately 27 million Noble Energy shares, not including options and warrants exchanged in the transaction, and subject to adjustment as provided in the Merger Agreement. Under the terms of the Merger Agreement, Patina shareholders will have the right to elect to receive either cash or Noble Energy common stock, or a combination thereof, in exchange for their shares of Patina common stock, subject to an allocation mechanism if either the cash election or the stock election is oversubscribed. While the per share consideration was initially set in the Merger Agreement at $37.00 in cash or 0.6252 shares of Noble Energy common stock, the per share consideration is subject to adjustment upwards or downwards. This adjustment will reflect 37.5126 percent of the difference between $59.18 and the price of Noble Energy’s shares during a specified period prior to closing. In addition, the per share consideration is adjusted so that each Patina share receives consideration representing equal value regardless of whether it is converted into cash or Noble Energy common

stock. The proposed merger is subject to certain approvals of the shareholders of Noble Energy and Patina and other customary conditions. Special meetings for the respective shareholders of Noble Energy and Patina have been scheduled for May 11, 2005 for this purpose.

Continuing Operations – The Company expects crude oil and natural gas production from continuing operations to increase in 2005 compared to 2004. The increased production is expected primarily from the continued expansion of natural gas markets in Israel, a full year of production from Phase 2A, the Phase 2B expansion of LPG plant in Equatorial Guinea and new deepwater wells in the Gulf of Mexico. The Company’s production profile may be impacted by several factors, including:

• The timing of the production increases from Phase 2B in Equatorial Guinea and deepwater developments in the Gulf of Mexico during 2005;

• Seasonal variations in electricity demand and the timing of infrastructure development in Israel;

• 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.

2005 Budget – The Company set its 2005 capital expenditures budget at approximately $735.0 million. Approximately 30 percent of the 2005 capital budget has been allocated for exploration opportunities and 70 percent has been dedicated to production, development and other projects. Domestic spending is budgeted at $485.0 million (66 percent of the worldwide 2005 capital budget), international expenditures are budgeted at $228.0 million (31 percent) and corporate expenditures are budgeted at $22.0 million (three percent). 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. Excluding possible asset purchases or the previously announced proposed merger with Patina, the Company plans to fund such expenditures primarily from cash flows from operations. 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 periodically enters into crude oil and natural gas commodity hedges as a means to help reduce commodity price volatility. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.

Recently Issued Pronouncements

accordance with SFAS No. 123(R). Unvested equity-classified awards that were granted prior to January 1, 2006 will be accounted for in accordance with SFAS No. 123, except that the amounts will be recognized on the Company’s consolidated statements of operations. The Company is currently evaluating the impact of SFAS No. 123(R) and expects that it will recognize additional compensation expense during first quarter 2006.

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 instruments and may do so in the future as a means of managing its exposure to price changes.

As of March 31, 2005, 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
		Average Price						Average Price
Production		Per MMBTU				Production		Per Bbl
Period	MMBTUpd	Floor		Ceiling		Period	Bopd	Floor		Ceiling
Apr-Dec 2005	75,000	$	5.00	$	7.50	Apr-Dec 2005	20,431	$	31.30	$	43.99
2006	3,699	$	5.00	$	8.00	2006	1,865	$	29.00	$	34.93

As of March 31, 2005, the Company had entered into future fixed price swap 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		Production Period	Bopd	Average Price Per Bbl
May-Dec 2005	130,000	$	6.76	May-Dec 2005	13,100	$	39.62
2006	170,000	$	6.48	2006	16,600	$	40.47
2007	170,000	$	6.03	2007	17,100	$	39.19
2008	170,000	$	5.67	2008	16,500	$	38.23

As of March 31, 2005, the Company had a net unrealized loss of $385.5 million, net of taxes, related to crude oil and natural gas derivative instruments accounted for as cash flow hedges. In the following month, future commodity prices decreased and, as of April 30, 2005, the Company’s net unrealized loss was $288.8 million, net of tax.

In connection with the announcement of the Merger Agreement, in order to reduce the price sensitivity associated with future crude oil and natural gas prices, Noble Energy entered into additional derivative transactions (“hedges”), which are included in the tables above, using its own production that was available to be hedged. The natural gas hedges totaled 130,000 MMBTUpd starting in May 2005 through December 2005 and 170,000 MMBTUpd for 2006 through 2008. The crude oil hedges totaled 13,100 Bopd starting in May 2005 through December 2005 and approximately 16,700 Bopd for 2006 through 2008. These hedges consist of fixed price swaps that average $6.16 per MMBTU for natural gas and $39.34 per barrel of oil. Prior to closing of the proposed merger, Noble Energy may enter into additional derivative transactions using its existing production. The Merger Agreement provides that if Noble Energy terminates the Merger Agreement within three business days of receiving notification that the Patina Board of Directors has made an adverse recommendation change, or resolved to make such a change (in either case for any reason other than a superior proposal), Patina would be required to reimburse Noble Energy for up to $45.0 million of actual losses realized by Noble Energy with respect to certain hedges for the years 2006 through 2008.

Derivative Instruments Held for Trading Purposes – Noble Energy, from time to time, employs derivative instruments in connection with its purchases and sales of production. While most of the purchases are made for an index-based price, 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, the Company 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, the Company believes it had no material market risk exposure from these derivative instruments as of March 31, 2005. As of March 31, 2005, the Company had a net receivable 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 March 31, 2005, the Company had $820 million of debt outstanding of which $650 million was fixed-rate debt. The Company believes that anticipated near term changes in interest rates would not have a material effect on the fair value of the Company’s fixed-rate debt and would not expose the Company to the risk of earnings or cash flow loss.

The remainder of the Company’s debt at March 31, 2005 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, 2005, $170 million of variable-rate debt was outstanding. A 10 percent change in the floating interest rates applicable to the March 31, 2005 balance would result in a change in annual interest expense of approximately $.6 million.

Foreign Currency Risk

The Company does not enter into foreign currency derivatives. The U.S. dollar is considered the functional currency for each of the Company’s international operations. Transactions that are completed in a foreign currency are remeasured 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 expense (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.

Other. In the Company’s exploration operations, losses may occur before any accumulation of crude oil or natural gas is found. If crude oil or natural gas is discovered, no assurance can be given that sufficient reserves will be developed to enable the Company to recover the costs incurred in obtaining the reserves or that reserves will be developed at a sufficient rate to replace reserves currently being produced and sold. The Company’s international operations are also subject to certain political, economic and other uncertainties including, among others, risk of war, terrorist acts and civil disturbances; expropriation or nationalization of assets; renegotiation, modification or nullification of existing contracts; changes in taxation policies; laws and policies of the U.S. affecting foreign investment, taxation, trade and business conduct; foreign exchange restrictions; international monetary fluctuations; and other hazards arising out of foreign governmental sovereignty over areas in which the Company conducts operations.

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 Chris Tong, 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 1. LEGAL PROCEEDINGS

Refer to “Note 12 - Commitments and Contingencies” to the consolidated condensed financial statements.

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 26, 2005 in Houston, Texas.

(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 59,308,957 shares of common stock of the Company outstanding and entitled to vote, 54,598,855 shares were present in person or by proxy, representing approximately 92 percent.

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

Michael A. Cawley	53,619,653	979,202
Edward F. Cox	53,854,685	744,170
Charles D. Davidson	54,148,192	450,663
Kirby L. Hedrick	54,139,167	459,688
Bruce A. Smith	53,889,710	709,145

(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 53,942,014; Against 616,074; Abstaining 40,767)

Proposal III. Approval of 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (For 35,599,676; Against 14,711,947; Abstaining 77,652; Broker Non-Votes 4,209,580)

ITEM 6. EXHIBITS

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

INDEX TO EXHIBITS


Exhibit Number		Exhibit

2.1		Amendment Agreement dated as of May 3, 2005 to the Agreement and Plan of Merger by and among Noble Energy, Inc., Noble Energy Production, Inc. and Patina Oil & Gas Corporation dated as of December 15, 2004 (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Event: May 3, 2005) filed May 4, 2005, and incorporated herein by reference.

10.1		$1.3 billion Five-Year Credit Agreement, dated April 4, 2005, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Wachovia Bank, National Association and The Royal Bank of Scotland PLC, as co-syndication agents, Deutsche Bank Securities Inc. and Citibank, N.A., as co-documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: April 4, 2005) filed April 8, 2005 and incorporated herein by reference).

10.2		Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended through April 25, 2005, filed herewith.

10.3		2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: April 26, 2005) filed April 29, 2005 and incorporated herein by reference).

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).

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)

		NOBLE ENERGY, INC.
		(Registrant)



Date	May 6, 2005	/s/ CHRIS TONG
		CHRIS TONG
		Senior Vice President, Chief Financial Officer and Treasurer