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, 2006

OR

o  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from       to      

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	73-0785597
(State of incorporation)	(I.R.S. employer identification number)
100 Glenborough Drive, Suite 100
Houston, Texas	77067
(Address of principal executive offices)	(Zip Code)

(281) 872-3100

(Registrant’s telephone number, including area code)

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

Yes ý    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o    No ý

Number of shares of common stock outstanding as of April 28, 2006: 177,149,761

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Noble Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands, except share amounts)

	(Unaudited) March 31,			December 31,
	2006			2005
ASSETS
Current Assets:
Cash and cash equivalents	$	135,950		$	110,321
Accounts receivable - trade, net	548,773			566,206
Derivative instruments	33,486			29,258
Materials and supplies inventories	47,335			33,802
Deferred income taxes	242,646			237,045
Prepaid expenses and other	46,742			56,568
Probable insurance claims	127,098			142,311
Total current assets	1,182,030			1,175,511
Property, plant and equipment, at cost:
Oil and gas mineral interests, equipment and facilities (successful efforts method of accounting)	9,104,877			8,411,426
Other	72,123			69,869
	9,177,000			8,481,295
Accumulated depreciation, depletion and amortization	(2,357,807		)	(2,282,379		)
Total property, plant and equipment, net	6,819,193			6,198,916
Equity method investments	404,607			420,362
Other assets	224,363			220,376
Goodwill	929,145			862,868
Total Assets	$	9,559,338		$	8,878,033
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	484,453		$	519,971
Derivative instruments	356,729			445,939
Income taxes	146,555			65,136
Asset retirement obligations	51,198			60,331
Accrued and other current liabilities	134,581			137,428
Interest payable	23,683			11,340
Short-term borrowings	25,000			—
Total current liabilities	1,222,199			1,240,145
Deferred income taxes	1,433,451			1,201,191
Asset retirement obligations	260,115			278,540
Derivative instruments	724,953			757,509
Deferred compensation liability	153,437			141,185
Other deferred credits and noncurrent liabilities	141,407			138,786
Long-term debt	2,140,603			2,030,533
Total Liabilities	6,076,165			5,787,889
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; 250,000,000 shares authorized; 186,071,451 and 184,893,510 shares issued, respectively	620,238			616,311
Capital in excess of par value	1,967,511			1,945,239
Deferred compensation	—			(5,288		)
Accumulated other comprehensive loss	(652,927		)	(783,499		)
Treasury stock, at cost: 8,855,932 and 9,268,932 shares, respectively	(134,667		)	(148,476		)
Retained earnings	1,683,018			1,465,857
Total Shareholders’ Equity	3,483,173			3,090,144
Total Liabilities and Shareholders’ Equity	$	9,559,338		$	8,878,033

The accompanying notes are an integral part of these financial statements

2

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(in thousands, except per share amounts)

(Unaudited)

	Three Months Ended March 31,
	2006			2005
Revenues:
Oil and gas sales and royalties	$	646,252		$	315,244
Gathering, marketing and processing	8,183			11,483
Electricity sales	17,912			21,591
Income from equity method investments	39,650			19,894
Total Revenues	711,997			368,212
Costs and Expenses:
Oil and gas operations	62,602			32,680
Workovers and repairs	19,591			3,240
Production and ad valorem taxes	25,453			9,220
Transportation	5,061			3,668
Oil and gas exploration	32,022			23,657
Gathering, marketing and processing	5,502			8,237
Electricity generation	10,626			11,439
Depreciation, depletion and amortization	124,465			70,279
Selling, general and administrative	35,398			15,168
Accretion of discount on asset retirement obligations	3,318			2,551
Interest, net of capitalized interest	33,168			11,732
Deferred compensation adjustment	9,176			—
Other expense (income), net	(3,738		)	1,859
Total Costs and Expenses	362,644			193,730
Income Before Taxes	349,353			174,482
Income Tax Provision	123,266			64,514
Net Income	$	226,087		$	109,968
Earnings Per Share:
Basic	$	1.28		$	0.93
Diluted	$	1.26		$	0.92
Weighted average number of shares outstanding:
Basic	176,136			118,166
Diluted	180,099			120,278

The accompanying notes are an integral part of these financial statements

3

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2006			2005
Cash Flows from Operating Activities:
Net income	$	226,087		$	109,968
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	124,465			70,279
Depreciation, depletion and amortization - electricity generation	4,151			4,308
Dry hole expense	7,383			8,862
Amortization of unproved leasehold costs	5,491			4,904
Stock based compensation expense	3,154			526
Gain on disposal of assets	—			(1,276		)
Deferred income taxes	55,460			11,147
Accretion of discount on asset retirement obligations	3,318			2,551
Income from equity method investments	(39,650		)	(19,894		)
Dividends received from equity method investees	9,000			17,550
Deferred compensation adjustment	9,176			—
Loss on derivative instruments	30,686			2,643
Other	5,110			5,984
Changes in operating assets and liabilities, net of acquisition:
Decrease in accounts receivable	25,575			20,561
Increase in other current assets	(1,277		)	(23,816		)
Decrease (increase) in probable insurance claims	66,014			(3,515		)
Decrease in accounts payable	(42,843		)	(24,389		)
Increase in other current liabilities	36,209			18,132
Net Cash Provided by Operating Activities	527,509			204,525
Cash Flows From Investing Activities:
Additions to property, plant and equipment	(288,018		)	(131,639		)
U.S. Exploration acquisition, net of cash acquired	(412,257		)	—
Proceeds from sale of property, plant and equipment	—			320
Investments in equity method investees	—			(13,917		)
Distribution from equity method investee	47,023			1,305
Net Cash Used in Investing Activities	(653,252		)	(143,931		)
Cash Flows From Financing Activities:
Exercise of stock options	20,236			9,058
Excess tax benefits from stock-based awards	5,062			—
Cash dividends paid	(8,926		)	(2,950		)
Proceeds from credit facilities	300,000			10,000
Repayment of credit facilities	(110,000		)	(74,931		)
Repayment of term loans	(80,000		)	—
Proceeds from short term borrowings	25,000			—
Net Cash Provided by (Used in) Financing Activities	151,372			(58,823		)
Increase in Cash and Cash Equivalents	25,629			1,771
Cash and Cash Equivalents at Beginning of Period	110,321			179,794
Cash and Cash Equivalents at End of Period	$	135,950		$	181,565

The accompanying notes are an integral part of these financial statements

4

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Shareholders’ Equity

(in thousands)

(Unaudited)

	Common Stock		Capital in Excess of Par Value			Deferred Compensation - Restricted Stock			Accumulated Other Comprehensive Income (Loss)			Treasury Stock at Cost			Retained Earnings			Total Shareholders’ Equity
January 1, 2006	$	616,311	$	1,945,239		$	(5,288	)	$	(783,499	)	$	(148,476	)	$	1,465,857		$	3,090,144
Net income	—		—			—			—			—			226,087			226,087
Adoption of SFAS No. 123(R)	—		(5,288		)	5,288			—			—			—			—
Stock-based compensation	—		3,154			—			—			—			—			3,154
Exercise of stock options	3,660		16,576			—			—			—			—			20,236
Tax benefits related to exercise of stock options	—		5,062			—			—			—			—			5,062
Issuance of restricted stock	267		(267		)	—			—			—			—			—
Cash dividends ($0.05 per share)	—		—			—			—			—			(8,926		)	(8,926		)
Rabbi trust shares sold	—		3,035			—			—			13,809			—			16,844
Unrealized hedging gains	—		—			—			60,527			—			—			60,527
Hedges reclassified to net income	—		—			—			69,879			—			—			69,879
Other	—		—			—			166			—			—			166
March 31, 2006	$	620,238	$	1,967,511		$	—		$	(652,927	)	$	(134,667	)	$	1,683,018		$	3,483,173
January 1, 2005	$	417,152	$	291,458		$	(1,671	)	$	(14,787	)	$	(75,956	)	$	843,792		$	1,459,988
Net income	—		—			—			—			—			109,968			109,968
Exercise of stock options	1,708		7,350			—			—			—			—			9,058
Tax benefits related to exercise of stock options	—		2,750			—			—			—			—			2,750
Issuance of restricted stock	270		2,649			(2,919		)	—			—			—			—
Amortization of restricted stock	—		—			526			—			—			—			526
Cash dividends ($0.025 per share)	—		—			—			—			—			(2,951		)	(2,951		)
Unrealized hedging losses	—		—			—			(387,526		)	—			—			(387,526		)
Hedges reclassified to net income	—		—			—			9,081			—			—			9,081
Other	—		—			—			99			—			—			99
March 31, 2005	$	419,130	$	304,207		$	(4,064	)	$	(393,133	)	$	(75,956	)	$	950,809		$	1,200,993

The accompanying notes are an integral part of these financial statements

5

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

(Unaudited)

	Three Months Ended March 31,
	2006			2005
Net income	$	226,087		$	109,968
Other comprehensive income (loss):
Unrealized gain (loss) on cash flow hedges:
Oil and gas cash flow hedges	93,119			(596,194		)
Less tax provision	(32,592		)	208,668
Less reclassification adjustment for amounts out of AOCL:
Oil and gas cash flow hedges	107,317			13,782
Less tax provision	(37,561		)	(4,824		)
Interest rate lock cash flow hedge	189			189
Less tax provision	(66		)	(66		)
Other	255			152
Less tax provision	(89		)	(53		)
Other comprehensive income (loss)	130,572			(378,346		)
Comprehensive income (loss)	$	356,659		$	(268,378	)

The accompanying notes are an integral part of these financial statements

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Organization and Nature of Operations

We are an independent energy company engaged, directly or through our subsidiaries, in the exploration, development, production and marketing of crude oil and natural gas. We have exploration, exploitation and production operations domestically and internationally. We operate throughout major basins in the United States including Colorado’s Wattenberg field, the Mid-continent region of western Oklahoma and the Texas Panhandle, the San Juan basin in New Mexico, the Gulf Coast and the Gulf of Mexico. In addition, we operate internationally in Equatorial Guinea, the Mediterranean Sea, Ecuador, the North Sea, China, Argentina and Suriname.

Purchase of U.S. Exploration Holdings, Inc. – On March 29, 2006,we purchased the common stock of U.S. Exploration Holdings, Inc. (“U.S. Exploration”), a privately held corporation located in Billings, Montana, for $412 million. U.S. Exploration’s reserves and production are located in the Wattenberg field of Colorado’s Denver-Julesburg (“D-J”) basin. See Note 3 - Acquisitions.

Patina Merger – On May 16, 2005, we completed a merger (the “Patina Merger”) with Patina Oil & Gas Corporation (“Patina”). Patina was an independent energy company engaged in the acquisition, development and exploitation of crude oil and natural gas properties within the continental United States. Patina’s properties and oil and gas reserves are principally located in relatively long-lived fields with established production histories. The properties are primarily concentrated in the Wattenberg field of Colorado’s D-J basin, the Mid-continent region of western Oklahoma and the Texas Panhandle, and the San Juan basin in New Mexico. See Note 3 - Acquisitions.

Note 2 - Basis of Presentation

Presentation – The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements at March 31, 2006 and December 31, 2005 and for the three months ended March 31, 2006 and 2005 contain all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the three-month period ended March 31, 2006 are not necessarily indicative of the results that may be expected for the year ended December 31, 2006. 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 our annual report on Form 10-K for the year ended December 31, 2005. Unless otherwise specified or the context otherwise requires, all references in these notes to “Noble Energy,” “we,” “us” or “our” are to Noble Energy, Inc. and its subsidiaries.

We have accounted for the purchase of U.S. Exploration and the Patina Merger in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations.”  As a result, our consolidated balance sheet at March 31, 2006 includes the assets and liabilities of U.S. Exploration as well as the assets and liabilities of Patina. Our consolidated balance sheet at December 31, 2005 includes only the assets and liabilities of Patina. Our consolidated statements of operations and statements of cash flows include financial results of U. S. Exploration after March 29, 2006 and financial results of Patina from May 16, 2005. See Note 3 - Acquisitions.

Common Stock Split – On August 17, 2005, our Board of Directors approved a two-for-one split of Noble Energy common stock that was effected in the form of a stock dividend. All share and per share data except par value have been adjusted to reflect the effect of the stock split for all periods presented.

7

Accounting for Stock-Based Compensation –Through December 31, 2005, we accounted for our stock-based compensation plans under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and related Interpretations. As of January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment” (“SFAS 123(R)”). SFAS 123(R) revised SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”) and nullified APB 25 and its related implementation guidance. SFAS 123(R) requires companies to recognize in the statement of operations the grant-date fair value of stock options and other stock-based compensation issued to employees and is effective for interim or annual periods beginning January 1, 2006. The fair value is expensed over the requisite service period of the award. In accordance with the modified prospective transition method, prior period amounts have not been restated. See Note 4 – Stock-Based Compensation.

Note 3 - Acquisitions

Purchase of U.S. Exploration – On March 29, 2006, we closed on our agreement to purchase U.S. Exploration for a cash purchase price of $412 million. The total purchase price was allocated preliminarily to the assets acquired and the liabilities assumed based on fair values at the acquisition date as follows:

•$383 million to proved oil and gas properties;

•$119 million to unproved oil and gas properties;

•$67 million to goodwill; and

•$157 million to deferred income taxes.

Certain data necessary to complete the final purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed and final tax returns that provide the underlying tax bases of assets and liabilities. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation will be revised and goodwill will be adjusted, if necessary.

Merger with Patina Oil & Gas Corporation – On May 16, 2005, we completed the Patina Merger. We acquired the common stock of Patina for a total purchase price of approximately $4.9 billion, which was comprised primarily of cash and Noble Energy common stock, plus liabilities assumed. In exchange for Patina’s common stock and stock options held by Patina’s employees, we issued 55.7 million shares of stock valued at $1.7 billion, issued options valued at $104.9 million, paid $1.1 billion in cash to Patina shareholders and assumed debt of $610.5 million and deferred taxes of $1.1 billion. The total purchase price was allocated to the assets acquired and the liabilities assumed based on fair values at the merger date as follows:

•$2.642 billion to proved oil and gas properties;

•$1.068 billion to unproved oil and gas properties;

•$878.3 million allocated to goodwill; and

•$1.1 billion to deferred income taxes.

The amount of goodwill recorded in the Patina Merger has been reduced by a total of $15.7 million ($3.8 million during first quarter 2006) for tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the Merger.

8

Pro Forma Financial Information – The following pro forma condensed combined financial information for the three months ended March 31, 2005 was derived from the historical financial statements of Noble Energy and Patina and gives effect to the merger as if it had occurred on January 1, 2005. The pro forma condensed combined financial information has been included for comparative purposes with first quarter 2006 actual results (as included in our consolidated statements of operations) and is not necessarily indicative of the results that might have occurred had the merger taken place at the dates indicated and is not intended to be a projection of future results.

	Three Months Ended March 31,
	2005
	(in thousands,
	except per share amounts)
Revenues	$	527,505
Net income	158,305
Earnings per share:
Basic	$	0.84
Diluted	0.81

Note 4 - Stock-Based Compensation

As discussed in Note 2 - Basis of Presentation, effective January 1, 2006, we adopted the fair value recognition provisions for stock-based awards granted to employees using the modified prospective application method provided by SFAS 123(R). Accordingly, prior period amounts have not been restated. SFAS 123(R) requires companies to recognize in the statement of operations the grant-date fair value of stock options and other stock-based compensation issued to employees and is effective for interim or annual periods beginning January 1, 2006.

The total stock-based compensation expense recognized for the cost of options and restricted stock during the three months ended March 31, 2006 was $3.2 million of which $2.9 million is included in selling, general and administrative expense and $0.3 million is included in exploration expense. The total stock-based compensation expense recognized for the cost of options and restricted stock during the three months ended March 31, 2005 was $0.5 million, which was included in selling, general and administrative expense. The tax benefit related to stock-based compensation expense was $1.1 million and $0.2 million during the three months ended March 31, 2006 and 2005. We recognize the expense of all stock-based awards on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award).

As a result of adopting SFAS 123(R) on January 1, 2006, our income before income taxes for first quarter 2006 was $2.4 million lower and our net income for first quarter 2006 was $1.6 million lower than if we had continued to account for stock-based compensation under APB 25. Basic and diluted earnings per share for the three months ended March 31, 2006 were  $0.01 and $0.01 lower, respectively, than if we had continued to account for stock-based compensation under APB 25.

Prior to the adoption of SFAS 123(R), we presented tax benefits resulting from the exercise of stock-based compensation awards as cash flows from operating activities within our consolidated statements of cash flows. SFAS 123(R) requires the tax benefits in excess of the tax benefits associated with compensation cost recognized for those awards to be presented as cash flows from financing activities. The $5.1 million excess tax benefit from stock-based awards presented as cash flows from financing activities in first quarter 2006 would have been presented as cash flows from operating activities if we had continued to account for stock-based compensation under APB 25.

9

The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation in all periods presented. The actual and pro forma net income and earnings per share for the three months ended March 31, 2006 below are the same since we have adopted FAS 123(R) as of January 1, 2006. The 2006 amounts are presented for comparison to prior year.

	Three Months Ended March 31,
	2006			2005
	Actual			Pro Forma
	(in thousands, except per share amounts)
Net income, as reported	$	226,087		$	109,968
Add: Stock-based compensation cost recognized, net of related tax effects	2,050			341
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2,050		)	(1,915		)
Pro forma net income	$	226,087		$	108,394
Earnings per share:
Basic - as reported	$	1.28		$	0.93
Basic - pro forma	$	1.28		$	0.92
Diluted - as reported	$	1.26		$	0.92
Diluted - pro forma	$	1.26		$	0.90

Our stock option and restricted stock plans and incentive plan are described below.

1992 Stock Option and Restricted Stock Plan

Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the “1992 Plan”), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the “Committee”) may grant stock options and award restricted stock to officers or other employees of Noble Energy and its subsidiaries. The maximum number of shares of common stock that may be issued under the 1992 Plan is 18,500,000 shares. At March 31, 2006, 8,926,894 shares of common stock were reserved for issuance, including 4,456,900 shares available for future grants and awards, under the 1992 Plan.

1992 Plan Stock Options – Stock options are issued with an exercise price equal to the market price of Noble Energy common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire ten years from the grant date. Option grants generally vest 1/3 per year over a 3-year period.

1992 Plan Restricted Stock – Restricted stock awards made under the 1992 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. Restricted Stock awards generally vest over periods of one to three years.

2004 Long-Term Incentive Plan

Under the Noble Energy, Inc. 2004 Long-Term Incentive Plan (the “2004 LTIP”), the Committee may make incentive awards to key employees of Noble Energy and its subsidiaries. Incentive compensation is based upon the attainment of specific market and performance goals established by the Committee. Awards may be in the form of stock options or restricted stock or in the form of performance units or other incentive measurements providing for the payment of bonuses in cash, or in any combination thereof, as determined by the Committee in its discretion. Stock options granted and restricted stock awarded

10

under the 2004 LTIP are granted and awarded pursuant to the terms of the 1992 Plan. Our cash based performance units and/or cash based bonuses are accounted for under SFAS 5, “Accounting for Contingencies” and are excluded from the provisions of SFAS 123(R).

2005 Stock Plan for Non-Employee Directors

The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (the “2005 Plan”) provides for grants of stock options and awards of restricted stock to non-employee directors of Noble Energy. The 2005 Plan superseded and replaced the 1988 Nonqualified Stock Option Plan for Non-Employee Directors. The total number of shares of common stock that may be issued under the 2005 Plan is 800,000. At March 31, 2006, 800,000 shares of common stock were reserved for issuance, including 715,180 shares available for future grants under the 2005 Plan.

2005 Plan Stock Options – The 2005 Plan provides for the granting to a non-employee director of 11,200 stock options on the date of election to the Board of Directors, annual grants of 2,800 options on February 1 of each year, and discretionary grants by the Board of Directors (up to a maximum of 11,200 options granted in any one year). Options are issued with an exercise price equal to the market price of Noble Energy common stock on the date of grant and may be exercised one year after the date of grant. The options expire ten years from the date of grant.

2005 Plan Restricted Stock – The 2005 Plan also provides for the granting to a non-employee director of 4,800 shares of restricted stock on the date of election to the Board of Directors, annual awards of 1,200 shares of restricted stock on February 1 of each year, and discretionary grants by the Board of Directors (up to a maximum of 4,800 shares of restricted stock awarded in any one year). Restricted stock is restricted for a period of at least one year from the date of grant.

1988 Nonqualified Stock Option Plan

The 1988 Nonqualified Stock Option Plan for Non-Employee Directors of Noble Energy, Inc., as amended, (the “1988 Plan”) provided for the issuance of stock options to non-employee directors of Noble Energy. The options may be exercised one year after grant and expire ten years from the grant date. The 1988 Plan provided for the granting of a fixed number of stock options to each non-employee director annually (10,000 stock options for the first calendar year of service and 5,000 stock options for each year thereafter) on February 1 of each year. The 1988 Plan was terminated in 2005.

Stock Option Awards

The fair value of each option award was estimated on the date of grant using a Black-Scholes-Merton option valuation model that uses the assumptions noted in the following table. The expected term represents the period of time that options granted are expected to be outstanding. The hypothetical midpoint scenario we use considers the actual exercise and post-vesting cancellation history of stock based compensation historical trends to develop expectations for future periods. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the anticipated term of the award. We used the historical volatility of Noble Energy common stock for the 5.5-year period ended prior to the date of grant. The risk-free rate is based on a weighting of five and seven year U.S. Treasury securities as of the year ended prior to the date of grant to arrive at an approximated 5.5-year risk free rate of return which was determined to be 4.72%. The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.

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Black-Scholes-Merton Assumptions	2006 Grants
Expected term (in years)	5.5
Expected volatility	31.79	%
Risk-free rate	4.72	%
Dividend yield	0.76	%

A summary of option activity for the three months ended March 31, 2006 follows:

	Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
					(years)	(in thousands)
Outstanding at December 31, 2005	9,319,642		$	19.21
Granted	747,847		45.92
Exercised	(1,097,731	)	18.43
Forfeited	(16,129	)	37.09
Canceled / expired	—		—
Outstanding at March 31, 2006	8,953,629		$	21.51	4.5	$	199,081
Exercisable at March 31, 2006	7,559,536		$	18.45	3.7	$	191,214

The weighted-average grant-date fair value of options granted during the three months ended March 31, 2006 and 2005 was $16.37 and $11.78, respectively. The total intrinsic value of options exercised during the three months ended March 31, 2006 and 2005 was $27.1 million and $7.9 million, respectively.

As of March 31, 2006, there was $16.3 million of total unrecognized compensation cost related to nonvested stock options granted under the Plans. That cost is expected to be recognized over a weighted-average period of 1.7 years.

Cash received from option exercises under all stock-based payment arrangements for the three months ended March 31, 2006 and 2005 was $20.2 million and $9.1 million, respectively. The actual tax benefit realized for the tax deductions from option exercise under all stock-based payment arrangements totaled $5.1 million and $2.8 million, respectively, for the three months ended March 31, 2006 and 2005.

We issue new shares of common stock to settle option exercises.

Restricted Stock Awards

Grants of service based restricted stock awards are valued at our common stock price at the date of grant. The fair value of market based restricted stock awards is estimated on the date of grant using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three-year period ended prior to the date of grant. The risk-free rate is based on a three-year period from U.S. Treasury securities as of the year ended prior to the date of grant.

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Monte Carlo Assumptions	2006 Grants
Number of simulations	100,000
Expected volatility	28.4	%
Risk-free rate	4.35	%

A summary of restricted stock activity for the three months ended March 31, 2006 follows:

	Subject to Service Conditions	Weighted Average Grant Date Fair Value		Subject to Market Conditions		Weighted Average Grant Date Fair Value
	(shares)			(shares)
Restricted Stock at December 31, 2005	123,246	$	33.79	133,515		$	23.60
Granted	11,039	45.10		70,563		39.51
Vested	—	—		—		—
Forfeited	—	—		(1,392	)	31.24
Restricted Stock at March 31, 2006	134,285	$	34.72	202,686		$	29.09

As of March 31, 2006, there was $7.5 million of total unrecognized compensation cost related to nonvested restricted stock awarded under the Plans. That cost is expected to be recognized over a weighted-average period of 1.5 years.

We issue new shares of common stock to settle restricted stock grants.

Note 5 - Derivative Instruments and Hedging Activities

Cash Flow Hedges – We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such instruments include variable to fixed price swaps and costless collars. Although these derivative instruments expose us to credit risk, we monitor the creditworthiness of our counterparties and management believes that losses from nonperformance are unlikely to be significant. However, we are not able to predict sudden changes in the creditworthiness of our counterparties.

We account for derivative instruments and hedging activities in accordance with SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and have elected to designate our derivative instruments as cash flow hedges. Derivative instruments designated as cash flow hedges are reflected at fair value on our consolidated balance sheets. Changes in fair value, to the extent the hedge is effective, are reported in accumulated other comprehensive loss  (“AOCL”) until the forecasted transaction occurs. Gains and losses from such derivative instruments related to our crude oil and natural gas production and which qualify for hedge accounting treatment are recorded in oil and gas sales and royalties on our consolidated statements of operations upon sale of the associated products. We assess hedge effectiveness 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.

If it becomes probable that the hedging instrument is no longer highly effective, the hedging instrument loses hedge accounting treatment. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in AOCL related to the hedging instrument are also reclassified to earnings. As a result of the impacts of Hurricanes Katrina and Rita on the timing of forecasted production during first quarter 2006, derivative instruments hedging approximately 6,000 barrels per day of crude oil and 40,000 MMBtu per day of natural gas did not qualify for hedge accounting during a portion of first quarter 2006. Accordingly, the changes in fair value of these derivative contracts were

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recognized in our results of operations, causing a mark-to-market gain of $39.2 million ($25.5 million, net of tax) in first quarter 2006. These derivative instruments were re-designated as cash flow hedges in February 2006. In addition, the delay in the timing of our production resulted in a loss of $25.4 million ($16.5 million, net of tax) related to amounts previously recorded in AOCL. Both the gain and the loss are included in other expense (income), net in the statement of operations. No other gains or losses were reclassified from AOCL into earnings as a result of the discontinuance of hedge accounting treatment during first quarter 2006 or 2005.

Derivative instrument activity related to our crude oil and natural gas production was as follows:

	Three Months Ended March 31,
	2006			2005
Natural Gas Collars:
NYMEX -
Hedge MMBtupd	15,000			95,000
Floor price range	$5.00 - $5.00			$5.00 - $5.75
Ceiling price range	$8.00 - $8.00			$7.80 - $9.50
Percent of daily worldwide production	2		%	27	%
CIG (1) -
Hedge MMBtupd	3,444			—
Floor price range	$5.25 - $5.25			—
Ceiling price range	$10.20 - $10.20			—
Percent of daily worldwide production	1		%	—
Crude Oil Collars:
NYMEX -
Hedge Bpd	4,333			15,788
Floor price range	$29.00 - $60.00			$29.00 - $32.00
Ceiling price range	$35.50 - $73.80			$37.65 - $44.80
Percent of daily worldwide production	5		%	34	%
Brent -
Hedge Bpd	—			5,000
Floor price range	—			$37.50 - $37.50
Ceiling price range	—			$50.50 - $50.50
Percent of daily worldwide production	—			11	%
Natural Gas Swaps:
NYMEX -
Hedge MMBtupd	170,000			—
Average price per MMBtu	$	7.34		—
Percent of daily worldwide production	27		%	—
Crude Oil Swaps:
NYMEX -
Hedge Bpd	16,600			—
Average price per Bbl	$	41.17		—
Percent of daily worldwide production	21		%	—
Basis Swaps vs. NYMEX: (2)
CIG -
Hedge MMBtupd	24,111			—
Average differential per MMBtu	$	1.45		—

(1)	Colorado Interstate Gas
(2)	The basis swaps have been combined with NYMEX commodity swaps and designated as cash flow hedges.

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For first quarter 2006 and 2005, oil and gas sales and royalties included losses related to cash flow hedges of $107.3 million and $13.8 million, respectively. Ineffectiveness losses related to cash flow hedges totaled $8.7 million and $2.6 million for first quarter 2006 and 2005, respectively and are included in other expense (income), net.

At March 31, 2006, we had entered into future costless collar transactions related to crude oil and natural gas production as follows:

	Natural Gas					Crude Oil
		Average price per MMBtu					Average price per Bbl
Production Period	MMBtupd	Floor		Ceiling		Bopd	Floor		Ceiling
April - December 2006 (NYMEX)	—	$	—	$	—	2,286	$	43.92	$	52.92
April - December 2006 (CIG)	10,000	5.25		10.20		—	—		—
2007 (NYMEX)	—	—		—		2,700	60.00		74.30
2007 (CIG)	12,000	6.50		9.50		—	—		—
2007 (Brent)	—	—		—		6,748	45.00		70.63
2008 (NYMEX)	—	—		—		3,100	60.00		72.40
2008 (CIG)	14,000	6.75		8.70		—	—		—
2008 (Brent)	—	—		—		4,066	45.00		66.52
2009 (NYMEX)	—	—		—		3,700	60.00		70.00
2009 (CIG)	15,000	6.00		9.90		—	—		—
2009 (Brent)	—	—		—		3,074	45.00		63.04
2010 (NYMEX)	—	—		—		3,500	55.00		73.80
2010 (CIG)	15,000	6.25		8.10		—	—		—

At March 31, 2006, we had entered into future fixed price swap transactions related to crude oil and natural gas production as follows:

	Natural Gas			Crude Oil
Production Period	MMBtupd	Average Price per MMBtu		Bopd	Average price per Bbl
April - December 2006 (NYMEX) (1)	170,000	$	6.20	16,600	$	40.24
2007 (NYMEX)	170,000	6.04		17,100	39.19
2008 (NYMEX)	170,000	5.67		16,500	38.23

(1) Includes derivative instruments of 40,000 MMBtupd of natural gas and 6,000 Bopd of crude oil that did not qualify for hedge accounting treatment at December 31, 2005. These derivative instruments were re-designated as cash flow hedges in February 2006.

At March 31, 2006, we had entered into basis swap (CIG vs. NYMEX) transactions related to natural gas production. These basis swaps have been combined with NYMEX commodity swaps and designated as cash flow hedges. The basis swaps are as follows:

	Natural Gas
Production Period	MMBtupd	Average Differential per MMBtu
April - December 2006 (CIG vs. NYMEX)	70,000	$	1.45

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If commodity prices were to stay the same as they were at March 31, 2006, approximately $172.6 million of deferred losses, net of taxes, related to the fair values of the derivative instruments included in AOCL at March 31, 2006 would be reversed during the next twelve months as the forecasted transactions 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 2010.

The fair value of derivative instruments included in the consolidated balance sheets is as follows:

	March 31, 2006			December 31, 2005
	(in thousands)
Derivative instruments (current asset)	$	33,486		$	29,258
Derivative instruments (long-term asset)	$	49,135		$	17,259
Derivative instruments (current liability)	$	(356,729	)	$	(445,939	)
Derivative instruments (long-term liability)	$	(724,953	)	$	(757,509	)

Other Derivative Instruments – We also use various derivative instruments in connection with our purchases and sales of third-party production to lock in profits or limit exposure to natural gas price risk. Most of the purchases are made on an index basis. However, purchasers in the markets in which we sell often require fixed or NYMEX-related pricing. We 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.

We record 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. Net gains (losses) related to these derivative instruments  were de minimis for first quarter 2006 and 2005.

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Note 6 - Employee Benefit Plans

Pension and Welfare Benefit Plans –We have a noncontributory, tax-qualified defined benefit pension plan covering certain domestic employees. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the pension plan because of the compensation and benefit limitations imposed on the pension plan by federal tax laws. We sponsor other plans for the benefit of our employees and retirees, which include health care and life insurance benefits.

Former Patina employees began participation in the defined benefit pension plan and the restoration plan on January 1, 2006, with vesting service from their original Patina hire date and credited service for benefit accruals starting January 1, 2006. Additionally, all former Patina employees were covered under the health care and life insurance plans effective January 1, 2006. Net periodic benefit cost related to pension and other postretirement benefit plans was as follows.

	Retirement & Restoration Plan Benefits						Medical & Life Plan Benefits
	2006			2005			2006			2005
	(in thousands)
Three Months Ended March 31:
Service cost	$	3,305		$	1,514		$	744		$	184
Interest cost	2,272			1,666			369			282
Expected return on plan assets	(1,963		)	(1,799		)	—			—
Transition obligation recognition	60			(54		)	—			60
Amortization of prior service cost	93			101			(59		)	(13		)
Recognized net actuarial loss	720			200			331			56
Net periodic benefit cost	$	4,487		$	1,628		$	1,385		$	569

Cash contributions of $2.2 million were made to the pension plan during April 2006.

Note 7 - Effect of Gulf Coast Hurricanes

Hurricane Ivan in 2004 and Hurricane Katrina in 2005 caused substantial damage to our Main Pass assets. As of March 31, 2006, based upon work completed, we have submitted $104 million (cumulative) in claims related to Hurricane Ivan damage, none of which has been disputed, and received $104 million (cumulative) in reimbursements. We have submitted $9 million (cumulative) in claims related to Hurricane Katrina damage, none of which has been disputed, and received $7.2 million (cumulative) in reimbursements. We expect to continue to incur costs, submit claims and receive reimbursements in the normal course of business in 2006 and beyond. During 2005, we were notified by our insurance carrier that its maximum exposure limit for losses incurred during Hurricane Katrina had been reached and that, consequently, our final insurance recovery will be limited. We have recorded probable insurance claims of $79.5 million, the estimated final recovery for losses sustained from Hurricane Katrina. Total Hurricane Katrina costs for clean-up and redevelopment are currently estimated at $170 million. There have been no significant changes in estimates for costs and insurance recoveries from 2005 year-end.

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Assets (liabilities) related to the hurricane insurance recoveries and included in our consolidated balance sheets consist of the following:

	March 31, 2006			December 31, 2005
	(in thousands)
Probable insurance claims - current	$	127,098		$	142,311
Other assets (long-term portion of probable insurance claims)	62,000			112,800
Total Ivan and Katrina probable insurance claims	$	189,098		$	255,111
Asset retirement obligations - current	$	(36,793	)	$	(42,016	)
Asset retirement obligations - long-term	(103,000		)	(121,800		)
Total asset retirement obligations related to Main Pass assets	$	(139,793	)	$	(163,816	)

Note 8 - Asset Retirement Obligations

Asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows:

	Three Months Ended March 31, 2006
	(in thousands)
Asset retirement obligations, beginning of period	$	338,871
Liabilities incurred in current period	1,838
Liabilities settled in current period	(33,898		)
Revisions	1,184
Accretion expense	3,318
Asset retirement obligations, end of period	$	311,313
Current portion	$	51,198
Noncurrent portion	260,115

The ending aggregate carrying amount includes $139.8 million, which we expect to be reimbursed by insurance, related to damage to the Main Pass assets caused by Hurricanes Ivan and Katrina in the Gulf of Mexico. Liabilities settled during the period were mainly related to clean up of hurricane damage at Main Pass.

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Note 9 – Equity Method Investments

We have the following investments accounted for using the equity method:

•45% interest in Atlantic Methanol Production Company, LLC (“AMPCO, LLC”) which owns and operates a methanol production facility and related facilities in Equatorial Guinea;

•50% interests in AMPCO Marketing, LLC and AMPCO Services, LLC, which provide technical and consulting services; and

•28% interest in Alba Plant, LLC which owns and operates an LPG processing plant.

Dividends and distributions received from equity method investees were $56 million and $18.9 million for the three months ended March 31, 2006 and 2005, respectively. Our investments in equity method investees are presented below:

	March 31, 2006		December 31, 2005
	(in thousands)
Equity method investments:
Atlantic Methanol Production Company, LLC	$	216,498	$	214,226
Alba Plant, LLC	176,419		195,109
AMPCO Marketing, LLC	9,668		9,014
AMPCO Services, LLC	2,022		2,013
Total equity method investments	$	404,607	$	420,362

Summarized, 100% combined financial statement information for our equity method investees is presented in the table below:

Balance Sheet Information

	March 31, 2006			December 31, 2005
	(in thousands)
Current assets	$	287,471		$	274,484
Noncurrent assets	858,466			877,402
Current liabilities	(199,189		)	(119,912		)
Noncurrent liabilities	(315,093		)	(450,156		)

Statements of Operations Information

	Three Months Ended March 31,
	2006		2005
	(in thousands)
Operating revenues	$	180,597	$	84,337
Gross margin	139,705		55,051
Net income	115,278		49,582

Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investments and is not included in our income tax provision in the consolidated statements of operations.

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Note 10 - 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 and restricted stock. The following table summarizes the calculation of basic and diluted EPS:

	Three Months Ended March 31,
	2006			2005
	Income		Shares	Income		Shares
	(in thousands, except per share amounts)
Net income available to common shareholders	$	226,087	176,136	$	109,968	118,166
Basic EPS	$	1.28		$	0.93
Net income available to common shareholders	$	226,087	176,136	$	109,968	118,166
Effect of dilutive stock options and restricted stock awards			3,963			2,112
Adjusted net income and shares	$	226,087	180,099	$	109,968	120,278
Diluted EPS	$	1.26		$	0.92

Stock-based awards (options and restricted stock) that are antidilutive are excluded from the calculation of diluted EPS. A total of 607,253 weighted average awards were antidilutive and were excluded from the diluted EPS calculation above for the three months ended March 31, 2006. The weighted average exercise price of options excluded from the diluted EPS calculation was $41.20. There were no antidilutive awards for the first quarter 2005.

A total of 2,041,410 weighted average shares of Noble Energy common stock held by a rabbi trust and accounted for as treasury stock were excluded from the March 31, 2006 EPS calculation above as they were antidilutive. These shares were acquired in the Patina Merger on May 16, 2005 and therefore had no effect on the March 31, 2005 EPS calculation.

Note 11 - Income Taxes

The income tax provision consists of the following:

	Three Months Ended March 31,
	2006		2005
	(in thousands)
Current	$	67,806	$	53,367
Deferred	55,460		11,147
Total income tax provision	$	123,266	$	64,514

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.

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At December 31, 2005, we had recorded a deferred tax asset of $54.9 million for the future foreign tax credits associated with deferred tax liabilities recorded by our foreign branch operations. The valuation allowance with respect to that asset was increased from $41.4 million to $50.9 million during the three months ended March 31, 2006.

Note 12 - Geographical Data

We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration and production:  United States; Equatorial Guinea; North Sea; Israel; and Other International, Corporate and Marketing. Other International includes operations in Argentina, China, Ecuador and Suriname. The following data was prepared on the same basis as our consolidated financial statements. The information excludes the effects of income taxes.

	Consolidated		United States		Equatorial Guinea		North Sea		Israel		Other Int’l, Corporate & Marketing
	(in thousands)
Three Months Ended March 31, 2006:
Revenues from third parties	$	672,347	$	278,813	$	124,039	$	36,287	$	19,759	$	213,449
Intersegment revenue	—		152,043		—		—		—		(152,043		)
Income from equity method investments	39,650		—		39,650		—		—		—
Total Revenues	$	711,997	$	430,856	$	163,689	$	36,287	$	19,759	$	61,406
DD&A	$	124,465	104,692		6,115		1,874		3,199		8,585
Accretion of discount on asset retirement obligations	$	3,318	2,836		26		291		106		59
Income before taxes	$	349,353	187,539		147,892		25,663		14,728		(26,469		)
Three Months Ended March 31, 2005:
Revenues from third parties	$	348,318	$	98,239	$	54,647	$	29,232	$	14,676	$	151,524
Intersegment revenue	—		90,369		—		—		—		(90,369		)
Income from equity method investments	19,894		—		19,894		—		—		—
Total Revenues	$	368,212	$	188,608	$	74,541	$	29,232	$	14,676	$	61,155
DD&A	$	70,279	51,832		5,146		2,872		2,560		7,869
Accretion of discount on asset retirement obligations	$	2,551	2,174		9		279		55		34
Income before taxes	$	174,482	80,667		62,423		19,651		10,494		1,247
Total assets at March 31, 2006  (1)	$	9,559,338	7,298,320		870,399		174,477		251,036		965,106
Total assets at December 31, 2005  (2)	$	8,878,033	6,577,853		877,409		146,311		266,312		1,010,148

(1) The domestic reporting unit includes goodwill of $862.6 million related to the Patina merger and $66.5 million related to the acquisition of U.S. Exploration. (See Note 3 – Acquisitions)

(2) The domestic reporting unit includes goodwill of $862.9 million related to the Patina merger.

Note 13 - Commitments and Contingencies

Legal Proceedings – The ruling by the Colorado Supreme Court in Rogers v. Westerman Farm Co. in July 2001 resulted in uncertainty regarding the deductibility of certain post-production costs from payments to be made to royalty interest owners.

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In January 2003, Patina was named as a defendant in a lawsuit, which plaintiff sought to certify as a class action, based upon the Rogers ruling alleging that Patina had improperly deducted certain costs in connection with its calculation of royalty payments relating to its Wattenberg field operations (Jack Holman, et al v. Patina Oil & Gas Corporation; Case No. 03-CV-09; District Court, Weld County, Colorado). In May 2004, the plaintiff filed an amended complaint narrowing the class of potential plaintiffs, and thereafter filed a motion seeking to certify the narrowed class as described in the amended complaint. Patina filed an answer to the amended complaint. A motion seeking class certification was heard on September 22, 2005 and granted on October 13, 2005. The Colorado Supreme Court denied our petition for review on November 23, 2005.

The Illinois Environmental Protection Agency (IEPA) issued a notice of violation to Equinox Oil Company on September 25, 2001 alleging violation of air emission and permitting regulations for a facility known as the Zif Gas Plant located near Clay City, Illinois. Elysium Energy, LLC acquired Equinox, and Elysium subsequently was acquired by Patina. The facility is a small amine processing unit used to treat and remove hydrogen sulfide from natural gas prior to transportation. The notice of violation alleges violation of permit requirements under the Clean Air Act dating back to 1986 as well as excessive hydrogen sulfide emissions at the plant. We are cooperatively working with the IEPA staff to address this matter. It is within the discretion of the IEPA to assess a fine for violating emission and permit regulations. We have not been assessed a fine or other penalty at this time.

We are involved in various legal proceedings, including the foregoing matters, in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending the company vigorously in all such matters and we do not believe that the ultimate disposition of such proceedings will have a material adverse effect on our financial position, results of operations or cash flows.

Note 14 - Capitalized Exploratory Well Costs

Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period.

	Three Months Ended March 31, 2006
	(in thousands)
Capitalized exploratory well costs, beginning of period	$	35,228
Additions to capitalized exploratory well costs pending determination of proved reserves	25,755
Reclassified to property, plant and equipment based on determination of proved reserves	(358		)
Capitalized exploratory well costs charged to expense	(172		)
Capitalized exploratory well costs, end of period	$	60,453

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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:

	March 31, 2006		December 31, 2005
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	60,453	$	35,228
Capitalized exploratory well costs that have been capitalized for a period greater than one year	—		—
Balance at end of period	$	60,453	$	35,228
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	none		none

Note 15 - Recently Issued Pronouncements

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). SFAS 155 permits an entity to measure at fair value any financial instrument that contains an embedded derivative that otherwise would require bifurcation. This Statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We are currently evaluating the provisions of SFAS 155 and believe that adoption will not have a material effect on our financial position, results of operations or cash flows.

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

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash flow through the development of a high quality portfolio of producing assets that is balanced between domestic and international projects. Our merger with Patina and our purchase of U.S. Exploration have allowed us to achieve a strategic objective of enhancing our United States asset portfolio and have resulted in a company with assets and capabilities that include growing U.S. basins, coupled with a significant portfolio of international properties. We are now a larger, more diversified company with greater opportunities for both domestic and international growth through high upside exploration drilling as well as lower risk exploitation projects.

First quarter 2006 financial highlights included the following:

•net income of $226.1 million, more than double that of first quarter 2005;

•diluted earnings per share of $1.26, a 37% increase over first quarter 2005; and

•cash flows provided by operating activities of $527.5 million, more than 2 1/2 times that of first quarter 2005.

First quarter 2006 significant operational highlights included the following:

•purchase of U.S. Exploration;

•full quarter of Patina operations whereas there was no benefit from Patina in first quarter 2005 as the merger had not yet occurred;

•first production from the Ticonderoga deepwater Gulf of Mexico development on February 16, 2006;

•apparent high bids on 8 lease blocks at the Central Gulf of Mexico Outer Continental Shelf Sale 198;

•Gulf of Mexico deepwater discovery at Redrock prospect (Mississippi Canyon Block 204, 50% working interest);

•full quarter of production from the Phase 2B liquids expansion project in Equatorial Guinea;

•a 77% increase in overall daily sales volumes from first quarter 2005, including a 113% domestic increase and a 40% international increase; and

•increases of 22% in the average realized crude oil price and 17% in the average realized natural gas price over first quarter 2005.

Purchase of U.S. Exploration – On March 29, 2006,we purchased the common stock of U.S. Exploration, a privately held corporation located in Billings, Montana, for $412 million. U.S. Exploration’s reserves and production are located in the Wattenberg field of Colorado’s D-J basin. The following consolidated operating and cash flow information includes financial results of U.S. Exploration after March 29, 2006.

Merger with Patina Oil & Gas Corporation – On May 16, 2005, we acquired the common stock of Patina for a total purchase price of approximately $4.9 billion. Patina was an independent energy company engaged in the acquisition, development and exploitation of crude oil and natural gas properties within the continental United States. Patina’s properties and oil and gas reserves are principally located in relatively long-lived fields with established production histories. The properties are primarily concentrated in the Wattenberg field of Colorado’s D-J Basin, the Mid-continent region of western Oklahoma and the Texas Panhandle, and the San Juan Basin in New Mexico. The following consolidated operating and cash flow information includes financial results of Patina from May 16, 2005.

Adoption of SFAS 123(R) – We adopted SFAS 123(R) as of January 1, 2006. As a result, we recognized compensation expense of $3.2 million related to stock-based awards made in 2006 and the unvested portions of awards made in prior years. As a result of this change in accounting method, our net income was reduced by $2.4 million, or $0.01 per diluted share. In addition, $5.1 million of excess tax benefits related to option exercises were included in cash flows from financing activities

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rather than cash flows from operating activities in first quarter 2006. In first quarter 2005, excess tax benefits of $2.8 million were included in cash flows from operating activities.

OUTLOOK

We expect crude oil and natural gas production to increase in 2006 compared to 2005. The expected year-over-year increase in production is impacted by several factors including:

•a full year of production including Patina assets;

•nine months of production from U.S. Exploration assets;

•the contribution of the Swordfish deepwater Gulf of Mexico development, which commenced production fourth quarter 2005;

•the contribution of the Ticonderoga deepwater Gulf of Mexico development, which commenced production February 16, 2006;

•the expected start-up of production from the Lorien deepwater Gulf of Mexico development, which is expected to commence second quarter 2006 ; and

•a full year of production from the Phase 2B liquids expansion project in Equatorial Guinea.

Factors impacting our production profile include:

•the timing and amount of production from Ticonderoga and Lorien;

•seasonal variations in rainfall in Ecuador that affect our natural gas-to-power project;

•potential weather-related shut-ins in the Gulf of Mexico and Gulf Coast areas; and

•downtime associated with methanol plant maintenance or turnaround.

2006 Capital Expenditures – We currently expect 2006 capital expenditures to total $1.4 billion, excluding the $412 million acquisition of U.S. Exploration. Approximately 21% of 2006 capital expenditures will be spent for exploration opportunities and 79% will be spent for production, development and other projects. On a geographic basis, approximately 70% of the capital expenditures will be domestic spending, 27% will be international spending and 3% will be corporate spending. Expected 2006 capital expenditures do not include the impact of possible asset purchases. We expect that our 2006 capital expenditures will be funded primarily from cash flows from operations. We will evaluate the level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations and property acquisitions.

We believe that we are well positioned with our 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. We periodically enter into crude oil and natural gas commodity hedges as a means to help reduce commodity price volatility. We cannot predict the extent to which revenues will be affected by inflation, government regulation or changing prices.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our 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 cash contributions to the pension and postretirement benefit plans. Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under credit facilities. Occasional sales of non-strategic crude oil and natural gas properties may also generate funds.

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Cash Flows

Operating Activities – For first quarter 2006, we reported net cash provided by operating activities of $527.5 million as compared with $204.5 million for first quarter 2005. The increase was due to higher sales volumes, primarily due to the inclusion of Patina properties in first quarter 2006 results, and higher commodity prices. We received $62.2 million of insurance reimbursements during first quarter 2006.

Investing Activities – Net cash used in investing activities for first quarter 2006 totaled $653.3 million, as compared with $143.9 million for first quarter 2005. The 2006 investing activities included $412 million for the purchase of U.S. Exploration and $288.0 million of expenditures for the exploration and development of crude oil and natural gas properties. The 2005 investing activities included $131.6 million of expenditures for exploration and development. We also made an investment of $13.9 million in Alba Plant, LLC during first quarter 2005.

Financing Activities – Net cash provided by (used in) financing activities totaled $151.4 million and ($58.8) million for first quarter 2006 and 2005, respectively. Financing activities for first quarter 2006 consisted primarily of $135 million net proceeds from short-term and long-term borrowings. Other financing activities included payment of cash dividends on Noble Energy common stock of $8.9 million, proceeds from the exercise of stock options of $20.2 million, and $5.1 million for tax benefits related to the exercise of employee stock options. Financing activities for first quarter 2005 consisted primarily of $64.9 million net repayments of long-term borrowings. Other financing activities included payment of cash dividends on our common stock of $3.0 million, and proceeds from exercise of stock options of $9.1 million.

Acquisition, Exploration and Development-Related Expenditures

Exploration and development-related expenditure information is as follows:

	Three Months Ended March 31,
	2006		2005
	(in thousands)
Exploration and Development-Related Expenditures:
Exploratory drilling and completion	$	16,356	$	7,487
Dry hole	7,383		8,862
Lease acquisition costs	16,614		10,130
Seismic	12,947		3,784
Total exploration expenditures	53,300		30,263
Development drilling and completion	215,917		94,316
Corporate and other	6,726		6,739
Total exploration and development-related expenditures from consolidated operations	$	275,943	$	131,318
Capital contributions to equity method investees	—		13,917

As of March 29, 2006, we allocated preliminary fair values of $383 million to proved oil and gas properties and $119 million to unproved oil and gas properties acquired in the purchase of U.S. Exploration.

Financing Activities

Long-Term Debt – Our long-term debt totaled $2.141 billion (net of unamortized discount) at March 31, 2006. Maturities range from 2009 to 2097. Our ratio of debt-to-book capital (defined as total debt divided by the sum of total debt plus equity) was 38% at March 31, 2006 as compared with 40% at December 31, 2005.

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Our principal source of liquidity is a $2.1 billion unsecured five-year credit facility (the “Credit Facility”) due December 2010. The Credit Facility is available to refinance existing indebtedness and for general corporate purposes. The Credit Facility is with certain commercial lending institutions and bears interest based upon a Eurodollar rate plus a range of 20.0 basis points to 95.0 basis points depending upon our credit rating and utilization of the Credit Facility. The Credit Facility has facility fees that range from 7.5 basis points to 17.5 basis points depending upon our credit rating. At March 31, 2006, $1.470 billion in borrowings were outstanding under the Credit Facility. The interest rate applicable to the Credit Facility at March 31, 2006 was 5.5%.

The Credit Facility contains customary representations and warranties and affirmative and negative covenants, including, but not limited to, the following financial covenants:

(a)the ratio of Earnings Before Interest, Taxes, Depreciation and Exploration Expense to interest expense for any consecutive period of four fiscal quarters ending on the last day of a fiscal quarter may not be less than 4.0 to 1.0; and

(b)the total debt to capitalization ratio, expressed as a percentage, may not exceed 60% at any time.

A violation of these covenants will result in a default under the Credit Facility, which could permit the participating banks to restrict our ability to access the Credit Facility and require the immediate repayment of any outstanding advances under the Credit Facility. At March 31, 2006, the ratios were 17.9 to 1.0 and 34.4%. The total debt to capitalization ratio for this purpose is calculated as our total debt divided by the sum of debt plus equity, with increases or decreases thereto as provided by the Credit Facility.

Short-Term Borrowings – Our credit agreement is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. At March 31, 2006, we had $25 million of short-term borrowings outstanding under uncommitted lines with interest payable at 5.29%.

Debt Repayments – During first quarter 2006, we prepaid $80 million of term loans due January 2009.

Dividends – We paid a quarterly cash dividend of 5.0 cents per share of common stock during first quarter 2006. We paid a quarterly cash dividend of 2.5 cents (as adjusted for our two-for-one stock split, effected in the form of a stock dividend, in third quarter 2005) per share of common stock during first quarter 2005. On April 24, 2006, our Board of Directors declared a quarterly cash dividend of 7.5 cents per common share, payable May 22, 2006, to shareholders of record on May 8, 2006. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

Exercise of Stock Options – We received $20.2 million from the exercise of stock options during first quarter 2006, as compared to $9.1 million during first quarter 2005.

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RESULTS OF OPERATIONS

Natural Gas Information

Natural gas revenues more than doubled first quarter 2006 over first quarter 2005. The increase was due to higher realized natural gas prices and higher sales volumes.

	Three Months Ended March 31,
	2006		2005
	(in thousands)
Natural gas sales	$	319,177	$	146,860

Average daily natural gas sales volumes and prices were as follows:

	Three Months Ended March 31,
	2006			2005
	Mcfpd	$/Mcf		Mcfpd	$/Mcf
United States (1)	462,547	$	6.96	214,500	$	6.54
Equatorial Guinea (2)	54,613	0.35		43,833	0.25
North Sea	8,485	10.62		9,283	5.82
Israel	82,556	2.66		58,657	2.78
Ecuador (3)	26,321	—		24,534	—
Other International	415	1.09		—	—
Total	634,937	$	5.83	350,807	$	5.00

(1)	Reflects reductions of $1.23 per Mcf in 2006 and $0.01 per Mcf in 2005 from hedging activities.
(2)	Natural gas in Equatorial Guinea is under contract for $0.25 per MMBtu through 2026 to a methanol plant and year-to-year to an LPG plant. Each of these plants is owned by an affiliated entity accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in the table below under crude oil information. Beginning in 2006, the price on an Mcf basis has been adjusted to reflect the Btu content.
(3)	The natural gas-to-power project in Ecuador is 100% owned by a subsidiary of Noble Energy and intercompany natural gas sales are eliminated for accounting purposes. Electricity sales of $17.9 million and $21.6 million are included in total revenues for 2006 and 2005, respectively.

Factors contributing to the change in natural gas sales volumes included:

•additional domestic production from Patina properties which were acquired second quarter 2005;

•increases in deepwater Gulf of Mexico production at Swordfish and Ticonderoga;

•a full quarter of production from the Phase 2B liquids expansion project in Equatorial Guinea; and

•increased demand from Israel Electric Corporation Limited and first full quarter of sales to the Bazan Oil Refinery in Israel.

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Crude Oil Information

Crude oil revenues increased 94% first quarter 2006 over first quarter 2005. The increase was due to higher realized crude oil prices and higher sales volumes.

	Three Months Ended March 31,
	2006		2005
	(in thousands)
Crude oil sales	$	327,075	$	168,384

Average daily crude oil sales volumes and prices were as follows:

	Three Months Ended March 31,
	2006			2005
	Bopd	$/Bbl		Bopd	$/Bbl
United States (1)	37,205	$	42.20	17,927	$	38.60
Equatorial Guinea (2)	23,246	58.46		13,332	44.72
North Sea	4,255	73.59		5,778	46.87
Other International (3)	7,800	50.24		8,749	35.66
Total Consolidated Operations	72,506	50.12		45,786	40.86
Equity Investee  (4)	8,124	45.07		797	32.57
Total	80,630	$	49.61	46,583	$	40.72

(1)Reflects reductions of $16.76 per Bbl in 2006 and $8.31 per Bbl in 2005 from hedging activities.

(2)Reflects reductions of $0.31 per Bbl in 2005 from hedging activities.

(3)Other International includes Argentina and China.

(4)Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. LPG volumes were 7,054 Bopd and 642 Bopd for 2006 and 2005, respectively.

Factors contributing to the change in crude oil sales volumes included:

•additional domestic production from Patina properties which were acquired second quarter 2005;

•increases in deepwater Gulf of Mexico production at Swordfish and Ticonderoga; and

•a full quarter of production from the Phase 2B liquids expansion project in Equatorial Guinea.

Effect of Hedging Activities

We hedge varying portions of anticipated future crude oil and natural gas production to reduce the exposure to commodity price fluctuations. Revenues from oil and gas sales and royalties include the results of crude oil and natural gas cash flow hedging activities. Hedging activities reduced revenues by $107.3 million ($69.7 million, net of tax) for first quarter 2006 and $13.8 million ($9.0 million, net of tax) for first quarter 2005.

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Gathering, Marketing and Processing

We market a portion of our domestic natural gas production, as well as certain third-party natural gas, through Noble Energy Marketing, Inc. (“NEMI”), a wholly-owned subsidiary. Through NEMI, we sell natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power generators and local distribution companies. We also market certain third-party crude oil through NEMI. Our gross margin from gathering, marketing and processing (“GMP”) activities was as follows:

	Three Months Ended March 31,
	2006		2005
	(in thousands)
GMP revenues	$	8,183	$	11,483
GMP expenses	5,502		8,237
Gross margin	$	2,681	$	3,246

GMP activity was reduced in first quarter 2006 due to the sale of certain gas sales and transportation contractual assets in 2005.

Electricity Sales - Ecuador Integrated Power Project

Through our subsidiaries, EDC Ecuador Ltd. and MachalaPower Cia. Ltda., we have a 100% 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. Operating data is as follows:

	Three Months Ended March 31,
	2006		2005
Operating income (in thousands)	$	7,286	$	10,152
Power production (MW)	229,703		208,771
Average power price ($/Kwh)	$	0.078	$	0.103

The reductions in average power price and operating income are due to changes in the regulatory environment in Ecuador as it relates to electricity pricing. The volume of electric power produced in Ecuador is related to thermal electricity demand which fluctuates with the availability of local hydroelectric power. We experience variable demand dependant upon rainfall which affects hydroelectric power production.

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Equity Method Investees

Our share of operations of equity method investees was as follows:

	Three Months Ended March 31,
	2006		2005
Net income (in thousands):
AMPCO, LLC and Affiliates	$	12,547	$	16,609
Alba Plant, LLC	27,103		3,285
Distributions/Dividends (in thousands):
AMPCO, LLC	9,750		17,550
Alba Plant, LLC	46,273		—
Sales volumes:
Methanol (gallons in thousands)	34,109		43,076
Condensate (Bopd)	1,070		155
LPG (Bopd)	7,054		642
Average realized prices:
Methanol (per gallon)	$	0.82	$	0.79
Condensate (per Bbl)	60.99		44.75
LPG (per Bbl)	42.66		29.63

Dividends of $9.0 million and $17.5 million received from AMPCO, LLC in first quarter 2006 and 2005, respectively, are included in cash flows from operating activities in our consolidated statements of cash flows. Distributions of $0.75 million received from AMPCO, LLC and $46.3 million received from Alba Plant, LLC in first quarter 2006 are included in cash flows from investing activities in our consolidated statements of cash flows.

First quarter 2006 net income from AMPCO, LLC declined relative to the same period last year due to lower methanol sales as inventory was built up in anticipation of a 46-day plant turnaround and expansion scheduled to begin during the first week of May 2006 and due to the timing of methanol deliveries to international customers. The increases in net income for Alba Plant, LLC and in condensate and LPG sales volumes reflect the completion and ramp up to full production of the Phase 2B liquids expansion project at the Alba field.

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Costs and Expenses

Production Costs – Total production costs were as follows:

	Consolidated		United States		Equatorial Guinea		North Sea		Israel		Other Int’l / Corporate
	(in thousands)
Three Months Ended March 31, 2006:
Lease operating	$	62,602	$	46,198	$	7,547	$	2,333	$	2,123	$	4,401
Workover and repair expense	19,591		19,522		—		—		—		69
Production and ad valorem taxes	25,453		22,077		—		—		—		3,376
Transportation expense	5,061		3,375		—		1,493		—		193
Total production costs	$	112,707	$	91,172	$	7,547	$	3,826	$	2,123	$	8,039
Three Months Ended March 31, 2005:
Lease operating	$	32,680	$	18,432	$	5,321	$	3,062	$	1,891	$	3,974
Workover and repair expense	3,240		3,240		—		—		—		—
Production and ad valorem taxes	9,220		6,144		—		—		—		3,076
Transportation expense	3,668		2,029		—		1,497		—		142
Total production costs	$	48,808	$	29,845	$	5,321	$	4,559	$	1,891	$	7,192

Selected expenses on a per barrel of oil equivalent (“BOE”) basis were as follows:

	Three Months Ended March 31,
	2006		2005
Lease operating	$	3.90	$	3.48
Workover and repair expense	1.22		0.35
Production and ad valorem taxes	1.59		0.98
Transportation expense	0.32		0.39
Total production costs	$	7.03	$	5.20

Lease operating expense increased $29.9 million for first quarter 2006, as compared with first quarter 2005. The increase reflects expenses associated with production from Patina properties, higher production in Equatorial Guinea and Israel, and rising third-party costs. Workover and repair expense includes $14.8 million of hurricane-related repair expense in 2006.Production and ad valorem tax expense increased $16.2 million first quarter 2006 over first quarter 2005 due to higher production, higher commodity prices and to the addition of Patina, which has proportionately more production subject to such taxes.

The unit rate of oil and gas operations expense per BOE, converting gas to oil on the basis of six Mcf per barrel, was $7.03 for first quarter 2006 as compared with $5.20 for first quarter 2005. The increase is due to rising third-party costs, hurricane-related repair expense and increased production taxes due to a larger proportion of production subject to such taxes.

Oil and Gas Exploration Expense – Oil and gas exploration expense consists of dry hole expense, unproved lease amortization, seismic, staff expense (including stock-based compensation expense of $0.3 million which began in 2006) and other miscellaneous exploration expense, including lease rentals. Oil and gas exploration expense was $32.0 million for first

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quarter 2006, as compared with $23.7 million for first quarter 2005. Oil and gas exploration expense for first quarter 2006 includes approximately $9.2 million additional seismic expense, primarily in Equatorial Guinea, Suriname and deepwater Gulf of Mexico. See also “Stock-Based Compensation Expense” below.

Depreciation, Depletion and Amortization – Depreciation, depletion and amortization (“DD&A”) expense was as follows:

	Three Months Ended March 31,
	2006		2005
Depreciation, depletion and amortization expense (in thousands)	$	124,465	$	70,279
Unit rate per BOE	7.76		7.49

The increase in the unit rate was primarily due to higher production volumes from higher-cost Gulf of Mexico deepwater locations. DD&A expense also includes abandoned assets expense of $7.5 million in first quarter 2005 and none in first quarter 2006.

Selling, General and Administrative Expense – Selling, general and administrative expense (“SG&A”) was as follows:

	Three Months Ended March 31,
	2006		2005
Selling, general and administrative expense (in thousands)	$	35,398	$	15,168
Unit rate per BOE	2.21		1.62

SG&A expense more than doubled first quarter 2006 over first quarter 2005. SG&A expense for first quarter 2006 increased due to higher salaries and wages and the inclusion of SG&A expense related to Patina operations. SG&A expense includes deferred compensation expense of $2.9 million (calculated under SFAS 123(R)) for first quarter 2006 and $0.5 million (calculated under APB 25) for first quarter 2005. See “Stock-Based Compensation Expense” below.

Interest Expense and Capitalized Interest – Interest expense (net of interest capitalized) increased $21.5 million to $33.2 million for first quarter 2006, as compared with $11.7 million for first quarter 2005. Capitalized interest was $1.5 million for first quarter 2006, compared with $2.5 million for first quarter 2005. Interest expense (net of interest capitalized) for the quarter increased due to increased borrowings related to the Patina Merger and to an increase in the interest rate applicable to the Credit Facility from 4.8% at December 31, 2005 to 5.5% at March 31, 2006.

Deferred Compensation Adjustment – The deferred compensation adjustment includes increases or decreases in the market value of the deferred compensation liability, including the shares of Noble Energy common stock held by a rabbi trust, while recorded as treasury stock. Based on the changes in the total market value of the rabbi trust’s assets, a deferred compensation adjustment of $9.2 million was recognized first quarter 2006.

Stock-Based Compensation Expense – We adopted FAS 123(R) on January 1, 2006 using the modified prospective transition method. Under this method, we record compensation expense for all stock-based awards granted after the date of adoption and for the unvested portion of previously granted awards that are outstanding at the date of adoption. Accordingly, prior period amounts are not restated. Stock-based compensation expense totaled $3.2 million ($2.1 million after tax) for first quarter 2006. This amount was included in the consolidated statements of operations as oil and gas exploration expense ($0.3 million) and SG&A expense ($2.9 million). As of March 31, 2006, unrecognized compensation expense related to the unvested portion of stock-based awards was approximately $23.7 million. We expect this amount to be recognized over a weighted-average period of approximately 1.6 years. See Note 4 - Stock-Based Compensation.

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Through December 31, 2005, we accounted for stock-based compensation under the intrinsic value recognition and measurement principles of APB 25 and related Interpretations. When stock options were issued under APB 25, no compensation cost was recognized as the options were granted at an exercise price equal to the market value of Noble Energy common stock on the date of grant. Stock-based compensation expense related to restricted stock was recognized under APB 25 and totaled $0.5 million ($0.3 million after tax) for first quarter 2005.

Other Expense (Income), Net – Asa result of the impacts of Hurricanes Katrina and Rita on the timing of our forecasted production, derivative instruments hedging approximately 6,000 barrels per day of crude oil and 40,000 MMBtu per day of natural gas did not qualify for hedge accounting treatment during a portion of first quarter 2006. Accordingly, the changes in fair value of these derivative instruments were recognized in our results of operations. Mark-to-market gains totaled $39.2 million ($25.5 million, net of tax) and were included in other expense (income), net in the consolidated statements of operations. In addition, the delay in the timing of production resulted in a loss of $25.4 million ($16.5 million, net of tax) related to amounts previously recorded in AOCL. These derivative instruments were re-designated as cash flow hedges in February 2006. Other expense (income), net for first quarter 2006 also includes an ineffectiveness loss of $8.7 million related to cash flow hedges.

Income Tax Provision – Income tax expense was as follows:

	Three Months Ended March 31,
	2006			2005
	(in thousands)
Income tax provision	$	123,266		$	64,514
Effective rate	35		%	37		%

The decrease in the effective rate for first quarter 2006 is due primarily to the ability to utilize foreign tax credits and an increase in equity earnings from Alba Plant, LLC, which is a permanent difference for tax provision purposes.

In addition, at December 31, 2005, we had recorded a deferred tax asset of $54.9 million for the future foreign tax credits associated with deferred tax liabilities recorded by our foreign branch operations. The valuation allowance with respect to that asset was increased from $41.4 million to $50.9 million during the three months ended March 31, 2006.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes – We are exposed to market risk in the normal course of business operations. Management believes that we are well positioned with our 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, we have used derivative instruments and may do so in the future as a means of managing our exposure to price changes.

At March 31, 2006, we had entered into future costless collar transactions related to crude oil and natural gas production as follows:

	Natural Gas					Crude Oil
		Average price per MMBtu					Average price per Bbl
Production Period	MMBtupd	Floor		Ceiling		Bopd	Floor		Ceiling
April - December 2006 (NYMEX)	—	$	—	$	—	2,286	$	43.92	$	52.92
April - December 2006 (CIG)	10,000	5.25		10.20		—	—		—
2007 (NYMEX)	—	—		—		2,700	60.00		74.30
2007 (CIG)	12,000	6.50		9.50		—	—		—
2007 (Brent)	—	—		—		6,748	45.00		70.63
2008 (NYMEX)	—	—		—		3,100	60.00		72.40
2008 (CIG)	14,000	6.75		8.70		—	—		—
2008 (Brent)	—	—		—		4,066	45.00		66.52
2009 (NYMEX)	—	—		—		3,700	60.00		70.00
2009 (CIG)	15,000	6.00		9.90		—	—		—
2009 (Brent)	—	—		—		3,074	45.00		63.04
2010 (NYMEX)	—	—		—		3,500	55.00		73.80
2010 (CIG)	15,000	6.25		8.10		—	—		—

At March 31, 2006, we had entered into future fixed price swap transactions related to crude oil and natural gas production as follows:

	Natural Gas			Crude Oil
Production Period	MMBtupd	Average Price per MMBtu		Bopd	Average price per Bbl
April - December 2006 (NYMEX) (1)	170,000	$	6.20	16,600	$	40.24
2007 (NYMEX)	170,000	6.04		17,100	39.19
2008 (NYMEX)	170,000	5.67		16,500	38.23

(1) Includes derivative instruments of 40,000 MMBtupd of natural gas and 6,000 Bopd of crude oil that did not qualify for hedge accounting treatment at December 31, 2005. These derivative instruments were re-designated as cash flow hedges in February 2006.

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At March 31, 2006, we had entered into basis swap (CIG vs. NYMEX) transactions related to natural gas production. These basis swaps have been combined with NYMEX commodity swaps and designated as cash flow hedges. The basis swaps are as follows:

	Natural Gas
Production Period	MMBtupd	Average Differential per MMBtu
April - December 2006 (CIG vs. NYMEX)	70,000	$	1.45

At March 31, 2006, we had a net unrealized loss of approximately $1 billion (pre-tax) related to crude oil and natural gas derivative instruments entered into for hedging purposes. A net unrealized loss of $633.6 million, net of tax, is recorded in AOCL in shareholders’ equity and will be recognized in earnings as adjustments to revenue as the individual contracts are settled.

Derivative Instruments Held for Trading Purposes – From time to time, we employ derivative instruments in connection with 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, we 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, we believe we have no material market risk exposure from these derivative instruments at March 31, 2006.

Interest Rate Risk

We are exposed to interest rate risk related to our variable and fixed interest rate debt. At March 31, 2006, we had $2.145 billion (excluding unamortized discount) of long-term debt outstanding, of which $650 million was fixed-rate debt. We believe that anticipated near term changes in interest rates would not have a material effect on the fair value of our fixed-rate debt and would not expose us to the risk of material earnings or cash flow loss.

At March 31, 2006, we had $1.495 billion of long-term variable-rate debt and $25 million of short-term variable rate debt outstanding. Variable rate debt exposes us to the risk of earnings or cash flow loss due to changes in market interest rates. We estimate that a hypothetical 10% change in the floating interest rates applicable to our March 31, 2006 debt balance would result in a change in annual interest expense of approximately $8.0 million.

Foreign Currency Risk

We do not enter into foreign currency derivatives. The U.S. dollar is considered the functional currency for each of our 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 we do not believe we are 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.

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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:

•our growth strategies;

•our ability to successfully and economically explore for and develop crude oil and natural gas resources;

•anticipated trends in our business;

•our future results of operations;

•our liquidity and ability to finance our exploration and development activities;

•market conditions in the oil and gas industry;

•our ability to make and integrate acquisitions; and

•the impact of governmental regulation.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our annual report on Form 10-K, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

We believe 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. We do not intend to update the description of important factors each time a potential important factor arises. We advise our stockholders that they should do the following:

•be aware that important factors not described below could affect the accuracy of our forward-looking statements; and

•use caution and common sense when analyzing our 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 our control. Some of our 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. We expect that our 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 the following:

•our financial position, results of operations and cash flows;

•the quantities of natural gas and crude oil reserves that we can economically produce;

•the quantity and value of estimated proved and unproved reserves that may be attributed to our properties; and

•our ability to fund our 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

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on a number of factors, including, but not limited to, 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 our 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, our 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, our finding and development costs may not justify the use of resources to explore for and develop such reserves.

Reserve Estimates. Forward-looking statements are predicated, in part, on estimates of our crude oil and natural gas reserves. All of the reserve data in this Form 10-Q or otherwise made by or on our behalf 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 our 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. Our 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 future results of our operations and financial condition. Our 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 United States and laws and regulations of foreign nations, affecting the following:

•crude oil and natural gas production;

•taxes applicable to us and/or our production;

•the amount of crude oil and natural gas available for sale;

•the availability of adequate pipeline and other transportation and processing facilities; and

•the marketing of competitive fuels.

Our operations are also subject to extensive federal, state and local laws and regulations in the United States and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Our forward-looking statements are generally based upon the expectation that we will not be required, in the near future, to expend cash to comply with environmental laws and regulations that are material in relation to our total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, we are unable to accurately predict the ultimate financial impact of compliance.

Drilling and Operating Risks. Our 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 our 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.

Insurance. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses, including the loss of wells, blowouts, pipeline leakage or other damage, certain costs of pollution control and physical damages on certain assets. Our insurance coverage includes crude oil and natural gas properties and construction insurance,

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marine cargo insurance and third party and comprehensive general liability insurance. Except for our operations in Israel and Equatorial Guinea, we do not carry business interruption insurance.

During first quarter 2006, our insurance carrier determined that its Aggregation Limit would be reduced to $500 million effective June 1, 2006. We are currently exploring alternative coverage. However, we may not have sufficient coverage for some of the risks we face, either because insurance is not available on commercially reasonable terms or because of single event limitations by our insurer. If an event occurs that is not covered, or not fully covered, by insurance, it could harm our financial condition, results of operations and cash flows. In addition, we cannot fully insure against pollution and environmental risks.

Competition. Competition in the industry is intense. We actively compete 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. Our 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 ours.

Other. In our 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 us 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. Our international operations are also subject to certain political, economic and other uncertainties that include, among others, the following:

•risk of war;

•terrorist acts and civil disturbances;

•expropriation or nationalization of assets;

•renegotiation, modification or nullification of existing contracts;

•changes in taxation policies, including the effects of additional oil profits taxes recently imposed by China and Ecuador and the proposed increase in the Supplementary Charge imposed by the United Kingdom on North Sea income;

•laws and policies of the United States 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 we conduct operations.

ITEM 4. CONTROLS AND PROCEDURES

Based on the evaluation of our disclosure controls and procedures by Charles D. Davidson, Noble Energy’s principal executive officer, and Chris Tong, Noble Energy’s principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures are effective. There were no changes in 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, our internal controls over financial reporting, except that we are in the process of integrating the newly acquired Patina Oil & Gas Corporation and U.S. Exploration Holdings, Inc. into our existing internal control structure. We acquired Patina on May 16, 2005 and U.S. Exploration on March 29, 2006, and we are in the process of integrating the disclosure controls and procedures of Patina and U.S. Exploration where appropriate.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Refer to Note 13 - Commitments and Contingencies to the consolidated financial statements.

ITEM 1A. RISK FACTORS

None.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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 25, 2006 in Houston, Texas.

(b)Proxies were solicited by the Board of Directors of Noble Energy 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 178,667,209 shares of common stock of Noble Energy outstanding and entitled to vote, 157,530,308 shares were present in person or by proxy, representing approximately 88.2%.

The shareholder voting results are as follows:

Proposal I. Directors Election

	Number of Shares Voting for Election As Director	Number of Shares Withholding Authority To Vote for Election As Director
Jeffrey L. Berenson	155,248,029	2,282,279
Michael A. Cawley	142,935,133	14,595,175
Edward F. Cox	153,957,170	3,573,138
Charles D. Davidson	152,581,231	4,949,077
Thomas J. Edelman	147,136,007	10,394,301
Kirby L. Hedrick	155,245,949	2,284,359
Bruce A. Smith	149,131,870	8,398,438
William T. Van Kleef	154,629,300	2,901,008

Proposal II. Ratification of Appointment of KPMG LLP as Independent Auditors

(For 156,450,156; Against 1,040,184; Abstaining 39,969)

Proposal III. Stockholder Proposal on Independent Board Chairman

(For 31,405,831; Against 107,136,994; Abstaining 207,069; Broker Non-Votes 18,780,414)

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ITEM 5. OTHER INFORMATION

None.

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.

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SIGNATURES

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 2, 2006		/s/ CHRIS TONG
			CHRIS TONG
			Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit Number	Exhibit
10.1	Purchase and Sale Agreement, dated February 7, 2006, among Noble Energy Production, Inc., U.S. Exploration Holdings, LLC, U.S. Exploration Holdings, Inc. and United States Exploration, Inc. ( filed as Exhibit 10.28 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 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).

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