UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2006

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 x 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 x

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 x

Number of shares of common stock outstanding as of July 31, 2006: 176,593,499

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Noble Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(in thousands, except share amounts)

	(Unaudited)
	June 30,			December 31,
	2006			2005
ASSETS
Current Assets
Cash and cash equivalents	$	181,391		$	110,321
Accounts receivable - trade, net	640,916			566,206
Probable insurance claims	93,577			142,311
Assets held for sale	241,953			—
Deferred income taxes	242,646			237,045
Other current assets	105,631			119,628
Total current assets	1,506,114			1,175,511
Property, plant and equipment
Oil and gas properties (successful efforts method of accounting)	8,186,352			8,411,426
Other property, plant and equipment	74,906			69,869
	8,261,258			8,481,295
Accumulated depreciation, depletion and amortization	(1,473,170		)	(2,282,379		)
Total property, plant and equipment, net	6,788,088			6,198,916
Other noncurrent assets	574,847			640,738
Goodwill	895,038			862,868
Total Assets	$	9,764,087		$	8,878,033

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable - trade	$	556,359		$	519,971
Derivative instruments	374,527			445,939
Income taxes	4,520			65,136
Asset retirement obligations	143,978			60,331
Other current liabilities	363,219			148,768
Total current liabilities	1,442,603			1,240,145
Deferred income taxes	1,506,267			1,201,191
Asset retirement obligations	147,848			278,540
Derivative instruments	645,414			757,509
Other noncurrent liabilities	297,082			279,971
Long-term debt	2,040,672			2,030,533
Total Liabilities	6,079,886			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; 186,509,157 and 184,893,510 shares issued, respectively	621,697			616,311
Capital in excess of par value	1,980,812			1,945,239
Deferred compensation	—			(5,288		)
Accumulated other comprehensive loss	(398,848		)	(783,499		)
Treasury stock, at cost: 9,443,532 and 9,268,932 shares, respectively	(158,349		)	(148,476		)
Retained earnings	1,638,889			1,465,857
Total Shareholders’ Equity	3,684,201			3,090,144
Total Liabilities and Shareholders’ Equity	$	9,764,087		$	8,878,033

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(in thousands, except per share amounts)
(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006		2005
Revenues
Oil and gas sales	$	714,860		$	443,934		$	1,361,112	$	759,178
Income from equity method investees	35,441			18,544			75,091		38,438
Other revenues	22,279			22,965			48,374		56,039
Total Revenues	772,580			485,443			1,484,577		853,655

Costs and Expenses
Lease operating costs	79,186			48,196			161,379		84,116
Production and ad valorem taxes	27,513			17,601			52,966		26,821
Transportation costs	8,871			6,553			13,932		10,220
Exploration costs	29,400			25,598			61,423		49,255
Depreciation, depletion and amortization	168,648			95,897			293,113		166,176
General and administrative	37,661			24,812			73,059		39,980
Accretion of discount on asset retirement obligations	2,662			2,658			5,979		5,209
Interest, net of amount capitalized	33,918			18,253			67,086		29,985
Loss (gain) on derivative instruments	401,197			(263		)	396,039		2,380
Other expense (income), net	28,389			21,738			55,112		40,631
Total Costs and Expenses	817,445			261,043			1,180,088		454,773

(Loss) Income Before Taxes	(44,865		)	224,400			304,489		398,882
Income Tax (Benefit) Provision	(14,160		)	87,523			109,107		152,037
Net (Loss) Income	$	(30,705	)	$	136,877		$	195,382	$	246,845

Earnings (Loss) Per Share
Basic	$	(0.17	)	$	0.94		$	1.11	$	1.87
Diluted	(0.17		)	0.91			1.08		1.83

Weighted average number of shares outstanding
Basic	177,160			146,356			176,651		132,338
Diluted	177,160			150,330			180,460		135,304

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

	Six Months Ended June 30,
	2006			2005
Cash Flows from Operating Activities
Net income	$	195,382		$	246,845
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	293,113			166,176
Depreciation, depletion and amortization - electricity generation	8,067			7,909
Dry hole expense	15,019			19,500
Impairment of operating assets	6,359			—
Amortization of unproved leasehold costs	10,086			8,372
Stock-based compensation expense	6,323			1,255
Gain on disposal of assets	(11,015		)	(4,181		)
Deferred income taxes	47,059			75,307
Accretion of discount on asset retirement obligations	5,979			5,209
Income from equity method investees	(75,091		)	(38,438		)
Dividends received from equity method investees	18,000			27,675
Deferred compensation adjustment	14,740			9,878
Loss on derivative instruments	447,789			2,380
Other	8,440			(2,687		)
Changes in operating assets and liabilities, net of effect of acquisition
(Increase) decrease in accounts receivable	(69,810		)	68,121
Increase in other current assets	(30,800		)	(15,789		)
Decrease (increase) in probable insurance claims	91,560			(12,738		)
Increase (decrease) in accounts payable	33,596			(108,777		)
(Decrease) increase in other current liabilities	(80,556		)	30,524
Net Cash Provided by Operating Activities	934,240			486,541

Cash Flows From Investing Activities
Additions to property, plant and equipment	(629,860		)	(311,088		)
U.S. Exploration acquisition, net of cash acquired	(412,257		)	—
Patina merger, net of cash acquired	—			(1,111,099		)
Proceeds from sale of property, plant and equipment	16,928			320
Investments in equity method investees	(1,358		)	(13,917		)
Distribution from equity method investee	77,520			2,025
Net Cash Used in Investing Activities	(949,027		)	(1,433,759		)

Cash Flows From Financing Activities
Exercise of stock options	29,289			47,352
Excess tax benefits from stock-based awards	7,600			—
Cash dividends paid	(22,350		)	(5,914		)
Purchase of treasury stock	(23,682		)	—
Proceeds from credit facilities	300,000			2,010,000
Repayment of credit facilities	(210,000		)	(395,000		)
Repayment of term loans	(80,000		)	—
Proceeds from short-term borrowings	490,000			—
Repayment of short-term borrowings	(405,000		)	—
Repayment of Patina debt	—			(610,865		)
Net Cash Provided by Financing Activities	85,857			1,045,573
Increase in Cash and Cash Equivalents	71,070			98,355
Cash and Cash Equivalents at Beginning of Period	110,321			179,794
Cash and Cash Equivalents at End of Period	$	181,391		$	278,149

The accompanying notes are an integral part of these financial statements

Consolidated Statements of Shareholders’ Equity
(in thousands)
(Unaudited)

									Accumulated
			Capital in						Other			Treasury						Total
	Common		Excess of			Deferred			Comprehensive			Stock,			Retained			Shareholders’
	Stock		Par Value			Compensation			Loss			at Cost			Earnings			Equity

January 1, 2006	$	616,311	$	1,945,239		$	(5,288	)	$	(783,499	)	$	(148,476	)	$	1,465,857		$	3,090,144

Net income	—		—			—			—			—			195,382			195,382
Adoption of SFAS No. 123(R)	—		(5,288		)	5,288			—			—			—			—
Stock-based compensation expense	—		6,323			—			—			—			—			6,323
Exercise of stock options	5,169		24,120			—			—			—			—			29,289
Tax benefits related to exercise of stock options	—		7,600			—			—			—			—			7,600
Issuance of restricted stock, net	217		(217		)	—			—			—			—			—
Cash dividends ($0.125 per share)	—		—			—			—			—			(22,350		)	(22,350		)
Purchases of treasury stock	—		—			—			—			(23,682		)	—			(23,682		)
Rabbi trust shares sold	—		3,035			—			—			13,809			—			16,844
Unrealized hedging losses	—		—			—			(5,121		)	—			—			(5,121		)
Redesignation of cash flow hedges									275,542									275,542
Hedges reclassified to net income	—		—			—			114,150			—			—			114,150
Other	—		—			—			80			—			—			80

June 30, 2006	$	621,697	$	1,980,812		$	—		$	(398,848	)	$	(158,349	)	$	1,638,889		$	3,684,201

January 1, 2005	$	417,152	$	291,458		$	(1,671	)	$	(14,787	)	$	(75,956	)	$	843,792		$	1,459,988

Net income	—		—			—			—			—			246,845			246,845
Patina Merger	185,568		1,576,799			—			—			(73,203		)	—			1,689,164
Stock issuance costs	—		(206		)	—			—			—			—			(206		)
Exercise of stock options	9,050		38,302			—			—			—			—			47,352
Tax benefits related to exercise of stock options	—		10,192			—			—			—			—			10,192
Issuance of restricted stock, net	512		5,138			(5,650		)	—			—			—			—
Amortization of restricted stock	—		—			1,255			—			—			—			1,255
Cash dividends ($0.05 per share)	—		—			—			—			—			(5,914		)	(5,914		)
Rabbi trust shares sold	—		84			—			—			655			—			739
Unrealized hedging losses	—		—			—			(489,765		)	—			—			(489,765		)
Hedges reclassified to net income	—		—			—			27,180			—			—			27,180
Other	—		—			—			109			—			—			109

June 30, 2005	$	612,282	$	1,921,767		$	(6,066	)	$	(477,263	)	$	(148,504	)	$	1,084,723		$	2,986,939

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
(in thousands)
(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005

Net income (loss)	$	(30,705	)	$	136,877		$	195,382		$	246,845
Other comprehensive income (loss)
Unrealized loss on cash flow hedges:
Changes in fair value of cash flow hedges	(75,603		)	(157,291		)	(7,878		)	(753,485		)
Less tax provision	26,462			55,052			2,757			263,720
Redesignation of cash flow hedges:
Redesignation of cash flow hedges	398,516			—			423,910			—
Less tax provision	(139,481		)	—			(148,368		)	—
Less reclassification adjustment for amounts out of accumulated other comprehensive income:
Oil and gas cash flow hedges	67,920			27,655			175,237			41,437
Less tax provision	(23,772		)	(9,679		)	(61,333		)	(14,503		)
Interest rate lock cash flow hedge	189			189			378			378
Less tax provision	(66		)	(66		)	(132		)	(132		)
Other comprehensive income (loss)	(131		)	17			123			168
Less tax provision	46			(6		)	(43		)	(59		)
Other comprehensive income (loss)	254,080			(84,129		)	384,651			(462,476		)
Comprehensive income (loss)	$	223,375		$	52,748		$	580,033		$	(215,631	)

The accompanying notes are an integral part of these financial statements

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 West Africa (Equatorial Guinea and Cameroon), 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 - Asset Purchases and Sales.

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 — Asset Purchases and Sales.

Sale of Gulf of Mexico Shelf Properties Subsequent to Quarter-End — On July 14, 2006, we completed the sale of our Gulf of Mexico shelf assets. The sale included essentially all of our assets in the Gulf of Mexico shelf except for our interest in the Main Pass area, which we have retained. See Note 3 - Asset Purchases and Sales and Note 5 - Derivative Instruments and Hedging Activities.

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 U.S. generally accepted accounting principles (“GAAP”) for complete financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements at June 30, 2006 and December 31, 2005 and for the three months and six months ended June 30, 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 months and six months ended June 30, 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 June 30, 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 - Asset Purchases and Sales.

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.

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.

Balance Sheet and Income Statement Information —
Other current assets consist of the following:

	June 30,		December 31,
	2006		2005
	(in thousands)

Derivative instruments	$	23,270	$	29,258
Materials and supplies inventories	47,722		33,802
Prepaid expenses and other	34,639		56,568
Total	$	105,631	$	119,628

Other non-current assets consist of the following:

	June 30,		December 31,
	2006		2005
	(in thousands)

Equity method investments	$	400,625	$	420,362
Probable insurance claims	69,975		112,800
Derivative instruments	2,107		17,259
Other assets	102,140		90,317
Total	$	574,847	$	640,738

Other current liabilities consist of the following:

	June 30,		December 31,
	2006		2005
	(in thousands)

Accrued and other current liabilities	$	161,127	$	137,428
Current deferred income taxes	98,071		—
Interest payable	19,021		11,340
Short-term borrowings	85,000		—
Total	$	363,219	$	148,768

Other revenues consist of the following:

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)

Gathering, marketing and processing	$	6,760	$	8,421	$	14,943	$	19,904
Electricity sales	15,519		14,544		33,431		36,135
Total	$	22,279	$	22,965	$	48,374	$	56,039

Other expense (income), net consists of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	(in thousands)

Electricity generation	$	14,597		$	9,452		$	25,224		$	20,891
Gathering, marketing and processing	5,968			6,812			11,470			15,049
Deferred compensation	5,563			9,878			14,740			9,878
Impairments	6,359			—			6,359			—
Other	(4,098		)	(4,404		)	(2,681		)	(5,187		)
Total	$	28,389		$	21,738		$	55,112		$	40,631

Note 3 - Asset Purchases and Sales

Purchase of U.S. Exploration — On March 29, 2006, we completed the purchase of 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. The allocation, which has been revised based on updated information, is as follows:

· $412.7 million to proved oil and gas properties;

· $130.8 million to unproved oil and gas properties;

· $33.8 million to goodwill; and

· $171.9 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.

Patina Merger — 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 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 $17.1 million ($5.1 million during the first six months of 2006) for tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the merger in accordance with Emerging Issues Task Force (“EITF”) Abstract Issue No. 00-23, “Issues Related to the Accounting for Stock Compensation under APB Opinion No. 24 and FASB Interpretation No. 44.”

Pro Forma Financial Information — The following pro forma condensed combined financial information for the three and six months ended June 30, 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 actual results for the three and six months ended June 30, 2006 (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		Six Months Ended
	June 30,		June 30,
	2005		2005
	(in thousands, except per share amounts)

Revenues	$	569,854	$	1,101,609
Income from continuing operations	153,919		294,217
Net income	153,919		294,217

Earnings per share:
Basic	$	0.90	$	1.69
Diluted	0.87		1.64

Sale of Gulf of Mexico Shelf Assets Subsequent to Quarter-End — On July 14, 2006, we completed the sale of our Gulf of Mexico shelf assets. The sale included essentially all of our assets in the Gulf of Mexico shelf except for our interest in the Main Pass area, which we have retained. After-tax cash proceeds from the sale are expected to total $504 million, including proceeds to be received from parties who exercised preferential rights to purchase certain minor properties. We anticipate recording a pretax gain of approximately $215 million from the sale during third quarter 2006. Gulf of Mexico shelf assets of $242 million are classified as assets held for sale in our consolidated balance sheet at June 30, 2006. Asset retirement obligations of $45.9 million are related to the Gulf of Mexico shelf assets and are included in current asset retirement obligations in our consolidated balance sheet at June 30, 2006. All estimates are subject to change based on final analysis of assets and liabilities sold and market conditions.

As a result of the pending sale, we recognized a pretax charge of $398.5 million related to cash flow hedges which were reclassified from accumulated other comprehensive loss (“AOCL”) to earnings during second quarter 2006. This reclassification reflected the mark-to-market value of the cash flow hedges that related to Gulf of Mexico shelf production. See Note 5 - Derivative Instruments and Hedging Activities.

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.

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). We recognized total stock-based compensation expense as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)
Stock-based compensation expense included in:
General and administrative expense	$	2,893	$	703	$	5,773	$	1,255
Exploration expense and other	276		—		550		—
Total stock-based compensation expense	3,169		703		6,323		1,255

Tax benefit from expense recognized	$	1,109	$	246	$	2,213	$	439

As a result of adopting SFAS 123(R) on January 1, 2006, our income before income taxes, net income and earnings per share were lower than if we had continued to account for stock-based compensation under APB 25. The impact on our financial results related to the adoption of SFAS 123(R) is as follows:

	Three Months Ended June 30,			Six Months Ended June 30,
	2006			2006
	(in thousands,			(in thousands,
	except per share amounts)			except per share amounts)
Increase in loss:			Decrease in income:
Loss before taxes	$	1,561	Income before taxes	$	3,964
Net loss	1,015		Net income	2,577
Basic loss per share	$	0.00	Basic earnings per share	$	0.01
Diluted loss per share	0.00		Diluted earnings per share	0.02

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 that tax benefits in excess of the tax benefits associated with recognized compensation cost be presented as cash flows from financing activities. Excess tax benefits presented as cash flows from financing activities totaled $2.5 million and $7.6 million for the three and six months ended June 30, 2006, respectively. These amounts would have been presented as cash flows from operating activities if we had continued to account for stock-based compensation under APB 25.

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 2006 below are the same since we have adopted SFAS 123(R) as of January 1, 2006. The 2006 amounts are presented for comparison to the prior year.

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
	Actual			Pro Forma			Actual			Pro Forma
	(in thousands, except per share amounts)

Net income (loss), as reported	$	(30,705	)	$	136,877		$	195,382		$	246,845
Add: Stock-based compensation cost recognized, net of related tax effects	2,060			457			4,110			798
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2,060		)	(2,050		)	(4,110		)	(3,965		)
Pro forma net income (loss)	$	(30,705	)	$	135,284		$	195,382		$	243,678

Earnings (loss) per share:
Basic - as reported	$	(0.17	)	$	0.94		$	1.11		$	1.87
Basic - pro forma	$	(0.17	)	$	0.92		$	1.11		$	1.84
Diluted - as reported	$	(0.17	)	$	0.91		$	1.08		$	1.83
Diluted - pro forma	$	(0.17	)	$	0.90		$	1.08		$	1.80

Our stock option and restricted stock plans (the “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 June 30, 2006, 8,803,432 shares of common stock were reserved for issuance, including 4,422,608 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 ratably 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

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 No. 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 June 30, 2006, 790,400 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. Options issued under the 1988 Plan 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. 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.

Assumptions - Stock Option Awards	2006 Grants
	(weighted averages)

Expected term (in years)	5.5
Expected volatility	31.79	%
Risk-free rate	4.72	%
Dividend yield	0.79	%

A summary of option activity for the six months ended June 30, 2006 follows:

					Weighted
			Weighted		Average
			Average		Remaining	Aggregate
			Exercise		Contractual	Intrinsic
	Options		Price		Term	Value
					(years)	(in thousands)
Outstanding at December 31, 2005	9,319,642		$	19.21
Granted	822,719		45.24
Exercised	(1,550,591	)	18.89
Forfeited	(58,273	)	38.96
Canceled / expired	—		—
Outstanding at June 30, 2006	8,533,497		$	21.64	4.4	$	212,428
Exercisable at June 30, 2006	7,137,051		$	18.41	3.5	$	200,725

The weighted-average grant-date fair value of options granted during the six months ended June 30, 2006 and 2005 was $16.08 and $11.84, respectively. The total intrinsic value of options exercised during the six months ended June 30, 2006 and 2005 was $38.9 million and $48.4 million, respectively.

As of June 30, 2006, there was $15.1 million of total unrecognized compensation cost related to nonvested stock options granted under the Plans. The cost is expected to be recognized over a weighted-average period of 1.7 years. 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.

Assumptions - Restricted Stock	2006 Grants

Number of simulations	100,000
Expected volatility	28.4	%
Risk-free rate	4.35	%

A summary of restricted stock activity for the six months ended June 30, 2006 follows:

			Weighted				Weighted
	Subject to		Average		Subject to		Average
	Service		Grant Date		Market		Grant Date
	Conditions		Fair Value		Conditions		Fair Value
	(shares)				(shares)
Restricted stock at December 31, 2005	123,246		$	33.79	133,515		$	23.60
Granted	11,039		45.10		77,563		39.51
Vested	(40,672	)	33.44		—		—
Forfeited	(16,718	)	33.44		(6,828	)	34.59
Restricted stock at June 30, 2006	76,895		$	35.67	204,250		$	29.27

The total intrinsic value of restricted stock that vested during the six months ended June 30, 2006 was $1.9 million. No restricted stock vested during the six months ended June 30, 2005.

As of June 30, 2006, there was $4.8 million of total unrecognized compensation cost related to nonvested restricted stock granted under the Plans. The cost is expected to be recognized over a weighted-average period of 1.5 years. Common stock dividends accrue on restricted stock grants and are paid upon vesting. We issue new shares of common stock when awarding restricted stock.

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, costless collars and basis swaps. Although these derivative instruments expose us to credit risk, we monitor the creditworthiness of our counterparties and we believe 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 No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and have elected to designate the majority of our derivative instruments as cash flow hedges. Derivative instruments designated as cash flow hedges are reflected at fair value in our consolidated balance sheets. Changes in fair value, to the extent the hedge is effective, are reported in 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 in 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 and is included in loss on derivative instruments in the consolidated statements of operations.

Ineffectiveness was recognized as follows:

	Three Months Ended June 30,					Six Months Ended June 30,
	2006		2005			2006		2005
	(in thousands)

Ineffectiveness losses (gains)	$	2,681	$	(263	)	$	11,341	$	2,380

If it becomes probable that the hedge transaction will not occur, the hedging instrument loses hedge accounting treatment. All prospective mark-to-market gains and losses are recorded in earnings and the related accumulated gains or losses recorded in AOCL 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 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 redesignated 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 loss on derivative instruments in the consolidated statements of operations.

We have hedging instruments that were designated as cash flow hedges of production from our Gulf of Mexico shelf assets. We sold these shelf assets subsequent to the end of second quarter 2006. During second quarter 2006, when it became probable that forecasted production would not occur due to the pending sale, we determined that deferral of losses in AOCL related to this forecasted production was no longer appropriate under SFAS 133. As a result, we reclassified a pretax charge of $398.5 million related to the cash flow hedges from AOCL to earnings. We have redesignated the majority of these instruments as cash flow hedges for other North America production. Future earnings will reflect only those changes in derivative fair value that occur after the date of redesignation and are deferred in AOCL until the forecasted production occurs.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005
Natural Gas Collars:
NYMEX -
Hedge MMBtupd	—			75,000			7,459			84,945
Floor price range	—			$	5.00 - $5.00		$	5.00 - $5.00		$	5.00 - $5.75
Ceiling price range	—			$	7.20 - $7.80		$	8.00 - $8.00		$	7.20 - $9.50
% of daily worldwide sales	—			16.0		%	1.2		%	20.0		%

CIG(1) -
Hedge MMBtupd	10,000			—			6,740			—
Floor price	$	5.25		—			$	5.25		—
Ceiling price	$	10.20		—			$	10.20		—
% of daily worldwide sales	1.6		%	—			1.1		%	—

Crude Oil Collars:
NYMEX -
Hedge Bpd	4,658			15,250			4,502			15,518
Floor price range	$	29.00 - $60.00		$	29.00 - $32.00		$	29.00 - $60.00		$	29.00 - $32.00
Ceiling price range	$	34.30 - $73.00		$	37.25 - $42.00		$	34.30 - $73.00		$	37.25 - $44.80
% of daily worldwide sales	5.3		%	26.0		%	5.4		%	29.3		%
Brent -
Hedge Bpd	—			5,000			—			5,000
Floor price range	—			$	32.50 - $32.50		—			$	32.50 - $37.50
Ceiling price range	—			$	56.50 - $56.50		—			$	50.50 - $56.50
% of daily worldwide sales	—			8.0		%	—			9.4		%

Natural Gas Swaps:
NYMEX -
Hedge MMBtupd	170,000			87,143			170,000			43,812
Average price per MMBtu	$	6.11		$	6.57		$	6.72		$	6.57
% of daily worldwide sales	26.9		%	18.0		%	26.7		%	11.0		%

Crude Oil Swaps:
NYMEX -
Hedge Bpd	16,600			8,781			16,600			4,415
Average price per Bbl	$	40.65		$	40.13		$	40.91		$	40.13
% of daily worldwide sales	19.5		%	15.0		%	19.9		%	8.0		%

Basis Swaps vs. NYMEX:(2)
CIG -
Hedge MMBtupd	70,000			—			47,182			—
Average differential per MMBtu	$	1.49		—			$	1.49		—
ANR(3)				—
Hedge MMBtupd	6,593			—			3,315			—
Average differential per MMBtu	$	1.14		—			$	1.14		—

(1) Colorado Interstate Gas

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

(3) ANR Pipeline

Effects of cash flow hedges on oil and gas sales were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)
Reduction of oil and gas sales	$	67,920	$	27,655	$	175,237	$	41,436

At June 30, 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					Average price
		per MMBtu					per Bbl
Production Period	MMBtupd	Floor		Ceiling		Bopd	Floor		Ceiling

July - December 2006 (NYMEX)	—	—		—		1,100	$	60.00	$	73.00
July - 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 June 30, 2006, we had entered into future fixed price swap transactions related to crude oil and natural gas production as follows:

	Natural Gas				Crude Oil
			Average Price			Average price
Production Period	MMBtupd		per MMBtu		Bopd	per Bbl

July - Dec 2006 (NYMEX)	170,000	(1)	$	6.25	16,600	$	40.04
2007 (NYMEX)	170,000	(1)	6.04		17,100	39.19
2008 (NYMEX)	170,000	(1)	5.67		16,500	38.23

(1) Includes fixed price swaps (with associated basis swaps) of 90,000 MMBtupd of natural gas for 2006, 140,000 MMBtupd of natural gas for 2007, and 150,000 MMBtupd of natural gas for 2008 for which cash flow hedge accounting was discontinued at June 30, 2006 due to the pending sale of Gulf of Mexico shelf assets. These swaps were redesignated as cash flow hedges in second quarter 2006.

At June 30, 2006, we had entered into basis swap 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
		Average
		Differential
Production Period	MMBtupd	per MMBtu

July - December 2006 (CIG vs. NYMEX)	70,000	$	1.49
July - December 2006 (ANR vs. NYMEX)	20,000	1.14
2007 (CIG vs. NYMEX)	100,000	2.02
2007 (ANR vs. NYMEX)	30,000	1.17
2007 (PEPL (1) vs. NYMEX)	10,000	1.11
2008 (CIG vs. NYMEX)	100,000	1.66
2008 (ANR vs. NYMEX)	40,000	1.01
2008 (PEPL vs. NYMEX)	10,000	0.98

(1) Panhandle Eastern Pipe Line

If commodity prices were to stay the same as they were at June 30, 2006, approximately $169.4 million of deferred losses, net of taxes, related to the fair values of the derivative instruments included in AOCL at June 30, 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. 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:

	June 30,			December 31,
	2006			2005
	(in thousands)

Derivative instruments (current asset)	$	23,270		$	29,258
Derivative instruments (long-term asset)	$	2,107		$	17,259
Derivative instruments (current liability)	$	(374,527	)	$	(445,939	)
Derivative instruments (long-term liability)	$	(645,414	)	$	(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 the first six months of 2006 and 2005.

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 is reflected in the table below. Net periodic benefit cost includes plan design changes made effective May 1, 2006 and a discount rate of 6.25%.

	Retirement & Restoration						Medical & Life
	Plan Benefits						Plan Benefits
	2006			2005			2006			2005
	(in thousands)
Three Months Ended June 30:
Service cost	$	2,701		$	1,514		$	528		$	184
Interest cost	2,240			1,666			321			282
Expected return on plan assets	(2,018		)	(1,799		)	—			—
Transition obligation recognition	60			(54		)	—			60
Amortization of prior service cost	(45		)	101			(184		)	(13		)
Recognized net actuarial loss	520			200			217			56
Net periodic benefit cost	$	3,458		$	1,628		$	882		$	569

Six Months Ended June 30:
Service cost	$	6,006		$	3,029		$	1,272		$	369
Interest cost	4,512			3,331			690			564
Expected return on plan assets	(3,981		)	(3,598		)	—			—
Transition obligation recognition	120			(108		)	—			120
Amortization of prior service cost	48			203			(243		)	(26		)
Recognized net actuarial loss	1,240			399			548			112
Net periodic benefit cost	$	7,945		$	3,256		$	2,267		$	1,139

We made cash contributions to the pension plan of $2.2 million in 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 June 30, 2006, based upon work completed, we have submitted $154.3 million (cumulative) in insurance claims related to Hurricane Ivan damage, none of which has been disputed, and received $134 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 $9 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 $70 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.

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

	June 30,			December 31,
	2006			2005
	(in thousands)
Probable insurance claims - current	$	93,577		$	142,311
Other assets (long-term portion of probable insurance claims)	69,975			112,800
Total Ivan, Katrina and Rita probable insurance claims	163,552			255,111

Asset retirement obligations - current	$	(119,044	)	$	(42,016	)
Asset retirement obligations - long-term	—			(121,800		)
Total asset retirement obligations related to Main Pass assets	(119,044		)	(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:

	Six Months Ended June 30,
	2006
	(in thousands)

Asset retirement obligations, beginning of period	$	338,871
Liabilities incurred in current period	2,516
Liabilities settled in current period	(59,986		)
Revisions	4,446
Accretion expense	5,979
Asset retirement obligations, end of period	$	291,826

Current portion	$	143,978
Noncurrent portion	147,848

The ending aggregate carrying amount includes $119 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. The current portion includes $45.9 million related to Gulf of Mexico shelf assets sold in July 2006.

Note 9 - Equity Method Investments

We have the following investments accounted for under 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;

· 27.8% interest in Alba Plant, LLC, which owns and operates an LPG processing plant; and

· 50% interests in AMPCO Marketing, LLC and AMPCO Services, LLC, which provide technical and consulting services.

Dividends and distributions received from equity method investees were $95.5 million and $30 million for the six months ended June 30, 2006 and 2005, respectively. Investments in equity method investees are included in other noncurrent assets in our consolidated balance sheets. Investments are as follows:

	June 30,		December 31,
	2006		2005
	(in thousands)
Equity method investments:
Atlantic Methanol Production Company, LLC	$	218,339	$	214,226
Alba Plant, LLC	170,480		195,109
AMPCO Marketing, LLC	9,774		9,014
AMPCO Services, LLC	2,032		2,013
Total equity method investments	$	400,625	$	420,362

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

Balance Sheet Information

	June 30,			December 31,
	2006			2005
	(in thousands)

Current assets	$	209,843		$	274,484
Noncurrent assets	881,303			877,402
Current liabilities	(63,701		)	(119,912		)
Noncurrent liabilities	(286,124		)	(450,156		)

Statements of Operations Information

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)
Operating revenues	$	174,265	$	90,738	$	354,862	$	175,075
Gross margin	124,415		63,360		264,119		118,411
Net income	105,340		51,717		220,619		101,298

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.

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:

				Weighted			Weighted
				Average			Average
	Income			Shares	Income		Shares
	2006				2005
	(in thousands, except per share amounts)
Three Months Ended June 30:

Net (loss) income available to common shareholders	$	(30,705	)	177,160	$	136,877	146,356
Basic EPS	$	(0.17	)		$	0.94

Net (loss) income available to common shareholders	$	(30,705	)	177,160	$	136,877	146,356
Plus: Incremental shares from assumed conversions
Dilutive stock options				—			3,812
Dilutive restricted stock				—			162
Adjusted net (loss) income and shares	$	(30,705	)	177,160	$	136,877	150,330
Diluted EPS	$	(0.17	)		$	0.91

Six Months Ended June 30:

Net income available to common shareholders	$	195,382		176,651	$	246,845	132,338
Basic EPS	$	1.11			$	1.87

Net income available to common shareholders	$	195,382		176,651	$	246,845	132,338
Plus: Incremental shares from assumed conversions
Dilutive stock options				3,662			2,798
Dilutive restricted stock				147			168
Adjusted net income and shares	$	195,382		180,460	$	246,845	135,304
Diluted EPS	$	1.08			$	1.83

Stock-based awards (options and restricted stock) that are antidilutive are excluded from the calculation of diluted EPS. The following table summarizes the antidilutive awards and shares excluded from diluted EPS.

	Weighted	Weighted		Weighted	Weighted
	Outstanding	Average		Outstanding	Average
	Awards/Shares	Exercise Price		Awards/Shares	Exercise Price
	2006			2005
	(in thousands, except per share amounts)
Three Months Ended June 30:
Stock option awards	781	$	45.41	—	$	—
Restricted stock	1			—
Noble shares held in rabbi trust	1,756			—
Total excluded from diluted EPS calculation	2,538			—

Six Months Ended June 30:
Stock option awards	668	$	45.29	—	$	—
Restricted stock	28			—
Noble shares held in rabbi trust	1,899			—
Total excluded from diluted EPS calculation	2,595			—

Note 11 - Income Taxes

The income tax provision consists of the following:

	Three Months Ended June 30,					Six Months Ended June 30,
	2006			2005		2006		2005
	(in thousands)

Current	$	(5,758	)	$	23,364	$	62,048	$	76,730
Deferred	(8,402		)	64,159		47,059		75,307

Total income tax (benefit) provision	$	(14,160	)	$	87,523	$	109,107	$	152,037

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.

At December 31, 2005, we had recorded a deferred U.S. tax asset of $54.9 million for the future foreign tax credits associated with deferred foreign tax liabilities recorded by our foreign branch operations. The valuation allowance with respect to the deferred U.S. tax asset was increased from $41.4 million at December 31, 2005 to $51.5 million during the six months ended June 30, 2006.

Note 12 - Geographical Data

We have operations throughout the world and manage our operations by geographic region or 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; West Africa; North Sea; Israel; and Other International, Corporate and Marketing. West Africa includes Equatorial Guinea and Cameroon. Other International includes 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			West Africa		North Sea		Israel		Other Int’l Corporate & Marketing
	(in thousands)
Three Months Ended June 30, 2006:

Revenues from third parties	$	737,139		$	412,226		$	97,333	$	26,354	$	18,231	$	182,995
Intersegment revenue	—			121,064			—		—		—		(121,064		)
Income from equity method investments	35,441			—			35,441		—		—		—
Total Revenues	772,580			533,290			132,774		26,354		18,231		61,931

DD&A	168,648			151,331			4,206		1,456		3,053		8,602
Loss on derivative instruments	401,197			401,197			—		—		—		—
Income (loss) before taxes	(44,865		)	(152,136		)	118,391		17,881		13,338		(42,339		)

Three Months Ended June 30, 2005:

Revenues from third parties	$	466,899		$	198,073		$	70,678	$	31,326	$	15,354	$	151,468
Intersegment revenue	—			97,516			—		—		—		(97,516		)
Income from equity method investments	18,544			—			18,544		—		—		—
Total Revenues	485,443			295,589			89,222		31,326		15,354		53,952

DD&A	95,897			75,098			7,404		2,821		2,639		7,935
Gain on derivative instruments	(263		)	(263		)	—		—		—		—
Income (loss) before taxes	224,400			139,391			75,786		21,546		10,969		(23,292		)

	Consolidated		United States		West Africa		North Sea		Israel		Other Int’l Corporate & Marketing
	(in thousands)
Six Months Ended June 30, 2006:

Revenues from third parties	$	1,409,486	$	691,039	$	221,372	$	62,641	$	37,990	$	396,444
Intersegment revenue	—		273,107		—		—		—		(273,107		)
Income from equity method investments	75,091		—		75,091		—		—		—
Total Revenues	1,484,577		964,146		296,463		62,641		37,990		123,337

DD&A	293,113		256,023		10,321		3,330		6,252		17,187
Loss on derivative instruments	396,039		396,039		—		—		—		—
Income (loss) before taxes	304,489		49,223		266,283		43,544		28,066		(82,627		)

Six Months Ended June 30, 2005:

Revenues from third parties	$	815,217	$	296,308	$	125,329	$	60,558	$	30,030	$	302,992
Intersegment revenue	—		187,885		—		—		—		(187,885		)
Income from equity method investments	38,438		—		38,438		—		—		—
Total Revenues	853,655		484,193		163,767		60,558		30,030		115,107

DD&A	166,176		126,930		12,550		5,693		5,199		15,804
Loss on derivative instruments	2,380		2,380		—		—		—		—
Income (loss) before taxes	398,882		220,055		138,213		41,197		21,463		(22,046		)

Total assets at June 30, 2006(1)	$	9,764,087	$	7,342,745	$	902,899	$	264,702	$	253,087	$	1,000,654
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 $895.0 million.

(2) The domestic reporting unit includes goodwill of $862.9 million.

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. 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 and seeking monetary damages (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 matter has been set for trial scheduled to commence April 24, 2007.

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 and have received a permit to allow the installation of remediation equipment. It is within the discretion of the IEPA to assess a fine for violating emission and permit regulations. However, 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. The company is defending itself 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.

	Six Months Ended June 30,
	2006
	(in thousands)

Capitalized exploratory well costs, beginning of period	$	35,228
Additions to capitalized exploratory well costs pending determination of proved reserves	43,628
Reclassified to property, plant and equipment based on determination of proved reserves	(15,073		)
Capitalized exploratory well costs charged to expense	(331		)
Capitalized exploratory well costs, end of period	$	63,452

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:

	June 30,		December 31,
	2006		2005
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	63,452	$	35,228
Capitalized exploratory well costs that have been capitalized for a period greater than one year	—		—
Balance at end of period	$	63,452	$	35,228

Note 15 - Recently Issued Pronouncements

In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and assessing the impact it may have on our financial position and results of operations.

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, purchase of U.S. Exploration and recent divestiture of Gulf of Mexico shelf assets have allowed us to achieve a strategic objective of enhancing our United States asset portfolio. The result is 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.

Second quarter 2006 financial results included the following:

· net loss of $(30.7) million compared with net income of $136.9 million in the second quarter 2005;

· recognition of a non-cash, pretax charge of $398.5 million related to previously forecasted hedge production that is no longer probable of occurring due to the third quarter sale of Gulf of Mexico shelf assets (See Note 5 - Derivative Instruments and Hedging Activities);

· diluted loss per share of $(0.17) compared with diluted income per share of $0.91 in the second quarter 2005;

· cash flow from operating activities of $934.2 million for the first six months of 2006, a 92% increase over the first six months of 2005; and

· common stock repurchases of $23.7 million resulting from approval by the Board of Directors of a $500 million common stock repurchase program.

Second quarter 2006 significant operational highlights included the following:

· full quarter of operations of U.S. Exploration acquired on March 29;

· commencement of production from the Lorien deepwater Gulf of Mexico development (Green Canyon Block 199, 60% working interest) on April 27;

· Gulf of Mexico deepwater discovery at Raton prospect (Mississippi Canyon Block 248, 50% working interest);

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

· acquisition of a 50% participating interest in the PH-77 license, offshore the Republic of Cameroon;

· first natural gas sales to the Reading power plant in Tel Aviv, Israel;

· a 37% increase in overall daily sales volumes from second quarter 2005, including a 69% domestic increase and a 5% international decrease; and

· increases of 30% in the average realized crude oil price and 6% in the average realized natural gas price over second quarter 2005.

Portfolio Enhancements — During the first six months of 2006, we continued to enhance our portfolio with significant purchases of assets. In addition, we completed the sale of certain Gulf of Mexico shelf assets in July 2006.

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. This acquisition significantly expands our operations in one of our core areas. Proved reserves of U.S. Exploration are estimated to be approximately 248 Bcfe, of which 41% are proved developed and 55% are natural gas. Our consolidated operating and cash flow information includes financial results of U.S. Exploration after March 29, 2006.

During second quarter 2006, we acquired a 50% participating interest in the PH-77 license, offshore the Republic of Cameroon, for which we have been approved to be the operator. PH-77 covers 1.125 million acres.

On July 14, 2006, we completed the sale of substantially all of our Gulf of Mexico shelf assets except for the Main Pass area, which is currently undergoing repair work after suffering significant hurricane damage in 2004 and 2005. The sale of these non-core assets will allow us to focus future investments and growth in areas with higher potential. After-tax proceeds from the sale are expected to total $504 million, including proceeds to be received from parties who exercised preferential rights to purchase certain minor properties. Current production from the assets sold totaled approximately 5,000 Bpd of crude oil and 90 Mmcfpd of natural gas, net to our interest. As of March 1, 2006, the effective date of the sale, proved reserves for the assets sold totaled approximately 7 MMBbls of crude oil and 120 Bcf of natural gas. A pretax gain of approximately $215 million from the sale will be included in our results of operations for third quarter 2006.

Common Stock Repurchase Program — On May 16, 2006, we announced that our Board of Directors had authorized the repurchase of up to $500 million of common stock. We may buy shares from time to time on the open market or in negotiated purchases and expect to fund the repurchases primarily from cash flows from operations and proceeds from the sale of Gulf of Mexico shelf assets. The timing and amounts of any repurchases will be at management’s discretion and in accordance with securities laws and other legal requirements. The repurchase program is subject to reevaluation in the event of changes in market conditions. During second quarter 2006, we repurchased 587,600 shares of our common stock at an aggregate cost of $23.7 million.

Adoption of SFAS 123(R) — We adopted SFAS 123(R) as of January 1, 2006. As a result, we recognized compensation expense of $6.3 million related to stock-based awards during the first six months of 2006. This expense relates to stock-based awards made in 2006 and to the unvested portions of awards made in prior years. As a result of this change in accounting method, our net income was reduced by $2.6 million, or $0.02 per diluted share for the first six months of 2006. In addition, $7.6 million of excess tax benefits related to option exercises were included in cash flows from financing activities rather than cash flows from operating activities. In 2005, excess tax benefits of $10.2 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 from 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 contribution of the Lorien deepwater Gulf of Mexico development, which commenced production April 27, 2006 ; and

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

· partially offset by loss of production from Gulf of Mexico shelf assets sold in July 2006.

Factors impacting our production profile include:

· the timing and amount of production from Swordfish, Ticonderoga and Lorien;

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

· infrastructure development in Israel;

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

· downtime associated with methanol plant maintenance or its turnaround; and

· capital expenditures, as discussed below, which are expected to result in near-term production.

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.

Recently Issued Pronouncements — See Note 15 - Recently Issued Pronouncements.

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, and to fund our stock repurchase program. 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.

Cash Flows

Operating Activities — For the first six months of 2006, we reported net cash provided by operating activities of $934.2 million as compared with $486.5 million for the first six months of 2005, an increase of 92%. Factors contributing to the increase included:

· a $155.0 million increase in oil and gas sales due to higher sales volumes;

· a $116.0 million increase in oil and gas sales due to higher realized crude oil and natural gas prices; and

· $94.0 million reimbursements of insurance claims.

Investing Activities — Net cash used in investing activities for the first six months of 2006 totaled $949.0 million, as compared with $1.434 billion for the first six months of 2005. Significant investing activities in 2006 to date included:

· $412.3 million used for the purchase of U.S. Exploration; and

· $629.9 million used for capital expenditures;

· partially offset by $77.5 million distributions received from equity method investees.

Significant investing activities for the first six months of 2005 included:

· $1.111 billion used for the Patina acquisition; and

· $311.1 million used for capital expenditures.

Financing Activities — Net cash provided by financing activities totaled $85.9 million and $1.046 billion for the first six months of 2006 and 2005, respectively. Significant financing activities in 2006 to date included:

· $95.0 million net proceeds from short-term and long-term borrowings;

· $29.3 million proceeds from the exercise of stock options;

· $22.4 million cash dividends paid on Noble Energy common stock; and

· $23.7 million paid for repurchases of Noble Energy common stock.

Significant financing activities for the first six months of 2005 included:

· $1.615 billion net proceeds from long-term borrowings;

· $47.4 million proceeds from exercise of stock options; and

· $5.9 million cash dividends paid on Noble Energy common stock.

Acquisition, Exploration and Development-Related Expenditures

Acquisition, exploration and development-related expenditure information is as follows:

	Six Months Ended June 30,
	2006		2005
	(in thousands)
Acquisitions(1):
Proved properties	$	412,687	$	2,642,224
Unproved properties	130,819		1,068,000
Total	$	543,506	$	3,710,224

Exploration and Development:
Exploratory drilling and completion	$	63,595	$	27,387
Dry hole(2)	15,019		19,500
Lease acquisition costs	43,565		11,738
Seismic(2)	18,898		7,109
Total exploration expenditures	141,077		65,734
Development drilling and completion	497,263		256,456
Corporate and other	10,082		10,425
Total exploration and development-related expenditures from consolidated operations	$	648,422	$	332,615

Capital contributions to equity method investees	$	1,358	$	13,917

(1) We acquired U.S. Exploration on March 29, 2006 and completed the Patina Merger on May 16, 2005.

(2) Dry hole and seismic expenditures are included in exploration costs in the consolidated statements of operations.

Financing Activities

Long-Term Debt — Our long-term debt totaled $2.041 billion (net of unamortized discount) at June 30, 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 36.6% at June 30, 2006 as compared with 40% at December 31, 2005.

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 June 30, 2006, $1.370 billion in borrowings were outstanding under the Credit Facility. The weighted average interest rate applicable to borrowings under the Credit Facility at June 30, 2006 was 5.92%.

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 June 30, 2006, we had $85 million of short-term borrowings outstanding under uncommitted lines with interest payable at a weighted average rate of 5.86%.

Dividends — We paid a quarterly cash dividend of 5.0 cents per share of common stock during first quarter 2006 and increased it to 7.5 cents per share of common stock during second 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 and second quarter 2005. On July 25, 2006, our Board of Directors declared a quarterly cash dividend of 7.5 cents per common share, payable August 21, 2006, to shareholders of record on August 7, 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 $29.3 million from the exercise of stock options during the first six months of 2006, as compared to $47.4 million during the first six months of 2005.

RESULTS OF OPERATIONS

Natural Gas Information

Natural gas revenues increased 40% second quarter 2006 over second quarter 2005 and 71% for the first six months of 2006 over the first six months of 2005. The increases were due to higher realized natural gas sales prices and higher sales volumes.

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)

Natural gas sales	$	307,651	$	219,846	$	626,828	$	366,706

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

	Three Months Ended June 30,
	2006			2005
	Mcfpd	$/Mcf		Mcfpd	$/Mcf
United States(1)	493,268	$	6.29	323,449	$	6.78
West Africa(2)	37,741	0.41		73,722	0.25
North Sea	8,342	7.19		8,594	5.31
Israel	75,317	2.66		60,690	2.78
Ecuador(3)	21,908	—		16,316	—
Other International	360	1.15		42	1.07
Total	636,936	$	5.50	482,813	$	5.18

	Six Months Ended June 30,
	2006			2005
	Mcfpd	$/Mcf		Mcfpd	$/Mcf
United States(1)	477,993	$	6.61	269,276	$	6.69
West Africa(2)	46,130	0.38		58,860	0.25
North Sea	8,413	8.91		8,937	5.57
Israel	78,916	2.66		59,679	2.78
Ecuador(3)	24,102	—		20,403	—
Other International	388	1.12		20	1.07
Total	635,942	$	5.66	417,175	$	5.12

(1) Reflects increases (reductions) of $(0.24) per Mcf and $0.04 per Mcf for second quarter 2006 and 2005, respectively, and $(0.72) per Mcf and $0.02 per Mcf for the first six months of 2006 and 2005, respectively, 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 $33.4 million and $36.1 million are included in total revenues for the first six months of 2006 and 2005, respectively.

Factors contributing to the change in natural gas sales volumes in 2006 included:

· additional domestic production from Patina properties, acquired May 16, 2005;

· additional domestic production from U.S. Exploration properties, acquired March 29, 2006;

· increases in deepwater Gulf of Mexico production at Swordfish, Ticonderoga and Lorien;

· turnaround of the AMPCO methanol plant in Equatorial Guinea, which lasted 57 days; and

· increased demand from Israel Electric Corporation Limited, full six months of sales to Bazan Oil Refinery and commencement of natural gas sales to the Reading power plant in Tel Aviv, Israel.

Crude Oil Information

Crude oil revenues increased 82% second quarter 2006 over second quarter 2005 and increased 87% for the first six months of 2006 over the first six months of 2005. The increase was due to higher realized crude oil sales prices and higher sales volumes.

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(in thousands)
Crude oil sales	$	407,209	$	224,088	$	734,284	$	392,472

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

	Three Months Ended June 30,
	2006			2005
	Bopd	$/Bbl		Bopd	$/Bbl
United States(1)	51,983	$	53.01	25,310	$	41.70
West Africa(2)	15,332	68.76		17,595	43.64
North Sea	3,322	69.14		5,921	50.43
Other international(3)	7,777	55.98		8,034	42.38
Total Consolidated Operations	78,414	57.07		56,860	43.31
Equity Investee(4)	7,439	46.68		2,436	41.29
Total	85,853	$	56.19	59,296	$	43.22

	Six Months Ended June 30,
	2006			2005
	Bopd	$/Bbl		Bopd	$/Bbl
United States(1)	44,634	$	48.53	21,639	$	40.42
West Africa(2)	19,267	62.58		15,475	44.10
North Sea	3,786	71.62		5,850	48.68
Other international(3)	7,788	53.12		8,390	38.89
Total Consolidated Operations	75,475	53.75		51,354	42.22
Equity Investee(4)	7,780	45.85		1,621	39.15
Total	83,255	$	53.02	52,975	$	42.13

(1) Reflects reductions of $(12.09) per Bbl and $(8.55) per Bbl second quarter 2006 and 2005, respectively, and $(14.02) per Bbl and $(8.45) per Bbl for the first six months of 2006 and 2005, respectively, from hedging activities.

(2) Production totaled 18,017 Bopd and 18,012 Bopd for the three and six months ended June 30, 2006, respectively. The variance between production and actual sales volumes is attributable to the timing of liquid hydrocarbon liftings. Average realized sales prices reflect reductions of $(5.64) per Bbl second quarter 2005 and $(3.36) per Bbl for the first six months of 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 5,218 Bopd and 1,524 Bopd for second quarter 2006 and 2005, respectively, and 6,131 Bopd and 1,086 Bopd for the first six months of 2006 and 2005, respectively.

Factors contributing to the change in crude oil sales volumes in 2006 included:

· additional domestic production from Patina properties, acquired May 16, 2005;

· additional domestic production from U.S. Exploration properties, acquired March 29, 2006;

· increases in deepwater Gulf of Mexico production at Swordfish, Ticonderoga and Lorien;

· full quarters of production from the Phase 2B liquids expansion project in Equatorial Guinea; and

· natural field decline in the North Sea and timing of liftings.

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 include the results of crude oil and natural gas cash flow hedging activities. Hedging activities reduced revenues by $67.9 million and $27.7 million for second quarter 2006 and 2005, respectively, and $175.2 million and $41.4 million for the first six months of 2006 and 2005, respectively.

Equity Method Investees

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005

Net income (in thousands):
AMPCO, LLC and Affiliates	$	11,566	$	11,444	$	24,113	$	28,053
Alba Plant, LLC	23,875		7,100		50,978		10,385
Distributions/Dividends (in thousands):
AMPCO, LLC	9,750		10,845		19,500		29,700
Alba Plant, LLC	29,747		—		76,020		—
Sales volumes:
Methanol (gallons in thousands)	32,355		33,047		66,464		76,123
Condensate (Bopd)	2,222		912		1,649		535
LPG (Bopd)	5,217		1,524		6,131		1,086
Average realized prices:
Methanol (per gallon)	$	0.84	$	0.79	$	0.83	$	0.79
Condensate (per Bbl)	68.86		50.12		66.32		49.35
LPG (per Bbl)	37.24		36.00		40.34		34.12

Net income from AMPCO, LLC in 2006 has declined relative to last year due to a 57-day shutdown of methanol production for the plant turnaround that occurred during May and June 2006. 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.

Costs and Expenses

Production Costs — Total production costs were as follows:

	Consolidated		United States		West Africa		North Sea		Israel		Other Int’l/ Corporate
	(in thousands)
Three Months Ended June 30, 2006:

Oil and gas operating costs	$	66,517	$	50,406	$	7,903	$	2,310	$	2,132	$	3,766
Workover and repair expense	12,669		12,653		—		—		—		16
Lease operating costs	79,186		63,059		7,903		2,310		2,132		3,782
Production and ad valorem taxes	27,513		21,660		—		—		—		5,853
Transportation expense	8,871		7,289		—		1,398		—		184
Total production costs	$	115,570	$	92,008	$	7,903	$	3,708	$	2,132	$	9,819

Three Months Ended June 30, 2005:

Oil and gas operating costs	$	46,111	$	30,927	$	6,364	$	3,065	$	2,109	$	3,646
Workover and repair expense	2,085		2,085		—		—		—		—
Lease operating costs	48,196		33,012		6,364		3,065		2,109		3,646
Production and ad valorem taxes	17,601		12,886		—		—		—		4,715
Transportation expense	6,553		4,691		—		1,601		—		261
Total production costs	$	72,350	$	50,589	$	6,364	$	4,666	$	2,109	$	8,622

	Consolidated		United States		West Africa		North Sea		Israel		Other Int’l/ Corporate
	(in thousands)
Six Months Ended June 30, 2006:

Oil and gas operating costs	$	129,119	$	96,604	$	15,450	$	4,643	$	4,255	$	8,167
Workover and repair expense	32,260		32,175		—		—		—		85
Lease operating costs	161,379		128,779		15,450		4,643		4,255		8,252
Production and ad valorem taxes	52,966		43,737		—		—		—		9,229
Transportation expense	13,932		10,664		—		2,891		—		377
Total production costs	$	228,277	$	183,180	$	15,450	$	7,534	$	4,255	$	17,858

Six Months Ended June 30, 2005:

Oil and gas operating costs	$	78,791	$	49,359	$	11,685	$	6,127	$	4,000	$	7,620
Workover and repair expense	5,325		5,325		—		—		—		—
Lease operating costs	84,116		54,684		11,685		6,127		4,000		7,620
Production and ad valorem taxes	26,821		19,030		—		—		—		7,791
Transportation expense	10,220		6,719		—		3,098		—		403
Total production costs	$	121,157	$	80,433	$	11,685	$	9,225	$	4,000	$	15,814

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005

Oil and gas operating costs	$	3.97	$	3.69	$	3.93	$	3.60
Workover and repair expense	0.75		0.17		0.98		0.24
Lease operating costs	$	4.72	$	3.86	$	4.91	$	3.84
Production and ad valorem taxes	1.64		1.41		1.61		1.23
Transportation expense	0.53		0.52		0.42		0.47
Total production costs	$	6.89	$	5.79	$	6.94	$	5.54

Lease operating expense (“LOE”), excluding workover and repair expense, increased $20.4 million, or 44% for second quarter 2006 as compared with second quarter 2005. The increase reflects expenses associated with a full quarter of Patina properties, compared to only a partial quarter in 2005, which accounted for $8.9 million of the increase, the start up of Lorien and a full quarter of Swordfish and Ticonderoga operations, which contributed $6.4 million and higher lease operating expenses in Equatorial Guinea of $1.6 million. LOE, excluding workover and repair expense, increased $50.3 million, or 64%, for the first six months of 2006 as compared with the first six months of 2005. The increase reflects a full six months of Patina operations, compared to only 45 days in 2005, which accounted for $32.2 million of the increase, the start up of Lorien, Swordfish and Ticonderoga, none of which were online in the first half of 2005, which contributed $10.1 million and $3.8 million associated with Equatorial Guinea. In addition, the current high commodity price environment has led to higher service, contract labor and fuel costs.

Workover and repair expense increased $10.6 million for the second quarter 2006, as compared with the second quarter 2005. The 2006 expense for the second quarter reflects $2.1 million of workovers associated with the Patina properties, $4.0 million of workovers associated with other North America properties and $6.6 million ($0.39 per BOE) of hurricane-related repair expense. Workover and repair expense increased $26.9 million for the first six months of 2006, as compared with the first six months of 2005. The 2006 expense for the full six months includes Patina workover related expenses of $5.0 million, other North America workover related expenses of $6.0 million and $21.4 million ($0.65 per BOE) of hurricane-related repair expense.

Production and ad valorem tax expense increased $9.9 million, or 56%, for second quarter 2006, as compared with second quarter 2005. The increase reflects a full quarter of production from Patina and U.S. Exploration properties as compared to 2005. Production and ad valorem tax expense increased $26.1 million for the first six months of 2006, as compared with the first six months of 2005. The increase reflects a full six months of production from Patina operations, compared to only 45 days in 2005 and to production from U.S. Exploration properties. Patina and U.S. Exploration properties have proportionately more production subject to such taxes. In addition, revenues generally are taxed at higher rates as commodity prices rise.

The unit rates of oil and gas operations expense per BOE, converting gas to oil on the basis of six Mcf per barrel, were $6.89 per BOE second quarter 2006 as compared with $5.79 per BOE second quarter 2005 and $6.94 per BOE for the first six months of 2006 as compared with $5.54 per BOE for the first six months of 2005. The increases are due to rising third-party costs, hurricane-related repair expense and higher production taxes.

Oil and Gas Exploration Expense — Oil and gas exploration expense consists of dry hole expense, unproved lease amortization, seismic, staff expense and other miscellaneous exploration expense, including lease rentals. Oil and gas exploration expense was $29.4 million for second quarter 2006 (including stock-based compensation expense of $0.2 million), as compared with $25.6 million for second quarter 2005. Oil and gas exploration expense for the second quarter 2006 includes a $3.8 million increase in exploration general and administrative expense as compared with second quarter 2005.

Oil and gas exploration expense was $61.4 million (including stock-based compensation expense of $0.5 million) for the first six months of 2006, as compared with $49.3 million for the first six months of 2005. The increase is associated with 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 June 30,				Six Months Ended June 30,
	2006		2005		2006		2005

Depreciation, depletion and amortization expense (in thousands)	$	168,648	$	95,897	$	293,113	$	166,176
Unit rate per BOE	$	10.04	$	7.67	$	8.92	$	7.59

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 $0.5 million and $1 million for second quarter 2006 and 2005, respectively, and $0.5 million and $8.5 million for the first six months of 2006 and 2005, respectively.

General and Administrative Expense — General and administrative expense (“G&A”) was as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005

General and administrative expense (in thousands)	$	37,661	$	24,812	$	73,059	$	39,980
Unit rate per BOE	$	2.24	$	1.99	$	2.22	$	1.83

G&A expense increased second quarter 2006 over second quarter 2005 and for the first six months of 2006 as compared with the first six months of 2005. The increases were due to higher salaries and wages and the inclusion of G&A expense related to Patina operations. We are experiencing wage inflation due to the tight labor market which has resulted from the current high commodity price environment. G&A expense includes deferred compensation expense of $3.2 million (calculated under SFAS 123(R)) for second quarter 2006 and $0.8 million (calculated under APB 25) for second quarter 2005. G&A expense includes deferred compensation expense of $6.4 million and $1.3 million for the first six months of 2006 and 2005, respectively. See “Stock-Based Compensation Expense” below.

Interest Expense and Capitalized Interest — Interest expense (net of interest capitalized) increased $15.6 million to $33.9 million for second quarter 2006, as compared with $18.3 million for second quarter 2005. Capitalized interest was $0.8 million for second quarter 2006, compared with $2.4 million for second quarter 2005. Interest expense (net of interest capitalized) increased $37.1 million to $67.1 million for the first six months of 2006, as compared with $30 million for the first six months of 2005. Capitalized interest was $2.3 million for the first six months of 2006, compared with $4.9 million for the first six months of 2005. Interest expense (net of interest capitalized) increased due to increased borrowings related to the Patina Merger and U.S. Exploration acquisition and to an increase in the interest rate applicable to the Credit Facility from 4.8% at December 31, 2005 to 5.92% at June 30, 2006.

Stock-Based Compensation Expense — We adopted SFAS 123(R) on January 1, 2006 using the modified prospective transition method. See Note 4 - Stock-Based Compensation.

Loss on Derivative Instruments — Loss on derivative instruments includes the following:

· $398.5 million loss related to amounts previously recorded in AOCL for certain cash flow hedges that were discontinued second quarter 2006 due to the pending sale of Gulf of Mexico shelf assets;

· $25.4 million loss related to amounts previously recorded in AOCL for which the forecasted production was no longer probable of occurring;

· $39.2 million mark-to-market gain due to the loss of hedge accounting treatment for certain cash flow hedges during a portion of first quarter 2006; and

· cash flow hedge ineffectiveness gains (losses) of $(2.7) million and $(11.3) million for the three and six months ended June 30, 2006, respectively, and $0.3 million and $(2.4) million for the three and six months ended June 30, 2005, respectively.

See Note 5 - Derivative Instruments and Hedging Activities.

Other Expense (Income), Net — See Note 2 - Basis of Presentation.

Income Tax Provision (Benefit) — The income tax provision (benefit) was as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2006			2005			2006			2005

Income tax provision (benefit) (in thousands)	$	(14,160	)	$	87,523		$	109,107		$	152,037
Effective rate	31.6		%	39.0		%	35.8		%	38.1		%

The decrease in the effective rate for the first six months of 2006 is due primarily to the ability to utilize foreign tax credits and an increase in earnings from equity method investees, which is a permanent difference for tax provision purposes.

In addition, at December 31, 2005, we had recorded a deferred U.S. tax asset of $54.9 million for the future foreign tax credits associated with deferred foreign tax liabilities recorded by our foreign branch operations. The valuation allowance with respect to the deferred U.S. tax asset was increased from $41.4 million at December 31, 2005, to $51.5 million during the first six months of 2006.

The UK Finance Act of 2006, enacted on July 19, increases the income tax rate on our UK operations retroactive to January 1, 2006. Although we are still in the process of evaluating the impact of this change on our 2006 earnings, preliminary results indicate that it will increase our income tax expense for the year by approximately $10 million.

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 June 30, 2006, we had entered into future costless collar and fixed price swap transactions related to crude oil and natural gas and basis swap transactions related to natural gas production. See Note 5 - Derivative Instruments and Hedging Activities.

At June 30, 2006, we had a net liability related to derivative instruments of approximately $994.6 million (pretax) related to crude oil and natural gas derivative instruments on our consolidated balance sheets. A net unrealized loss of $379.5 million, net of tax, is deferred in AOCL in shareholders’ equity. We will reclassify the loss to earnings as adjustments to revenue when future production occurs.

Interest Rate Risk

We are exposed to interest rate risk related to our variable and fixed interest rate debt. At June 30, 2006, we had $2.045 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 June 30, 2006, we had $1.395 billion of long-term variable-rate debt and $85 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 June 30, 2006 debt balance would result in a pre-tax change in annual interest expense of approximately $8.6 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 in the consolidated statements of operations.

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 factors or factors unknown to us 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 and for evaluating the book value of our assets. We expect that our assumptions may change over time and that actual prices in the future may differ from our estimates. We periodically enter into crude oil and natural gas commodity hedges as a means to mitigate commodity price volatility. However, no assurance can be given that changing commodity prices will not adversely affect our operations. 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 crude oil and natural gas properties;

· the carrying value of our crude oil and natural gas 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 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 perils, including the loss of wells, blowouts, pipeline leakage or other damage, and certain costs of pollution control. Our insurance program responds to covered losses due to physical damage to our assets, liability claims of third parties and business interruption (loss of production) on certain assets.

We carry up to $259 million property damage coverage per loss event. During first quarter 2006, our insurance carrier determined that its Aggregation Limit would be reduced from $1 billion to $500 million effective June 1, 2006. This insurance company modification, in response to large claims from losses caused by Hurricanes Katrina and Rita, increases the risk that we could recover less than our stated limits on any insured catastrophic loss event should the total aggregate losses realized by our carrier exceed its $500 million Aggregation Limit applicable to any single loss event. Although the insurance industry has reduced underwriting capacity for windstorm exposure in the Gulf of Mexico, we were able to secure $100 million additional insurance coverage applicable to specified deepwater properties, in the form of a package policy that covers property damage on an excess of loss limits basis, in addition to coverage for primary/contingent business interruption due solely to named windstorm loss events. The need for this package policy will be assessed annually and there is no assurance that we will be able to secure adequate insurance coverage for Gulf of Mexico exposure at policy expiration. As a consequence, we may not have sufficient coverage for some of the exposures 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.

Competition. Competition in our 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.

International operations. Our international operations are also subject to certain political, economic and other uncertainties. International risk factors include, among others, the following:

· 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 increase in the Supplementary Charge imposed by the UK on North Sea income;

· laws and policies of the United States and foreign jurisdictions 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.

Conflict in the Middle East has been increasing and the political situation remains uncertain. To date, we have not experienced any disruption in our operations in Israel but can provide no assurance that future political or economic events affecting Israel will not adversely affect our operations.

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.

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, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, 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 U.S. Exploration Holdings, Inc. into our existing internal control structure. We acquired U.S. Exploration on March 29, 2006, and we are in the process of integrating the disclosure controls and procedures of U.S. Exploration where appropriate.

PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2005 except for changes in our insurance coverage and taxation policies in certain foreign locations. See Insurance and International operations above.

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

Issuer Purchase of Equity Securities.

On May 16, 2006, we announced that our Board of Directors has authorized the repurchase of up to $500 million of our common stock. We may buy shares from time to time on the open market or in negotiated purchases. The timing and amounts of any repurchases will be at management’s discretion and in accordance with securities laws and other legal requirements. The repurchase program is subject to reevaluation in the event of changes in market conditions.

The following table summarizes repurchases of our common stock occurring second quarter 2006.

				Total Number of	Approximate Dollar
				Shares Purchased	Value of Shares that
	Total Number	Average Price		as Part of Publicly	May Yet Be
	of Shares	Paid		Announced Plans	Purchased Under the
Period	Purchased	Per Share		or Programs(1)	Plans or Programs
					(in thousands)
04/01/06 - 04/30/06	—	$	—	—	$	500,000
05/01/06 - 05/31/06	—	—		—	—
06/01/06 - 06/30/06	587,600	40.28		587,600	(23,670		)
Total	587,600	$	40.28	587,600	$	476,330

(1) As of July 31, 2006, we had repurchased an additional 1,068,200 shares of common stock at an aggregate cost of approximately $50.9 million.

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. Election of the Board of Directors of Noble Energy to serve until the next annual meeting of the Company’s stockholders.

		Number of Shares
	Number of Shares	Withholding Authority
	Voting for Election	To Vote for Election
	As Director	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 of the Company.

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

Proposal III. Stockholder proposal requiring that the Chairman of the Board be an independent director, with limited exceptions.

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

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.

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	August 4, 2006	/s/ CHRIS TONG
		CHRIS TONG
		Senior Vice President and Chief Financial Officer

INDEX TO EXHIBITS

Exhibit Number		Exhibit

10.1		Purchase and Sale Agreement dated May 15, 2006 by and between the Company and Coldren Resources LP.

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).

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK