Edgar Filing: NOBLE ENERGY INC

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 September 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 October 25, 2006: 173,814,393

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Noble Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands, except share amounts)

	(Unaudited)
	September 30,			December 31,
	2006			2005
ASSETS
Current Assets
Cash and cash equivalents	$	89,803		$	110,321
Accounts receivable - trade, net	605,380			566,206
Probable insurance claims	101,018			142,311
Deferred income taxes	143,510			237,045
Other current assets	116,584			119,628
Total current assets	1,056,295			1,175,511
Property, plant and equipment
Oil and gas properties (successful efforts method of accounting)	8,507,211			8,411,426
Other property, plant and equipment	77,610			69,869
	8,584,821			8,481,295
Accumulated depreciation, depletion and amortization	(1,608,262		)	(2,282,379		)
Total property, plant and equipment, net	6,976,559			6,198,916
Other noncurrent assets	580,153			640,738
Goodwill	783,208			862,868
Total Assets	$	9,396,215		$	8,878,033

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable - trade	$	493,517		$	519,971
Derivative instruments	263,447			445,939
Income taxes	73,936			65,136
Asset retirement obligations	93,619			60,331
Other current liabilities	235,306			148,768
Total current liabilities	1,159,825			1,240,145
Deferred income taxes	1,706,728			1,201,191
Asset retirement obligations	130,639			278,540
Derivative instruments	422,384			757,509
Other noncurrent liabilities	271,861			279,971
Long-term debt	1,620,741			2,030,533
Total Liabilities	5,312,178			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; 187,773,262 and 184,893,510 shares issued, respectively	625,910			616,311
Capital in excess of par value	2,016,619			1,945,239
Deferred compensation	—			(5,288		)
Accumulated other comprehensive loss	(184,916		)	(783,499		)
Treasury stock, at cost: 12,707,784 and 9,268,932 shares, respectively	(317,103		)	(148,476		)
Retained earnings	1,943,527			1,465,857
Total Shareholders’ Equity	4,084,037			3,090,144
Total Liabilities and Shareholders’ Equity	$	9,396,215		$	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						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Revenues
Oil and gas sales	$	683,544		$	581,585		$	2,044,656		$	1,340,763
Income from equity method investees	33,810			22,829			108,901			61,267
Other revenues	23,965			27,674			72,339			83,713
Total Revenues	741,319			632,088			2,225,896			1,485,743

Costs and Expenses
Lease operating costs	76,928			63,433			238,307			146,673
Production and ad valorem taxes	30,697			24,304			83,663			51,125
Transportation costs	4,531			1,871			18,463			12,091
Exploration costs	30,904			77,253			92,327			126,508
Depreciation, depletion and amortization	165,765			111,653			458,878			277,829
General and administrative	40,657			29,346			113,716			69,326
Accretion of discount on asset retirement obligations	2,426			2,928			8,405			8,137
Interest, net of amount capitalized	28,556			29,045			95,642			59,030
(Gain) loss on derivative instruments	(6,315		)	(259		)	389,723			2,121
Gain on sale of assets	(200,676		)	(1,234		)	(211,691		)	(5,415		)
Other expense (income), net	22,880			52,612			89,008			98,295
Total Costs and Expenses	196,353			390,952			1,376,441			845,720

Income Before Taxes	544,966			241,136			849,455			640,023
Income Tax Provision	226,902			64,180			336,009			216,222
Net Income	$	318,064		$	176,956		$	513,446		$	423,801

Earnings Per Share
Basic	$	1.80		$	1.01		$	2.91		$	2.89
Diluted	1.75			0.99			2.85			2.84

Weighted average number of shares outstanding
Basic	176,218			174,703			176,505			146,612
Diluted	181,077			178,747			180,158			149,164

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2006			2005
Cash Flows from Operating Activities
Net income	$	513,446		$	423,801
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	458,878			277,829
Depreciation, depletion and amortization - electricity generation	11,842			12,395
Dry hole expense	24,164			77,494
Impairment of operating assets	6,359			5,198
Amortization of unproved leasehold costs	15,180			12,766
Stock-based compensation expense	9,320			2,742
Gain on disposal of assets	(211,691		)	(5,415		)
Deferred income taxes	146,709			100,433
Accretion of discount on asset retirement obligations	8,405			8,137
Income from equity method investees	(108,901		)	(61,267		)
Dividends received from equity method investees	18,000			42,975
Deferred compensation adjustment	15,673			31,307
Loss on derivative instruments	430,328			2,121
Other	(7,093		)	31,055
Changes in operating assets and liabilities, net of effect of acquisition
Increase in accounts receivable	(41,222		)	(36,204		)
Decrease (increase) in other current assets	13,479			(30,690		)
Decrease (increase) in probable insurance claims	101,612			(2,552		)
(Decrease) increase in accounts payable	(29,246		)	30,527
(Decrease) increase in other current liabilities	(34,429		)	44,189
Net Cash Provided by Operating Activities	1,340,813			966,841

Cash Flows From Investing Activities
Additions to property, plant and equipment	(1,030,430		)	(576,220		)
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	504,259			320
Investments in equity method investees	(5,126		)	(13,927		)
Distributions from equity method investees	116,521			3,581
Net Cash Used in Investing Activities	(827,033		)	(1,697,345		)

Cash Flows From Financing Activities
Exercise of stock options	50,576			63,766
Tax benefits from stock-based awards	18,534			-
Cash dividends paid	(35,776		)	(14,788		)
Purchase of treasury stock	(192,632		)	-
Proceeds from credit facilities	300,000			2,010,000
Repayment of credit facilities	(605,000		)	(773,667		)
Repayment of term loans	(105,000		)	—
Proceeds from short-term borrowings	845,000			—
Repayment of short-term borrowings	(810,000		)	—
Repayment of Patina debt	—			(610,865		)
Net Cash (Used in) Provided by Financing Activities	(534,298		)	674,446
Decrease in Cash and Cash Equivalents	(20,518		)	(56,058		)
Cash and Cash Equivalents at Beginning of Period	110,321			179,794
Cash and Cash Equivalents at End of Period	$	89,803		$	123,736

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries

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	—		—			—			—			—			513,446			513,446
Adoption of SFAS No. 123(R)	—		(5,288		)	5,288			—			—			—			—
Stock-based compensation expense	—		9,320			—			—			—			—			9,320
Exercise of stock options	9,382		41,194			—			—			—			—			50,576
Tax benefits related to exercise of stock options	—		18,534			—			—			—			—			18,534
Issuance of restricted stock, net	217		(217		)	—			—			—			—			—
Cash dividends ($0.20 per share)	—		—			—			—			—			(35,776		)	(35,776		)
Purchases of treasury stock	—		—			—			—			(192,632		)				(192,632		)
Rabbi trust shares sold	—		7,837			—			—			24,005			—			31,842
Unrealized changes in fair value of cash flow hedges	—		—			—			197,239			—			—			197,239
Unrealized cash flow hedges recognized in net income	—		—			—			264,265			—			—			264,265
Realized cash flow hedges reclassified out of accumulated other comprehensive loss	—		—			—			136,890			—			—			136,890
Other	—		—			—			189			—			—			189

September 30, 2006	$	625,910	$	2,016,619		$	—		$	(184,916	)	$	(317,103	)	$	1,943,527		$	4,084,037

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

Net income	—		—			—			—			—			423,801			423,801
Patina Merger	185,568		1,576,799			—			—			(73,203		)	—			1,689,164
Stock issuance costs	—		(206		)	—			—			—			—			(206		)
Exercise of stock options	11,544		52,222			—			—			—			—			63,766
Tax benefits related to exercise of stock options	—		13,346			—			—			—			—			13,346
Issuance of restricted stock, net	566		7,301			(7,867		)	—			—			—			—
Amortization of restricted stock	—		—			2,742			—			—			—			2,742
Cash dividends ($0.10 per share)	—		—			—			—			—			(14,788		)	(14,788		)
Rabbi trust shares sold	—		90			—			—			683			—			773
Unrealized changes in fair value of cash flow hedges	—		—			—			(955,837		)	—			—			(955,837		)
Realized cash flow hedges reclassified out of accumulated other comprehensive loss	—		—			—			85,845			—			—			85,845
Other	—		—			—			350			—			—			350

September 30, 2005	$	614,830	$	1,941,010		$	(6,796	)	$	(884,429	)	$	(148,476	)	$	1,252,805		$	2,768,944

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						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005

Net income	$	318,064		$	176,956		$	513,446		$	423,801
Other comprehensive income (loss)
Unrealized gain (loss) on cash flow hedges:
Changes in fair value of cash flow hedges	274,361			(717,035		)	266,483			(1,470,519		)
Less tax provision	(87,952		)	250,962			(69,244		)	514,682
Recognized in net income	—			—			423,910			—
Less tax provision	—			—			(159,645		)	—
Realized cash flow hedges reclassified out of accumulated other comprehensive loss:
Oil and gas cash flow hedges	43,798			90,065			219,035			131,502
Less tax provision	(16,494		)	(31,523		)	(82,489		)	(46,026		)
Interest rate lock cash flow hedge	174			189			552			568
Less tax provision	(66		)	(66		)	(208		)	(199		)
Other comprehensive income (loss)	180			372			303			538
Less tax provision	(68		)	(130		)	(114		)	(188		)
Other comprehensive income (loss)	213,933			(407,166		)	598,583			(869,642		)
Comprehensive income (loss)	$	531,997		$	(230,210	)	$	1,112,029		$	(445,841	)

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 conduct business internationally in West Africa (Equatorial Guinea and Cameroon), the Mediterranean Sea, Ecuador, the North Sea, China, Argentina, and Suriname.

Sale of Gulf of Mexico Shelf Properties – 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. Pretax cash proceeds from the sale totaled $487 million including proceeds received from parties who exercised preferential rights to purchase certain properties. See Note 3 - Asset Purchases and Sales and Note 5 - Derivative Instruments and Hedging Activities.

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 $411.6 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.

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 September 30, 2006 and December 31, 2005 and for the three months and nine months ended September 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 nine months ended September 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 September 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.

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” 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:

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

Derivative instruments	$	23,636	$	29,258
Materials and supplies inventories	45,584		33,802
Prepaid expenses and other	47,364		56,568
Total	$	116,584	$	119,628

Other noncurrent assets consist of the following:

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

Equity method investments	$	399,630	$	420,362
Probable insurance claims	52,481		112,800
Derivative instruments	2,914		17,259
Other assets	125,128		90,317
Total	$	580,153	$	640,738

Other current liabilities consist of the following:

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

Accrued and other current liabilities	$	176,300	$	137,428
Interest payable	24,006		11,340
Short-term borrowings	35,000		—
Total	$	235,306	$	148,768

Other revenues consist of the following:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)

Electricity sales	$	16,241	$	18,843	$	49,672	$	54,978
Gathering, marketing and processing	7,724		8,831		22,667		28,735
Total	$	23,965	$	27,674	$	72,339	$	83,713

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006		2005
	(in thousands)

Electricity generation (1)	$	17,876		$	16,746	$	43,099	$	37,637
Gathering, marketing and processing	4,204			5,856		15,674		20,905
Deferred compensation	933			21,429		15,673		31,307
Impairments	—			5,198		6,359		5,198
Other	(133		)	3,383		8,203		3,248
Total	$	22,880		$	52,612	$	89,008	$	98,295

(1) Includes increases in the allowance for doubtful accounts of $6.9 million and $6.1 million for third quarter 2006 and 2005, respectively, and $10.6 million and $7.4 million for the first nine months of 2006 and 2005, respectively. These increases have been made to cover potentially uncollectible balances related to the Ecuador power operations. Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. We are pursuing various strategies to protect our interests including international arbitration and litigation.

Note 3 - Asset Purchases and Sales

Sale of Gulf of Mexico Shelf Assets – 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. Pretax cash proceeds from the sale totaled $487 million including proceeds received from parties who exercised preferential rights to purchase certain properties. We recorded a pretax gain of $203.5 million from the sale during third quarter 2006. The net book value of assets sold totaled $221.4 million. Asset retirement obligations of $43.6 million, related to the Gulf of Mexico shelf assets, were also included in the sale. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” we have allocated $100 million of our domestic reporting unit goodwill to the sale.

As a result of the 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.

Purchase of U.S. Exploration – On March 29, 2006, we completed the purchase of U.S. Exploration for a cash purchase price of $411.6 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;

· $33.9 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 twelve-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

· $1.108 billion to deferred income taxes.

The amount of goodwill recorded in the Patina Merger has been reduced by a total of $21.2 million ($9.3 million during the first nine 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 Abstract Issue No. 00-23, “Issues Related to the Accounting for Stock Compensation under APB Opinion No. 25 and FASB Interpretation No. 44.”

Pro Forma Financial Information – The following pro forma condensed combined financial information for the nine months ended September 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 nine months ended September 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.

	Nine Months Ended
	September 30,
	2005
	(in thousands, except
	per share amounts)

Revenues	$	1,733,697
Income from continuing operations	471,173
Net income	471,173

Earnings per share:
Basic	$	2.74
Diluted	$	2.71

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				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)
Stock-based compensation expense included in:
General and administrative expense	$	2,720	$	1,406	$	8,493	$	2,742
Exploration expense and other	277		—		827		—
Total stock-based compensation expense	2,997		1,406		9,320		2,742

Tax benefit from expense recognized	$	1,129	$	492	$	3,510	$	960

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		Nine Months Ended
	September 30,		September 30,
	2006		2006
	(in thousands, except per share amounts)
Decrease in income:
Income before taxes	$	2,041	$	6,005
Net income	1,272		3,744
Basic earnings per share	$	< 0.01	$	0.02
Diluted earnings per share	$	< 0.01	$	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. Tax benefits presented as cash flows from financing activities totaled $10.9 million and $18.5 million for the three and nine months ended September 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						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	Actual			Pro Forma			Actual			Pro Forma
	(in thousands, except per share amounts)

Net income, as reported	$	318,064		$	176,956		$	513,446		$	423,801
Add: Stock-based compensation cost recognized, net of related tax effects	1,868			914			5,810			1,713
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(1,868		)	(2,380		)	(5,810		)	(6,346		)
Pro forma net income	$	318,064		$	175,490		$	513,446		$	419,168

Earnings per share
Basic - as reported	$	1.80		$	1.01		$	2.91		$	2.89
Basic - pro forma	$	1.80		$	1.00		$	2.91		$	2.86
Diluted - as reported	$	1.75		$	0.99		$	2.85		$	2.84
Diluted - pro forma	$	1.75		$	0.98		$	2.85		$	2.81

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. The maximum number of shares of common stock that may be issued under the 1992 Plan is 18,500,000 shares. At September 30, 2006, 8,359,634 shares of common stock were reserved for issuance, including 4,466,432 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 three-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 (both service based and market based) awarded under the 2004 LTIP are granted and awarded pursuant to the terms of the 1992 Plan. These awards are accounted for in accordance with the provisions of SFAS 123(R) which provides for the grant-date fair value of the awards to be recognized in the income statement over the service period. Our cash based performance units and/or cash based bonuses are accounted for under SFAS No. 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 September 30, 2006, 790,400 shares of common stock were reserved for issuance, including 715,180 shares available for future grants and awards 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 per non-employee director on February 1 of each year, and discretionary grants by the Board of Directors (up to a maximum of 11,200 options per non-employee director 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 per non-employee director 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 per non-employee director 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 nine months ended September 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	(2,814,696	)	17.97
Forfeited	(85,379	)	38.48
Canceled / expired	—		—
Outstanding at September 30, 2006	7,242,286		$	22.42	4.4	$	167,801
Exercisable at September 30, 2006	5,888,948		$	18.81	3.4	$	157,704

The weighted-average grant-date fair value of options granted during the nine months ended September 30, 2006 and 2005 was $16.08 and $12.12, respectively. The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005 was $79.8 million and $63.7 million, respectively.

As of September 30, 2006, there was $12.5 million of total unrecognized compensation cost related to unvested stock options granted under the Plans. The cost is expected to be recognized over a weighted-average period of 1.6 years. We issue new shares of common stock to settle option exercises.

Approximately 2,000,000 of the options exercised during the nine months ended September 30, 2006 were options held by Patina employees which were converted into options for Noble Energy common stock at the date of the Patina Merger.

Restricted Stock Awards

Grants of service based restricted stock awards are valued at our common stock price at the date of grant. The fair values of market based restricted stock awards are 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 nine months ended September 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 September 30, 2006	76,895		$	35.67	204,250		$	29.27

The total intrinsic value of restricted stock that vested during the nine months ended September 30, 2006 was $1.9 million. The shares of restricted stock which vested during the nine months ended September 30, 2006 were issued in connection with the Patina Merger on May 16, 2005 and were subject to a one-year vesting period. No restricted stock vested during the nine months ended September 30, 2005.

As of September 30, 2006, there was $3.9 million of total unrecognized compensation cost related to unvested 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 (gain) loss on derivative instruments in the consolidated statements of operations.

Ineffectiveness was recognized as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006		2005
	(in thousands)

Ineffectiveness (gains) losses	$	(2,957	)	$	(259	)	$	8,384	$	2,121

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 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 related to amounts previously recorded in AOCL. Both the gain and the loss are included in (gain) 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 during the third 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. In addition, a mark-to-market gain of $3.4 million relating to a hedging instrument that was not redesignated is included in (gain) loss on derivative instruments for third quarter 2006.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Reduction of oil and gas sales	$	43,798	$	90,065	$	219,035	$	131,502

At September 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

October - December 2006 (NYMEX)	—	—		—		1,100	$	60.00	$	73.00
October - December 2006 (CIG) (1)	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		—	—		—

(1) Colorado Interstate Gas

At September 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

October - Dec 2006 (NYMEX)	170,000	(1)	$	6.39	16,600	$	39.86
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 the second quarter 2006.

At September 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

October - December 2006 (CIG vs. NYMEX)	70,000	$	1.49
October - December 2006 (ANR (1) vs. NYMEX)	20,000	$	1.14
2007 (CIG vs. NYMEX)	100,000	$	2.02
2007 (ANR vs. NYMEX)	30,000	$	1.17
2007 (PEPL (2) 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) ANR Pipeline

(2) Panhandle Eastern Pipe Line

If commodity prices were to stay the same as they were at September 30, 2006, approximately $56.0 million of deferred losses, net of taxes, related to the fair values of the derivative instruments included in AOCL at September 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 hedged are expected to occur by December 2010.

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

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

Derivative instruments (current asset)	$	23,636		$	29,258
Derivative instruments (long-term asset)	$	2,914		$	17,259
Derivative instruments (current liability)	$	(263,447	)	$	(445,939	)
Derivative instruments (long-term liability)	$	(422,384	)	$	(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, used for certain marketing programs, 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 nine 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 September 30:
Service cost	$	2,400		$	1,302		$	420		$	185
Interest cost	2,224			1,664			296			292
Expected return on plan assets	(2,046		)	(1,748		)	—			—
Transition obligation recognition	60			(54		)	—			60
Amortization of prior service cost	(114		)	113			(246		)	(3		)
Recognized net actuarial loss	420			204			320			57
Net periodic benefit cost	$	2,944		$	1,481		$	790		$	591

Nine Months Ended September 30:
Service cost	$	8,406		$	4,331		$	1,692		$	554
Interest cost	6,736			4,995			986			856
Expected return on plan assets	(6,027		)	(5,346		)	—			—
Transition obligation recognition	180			(161		)	—			180
Amortization of prior service cost	(66		)	316			(489		)	(29		)
Recognized net actuarial loss	1,660			603			868			169
Net periodic benefit cost	$	10,889		$	4,738		$	3,057		$	1,730

We made cash contributions to the pension plan of $32.2 million during the third quarter 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 September 30, 2006, based upon work completed, we have incurred $177.3 million (cumulative) in costs related to Hurricane Ivan damage. Our insurance providers have approved and reimbursed $147.0 million of these costs with the balance pending subsequent review and approval. We have incurred $47.0 million (cumulative) in costs related to Hurricane Katrina damage, $9.0 million of which has been approved and reimbursed by our insurance providers. During 2005, we were notified by one of our insurance providers that its maximum exposure limit for losses incurred during Hurricane Katrina had been reached and that, consequently, our final insurance recovery will be limited. As of September 30, 2006 we have recorded probable insurance claims of $70.4 million, the estimated remaining recovery for losses sustained from Hurricane Katrina. Total Hurricane Katrina costs for clean-up and redevelopment are currently estimated at approximately $170.0 million. We expect to complete clean-up work during 2007 and receive final reimbursements thereafter. There have been no significant changes in estimates for costs and insurance recoveries from 2005 year-end.

Hurricane Rita in 2005 caused minor damage to our Gulf of Mexico assets. As of September 30, 2006, based upon work completed, we have incurred $6.9 million (cumulative) in costs related to Hurricane Rita damage. We expect our insurance providers to approve and reimburse these costs subject to our $1.0 million deductible.

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

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

Probable insurance claims - current	$	101,018		$	142,311
Other assets (long-term portion of probable insurance claims)	52,481			112,800
Total Ivan, Katrina and Rita probable insurance claims	153,499			255,111

Asset retirement obligations - current	$	(90,012	)	$	(42,016	)
Asset retirement obligations - long-term	—			(121,800		)
Total asset retirement obligations related to Main Pass assets	(90,012		)	(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:

	Nine Months Ended
	September 30,
	2006
	(in thousands)

Asset retirement obligations, beginning of period	$	338,871
Liabilities incurred in current period	3,276
Liabilities transferred in sale of Gulf of Mexico shelf assets	(43,562		)
Liabilities settled in current period	(94,689		)
Revisions	11,957
Accretion expense	8,405
Asset retirement obligations, end of period	$	224,258

Current portion	$	93,619
Noncurrent portion	130,639

The ending aggregate carrying amount includes $90.0 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.

Note 9 - Equity Method Investments

Investments accounted for under the equity method consist primarily of the following:

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

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

Dividends and distributions received from equity method investees were $134.5 million and $46.6 million for the nine months ended September 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:

	September 30,		December 31,
	2006		2005
	(in thousands)
Equity method investments:
Atlantic Methanol Production Company, LLC	$	221,414	$	214,226
Alba Plant, LLC	162,306		195,109
Other	15,910		11,027
Total equity method investments	$	399,630	$	420,362

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

Balance Sheet Information

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

Current assets	$	193,379	$	274,484
Noncurrent assets	879,119		877,402
Current liabilities	81,266		119,912
Noncurrent liabilities	145,533		450,156

Statements of Operations Information

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)
Operating revenues	$	179,087	$	129,562	$	533,949	$	304,637
Gross margin	123,930		93,274		388,049		211,685
Net income	111,981		59,728		332,600		161,026

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 September 30:

Net income available to common shareholders	$	318,064		176,218	$	176,956	174,703
Basic EPS	$	1.80			$	1.01

Net income available to common shareholders	$	318,064		176,218	$	176,956	174,703
Plus: Incremental shares from assumed conversions
Dilutive stock options				3,198			3,879
Dilutive restricted stock				141			165
Dilutive rabbi trust shares	(708		)	1,520	—		—
Adjusted net income and shares	$	317,356		181,077	$	176,956	178,747
Diluted EPS	$	1.75			$	0.99

Nine Months Ended September 30:

Net income available to common shareholders	$	513,446		176,505	$	423,801	146,612
Basic EPS	$	2.91			$	2.89

Net income available to common shareholders	$	513,446		176,505	$	423,801	146,612
Plus: Incremental shares from assumed conversions
Dilutive stock options				3,508			2,422
Dilutive restricted stock				145			130
Dilutive rabbi trust shares	—			—	—		—
Adjusted net income and shares	$	513,446		180,158	$	423,801	149,164
Diluted EPS	$	2.85			$	2.84

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 September 30:
Stock option awards	827	$	44.96	—	$	—
Restricted stock	2			—
Noble shares held in rabbi trust	—			—
Total excluded from diluted EPS calculation	829			—

Nine Months Ended September 30:
Stock option awards	721	$	45.18	48	$	41.47
Restricted stock	19			—
Noble shares held in rabbi trust	1,266			—
Total excluded from diluted EPS calculation	2,006			48

Note 11 - Income Taxes

The income tax provision consists of the following:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)

Current	$	127,252	$	39,054	$	189,300	$	115,789
Deferred	99,650		25,126		146,709		100,433
Total income tax provision	$	226,902	$	64,180	$	336,009	$	216,222

During third quarter 2006, we increased the effective rate for the first nine months of 2006 due primarily to the nondeductible goodwill write-down allocated to the sale of the Gulf of Mexico shelf assets and the increase in the UK tax rate. The UK Finance Act of 2006, enacted on July 19, increased 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, we are currently forecasting that it will increase our income tax expense for the fiscal year 2006 by approximately $10 million.

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 $54.3 million during the nine months ended September 30, 2006 due to changes in the forecast of limitations on the ability to claim foreign tax credits.

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.

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

Revenues from third parties	$	707,509		$	406,173		$	85,498	$	26,082	$	30,451	$	159,305
Intersegment revenue	—			99,549			—		—		—		(99,549		)
Income from equity method investments	33,810			—			33,810		—		—		—
Total Revenues	741,319			505,722			119,308		26,082		30,451		59,756

DD&A	165,765			146,010			5,353		2,603		4,115		7,684
Gain on derivative instruments	(6,315		)	(6,315		)	—		—		—		—
Income (loss) before taxes	544,966			435,432			107,206		15,707		24,785		(38,164		)

Three Months Ended September 30, 2005

Revenues from third parties	$	609,259		$	296,461		$	91,495	$	33,262	$	19,377	$	168,664
Intersegment revenue	—			106,817			—		—		—		(106,817		)
Income from equity method investments	22,829			—			22,829		—		—		—
Total Revenues	632,088			403,278			114,324		33,262		19,377		61,847

DD&A	111,653			89,623			8,127		2,548		3,201		8,154
Gain on derivative instruments	(259		)	(259		)	—		—		—		—
Income (loss) before taxes	241,136			153,253			97,214		23,996		14,419		(47,746		)

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

Revenues from third parties	$	2,116,995	$	1,097,212	$	306,870	$	88,723	$	68,441	$	555,749
Intersegment revenue	—		372,656		—		—		—		(372,656		)
Income from equity method investments	108,901		—		108,901		—		—		—
Total Revenues	2,225,896		1,469,868		415,771		88,723		68,441		183,093

DD&A	458,878		402,033		15,674		5,933		10,367		24,871
Loss on derivative instruments	389,723		389,723		—		—		—		—
Income (loss) before taxes	849,455		484,655		373,490		59,250		52,851		(120,791		)

Nine Months Ended September 30, 2005

Revenues from third parties	$	1,424,476	$	592,769	$	216,824	$	93,820	$	49,407	$	471,656
Intersegment revenue	—		294,702		—		—		—		(294,702		)
Income from equity method investments	61,267		—		61,267		—		—		—
Total Revenues	1,485,743		887,471		278,091		93,820		49,407		176,954

DD&A	277,829		216,553		20,677		8,241		8,400		23,958
Loss on derivative instruments	2,121		2,121		—		—		—		—
Income (loss) before taxes	640,023		373,308		235,434		65,193		35,882		(69,794		)

Total assets at September 30, 2006 (1)	$	9,396,215	$	7,096,154	$	921,484	$	288,476	$	267,485	$	822,616
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 $783.2 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. In October, we received service in an additional lawsuit styled Wardell Family Partnership and Glen Droegemueller v. Noble Energy, Inc. et al, involving royalty and overriding royalty interest owners in the same field and not a member of the Holman class. The Plaintiffs seek to certify the lawsuit as a class action and allegations are made of a similar nature as the Holman lawsuit. We intend to timely file an answer and defend this lawsuit.

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.

	Nine Months Ended
	September 30, 2006
	(in thousands)

Capitalized exploratory well costs, beginning of period	$	35,228
Additions to capitalized exploratory well costs pending determination of proved reserves	64,669
Reclassified to property, plant and equipment based on determination of proved reserves	(15,073		)
Capitalized exploratory well costs charged to expense	(367		)
Capitalized exploratory well costs, end of period	$	84,457

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:

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

Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	84,457	$	35,228
Capitalized exploratory well costs that have been capitalized for a period greater than one year	—		—
Balance at end of period	$	84,457	$	35,228
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	—		—

Note 15 - Recently Issued Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued the following:

SFAS No. 157 – Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“SFAS 157”), establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. SFAS 157 is effective for fair value measures already required or permitted by other standards for fiscal years

beginning after November 15, 2007 and interim periods within those fiscal years. We are currently evaluating the provisions of SFAS 157 and assessing the impact it may have on our financial position and results of operations.

SFAS No. 158 – Statement of Financial Accounting Standard No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS 158”), requires employers to recognize on their balance sheet the funded status of pension and other postretirement benefits, measured as the difference between the fair value of the plan assets and the benefit obligation. Additionally, companies must recognize as a component of accumulated other comprehensive income, net of tax, actuarial gains and losses, prior service cost, and any remaining transition amounts that arise during the period but are not recognized as components of net periodic benefit cost. SFAS 158 is effective for fiscal years ending after December 15, 2006. Due to the provisions of SFAS 158, we expect to record an additional liability as of December 31, 2006. However, the amount of the additional liability will be determined as of the December 31, 2006 measurement date. In addition, we will recognize actuarial gains and losses, prior service cost, and any remaining transition amounts, with the offset to accumulated other comprehensive income.

FASB Staff Position No. AUG AIR-1 – FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities”, prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. We do not expect that adoption of the FASB Staff Position will have a significant impact on our financial position or results of operations.

Staff Accounting Bulletin No. 108 - In September 2006 the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 expresses the SEC staff’s views regarding the process of quantifying financial statement misstatements. The SEC staff believes registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The SEC staff will not object if a registrant records a one-time cumulative effect adjustment to correct errors existing in prior years that previously had been considered immaterial, quantitatively and qualitatively, based on appropriate use of the registrant’s approach. SAB 108 describes the circumstances where this would be appropriate as well as required disclosures to investors. SAB 108 is effective for fiscal years ending on or after November 15, 2006. We are currently assessing the impact of adoption of SAB 108 on our financial statements but do not expect that adoption will have a material effect on our financial position or 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.

Third quarter 2006 financial results included the following:

· net income of $318.1 million, an 80% increase over third quarter 2005;

· diluted income per share of $1.75, a 77% increase over third quarter 2005;

· cash flow from operating activities of $1.341 billion for the first nine months of 2006, a 39% increase over the first nine months of 2005;

· net reduction in long-term debt of $420 million, or 21%, during the third quarter 2006; and

· common stock repurchases of $168.9 million resulting from approval by the Board of Directors of a $500 million common stock repurchase program.

Third quarter 2006 significant operational highlights included the following:

· sale of Gulf of Mexico shelf assets with pretax cash proceeds of $487 million;

· a 9% increase in overall daily sales volumes from third quarter 2005, including a 21% domestic increase and an 8% international decrease; and

· an increase of 22% in the average realized crude oil price and a decrease of 5% in the average realized natural gas price from third quarter 2005.

Portfolio Enhancements — During the first nine months of 2006, we continued to enhance our portfolio with significant purchases and sales of assets.

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 allows us to focus future investments and growth in areas with higher potential. Pretax cash proceeds from the sale totaled $487 million including proceeds received from parties who exercised preferential rights to purchase certain properties. 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 $203.5 million from the sale is included in our results of operations for third quarter 2006.

On March 29, 2006, we purchased the common stock of U.S. Exploration, a privately held corporation, located in Billings, Montana, for $411.6 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.

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 third quarter 2006, we repurchased 3,569,200 shares of our common stock at an aggregate cost of $168.9 million. Year to date we have repurchased 4,156,800 shares of common stock at an aggregate cost of $192.6 million.

Adoption of SFAS 123(R) – We adopted SFAS 123(R) as of January 1, 2006. As a result, we recognized compensation expense of $9.3 million related to stock-based awards during the first nine months of 2006. This expense relates to stock-based awards made in 2006 and prior years that vest in 2006 and thereafter. As a result of this change in accounting method, our net income was reduced by $3.7 million, or $0.02 per diluted share, for the first nine months of 2006. In addition, $18.5 million of tax benefits related to option exercises were included in cash flows from financing activities rather than cash flows from operating activities. For the first nine months of 2005, tax benefits of $13.3 million were included in cash flows from operating activities.

OUTLOOK

We expect crude oil and natural gas production to increase for the full year 2006 compared to 2005. The expected year-over-year increase in production is due to 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;

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

· 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 $411.6 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 nine months of 2006, we reported net cash provided by operating activities of $1.341 billion as compared with $966.8 million for the first nine months of 2005, an increase of 39%. Factors contributing to the increase included:

· a $439 million increase in oil and gas sales due to higher sales volumes;

· a $265 million increase in oil and gas sales due to higher realized crude oil and natural gas prices;

· offset by a $131 million increase in total production costs (lease operating costs, production and ad valorem taxes and transportation expense), a $44 million increase in general and administrative expense and a $37 million increase in interest expense.

Factors contributing to net cash provided by operating activities for the first nine months of 2005 included:

· a $230 million increase in oil and gas sales from the previous year due to higher sales volumes; and

· a $254 million increase in oil and gas sales due to higher realized crude oil and natural gas prices;

· offset by a $74 million increase in total production costs.

Investing Activities – Net cash used in investing activities for the first nine months of 2006 totaled $827 million, as compared with $1.697 billion for the first nine months of 2005. Significant investing activities in 2006 to date included:

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

· $1.030 billion used for capital expenditures;

· partially offset by $504.3 million net proceeds from the sale of assets; and

· $116.5 million distributions received from equity method investees.

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

· $1.111 billion used for the Patina Merger; and

· $576.2 million used for capital expenditures.

Financing Activities – Net cash used in financing activities for the first nine months of 2006 totaled $534.3 million compared with net cash provided by financing activities of $674.4 million for the first nine months of 2005. Significant financing activities in 2006 to date included:

· $375 million net reduction in short-term and long-term borrowings;

· $35.8 million cash dividends paid on Noble Energy common stock;

· $192.6 million paid for repurchases of Noble Energy common stock; and

· offset by $50.6 million proceeds from the exercise of stock options.

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

· $625.5 million net proceeds from long-term borrowings;

· $63.8 million proceeds from exercise of stock options; and

· offset by $14.8 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:

	Nine Months Ended
	September 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	$	92,996	$	29,768
Dry hole (2)	24,164		77,494
Lease acquisition costs	52,117		11,964
Seismic (2)	23,619		9,886
Total exploration expenditures	192,896		129,112
Development drilling and completion	825,481		440,203
Corporate and other	15,948		16,791
Total exploration and development-related expenditures from consolidated operations	$	1,034,325	$	586,106
Investments in equity method investees	$	5,126	$	13,927

(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 $1.621 billion (net of unamortized discount) at September 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 28.9% at September 30, 2006 as compared with 39.7% at December 31, 2005.

Our principal source of liquidity is a $2.1 billion unsecured credit facility (the “Credit Facility”) due December 2010. The Credit Facility is available 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 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 to 17.5 basis points depending upon our credit rating. At September 30, 2006, $975 million in borrowings were outstanding under the Credit Facility. The weighted average interest rate applicable to borrowings under the Credit Facility at September 30, 2006 was 6.09%.

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 September 30, 2006, we had $35 million of short-term borrowings outstanding under uncommitted lines with interest payable at a weighted average rate of 5.71%.

Debt Repayments – During third quarter 2006, we prepaid the remaining $25 million of term loans due January 2009. We also reduced the credit facility during third quarter 2006 with net payments of $395 million. Additionally, we reduced short-term debt by $50 million during third quarter 2006.

Dividends – During 2006, we paid quarterly cash dividends of 5.0 cents per share of common stock during first quarter, 7.5 cents per share during second quarter, and 7.5 cents per share during third quarter. During 2005, we paid quarterly cash dividends of 2.5 cents per share of common stock during first quarter, 2.5 cents per share during second quarter, and 5.0 cents during third quarter. On October 24, 2006, our Board of Directors declared a quarterly cash dividend of 7.5 cents per common share, payable November 20, 2006, to shareholders of record on November 6, 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.

Pension Contributions – We made cash contributions to the defined benefit pension plan of $32.2 million during the third quarter 2006.

Exercise of Stock Options – We received $50.6 million from the exercise of stock options during the first nine months of 2006, as compared to $63.8 million during the first nine months of 2005.

RESULTS OF OPERATIONS

Natural Gas Information

Natural gas sales remained flat for third quarter 2006 compared with third quarter 2005. An increase in sales due to higher sales volumes was offset by a decrease in realized sales prices. Natural gas sales increased $260 million, or 40%, for the first nine months of 2006 over the first nine months of 2005. Approximately $220 million of the increase was due to higher sales volumes and $40 million was due to higher realized sales prices.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)

Natural gas sales	$	290,845	$	290,943	$	917,673	$	657,649

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

	Mcfpd	$/Mcf		Mcfpd	$/Mcf
	2006			2005
Three Months Ended September 30
United States (1)	430,072	$	6.41	413,789	$	6.95
West Africa (2)	40,498	0.39		63,193	0.40
North Sea	8,553	6.62		9,970	5.14
Israel	116,718	2.84		81,942	2.57
Ecuador (3)	20,131	—		24,466	—
Other International (4)	198	1.51		260	1.10
Total	616,170	$	5.30	593,620	$	5.56

Nine Months Ended September 30
United States (1)	461,843	$	6.55	317,976	$	6.80
West Africa (2)	44,232	0.38		60,320	0.25
North Sea	8,460	8.13		9,285	5.41
Israel	91,656	2.74		67,182	2.69
Ecuador (3)	22,764	—		21,772	—
Other International (4)	324	1.20		101	1.10
Total	629,279	$	5.54	476,636	$	5.30

(1) Reflects increases (reductions) of $0.07 per Mcf and $(0.77) per Mcf for third quarter 2006 and 2005, respectively, and $(0.47) per Mcf and $(0.32) per Mcf for the first nine 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 sold 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 $49.7 million and $55.0 million are included in other revenues for the first nine months of 2006 and 2005, respectively.

(4) Other international includes Argentina.

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, followed by reduced production levels caused by 35 days of compressor repairs; and

· increased demand from Israel Electric Corporation Limited, full nine 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 $102 million, or 35%, third quarter 2006 over third quarter 2005. Approximately $75 million of the increase was due to higher realized sales prices and $27 million of the increase was due to higher sales volumes. Crude oil revenues increased $444 million, or 65%, for the first nine months of 2006 over the first nine months of 2005. Approximately $225 million of the increase was due to higher realized sales prices and $219 million was due to higher sales volumes.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
	(in thousands)

Crude oil sales	$	392,699	$	290,642	$	1,126,983	$	683,114

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

	Bopd	$/Bbl		Bopd	$/Bbl
	2006			2005
Three Months Ended September 30
United States (1)	48,193	$	56.84	30,475	$	49.49
West Africa (2)	13,649	66.93		22,023	44.02
North Sea	3,292	68.90		5,198	59.71
Other international (3)	6,825	56.96		8,173	45.41
Total Consolidated Operations	71,959	59.32		65,869	47.96
Equity Investee (4)	8,932	48.88		3,859	41.04
Total	80,891	$	58.17	69,728	$	47.58

Nine Months Ended September 30
United States (1)	45,834	$	51.48	24,617	$	44.21
West Africa (2)	17,374	63.73		17,681	44.07
North Sea	3,619	70.79		5,630	52.11
Other international (3)	7,463	54.31		8,317	41.05
Total Consolidated Operations	74,290	55.57		56,245	44.49
Equity Investee (4)	8,168	46.96		2,376	40.18
Total	82,458	$	54.72	58,621	$	44.31

(1) Reflects reductions of $(10.46) per Bbl and $(10.88) per Bbl third quarter 2006 and 2005, respectively, and $(12.76) per Bbl and $(9.46) per Bbl for the first nine months of 2006 and 2005, respectively, from hedging activities.

(2) Production averaged 16,890 Bopd and 17,634 Bopd for the three and nine months ended September 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 $(14.95) per Bbl third quarter 2005 and $(8.22) per Bbl for the first nine 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 6,957 Bopd and 2,918 Bopd for third quarter 2006 and 2005, respectively, and 6,409 Bopd and 1,704 Bopd for the first nine months of 2006 and 2005, respectively.

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

· timing of liftings in Equatorial Guinea;

· 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 $43.8 million and $90.1 million for third quarter 2006 and 2005, respectively, and $219.0 million and $131.5 million for the first nine months of 2006 and 2005, respectively.

Equity Method Investees

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Net income (in thousands):
AMPCO, LLC and Affiliates	$	3,302	$	16,226	$	27,415	$	44,279
Alba Plant, LLC	30,508		6,603		81,486		16,989
Distributions/Dividends (in thousands):
AMPCO, LLC	—		16,856		19,500		46,556
Alba Plant, LLC	39,001		—		115,021		—
Sales volumes:
Methanol (Mgal)	18,769		46,133		85,233		122,256
Condensate (Bopd)	1,975		941		1,759		672
LPG (Bpd)	6,957		2,918		6,409		1,704
Average realized prices:
Methanol (per gallon)	$	0.83	$	0.75	$	0.83	$	0.78
Condensate (per Bbl)	69.46		57.41		67.51		53.16
LPG (per Bbl)	43.03		35.75		41.32		35.06

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 turnaround was followed by 35 days of compressor repairs which resulted in reduced methanol production levels. 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 plant.

Costs and Expenses

Production Costs — Total production costs were as follows:

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

Oil and gas operating costs	$	66,431	$	50,753	$	6,310	$	3,355	$	2,134	$	3,879
Workover and repair expense	10,497		10,453		—		—		—		44
Lease operating costs	76,928		61,206		6,310		3,355		2,134		3,923
Production and ad valorem taxes	30,697		22,636		—		—		—		8,061
Transportation expense	4,531		3,358		—		952		—		221
Total production costs	$	112,156	$	87,200	$	6,310	$	4,307	$	2,134	$	12,205

Three Months Ended September 30, 2005

Oil and gas operating costs	$	60,091	$	42,717	$	8,758	$	2,636	$	2,124	$	3,856
Workover and repair expense	3,342		3,105		—		237		—		—
Lease operating costs	63,433		45,822		8,758		2,873		2,124		3,856
Production and ad valorem taxes	24,304		22,316		—		—		—		1,988
Transportation expense	1,871		—		—		1,630		—		241
Total production costs	$	89,608	$	68,138	$	8,758	$	4,503	$	2,124	$	6,085

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

Oil and gas operating costs	$	195,550	$	147,357	$	21,760	$	7,998	$	6,389	$	12,046
Workover and repair expense	42,757		42,628		—		—		—		129
Lease operating costs	238,307		189,985		21,760		7,998		6,389		12,175
Production and ad valorem taxes	83,663		66,373		—		—		—		17,290
Transportation expense	18,463		14,022		—		3,843		—		598
Total production costs	$	340,433	$	270,380	$	21,760	$	11,841	$	6,389	$	30,063

Nine Months Ended September 30, 2005:

Oil and gas operating costs	$	138,006	$	92,076	$	19,567	$	8,763	$	6,124	$	11,476
Workover and repair expense	8,667		8,430		—		237		—		—
Lease operating costs	146,673		100,506		19,567		9,000		6,124		11,476
Production and ad valorem taxes	51,125		41,346		—		—		—		9,779
Transportation expense	12,091		6,706		—		4,728		—		657
Total production costs	$	209,889	$	148,558	$	19,567	$	13,728	$	6,124	$	21,912

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Oil and gas operating costs	$	4.14	$	3.96	$	4.00	$	3.73
Workover and repair expense	0.65		0.22		0.87		0.23
Lease operating costs	4.79		4.18		4.87		3.96
Production and ad valorem taxes	1.91		1.60		1.71		1.38
Transportation expense	0.28		0.12		0.38		0.33
Total production costs	$	6.98	$	5.90	$	6.96	$	5.67

Lease operating costs, excluding workover and repair expense, increased $6.3 million, or 11% for third quarter 2006 as compared with third quarter 2005. Lease operating costs, excluding workover and repair expense, increased $57.5 million, or 42%, for the first nine months of 2006 as compared with the first nine months of 2005. The increases reflect expenses associated with Lorien, Swordfish and Ticonderoga operations, as well as expenses associated with U.S. Exploration operations, offset by the effect of the sale of the Gulf of Mexico shelf properties. In general, the current high commodity price environment has led to higher service, contract labor and fuel costs. In addition, we are incurring higher insurance premiums than in 2005.

Workover and repair expense increased $7.2 million for the third quarter 2006, as compared with the third quarter 2005. The expense for third quarter 2006 reflects workover expense of $2.6 million associated with the Patina properties and $7.9 million associated with other North America properties. The expense includes $4.2 million ($0.26 per BOE) of hurricane-related repair expense. The expense for third quarter 2005 reflects workover expense of $0.9 million associated with the Patina properties and $2.2 million associated with other North America properties.

Workover and repair expense increased $34.1 million for the first nine months of 2006, as compared with the first nine months of 2005. The expense for the first nine months of 2006 includes workover expense of $7.6 million associated with the Patina properties and $35.1 million associated with other North America properties. The expense includes $25.6 million ($0.52 per BOE) of hurricane-related repair expense. The expense for the first nine months of 2005 includes workover expense of $1.9 million associated with the Patina properties and $6.6 million associated with other North America properties.

Production and ad valorem tax expense increased $6.4 million, or 26%, for third quarter 2006, as compared with third quarter 2005. The increase reflects additional production from Patina and U.S. Exploration properties as compared to 2005. Production and ad valorem tax expense increased $32.5 million, or 64%, for the first nine months of 2006, as compared with the first nine months of 2005. The increase reflects a full nine months of production from Patina operations and additional 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 total production costs per BOE, converting gas to oil on the basis of six Mcf per barrel, were $6.98 per BOE third quarter 2006 as compared with $5.90 per BOE third quarter 2005 and $6.96 per BOE for the first nine months of 2006 as compared with $5.67 per BOE for the first nine 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 $30.9 million for third quarter 2006 (including stock-based compensation expense of $0.3 million),

as compared with $77.3 million for third quarter 2005. The decrease in oil and gas exploration expense for the third quarter 2006 is due to a $48.8 million decrease in dry hole expense offset by a $1.9 million increase in seismic expense.

Oil and gas exploration expense was $92.3 million (including stock-based compensation expense of $0.8 million) for the first nine months of 2006, as compared with $126.5 million for the first nine months of 2005. The decrease is due to a $53.9 million decrease in dry hole expense, primarily in the Gulf Coast region and Gulf of Mexico deepwater, offset by a $13.7 million increase in seismic expense. See also Note 4 - “Stock-Based Compensation Expense”.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

Depreciation, depletion and amortization expense (in thousands)	$	165,765	$	111,653	$	458,878	$	277,829
Unit rate per BOE	$	10.32	$	7.36	$	9.38	$	7.50

The increase in the unit rate for the quarter and year-to-date was primarily due to the change in the mix of our sales volumes. In particular, Gulf of Mexico deepwater production carries a unit rate which is higher than the company average. As deepwater production has increased from 2,038 Boepd, or 1% of third quarter 2005 total consolidated sales volumes to approximately 29,019 Boepd, or 17% of total consolidated sales volumes in the third quarter of 2006, the unit rate has increased. During the first nine months of 2006, deepwater sales volumes averaged 24,215 Boepd, 14% of consolidated sales volumes, as compared to 3,143 Boepd, or 2% of total consolidated sales volumes during the first nine months of 2005. DD&A expense also includes abandoned assets expense of $0.7 million and $0.6 million for third quarter 2006 and 2005, respectively, and $1.2 million and $9.1 million for the first nine months of 2006 and 2005, respectively.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005

General and administrative expense (in thousands)	$	40,657	$	29,346	$	113,716	$	69,326
Unit rate per BOE	$	2.53	$	1.94	$	2.32	$	1.87

G&A expense increased third quarter 2006 over third quarter 2005 and for the first nine months of 2006 as compared with the first nine 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 stock-based compensation expense of $2.7 million (calculated under SFAS 123(R)) for third quarter 2006 and $1.4 million (calculated under APB 25) for third quarter 2005. G&A expense includes stock-based compensation expense of $8.5 million and $2.7 million for the first nine months of 2006 and 2005, respectively. See Note 4 - Stock-Based Compensation Expense.

Interest Expense and Capitalized Interest – Interest expense (net of interest capitalized) decreased $0.4 million to $28.6 million for third quarter 2006, as compared with $29.0 million for third quarter 2005. Capitalized interest was $1.2 million for third quarter 2006, compared with $2.4 million for third quarter 2005. Interest expense (net of interest capitalized) increased $36.6 million to $95.6 million for the first nine months of 2006, as compared with $59.0 million for the first nine months of 2005. Capitalized interest was $3.4 million for the first nine months of 2006, compared with $7.3 million for the first nine months of 2005. Interest expense (net of interest capitalized) increased due to additional 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 6.09% at September 30, 2006.

(Gain) Loss on Derivative Instruments – (Gain) loss on derivative instruments for the nine months ending September 30, 2006 includes the following:

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

· $25.4 million loss in first quarter 2006 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;

· cash flow hedge ineffectiveness (gains) losses of $(3.0) million and $(0.3) million for third quarter 2006 and 2005, respectively, and $8.4 million and $2.1 million for the first nine months of 2006 and 2005, respectively; and

· mark-to-market gain of $3.4 million in third quarter 2006.

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						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005

Income tax provision (in thousands)	$	226,902		$	64,180		$	336,009		$	216,222
Effective rate	41.6		%	26.6		%	39.6		%	33.8		%

The increase in the effective rate for the first nine months of 2006 is due primarily to the nondeductible goodwill write-down allocated to the sale of the Gulf of Mexico shelf assets and the increase in the UK tax rate.

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 $54.3 million during the first nine months of 2006 due to changes in the forecast of limitations on the ability to claim foreign tax credits.

The UK Finance Act of 2006, enacted on July 19, increased 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, we are currently forecasting that it will increase our income tax expense for the fiscal year 2006 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 September 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 September 30, 2006, we had a net liability related to crude oil and natural gas derivative instruments of approximately $659.3 million (pretax) on our consolidated balance sheets. A net unrealized loss of $165.8 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 September 30, 2006, we had $1.625 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 September 30, 2006, we had $975 million of long-term variable-rate debt and $35 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 September 30, 2006 debt balance would result in a pre-tax change in annual interest expense of approximately $6.1 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 at prevailing foreign exchange rates. 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, crude oil and natural gas 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 crude oil and natural gas. These price assumptions are used for planning purposes and for evaluating the carrying 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 crude oil and/or natural gas could have a material effect on the following:

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

· the quantities of crude oil and natural gas 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 crude oil and natural gas, 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 crude oil and natural gas, 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 crude oil and natural gas 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.

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;

· actions taken by foreign oil and gas producing nations, such as expropriation or nationalization of assets and 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.

Public officials in certain foreign countries, including Equatorial Guinea, have been quoted in recent publications as expressing an interest in increasing their country’s share of oil and gas revenues whether through renegotiating contracts, raising taxes or other methods. We strive to maintain good relations with all countries in which we conduct business, including the country of Equatorial Guinea.

Conflicts remain in the Middle East 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.

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 including hurricanes. 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 elect to or 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 have an adverse impact on 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, crude oil and natural gas marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers, many of whom have greater financial resources than ours.

Other. In our exploration operations, losses may occur before any accumulation of crude oil or natural gas is found. If crude oil or natural gas is discovered, no assurance can be given that sufficient reserves will be developed to enable us to recover the costs incurred in obtaining the reserves or that reserves will be developed at a sufficient rate to replace reserves currently being produced and sold.

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 (page 43) and International operations (page 42) 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 third 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)
06/30/06					$	476,330
07/01/06 - 07/31/06	1,068,200	$	47.62	1,068,200	(50,864		)
08/01/06 - 08/31/06	1,108,500	49.58		1,108,500	(54,960		)
09/01/06 - 09/30/06	1,392,500	45.28		1,392,500	(63,055		)
Total	3,569,200	$	47.32	3,569,200	$	307,451

(1) By October 25, 2006, we had repurchased an additional 1,394,700 shares of common stock at an aggregate cost of approximately $64.4 million.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

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	November 3, 2006	/s/ CHRIS TONG
		CHRIS TONG
		Senior Vice President and Chief Financial Officer

INDEX TO EXHIBITS

Exhibit
Number		Exhibit

10.1		Noble Energy, Inc. Change of Control Severance Plan for Executives (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: October 24, 2006) filed October 30, 2006 and incorporated herein by reference)

12.1		Computation of ratio of earnings to fixed charges.

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

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

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

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURESABOUT MARKET RISK

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK