UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to          

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

(281) 872-3100

(Registrant’s telephone number, including area code)

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

Yes  ý  No  o

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

Yes  ý  No  o

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

Yes  o  No  ý

Number of shares of common stock outstanding as of October 31, 2005: 174,942,995

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,
	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	123,736		$	179,794
Accounts receivable - trade, net	534,761			407,349
Derivative instruments	70,362			28,733
Materials and supplies inventories	36,390			12,109
Deferred taxes	290,104			13,039
Prepaid expenses and other	47,457			28,278
Probable insurance claims	85,200			65,000
Total current assets	1,188,010			734,302
Property, Plant and Equipment, at Cost
Oil and gas mineral interests, equipment and facilities (successful efforts method of accounting)	8,333,104			4,292,561
Other	67,469			56,707
	8,400,573			4,349,268
Accumulated depreciation, depletion and amortization	(2,211,156		)	(2,016,318		)
Total property, plant and equipment, net	6,189,417			2,332,950
Investment in Unconsolidated Subsidiaries	229,991			231,795
Other Assets	189,420			144,124
Goodwill	898,241			—
Total Assets	$	8,695,079		$	3,443,171
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable - trade	$	532,870		$	431,521
Derivative instruments	656,960			50,304
Interest payable	19,160			11,439
Income taxes	61,904			64,852
Asset retirement obligations	59,413			79,568
Accrued and other current liabilities	113,400			27,320
Total current liabilities	1,443,707			665,004
Deferred Income Taxes	1,124,855			183,351
Asset Retirement Obligations	223,963			175,415
Derivative Instruments	767,927			9,678
Deferred Compensation Liability	154,204			10,224
Other Deferred Credits and Noncurrent Liabilities	94,682			59,255
Long-Term Debt	2,116,797			880,256
Total Liabilities	5,926,135			1,983,183
Commitments and Contingencies
Shareholders’ Equity:
Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued	—			—
Common stock - par value $3.33 1/3; 250,000,000 shares authorized; 184,449,809 and 125,144,834 shares issued, respectively	614,830			417,152
Capital in excess of par value	1,941,010			291,458
Deferred compensation	(6,796		)	(1,671		)
Accumulated other comprehensive loss	(884,429		)	(14,787		)
Treasury stock, at cost: 9,268,932 and 7,099,952 shares, respectively	(148,476		)	(75,956		)
Retained earnings	1,252,805			843,792
Total Shareholders’ Equity	2,768,944			1,459,988
Total Liabilities and Shareholders’ Equity	$	8,695,079		$	3,443,171

See notes to consolidated financial statements.

2

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Revenues:
Oil and gas sales and royalties	$	601,269		$	288,499		$	1,371,930		$	855,351
Gathering, marketing and processing	8,831			10,175			28,735			37,295
Electricity sales	18,843			7,504			54,978			38,369
Income from investment in unconsolidated subsidiaries	16,226			13,585			44,279			43,953
Total Revenues	645,169			319,763			1,499,922			974,968
Costs and Expenses:
Oil and gas operations	64,775			36,449			151,183			112,575
Production and ad valorem taxes	24,304			7,193			51,125			20,458
Transportation	8,357			3,718			18,577			14,284
Oil and gas exploration	77,253			26,588			126,508			82,100
Gathering, marketing and processing	5,856			8,642			20,905			29,992
Electricity generation	16,746			8,600			37,637			32,034
Depreciation, depletion and amortization	113,835			75,040			281,041			233,365
Impairment of operating assets	5,198			—			5,198			—
Selling, general and administrative	29,346			13,326			69,326			41,518
Accretion of discount on asset retirement obligations	2,928			2,067			8,137			7,080
Interest	31,438			17,961			66,327			48,973
Interest capitalized	(2,393		)	(3,013		)	(11,340		)	(9,655		)
Deferred compensation adjustment	21,429			—			31,307			—
Loss on involuntary conversion of assets	1,000			1,000			1,000			1,000
Other expense (income), net	890			(6,399		)	(1,046		)	(12,178		)
Total Costs and Expenses	400,962			191,172			855,885			601,546
Income Before Taxes	244,207			128,591			644,037			373,422
Income Tax Provision	67,251			47,620			220,236			146,511
Income From Continuing Operations	176,956			80,971			423,801			226,911
Discontinued Operations, Net of Tax	—			2,721			—			14,354
Net Income	$	176,956		$	83,692		$	423,801		$	241,265
Earnings Per Share:
Basic -
Income from continuing operations	$	1.01		$	0.69		$	2.89		$	1.95
Discontinued operations, net of tax	—			0.03			—			0.13
Net Income	$	1.01		$	0.72		$	2.89		$	2.08
Diluted -
Income from continuing operations	$	0.99		$	0.68		$	2.84		$	1.92
Discontinued operations, net of tax	—			0.02			—			0.12
Net Income	$	0.99		$	0.70		$	2.84		$	2.04
Weighted average number of shares outstanding - Basic	174,703			116,906			146,612			116,136
Weighted average number of shares outstanding - Diluted	178,747			118,974			149,164			118,004

See notes to consolidated financial statements.

3

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(In Thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Comprehensive Income/(Loss):
Net income	$	176,956		$	83,692		$	423,801		$	241,265
Other comprehensive income/(loss), net of tax:
Unrealized loss on cash flow hedges:
Oil and gas cash flow hedges (1)	(466,073		)	(39,472		)	(955,837		)	(58,358		)
Interest rate lock cash flow hedge (2)	—			—			—			(2,417		)
Less: reclassification adjustment for amounts out of OCI:
Oil and gas cash flow hedges (3)	58,542			11,692			85,476			22,854
Interest rate lock cash flow hedge (4)	123			123			369			225
	(407,408		)	(27,657		)	(869,992		)	(37,696		)
Change in additional minimum pension liability and other (5)	242			999			350			165
Other comprehensive income/(loss)	(407,166		)	(26,658		)	(869,642		)	(37,531		)
Comprehensive income/(loss)	$	(230,210	)	$	57,034		$	(445,841	)	$	203,734
(1) Net of income tax benefit	$	250,962		$	21,254		$	514,682		$	31,424
(2) Net of income tax benefit	$	—		$	—		$	—		$	1,301
(3) Net of income tax provision	$	(31,523	)	$	(6,296	)	$	(46,026	)	$	(12,306	)
(4) Net of income tax provision	$	(66	)	$	(66	)	$	(199	)	$	(121	)
(5) Net of income tax provision	$	(130	)	$	(538	)	$	(188	)	$	(89	)

See notes to consolidated financial statements.

4

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In Thousands)

						Deferred			Accumulated
			Capital in			Compensation -			Other			Treasury						Total
	Common		Excess of			Restricted			Comprehensive			Stock			Retained			Shareholders’
	Stock		Par Value			Stock			Income (Loss)			at Cost			Earnings			Equity
January 1, 2005	$	417,152	$	291,458		$	(1,671	)	$	(14,787	)	$	(75,956	)	$	843,792		$	1,459,988
Patina Merger	185,568		1,576,799			—			—			(73,203		)	—			1,689,164
Exercise of stock options	11,544		52,222			—			—			—			—			63,766
Tax benefits related to exercise of stock options	—		13,346			—			—			—			—			13,346
Cash dividends ($.10 per share)	—		—			—			—			—			(14,788		)	(14,788		)
Issuance of restricted stock	566		7,301			(7,867		)	—			—			—			—
Amortization of restricted stock	—		—			2,742			—			—			—			2,742
Rabbi trust shares sold	—		90			—			—			683			—			773
Stock issuance costs	—		(206		)	—			—			—			—			(206		)
Net income	—		—			—			—			—			423,801			423,801
Other comprehensive income (loss):
Unrealized loss on cash flow hedges	—		—			—			(955,837		)	—			—			(955,837		)
Reclassified to net income	—		—			—			85,845			—			—			85,845
Change in additional minimum pension liability and other	—		—			—			350			—			—			350
September 30, 2005	$	614,830	$	1,941,010		$	(6,796	)	$	(884,429	)	$	(148,476	)	$	1,252,805		$	2,768,944
January 1, 2004	$	404,960	$	228,728		$	—		$	(10,886	)	$	(75,956	)	$	526,728		$	1,073,574
Exercise of stock options	10,360		43,187			—			—			—			—			53,547
Tax benefits related to exercise of stock options	—		9,819			—			—			—			—			9,819
Cash dividends ($.075 per share)	—		—			—			—			—			(8,705		)	(8,705		)
Net income	—		—			—			—			—			241,265			241,265
Other comprehensive income (loss):
Unrealized loss on cash flow hedges	—		—			—			(60,775		)	—			—			(60,775		)
Reclassified to net income	—		—			—			23,079			—			—			23,079
Change in additional minimum pension liability and other	—		—			—			165			—			—			165
September 30, 2004	$	415,320	$	281,734		$	—		$	(48,417	)	$	(75,956	)	$	759,288		$	1,331,969

See notes to consolidated financial statements.

5

NOBLE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended September 30,
	2005			2004
Cash Flows from Operating Activities:
Net income	$	423,801		$	241,265
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	281,041			233,365
Depreciation, depletion and amortization - electricity generation	12,395			15,361
Dry hole expense	77,494			37,546
Impairment of operating assets	5,198			—
Amortization of unproved leasehold costs	12,766			15,406
Non-cash effect of discontinued operations	—			(14,179		)
Gain on disposal of assets	(5,415		)	(8,291		)
Deferred income taxes	100,433			44,446
Accretion of discount on asset retirement obligations	8,137			7,080
Income from investment in unconsolidated subsidiaries	(44,279		)	(43,953		)
Dividends received from unconsolidated subsidiary	42,975			46,125
Deferred compensation adjustment	31,307			—
Loss on involuntary conversion of assets	1,000			1,000
Increase (decrease) in noncurrent liabilities	7,349			(5,414		)
Other	16,017			847
Changes in operating assets and liabilities, net of effect of acquisition:
(Increase) decrease in accounts receivable	(36,204		)	11,700
Increase in other current assets	(84,177		)	(67,107		)
Increase (decrease) in accounts payable	30,527			(38,099		)
Increase in other current liabilities	44,189			46,916
Net Cash Provided by Operating Activities	924,554			524,014
Cash Flows From Investing Activities:
Capital expenditures	(590,147		)	(457,044		)
Patina acquisition, net of cash acquired	(1,111,099		)	—
Proceeds from sale of property, plant and equipment	320			36,160
Insurance recovery - involuntary conversion	42,287			—
Distribution from unconsolidated subsidiaries	3,581			3,432
Net Cash Used in Investing Activities	(1,655,058		)	(417,452		)
Cash Flows From Financing Activities:
Exercise of stock options	63,766			53,547
Cash dividends paid	(14,788		)	(8,705		)
Proceeds from credit facilities	2,010,000			205,000
Repayment of credit facilities	(773,667		)	(449,822		)
Repayment of Patina debt	(610,865		)	—
Issuance of long-term debt	—			197,688
Proceeds from term loans	—			150,000
Repayment of notes	—			(156,545		)
Net Cash Provided by (Used in) Financing Activities	674,446			(8,837		)
(Decrease) Increase in Cash and Cash Equivalents	(56,058		)	97,725
Cash and Cash Equivalents at Beginning of Period	179,794			62,374
Cash and Cash Equivalents at End of Period	$	123,736		$	160,099

See notes to consolidated financial statements.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Organization and Nature of Operations

Noble Energy, Inc. (“Noble Energy” or the “Company”), a Delaware corporation, is an independent energy company that, directly or through its subsidiaries or various arrangements with other companies, explores for, develops and produces crude oil and natural gas. Exploration activities include geophysical and geological evaluation and exploratory drilling on properties for which the Company has exploration rights. Noble Energy has exploration, exploitation and production operations domestically and internationally. The domestic areas consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana and Texas); the Mid-continent Region (Illinois, Oklahoma and Kansas); and the Rocky Mountain Region (Colorado, Montana, Nevada, New Mexico and Wyoming). The international areas of operations include Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea (Israel), and the North Sea (the Netherlands and the United Kingdom).

On May 16, 2005, Noble Energy completed a merger (the “Patina Merger”) with Patina Oil & Gas Corporation (“Patina”), as set forth in the Agreement and Plan of Merger, dated as of December 15, 2004, as amended. 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 Denver-Julesburg Basin, the Mid-continent region of western Oklahoma and the Texas Panhandle, and the San Juan Basin in New Mexico. See Note 3 – Merger with Patina Oil & Gas Corporation.

Note 2 – Basis of Presentation

Presentation –The consolidated financial statements of Noble Energy included herein have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and, accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. In the opinion of Noble Energy, the accompanying unaudited consolidated financial statements as of September 30, 2005 and December 31, 2004 and for the three and nine months ended September 30, 2005 and 2004 contain all adjustments, consisting only of necessary and normal recurring adjustments, necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for such periods. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2004.

In accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations” (“SFAS No. 141”), Noble Energy has accounted for the Patina Merger as a purchase of Patina by Noble Energy.  As a result, the consolidated balance sheet of Noble Energy at September 30, 2005 includes the assets and liabilities of Patina. The consolidated statements of operations and statements of cash flows include financial results of Patina after May 16, 2005. See Note 3 – Merger with Patina Oil & Gas Corporation.

Common Stock Split – On August 17, 2005, Noble Energy’s Board of Directors approved a two-for-one split of its common stock that was effected in the form of a stock dividend. The stock dividend was distributed on September 14, 2005 to shareholders of record as of August 31, 2005. All share and per share data except par value have been adjusted to reflect the effect of the stock split for all periods presented.

Employee Stock-Based Compensation –The Company currently accounts for employee stock-based compensation plans under the recognition and measurement principles of the Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. In connection with the Patina Merger, the Company assumed outstanding, fully-vested options to purchase 7.8 million shares of Noble Energy common stock at a weighted-average exercise price of $17.93 per share.

7

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in thousands, except per share amounts)
Net income, as reported	$	176,956		$	83,692		$	423,801		$	241,265
Add: Stock-based compensation cost recognized, net of related tax effects	914			212			1,713			434
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2,380		)	(2,062		)	(6,346		)	(6,042		)
Pro forma net income	$	175,490		$	81,842		$	419,168		$	235,657
Earnings per share:
Basic - as reported	$	1.01		$	0.72		$	2.89		$	2.08
Basic - pro forma	$	1.00		$	0.70		$	2.86		$	2.03
Diluted - as reported	$	0.99		$	0.70		$	2.84		$	2.04
Diluted - pro forma	$	0.98		$	0.69		$	2.81		$	2.00

Allowance for Doubtful Accounts – The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility and accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. The allowance was increased by $6.1 million during third quarter 2005 and $7.4 million during the first nine months of 2005 to reflect additional collection allowances related to Ecuador power operations.

Impairment of Operating Assets – The Company recorded $5.2 million of impairments in 2005, primarily related to downward reserve revisions on three domestic properties. No impairments were recorded during the first nine months of 2004.

Note 3 – Merger with Patina Oil & Gas Corporation

On May 16, 2005, Noble Energy completed the Patina Merger and the results of operations of Patina’s operations since this date are included in the Company’s consolidated statements of operations. In connection with the merger, Noble Energy issued 55.7 million shares of its common stock and paid $1.1 billion in cash to Patina shareholders. In addition, the Company repaid $610.9 million of Patina debt, including accrued interest, outstanding at the merger date. The common stock exchanged in the merger was valued at $29.77 per share based on the volume-weighted average prices of Noble Energy common stock during the five business days commencing two days before the terms of the merger were agreed to and announced. In addition, 7.8 million stock options held by Patina employees were converted into options for Noble Energy stock. The fair value of the vested options was $104.9 million, estimated using the Black-Scholes option-pricing model. The Company financed the cash consideration paid in the merger and the repayment of Patina debt through borrowings on its credit facilities, including a new $1.3 billion credit facility. See Note 4 – Debt. (The above amounts related to the number of shares issued, the value per share and the number of stock options issued have been adjusted for Noble Energy’s two-for-one stock split in third quarter 2005.)

The Company considered the following strategic benefits of the merger, among others, in determining its offering price for the Patina net assets, which resulted in the recognition of goodwill:

•The merger establishes new core areas for Noble Energy in the Rocky Mountain and Mid-continent regions;

•The merger increases Noble Energy’s proved reserves and production and lengthens Noble Energy’s domestic reserve life;

•Patina’s long-lived oil and gas reserves provide a significant inventory of low-risk opportunities that will balance Noble Energy’s existing portfolio;

8

•Noble Energy expects to benefit from Patina’s extensive tight gas sands technological and operational expertise that it gained in connection with the development of its Wattenberg field, particularly with respect to the development of Noble Energy’s existing Rocky Mountain assets; and

•The combined company is significantly larger than Noble Energy was prior to the merger and, as a result, should have greater exploration and production strengths, greater liquidity in the market for its securities and additional future strategic opportunities that might not otherwise be possible.

Allocation of Purchase Price –The following table represents the preliminary allocation of the total purchase price of Patina to the assets acquired and the liabilities assumed based on the fair values at the merger date. Certain data necessary to complete the Company’s final purchase price allocation is not yet available, and includes, but is not limited to,  valuation of pre-acquisition contingencies (See Note 15 – Commitments and Contingencies), final tax returns that provide the underlying tax bases of Patina’s assets and liabilities at May 16, 2005, and final appraisals of assets acquired and liabilities assumed. The Company expects to complete its 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.

The following table sets forth Noble Energy’s preliminary purchase price allocation:

	(in thousands,
	except
	stock price)
Shares of Noble Energy common stock issued to Patina shareholders	55,670
Average Noble Energy common stock price	$	29.77
Fair value of common stock issued	$	1,657,491
Cash consideration paid to Patina shareholders	1,098,078
Plus: fair value of Patina employee stock options	104,876
Plus: Noble Energy merger costs	13,347
Total purchase price	2,873,792
Plus: liabilities assumed by Noble Energy
Current liabilities, excluding warrant obligation	88,096
Warrant obligation	16,840
Fair value of long-term debt, net of cash acquired	610,539
Deferred compensation liability (See Note 6 - Employee Benefit Plans)	108,972
Asset retirement obligations	36,004
Other non-current liabilities	31,780
Deferred income taxes	1,111,534
Total purchase price plus liabilities assumed	$	4,877,557
Fair value of Patina assets:
Current assets	$	184,871
Proved oil and gas properties	2,642,000
Unproved oil and gas properties	1,024,000
Other non-current assets	46,532
Treasury stock held in deferred compensation plan (See Note 6 - Employee Benefit Plans)	73,203
Goodwill	906,951
Total fair value of Patina assets	$	4,877,557

Deferred Income Taxes – The amount allocated to deferred income taxes results from differences between the assigned values and the tax bases of the assets acquired and liabilities assumed in accordance with SFAS No. 109, “Accounting for Income Taxes.”The Company is reviewing the historical deferred tax balances as well as the adjustment for the difference in book and tax basis for the fair value of the assets. Any adjustments, if necessary, will be reflected as a purchase price adjustment.

9

Goodwill –The preliminary allocation of purchase price included approximately $907.0 million of goodwill. The significant factors that contributed to the recognition of goodwill include, but are not limited to, economies of scale in connection with the Company’s existing domestic operations, and the ability to acquire an established business with an assembled workforce with technological and operational expertise in tight gas sand formations. The goodwill was assigned to the Company’s domestic reporting unit. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”, goodwill is not amortized to earnings but is tested, at least annually, for impairment at the reporting unit level. Other events and changes in circumstances, such as a sale of domestic properties, may also require goodwill to be tested for impairment between annual measurement dates. If the carrying value of goodwill is determined to be impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired. The Company does not expect the goodwill to be deductible for income tax purposes.

In accordance with Emerging Issues Task Force (“EITF”) Abstract Issue No. 00-23,  “Issues Related to the Accounting for Stock Compensation under APB Opinion No. 25 and FASB Interpretation No. 44”, the Company has reduced the amount of goodwill originally recorded by $8.7 million for tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the Patina Merger to the extent that the stock-based compensation expense reported for tax purposes did not exceed the fair value of the awards recognized as part of the total purchase price.

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 following pro forma condensed combined financial information for the nine months ended September 30, 2004 was derived from the historical financial statements of Noble Energy and Patina giving effect to the Patina Merger as if it had occurred on January 1, 2004. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have occurred had the merger taken place as of the dates indicated and is not intended to be a projection of future results.

	Nine Months Ended September 30,
	2005		2004
	(in thousands, except per share amounts)
Revenues	$	1,747,876	$	1,380,683
Income from continuing operations	$	471,173	$	284,194
Net income	$	471,173	$	298,548
Earnings per share:
Basic -	$	2.74	$	1.77
Diluted -	$	2.71	$	1.71

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Note 4 – Debt

Noble Energy incurred approximately $1.7 billion of indebtedness in the Patina Merger, primarily to fund the cash consideration, repay Patina’s debt, and fund merger costs. In connection with the merger, the Company entered into a new $1.3 billion credit facility with certain financial institutions. The new facility is a reducing revolver due 2010 with a 5% per quarter commitment reduction in each quarter during year four of the facility and a 20% per quarter commitment reduction in each quarter during year five of the facility. The facility incurred a 7.5 basis point standby commitment fee, totaling $0.1 million, from the effective date, April 4, 2005, until the initial borrowing date under the facility, May 16, 2005. Commencing on May 16, 2005, the Company incurs a facility fee of 10 to 25 basis points per annum (15 basis points at September 30, 2005) depending upon the Company’s credit rating. The facility bears interest based upon a Eurodollar rate plus 30 to 100 basis points (60 basis points at September 30, 2005) depending upon the Company’s credit rating. Financial covenants on the new facility are similar to those for the Company’s currently outstanding debt. In addition, the commitment will be reduced by the net proceeds from certain issuances of debt by the Company and by the amount of proceeds from certain asset sales. The facility was used to fund the merger with Patina and remains available to refinance existing indebtedness of the Company and for general corporate purposes. The Company incurred debt issuance costs of $2.4 million in connection with the new credit facility. These costs will be amortized to expense over the life of the credit facility.

A summary of the Company’s debt follows:

	September 30, 2005				December 31, 2004
				Interest				Interest
	Debt			Rate	Debt			Rate
	(in thousands)			(%)	(in thousands)			(%)
$1.3 billion Credit Agreement, due April 2010	$	921,333		4.39	$	—		—
$400 million Credit Agreement, due October 2009	400,000			4.28	85,000			2.86
$400 million Credit Agreement, due November 2006	—			—	—			—
5 1/4% Senior Notes, due 2014	200,000			5.25	200,000			5.25
7 1/4% Notes, due 2023	100,000			7.25	100,000			7.25
8% Senior Notes, due 2027	250,000			8.00	250,000			8.00
7 1/4% Senior Debentures, due 2097	100,000			7.25	100,000			7.25
Term Loans, due January 2009	150,000			4.85	150,000			3.00
Outstanding debt	2,121,333				885,000
Unamortized discount	(4,536		)		(4,744		)
Long-term debt	$	2,116,797			$	880,256

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Note 5 – Derivative Instruments and Hedging Activities

Cash Flow Hedges – The Company from time to time uses various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such instruments include fixed price hedges, variable to fixed price swaps, costless collars and other contractual arrangements. Although these derivative instruments expose the Company to credit risk, the Company takes reasonable steps to protect itself from nonperformance by its counterparties and periodically assesses necessary provisions for bad debt allowance. However, the Company is not able to predict sudden changes in its counterparties’ creditworthiness.

The Company accounts for its derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, and has elected to designate its derivative instruments as cash flow hedges. Derivative instruments designated as cash flow hedges are reflected at fair value on the Company’s consolidated balance sheets. Changes in fair value, to the extent the hedge is effective, are reported in accumulated other comprehensive income/(loss) until the forecasted transaction occurs. Gains and losses from such derivative instruments related to the Company’s crude oil and natural gas production and which qualify for hedge accounting treatment are recorded in oil and gas sales and royalties on the Company’s consolidated statements of operations upon sale of the associated products. Hedge effectiveness is assessed quarterly based on total changes in the derivative’s fair value. Any ineffective portion of the derivative instrument’s change in fair value is recognized immediately in other expense (income), net.

The Company’s derivative instrument activity related to its natural gas and crude oil production was as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
Natural Gas Collars:
Hedge MMBTUpd	75,000			120,000		81,593			120,379
Floor price range	$	5.00		$4.00 - $4.25		$5.00 - $5.75			$3.75 - $5.00
Ceiling price range	$7.20 - $7.80			$5.60 - $6.20		$7.20 - $9.50			$5.16 - $9.65
Percent of daily production	13		%	32	%	17		%	33	%
Crude Oil Collars:
Hedge Bpd	20,745			15,000		20,594			15,006
Floor price range	$31.00 - $32.50			$24.00 - $27.00		$29.00 - $37.50			$24.00 - $27.00
Ceiling price range	$37.65 - $52.80			$30.20 - $31.70		$37.25 - $56.50			$30.20 - $32.65
Percent of daily production	30		%	35	%	35		%	33	%
Natural Gas Swaps:
Hedge MMBTUpd	130,000			—		72,857			—
Average price per MMBTU	$	6.66		—		$	6.62		—
Percent of daily production	22		%	—		15		%	—
Crude Oil Swaps:
Hedge Bpd	13,100			—		7,342			—
Average price per Bbl	$	39.71		—		$	39.87		—
Percent of daily production	19		%	—		13		%	—

For third quarter 2005 and 2004, oil and gas sales and royalties included losses related to cash flow hedges of $90.1 million and $18.0 million, respectively. Ineffectiveness (income) totaled $(0.3) million and $(3.7) million, respectively.

For the first nine months of 2005 and 2004, oil and gas sales and royalties included losses related to cash flow hedges of $131.5 million and $35.2 million, respectively. Ineffectiveness loss totaled  $2.1 million and $0.8 million, respectively.

12

As of September 30, 2005, the Company had entered into future costless collar transactions related to its natural gas and crude oil production to support the Company’s investment program as follows:

	Natural Gas					Crude Oil
		Average price per MMBTU					Average price per Bbl
Production Period	MMBTUpd	Floor		Ceiling		Bopd	Floor		Ceiling
October - December 2005	75,000	$	5.00	$	7.66	20,295	$	31.12	$	43.99
2006	3,699	$	5.00	$	8.00	1,865	$	29.00	$	34.93

As of September 30, 2005, the Company had entered into future fixed price swap transactions related to its natural gas and crude oil production to support the Company’s investment program as follows:

	Natural Gas			Crude Oil
		Average Price			Average price
Production Period	MMBTUpd	per MMBTU		Bopd	per Bbl
October - December 2005	130,000	$	7.00	13,100	$	39.19
2006	170,000	$	6.49	16,600	$	40.47
2007	170,000	$	6.04	17,100	$	39.19
2008	170,000	$	5.67	16,500	$	38.23

If commodity prices were to stay the same as they were at September 30, 2005, approximately $382.5 million of deferred losses, net of taxes, related to the fair values of the Company’s derivative instruments included in accumulated other comprehensive loss at September 30, 2005 would be reversed during the next twelve months as the forecasted transactions occur, and settlements would be recorded as a reduction in oil and gas sales and royalties. All forecasted transactions currently being hedged are expected to occur by December 31, 2008.

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

	September 30, 2005			December 31, 2004
	(in thousands)
Derivative instruments (current asset)	$	70,362		$	28,733
Derivative instruments (long-term asset)	$	3,860		$	20,427
Derivative instruments (current liability)	$	(656,960	)	$	(50,304	)
Derivative instruments (long-term liability)	$	(767,927	)	$	(9,678	)

The increase in derivative liability balances reflects record high crude oil and natural gas prices.

Other Derivative Instruments – Noble Energy from time to time employs various derivative instruments in connection with its purchases and sales of third-party production to lock in profits or limit exposure to natural gas price risk. Most of the purchases made by the Company are on an index basis; however, purchasers in the markets in which the Company sells often require fixed or NYMEX-related pricing. The Company may use a derivative instrument to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility.

The Company records gains and losses on these derivative instruments using mark-to-market accounting. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The Company recorded gains of $0.1 million and $20,000 for the nine months ended September 30, 2005 and 2004, respectively, and gains of $0.8 million and $0.2 million for third quarter 2005 and 2004, respectively, related to derivative instruments not accounted for as cash flow hedges.

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Note 6 – Employee Benefit Plans

Defined Benefit Pension Plan – The Company has a non-contributory defined benefit pension plan covering certain domestic employees. The Company also sponsors an unfunded restoration plan, as well as other plans that provide for health care and life insurance benefits for its employees and retirees. The following table reflects the components of net periodic benefit cost recognized by the Company related to pension and other postretirement benefit plans.

Three Months Ended September 30:

	Pension Benefits						Other Benefits
	2005			2004			2005			2004
	(in thousands)
Service cost	$	1,302		$	1,408		$	185		$	181
Interest cost	1,664			1,559			292			273
Expected return on plan assets	(1,748		)	(1,666		)	—			—
Transition obligation recognition	(54		)	(54		)	60			60
Amortization of prior service cost	113			102			(3		)	(11		)
Recognized net actuarial loss	204			95			57			51
Net periodic benefit cost	$	1,481		$	1,444		$	591		$	554

Nine Months Ended September 30:

	Pension Benefits						Other Benefits
	2005			2004			2005			2004
	(in thousands)
Service cost	$	4,331		$	4,133		$	554		$	527
Interest cost	4,995			4,654			856			816
Expected return on plan assets	(5,346		)	(5,078		)	—			—
Transition obligation recognition	(161		)	(162		)	180			180
Amortization of prior service cost	316			302			(29		)	(40		)
Recognized net actuarial loss	603			261			169			153
Net periodic benefit cost	$	4,738		$	4,110		$	1,730		$	1,636

The Company contributed cash of $12.3 million to its pension plans during the first nine months of 2005.

Deferred Compensation Plan – In connection with the Patina Merger, the Company acquired the assets and assumed the liabilities related to a Patina shareholder-approved deferred compensation plan. This plan was available to officers and certain managers of Patina and allowed participants to defer all or a portion of their salary and annual bonuses (either in cash or common stock). The assets are invested in instruments as directed by the participants and held in a rabbi trust and, therefore, may be available to satisfy the claims of the Company’s creditors in the event of bankruptcy or insolvency. Participants have the ability to direct the plan administrator to invest their salary and bonus deferrals into pre-approved mutual funds held by the rabbi trust. In addition, participants have the right to request that the plan administrator re-allocate the portfolio of investments (i.e., cash, mutual funds, common stock) in the participants’ individual accounts within the rabbi trust. However, the plan administrator is not required to honor such requests. Participants may elect to receive distributions in either cash or common stock. At the date of the merger, the shares of Patina common stock held in the rabbi trust were allocated 87% in Noble Energy common stock and 13% in cash, with the cash received by the rabbi trust used to purchase additional mutual fund investments. At September 30, 2005, the balance of the assets in the rabbi trust totaled $140.4 million, including 2,168,980 shares of common stock of Noble Energy valued at $101.7 million. The Company accounts for the deferred compensation plan in accordance with EITF 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested.”

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Assets of the rabbi trust, other than common stock of the Company, are invested in nineteen mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds are publicly quoted and reported at market value. The Company accounts for these investments in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” The Company’s common stock held by the rabbi trust at September 30, 2005 has been classified as treasury stock in the shareholders’ equity section of the accompanying consolidated balance sheets. The market value of the assets held by the rabbi trust, exclusive of the market value of the shares of the Company’s common stock that are reflected as treasury stock, at September 30, 2005 was $38.7 million, and is included in other assets in the accompanying consolidated balance sheets. The amounts payable to the plan participants at September 30, 2005, including the market value of the shares of the Company’s common stock that are reflected as treasury stock, total $140.4 million, and are included in deferred compensation liability in the accompanying consolidated balance sheets. Approximately 2,060,000 shares or 95% of the common stock held in the plan at September 30, 2005 were attributable to a member of the Company’s Board of Directors. Since May 16, 2005, plan participants have sold investments in 20,434 shares of Noble Energy common stock in the rabbi trust and invested the proceeds in mutual funds.

In accordance with EITF 97-14, all fluctuations in market value of the rabbi trust assets have been reflected in the accompanying consolidated statements of operations. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included in other income in the accompanying consolidated statements of operations. Increases or decreases in the market value of the deferred compensation liability, including the shares of common stock of the Company held by the rabbi trust, while recorded as treasury stock, are included as deferred compensation adjustments in the accompanying consolidated statements of operations. Based on the changes in the total market value of the rabbi trust’s assets, the Company recorded deferred compensation adjustments of $31.3 million from acquisition date through September 30, 2005.

Note 7 – Effect of Gulf Coast Hurricanes

Hurricane Katrina – In August 2005 Hurricane Katrina moved through the Gulf of Mexico and resulted in the loss of the Main Pass 306D platform. The net book value of the platform was $14.0 million. The Company expects that the costs will be recoverable from insurance proceeds, subject to a $1.0 million deductible. This amount was recognized as a loss on involuntary conversion of assets during third quarter 2005. However, if the insurer reaches its maximum exposure to a single event due to Hurricane Katrina, the final insurance recovery to Noble Energy may be limited. The Company will adjust the total gain or loss attributable to the involuntary conversion in the period in which the contingencies related to the replacement costs and related insurance recoveries are resolved.

Hurricane Rita – Hurricane Rita struck the Gulf Coast in September 2005. Initial inspection of the Company’s operated platforms indicated there was no additional major damage, although damage to third party processing and pipeline facilities has slowed reinstatement of production.

Hurricane Ivan – In September 2004, Hurricane Ivan caused infrastructure damage at Main Pass 293/305/306. Costs related to clean-up and redevelopment are insured to a limit that the Company believes will allow for restoration of production. The Company is in the process of replacing the assets that were destroyed by Hurricane Ivan and expects that the costs of replacing those assets will be recoverable from insurance proceeds, subject to a $1.0 million deductible. This amount was recognized as a loss on involuntary conversion of assets during 2004. The Company will adjust the total gain or loss attributable to the involuntary conversion in the period in which the contingencies related to the replacement costs and related insurance recoveries are resolved. The remediation work has begun and the Company commenced production from undamaged platforms in third quarter 2005. However, damage to third party processing and pipeline facilities caused by Hurricanes Katrina and Rita has shut in production.

The loss of production is not covered by business interruption insurance.

15

Assets (liabilities) related to the Katrina and Ivan insurance recoveries and included in the Company’s balance sheet consist of the following:

	September 30, 2005			December 31, 2004
	(in thousands)
Probable insurance claims - current	$	85,200		$	65,000
Other assets (long-term portion of probable insurance claims)	83,305			84,832
Total expected Ivan and Katrina insurance recoveries	$	168,505		$	149,832
Asset retirement obligations - current	$	(43,551	)	$	(65,000	)
Asset retirement obligations - long-term	(77,648		)	(65,000		)
Total asset retirement obligations related to Main Pass assets	$	(121,199	)	$	(130,000	)

Note 8 – Asset Retirement Obligations

The Company’s asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and gas properties. The following table reflects the net changes in the Company’s asset retirement obligations.

	Nine Months Ended
	September 30, 2005
	(in thousands)
Asset retirement obligations, beginning of period	$	254,983
Fair value of Patina liabilities assumed	36,004
Liabilities incurred in current period	1,294
Liabilities settled in current period	(38,172		)
Revisions	21,130
Accretion expense	8,137
Asset retirement obligations, end of period	$	283,376

The ending aggregate carrying amount includes $121.2 million, which is expected to be reimbursed by insurance, related to damage to the Main Pass assets caused by Hurricanes Ivan and Katrina in the Gulf of Mexico.

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Note 9 – Unconsolidated Subsidiaries

The Company has investments, at various percentages of ownership, in subsidiaries that are accounted for using the equity method of accounting. Through these subsidiaries, the Company has an interest in a methanol plant in Equatorial Guinea. Summarized, 100% combined statement of operations information for subsidiaries accounted for using the equity method is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(in thousands)
Revenues:
Methanol sales	$	77,211	$	55,219	$	210,997	$	163,284
Other income	1,727		11,003		7,285		23,025
Total revenues	78,938		66,222		218,282		186,309
Less cost of goods sold	27,069		30,941		76,087		72,735
Gross margin	51,869		35,281		142,195		113,574
Expenses:
DD&A	5,113		4,830		14,866		14,627
Administrative	885		798		2,875		2,694
Total expenses	5,998		5,628		17,741		17,321
Income before taxes	45,871		29,653		124,454		96,253
Income tax provision	10,274		—		27,572		—
Net income	$	35,597	$	29,653	$	96,882	$	96,253

Note 10 – Shareholders’ Equity

The following table reflects the activity in shares (as adjusted for the two-for-one stock split in third quarter 2005) of the Company’s common stock and treasury stock:

	Nine Months Ended September 30,
	2005		2004
Common Stock Outstanding:
Shares at beginning of period	125,144,834		121,489,166
Shares issued in Patina acquisition	55,670,408		—
Exercise of common stock options	3,463,148		3,023,614
Restricted stock grants, net of forfeitures	171,419		—
Shares at end of period	184,449,809		124,512,780
Treasury Stock Outstanding:
Shares at beginning of period	7,099,952		7,099,952
Shares issued in Patina acquisition	2,189,414		—
Rabbi trust shares sold	(20,434	)	—
Shares at end of period	9,268,932		7,099,952

17

Restricted Stock  – The Company issued 171,419 shares (net of forfeitures) of restricted stock during the first nine months of 2005, and recognized restricted stock amortization expense of $2.7 million for the first nine months of 2005.

Dividends – In July 2005, the Board of Directors declared an increase in the quarterly cash dividend to five cents (as adjusted for the two-for-one stock split in third quarter 2005) per common share for third quarter 2005. In October 2005, the Board of Directors declared a quarterly cash dividend of five cents per common share for fourth quarter 2005.

Note 11 – 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:

	2005					2004
	Income		Shares	Per Share		Income		Shares	Per Share
	(in thousands, except per share amounts)
Three Months Ended September 30:
Basic EPS:
Net income available to common shareholders	$	176,956	174,703	$	1.01	$	83,692	116,906	$	0.72
Effect of dilutive stock options and restricted stock awards	—		4,044			—		2,068
Diluted EPS:
Net income available to common shareholders	$	176,956	178,747	$	0.99	$	83,692	118,974	$	0.70
Nine Months Ended September 30:
Basic EPS:
Net income available to common shareholders	$	423,801	146,612	$	2.89	$	241,265	116,136	$	2.08
Effect of dilutive stock options and restricted stock awards	—		2,552			—		1,868
Diluted EPS:
Net income available to common shareholders	$	423,801	149,164	$	2.84	$	241,265	118,004	$	2.04

A total of 48,000 options (each with an exercise price of $41.465) were antidilutive and were excluded from the EPS calculation above for the nine months ended September 30, 2005. There were no antidilutive options for the third quarters of 2005 or 2004 or for the first nine months of 2004, as the average market price of Company common stock for those periods was in excess of the exercise price for all options outstanding.

18

Note 12 – Income Taxes

The income tax provision consists of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(in thousands)
Current	$	42,125	$	43,302	$	119,803	$	102,624
Deferred	25,126		4,318		100,433		43,887
Total income tax provision	$	67,251	$	47,620	$	220,236	$	146,511

In assessing whether or not deferred tax assets are realizable, management considers whether it is more likely than not that some portion of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

The income tax provisions associated with discontinued operations were $1.5 million and $7.7 million for the three-month and nine-month periods ending September 30, 2004, respectively.

American Jobs Creations Act – On October 22, 2004, the American Jobs Creation Act (“AJCA”) became law. The AJCA included numerous provisions that may materially affect accounting for income taxes. Those provisions include a repeal of an export tax benefit for U.S.-based manufacturing activities and grants a special deduction that, depending on the circumstances, could reduce the effective tax rate. In accordance with FSP FAS 109-1, “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” the Company is accounting for any qualified production activities deduction as a special deduction in 2005. The Company believes that because of the phased-in nature of the deduction, it will not have a significant impact on its income tax provision or deferred tax assets or liabilities in 2005.

The AJCA also created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing for an 85% dividends-received deduction for certain dividends from controlled foreign corporations. The deduction is subject to a number of limitations and, to date, uncertainty remains as to how to interpret some provisions of the AJCA. FSP FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision with the American Jobs Creation Act of 2004,” allowed enterprises time beyond the financial reporting period of enactment of the AJCA to evaluate the effect of the Act on plans for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. In July 2005, the Company completed its evaluation of the effects of the repatriation provision, and the Company’s Board of Directors approved a plan to repatriate $118.0 million in earnings of the Company’s Samedan Methanol subsidiary during third quarter 2005. Because the Company has provided U.S. tax on most of Samedan Methanol’s earnings at 35% through December 31, 2004, repatriation under the Act resulted in a net tax benefit of  $35.1 million recorded in third quarter 2005.

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Note 13 – Geographical Data

The Company has operations throughout the world and manages its operations by country. The following information is grouped into five components that are all primarily in the business of natural gas and crude oil exploration and production:  United States; Equatorial Guinea; North Sea; Israel; and Other International, Corporate and Marketing. Other International includes operations in Argentina, China and Ecuador. The following data was prepared on the same basis as Noble Energy’s consolidated financial statements. The information does not include the effects of income taxes.

											Other Int’l,
			United		Equatorial						Corporate &
	Consolidated		States		Guinea		North Sea		Israel		Marketing
	(in thousands)
Three Months Ended September 30, 2005:
Revenues from third parties	$	628,943	$	302,947	$	104,692	$	33,262	$	19,377	$	168,665
Intersegment revenue	—		106,817		—		—		—		(106,817		)
Income from unconsolidated  subsidiaries	16,226		—		16,226		—		—		—
Total Revenues	$	645,169	$	409,764	$	120,918	$	33,262	$	19,377	$	61,848
DD&A	$	113,835	$	89,623	$	10,309	$	2,548	$	3,201	$	8,154
Accretion of discount on asset retirement obligations	$	2,928	$	2,544	$	10	$	285	$	55	$	34
Impairment of operating assets	$	5,198	$	5,198	$	—	$	—	$	—	$	—
Income from continuing operations before tax	$	244,207	$	150,874	$	100,281	$	23,996	$	14,419	$	(45,363	)
Three Months Ended September 30, 2004:
Revenues from third parties	$	306,178	$	96,692	$	33,238	$	27,773	$	18,318	$	130,157
Intersegment revenue	—		90,743		—		—		—		(90,743		)
Income from unconsolidated  subsidiaries	13,585		—		13,585		—		—		—
Total Revenues	$	319,763	$	187,435	$	46,823	$	27,773	$	18,318	$	39,414
DD&A	$	75,040	$	57,328	$	3,819	$	3,985	$	3,013	$	6,895
Accretion of discount on  asset retirement obligations	$	2,067	$	1,754	$	—	$	264	$	49	$	—
Income from continuing  operations before tax	$	128,591	$	75,742	$	37,617	$	15,008	$	14,156	$	(13,932	)

20

												Other Int’l,
			United			Equatorial						Corporate &
	Consolidated		States			Guinea		North Sea		Israel		Marketing
	(in thousands)
Nine Months Ended September 30, 2005:
Revenues from third parties	$	1,455,643	$	599,255		$	241,504	$	93,820	$	49,407	$	471,657
Intersegment revenue	—		294,702			—		—		—		(294,702		)
Income from unconsolidated  subsidiaries	44,279		—			44,279		—		—		—
Total Revenues	$	1,499,922	$	893,957		$	285,783	$	93,820	$	49,407	$	176,955
DD&A	$	281,041	$	216,553		$	23,889	$	8,241	$	8,400	$	23,958
Accretion of discount on  asset retirement obligations	$	8,137	$	6,994		$	28	$	849	$	165	$	101
Impairment of operating assets	$	5,198	$	5,198		$	—	$	—	$	—	$	—
Income from continuing  operations before tax	$	644,037	$	373,309		$	235,402	$	65,193	$	35,882	$	(65,749	)
Nine Months Ended September 30, 2004:
Revenues from third parties	$	931,015	$	236,914		$	92,402	$	85,100	$	33,498	$	483,101
Intersegment revenue	—		349,863			—		—		—		(349,863		)
Income from unconsolidated  subsidiaries	43,953		—			43,953		—		—		—
Total Revenues	$	974,968	$	586,777		$	136,355	$	85,100	$	33,498	$	133,238
DD&A	$	233,365	$	183,271		$	9,575	$	14,426	$	6,464	$	19,629
Accretion of discount on  asset retirement obligations	$	7,080	$	6,066		$	—	$	886	$	128	$	—
Income from continuing  operations before tax	$	373,422	$	225,089		$	109,982	$	46,923	$	22,239	$	(30,811	)
Total assets at September 30, 2005	$	8,695,079	$	6,275,980	(1)	$	885,561	$	122,125	$	251,318	$	1,160,095
Total assets at December 31, 2004	$	3,443,171	$	1,299,547		$	817,062	$	218,881	$	273,347	$	834,334

(1) The U.S. reporting unit includes goodwill of $898.2 million related to the Patina merger.

Note 14 – Discontinued Operations

During 2004, the Company completed an asset disposition program that had first been announced in July 2003. The asset disposition program included five domestic property packages. The sales price for the five property packages totaled approximately $130.0 million before closing adjustments. The Company’s consolidated financial statements have been reclassified to reflect the operations of the properties sold as discontinued operations. The net income from discontinued operations was classified on the consolidated statements of operations as “Discontinued Operations, Net of Tax.”

21

Summarized results of discontinued operations are as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2004		September 30, 2004
	(in thousands)
Oil and gas sales and royalties	$	10	$	12,468
Realized gain	$	4,580	$	14,179
Income before income taxes	$	4,186	$	22,083

There was no discontinued operations activity during the first nine months of 2005.

Note 15 – Commitments and Contingencies

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 Colorado operations (Jack Holman, et al v. Patina Oil & Gas Corporation; Case No. 03-CV-09; District Court, Weld County, Colorado). In May 2004, the plaintiff filed an amended complaint narrowing the class of potential plaintiffs, and thereafter filed a motion seeking to certify the narrowed class as described in the amended complaint. Patina filed an answer to the amended complaint. A motion seeking class certification was heard on September 22, 2005. The motion was granted on October 13, 2005. The Company intends to seek review of certification and to vigorously defend this action. The potential liability, if any, from this claim cannot currently be reasonably estimated, and no provision has been accrued for this matter in the Company’s financial statements.

The Company and its subsidiaries are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the inherent uncertainties in any litigation. The Company is defending itself vigorously in all such matters and does not believe that the ultimate disposition of such proceedings will have a material adverse effect on the Company’s consolidated financial position, results of operations or liquidity.

Note 16 – Capitalized Exploratory Well Costs

As of January 1, 2005, the Company adopted FASB Staff Position FAS 19-1, “Accounting for Suspended Well Costs.” The following table reflects the net changes in capitalized exploratory well costs for the nine months ended September 30, 2005 and does not include amounts that were capitalized and subsequently expensed in the same period.

	Nine Months Ended
	September 30, 2005
	(in thousands)
Capitalized exploratory well costs, beginning of period	$	62,724
Additions to capitalized exploratory well costs pending determination of proved reserves	79,043
Reclassified to property, plant and equipment based on determination of proved reserves	(4,743		)
Capitalized exploratory well costs charged to expense	(3,200		)
Capitalized exploratory well costs, end of period	$	133,824

22

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,
	2005		2004
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	21,694	$	44,986
Capitalized exploratory well costs that have been capitalized for a period greater than one year	112,130		17,738
Balance at end of period	$	133,824	$	62,724
Number of projects that have exploratory well costs that have been  capitalized for a period greater than one year	3		4

Of the $112.1 million of exploratory well costs that have been capitalized for a period greater than one year, $96.0 million is associated with Lorien (Green Canyon 199), a deepwater Gulf of Mexico project discovered in 2003. The Company increased its working interest from 20% to 60% in the second quarter of 2004. A successful appraisal sidetrack well was drilled in 2004 and a second appraisal well was drilled in the first quarter of 2005 to delineate the reservoir. The Company expects to record reserves in 2005, at which time the suspended well costs will be reclassified to property, plant and equipment. An additional $9.5 million of costs capitalized greater than one year is related to a North Sea project awaiting sanctioning which is expected by year end 2005. The remaining $6.6 million relates to activities that are ongoing and are being actively pursued. The Company’s assessment of suspended well costs is continuous until a determination is made that the well has found proved reserves or is noncommercial and is impaired.

Note 17 – Recently Issued Pronouncements

The FASB has recently issued two FASB Staff Positions (“FSP’s”) on SFAS No. 123(R), “Share-Based Payment”. The Company is planning to adopt the provisions of SFAS No. 123(R) as of January 1, 2006, and the guidance in these FSP’s will be applied upon initial adoption. FSP FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R)”, defers the requirement of FAS No. 123(R) that a freestanding financial instrument originally subject to Statement 123(R) becomes subject to the recognition and measurement requirements of other applicable generally accepted accounting principles when the rights conveyed by the instrument to the holder are no longer dependent on the holder being an employee of the entity.

FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as Defined in FASB Statement No. 123(R)”, provides that in determining the grant date of an award subject to Statement 123(R), assuming all other criteria in the grant date definition have been met, a mutual understanding of the key terms and conditions of an award to an individual employee shall be presumed to exist at the date the award is approved in accordance with the relevant corporate governance requirements (that is, by the Board or management with the relevant authority) if both of the following conditions are met:

a. The award is a unilateral grant and, therefore, the recipient does not have the ability to negotiate the key terms and conditions of the award with the employer.

b. The key terms and conditions of the award are expected to be communicated to an individual recipient within a relatively short time period from the date of approval.

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

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Noble Energy continued its trend of stable and consistent growth during the third quarter, despite the impact of two large hurricanes.  This was the Company’s first full quarter with Patina Oil & Gas Corporation (“Patina”) integrated into Noble Energy’s operations.  Patina’s long-lived assets not only added to Noble Energy’s domestic production base, they provided stability while Gulf of Mexico and Gulf Coast production was impacted by Hurricanes Katrina and Rita.  International operations also continued to ramp up with new production in Equatorial Guinea and Israel.  The Company’s deepwater Swordfish development has begun producing and is expected to reach 10,000 barrels of oil equivalent per day (Boepd), net to Noble Energy, during the fourth quarter.  Two additional deepwater developments of similar size, Lorien and Ticonderoga, are scheduled to commence production during the second and third quarters of next year, respectively.

Third quarter 2005 production was 168,666 Boepd. Domestic production was reduced by approximately 7,600 Boepd due to Hurricanes Katrina and Rita.  International production was 55% above third quarter last year, primarily because of increases in condensate and natural gas volumes in Equatorial Guinea following the completion of two liquids expansion projects.

Financial and operating events for third quarter 2005 included the following:

•Impact of Hurricanes Katrina and Rita;

•Integration of Patina operations;

•Net income of $177.0 million, a 111% increase over third quarter 2004;

•Diluted earnings per share of $0.99, a 41% increase over third quarter 2004;

•Cash flows provided by operating activities of $924.6 million, year-to-date, a 77% increase over 2004;

•A 61% increase in daily production over third quarter 2004, including a 55% international increase and a 66% domestic increase; and

•Increases of 34% in the average realized crude oil price and 25% in the average realized natural gas price over third quarter 2004.

Impact of Gulf Coast Hurricanes – In August 2005 Hurricane Katrina moved through the Gulf of Mexico and resulted in the loss of the Main Pass 306D platform. In September 2005 Hurricane Rita struck the Gulf Coast. Initial inspection of the Company’s operated platforms indicated there was no additional major damage due to Hurricane Rita, although damage to third party processing and pipeline facilities has slowed reinstatement of production from the Company’s Gulf of Mexico assets. In addition, the hurricanes delayed efforts to restore sales of production from undamaged platforms at Main Pass 293/305/306 that were shut-in by Hurricane Ivan in 2004.

Prior to Hurricane Katrina, Noble Energy’s net Gulf of Mexico production averaged approximately 26,000 Boepd for June and July, or approximately 16% of Noble Energy’s total net production at the end of the second quarter. The Company expects Gulf of Mexico production to continue to increase depending on the restarting of pipeline and other facilities not operated by Noble Energy.

Belinda Discovery –In October, Noble Energy announced successful results from its offshore Belinda exploration well on Block “O” in Equatorial Guinea. The Company is currently reviewing options for a multi-well exploration and appraisal program, which could begin in 2006.  Noble Energy is the technical operator of Block “O” with a 45% participating interest.

Merger with Patina Oil & Gas Corporation – On May 16, 2005, Noble Energy completed the Patina Merger in a transaction accounted for as a purchase of Patina by Noble Energy. 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 Denver-Julesburg Basin, the Mid-continent region of western Oklahoma and the Texas Panhandle, and the San Juan Basin in New Mexico. The following consolidated operating and cash flow information includes financial results of Patina after May 16, 2005.

24

LIQUIDITY AND CAPITAL RESOURCES

Overview

The Company’s primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of crude oil and natural gas properties, to repay outstanding borrowings, or to pay other contractual commitments, for interest payments on debt and to pay cash dividends on common stock. The Company’s traditional sources of liquidity are its cash on hand, cash flows from operations and available borrowing capacity under its credit facilities. Funds may also be generated from occasional sales of non-strategic crude oil and natural gas properties.

Cash Flows

Operating Activities – For the first nine months of 2005, the Company reported net cash provided by operating activities of $924.6 million, a 77% increase as compared with $524.0 million for the first nine months of 2004. The increase was due primarily to higher production and commodity prices, partially offset by increased exploration and operating expense.

Investing Activities – Net cash used in investing activities for the first nine months of 2005 totaled $1.7 billion, as compared with $417.5 million for the first nine months of 2004. For 2005, $1.1 billion related to the cash portion of the acquisition price for Patina, and approximately $590.1 million related to capital expenditures. In addition, during third quarter 2005 the Company received $40.0 million in insurance proceeds related to Hurricane Ivan damage. Net cash used in investing activities for 2004 included capital expenditures of $457.0 million, which was partially offset by proceeds of $36.2 million from property sales.

Financing Activities – Net cash provided by (used in) financing activities totaled $674.4 million and $(8.8) million for the first nine months of 2005 and 2004, respectively. Financing activities consisted primarily of net proceeds from the Company’s credit facilities used to fund the cash consideration in the Patina Merger, merger expenses and repayment of Patina debt. Other financing activities included payment of cash dividends on Company common stock of $14.8 million and proceeds from the exercise of stock options of $63.8 million.

Repatriation of Accumulated Income Earned Abroad – In third quarter 2005, the Company completed its repatriation of $118.0 million in earnings of the Company’s Samedan Methanol subsidiary.

Acquisition, Exploration and Development-Related Expenditures

Values preliminarily allocated to proved and unproved oil and gas properties acquired in the Patina Merger were $2.6 billion and $1.0 billion, respectively. The Company’s exploration and development-related expenditure information is as follows:

	Nine Months Ended September 30,
	2005		2004
	(in thousands)
Exploration and Development-Related Expenditures:
Exploratory drilling and completion	$	29,768	$	24,484
Dry hole	77,494		37,546
Lease acquisition costs	11,964		26,594
Seismic	9,886		9,130
Total exploration expenditures	129,112		97,754
Development drilling and completion	454,130		368,625
Corporate and other	16,791		14,029
Total exploration and development-related expenditures	$	600,033	$	480,408

The exploration and development-related expenditures above include $153.9 million of post-merger expenditures related to Patina properties.

25

Financing Activities

Debt – The Company’s outstanding debt balance, excluding discount, was $2.1 billion at September 30, 2005 as compared with $885.0 million at December 31, 2004. During second quarter 2005 the Company drew on its credit facilities in order to fund $1.1 billion cash consideration paid to Patina shareholders in the merger and to repay $610.9 million of Patina long-term debt assumed, including accrued interest.

The Company has credit agreements totaling $2.1 billion. These credit agreements consist of a new $1.3 billion credit agreement due April 2010, a $400 million credit agreement due October 2009, and a $400 million credit agreement due November 2006. Borrowings under these credit agreements totaled $1.3 billion at September 30, 2005, leaving approximately $800 million in unused borrowing capacity. The Company’s credit agreements are supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. The uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. No amounts were outstanding under these credit lines at September 30, 2005. The Company also had $650.0 million of fixed-rate debt and $150.0 million in variable-rate term loans at September 30, 2005.

As a result of the Patina Merger, Noble Energy’s ratio of debt-to-book capital (defined as the Company’s total debt divided by the sum of total debt plus equity) has increased to 43% at September 30, 2005, compared to 38% at December 31, 2004.

Dividends – The Company paid quarterly cash dividends of 2.5 cents (as adjusted for the two-for-one stock split in third quarter 2005) per share of common stock during first and second quarters of 2005. In July 2005, the Company’s Board of Directors declared an increase in the quarterly cash dividend to five cents per common share for third quarter 2005. In October, the Board declared quarterly cash dividends of five cents per share of common stock for fourth quarter 2005.

Exercise of Stock Options – The Company received $63.8 million from the exercise of stock options during the first nine months of 2005, as compared to $53.5 million during the first nine months of 2004. Of the $63.8 million received, approximately $39.2 million resulted from the exercise of Patina options that had been exchanged for Noble Energy options in the Patina Merger.

RESULTS OF OPERATIONS

Natural Gas Information

Natural gas revenues almost doubled third quarter 2005 over third quarter 2004, and increased 50% for the first nine months of 2005, compared with the first nine months of 2004. The increases were due to higher net realized gas prices and higher production.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Natural gas sales	$	296,056	$	148,782	$	662,753	$	443,122

26

The tables below include average daily natural gas production volumes and prices from continuing operations:

	Three Months Ended September 30,
	2005			2004
		Price			Price
	Mcfpd	Per Mcf		Mcfpd	Per Mcf
United States	413,789	$	7.12	231,990	$	5.89
Equatorial Guinea (1)	63,193	0.16		45,364	0.22
North Sea	9,970	5.14		9,694	4.29
Israel	81,942	2.57		71,619	2.78
Other International (2)	24,726	1.10		11,762	0.93
Total (3)	593,620	$	5.65	370,429	$	4.51

	Nine Months Ended September 30,
	2005			2004
		Price			Price
	Mcfpd	Per Mcf		Mcfpd	Per Mcf
United States	317,976	$	6.88	246,334	$	5.82
Equatorial Guinea (1)	60,320	0.17		45,097	0.21
North Sea	9,285	5.41		11,471	4.43
Israel	67,182	2.69		43,976	2.78
Other International (2)	21,873	1.10		20,687	0.72
Total (3)	476,636	$	5.34	367,565	$	4.66

(1)Natural gas in Equatorial Guinea is under a contract through 2026 for $0.25 per MMBTU. Intercompany sales have been eliminated resulting in a lower realized price.

(2)Other International includes Argentina and Ecuador. Ecuador natural gas volumes are included in Other International production, but are not included in natural gas sales revenues and average price. Because the natural gas-to-power project in Ecuador is 100% owned by Noble Energy, intercompany natural gas sales are eliminated.

(3)Reflects reductions of $0.54 and $0.01 per Mcf for third quarter 2005 and 2004, respectively, and reductions of $0.22 and $0.03 per Mcf for the first nine months of 2005 and 2004, respectively, from hedging activities.

Variances in natural gas production were attributable to the following:

•Additional domestic production (222 MMcfpd for third quarter) from Patina properties, offset by natural decline in the Gulf of Mexico and loss of production due to Gulf Coast hurricanes;

•Increase in Phase 2A production and start-up of Phase 2B in Equatorial Guinea;

•Natural field decline in the North Sea;

•Higher production in Israel which was ramping up during second quarter 2004; and

•Increase in gas production in Ecuador.

Crude Oil Information

Crude oil revenues more than doubled third quarter 2005 over third quarter 2004, and increased 72% for the first nine months of 2005, compared with the first nine months of 2004.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Crude oil sales	$	305,213	$	139,717	$	709,177	$	412,229

27

The tables below include average daily crude oil production volumes and prices from continuing operations:

	Three Months Ended September 30,
	2005			2004
		Price			Price
	Bopd	Per Bbl		Bopd	Per Bbl
United States	30,475	$	49.49	21,219	$	31.61
Equatorial Guinea	25,883	$	43.57	8,573	41.00
North Sea	5,198	$	59.71	5,989	43.46
Other International (1)	8,173	$	45.41	6,948	33.99
Total (2)	69,729	$	47.58	42,729	$	35.62

	Nine Months Ended September 30,
	2005		2004
		Price		Price
	Bopd	Per Bbl	Bopd	Per Bbl
United States	24,617	44.21	22,424	$	31.53
Equatorial Guinea	20,057	43.61	9,223	35.54
North Sea	5,630	52.11	6,919	37.55
Other International (1)	8,317	41.05	6,890	30.45
Total (2)	58,621	44.31	45,456	$	33.10

(1)	Other International includes Argentina and China.
(2)	Reflects reductions of $9.48 and $4.47 per Bbl for third quarter 2005 and 2004, respectively, and reductions of $6.45 and $2.59 per Bbl for the first nine months of 2005 and 2004, respectively, from hedging activities.

Variances in crude oil production were attributable to the following:

•Additional domestic production (19 MBopd for third quarter) from Patina properties, offset by natural decline in the Gulf of Mexico and loss of production due to Gulf Coast hurricanes;

•Increase in Phase 2A production and start-up of Phase 2B in Equatorial Guinea;

•Natural field decline in the North Sea; and

•Increase in production from China.

Effect of Hedging Activities

The Company hedges varying portions of anticipated future oil and gas production to reduce the exposure to commodity price fluctuations. Results of oil and gas cash flow hedging activities are included in revenues from oil and gas sales and royalties. Hedging activities reduced revenues by $90.1 million for third quarter 2005 and $18.0 million for third quarter 2004. For the first nine months of 2005 and 2004, hedging activities reduced revenues by $131.5 million and $35.2 million, respectively.

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Gathering, Marketing and Processing

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
GMP revenues	$	8,831	$	10,175	$	28,735	$	37,295
GMP expenses	5,856		8,642		20,905		29,992
Gross margin	$	2,975	$	1,533	$	7,830	$	7,303

The Company recorded gains of $0.1 million and $20,000 for the nine months ended September 30, 2005 and 2004, respectively, and gains of $0.8 million and $0.2 million for third quarter 2005 and 2004, respectively, related to derivative instruments not accounted for as cash flow hedges.

Electricity Sales - Ecuador Integrated Power Project

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005		2004
	(in thousands)
Electricity sales	$	18,843	$	7,504		$	54,978	$	38,369
Electricity generation expense	16,746		8,600			37,637		32,034
Operating income	$	2,097	$	(1,096	)	$	17,341	$	6,335
Power production (total MW)	221,840		97,291			565,724		519,167
Average power price ($/Kwh)	$	0.085	$	0.077		$	0.097	$	0.074
Natural gas production (Mcfpd)	24,466		11,645			21,772		20,247
Average natural gas price ($/Mcf) (1)	$	3.93	$	3.19		$	3.86	$	3.01

(1) Intercompany natural gas sales are eliminated.

Electricity generation expense for third quarter 2005 and the first nine months of 2005 includes $6.1 million and $7.4 million, respectively, for increases in the allowance for doubtful accounts. 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 Noble Energy. The Company is pursuing various strategies to protect its interests including international arbitration and litigation.

29

Income from Investment in Unconsolidated Subsidiaries

Income from investment in unconsolidated subsidiaries includes income from Atlantic Methanol Production Company (“AMPCO”), an unconsolidated subsidiary that owns a methanol plant in Equatorial Guinea. The Company owns a 45% interest in AMPCO. The Company’s share of results from methanol operations was as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Income from investment in unconsolidated subsidiaries (in thousands)	$	16,226	$	13,585	$	44,279	$	43,953
Methanol sales volume (gallons in thousands)	46,133		33,451		122,256		109,012
Average price (per gallon)	$	0.75	$	0.74	$	0.78	$	0.67

Costs and Expenses

Production Expenses – The table below includes oil and gas operations expense and total production costs from continuing operations:

			United		Equatorial						Other
	Consolidated		States		Guinea		North Sea		Israel		International
	(in thousands)
Three Months Ended September 30, 2005:
Lease operating (1)	$	61,433	$	42,717	$	10,100	$	2,636	$	2,124	$	3,856
Workover expense	3,342		3,105		—		237		—		—
Oil and gas operations expense	64,775		45,822		10,100		2,873		2,124		3,856
Production and ad valorem taxes	24,304		22,316		—		—		—		1,988
Transportation expense	8,357		6,473		—		1,630		—		254
Total production costs	$	97,436	$	74,611	$	10,100	$	4,503	$	2,124	$	6,098
Three Months Ended September 30, 2004:
Lease operating (1)	$	33,490	$	19,420	$	5,422	$	2,729	$	2,126	$	3,793
Workover expense	2,959		2,959		—		—		—		—
Oil and gas operations expense	36,449		22,379		5,422		2,729		2,126		3,793
Production and ad valorem taxes	7,193		5,548		—		—		—		1,645
Transportation expense	3,718		1,533		—		2,034		—		151
Total production costs	$	47,360	$	29,460	$	5,422	$	4,763	$	2,126	$	5,589

30

			United		Equatorial						Other
	Consolidated		States		Guinea		North Sea		Israel		International
	(in thousands)
Nine Months Ended September 30, 2005:
Lease operating (1)	$	142,516	$	92,076	$	24,077	$	8,763	$	6,124	$	11,476
Workover expense	8,667		8,430		—		237		—		—
Oil and gas operations expense	151,183		100,506		24,077		9,000		6,124		11,476
Production and ad valorem taxes	51,125		41,346		—		—		—		9,779
Transportation expense	18,577		13,192		—		4,728		—		657
Total production costs	$	220,885	$	155,044	$	24,077	$	13,728	$	6,124	$	21,912
Nine Months Ended September 30, 2004:
Lease operating (1)	$	100,308	$	60,432	$	16,095	$	8,143	$	5,123	$	10,515
Workover expense	12,267		12,267		—		—		—		—
Oil and gas operations expense	112,575		72,699		16,095		8,143		5,123		10,515
Production and ad valorem taxes	20,458		16,793		—		—		—		3,665
Transportation expense	14,284		7,184		—		6,639		—		461
Total production costs	$	147,317	$	96,676	$	16,095	$	14,782	$	5,123	$	14,641

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

Selected expenses on a per BOE basis were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Lease operating	$	3.95	$	3.48	$	3.78	$	3.43
Workover expense	0.22		0.31		0.23		0.42
Oil and gas operations expense	4.17		3.79		4.01		3.85
Production and ad valorem taxes	1.57		0.75		1.36		0.70
Transportation expense	0.54		0.39		0.49		0.49
Total production costs	$	6.28	$	4.93	$	5.86	$	5.04

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Oil and gas operations expense, consisting of lease operating expense and workover expense, increased $28.3 million, or 78%, for third quarter 2005, as compared with third quarter 2004. Oil and gas operations expense increased $38.6 million, or 34%, for the first nine months of 2005, as compared with the first nine months of 2004. The increase in oil and gas operations expense reflects higher production primarily in the U.S. and Equatorial Guinea and rising lease operating costs.

The unit rate of oil and gas operations expense per barrel of oil equivalent (“BOE”), converting gas to oil on the basis of six Mcf per barrel, was $4.17 for third quarter 2005 as compared with $3.79 for third quarter 2004.

Production and ad valorem tax expense increased $17.1 million third quarter 2005 over third quarter 2004 and $30.7 million for the first nine months of 2005 as compared with the first nine months of 2004 due to higher commodity prices and to the addition of Patina, which has proportionately more production subject to such taxes.

Oil and Gas Exploration Expense – Oil and gas exploration expense consists of dry hole expense, unproved lease amortization, seismic, staff expense and other miscellaneous exploration expense, including lease rentals. Oil and gas exploration expense was $77.3 million for third quarter 2005, as compared with $ 26.6 million for third quarter 2004. The increase was due to a $48.2 million period-over-period increase in dry hole expense, primarily in the Gulf Coast region and Gulf of Mexico deepwater.

Oil and gas exploration expense was $126.5 million for the first nine months of 2005, as compared with $82.1 million for the first nine months of 2004. The increase was due primarily to a $41.2 million period-over-period increase in dry hole 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,
	2005		2004		2005		2004
	(in thousands except unit rate)
Depreciation, depletion and amortization expense	$	113,835	$	75,040	$	281,041	$	233,365
Unit rate per BOE	$	7.34	$	7.81	$	7.46	$	7.98

The decline in the unit rate was primarily due to increased low-cost volumes in Equatorial Guinea, Israel, and China. DD&A expense also includes abandoned assets expense of $0.6 million and $7.9 million for third quarter 2005 and 2004, respectively, and $9.1 million and $10.5 million for the first nine months of 2005 and 2004, respectively.

Impairment of Operating Assets – During third quarter 2005 the Company recorded $5.2 million of impairment expense, primarily related to downward reserve revisions on three domestic properties. No impairments were recorded during the first nine months of 2004.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands except unit rate)
Selling, general and administrative expense	$	29,346	$	13,326	$	69,326	$	41,518
Unit rate per BOE	$	1.89	$	1.39	$	1.84	$	1.42

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SG&A expense increased 67% for the first nine months of 2005, as compared with the first nine months of 2004 due to increased personnel costs, including the impact of Patina in SG&A.

Interest Expense – Interest expense (net of interest capitalized) increased $14.1 million to $29.0 million for third quarter 2005, as compared with $14.9 million for third quarter 2004. Capitalized interest was $2.4 million for third quarter 2005, compared with $3.0 million for third quarter 2004. Interest expense (net of interest capitalized) for the quarter increased due to increased borrowings related to the Patina Merger.

Interest expense (net of interest capitalized) increased $15.7 million, or 40%, to $55.0 million for the nine months ended September 30, 2005, as compared to $39.3 million for the same period in 2004. Capitalized interest increased $1.7 million period-over-period.

Deferred Compensation Adjustment – The deferred compensation adjustment includes increases or decreases in the market value of the deferred compensation liability, including the shares of common stock of the Company held by the rabbi trust, while recorded as treasury stock. Based on the changes in the total market value of the rabbi trust’s assets, the Company recorded deferred compensation adjustments of $31.3 million from the Patina acquisition date through September 30, 2005.

Loss on Involuntary Conversion of Assets – The loss on involuntary conversion of assets for third quarter 2005 is due to the Company’s insurance deductible related to the loss of the Main Pass 306D platform caused by Hurricane Katrina. The loss for third quarter 2004 relates to the insurance deductible for infrastructure damage at Main Pass 293/305/306 caused by Hurricane Ivan. If the insurer reaches its maximum exposure to a single event due to Hurricane Katrina, the final insurance recovery to Noble Energy for the Main Pass 306D platform may be limited. The Company will adjust the total gain or loss attributable to the involuntary conversions in the period in which the contingencies related to the replacement costs and related insurance recoveries are resolved. The loss of production is not covered by business interruption insurance.

Income Tax Provision – Income tax expense associated with continuing operations was as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(in thousands except effective rate)
Income tax provision	$	67,251		$	47,620		$	220,236		$	146,511
Effective rate	28		%	37		%	34		%	39		%

In third quarter 2005, the Company completed its repatriation of $118.0 million in earnings of the Company’s Samedan Methanol subsidiary, which will qualify for the 85% dividends received deduction under the American Jobs Creation Act. Because the Company has provided U.S. tax on most of Samedan Methanol’s earnings at 35% through December 31, 2004, repatriation under the Act resulted in a net tax benefit of  $35.1 million recorded in third quarter 2005.

The decrease in the effective rate for the first nine months of 2005 is due to shifts in the combination of international and domestic income (e.g., Patina Merger), a decrease in deferred taxes related to the methanol business, and the repatriation benefit discussed above.

Discontinued Operations

During 2004, the Company completed an asset disposition program that had first been announced in July 2003. The asset disposition program included five domestic property packages. The sales price for the five property packages totaled approximately $130 million before closing adjustments. The Company’s consolidated financial statements have been reclassified to reflect the operations of the properties sold as discontinued operations. The net income from discontinued operations was classified on the consolidated statements of operations as “Discontinued Operations, Net of Tax.”

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Summarized results of discontinued operations are as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2004		September 30, 2004
	(in thousands, except statistics)
Oil and gas sales and royalties	$	10	$	12,468
Realized gain	$	4,580	$	14,179
Income before income taxes	$	4,186	$	22,083
Key Statistics:
Daily production -          Liquids (Bbls)	—		301
Natural Gas ($/Mcf)	—		5,917
Average realized price - Liquids ($/Bbl)	$	—	$	33.96
Natural Gas ($/Mcf)	$	—	$	5.97

There was no discontinued operations activity during the first nine months of 2005.

FUTURE TRENDS

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

•Potential additional weather-related shut-ins in the U.S. Gulf of Mexico and Gulf Coast areas;

•Timing of the ramp-up of the Swordfish deepwater development;

•The rate at which third party processing facilities and pipelines return to operations.

2005 Budget – Noble Energy has increased its 2005 capital expenditures budget to $987.0 million for the Company over its original budget of $735 million. The increase is primarily attributable to investment in the acquired Patina properties.  Approximately 25% of the 2005 capital budget has been allocated for exploration opportunities and 75% has been dedicated to production, development and other projects. Domestic spending is budgeted at approximately $764.0 million, international expenditures are budgeted at approximately $208.0 million, and corporate spending is budgeted at $15.0 million. The Company will evaluate its level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations and property acquisitions. Excluding possible asset purchases, the Company plans to fund such expenditures primarily from cash flows from operations. The Company believes that it has the capital structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows or available lines of credit and other borrowing opportunities.

Management believes that the Company is well positioned with its balanced reserves of crude oil and natural gas and downstream projects. The uncertainty of commodity prices continues to affect the crude oil, natural gas and methanol industries. The Company periodically enters into crude oil and natural gas commodity hedges as a means to help reduce commodity price volatility. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.

Recently Issued Pronouncements

The FASB has recently issued two FASB Staff Positions (“FSP’s”) on SFAS No. 123(R), “Share-Based Payment”. The Company is planning to adopt the provisions of SFAS No. 123(R) as of January 1, 2006, and the guidance in these FSP’s will be applied upon initial adoption. FSP FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R)”, defers the requirement of FAS No. 123(R) that a freestanding financial instrument originally subject to Statement 123(R) becomes subject to the recognition and measurement requirements of other applicable generally accepted accounting principles when the rights conveyed by the instrument to the holder are no longer dependent on the holder being an employee of the entity.

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FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as Defined in FASB Statement No. 123(R)”, provides that in determining the grant date of an award subject to Statement 123(R), assuming all other criteria in the grant date definition have been met, a mutual understanding of the key terms and conditions of an award to an individual employee shall be presumed to exist at the date the award is approved in accordance with the relevant corporate governance requirements (that is, by the Board or management with the relevant authority) if both of the following conditions are met:

a. The award is a unilateral grant and, therefore, the recipient does not have the ability to negotiate the key terms and conditions of the award with the employer.

b. The key terms and conditions of the award are expected to be communicated to an individual recipient within a relatively short time period from the date of approval.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes – The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, the Company from time to time has used derivative instruments and may do so in the future as a means of managing its exposure to price changes.

As of September 30, 2005, the Company had entered into future costless collar transactions related to its natural gas and crude oil production to support the Company’s investment program as follows:

	Natural Gas					Crude Oil
		Average price					Average price
		per MMBTU					per Bbl
Production Period	MMBTUpd	Floor		Ceiling		Bopd	Floor		Ceiling
October - December 2005	75,000	$	5.00	$	7.66	20,295	$	31.12	$	43.99
2006	3,699	$	5.00	$	8.00	1,865	$	29.00	$	34.93

As of September 30, 2005, the Company had entered into future fixed price swap transactions related to its natural gas and crude oil production to support the Company’s investment program as follows:

	Natural Gas			Crude Oil
		Average Price			Average price
Production Period	MMBTUpd	per MMBTU		Bopd	per Bbl
October - December 2005	130,000	$	7.00	13,100	$	39.19
2006	170,000	$	6.49	16,600	$	40.47
2007	170,000	$	6.04	17,100	$	39.19
2008	170,000	$	5.67	16,500	$	38.23

As of September 30, 2005, the Company had a net unrealized loss of $877.3 million, net of taxes, related to crude oil and natural gas derivative instruments accounted for as cash flow hedges.

Derivative Instruments Held for Trading Purposes – Noble Energy, from time to time, employs derivative instruments in connection with its purchases and sales of production. While most of the purchases are made for an index-based price, customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, the Company may convert a fixed or NYMEX sale to an index-based sales price (such as purchasing a NYMEX futures contract at the Henry Hub with an adjoining basis swap at a physical location). Due to the size of such transactions and certain restraints imposed by contract and by Company guidelines, the Company believes it had no material market risk exposure from these derivative instruments as of September 30, 2005.

Interest Rate Risk

The Company is exposed to interest rate risk related to its variable and fixed interest rate debt. As of September 30, 2005, the Company had $2.1 billion of debt outstanding of which $650 million was fixed-rate debt. The Company believes that anticipated near term changes in interest rates would not have a material effect on the fair value of the Company’s fixed-rate debt and would not expose the Company to the risk of material earnings or cash flow loss.

The remainder of the Company’s debt at September 30, 2005 ($1.5 billion) was variable-rate debt and therefore exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The Company estimates that a 10%

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change in the floating interest rates applicable to the September 30, 2005 balance would result in a change in annual interest expense of approximately $6.5 million.

Foreign Currency Risk

The Company does not enter into foreign currency derivatives. The U.S. dollar is considered the functional currency for each of the Company’s international operations. Transactions that are completed in a foreign currency are remeasured into U.S. dollars and recorded in the financial statements. Transaction gains or losses were not material in any of the periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis. Such gains or losses are included in other income on the statements of operations.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

General. Noble Energy is including the following discussion to generally inform its existing and potential security holders of some of the risks and uncertainties that can affect the Company and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, the Company’s management or persons acting on management’s behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include, but are not limited to, projections and estimates concerning the timing and success of specific projects and the Company’s future: (1) income, (2) crude oil and natural gas production, (3) crude oil and natural gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Sometimes the Company will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this Form 10-Q, the matters discussed in this Form 10-Q are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.

Noble Energy believes the factors discussed below are important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made herein or elsewhere by the Company or on its behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. Noble Energy does not intend to update its description of important factors each time a potential important factor arises. The Company advises its stockholders that they should: (1) be aware that important factors not described below could affect the accuracy of its forward-looking statements, and (2) use caution and common sense when analyzing its forward-looking statements in this document or elsewhere. All of such forward-looking statements are qualified in their entirety by this cautionary statement.

Volatility and Level of Hydrocarbon Commodity Prices. Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market supply and demand fundamentals and changes in the political, regulatory and economic climates and other factors that affect commodities markets generally and are outside of Noble Energy’s control. Some of Noble Energy’s projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. The Company expects its assumptions may change over time and that actual prices in the future may differ from its estimates. Any substantial or extended change in the actual prices of natural gas and/or crude oil could have a material effect on: (1) the Company’s financial position,  results of operations and cash flows, (2) the quantities of natural gas and crude oil reserves that the Company can economically produce, (3) the quantity and value of estimated proved and unproved reserves that may be attributed to its properties, and (4) the Company’s ability to fund its capital program.

Production Rates and Reserve Replacement. Projecting future rates of crude oil and natural gas production is inherently imprecise.  Producing crude oil and natural gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including, but not limited to, geological, geophysical and engineering issues, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climates. Another factor affecting production rates is Noble Energy’s ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, the Company’s ability to replace

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reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price environment for natural gas and crude oil, Noble Energy’s finding and development costs may not justify the use of resources to explore for and develop such reserves.

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

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

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

Competition. Competition in the industry is intense. Noble Energy actively competes for reserve acquisitions and exploration leases and licenses, for the labor and equipment required to operate and develop crude oil and natural gas properties and in the gathering and marketing of natural gas, crude oil, methanol and power. The Company’s competitors include the major integrated oil companies, independent crude oil and natural gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers, many of whom have greater financial resources than the Company.

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

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ITEM 4.  CONTROLS AND PROCEDURES

Based on the evaluation of the Company’s disclosure controls and procedures by Charles D. Davidson, the Company’s principal executive officer, and Chris Tong, the Company’s principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that the Company’s disclosure controls and procedures are effective. There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting, except that the Company is in the process of integrating the newly acquired Patina Oil & Gas Corporation into its existing internal control structure. The Company acquired Patina on May 16, 2005 and is in the process of integrating Patina’s disclosure controls and procedures where appropriate.

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PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Refer to “Note 15 - Commitments and Contingencies” to the consolidated financial statements.

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.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934 as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		NOBLE ENERGY, INC.
		(Registrant)
Date	November 4, 2005	/s/ CHRIS TONG
		CHRIS TONG
		Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit
Number	Exhibit
12.1	Computation of ratio of earnings to fixed charges.
31.1	Certification of the Company’s Chief Executive Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2	Certification of the Company’s Chief Financial Officer Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1	Certification of the Company’s Chief Executive Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2	Certification of the Company’s Chief Financial Officer Pursuant To Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

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