Edgar Filing: NOBLE ENERGY INC

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2007

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware		73-0785597
(State of incorporation)		(I.R.S. employer identification number)

100 Glenborough Drive, Suite 100
Houston, Texas		77067
(Address of principal executive offices)		(Zip Code)

(281) 872-3100

(Registrant’s telephone number, including area code)

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

Yes x No o

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

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

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

Yes o No x

Number of shares of common stock outstanding as of April 25, 2007: 170,862,159

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Noble Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands, except share amounts)

	(Unaudited)
	March 31,			December 31,
	2007			2006
ASSETS
Current Assets
Cash and cash equivalents	$	249,219		$	153,408
Accounts receivable - trade, net	633,250			586,882
Probable insurance claims	72,160			101,233
Deferred income taxes	51,247			99,835
Other current assets	89,333			127,188
Total current assets	1,095,209			1,068,546
Property, plant and equipment
Oil and gas properties (successful efforts method of accounting)	9,114,554			8,867,639
Other property, plant and equipment	81,535			79,646
	9,196,089			8,947,285
Accumulated depreciation, depletion and amortization	(1,936,758		)	(1,776,528		)
Total property, plant and equipment, net	7,259,331			7,170,757
Other noncurrent assets	579,437			568,032
Goodwill	767,214			781,290
Total Assets	$	9,701,191		$	9,588,625

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable - trade	$	530,290		$	518,609
Derivative instruments	330,586			254,625
Income taxes	134,698			107,136
Short-term borrowings	100,000			—
Asset retirement obligations	31,204			68,500
Other current liabilities	188,641			235,392
Total current liabilities	1,315,419			1,184,262
Deferred income taxes	1,704,274			1,758,452
Asset retirement obligations	120,884			127,689
Derivative instruments	293,150			328,875
Other noncurrent liabilities	300,069			274,720
Long-term debt	1,800,879			1,800,810
Total Liabilities	5,534,675			5,474,808

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; 190,103,659 and 188,808,087 shares issued, respectively	633,681			629,360
Capital in excess of par value	2,063,018			2,041,048
Accumulated other comprehensive loss	(211,436		)	(140,509		)
Treasury stock, at cost: 18,580,865 and 16,574,384 shares, respectively	(612,976		)	(511,443		)
Retained earnings	2,294,229			2,095,361
Total Shareholders’ Equity	4,166,516			4,113,817
Total Liabilities and Shareholders’ Equity	$	9,701,191		$	9,588,625

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(in thousands, except per share amounts)

(Unaudited)

	Three Months Ended
	March 31,
	2007		2006
Revenues
Oil and gas sales	$	667,042	$	646,252
Income from equity method investments	45,563		39,650
Other revenues	29,940		26,095
Total Revenues	742,545		711,997

Costs and Expenses
Lease operating costs	78,875		82,193
Production and ad valorem taxes	25,167		25,453
Transportation costs	11,034		5,061
Exploration costs	45,241		32,022
Depreciation, depletion and amortization	163,960		124,465
General and administrative	45,089		35,398
Accretion of discount on asset retirement obligations	2,387		3,318
Interest, net of amount capitalized	26,872		33,168
Other expense, net	40,068		21,566
Total Costs and Expenses	438,693		362,644

Income Before Taxes	303,852		349,353
Income Tax Provision	92,040		123,266
Net Income	$	211,812	$	226,087

Earnings Per Share
Basic	$	1.24	$	1.28
Diluted	$	1.22	$	1.26

Weighted average number of shares outstanding
Basic	170,844		176,136
Diluted	173,043		180,099

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2007			2006
Cash Flows From Operating Activities
Net income	$	211,812		$	226,087
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization - oil and gas production	163,960			124,465
Depreciation, depletion and amortization - electricity generation	3,472			4,151
Dry hole expense	20,235			7,383
Amortization of unproved leasehold costs	6,085			5,491
Stock-based compensation expense	5,447			3,154
Gain on sale of assets	(5,152		)	—
Deferred income taxes	47,720			55,460
Accretion of discount on asset retirement obligations	2,387			3,318
Income from equity method investees	(45,563		)	(39,650		)
Dividends received from equity method investees	52,693			9,000
Deferred compensation expense	11,649			9,176
(Gain) loss on derivative instruments	(52,035		)	30,686
Loss on involuntary conversion	13,115			—
Other	3,647			5,110
Changes in operating assets and liabilities, net of acquisition:
(Increase) decrease in accounts receivable	(50,869		)	25,575
Decrease (increase) in other current assets	17,016			(1,277		)
Decrease in probable insurance claims	16,661			66,014
Increase (decrease) in accounts payable	11,680			(42,843		)
(Decrease) increase in other current liabilities	(11,640		)	36,209
Net Cash Provided by Operating Activities	422,320			527,509

Cash Flows From Investing Activities
Additions to property, plant and equipment	(332,876		)	(288,018		)
U.S. Exploration acquisition, net of cash acquired	—			(412,257		)
Distributions from equity method investees	—			47,023
Net Cash Used in Investing Activities	(332,876		)	(653,252		)

Cash Flows From Financing Activities
Exercise of stock options	12,603			20,236
Tax benefits from stock-based awards	8,241			5,062
Cash dividends paid	(12,944		)	(8,926		)
Purchases of treasury stock	(101,533		)	—
Proceeds from credit facilities	115,000			300,000
Repayment of credit facilities	(115,000		)	(110,000		)
Repayment of term loans	—			(80,000		)
Proceeds from short term borrowings	100,000			25,000
Net Cash Provided by Financing Activities	6,367			151,372
Increase in Cash and Cash Equivalents	95,811			25,629
Cash and Cash Equivalents at Beginning of Period	153,408			110,321
Cash and Cash Equivalents at End of Period	$	249,219		$	135,950

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Shareholders’ Equity

(in thousands)

(Unaudited)

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

December 31, 2006	$	629,360	$	2,041,048		$	—		$	(140,509	)	$	(511,443	)	$	2,095,361		$	4,113,817
Net income	—		—			—			—			—			211,812			211,812
Stock-based compensation expense	—		5,447			—			—			—			—			5,447
Exercise of stock options	2,581		10,022			—			—			—			—			12,603
Tax benefits related to exercise of stock options	—		8,241			—			—			—			—			8,241
Issuance of restricted stock, net	1,740		(1,740		)	—			—			—			—			—
Dividends ($0.075 per share)	—		—			—			—			—			(12,944		)	(12,944		)
Purchases of treasury stock	—		—			—			—			(101,533		)	—			(101,533		)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings	—		—			—			(9,195		)	—			—			(9,195		)
Unrealized change in fair value	—		—			—			(62,568		)	—			—			(62,568		)
Net change in other	—		—			—			836			—			—			836
March 31, 2007	$	633,681	$	2,063,018		$	—		$	(211,436	)	$	(612,976	)	$	2,294,229		$	4,166,516

December 31, 2005	$	616,311	$	1,945,239		$	(5,288	)	$	(783,499	)	$	(148,476	)	$	1,465,857		$	3,090,144
Net income	—		—			—			—			—			226,087			226,087
Adoption of SFAS 123(R), net of tax	—		(5,288		)	5,288			—			—			—			—
Stock-based compensation expense	—		3,154			—			—			—			—			3,154
Exercise of stock options	3,660		16,576			—			—			—			—			20,236
Tax benefits related to exercise of stock options	—		5,062			—			—			—			—			5,062
Issuance of restricted stock, net	267		(267		)	—			—			—			—			—
Dividends ($0.05 per share)	—		—			—			—			—			(8,926		)	(8,926		)
Rabbi trust shares sold	—		3,035			—			—			13,809			—			16,844
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings	—		—			—			69,755			—			—			69,755
Unrealized amounts reclassified into earnings	—		—			—			16,507			—			—			16,507
Unrealized change in fair value	—		—			—			44,020			—			—			44,020
Net change in other	—		—			—			290			—			—			290
March 31, 2006	$	620,238	$	1,967,511		$	—		$	(652,927	)	$	(134,667	)	$	1,683,018		$	3,483,173

The accompanying notes are an integral part of these financial statements

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

(in thousands)

(Unaudited)

	Three Months Ended
	March 31,
	2007			2006

Net income	$	211,812		$	226,087

Other items of comprehensive income (loss)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings	(14,736		)	107,316
Less tax provision	5,541			(37,561		)
Unrealized amounts reclassified into earnings	—			25,394
Less tax provision	—			(8,887		)
Unrealized change in fair value	(100,270		)	67,725
Less tax provision	37,702			(23,705		)
Net change in other:	1,340			445
Less tax provision	(504		)	(155		)
Other comprehensive (loss) income	(70,927		)	130,572

Comprehensive income	$	140,885		$	356,659

The accompanying notes are an integral part of these financial statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Organization and Nature of Operations

Noble Energy, Inc. (“Noble Energy”, “we” or “us”) is an independent energy company engaged in the exploration, development, production and marketing of crude oil and natural gas. We have exploration, exploitation and production operations domestically and internationally. We operate throughout major basins in the U.S. including Colorado’s Wattenberg field, the Mid-continent region of western Oklahoma and the Texas Panhandle, the San Juan Basin in New Mexico, the Gulf Coast and the Gulf of Mexico. In addition, we conduct business internationally in West Africa (Equatorial Guinea and Cameroon), the Mediterranean Sea (Israel), Ecuador, the North Sea (UK, the Netherlands and Norway), China, Argentina and Suriname.

Note 2 - Basis of Presentation

Presentation – The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by U.S. generally accepted accounting principles (“GAAP”) for complete financial statements. The accompanying unaudited consolidated financial statements at March 31, 2007 and December 31, 2006 and for the three months ended March 31, 2007 and 2006 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the three-month period ended March 31, 2007 are not necessarily indicative of the results that may be expected for the year ended December 31, 2007. Certain reclassifications of amounts previously reported have been made to conform to current year presentations. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our annual report on Form 10-K for the year ended December 31, 2006.

Accounting for Uncertainty in Income Taxes – We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (“FIN 48”) as of January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We also adopted FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No.48” (“FSP FIN 48-1”) as of January 1, 2007. FSP FIN 48-1 provides that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. The adoption of FIN 48 and FSP FIN 48-1 had no effect on our financial position or results of operations. See Note 10 - Income Taxes.

Balance Sheet and Statement of Operations Information —

Other balance sheet and statement of operations information is as follows:

	March 31,		December 31,
	2007		2006
	(in thousands)
Other Current Assets
Derivative instruments	$	14,528	$	35,242
Materials and supplies inventories	44,930		46,973
Prepaid expenses and other current assets	29,875		44,973
Total	$	89,333	$	127,188
Other Noncurrent Assets
Equity method investments	$	366,642	$	373,372
Mutual fund investments	118,623		116,314
Probable insurance claims	58,913		46,500
Derivative instruments	726		2,862
Other noncurrent assets	34,533		28,984
Total	$	579,437	$	568,032
Other Current Liabilities
Accrued and other current liabilities	$	163,410	$	219,885
Interest payable	25,231		15,507
Total	$	188,641	$	235,392
Other Noncurrent Liabilities
Deferred compensation liability	$	190,716	$	173,253
Accrued benefit costs	62,827		58,491
Other noncurrent liabilities	46,526		42,976
Total	$	300,069	$	274,720

	Three Months Ended
	March 31,
	2007			2006
	(in thousands)
Other Revenues
Electricity sales	$	23,224		$	17,912
Gathering, marketing and processing	6,716			8,183
Total	$	29,940		$	26,095

Other Expense, net
Loss on involuntary conversion	$	13,115		$	—
Electricity generation (1)	16,093			10,626
Gathering, marketing and processing	5,016			5,502
Deferred compensation expense	11,649			9,176
Gain on derivative instruments	(1,005		)	(5,159		)
Other	(4,800		)	1,421
Total	$	40,068		$	21,566

(1) Includes an increase in the allowance for doubtful accounts of $5 million for first quarter 2007. This increase has been made to cover potentially uncollectible balances related to the Ecuador power operations. Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. We are pursuing various strategies to protect our interests including international arbitration and litigation.

Note 3 - Derivative Instruments and Hedging Activities

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

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

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

	March 31,
	2007			2006
	(in thousands)
Decrease in crude oil sales	$	(28,103	)	$	(56,115	)
Increase (decrease) in natural gas sales	42,839			(51,201		)
Total increase (decrease) in oil and gas sales	$	14,736		$	(107,316	)

We recognized a hedge ineffectiveness gain of $1 million in first quarter 2007 and a loss of $9 million in first quarter 2006.

If it becomes probable that the hedging instrument is no longer highly effective, the hedging instrument loses hedge accounting treatment. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in AOCL related to the hedging instrument may also be reclassified to earnings. As a result of the impacts of Hurricanes Katrina and Rita on the timing of forecasted production during first quarter 2006, derivative instruments hedging approximately 6,000 barrels per day of crude oil and 40,000 MMBtu per day of natural gas did not qualify for hedge accounting during a portion of first quarter 2006. Accordingly, the changes in fair value of these derivative contracts were recognized in our results of operations, causing a mark-to-market gain of $39 million in first quarter 2006. These derivative instruments were re-designated as cash flow hedges in February 2006. In addition, the delay in the timing of our Gulf of Mexico production resulted in a loss of $25 million related to amounts previously recorded in AOCL. Both the gain and the loss are included in gain on derivative instruments. No other gains or losses were reclassified from AOCL into earnings as a result of the discontinuance of hedge accounting treatment for individual contracts during first quarter 2007 or 2006.

At March 31, 2007, we had entered into costless collar derivative instruments related to crude oil and natural gas production as follows:

	Natural Gas					Crude Oil
		Average price					Average price
		per MMBtu					per Bbl
Production Period	MMBtupd	Floor		Ceiling		Bopd	Floor		Ceiling
April - December 2007 (NYMEX)	—	$	—	$	—	2,700	$	60.00	$	74.30
April - December 2007 (CIG) (1)	12,000	6.50		9.50		—	—		—
April - December 2007 (Brent)	—	—		—		7,265	45.00		70.65

2008 (NYMEX)	—	—		—		3,100	60.00		72.40
2008 (CIG)	14,000	6.75		8.70		—	—		—
2008 (Brent)	—	—		—		4,074	45.00		66.52

2009 (NYMEX)	—	—		—		3,700	60.00		70.00
2009 (CIG)	15,000	6.00		9.90		—	—		—
2009 (Brent)	—	—		—		3,074	45.00		63.04

2010 (NYMEX)	—	—		—		3,500	55.00		73.80
2010 (CIG)	15,000	6.25		8.10		—	—		—

(1) Colorado Interstate Gas

At March 31, 2007, we had entered into fixed price swap derivative instruments related to crude oil and natural gas production as follows:

	Natural Gas			Crude Oil
		Average Price			Average price
Production Period	MMBtupd	per MMBtu		Bopd	per Bbl
April - December 2007 (NYMEX)	170,000	$	5.78	17,100	$	39.04

2008 (NYMEX)	170,000	5.66		16,500	38.23

At March 31, 2007, we had entered into basis swap derivative instruments related to natural gas production. These basis swaps have been combined with NYMEX fixed to variable swaps and designated as cash flow hedges. The basis swaps are as follows:

	Natural Gas
		Average
		Differential
Production Period	MMBtupd	per MMBtu
April - December 2007 (CIG vs. NYMEX)	100,000	$	2.02
April - December 2007 (ANR (1) vs. NYMEX)	30,000	1.17
April - December 2007 (PEPL (2) vs. NYMEX)	10,000	1.11

2008 (CIG vs. NYMEX)	100,000	1.66
2008 (ANR vs. NYMEX)	40,000	1.01
2008 (PEPL vs. NYMEX)	10,000	0.98

(1) ANR Pipeline

(2) Panhandle Eastern Pipe Line

If commodity prices were to stay the same as they were at March 31, 2007, approximately $75 million of deferred losses, net of taxes, related to the fair values of the derivative instruments included in AOCL at March 31, 2007 would be reversed during the next twelve months as the forecasted transactions occur, and settlements would be recorded as a reduction in oil and gas sales. All forecasted transactions currently being hedged are expected to occur by December 2010.

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

We record gains and losses on these derivative instruments using mark-to-market accounting. Under this accounting method, the changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. Net gains (losses) related to these derivative instruments were de minimis for first quarter 2007 and 2006.

Note 4 - Employee Benefit Plans

We have a noncontributory, tax-qualified defined benefit pension plan covering certain domestic employees. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by ERISA. We sponsor other plans for the benefit of our employees and retirees, which include health care and life insurance benefits. Net periodic benefit cost related to pension and other postretirement benefit plans was as follows:

	Retirement & Restoration						Medical & Life
	Plan Benefits						Plan Benefits
	2007			2006			2007			2006
	(in thousands)
Three Months Ended March 31,
Service cost	$	3,087		$	3,305		$	502		$	744
Interest cost	2,474			2,272			293			369
Expected return on plan assets	(2,693		)	(1,963		)	—			—
Transition obligation recognition	60			60			—			—
Amortization of prior service cost	(129		)	93			(232		)	(59		)
Recognized net actuarial loss	978			720			293			331
Net periodic benefit cost	$	3,777		$	4,487		$	856		$	1,385

Note 5 - Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Stock-based compensation expense	$	5,447	$	3,154
Tax benefit from expense recognized	2,048		1,104

During the three months ended March 31, 2007, we granted 1,454,336 stock options with a weighted-average grant-date fair value of $18.71 and awarded 524,602 shares of restricted stock subject to service conditions with a weighted-average grant-date fair value of $53.43.

Note 6 - Effect of Gulf Coast Hurricanes

We have nearly completed our cleanup activities relating to the damage caused by Hurricane Ivan in 2004. In April 2007, we completed the abandonment of the wells damaged by Ivan. The most significant remaining activity is the lifting and removal of the three platform decks that were sheared from their supporting structures during the storm. We are currently working with service providers to finalize a plan to safely and efficiently remove the decks from the ocean floor. We have made

substantial progress in this effort and expect to remove the decks and finalize all Ivan related cleanup activities during second quarter 2007.

As a result of weather problems in the first quarter 2007, we were required to extend the contract for the necessary salvage vessels which resulted in a $10 million increase in total cleanup costs. This increase caused the sum of the expected total project costs and the net book value of the assets destroyed to reach $270 million, $10 million in excess of our maximum single event insurance coverage of $260 million. We have recorded the $10 million as an increase to our asset retirement obligations with a corresponding loss on involuntary conversion, which is included in other expense, net in the consolidated statements of operations. As of March 31, 2007, we have been reimbursed $195 million by our insurance providers and have recorded probable insurance claims of $57 million and asset retirement obligations of $5 million related to Hurricane Ivan.

We are also continuing our cleanup activities relating to the damage caused by Hurricane Katrina in 2005. The most significant remaining activity is the completion of abandonment of wells damaged by Katrina as well as the lifting and removal of a platform deck that toppled during the storm. The removal of this deck will be performed in conjunction with the deck liftings for Ivan.

The weather problems that delayed the Hurricane Ivan cleanup activities also impacted the Hurricane Katrina cleanup activities, which resulted in a $5 million increase in total cleanup costs. This increase caused the sum of the expected total project costs and the net book value of the assets destroyed to reach $188 million, $3 million in excess of our estimated recoverable insurance coverage. Accordingly, we have recorded a $5 million increase to our asset retirement obligations with a $3 million loss on involuntary conversion, which is included in other expense, net. As of March 31, 2007, we have been reimbursed $16 million by our insurance providers and have recorded probable insurance claims of $66 million and asset retirement obligations of $23 million related to Hurricane Katrina.

Note 7 - Asset Retirement Obligations

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

	Three Months Ended
	March 31, 2007
	(in thousands)
Asset retirement obligations at beginning of period	$	196,189
Liabilities incurred in current period	540
Liabilities settled in current period	(65,421		)
Revisions	18,393
Accretion expense	2,387
Asset retirement obligations at end of period	$	152,088

The ending aggregate carrying amount includes $28 million related to damage to the Main Pass assets caused by Hurricanes Ivan and Katrina in the Gulf of Mexico. Liabilities settled during the period were primarily related to cleanup of hurricane damage at Main Pass.

Note 8 – Equity Method Investments

Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investments in our consolidated statements of operations. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investments and is not included in our income tax provision in our consolidated statements of operations. Investments and summarized, 100% combined financial information are as follows:

	2007		2006
	(in thousands)
Equity method investments as of March 31,
Atlantic Methanol Production Company, LLC (“AMPCO, LLC”)	$	214,421	$	211,325
Alba Plant LLC	135,326		146,051
Other	16,895		15,996
Total equity method investments	$	366,642	$	373,372

Summarized, 100% combined information:
Balance sheet information as of March 31 and December 31, respectively,
Current assets	$	234,643	$	252,201
Noncurrent assets	850,248		857,465
Current liabilities	163,286		171,028
Noncurrent liabilities	2,317		2,385

Statements of operations information for the three months ended March 31,
Operating revenues	$	208,256	$	180,597
Less cost of goods sold	54,402		40,892
Gross margin	153,854		139,705
Less other expense	10,709		15,746
Less income tax expense	13,802		8,681
Net income	$	129,343	$	115,278

Note 9 - Basic Earnings Per Share and Diluted Earnings Per Share

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

	Three Months Ended March 31,
	2007			2006
			Weighted			Weighted
	Net		Average	Net		Average
	Income		Shares	Income		Shares
	(in thousands, except per share amounts)

Net income available to common shareholders	$	211,812	170,844	$	226,087	176,136
Basic EPS	$	1.24		$	1.28

Net income available to common shareholders	$	211,812	170,844	$	226,087	176,136
Plus: Incremental shares from assumed conversions
Dilutive stock options			2,058			3,827
Dilutive restricted stock			141			136
Adjusted net income and shares	$	211,812	173,043	$	226,087	180,099
Diluted EPS	$	1.22		$	1.26

Certain stock options and shares of our common stock held in a rabbi trust were antidilutive and were excluded from the calculation of diluted EPS. These items represented 2.5 million and 2.6 million weighted average shares for first quarter 2007 and 2006, respectively.

Note 10 - Income Taxes

The income tax provision consists of the following:

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Current	$	44,320	$	67,806
Deferred	47,720		55,460
Total income tax provision	$	92,040	$	123,266

Our effective tax rate decreased from 35% in first quarter 2006 to 30% in first quarter 2007. The decrease was due primarily to higher earnings from equity method investments in first quarter 2007, which is a favorable permanent difference in calculating income tax expense. In addition, an increase in the valuation allowance on a deferred tax asset for future foreign tax credits resulted in an increase in the effective tax rate in first quarter 2006.

In assessing whether or not deferred tax assets are realizable, we consider whether it is more likely than not that some portion of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2006, we had recorded deferred tax assets, subject to valuation allowances, of $74 million related to foreign tax credits and losses on foreign operations. The valuation allowances with respect to the deferred tax assets totaled $74 million at December 31, 2006. These deferred tax assets and valuation allowances are expected to increase to $86 million by the end of 2007.

On March 16, 2007, China’s legislature, the National People’s Congress, enacted the China Corporate Income Tax Law. This new legislation will decrease our tax rate in China from 33% to 25% starting in 2008. The deferred tax liability for China as of December 31, 2006 was revised during first quarter 2007 to reflect the new rate, which decreased deferred tax expense by $2 million during the three months ended March 31, 2007.

Adoption of FIN 48 and FSP FIN 48-1 — As discussed in Note 2 - Basis of Presentation, we adopted FIN 48 and FSP FIN 48-1 as of January 1, 2007. The adoption had no effect on our financial position or results of operations. As of January 1, 2007 and March 31, 2007, the total amount of unrecognized tax benefits was $400,000, all of which would affect our effective tax rate if recognized. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: U.S. - 2003, Equatorial Guinea - 2002, China - 2003, Israel - 2000, UK - 2005 and the Netherlands - 2000.

We recognize interest and penalties related to unrecognized tax benefits in income tax expense. We had accrued no interest or penalties at March 31, 2007, because the jurisdiction in which we have unrecognized tax benefits has not historically imposed interest and penalties.

Note 11 - Geographical Data

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

											Other Int’l
			North		West						Corporate &
	Consolidated		America		Africa		North Sea		Israel		Marketing
	(in thousands)
Three Months Ended March 31, 2007
Revenues from third parties	$	696,982	$	397,660	$	63,737	$	55,161	$	25,375	$	155,049
Intersegment revenue	—		95,575		—		—		—		(95,575		)
Income from equity method investments	45,563		—		45,563		—		—		—
Total Revenues	742,545		493,235		109,300		55,161		25,375		59,474

DD&A	163,960		137,821		3,242		11,655		3,711		7,531
Income before taxes	303,852		217,507		83,446		32,161		19,682		(48,944		)

Three Months Ended March 31, 2006
Revenues from third parties	$	672,347	$	278,813	$	124,039	$	36,287	$	19,759	$	213,449
Intersegment revenue	—		152,043		—		—		—		(152,043		)
Income from equity method investments	39,650		—		39,650		—		—		—
Total Revenues	711,997		430,856		163,689		36,287		19,759		61,406

DD&A	124,465		104,692		6,115		1,874		3,199		8,585
Income before taxes	349,353		201,358		147,892		25,663		14,728		(40,288		)

Total assets at March 31, 2007 (1)	$	9,701,191	$	7,213,541	$	1,028,462	$	374,302	$	270,913	$	813,973
Total assets at December 31, 2006 (2)	9,588,625		7,224,920		960,357		343,236		256,913		803,199

(1) The North America reporting unit includes goodwill of $767 million.

(2) The North America reporting unit includes goodwill of $781 million.

Note 12 - Commitments and Contingencies

Legal Proceedings — In January 2003, Patina Oil & Gas Corporation (“Patina”), a company acquired by us in 2005, was named as a defendant in a lawsuit alleging that Patina had improperly deducted certain costs in connection with its calculation of royalty payments relating to its Wattenberg field operations (Jack Holman, et al v. Patina Oil & Gas Corporation; Case No. 03-CV-09; District Court, Weld County, Colorado). In October 2006, we received service in an additional lawsuit styled Wardell Family Partnership and Glen Droegemueller v. Noble Energy, Inc. et al; Case No. 06-CV-734, District Court, Weld County, Colorado, involving royalty and overriding royalty interest owners in the same field and not members of the Holman class. Through a mediation process, we and the attorneys representing the Holman class and Wardell putative class entered into a Settlement Agreement dated February 15, 2007. Such a settlement was preliminarily approved by the court with notice of the settlement published in local newspapers and sent to all members of the Holman class and Wardell putative class. In accordance with the terms of the Settlement Agreement, we deposited the settlement funds into an escrow account in April 2007. A Final Approval Hearing is set with the Court for June 11, 2007. The amount of the settlement was fully accrued and had no material adverse effect on our first quarter 2007 financial position, results of operations or cash flows.

The Illinois Environmental Protection Agency (“IEPA”) issued a notice of violation to Equinox Oil Company on September 25, 2001 alleging violation of air emission and permitting regulations for a facility known as the Zif Gas Plant located near Clay City, Illinois. On January 17, 2007, the IEPA re-issued written notices of these alleged violations in the name of Equinox’s successors in interest, and our subsidiaries, Elysium Energy, LLC and Noble Energy Production, Inc. On March 16, 2007, the IEPA accepted Noble Energy Production’s and Elysium’s compliance commitment agreement wherein the companies agreed to pay a delayed permit fee, install an incineration/caustic scrubber emissions control system at the site, and fund a supplemental environmental project (“SEP”) in the nearby community. At this time, we expect no additional monies to be expended other than these amounts. However, the matter will remain open until the emissions control system is constructed and operating within IEPA parameters and the SEP is completed, which is expected to occur in the third quarter of 2007.

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

Note 13 - Capitalized Exploratory Well Costs

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

	Three Months Ended
	March 31, 2007
	(in thousands)

Capitalized exploratory well costs at beginning of period	$	80,359
Additions to capitalized exploratory well costs pending determination of proved reserves	35,823
Reclassified to property, plant and equipment based on determination of proved reserves	(10,127		)
Capitalized exploratory well costs charged to expense	(2,836		)
Capitalized exploratory well costs at end of period	$	103,219

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

	March 31,		December 31,
	2007		2006
	(in thousands)
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	80,824	$	58,493
Capitalized exploratory well costs that have been capitalized for a period greater than one year after completion of drilling	22,395		21,866
Balance at end of period	$	103,219	$	80,359

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year after completion of drilling	5		4

Included in the capitalized exploratory well costs capitalized for more than one year at March 31, 2007 were five projects. One of the projects, Blocks O and I, which includes approximately $20 million, is located offshore Equatorial Guinea. Since drilling the initial well for the project, additional seismic work has been completed and current plans are to drill an appraisal well in 2007 to further evaluate this apparent discovery. The remaining four projects, which total approximately $2 million, are all located in Alabama and are currently waiting on sales lines.

Note 14 - Recently Issued Pronouncements

SFAS 157 – In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. SFAS 157 is effective for fair value measures already required or permitted by other standards for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will adopt SFAS 157 on January 1, 2008 and are currently evaluating the provisions of SFAS 157 and assessing the impact it may have on our financial position and results of operations.

SFAS 159 – In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We are currently evaluating the provisions of SFAS 159 and assessing the impact it may have on our financial position and results of operations.

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

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash flow through the development of a high quality portfolio of producing assets that is balanced between domestic and international projects.

First quarter 2007 financial results included the following:

· net income of $212 million and diluted earnings per share of $1.22, as compared with net income of $226 million and diluted earnings per share of $1.26 for first quarter 2006;

· cash flow from operating activities of $422 million, as compared with $528 million for first quarter 2006; and

· completion of a $500 million common stock repurchase program.

First quarter 2007 operational results included the following:

· commencement of production from the Dumbarton development in Blocks 15/20a and 15/20b in the UK sector of the North Sea in January 2007;

· successful appraisal of the Flyndre prospect in the UK sector of the North Sea;

· completion of the Mari-B #7 development well and increased natural gas sales in Israel;

· full production during the first quarter from U.S. Exploration Holdings, Inc. (“U.S. Exploration”) which we acquired on March 29, 2006; and

· temporary production curtailments in the Northern region of our North America operations due to severe winter weather.

OUTLOOK

We expect crude oil and natural gas production to increase in 2007 compared to 2006. The expected year-over-year increase in production is impacted by several factors including:

· production contributions from the sale of natural gas from the Alba field in Equatorial Guinea to an LNG facility;

· the contribution of production from the Dumbarton North Sea development;

· growing natural gas sales in Israel due to the planned conversion of additional power plants to use natural gas as fuel;

· growing production from the Piceance Basin, in western Colorado, where we are continuing an active drilling program;

· a full year of production from our acquisition of U.S. Exploration;

· partially offset by loss of production from Gulf of Mexico shelf properties sold in July 2006 and natural production decline in certain fields.

Factors impacting our expected production profile for 2007 include:

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

· infrastructure development in Israel;

· potential weather-related volume curtailments in the Gulf of Mexico and Gulf Coast areas;

· potential weather-related volume curtailments in the Northern region of our North America operations; and

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

2007 Capital Expenditures – We currently expect 2007 capital expenditures to total $1.42 billion. Approximately 26% of the 2007 capital expenditures will be spent for exploration opportunities and 74% will be spent for production, development and other projects. On a geographic basis, approximately 77% of the capital expenditures will be domestic spending, 21% will be international spending and 2% will be corporate spending. Expected 2007 capital expenditures do not include the impact of possible asset purchases. We expect that our 2007 capital expenditures will be funded primarily from cash flows from

operations. We will evaluate the level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations, and property acquisitions and divestitures.

Recent Developments in Equatorial Guinea – Effective November 2006, the government of Equatorial Guinea enacted a new hydrocarbons law (the “2006 Hydrocarbons Law”) governing petroleum operations in Equatorial Guinea. The governmental agency responsible for the energy industry was given the authority to renegotiate any contract for the purpose of adapting any terms and conditions that are inconsistent with the new law. We are continuing our assessment of the impact of the change in the law and are working with various governmental authorities to determine the effect on our current contracts. However, at this time the final impact of the 2006 Hydrocarbons Law on our operations in Equatorial Guinea remains uncertain.

Recently Issued Pronouncements — See Item 1. Financial Statements – Note 14 - Recently Issued Pronouncements.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of crude oil and natural gas properties, to repay outstanding borrowings or to pay other contractual commitments and interest payments on debt. Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under credit facilities. Occasional sales of non-strategic crude oil and natural gas properties may also generate funds.

Cash Flows

Operating Activities – For first quarter 2007, we reported net cash provided by operating activities of $422 million as compared with $528 million for first quarter 2006. Significant factors contributing to the decrease in net cash provided by operating activities in the first quarter 2007 as compared to first quarter 2006 included:

· higher ratio of accounts receivable to revenue due to an increase in commodity prices near the end of first quarter 2007;

· increase in general and administrative expense and transportation costs;

· reduction in amount of insurance proceeds received;

· offset by higher dividends received from equity method investees.

Investing Activities – Net cash used in investing activities for first quarter 2007 totaled $333 million, as compared with $653 million for first quarter 2006. Investing activities for 2007 to date relate primarily to capital expenditures.

Significant investing activities for first quarter 2006 included:

· $412 million used for our acquisition of U.S. Exploration;

· $288 million used for capital expenditures;

· offset by $47 million in distributions received from equity investees.

Financing Activities – Net cash provided by financing activities for first quarter 2007 totaled $6 million, as compared with $151 million for first quarter 2006. Significant financing activities for first quarter 2007 included:

· $100 million net proceeds from short-term borrowings;

· offset by $102 million paid for repurchases of our common stock.

Significant financing activities for first quarter 2006 included $135 million net proceeds from short-term and long-term borrowings.

Acquisition and Capital Expenditures

Capital expenditure information (on an accrual basis) is as follows:

	Three Months Ended March 31,
	2007		2006
	(in thousands)
Capital Expenditures
Lease acquisition of unproved property	$	3,402	$	16,614
Exploration expenditures	61,587		36,686
Development expenditures	210,503		215,917
Corporate and other expenditures	8,818		6,726
Total capital expenditures	$	284,310	$	275,943

Values allocated to proved and unproved crude oil and natural gas properties acquired in the acquisition of U.S. Exploration in 2006 were $413 million and $131 million, respectively.

The U.S. central Gulf of Mexico lease sale scheduled for first quarter 2007 was postponed until fourth quarter 2007 which contributed to the lower lease acquisition expenditure for first quarter 2007. Equatorial Guinea exploration drilling increased our exploration expenditures for first quarter 2007.

Insurance Recoveries

We have nearly completed our cleanup activities relating to the damage caused by Hurricanes Ivan in 2004 and Katrina in 2005. The most significant remaining activity is the lifting and removal of platform decks that were separated from their supporting structures during the storm. Weather delays in the first quarter 2007 resulted in a $15 million increase in total asset retirement obligation estimates. This increase caused the expected total project costs to exceed our estimated recoverable insurance coverage. Accordingly, we have recorded a $15 million increase to our asset retirement obligations. $13 million of this amount has been recorded as a loss on involuntary conversion.

We expect to spend $28 million on asset retirement obligations in the second quarter 2007, which we have fully accrued. Insurance recovery related to additional increases in our asset retirement obligations or redevelopment costs will be limited by our maximum coverage per loss event or the insurance providers’ aggregation limit per event.

We carry up to $260 million property damage coverage per loss event. During first quarter 2007, our insurance carrier determined that its aggregation limit would be increased from $500 million to $750 million effective June 1, 2007. While the increase is to our benefit, if an insured catastrophic loss event occurs, we could still recover less than our stated limits should the total aggregate losses realized by our carrier exceed its $750 million aggregation limit applicable to any single loss event.

Financing Activities

Long-Term Debt – Our long-term debt totaled $1.801 billion (net of unamortized discount) at March 31, 2007. Maturities range from 2011 to 2097. Our ratio of debt-to-book capital (defined as total debt divided by the sum of total debt plus equity) was 31% at March 31, 2007 as compared with 30% at December 31, 2006.

Our principal source of liquidity is a $2.1 billion unsecured revolving credit facility (the “Credit Facility”) due December 2011. The Credit Facility (i) provides for Credit Facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) makes available swingline loans up to an aggregate amount of $300 million and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the Credit Facility. The Credit Facility is with certain commercial lending institutions and is available for general corporate purposes. At March 31, 2007, $1.155 billion in borrowings were outstanding under the Credit Facility. The weighted average interest rate applicable to borrowings under the Credit Facility at March 31, 2007 was 5.67%.

Short-Term Borrowings – Our credit agreement is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates

negotiated at the time of borrowing. At March 31, 2007, we had $100 million of short-term borrowings outstanding under uncommitted lines with a weighted average interest rate of 5.61%.

Dividends – We paid a quarterly cash dividend of 7.5 cents per share of common stock during first quarter 2007 and 5.0 cents per share of common stock during first quarter 2006. On April 23, 2007, our Board of Directors declared an increase in our quarterly cash dividend to 12.0 cents per common share, payable May 21, 2007 to shareholders of record on May 7, 2007. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.

Exercise of Stock Options – We received $13 million from the exercise of stock options during first quarter 2007 as compared to $20 million during first quarter 2006.

Common Stock Repurchase Program – During first quarter 2007, we repurchased 2 million shares of our common stock at an aggregate cost of $102 million. Since the repurchase program was announced in 2006, we have repurchased a total of 10.4 million shares with an aggregate cost of $500 million.

RESULTS OF OPERATIONS

Natural Gas Information

Natural gas sales increased 5% in first quarter 2007 compared to 2006 due to an 11% increase in average realized natural gas prices offset by a 5% decrease in daily natural gas sales volumes. Higher average realized prices had a positive effect of $33 million on natural gas sales. Lower sales volumes had a negative effect of $18 million on natural gas sales. Natural gas sales are net of the effects of the settlement of derivative contracts that are accounted for as cash flow hedges. Natural gas sales for first quarter 2007 include a non-cash, increase of $51 million related to hedge contracts that were re-designated at the time of the Gulf of Mexico shelf asset sale and settled during first quarter 2007.

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)

Natural gas sales	$	333,896	$	319,177

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

	2007			2006
	Mcfpd	$/Mcf		Mcfpd	$/Mcf
Three Months Ended March 31,
North America (1)	408,275	$	8.24	462,547	$	6.96
West Africa (2)	55,289	0.36		54,613	0.35
North Sea	7,170	6.02		8,485	10.62
Israel	103,115	2.73		82,556	2.66
Ecuador (3)	30,273	—		26,321	—
Other International	39	1.00		415	1.09
Total	604,161	$	6.46	634,937	$	5.83

(1) Reflects an increase of $1.17 per Mcf in 2007 and a decrease of $1.23 per Mcf in 2006 from hedging activities.

(2) Natural gas in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant and an LPG plant. The plants are owned by affiliated entities accounted for under the equity method of accounting. The volumes sold by the LPG plant are included in the table below under crude oil information.

(3) The natural gas-to-power project in Ecuador is 100% owned by our subsidiaries and intercompany natural gas sales are eliminated for accounting purposes. Electricity sales of $23 million and $18 million are included in other revenues for 2007 and 2006, respectively.

Factors contributing to the change in natural gas sales volumes in the first quarter 2007 included:

· reduction due to sale of Gulf of Mexico shelf properties in 2006;

· temporary decline in production due to weather-related curtailments in the Northern region of our North America operations;

· natural field decline in the North Sea;

offset by:

· increases in deepwater Gulf of Mexico production;

· a full quarter of production from U.S. Exploration properties and successful development activity in the Northern region of our North America operations;

· a full quarter of sales to Israeli Electric Company’s Reading power plant in Tel Aviv; and

· increased seasonal demand for electricity in Ecuador.

Crude Oil Information

Crude oil sales increased 2% in first quarter 2007 compared to 2006 due to a 3% increase in consolidated daily crude oil sales volumes offset by a 1% decrease in average realized crude oil prices. Higher sales volumes had a positive effect of $9 million on crude oil sales. Lower average realized sales prices had a negative effect of $3 million on crude oil sales. Crude oil sales are net of the effects of the settlement of derivative contracts that are accounted for as cash flow hedges.

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Crude oil sales	$	333,146	$	327,075

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

	2007			2006
	Bopd	$/Bbl		Bopd	$/Bbl
Three Months Ended March 31,
North America (1)	45,576	$	46.42	37,205	$	42.20
West Africa (2)	12,236	56.25		23,246	58.46
North Sea (3)	9,362	60.85		4,255	73.59
Other International (4)	7,253	45.24		7,800	50.24
Total Consolidated Operations	74,427	49.73		72,506	50.12
Equity Investees (5)	7,014	44.51		8,124	45.07
Total	81,441	$	49.28	80,630	$	49.61

(1) Reflects reductions of $6.85 per Bbl in 2007 and $16.76 per Bbl in 2006 from hedging activities.

(2) Production averaged 16,250 Bopd in 2007 and 18,007 Bopd in 2006. The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings.

(3) Production averaged 9,319 Bopd in 2007 and 4,178 Bopd in 2006. The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings.

(4) Production averaged 7,546 Bopd in 2007 and 7,390 Bopd in 2006. The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings.

(5) Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. LPG volumes were 5,179 Bpd and 7,054 Bpd for 2007 and 2006, respectively. Equity investee production averaged 8,203 Bpd in 2007 and 6,951 Bpd in 2006. The variance between production and sales volumes is attributable to the timing of tanker liftings.

Factors contributing to the change in crude oil sales volumes in 2007 included:

· increases in deepwater Gulf of Mexico production;

· contribution of Dumbarton North Sea development;

· a full first quarter of production from U.S. Exploration properties and successful development activity in the Northern region of our North America operations;

offset by:

· reduction due to sale of Gulf of Mexico shelf properties in 2006;

· timing of liftings in Equatorial Guinea; and

· temporary decline in production due to weather-related curtailments in the Northern region.

Effect of Hedging Activities

We hedge varying portions of forecasted future crude oil and natural gas production to reduce the exposure to commodity price fluctuations. Revenues from oil and gas sales include the results of crude oil and natural gas cash flow hedging activities. Cash flow hedging activities increased oil and gas sales by $15 million for first quarter 2007 and decreased oil and gas sales by $107 million for first quarter 2006.

Equity Method Investees

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

	Three Months Ended
	March 31,
	2007		2006
Net income (in thousands):
AMPCO, LLC and affiliates	$	24,753	$	12,547
Alba Plant LLC	$	20,810	$	27,103
Distributions/Dividends (in thousands):
AMPCO, LLC	$	20,963	$	9,750
Alba Plant LLC	$	31,730	$	46,273
Sales volumes:
Methanol (Kgal)	39,692		34,109
Condensate (Bopd)	1,835		1,070
LPG (Bpd)	5,179		7,054
Average realized prices:
Methanol (per gallon)	$	1.22	$	0.82
Condensate (per Bbl)	$	59.35	$	60.99
LPG (per Bbl)	$	39.25	$	42.66

Net income from AMPCO, LLC in 2007 has increased relative to 2006 due to a 49% increase in average realized methanol prices and a 17% increase in methanol sales volumes. During first quarter 2006, inventory was accumulated in anticipation of a 57-day plant turnaround and expansion that occurred during May and June 2006. Net income from Alba Plant LLC in 2007 has decreased relative to 2006 due to a decrease in the number of tanker liftings.

For first quarter 2007, the $32 million received from Alba Plant LLC was classified within operating cash flows as a dividend from equity investee as compared to first quarter 2006 in which the distributions were classified within investing cash flows as a repayment of a loan. The change in classification was the result of all outstanding loans being repaid to us by Alba Plant LLC in December 2006.

Costs and Expenses

Production Costs – Production costs were as follows:

			North		West						Other Int’l /
	Consolidated		America		Africa		North Sea		Israel		Corporate(2)
	(in thousands)
Three Months Ended March 31, 2007

Oil and gas operating costs (1)	$	74,920	$	55,165	$	6,691	$	6,060	$	2,136	$	4,868
Workover and repair expense	3,955		3,829		—		—		—		126
Lease operating expense	78,875		58,994		6,691		6,060		2,136		4,994
Production and ad valorem taxes	25,167		20,467		—		—		—		4,700
Transportation expense	11,034		7,798		—		2,474		—		762
Total production costs	$	115,076	$	87,259	$	6,691	$	8,534	$	2,136	$	10,456

Three Months Ended March 31, 2006

Oil and gas operating costs (1)	$	62,602	$	46,198	$	7,547	$	2,333	$	2,123	$	4,401
Workover and repair expense	19,591		19,522		—		—		—		69
Lease operating expense	82,193		65,720		7,547		2,333		2,123		4,470
Production and ad valorem taxes	25,453		22,077		—		—		—		3,376
Transportation expense	5,061		3,375		—		1,493		—		193
Total production costs	$	112,707	$	91,172	$	7,547	$	3,826	$	2,123	$	8,039

(1) Oil and gas operating costs include labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs.

(2) Other international includes Ecuador, China, and Argentina.

Oil and gas operating costs increased $12 million, or 20%, first quarter 2007, as compared with first quarter 2006, primarily as a result of expanded operations in the deepwater Gulf of Mexico, Northern region of our North America operations, and North Sea. In addition, first quarter 2007 includes increased expense, including snow removal cost, related to severe winter weather in the Northern region and added costs for business interruption insurance.

Workover and repair expense decreased $16 million for first quarter 2007, as compared with first quarter 2006. Hurricane-related repair expense was de minimus for the first quarter 2007, as compared with $15 million for first quarter 2006. In addition, workover activity was reduced due to severe winter weather in the Northern region of our North America operations.

Transportation expense increased first quarter 2007 due to increases in production in the deepwater Gulf of Mexico and the Rocky Mountain area and the commencement of production at the Dumbarton North Sea development.

Selected expenses on a per BOE basis were as follows (Natural gas volumes are converted to oil equivalent volumes on the basis of six Mcf per barrel.):

	Three Months Ended
	March 31,
	2007		2006

Oil and gas operating costs	$	4.75	$	3.90
Workover and repair expense	0.25		1.22
Lease operating expense	5.00		5.12
Production and ad valorem taxes	1.60		1.59
Transportation expense	0.70		0.32
Total production costs	$	7.30	$	7.03

The unit rate of total production costs per BOE increased first quarter 2007 as compared with first quarter 2006. Contributing to the increase is the impact of the mix of our sales volumes on the unit rate of oil and gas operations cost. In first quarter 2007, there was a decrease in Equatorial Guinea sales volumes, which have lower operating costs. Workover and repair costs per BOE decreased first quarter 2007 due to a reduction in hurricane-related repair expense.

Oil and Gas Exploration Expense – Oil and gas exploration expense consists of dry hole expense, unproved lease amortization, seismic expense, staff expense and other miscellaneous exploration expense, including lease rentals. Oil and gas exploration expense was $45 million for first quarter 2007, as compared with $32 million for first quarter 2006. The increase was due to a $13 million increase in dry hole expense and increased staff expense related to new venture activity, offset by a $4 million reduction in seismic expenditures.

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

	Three Months Ended
	March 31,
	2007		2006

DD&A expense (in thousands)	$	163,960	$	124,465
Unit rate per BOE	10.40		7.76

Total DD&A expense for first quarter 2007 increased as compared to first quarter 2006 primarily due to increased deepwater Gulf of Mexico sales volumes and higher rates in our Western Mid-continent region and Wattenberg field. Sales volumes from the Dumbarton North Sea development as well as additional sales volumes in Israel also contributed to the increase in DD&A expense for first quarter 2007. The increase in the unit rate was primarily due to the change in the mix of our sales volumes. In particular, sales from Equatorial Guinea, which carries a unit rate lower than our average, decreased first quarter 2007, compared to first quarter 2006.

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

	Three Months Ended
	March 31,
	2007		2006

G&A expense (in thousands)	$	45,089	$	35,398
Unit rate per BOE	2.86		2.21

G&A expense increased first quarter 2007 over first quarter 2006 primarily due to higher salaries and wages resulting from an increase in headcount to address our increase in activities. G&A expense includes stock-based compensation expense of $5 million in first quarter 2007 compared to $3 million in first quarter 2006.

Interest Expense and Capitalized Interest – Interest expense (net of interest capitalized) decreased $6 million to $27 million for first quarter 2007, as compared with $33 million for first quarter 2006. Capitalized interest was $4 million for first quarter 2007, compared with $2 million for first quarter 2006. Interest expense (net of interest capitalized) also decreased due to an overall reduction in debt, offset by higher interest rates applicable to amounts borrowed under the Credit Facility and short-term loans.

Other Expense, Net – See Item I. Financial Statements - Note 2 – Basis of Presentation.

Income Tax Provision – The income tax provision was as follows:

	Three Months Ended
	March 31,
	2007			2006

Income tax provision (in thousands)	$	92,040		$	123,266
Effective rate	30		%	35		%

The decrease in the effective rate was due primarily to higher earnings from equity method investments in first quarter 2007, which is a favorable permanent difference in calculating income tax expense. In addition, an increase in the valuation allowance on a deferred tax asset for future foreign tax credits increased the effective rate in 2006.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes – We are exposed to market risk in the normal course of business operations. Management believes that we are well positioned with our mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.

At March 31, 2007, we had entered into fixed price swaps, costless collars and basis swaps related to crude oil and natural gas production. See Item 1. Financial Statements - Note 3 – Derivative Instruments and Hedging Activities.

At March 31, 2007, we had a net unrealized loss of $282 million (pre-tax) related to crude oil and natural gas derivative instruments entered into for hedging purposes. A net unrealized loss of $176 million, net of tax, is recorded in AOCL in the shareholders’ equity section of our consolidated balance sheet. We will reclassify the loss to earnings as adjustments to revenue when future production occurs.

Interest Rate Risk

We are exposed to interest rate risk related to our variable and fixed interest rate debt. At March 31, 2007, we had $1.805 billion (excluding unamortized discount) of long-term debt outstanding, of which $650 million was fixed-rate debt. We believe that anticipated near term changes in interest rates would not have a material effect on the fair value of our fixed-rate debt and would not expose us to the risk of material earnings or cash flow loss.

At March 31, 2007, we had $1.155 billion of long-term variable-rate debt and $100 million of short-term variable-rate debt outstanding. Variable rate debt exposes us to the risk of earnings or cash flow loss due to changes in market interest rates. We estimate that a hypothetical 10% change in the floating interest rates applicable to our March 31, 2007 balance of variable-rate debt would result in a change in annual interest expense of approximately $7 million.

Foreign Currency Risk

We do not enter into foreign currency derivatives. The U.S. dollar is considered the functional currency for each of our international operations. Transactions that are completed in a foreign currency are remeasured into U.S. dollars and recorded in the financial statements at prevailing currency exchange rates. Transaction gains or losses were not material in any of the periods presented and we do not believe we are currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense, net on the statements of operations.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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

· our growth strategies;

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

· anticipated trends in our business;

· our future results of operations;

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

· market conditions in the oil and gas industry;

· our ability to make and integrate acquisitions; and

· the impact of governmental regulation.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included herein and included in our 2006 annual report on Form 10-K, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our 2006 annual report on Form 10-K is available on our website at www.nobleenergyinc.com.

ITEM 4. CONTROLS AND PROCEDURES

Based on the evaluation of our disclosure controls and procedures by Charles D. Davidson, Noble Energy’s principal executive officer, and Chris Tong, Noble Energy’s principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, are effective. There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Item I. Financial Statements - Note 12 – Commitments and Contingencies.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2006 other than the following:

Information technology systems implementation issues could disrupt our internal operations and adversely affect our financial results or our ability to report our financial results.

We are currently in the process of implementing a new Enterprise Resource Planning software system to replace our various legacy systems. As a part of this effort, we are transitioning data and changing processes and this may be more expensive, time consuming and resource intensive than planned. Any disruptions that may occur in the implementation or operation of this system or any future systems could increase our expenses and adversely affect our ability to report in an accurate and timely manner our financial position, results of operations and cash flows and to otherwise operate our business.

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

Issuer Purchase of Equity Securities.

The following table summarizes repurchases of common stock occurring first quarter 2007.

				Total Number of	Approximate Dollar
				Shares Purchased	Value of Shares that
	Total Number	Average Price		as Part of Publicly	May Yet Be
	of Shares	Paid		Announced Plans	Purchased Under the
Period	Purchased	Per Share		or Programs (1)	Plans or Programs
					(in thousands)
01/01/07 - 01/31/07	1,370,200	$	48.79	1,370,200
02/01/07 - 02/28/07	497,400	53.53		497,400
03/01/07 - 03/31/07	138,881	57.67		138,881
Total	2,006,481	$	50.58	2,006,481	$	—

(1) On May 16, 2006, we announced that our Board of Directors had authorized the repurchase of up to $500 million of our common stock. As of March 31, 2007, the stock repurchase program had been completed, with total repurchases of 10.4 million shares at an aggregate cost of $500 million.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

SIGNATURES

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

		NOBLE ENERGY, INC.
		(Registrant)


Date	May 3, 2007	/s/ CHRIS TONG
		CHRIS TONG
		Senior Vice President and Chief Financial Officer

INDEX TO EXHIBITS

Exhibit Number		Exhibit

10.1		Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended through April 24, 2007), (filed as exhibit 10.1 to Registrant’s Current Report on Form 8-K (Date of Event: April 24, 2007) filed April 30, 2007 and incorporated herein by reference).

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).