Edgar Filing: NOBLE ENERGY INC

form10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2010

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 or other jurisdiction of incorporation or organization)		(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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
	(Do not check if a smaller reporting company)

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

As of October 15, 2010, there were 175,094,899 shares of the registrant’s common stock,

par value $3.33 1/3 per share, outstanding.

	TABLE OF CONTENTS
		Page
	PART I
Item 1.	Financial Statements
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009	3
	Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009	4
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009	5
	Consolidated Statements of Shareholders' Equity for the Nine Months Ended September 30, 2010 and 2009	6
	Notes to Consolidated Financial Statements	7

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	40

	PART II
Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 3.	Defaults Upon Senior Securities	41

Item 4.	(Removed and Reserved)	41

Item 5.	Other Information	41

Item 6.	Exhibits	41

Table of Contents

Noble Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(millions, except per share amounts)

(unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
Revenues
Oil, Gas and NGL Sales	$	704		$	573	$	2,102		$	1,440
Income from Equity Method Investees		34			25		85			52
Other Revenues		17			23		52			61
Total		755			621		2,239			1,553
Costs and Expenses
Production Expense		141			131		430			390
Exploration Expense		35			27		167			102
Depreciation, Depletion and Amortization		231			205		662			601
General and Administrative		65			53		194			173
Gain on Asset Sale		(114	)		-		(114	)		(24	)
Asset Impairments		100			-		100			437
Other Operating (Income) Expense, Net		4			34		59			46
Total		462			450		1,498			1,725
Operating Income (Loss)		293			171		741			(172	)
Other (Income) Expense
(Gain) Loss on Commodity Derivative Instruments		(38	)		28		(280	)		95
Interest, Net of Amount Capitalized		21			23		60			64
Other Non-Operating (Income) Expense, Net		12			5		(1	)		18
Total		(5	)		56		(221	)		177
Income (Loss) Before Income Taxes		298			115		962			(349	)
Income Tax Provision (Benefit)		66			8		289			(210	)
Net Income (Loss)	$	232		$	107	$	673		$	(139	)

Earnings (Loss) Per Share, Basic	$	1.33		$	0.62	$	3.86		$	(0.80	)
Earnings (Loss) Per Share, Diluted		1.31			0.61		3.80			(0.80	)

Weighted Average Number of Shares Outstanding, Basic		175			173		175			173
Weighted Average Number of Shares Outstanding, Diluted		177			175		178			173

The accompanying notes are an integral part of these financial statements.

Table of Contents

Noble Energy, Inc.

Consolidated Balance Sheets

(millions)

	(unaudited) September 30,			December 31,
	2010			2009
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,149		$	1,014
Accounts Receivable, Net		532			465
Other Current Assets		322			199
Total Assets, Current		2,003			1,678
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)		13,937			12,584
Property, Plant and Equipment, Other		260			240
Total Property, Plant and Equipment, Gross		14,197			12,824
Accumulated Depreciation, Depletion and Amortization		(4,286	)		(3,908	)
Total Property, Plant and Equipment, Net		9,911			8,916
Goodwill		696			758
Other Noncurrent Assets		479			455
Total Assets	$	13,089		$	11,807

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	924		$	548
Other Current Liabilities		493			442
Total Liabilities, Current		1,417			990
Long-Term Debt		2,194			2,037
Deferred Income Taxes, Noncurrent		2,187			2,076
Other Noncurrent Liabilities		554			547
Total Liabilities		6,352			5,650

Commitments and Contingencies

Shareholders’ Equity
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued		-			-
Common Stock - Par Value $3.33 1/3 per share; 250 Million Shares Authorized; 195 Million and 194 Million Shares Issued, Respectively		650			645
Additional Paid in Capital		2,349			2,260
Accumulated Other Comprehensive Loss		(155	)		(75	)
Treasury Stock, at Cost; 19 Million Shares		(627	)		(615	)
Retained Earnings		4,520			3,942
Total Shareholders’ Equity		6,737			6,157
Total Liabilities and Shareholders’ Equity	$	13,089		$	11,807

The accompanying notes are an integral part of these financial statements.

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Noble Energy, Inc.

Consolidated Statements of Cash Flows

(millions)

(unaudited)

	Nine Months Ended September 30,
	2010			2009
Cash Flows From Operating Activities
Net Income (Loss)	$	673		$	(139	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Depreciation, Depletion and Amortization		662			601
Dry Hole Cost		57			11
Gain on Asset Sales		(114	)		(24	)
Asset Impairments		100			437
Deferred Income Taxes		109			(443	)
Dividends (Income) from Equity Method Investees, Net		6			(15	)
Unrealized (Gain) Loss on Commodity Derivative Instruments		(215	)		508
Other Adjustments for Noncash Items Included in Income		40			39
Changes in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable		(63	)		92
Decrease in Other Current Assets		18			25
Increase (Decrease) in Accounts Payable		214			(65	)
Increase (Decrease) in Other Current Liabilities		(17	)		10
Other Operating Assets and Liabilities, Net		(18	)		(51	)
Net Cash Provided by Operating Activities		1,452			986

Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(1,326	)		(1,012	)
DJ Basin Asset Acquisition		(458	)		-
Proceeds from Sale of Property, Plant and Equipment		552			-
Net Cash Used in Investing Activities		(1,232	)		(1,012	)

Cash Flows From Financing Activities
Exercise of Stock Options		35			15
Excess Tax Benefits from Stock-Based Awards		19			3
Dividends Paid, Common Stock		(95	)		(94	)
Purchase of Treasury Stock		(12	)		(1	)
Proceeds from Credit Facilities		760			340
Repayment of Credit Facilities		(792	)		(1,411	)
Proceeds from Issuance of Senior Long-Term Debt		-			989
Repayment of Installment Note		-			(25	)
Repurchase of Senior Debentures		-			(4	)
Net Cash Used in Financing Activities		(85	)		(188	)
Increase (Decrease) in Cash and Cash Equivalents		135			(214	)
Cash and Cash Equivalents at Beginning of Period		1,014			1,140
Cash and Cash Equivalents at End of Period	$	1,149		$	926

The accompanying notes are an integral part of these financial statements.

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Noble Energy, Inc.

Consolidated Statements of Shareholders' Equity

(millions)

(unaudited)

	Common Stock		Additional Paid in Capital			Acumulated Other Comprehensive Loss			Treasury Stock at Cost			Retained Earnings			Total Shareholders' Equity
December 31, 2009	$	645	$	2,260		$	(75	)	$	(615	)	$	3,942		$	6,157
Net Income		-		-			-			-			673			673
Stock-based Compensation		-		40			-			-			-			40
Exercise of Stock Options		3		32			-			-			-			35
Tax Benefits Related to Exercise of Stock Options		-		19			-			-			-			19
Restricted Stock Awards, Net		2		(2	)		-			-			-			-
Dividends (54 cents per share)		-		-			-			-			(95	)		(95	)
Changes in Treasury Stock, Net		-		-			-			(12	)		-			(12	)
Oil and Gas Cash Flow Hedges
Realized Amounts Reclassified Into Earnings		-		-			10			-			-			10
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		-		-			(92	)		-			-			(92	)
Net Change in Other		-		-			2			-			-			2
September 30, 2010	$	650	$	2,349		$	(155	)	$	(627	)	$	4,520		$	6,737

December 31, 2008	$	641	$	2,193		$	(110	)	$	(614	)	$	4,199		$	6,309
Net Loss		-		-			-			-			(139	)		(139	)
Stock-based Compensation		-		37			-			-			-			37
Exercise of Stock Options		2		13			-			-			-			15
Tax Benefits Related to Exercise of Stock Options		-		3			-			-			-			3
Restricted Stock Awards, Net		2		(2	)		-			-			-			-
Dividends (54 cents per share)		-		-			-			-			(94	)		(94	)
Changes in Treasury Stock, Net		-		-			-			(1	)		-			(1	)
Oil and Gas Cash Flow Hedges
Realized Amounts Reclassified Into Earnings		-		-			28			-			-			28
September 30, 2009	$	645	$	2,244		$	(82	)	$	(615	)	$	3,966		$	6,158

The accompanying notes are an integral part of these financial statements.

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Noble Energy, Inc.

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 global crude oil, natural gas and NGL exploration and production. We operate primarily in the Rocky Mountains, Mid-Continent, and deepwater Gulf of Mexico areas in the US, with core international operations offshore Israel and West Africa.

Note 2. Basis of Presentation

Presentation Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US 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 US generally accepted accounting principles (GAAP) for complete financial statements. The accompanying consolidated financial statements at September 30, 2010 and December 31, 2009 and for the three and nine months ended September 30, 2010 and 2009 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 and nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. 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 accompanying notes included in our annual report on Form 10-K for the year ended December 31, 2009.

Estimates The preparation of consolidated financial statements in conformity with GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates.

Statements of Operations Information Other statements of operations information is as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
(millions)
Other Revenues
Electricity Sales (1)	$	19		$	20		$	53		$	51
Other		(2	)		3			(1	)		10
Total	$	17		$	23		$	52		$	61
Production Expense
Lease Operating Expense	$	95		$	88		$	283		$	281
Production and Ad Valorem Taxes		29			25			96			66
Transportation Expense		17			18			51			43
Total	$	141		$	131		$	430		$	390
Other Operating (Income) Expense, Net
Rig Contract Termination Expense (2)	$	-		$	-		$	27		$	-
Electricity Generation Expense (1)		9			19			26			-
Write-down of SemCrude L.P. Receivable		-			12			-			12
Miscellaneous Income		(13	)		-			(13	)		-
Other, Net		8			3			19			34
Total	$	4		$	34		$	59		$	46
Other Non-Operating (Income) Expense, Net
Deferred Compensation (3)	$	15		$	7		$	4		$	18
Interest Income		(1	)		(1	)		(4	)		(2	)
Other (Income) Expense, Net		(2	)		(1	)		(1	)		2
Total	$	12		$	5		$	(1	)	$	18

(1)

Includes amounts related to our wholly-owned Ecuador integrated power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies natural gas to fuel the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including depreciation, depletion and amortization expense (DD&A) and changes in the allowance for doubtful accounts. Electricity generation expense for the first nine months of 2009 includes a reduction in the allowance for doubtful accounts of $36 million.

(2)	See Note 5. Impact of Federal Deepwater Moratorium.

(3)	Amount represents increases in the fair value of our common stock held in a rabbi trust.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Balance Sheet Information Other balance sheet information is as follows:

	September 30,			December 31,
	2010			2009
(millions)
Accounts Receivable, Net
Commodity Sales	$	266		$	205
Joint Interest Billings		256			140
Refund of Deepwater Gulf of Mexico Royalties (1)		-			97
Other		37			54
Allowance for Doubtful Accounts		(27	)		(31	)
Total	$	532		$	465
Other Current Assets
Inventories, Current	$	104		$	89
Commodity Derivative Assets, Current		113			13
Deferred Income Taxes, Net, Current		76			32
Assets Held-for-Sale (2)		4			-
Prepaid Expenses and Other Assets, Current		25			65
Total	$	322		$	199
Other Noncurrent Assets
Equity Method Investments	$	299		$	303
Mutual Fund Investments		112			108
Commodity Derivative Assets, Noncurrent		23			1
Other Assets, Noncurrent		45			43
Total	$	479		$	455
Accounts Payable - Trade
Capital Costs	$	605		$	277
Royalties Payable		93			65
Lease Operating Expense		36			27
Rig Contract Termination Expense (3)		16			-
Other		174			179
Total	$	924		$	548
Other Current Liabilities
Production and Ad Valorem Taxes	$	117		$	103
Commodity Derivative Liabilities, Current		5			100
Interest Rate Derivative Liability, Current (4)		141			-
Income Taxes Payable		79			60
Asset Retirement Obligations, Current		33			51
Interest Payable		24			37
Other		94			91
Total	$	493		$	442
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	226		$	213
Asset Retirement Obligations, Noncurrent		202			181
Accrued Benefit Costs, Noncurrent		68			76
Commodity Derivative Liabilities, Noncurrent		6			17
Other		52			60
Total	$	554		$	547

(1)	During 2010, we received a refund, including interest thereon, attributable to royalties that we previously paid on crude oil and natural gas produced in the deepwater Gulf of Mexico from January 1, 2003 through July 31, 2009.

(2)	We expect to close on a sale of non-core onshore US assets in fourth quarter 2010.

(3)	See Note 5. Impact of Federal Deepwater Moratorium.

(4)	See Note 7. Derivative Instruments and Hedging Activities and Note 8. Fair Value Measurement and Disclosures for further discussion.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Recently Adopted Accounting Standards In February 2010, the Financial Accounting Standards Board (FASB) amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance effective first quarter 2010.

The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 (quoted prices in active markets) and 2 (significant other observable inputs) measurements and gross presentation of activity within a Level 3 (significant unobservable inputs) roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted this guidance effective first quarter 2010. Adoption had no impact on our financial position or results of operations. See Note 8. Fair Value Measurements and Disclosures.

Note 3. Acquisitions and Divestitures

Sale of Non-Core Onshore US Assets On August 12, 2010, we closed the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas. Information regarding the sale is as follows:

	Three Months Ended September 30,
	2010
(millions)
Cash Proceeds	$	552
Less
Net Book Value of Assets Sold		(394	)
Goodwill Allocated to Assets Sold		(61	)
Asset Retirement Obligations Associated with Assets Sold		10
Other Closing Adjustments		7
Gain on Asset Sale	$	114

DJ Basin Asset Acquisition On March 1, 2010, we acquired substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. The acquisition included properties located in the Greater Denver-Julesberg (DJ) Basin, one of our core onshore US operating areas. We funded the acquisition using our existing credit facility.

The total purchase price and allocation of the total purchase price are as follows:

	September 30,
	2010
(millions)
Total Purchase Price
Cash Paid	$	458
Net Liabilities Assumed		40
Total	$	498

Allocation of Total Purchase Price
Proved Oil and Gas Properties	$	352
Unproved Oil and Gas Properties		146
Total	$	498

The difference between the total purchase price and the fair values of the assets acquired was de minimis.

To estimate the fair values of the properties, we used an income approach as comparable market data was not available.

We utilized a discounted cash flow model which took into account the following inputs to arrive at estimates of future net cash flows:

estimated quantities of crude oil and natural gas prepared by our qualified petroleum engineers;

estimated future commodity prices based on NYMEX crude oil and natural gas futures prices as of the acquisition date and adjusted for estimated location and quality differentials;

estimated future production rates based on our experience with similar DJ Basin properties which we operate; and

estimated timing and amounts of future operating and development costs based on our experience with similar DJ Basin properties which we operate.

To estimate the fair value of proved properties, we discounted the future net cash flows using a market-based weighted average cost of capital rate determined appropriate at the acquisition date. To compensate for the inherent risk of estimating and valuing unproved properties, we reduced the discounted future net cash flows of probable and possible reserves by additional risk-weighting factors. The fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Certain data necessary to complete the final purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed. We expect to complete the final purchase price allocation during the 12-month period following the acquisition date, during which time the preliminary allocation may be revised.

Related transaction costs were expensed. We have not presented pro forma information for the acquired business as the impact of the acquisition was not material to our consolidated balance sheet as of September 30, 2010, or our consolidated results of operations for the three and nine months ended September 30, 2010.

Sale of Argentina In February 2008, we sold our interest in Argentina. The $24 million gain on sale was deferred until second quarter 2009 when the Argentine government approved the sale.

Note 4. Asset Impairments

2010 Due to recent declines in natural gas prices and recent drilling results, we determined that the carrying amounts of our Iron Horse development and certain other Gulf of Mexico US properties were not recoverable from future cash flows and, therefore, were impaired at September 30, 2010. We also recorded an impairment related to non-core, New Albany Shale assets held-for-sale at September 30, 2010.

2009 We determined that the carrying amount of Granite Wash, an onshore US area where we have significantly reduced investments beginning in 2007, was not recoverable from future cash flows and, therefore, was impaired. We also impaired our Gulf of Mexico Main Pass asset. The assets were reduced to their estimated fair values.

Impairments related to the following properties:

	Nine Months Ended September 30,
	2010		2009
(millions)
Iron Horse development (onshore US)	$	71	$	-
New Albany Shale held-for-sale (onshore US)		19		-
Granite Wash (onshore US)		-		389
Gulf of Mexico assets		10		48
Total	$	100	$	437

New Albany Shale assets held-for-sale were reduced to expected sales proceeds less costs to sell. We reduced the remaining properties to their fair values using a discounted cash flow method, as comparable market data was not available. The discounted cash flow models included management’s estimates of future oil and gas production, commodity prices based on forward commodity price curves as of the date of the estimate, operating and development costs, and discount rates. See Note 8. Fair Value Measurements and Disclosures.

Note 5. Impact of Federal Deepwater Moratorium

During second quarter 2010, a six-month moratorium on drilling in the deepwater Gulf of Mexico (Federal Deepwater Moratorium or Moratorium) was enacted in response to a blowout and fire on a deepwater drilling rig, Deepwater Horizon, which was engaged in drilling operations for another operator (the Deepwater Horizon Incident or the Incident). The Incident resulted in the loss of life and a significant oil spill. As a result, all deepwater drilling activities in progress at the time the Moratorium was announced were suspended.

As a result of the Moratorium, we entered into an agreement to terminate our contract for the Noble Clyde Boudreaux drilling rig and recognized rig contract termination expense of $27 million during the first nine months of 2010, in accordance with GAAP for contract termination costs. The amount is included in other operating (income) expense, net in our consolidated statements of operations. The US reporting unit recorded a related liability for accrued rig contract termination expense as follows:

	Nine Months Ended
	September 30,
	2010
(millions)
Balance, Beginning of Period	$	-
Amount Incurred and Charged to Expense During Period		27
Amount Paid During Period		(11)
Balance, End of Period	$	16

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 6. Debt

Our debt consists of the following:

	September 30,						December 31,
	2010						2009
	Debt			Interest Rate			Debt			Interest Rate
(millions, except percentages)
Credit Facility	$	350			0.57	%	$	382			0.54	%
5¼% Senior Notes, due April 15, 2014		200			5.25	%		200			5.25	%
8¼% Senior Notes, due March 1, 2019		1,000			8.25	%		1,000			8.25	%
7¼% Notes, due October 15, 2023		100			7.25	%		100			7.25	%
8% Senior Notes, due April 1, 2027		250			8.00	%		250			8.00	%
7¼% Senior Debentures, due August 1, 2097		84			7.25	%		84			7.25	%
FPSO Lease Obligation (1)		217			-			29			-
Total		2,201						2,045
Unamortized Discount		(7	)					(8	)
Total Debt, Net of Discount	$	2,194					$	2,037

(1)

Amount reported is based on percentage of floating production, storage and offloading vessel (FPSO) construction activities completed as of September 30, 2010, and therefore does not reflect future minimum lease obligations. The increase in the FPSO lease obligation is a non-cash financing activity.

Note 7. Derivative Instruments and Hedging Activities

Objectives and Strategies for Using Derivative Instruments In order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The derivative instruments we use include variable to fixed price commodity swaps, collars and basis swaps.

We have also begun to use three-way collars in addition to our two-way collars. A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a price below the floor price of the two-way collar. We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option floor price. If commodity prices fall below the sold put option floor price, we receive the cash market price plus the delta between the two put option floor prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment.

While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices.

We also use derivative instruments to manage interest rate risk by entering into forward contracts or swap agreements to minimize the impact of interest rate fluctuations associated with fixed or floating rate borrowings. We have historically designated these as cash flow hedges.

All derivative instruments are reflected as either assets or liabilities at fair value in our consolidated balance sheets. See Note 8. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of derivative instruments and gross amounts of derivative assets and liabilities.

Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices as well as incur a loss. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments in an asset position.

Accounting for Commodity Derivative Instruments We recognize all gains and losses on commodity derivative instruments in earnings during the period in which they occur. Prior to January 1, 2008, we elected to designate certain of our commodity derivative instruments as cash flow hedges. Net derivative gains and losses that were deferred in accumulated other comprehensive loss (AOCL) as of January 1, 2008, as a result of previous cash flow hedge accounting, are reclassified to earnings in future periods as the original hedged transactions occur. See Derivative Instruments in Cash Flow Hedging Relationships table below.

Accounting for Interest Rate Derivative Instruments Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes. In January 2010, in anticipation of a long-term debt issuance, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on the anticipated debt issuance. We are accounting for the instrument as a cash flow hedge against the variability of interest payments attributable to changes in interest rates on the forecasted issuance of fixed-rate debt. The swap is in the notional amount of $500 million and is based on a 30-year LIBOR swap rate.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Unsettled Derivative Instruments As of September 30, 2010, we had entered into the following crude oil derivative instruments:

	Variable to Fixed Price Swaps					Two Way Collars
Period	Index	Bbls Per Day		Weighted Average Fixed Price		Index		Bbls Per Day		Weighted Average Floor Price		Weighted Average Ceiling Price

4th Qtr 2010	NYMEX WTI		3,000	$	83.36	NYMEX WTI			14,500	$	61.48	$	75.63
4th Qtr 2010	Dated Brent		1,000		80.05	Dated Brent			7,000		64.00		73.96
2010 Average			4,000		82.53				21,500		62.30		75.09

2011	NYMEX WTI		5,000		85.52	NYMEX WTI			13,000		80.15		94.63

2012	NYMEX WTI		5,000		91.84		-		-		-		-
2012	Dated Brent		5,000		83.09		-		-		-		-
2012 Average			10,000		87.47		-		-		-		-

	Three Way Collars
Period	Index	Bbls Per Day		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price

2011	NYMEX WTI		5,000	$	56.00	$	76.00	$	101.46

2012	NYMEX WTI		12,000		60.00		81.25		101.06

Between October 1 and October 18, 2010, we entered into additional NYMEX WTI three way collars covering 6,000 Bbls per day for calendar year 2012 with a weighted average short put price, floor price and ceiling price of $60.00, $85.00 and $100.02, respectively.

As of September 30, 2010, we had entered into the following natural gas derivative instruments:

	Variable to Fixed Price Swaps						Two Way Collars
Period	Index		MMBtu Per Day		Weighted Average Fixed Price		Index	MMBtu Per Day		Weighted Average Floor Price		Weighted Average Ceiling Price

4th Qtr 2010	NYMEX HH			40,000	$	6.10	NYMEX HH (1)		210,000	$	5.90	$	6.73
4th Qtr 2010		-		-		-	IFERC CIG (2)		15,000		6.25		8.10
2010 Average				40,000		6.10			225,000		5.93		6.82

2011	NYMEX HH			25,000		6.41	NYMEX HH		140,000		5.95		6.82

	Three Way Collars
Period	Index	MMBtu Per Day		Weighted Average Short Put Price		Weighted Average Floor Price		Weighted Average Ceiling Price

2011	NYMEX HH		50,000	$	4.00	$	5.00	$	6.70

2012	NYMEX HH		50,000		4.75		5.50		7.92

(1)

Henry Hub

(2)	Colorado Interstate Gas - Northern System

Table of Contents

Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

As of September 30, 2010, we had entered into the following natural gas basis swaps:

	Basis Swaps
Period	Index	Index Less Differential	MMBtu Per Day		Weighted Average Differential
4th Qtr 2010	IFERC CIG	NYMEX HH		110,000	$	(1.49	)
2011	IFERC CIG	NYMEX HH		140,000		(0.70	)
2012	IFERC CIG	NYMEX HH		150,000		(0.52	)

Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows:

Fair Value of Derivative Instruments

	Asset Derivative Instruments						Liability Derivative Instruments
	September 30,			December 31,			September 30,			December 31,
	2010			2009			2010			2009
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
(millions)
Commodity Derivative Instruments (Not Designated as Hedging Instruments)	Current Assets	$	113	Current Assets	$	13	Current Liabilities	$	5	Current Liabilities	$	100
	Noncurrent Assets		23	Noncurrent Assets		1	Noncurrent Liabilities		6	Noncurrent Liabilities		17

Interest Rate Derivative Instruments (Designated as Hedging Instruments)	Current Assets		-	Current Assets		-	Current Liabilities		141	Current Liabilities		-
Total		$	136		$	14		$	152		$	117

The effect of derivative instruments on our consolidated statements of operations was as follows:

Commodity Derivative Instruments Not Designated as Hedging Instruments

Amount of (Gain) Loss on Derivative Instruments Recognized in Income

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
(millions)
Realized Mark-to-Market (Gain) Loss	$	(33	)	$	(121	)	$	(65	)	$	(413	)
Unrealized Mark-to-Market (Gain) Loss		(5	)		149			(215	)		508
Total (Gain) Loss on Commodity Derivative Instruments	$	(38	)	$	28		$	(280	)	$	95

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Derivative Instruments in Cash Flow Hedging Relationships

	Amount of Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss					Amount of Loss on Derivative Instruments Reclassified from Accumulated Other Comprehensive Loss
		2010		2009		2010		2009
(millions)
Three Months Ended September 30,
Commodity Derivative Instruments in Previously Designated Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-	$	-	$	5	$	14

Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			47		-		-		-
Total		$	47	$	-	$	5	$	14
Nine Months Ended September 30,
Commodity Derivative Instruments in Previously Designated Cash Flow Hedging Relationships (1)
Crude Oil Derivative Instruments		$	-	$	-	$	14	$	45
Natural Gas Derivative Instruments			-		-		1		-

Interest Rate Derivative Instruments in Cash Flow Hedging Relationships			141		-		-		-
Total		$	141	$	-	$	15	$	45

(1)

Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. Net derivative gains and losses that were deferred in AOCL as of January 1, 2008, as a result of previous cash flow hedge accounting, are reclassified to earnings in future periods as the original hedged transactions occur.

AOCL As of September 30, 2010, the balance in AOCL included deferred losses of $3 million related to the fair value of commodity derivative instruments previously accounted for as cash flow hedges. The deferred losses are net of deferred income tax benefits of $2 million. All remaining deferred losses will be reclassified to earnings during the period October 1 through December 31, 2010, as the forecasted transactions occur, and will be recorded as a reduction in oil and gas sales of approximately $5 million before tax.

AOCL also included deferred losses of $93 million, net of tax, related to interest rate derivative instruments. Of this amount, $1 million, net of tax, is currently being reclassified into earnings as adjustments to interest expense over the term of our Senior Notes due April 2014. Approximately $92 million will remain in AOCL until fixed-rate debt is issued, at which time we will begin amortizing it to interest expense over the life of the related debt issuance.

Note 8. Fair Value Measurements and Disclosures

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.

Mutual Fund Investments Our mutual fund investments, which primarily include assets held in a rabbi trust, consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.

Commodity Derivative Instruments Our commodity derivative instruments consist of variable to fixed price commodity swaps, collars and basis swaps. We estimate the fair values of these instruments based on published forward commodity price curves for the underlying commodities as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty credit risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 7. Derivative Instruments and Hedging Activities.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Interest Rate Derivative Instrument We estimate the fair value of our forward starting swap based on published interest rate yield curves as of the date of the estimate. The fair values of interest rate derivative instruments in an asset position include a measure of counterparty credit risk, and the fair values of interest rate derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates.

Deferred Compensation Liability A portion of our deferred compensation liability is measured at fair value, which is dependant upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.

Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:

	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1) (1)			Significant Other Observable Inputs (Level 2) (2)			Significant Unobservable Inputs (Level 3) (3)		Adjustment (4)			Fair Value Measurement
(millions)
September 30, 2010
Financial Assets
Mutual Fund Investments	$	112		$	-		$	-	$	-		$	112
Commodity Derivative Instruments		-			187			-		(51	)		136
Financial Liabilities
Commodity Derivative Instruments		-			(62	)		-		51			(11	)
Interest Rate Derivative Instrument		-			(141	)		-		-			(141	)
Portion of Deferred Compensation Liability Measured at Fair Value		(177	)		-			-		-			(177	)
December 31, 2009
Financial Assets
Mutual Fund Investments	$	108		$	-		$	-	$	-		$	108
Commodity Derivative Instruments		-			42			-		(28	)		14
Financial Liabilities
Commodity Derivative Instruments		-			(145	)		-		28			(117	)
Portion of Deferred Compensation Liability Measured at Fair Value		(168	)		-			-		-			(168	)

(1)	Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.

(2)	Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.

(3)	Level 3 measurements are fair value measurements which use unobservable inputs.

(4)	Amount represents the impact of master netting agreements that allow us to net cash settle asset and liability positions with the same counterparty.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

DJ Basin Asset Acquisition See Note 3. Acquisitions and Divestitures.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Asset Impairments Information about the impaired assets is as follows:

	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)				Total Pre-tax (Non-cash) Impairment Loss
							Net Book Value
Description							Net Book Value
(millions)
Nine Months Ended September 30, 2010
Impaired US Oil and Gas Properties	$	-	$	-	$	48	$	148	$	100
Nine Months Ended September 30, 2009
Impaired US Oil and Gas Properties		-		-		316		753		437

Onshore US assets held-for-sale were written down to their expected sales proceeds less costs to sell. The fair values of the remaining properties were determined as of the date of the assessment using a discounted cash flow method, as comparable market data was not available. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. See Note 4. Asset Impairments.

Additional Fair Value Disclosures

Debt The fair value of fixed-rate debt is estimated based on the published market prices for the same or similar issues. The carrying amount of floating-rate debt approximates fair value because the interest rate paid on such debt is set for periods of three months or less. See Note 6. Debt.

Fair value information regarding our debt is as follows:

	September 30,				December 31,
	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions)
Long-Term Debt, Net of Unamortized Discount (1)	$	1,977	$	2,385	$	2,008	$	2,279

(1)	Excludes obligation under FPSO lease.

Note 9. Capitalized Exploratory Well Costs

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

	Nine Months Ended September 30, 2010
(millions)
Capitalized Exploratory Well Costs, Beginning of Period	$	432
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves		78
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves		(84	)
Capitalized Exploratory Well Costs Charged to Expense		(4	)
Capitalized Exploratory Well Costs, End of Period	$	422

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

The following table provides an aging of capitalized exploratory well costs (suspended 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,
	2010		2009
(millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	108	$	158
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling		314		274
Balance at End of Period	$	422	$	432
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling		9		5

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of September 30, 2010:

			Suspended Since
	Total		2009		2008		2007 & Prior
(millions)
Project
Blocks O and I (West Africa)	$	189	$	8	$	71	$	110
Dalit (Israel)		20		20		-		-
Gunflint (Deepwater Gulf of Mexico)		49		-		49		-
Redrock (Deepwater Gulf of Mexico)		17		-		-		17
Flyndre (North Sea)		13		-		-		13
Selkirk (North Sea)		20		-		-		20
Other		6		3		3		-
Total Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	$	314	$	31	$	123	$	160

West Africa The West Africa project includes Blocks O and I offshore Equatorial Guinea and the YoYo concession and Tilapia production sharing contract offshore Cameroon. We have evaluated the potential for additional liquids and gas projects, and determined that the next development after Aseng will be at the Alen (formerly known as Belinda) field, offshore Equatorial Guinea. We are also evaluating future oil projects at Diega and Carmen, offshore Equatorial Guinea. In Cameroon, we recently completed a 3-D seismic acquisition, and results are being processed for future drilling potential.

Israel The Israel project includes Dalit, a 2009 natural gas discovery located offshore Israel. We are currently working with our partners on a cost-effective development plan.

Gunflint (Deepwater Gulf of Mexico) Gunflint (Mississippi Canyon Block 948) is our largest deepwater Gulf of Mexico discovery to date. We had planned to drill one or two appraisal wells in 2010. These plans were delayed by the Federal Deepwater Moratorium. We are currently reviewing host platform options, including subsea tieback to an existing third-party host, procurement and modification of an existing platform, or new construction. If we are able to connect to an existing third-party host, the project could have an accelerated completion schedule, thereby absorbing time lost to the drilling delay caused by the Moratorium.

Redrock (Deepwater Gulf of Mexico) Redrock (Mississippi Canyon Block 204) was a 2006 natural gas/condensate discovery and is currently considered a co-development candidate with Raton South (Mississippi Canyon Block 292). The anticipated development plan consists of tying Raton South back to a host platform at Viosca Knoll Block 900 for processing and then connecting Redrock into this gathering system. Tie-back of Redrock is anticipated to occur following the development of Raton South.

Flyndre (North Sea) The Flyndre project is located in the UK sector of the North Sea and we successfully completed an exploratory appraisal well in 2007. We are currently working with the project operator and other partners to finalize the field development plan and relevant operating agreements.

Selkirk (North Sea) The Selkirk project is also located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an exploratory well. We are currently working with our partners on a cost-effective development plan, including selection of a host facility.

Other Other projects consist of three onshore US wells which continue to be evaluated by various means including additional seismic work, drilling additional wells and evaluating the potential of the exploration well.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 10. Asset Retirement Obligations

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

	Nine Months Ended September 30,
	2010			2009
(millions)
Asset Retirement Obligations, Beginning Balance	$	232		$	211
Liabilities Incurred		14			6
Liabilities Settled		(35	)		(23	)
Revision of Estimate		11			23
Accretion Expense		13			11
Asset Retirement Obligations, Ending Balance	$	235		$	228

Liabilities incurred in 2010 were primarily due to the DJ Basin asset acquisition. Liabilities settled in 2010 related to US onshore assets sold and a Gulf of Mexico shelf asset. Liabilities settled in 2009 related primarily to our Gulf of Mexico Main Pass asset and a deepwater Gulf of Mexico asset. Accretion expense is included in DD&A expense in the consolidated statements of operations.

Note 11. Employee Benefit Plans

We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006. 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 the Internal Revenue Code of 1986, as amended. Net periodic benefit cost related to the retirement and restoration plans was as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
(millions)
Service Cost	$	4		$	3		$	11		$	9
Interest Cost		3			3			10			9
Expected Return on Plan Assets		(3	)		(3	)		(10	)		(10	)
Other		1			-			4			1
Net Periodic Benefit Cost	$	5		$	3		$	15		$	9

During the nine months ended September 30, 2010, we made cash contributions of $20 million to the pension plan.

Note 12. Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
(millions)
Stock-Based Compensation Expense	$	13		$	13		$	40		$	37
Tax Benefit Recognized		(5	)		(5	)		(14	)		(13	)

During the nine months ended September 30, 2010, we granted stock options and awarded shares of restricted stock, subject to service conditions, as follows:

	Number Granted/Awarded		Weighted Average Fair Value
Stock Options		1,027,187	$	25.06
Shares of Restricted Stock		420,858		75.08

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 13. Basic and Diluted Earnings (Loss) Per Share

Basic earnings (loss) per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings (loss) per share of common stock may include the effect of our shares held in a rabbi trust, outstanding stock options or shares of restricted stock, except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings (loss) per share:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
(millions, except per share amounts)
Net Income (Loss)	$	232	$	107	$	673	$	(139	)
Earnings Adjustment from Assumed Conversion of
Dilutive Shares of Common Stock in Rabbi Trust (1)		-		-		3		-
Net Income (Loss) Used for Diluted Earnings Per Share Calculation	$	232	$	107	$	676	$	(139	)

Weighted Average Number of Shares Outstanding, Basic		175		173		175		173
Incremental Shares from Assumed Conversion of
Dilutive Options, Restricted Stock and Shares of Common Stock in Rabbi Trust		2		2		3		-
Weighted Average Number of Shares Outstanding, Diluted		177		175		178		173
Earnings (Loss) Per Share, Basic	$	1.33	$	0.62	$	3.86	$	(0.80	)
Earnings (Loss) Per Share, Diluted		1.31		0.61		3.80		(0.80	)

(1)

The diluted earnings per share calculation for the nine months ended September 30, 2010 includes an increase to net income related to a deferred compensation loss from Noble Energy shares held in a rabbi trust. When dilutive, the deferred compensation gain or loss (net of tax) is excluded from net income while the Noble Energy shares held in the rabbi trust are included in the diluted share count.

Additional information is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
(millions)
Antidilutive stock options, shares of restricted stock and common shares held in a rabbi trust excluded from calculation above		2		3		2		4

Incremental stock options and shares of restricted stock excluded from calculation of diluted earnings in loss period		-		-		-		2

Note 14. Income Taxes

The income tax provision (benefit) consists of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
(millions)
Current	$	42		$	92		$	180		$	233
Deferred		24			(84	)		109			(443	)
Total Income Tax Provision (Benefit)	$	66		$	8		$	289		$	(210	)
Effective Tax Rate		22	%		7	%		30	%		60	%

Our effective tax rate decreased for the first nine months of 2010 as compared with the first nine months of 2009. For 2010, the effective rate is lower than the federal statutory rate because our income from equity method investees and other permanent differences have the impact of decreasing the effective rate when we have pre-tax income. In 2009, we had a pre-tax loss resulting in a tax benefit. In that case, the permanent differences increased the amount of the benefit and, therefore, increased the effective tax rate for the year.

As of December 31, 2009, we had provided a valuation allowance of $28 million against a deferred tax asset of the same amount for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations. In third quarter 2010, we reversed this valuation allowance and recorded a reduction in income tax expense. We now believe it is more likely than not that this deferred tax asset will be realized.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

The deferred tax benefit for the first nine months of 2009 resulted from the reversal of a deferred tax liability recorded in 2008 with respect to unrealized mark-to-market gains which were realized in 2009. In addition, we recorded a deferred tax asset with respect to impairment losses on our US oil and gas properties.

During first quarter 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. The repatriation increased US tax expense by $13 million of which $9 million was recorded in 2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows.

Unrecognized Tax Positions We do not have significant unrecognized tax benefits as of September 30, 2010. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. We did not accrue interest or penalties at September 30, 2010, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax, and we believe that we are below the minimum statutory threshold for imposition of penalties.

In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2006, Equatorial Guinea – 2007, China – 2006, Israel – 2008, UK – 2007 and the Netherlands – 2005.

Note 15. Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and certain items recorded directly to shareholders’ equity and classified as AOCL. Comprehensive income (loss) was calculated as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
(millions)
Net Income (Loss)	$	232		$	107		$	673		$	(139	)
Other Items of Comprehensive Income (Loss)
Oil and Gas Cash Flow Hedges
Realized Losses Reclassified Into Earnings		5			14			15			45
Less Tax Provision		(2	)		(5	)		(5	)		(17	)
Interest Rate Cash Flow Hedges
Unrealized Change in Fair Value		(47	)		-			(141	)		-
Less Tax Provision		16			-			49			-
Net Change in Other		1			-			2			-
Other Comprehensive Income (Loss)		(27	)		9			(80	)		28
Comprehensive Income (Loss)	$	205		$	116		$	593		$	(111	)

Note 16. Segment Information

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

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

	Consolidated			United States			West Africa			Eastern Mediterranean		North Sea		Other Int'l and Corporate
(millions)
Three Months Ended September 30, 2010
Revenues from Third Parties	$	726		$	458		$	64		$	63	$	99	$	42
Reclassification from AOCL (1)		(5	)		(5	)		-			-		-		-
Income from Equity Method Investees		34			-			34			-		-		-
Total Revenues		755			453			98			63		99		42
DD&A		231			184			10			7		20		10
Gain on Asset Sale		(114	)		(114	)		-			-		-		-
Asset Impairments		100			100			-			-		-		-
(Gain) Loss on Commodity Derivative Instruments		(38	)		(49	)		11			-		-		-
Income (Loss) Before Income Taxes		298			211			64			51		59		(87	)
Three Months Ended September 30, 2009
Revenues from Third Parties	$	610		$	365		$	95		$	53	$	51	$	46
Reclassification from AOCL (1)		(14	)		(7	)		(7	)		-		-		-
Income from Equity Method Investees		25			-			25			-		-		-
Total Revenues		621			358			113			53		51		46
DD&A		205			172			9			6		10		8
(Gain) Loss on Commodity Derivative Instruments		28			34			(6	)		-		-		-
Income (Loss) Before Income Taxes		115			42			94			43		25		(89	)
Nine Months Ended September 30, 2010
Revenues from Third Parties	$	2,169		$	1,425		$	243		$	144	$	227	$	130
Reclassification from AOCL (1)		(15	)		(15	)		-			-		-		-
Income from Equity Method Investees		85			-			85			-		-		-
Total Revenues		2,239			1,410			328			144		227		130
DD&A		662			543			28			18		45		28
Gain on Asset Sale		(114	)		(114	)		-			-		-		-
Asset Impairments		100			100			-			-		-		-
Gain on Commodity Derivative Instruments		(280	)		(277	)		(3	)		-		-		-
Income (Loss) Before Income Taxes		962			681			258			110		132		(219	)
Nine Months Ended September 30, 2009
Revenues from Third Parties	$	1,546		$	964		$	238		$	105	$	120	$	119
Reclassification from AOCL (1)		(45	)		(23	)		(22	)		-		-		-
Income from Equity Method Investees		52			-			52			-		-		-
Total Revenues		1,553			941			268			105		120		119
DD&A		601			505			27			16		28		25
Gain on Asset Sale		(24	)		-			-			-		-		(24	)
Asset Impairments		437			437			-			-		-		-
Loss on Commodity Derivative Instruments		95			76			19			-		-		-
Income (Loss) Before Income Taxes		(349	)		(439	)		176			77		49		(212	)
September 30, 2010
Goodwill	$	696		$	696		$	-		$	-	$	-	$	-
Total Assets		13,089			9,050			2,172			818		730		319
December 31, 2009
Goodwill		758			758			-			-		-		-
Total Assets		11,807			8,669			1,731			486		635		286

(1)	Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues.

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Noble Energy, Inc.

Notes to Consolidated Financial Statements

(unaudited)

Note 17. Commitments and Contingencies

Legal Proceedings We are involved in various legal proceedings 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 believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.

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Item 2. Management’s Discussion and Analysis of Financial Condition

and Results of Operations

EXECUTIVE OVERVIEW

We are an independent energy company engaged in global crude oil, natural gas and NGL exploration and production. Our strategy is to achieve growth in earnings and cash flows through the continued expansion of a high quality portfolio of producing assets that is diversified among US and international projects, crude oil and natural gas, and near, medium and long-term opportunities.

Our accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion.

Our financial results for third quarter 2010 included:

net income of $232 million, as compared with net income of $107 million for third quarter 2009;

gain of $114 million on sale of certain non-core onshore US assets;

asset impairment charges of $100 million related to certain US assets;

gain on commodity derivative instruments of $38 million (including unrealized mark-to-market gain of $5 million) as compared with a loss on commodity derivative instruments of $28 million (including unrealized mark-to-market loss of $149 million) for third quarter 2009;

diluted earnings per share of $1.31, as compared with diluted earnings per share of $0.61 for third quarter 2009;

cash flow provided by operating activities of $608 million, as compared with $488 million for third quarter 2009;

capital spending (excluding $80 million impact of the FPSO accrual) of $608 million as compared with $224 million for third quarter 2009;

net decrease of $32 million principal amount of debt, excluding $188 million increase in FPSO lease accrual, from December 31, 2009;

ending cash and cash equivalents balance of $1.1 billion at September 30, 2010 as compared with $1 billion at December 31, 2009;

total liquidity of $2.9 billion at September 30, 2010, consisting of ending cash balance plus funds available under credit facility, as compared with $2.7 billion at December 31, 2009; and

ratio of debt-to-book capital of 25% (including FPSO lease accrual) at both September 30, 2010 and December 31, 2009.

Significant operational highlights for third quarter 2010 included:

record total sales volumes of 230 MBoepd;

record Israel natural gas sales of 178 MMcfpd;

sanctioned Tamar project, offshore Israel;

completed two new Mari-B wells, offshore Israel, maintaining field deliverability of 600 MMcfpd, gross;

produced Central DJ Basin liquid volumes of 30 MBpd, up over 35% from the third quarter 2009;

increased Central DJ Basin position to over 830,000 net acres;

closed on the previously-announced sale of certain Mid-Continent and Illinois Basin assets for $552 million;

commenced completion activities at Santa Cruz and Isabela in the deepwater Gulf of Mexico; and

concluded field drilling and initiated completions at Aseng, offshore Equatorial Guinea.

Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium - Update

In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for another operator, sank after an apparent blowout and fire. The resulting leak caused a significant oil spill. In May 2010, in response to the Incident, the President of the United States announced a six-month moratorium on drilling in the deepwater Gulf of Mexico (Federal Deepwater Moratorium or the Moratorium). Under the Federal Deepwater Moratorium, no new drilling, including sidetracks and bypasses of wells, were allowed in water depths greater than 500 feet. As a result, all deepwater drilling activities in progress at the time the Moratorium was announced were suspended.

During third quarter 2010, the Outer Continental Shelf Safety Oversight Board, established by the Secretary of the Interior, issued its recommendations for the strengthening of permitting, inspections, enforcement and environmental stewardship. In addition, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) developed an implementation plan for the recommendations, many of which are already underway or planned.

On September 30, 2010, the Department of the Interior announced two new rules (The Drilling Safety Rule and the Workplace Safety Rule) that are intended to improve drilling safety by strengthening requirements for safety equipment, well control systems, and blowout prevention practices on offshore oil and gas operations, and improve workplace safety.

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The Secretary of the Interior lifted the Moratorium on October 12, 2010. In order for an operator like us to resume deepwater drilling, it is required to comply with existing and newly developed regulations. The new regulations, among other things, require the chief executive officer of each operator seeking to perform deepwater drilling to certify to the BOEMRE their compliance with all safety regulations and demonstrate they possess the necessary equipment to contain a deepwater well blowout. In light of the newly developed regulations, delays in the permitting process, difficulty or delay in implementing legislative or regulatory changes, or unavailability of drilling rigs, support vessels and equipment, and other oilfield services could delay the resumption of activities in the Gulf of Mexico.

Despite the Federal Deepwater Moratorium, we have been able to move forward on two of our major deepwater projects.

Galapagos Project – The Galapagos project includes the previously-drilled Santa Cruz and Isabela wells. During the third quarter of 2010, we obtained permits to perform completion work and commenced completion operations.

Gunflint Project – We are currently reviewing host platform options including subsea tieback to existing third-party host, procurement and modification of existing platform, or new construction. If we are able to connect to an existing third-party host, the project could have an accelerated completion schedule, thereby absorbing time lost to a Moratorium-related delay of up to a year.

We believe an increase in development costs or the delay in drilling activities caused by the Moratorium will not have a significant impact on the total cash flows we expect to derive from the Galapagos and Gunflint projects, which are expected to commence in 2011 and 2015, respectively.

The Deepwater Horizon Incident is likely to have a significant and lasting effect on the US offshore energy industry, and will likely result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased politicization of the industry. Other countries, including some in which we currently conduct business, are considering legislative or regulatory changes which could also have an impact on offshore drilling activities. These changes may result in increases in our operating and development costs and extend project development timelines because of new regulatory requirements. There may be other impacts of which we are not aware at this time.

See also Risk and Insurance Program Update and Liquidity and Capital Resources – Capital Structure/Financing Strategy, below.

Onshore US, West Africa and Eastern Mediterranean Update

Sale of Onshore US Assets On August 12, 2010, we closed the sale of certain non-core assets in the Mid-Continent and Illinois Basin areas for sales proceeds of $552 million and recorded a gain of $114 million on the sale. The properties represented approximately 5.7 MBoepd of production and 32 MMBoe of reserves.

DJ Basin Asset Acquisition On March 1, 2010, we closed the acquisition of substantially all of the US Rockies upstream assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. The transaction increased our presence in the Wattenberg field and further expanded our opportunity in the DJ Basin. The acquisition added approximately 10 MBoepd to our daily production base and approximately 46 MMBoe of proved reserves expanding our acreage and development opportunity in the area. A majority of the reserves are within the Wattenberg field, where our largest onshore US asset is located.

Exploration Program Continued investment in significant exploration remains a key component to our strategy. During third quarter 2010, our exploration teams remained very active with additional horizontal test activities in the Niobrara formation onshore US, and in October we spud a well on the Leviathan prospect, offshore Israel. We are in the process of integrating recently-acquired 3-D seismic information for our properties offshore Cameroon and reprocessing seismic information on Blocks O and I offshore Equatorial Guinea, in preparation for future drilling programs. In addition, we have begun acquiring 3-D seismic in Nicaragua.

Major Development Projects During third quarter 2010, we continued to advance our major development projects in the Central DJ Basin onshore US, at the Galapagos project in the deepwater Gulf of Mexico, the Aseng oil field offshore Equatorial Guinea, and the Tamar project offshore Israel. At Galapagos, we received permits for completion work at the Santa Cruz and Isabela wells. We completed drilling at Aseng, and conversion work is ongoing for the FPSO vessel that will be used in the Aseng development. In addition, we are continuing FEED (front end engineering and design) work for the Alen project and recently submitted the Plan of Development to the government of Equatorial Guinea. In Israel, we sanctioned the development plan for Tamar and are negotiating additional natural gas sales contracts.

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Asset Impairments

During third quarter 2010, we recorded asset impairment charges of $100 million related to some of our US assets. The impairments were due to recent declines in natural gas prices, recent drilling results and the classification of non-core, onshore US assets as held-for-sale at September 30, 2010.

A decrease in forward natural gas prices during fourth quarter 2010 could result in significant additional impairment charges. Our Piceance Basin (western Colorado) and Shattuck (western Oklahoma) properties are significantly natural gas reserves and therefore are sensitive to declines in natural gas prices. These assets, which have a combined net book value of approximately $950 million at September 30, 2010, are at risk of impairment if future NYMEX Henry Hub natural gas prices experience further decline. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a substantial decrease in forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. See Item 1. Financial Statements – Note 4. Asset Impairments.

Sales Volumes

On a BOE basis, total sales volumes were 6% higher third quarter 2010 as compared with third quarter 2009, and our mix of sales volumes was 38% global liquids, 33% international natural gas with long-term pricing contracts, and 29% US natural gas. Production was higher in the onshore US areas due to record production in the Wattenberg field primarily due to the recent acquisition of producing properties and continued field development. In Israel, there was an increase in demand for natural gas to produce electricity due to warmer weather, and a higher percentage of the demand was met by production from our properties. There was also an increase in crude oil volumes lifted in the North Sea. These increases were partially offset by a decrease in crude oil volumes lifted in Equatorial Guinea.

Commodity Price Changes and Hedging

The liquids (crude oil) market has been strengthening this year, showing benefit from the global economic recovery. As a result, third quarter 2010 average realized crude oil prices were significantly higher than those we experienced third quarter 2009.

However, the natural gas market remains weak. Although there has been some recovery in natural gas prices this year, prices are still low compared to 2008 levels.

We have hedged approximately 39% of our expected global crude oil production and 68% of our expected domestic natural gas production for the remainder of 2010.

Current Conditions in Ecuador The economic and political environment in Ecuador has become increasingly unsettled. See Item 1A. Risk Factors – Our operations and investment in Ecuador may be adversely affected by the country’s new hydrocarbon reform bill.

OUTLOOK

Our expected crude oil, natural gas and NGL production for the remainder of 2010 may be impacted by several factors including:

overall level and timing of capital expenditures which, dependent upon our drilling success and notwithstanding the other factors listed below, are expected to maintain our near-term production volumes (See 2010 Budget discussion below);

natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas of our US operations and in the North Sea;

impact of potential legislative and regulatory changes on deepwater Gulf of Mexico operating and safety standards for producing activities due to the Deepwater Horizon Incident;

variations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to potential downtime at the methanol, LPG and/or LNG plants;

Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth and competing deliveries of natural gas from Egypt;

variations in North Sea sales volumes due to potential FPSO downtime and timing of liftings;

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

potential hurricane-related volume curtailments in the deepwater Gulf of Mexico and Gulf Coast areas;

potential winter storm-related volume curtailments in the Northern region of our US operations;

potential pipeline and processing facility capacity constraints in the Rocky Mountains and deepwater Gulf of Mexico;

potential volume curtailments in Ecuador due to unsettled economic and political environment;

impact of asset purchases;

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timing of significant project completion and initial production; and

impact of sales of non-core operating assets expected to close in the fourth quarter 2010.

2010 Budget We have updated our business plan for the remainder of 2010 to take into account the impact of the Federal Deepwater Moratorium as well as the subsequent delay in the resumption of activities now that the Moratorium has been lifted. The delay in spending caused by the Moratorium will have a positive effect on our short-term net cash flows due to reductions in capital spending.

Our total capital investment program for 2010 is now estimated at $2.2 billion, $300 million less than the original budget, with approximately 37% going toward major project investments, 17% for exploration and appraisal activities, and the remaining 46% for ongoing maintenance and near-term development opportunities. We have planned to spend about $832 million on major project investments, with the majority of capital directed toward the development of Galapagos in the deepwater Gulf of Mexico, Aseng offshore Equatorial Guinea and Tamar offshore Israel. We expect to spend approximately $380 million for exploration activities. The remainder of our budget is focused on liquid-rich and emerging opportunities onshore US, as well as near-term development projects in Israel, the North Sea and China.

Excluded from the budget discussed above is the $498 million total purchase price for the DJ Basin asset acquisition on March 1, 2010, as well as $258 million of non-cash capital expected to be accrued for the Aseng FPSO capital lease.

We have a well-balanced and diverse domestic and international portfolio as well as ample liquidity which allow us to engage in activities that mitigate the impact of the Moratorium. Numerous opportunities are available to us, and it is possible that we may reallocate capital to onshore US or international locations. We will continue to review our options as the legislative and regulatory response to the Deepwater Horizon Incident unfolds.

We expect that the remaining 2010 budget will be funded primarily from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing. We will evaluate the level of capital spending throughout the year based on drilling results, commodity prices, cash flows from operations, the full impact of the Federal Deepwater Moratorium and legislative response, and property acquisitions and divestitures. Our capital spending is integrated with our goal of maintaining a strong balance sheet and ample liquidity. See Liquidity and Capital Resources – Capital Structure/Financing Strategy, below.

Risk and Insurance Program Update In accordance with industry practices, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from significant unfavorable losses resulting from damages to, or the loss of, physical assets or loss of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets and including such occurrences as well blowouts and resulting oil spills, at a level that balances cost of insurance with our assessment of risk and our ability to achieve a reasonable rate of return on our investments. We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.

We expect the future availability and cost of insurance to be impacted by the recent Deepwater Horizon Incident. Impacts could include: tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico, including possible increases in liability caps for claims of damages from oil spills. We will continue to monitor the expected regulatory and legislative response and its impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection, at a level that we can afford considering the cost of insurance and our desired rates of return, against disruption to our operations and cash flows.

We currently carry insurance protection for our net share of any potential financial losses occurring as a result of events such as the Deepwater Horizon Incident. This protection consists of $250 million of well control, pollution cleanup and consequential damages coverage and $251 million of additional pollution cleanup and consequential damages coverage, which also covers third party personal injury and death. Consequently if we were to experience an accident similar to the Deepwater Horizon Incident, our total coverage for cleanup and consequential damages would be $501 million for our net share, subject to reduction for claims related to well control and third party damages.

We are a member of Oil Insurance Limited (OIL), a mutual insurance company. Due to recent reductions in windstorm coverage by OIL, we now believe it is commercially more reasonable to self insure against this particular risk. Therefore, we have elected to self insure our 2010 windstorm exposure. Recent abandonment activities on the Gulf of Mexico shelf have significantly reduced our windstorm exposure as our remaining Gulf of Mexico assets are primarily subsea operations. However, we are now responsible for substantially all windstorm-related damages to these assets.

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RESULTS OF OPERATIONS

Revenues

Revenues were as follows:

					Increase (Decrease) from Prior Year
	2010		2009		Increase (Decrease) from Prior Year
(millions)
Three Months Ended September 30,
Oil, Gas and NGL Sales	$	704	$	573		23	%
Income from Equity Method Investees		34		25		36	%
Other Revenues		17		23		(26	%)
Total	$	755	$	621		22	%

Nine Months Ended September 30,
Oil, Gas and NGL Sales	$	2,102	$	1,440		46	%
Income from Equity Method Investees		85		52		63	%
Other Revenues		52		61		(15	%)
Total	$	2,239	$	1,553		44	%

Changes in revenues are discussed below.

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Oil, Gas and NGL Sales Average daily sales volumes and average realized sales prices were as follows:

	Sales Volumes								Average Realized Sales Prices
	Crude Oil & Condensate		Natural Gas		NGLs		Total		Crude Oil & Condensate		Natural Gas		NGLs
	(MBpd)		(MMcfpd)		(MBpd)		(MBoepd) (1)		(Per Bbl)		(Per Mcf)		(Per Bbl)
Three Months Ended September 30, 2010
United States (2)		41		399		13		120	$	71.28	$	3.87	$	36.30
Equatorial Guinea (3) (4)		8		243		-		49		76.28		0.27		-
Israel		-		178		-		30		-		3.85		-
North Sea		13		6		-		14		78.89		5.82		-
Ecuador (5)		-		28		-		5		-		-		-
China		4		-		-		4		71.37		-		-
Total Consolidated Operations		66		854		13		222		73.41		2.82		36.30
Equity Investees (6)		2		-		6		8		77.03		-		50.83
Total Operations		68		854		19		230	$	73.53	$	2.82	$	40.77
Three Months Ended September 30, 2009
United States (2)		39		397		10		115	$	62.30	$	3.05	$	25.39
Equatorial Guinea (3) (4)		14		228		-		52		63.10		0.27		-
Israel		-		144		-		24		-		3.95		-
North Sea		8		5		-		9		69.56		4.63		-
Ecuador (5)		-		28		-		5		-		-		-
China		4		-		-		4		62.75		-		-
Total Consolidated Operations		65		802		10		209		63.36		2.41		25.39
Equity Investees (6)		2		-		6		8		66.33		-		38.26
Total Operations		67		802		16		217	$	63.46	$	2.41	$	30.25
Nine Months Ended September 30, 2010
United States (2)		40		399		13		119	$	73.31	$	4.38	$	40.17
Equatorial Guinea (3) (4)		11		221		-		48		75.44		0.27		-
Israel		-		129		-		22		-		4.08		-
North Sea		10		7		-		11		77.33		5.25		-
Ecuador (5)		-		28		-		4		-		-		-
China		4		-		-		4		73.27		-		-
Total Consolidated Operations		65		784		13		208		74.30		3.13		40.17
Equity Investees (6)		2		-		5		7		75.84		-		52.04
Total Operations		67		784		18		215	$	74.35	$	3.13	$	43.58
Nine Months Ended September 30, 2009
United States (2)		37		401		10		113	$	50.45	$	3.36	$	24.70
Equatorial Guinea (3) (4)		14		238		-		54		51.94		0.27		-
Israel		-		117		-		20		-		3.27		-
North Sea		7		5		-		8		57.61		5.94		-
Ecuador (5)		-		24		-		4		-		-		-
China		4		-		-		4		49.76		-		-
Total Consolidated Operations		62		785		10		203		51.55		2.40		24.70
Equity Investees (6)		2		-		6		8		56.42		-		31.65
Total Operations		64		785		16		211	$	51.70	$	2.40	$	27.40

(1)

Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given recent commodity price differentials, the price for a barrel of oil equivalent for natural gas is significantly less than the price for a barrel of oil.

(2)	Average realized crude oil and condensate prices reflect reductions of $1.25 per Bbl and $1.89 per Bbl for third quarter 2010 and 2009, respectively, and $1.31 per Bbl and $2.28 per Bbl for the first nine months of 2010 and 2009, respectively, from hedging activities.

Average realized natural gas prices reflect a reduction of $0.01 per Mcf for the first nine months of 2010 and an increase of $0.01 per Mcf for third quarter 2009 from hedging activities. The price increase/reduction resulted from hedge gains/losses that were previously deferred in AOCL. The average realized natural gas prices for the third quarter of 2010 and first nine months of 2009 were not impacted by hedging activities, as the net deferred gains reclassified from AOCL were de minimis.

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(3)

Average realized crude oil and condensate prices reflect a reduction of $5.32 per Bbl for third quarter 2009 and $5.84 per Bbl for the first nine months of 2009 from hedging activities. The price reduction resulted from hedge losses that were previously deferred in AOCL. All hedge gains or losses relating to Equatorial Guinea production had been reclassified to revenues by December 31, 2009.

(4)	Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.

(5)	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 are included in other revenues. See Item 1. Financial Statements – Note 2. Basis of Presentation.

(6)	Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Equity Method Investees below.

If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity derivative instruments in our consolidated statements of operations, had been included in oil and gas revenues, the effect on average realized prices would have been as follows:

	Commodity Price Increase (Decrease)
	2010					2009
	Crude Oil & Condensate			Natural Gas		Crude Oil & Condensate		Natural Gas
	(Per Bbl)			(Per Mcf)		(Per Bbl)		(Per Mcf)
Three Months Ended September 30,
United States	$	0.86		$	0.87	$	9.29	$	1.95
Equatorial Guinea		(2.09	)		-		12.99		-
Total Consolidated Operations		0.27			0.41		8.41		1.00
Total Operations		0.26			0.41		8.14		1.00

Nine Months Ended September 30,
United States	$	0.16		$	0.63	$	14.38	$	1.84
Equatorial Guinea		(1.86	)		-		17.48		-
Total Consolidated Operations		(0.22	)		0.32		12.46		0.97
Total Operations		(0.21	)		0.32		12.09		0.97

An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows:

	Sales Revenues
	Crude Oil & Condensate		Natural Gas			NGLs		Total
(millions)
Three Months Ended September 30, 2009	$	377	$	172		$	24	$	573
Changes due to
Increase in Sales Volumes		8		11			7		26
Increase in Sales Prices Before Hedging		52		31			13		96
Change in Amounts Reclassified from AOCL		9		-			-		9
Three Months Ended September 30, 2010	$	446	$	214		$	44	$	704

Nine Months Ended September 30, 2009	$	876	$	498		$	66	$	1,440
Changes due to
Increase (Decrease) in Sales Volumes		35		(4	)		22		53
Increase in Sales Prices Before Hedging		371		153			55		579
Change in Amounts Reclassified from AOCL		31		(1	)		-		30
Nine Months Ended September 30, 2010	$	1,313	$	646		$	143	$	2,102

Crude oil and condensate sales – Revenues from crude oil and condensate sales increased during the third quarter and first nine months of 2010 as compared with 2009 due to the following:

an increase in total consolidated average realized prices due to increased demand resulting from the global economic recovery;

increased production from the Central DJ Basin in the northern region of our US operations due to ongoing development activity in the Wattenberg field and the horizontal Niobrara development;

additional production from the DJ Basin asset acquisition earlier in 2010;

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crude oil production from a sidetrack to a Swordfish natural gas well that commenced production first quarter 2010;

renewed production from Ticonderoga in the deepwater Gulf of Mexico which was off-line first quarter 2009 as a result of hurricane damage to third-party processing and pipeline facilities; and

an increase in North Sea sales volumes primarily as a result of increased deliverability at the Dumbarton complex, which included the addition of two Lochranza wells in 2010;

partially offset by

a decrease in onshore US volumes due to the sale of mature oil assets;

a decrease in deepwater Gulf of Mexico volumes due to natural field decline and third party downstream facility constraints;

a decrease in onshore US volumes due to natural field decline in the Mid-Continent and Gulf Coast areas; and

a decrease in Equatorial Guinea sales volumes due to the timing of liftings.

Revenues from crude oil and condensate sales included deferred losses of $5 million and $14 million for third quarter 2010 and 2009, respectively, and $14 million and $45 million for the first nine months of 2010 and 2009, respectively, reclassified from AOCL and related to commodity derivative instruments previously accounted for as cash flow hedges.

Natural gas sales – Revenues from natural gas sales increased during the third quarter and first nine months of 2010 as compared with 2009 due to the following:

an increase in total consolidated and US average realized prices due to increased demand resulting from the economic recovery;

an increase in Israel average realized prices for the first nine months of 2010, which are tied to the global liquid markets;

increased production from the Central DJ Basin in the northern region of our US operations due to ongoing development activity in the Wattenberg field and the horizontal Niobrara development;

additional production from the DJ Basin asset acquisition earlier in 2010; and

an increase in Israel sales volumes due to an increase in demand for our natural gas driven by increased electricity production due to warmer weather and lower levels of competitor natural gas imports from Egypt;

partially offset by

a decrease in Equatorial Guinea sales volumes for the first nine months of 2010 due to the planned shut-down of the Alba field for facilities maintenance and repair;

lower natural gas production in the deepwater Gulf of Mexico at Raton and Swordfish; and

natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-Continent areas.

Revenues from natural gas sales included deferred losses of $1 million for the first nine months of 2010 reclassified from AOCL and related to commodity derivative instruments previously accounted for as cash flow hedges. Revenues for the third quarter of 2010 and the third quarter and first nine months of 2009 included de minimis amounts reclassified from AOCL.

NGL sales – Most of our US NGL production is from the Wattenberg field and deepwater Gulf of Mexico. NGL sales revenues increased during the third quarter and first nine months of 2010 as compared with 2009 due to an increase in sales volumes from the Wattenberg field and an increase in consolidated average realized prices which benefitted from increased demand resulting from the global economic recovery.

Income from Equity Method Investees We have a 45% interest in Atlantic Methanol Production Company, LLC, which owns and operates a methanol plant and related facilities and a 28% interest in Alba Plant LLC, which owns and operates a liquefied petroleum gas processing plant. Both plants are located onshore in Equatorial Guinea. Equity method investments are included in other noncurrent assets in our consolidated balance sheets, our share of earnings is reported as income from equity method investees in our consolidated statements of operations, and our share of dividends is reported within cash flows from operating activities in our consolidated statements of cash flows.

The increase in income from equity method investees for the third quarter and first nine months of 2010 as compared with 2009 was due to an increase in average realized condensate, LPG and methanol prices from increased demand due to the global economic recovery. Condensate and LPG sales volumes and average realized prices are included in the average daily sales volumes and average realized sales prices table above. Methanol sales volumes and prices were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Methanol Sales Volumes in MMgal		33		41		102		109
Methanol Sales Prices	$	0.84	$	0.64	$	0.84	$	0.52

The increase in dividends from equity method investees to $91 million for the first nine months of 2010 as compared with $37 million for the first nine months of 2009 was due to their increased profitability.

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Other Revenues Other revenues include electricity sales and other revenues from operating activities. See Item 1. Financial Statements – Note 2. Basis of Presentation.

Operating Costs and Expenses

Operating costs and expenses were as follows:

							Increase (Decrease) from Prior Year
	2010			2009			Increase (Decrease) from Prior Year
(millions)
Three Months Ended September 30,
Production Expense	$	141		$	131			8	%
Exploration Expense		35			27			30	%
Depreciation, Depletion and Amortization		231			205			13	%
General and Administrative		65			53			23	%
Gain on Asset Sale		(114	)		-			N/M
Asset Impairments		100			-			N/M
Other Operating (Income) Expense, Net		4			34			(88	%)
Total	$	462		$	450			3	%
Nine Months Ended September 30,
Production Expense	$	430		$	390			10	%
Exploration Expense		167			102			64	%
Depreciation, Depletion and Amortization		662			601			10	%
General and Administrative		194			173			12	%
Gain on Asset Sale		(114	)		(24	)		N/M
Asset Impairments		100			437			(77	%)
Other Operating (Income) Expense, Net		59			46			28	%
Total	$	1,498		$	1,725			(13	%)

(N/M) The percentage is so large that it is not meaningful.

Changes in operating costs and expenses are discussed below.

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Production Expense Components of production expense were as follows:

	Total per BOE (1)		Total		United States		Equatorial Guinea		Israel		North Sea		Other Int'l, Corporate
(millions, except unit rate)
Three Months Ended September 30, 2010
Lease Operating Expense (2)	$	4.65	$	95	$	60	$	11	$	2	$	16	$	6
Production and Ad Valorem Taxes		1.40		29		24		-		-		-		5
Transportation Expense		0.84		17		14		-		-		2		1
Total Production Expense	$	6.89	$	141	$	98	$	11	$	2	$	18	$	12
Three Months Ended September 30, 2009
Lease Operating Expense (2)	$	4.57	$	88	$	55	$	13	$	3	$	13	$	4
Production and Ad Valorem Taxes		1.28		25		21		-		-		-		4
Transportation Expense		0.93		18		16		-		-		1		1
Total Production Expense	$	6.78	$	131	$	92	$	13	$	3	$	14	$	9
Nine Months Ended September, 2010
Lease Operating Expense (2)	$	4.97	$	283	$	193	$	31	$	7	$	38	$	14
Production and Ad Valorem Taxes		1.69		96		80		-		-		-		16
Transportation Expense		0.90		51		44		-		-		5		2
Total Production Expense	$	7.56	$	430	$	317	$	31	$	7	$	43	$	32
Nine Months Ended September, 2009
Lease Operating Expense (2)	$	5.07	$	281	$	196	$	33	$	7	$	32	$	13
Production and Ad Valorem Taxes		1.19		66		58		-		-		-		8
Transportation Expense		0.77		43		37		-		-		3		3
Total Production Expense	$	7.03	$	390	$	291	$	33	$	7	$	35	$	24

(1)	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

(2)	Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.

For the third quarter and first nine months of 2010, total production expense increased as compared with 2009 due to the following:

an increase in lease operating expense in the US due to the acquisition of producing properties;

an increase in North Sea lease operating expense due to higher sales volumes;

an increase in production taxes in the US and China due to higher commodity prices; and

an increase in transportation expense in the Wattenberg field due to increased crude oil and condensate production and the use of a new interstate crude oil transportation pipeline system to market production.

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Oil and Gas Exploration Expense Components of oil and gas exploration expense were as follows:

	Total		United States			West Africa (1)		Eastern Mediterranean (2)		North Sea		Other Int'l, Corporate (3)
(millions)
Three Months Ended September 30, 2010
Dry Hole Cost	$	2	$	1		$	-	$	-	$	-	$	1
Seismic		17		4			-		4		-		9
Staff Expense		12		(4	)		1		1		1		13
Other		4		4			-		-		-		-
Total Exploration Expense	$	35	$	5		$	1	$	5	$	1	$	23
Three Months Ended September 30, 2009
Dry Hole Cost	$	3	$	3		$	-	$	-	$	-	$	-
Seismic		7		5			-		2		-		-
Staff Expense		17		4			3		-		-		10
Other		-		-			-		-		-		-
Total Exploration Expense	$	27	$	12		$	3	$	2	$	-	$	10
Nine Months Ended September 30, 2010
Dry Hole Cost	$	57	$	53		$	3	$	-	$	-	$	1
Seismic		52		32			5		6		-		9
Staff Expense		46		4			4		2		2		34
Other		12		12			-		-		-		-
Total Exploration Expense	$	167	$	101		$	12	$	8	$	2	$	44
Nine Months Ended September 30, 2009
Dry Hole Cost	$	11	$	8		$	4	$	-	$	-	$	(1	)
Seismic		37		33			-		4		-		-
Staff Expense		50		10			9		1		1		29
Other		4		4			-		-		-		-
Total Exploration Expense	$	102	$	55		$	13	$	5	$	1	$	28

(1)	West Africa includes Equatorial Guinea and Cameroon.

(2)	Eastern Mediterranean includes Israel and Cyprus.

(3)	Other International includes China, Ecuador and other amounts spent in support of various international new ventures.

Oil and gas exploration expense for the third quarter and first nine months of 2010 increased as compared with 2009. US dry hole expense was associated with the Double Mountain exploration well in the deepwater Gulf of Mexico, which found noncommercial quantities of hydrocarbons. US seismic expense was incurred in support of Central Gulf of Mexico lease sales and West Africa seismic expenditures represented the acquisition of 3-D seismic information for Cameroon.

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Depreciation, Depletion and Amortization DD&A expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
(millions, except unit rate)
DD&A Expense	$	227	$	201	$	649	$	590
Accretion of Discount on Asset Retirement Obligations		4		4		13		11
Total DD&A Expense	$	231	$	205	$	662	$	601
Unit Rate per BOE (1)	$	11.35	$	10.68	$	11.64	$	10.86

(1)	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

Total DD&A expense for the third quarter and first nine months of 2010 increased as compared with 2009 due to the following:

higher production in the DJ Basin, Piceance and Western Oklahoma areas of our US operations, which have high DD&A rates relative to production from Equatorial Guinea and Israel which have lower DD&A rates;

ongoing capital spending in the Northern region of our US operations;

higher sales volumes in the North Sea; and

impact of lower year-end 2009 commodity prices on oil and gas reserves;

partially offset by

lower DD&A expense in the Mid-Continent area which has a reduced net book value resulting from an impairment recorded at the end of 2009; and

the cessation of DD&A associated with assets held-for-sale and/or sold during the nine months ended September 30, 2010.

The unit rate per BOE increased for the third quarter and first nine months of 2010 as compared with 2009 due to the change in mix of production, including decreases in lower-cost sales volumes from Equatorial Guinea and the impact of lower year-end 2009 commodity prices on oil and gas reserves, offset by a lower rate for the Mid-Continent area and the cessation of DD&A associated with assets held-for-sale.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
G&A Expense (millions)	$	65	$	53	$	194	$	173
Unit Rate per BOE (1)	$	3.20	$	2.78	$	3.42	$	3.11

(1)	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

G&A expense for the third quarter and first nine months of 2010 increased as compared with 2009 primarily due to additional expenses relating to personnel and office costs in support of our major projects.

Gain on Asset Sales Gain on asset sales for the first nine months of 2010 and 2009 was related to the sale of non-core onshore US assets and the recognition of the gain on the sale of Argentina assets, respectively. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.

Asset Impairments See Item 1. Financial Statements – Note 4. Asset Impairments.

Other Operating (Income) Expense, Net Other operating (income) expense, net includes rig contract termination expense related to the Federal Deepwater Moratorium, electricity generation expense and other items of operating income or expense. See Item 1. Financial Statements – Note 2. Basis of Presentation and Note 5. Impact of Federal Deepwater Moratorium.

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Other (Income) Expense

Other (income) expense was as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
(millions)
(Gain) Loss on Commodity Derivative Instruments	$	(38	)	$	28	$	(280	)	$	95
Interest, Net of Amount Capitalized		21			23		60			64
Other Non-Operating (Income) Expense, Net		12			5		(1	)		18
Total	$	(5	)	$	56	$	(221	)	$	177

(Gain) Loss on Commodity Derivative Instruments (Gain) loss on commodity derivative instruments is a result of mark-to-market accounting. See Item 1. Financial Statements – Note 7. Derivative Instruments and Hedging Activities and Note 8. Fair Value Measurements and Disclosures.

Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
(millions, except unit rate)
Interest Expense	$	36		$	35		$	105		$	94
Capitalized Interest		(15	)		(12	)		(45	)		(30	)
Interest Expense, Net	$	21		$	23		$	60		$	64
Unit Rate, per BOE (1)	$	1.02		$	1.21		$	1.05		$	1.16

(1)	Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.

Interest expense increased for the first nine months of 2010, as compared with 2009. The increase in interest expense primarily relates to our $1 billion 8¼% senior unsecured notes due March 1, 2019, which we issued on February 27, 2009. The higher rate on the senior unsecured notes replaced the substantially lower rate applicable to our revolving credit facility. See also Liquidity and Capital Resources – Financing Activities below.

The increases in the amount of interest capitalized are due to higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, West Africa, and Israel and the higher interest rate associated with our $1 billion 8¼% senior unsecured notes due March 1, 2019.

Other Non-operating (Income) Expense, Net Other non-operating (income) expense, net includes deferred compensation (income) expense, interest income and other (income) expense. The decrease for the first nine months of 2010 was due to a reduction in deferred compensation expense and increases in interest and other income. See Item 1. Financial Statements – Note 2. Basis of Presentation.

Income Tax Provision (Benefit)

See Item 1. Financial Statements – Note 14. Income Taxes for a discussion of the change in our effective tax rate during the first nine months of 2010 as compared with 2009.

LIQUIDITY AND CAPITAL RESOURCES

Capital Structure/Financing Strategy

We strive to employ a capital structure, emphasizing a strong balance sheet, and financing strategy designed to provide ample liquidity throughout the commodity price cycle, sufficient to fund growth and major project development. Specifically, we strive to retain the ability to fund long-cycle, capital intensive development projects while also maintaining the capability for financially attractive periodic mergers and acquisitions activity, such as the DJ Basin asset acquisition on March 1, 2010. We endeavor to maintain an investment grade debt rating in support of these objectives. We also utilize a commodity price hedging program to reduce commodity price uncertainty and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our operations and cash flows. See Risk and Insurance Program Update, above.

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We have reduced our total capital investment program for 2010 to $2.2 billion from $2.5 billion. We expect funding to be provided by cash flows from operations, cash on hand and borrowings under our revolving credit facility and/or other financing. Cash may also be generated by occasional sales of non-strategic crude oil and natural gas properties.

Our capital structure approach allows us to maintain a strong liquidity position. At September 30, 2010, we had over $1 billion in cash and significant remaining capacity under our credit facility for a total liquidity of $2.9 billion. This strong financial capacity, coupled with our well-balanced and diverse portfolio, provides us with flexibility in our investment decisions.

Information regarding cash and debt balances was as follows:

	September 30,			December 31,
	2010			2009
(millions, except percentages)
Cash and Cash Equivalents	$	1,149		$	1,014
Amount Available to be Borrowed Under Credit Facility		1,750			1,718
Total Liquidity	$	2,899		$	2,732

Total Debt (Excluding Unamortized Discount)	$	2,201		$	2,045
Total Shareholders' Equity		6,737			6,157
Debt-to-Capital Ratio (1)		25	%		25	%

(1)	We define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.

Cash and Cash Equivalents We had $1.1 billion in cash and cash equivalents at September 30, 2010, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. A majority of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if repatriated. We currently intend to use our international cash to fund international projects, including the planned developments in Equatorial Guinea and Israel.

Credit Facility We have an unsecured revolving credit facility that matures December 9, 2012. The commitment is $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. We ended third quarter 2010 with almost $1.75 billion remaining available for borrowing of the current $2.1 billion commitment.

Derivative Instruments We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments include variable to fixed commodity price swaps, two and three-way collars and basis swaps. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments. Except for certain minor derivative contracts that we enter into from time to time in order to market third-party natural gas, none of our counterparty agreements contain margin requirements. We also use derivative instruments to manage interest rate risk by entering into forward contracts or swap agreements to minimize the impact of interest rate fluctuations associated with fixed or floating rate borrowings.

Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs. As of September 30, 2010 the fair value of our commodity derivative assets was $136 million and the fair value of our commodity derivative liabilities was $11 million (after consideration of netting agreements). Interest rate derivative instruments, which are designated as cash flow hedges, are recorded at fair value in our consolidated balance sheets, and changes in fair value are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes. As of September 30, 2010 the fair value of our interest rate derivative liability was $141 million. See Item 1. Financial Statements – Note 7. Derivative Instruments and Hedging Activities for a discussion of counterparty credit risk and Note 8. Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of derivative instruments.

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Cash Flows

Cash flow information is as follows:

	Nine Months Ended September 30,
	2010			2009
(millions)
Total Cash Provided By (Used in)
Operating Activities	$	1,452		$	986
Investing Activities		(1,232	)		(1,012	)
Financing Activities		(85	)		(188	)
Increase (Decrease) in Cash and Cash Equivalents	$	135		$	(214	)

Operating Activities Net cash provided by operating activities for the first nine months of 2010 increased as compared with the first nine months of 2009 due to increases in commodity prices, higher sales volumes, the refund of deepwater Gulf of Mexico royalties and an increase in dividends received from equity method investees.

Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties, which may be offset by proceeds from property sales. Capital spending, on a cash basis, increased by $772 million during the first nine months of 2010 as compared with the first nine months of 2009, primarily due to the DJ Basin asset acquisition, and was offset by $552 million proceeds from the sale of non-core onshore US assets. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures. See also Investing Activities – Acquisition, Capital and Exploration Expenditures below.

Financing Activities Our financing activities include the issuance or repurchase of our common stock, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings. During the first nine months of 2010, $32 million of funds were used to repay borrowings under our revolving credit facility. Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($54 million). We used cash to pay dividends on our common stock ($95 million) and to repurchase shares of our common stock ($12 million).

In comparison, during the first nine months of 2009, funds were provided by net proceeds from the issuance of our 8¼% senior notes ($989 million) and cash proceeds from, and tax benefits related to, the exercise of stock options ($18 million). We used cash to pay dividends on our common stock ($94 million), to repurchase shares of our common stock ($1 million), for net repayments of amounts outstanding under our revolving credit facility ($1.1 billion), for the repayment of an installment note ($25 million), and for the repurchase of senior debt ($4 million).

Investing Activities

Acquisition, Capital and Exploration Expenditures Information for investing activities (on an accrual basis) is as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010		2009
(millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition	$	86		$	2	$	294	$	64
Proved Property Acquisition		(11	)		-		352		-
Exploration		51			22		222		167
Development		459			186		1,096		615
Corporate and Other		23			14		81		87
Total	$	608		$	224	$	2,045	$	933

Increase in FPSO Lease Obligation	$	80		$	-	$	188	$	-

2010 Unproved property acquisition costs for the first nine months of 2010 include $38 million of lease bonuses paid on deepwater Gulf of Mexico lease blocks, $146 million related to the DJ Basin asset acquisition, and the remainder for other Northern region, primarily Wattenberg field area, US lease acquisitions. Proved property acquisition costs are the result of the DJ Basin asset acquisition. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures.

The obligation under FPSO lease represents the increase in estimated construction in progress to date on an FPSO to be used in the development of the Aseng field in Equatorial Guinea. See Item 1. Financial Statements – Note 6. Debt.

In August 2010, we received proceeds of $552 million from the sale of non-core onshore US assets.

2009 Unproved property acquisition costs include primarily lease bonuses on deepwater Gulf of Mexico lease blocks.

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Financing Activities

Long-Term Debt Our principal source of liquidity is an unsecured revolving credit facility that matures December 9, 2012. The commitment is $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. 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 short-term loans up to an aggregate amount of $300 million within the current $2.1 billion commitment 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 September 30, 2010, borrowings outstanding under the credit facility totaled $350 million, leaving almost $1.75 billion available for use. The weighted average interest rate applicable to borrowings under the credit facility at September 30, 2010 was 0.57%. We periodically borrow amounts under provision (ii) above for working capital purposes.

Our outstanding fixed-rate debt totaled $1.6 billion at September 30, 2010. The weighted average interest rate on fixed-rate debt was 7.73%, with maturities ranging from 2014 to 2097.

Our ratio of debt-to-book capital was 25% at both September 30, 2010 and December 31, 2009. We define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.

Other Short-Term Borrowings Our committed credit facility may be 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. There were no amounts outstanding under uncommitted credit lines at September 30, 2010 or December 31, 2009, nor did we borrow any funds under uncommitted credit lines during the first nine months of 2010. Depending upon future credit market conditions, these sources may or may not be available. However, we are not dependent on them to fund our day-to-day operations.

Dividends We paid total cash dividends of 54 cents per share of our common stock during the first nine months of each of 2010 and 2009. On October 26, 2010, our Board of Directors declared a quarterly cash dividend of 18 cents per common share, payable November 22, 2010 to shareholders of record on November 8, 2010. 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 cash proceeds of $35 million from the exercise of stock options during the first nine months of 2010 as compared with $15 million during the first nine months of 2009.

Common Stock Repurchases We receive shares of common stock from employees for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received 164,515 shares with a value of $12 million during the first nine months of 2010 and 20,464 shares with a value of $1 million during the first nine months of 2009.

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Item 3. Quantitative and Qualitative Disclosures

About Market Risk

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes We are exposed to market risk in the normal course of business operations, and 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 September 30, 2010, we had entered into variable to fixed price commodity swaps, collars and basis swaps related to crude oil and natural gas sales. Our open commodity derivative instruments were in a net receivable position with a fair value of $125 million. Based on the September 30, 2010 published commodity futures price strips for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would decrease the fair value of our net commodity derivative receivable by approximately $13 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would decrease the fair value of our net commodity derivative receivable by approximately $7 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 7. Derivative Instruments and Hedging Activities.

Interest Rate Risk

Changes in interest rates affect the amount of interest we pay on borrowings under our revolving credit facility and the amount of interest we earn on our short-term investments.

At September 30, 2010, we had $2.0 billion (excluding the FPSO lease and unamortized discount) of long-term debt outstanding. Of this amount, $1.6 billion was fixed-rate debt with a weighted average interest rate of 7.73%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss.

The remainder of our long-term debt, $350 million at September 30, 2010, was variable-rate debt drawn under our credit facility. Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We estimate that a hypothetical 25 basis point change in the floating interest rates applicable to the September 30, 2010 balance of our variable-rate debt would result in a change in annual interest expense of approximately $1 million.

We occasionally enter into interest rate derivative instruments such as forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate derivative instruments used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At September 30, 2010, AOCL included $93 million, net of tax, related to interest rate derivative instruments. Of this amount, $1 million, net of tax, is currently being reclassified into earnings as adjustments to interest expense over the term of our 5¼% Senior Notes due April 2014. The remainder ($92 million, net of tax) is related to the change in fair value of an interest rate forward starting swap. Based on the notional amount subject to the interest rate forward starting swap at September 30, 2010, a hypothetical 10% increase in the implied 30-year forward starting swap rate would decrease the fair value of the interest rate derivative liability by approximately $33 million.

See Item 8. Financial Statements and Supplementary Data – Note 7. Derivative Instruments and Hedging Activities.

We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of September 30, 2010, our cash and cash equivalents totaled $1.1 billion, approximately 71% of which was invested in money market funds and short-term investments with major financial institutions. A hypothetical 25 basis point change in the floating interest rates applicable to the amount invested as of September 30, 2010 would result in a change in annual interest income of approximately $2 million.

Foreign Currency Risk

The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, such as foreign deferred tax liabilities in certain foreign tax jurisdictions, are denominated in a foreign currency. An increase in exchange rates between the US dollar and the currency of the foreign tax jurisdiction in which these liabilities are located could result in the use of additional cash to settle these liabilities. Transaction gains or losses were not material in any of the periods presented and are included in other (income) expense, net in the consolidated statements of operations.

We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determined that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk.

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Disclosure Regarding Forward-Looking Statements

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

our growth strategies;

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

anticipated trends in our business;

our future results of operations;

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

market conditions in the oil and gas industry;

our ability to make and integrate acquisitions; and

the impact of governmental regulation.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our 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, if any, and included in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010, and our Annual Report on Form 10-K for the year ended December 31, 2009, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010, and our Annual Report on Form 10-K for the year ended December 31, 2009 are available on our website at www.nobleenergyinc.com.

Item 4. Controls and Procedures

Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our 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 17. 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 quarterly reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010, or our annual report on Form 10-K for the year ended December 31, 2009, other than the following:

Our operations and investment in Ecuador may be adversely affected by the country's new hydrocarbon reform bill.

A newly enacted hydrocarbon reform bill in Ecuador aims to change current production-sharing arrangements under service contracts and provides that all contracts must be renegotiated by November 23, 2010. It also allows the Ecuadorian government to nationalize oil fields if a private operator does not comply with local laws. We are currently engaged in negotiations with the government. However, we are uncertain as to the potential outcome of this matter, resolution of which could ultimately lead to a reduction in the value of our investments in Ecuador which, as of September 30, 2010, had a net book value of approximately $59 million.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Period	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
							(in thousands)
07/01/10 - 07/31/10		188	$	66.04		-		-
08/01/10 - 08/31/10		415		67.28		-		-
09/01/10 - 09/30/10		524		74.33		-		-
Total		1,127	$	70.35		-		-

(1)	Stock repurchases during the period related to stock received by us from employees for the payment of withholding taxes due on shares issued under stock-based compensation plans.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

Item 6. Exhibits

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

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Signatures

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

	NOBLE ENERGY, INC.
	(Registrant)

Date	October 28, 2010		/s/ Kenneth M. Fisher
			Kenneth M. Fisher Senior Vice President, Chief Financial Officer

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Index to Exhibits

Exhibit
Number		Exhibit

3.1		Certificate of Incorporation, as amended through May 16, 2005, of the Registrant (filed as Exhibit 3.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference).

3.2		By-Laws of Noble Energy, Inc. as amended through June 1, 2009 (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: February 17, 2009) filed February 19, 2009 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), filed herewith.

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), filed herewith.

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), filed herewith.

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), filed herewith.

101.INS		XBRL Instance Document

101.SCH		XBRL Schema Document

101.CAL		XBRL Calculation Linkbase Document

101.LAB		XBRL Label Linkbase Document

101.PRE		XBRL Presentation Linkbase Document

101.DEF		XBRL Definition Linkbase Document