10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	73-0785597
(State 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 [  ]

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 [  ]

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 [  ]	Non-accelerated filer [  ]	Smaller reporting company [  ]
	(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 [  ]    No [X]

As of October 13, 2009, there were 173,477,323 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, 2009 and 2008	3
	Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008	4
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008	5
	Consolidated Statements of Shareholders' Equity for the Nine Months Ended September 30, 2009 and 2008	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	44
	PART II
Item 1.	Legal Proceedings	44
Item 1A.	Risk Factors	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Submission of Matters to a Vote of Security Holders	46
Item 5.	Other Information	46
Item 6.	Exhibits	46

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NOBLE ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)

(unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009			2008
Revenues
Oil, Gas and NGL Sales	$	573	$	1,040		$	1,440		$	3,115
Income from Equity Method Investees		25		40			52			158
Other Revenues		23		18			61			55
Total Revenues		621		1,098			1,553			3,328
Costs and Expenses
Lease Operating Expense		88		98			281			268
Production and Ad Valorem Taxes		25		47			66			141
Transportation Expense		18		14			43			43
Exploration Expense		27		39			102			181
Depreciation, Depletion and Amortization		205		194			601			593
General and Administrative		53		63			173			184
Asset Impairments		-		38			437			38
Other Operating (Income) Expense, Net		34		60			22			107
Total Operating Expenses		450		553			1,725			1,555
Operating Income (Loss)		171		545			(172	)		1,773
Other (Income) Expense
(Gain) Loss on Commodity Derivative Instruments		28		(875	)		95			190
Interest, Net of Amount Capitalized		23		18			64			52
Other Non-Operating (Income) Expense, Net		5		(52	)		18			(42	)
Total Non-Operating (Income) Expense		56		(909	)		177			200
Income (Loss) Before Income Taxes		115		1,454			(349	)		1,573
Income Tax Provision (Benefit)		8		480			(210	)		528
Net Income (Loss)	$	107	$	974		$	(139	)	$	1,045
Earnings (Loss) Per Share, Basic	$	0.62	$	5.64		$	(0.80	)	$	6.06
Earnings (Loss) Per Share, Diluted		0.61		5.37			(0.80	)		5.86
Weighted Average Number of Shares Outstanding, Basic		173		173			173			172
Weighted Average Number of Shares Outstanding, Diluted		175		176			173			176
The accompanying notes are an integral part of these financial statements.

3

NOBLE ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(in millions)

		(unaudited) September 30,		December 31,
		2009			2008
ASSETS
Current Assets
Cash and Cash Equivalents	$	926		$	1,140
Accounts Receivable, Net		348			423
Commodity Derivative Assets, Current		96			437
Other Current Assets		130			158
Total Assets, Current		1,500			2,158
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method of Accounting)		12,364			11,963
Property, Plant and Equipment, Other		228			175
Total Property, Plant and Equipment, Gross		12,592			12,138
Accumulated Depreciation, Depletion and Amortization		(3,696	)		(3,134	)
Total Property, Plant and Equipment, Net		8,896			9,004
Goodwill		758			759
Other Noncurrent Assets		481			463
Total Assets	$	11,635		$	12,384
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts Payable - Trade	$	397		$	579
Income Taxes Payable		137			130
Deferred Income Taxes, Net, Current		1			142
Other Current Liabilities		311			323
Total Liabilities, Current		846			1,174
Long-Term Debt		2,161			2,241
Deferred Income Taxes, Noncurrent		1,905			2,174
Other Noncurrent Liabilities		565			486
Total Liabilities		5,477			6,075
Commitments and Contingencies
Shareholders’ Equity
Preferred Stock - Par Value $1.00; 4 million Shares Authorized, None Issued		-			-
Common Stock - Par Value $3.33 1/3; 250 Million Shares Authorized; 193 Million and 192 Million Shares Issued, Respectively		645			641
Additional Paid in Capital		2,244			2,193
Accumulated Other Comprehensive Loss		(82	)		(110	)
Treasury Stock, at Cost; 19 Million Shares		(615	)		(614	)
Retained Earnings		3,966			4,199
Total Shareholders’ Equity		6,158			6,309
Total Liabilities and Shareholders’ Equity	$	11,635		$	12,384
The accompanying notes are an integral part of these financial statements.

4

NOBLE ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2009			2008
Cash Flows From Operating Activities
Net Income (Loss)	$	(139	)	$	1,045
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		601			593
Asset Impairments		437			38
Deferred Income Taxes		(443	)		173
Income from Equity Method Investees		(52	)		(158	)
Dividends from Equity Method Investees		37			192
Unrealized (Gain) Loss on Commodity Derivative Instruments		508			(9	)
Settlement of Previously Recognized Hedge Losses		-			(144	)
Allowance for Doubtful Accounts		(22	)		47
Gain on Asset Sale		(24	)		-
Other Adjustments for Noncash Items Included in Income		72			99
Changes in Operating Assets and Liabilities:
(Increase) Decrease in Accounts Receivable		92			(94	)
(Increase) Decrease in Other Current Assets		25			(19	)
(Decrease) in Accounts Payable		(65	)		(135	)
Increase in Other Current Liabilities		10			235
Other Assets and Liabilities, Net		(51	)		4
Net Cash Provided by Operating Activities		986			1,867
Cash Flows From Investing Activities
Additions to Property, Plant and Equipment		(1,012	)		(1,852	)
Proceeds from Sale of Property, Plant and Equipment		-			131
Net Cash Used in Investing Activities		(1,012	)		(1,721	)
Cash Flows From Financing Activities
Exercise of Stock Options		15			26
Excess Tax Benefits from Stock-Based Awards		3			23
Dividends Paid, Common Stock		(94	)		(84	)
Purchase of Treasury Stock		(1	)		(2	)
Proceeds from Credit Facilities		340			650
Repayment of Credit Facilities		(1,411	)		(425	)
Net Proceeds from Issuance of 8 ¼% Senior Notes		989			-
Repayment of Installment Note		(25	)		(25	)
Repurchase of Senior Debentures		(4	)		-
Proceeds from Short Term Borrowings		-			23
Net Cash Provided by (Used in) Financing Activities		(188	)		186
Increase (Decrease) in Cash and Cash Equivalents		(214	)		332
Cash and Cash Equivalents at Beginning of Period		1,140			660
Cash and Cash Equivalents at End of Period	$	926		$	992
The accompanying notes are an integral part of these financial statements.

5

NOBLE ENERGY, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

(unaudited)

	Nine Months Ended September 30,
	2009			2008
Common Stock
Balance, Beginning of Period	$	641		$	636
Exercise of Stock Options		2			4
Restricted Stock Awards, Net		2			1
Balance, End of Period		645			641
Capital in Excess of Par Value
Balance, Beginning of Period		2,193			2,106
Stock-Based Compensation Expense		37			30
Exercise of Stock Options		13			22
Tax Benefits Related to Exercise of Stock Options		3			23
Restricted Stock Awards, Net		(2	)		(1	)
Rabbi Trust Shares Sold		-			2
Balance, End of Period		2,244			2,182
Accumulated Other Comprehensive Loss
Balance, Beginning of Period		(110	)		(284	)
Oil and Gas Cash Flow Hedges:
Realized Amounts Reclassified Into Earnings		28			155
Balance, End of Period		(82	)		(129	)
Treasury Stock at Cost
Balance, Beginning of Period		(614	)		(613	)
Purchases of Treasury Stock		(1	)		(2	)
Rabbi Trust Shares Sold		-			1
Balance, End of Period		(615	)		(614	)
Retained Earnings
Balance, Beginning of Period		4,199			2,964
Net Income (Loss)		(139	)		1,045
Cash Dividends ($0.54 Per Share and $0.48 Per Share, Respectively)		(94	)		(84	)
Balance, End of Period		3,966			3,925
Total Shareholders' Equity	$	6,158		$	6,005
The accompanying notes are an integral part of these financial statements.

6

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 worldwide crude oil, natural gas and natural gas liquids (NGL) acquisition, exploration and production. We operate primarily in the Rocky Mountains, Mid-continent, and deepwater Gulf of Mexico areas in the US, with significant 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, 2009 and December 31, 2008 and for the three months and nine months ended September 30, 2009 and 2008 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations and cash flows for such periods. Operating results for the three-month and nine-month periods ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ended December 31, 2009. 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, 2008.

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. Current credit market conditions combined with volatile commodity prices have resulted in increased uncertainty inherent in such estimates and assumptions. As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in millions)
Other Revenues
Electricity Sales (1)	$	20		$	14		$	51		$	42
Gathering, Marketing and Processing (GMP) Revenues		3			4			10			13
Total	$	23		$	18		$	61		$	55
Other Operating (Income) Expense, Net
Gain on Asset Sale (2)	$	-		$	(8	)	$	(24	)	$	(8	)
Electricity Generation Expense (1)		19			13			-			41
GMP Expense		5			5			15			14
Settlement of Legal Proceedings (3)		-			-			9			-
(Gain) Loss on Involuntary Conversion (4)		-			9			(4	)		9
Other, Net (5)		10			41			26			51
Total	$	34		$	60		$	22		$	107
Other Non-Operating (Income) Expense, Net
Deferred Compensation (Income) Expense (6)	$	7		$	(47	)	$	18		$	(25	)
Interest Income		(1	)		(6	)		(2	)		(18	)
Other (Income) Expense, Net		(1	)		1			2			1
Total	$	5		$	(52	)	$	18		$	(42	)

(1) Includes amounts related to our 100%-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. We recognized a net increase of $4 million in the allowance during third quarter 2009 and a net decrease of $36 million in the allowance during the first nine months of 2009. We recognized net increases of $3 million and $9 million in the allowance during the third quarter and first nine months of 2008, respectively. See Allowance for Doubtful Accounts below.

7

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

(2) In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million. The gain on sale was deferred until second quarter 2009 when the Argentine government approved the sale.

(3) Amount for the first nine months of 2009 includes a $19 million charge on legal settlement, offset by a $15 million gain on legal settlement related to reimbursement of bonuses paid for federal leases offshore California.

(4) Amount for the first nine months of 2009 represents final receipt of insurance claims related to Hurricanes Katrina and Rita damage. Amount for the first nine months of 2008 represents interim settlement of the replacement cost portion of the Hurricane Katrina insurance claim.

(5) Includes write-downs of SemCrude L.P. receivable of $12 million in third quarter 2009 and $38 million in third quarter 2008. See Allowance for Doubtful Accounts below and Note 14 – Commitments and Contingencies.

(6) Amount represents increases or (decreases) in the fair value of Noble Energy common stock held in a rabbi trust.

Balance Sheet Information – Other balance sheet information is as follows:

	September 30,		December 31,
		2009	2008
		(in millions)
Other Current Assets
Inventories, Current	$	101	$	105
Prepaid Expenses and Other Assets, Current		29		27
Asset Held for Sale (1)		-		26
Total	$	130	$	158
Other Noncurrent Assets
Equity Method Investments	$	329	$	311
Mutual Fund Investments		103		84
Commodity Derivative Assets, Noncurrent		-		33
Other Assets, Noncurrent		49		35
Total	$	481	$	463

(1) The Main Pass asset was reclassified as held-and-used and impaired during first quarter 2009. Estimated proved reserves attributed to this property were less than 1% of our total estimated proved reserves. See Note 5 – Fair Value Measurements and Disclosures.

8

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

	September 30,		December 31,
		2009	2008
		(in millions)
Other Current Liabilities
Production and Ad Valorem Taxes	$	116	$	114
Commodity Derivative Liabilities, Current		58		23
Asset Retirement Obligations, Current		44		27
Interest Payable		24		9
Short-Term Borrowings		-		25
Deferred Gain on Asset Sale, Current (1)		-		24
Other		69		101
Total	$	311	$	323
Other Noncurrent Liabilities
Deferred Compensation Liabilities, Noncurrent	$	202	$	159
Asset Retirement Obligations, Noncurrent		184		184
Accrued Benefit Costs, Noncurrent		71		81
Commodity Derivative Liabilities, Noncurrent		56		2
Other Liabilities, Noncurrent		52		60
Total	$	565	$	486

 (1) See footnote (2) to Statements of Operations Information above.

Allowance for Doubtful Accounts – Through December 31, 2008, we had recorded an allowance for doubtful accounts of $57 million related to our Ecuador power operations. The allowance was necessary to cover potentially uncollectible balances, as certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. As a result of pursuing various strategies to protect our interests, including international arbitration and litigation, we reached a settlement in fourth quarter 2008. In March and April 2009, we received total payments of $60 million in accordance with the terms of the settlement, against which a reserve of $46 million had previously been recorded.  Accordingly, we reduced the allowance for doubtful accounts by $46 million and included the amount as a reduction in electricity generation expense during first quarter 2009. We recorded additions to the allowance for doubtful accounts of $4 million and $12 million during the third quarter and first nine months of 2009, respectively, related to current period commodity and electricity sales. We also recorded an addition of $12 million related to the SemCrude L.P. receivable during third quarter 2009. See Note 4 – Derivative Instruments and Hedging Activities – Counterparty Credit Risk and Note 14 – Commitments and Contingencies.

Recently Adopted Accounting Standards –

Postretirement Benefit Plan Asset Disclosures – In December 2008, the Financial Accounting Standards Board (FASB) issued new standards which require employers to make additional disclosures about plan assets for defined benefit pension and other postretirement benefit plans beginning with annual periods ending after December 15, 2009. Disclosures must provide an understanding of how investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair-value measurements using significant unobservable inputs on changes in plan assets for the period, and significant concentrations of risk within plan assets. We adopted the new standards as of January 1, 2009. Adoption had no impact on our financial position or results of operations. Enhanced disclosures are required for annual periods only.

Business Combinations and Noncontrolling Interests in Consolidated Financial Statements – In 2007, the FASB issued new standards regarding the accounting for business combinations and noncontrolling interests in consolidated financial statements. These standards require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. We adopted the new standards as of January 1, 2009. There were no non-controlling interests at adoption date. Adoption had no impact on our financial position or results of operations.

Fair Value Measurements – The FASB’s fair value measurement standards establish a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and create a fair value hierarchy that prioritizes the information used to develop those assumptions. The standards require additional disclosures, including disclosures of fair value measurements by level within the fair value hierarchy. As of January 1, 2008, we adopted the new standards as they related to our financial assets and liabilities. As of January 1, 2009, we adopted the new standards as they related to our nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill impairment assessments; and initial recognition of asset retirement obligations. Adoption did not have a significant impact on our consolidated financial statements. See Note 5 – Fair Value Measurements and Disclosures and Note 16 – Recently Issued Pronouncements.

9

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

In April 2009, the FASB issued additional guidance clarifying the application of US GAAP for fair value measurements in the current economic environment, modifying the recognition of other-than-temporary impairments of debt securities, and requiring companies to disclose the fair value of financial instruments in interim periods. The revised guidance is effective for interim and annual periods ending after June 15, 2009. The guidance:

· descibes how to determine the fair value of assets and liabilities in the current economic environment and reemphasizes that the objective of a fair value measurement remains the price that would be received to sell an asset or paid to transfer a liability at the measurement date.

· modifies the requirements for recognizing other-than-temporarily impaired debt securities and significantly changes the existing impairment model for such securities. It also modifies the presentation of other-than-temporary impairment losses and increases the frequency of and expands already required disclosures about other-than-temporary impairment for debt and equity securities.

· requires disclosures of the fair value of financial instruments in interim financial statements, the method or methods and significant assumptions used to estimate the fair value of financial instruments, and a discussion of changes, if any, in the method or methods and significant assumptions during the period.

We adopted this new guidance for the quarter ended June 30, 2009. Adoption had no impact on our financial position or results of operations. See Note 5 – Fair Value Measurements and Disclosures for additional interim disclosure requirements.

Derivative Instruments and Hedging Activities – In March 2008, the FASB issued new standards which amended and expanded previous disclosure requirements related to derivative instruments and hedging activities. The new standards require qualitative disclosures about objectives and strategies for using derivative instruments, quantitative disclosures about fair value amounts of derivative instruments and related gains and losses, and disclosures about credit risk-related contingent features in derivative agreements. We adopted the new standards as of January 1, 2009. They provide only for enhanced disclosures, and adoption had no impact on our financial position or results of operations. See Note 4 – Derivative Instruments and Hedging Activities.

Subsequent Events – In May 2009, the FASB issued new standards which establish the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, the new standards set forth:

· the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued);

· the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and

· the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.

We adopted the new standards as of June 30, 2009. We have evaluated subsequent events after the balance sheet date of September 30, 2009 through the time of filing with the Securities and Exchange Commission (SEC) on October 29, 2009 which is the date the financial statements were issued. See Note 15 – Subsequent Events.

Accounting Standards Codification – In June 2009, the FASB established the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to become the source of authoritative US GAAP recognized by the FASB to be applied by nongovernmental entities.  Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants.  Generally, the Codification is not expected to change US GAAP.  All other accounting literature excluded from the Codification will be considered nonauthoritative.  The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009.  We adopted the new standards for our quarter ending September 30, 2009.  All references to authoritative accounting literature are now referenced in accordance with the Codification.

10

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

Equity Method Investments – In November 2008, the FASB issued new guidance in accounting for equity method investments. The new guidance was issued to address questions that arose regarding the application of the equity method subsequent to the issuance of new business combination standards. The new guidance concluded that equity method investments should continue to be recognized using a cost accumulation model, thus continuing to include transaction costs in the carrying amount of the equity method investment. In addition, it clarified that an impairment assessment should be applied to the equity method investment as a whole, rather than to the individual assets underlying the investment. We adopted the new guidance as of January 1, 2009. Adoption had no impact on our financial position or results of operations.

Note 3 – Debt

On February 27, 2009, we closed an offering of $1 billion senior unsecured notes receiving net proceeds of $989 million, after deducting the discount and underwriting fees. The notes are due March 1, 2019, and pay interest semi-annually at 8¼%. Debt issuance costs of approximately $2 million were incurred and are being amortized to expense over the life of the debt issue. Substantially all of the net proceeds from the offering were used to repay outstanding indebtedness under our revolving credit facility maturing 2012. The notes are senior unsecured debt and will rank pari passu with any of our other senior unsecured indebtedness with respect to the payment of both principal and interest.

On May 11, 2009, we made the final $25 million installment payment to the seller of properties we purchased in 2007. Interest on the unpaid amount was due quarterly and accrued at a LIBOR rate plus .30%. The interest rate was 1.51% at the date of payment.

On July 22, 2009, we repurchased $5 million of our 7¼% Senior Debentures due August 1, 2097, recognizing a debt extinguishment gain of $1 million, which is included in other non-operating (income) expense, net.

On October 6, 2009, we entered into a lease agreement which will result in the recording of an additional long-term obligation in our balance sheet, as the related asset is constructed.  See Note 15 – Subsequent Events.

Our debt consists of the following:

	September 30,						December 31,
	2009						2008
	Debt			Interest Rate			Debt			Interest Rate
	(in millions, except percentages)
Credit Facility	$	535			0.56	%	$	1,606			0.80	%
5 ¼% Senior Notes, due April 15, 2014		200			5.25	%		200			5.25	%
8 ¼% Senior Notes, due March 1, 2019		1,000			8.25	%		-			-
7 ¼% Notes, due October 15, 2023		100			7.25	%		100			7.25	%
8% Senior Notes, due April 1, 2027		250			8.00	%		250			8.00	%
7 ¼% Senior Debentures, due August 1, 2097		84			7.25	%		89			7.25	%
Long-term Debt		2,169						2,245
Installment Payment, due May 11, 2009		-			-			25			4.18	%
Total Debt		2,169						2,270
Unamortized Discount		(8	)					(4	)
Total Debt, Net of Discount	$	2,161					$	2,266

Note 4 – Derivative Instruments and Hedging Activities

Objectives and Strategies for Using Derivative Instruments – We are exposed to certain risks relating to our ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk. We use various commodity derivative instruments in connection with forecasted crude oil and natural gas sales to minimize the impact of commodity price fluctuations. Such instruments include variable to fixed price swaps, collars and basis swaps.

We may 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 may designate these as cash flow hedges.

11

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

In accordance with US GAAP for derivative instruments and hedging activities, all of our derivative instruments are reflected as either assets or liabilities at fair value in our consolidated balance sheets. See Note 5 – Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our commodity derivative instruments and gross amounts of commodity 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 financial institutions, a majority of which are lenders under our credit facility arrangement.  Certain of these financial institutions have received capital injections and other forms of support from government sources, and may require additional financial assistance in the future to remain viable.  Discontinuance of government support to these institutions could have an adverse impact on the collectibility of our derivative receivables. 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 financial 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 commodity derivative instruments in an asset position. See also Note 5 – Fair Value Measurements and Disclosures.

Accounting for Commodity Derivative Instruments – During 2009 and 2008 we accounted for our commodity derivative instruments using mark-to-market accounting, and we recognize all gains and losses on such 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 Previously Designated Cash Flow Hedging Relationships table below.

Unsettled Derivative Instruments – As of September 30, 2009, we had entered into the following crude oil derivative instruments:  

	Variable to Fixed Price Swaps						Collars
					Weighted					Weighted		Weighted
Production			Bbls		Average			Bbls		Average		Average
Period	Index		Per Day		Fixed Price		Index	Per Day		Floor Price		Ceiling Price
4th Qtr 2009	NYMEX WTI			9,000	$	88.43	NYMEX WTI		6,700	$	79.70	$	90.60
4th Qtr 2009	Dated Brent			2,000		87.98	Dated Brent		4,848		71.82		88.66
4th Qtr 2009 Average				11,000		88.35			11,548		76.39		89.79
2010		-		-		-	NYMEX WTI		14,500		61.48		75.63
2010	Dated Brent			1,000		80.05	Dated Brent		7,000		64.00		73.96
2010 Average				1,000		80.05			21,500		62.30		75.09
2011		-		-		-	NYMEX WTI		1,000		70.00		82.40

12

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

As of September 30, 2009, we had entered into the following natural gas derivative instruments:

	Variable to Fixed Price Swaps						Collars
					Weighted					Weighted		Weighted
Production			MMBtu		Average			MMBtu		Average		Average
Period	Index		Per Day		Fixed Price		Index	Per Day		Floor Price		Ceiling Price
4th Qtr 2009		-		-		-	NYMEX HH (1)		170,000	$	9.15	$	10.81
4th Qtr 2009		-		-		-	IFERC CIG (2)		15,000		6.00		9.90
4th Qtr 2009 Average				-		-			185,000		8.90		10.73
2010	NYMEX HH			20,000		6.10	NYMEX HH		210,000		5.90		6.73
2010		-		-		-	IFERC CIG		15,000		6.25		8.10
2010 Average				20,000		6.10			225,000		5.93		6.82
2011		-		-		-	NYMEX HH		140,000		5.95		6.82

(1) Henry Hub

(2) Colorado Interstate Gas – Northern System

As of September 30, 2009, we had entered into the following natural gas basis swaps:

	Basis Swaps
					Weighted
Production		Index Less	MMBtu		Average
Period	Index	Differential	Per Day		Differential
4th Qtr 2009	IFERC CIG	NYMEX HH		140,000	$	(2.49	)
2010	IFERC CIG	NYMEX HH		100,000		(1.60	)
2011	IFERC CIG	NYMEX HH		80,000		(0.84	)

13

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

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

	Derivative Instruments Not Designated as Hedging Instruments
	Asset Derivative Instruments						Liability Derivative Instruments
	September 30,			December 31,			September 30,			December 31,
	2009			2008			2009			2008
(in millions)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity Derivative Instruments
	Current Assets	$	96	Current Assets	$	437	Current Liabilities	$	58	Current Liabilities	$	23
	Noncurrent Assets		-	Noncurrent Assets		33	Noncurrent Liabilities		56	Noncurrent Liabilities		2
Total		$	96		$	470		$	114		$	25

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

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,
		2009			2008			2009			2008
		(in millions)
Commodity Derivative Instruments
Realized Mark-to-Market (Gain) Loss (1)	$	(121	)	$	68		$	(413	)	$	199
Unrealized Mark-to-Market (Gain) Loss (1)		149			(943	)		508			(9	)
Total (Gain) Loss on Commodity Derivative Instruments	$	28		$	(875	)	$	95		$	190

(1) Amounts are recognized as (Gain) Loss on Commodity Derivative Instruments in our consolidated statements of operations.

14

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

Derivative Instruments in Previously Designated Cash Flow Hedging Relationships
	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive Income					Amount of (Gain) Loss on Derivative Instruments Reclassified from Accumulated Other Comprehensive Loss
	2009		2008			2009		2008
	(in millions)					(in millions)
Three Months Ended September 30,
Commodity Derivative Instruments (1)
Crude Oil (2)	$	-	$	-		$	14	$	89
Natural Gas (2)		-		-			-		4
Treasury Rate Locks		-		(12	)		-		-
Total	$	-	$	(12	)	$	14	$	93
Nine Months Ended September 30,
Commodity Derivative Instruments (1)
Crude Oil (2)	$	-	$	-		$	45	$	279
Natural Gas (2)		-		-			-		(31	)
Treasury Rate Locks		-		(1	)		-		-
Total	$	-	$	(1	)	$	45	$	248

(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.

(2) The amount of (Gain) Loss reclassified from AOCL on Derivative Instruments is recognized in Oil, Gas and NGL Sales within our consolidated statements of operations.

AOCL – As of September 30, 2009, the balance in AOCL included net deferred losses of $20 million related to the fair value of commodity derivative instruments previously accounted for as cash flow hedges. The net deferred losses are net of deferred income tax benefits of $12 million. Approximately $17 million of deferred losses (net of tax) related to the fair values of the commodity derivative instruments previously designated as cash flow hedges and remaining in AOCL at September 30, 2009 will be reclassified to earnings during the next 12 months as the forecasted transactions occur, and will be recorded as a reduction in oil and gas sales of approximately $27 million before tax. All forecasted transactions currently being hedged and for which amounts remain in AOCL at September 30, 2009, are expected to occur by December 2010.

Note 5 – Fair Value Measurements and Disclosures

US GAAP for fair value measurements establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. 

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. 

15

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

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 commodity futures price strips 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 4 – Derivative Instruments and Hedging Activities.

Patina Deferred Compensation Liability - The value is dependant upon the fair values of mutual fund investments and shares of Noble Energy 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)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Adjustment (1)			Fair Value Measurement
		(in millions)
As of September 30, 2009
Financial Assets:
Mutual Fund Investments	$	103		$	-		$	-	$	-		$	103
Commodity Derivative Instruments		-			127			-		(31	)		96
Financial Liabilities:
Commodity Derivative Instruments		-			(145	)		-		31			(114	)
Patina Deferred Compensation Liability		(158	)		-			-		-			(158	)
As of December 31, 2008
Financial Assets:
Mutual Fund Investments	$	84		$	-		$	-	$	-		$	84
Commodity Derivative Instruments		-			492			-		(22	)		470
Financial Liabilities:
Commodity Derivative Instruments		-			(47	)		-		22			(25	)
Patina Deferred Compensation Liability		(123	)		-			-		-			(123	)

(1)       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: 

Asset Impairments – In accordance with US GAAP for the impairment or disposal of long-lived assets, we review an oil and gas property for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. We estimate the future cash flows expected in connection with the property and compare such future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.

As a result of a significant decline in the forward natural gas futures price strip at March 31, 2009, we reviewed our oil and gas properties that are sensitive to natural gas price decreases for impairment. 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 at March 31, 2009.  We reduced Granite Wash to its fair value, which was determined using the discounted cash flow method described above, as comparable market data was not available.  We also impaired the Main Pass asset which had been reclassified from held-for-sale to held-and-used. Total pre-tax (non-cash) impairments for first quarter 2009 were $437 million. The impaired assets, which had a total carrying amount of $753 million, were reduced to their estimated fair value of $316 million.

16

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

An impairment loss of $38 million, also related to the Main Pass asset, was recognized during third quarter 2008.

The asset impairments were Level 3 fair value measurements.

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 fair value of floating-rate debt is estimated using the carrying amounts because the interest rates paid on such debt are set for periods of three months or less. See Note 3 – Debt.

Fair value information regarding our debt is as follows:

	September 30,				December 31,
	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Total Debt, Net of Unamortized Discount	$	2,161	$	2,418	$	2,266	$	2,172

Note 6 – 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, 2009
		(in millions)
Capitalized Exploratory Well Costs, Beginning of Period	$	501
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves		101
Reclassified to Property, Plant and Equipment Based on Determination of Proved Reserves		(198	)
Capitalized Exploratory Well Costs Charged to Expense		(7	)
Capitalized Exploratory Well Costs, End of Period	$	397

17

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,
	2009		2008
	(in millions)
Exploratory Well Costs Capitalized for a Period of One Year or Less	$	116	$	256
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling		281		245
Balance at End of Period	$	397	$	501
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling		5		6

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, 2009:

			Suspended Since
	Total		2008		2007		2006 & Prior
	(in millions)
Project
West Africa	$	179	$	69	$	96	$	14
Gunflint (deepwater Gulf of Mexico)		48		48		-		-
Redrock (deepwater Gulf of Mexico)		17		-		-		17
Flyndre (North Sea)		15		-		12		3
Selkirk (North Sea)		22		-		22		-
Total Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling	$	281	$	117	$	130	$	34

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. Since drilling the initial well for this project, additional seismic work has been completed and exploration and appraisal wells have been drilled to further evaluate our discoveries. The West Africa development team is proceeding with a program to further define the resources in this area such that an optimal development program may be designed. On July 22, 2009, we announced that the Plan of Development for the Aseng field (formerly Benita) on Block I has been sanctioned by us, our partners, and the Ministry of Mines, Industry, and Energy of the Republic of Equatorial Guinea.  As a result, we have reclassified $76 million of capitalized costs relating to the Aseng field out of capitalized exploratory well costs. In addition to the remaining exploratory well costs that have been capitalized for a period greater than one year for the West Africa project, we have incurred $12 million in suspended costs related to additional drilling activity in West Africa through September 30, 2009.

Gunflint (Deepwater Gulf of Mexico) – Gunflint (Mississippi Canyon Block 948) was a 2008 crude oil discovery and is our largest deepwater Gulf of Mexico discovery to date. We are currently acquiring additional seismic information and are preparing to drill an appraisal well in 2010.

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 through the Gemini system 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.

18

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

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 appraisal well which was then sidetracked to the original discovery well location, to ensure presence of effective reservoir, and suspended as a future producer. We are currently working with our partners on an alternative host and to reduce costs.

Note 7 – Asset Retirement Obligations

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

	Nine Months Ended September 30,
	2009			2008
	(in millions)
Asset Retirement Obligations, Beginning of Period	$	211		$	144
Liabilities Incurred in Current Period		6			15
Liabilities Settled in Current Period		(23	)		(16	)
Revisions		23			10
Accretion Expense		11			7
Asset Retirement Obligations, End of Period	$	228		$	160

Liabilities settled in 2009 relate primarily to the Main Pass asset. Revisions in 2009 relate to the Main Pass asset and a deepwater Gulf of Mexico property. Accretion expense is included in DD&Aexpense in the consolidated statements ofoperations.

Note 8 – 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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in millions)
Service Cost	$	3		$	3		$	9		$	9
Interest Cost		3			3			9			9
Expected Return on Plan Assets		(3	)		(3	)		(10	)		(9	)
Other		-			1			1			2
Net Periodic Benefit Cost	$	3		$	4		$	9		$	11

During the nine months ended September 30, 2009, we made cash contributions to the pension plan totaling $18 million.

Note 9 – Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in millions)
Stock-Based Compensation Expense	$	13		$	10		$	37		$	30
Tax Benefit Recognized		(5	)		(4	)		(13	)		(11	)

19

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

During the nine months ended September 30, 2009, we granted 1.5 million stock options with a weighted-average grant-date fair value of $18.77 per share and awarded 0.6 million shares of restricted stock subject to service conditions with a weighted-average grant-date fair value of $50.24 per share. In 2009, we began making grants of restricted stock under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (the Plan) that will time-vest 20% after year one, an additional 30% after year two and the remaining 50% after year three.

On April 28, 2009, our stockholders approved an amendment to the Plan that increased the number of shares of our common stock authorized for issuance under the Plan from 22 million to 24 million.

Note 10 – 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 per share of common stock may include the effect of Noble Energy 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					Nine Months Ended
	September 30,					September 30,
	2009		2008			2009			2008
	(in millions, except per share amounts)
Net Income (Loss)	$	107	$	974		$	(139	)	$	1,045
Earnings Adjustment from Assumed Conversion of
Dilutive Shares of Common Stock in Rabbi Trust (1)		-		(29	)		-			(16	)
Net Income (Loss) Used for Diluted Earnings Per Share Calculation	$	107	$	945		$	(139	)	$	1,029
Weighted Average Number of Shares Outstanding, Basic		173		173			173			172
Incremental Shares from Assumed Conversion of
Dilutive Options, Restricted Stock and Shares of Common Stock in Rabbi Trust		2		3			-			4
Weighted Average Number of Shares Outstanding, Diluted		175		176			173			176
Earnings (Loss) Per Share, Basic	$	0.62	$	5.64		$	(0.80	)	$	6.06
Earnings (Loss) Per Share, Diluted	$	0.61	$	5.37		$	(0.80	)	$	5.86

(1) The diluted earnings per share calculation for the three and nine months ended September 30, 2008 includes decreases to net income of $29 million and $16 million (net of tax), respectively, related to a deferred compensation gain 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.

The effect of stock options and unvested shares of restricted stock outstanding has not been included in the calculation of weighted average shares outstanding for diluted earnings per share for the first nine months of 2009 as their effect would have been antidilutive. Had we recognized net income for this period, incremental shares attributable to the assumed exercise of outstanding options and shares of restricted stock would have increased diluted weighted average shares outstanding by 1.9 million shares for the nine months ended September 30, 2009.

A total of 3.1 million and 3.9 million weighted average stock options, shares of restricted stock and shares of common stock held in a rabbi trust were antidilutive for the third quarter and first nine months of 2009, respectively, and were excluded from the calculation of diluted earnings per share.  A total of 1.1 million and 0.8 million weighted average stock options, shares of restricted stock and shares of common stock held in a rabbi trust were antidilutive for the third quarter and first nine months of 2008, respectively, and were excluded from the calculation of diluted earnings per share.

20

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

Note 11 – Income Taxes

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008
	(in millions)
Current	$	92		$	316	$	233		$	355
Deferred		(84	)		164		(443	)		173
Total Income Tax Provision (Benefit)	$	8		$	480	$	(210	)	$	528

The deferred tax benefit for the nine months ended September 30, 2009 was the result of 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.

Our effective tax rate increased to 60% for the first nine months of 2009 as compared with 34% for the first nine months of 2008 and is the result of a tax benefit divided by a pre-tax loss.  In the case of a loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective rate.

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 $9 million, which 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, 2009. 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, 2009, 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 – 2000, UK – 2007 and the Netherlands – 2005.

Note 12 – 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,
	2009			2008			2009			2008
	(in millions)
Net Income (Loss)	$	107		$	974		$	(139	)	$	1,045
Other Items of Comprehensive Income (Loss)
Oil and Gas Cash Flow Hedges
Realized Losses Reclassified Into Earnings		14			93			45			248
Less Tax Provision		(5	)		(35	)		(17	)		(93	)
Interest Rate Cash Flow Hedges
Unrealized Gain in Fair Value		-			12			-			1
Less Tax Provision		-			(5	)		-			-
Net Change in Other		-			-			-			(1	)
Other Comprehensive Income		9			65			28			155
Comprehensive Income (Loss)	$	116		$	1,039		$	(111	)	$	1,200

21

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

Note 13 – 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 acquisition, exploration and production:  the United States; West Africa (Equatorial Guinea and Cameroon); the North Sea (UK and the Netherlands); Eastern Mediterranean (Israel and Cyprus); and Other International, Corporate and Marketing. The following data was prepared on the same basis as our consolidated financial statements and excludes the effects of income taxes.

	Consolidated			United States			West Africa			North Sea		Eastern Mediter-ranean		Other Int'l, Corporate, Marketing (1)
	(in millions)
Three Months Ended September 30, 2009
Revenues from Third Parties	$	610		$	332		$	95		$	51	$	53	$	79
Reclassification from AOCL (2)		(14	)		(7	)		(7	)		-		-		-
Intersegment Revenue		-			33			-			-		-		(33	)
Income from Equity Method Investees		25			-			25			-		-		-
Total Revenues		621			358			113			51		53		46
DD&A		205			172			9			10		6		8
Loss (gain) on Commodity Derivative Instruments		28			34			(6	)		-		-		-
Income (Loss) Before Income Taxes		115			42			94			25		43		(89	)
Three Months Ended September 30, 2008
Revenues from Third Parties	$	1,151		$	646		$	156		$	136	$	51	$	162
Reclassification from AOCL (2)		(93	)		(84	)		(9	)		-		-		-
Intersegment Revenue		-			112			-			-		-		(112	)
Income from Equity Method Investees		40			-			40			-		-		-
Total Revenues		1,098			674			187			136		51		50
DD&A		194			158			8			12		7		9
Asset Impairments		38			38			-			-		-		-
(Gain) on Commodity Derivative Instruments		(875	)		(749	)		(126	)		-		-		-
Income (Loss) Before Income Taxes		1,454			1,058			303			107		40		(54	)

22

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

	Consolidated			United States			West Africa			North Sea		Eastern Mediter-ranean		Other Int'l, Corporate, Marketing (1)
	(in millions)
Nine Months Ended September 30, 2009
Revenues from Third Parties	$	1,546		$	843		$	238		$	120	$	105	$	240
Reclassification from AOCL (2)		(45	)		(23	)		(22	)		-		-		-
Intersegment Revenue		-			121			-			-		-		(121	)
Income from Equity Method Investees		52			-			52			-		-		-
Total Revenues		1,553			941			268			120		105		119
DD&A		601			505			27			28		16		25
Asset Impairments		437			437			-			-		-		-
Loss on Commodity Derivative Instruments		95			76			19			-		-		-
Income (Loss) Before Income Taxes		(349	)		(439	)		176			49		77		(212	)
Nine Months Ended September 30, 2008
Revenues from Third Parties	$	3,418		$	1,975		$	460		$	327	$	121	$	535
Reclassification from AOCL (2)		(248	)		(216	)		(32	)		-		-		-
Intersegment Revenue		-			372			-			-		-		(372	)
Income from Equity Method Investees		158			-			158			-		-		-
Total Revenues		3,328			2,131			586			327		121		163
DD&A		593			487			26			40		18		22
Asset Impairments		38			38			-			-		-		-
Loss on Commodity Derivative Instruments		190			137			53			-		-		-
Income (Loss) Before Income Taxes		1,573			990			491			234		94		(236	)
Total Assets at September 30, 2009 (3)	$	11,635		$	8,557		$	1,667		$	605	$	426	$	380
Total Assets at December 31, 2008 (3)		12,384			9,212			1,614			775		366		417

(1) Other international includes China, Ecuador and Argentina (through February 2008) operations and the gain on sale of Argentina (in 2009).

(2) 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.

(3) The US reporting unit includes goodwill of $758 million at September 30, 2009 and $759 million at December 31, 2008.

23

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

Note 14 – Commitments and Contingencies

Purchaser Bankruptcy –We have an exposure from crude oil sales for the months of June and July 2008 to SemCrude, L.P. (SemCrude), a subsidiary of SemGroup, L.P. (SemGroup).  On July 22, 2008, SemGroup, including SemCrude, filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code under Case Number 08-11525 (BLS) in the United States Bankruptcy Court for the District of Delaware.

We previously determined that carrying value of our receivable of $70 million should be reduced by $38 million. Based upon the confirmation of SemCrude's plan for reorganization on October 26, 2009 and further based upon a settlement reached with SemCrude on October 27, 2009, we have further reduced the carrying value of our receivable by $12 million and believe the disposition of this matter to be finally determined.

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.

Note 15 – Subsequent Events

Recovery of Deepwater Royalties – On October 5, 2009, the U.S. Supreme Court denied a petition filed by the U.S. Department of the Interior (DOI) in a case styled Dept. of Interior, et al v. Kerr-McGee Oil and Gas Corp. (09-54).  This case involved the payment of royalties attributable to federal leases acquired by Kerr-McGee Oil and Gas Corporation (Kerr-McGee) pursuant to Section 304 of the Outer Continental Shelf Deep Water Royalty Relief Act of 1995 (DWRRA).  As a result of the Supreme Court’s decision, lower court rulings from the U.S. District Court of the Western District of Louisiana and U.S. Court of Appeals for the Fifth Circuit, which were in favor of Kerr-McGee, were left to stand.  Those courts ruled that the DOI did not have the authority to impose price thresholds that required the payment of royalties before minimum royalty suspension volumes imposed by Section 304 of the DWRRA were produced.

Based upon our analysis of the Kerr-McGee case, we believe that the Supreme Court’s decision will impact other companies, including us, who were not directly involved in the case but, like Kerr-McGee, acquired leases issued pursuant to Section 304 of the DWRRA.  As a result, we believe that we are entitled to a refund of approximately $84 million plus interest as of September 30, 2009. The refund is attributable to royalties that we previously paid on production of approximately 900 MBbls of crude oil and 3,000 MMcf of natural gas that was produced from January 1, 2003 through September 30, 2009.

We plan to vigorously pursue all means of reimbursement. However, pending the expiration of the period for rehearing and pending clarification from the U.S. Minerals Management Service, a department of the DOI, (the MMS) regarding the position the MMS may take with respect to other similarly situated companies, we have not recorded any income associated with this claim at this time.

Lease Obligation – On October 6, 2009, we entered into an agreement with an unrelated offshore technology provider for the construction and lease of a floating production, storage and offloading vessel (FPSO) to be used for the development of the Aseng field, offshore Equatorial Guinea. We serve as technical operator of the development project with a 40% working interest.

Construction of the FPSO is scheduled to be completed in 2012, at which time the FPSO will be delivered to Block I, offshore Equatorial Guinea, for the start-up of the Aseng field. The initial term of the lease is for a period of 15 years. We expect to account for the lease agreement as a capital lease. As a result, the FPSO will be included in oil and gas properties and the associated long-term obligation will be included in our balance sheet.  We expect that the lease obligation will total approximately $340 million, net to our 40% interest.  This amount represents our share of the expected present value of the future minimum lease payments, excluding executory costs, and is subject to change based on change orders implemented during the construction period, final accounting treatment and other factors.

Once construction has begun and throughout the construction phase, we will include both the FPSO asset and associated long-term obligation in our balance sheet, based upon the percentage of construction completed at the end of each reporting period.

Monthly lease payments will exclude regular maintenance and operational costs, and will begin when the FPSO initiates producing operations.  Annual lease payments, net to our 40% interest, are expected to total approximately $69 million per year for years 1-4 of the lease agreement, $43 million per year for years 5-7; and $8 million per year for the remaining years of the initial 15-year lease term.  These payments are also subject to change based on change orders implemented during the construction period and other factors.

24

NOBLE ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

Note 16 – Recently Issued Pronouncements

Accounting Standards Update – In August 2009, the FASB issued Accounting Standards Update (Update) 2009-5, “Measuring Liabilities at Fair Value” in order to provide further guidance on how to measure the fair value of a liability. The Update clarifies that, in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more prescribed techniques. We adopted the new guidance as of October 1, 2009. Adoption had no impact on our financial position or results of operations.

Recent SEC Rule-Making Activity – In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:

· Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price unless contractual arrangements designate the price to be used.

· Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

· Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered.

· Reserve Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

· Reserve Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees our reserves estimation process.  We will also be required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

· Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and gas proved reserves.

· Non-Traditional Resources – The definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.

The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted.

The SEC is coordinating with the FASB to obtain the revisions necessary to US GAAP concerning financial accounting and reporting by oil and gas producing companies and disclosures about oil and gas producing activities to provide consistency with the new rules. During September 2009, the FASB issued an exposure draft of a proposed Accounting Standards Update, “Oil and Gas Reserves Estimation and Disclosures”. The proposed Update would amend existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules. As proposed, the  Update would be effective for annual reporting periods ending on or after December 31, 2009, and would be applied prospectively as a change in estimate.

We are currently evaluating the new SEC rules and proposed FASB Accounting Standards Update and assessing the impact they will have on our reported oil and gas reserves.

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

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 2009 included:

· net income of $107 million, as compared with net income of $974 million for third quarter 2008;

· loss on commodity derivative instruments of $28 million (including unrealized mark-to-market loss of $149 million) as compared with a gain on commodity derivative instruments of $875 million (including unrealized mark-to-market gain of $943 million) for third quarter 2008;

· diluted earnings per share of $0.61, as compared with diluted earnings per share of $5.37 for third quarter 2008;

· ending cash and cash equivalents balance of $926 million as compared with $1.1 billion at December 31, 2008; and

· cash flow provided by operating activities of $488 million, as compared with $713 million for third quarter 2008.

Significant operational highlights for third quarter 2009 included:

United States – Offshore

· Ticonderoga, in the deepwater Gulf of Mexico, returned to full production of approximately 5,000 Boepd, net in August 2009 after being offline due to Hurricane Ike in 2008; and

· approved Isabela/Santa Cruz oil project in the deepwater Gulf of Mexico.

United States – Onshore

· record quarterly Wattenberg production of 283 MMcfepd, including liquid volumes of 22 MBpd; and

· completed our first horizontal East Texas Haynesville shale well with an initial thirty-day average production rate of over 11 MMcfpd, gross.

International

· sanctioned Aseng field in Block I offshore Equatorial Guinea; and

· executed an additional sales agreement in Israel which raised average natural gas sales prices by over 40% from the previous quarter.

Sanction of Aseng Field– On July 22, 2009, we announced that the Plan of Development for the Aseng field has been sanctioned by us, our partners, and the Ministry of Mines, Industry, and Energy of the Republic of Equatorial Guinea.  We serve as technical operator of the development with a 40% working interest.

Formerly known as Benita, Aseng was originally discovered in 2007 as a gas-condensate field in Block I offshore Equatorial Guinea. Subsequently, two appraisal wells were drilled in the structure, with the first identifying the oil resources and the second determining the reservoir limits.

Initial development of the field will include multiple subsea wells flowing to an FPSO where the production stream will be separated.  The oil will be stored on the FPSO until sold, while the natural gas and water will be reinjected into the reservoir to maintain pressure and maximize oil recoveries. The FPSO was designed with capacity to handle 120,000 barrels of liquids per day, including 80,000 barrels of oil per day. In addition, the vessel will be capable of reinjecting 170 million cubic feet per day of natural gas. Storage on the vessel will be approximately 1.5 million barrels of oil and condensate.

Total development costs, excluding the costs related to the FPSO, are estimated at $1.3 billion ($530 million, net) with the majority of this capital to be invested in 2010 and 2011. First production from the field is estimated to commence by mid-year 2012 at 50,000 barrels of oil per day gross (16,500 barrels per day net). The FPSO lease has been awarded and a leasing contract has been signed. See Item 1. Financial Statements – Note 15 – Subsequent Events and Liquidity and Capital Resources – Contractual Obligations.

26

Approval  of Isabela/Santa Cruz Project – During third quarter 2009, we approved the Isabela/Santa Cruz development project in the deepwater Gulf of Mexico. The phased development plan will consist of an initial two to three wells with subsea tiebacks to nearby infrastructure. Initial production is expected in 2011. We have a 33.33% non-operated working interest in Isabela and a 23.25% operated working interest in Santa Cruz.

New Israel Natural Gas Sales Contract – We signed a new natural gas sales contract with our primary customer, Israel Electric Corporation, to purchase our remaining undedicated Mari-B field gas at prices expected to be significantly higher than what we have been receiving under the original contract. The actual price received will be tied to a blend of liquids prices and a producer price index.  In addition, it was agreed that all sales from the Mari-B field going forward will be proportionately allocated between the two contracts regardless of the total volume sold. This is a major change from the past arrangement wherein only “excess” volumes above a threshold level received premium prices.

Impact of Recession and Current Credit and Commodity Markets– During 2009, we have taken initiatives to strengthen our liquidity and lengthen our weighted average debt maturities in response to ongoing uncertainty in the credit markets.  In February we issued $1 billion of 8¼% senior notes due 2019 and used substantially all of the net proceeds to repay outstanding indebtedness under our credit facility.  In addition, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. See Liquidity and Capital Resources below.

As noted in our 2008 Annual Report on Form 10-K (Item 1A. Risk Factors), significant decreases in crude oil and natural gas prices could result in a reduction of the carrying values of our oil and gas properties.  The commodity price decreases that began during the second half of 2008 required us to record asset impairment charges during fourth quarter 2008.  Further declines in natural gas prices during first quarter 2009 led us to review those properties that, at year-end 2008, were susceptible to impairment should commodity prices continue to decline appreciably.  As a result of this review, we determined that additional properties were impaired as of March 31, 2009. Total pre-tax (non-cash) impairments for first quarter 2009 were $437 million and were predominately related to Granite Wash, an onshore US area in which we have significantly reduced investments beginning in 2007. The decrease in the natural gas futures price strip that occurred during first quarter 2009 was the primary factor that required an impairment of Granite Wash.  There were no asset impairments during the second or third quarters of 2009. However, further declines in commodity prices could result in additional impairment of our oil and gas properties, other long-lived assets or goodwill. See Item 1. Financial Statements – Note 5 – Fair Value Measurements and Disclosures.

During the second and third quarters of 2009, our operations benefited from the strengthening crude oil market, but sustained lower commodity prices will continue to reduce our cash flows from operations as compared to prior years. To mitigate the impact of lower commodity prices on our cash flows, we entered into crude oil and natural gas commodity contracts for 2009, 2010 and 2011. Depending on the length of the current recession, commodity prices may stay depressed or decline further, thereby causing a prolonged downturn, which would further reduce our cash flows from operations.  This could cause us to alter our business plans including reducing or delaying our exploration and development program spending and other cost reduction initiatives.  See 2009 Budget below.

We are closely monitoring costs and have implemented several cost savings initiatives, including continued reduction of well costs through drilling and completion efficiencies and comprehensive review of oil and gas operating costs.  We are also continuing to see reductions in third party drilling costs and operating supplies and services.

OUTLOOK

Our expected crude oil, natural gas and NGL production for the remainder of 2009 may be impacted by several factors including:

· overall level and timing of capital expenditures, as discussed below, which, dependent upon our drilling success, are expected to maintain our near-term production volumes;

· natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-continent areas of our US operations;

· downtime beginning in mid-August at the Dumbarton field in the UK sector of the North Sea due to FPSO repairs with an expected return to operation by the end of October;

· 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;

· potential hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast areas as occurred with Hurricanes Gustav and Ike in 2008;

27

· 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 area of our US operations;

· 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;

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

· timing of significant project completion and initial production.

2009 Budget– Due to the uncertain economic and commodity price environment, we designed a flexible capital spending program that has been responsive to conditions that developed during 2009.  Our revised capital program for 2009 targets an investment level of approximately $1.4 billion.  

Approximately 40% of the 2009 budget is committed to longer-term projects that will provide considerable production growth several years in the future. The remainder is allocated toward maintaining and strengthening the existing property base.  Development spending is focused on our international and deepwater Gulf of Mexico assets as well as certain higher return opportunities onshore in the US including the Wattenberg field.  The exploration budget is centered on significant resource potential in Israel, West Africa and the deepwater Gulf of Mexico.  International expenditures are estimated to represent 30% of the total capital program.

The 2009 budget does not include the impact of possible asset purchases. We expect that the remaining 2009 budget will be funded primarily from cash flows from operations, cash on hand, and borrowings under our revolving credit facility.

Potential Sale of Noble Energy Europe – We maintain an ongoing portfolio optimization program which may result in the divestiture of non-core assets in order to maintain a balanced portfolio of high-quality, core properties. We are marketing our wholly-owned European subsidiary Noble Energy (Europe) Limited (Noble Energy Europe).  Noble Energy Europe holds non-operated interests in four UK Central North Sea producing oil fields, four UK Southern Gas Basin fields and an oil/gas field offshore Netherlands. Additionally, Noble Energy Europe has interests in a number of North Sea exploration and development projects and minor onshore UK fields. We are currently soliciting bids, but the board of directors and management have not committed to a plan to sell the asset.

Change in Insurance Coverage – We are a member in Oil Insurance Limited (OIL). OIL is a mutual insurance company which insures property, pollution liability, control of well and other catastrophic risks. In September 2009, OIL members approved a proposal that will eliminate 40% of the current per occurrence windstorm coverage provided by OIL to members, effective January 1, 2010.  As of that date, windstorm coverage will be provided on a 60% quota share basis. As a result, our maximum recovery from OIL for any one windstorm loss, excess of a $10 million deductible, has been reduced from $250 million to $150 million. As a result of our recent asset retirement efforts at Main Pass, our risk of windstorm damage has been reduced.  We have not yet determined whether we will seek additional third party insurance to replace the reduction in OIL coverage.

Recently Issued Pronouncements – See Item 1. Financial Statements – Note 16 – Recently Issued Pronouncements.

28

RESULTS OF OPERATIONS

Oil, Gas and NGL Sales

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

	Crude Oil and Condensate			Natural Gas			NGLs			Total
	(in millions)
Three Months Ended September 30,
2008 Sales	$	629		$	361		$	50		$	1,040
Changes due to:
Sales Volumes		(22	)		18			3			(1	)
Sales Prices		(305	)		(211	)		(29	)		(545	)
Amounts Reclassified from AOCL		75			4			-			79
2009 Sales	$	377		$	172		$	24		$	573
(Decrease) from prior period		-40	%		-52	%		-52	%		-45	%
Nine Months Ended September 30,
2008 Sales	$	1,830		$	1,132		$	153		$	3,115
Changes due to:
Sales Volumes		(215	)		11			1			(203	)
Sales Prices		(973	)		(614	)		(88	)		(1,675	)
Amounts Reclassified from AOCL		234			(31	)		-			203
2009 Sales	$	876		$	498		$	66		$	1,440
(Decrease) from prior period		-52	%		-56	%		-57	%		-54	%

29

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

	Sales Volumes				Average Realized Sales Prices
	Crude Oil & Condensate (MBpd)	Natural Gas (MMcfpd)	NGLs (MBpd)		Crude Oil & Condensate (Per Bbl)	Natural Gas (Per Mcf)			NGLs (Per Bbl)
Three Months Ended September 30, 2009
United States (1) (2)	39	397	10	$	62.30	$	3.05	$	25.39
West Africa (3) (4)	14	228	-		63.10		0.27		-
North Sea	8	5	-		69.56		4.63		-
Israel	-	144	-		-		3.95		-
Ecuador (5)	-	28	-		-		-		-
Other International	4	-	-		62.75		-		-
Total Consolidated Operations	65	802	10		63.36		2.41		25.39
Equity Investees (6)	2	-	6		66.33		-		38.26
Total	67	802	16	$	63.46	$	2.41	$	30.25
Three Months Ended September 30, 2008
United States (1) (2)	38	384	10	$	93.47	$	8.48	$	57.06
West Africa (3) (4)	14	194	-		109.90		0.27		-
North Sea	12	6	-		117.44		11.54		-
Israel	-	155	-		-		3.57		-
Ecuador (5)	-	21	-		-		-		-
Other International	3	-	-		106.03		-		-
Total Consolidated Operations	67	760	10		101.82		5.31		57.06
Equity Investees (6)	2	-	5		116.04		-		67.56
Total	69	760	15	$	102.25	$	5.31	$	60.80
Nine Months Ended September 30, 2009
United States (1) (2)	37	401	10	$	50.45	$	3.36	$	24.70
West Africa (3) (4)	14	238	-		51.94		0.27		-
North Sea	7	5	-		57.61		5.94		-
Israel	-	117	-		-		3.27		-
Ecuador (5)	-	24	-		-		-		-
Other International	4	-	-		49.76		-		-
Total Consolidated Operations	62	785	10		51.55		2.40		24.70
Equity Investees (6)	2	-	6		56.42		-		31.65
Total	64	785	16	$	51.70	$	2.40	$	27.40
Nine Months Ended September 30, 2008
United States (1) (2)	41	393	10	$	87.84	$	9.10	$	57.39
West Africa (3) (4)	15	212	-		103.31		0.27		-
North Sea	10	6	-		114.42		10.62		-
Israel	-	140	-		-		3.15		-
Ecuador (5)	-	22	-		-		-		-
Other International	4	-	-		73.37		-		-
Total Consolidated Operations	70	773	10		78.89		5.50		57.39
Equity Investees (6)	2	-	6		110.43		-		66.08
Total	72	773	16	$	95.47	$	5.50	$	60.80

30

(1) Average realized crude oil and condensate prices reflect reductions of $1.89 per Bbl and $22.95 per Bbl for third quarter 2009 and 2008, respectively, and reductions of $2.28 per Bbl and $21.69 per Bbl for the first nine months of 2009 and 2008, respectively, from hedging activities. The price reductions resulted from hedge losses that were previously deferred in AOCL.

(2) Average realized natural gas prices reflect an increase of $0.01 per Mcf and a reduction of $0.12 per Mcf for third quarter 2009 and 2008, respectively, and an increase of $0.29 per Mcf for the first nine months of 2008 from hedging activities.  The price increases and reduction resulted from hedge gains and losses that were previously deferred in AOCL. The average realized natural gas price for the first nine months of 2009 was not impacted by hedging activities, as the net deferred gain reclassified from AOCL was de minimis.

(3) Average realized crude oil and condensate prices reflect reductions of $5.32 per Bbl and $7.42 per Bbl for third quarter 2009 and 2008, respectively, and $5.84 per Bbl and $8.10 per Bbl for the first nine months of 2009 and 2008, respectively, from hedging activities.  The price reductions resulted from hedge losses that were previously deferred in AOCL.

(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.  Natural gas volumes sold to the LNG plant totaled 175 MMcfpd and 160 MMcfpd during third quarter 2009 and 2008, respectively, and 187 MMcfpd and 169 MMcfpd during the first nine months of 2009 and 2008, respectively.

(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.

Crude oil and condensate sales volumes in the table above differ from actual production volumes due to the timing of liquid hydrocarbon tanker liftings and changes in inventory held in tanks and pipelines. Crude oil and condensate production volumes were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(MBopd)
United States		39		38		37		41
West Africa		14		15		16		15
North Sea		7		9		9		10
Other International		4		3		5		4
Total Consolidated Operations		64		65		67		70
Equity Investees		2		2		2		2
Total		66		67		69		72

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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)
	Crude Oil & Condensate		Natural Gas		Crude Oil & Condensate			Natural Gas
	2009				2008
	(Per Bbl)		(Per Mcf)		(Per Bbl)			(Per Mcf)
Three Months Ended September 30,
United States	$	9.29	$	1.95	$	(14.10	)	$	(0.20	)
West Africa		12.99		-		(9.76	)		-
Total Consolidated Operations		8.41		1.00		(9.96	)		(0.10	)
Total		8.14		1.00		(9.66	)		(0.10	)
Nine Months Ended September 30,
United States	$	14.38	$	1.84	$	(9.62	)	$	(0.55	)
West Africa		17.48		-		(7.71	)		-
Total Consolidated Operations		12.46		0.97		(7.28	)		(0.29	)
Total		12.09		0.97		(7.09	)		(0.29	)

Crude Oil and Condensate Sales – Revenues from crude oil and condensate sales decreased during the third quarter of 2009 as compared with the third quarter of 2008 due to the following:

· a 38% decline in total consolidated average realized prices;

· downtime beginning in mid-August at the Dumbarton field in the UK sector of the North Sea due to FPSO repairs; and

· natural field decline in the deepwater Gulf of Mexico and Gulf Coast area;

offset by

· increased production from the Wattenberg field in the northern region of our US operations due to ongoing development activity; and

· return of Ticonderoga in the deepwater Gulf of Mexico to full production in August 2009 after being off-line after Hurricane Ike in 2008.

Revenues from crude oil and condensate sales decreased during the first nine months of 2009 as compared with the first nine months of 2008 due to the following:

· a 35% decline in total consolidated average realized prices;

· impact of shut-ins related to Hurricane Ike in the deepwater Gulf of Mexico;

· downtime beginning in mid-August at the Dumbarton field in the UK sector of the North Sea due to FPSO repairs; and

· natural field decline in the deepwater Gulf of Mexico and Gulf Coast area;

offset by

· increased Wattenberg field production due to ongoing development activity.

Revenues from crude oil and condensate sales included deferred losses of $14 million and $89 million for third quarter 2009 and 2008, respectively, and $45 million and $279 million for the first nine months of 2009 and 2008, 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 decreased during the third quarter of 2009 as compared with the third quarter of 2008 due to the following:

· a 55% decline in total consolidated average realized prices; and

· natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-continent areas;

offset by

· increased production from the Wattenberg, Piceance and Shattuck (Western Oklahoma) areas of our US operations;

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· return of Ticonderoga in the deepwater Gulf of Mexico to full production; and

· sales of natural gas from the Raton development in the deepwater Gulf of Mexico which began year-end 2008.

Revenues from natural gas sales decreased during the first nine months of 2009 as compared with the first nine months of 2008 due to the following:

· a 56% decline in total consolidated average realized prices;

· shut-ins related to Hurricane Ike in the deepwater Gulf of Mexico; and

· decreased Israel natural gas sales due to power plant downtime and competing natural gas sales from Egypt;

offset by

· increased production from the Wattenberg, Piceance and Shattuck areas;

· sales of natural gas from the Raton development in the deepwater Gulf of Mexico which began year-end 2008; and

· increase in Equatorial Guinea volumes sold to the LNG plant due to less maintenance downtime at the LNG plant.

Revenues from natural gas sales included a deferred loss of $4 million for third quarter 2008 and a deferred gain of $31 million for the first nine months of 2008 reclassified from AOCL and related to commodity derivative instruments previously accounted for as cash flow hedges. Revenues for the third quarter and first nine months of 2009 included a de minimis amount reclassified from AOCL and related to commodity derivative instruments previously accounted for as cash flow hedges.

NGL Sales – Most of our US NGL production is from the Wattenberg field and deepwater Gulf of Mexico. NGL sales decreased during the third quarter and first nine months of 2009 as compared with 2008 due to the significant decrease in average realized NGL prices.

Equity Method Investees

Our share of operations of equity method investees, Atlantic Methanol Production Company, LLC (AMPCO) and Alba Plant LLC (Alba Plant), was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Net Income (in millions):
AMPCO and Affiliates	$	6	$	5	$	9	$	51
Alba Plant		19		35		43		107
Dividends (in millions):
AMPCO and Affiliates		6		16		6		54
Alba Plant		26		55		31		138
Sales Volumes:
Methanol (MMgal)		41		23		109		93
Condensate (MBopd)		2		2		2		2
LPG (MBpd)		6		5		6		6
Production Volumes:
Methanol (MMgal)		35		21		111		83
Condensate (MBopd)		2		2		2		2
LPG (MBpd)		6		6		6		6
Average Realized Prices:
Methanol (per gallon)	$	0.64	$	1.16	$	0.52	$	1.33
Condensate (per Bbl)		66.33		116.04		56.42		110.43
LPG (per Bbl)		38.26		67.56		31.65		66.08

The decrease in net income for each of the equity method investees for the third quarter and first nine months of 2009 as compared with 2008 was due to significant decreases in average realized prices. Methanol sales volumes were higher during the third quarter and first nine months of 2009 as compared with 2008 as AMPCO experienced significant downtime for compressor and other equipment maintenance during 2008.

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The decreases in dividends for each of the equity method investees during the third quarter and first nine months of 2009 were due to reduced year-to-date net income.

Other Revenues

Other revenues include electricity sales and GMP revenues. See Item 1. Financial Statements – Note 2 – Basis of Presentation.

Costs and Expenses

Production Costs

Components of production costs were as follows:

	Total		United States		West Africa		North Sea		Israel		Other Int'l, Corporate(1)
	(in millions)
Three Months Ended September 30, 2009
Lease Operating Expense (2)	$	88	$	55	$	13	$	13	$	3	$	4
Production and Ad Valorem Taxes		25		21		-		-		-		4
Transportation Expense		18		16		-		1		-		1
Total Production Costs	$	131	$	92	$	13	$	14	$	3	$	9
Three Months Ended September 30, 2008
Lease Operating Expense (2)	$	98	$	64	$	10	$	18	$	3	$	3
Production and Ad Valorem Taxes		47		38		-		-		-		9
Transportation Expense		14		12		-		2		-		-
Total Production Costs	$	159	$	114	$	10	$	20	$	3	$	12
Nine Months Ended September 30, 2009
Lease Operating Expense (2)	$	281	$	196	$	33	$	32	$	7	$	13
Production and Ad Valorem Taxes		66		58		-		-		-		8
Transportation Expense		43		37		-		3		-		3
Total Production Costs	$	390	$	291	$	33	$	35	$	7	$	24
Nine Months Ended September 30, 2008
Lease Operating Expense (2)	$	268	$	183	$	29	$	38	$	7	$	11
Production and Ad Valorem Taxes		141		112		-		-		-		29
Transportation Expense		43		36		-		6		-		1
Total Production Costs	$	452	$	331	$	29	$	44	$	7	$	41

(1) Other international includes Ecuador, China, and Argentina (through February 2008).

(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 of 2009, total production costs decreased as compared with the third quarter of 2008 due to the following:

· decrease in US lease operating expense associated with cost savings initiatives including reduced repair programs and a reduction of other discretionary spending in our onshore US operations including a reduced workover program in the Northern region;

· decrease in North Sea lease operating expense due to lower sales volumes, resulting in an increase in crude oil inventory, which includes production cost expense;

· decrease in production and ad valorem taxes due to reduced proceeds from sales attributable to lower commodity prices in the US and China and the cessation of production due to the sale of our interest in Argentina; and

· decrease in North Sea transportation expense due to decrease in production;

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offset by

· increase in West Africa lease operating expense due to higher contractor costs; and

· increase in US transportation expense due to start up of a new interstate crude oil transportation pipeline system used to market our Wattenberg production.

For the first nine months of 2009, total production costs decreased as compared with the first nine months of 2008 due to the following:

· decrease in North Sea lease operating expense due to an increase in crude oil inventory;

· decrease in US lease operating expense due to a reduced workover program in the Northern region;

· decrease in production and ad valorem taxes due to reduced proceeds from sales attributable to lower commodity prices in the US and China and the cessation of production due to the sale of our interest in Argentina; and

· decrease in North Sea transportation expense due to decrease in production;

offset by

· increase in US lease operating expense due to an increase in well count, higher salt water disposal costs in the Northern region and higher insurance expense;

· increase in West Africa lease operating expense due to higher contractor costs and higher maintenance expense; and

· increase in US transportation expense due to start up of a new interstate crude oil transportation pipeline system used to market our Wattenberg production.

Selected expenses on a per BOE basis were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Lease Operating Expense	$	4.57	$	5.22	$	5.07	$	4.69
Production and Ad Valorem Taxes		1.28		2.50		1.19		2.47
Transportation Expense		0.93		0.76		0.77		0.75
Total Production Costs (1) (2)	$	6.78	$	8.48	$	7.03	$	7.91

(1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea. The inclusion of these volumes reduced the unit rate by $1.10 per BOE and $1.28 per BOE for third quarter 2009 and 2008, respectively, and $1.28 per BOE and $1.23 per BOE for the first nine months of 2009 and 2008, respectively.

(2) Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.

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Oil and Gas Exploration Expense

Components of oil and gas exploration expense were as follows:

	Total		United States		West Africa		North Sea		Eastern Mediter-ranean		Other Int'l, Corporate (1)
	(in millions)
Three Months Ended September 30, 2009
Dry Hole Expense	$	3	$	3	$	-	$	-	$	-	$	-
Seismic		7		5		-		-		2		-
Staff Expense		17		4		3		-		-		10
Other		-		-		-		-		-		-
Total Exploration Expense	$	27	$	12	$	3	$	-	$	2	$	10
Three Months Ended September 30, 2008
Dry Hole Expense	$	10	$	10	$	-	$	-	$	-	$	-
Seismic		14		11		-		-		3		-
Staff Expense		14		3		-		-		-		11
Other		1		1		-		-		-		-
Total Exploration Expense	$	39	$	25	$	-	$	-	$	3	$	11
Nine Months Ended September 30, 2009
Dry Hole Expense	$	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	$	1	$	5	$	28
Nine Months Ended September 30, 2008
Dry Hole Expense	$	78	$	37	$	1	$	8	$	-	$	32
Seismic		47		40		-		4		3		-
Staff Expense		45		9		4		4		-		28
Other		11		11		-		-		-		-
Total Exploration Expense	$	181	$	97	$	5	$	16	$	3	$	60

(1) Other international includes amounts spent in support of various international new ventures.

Oil and gas exploration expense for the third quarter and first nine months of 2009 decreased as compared with the same periods in 2008 primarily due to reductions in dry hole and seismic expenses. There was less dry hole expense in 2009 due to our successful exploration drilling programs. Dry hole expense in 2008 was due primarily to exploration wells in Suriname and the deepwater Gulf of Mexico which did not encounter hydrocarbons in commercial quantities. US seismic expense decreased in 2009 as compared with 2008 due to a reduction in expenditures made for seismic data in the deepwater Gulf of Mexico.

Exploration expense also includes stock-based compensation expense of $2 million and $1 million for third quarter 2009 and 2008, respectively, and $7 million and $2 million for the first nine months of 2009 and 2008, respectively.

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Depreciation, Depletion and Amortization

DD&A expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in millions, except unit rate)
DD&A Expense	$	201	$	191	$	590	$	586
Accretion of Discount on Asset Retirement Obligations		4		3		11		7
Total DD&A Expense	$	205	$	194	$	601	$	593
Unit Rate per BOE (1)	$	10.68	$	10.38	$	10.86	$	10.37

(1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea. The inclusion of these volumes reduced the unit rate by $1.44 per BOE and $1.25 per BOE for third quarter 2009 and 2008, respectively, and $1.64 and $1.31 per BOE for the first nine months of 2009 and 2008, respectively.

Total DD&A expense for the third quarter of 2009 increased as compared with the third quarter of 2008 due to the following:

· higher production in the Wattenberg, Piceance and Shattuck areas;

· ongoing capital spending in the Northern region; and

· negative reserve revisions related to lower year-end 2008 commodity prices;

Offset by lower sales volumes in the North Sea.

Total DD&A expense for the first nine months of 2009 increased as compared with the first nine months of 2008 due to the following:

· higher production in the Wattenberg, Piceance and Shattuck areas;

· ongoing capital spending in the Northern region;

· negative reserve revisions related to lower year-end 2008 commodity prices; and

· inclusion of $4 million of abandoned asset expense in 2009.

Offset by lower sales volumes in the North Sea and Israel.

The unit rate per BOE increased for both the third quarter and first nine months of 2009 as compared with the same periods in 2008 due to the change in mix of production, including a decrease in lower-cost volumes from Israel; ongoing capital spending in the Northern region; and negative reserve revisions related to lower year-end 2008 commodity prices.

General and Administrative Expense

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
G&A Expense (in millions)	$	53	$	63	$	173	$	184
Unit Rate per BOE (1)	$	2.78	$	3.37	$	3.11	$	3.22

(1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea. The inclusion of these volumes reduced the unit rate by $0.47 per BOE and $0.51 per BOE for third quarter 2009 and 2008, respectively, and $0.57 per BOE and $0.50 per BOE for the first nine months of 2009 and 2008, respectively.

G&A expense decreased $10 million, or 16%, for the third quarter of 2009 as compared with the third quarter of 2008 and $11 million, or 6%, for the first nine months of 2009 as compared with the first nine months of 2008. The decreases were due to reductions in variable components of incentive compensation.

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G&A expense included stock-based compensation expense of $9 million for the third quarters of both 2009 and 2008, and $27 million and $28 million for the first nine months of 2009 and 2008, respectively.

The unit rate per BOE for the third quarter and first nine months of 2009 decreased as compared with 2008 due primarily to the reduced G&A expense, as sales volumes on a BOE basis remained about the same period-to-period.

Asset Impairments

Asset impairment expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in millions)
Impairment Expense	$	-	$	38	$	437	$	38

During first quarter 2009 we recorded total pre-tax (non-cash) impairment charges of $437 million on certain US oil and gas properties, primarily due to lower natural gas prices. In determining the fair values of the impaired properties, we applied the principles of fair value measurements as defined by US GAAP. These principles require that fair values be determined from the perspective of a market participant considering, among other things, appropriate discount rates, multiple valuation techniques, the most advantageous market and assumptions around the highest and best use of the assets. Due to the absence of comparable market data for the impaired properties, we estimated the fair values using a discounted cash flow method. Estimated future cash flows were based on management’s expectations for the future and included management’s estimates of future oil and gas production, commodity prices based on published commodity futures price strips as of March 31, 2009, operating and development costs, as well as appropriate discount rates. Due to the use of significant unobservable inputs, the fair values of the impaired properties were classified as Level 3 measurements in the fair value hierarchy. A change in any of the assumptions used, such as a significant increase or decrease in estimated commodity prices or production, could have had a significant impact on the amount of the impairment loss recognized. There were no asset impairments during the second or third quarters of 2009. See Item 1. Financial Statements – Note 5 – Fair Value Measurements and Disclosures.

Other Operating (Income) Expense, Net

Other operating (income) expense was as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in millions)
Other Operating (Income) Expense, Net	$	34	$	60	$	22	$	107

Other operating (income) expense, net includes gain on asset sales, electricity generation expense, GMP expense, settlement of legal proceedings, (gain) loss on involuntary conversion, write-down of the SemCrude receivable and other items of operating income or expense. See Item 1. Financial Statements – Note 2 – Basis of Presentation and Note 14 – Commitments and Contingencies.

(Gain) Loss on Commodity Derivative Instruments

(Gain) loss on commodity derivative instruments was as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
	(in millions)
(Gain) Loss on Commodity Derivative Instruments	$	28	$	(875	)	$	95	$	190

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See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities and Note 5 – 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,
	2009			2008			2009			2008
	(in millions)
Interest Expense	$	35		$	26		$	94		$	75
Capitalized Interest		(12	)		(8	)		(30	)		(23	)
Interest Expense, net	$	23		$	18		$	64		$	52

Interest expense increased $9 million for third quarter 2009 and $19 million for the first nine months of 2009, as compared with 2008. 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. This increase was partially offset by a significant decrease in credit facility interest expense due to a decline in both the average outstanding balance and the average interest rate. See also Liquidity and Capital Resources – Financing Activities below.

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

Other Non-operating (Income) Expense, Net

Other non-operating (income) expense was as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
	(in millions)
Other Non-operating (Income) Expense, Net	$	5	$	(52	)	$	18	$	(42	)

Other non-operating (income) expense includes deferred compensation (income) expense, interest income and other (income) expense. See Item 1. Financial Statements – Note 2 – Basis of Presentation.

Income Tax Provision (Benefit)

The income tax provision (benefit) was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Income Tax Provision (Benefit) (in millions)	$	8		$	480		$	(210	)	$	528
Effective Rate		7	%		33	%		60	%		34	%

See Item 1. Financial Statements – Note 11 – Income Taxes for a discussion of the change in our effective tax rate during the first nine months of 2009 as compared with 2008.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

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

The ongoing disruption in the credit markets has had a significant adverse impact on a number of financial institutions. We have reviewed the creditworthiness of the banks and financial institutions with which we maintain our investments as well as the securities underlying our investments. Thus far, our liquidity and financial position have not been materially impacted. However, further deterioration in the credit markets could adversely affect our results of operations and cash flows. See Executive Overview – Impact of Recession and Current Credit and Commodity Markets.

Cash and Cash Equivalents – We had $926 million in cash and cash equivalents at September 30, 2009. Our cash is denominated in US dollars and was invested in US Treasury securities, money market funds and short-term deposits with major financial institutions at September 30, 2009. In response to the credit market crisis, we shortened the duration of our investment maturities and increased our investments in US Treasury securities.

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 development of West Africa and Israel.

During fourth quarter 2008, we performed an analysis of projected short-term working capital needs as well as long-term capital requirements for our US and foreign operations. As a result, we repatriated $180 million of the accumulated earnings of foreign subsidiaries during first quarter 2009. We used the proceeds for debt repayment and general corporate purposes. See Item 1. Financial Statements – Note 11 – Income Taxes for a discussion of the related income tax effects.

Commodity 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. Such instruments include variable to fixed commodity price swaps, 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 are entered into from time to time by our marketing subsidiary, none of our counterparty agreements contain margin requirements.

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, 2009, the fair value of our commodity derivative assets was $96 million and the fair value of our commodity derivative liabilities was $114 million (after consideration of netting agreements). See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities for a discussion of counterparty credit risk and Note 5 – Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of commodity derivative instruments.

Contractual Obligations

Debt Offering –In February 2009, we completed an underwritten public offering of $1 billion of 8¼% senior unsecured notes due March 1, 2019. See Financing Activities below. As a result, our future debt principal payments as of September 30, 2009 consist of the following: $535 million for 2012; and $1.6 billion for 2014 and beyond for a total of $2.1 billion. Based on the total debt balance, scheduled maturities and interest rates in effect at September 30, 2009, our cash payments for interest would be $20 million for the remainder of 2009; $129 million in 2010; $129 million in 2011; $129 million in 2012; $126 million in 2013; and $1.3 billion for the remaining years for a total of $1.8 billion. See Item 1. Financial Statements – Note 3 – Debt.

Lease Obligation – On October 6, 2009, we signed an agreement with an unrelated offshore technology provider for the construction and lease of an FPSO to be used for the development of the Aseng field offshore Equatorial Guinea. See Item 1. Financial Statements – Note 15 – Subsequent Events.

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Drilling Contracts – During third quarter 2009, we entered into two drilling rig contracts for our international operations totaling $356 million.  Annual payments are expected to be $183 million for 2010 and $173 million for 2011.  These amounts represent the gross contract amounts and will be reduced by our non-operating partners’ working interests. These drilling rigs are presently planned to drill wells having an average Noble Energy working interest between approximately 35% to 45%.

Cash Flows

Cash flow information is as follows:

	Nine Months Ended September 30,
	2009			2008
	(in millions)
Total Cash Provided By (Used in):
Operating Activities	$	986		$	1,867
Investing Activities		(1,012	)		(1,721	)
Financing Activities		(188	)		186
Increase (Decrease) in Cash and Cash Equivalents	$	(214	)	$	332

Operating Activities – Net cash provided by operating activities for the first nine months of 2009 decreased as compared with the first nine months of 2008 due primarily to decreases in commodity prices.

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. Net cash used in investing activities decreased by $709 million during the first nine months of 2009 as compared with the first nine months of 2008. Activity for the first nine months of 2008 included capital spending of $1.9 billion, which was partially offset by net proceeds of $131 million from asset sales. See 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 2009, we received $989 million net proceeds from the issuance of our 8¼% senior notes, and $18 million of funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options. We used $1.1 billion cash for net repayments of amounts outstanding under our revolving credit facility, $25 million for the repayment of an installment note, and $4 million for the repurchase of our 7¼% Senior Debentures due August 1, 2097. We also paid $94 million in cash dividends on our common stock and used $1 million to repurchase shares of our common stock.

In comparison, during the first nine months of 2008, $223 million of funds were provided by a net increase in debt, $49 million of funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options. We paid $84 million in cash dividends on our common stock and used $2 million to repurchase shares of our common stock.

Investing Activities

Acquisition, Capital and Exploration Expenditures– Information for investing activities, which consist of capital spending (including seismic expense) on an accrual basis, is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(in millions)
Acquisition, Capital and Exploration Expenditures
Unproved Property Acquisition	$	2	$	36	$	64	$	299
Proved Property Acquisition		-		255		-		255
Exploration		22		142		167		385
Development		186		334		615		840
Corporate and Other		14		19		87		53
Total	$	224	$	786	$	933	$	1,832

Unproved property acquisition costs for the first nine months of 2009 included lease bonuses on deepwater lease blocks acquired as a result of the March 2009 central Gulf of Mexico lease sale. Unproved property acquisition costs for the first nine months of 2008 included lease bonuses on deepwater lease blocks acquired as a result of the March 2008 central Gulf of Mexico lease sale and the acquisition of properties in western Oklahoma in July 2008.

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Proved property acquisition costs for the first nine months of 2008 included the acquisition of producing properties in western Oklahoma in July 2008.

Property Sales–In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million. The gain on sale was deferred until second quarter 2009 when the Argentine government approved the sale.

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 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.

In order to provide increased liquidity and lengthen our weighted average debt maturity, on February 27, 2009 we completed an underwritten public offering of $1 billion of 8¼% senior unsecured notes due March 1, 2019, receiving net proceeds of $989 million.  We used substantially all of the net proceeds from the offering to repay outstanding indebtedness under the revolving credit facility.

As a result, at September 30, 2009, borrowings outstanding under the credit facility totaled $535 million, leaving approximately $1.6 billion available for use. The weighted average interest rate applicable to borrowings under the credit facility at September 30, 2009 was 0.56%.

On July 22, 2009, we repurchased $5 million of our 7¼% Senior Debentures due August 1, 2097, recognizing a debt extinguishment gain of $1 million, which is included in other non-operating (income) expense, net.

Our outstanding fixed-rate debt, including the new 8¼% senior unsecured notes and net of the repurchase discussed above, totaled $1.6 billion at September 30, 2009. 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 26% at both September 30, 2009 and December 31, 2008. 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.

Short-Term Borrowings – In May 2009, we made the final $25 million installment payment to the seller of properties we purchased in 2007. Interest on the unpaid amount was due quarterly and accrued at a LIBOR rate plus .30%. The interest rate was 1.51% at the date of payment.

Our committed credit facility has been 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, 2009 or December 31, 2008. 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 54.0 cents per share of common stock during the first nine months of 2009 and 48.0 cents per share of common stock during the first nine months of 2008. On October 27, 2009, our Board of Directors declared a quarterly cash dividend of 18.0 cents per common share, payable November 23, 2009 to shareholders of record on November 9, 2009. 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 $15 million from the exercise of stock options during the first nine months of 2009 as compared with $26 million during the first nine months of 2008.

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 20,464 shares with a value of $1 million during the first nine months of 2009 and 32,518 shares with a value of $2 million during the first nine months of 2008. 

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes–We areexposed 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, 2009, 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 payable position with a fair value of $18 million. Based on the September 30, 2009 published commodity futures price strips for the underlying commodities, a price increase of $1.00 per Bbl for crude oil would increase the fair value of our net commodity derivative payable by approximately $9 million. A price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative payable by approximately $8 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 4 – 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 other variable-rate debt and the amount of interest we earn on our short-term investments.

At September 30, 2009, we had $2.2 billion (excluding 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, $535 million at September 30, 2009, 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, 2009 balance of our variable-rate debt would result in a change in annual interest expense of approximately $1 million.

We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. 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. At September 30, 2009, AOCL included $2 million, net of tax, related to interest rate locks. This amount is currently being reclassified into earnings as adjustments to interest expense over the term of our 5¼% Senior Notes due April 2014. We currently have no treasury locks outstanding.

We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of September 30, 2009, our cash and cash equivalents totaled $926 million. Approximately 51% of this amount was invested in US Treasury securities, 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, 2009 would result in a change in annual interest income of approximately $1 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.

In the UK sector of our North Sea operations, significant future capital commitments and certain operating expenses are expected to be denominated in British pounds. Therefore, our cash flows could be impacted by future changes in the exchange rate between the US dollar and the British pound. 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:

· the extent and effect of any hedging activities engaged in by us;

· 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;

· effect of current volatility in the credit markets;

· 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, 2009 and June 30, 2009, and our Annual Report on Form 10-K for the year ended December 31, 2008, 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, 2009 and June 30, 2009, and our Annual Report on Form 10-K for the year ended December 31, 2008 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 acting 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 14 – 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, 2009 and June 30, 2009, or our Annual Report on Form 10-K for the year ended December 31, 2008, other than the following:

The adoption of pending climate change legislation could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill. The U.S. Senate’s version, The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been introduced, but has not been passed. Although these bills include several differences that require reconciliation before becoming law, both bills contain the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions in the US. Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this legislative initiative remains uncertain. However, since approximately 60% of our overall crude oil and 51% of our natural gas production derives from the US, any laws or regulations that may be adopted to restrict or reduce emissions of US greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

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Federal hydraulic fracturing legislation could increase our costs and restrict our access to oil and gas reserves.

Several proposals are before the U.S. Congress that, if implemented, would either prohibit the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs, including those in the Northern region of our US operations.

Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay our ability to develop oil and gas reserves.

Derivatives regulation could restrict our ability to execute commodity derivative instruments as a hedge against fluctuating commodity prices.

Various measures are being proposed by committees of Congress, the U.S. Treasury Department, and other agencies to restrict the use of over-the-counter (OTC) derivative instruments.  These proposals include, but are not limited to, requiring cash collateral on all OTC derivatives and requiring all OTC derivatives to be executed and settled through an exchange system.

Although we do not currently know the exact form any final legislation or rule-making activity will take, any restriction on the use of OTC instruments could have a significant impact on our business. Limits on the use of OTC instruments could significantly reduce our ability to execute strategic price hedges against commodity price volatility.  In addition, cash collateral requirements could create significant liquidity issues and exchange system trades may restrict our ability to execute derivative instruments to fit our strategic needs.

Our operations and investment in Ecuador may be adversely affected by the country's unsettled economic and political environment.

The economic and political environment in Ecuador has become increasingly unsettled. We are aware of recent media reports of expropriation or nationalization attempts by the government of Ecuador involving other US or foreign companies with investments in the country. We continue to not be fully paid for electricity sales from our Machala power plant, and we recently entered into independent power purchase agreements for such sales, the effect of which on payment is unknown. In addition, on August 24, 2009, we became aware that our proposed plan of development for the Amistad field (offshore Ecuador), which had been submitted to the government of Ecuador, had been rejected. We are uncertain as to the potential outcome of these issues, resolution of which could ultimately lead to a diminution in the value of our investments in Ecuador which, as of September 30, 2009, had a net book value of approximately $170 million.

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)
07/01/09 - 07/31/09		-	$	-		-		-
08/01/09 - 08/31/09		2,954		60.28		-		-
09/01/09 - 09/30/09		-		-		-		-
Total		2,954	$	60.28		-		-

(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.

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

None.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

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

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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 29, 2009	/s/ Frederick B. Bruning
		Frederick B. Bruning Vice President and Chief Accounting Officer

47

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 December 9, 2008 (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: December 9, 2008) filed December 15, 2008 and incorporated herein by reference).

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

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

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

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

101 The following materials from the Noble Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Operations, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Shareholders’ Equity, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.

48

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 7241)

I, Charles D. Davidson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Noble Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 29, 2009
/s/ CHARLES D. DAVIDSON
CHARLES D. DAVIDSON
Chief Executive Officer

1

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 7241)

I, Frederick B. Bruning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Noble Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting, which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	October 29, 2009
/s/ FREDERICK B. BRUNING
FREDERICK B. BRUNING
Vice President and Chief Accounting Officer

(Acting Principal Financial Officer for purposes of this Certification)

1

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2009 (the “Report”), I, Charles D. Davidson, Chief Executive Officer of the Company, hereby certify that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date	October 29, 2009	/s/ CHARLES D. DAVIDSON
		CHARLES D. DAVIDSON
		Chief Executive Officer

1

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

In connection with the accompanying Quarterly Report of Noble Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2009 (the “Report”), I, Frederick B. Bruning, Vice President and Chief Accounting Officer of the Company, hereby certify that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	October 29, 2009	/s/ FREDERICK B. BRUNING
		FREDERICK B. BRUNING
		Vice President and Chief Accounting Officer
		(Acting Principal Financial Officer for purposes of this Certification)

1