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, 2008

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

(281) 872-3100

(Registrant’s telephone number, including area code)

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

Yes [X]    No [  ]

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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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]

Number of shares of common stock outstanding as of October 15, 2008: 172,745,476.

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
(in millions, except per share amounts)
(unaudited)
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008			2007
Revenues
Oil, gas and NGL sales	$	1,040		$	746	$	3,115		$	2,140
Income from equity method investees		40			46		158			140
Other revenues		18			22		55			70
Total		1,098			814		3,328			2,350
Costs and Expenses
Lease operating expense		98			82		268			243
Production and ad valorem taxes		47			27		141			81
Transportation expense		14			13		43			40
Exploration expense		39			46		181			145
Depreciation, depletion and amortization		194			197		593			547
General and administrative		63			49		184			142
Other operating expense, net		97			24		136			106
Total		552			438		1,546			1,304
Operating Income		546			376		1,782			1,046
Other (Income) Expense
(Gain) loss on commodity derivative instruments		(875	)		2		190			(1	)
Interest, net of amount capitalized		18			29		52			87
Other (income) expense, net		(51	)		2		(33	)		20
Total		(908	)		33		209			106
Income Before Income Taxes		1,454			343		1,573			940
Income Tax Provision		480			120		528			296
Net Income	$	974		$	223	$	1,045		$	644
Earnings Per Share
Basic	$	5.64		$	1.30	$	6.06		$	3.76
Diluted	$	5.37		$	1.28	$	5.86		$	3.72
Weighted average number of shares outstanding
Basic		173			171		172			171
Diluted		176			173		176			173
The accompanying notes are an integral part of these financial statements.

2

Noble Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(in millions, except share amounts)
	(Unaudited)
	September 30,			December 31,
	2008			2007
ASSETS
Current Assets
Cash and cash equivalents	$	992		$	660
Accounts receivable - trade, net		641			594
Other current assets		236			315
Total current assets		1,869			1,569
Property, plant and equipment
Oil and gas properties (successful efforts method of accounting)		11,769			10,217
Other property, plant and equipment		158			112
Total property, plant and equipment		11,927			10,329
Accumulated depreciation, depletion and amortization		(2,946	)		(2,384	)
Total property, plant and equipment, net		8,981			7,945
Goodwill		759			761
Other noncurrent assets		507			556
Total Assets	$	12,116		$	10,831
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable - trade	$	646		$	781
Commodity derivative instruments		189			540
Other current liabilities		541			315
Total current liabilities		1,376			1,636
Deferred income taxes		2,169			1,984
Asset retirement obligations		147			131
Commodity derivative instruments		69			83
Other noncurrent liabilities		299			337
Long-term debt		2,051			1,851
Total Liabilities		6,111			6,022
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; 192 million and 191 million shares issued, respectively		641			636
Capital in excess of par value		2,182			2,106
Accumulated other comprehensive loss		(129	)		(284	)
Treasury stock, at cost; 19 million shares		(614	)		(613	)
Retained earnings		3,925			2,964
Total Shareholders’ Equity		6,005			4,809
Total Liabilities and Shareholders’ Equity	$	12,116		$	10,831
The accompanying notes are an integral part of these financial statements.

3

Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(in millions)
(unaudited)
	Nine Months Ended
	September 30,
	2008			2007
Cash Flows From Operating Activities
Net income	$	1,045		$	644
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		593			547
Dry hole expense		78			48
Deferred income taxes		173			192
Income from equity method investees		(158	)		(140	)
Dividends received from equity method investees		192			153
Unrealized (gain) on commodity derivative instruments		(9	)		(1	)
Settlement of previously recognized hedge losses		(144	)		(133	)
Loss on involuntary conversion		9			51
Impairment of operating assets		38			4
Allowance for doubtful accounts		47			11
Other		12			69
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, trade		(94	)		21
(Increase) decrease in other current assets		(19	)		92
(Decrease) in accounts payable		(135	)		(12	)
Increase (decrease) in other current liabilities		239			(225	)
Net Cash Provided by Operating Activities		1,867			1,321
Cash Flows From Investing Activities
Additions to property, plant and equipment		(1,852	)		(1,017	)
Proceeds from property sales		131			-
Distributions from equity method investees		-			2
Net Cash Used in Investing Activities		(1,721	)		(1,015	)
Cash Flows From Financing Activities
Exercise of stock options		26			19
Excess tax benefits from stock-based awards		23			14
Cash dividends paid		(84	)		(54	)
Purchases of treasury stock		(2	)		(102	)
Proceeds from credit facility		650			280
Repayment of credit facility		(425	)		(165	)
Repayment of installment notes		(25	)		-
Proceeds from short term borrowings		23			-
Net Cash Provided by (Used in) Financing Activities		186			(8	)
Increase in Cash and Cash Equivalents		332			298
Cash and Cash Equivalents at Beginning of Period		660			153
Cash and Cash Equivalents at End of Period	$	992		$	451
The accompanying notes are an integral part of these financial statements.

4

Noble Energy, Inc. and Subsidiaries
Consolidated Statements of Shareholders' Equity
(in millions)
(unaudited)
										Accumulated
	Shares of Stock						Capital in			Other			Treasury						Total
	Common		Treasury		Common		Excess of			Comprehensive			Stock			Retained			Shareholders'
	Stock		Stock		Stock		Par Value			Loss			at Cost			Earnings			Equity
December 31, 2007		191		19	$	636	$	2,106		$	(284	)	$	(613	)	$	2,964		$	4,809
Net income		-		-		-		-			-			-			1,045			1,045
Stock-based compensation expense		-		-		-		30			-			-			-			30
Exercise of stock options		1		-		4		22			-			-			-			26
Tax benefits related to exercise of stock options		-		-		-		23			-			-			-			23
Restricted stock awards, net		-		-		1		(1	)		-			-			-			-
Dividends ($0.48 per share)		-		-		-		-			-			-			(84	)		(84	)
Changes in treasury stock, net		-		-		-		2			-			(1	)		-			1
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		-		-		-		-			155			-			-			155
Interest rate cash flow hedges:
Unrealized change in fair value		-		-		-		-			1			-			-			1
Net change in other		-		-		-		-			(1	)		-			-			(1	)
September 30, 2008		192		19	$	641	$	2,182		$	(129	)	$	(614	)	$	3,925		$	6,005
December 31, 2006		188		17	$	629	$	2,041		$	(140	)	$	(511	)	$	2,095		$	4,114
Net income		-		-		-		-			-			-			644			644
Stock-based compensation expense		-		-		-		20			-			-			-			20
Exercise of stock options		1		-		4		15			-			-			-			19
Tax benefits related to exercise of stock options		-		-		-		14			-			-			-			14
Restricted stock awards, net		1		-		2		(2	)		-			-			-			-
Dividends ($0.315 per share)		-		-		-		-			-			-			(54	)		(54	)
Purchases of treasury stock		-		2		-		-			-			(102	)		-			(102	)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		-		-		-		-			5			-			-			5
Unrealized change in fair value		-		-		-		-			(44	)		-			-			(44	)
Net change in other		-		-		-		-			2			-			-			2
September 30, 2007		190		19	$	635	$	2,088		$	(177	)	$	(613	)	$	2,685		$	4,618
The accompanying notes are an integral part of these financial statements.

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 (unaudited)

Note 1 – Organization and Nature of Operations

Noble Energy, Inc. (Noble Energy, we or us) is an independent energy company engaged in the acquisition, exploration, development, production and marketing of crude oil, natural gas and natural gas liquids (NGLs). We have exploration, exploitation and production operations in the US and internationally. We operate throughout major basins in the US including Colorado’s Wattenberg field and Piceance basin, the Mid-continent region of western Oklahoma and the Texas Panhandle, the San Juan Basin in New Mexico, the Gulf Coast and the Gulf of Mexico. In addition, we conduct business internationally in China, Ecuador, the Mediterranean Sea, the North Sea, West Africa (Equatorial Guinea and Cameroon) and in other areas.

Note 2 – Basis of Presentation

Presentation – 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, 2008 (unaudited) and December 31, 2007 and for the three months and nine months ended September 30, 2008 and 2007 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 nine-month period ended September 30, 2008 are not necessarily indicative of the results that may be expected for the year ended December 31, 2008. 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, 2007, as amended.

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

Mid-continent Acquisition – In July 2008, we acquired producing properties in western Oklahoma for $292 million in cash. Properties acquired cover approximately 15,500 net acres and are currently producing 25 MMcfepd. The total purchase price has been preliminarily allocated to the proved and unproved properties acquired based on fair values at the acquisition date. Approximately $254 million was allocated to proved properties and $38 million to unproved properties.

Sale of Main Pass Assets – We expect to sell essentially all of our remaining non-core Gulf of Mexico shelf assets in the near future. These assets, located at Main Pass, suffered significant hurricane damage in 2004 and 2005 and have undergone cleanup activities that were completed in the third quarter of 2007. During third quarter 2008, in anticipation of the sale, we recorded an impairment loss of $38 million (based on anticipated sales proceeds less costs to sell) related to the Main Pass assets and reclassified their remaining net book value of $11 million to assets held for sale. We also recorded a loss on involuntary conversion of $9 million upon resolution of our insurance claims related to the hurricane damage sustained in 2005.

6

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(in millions)
Other Revenues
Electricity sales	$	14		$	17		$	42		$	54
Gathering, marketing and processing revenues		4			5			13			16
Total	$	18		$	22		$	55		$	70
Other Operating Expense, net
Electricity generation (1)	$	13		$	14		$	41		$	42
Gathering, marketing and processing		5			4			14			13
Loss on involuntary conversion		9			-			9			51
Impairment of operating assets (2)		38			4			38			4
Other operating (income) expense, net (3)		32			2			34			(4	)
Total	$	97		$	24		$	136		$	106
Other Expense, net
Deferred compensation (4)	$	(47	)	$	8		$	(25	)	$	23
Interest income		(6	)		(2	)		(18	)		(8	)
Other (income) expense, net		2			(4	)		10			5
Total	$	(51	)	$	2		$	(33	)	$	20

(1) Includes increases in the allowance for doubtful accounts of $3 million each in third quarter 2008 and 2007 and $9 million and $11 million for the first nine months of 2008 and 2007, respectively.

(2) Includes third quarter 2008 impairment loss on Gulf of Mexico Main Pass assets.

(3)  Includes $38 million write-down of SemCrude L.P. receivable in third quarter 2008. See Note 13 – Commitments and Contingencies.

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

7

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

	September 30,		December 31,
	2008		2007
	(in millions)
Other Current Assets
Inventories	$	91	$	60
Commodity derivative instruments		40		15
Prepaid expenses and other current assets		28		25
Deferred income taxes		49		131
Assets held for sale		11		82
Probable insurance claims		17		2
Total	$	236	$	315
Other Noncurrent Assets
Equity method investments	$	324	$	357
Mutual fund investments		101		124
Probable insurance claims		8		37
Commodity derivative instruments		18		5
Other noncurrent assets		56		33
Total	$	507	$	556
Other Current Liabilities
Accrued and other current liabilities	$	258	$	207
Current income taxes payable		181		52
Short-term borrowings		48		25
Asset retirement obligations		13		13
Interest payable		17		18
Deferred gain on sale of assets		24		-
Total	$	541	$	315
Other Noncurrent Liabilities
Deferred compensation liability	$	185	$	225
Accrued benefit costs		53		51
Other noncurrent liabilities		61		61
Total	$	299	$	337

Adoption of SFAS 157 – We adopted Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157), as of January 1, 2008 as related to our financial assets and liabilities. SFAS 157 establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. As a result of adoption, we began incorporating a credit risk assumption into the measurement of certain assets and liabilities. Adoption of SFAS 157 did not have a significant impact on our consolidated financial statements. See Note 3 – Fair Value Measurements. On January 1, 2009, we will adopt SFAS 157 as it relates to nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and initial recognition of asset retirement obligations. We do not expect any significant impact to our consolidated financial statements when we implement SFAS 157 for our existing nonfinancial assets and liabilities.

Adoption of FSP FIN 39-1 – We adopted FASB Staff Position FIN 39-1, “An Amendment of FASB Interpretation No. 39” (FSP FIN 39-1), as of January 1, 2008. FSP FIN 39-1 addresses certain modifications to FIN 39, “Offsetting of Amounts Related to Certain Contracts.” FIN 39-1 allows companies to offset fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master netting arrangement. Upon adoption, we elected to offset the right to reclaim cash collateral or the obligation to return cash collateral against our net derivative positions for which master netting agreements exist. As of September 30, 2008 and December 31, 2007, we had no significant cash collateral obligations.

8

Note 3 – Fair Value Measurements

Measurement information for financial assets and liabilities reported at fair value at September 30, 2008, includes the following:

	Fair Value Measurements Using
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustment (1)		Fair Value Measurement
		(in millions)
Financial assets:
Mutual fund investments	$	101	$	-	$	-	$	-	$	101
Commodity derivative instruments		-		149		-		(91)		58
Financial liabilities:
Commodity derivative instruments		-		(349)		-		91		(258)

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

SFAS 157, which we adopted as of January 1, 2008, 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. We use the following methods and assumptions to estimate the fair values of the assets and liabilities in the table above:

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.

Commodity Derivative Instruments – Our commodity derivative instruments consist of variable to fixed price commodity swaps, costless collars and basis swaps. We estimate the fair values of these instruments based on published forward commodity price curves for the underlying commodities as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values also include a measure of counterparty credit risk or our own nonperformance risk based on the current published credit default swap rates. In addition, for costless 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 parameters. See Note 4 – Derivative Instruments and Hedging Activities.

Note 4 – Derivative Instruments and Hedging Activities

Commodity Derivative Instruments – We use various derivative instruments in connection with forecasted crude oil and natural gas sales to minimize the impact of commodity price fluctuations on cash flows. Such instruments include variable to fixed price commodity swaps, costless collars and basis swaps. Although these derivative instruments expose us to credit risk, we monitor the creditworthiness of our counterparties, and we are not currently aware of any inability on the part of our counterparties to perform under the contracts. However, we are not able to predict sudden changes in the creditworthiness of our counterparties.

9

We account for derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), and all derivative instruments are reflected at fair value on our consolidated balance sheets. We elected to designate certain of our commodity derivative instruments as cash flow hedges through December 31, 2007. However, effective January 1, 2008, we voluntarily discontinued cash flow hedge accounting on all existing commodity derivative instruments. We made this change to provide greater flexibility in our use of derivative instruments. From January 1, 2008 forward, we recognize all gains and losses on such instruments in earnings during the period in which they occur. Net derivative losses that were deferred in accumulated other comprehensive income (loss) (AOCL) as of December 31, 2007, as a result of previous cash flow hedge accounting, will be reclassified to earnings in future periods as the original hedged transactions occur. Our discontinuation of cash flow hedge accounting for commodity derivative instruments did not affect our net assets or cash flows at December 31, 2007 and does not require adjustments to our previously reported financial statements.

The components of (gain) loss on commodity derivative instruments included in the consolidated statements of operations are as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008			2007
	(in millions)
Unrealized (gain) on commodity derivative instruments	$	(943	)	$	-	$	(9	)	$	-
Realized loss on commodity derivative instruments		68			-		199			-
Ineffectiveness loss (gain)		-			2		-			(1	)
(Gain) loss on commodity derivative instruments	$	(875	)	$	2	$	190		$	(1	)

Crude oil and natural gas sales include amounts reclassified from AOCL as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(in millions)
(Decrease) in crude oil sales	$	(89	)	$	(60	)	$	(279	)	$	(128	)
(Decrease) increase in natural gas sales		(4	)		48			31			120
Total (decrease) in oil and gas sales	$	(93	)	$	(12	)	$	(248	)	$	(8	)

10

Approximately $80 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, 2008 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 the $80 million deferred losses (net of tax) approximately $52 million is expected to be reclassified to earnings during the fourth quarter of 2008.

As of October 23, 2008, we had entered into the following crude oil derivative instruments:

	Variable to Fixed Price Swaps					Costless 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 2008	NYMEX WTI		16,500	$	37.92	NYMEX WTI		3,100	$	60.00	$	72.40
4th Qtr 2008	Dated Brent		2,000		88.18	Dated Brent		3,587		45.00		65.90
4th Qtr 2008 Average			18,500		43.35			6,687		51.95		68.91
2009	NYMEX WTI		9,000		88.43	NYMEX WTI		6,700		79.70		90.60
2009	Dated Brent		2,000		87.98	Dated Brent		5,074		70.62		87.93
2009 Average			11,000		88.35			11,774		75.79		89.45
2010	-		-		-	NYMEX WTI		5,500		69.00		85.65

As of October 23, 2008, we had entered into the following natural gas derivative instruments:

	Variable to Fixed Price Swaps						Costless 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 2008	NYMEX HH			170,000	$	5.63	IFERC CIG		14,000	$	6.75	$	8.70
2009		-		-		-	NYMEX HH		170,000		9.15		10.81
2009		-		-		-	IFERC CIG		15,000		6.00		9.90
2009 Average				-		-			185,000		8.90		10.73
2010		-		-		-	IFERC CIG		15,000		6.25		8.10

11

As of October 23, 2008, 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 2008	IFERC CIG	NYMEX HH		100,000	$	1.66
4th Qtr 2008	IFERC ANR-OK	NYMEX HH		40,000		1.01
4th Qtr 2008	IFERC PEPL	NYMEX HH		10,000		0.98
4th Qtr 2008 Average				150,000		1.44
2009	IFERC CIG	NYMEX HH		140,000		2.49

Interest Rate Lock Derivative Instruments – We entered into two interest rate swaps, or interest rate “locks”, each in the notional amount of $500 million. The locks were based on five and ten year US Treasury rates of 3.55% and 4.15%, respectively, and were scheduled to expire in September 2008. We settled the locks in July 2008 at a total cost of $0.2 million.

Note 5 – Capitalized Exploratory Well Costs

Changes in capitalized exploratory well costs during the period were as follows:

	Nine Months Ended
	September 30, 2008 (1)
	(in millions)
Capitalized exploratory well costs at beginning of period	$	249
Additions to capitalized exploratory well costs pending determination of proved reserves		267
Reclassified to proved oil and gas properties based on determination of proved reserves		-
Capitalized exploratory well costs charged to expense		(1	)
Capitalized exploratory well costs at end of period	$	515

(1)  Changes in capitalized exploratory well costs exclude amounts that were capitalized and subsequently expensed in the same period.

12

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,
	2008		2007
	(in millions, except number of projects)
Exploratory well costs capitalized for a period of one year or less	$	364	$	187
Exploratory well costs capitalized for a period greater than one year after completion of drilling		151		62
Balance at end of period	$	515	$	249
Number of projects with exploratory well costs that have been capitalized for a period greater than one year after completion of drilling		5		5

The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of September 30, 2008:

			Suspended Since
	Total		2007		2006		2005
			(in millions)
Project
Raton South (deepwater Gulf of Mexico)	$	28	$	5	$	23	$	-
Redrock (deepwater Gulf of Mexico)		17		-		17		-
Blocks O and I (West Africa)		88		68		1		19
Flyndre (North Sea)		15		12		3		-
Other		3		-		3		-
Total capitalized exploratory well costs that have been
capitalized for a period greater than one year since completion of drilling	$	151	$	85	$	47	$	19

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Exploratory well costs capitalized for more than one year at September 30, 2008 include five projects, two of which include activity in the deepwater Gulf of Mexico.  One project relates to Raton South (Mississippi Canyon Block 292) and includes $28 million of suspended exploratory well costs. A successful sidetrack well was recently completed on this prospect and tie back to a host facility is anticipated in late 2009. The other project relates to Redrock (Mississippi Canyon Block 204) and includes $17 million of suspended exploratory well costs. Redrock is currently considered a co-development candidate to the completed sidetrack well at Raton South.

We also incurred exploratory well costs of $88 million for the Blocks O and I project in West Africa. Since drilling the initial well for the 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. In addition to the amount of exploratory well costs that have been capitalized for a period greater than one year for the Blocks O and I project, we have incurred $175 million in suspended costs related to additional drilling activity in West Africa through September 30, 2008.

Another project, Flyndre, is located in the UK sector of the North Sea and incurred exploratory well costs of $15 million.  We successfully completed an exploratory appraisal well in 2007 and are working with the operator to formulate a development plan.

The remaining project, which totals $3 million in suspended exploratory well costs, continues to be evaluated by various means including additional seismic work, drilling additional wells and evaluating the potential of the exploration well.

Note 6 – 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, 2008
	(in millions)
Asset retirement obligations at January 1, 2008	$	144
Liabilities incurred in current period		15
Liabilities settled in current period		(16	)
Revisions		10
Accretion expense		7
Asset retirement obligations at September 30, 2008	$	160

Accretion expense is included in depreciation, depletion and amortizationexpense in the consolidated statements ofoperations.

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Note 7 – 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 tax-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 pension and restoration plans is as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(in millions)
Service cost	$	3		$	3		$	9		$	9
Interest cost		3			3			9			7
Expected return on plan assets		(3	)		(3	)		(9	)		(8	)
Other		1			-			2			2
Net periodic benefit cost	$	4		$	3		$	11		$	10

Cash contributions to the pension plan totaled $32 million and $10 million during the first nine months of 2008 and 2007, respectively.

Note 8 – Stock-Based Compensation

We recognized stock-based compensation expense as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(in millions)
Stock-based compensation expense	$	10		$	8		$	30		$	20
Tax benefit recognized	$	(4	)	$	(3	)	$	(11	)	$	(8	)

During the nine months ended September 30, 2008, we granted 1.1 million stock options with a weighted-average grant-date fair value of $20.42 per share and awarded 0.5 million shares of restricted stock subject to time vesting with a weighted-average grant-date fair value of $74.04 per share.

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Note 9 – Basic and Diluted Earnings Per Share

Basic earnings 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 per share:

				Weighted				Weighted
	Net			Average		Net		Average
	Income			Shares		Income		Shares
	2008					2007
	(in millions, except per share amounts)
Three Months Ended September 30:
Net income	$	974			173	$	223		171
Basic Earnings Per Share	$	5.64				$	1.30
Net income	$	974			173	$	223		171
Effect of dilutive stock options and restricted stock		-			2		-		2
Effect of shares of Noble Energy stock in rabbi trust (1)		(29	)		1		-		-
Net income available to common shareholders	$	945			176	$	223		173
Diluted Earnings Per Share	$	5.37				$	1.28
Nine Months Ended September 30:
Net income	$	1,045			172	$	644		171
Basic Earnings Per Share	$	6.06				$	3.76
Net income	$	1,045			172	$	644		171
Effect of dilutive stock options and restricted stock		-			3		-		2
Effect of shares of Noble Energy stock in rabbi trust (1)		(16	)		1		-		-
Net income available to common shareholders	$	1,029			176	$	644		173
Diluted Earnings Per Share	$	5.86				$	3.72

(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.

Approximately 1 million weighted average stock options and shares of restricted stock were antidilutive for each of the third quarter and the first nine months of 2008 and were excluded from the calculation of diluted earnings per share. Approximately 2 million weighted average shares of Noble Energy common stock held in a rabbi trust, stock options and shares of restricted stock were antidilutive for each of the third quarter and the first nine months of 2007 and were excluded from the calculation of diluted earnings per share.

Note 10 – Income Taxes

The income tax provision consists of the following:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in millions)
Current	$	316	$	32	$	355	$	104
Deferred		164		88		173		192
Total income tax provision	$	480	$	120	$	528	$	296

The deferred tax assets associated with the foreign loss carryforwards of certain controlled foreign corporations, primarily Suriname, have increased during 2008.  In addition, because management currently does not believe it is more likely than not that the deferred tax assets related to these foreign loss carryforwards will be realized, the valuation allowance has been increased. The Suriname valuation allowance is expected to increase by $36 million during 2008 to a balance of $51 million at year end.

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In 2007, China’s legislature, the National People’s Congress, enacted the China Corporate Income Tax Law.  This new legislation decreased our tax rate in China from 33% to 25% starting in 2008.

Unrecognized Tax Positions –We do not have significant unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of September 30, 2008. 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, 2008, 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 – 2005, Equatorial Guinea – 2006, China – 2006, Israel – 2000, UK – 2006 and the Netherlands – 2005.

Note 11 – Comprehensive Income

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(in millions)
Net income	$	974		$	223		$	1,045		$	644
Other items of comprehensive income (loss)
Oil and gas cash flow hedges:
Realized amounts reclassified into earnings		93			12			248			8
Less tax provision		(35	)		(5	)		(93	)		(3	)
Unrealized change in fair value		-			12			-			(71	)
Less tax provision		-			(4	)		-			27
Interest rate cash flow hedges:
Unrealized change in fair value		12			-			1			-
Less tax provision		(5	)		-			-			-
Net change in other		-			-			(1	)		2
Other comprehensive income (loss)		65			15			155			(37	)
Comprehensive income	$	1,039		$	238		$	1,200		$	607

Note 12 – 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 natural gas and crude oil acquisition, exploration, development, production and marketing:  the US, West Africa, the North Sea, Israel, and Other International, Corporate and Marketing. Other International includes  primarily Argentina (through February 2008), China, Ecuador and Suriname.

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The following data was prepared on the same basis as our consolidated financial statements and excludes the effects of income taxes.

														Other Int'l
				United			West			North				Corporate &
	Consolidated			States			Africa			Sea		Israel		Marketing
	(in millions)
Three Months Ended September 30, 2008
Revenues from third parties	$	1,151		$	646		$	156		$	136	$	51	$	162
Amount reclassified from AOCL (1)		(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
Loss on involuntary conversion		9			9			-			-		-		-
Impairment of operating assets		38			38			-			-		-		-
(Gain) on commodity derivative instruments		(875	)		(749	)		(126	)		-		-		-
Income (loss) before taxes		1,454			1,058			303			107		40		(54	)
Three Months Ended September 30, 2007
Revenues from third parties	$	780		$	406		$	101		$	122	$	35	$	116
Amount reclassified from AOCL (1)		(12	)		(9	)		(3	)		-		-		-
Intersegment revenue		-			60			-			-		-		(60	)
Income from equity method investees		46			-			46			-		-		-
Total Revenues		814			457			144			122		35		56
DD&A		197			145			9			30		5		8
Impairment of operating assets		4			4			-			-		-		-
Loss on commodity derivative instruments		2			2			-			-		-		-
Income (loss) before taxes		343			181			112			78		28		(56	)
Nine Months Ended September 30, 2008
Revenues from third parties	$	3,418		$	1,975		$	460		$	327	$	121	$	535
Amount reclassified from AOCL (1)		(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
Loss on involuntary conversion		9			9			-			-		-		-
Impairment of operating assets		38			38			-			-		-		-
Loss on commodity derivative instruments		190			137			53			-		-		-
Income (loss) before taxes		1,573			990			491			234		94		(236	)
Nine Months Ended September 30, 2007
Revenues from third parties	$	2,218		$	1,214		$	286		$	239	$	85	$	394
Amount reclassified from AOCL (1)		(8	)		(5	)		(3	)		-		-		-
Intersegment revenue		-			227			-			-		-		(227	)
Income from equity method investees		140			-			140			-		-		-
Total Revenues		2,350			1,436			423			239		85		167
DD&A		547			433			19			58		13		24
Loss on involuntary conversion		51			51			-			-		-		-
Impairment of operating assets		4			4			-			-		-		-
Gain on commodity derivative instruments		(1	)		(1	)		-			-		-		-
Income (loss) before taxes		940			559			338			137		65		(159	)
Total assets at September 30, 2008 (2)	$	12,116			8,937			1,650			759		285		485
Total assets at December 31, 2007 (2)		10,831			7,918			1,355			562		268		728

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

(2) The US reporting unit includes goodwill of $759 million at September 30, 2008 and $761 million at December 31, 2007.

Note 13 – 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.

As of September 30, 2008, we had a receivable of approximately $71 million from SemCrude. We have determined that it is probable that a portion of the receivable is uncollectible. Therefore, during third quarter 2008, we reduced the carrying value of the SemCrude receivable and recognized a pre-tax charge of $38 million for the probable loss. We are pursuing various legal remedies to protect our interests. We believe that ultimate disposition of this matter will not have a material adverse affect on our financial position, results of operations, or cash flows.

Legal Proceedings – We are among a group of 18 defendants named in a lawsuit filed August 23, 2002 by Dore Energy Corporation under Docket Number 10-16202 in the 38th Judicial District Court, Cameron Parish, Louisiana.  The lawsuit alleges damage to property owned by Dore resulting from oil and gas activities dating to the 1930’s.  Our predecessor, Samedan Oil Corporation, operated on a portion of the property from 1989 to 1999.  Dore has delivered documents alleging approximately $140 million in damages.  The September 29, 2008 trial setting was continued without the setting of a new date.  We intend to vigorously defend against these allegations and believe that our share of damages, if any, will not have a material adverse effect on our financial position, results of operations, or cash flows.

We are involved in various other 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 14 – Recently Issued Pronouncements

SFAS 141(R) and SFAS 160 – In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS 141(R)) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160). These statements 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. Both statements are effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. SFAS 141(R) will be applied to business combinations occurring after the effective date and SFAS 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We are currently evaluating the provisions of SFAS 141(R) and SFAS 160 and assessing the impact, if any, they may have on our financial position and results of operations.

SFAS 161 – In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161). SFAS 161 amends and expands the disclosure requirements of SFAS 133 and requires qualitative disclosures about objectives and strategies for using derivatives, 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. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently evaluating the provisions of SFAS 161. The statement provides only for enhanced disclosures. Therefore, adoption will have no impact on our financial position or results of operations.

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

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

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

Net income for the third quarter of 2008 included a $943 million pre-tax, unrealized, non-cash gain due to the change in the mark-to-market value of our commodity contracts (or “commodity derivative instruments”) related to production in future periods. Unrealized mark-to-market gains or losses recognized in the current period will be realized in the future when they are cash settled in the month that the related production occurs. The amount of realized gain or loss may be more or less than the amount of mark-to-market gain or loss previously recognized.

Financial results for third quarter 2008 also included the following:

· net income of $974 million, as compared with $223 million for 2007;

· diluted income per share of $5.37, as compared with $1.28 for 2007; and

· cash flow from operating activities of $713 million, as compared with $548 million for third quarter 2007.

Operational results for third quarter 2008 included the following:

· significant oil discovery at the Gunflint prospect in the deepwater Gulf of Mexico;

· successful appraisal of the South Raton discovery in the deepwater Gulf of Mexico;

· record quarterly natural gas production in Israel of 155 MMcfpd;

· commencement of production from the phase two development of Dumbarton in the North Sea;

· successful oil test offshore Equatorial Guinea at the Diega discovery; and

· acquisition of producing properties in western Oklahoma.

Impact of Current Credit and Commodity Markets – The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit market crisis includes our revolving credit facility, cash investments and counterparty performance risks.

Our revolving credit facility is committed in the amount of $2.1 billion until December 2011, at which time it reduces to $1.8 billion. As of the end of the quarter, we had $695 million available credit under the facility. If not extended, the credit facility matures in December 2012. Should current credit market volatility be prolonged for several years, future extensions of our credit facility may contain terms that are less favorable than those of our current credit facility.  Bond markets have been negatively impacted, which has resulted in more restrictive access by issuers and with higher costs.  While we currently have no plans to access the bond market, should we decide to do so in the near term the terms, size and cost of a new debt issue would be less favorable.

Current market conditions also elevate the concern over our cash investments, which total nearly $1 billion, and counterparty risks related to our commodity derivative contracts and trade credit.  With regard to our cash investments, we invest in highly liquid investment grade securities, US Treasuries and short term deposits with major financial institutions.  We have all of our commodity derivatives with major financial institutions.  Should one of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices.  We sell our crude oil, natural gas and natural gas liquids to a variety of purchasers.  Some of these parties are not as creditworthy as we are and may experience liquidity problems.  Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit; however, we do not have all of our trade credit enhanced through guarantees or credit support.  Non performance by a trade creditor could result in losses.

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Crude oil and natural gas prices are also volatile and have declined significantly since the end of the quarter. This will reduce our cash flows from operations. To mitigate the impact of lower commodity prices on our cash flows, we have entered into crude oil and natural gas commodity contracts for 2009 and, to a lesser extent, 2010  (see Note 4 – Derivative Instruments and Hedging Activities).  In the event of a global recession commodity prices may stay depressed or reduce further thereby causing a prolonged downturn, which would further reduce our cash flow from operations.  This could cause us to alter our business plans including reducing our exploration and development programs.

Impact of Hurricanes Gustav and Ike – In September, Hurricanes Gustav and Ike moved through the Gulf of Mexico. Inspection of our facilities and equipment indicated there was no major damage from the hurricanes, although damage to third party processing and pipeline facilities has slowed reinstatement of production from our Gulf of Mexico assets. Temporary shut-ins of production reduced volumes on average 7,500 Boepd during third quarter 2008.  We expect our Gulf of Mexico production to come back online depending on the restarting of pipeline and other non-operated facilities.

Mid-continent Acquisition – In July 2008, we acquired producing properties in western Oklahoma for $292 million in cash. Properties acquired cover approximately 15,500 net acres and are currently producing 25 MMcfepd with approximately 70% natural gas and 30% liquids. We operate the assets with an average working interest of 83%.

Main Pass Assets – We expect to sell essentially all of our remaining non-core Gulf of Mexico shelf assets in the near future. These assets, located at Main Pass, suffered significant hurricane damage in 2004 and 2005 and have undergone cleanup activities that were completed in the third quarter of 2007. During third quarter 2008, in anticipation of the sale, we recorded an impairment loss of $38 million (based on anticipated proceeds less costs to sell) related to the Main Pass assets. We also recorded a loss on involuntary conversion of $9 million upon resolution of our insurance claims related to the hurricane damage sustained in 2005.

OUTLOOK

We expect crude oil, condensate, natural gas and NGL production to increase in 2008 compared to 2007. The expected year-over-year increase in production is impacted by several factors including:

· higher sales of natural gas from the Alba field in Equatorial Guinea;

· growth in demand for natural gas in Israel;

· growing production from our Rocky Mountain assets, where we are continuing active drilling programs;

offset by

· natural field decline in the Gulf Coast and Mid-continent areas of our US operations.

Factors impacting our expected production profile for 2008 include:

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

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

· potential pipeline and processing facility capacity constraints in the Rocky Mountain area of our US operations;

· infrastructure development and deliverability of Egyptian gas in Israel, which could lower our sales volumes;

· potential downtime at the methanol, LPG and/or LNG facilities in Equatorial Guinea;

· timing of workovers and turbine repairs and seasonal variations in rainfall in Ecuador that affect our natural gas-to-power project;

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

· timing of significant project completion and initial production.

2008 Capital Expenditures – We have forecasted capital expenditures of approximately $2.4 billion for 2008.  Approximately 33% of the 2008 capital forecast has been allocated to exploration opportunities, including additions for the deepwater lease sale and other leasehold acquisitions.  Approximately 67% of the 2008 capital forecast has been allocated to acquisition, production, development and other projects. US expenditures are forecast at approximately $1.9 billion, international expenditures are forecast at $413 million and corporate expenditures are forecast at $43 million. We expect that our 2008 capital forecast will be funded primarily from cash flows from operations and, if necessary borrowings under our revolving credit facility.

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

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RESULTS OF OPERATIONS

Oil, Gas and NGL Sales

Revenues from sales of commodities were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in millions)
Crude oil and condensate sales	$	629	$	450	$	1,830	$	1,205
Natural gas sales		361		296		1,132		935
NGL sales (1)		50		-		153		-
Total	$	1,040	$	746	$	3,115	$	2,140

(1)  For 2007, US NGL sales volumes were included with natural gas volumes.  Effective in 2008, we began reporting US NGLs, which has lowered the comparative natural gas sales revenues from 2007 to 2008.

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

	Sales Volumes						Average Realized Sales Prices
	Crude Oil &		Natural				Crude Oil &		Natural
	Condensate		Gas (1)		NGLs (1)		Condensate		Gas (1)		NGLs (1)
	(MBopd)		(MMcfpd)		(MBpd)		(Per Bbl)		(Per Mcf)		(Per Bbl)
Three Months Ended September 30, 2008
United States (2)		38		384		10	$	93.47	$	8.48	$	57.06
West Africa (3)		14		194		-		109.90		0.27		-
North Sea		12		6		-		117.44		11.54		-
Israel		-		155		-		-		3.57		-
Ecuador (4)		-		21		-		-		-		-
Other International		3		-		-		106.03		-		-
Total Consolidated Operations		67		760		10		101.82		5.31		57.06
Equity Investees (5)		2		-		5		116.04		-		67.56
Total		69		760		15	$	102.25	$	5.31	$	60.80
Three Months Ended September 30, 2007
United States (2)		40		404		-	$	55.85	$	6.77	$	-
West Africa (3)		14		208		-		73.25		0.27		-
North Sea		17		5		-		77.13		7.26		-
Israel		-		131		-		-		2.95		-
Ecuador (4)		-		25		-		-		-		-
Other International		6		-		-		55.55		-		-
Total Consolidated Operations		77		773		-		63.53		4.30		-
Equity Investees (5)		2		-		5		77.91		-		49.98
Total		79		773		5	$	62.98	$	4.30	$	49.98
Nine Months Ended September 30, 2008
United States (2)		41		393		10	$	87.84	$	9.10	$	57.39
West Africa (3)		15		212		-		103.31		0.27		-
North Sea		10		6		-		114.42		10.62		-
Israel		-		140		-		-		3.15		-
Ecuador (4)		-		22		-		-		-		-
Other International		4		-		-		73.37		-		-
Total Consolidated Operations		70		773		10		78.89		5.50		57.39
Equity Investees (5)		2		-		6		110.43		-		66.08
Total		72		773		16	$	95.47	$	5.50	$	60.80
Nine Months Ended September 30, 2007
United States (2)		43		410		-	$	51.04	$	7.42	$	-
West Africa (3)		15		127		-		66.97		0.29		-
North Sea		12		6		-		70.41		6.05		-
Israel		-		111		-		-		2.81		-
Ecuador (4)		-		25		-		-				-
Other International		7		-		-		50.30		-		-
Total Consolidated Operations		77		679		-		57.03		5.24		-
Equity Investees (5)		2		-		6		69.63		-		44.75
Total		79		679		6	$	56.47	$	5.24	$	44.75

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(1)  In 2007, US NGL sales volumes were included with natural gas volumes.  Effective in 2008, we began reporting US NGLs, which has lowered the comparative natural gas sales volumes from 2007 to 2008.

 (2) Average realized crude oil and condensate prices reflect reductions of $22.95 per Bbl and $15.64 per Bbl for third quarter 2008 and 2007, respectively, and reductions of $21.69 per Bbl and $10.57 per Bbl for the first nine months of 2008 and 2007, respectively, from hedging activities. Average realized natural gas prices reflect a reduction of $0.12 per Mcf and an increase of $1.29 per Mcf for third quarter 2008 and 2007, respectively, and increases of $0.29 per Mcf and $1.07 per Mcf for the first nine months of 2008 and 2007, respectively, from hedging activities.  The price increases and reductions resulted from hedge gains and losses that had been previously deferred in AOCL.

(3)  Average realized crude oil and condensate prices reflect reductions of $7.42 per Bbl and $2.18 per Bbl for third quarter 2008 and 2007, respectively, and reductions of $8.10 per Bbl and $0.68 per Bbl for the first nine months of 2008 and 2007, respectively, from hedging activities.  The price reductions resulted from hedge losses that had been previously deferred in AOCL.  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 facility. 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 facility totaled 160 MMcfpd and 155 MMcfpd during third quarter 2008 and 2007, respectively, and 169 MMcfpd and 72 MMcfpd during the first nine months of 2008 and 2007, respectively. The natural gas sold to the LNG facility and methanol plant has a lower Btu content than the natural gas sold to the LPG plant. As a result of the increase in natural gas volumes sold to the LNG plant in 2008, the average price received on an Mcf basis is lower.

(4)  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.

(5)  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. Crude oil and condensate production volumes were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(MBopd)
United States		38		40		41		43
West Africa		15		15		15		16
North Sea		9		16		10		12
Other International		3		7		4		7
Total Consolidated Operations		65		78		70		78
Equity Investees		2		2		2		2
Total		67		80		72		80

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If the realized gains and losses on commodity derivative instruments had been included in oil and gas revenues, average realized prices would have been as follows:

		Three Months Ended			Nine Months Ended
		September 30, 2008			September 30, 2008
		Crude Oil &		Natural		Crude Oil &		Natural
		Condensate		Gas		Condensate		Gas
		(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Mcf)
United States	$	88.77	$	8.41	$	78.11	$	8.55
West Africa		106.61		0.27		95.83		0.27
Total Consolidated Operations		98.47		5.28		71.59		5.22
Total		99.00		5.28		88.37		5.22

Crude Oil and Condensate Sales – During third quarter 2008, crude oil and condensate sales increased a net $179 million, or 40%, as compared with third quarter 2007. US sales increased by $119 million, or 58%, and international sales increased $60 million, or 24%.

During the first nine months of 2008, crude oil and condensate sales increased a net $625 million, or 52%, as compared with the first nine months of 2007. US sales increased by $392 million, or 65%, from the first nine months of 2007, and international sales increased $233 million, or 39%.

Factors contributing to the changes in crude oil and condensate sales included:

· higher worldwide commodity prices; and

· growth in the Rocky Mountain area of our US operations;

offset by:

· hurricane-related production shut-ins in the Gulf of Mexico from Hurricanes Gustav and Ike;

· declining production in the Gulf Coast onshore and Mid-continent areas of our US operations; and

· natural field decline in the North Sea.

Revenues include amounts reclassified from AOCL related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007.  Amounts included decreases of $89 million and $60 million for third quarter 2008 and 2007, respectively, and decreases of $279 million and $128 million for the first nine months of 2008 and 2007, respectively.

Natural Gas Sales –During third quarter 2008, natural gas sales increased a net $65 million, or 22%, as compared with third quarter 2007. US sales increased $48 million, or 19%, and international sales increased $17 million, or 38%.

During the first nine months of 2008, natural gas sales increased a net $197 million, or 21%, as compared with the first nine months of 2007. US sales increased $149 million, or 18%, and international sales increased $48 million, or 46%.

Factors contributing to the changes in natural gas sales included:

· higher commodity prices;

· successful drilling program in the Piceance basin along with less severe winter weather in the Rocky Mountain area of our US operations;

· increased natural gas sales volumes in Israel; and

· increased sales from the Alba field in Equatorial Guinea to an LNG plant;

offset by:

· hurricane-related production shut-ins in the Gulf of Mexico from Hurricanes Gustav and Ike;

· a reduction for shrink gas associated with the natural gas liquids now being reported separately;

· declining production in the Gulf Coast onshore and Mid-continent areas of our US operations; and

· lower average realized prices in West Africa.

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Revenues include amounts reclassified from AOCL related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007.  Amounts included a decrease of $4 million and an increase of $48 million for third quarter 2008 and 2007, respectively, and increases of $31 million and $120 million for the first nine months of 2008 and 2007, respectively.

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				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Net income	(in millions, except where noted)
AMPCO and affiliates	$	5	$	15	$	51	$	50
Alba Plant	$	35	$	31	$	107	$	90
Distributions/Dividends
AMPCO	$	16	$	17	$	54	$	60
Alba Plant	$	55	$	41	$	138	$	95
Sales volumes
Methanol (Mgal)		23		44		93		117
Condensate (MBopd)		2		2		2		2
LPG (MBpd)		5		5		6		6
Production volumes
Methanol (Mgal)		21		41		83		122
Condensate (MBopd)		2		2		2		2
LPG (MBpd)		6		6		6		6
Average realized prices
Methanol (per gallon)	$	1.16	$	0.80	$	1.33	$	0.96
Condensate (per Bbl)	$	116.04	$	77.91	$	110.43	$	69.63
LPG (per Bbl)	$	67.56	$	49.98	$	66.08	$	44.75

Net income from AMPCO decreased $10 million, or 67%, during third quarter 2008 as compared with third quarter 2007 primarily due to decreases in methanol sales volumes that resulted from down time for compressor and other equipment maintenance. Net income from AMPCO increased $1 million, or 2%, during the first nine months of 2008 as compared with the first nine months of 2007 primarily due to higher average realized methanol prices, offset by decreases in methanol sales volumes that resulted from down time for compressor and other equipment maintenance.

Net income from Alba Plant increased $4 million, or 13%, during third quarter 2008 as compared with third quarter 2007 and increased $17 million, or 19%, during the first nine months of 2008 as compared with the first nine months of 2007 primarily due to higher average realized condensate and LPG prices, offset by the expiration of the Alba Plant tax holiday. See Income Tax Provision (Benefit) below.

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Costs and Expenses

Production Costs – Production costs were as follows:

			United		West		North				Other Int'l /
	Consolidated		States		Africa		Sea		Israel		Corp(1)
	(in millions)
Three Months Ended September 30, 2008
Oil and gas operating costs (2)	$	88	$	55	$	10	$	17	$	3	$	3
Workover and repair expense		10		9		-		1		-		-
Lease operating expense		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
Three Months Ended September 30, 2007
Oil and gas operating costs (2)	$	77	$	50	$	7	$	11	$	3	$	6
Workover and repair expense		5		5		-		-		-		-
Lease operating expense		82		55		7		11		3		6
Production and ad valorem taxes		27		21		-		-		-		6
Transportation expense		13		10		-		3		-		-
Total production costs	$	122	$	86	$	7	$	14	$	3	$	12
Nine Months Ended September 30, 2008
Oil and gas operating costs (2)	$	244	$	160	$	29	$	37	$	7	$	11
Workover and repair expense		24		23		-		1		-		-
Lease operating expense		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
Nine Months Ended September 30, 2007
Oil and gas operating costs (2)	$	229	$	156	$	25	$	24	$	7	$	17
Workover and repair expense		14		14		-		-		-		-
Lease operating expense		243		170		25		24		7		17
Production and ad valorem taxes		81		66		-		-		-		15
Transportation expense		40		32		-		7		-		1
Total production costs	$	364	$	268	$	25	$	31	$	7	$	33

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

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

Total production costs increased $37 million, or 30%, during third quarter 2008 as compared with third quarter 2007 and increased $88 million, or 24%, during the first nine months of 2008 as compared with the first nine months of 2007. US lease operating expense increased from 2007 primarily due to higher costs related to the continuing active drilling program in the Northern region and expenses relating to increased workover activity. The year-to-year increase was partially offset by a decrease in insurance costs for our Gulf of Mexico deepwater operations related to a change in insurance coverage made third quarter 2007. North Sea oil and gas operating costs for the third quarter and first nine months of 2008 increased as compared with 2007 due to expanded operations and higher costs. The increase in production and ad valorem taxes was driven primarily by higher commodity prices and also by an increase in volumes subject to such taxes.

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Selected expenses on a per BOE basis were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Oil and gas operating costs	$	4.71	$	4.08	$	4.27	$	4.40
Workover and repair expense		0.51		0.24		0.42		0.28
Lease operating expense		5.22		4.32		4.69		4.68
Production and ad valorem taxes		2.50		1.41		2.47		1.55
Transportation expense		0.76		0.70		0.75		0.78
Total production costs (1) (2) (3)	$	8.48	$	6.43	$	7.91	$	7.01

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

(2) Sales volumes include natural gas sales to an LNG facility in Equatorial Guinea that began late first quarter 2007. Inclusion of these volumes reduced the unit rate by $1.28 per BOE and $0.92 per BOE for third quarter 2008 and 2007, respectively, and $1.23 per BOE and $0.47 per BOE for the first nine months of 2008 and 2007, respectively.  

(3) Natural gas volumes are converted to oil equivalent volumes on the basis of six thousand cubic feet of gas per barrel of oil.

Oil and Gas Exploration Expense – Oil and gas exploration expense was as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in millions)
Oil and gas exploration expense (1)	$	39	$	46	$	181	$	145

(1) Oil and gas exploration expense includes dry hole expense, unproved lease amortization, seismic expense, staff expense, lease rentals and other miscellaneous exploration expense.

Oil and gas exploration expense decreased $7 million during third quarter 2008 as compared with third quarter 2007 and increased $36 million during the first nine months of 2008 as compared with the first nine months of 2007. The increase for the first nine months of 2008 was primarily the result of increased dry hole expense. A significant portion of 2008 dry hole expense relates to the West Tapir exploration well on Block 30 offshore Suriname and the Stones River exploration well (Mississippi Canyon Block 285) in the deepwater Gulf of Mexico.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in millions, except unit rate)
DD&A expense - property, plant and equipment	$	191	$	195	$	586	$	541
Accretion of discount on asset retirement obligations		3		2		7		6
Total DD&A expense	$	194	$	197	$	593	$	547
Unit rate per BOE (1) (2)	$	10.38	$	10.41	$	10.37	$	10.47

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

(2) Sales volumes include natural gas sales to an LNG facility in Equatorial Guinea that began late first quarter 2007. Inclusion of these volumes reduced the unit rate by $1.25 per BOE and $1.20 per BOE for third quarter 2008 and 2007, respectively, and $1.31 per BOE and $0.57 per BOE for the first nine months of 2008 and 2007, respectively.

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Total DD&A expense for the first nine months of 2008 increased as compared with 2007 primarily due to the increase in sales volumes. The decrease in the unit rate is due to a change in the mix of production.  Increased production of lower-cost natural gas volumes from the Alba field in Equatorial Guinea and Israel were partially offset by production from areas with higher acquisition and/or development costs (the Wattenberg field and deepwater Gulf of Mexico in the US).

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
G&A expense (in millions)	$	63	$	49	$	184	$	142
Unit rate per BOE (1) (2)	$	3.37	$	2.61	$	3.22	$	2.74

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

(2) Sales volumes include natural gas sales to an LNG facility in Equatorial Guinea that began late first quarter 2007. Inclusion of these volumes reduced the unit rate by $0.51 per BOE and $0.38 per BOE for third quarter 2008 and 2007, respectively, and $0.50 per BOE and $0.18 per BOE for the first nine months of 2008 and 2007, respectively.

G&A expense increased during the third quarter and first nine months of 2008 as compared with 2007.  Our increased activities require additional personnel, which has resulted in higher payroll costs. In addition, we have increased our incentive compensation accruals to align with current expectations of achievement, and stock-based compensation increased $2 million and $10 million during the third quarter and first nine months of 2008, respectively, as compared with 2007.

Other Operating Expense, Net – See Item I. Financial Statements – Note 2 – Basis of Presentation and Note 13 - Commitments and Contingencies - Purchaser Bankruptcy for a discussion of the SemCrude matter.

Loss (Gain) on Commodity Derivative Instruments – Effective January 1, 2008, we discontinued cash flow hedge accounting on all existing crude oil and natural gas commodity contracts (or “commodity derivative instruments”). We voluntarily made this change to provide greater flexibility in our use of commodity contracts. From January 1, 2008 forward, we recognize all mark-to-market gains and losses on such instruments in earnings in the period in which they occur, rather than deferring them in shareholders’ equity until the related future production occurs. Our discontinuation of cash flow hedge accounting has no impact on our net assets or cash flows and previously reported amounts have not been adjusted. However, the use of mark-to-market accounting adds volatility to our reported earnings. See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(in millions)
Interest expense	$	26		$	33		$	75		$	97
Capitalized interest		(8	)		(4	)		(23	)		(10	)
Interest expense, net	$	18		$	29		$	52		$	87

Interest expense decreased during the third quarter and first nine months of 2008, as compared with 2007 due to declining interest rates applicable to our credit facility from 5.77% at September 30, 2007 to 4.064% at September 30, 2008 and a slightly lower average outstanding debt balance.

29

The amount of interest capitalized increased due to long lead-time projects in West Africa and the Gulf of Mexico.

Other Expense, Net – See Item 1. Financial Statements – Note 2 – Basis of Presentation.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
Income tax provision (in millions)	$	480		$	120		$	528		$	296
Effective rate		33.0	%		35.1	%		33.6	%		31.5	%

Our effective tax rate increased during the first nine months of 2008 as compared with 2007. The rate increase is caused by several factors, one of which is that the foreign pretax income in higher taxing jurisdictions, such as the United Kingdom and the Netherlands, increased in 2008.  Another increase that affected the rate was the recognition of losses from certain controlled foreign corporations, primarily Suriname, for which no foreign tax benefit was recognized. The overall rate increase was partially offset by the impact of an increase in earnings from our equity method investees. Earnings from equity method investees represent a favorable permanent difference in calculating income tax expense.

 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 may also generate cash.

The recent 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 Current Credit and Commodity Markets.

Cash and Cash Equivalents – We had $992 million in cash and cash equivalents at September 30, 2008, compared with $660 million at December 31, 2007. Our cash is denominated in US dollars and is invested in highly liquid, investment-grade securities with original maturities of three months or less at the time of purchase. Substantially all 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.

Commodity Derivative Instruments – As of September 30, 2008, we had commodity derivative assets totaling $58 million and commodity derivative liabilities totaling $258 million (after consideration of netting agreements). Our hedging arrangements are currently with a diversified group of 13 financial institutions, substantially all of which are lenders under our credit facility arrangement. See Part II. Item 1A. Risk Factors.

We estimated the fair values of our commodity derivative instruments in accordance with SFAS 157, which we adopted as of January 1, 2008. In order to determine the fair value at the end of each reporting period, we compute discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves for the underlying commodities as of the date of the estimate. We compare these prices to the price parameters contained in our hedge contracts to determine estimated future cash inflows or outflows. We then discount the cash inflows or outflows using a combination of published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of our commodity derivative assets and liabilities include a measure of credit risk based on current published credit default swap rates. In addition, for costless 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 parameters.  We compare our estimates of fair value with those provided by our counterparties. There have been no significant differences.

30

Beginning January 1, 2008, we use mark-to-market accounting for our commodity derivative instruments and recognize all changes in fair value in earnings in the period they occur. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Our liquidity is impacted by current period settlements 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 provided by operating activities will be lower than if we had no derivative instruments. As of September 30, 2008, the current portion of our commodity derivative liability totaled $189 million. 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. We expect that future settlements of these liabilities would be funded from cash flows from operations, and would be substantially offset by related increases in crude oil and natural gas revenues.  See additional information included in Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Certain of our commodity contracts were executed in connection with our merger with Patina Oil & Gas Corporation, prior to the global crude oil and natural gas price escalations which began in early 2005.  The settlements of these contracts have reduced our cash flows. However, these contracts will expire in December 2008.  Our remaining commodity contracts were executed in more favorable price environments.  Although we cannot predict market prices, our remaining commodity contract positions should result in more favorable cash flows as compared to our commodity contract positions in prior periods.  See Note 4 – Derivative Instruments and Hedging Activities for our current hedge positions.

Contractual Obligations – During the first nine months of 2008, we entered into drilling and equipment contracts for our domestic operations totaling $484 million and for our international operations totaling $278 million.  Had these contracts been included in our contractual obligations table in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2007, as amended, our domestic drilling and equipment obligations would have been $181 million in 2008, $105 million in 2009, $315 million in 2010, $301 million in 2011 and $45 million in 2012 for a total of $947 million and our international drilling and equipment obligations would have been $115 million in 2008, $75 million in 2009, $90 million in 2010 and $66 million in 2011 for a total of $346 million.

31

Cash Flows

Cash flow information is as follows:

	Nine Months Ended
	September 30,
	2008			2007
	(in millions)
Total cash provided by (used in):
Operating activities	$	1,867		$	1,321
Investing activities		(1,721	)		(1,015	)
Financing activities		186			(8	)
Increase in cash and cash equivalents	$	332		$	298

Operating Activities – Net cash provided by operating activities was $1.9 billion for the first nine months of 2008, as compared with $1.3 billion for the first nine months of 2007.  The increase was primarily due to higher commodity prices.

Investing Activities – Net cash used in investing activities was $1.7 billion for the first nine months of 2008, as compared with $1.0 billion for the first nine months of 2007.  Investing activities in 2008 consisted of $1.9 billion in capital expenditures offset by $131 million in proceeds from asset sales. Investing activities in 2007 consisted primarily of capital expenditures. See Acquisition, Capital and Other Exploration Expenditures below.

Financing Activities – Net cash provided by financing activities was $186 million for the first nine months of 2008, as compared with $8 million used in financing activities for the first nine months of 2007.  During 2008 and 2007, financing cash flows were provided by the exercise of stock options and related excess tax benefits. Financing cash flows were used to pay dividends on common stock. In addition, there were net proceeds from borrowings of $223 million in 2008 and $115 million in 2007. In 2008, $2 million was used to repurchase common stock as compared with $102 million used in 2007.

Investing Activities

Acquisition, Capital and Other Exploration Expenditures – Expenditure information (on an accrual basis) is as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(in millions)
Acquisition, Capital and Other Exploration Expenditures
Unproved property acquisition (1)	$	36	$	2	$	299	$	93
Proved property acquisition (2)		255		-		255		6
Exploration expenditures		142		97		385		250
Development expenditures		334		345		840		842
Corporate and other expenditures		19		5		53		24
Total capital expenditures	$	786	$	449	$	1,832	$	1,215

(1) Unproved property acquisition cost for the first nine months of 2008 includes deepwater lease blocks acquired in the March 2008 Gulf of Mexico lease sale and the Mid-continent acquisition completed in July 2008.  

(2) Proved property acquisition cost for the first nine months of 2008 includes the Mid-continent acquisition.

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Financing Activities

Long-Term Debt – Our long-term debt totaled $2.1 billion (net of unamortized discount) at September 30, 2008. Maturities range from 2011 to 2097. Our ratio of debt-to-book capital was 26% at September 30, 2008 as compared with 28% at December 31, 2007. 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.

Our principal source of liquidity is an unsecured revolving credit facility due 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.  At September 30, 2008, $1.405 billion in borrowings were outstanding under the credit facility, leaving  $695 million available for use.  The weighted average interest rate applicable to borrowings under the credit facility at September 30, 2008 was 4.064%. October borrowing requests have been funded.

Our bank group is comprised of 24 commercial lending institutions, each holding between 1.0% and 7.0% of the total facility.  Due to recent consolidation in the banking sector resulting from heightened stress in the credit markets, the number of lenders and their effective commitment levels within our credit facility may be reallocated over time.

Short-term Borrowings – We owe $25 million in the form of an installment payment to the seller of properties we purchased in 2007. The amount is due May 11, 2009 and is included in short-term borrowings in the consolidated balance sheets. Interest on the unpaid amount is due quarterly and accrues at a LIBOR rate plus .30%.  The interest rate was 3.1% at September 30, 2008.

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.  Amounts outstanding under uncommitted credit lines totaled $23 million with a weighted average interest rate of 4.92% at September 30, 2008. These amounts are included in short-term borrowings in the consolidated balance sheets. 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 cash dividends of 48 cents per share of common stock during the first nine months of 2008 and 31.5 cents per share of common stock during the first nine months of 2007. On October 21, 2008, our Board of Directors declared a quarterly cash dividend of 18 cents per common share, payable November 17, 2008 to shareholders of record on November 3, 2008. 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 $26 million from the exercise of stock options during the first nine months of 2008 as compared to $19 million during the first nine months of 2007.

Common Stock Repurchases – During the first nine months of 2008, we received from employees 33,000 shares of common stock with a total value of $2 million for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans.  During the first nine months of 2007, we repurchased 2 million shares of our common stock at an aggregate cost of $102 million, pursuant to a common stock repurchase program. The repurchase program was completed in 2007.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES

ABOUT MARKET RISK

Commodity Price Risk

Derivative Instruments Held for Non-Trading Purposes – We are exposed to market risk in the normal course of business operations. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.

At September 30, 2008, we had entered into variable to fixed price commodity swaps, costless collars and basis swaps related to crude oil and natural gas sales.  Our open commodity derivative instruments were in a net liability position with a fair value of $200 million. Based on the September 30, 2008 published forward commodity price curves 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 liability by approximately $12 million. A price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $7 million.  Based on the October 24, 2008 published forward commodity price curves for the underlying commodities, our open commodity derivative instruments had changed to a net asset position of $245 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 settled at the time of election. See Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities.

Interest Rate Risk

We are exposed to interest rate risk related to our variable and fixed interest rate debt. At September 30, 2008, we had $2.1 billion (excluding unamortized discount) of long-term debt outstanding, of which $650 million was fixed-rate debt with a weighted average interest rate of 6.92%. We believe that anticipated near term changes in interest rates would not have a material effect on the fair value of our fixed-rate debt and would not expose us to the risk of material earnings or cash flow loss.

The remainder of our long-term debt, $1.405 billion at September 30, 2008, was variable-rate debt. We also had $48 million in short-term debt at September 30, 2008. Variable rate debt exposes us to the risk of earnings or cash flow loss due to changes in market interest rates. We estimate that a hypothetical 25 basis point change in the floating interest rates applicable to our September 30, 2008 balance of variable-rate debt would result in a change in annual interest expense of approximately $4 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, 2008, AOCL included $3 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 are also exposed to interest rate risk related to our short-term investments. As of September 30, 2008, substantially all of our cash was invested in highly liquid, short-term investment grade securities with original maturities of three months or less at the time of purchase. A hypothetical 25 basis point change in the floating interest rates applicable to the September 30, 2008 balance would result in a change in annual interest income of approximately $2 million.

Foreign Currency Risk

We have not entered into foreign currency derivatives. The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in a foreign currency are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. We do not have any significant monetary assets or liabilities denominated in a foreign currency other than our foreign deferred tax liabilities in certain foreign tax jurisdictions. 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. However, transaction gains or losses were not material in any of the periods presented and we do not believe we are currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense, net in the consolidated statements of operations.

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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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

· our growth strategies;

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

· anticipated trends in our business;

· our future results of operations;

· 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 2007 annual report on Form 10-K, as amended, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.  Our 2007 annual report on Form 10-K, as amended, is available on our website at www.nobleenergyinc.com.

ITEM 4.  CONTROLS AND PROCEDURES

Based on the evaluation of our disclosure controls and procedures by Charles D. Davidson, our principal executive officer, and Chris Tong, our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, are effective.

We are in the process of implementing a new Enterprise Resource Planning (ERP) software system to replace our various legacy systems.  During the third quarter of 2008 we implemented another phase of the system. As appropriate, we modified the design and documentation of internal control processes and procedures relating to the implementation of the newest phase.  We believe that the new ERP system has strengthened and will continue to enhance our internal controls over financial reporting as additional phases are put to use; however, there are inherent risks in implementing any new system that could impact our financial reporting.

In the event that issues arise, we have manual procedures in place which would facilitate our continued recording and reporting of results from the new ERP system. However, because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We will continue to monitor, test, and appraise the impact and effect of the new ERP system on our internal controls and procedures as additional phases and features of the system are implemented. There were no changes in internal controls over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting, except as described above.

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PART II. OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

See Item I. Financial Statements – Note 13 – Commitments and Contingencies.

ITEM 1A.  RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2007, as amended, other than the following:

Hedging transactions expose us to counterparty credit risk.

Our hedging transactions also expose us to risk of financial loss if a counterparty fails to perform under a contract.  To mitigate counterparty credit risk we conduct our hedging activities with a diverse group of major financial institutions.  We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. We also  monitor the creditworthiness of our counterparties on an ongoing basis. However, the current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform.

In addition, during periods of falling commodity prices, such as has occurred recently, our hedge receivable positions increase, which increases our exposure. If commodity prices continue to decline and our receivable positions continue to increase, a loss from counterparty nonperformance could be significant.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

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

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SIGNATURES

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

	NOBLE ENERGY, INC.
	(Registrant)
Date:   October 29, 2008	/s/ CHRIS TONG
	CHRIS TONG
	Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit

Number                      Exhibit                      

10.1 Amendment to the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (effective September 1, 2008), filed herewith.

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

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

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

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

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